ops & wsg manual

technical training 2008

Operations&

Wellsite Geologist

Stag Geological Services Ltd.Reading

United Kingdom

Revision EJanuary 2008

www.stag-geological.com


Section 1 Operations & Wellsite GeologyChapter 1: Operations GeologyChapter 2: Wellsite GeologistChapter 3: Wireline LogsChapter 4: CoringChapter 5: Log WitnessingChapter 6: Pressure ConceptsChapter 7: Pressure DetectionChapter 8: Fracture Pressure

Section 2 Reporting ProceduresEnd-of-Well ReportDaily Reports

Section 3 Wellsite Geological ProcessesChapter 1: Formation EvaluationChapter 2: Lag TimeChapter 3: Mudlogging UnitChapter 4: Gas DetectionChapter 5: Sedimentary PetrologyChapter 6: Cuttings Evaluation

Section 4 Measurement While DrillingChapter 1: MWD OverviewChapter 2: Imaging LogsChapter 3: Geosteering TechniquesChapter 4: Geosteering Strategies

Section 5 Log ExamplesSection 6 Geosteering Case StudySection 7 Log Interpretation Charts

Figure 1: Table of Contents

Operations Geology

Operations & Wellsite Geology 1-1

IntroductionOperations and Wellsite Geology support plays a crucial role in the success ofdrilling and production ventures. Typically the Operations Geologist will be amember of the exploration department of the operating company although now, inmany cases, he is responsible to the project or drilling manager and thus may havea dual reporting role.

The drilling department will require information during the planning stage regard-ing the detailed geological stratigraphy, targets, offsets, problem formations andthe exploration department will require the collection and quality control of geo-logical data as the well is drilled.

The Operations Geologist will have been assigned at the beginning of the wellplanning phase and is the main communication link between the exploration anddrilling departments. He is a vital interface between the rig and the office and isalso responsible for the provision of wellsite contractor services. Partners willrequire the Operations Geologist to provide them with data and operational infor-mation in a timely manner.

The Wellsite Geologist is responsible the wellsite geological data collection andquality control of contractor�s services under the supervision of the OperationsGeologist. He may not have been involved in the planning process but obviouslyneeds to be sufficiently briefed prior to the commencement of the job in order tobe fully aware of the duties and responsibilities required of him.

The Operations Geologist and the Wellsite Geologist may be full time employeesof the Operator or specialist consultants. Consultants are usually very experiencedin both drilling and formation evaluation; many having begun their careers asMudloggers and so gained an appreciation of many the different disciplinesinvolved in drilling, evaluating and completing wells.

It is often the case that full time employees of oil companies are given operationsand wellsite roles early in their careers as a stepping stone in their overall develop-ment. The latter will need a great deal of supervision, guidance and training fromtheir managers as well as constructive support form the contractor�s personnel thatthey are dealing with.

General Duties of the Operations Geologist� Be an active member of the project team providing geotechnical support to

design and execute a well plan to meet exploration objectives

� Provide a Data Acquisition program to meet licence members objectives and government requirements

Operations Geology

Operations & Wellsite Geology1-2

� Compile the G&G section of the drilling program.

� Identify and select wellsite and post well analysis services

� Manage and QA formation evaluation Contractors and services

� Provide office based technical support to the rig team

� Receipt of data from all formation evaluation service providers

� Logistical support for wellsite Formation evaluation services

� Focal point for distribution of daily updates and communication for partners and government bodies

� Review of actual versus planned performance indicators

� Cost control of formation evaluation services

� Compilation of Completion Log

� Production of End-of-Well report

Well PlanningEstablishing a time frame for all activities is critical to the success of the projectmanagement. All critical path activities should be carried out efficiently andsmoothly; other activities need to be conducted in a manner that will not adverselyaffect critical path activities and particularly to the effect that they will not becomecritical path activities themselves.

The lack of key geological information can have a serious impact on the criticalpath. For example the lack of site survey information may delay rig choice andwell path planning and the lack of a pore pressure profile will impact casing andwellhead design.

Tasks for the Operations Geologist� Co-ordinate the needs of the exploration team and compile a DAP

� Organise vendor presentations for the project team

� Undertake vendor appraisals and organise contracts

� Meet deadlines for the Detailed Drilling Plan: Pore Pressure/Fracture Pressure Profiles, Site Survey data, Geological hazards

� Prepare a Data Acquisition Procedures manual

� Attend partner and government agency meetings

� Organise and facilitate pre-spud meetings and training

Operations Geology


Well Planning Process

The project team will have determined a set of well objectives which will form thebasis of the Detailed Drilling Plan (DDP). This will be compiled from G&G datasupplied by the Operations and Exploration department. In turn the DDP will allowthe Authorisation for Expenditure (AFE) proposal to be written and submitted forapproval. The AFE then becomes the most important document in the planning andexecution phases since it provides the controls and limitations for the entireproject.

Figure 1: Well Planning Process

1© 1999 Stag Engineering Services Limited

Well Planning Process

GeologyGeophysics

! Seismic Sections! Maps! Structures

Reserves! Field! Block! Area of Interest! Reservoir! Well

Well objectivesIncrease production & reservesIncrease efficiency & decrease project development costFlexible design: producer & injectorImprove Enhanced Oil Recovery/water-floodExploration tool in reservoir evaluationAny combination of the above

Well objectivesIncrease production & reservesIncrease efficiency & decrease project development costFlexible design: producer & injectorImprove Enhanced Oil Recovery/water-floodExploration tool in reservoir evaluationAny combination of the above

Asset Team RequirementsArchives

!Field Studies!Geology!Petrophysicss!Engineering!Simulation!Special Studies

Petrophysics(Logs)

! Gross column! Net column

!Φ! Lithology! Fluid Saturation!Geological Markers

Productivity/injectivity! Well location! Drilling & completion details! Well treatment! Well type producer, injector, Obs.! Status Shut In, Abd, Prod, etc! Artificial Lift System! Rates, oil, water, gas, choke size! Cumulative oil, water, gas

Petrophysics (Cores)! Φ & Horiz. & vert. k.! Petrology! Mineralogy! Clay Content

Fluid! Fluid Properties oil, water, gas! API Gravity, Viscosity! PVT Data

Well Proposal(inc. Reservoir Deliverables)

Surface location & ID, well length, orientation & targetsCorrelation wells, regional data, sections & mapsPrognosed Geology, formation tops, FBG, temperature Formation evaluation, logging, coring WSGExpected reservoir pressures & fluidsRecoverable reserves, production forecast oil, water & gasCompletion requirements inc. sand control &/or stimulationCompletion design & predicted flowing conditionsPotential for for future well interventionsQuality indicators

Well Proposal(inc. Reservoir Deliverables)

Surface location & ID, well length, orientation & targetsCorrelation wells, regional data, sections & mapsPrognosed Geology, formation tops, FBG, temperature Formation evaluation, logging, coring WSGExpected reservoir pressures & fluidsRecoverable reserves, production forecast oil, water & gasCompletion requirements inc. sand control &/or stimulationCompletion design & predicted flowing conditionsPotential for for future well interventionsQuality indicators Methods

Material balance calculationsVolumetric analysisDecline curve analysisLog evaluationPressure transient analysisAnalytic models e.g. JTI HorizontalEOR screeningGeostatistics & reservoir characterizationReservoir simulation

MethodsMaterial balance calculationsVolumetric analysisDecline curve analysisLog evaluationPressure transient analysisAnalytic models e.g. JTI HorizontalEOR screeningGeostatistics & reservoir characterizationReservoir simulation

Reservoir Analysis- Original oil/gas in place & recovery to date- Drive mechanisms- Changes of OWC & GOC with time- Rock & fluid characteristics of all zones- Production/completion problems e.g. sand, wax- Depletion of reservoir pressure with time- Production forecasts assuming no EOR- Field/reservoir recovery factors- Remaining recoverable oil & gas reserves- Identify/explain zones of low recovery &/or bypassed oil- Construct reservoir model to predict reservoir performance

Reservoir Analysis- Original oil/gas in place & recovery to date- Drive mechanisms- Changes of OWC & GOC with time- Rock & fluid characteristics of all zones- Production/completion problems e.g. sand, wax- Depletion of reservoir pressure with time- Production forecasts assuming no EOR- Field/reservoir recovery factors- Remaining recoverable oil & gas reserves- Identify/explain zones of low recovery &/or bypassed oil- Construct reservoir model to predict reservoir performance

Data Acquisition& Analysis

Data Acquisition& Analysis

Operations Geology


Figure 2: Detailed Drilling Plan

Operations Geology


Figure 3: AFE Template

Operations Geology


Generalised G&G data needs to be submitted to the Drilling Engineers at an earlystage in order that the initial well plan and design can begin. This may be up to oneyear before spud date. The G&G data will necessarily be lacking detail but the gen-eralities of a planned logging programme will influence the drilling plan. Somelogging tools will, for example, be mud specific and will need to be identified earlyon.

The Geological Program and the DDP will evolve over time. They will becompiled by individuals with input from many other contributors. Regularmeetings need to be held with project and exploration team members to communi-cate goals and plans and solicit constructive feedback. All planning documentsneed to be verified by team members before being submitted for approval. The dis-tribution of all documents will be controlled in order that amendments may bemanaged correctly and that all individuals are using the most up-to-date versionsof them.

Summary of Operations Geological Issues for Well Planning

Well Objectives

� Should take into account all of the above points and will include production criteria, reservoir exposure, coring, testing and safety issues.

� Risks- Mitigations

� MWD/LWD

� �Wireline� logs

� Other formation evaluation services

� Communications & Team Work

Critical G&G data for Detailed Drilling PlanThe following data is critical for the early development of the detailed drillingplan. They impact rig selection, casing and wellhead equipment selection.

� Site Survey/Shallow hazards

� Pore Pressure Prognosis

� Fracture Pressure Prognosis

� Geological Hazards

Operations Geology


Site Survey/Shallow hazardsThe site survey should be carried out at least six months prior to spud and willnormally consist of the following components:

� Positioning

� Sea-Bed Investigations

� Sub-Bottom Investigations

Figure 4: Components of a Site Survey

GPSDifferential Corrections

Seismic Relection(sub-surface)

Sidescan Sonar(surface area)

Operations Geology


PositioningGeodesy: Measuring the Earth3 Reference Surfaces:

� Topography

� Geoid

� Ellipsoid (Spheroid)

2 Measurement Systems:

� Geographical

� Projections

Ellipsoid is the basic reference surface

Heights are often related to Geoid (MSL)

GPS heights are related to Ellipsoid

Latitude/ Longitude referenced to Ellipsoid

Lat/ Long ALWAYS need associated DATUM

Projections (UTM etc.) ALSO need DATUM

Locating & Orientating the Ellipsoid in space requires 8 constants to be defined:

� Size & shape of Ellipsoid (2 parameters)

� Direction of minor axis (2 parameters)

� Position of the centre (3 parameters)

� A zero coordinate (1 parameter)

� Naming of Datums can be problematicalVenezuela has 17 Datums in Maracaibo3 are called "Maracaibo Cathedral�

Operations Geology


Ellipsoids always associated with Datums

� Ellipsoid names can be duplicated

� Ellipsoid PARAMETERS are best

� There are several �versions� of ED50 Datum

� All convert to/from WGS 84 DIFFERENTLY

� 54 deg N/ 3 deg E (ED50 / ED87 Equivalent): --53d 59m 57.51s N/ 2d 59m 55.08s E (WGS 84)

� 54 deg N/ 3 deg E (ED50, old �general�):--53d 59m 57.29s N/ 2d 59m 54.87s E (WGS 84)

� Approx. 8 metres variation

� Vessel navigation, typically (95%) 3 - 5 m

� Bathymetry: depends on depth

� Sidescan sonar, typically (95%, relative) 5 - 8 m

� Sparker, boomer, airgun (95%, relative)3 - 5 m

� Hydrophone arrays (95%, relative) 5 - 8 m

� RMS Sidescan6 - 9.5 m

� RMS sources4 - 7 m

� RMS hydrophones

Sea-bed InvestigationsSea floor cores and samples are taken to determine the nature and strength of sed-iments and to calibrate side-scan sonar and bathymetry data. This is particularlyimportant for Jack-Up rigs in order to prevent leg instability.

Sea-floor samples

Grab sampler This is dropped under its own weight and is spring triggered on impact. The bucketrotates, trapping the sample. It is limited to the top 30-40 cm of seabed. The sampleis collected with minimal disturbance.

Operations Geology


Core samplerGravity Corers - these corers are available in a wide range of options, withlengths of corer tubes from 1m to 10m in a variety of diameters, with or withoutinternal tube liners. With tube barrels of either mild steel (with a choice of finishes)or stainless steel. The tube barrels are supplied with or without cutters. The largestGravity Corer supplied to-date, had a barrel length of 32m and weight 10 tonnes.

Figure 5: Grab & Core sampling

Grab sampler dropped under own weight.Spring triggered on impact. Bucket rotates,trapping sample. Limited to top 30-40 cmof seabed. Sample collected with minimaldisturbance.

Weight

RotatingBucket

Coil Spring

Fin

Weight

Core Tube

Core Liner

Piston

Tough Nose& Core Catcher

Weight

Free-Fall Release Gear

Grab & Core SamplingRequired to “ground truth” sidescan and bathymetry data by calibrating records to sample types. Samples taken at points in the survey area identified by sidescan. Enables confident extrapolation of very shallow sediments over a wide area

Operations Geology


Side-scan SonarThe intensity of sound received by the sidescan-sonar tow vehicle from the seafloor (backscatter) provides information as to the general distribution & character-istics of the superficial sediment. This may include channels, boulders, subsidence(pock marks), sea-bed features and sub-sea structures e.g. wellheads, pipe linesand shipwrecks.

In the lower left schematic, strong reflections (high backscatter) from boulders,gravel & vertical features facing the sonar transducers are white; weak reflections(low backscatter) from finer sediments or shadows behind positive topographicfeatures are black. The sea floor is typically surveyed in swaths 100-500 meterswide; the swaths are mosaiced together to form a composite image of the surveyarea.

Figure 6: Grab & Core sampling

Operations Geology


Figure 7: Sidescan sonar

Operations Geology


Figure 8: Sidescan Sonar example

Sidescan Example: Port Hunter

Operations Geology


Seismic Reflection ProfilingSeismic reflection profiling is accomplished by towing a sound source that emitsacoustic energy at intervals behind a survey vessel. The transmitted acousticenergy is reflected from boundaries between various mediums of different acousticimpedances (i.e. the water-sediment interface or between geologic units). Acousticimpedance is defined by the bulk density of the medium & the velocity of thesound within that medium. The reflected acoustic signal is received by a ship-towed hydrophone (or array of hydrophones), which converts the reflected signalto a digital or analog signal. The signal from the hydrophone can be logged,filtered & displayed. The digital data can then be gathered with information fromadjacent hydrophones to enhance the signal to noise ratio.

A shallow seismic survey is commonly run over 6.5 square km area with the spudlocation at its centre. It will identify shallow geological features such as channels,shallow sands and shallow gas deposits down to the depth at which casing wouldnormally be set at the BOP installed.

Figure 9: Pockmarks

Operations Geology


The SparkerThe Sparker is a relatively high powered sound source, dependent on an electricalarc which momentarily vaporises water between positive & negative leads. Thecollapsing bubbles produce a broad band (50 Hz - 4 kHz) omni directional pulsewhich can penetrate several hundred meters into the subsurface. Resolution is 2-5metres. Hydrophone arrays towed nearby receive the return signals.

Figure 10: Seismic Reflection Profiling

Operations Geology


The Pinger (CHIRP)The Geo Acoustics GeoChirp is a sub-bottom profiling system for high resolutionshallow geophysical surveys. The Chirp concept uses advanced frequency modu-lation (FM) & digital signal processing to attain good penetration of the sub-bottom layers whilst achieving higher resolution records. The Geochirp is config-ured with the electronics bottle mounted on the towfish & the receiving hydro-phone attached & towed directly from the rear of the fish. Data from the GeoChirpmay be displayed on a variety of graphics recorders or sonar acquisition systems.

Figure 11: Sparker

Operations Geology


Figure 12: Pinger

Operations Geology


Figure 13: Boomer

Figure 14: Sparker Profile

Operations Geology


Figure 15: Pinger Profile

Operations Geology


Figure 16: Boomer Profile

Operations Geology


Figure 17: Pinger - Shallow Gas profile

Figure 18: Shallow Gas profile

Operations Geology


The Boomer This is a broad band sound source operating in the 300Hz - 3kHz range. By sendingelectrical energy from the power supply through the wire coils (above), the twospring loaded plates in the boomer transducer are charged, causing the plates torepel, thus generating an acoustic pulse. This system is commonly mounted on asled & towed behind the boat. Resolution of the boomer system ranges from 0.5 to1 m; penetration from 25 to 50 m.

The processed section, (Fig.18), is of a boomer source into a single short streamer.Profile spacing 500m.

Sea floor is either a strong till-layer reflection (1) or a weaker mud horizon at (2)from unconsolidated sediments. A bright spot at 3 is a reflection with invertedsignal phase. This has been interpreted to be shallow gas, at a depth of around 4 mbelow the mud surface. There is a second till-layer at (4) which is faulted & mayconsist of coarser material than the sea floor till. At this depth we also see dippingfeatures (5) which aren�t classified. Deeper, we start to see prominent multiples,which mask deeper geology.

Overview Of Shallow Gas

Offshore v onshore risksShallow gas has often been thought of as a problem that occurs only offshore - thisis not true (although shallow gas onshore is less frequent).

The guidelines laid out in this guideline document are to be applied (where neces-sary) to all operations irrespective of whether on land or offshore. It is not commonpractice to conduct shallow gas surveys onshore.

Definition�Shallow Gas� can be defined as formation gas that is encountered in a well priorto running the full pressure containing BOP stack.

In general, this means �top hole� until 20" casing (or similar diameter) has been set,but wells have been drilled with a diverted installed until the 133/8" casing has beenset at depths in excess of 4,000 ft.

EquipmentThe equipment employed to handle shallow gas is principally dependent on thetype of installation or rig carrying out the drilling operation. If the installation is afloating unit, then where environmental legislation permits the well should bedrilled riserless. Where riserless drilling is not permitted a subsurface divertor is

Operations Geology


employed. Both options allow all gas to be released subsea & the rig involved tomove off the location.

If a bottom supported rig is being employed a surface divertor system is used. Incase the rig cannot be moved off location, diverting the gas away from the unit isthe only option. Shallow gas is only diverted if the wellbore formation is suffi-ciently weak that if closed-in by use of a conventional BOP stack a sub-seablowout would result.

Type of GasShallow Gas is most likely to be a hydrocarbon gas but may also be H2S. It can becapable of carrying large quantities of abrasive formation such as sand & rocks,consequently erosion of equipment is a major issue.

Irrespective of its chemistry, shallow gas will create a risk to personnel & equip-ment if allowed to surface around the rig.

Origins of Shallow GasGas is generally believed to be the result of decayed organic material & as suchcan exist at any depth. Accumulations that can endanger the drilling operationduring top hole, are most likely to be in sediments with high porosity & high per-meability. Shallow gas accumulations may be under either a �normal� or �abnor-mal� pressure regime. An accumulation of shallow gas can therefore exist invarying quantities (volume), under varying pressures & in formations with differ-ent permeabilities.

No matter what the conditions, shallow gas must ALWAYS be treated withextreme care.

On multi-well platforms, gas may accumulate at shallow depths as a result of com-munication behind poorly cemented casing strings. H2S can also be a majorproblem due to decomposing mud products.

DetectionThe detection of shallow gas falls into two distinct phases:

Prior to spudThis involves various surveys that are carried out by the Operator prior to drilling.These include, but are not limited to:

a) Sea bed surveys

b) Shallow seismic surveys

Operations Geology


c) Soil borings

Soil sampling is a hazardous operation, because shallow gas might be encounteredduring the coring process. The lack of string valve protection, can result in the holeblowing out through the pipe. In offshore operations, a safer approach would be toinvestigate the soil for shallow gas prior to undertaking soil sampling by drilling atest hole with float valve protection to at least the deepest sampling point.

It is imperative that the Operator undertakes extensive soil borings when selectinga location for a bottom supported rig &/or platform location. Soil borings offer:

� Tie-in of geology to seismics & other offset data.

� Potential shallow gas zones.

� Information on hydrocarbon content.

� Detailed lithology of soil layers.

� Strength determination of formation, important for platform position, con-ductor setting depth & the cementation design for surface casing. Note that in soft seabed areas, leg penetration can be up to 100 ft below the mud line, which can cause risks with jacking up.

d) Pilot hole drilling from specialised units

Pilot holes may be drilled up to conductor string depth, as part of a preliminaryshallow gas investigation programme, prior to spudding a well. The following sit-uations may justify drilling pre-spud pilot holes:

� At locations where offshore platforms are planned to be installed.

� In areas where little geological information is available.

� In areas with a high probability of shallow gas whereby the depth of shallow gas is unknown.

� In floating drilling operations, which require returns to surface for geologi-cal reasons (formation cuttings control).

� Pilot hole drilling (pre-spud) should be done with a floating vessel, which can move off location efficiently in case of a shallow gas problem.

e) Information which may be used to examine the potential for shallow gas shouldalso include a review of all existing documentation (& experience) for the area inquestion, which may contain useful pointers to shallow gas. The following reportsmay be considered:

� Subsea Platform Inspection Reports

� Pile & Conductor Reports

Operations Geology


� Offset Well Data

Whatever type of data is collected, it is the responsibility of the Rig Manager toensure that data is reviewed & analysed in conjunction with the client.

It is essential that offshore & onshore senior personnel make every effort toresearch & communicate information relating to special features during top holedrilling. Remember that the success of a survey (non-invasive technique), is noguarantee that there will be an absence of shallow gas.

Specific �shallow gas� pre-spud meetings with all concerned are a must. All con-tingencies must be covered & mutually agreed & written up for distribution priorto spud.

After spuddingFollowing spud, rig-site supervisors must ensure that hole & environmental con-ditions are continually monitored from spud to casing being set. Parameters thatmust be monitored include ROP, hole volume & return flow (if riser employed),geology (cuttings, MWD), swab & surge, prevailing weather & moon pool watch.

Well control techniques relevant to top hole drilling must be employed

Formation Pressure PrognosisThis can be prepared from Offset Well Data:

� Mudlogging reports

� Wireline/LWD logs

� Direct Pressure Measurements

� End-of-Well Reports

Pore pressure estimates should agree with offset data, particularly with MDT/RFTresults. Fracture gradient predictions should be based on LOT/FIT data and anydiscrepancies, such as Fracture Gradient predictions in excess of OverburdenGradient should be investigated.

Pressure transition zones are particularly important to identify. Different pressureregimes are not normally separated by a sharp boundary but by a gradation, oftentens of metres thick. It is important to identify the thickness of the transition zoneand also the pressure gradients within.

Fractures may transmit pressures to shallower depths and the crests of dipping per-meable rocks may also exhibit higher pressures than the surrounding shales withina pressured clay section.

Operations Geology


Initial casing design is based upon the pore pressure and rock fracture estimatesand the associated mud weight and ECD requirements. Remember that ECD willcontinue to increase when drilling horizontal sections although pore pressure andfracture pressure values may remain the same.

Operations Geology


Figure 19: Pressure Profile

Operations Geology


Other Geological Hazards

Gas HydratesGas Hydrates are compounds of frozen water that contain gas molecules. Theylook similar to white, powdery, snow and have one of two basic structures:

� Small structure holding up to 8 methane gas molecules and 46 water mole-cules. This structure may also contain ethane, H2S and CO2.

� Larger structure consisting of 136 water molecules with larger hydrocarbon molecules of pentanes and butanes.

Gas hydrates only occur in high pressure-low temperature conditions in shallowarctic or deep oceanic sediments. In Alaska they occur between 750m and 3500m.They may have a shallow biogenic origin or, because of their carbon and heliumisotope ratios, a crustal inorganic origin.

They may appear as bright spots on seismic lines but their presence is only usuallyconfirmed with drilling; penetration rates are typically slow and they have highresistivity and acoustic velocity coupled with low density.

Operations Geology


Hydrating ClaysMixed layer clays consisting of Illite/Smectite will exhibit hydrating and swellingcharacteristics due to the bound water in the mineral structure. The 2:1 layer claysconsist of negatively charged mica-like sheets which are held together by charge-balancing counter-ions such as Na+ and Ca2+. In the presence of water, the coun-terions hydrate and the interlayer water forces the clay layers apart. The interlayerconfiguration, and therefore the swelling properties of the clay, is controlled by anumber of factors including composition (total layer charge and charge location),interlayer cation (type, valency and hydration energy) and external environment(humidity, temperature and H2O pressure).

Typically swelling clays are controlled by using oil based mud which does nothave any free water to react with the clays to produce the hydrated material thatwill ball bits, restrict downhole circulation, and block flowlines and shale shakers.Otherwise the use of sea water and the addition of salts (K, Ca, Na) and variouspolymers will suppress this swelling tendency. Recently synthetic fluids based onolefins and esters and the addition of glycol to water based systems has also beenused.

Hard CarbonatesThick deposits of carbonates can cause major drilling problems. They are rarelyhomogenous; the autochthonous chalks of the North Sea are generally low porosity

Figure 20: Gas Hydrates

Operations Geology


whilst the allochthonous chalks are often very porous which contributes, togetherwith extensive fracturing, to the oil and gas reserves of Norway, Denmark andHolland.

Variable clay content, fracturing, recrystallisation, dolomitisation and the presenceof flint and chert all have a major impact on the choice of bits and drillstring com-ponents.

Commonly these rocks produce a harsh drilling environment with severedownhole vibration caused by bit bounce and stick-slip processes. Minimisingweak points in the BHA is prudent so running MWD tools in these sections shouldbe avoided if at all possible. If there are no objectives or operational decisions tobe made in these rocks then the decision is relatively easy. If there is a need to steerthe well through Chalk sections or if they are objectives then mud motors andvibration modules and thrusters should be used.

EvaporitesThe presence of salt will have a major impact on well design, particularly the mudand casing string. High pressures caused by squeezing salts need to be resistedduring and after drilling and dissolution of salt is required by the use of oil basedmuds or salt saturated water based systems.

Tectonic Stress and Borehole StabilityThis will be a problem when drilling into highly dipping beds, across fault zonesor in fractured rock. Ideally the well path should be aligned at 90º to the tectonicfeatures, though this is rarely achievable.

Borehole stability and hole cleaning is controlled by the drilling fluid. Mudweights, ECD, swab and surge pressures need to be closely monitored.

H2S

The presence of H2S will have a significant impact on well design. H2S is a safetyhazard and will affect wellsite operations. If the well is designated as an H2S wellspecial training programmes will need to be available for all personnel togetherwith the provision of specific PPE.

H2S is also extremely corrosive; special H2S resistant drillstring components,casing and tubing will have to be supplied. Long lead times on this equipment canbe expected.

WSG Responsibilities


Offshore Geologist

Job Specification

a. Key Result AreaTo supervise the acquisition of all offshore geo-seismic well information, inter-pret and evaluate the obtained data and communicate the results effectivelyaccording to the objectives in the Drilling Programme.

b. Performance IndicatorsAttaining the highest possible standards of technical achievements with relationto safety and secure acquisition and evaluation of geo-seismic data.

c. Responsibilities1. To ensure that all relevant geological information from offset well isavailable on the rig.

2. Co-ordinate and supervise all geological operations and provide sup-port and troubleshooting as and when required. Core handling, mudlog-ging, sampling, pore pressure evaluation, biostratigraphy and logging.

3. To ensure that all relevant geological data is acquired, recorded and ofthe highest possible quality.

4. To supervise the contractor personnel in the performance of theirduties.

5. Perform and ensure compliance with all Quality Control requirementscontained within the relevant QMS documents.

6. Maintain and revise existing Wellsite Geology work instructions basedon post-well experience and new Government requirements.

7. Prepare and send daily geology reports and well data to Company,Government and partners

8. Proactively participate in daily offshore team meetings

9. At the end of each well section or during periods slow operations, col-late the data in a way that it can be put straight into reports such as theFinal Well Report.

10. Log and monitor MWD tools offshore and report to Offshore WellSupervisor

11. Evaluate MWD formation evaluation logs for changes in lithologyand rock parameters. Use the data for correlating against offset wells.Report on the quality of the data received and operational efficiency ofeach run



d.OrganisationAccountable to:

Offshore Well Supervisors (Operationally) Operations Geologist (Functionaland Technical)

Subordinates:None

Internal Interfaces:All members of the Drilling Team and G&G operations staff

External Interfaces: Service companies and Drilling Contractor.

Qualification Requirements

a.Work Experience

Essential

• 6-8 years general wellsite geological experience with a minimum of 3 years offshore experience in the North Sea Arena.

Desirable

• Computer/keyboard skills and knowledge of reporting systems.

• Knowledge of data formats

• Knowledge of MWD and wireline logs

• Knowledge of real time pore pressure evaluation

b) Qualifications

• University degree or equivalent in geology/earth science.

• Updated in issues related to wellsite geology

• Fluent in the English language.

• Leiro II Part I and Part III



• Knowledge of relevant Country Rules and Regulations.

c) Physical Make-up

• Offshore Health Certificate

e) Abilities

• Communications and team skills.

• Setting of priorities and ability to meet deadlines.

• Ability to perform under pressure.

Wellsite Geologist

Wellsite Geology Responsibilities

Planning Phase

• Ensure adequate pre-job briefing.

• Familiarization with Client policy and procedures.

• Familiarization with well specific data requirements.

• Familiarization with relevant software packages used for reporting, log drawing and communication.

Operational Phase

• Participation in rig safety meetings.

• Liaison with key personnel (Operations Geologist, Well Supervisor, Mud-loggers, Log Witness, Mud Engineer, FEMWD/geosteering personnel, Directional Driller, core contractor representative, Toolpusher, Driller, Radio Operator, etc.

• Monitoring of operations

• Responsibility for collection, QC and dispatch of geological samples

• Responsibility for collection, QC and reporting of geological data

• Responsibility for lithological description and geological interpretation



• Responsibility for core point selection

• Responsibility for core retrieval and expeditious dispatch

• Supervision of contractor personnel (mudloggers, FEMWD/geosteering contractor etc.)

• Attendance and participation in relevant operational meetings and calls as operations dictate

• Ensure good team working and communication when more than one wellsite geologist is at the wellsite (e.g. HPHT, geosteering, extended coring pro-grammes, etc.)

• Ensure adequate briefing and full documentation at crew change

Post-well Phase

• Ensure that geological data and samples are dispatched from the rig.

• Ensure that geological computer hardware and consumables are secured.

• Completion Log Finalisation

Safety and CertificationThe Wellsite Geologist must adhere to, the health, safety and environmentalprocedures specific to the work location. The Wellsite Geologist is required toparticipate in rig safety meetings and drills as required for each installation.

Preparation and TrainingThe Wellsite Geologist must be familiar with the computing equipment andsoftware, techniques and requirements that are to be employed at the wellsite:

Computing Equipment and Software Packages

• Use of the PC network

• Maintenance of the geological database and generation of reports

• Completion / Lithlog drawing

• Adobe Acrobat software to convert graphics files to (.pdf) format files

• Business software



• Outlook e-mail

• Schlumberger’s PDS View / Atlas Meta Viewer software

• Zip software

Techniques

• Sample preparation and description

• Hydrocarbon show detection and description

• FEMWD service quality control

• Mudlogging

• Core point selection

• Core handling

• Geosteering supervision

• Biosteering supervision

• Pore Pressure detection and prediction

• Wellbore instability indications

• HT/HP techniques

• Petrophysical log operations witnessing when required including sidewall coring

• Formation evaluation interpretation from FEMWD and wireline logs

• Correlation.

CommunicationsThe Wellsite Geologist is required to maintain effective communications withthe Operations Geologist and key wellsite personnel. All operationally signifi-cant communications and data should be copied to the following personnel:

• Operations Geologist• Well Supervisor



All changes to the geological programme, or operational instructions will bedirected to the Wellsite Geologist through the Operations Geologist.

Where more than one Wellsite Geologist is at the wellsite, working practicesmust be adapted so that there is 24 hour geological cover. Work rotas shouldallow all the Wellsite Geologists to attend the morning operations meetings andcalls.

It is imperative that hand-over between shifts and/or between crews is seamless.Effective hand-over is a requirement and the responsibility of the all the partiesinvolved. Any queries or clarifications that arise should be addressed to theOperations Geologist.

Geological Data AcquisitionIt is the responsibility of the Wellsite Geologist to collect and interpret the geo-logical and operational data from all available sources. These data should besummarised in the Geological Morning Report, Mudlog and Completion Log/Lithlog.

Geological interpretations influencing operational decisions (e.g. coring point,geosteering, casing setting depths etc.) should be communicated immediatelyto the Well Supervisor and Operations Geologist.

The Wellsite Geologist is responsible for the collection, quality control,description, interpretation, reporting and dispatch of the following wellsitedata:

Samples

• Cuttings samples as per sampling programme in the Drilling Programme

• Mud samples as per sampling programme in the Drilling Programme

• Sidewall cores as advised during logging operations

• Hot shot samples as operations dictate

• Additional samples (i.e. bottoms up samples, samples from the mud clean-ing equipment, etc.)

• During sustained fast drilling, the Wellsite Geologist may vary the sampling interval if it is impractical. Any variations of sampling interval should be documented and the empty sample bags, (where used), included in the sam-ple boxes.



Conventional CoresThe Wellsite Geologist is responsible for the following aspects of conventionalcoring:

• Core point selection (as per the criteria in the Well Proposal Document)

• Core handling, depth control and marking

• Sampling for lithological identification and description

• Preserved sample collection and preservation

• Description and interpretation

• Packing

• Expeditious dispatch from the wellsite

Operational Data (subject to well specific requirements)

• FEMWD curves

• Operational detail

• Lithological descriptions

• Hydrocarbon show analysis

• Mudlogging detail

Reporting ProceduresOn arrival at the wellsite, contact the Operations Geologist.

Daily at 06:00, submit the following reports and logs to the Operations Geolo-gist:

(a) Geological Morning Report reflecting the geology, gas levels, ROP andoperations that have occurred within the previous 24 hour period(b) Digital file of Mudlog, covering the section logged in the previous 24hours. When appropriate, other logs such as the pressure log should also beattached with the report.(c) FEMWD logs at 1:500 scale in both MD and TVD acquired over the pre-vious 24 hours.(d) Periodically send in CGM files of Geologist’s Field Completion Log/Lithlog illustrating the geological interpretation over the previous section



Telephone updates to the Operations/Duty Geologist or geological support tothe Drilling Supervisor as follows:

(a) Morning rig call at designated time.(b) Afternoon rig call at designated time.(c) Ad-hoc updates as requested by the Operations Geologist.(d) At Any Time for geological support from the Operations Geologist orDuty Geologist. e.g. key decision points such as casing and coring).

During coring operations; for each core as soon as available:

(a) Core Report detailing the depths in MD and TVDSS, recovery, missingintervals, gas, ROP and geology (b) Core log at agreed scale (c) Core dispatch details (d) Sidewall Core Descriptions

Miscellaneous:

(a) Quality control report for the mudlogging service weekly(b) Quality control report for the FEMWD/Geosteering after each run (c) Sample dispatch details (d) Hot-shot sample dispatch details

Wellsite Supervision of Contractor PersonnelThe Wellsite Geologist is responsible for the supervision and quality control ofthe geological aspects of the following services whilst at the rig site:

• Mudlogging (service quality control, sampling interval, gas detection, pore pressure detection and the accuracy of the Mudlog.)

• FEMWD/Geosteering (data quality control, log transmission, data interpre-tation and geosteering recommendations.)

• Coring (core handling, cutting, packaging and despatch.)

• Biosteering (sample selection, data interpretation and biosteering recom-mendations.

Operational Guidelines The geologist should make every effort to maintain tight security on well dataeven when the well is not on tight hole status. All confidential data such as logs,reports etc. will be restricted to authorised personnel. No contractor personnel



should be admitted into the mud logging unit or the wireline logging unit, bothof which should be locked when unmanned.

On completion of the well the last wellsite geologist to leave the rig will extractfrom the file all working copies of exploration data and forward these to theClient.

Routine Sample DistributionWhen shipping samples from the wellsite it is important to follow the correctprocedure, as specified below:

Advance notification of all sample consignments should be made by fax oremail (i.e. not included in the geological report or other reports) to OperationsGeologist at the Client’s office. The message should specify the nature of thesamples (i.e. stratigraphic, "Hot Shots", oil samples etc.), depth interval(s),means of transport, name and/or number of carrier, and estimated times ofdeparture and arrival. Relevant information (i.e. well number, sample type,name of consignee and destination) should also be marked on the outside of thesample package.

In the case of bulk or other samples brought onshore by boat the same generalprocedure will apply. It is important that all unaccompanied sample consign-ments should be listed on the boat or helicopter cargo manifest in order to avoidpossible problems with customs and, also, to facilitate warehousing.

Avoid the use of misleading descriptions when entering data onto a manifest,e.g. 5 litre sample tins should never be called paint tins as this implies hazardouscargo.

MWD Logging DutiesQuality check all logs real time. Work with the MWD company and the ClientDrilling Supervisor to ensure that the environment for high quality MWD datais attained. Try to evaluate the data for early signs of trouble as well as for for-mation evaluation.

Send digital TIFF files (or equivalent) of FE MWD logs to the Client, partnersand Government Agencies daily when the tool is in use during drilling. In theevent of email outage the logs should be faxed.

The MWD log should be used in conjunction with mudlog data to generate aninterpreted lithology which will be displayed on the mudlog, completion log /Lithlog

At the end of each MWD run a report should be produced noting the MWDserv-ice, tool serial number, interval logged, circulating hours, drilling hours, relia-



bility of the data and usefulness for geological interpretation. Any problemsshould be noted and appraised with recommendation for further action or eval-uation.. Lost time e.g. trip to replace MWD module etc. should be highlighted.

As with wireline logging it is very desirable to try and tie in the logs with aprevious run. Generally MWD companies do not recommend that the well islogged at more than 20 m /hr however, for tie in purposes logs can be run at upto 60 m/hr with certain companies.

Geological Morning ReportNormally when new formation has been drilled a geological morning reportshould be transmitted at report time (0600 hrs) by email to Client and partners.A distribution list will been compiled for this purpose. The backup for emailwill be the telefax. Telefaxes to Client should be sent to; operations Geologist.

The geological morning report will contain:

• Well number

• Report date

• Present depth

• Age of formation

• Present activity

• A detailed summary of lithologies drilled since the previous report

• Formation tops

• Gas reading

• Hydrocarbon shows

• Coring

• DST / testing data where applicable

Any drilling/engineering data contained in the daily geological report should beverified by the drilling supervisor before distribution.

In addition to the routine reports, the geologist should at his discretion send insupplementary reports whenever important information becomes available.



Distribution of these reports would normally be the same as for the geologicalmorning reports.

Geological issues requiring immediate attention should be discussed by phoneor email with the duty geologist. Out of office hours contact with the duty geol-ogist should be made by phone.

Any geological report should be clear and concise and include any commentsthe geologist considers pertinent to the interpretation of the section based on hisobservation of the well data and his overall experience. Such comments mayappear highly subjective at the time but are often extremely valuable to headoffice personnel. Long and detailed lithological descriptions should be avoidedon these reports.

Formation tops should be marked as preliminary and should indicate the infor-mation used to aid selection.

Mudlogging SupervisionIt is the responsibility of the wellsite geologist to supervise the mud loggingcrew and to ensure that they perform their duties in a satisfactory manner. Inparticular, it is very important that the mud log is updated twice daily at shiftchange. Should the geologist consider any aspect of the mud logging service tobe unsatisfactory he/she should report this to the Client drilling supervisoroffshore and to the operations geologist onshore.

Completion Log & Lithology LogThe wellsite geologist will not be required to compile an independent lithlog asthis is simply a duplication of information. Instead, he should ensure that themudlog is as accurate a recording of the data possible, and should play a majorpart in its compilation.

Log draughting software will be available at the wellsite. This will be used forthe generation of a Completion Log. During the course of the well the wellsitegeologist should enter as much of the Completion Log data as possible, includ-ing graphic lithology, lithological descriptions, formation tops, cores, sidewallcores, RFT points, Two Way Time at formation tops, casing points, MudWeight, Pore Pressure, Porosity and Water Resistivity in reservoirs, engineer-ing data etc. This will minimise work required after completion of the well andhas the further advantage that the compiling is done while the well informationis fresh and freely available. Updates of this log should be periodically sent toClient as a.pdf or image file.

At the end of the well a .pdf or image file of the draft version of the completionlog should be sent to the Client. This will serve as a working copy until the final



version is made. Work on the final version of the completion log will notcommence until all post well data required for the log has been received.

The Field log is prepared on a 1:500 vertical scale using Resistivity/Sonic/GRdata. The MWD logging contractor will supply this data on a disc in LAS /ASCII format shortly after completing each logging run.

Final Completion Log should have the following curves:

• GR (API) ROP (M/HR) CAL (IN) (Log Track 1)

• RD & RS (OHMM) TGAS (%) (Log Track 2)

• Sonic (US/FT) DEN (G/CC) CNC (V/V) (Log Track 3)

Back up scales should be used if necessary. A tension curve, is not required.Density and resistivity logs recorded inside casing should be removed from thedisplay. (Note: the Field Log will have all log curves replaced using HQLD logsin the production of the Final Completion Log).

Draft Percentage Sample DescriptionsThe geological descriptions on the mudlog should primarily be those of thewellsite geologist. They should be compiled with the aid of "rock colourcharts", supplied by the mudlogging contractor, and by conferring with othermembers of the team. Use of the MWD information and mudlog informationshould enable the wellsite geologist to create an accurate interpreted lithologycolumn for display on the mudlog. Each cuttings sample should be describedseparately and manually on a "Wellsite Sample Description Sheet". Also, thesedescriptions should be registered electronically. The wellsite geologist shouldendeavour to enter each description into a word processor at opportunemoments. The file should contain every sample description of the well forinclusion in the Final Well Report. The descriptions should incorporate percent-age lithologies.

The individual sample descriptions are extremely important since they form theultimate point of reference for the lithology seen as the well is drilled.

Lithologies should be described clearly and fully, with minimum use of suchterms "As above". The end members of a long sequence linked by "As above"descriptions, may be completely different from each other. Each sample shouldbe listed and any shows should be thoroughly described. This file will also beincluded in the Final Well report.



CoringThe decision to core will be decided upon entering a sandstone with shows inthe prognosed Jurassic sandstones. The operational decision process is bulletedbelow and fully outlined in the drilling program.

• Resistivity close to bit (Resistivity 3m behind bit)

• Flow Check drill break on 3m

• Drill 5-8 m into top sst to identify increase in resistivity

• Low resistivity suggests water wet rock – drill on

• Increase in resistivity possible hydrocarbons (or increased cementation).

• Cut 9m core

(Use fluted aluminium inner barrel or pressure relief valves)(Use low invasion Core Head)(Use circulating sub above core barrel)

• After breaking off core circulate annulus to above BHA, activate circulating sub and circulate annulus clean of hydrocarbons

• POOH carefully (Do not jar barrel or trip at excessive speed)

• At 1000m wait on core to degas (Do not RIH with core)

• At 500m wait on core to degas. (Do not RIH with core)

• The preferred handling on the rig is to minimise handling of the core. If it is possible to decide on continued coring from the base of the core then cap the core, mark the core barrel as outlined in appendix 2, cut into 1 m lengths and ship to town..

• Where possible take digital photographs of core / core chips and send as email attachments to town.

• Minimise core handling and exposure to air.

Sidewall CoresRotary sidewall plugs (RCOR) may be required for reservoir data, petrographicanalysis, biostratigraphy and geochemistry. Sidewall coring points will beselected by the wellsite geologist in conjunction with the project geologist, afterevaluation of the electric logs. Recommended coring points should therefore be



telefaxed or emailed to the operations geologist as soon as possible. Once theRCOR points have been selected all partners should be advised ASAP.

Handling of these cores should be kept to a minimum as petrophysical measure-ments will be made on these plugs at the laboratory. On collecting of the plugfrom the tool, it should be gently wiped clean of drilling fluid and placed into acontainer. Each SWC container should then be labelled with depth, wellnumber, date and other relevant data. A brief visual description of each core canbe made by the wellsite geologist and the plug can be viewed under UV light.Under no circumstances should any fluids (water, acid etc.) be applied to theplug, nor should any part of the plug be rubbed or scratched.

Once briefly described the plugs should be securely packed in the special boxesprovided. SWCs and original descriptions should be despatched to the core lab-oratory by helicopter.

Pore Pressure AnalysisThe Wellsite Geologist will be knowledgeable and experienced in pore pressureevaluation techniques. During the well he will be in charge of monitoring thepore pressure utilising all sources of information including the FEMWD logs.He will work closely with the mudlogging data engineer to ensure that the wellis drilled in as safe a manner as possible. In the event that a pressure engineeris offshore the wellsite geologist will work with him and the mudlogging dataengineer to ensure a 24 hour quality appraisal of pore pressure is maintained.

Wellsite Geologists Final Well Report Content

• Introduction

• Stratigraphy

• Proposed Versus Actual Well Results

• Core Summary

• Hydrocarbon Indications

• Geological Samples Taken

• Core Description

• Completion Log (done offshore using Geo for Windows)

• Formation Pressure



• Report on anything related to the pore pressure of the well under construc-tion (the actual pore pressure and its deviation from what was planned, problems resulting from (unexpected) pore pressure).

• Fracture Gradient

Provide a table summary of all the casing shoe tests that have been per-formed.

• Casing Size

• Depth (TVD BRT)

• Mud Weight (ppg)

• Surface test pressure (psi)

• Equivalent mud weight (ppg)

• Type of test

Logging Witness

Job Specification

a. Key Result Area

• Provide expert advice on the drilling rig related to wireline logging, to ensure quality control of the measurements and to gather all relevant petro-physical data in such a way that the objectives outlined in the Drilling Pro-gramme are being met.

• To supervise the acquisition of borehole seismic survey information, inter-pret in-field and evaluate the obtained data to ensure quality control of measurements, and or gather all relevant geophysical data.

b. Performance Indicators

• That the wireline logging objectives are achieved and that a detailed log of logging operations is maintained.

• That the wireline logging operations are carried out in a coordinated and safe manner without any unnecessary delays.



• That the petrophysical logs are reported in a timely and professional manner.

• Attaining the highest possible standards in the acquisition of borehole seis-mic surveys through quality control.

• That borehole seismic survey operations are carried out in a co-ordinated and safe manner in an optimal time frame.

• That all data acquired for borehole seismic survey and site surveys is reported and transmitted for processing in a timely manner.

c. Responsibilities

• To ensure that all specified wireline equipment and personnel are available on the rig (and boat) with correct specification and/or certificates, to per-form the service safely and efficiently.

• To supervise all wireline logging operations and provide technical support and troubleshooting as required.

• To ensure that all relevant petrophysical data is recorded at the required quality and that RFT samples are collected as per the programme and prop-erly labelled.

• Supervise all borehole seismic survey operations, providing technical sup-port as and when required solely or in liaison with wellsite geologist(s).

• Keep a log of the operation and report any deviation from the planned activ-ities or any unplanned events without delay to the Senior Drilling Supervisor.

• To report and agree any deviations from the Wireline manual with the Oper-ations Geologist.

• To immediately report and agree any deviation from Borehole Seismic Work Instructions Manual or scope of contracted service/planned activity with Senior Drilling Supervisor and Wellsite Geologist.

• To prepare daily updates to the logging activities and analysis report. This should be passed on to the wellsite geologist for distribution to Company, Government and partners.

• Communicate observations, interpretations and suggestions to the opera-tions geologist.



• Verify the logging engineers tickets before passing onto the offshore super-visor for signing. Note on the tickets any disagreements and concerns.

d. OrganisationAccountable to: Drilling Supervisors (Operationally); Operations Geologist(Functionally and Technically)

Subordinates:None

Internal Interfaces:Drilling Supervisor, Wellsite Geologist and all members of the Drilling Team.

External Interfaces:Formation Evaluation service companies; Drilling Contractor; Other servicecompanies.

Qualification Requirements

a.Work ExperienceEssential

• 4 years petrophysical experience with a minimum of 2 years experience from the North Sea.

Desirable

• A broad experience in geology and petroleum engineering. Awareness of advances in the field of Borehole Seismic services.

• Computer/keyboard skills

b. Qualifications

• Technical education.

• Updated on technical issues related to wireline logging operations.

• Fluent in the English language.

• Leiro II part I and part II

• Knowledge of relevant Country Rules and Regulations.



c. Physical Make-upOffshore Health Certificate

d. Abilities

• Communications and team skills.

• Setting of priorities and ability to meet deadlines.

• Ability to perform under pressure.

Supervision of Mudlogging Services

GeneralThe operations geologist will meet with the mudlogging contractor and agreeon the detailed services to be provided for each job. The discussions shoulddecide on the formats of the log presentations, digital data formats, final reportcontents.

The Formation Evaluation Log (mud log) will be prepared by the mud loggingcontractor at a scale of 1:500 in meters in a format agreed. Other logs requiredare:

• Engineering Log at scale 1:1000

• Gas Ratio Log 1:2000 scale

• Pressure Evaluation Log 1:1000 scale.

The mudlogging company will supply all equipment and consumables agreedon in the scope of work of the contract. The unit will be equipped with RemoteData Management System Software and will be rig networked with 3 clientworkstations. The monitoring and analysis will cover, but not be limited to thefollowing tasks

• Total Gas Analysis

• Chromatographic Breakdown of gas (C1 - NC4)

• H2S analysis

• C02 analysis

• Drilling Parameters - Torque, RPM, PP, Flow in & Out, Temp in & out, WOB, PVT



• Calcimetry

• Cuttings analysis - microscope, chemicals, Rock Colour Chart, Grain size chart, UV light box Ditch Magnet Remote

• Data Management System Software data link

Fingerprinting is a technique requiring the establishment of a base line for aparameter e.g. gas composition. Specific arrangements relating to fingerprinting analysis will be agreed at the wellsite between the data engineers andthe offshore drilling supervisors.

ResponsibilitiesThe mudlogging geologists will work under the instructions of the wellsitegeologist. They will be responsible for the collection of all cuttings and mudsamples as outlined in the drilling programme. This includes 1 x 5 litre tin ofunwashed cuttings, 1 x 1 litre tin composite geochem sample, 1 washed anddried sample and periodic mud samples.

Mud samples will be taken on bottoms up at the end of each well section, beforecoring, before wireline logging, on entering the chalk, on entering the Jurassicreservoir and at 20 m intervals whilst drilling the Jurassic reservoir.

At the end of the well the mud logger's crew chief will bring the complete welldatabase and log plots to the contractor's field office for reproduction togetherwith the contractor's "End of Well Report". One proof copy of the report will besent to RFC, attention S.QSAPP. Also one proof copy of the CD will accom-pany the report. The CD will contain:

• PDF file of the report

• Tabular listings of all drill parameter and gas data

• Text file of the lithological descriptions

• All log plots in CGM format (EMF and PDF if CGM unavailable)

• CGM or EMF & PDF file of any time based plots featured in the end of well report.

A data listing at every 1m interval of all gas and drilling data should be outputas ASCII and LIS files onto CD. After any amendments are made the final datapackage required is; 8 CDs 1 hardcopy report with included log prints 1 extraset of paper log prints (Sepia logs may be requested if partners unable to printimage files).



Each morning the mud loggers will prepare a report covering the interval drilledand sampled, chromatography, pressure data, hydraulics and drilling breaks inthe previous 24 hours. This report, will be used by the wellsite geologist and thedrilling supervisor in the preparation of their daily reports.

A single print of the up-to-date mud log covering new footage drilled should besupplied to the wellsite geologist, for use in the morning meeting. PDF or TIFFimage files of the up-to-date mud log and other logs should also be provided fordistribution with the morning reports. If there are problems relating to the emailconnection then the up-to-date mud log will be telefaxed to RFC, partners, andNPD.

At the end of each bit run a ASCII file of drilling parameters and gas dataparameters should be downloaded to floppy and given to the wellsite geologistfor distribution to the partners. At the end of the well the mud log data disk forthe entire well will be brought in to the mud loggers field office. The mudlog-ging contractor will arrange to transcribe this data to ASCII and LIS files on CDto be included in the mud logger's "End of Well Report".

Drilling mud may have an effect on the detection of hydrocarbon shows. It istherefore important that the mud properties are closely monitored throughoutthe well. The senior mud logger must communicate closely with the mud engi-neer, obtain samples of mud constituents, and keep a time/volume record of sig-nificant quantities of materials added to the mud. Mud additives should beexamined for fluorescence and other possible hydrocarbon indications, and achromatograph profile should be obtained of all liquid additives, includingdiesel.

Before and at regular intervals during the penetration of zones of interest, themudloggers should take small reference samples of mud in the special cansprovided by the mudlogging contractor for any oil samples. These mud samplesshould be taken from the flowline, labelled with depth, time and well name,then boxed and stored with the cuttings samples ready for shipment at the endof the well.

At the end of the well, the Mudlogging contractor should be requested toprovide a text file of all the sample descriptions.

The senior mudloggers / data engineers, should compile an independentpressure analysis of the well utilising; drilling parameters Dxc trends gassestemperature cuttings shape LOTs & Direct Pressure measurements (RCI) Holeconditions (eg drag and fill on trips, )



The majority of the data provided will be depth based. However, during periodsof very slow drilling or well monitoring, time based information mayberequired, particularly if a non conformance has occurred eg a twist off, stuckpipe, a kick. Such data could be plots of torque time, or mud pit volume versustime. The mudlogging crew must be able and prepared to generate such plotsas requested during the course of the operation. Where such events haveoccurred the mudlogging crew will note the event and report it in their end ofwell report. Plots of the time based evidence should be included in the end ofwell report and on the accompanying CD.

The mudloggers will monitor the weight of metal collected from a ditch magnetand will graph it for each hole section. The metal should be collected from themagnet every100,000 drill string revolutions, weighed and plotted againstdepth. The purpose is to monitor casing wear and give early warnings ofanything untoward happening. Any large metal fragments collected should bereported to the drilling supervisor immediately.

Hydraulics calculations to be made for each BHA and hole section for the rangeof flow rates to be used.

During wireline logging formation fluid samples may be recovered by use ofthe RCI tool. If opened at the wellsite the mudlogging crew need to be preparedto collect any gas samples and perform gas chromatography on these collectedsamples.

Mudlogging crew will assist the wellsite geologist as and when required andparticularly with core catching, preparation of preserved samples and core chipdescription and analysis

During coring the mudloggers responsibilities include continual monitoring ofcoring parameter trends with feedback to drill floor to safeguard against drillingformation after core pack-off. If torque, ROP or stand pipe pressure vary sub-stantially from the baseline, the core hand, driller, wellsite geologist and coringengineer should be notified.

Coring parameters in paper form and electronic / ASCII format at wellsite to beprovided to the wellsite geologist and coring engineer after each core run. Tripmonitor information (depth of bit vs. time, instantaneous pipe speed) in elec-tronic / ASCII format to be provided to the wellsite geologist and coringengineer at wellsite immediately after each core run. A paper plot of trip per-formance should also be produced for immediate discussion with the companyman, wellsite geologist and core specialist, in case trip schedule requires mod-ification. Analysis of drill string vibration while coring when MWD tools runabove core barrel. Checking core on the drill floor for gas, (particularly H2S)



using a portable gas sniffer - when not undertaken by specialist company or rigcrew.

Formation Evaluation, Pressure, Gas Ratios and Drill Parameter LogsThe mudlogging contractor will prepare the Formation Evaluation Log at ascale of 1:500 in meters. The following items must all be routinely recorded onthe mudlog:

• Track 1: Rate of Penetration (m/hr), WOB (klb), RPM, MWD-GR (API),Date, Casing Shoe, Bit Run Number. Bit information: to include make, type, size, footage (m), time on bottom and motor, if used. Note: the detailed bit information should be placed on a bit record sheet and attached to the bottom of the log. On the log simply enter the bit run number

• Track 2: Cored Interval

• Track 3: Shows: giving fluorescence and cut ratings.

• Track 4: Measured Depth (M - BRT)

• Track 5: TVD (M - BRT)

• Track 6: Cuttings Lithology Percent

• Track 7: MWD deep resistivity (ohmm), Total Gas - avg (%), Total Gas -max (%), trip gas and connection gas annotations

• Track 8: Chromatographic analysis: C1, C2, C3, iC4, and nC4, (ppm).

• Track 9: Calcimetry results

• Track 10: Interpreted Lithology

• Track 11: Lithology Descriptions and comments. Lithology description and remarks column: to include a full lithological description and operational details such as casing, logs, surveys, cores, wireline logs run, mud data etc. Brief mud reports: every 500 m or whenever the mud properties are changed.

Tails can be added to the log to contain detailed information related tologgingruns, sidewall core descriptions, core descriptions, RCI pressure data and pointssampled, DST data



Gas Ratio Log

• Track 1: Average ROP (M/HR), GR (API)



• Track 4: Total Gas - average (%), Resistivity (ohmm)

• Track 5: Chromatographic analysis: C1, C2, C3, iC4, and nC4, (PPM).

• Track 6: Oil Character Qualifier

• Track 7: Wetness Ratio, Light to Heavy ratio Log header to contain algo-rithm used to define Oil Character Qualifier, Wetness ratio and Light to heavy ratio

Drilling Parameters Log (Engineering Log)

• Track 1: ROP (M/HR), WOB (KLBS)



• Track 4: RPM, Torque - Average (ft-lbs), Torque - Maximum (ft-lbs)

• Track 5: Flow rate (GPM), Standpipe Pressure (PSI)

• Track 6: Mud Weight in (SG), Mud Weight out (SG)

• Track 7: Total Gas - maximum (%), Total Gas average (%)

• Track 8: Remarks (Keep lithology descriptions brief)

Pressure Evaluation Log

• Track 1: WOB (KLB), ROP (m/hr), RPM, Torque (Ft-lbs), MW (SG),ECD (SG)

• Track 2: Depth (M-BRT)

• Track 3: Total Gas - average (%), Trip Gas, Connection gas, Dummy con-nection gas

• Track 4: Temp in (C), Temp Out (C), Differential temp (C)



• Track 5: Dxc

• Track 6: Pore Pressure (SG), Fracture Pressure (SG), OBG (SG)

• Track 7: Interpreted Lithology Track 8: Comments. Note particularly pit gains, LOT, drag and fill on connections, cuttings shape

ReportingThe final data package required is;

• 8 CDs

• 1 hardcopy report with included log prints

• 1 extra set of paper log prints

The report will contain the following information:

• Introduction

• Summary information

• Casing Summary

• Logging Services

• Rig Equipment

• Events by hole section

• Geological discussion

• Pressure Discussion

• Data Summaries

• Bit and Hydraulic Data

• BHA Data

• Drag Plots On / Off bottom

• Torque plots On / Off Bottom Pressure Plots



• Appendices

• Formation Evaluation Log

• Engineering Log

• Pressure Evaluation Log

• Gas Ratio Logs

• Time based plots (if required)

Note: Any issues related to geohazards such as gumbo, stuck pipe, vibrationrelated problems, inflows to the well, significant mud losses etc, should be dis-cussed in detail in the appropriate section of the report. Time based printsshould be used, if necessary, to elaborate on the incident under discussion.

Remote Data Management System SoftwareWhere Remote Data Management System Software or equivalent data manage-ment and transmission system is being used the following displays will be avail-able for selection by remote logon users;

• Drilling Display

• Mudlog setup

• Engineering Display

• Engineering log setup

• Pressure Display

• Mudlogging Pressure Evaluation Log setup

• Gas display

• Gas Log setup

• FEMWD Display-FEMWD log setup

• Vibration Display- Vibration Log Setup

• PWD Display-P W D Log setup



• Tripping Display

• Cementing Display

• Testing Display

MWD specific guidelines

Data acquisition programmeThis is schematically shown in figure 1. A full discussion regarding theFEMWD and wireline logging programme is given in the Drilling Programme.

• The 36" Hole to 170m requires a MWD DIR OD 9.5"

• The 9 7/8" Pilot hole requires a MWD/DIR/GR/EWR4 OD 8"

• The 26" / 20" hole requires a MWD DIR OD 9.5"

• The 17.5" hole require a MWD/DIR/GR/EWR4 OD 9.5"

• The 12.25" hole requires a MWD/DIR/GR/EWR4/PWD/VIB OD 9.5"

• The 8.5" hole requires a MWD/DIR/GR/EWR4/PWD/VIB OD 6.75"(A BAT tool may be added after coring.)

Whilst the tools are modular they are made up onshore and sent to the rig.Thismeans that there will be a significant amount of mobilisation and demobilisa-tion required through the course of the well. The BAT tool can be added to thebottom of the MWD assembly at the wellsite if required.

As soon as the logging engineer arrives on the rig, the geologist shall review theMWD logging program, logging parameters and MWD Specific Guidelines toensure that there is no misunderstanding about what is required.4.1.3The MWDprogram has been designed to achieve a number of objectives including holeverticality, knowledge of wellbore spatial position, OBM fluid dynamicspressure modelling, shallow gas identification, reduced vibration related prob-lems, hydrocarbon reconnaissance logging, core point picking, and geologicalcorrelation with offset wells. The geologist should use the MWD logs for cor-relation, tops picking and evidence of hydrocarbons. A primary purpose of thelogs is for the evaluation of pore pressure whilst drilling.

At the wellsite one field print will be required at the end of each run. Daily print-outs and image files will be required whist drilling.



The logging contractor's Real Time Acquisition Tape will be hand carried to theservice companies office at the end of the job by the logging engineer.

At the end of each section of the well the MWD operator should splice allFEMWD log runs together and save this to disc. The survey data should also beincluded as a separate LAS or ASCII file. Four paper prints should be made ofthis spliced log. The data disc, verification listing, log plot and image file to besent to MWD Contractor for QC. Two log prints to be sent to RFC office andone copy to be retained at the wellsite.

• At the end of the well the MWD contractor will provide to RFC:

• A composite set of FE curves from memory data, on tape or CD in LIS or DLIS format

• All the unspliced FE data (and full waveform data where applicable) for each MWD run on tape or CD in DLIS or LIS Format Verification listing of the data tape / CD.

• A complete survey listing of the entire well in LAS format

• Six paper log prints of the FE logs at 1:200 scale (separate from the report)

• One end of well report including log prints. The report is also to be provided in digital PDF format

• PDF, EMF & CGM files of all log prints (Sepia logs may be requested if partners unable to print image files)

The draft report of all MWD activity during the well should be prepared andforwarded to RFC with one week of completion of the well. All non-conform-ances must be addressed in the report.

The final report should be delivered to RFC within 6 weeks of the end of thewell. The report will contain the following:

• Description of each BHA MWD run, including bit type Performance of each MWD run and a brief description of the lithologies drilled

• Details of any problems encountered (engineering or geological) during the MWD run Section relating to the findings of the PWD data. The tool is run in the well to compare actual downhole pressures with the mud hydraulic modelling program. The tool may also highlight good and bad drilling prac-tises or supply useful information in the evaluation of an unexpected event whilst drilling or tripping. All these should be addressed.



• Time based example plots over limited periods should be generated to high-light examples being discussed in the text Section related to the vibration sensor results. Note the settings used for activation of caution and stop alarms. Note action taken through use of the information

• Tabulated listing of the survey data

• Battery Life monitoring records for each tool

• Composited MWD FE log plot Composited Depth Vibration Log plot

• Details of all splicing of MWD runs

• Details of all post well processing e.g Shear velocities from Sonic data. This section to include QC semblance plots and other QC plots.

• Section giving statistics relating to overall tool reliability.

• The compiled monthly reports calculating Mean Time Between Failure (MTBFF)should be included here. The statistics to include

• Total Operating time lost

• Total Circulating Hours

• MTBFF Highlights and Lowlights

• Section containing details of tool failures giving details of the problem, tool serial number, cause, action taken, closed out or open.



Wireline Logging ProceduresIn the event that an RFC log analyst is not at the wellsite, the wellsite geologistshall supervise all logging operations. He/she will make sure that all logheadings are complete and correct and instruct the mud engineer or mudloggerto have circulated mud samples ready for the logging engineer at the beginningof the logging job. Any difficulties experience during logging, and any anoma-lous log responses should be noted on the “Remarks” section of the log header.

On arrival at the wellsite the logging engineer and the wellsite geologist shouldgo over the mudlogs and MWD logs of the section to be logged and review theobjectives of the wireline programme. The Wireline Specific Guidelines andlogging parameters should also be reviewed to ensure that there are no misun-derstanding regarding requirements from the job.

A repeat section of at least 50 m should be recorded over a zone where logresponses show large variations, e.g. a sand/shale sequence. Additional repeatsections should be run over any intervals which show anomalous log responses.

All logs (with the exception of the NMR and resistivity logs) should be run atleast 50 m up into the casing. If no casing has been run since the previouslogging run then all logs should overlap the previous run by at least 50 m.

If a continuous temperature log is not being run in combination with the cabletension head then 3 thermometers should be run on all logging sondes, and themaximum temperature is to be recorded on the log header.

All logs must be digitally recorded on magnetic tape or CD.

Field prints of all logs are to be produced on both 1:500 and 1:200 verticalscales. Each 1:200 scale log with wall contact or centralised logging toolsshould have a cable tension curve recorded on the least crowded track. Repeatsections part to be attached to the 1:200 print. QC logs should be included aspart of the final log print.

If difficulty is experienced running logging tools to the bottom of the hole, theengineer will in any case log out from the deepest point reached bearing in mindthat the tool may stick at a shallower depth on subsequent runs.

At the wellsite four (4) sets of prints will be made of each log. One set of printswill be retained at the wellsite. Two (2) sets of prints should be packed in aseparate envelope, marked "Exploration Dept, attention Ops. Geologist", and 1set of prints are to accompany the raw data tape to Logtek, via the wireline com-panies office. (Sepia logs may be requested if partners unable to print imagefiles)



The logging contractor's Real Time Acquisition Tape and the original log willbe hand carried to town at the end of the job by the logging engineer. The tapewill also contain a full set of presentation and raw logs for the repeat section. Acopy of this tape should be sent to Logtek with a verification listing and a paperprint of the log.

All tools outlined in the logging programme for the section of the well will berequired to have a backup. The backup to the RCI for the 12.25" hole sectionwill be the FMT.

All logging tools should be accompanied by appropriate wireline cutting equip-ment, fishing tools and other attachments that may be required to aid logginge.g. a hole finder.

Pipe conveyed logging equipment should be available onshore for mobilisationat short notice, when not specified in the logging programme.

After logging all tools that are on rental should be returned to base on the firstavailable boat to minimise rental charges. Note. A GR/FMT run may berequired before coring in the 8.5" section. These tools should be left onboardwhilst drilling the 8.5" section.

Data RequirementsAt the end of each logging run the Logging Engineer will provide the witnesswith:

• A floppy disk containing the main FE curves acquired (LAS Format)

• A log print of the data acquired METAVIEW / PDS / TIFF file of log print

• Header information (Mud type, MW, Vis, BHT, Rm & RMF ifappropriate)

At the end of the job the logging engineer shall supply the witness with:

• 4 field prints

• Printout of logging diary (note the witness and logging engineer shall dis-cuss and agree on what was downtime, non productive time and operational time. Job tickets to be verified by witness and authorised by the drilling supervisor

The engineer will take the data tape to the contractors office and generateDigital data tapes or CD containing full waveform data of all display and rawlogs, including repeat section logs (LIS Format).

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Operations & Wellsite Geologist 3-1

Introduction

Electric logging services were introduced by Schlumberger in 1927. The firstresistivity log was hand plotted from point data and designed to help identify thelocation of reservoir rocks and hydrocarbon bearing formations. Since then, ofcourse, the sophistication, range and quality of logging operations has increaseddramatically but the principle aims remain largely the same.

Petrophysical logging tools are inserted into the borehole, usually at casingpoints, and the hole logged whilst retrieving the tools to the surface. Tradition-ally the tools are conveyed by wireline which also provides for tool operation anddata communication.

Typically measurements of natural radioactivity (Gamma Ray Log), formationresistivity, and porosity (Sonic Log, Neutron Porosity Log and Bulk DensityLog) are measured in the open hole section. Some radioactive tools can measurethrough casing.

Recently, high definition azimuthal tools have enabled images of the borehole tobe produced that can show bedding, dip, fractures and other geological and geo-engineering features.

Early electric logging was largely qualitative and it was not until the 1940s whenArchie (working for Shell) developed mathematical models for quantifyinghydrocarbon saturation.

Tool conveyance methods have also widened over the years. In tough conditionssuch as high borehole inclination or poor hole quality, logging tools can beconveyed by drillpipe or coiled tubing; some companies such as Reeves Wirelinehave also developed tools powered by batteries so eliminating the need for wirecables in these cases.

Since the late 1970s Measurement While Drilling (MWD) services have alsobeen developed with logging tools incorporated into the drillstring to facilitatelogging during the drilling processes. This provides valuable data for real-timegeosteering operations as well as reducing the need for traditional “wireline”type needs.

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Operations & Wellsite Geologist3-2

Figure 1: Wireline Logging Operations

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Logging ToolsThe tools, or sondes, typically contain a variety of transducer with associatedpower supplies, measurement systems, analogue-digital converters, processorsand communications electronics, encased in a stainless steel pressure casing.

The tools are supported and powered by a cable which may contain seven ormore electrical conductors. The surface equipment comprises a cable drum,motor and gearbox capable of running into and out of the hole quickly and of pro-viding a smooth, stable pulling speed during logging. The length of the cable ismeasured with a depth wheel over which the cable passes.

The tools vary in length from about 1m- 6m, with modern trends being towardsmore compact tools for ease of handling and deployment in tough logging con-ditions.

Figure 2: Logging Equipment Setup (Reeves Wireline)

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Historically many tools had to be run by themselves, thereby increasing time andcosts; today most tools are combinable and basic measurements of gamma ray,resistivity and porosity can usually be made in a single run.

For example, Schlumberger’s Platform Express service measures gamma ray,neutron porosity, bulk density, photoelectric effect (Pe), flushed zone resistivity(Rxo), mudcake thickness (Hmc), also called pad standoff, and true resistivity(Rt) derived from laterolog or induction imaging measurements in one tool 12m(38ft) long. Their previous integrated tool (the Triple Combo) came in at 27m(90ft).

Figure 3: Platform Xpress (Schlumberger)

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Reeves Wireline have Compact services with tools of 2.25” O.D. for use in slimholes and tubing conveyed applications. Their triple combo is 9m (29ft) long andthe heaviest tool weighs just 41Kg (90lbs). Many of these tools are also availableas CML tools (Compact Memory Logging) powered by a battery pack whichmeans there is no need for a wire cable when conveyed by tubing. data are storedin non-volatile memory, recorded every half second, and converted into depthlogs when recovered to the surface.

CML tools mean that data can be collected in holes that were not previouslylogged for technical or financial reasons. When conveyed with drillpipe there isno wireline, side-entry-sub or wet connect to slow the process down.

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Figure 4: Log Header

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Figure 5: Main Log

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MeasurementsTraditional open hole logging normally includes the following tools and associ-ated data.

Gamma RayThis records naturally occurring gamma radiation which originates from theradioactive isotopes of Potassium (K40), Uranium (U238) and Thorium (Th232).In sedimentary rocks these have low abundance in sandstones, siltstones and car-bonates, but generally high abundance in clays and shales.

Basic tools record total gamma ray abundance in API Gamma Ray units whichis defined as 1/200th of the difference between high and low radioactive concretein the API test borehole at the University of Houston.

The tools typically have scintillation detectors recording radioactive eventswhich are counted and recorded. Because of this, logging speeds need to be keptrelatively low in order to have enough time to make statistically valid interpreta-tions. Generally logging speeds of 1800 ft/hr are the norm with nuclear tools.

InterpretationThe gamma ray tool is used as a geological correlation tool, across multiple wellsand also between logging runs in the same borehole. As a first pass, high gammavalues are deemed to be clays and low gamma values, not clays. A sand-shale

Figure 6: Spectral Gamma Ray Log

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sequence will, therefore, have a typical response of alternating high and lowgamma ray values. Carbonates, (limestones and dolomites), will also tend tohave low gamma responses.

However, other minerals may also have higher than minimal gamma valuesmaking overall lithological determination less straightforward where the lithol-ogies are more complicated and the sands more shaly.

Orthoclase feldspar, micas, glauconite and some evaporites (sylvite, carnallite,polyhalite) all have high potassium content which could lead to misinterpreta-tion.

Uranium tends to be preserved in reducing conditions so that typical source rocks(deep water, dark coloured, organically rich clays and shales) often have signif-icantly higher gamma values than other fine grained clastic rocks.

Spectral Gamma RayThis records not only the number of gamma rays but also their energy; this in turnallows the elemental concentrations of K, U and Th to be estimated. Spectralanalysis can be very helpful in complicated lithologies such as shaly sands,arkoses, micaceous sands, and source rock identification. It can also help withclay mineral determination which can often be important in drilling operations:smectite rich clays (bentonite/montmorillonite) react with fresh water to hydrateand produce a viscous mush, (gumbo), which interferes with mud circulation,impedes hole cleaning and generally slows down the drilling process.

Shale VolumeWhilst the gamma ray log is mostly a qualitative geological correlation tool it canbe used, with others, to provide an estimate of the shale content of sandstone res-ervoirs. Shaly sands produce errors in porosity estimations from the neutronporosity log and the density tool and also reduce overall resistivity values.Hydrocarbon saturation is computed from resistivity and porosity data using theArchie formula.

If we assume that high gamma values represent shales and low gamma valuesrepresent clean quartz sands then higher than minimal values of gamma ray insands can indicate the amount of clay content, (Vcly or Vshale).

This, in turn, can be used to correct porosity values and obtain truer estimationsof formation resistivity (Rt) for saturation calculations.

Shaly sand models are normally used for saturation instead of the basic Archieformula. Commonly used formulae are the Simandoux and Indonesia models.

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Density LogsDensity logs are used to estimate porosity, establish compaction trends andidentify overpressured rocks. The photo-electric factor (Pe) can also be used tohelp identify rock types.

A gamma ray source is required to fire collimated gamma rays into the forma-tion. The source is typically chemical (Cs 137) although Schlumberger have atool which uses an accelerator. This is generally safer than a chemical sourcesince radiation is only emitted when the tool is switched on downhole. There aretypically two gamma detectors around 1.5m and 4.0m from the source.

Gamma rays interact with atomic electrons in three ways:

• Pair production

• Compton Scattering

• Photoelectric Absorption

Pair ProductionAt energy levels above 1.02 MeV the incident gamma rays produce positron-electron pairs. This is usually well above the energy of gamma rays from a

Figure 7: Density-Neutron Log

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chemical source (662 KeV), and so can be discounted in most logging opera-tions.

Compton ScatteringThis is the main interest in density logging. Incident gamma rays collide with,and are scattered by, orbital electrons, losing some of their energy in the process.The number of scattered gamma rays available for detection depends on theelectron density of the material through which they have passed. This is con-verted into bulk density for data collection and log presentation:

Photoelectric AbsorptionThis is the absorption of low energy gamma rays by atomic electrons, togetherwith spontaneous photon emission.The photo-electric cross section index, Pe,measured in barns/electron*, is a measure of the probability of this interactionoccurring and is strongly dependent on the atomic number, Z, of the nucleus ofthe target atom. Thus Pe is sensitive to rock chemistry and can be a useful lithol-ogy identifier.

Values of Pe for the common reservoir rock forming minerals are:

Quartz:1.8

Calcite:5.1

Dolomite:3.1

* 1 barn = 10-24 cm2

The presence of weighted muds can have a detrimental effect on lithology iden-tification from Pe since barite has a Pe value of 267 barns/electron which cancompletely overshadow to rock mineral values. This may be less of a problem inLWD logging operations since the invasion process will not have had as muchtime to develop.

Dual DetectorsDensity tools have dual detectors, both reading in the flushed zone, in order tomake a correction for standoff (mud cake thickness) and the effect this will haveon accurate density values.

ρe 2ZA---ρb=

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Porosity EstimationsPorosity can be estimated from bulk density values if the lithology and dominantpore fluid type are known.

Since:

then:

Neutron PorosityThe most common neutron porosity tools are based on dual spaced thermalneutron detection. Fast, high energy neutrons from a chemical source, (usuallyAmericium-Beryllium), are slowed the thermal energies by collisions withnuclei in surrounding materials. Most energy is lost in collisions with nuclei ofsimilar mass; in this case hydrogen nuclei. Since hydrogen is normally onlypresent in pore fluids the porosity can be determined from the hydrogen index.However, bound water in clay minerals can make the neutron tool a sensitiveshale indicator.

The mean distance travelled during this phase, the Slowing Down Length, is con-trolled largely by the density of hydrogen in the formation. Once at thermalenergies the neutrons are available for capture or detection in one of two helium-3 detectors. The mean distance travelled prior to capture is the Diffusion Length,the principle control on which is the Chlorine content.

Thus the ideal neutron log should be sensitive to the Slowing Down Length only.By using two detectors to measure neutron energy reduction, the ratio of near -far counts can give a reasonable porosity approximation.

Epithermal neutrons are insensitive to Diffusion Length and therefore notaffected by chlorine content. Until recently, however, poor count rates have mayrepeat ability of epithermal tools unreliable.

Neutron tools are calibrated so that they read true porosity in clean, freshwaterfilled limestones. Corrections are normally required when investigating otherlithologies and also when significant gas saturations are present.

ρb φ ρfluid( ) 1 φ–( ) ρmatrix( )+=

φρm ρb–ρm ρf–------------------=

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Sonic LogSonic logs measure velocities and waveforms of acoustic signals in the nearwellbore environment. Velocity is determined by timing a sound pulse as ittraverses a known distance through the rock.

The sound pulse is generated by one or more transmitters and the sound energypropagates a compressional wave through the borehole fluid until it encountersthe borehole wall at which point part of the incident energy is refracted into therock where it initiates compressional and shear wave particle motion. The wave-fronts travel at different speeds, compressional waves being the fastest.

Energy is radiated back into the drilling fluid as compressional energy and someof this is detected by receivers spaced along the tool. The first arriving wavebeing the compressional energy. Shear energy within the rock leaks back into theborehole as compressional energy but only if the rock shear velocity is greaterthan the fluid’s compressional velocity.

Measuring the time difference between arrivals at two receivers eliminates thecommon time spent by the signal in the borehole and enables the time spent inthe rock to be determined. This provides the interval transit time, or delta-t, (∆t).When divided by the receiver separation the log becomes an inverse velocity orslowness log. Units of slowness are microseconds per foot or per metre, (µ sec/ft or µ sec/m).

Values of µ sec/ft (compressional wave), for common reservoir rock mineralsare:

Quartz:55

Calcite:49

Dolomite:44

Porous sandstones, limestones and dolomites will have increasing travel timesfrom the matrix values. Pore fluid travel time will also affect overall values.

Seawater or salt water drilling fluids typically have µ sec/ft (compressionalwave) travel times of around 180. Sonic logs are often scaled from 40-140 µ sec/ft since sedimentary rocks will rarely have values outside these limits.

Porosity EstimationsPorosity estimations from sonic logs require information about matrix and fluidtravel times, as is the case with the density log.

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Porosity can be calculated as follows:

This works best in clean formations of moderate porosity. At high parasites wavepropagation may not be as effective and therefore porosity estimations may becompromised. Algorithms and correction charts are provided by the vendors inorder to make suitable corrections.

Resistivity LogsElectrical logs measure formation resistivity in order to determine fluid type;since the only conductive part of the rock is salty water, low formation resistivitynormally represents water filled porosity while high resistivity may indicate thepresence of hydrocarbons.

There are two basic varieties of wireline tools depending upon drilling fluid type:

Electrode (Guard) LogsThe modern version of this is the Laterolog. Current is emitted from a transmitterand prevented from travelling straight up the borehole through conductivedrilling fluid by the presence of guard electrodes at either end of the tool. Thecurrent is detected by receivers on the tool.

The distance between the transmitter and the receiver is called the spacing; thisaffects the depth of investigation and the vertical resolution. Longer spacingprovides deeper investigation but poorer resolution. Modern tools utilisemultiple transmitters and receivers in order to obtain a number of depths ofinvestigation and resolution curves.

The Dual Laterolog, for example, has a a deep (LLd) and a shallow (LLs) readingtogether with a micro-resistivity device (usually Micro-spherically focused orMSFL) to record the flushed zone resistivity.

Separation of different spacing curves usually indicates fluid invasion and there-fore, rock permeability.

Induction ToolsWhen a non-conductive drilling fluid is being used, such as fresh water or oilbased mud, then electrode type logs will not work. Induction logs have a seriesof electrical coils through which an alternating current is passed. This producesa magnetic field which induces a current to flow in the formation. This induced

φs∆t ∆tm–∆tf ∆tm–----------------------=

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current sets up a secondary magnetic field which influences the AC currentflowing around the coils.

The interference can be detected and used to compute the resistivity of the for-mation. In fact, this tool measures the conductivity of the rock which is normallyconverted to resistivity for plotting on the log.

Since the tool is measuring conductivity it may give slightly lower resistivityvalues than laterologs if there is formation heterogeneity.

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Figure 8: Dual Laterolog Tool

A2

A1M2M1A0M'1M'2A'1

A'2

Rxo pad

28ft

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Other MeasurementsOther measurements may be taken and tools run according to operationalrequirements:

CaliperCaliper logs measure the size of the borehole. Most are mechanical devices usingthe spring-loaded arms on pad sensors, (micro-resistivity; density; neutronporosity), to measure the borehole diameter in one or more azimuths.

Formation PressureThe Repeat Formation Tester (RFT) tool is able to measure formation pressureand take fluid samples from permeable zones. Using a pad, which is squeezed upto the borehole wall to remove mud hydrostatic pressure, and a probe which pen-etrates the reservoir rock flowing pressures and shut-in pressures can be recordedat multiple depths. Two fluid samples can be collected for surface evaluation.

Modern derivatives such as Schlumberger’s Modular Dynamics Tester (MDT)can be configured in a variety of operational set-ups, may use multiple probes,collect many fluid samples and using on-board resistivity and optical recognitiontechnology, identify fluid types downhole.

By taking multiple pressure readings at different vertical depths through the res-ervoir fluid pressure gradients can be established which will identify fluid typesand, at the intersection points of fluid gradients, fluid contacts.

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Imaging LogsBy taking closely spaced readings at multiple azimuths around the boreholeimaging logs can provide “pictures” of the borehole and geological features.Using density, resistivity and sonic measurements imaging logs can show dipand bedding, fractures, secondary porosity and borehole geometry features.

Figure 9: Schlumberger MDT Tool

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Whilst normally available only after drilling some LWD tools such as Schlum-berger’s ADT (Azimuthal Density Neutron Tool) service can provide usefulinformation in geosteering applications.

Figure 10: Schlumberger FMI Tool

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Figure 11: Image Log Concepts

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Figure 12: FMI Scan

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Lithology IdentificationMost of the logging tools described above can be used for lithology identifica-tion, particularly when two or, more data sets are cross-plotted. Trends, repeatedsections and curve shapes can also give indications of facies and environmentsof deposition.

Gamma RayThe Gamma Ray is initially thought of as a shale indicator. Typical reservoirrocks, sandstones, limestones and dolomites are likely to have low levels ofpotassium, thorium or uranium bearing minerals and, therefore, low overallgamma ray values. Shales and clays are likely to have high gamma ray values.API Gamma Ray units are designed to give values readings of about 100 units in“average” clays. But, of course, this depends upon the exact clay mineralogy.

Basic geological correlation can therefore be done with the Gamma Ray for com-paring sections over different wells and also between logging runs on the samewell. It is also used as a depth correlation tool for matching up different curvesand for locating shot depths for sidewall cores and for depths for pressure testsand fluid sampling with RFT/MDT tools.

Even clays and shales will have variations in gamma ray count according to theirmineralogy; illite clays (because of potassium binding the clay layers together)have high counts whereas smectites (including bentonite and montmorillonite)will have lower counts because of their water, rather than potassium, bonding.Most clays are of mixed and variable mineralogy and so will have intermediategamma ray values.

Other minerals with significant potassium content include:

• Orthoclase Feldspar• Micas• Glauconite• Evaporites (Sylvite, Polyhalite, Carnalite)

This means that arkoses, micaceous sandstones, glauconitic (green) sandstonesand certain evaporite sections may have gamma ray values well above “expectedminimums” and could cause interpretation difficulties.

Gamma Ray and Grain SizeThere is a potential correlation between gamma ray count and grain size in clasticsediments. Clay minerals (potentially rich in K40) are more likely to be associ-ated with fine sands and silts than coarser sediments because they will tend to be

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deposited in lower energy environments. Thus they will tend to have highergamma ray values than coarser sands and conglomerates.

This is nothing to do with the (quartz) grain size as such but just with the likeli-hood of associated clay minerals. If there are no clay minerals in the particularenvironment then none will be deposited and the correlation will not exist. Often,however, not only variations in gamma ray count can be seen but definite trendsof changing values can be identified.

Increasing gamma ray count upwards in a sand reservoir may indicate a finingupwards sequence; decreasing upward values may indicate a coarsening upwardssection. The former may represent a channel and the latter may represent a beachor barrier development. These trends may also be seen on density and resistivitylogs.

Photo-electric AbsorptionAs already discussed the Pe value can identify reservoir rocks when the influenceof weighted muds (the associated barite) is not great.

Density - Neutron CrossplotsBy themselves, density and neutron porosity curves are rarely definitive lithol-ogy identifiers. For non-porous, mono-mineralogical rocks such as evaporitesthe bulk density will be able to identify the lithology. Halite and Anhydrite, forexample, are readily identifiable from their very different densities if the beds arethick enough to be seen.

With porous rocks, however, it is necessary to cross-plot data in order to definethe dominant mineral. Log interpretation software can produce such cross-plotsand the vendors also supply charts to perform the task manually. Such cross-plotswork best in clean, (clay free), liquid filled formations. Gas content will dragdensities down and decrease apparent neutron porosity whilst clay will increaseporosities and effect density values according to the relative density of the clayminerals to the dominant quartz, calcite or dolomite of the reservoir rock.

Sonic LogThe sonic log is reflecting rock density so that its response is similar to the bulkdensity tool. Again, on its own only certain lithologies are identifiable but whencross-plotted with density and/or neutron porosity, dominant mineral assem-blages can be identified.

Halite at 67 µsec/ft, Anhydrite (50) and Gypsum (52) can often be identifieddirectly from the sonic but porous rocks will have a range of travel times.

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Resistivity LogThe resistivity log is primarily used for saturation determination. Howeverbehavioural trends can help identify environments and facies and absolute resis-tivity values can help identify lithologies. Tight or impermeable rocks, forexample, will have high resistivities whilst porous, water filled formations willhave low values. Again, resistivity is based used in conjunction with other curvesfor lithology investigation.

Curve GeometriesVisual examination of the curves, particularly the arrangement of the density-neutron curves, can indicate rock type.

Density-Neutron Porosity curves are plotted on the same track using compatiblescales. Since the Neutron Porosity tool is normally calibrated in LimestonePorosity Units the density log scale will have 2.70 gm/cc aligned with 0%apparent neutron porosity. This means that in clean, liquid filled limestones theapparent neutron porosity read from the log will be the correct value and thedensity and neutron curves will overlay one-another.

However in different lithologies the log porosities will need correction and thedensity and neutron curves will not overlay. In water filled, shale free sand-stones, the separation between the curves will be around 3-6 porosity units withthe density curve showing a slightly higher apparent porosity. Oil will produce areduction in density values whilst gas will also cause a reduction in apparentneutron porosity values leading to further curve separation.

Shaliness will cause the neutron curve to read high apparent porosities with aslight change in density according to the clay mineralogy in both carbonates andsandstones. The gamma ray will show higher values than clean formations.

Clay and shale beds will have high gamma ray values and large separationbetween the density-neutron curves, with the neutron reading exceptionally highapparent porosity values.

Dolomites will show a similar separation to shales but usually skewed towardshigh densities. The gamma ray will generally be low.

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Figure 13: Lithology Identification

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Figure 14: Gamma Ray & Grain Size

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Saturation DeterminationThe resistivity logs are used to identify potential hydrocarbon bearing zones aslong as the rock has porosity and permeability. Porous, water saturated, sedi-ments will tend to have low resistivities while hydrocarbon bearing formationswill have higher resistivities. To be sure it is necessary to evaluate both resistivityand porosity logs.

Water Saturated ZonesWhen the rock is 100% water saturated, (Sw = 1), its resistivity is known as Ro.The true formation resistivity is called Rt and is estimated from the deep readingresistivity tool.

When Sw = 1, Ro = Rt

HydrocarbonsWhen the rock contains hydrocarbons Rt increases according to hydrocarbon sat-uration and porosity. Ro remains the same; that is, the theoretical resistivity ofthe rock when 100% saturated with water, (of resistivity Rw), is Ro.

In the early days of logging this is about as far as it got. Quantitative analysiscame along in the 1940s from Mr. Archie.

Archie FormulaArchie, working for Shell, developed the basic algorithms to estimate hydrocar-bon saturation from resistivity and porosity.

Where:

Sw=Water Saturation

Ro=Formation Resistivity at Sw = 1

Rt=True Formation Resistivity

n=Saturation Exponent

Rt Ro≠

Sw RoRt-------n=

Wireline Logging


The saturation exponent, n, is an empiracally dervived variable. For Quick-LookInterpretation, n is normally 2.

Since Ro is not measured when hydrocarbons are present it needs to be deter-mined independently.

Ro DeterminationWhen a rock is saturated with water of resistivity Rw, the ratio of the wateroverall rock resistivity to the water resistivity is constant, providing the porosityremains the same:

Therefore:

Where:

F=Formation Resistivity Factor

The Formation Resistivity Factor, F, relates to the porosity. Changing the type ofwater filling the pores does not change the overall Ro/Rw ratio providing theporosity stays the same.

Archie determined a relationship for F and the porosity (φ) as follows:

Where:

a=Tortuosity Index

m=Cementation Factor

Values of a and m vary with lithology. Median values of a are around 1 andmedian values of m are around 2. Sandstones generally cause reductions in a andcarbonates cause significant increases in m. Values of a, m and n are computedfrom core analysis, offset data and other reservoir studies. If no information is

F RoRw--------=

Ro FxRw=

F aφm------=

Wireline Logging


available, a default relationship can be used though this is only an approxima-tion.

Substituting for Ro, the working version of Archie’s formula for Sw becomes:

F 1φ2-----=

Sw F Rw×Rt

-----------------=

Sw a Rw×

φm Rt×------------------n=

Wireline Logging


Coring


IntroductionCoring provides information about reservoir conditions and hydrocarbonreserves that may not be available during routine drilling or logging operations.Detailed porosity, permeability and hydrocarbon saturation measurements arepossible from conventional cores since the samples are large enough to showmost of the controlling features, apart perhaps, from macro or fracture porosity.

Of secondary importance is other geological information such as detailed sedi-mentary and lithological evaluation, micro palaeontological work and the oppor-tunity for uncontaminated geochemistry analysis.

Two main type of coring are available:

• Conventional CoringPerformed at the time of drilling Provides macro samples for complete reservoir evaluation

• Sidewall CoringPerformed after drilling using wireline technologyProvides small samples for lithological and palaeontological evaluation

Conventional CoringConventional coring is the most basic operation and has been routinely done invertical wells for many years. Core is collected in a steel tube or barrel usuallyeither 30ft, 60ft or 90ft long, giving sample diameters of between 2 inches and 5inches. For slimhole operations cores of 1.75 inches diameter may be obtained.

Conventional cores are normally cut to provide basic rock mechanics and reser-voir information from formations that are easily sampled and not prone tocollapse or desegregation. Where more detailed information is required, or whenthe formation may not be adequately recovered, specialised coring systems suchas containerisation may be employed.

Conventional coring is time consuming, and therefore expensive. It involves atleast two round trips, changing of the BHA and slower drilling rates are achievedover the cored interval. Only those formations of special interest are cored, andeven then conventional coring is usually limited to the primary and secondaryreservoir targets in most operations.

Coring


Because of the expense and the importance of the information required coringoperations are carried out with great care and usually with the assistance of spe-cialised personnel and equipment.

Core Point SelectionThe intervals chosen to be cored are determined far in advance of the drillingoperations and will normally be the primary and/or secondary targets of the well.Occasionally, when drilling in new fields or areas coring points may be estab-lished and substantially modified as a result of the drilling progress or loggingoperations.

Usually specific formations will need to be cored rather than merely drilling toparticular depths and so the coring points will normally be specified by the onsetof a formation top, and becomes a matter of detailed stratigraphic correlation.

Coring


Figure 1: Coring Decision Part 1

CORING DECISION SUMMARY

WELL NAME 05/28/2002 GEOLOGIST M. ButlerDATE 12/16/2001 TIME START/ FIN 3:25

DRILLING DATA

DEPTH DRILL BREAK 8548/-8465 CURRENT DEPTH 8560/-8477(mddbrt/ mtvdss) (mddbrt/ mtvdss)LENGTH OF BREAK 12ftROP Pre-break (ft/hr) 25 - 35 ROP during break (ft/hr) 66 - 105Torque Pre-break (klbs) 6 - 8 Torque during break (klbs) 8 - 9Mud weight in (ppg) 11.3 Mud weight out (ppg) 11.3ECD (ppg) 11.6 Estimated O/B ppg 8.7Pit gain (bbl) None Controlled drilling? Yes - using WOBEst pore pres Pre-break 8.7 Est pore pres during break 8.7

GEOLOGY

Lithology after circulating 40% Sandstonebottoms up 60% SiltstoneVisible porosityNature of cuttings, e.g. Sandstone: generally loose, locally well cementedangular, loose grains, size, Siltstone: normal subblockyshape

Coring


Offset DataFormation tops have been provisionally determined by the project geologistsusing seismic, wireline, MWD and wellsite geological data form previouslydrilled wells if such information is available. Mud logs, lithology logs, drillingexponents, Gamma Ray logs and Sonic logs provide the best information fordetailed correlation.

Figure 2: Coring Decision Part 2

SHOW DESCRIPTION

FLUIDS

Oil/ condensate Fluorescencestain Light brown colour moderate yellowbleed % of sample 100colour intensity (weak, etc.) Moderatewax cut fluor colour Blue whitelive cut speed slow to moderatecut colour and stain crush cut fluor colour Blue whitecrush cut speed solvent used Isopropanolcrush cut colour and stain

GAS

Pre-break From breakTotal gas 0.35 Total gas (0.35 b'grnd) 1.35 peakC1 1355 C1 4314C2 157 C2 649C3 136 C3 975iC4 28 iC4 108nC4 41 nC4 421C5 N/A C5 N/AH2S 0 H2S 0CO2 N/A CO2 N/A

Coring


During DrillingAs the well progresses, the mud loggers and wellsite geologists need to performcontinued analysis to ensure that the core point is reached without drilling to farinto the reservoir and perhaps missing vital information form the top of thesequence. Sometimes coring will begin on drilling into the potential reservoir. Atother times the cap rock or seal and its contact to the reservoir needs to be eval-uated which involves even more detailed study, and substantial local knowledge.

Cuttings lithology evaluation, MWD analysis and wireline log correlationprovide the basic wellsite evaluation tools, in conjunction with similar offsetdata. As the reservoir is approached, ROP (rate of penetration) becomes thesingle most important tool since this will usually indicate drilling through the capinto the reservoir section. The importance of ROP is that it provides instantane-ous information about rock strength and drillability when minutes or evenseconds can be important.

For example, if the ROP increases from 15m/hr to 30m/hr, 0.5 metres will bedrilled every minute. If this drilling break is not picked up for two or threeminutes a substantial part of the top of the reservoir may not be cored.

Confirmation of the core pointThe decision to stop drilling and take the core is critical and can lead to delay andexpense if the wrong decisions are made. The well prognosis should give clearindications of the exact procedures to be followed as the core point approaches.Specifically the exact criteria for coring needs to be clearly documented to avoidconfusion and costly mistakes. This may take a number of forms, for example:

• Begin coring when the “X” formation is drilled into

• Begin coring at “X” metres TVD (True Vertical Depth)

• Begin coring in the top of the “X” formation providing the lithology is sandstone

• Begin coring in the top of the “X” formation providing there are positive hydrocarbon shows and suitable gas

ratio analysis

Selection of the core point from hydrocarbon show evaluation and lithologicalconfirmation obviously requires the sample from the drilling break to be circu-lated to surface which is time consuming, but necessary to avoid error. It mayalso be necessary to drill a few metres of the new formation to establish beyonddoubt that it is the reservoir section and not just a small stringer above the mainzone.

Coring


When all the criteria are met coring can begin. The actual decisions are normallymade by operations personnel in the oil company office following discussionwith wellsite geologists and supervisors. In the event of poor communicationsbetween the wellsite and office then the onus will fall on the wellsite staff tomake the decisions. In this case it is vital to clarify oil and gas show characteris-tics in terms of fluorescence and cut tests, gas ratio analysis and evaluation ofdrilling parameters such as ROP in order that the correct decisions can be madeand substantiated.

Coring ProceduresThe basic coring procedures, equipment and requirements will have beendecided long beforehand and should be available at the wellsite in the drillingand formation evaluation prognosis. However local conditions may require mod-ification to the original plans and these should be discussed as appropriate but

Figure 3: Core Handling

Coring


with due regard to allowing enough time for replacement equipment or suppliesto be shipped to the wellsite if required. Specifically:

• All items of rig and coring equipment should be available and checked

• Drilling fluid properties should be optimised

• The borehole should be cleaned and stabilised before coring

• Geological information should be updated such as:Hardness and abrasiveness of the formationConsolidationFracturesHole and formation pressure problems

Coring EquipmentThe core barrel and associated equipment is normally provided by a specialisedcoring contractor who will also provide experienced personnel to help set up andrun the equipment and assist the driller in cutting the core. A standard core barrelconfiguration will comprise the following:

Core BarrelConventional Core Barrels consist of two main parts and can provide cores from1.75 - 5.25 inches in diameter. Outer and inner core barrels are connectedtogether to provide different length cores to be cut as required.

Outer BarrelLarge diameter outer tubes provide stiffness and protection for the core. Stabilis-ers can be attached if required. The outer tube allows drilling fluid to be circu-lated with the risk of washing away the core and also allows the drillstring to berotated, again without disturbing the core.

Inner BarrelSteel inner barrels are manufactured to very strict tolerances and are thoroughlychecked at the wellsite to ensure that there are no restrictions or her impediments.All the core is collected in the inner barrel which is removed from the outersleeve for core recovery.

Swivel

Coring


The swivel assembly allows rotation of the drillstring without disturbing thecore.

Safety JointAll core barrels are equipped with a safety joint to allow recovery of the innercore barrel and core should the outer core barrel become stuck. It also allows thebarrel to be prepared more quickly for the next run and reduces maintenancecosts.

Figure 4: Core Barrel

Coring


Pressure Relief PlugThis is necessary to:

• Circulate out inner barrel fill following running into the hole

• Enable circulation through the inner barrel when large amounts of fill are encountered.

Once the barrel is clean a drop-ball is run to prevent circulation through the innerbarrel during coring. Drilling fluid is vented via the drop-ball valve when coreenters the inner barrel.

Core HeadsThe core is cut by using a regular drilling bit equipped with a large diameter holethrough the centre to allow the core to pass into the inner core barrel.

Whilst roller cone bits are use it is more common to use a diamond headed, fixedcutter bit to cut the core. Diamond bits give a smoother driller response and gen-erally lead to better core recovery. Natural diamond bits are now being replacedby PDC bits which provide faster coring times without sacrificing recovery.

Core CatcherThe core catcher is located between the core head and the inner core barrel. Itspurpose is to prevent the core slipping out of the inner barrel after it has been cut.The core catcher consists of tungsten carbide slips and spring loaded dogs toensure positive containment of the core. Variations can be made to cope withunconsolidated formations or when containerised sleeves are used.

Containerised CoringOver the last few years most operators have utilised containerised coring toenhance their coring operations. Containerising developed to help ensuremaximum recovery of unconsolidated formations but has developed to includemost operations. The process provides additional benefits such as:

• Reduced coefficient of friction between core and inner barrel

• Decreased exposure of core to the atmosphere

• Reduction of induced fracturing of the core

• Increased core security

Coring


• The containerised core can be cut to length and shipped directly for analysis

Figure 5: Core Bit

Coring


Aluminium Inner TubesThe aluminium inner tube replaces the existing steel inner barrel. Useful in hightemperature applications the tubes come in lengths of 30ft and can be connectedtogether to provide 120ft of core. The filled tube can be cut to length, capped andshipped.

Fibreglass Inner TubesFibreglass tubes also come in 30ft connectable lengths to contain difficultsamples. They are not suitable for high temperature applications of more than250° F.

Figure 6: Core Catcher

Coring


Plastic LinersPlastic liners ensure recovery of soft, friable and unconsolidated formations, andcan recover up to 60ft at a time. They are unsuitable for temperatures above 140° F.

Coring ProceduresCareful attention to detail and operational parameters is required in order toensure a successful coring operation. Drilling should proceed relatively slowlyand evenly with slightly reduced WOB and Pump Pressure.

Figure 7: Containerised Core Sleeves

Coring


JunkOn the last bit run prior to coring a junk sub should be run in order to collectsmall bits and pieces from the borehole. Junk in the hole will cause damage tothe core head and reduce the chances of cutting and recovering a complete core.

Core Head SelectionThis is made with reference to the formation strength and abrasiveness and to thebottom hole pattern established by the previous bit run

BHA DesignSufficient drill collars are required to produced the necessary WOB as withroutine drilling., together with adequate stabilization.

CirculationCirculation rates need to be enough to clean the hole of cuttings but not too highto lift the core head off bottom and restrict drilling. With PDC core heads thislimit of Hydraulic Horsepower per square inch will be enforced anyway. Toohigh circulation rates may also tend to wash away the core as it enters the innerbarrel area. This can be minimised by reducing flow rates and using modern low-invasion core heads.

Lost Circulation Material (LCM)Lost Circulation Material can be used with caution in most coring operations butis not recommended.

Other Drilling ParametersOther parameters such as WOB, RPM and Torque will be established accordingto the equipment configuration and the nature of the formation. Rememberthough, that the primary objective is t cut ad recover the desired interval of core.

WOB is normally kept low until the core head has established a bottom holepattern and the first stabiliser has entered the new hole. It is then increased untiloptimum performance is reached.

Preparation for CoringWith the bit off bottom mud is circulated through the tool to ensure that there areno restrictions to flow or that fill has not entered the barrel. Once this has beenestablished and the hole has been circulated for 15 minutes or so the pressurerelief ball can be dropped. When the ball has seated a note is made of the off-bottom pump pressure.

Coring


Cutting the CoreDrilling proceeds in controlled manner with WOB and Pump pressure being reg-ulated to achieve optimum performance. Sudden changes to any of the coringparameters could damage the core head or the core itself.

The mud logging crew will continue to collect cuttings samples during thecutting of the core as back up information should recovery be incomplete. Thequality of these samples is much reduced however since circulation rates arelower, reducing effective hole cleaning and only an annulus around the core headis providing fresh cuttings material. There is though, still the same volume ofcavings recycled material and LCM as during normal drilling so that the amountof effective debris is increased.

Coring continues until the core barrel is full or becomes jammed. Careful moni-toring of depth and ROP should indicate when the barrel is becoming full as ROPwill decrease sharply at this stage. The core head should be allowed to drill offthe WOB to ensure a clean cut at the end of the core.

Core RecoveryThe type of core being cut will determine the exact handling and recovery pro-cedures that will be followed, along with operator requirements. Most conven-tional cores are recovered on the rig floor by removing the entire inner core barreland allowing the core to slide out to be collected in 1m (3ft) core boxes. Wirelineretrievable slim-hole cores are also handled in this manner. Containerised core isremoved from the outer barrel, cut to length, capped and shipped to town withlittle or no rig site processing.

Conventional Core recoveryIt is the responsibility of the wellsite geologist to ensure that the core is recov-ered, processed and evaluated according the operator requirements. In mostcases they will recover the core with the assistance of mudlogging personnel.prior to the coring operation it is necessary to ensure that sufficient stocks of con-sumables such as wooden core boxes, marker pens, rags, wrapping and packag-ing materials are available for the total amount of core that is to be cut.

During the cutting of the core the mudloggers will have gathered all the abovematerial together and labelled the required number of catching boxes with corenumber, box number and top and bottom markings.

The core barrel is retrieved to the surface and the inner barrel removed. Thedriller holds the inner barrel on the elevators and the core catcher removed. Thecore tongs are attached by the core hand and the inner barrel is slowly raisedwhilst the tongs are relaxed. this allows the barrel to slide over the core andexpose it on the rig floor. Once 1m (3ft) of core has been exposed it must bebroken off in order to fit into the recovery boxes.

Coring


Often the core will emerge broken pieces which need to be monitored to ensuretheir correct orientation when placed in the boxes.

CautionIt is important to remember not to reach underneath the core barrel whenbreaking or collecting the core as any uncontrolled slippage could cause seriousdamage.

Recovery of the core should proceed at a rate comfortable for the wellsite geol-ogist or mudlogger catching the samples. Each broken piece should be correctlyoriented prior to placement in the box and rubble should be collected and pacedin its appropriate place. The very bottom of the core is normally placed in thebottom of box #1, and the last piece of core will be at the top of box #?

Figure 8: Inner Core Barrel Removal

Coring


It should be remembered that the very bottom piece of core may still be attachedto the core catcher if it was jammed in. This is potentially the most importantpiece at the moment since the next rig operation may be dependent on what thebottom section represents. If it is still reservoir lithology with oil shows adecision to continue coring may be made, Alternatively if it is shale or reservoirrock without oil shows normal drilling may be resumed.

Processing the CoreConventional cores need to be cleaned, measured, described and evaluated for oiland gas shows, wrapped, re-boxed and shipped from the rig. All of this work isthe responsibility of the wellsite geologist and has to be performed in a speedyand accurate manner. With long coring runs using 90ft or 120 ft barrels thecomplete processing of one core can take many hours by which time the nextcore may be arriving at the rig floor.

The core needs to be worked on in a well lit, dry area with plenty of space toallow the core to be removed from its catching boxes, laid out and repackaged.The core should never be washed to avoid damaging its saturation and other res-ervoir characteristics, but should be wiped clean with rags to remove the mud andallow its lithological and sedimentary features to be described.

Prior to description the core should be accurately measured and some attemptmade to fit broken pieces together. Orientation marks, normally made byscribing red and black lines along the length of the core need to be mace very

Figure 9: Conventional Core Extraction

Coring


quickly so that each core piece can be oriented following removal from theoriginal catching boxes.

An accurate measurement is required to determine the amount of core recoveryand to correlate the core with depth. At this stage any missing core is deemed tohave been lost by falling out of the bottom of the barrel during recovery and alldepth measurements proceed from the top of the core. Detailed core analysis mayreveal a different story but this is not applicable at the wellsite.

Before wrapping, the core should be fully described and particular attention paidto larger scale sedimentary features that are not always apparent in drill cuttings.Samples should be taken at the regular sampling interval and extra sampleswhere oil shows are apparent. These should be processed in the normal mannerin the logging unit.

Other larger samples may need to be removed from the main body of the coreand shipped separately for other processing such as core analysis, or geochemis-try. The bulk of the core is wrapped in a variety of media in order to seal andprotect it before being placed in clean boxes for shipment. Aluminium foil, Saranwrap, polythene tubing and wax are all used for this process.

Figure 10: Core catching Boxes

Coring


Once packed for shipment, complete details should be recorded and packing listskept, plus details of shipping procedures. All this information should also becommunicated to the local operations office prior to shipment.

Other Specialised Applications

High Angle and Horizontal CoringSpecially designed core barrels are available for drilling high angle and horizon-tal wells. They provide extra stabilization and bearing adjustment to ensureoptimum performance. They can also include integral EMS surveying systemsfor accurate orientation when using a 3-knife scribing system.

Oriented Coring gathers comprehensive and reliable information on fracturedirection, the dip and strike of beds, and the direction of stresses. When a core isoriented, hole azimuth and inclination are recorded along with the directionalorientation of a reference mark on the core itself. Simple equipment and proce-

Figure 11: Core Marking

Coring


dures make this service economical and versatile with both conventional andadvanced technology coring systems.

The core barrels are usually driven by a Mach 1 Positive Displacement Motorsystem and incorporates a dropball sub that can be run after circulation to removefill.

Pressurised Core BarrelPressurised Core Barrels can be run to maintain bottom hole conditions andprovide more accurate saturation and mechanical property data. These systemsmay use a non-invading gel to maintain core sample quality while preventing gasexpansion and fluid loss.

At surface the inner tubes are frozen for transportation using dry ice to immobi-lise fluids and gases while retaining bottom hole pressure.

Reduced Fluid InvasionThe key to preventing drilling fluid from invading high permeability core is toprotect the filter cake that builds up around the core during the coring process. Ifthis can remain undisturbed than further flushing is prevented.

Special core heads allow the core to move immediately into the inner barrel byremoving internal cutters and gauge protection, and by ensuring that jet nozzlespoint away from the incoming core.

Gel CoringGel coring provides a means of protecting the core from the invasive drillingfluid by encapsulating it with a polypropylene glycol compound, and alsoprotects the core during handling, processing and transportation. The gel is pre-loaded into the core barrel before delivery and isolated from the drilling fluidduring the trip into the hole. It is displaced by the core which forces it around theinner barrel annulus as the core is cut. Any gel that does not adhere to the core isejected to the annulus and displaced by the drilling fluid.

Coring


Full Closure Core BarrelsWhen the reservoir rock is poorly cemented or unconsolidated additionalmeasures must be taken to ensure that the core is not lost through the corecatcher. Rather than the finger type catcher, such rocks need a full closurecatcher in order to retain the material.

Figure 12: Gel Coring

Coring


Wellsite Core EvaluationSome companies provide wellsite core evaluation equipment in order t o trans-portation costs in remote locations. Core cutting, slabbing, plugging and preser-vation equipment is available together with gamma ray, UV-light photography,porosity and permeability measurements.

Sidewall CoresSidewall cores, or CSTs (Core Sample Taker), provide a means of sampling theformation when a conventional core was not taken during routine drilling. Thegun, which can hold up to 30 bullets, is conveyed into the hole by wireline. Eachbullet can be individually fired at a specific depth in order to obtain a samplefrom a specific geological horizon. Depths are chosen by surface correlation anda Gamma Ray tool is run for confirmation.

The bullets are attached to the gun by wire fasteners and fired by an electricallytriggered explosive charge. The bullet is pulled from the formation as the tool israised together with its core plug; it is held by the wire fasteners as the tool ispulled to the surface. Different length fasteners are available to allow for varia-

Figure 13: Full closure core barrel

Coring


tions in hole size and there are different explosive charges and bullet designswhich are also Operator choosable.

The main purpose of sidewall cores is to obtain geological samples from a knownand specific geological horizon for lithological and bio-stratigraphical confirma-tion.

Since the core is obtained by impact it can damage weak reservoir rocks andrender estimations of porosity, permeability and saturation less than accurate.

The Wireline Logging personnel set up the tool and retrieve the core samples atthe end of the run. The samples are normally placed in small glass bottles withan identification label and passed to the Wellsite Geologist for examination anddispatch. The Wellsite Geologist is normally required to make brief sampledescriptions, including oil show evaluations before the samples are shipped fromthe rig.

Coring


Figure 14: Sidewall Coring Gun

Coring


Rotary Sidewall CoringSmall core plugs can be obtained by rotary sidewall coring operations in order toobtain samples after drilling or in the event of problems with conventionalcoring. Samples are less damaged than those from wireline CSTs and are suitablefor reservoir characterisation as well as lithology studies.

Figure 15: Sidewall Core recovery

Coring


Figure 16: Rotary Sidewall Core

Coring


Drilling ConsiderationsThe purpose of coring is to acquire a representative sample of the formationbeing cored. Alteration of the rock properties and fluids contained within the for-mation should be avoided as far as is possible if representative measurementsand information is to be gleaned from the core. Any coring operation shouldapproach fastest possible coring at highest possible recovery. Prior to coringmake sure to clean and ream the hole properly when POOH prior to start coring.Core with minimum overbalance. Consider high torque motor if string torque/offbottom torque is high. The degree of drilling fluid invasion during coring will ingeneral be influenced by:-

• Mud overbalance

• Compressibility of pore fluids

• Time of exposure

• Drilling fluid filter loss control properties

• (Relative) permeability of the rock.

Mud invasion can be minimised by increased coring rate, reduced filtration area,increased bridging solids in the drilling fluid and reduced contact time with thegauge cutters (Rathmell et al. (1990)). The low invasion coring system suggestedby Tibbits et al. (1990) combines application of specialised equipment (speciallydesigned core head, inner tube pilot shoe) with proper coring parameters and alow spurt loss fluid. Eaton et al. (1991) define low invasion technology as a com-bination of advanced core bit technology and modified coring techniques toproduce cores with no drilling fluid filtrate invasion over two-thirds of the core’scross section. Minimisation of core invasion is achieved by (Eaton et al. (1991)):

• Reducing the number of cutters over the entire bit

• Using a parabolic bit design

• Using a low fluid loss drilling fluid

• Reducing the number of gage cutters

• Eliminating all throat diamonds

Low invasion core heads should be preferred to other core heads. Also considerthe use of Gel to limit invasion of the core. Alteration of the core is not restricted

Coring


to the downhole coring process, but also to retrieving the core, (e.g. trippingspeed), laying down the core and processing the core for transport to the lab.

Jamming off It is quite common for cores to 'jam off' before the core barrel is full, especiallyin hard, fractured, formations. In friable, porous or fractured formations it maynot affect the R.O.P, and the only sign of jamming may be a slight increase intorque. In medium to hard formations ROP and torque may decrease. If jam-offof the core is suspected, it is recommended that coring should cease and that thecore is recovered before continuing the coring program. This will minimise thepossibility of a gap in the cored sequence in softer formations, and reduce thepotential for damage to the core already in the barrel. A possible exception is inthe event that no further cores are planned for the interval. In this circumstancethere may be benefits in attempting to restart the core, since there exists theopportunity of recovering core which would not otherwise be cut. Jamming offcan also occur due to the inability of the heave compensation systems of semisubs and drillships to adequately compensate during rough weather. In such cir-cumstances conditions may be fit for drilling but not for coring. Serious consid-erations should be given to telescopic core systems when coring from floatingplatforms.

Pulling Out When a core is brought up to the surface, pressure and temperature conditionsare altered considerably. This can cause:

• Elastic/anelastic expansion of the rock matrix, causing cracks or fissures

• Expansion of fluids with high compressibility and dissolution of gas.

• Matrix expansion and capillary suction in rocks with low compressibility fluids

This may lead to:

• Changes in pore geometry, porosity and permeability

• Wettability alterations

• Dissolution of gas and capillary effects Loss of interstitial water

• Salt precipitation

• Damage to clay fabric

• Continued filtrate invasion.

Coring


Pulling out of the hole with a core barrel should be accomplished as quickly aspossible, however it is important that the driller and rig crew take more thannormal care to ensure that jolts and jarring of the drillstring are avoided. Soft,friable cores and long, heavy cores in hard, dense formations are particularly sus-ceptible to damage or loss by careless tripping.

Expanding pore fluids that are unable to escape from the core during trip-out mayinduce whole core dilation, and/or axial vertical fracturing. This damage mech-anism is most common in poorly consolidated sediments containing viscouscrude, or core that has suffered a high degree of mud filtrate invasion. Fieldstudies have indicated that reducing the trip-out rate yields core of improvedquality, while laboratory studies have shown that the majority of core dilationoccurs over the latter stages of the trip. Therefore, reducing the trip rate as thecore nears the surface is likely to minimise core dilation and yield core ofimproved quality.

Fragile core material can be prone to structural damage resulting from gas expan-sion during retrieval. During trip-out, if pore fluid retention causes pore pressureto exceed surrounding mud pressure such that the tensile strength of the core isovercome, then disaggregation or expansion of the core will occur. This type ofdamage can often be identified if ‘overgauge’ core is recovered.

Reducing the core retrieval speed over the latter stages of the trip can yield coreof improved structural quality. Rapid tripping also increases the gas drive effecton core fluid saturation, and this may reduce the accuracy of the oil saturationresults.

Pressure depletion and temperature reduction during core surfacing also affordopportunities for wettability alteration, controlled tripping may help reduce thiseffect. If non-hydrocarbon bearing dense zones only is cored, then the core maybe tripped at near the normal controlled rate 1-1.5 minutes/stand’ for thecomplete trip.

In deep / high pressure wells, or areas where hydrogen sulphide gas is a knownhazard, it may be considered advisable to stop pulling out 500m below rotary.The core is then allowed to 'de-pressurise' for a period of time, depending on itssize, porosity and permeability. About 30mins is usual. However, in most casesthe core will have ample time to de-gas on its way out of the hole. RFC policyrequires the following tripping speeds:

• Normal tripping to 900 m

• 900 m to 450 m : 3 minutes per stand

• 450 m to surface : 6 minutes per stand

Coring


Security DBS recommended the following tripping speeds:

• Reducing POOH rate speed last 350 m

• Up to 350m: 1,0 min per stand

• 350-100m : 2,5 min per stand

• 100-surface ; 5,0 min per stand

Use the drilling brake and the slips GENTLY when POOH to prevent corecollapse or lost core.

Circulating Bottoms Up In contrast to most other drilling situations, circulating bottoms up after coringshould be avoided. The usual procedure after terminating a core run is to pull onestand off bottom, check for flow, and then pullout. Circulating carries with it therisk of sucking the core from the barrel. However, it is recognised that unfore-seen, unstable well conditions may necessitate circulation, and because of thispossibility it is recommended that a circulating sub is run above the core barrelto allow circulation if required.

HTHP Wells In HTHP wells the expansion of gas in the core as it is pulled to the surface cancreate a potentially dangerous situation. Documented cases have demonstratedthat the pressure of gas trapped in a core barrel or sleeve at surface can be suffi-cient to eject the core, and propel it across the width of a rig pipe deck with con-siderable force. To reduce the risk of this happening, core inner barrels are nowavailable with pressure relief valves at intervals along the length of the barrel,and these should be used whenever possible in HTHP situations. Fluted innerbarrels are also a solution to this issue. Alternatively pressure relief holes may bedrilled in the barrel after recovery, but this operation will present its own hazardswhich must be addressed at the wellsite. Sensible precautions should be takenwith regard to the area used to lay down the barrel, and the presence of anyunnecessary personnel. Personnel should be briefed on the potential hazards, andshould avoid placing themselves in the danger zones around the open ends of thebarrel. In some situations the option of freezing the core in its sleeve may beavailable. This is achieved using dry ice, before cutting the core into 1metrelengths.

Core Handling On Rig FloorThe aim is to remove the core inner barrel and core in 9m lengths from drill floorto processing area without core damage, and in minimum time to minimise cost.

Coring


Core laydown is not a routine activity. The core hand will lead a briefing and dis-cussion with the rig crew involved to ensure that safe and effective proceduresare used before beginning core laydown. Company drilling representative,wellsite geologist, corehand and core specialist and other key personnel shouldalso be present to highlight importance of safe effective core handling, and topromote good teamwork.

The core barrel will be checked for gas at surface before breakdown. Gentle corehandling is essential - the rig crew input to a safe and successful coring operationis critical at this point The inner barrels must be separated on the rig floor. Therig floor breakdown of the core barrel, laydown of the core inner barrel, andbreaking of the catcher will be led by the corehand. Any misalignment of theinner tube during inner tube separation and application of shearboot may resultin dropping the core on the drill floor. This activity must be conducted with greatcare.

When breaking the cores into 9m lengths a hydraulic cutting device or shear plateassembly should be used to prevent damage to the core. It has been shown byvisual and X-ray CT examination that the use of a hammer damages core up to 1m from the joint. After removal from the core barrel, the inner barrel must betransferred to the processing area, which provides a safe environment for the coreprocessing team, and minimises disruption to drilling operations. This must bedone without allowing the inner barrel to bend. Core cradles (or core sock) areused for this purpose.

Note: when a "CORE SOCK" is employed attention MUST be given to prevent-ing movement of the core within the core sock. An unsecured core can sufferdamage during movement from the rig floor to the designated core processingarea.

The core cradle is suspended vertically in the derrick alongside the 9m innerbarrel section and is secured to the inner barrel with straps. When the inner barrelis secured in the cradle, the tugger line is connected to the top of the cradle andthe air-hoist line removed from the inner barrel pick-up sub. Normal precautionsfor heavy lifting must be followed - particular care is required if rough weatherresults insubstantial rig movement. Various techniques are suitable for the suc-cessful laydown of core cradles. The rig crane may be used to directly transferthe cradle / inner barrel from the drill floor to the core processing area, or thecradle can be lowered gently down the pipe skid and onto the catwalk, and thentransferred by crane.

Awareness Of Gas In The CoreThere is likely to be a constant bleed of mud and gas from the core. Prior topulling the coring BHA above the BOP the moonpool area should be cleared and

Coring


access to the rig floor restricted to essential personnel only. Be aware of the pre-vailing wind direction and be particularly cautious in calm still conditions.

The rig crew must be made aware of the potential H2S presence in the reservoirand hence the core. Checks for H2S by a qualified person wearing breathingapparatus using a suitable H2S detector must be made during core retrieval andwhen each drill collar connection is broken.

If H2S is detected at this time consideration should be given to running the corebarrel back into the hole to below the BOP. Circulation can then be commencedto help dissipate the gas.-It will be necessary, under these circumstances for allpersonnel on the rig floor and those involved in core handling to don breathingapparatus while the inner core barrels are laid out and until declared safe by thequalified person using the detector.

When the last drill collar is broken off the core barrel, heavy gas maybe released.

The core will be laid out in 30 ft lengths using the inner core barrel handlingcradle. When separating the inner tubes, check for indications of confined pres-sure. If connections bubble with gas, cease backing out the connection until thebubbling has diminished. The upper shoe and core catcher are generally brokenout on the catwalk. Gas may be confined and precautions must be taken toprevent personnel from being around the end of the inner tube.

Core ProcessingCore cutting requires a high-powered air saw - this must only be used by quali-fied operators, with appropriate personal protective equipment(gloves, goggles,hearing protection and dust mask). All non-essential staff should stand clear.

Core processing is a non-routine activity. Pre-job briefings will be given to anystaff who will temporarily assist (e.g. rig crew, mudloggers). Air hoses will berouted to the core processing area and must be properly located, connected andsecured. All core processing activities must be discussed with and approved bythe drilling representative before work begins. Proper permits must be obtainedfor any specialised procedures and equipment.

Roles and Responsibilities: Core mark-up to be performed by the RFC wellsite geologist with assistancefrom the core specialist.

• Core GR to be run by the core hand.

• Core cutting will be performed by the core hand.

Coring


The coring contractor to supply personal safety equipment and coremark-up con-sumables. Rags for cleaning inner barrel. Pens or paint sticks that will indeliblymark inner barrel under rigsite conditions.

• Core GR

• Good quality measuring tape at least 10m long.

Core Cutting Saw with Diamond cutting blade will be used,cutting wax to beapplied onto the saw blade to provide adequate cooling and lubricating. Watermust NEVER be used. End Caps, Clips and Tools. Coring company to supplygood quality pneumatic and battery driven “screwdriver” to secure caps& clips.2 x caps & 2 clips required per cut section. Sealing sample bags and samplingequipment (spoon for sof sandstone and hammer and screwdriver or small chiselfor hard sections). Paint scraper for cleaning core faces for inspection. CoreBox's Wax bath for core preservation at the wellsite. (Can be supplied by the coreanalysis contractor). Only essential core processing staff will be allowed in thearea.

Conventional Core BarrelAfter removal from the core barrel the core(s) should be wiped with a rag andimmediately placed in core boxes without washing. Working from the shallowest(top) part to the deepest (bottom) part, mark the core with two (2) parallel lines,the right line in red and the left line in black. It is imperative to face the top ofthe core when marking it with parallel lines as described above. Otherwise, themarking will be exactly opposite of what is wanted and this may subsequentlycause considerable confusion. This conventional marking will facilitate reorien-tation of any pieces should they become misplaced.

Mark depths on the core each 0.5m starting from the top of the core. Indicatedepths with a line extending around as much of the circumference of the core aspossible, and write the depth clearly beneath the line. Where the core is rub-bleised, label any bags with the depth interval contained. In the case of length ofcore recovered being less than the interval cored, always assume that the 'lost'portion is missing from the base of the core. If there is good evidence that it ismissing from elsewhere in the core, note this on the core report and on thewellsite core log.

Numbering of core boxes should begin from the top of the core. Bottom (B) andtop (T) of the core is to be clearly marked on each box. Inside the lid mark theindividual depth interval of each core box. The outsides of the boxes should bemarked with the company name, well number, core number and box number.The whole core should be tightly wrapped in a none reactive plastic wrap e.g.Seran Wrap or pure polyethylene, and then wrapped in aluminium foil. Note,

Coring


Seran Wrap is recommended since cling film products may react with hydrocar-bons.

From sands preserve one 15 to 25 centimetre long sample every second meter, asabove, and seal the sample in plastic tubing/protec core, using a heat sealingmachine (provided by the core handling contractor). In hydrocarbon bearingzones preserve samples every meter. Alternatively, preservation of the chosenpieces may be done by wrapping the core piece in Seran Wrap, then aluminiumfoil and finally dipping it in a wax bath to seal.

In addition to marking the depth interval on the sample, the exterior wrappingmaterial should be labelled with the top and bottom depths, and an arrow shouldpoint to the upward end of the section. A cardboard label with details of the corenumber, well, company, date, and depth interval should be sealed in with waxedsamples or placed in a plastic bag inside the protective tubing. Normally pre-served samples will be replaced in their correct position with the rest of the corein the core boxes.

Fiberglas or Aluminium Core Sleeve On retrieval of the core sleeve, it is to be cleaned and marked with two parallellines, red to the right, black to the left as described above for conventional cores.After measuring, the mudlogging contractor and/ora core hand can cut the coreinto 3' or 1 m lengths (according to size of boxes) and samples taken at the endof each length of core.

Lithology from butt ends of each core is to be described. Each length of coresleeve will be capped and clamped. Subsequently, the cores are to be placedinside wooden boxes and properly padded for protection.

The depth interval and box number must be clearly marked on the outside andinside of the box. Top and bottom depth labels are to be marked on the fibreglasssleeve of each individual section.

An option exists not to cut the core at the wellsite. When this is exercised thebarrel is marked as noted above and the ends capped. A sample can be taken fromthe bottom of the barrel first. The inner barrel is then loaded into a cradle andloaded onto a boat for transport to town. It may be desirable to preserve piecesof the core at the wellsite. If so the procedure outlined in the last paragraph ofConventional Coring Procedures should be followed.

Cores can be prevented from drying out by either injecting the annulus of thecore sleeve with epoxy resin or foam.

Core chips (approx. 50 g) taken from the cores are to be sent to Shore Base forsubsequent biostratigraphic analysis, if appropriate. After sealing, labelling and

Coring


boxing, each individual core is to be sent to the core laboratory as fast as possi-ble. It should be noted that the wellsite geologist and the mud loggers are respon-sible for the handling and sealing of all cores. The wellsite geologist will notifyeach shipment by telefax or email to the Shore base office, attention Ops. Geol-ogist.

Aluminium Half Moon Inner Barrels The benefit of using a half moon barrel is that the whole core can be viewedwithout or before cutting into 1 m lengths. Once the inner barrel is laid out in thedesignated core handling work area the aluminium inner sleeve can be removedfrom the iron inner barrel. The wellsite geologist will find core top, and confirmcore recovery. The wellsite geologist will then lead core mark up. It is usuallybest to subsequently mark cut lines and then initially depth mark the core, toavoid confusion.

The top section of the Half Moon tube can if required at this point be lifted offfor a quick geological description, it must be placed back and secured with clipsbefore sawing process starts. After removing the top half of the tube a quick wipeof the core surface with clean rags can allow an overview of core recovery, sandshale net to gross and the location of hydrocarbons. The core can be digitallyphotographed, marked with master orientation lines (red to right, black to left),measured, marked up and very briefly described before replacing the sleevecover. The core can then be returned to the inner barrel, loaded into a cradle andshipped to shore without cutting.

Alternatively, clamps can be put on the inner barrel and the core cut into 1 m sec-tions, loaded into core boxes and shipped to town. When the core is cut intometer lengths the RFC wellsite geologist can take a small chip sample from eachtop face for subsequent detailed description. End caps and clips will be appliedto protect the core faces and prevent dehydration.

Core Handling It is wise to mark the inner barrel or liner as described above, before shipping totown. It is also wise to minimise core exposure time to the air to prevent dryingout. The quicker the core is handled the better. It is essential that the core is notallowed to remain lying around on board the rig or onboard a boat for days onend. Cores that are not preserved deteriorate so it is very important to get thecores to the laboratory as soon as possible.

CO

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CORELOGWELL INFORMATION EQUIPMENT PERFORMANCECompany Core BBL Type & NO: HT 60 Core no: 2Contractor Core BBL Size 180'X 9 1/2" X 5 1/4" Interval Cored-FFinish 8798 FtRig Name I.T. Type JAMBUSTER Start 8,675.0 FtWell No Stab. Size 12 7/32" Amount Cored 123.0 FtField L. Shoe & Catcher PILOT SHOE & SPRING Core Recovery 120.7 FtArea Bit Style & Size RC 478 C3 12 1/4" X 5 1/4" % Recovery 98% %Hole Temp Bit ser # 322935 Coring Hours 30.70 Hrs.Hole Size TFA 1.06 ROP 4.01 Ft/hrHole Angle IADC Dull Grade-Start 0/0/NO/A/X/IN/PN/PR Reaming WASHED/REAMED LAST STANDFormation IADC Dull Grade- Finish 3/7/WT/N&T/X/IN/CT/PR Service Engineer Name TOM/JOHNLithology SPP on/off bottom 725--1000 Date 18/19-12/01Mud Type K/CL Liner Size 6 1/2" RemarksWT.PPG 11.3 SPM WL 2% Tr GPM 200--400% Solids 6.8 LCM n/a OPERATING PARAMETERS

8,675

8,680

8,685

8,690

8,695

8,700

8,705

8,710

8,715

8,720

8,725

8,730

8,735

8,740

8,745

8,750

8,755

8,760

8,765

8,770

8,775

8,780

8,785

8,790

8,795

0 10 20 30 40 50 60 70 80

8,675

8,680

8,685

8,690

8,695

8,700

8,705

8,710

8,715

8,720

8,725

8,730

8,735

8,740

8,745

8,750

8,755

8,760

8,765

8,770

8,775

8,780

8,785

8,790

8,795

0 5 10 15 20 25 30 35 40 45 50

8,675

8,680

8,685

8,690

8,695

8,700

8,705

8,710

8,715

8,720

8,725

8,730

8,735

8,740

8,745

8,750

8,755

8,760

8,765

8,770

8,775

8,780

8,785

8,790

8,795

0 20 40 60 80 100

120

ROP Ft/hr PRESSUREpsi

TORQUEKft.lbs

8,675

8,680

8,685

8,690

8,695

8,700

8,705

8,710

8,715

8,720

8,725

8,730

8,735

8,740

8,745

8,750

8,755

8,760

8,765

8,770

8,775

8,780

8,785

8,790

8,795

0 2 4 6 8 10

WOB Klbs

8,675

8,680

8,685

8,690

8,695

8,700

8,705

8,710

8,715

8,720

8,725

8,730

8,735

8,740

8,745

8,750

8,755

8,760

8,765

8,770

8,775

8,780

8,785

8,790

8,795

0 200

400

600

800

1000

1200

RPM

Prepared By Billy Roy

SID

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Num

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Log Witnessing


Logging Witness

Job Specification

a. Key Result Area

• Provide expert advice on the drilling rig related to wireline logging, to ensure quality control of the measurements and to gather all relevant petro-physical data in such a way that the objectives outlined in the Drilling Pro-gramme are being met.

• To supervise the acquisition of borehole seismic survey information, inter-pret in-field and evaluate the obtained data to ensure quality control of measurements, and or gather all relevant geophysical data.

b. Performance Indicators

• That the wireline logging objectives are achieved and that a detailed log of logging operations is maintained.

• That the wireline logging operations are carried out in a coordinated and safe manner without any unnecessary delays.

• That the petrophysical logs are reported in a timely and professional manner.

• Attaining the highest possible standards in the acquisition of borehole seis-mic surveys through quality control.

• That borehole seismic survey operations are carried out in a co-ordinated and safe manner in an optimal time frame.

• That all data acquired for borehole seismic survey and site surveys is reported and transmitted for processing in a timely manner.

c. Responsibilities

• To ensure that all specified wireline equipment and personnel are available on the rig (and boat) with correct specification and/or certificates, to per-form the service safely and efficiently.

• To supervise all wireline logging operations and provide technical support and troubleshooting as required.

Log Witnessing


Wireline Logging Procedures In the event that an Operator log analyst is not at the wellsite, the wellsite geol-ogist shall supervise all logging operations. He/she will make sure that all logheadings are complete and correct and instruct the mud engineer or mudloggerto have circulated mud samples ready for the logging engineer at the beginningof the logging job. Any difficulties experienced during logging, and any anoma-lous log responses should be noted on the "Remarks" section of the log header

On arrival at the wellsite the logging engineer and the wellsite geologist shouldgo over the mudlogs and MWD logs of the section to be logged and review theobjectives of the wireline programme. The Wireline Specific Guidelines andlogging parameters should also be reviewed to ensure that there are no misunder-standings regarding requirements from the job. The WL engineer will tell thegeologist what he plans to do and what deliverables he intends to give. This willenable any misunderstandings to be dealt with before they cause a problem. Ifthere are added instructions to those that appear in the DP and the DAP then thewitness should provide these in written form.

All tools outlined in the logging programme for the section of the well will berequired to have a backup. In certain instances the backup need not necessarilybe the same tool type, e.g. an RCI™/MDT™ may be backed up with a FMT™ /RFT™. Details are given in the drilling program. Verify that all necessary toolsand back-ups are available on site in good time.

If fluid samples are to be taken, ensure an adequate supply of containers: plasticbottles for water samples and 1 gallon metal cans for oil samples.

Also ensure that a suitable measuring vessel, a gas meter and resistivity meter areon-site.

Prior to the job, ensure that all tools, and their back-ups are tested on surface andany problems or faults noted and rectified.

Ensure calibration checks are made and recorded prior to commencing logging,and again after each run. Attach these to the 1 :200 log plots.

All logging tools should be accompanied by appropriate wireline cutting equip-ment, fishing tools and other attachments that may be required to aid logging e.g.a hole finder. Verify they are onboard.

Pipe conveyed logging equipment should be available onshore for . mobilisationat short notice even when not specified in the logging programme. Check itsavailability.

Log Witnessing


The Witness should supply the logging engineer with the following informationfor the log header;

• Company Name

• Well Name

• Location co-ordinates Drillers Depth

• Reference Point or Datum. Nomally the rig rotary table. It should be recorded as MDBRT (measured depth below rotary table)

• Water Depth

• Casing size and depth

• Hole Size

• Name of Witness

• Time circulation stopped

• A mud sample collected after circulation was stopped, with a mud report on mudproperties. Also provide a fresh mud filtrate sample and a filter cakesample.

Prior to commencing an operation at the wellsite, a pre-job meeting should beorganised to ioclude the wireline crew, the logging witness, the drilling supervi-sor, the wellsite geologist, the toolpusher and other key personnel. The purposeis to ensure that all personnel involved are familiar with planned work pro-gramme and the procedures to be followed in executing it.

• Roles and responsibilities of personnel involved.

• Safety and operational procedures to be followed.

• Safety and operational risks and hazards.

• Work programme objectives and issues critical to the success of the operation.

• Well control procedures.

Log Witnessing


• Well status highlighting issues which could impact theplanned operation.

• Operator management approvals for approved work pro-gramme.

• Well evaluation tools or equipment should not be modifiedwithout the approval of the onshore supervisor of the com-pany who supplied the tools.

• Loads should not be lifted over the wireline or coiled tub-ing whilst operations are in progress. If an important lift isrequired during the course of operations the wire or coilshould be clamped and laid down prior to making the lift

• Loads in excess of the working strength values of the slick-line, wireline or coiled tubing set by service providers willnot be exceeded without the approval of the Drilling Super-visor.

Depth Control Ensure the logger checks the casing depth while going in the hole. Any variancebetween loggers and drilling casing depths should be resolved. Depths measuredwith casing are usually much closer to wireline depths; driller and logger shouldagree within 2ft at 5000ft, and within 5ft at 10000ft.

First LogOn the first log in a well the tool should be zeroed at the level of the DerrickFloor. Following the standard checks on the cable mark, the tool should bestopped on entering open hole and the casing shoe logged. Any discrepancy ofmore than 2 ft at 5000ft , and 5ft at 10,000ft between casing depth and log depthshould be investigated. For this purpose it is useful to retain each tally list on thewellsite. If the reasons for the discrepancy are not clear, the log may be run andthe surface zero depth checked at the end. If any depth adjustments are deemedto be necessary after logging these should be recorded in the remarks section onthe log and applied before any playback tapes or data transmissions are made.

Subsequent Logs Subsequent logs over the Same interval should be tied into the first survey, andany depth adjustments again applied before playback, transmission or field tapeproduction. Ensure the logger ties in with the previous run.

Log Witnessing


All subsequent surveys should be run on absolute depth. In addition to the checksabove, deeper surveys should include a section of overlap using through-casinggamma ray. If this overlap agrees within the tolerances given above with theprevious log, after stretch correction, the depths, should be matched and loggingcontinued, if the discrepancy is outside the above tolerances the reasons for thisshould be investigated. If it is established conclusively that the new depths aremore accurate this should be noted in "Remarks" and the survey can be run witha through-casing gamma ray recorded over the previously logged intervals forcorrelation. If the shallower logged interval is still in open hole, the completeinterval should be re-logged in the event of a depth adjustment.

As an additional independent check on depth control a short section of log overthe casing shoe should be recorded on the first descent of every set of logs, afterstretch corrections have made but before tying in and proceeding to TD. As notedabove, the casing shoe depth should agree with the drillers depth within 2ft at5000ft and 5ft at 10,000ft.

The depth shift must be noted while logging up to account for the cable stretchdue to the change in cable tension. The amount of stretch should be comparableto stretch charts and the stretch formula. Pay particular attention to the depthunits of the correction chart versus those being used for the logging.

Depth for cased hole logsSurveys which include a gamma-ray should be tied in to the appropriate open-hole density-neutron log. Surveys without a gammaray should be tied in to theCBL using the CCL. If a pup joint is present it should be logged and presented ifnot, enough casing joints must be logged above and below the zone of interest toavoid ambiguity.

Investigating Depth Discrepancies: In the event that drillers and loggers casing shoe depths are substantially outsidethe quoted tolerances, the following checks should be undertaken:

• Were the logging contractors depth control procedures applied correctly?

• Was an excessive shift applied to tie in to the previous run?

• Check the addition on the casing tally.

In the event that neither of the above show any discrepancy, the problem shouldbe discussed with the duty petrophysicist and consideration may be given tologging a CCL inside the casing to surface and checking this in detail against the

Log Witnessing


tally sheet. With this in mind a CCL should be included in the first or second toolstring in each logging suite.

Change of Derrick Floor Elevation or RigIn the event of a change of rig or adjustment in derrick floor elevation in thecourse of drilling a well, all log depths should be still referenced to the originalDerrick Floor elevation.

In the case of development wells drilled from a jack-up, a permanent datumshould be established on the wellhead or casing hanger. The original KellyBushing height above this datum should be reported on the log headings. Thecurrent Kelly Bushing (or deck) height should be noted in "Remarks" and the dif-ference added or subtracted when zeroing the tool at surface before logging.

In the case of wells drilled from floaters, mean-sea-level will remain the perma-nent datum.

Formation TemperatureWhere temperatures in the hole are expected to be close to the logging tool limitsit is suggested that the time spent on bottom is minimized and that logging com-mences as soon as the tool gets to bottom. All depth corrections can be made laterwhen the tools are in a less hostile environment. This will also have a bearing onwhere the repeat sections are performed

OtherAll formation tester, sidewall sample and CBL runs should be tied in to theappropriate density log

Observe and record any adverse hole problems while RIH. Report these directlyto the drilling supervisor.

Where possible, record data whilst RIH as an insurance in case of tool failure.Do not slow the RIH operation to acquire quality logs. Log down from the casingshoe to a point several hundred feet above TD at maximum speed without the logoverspeed aborting. Then log down a short section near TD at normal loggingspeed (900 or 1800ft/hr) for depth correlation purposes. In 99% of cases theinsurance log will never be needed.

A repeat section of at least 50 m should be recorded over a zone where logresponses show large variations, e.g. a sand/shale sequence. Additional repeatsections should be run over any intervals that show anomalous log responses. Aprint of the repeat section should be given to the witness prior to repeat loggingof the interval.

Log Witnessing


All logs (with the exception of the NMR and resistivity logs) should be run atleast 50 m up into the casing. If no casing has been run since the previous loggingrun then all logs should overlap the previous run by at least 50 m.

On the top hole log the GR shall be continued inside the casing to the mudline.

The Sonic log should be run inside the casing recording ∆tc to top of cement.

Following all open hole logging runs a depth zero check at surface should bemandatory with any depth error reported in the log header remarks. If this errorexceeds +/-5ft per 10,000ft well depth the reason must be given.

Where the zone of interest has been partially logged subsequent runs shouldcover the entire zone of interest.

If a continuous temperature log is not being run in combination with the cabletension head then 3 thermometers should be run on all logging sondes, and themaximum temperature is to be recorded on the log header.

If difficulty is experienced running logging tools to the bottom of the hole, theengineer will in any case log out from the deepest point reached bearing in mindthat the tool may stick at a shallower depth on subsequent runs.

During Pipe Conveyed Logging the drill pipe must not be rotated or significantweight used to push the tools through any tight spots. The maximum compres-sion possible on a tool string should be defined in the programme and agreedwith the Driller. TD should not be tagged with the tools

While TLC logging the side entry sub must not enter open hole

In the event that a wireline tool string is stuck in open hole the maximum pull of75% of the minimum weak point rating without exceeding 5O% of the cablebreaking strength may be applied. Before the decision is made to pull any weakpoint the drilling supervisor must be informed.

Where logging tools with a nuclear source are stuck in hole then every effortmust be made to retrieve the sources fishing. On no account should tools withnuclear sources be milled or washed over. In the event that a wireline tool stringwith nuclear sources is stuck in hole then reverse cut and thread should be used.

When new logging cables are used, precautions must be taken during the first 5runs in hole according to the relevant Logging Contractor Procedures. Where anew cable is used then reference to the revised running procedures and increasedjob times must be included in the work programme

Log Witnessing


Temperatures must be checked after every run in hole and recorded in the logheader.

All hole and tool concerns should be logged in the remarks section of the logheader. Note all points of interest in the remarks box.

There are several ways of numbering logging runs. Here is one recommendation.The numbering of logging run on all new wells will be as follows, where 1 rep-resents the first evaluation suite on the well and a, b, c etc. represents the indi-vidual runs, e.g.

The wellsite witness should use the logs to carry out a "quick look" interpretationat the wellsite, and email the results to the operator. The interpretation shouldinclude formation tops, top and bottom of each reservoir interval, together withdetails of thickness, porosity and water saturations of all significant porous zonespenetrated.

All logs must be digitally recorded on magnetic tape or CD

Field prints of all logs are to be produced on both 1:500 and 1 :200 verticalscales. Each 1:200 scale log with wall contact or centralised logging tools shouldhave a cable tension curve recorded on the least crowded track. Repeat sectionplots to be attached to the 1:200 print. QC logs and log calibrations should beincluded as part of the final log print

At the end of each logging run the Logging Engineer will provide the witnesswith:

• A disk containing the main FE curves acquired (LAS Format)

• A log print of the data acquired

• Plot files of log prints

First Evaluation Suite First run-in-hole 1a

Second run-in-hole 1b

Third run-in-hole 1c

Second Evaluation Suite First run-in-hole 2a

Second run-in-hole 2b

Figure 1: Log Numbering

Log Witnessing


including QC and repeat sections

• Header information (Mud type, MW, Vis, BHT, Rm & Rmf if appropriate)

At the wellsite four (4) sets of prints is normal for each log. One set of printsshould be retained at the wellsite. Two (2) sets of prints should be packed in aseparate envelope and sent to the operations geologist, and I set of prints are toaccompany the raw data tape to the wireline company’s office. (Sepia logs maybe requested if unable to print plot files).

At the end of the job the logging engineer shall supply the witness with;

• 4 field prints (as mentioned above)

• Printout of logging diary (note the witness and logging engineer shall discuss and agree onwhat was downtime, non productive time and operational time.

• Job tickets to be verified by witness and authorised by the drilling supervisor

• A diary of times and activities and comments(The witness and the logging engineer should agree which eventswill be classed as downtime).

Time Breakdown and Downtime A record of logging time breakdown should be made. Times should be recordedto the nearest 15 minutes and rig up and running times should be recorded sepa-rately.

Running time is taken from when the tool leaves the surface until it is back onthe drill floor. The rig down time for all but die last tool can be included in therig-up of the next tool. Downtime should be reconciled between witness andlogging engineer before submission of his tickets to the drilling supervisor.

The logging contractors Real Time Acquisition Tape and the original log will behand carried to the contractor's office at the end of the job by the logging engi-neer. The tape will also contain a full set of presentation and raw log plots for therepeat section. A copy of this tape should be sent to the operator with a verifica-tion listing and a paper print of the log. The engineer will generate Digital datatapes or CD containing full waveform data of all display and raw logs, including

Log Witnessing


repeat section logs, (LIS Format). A final set of plot files on CD - (6 copies)should be sent to the operator for distribution.

Post-Job ResponsibilitiesAfter logging all tools that are on rental should be returned to base on the firstavailable boat to minimise rental charges. Note: Any tools that may be requiredto assist operational decision may be left on the rig e.g. in the event a formationpressure measurement is required before making a coring run decision then aGR/FMT™ or RFT™ sonde may be left at the rig site.

Large sums of money are spent on logging operations. Even larger sums are atstake when wrong conclusions are made based on faulty logs. Carefully checkingthe log quality is essential.

Wireline Operations - Cased Hole Where well pressure is expected, full Pressure Control Equipment (PCE) withgrease injection head should be used on all wireline rig-ups, the number of flowtubes required will be calculated ~ 00 the maximun anticipated shut in wellheadpressure of the well to be worked on.

A toolcatcher and/or a tooltrap should be included in the rig-up for all wirelineoperations with PCE.

All wireline tool strings should include a depth correlation device.

A rope socket weak point feature should be included in all wireline tool stringsto facilitate the release of the cable from the tool string should the tool stringbecome stuck down hole. .

The weak point release value and the weight bar requirement should be calcu-lated for each operation based on the well pressure, depth and expected applica-tion. Loads in excess the service providers recommended value should not beapplied without the approval of the drilling supervisor.

For wireline perforating operations the weak point calculations must allow for asafety factor of 3 (maximum gun string weight less than 1/3 of the available weakpoint rating).

Contingency procedures should be in place to address any of the following inci-dents during wireline operations installation alarms:

• Parting of the wire

• A leak in the riserl lubricator or BOPs

Log Witnessing


• A leak at the grease injection head

• Tools becoming stuck downhole

• Powerpack failure.

Wireline Logging - Reporting

Daily Reporting During wireline logging operations the logging witness should prepare amorning report and distribute it via e-mail or fax or the web-based reportingsystem. The report should be distributed to all personnel involved.

The report should include:

• Brief summary of operations

• Detailed description of operations with time

• A look-ahead with estimated timing of outstanding operations

• Summary tables of pressure points, side-wall cores.

Issue Draft Evaluation Report After the job the logging witness should issue a draft evaluation report.. Thereport should contain the following sections:

Introduction. A summary of the daily operations based on the individual daily reports, cover-ing:

• Significant dates of logging operations

• Overview of each tool faiure or NPT event

• Overview of data quality

• Discussion on any hole problems

• Any services issues which were not classed as tool failuresor NPT.

Log Witnessing


Time breakdown

Job summary Non Productive Time analysis

A detailed breakdown and analysis of the non productive time giving root causesand actions taken

Log quality control

A section on log quality control should reference In each logging run made andnotes on the following aspects for each run should include:

• Log presentation

• Calibration

• Logging speed

• Data quality/spurious readings/repcatability.

Overview of contractor performanceA listing of the services with a discussion of the following points:

• Pre job description

• Surface cquipment

• Downholc equipment

• Operations

• Reporting

• Personnel

• Other - onshore support, logistics etc. All positive and negative points should be included and particular reference togood performance of the individuals.

Recommendations and lessons learnedAny operational or service issues will be subject to a post job critical review witha summary of lessons learned included in this section.

Log Witnessing


Appendices

• Operational Progress

• Logging Programmee

• Temperature (see below)

• Pressure Plots

• Quick Look Evaluation

Formation TemperatureThe static bottom hole temperature can be estimated with a "Horner plot". Aftertwo or more electric logs have been run, their respective bottomhole

temperature data can be used to construct the plot by following the next steps:

(I) Time the last circulation on bottom before logging was started (A). (2) Time the last circulation on bottom before logging was stopped (B). (3) Total circulation time (in hours) on bottom before logging:

T = (B - A). (4) Time the logging tool arrived on bottom (C). (5) For each log calculate the time (in hours) between end of circulation

(B) and tool on bottom: At = (C - B). (6) For each log calculate the following relationship: X = At/(T + At). (7) For each log record the maximum hottomhole tempe!1lture. .

For each log the value for the (log X) can now be plotted against its bottomholetemperature on a semi-logarithmic graph with (log X) plotted on the x-axis andthe temperature on the y-axis. Fit a straight line through the points and extend theline to where it intersects the y axis for X = 1.00. The temperature at the inter-section point will be an estimate for the static bottomhole temperature.

Log Witnessing


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Wireline Logging Summary 12 ¼” Hole Section

Calleva 28/05/02 Total Depth 9560 ftCasing 3320 ft

Start Time

Stop Time Elapsed Time Wireline Activity

22:00 22:05 0:05 toolbox talk22:05 23:45 1:40 begin rig up of Run #1: SP-DSI-HRLA-PEX23:45 0:40 0:55 toolbox talk for next crew

0:40 1:20 0:40 check toolstring1:20 1:30 0:10 load RA sources1:30 4:10 2:40 RIH4:10 4:30 0:20 on bottom, repeat pass4:30 6:40 2:10 main pass6:40 7:40 1:00 at casing shoe7:40 8:00 0:20 finish GR log8:00 8:15 0:15 unload RA sources8:15 9:15 1:00 finish after cals, Max Recorded Temps: 182, 181 degF9:15 9:30 0:15 finish rigging down Run #1, head changed, wait on crane lifts9:30 10:30 1:00 begin rigging up Run #210:30 10:45 0:15 operational check tool string10:45 12:18 1:33 RIH with FMI-HNGS-CMR12:18 12:20 0:02 at 8940 ft, open caliper Run #2 pass 1: FMI-HNGS12:20 12:38 0:18 log up repeat section, 900 fph, all buttons active12:38 12:40 0:02 at 8700 ft, close calipers12:40 12:47 0:07 RIH to 9250 ft, 12:47 12:49 0:02 open calipers12:49 12:57 0:08 log up main pass, 900 fph, pad press. 17%, every 2nd button on one pad & flap inactive12:57 13:01 0:04 abort log at 9160 ft, close caliper & RIH to 9250 ft, to try again13:01 13:10 0:09 log up main pass 2nd attempt, 900 fph, pad press. 50%, same pad/flap problem13:10 14:25 1:15 at 8200 ft, stop log, retract arms, RIH14:25 15:15 0:50 log up main pass Run #2 pass 2: CMR after tuning tool, 850 fph15:15 16:32 1:17 stop log at 8200 ft, RIH to 8732 ft, 16:32 16:37 0:05 tune CMR16:37 16:42 0:05 RIH to 8850 ft16:42 16:45 0:03 start repeat section at 8778 ft16:45 17:10 0:25 end repeat section & drop down to 8732 ft to tune tool17:10 17:15 0:05 tune CMR17:15 17:20 0:05 POOH17:20 19:00 1:40 perform after cals, rig down FMI-HNGS-CMR, MRT 183, 182 degF19:00 20:30 1:30 rig down FMI-CMR complete20:30 21:10 0:40 rig up Run #3: MDT pressure tests21:10 21:30 0:20 RIH21:30 23:24 1:54 Turn on motion compensator23:24 23:34 0:10 stick test23:34 0:00 2:18 1st correlation pass

0:00 1:50 1:50 stabilize temperature of MDT tool in hole at 8565 ft1:50 13:24 11:34 MDT pressure profile. 49 pressures attempted, 26 obtained, 16 dry tests, 7 lost seals13:24 15:30 2:06 POOH with MDT, Pressure survey completed15:30 16:00 0:30 wash down & flush out single probe16:00 16:45 0:45 rigged up additional MDT sampling modules to run #3 MDT tool16:45 17:00 0:15 surface check Run #4: MDT samples17:00 19:25 2:25 RIH to 8450 ft19:25 21:00 1:35 perform stick tests & allow, MDT to warm up21:00 21:15 0:15 correlation log to position for sample at 8468 ft21:15 23:10 1:55 Pumped out 39.7 litres and filled 3.74 litre sample chamber at 8468 ft with water23:10 23:35 0:25 correlation log to position for sample at 8938 ft23:35 0:43 1:08 Pumped out from 8938 ft, MDT tool plugged up after pumping 30 litres

0:43 1:17 0:34 Pumped out from 8936 ft, MDT tool plugged up after pumping 27 mins of pumping1:17 1:27 0:10 correlation log to position for sample at 8664 ft1:27 2:59 1:32 pumped out from 8664 ft. After pumping for 1.5 hrs O/W ratio was 50/50. Aborted sampling

since a 95% pure sample could not be obtained.2:59 3:15 0:16 Attempted to sample at 8561 ft, Aborted sampling after dry pretest3:15 3:36 0:21 Attempted to sample at 8563 ft, Aborted sampling after MDT tool plugged3:36 3:45 0:09 Attempted to sample at 8598 ft, Aborted sampling after dry pretest3:45 4:45 1:00 Attempted to sample at 8600 ft, Aborted sampling after MDT tool plugged4:45 6:40 1:55 Pull MDT tool out of the hole for inspection & servicing6:40 7:10 0:30 Turn off motion compensator, toolbox talk7:10 8:40 1:30 drain SC#1, sample from 8468 ft, volume 3750 psi8:40 9:00 0:20 probe plugged, took 3000 psi to clear, service tool9:00 10:00 1:00 begin making up MDT toolstring for run #510:00 11:00 1:00 surface check Run #5: MDT samples11:00 11:25 0:25 operational check11:25 11:55 0:30 Set compensator, RIH11:55 12:03 0:08 correlation run for sample at 8563 ft, add 3.5 ft12:03 12:45 0:42 Attempt sample at 8563 ft, aborted as sample not cleaning up above 50% oil12:45 12:52 0:07 Attempt sample at 8620 ft, telemetry failure, tool retracted automatically.12:52 13:00 0:08 Drop down to 8635 ft, no communication with tool.13:00 16:15 3:15 POOH, found short in cable head, rehead, lay out MDT (program cancelled)16:15 Rig up Run #6: VSI

29th December 2001

30th December 2001

31st December 2001, New Year's Eve

1st January 2002, New Year's Day

Page 1 of 1

Stag

Geo

logi

cal S

ervi

ces

Ltd.

Wel

l: C

alle

va 2

8/0

5/0

2D

ate

: 2

0th

May

20

02

Mob

ility

bas

ed o

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din

gs.

Larg

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Pro

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Tim

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Tim

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stat

ic B

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stat

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Star

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nis

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DB

RT

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BR

TSG

CQ

GEM

WSG

CQ

GEM

WG

rad

SGC

QG

Tem

pM

obili

tyC

omm

ents

#h

h:m

mm

m:s

sh

h:m

m#

(ft)

(ft)

(PSI

A)

(PSI

A)

(lb/

g)(P

SIA

)P

(PSI

A)

(lb/

g)(l

b/g)

(PSI

A)

(PSI

A)

Deg

FM

D/C

P

11:

5111

:00

2:02

4385

65.0

8563

.950

11.6

5011

.411

.23

4541

.145

40.7

10.1

750

11.6

5011

.216

4.6

11.8

Goo

d Te

st t

hen

Lost

Sea

l2:

0504

:40

2:09

4485

51.0

8549

.950

03.7

5003

.411

.23

5003

.750

03.4

Chec

k Se

al in

Sha

le -

OK

22:

1210

:02

2:22

4585

63.0

8561

.950

10.9

5010

.511

.23

4540

.545

40.1

10.1

750

10.7

5010

.216

5.6

773.

5G

ood

Test

3

2:25

10:5

02:

3546

8571

.085

69.9

5015

.250

15.1

11.2

345

43.2

4542

.810

.17

6.49

5015

.550

14.8

166.

313

80.6

Goo

d Te

st

42:

3811

:00

2:49

4785

81.0

8579

.950

21.2

5020

.811

.23

4546

.545

46.2

10.1

66.

5250

21.1

5020

.516

6.9

664.

0G

ood

Test

52:

5108

:30

2:59

4885

91.0

8589

.850

27.0

5026

.911

.23

4550

.045

50.0

10.1

66.

8350

26.9

5026

.716

7.5

Goo

d Te

st t

hen

Lost

Sea

l6

3:03

10:0

03:

1349

8592

.085

90.8

5027

.750

27.6

11.2

345

50.6

4550

.410

.16

6.86

5027

.750

26.9

167.

819

89.2

Goo

d Te

st7

3:16

11:1

03:

2750

8606

.086

04.8

5036

.050

35.7

11.2

345

55.6

4555

.510

.15

6.91

5035

.650

35.4

168.

313

3.2

Goo

d Te

st8

3:29

13:0

03:

4251

8611

.086

09.8

5038

.650

38.6

11.2

345

57.5

4557

.410

.15

6.95

5038

.650

37.9

168.

520

6.7

Goo

d Te

st9

3:44

10:2

03:

5452

8620

.086

18.8

5044

.050

43.9

11.2

345

60.6

4560

.710

.15

6.97

5044

.050

43.1

170.

011

79.1

Goo

d Te

st10

3:57

12:2

04:

0953

8627

.086

25.8

5048

.050

48.0

11.2

345

63.0

4563

.010

.15

6.90

5048

.050

47.2

169.

495

1.1

Goo

d Te

st11

4:12

14:2

04:

2654

8635

.086

33.8

5052

.750

52.7

11.2

345

66.4

4566

.510

.15

7.07

5052

.950

51.8

169.

778

.3G

ood

Test

124:

2907

:40

4:36

5586

54.0

8652

.850

63.6

5063

.511

.23

5063

.650

63.0

169.

9Lo

st S

eal

134:

3811

:10

4:49

5686

56.0

8654

.850

64.8

5064

.611

.23

4573

.145

73.1

10.1

46.

8450

64.7

5064

.017

0.2

940.

6G

ood

Test

144:

5211

:10

5:03

5786

64.0

8662

.850

69.2

5069

.411

.23

4575

.945

76.0

10.1

36.

8550

69.4

5068

.617

0.3

2383

.1G

ood

Test

155:

0509

:20

5:14

5886

74.0

8672

.850

75.1

5075

.111

.23

4582

.245

82.3

10.1

37.

3250

75.1

5074

.317

0.5

Goo

d Te

st t

hen

Lost

Sea

l16

5:16

12:1

05:

2859

8672

.086

70.8

5074

.050

73.5

11.2

345

78.8

4578

.910

.13

6.86

5074

.050

73.1

170.

656

1.5

Goo

d Te

st17

5:30

13:2

05:

4360

8684

.086

82.7

5081

.250

80.8

11.2

345

84.4

4584

.510

.13

7.07

5080

.850

80.0

170.

810

5.9

Goo

d Te

st w

ith L

ost

Seal

???

185:

4609

:30

5:55

6186

82.0

8680

.750

79.6

5079

.511

.23

4583

.045

83.0

10.1

36.

9550

79.6

5078

.817

1.0

996.

9G

ood

Test

195:

5811

:00

6:09

6287

20.0

8718

.751

01.4

5101

.611

.23

4595

.745

96.0

10.1

16.

8651

01.5

5100

.717

1.2

1744

.6G

ood

Test

206:

1111

:00

6:22

6387

30.0

8728

.751

07.1

5107

.211

.23

4599

.445

99.5

10.1

16.

8551

07.2

5106

.417

1.4

481.

5G

ood

Test

216:

2307

:20

6:30

6487

40.0

8738

.751

12.9

5112

.911

.23

4603

.046

02.6

10.1

06.

8051

13.1

5112

.717

1.6

Lost

Sea

l aft

er G

ood

Pres

sure

226:

3211

:50

6:43

6587

42.0

8740

.751

14.1

5113

.711

.23

4603

.846

03.7

10.1

06.

8551

14.4

5113

.317

1.7

1007

.5G

ood

Test

Cor

rela

tion

Pas

s Lo

gged

. MD

T O

ff D

epth

by

6 f

eet.

Sta

tion

s 2

3 &

24

hav

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hav

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he

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for

Gra

dien

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s.23

7:22

12:5

07:

3471

8756

.087

54.7

5118

.551

18.2

11.2

246

06.8

4606

.210

.09

6.60

5118

.951

18.5

172.

838

0.8

Goo

d Te

st24

7:47

11:5

07:

5872

8768

.087

66.6

5125

.951

25.6

11.2

246

10.2

4609

.710

.09

6.54

5125

.751

25.3

173.

026

3.1

Goo

d Te

st25

8:03

06:4

08:

0973

8777

.087

75.7

5130

.951

30.8

11.2

251

29.9

5130

.817

3.2

Dry

Tes

t26

8:13

06:4

08:

1974

8778

.087

76.6

5131

.251

31.3

11.2

251

31.4

5131

.117

3.5

Dry

Tes

t27

8:25

15:4

08:

4075

8797

.087

95.7

5142

.251

42.1

11.2

246

22.3

4621

.810

.08

6.72

5142

.551

42.2

173.

941

.6G

ood

Test

288:

4207

:00

8:49

7688

54.0

8852

.651

75.0

5175

.311

.22

5175

.051

75.2

Dry

Tes

t29

8:52

06:5

08:

5877

8853

.088

51.6

5174

.251

74.5

11.2

251

73.9

5174

.7D

ry T

est

309:

0005

:40

9:05

7888

55.0

8853

.551

75.5

5175

.511

.22

5175

.551

75.8

175.

5D

ry T

est

319:

0806

:40

9:14

7988

71.0

8869

.651

84.9

5185

.011

.22

5185

.051

85.3

176.

0D

ry T

est

329:

1806

:40

9:24

8088

73.0

8871

.651

85.8

5186

.211

.22

5186

.451

86.2

177.

4D

ry T

est

339:

2711

:40

9:38

8188

77.0

8875

.551

88.6

5188

.511

.22

4647

.446

46.8

10.0

46.

5551

88.9

5188

.316

1.0

Goo

d Te

st34

9:42

08:2

09:

5082

8898

.088

96.5

5201

.052

00.7

11.2

252

01.0

5200

.617

8.3

Dry

Tes

tC

orre

lati

on P

ass

Logg

ed. S

ubt

ract

ed 3

fee

t to

pu

t M

DT

on D

epth

.35

10:0

707

:20

10:1

485

8912

.089

10.5

5210

.752

10.6

11.2

252

10.6

5210

.517

9.0

Dry

Tes

t36

10:1

607

:40

10:2

386

8922

.089

20.5

5216

.452

16.3

11.2

252

17.0

5216

.217

9.0

Dry

Tes

t37

10:2

606

:40

10:3

287

8924

.089

22.6

5217

.952

17.7

11.2

252

17.6

5217

.617

9.3

Dry

Tes

t38

10:3

514

:10

10:4

988

8925

.089

23.5

5217

.552

17.4

11.2

246

64.0

4663

.610

.03

6.57

5217

.652

17.3

179.

213

26.7

Goo

d Te

st39

10:5

112

:30

11:0

389

8930

.089

28.5

5220

.852

20.8

11.2

246

65.6

4665

.410

.02

6.58

5221

.252

20.7

179.

437

8.0

Goo

d Te

st40

11:0

510

:30

11:1

590

8938

.089

36.5

5225

.552

25.5

11.2

246

68.3

4668

.010

.02

6.57

5225

.652

25.3

179.

668

2.9

Goo

d Te

st41

11:1

711

:17

9189

67.0

8965

.552

42.2

5242

.211

.22

5242

.452

42.3

Dry

Tes

t42

11:2

507

:20

11:3

292

8986

.089

84.5

5253

.452

53.5

11.2

252

53.4

5253

.418

0.0

Dry

Tes

tC

orre

lati

on P

ass

Logg

ed. S

ubt

ract

ed 3

fee

t to

pu

t M

DT

on D

epth

.43

11:4

711

:40

11:5

895

8986

.089

85.5

5256

.252

56.1

11.2

346

87.0

4686

.510

.01

6.65

5256

.452

56.2

180.

514

0.7

Goo

d Te

stP

ulle

d M

DT

Ou

t of

th

e H

ole

to ~

85

00

ft.

4412

:16

14:1

012

:30

9784

72.0

8471

.049

60.2

4958

.411

.23

4350

.043

48.2

9.84

4959

.749

58.4

178.

391

.8G

ood

Test

4512

:35

09:2

012

:44

9884

68.0

8467

.049

57.2

4956

.011

.23

4957

.349

56.0

176.

8Te

st w

ith L

ost

Seal

???

4612

:47

10:0

012

:57

9984

68.0

8467

.049

57.1

4956

.111

.23

4347

.543

46.3

9.84

4956

.949

561.

017

5.5

138.

6G

ood

Test

4713

:01

06:3

013

:07

100

8462

.084

61.0

4953

.449

52.7

11.2

349

53.1

4952

.717

4.0

Dry

Tes

t48

13:0

913

:09

101

8463

.084

62.0

4953

.949

53.2

11.2

349

53.7

4953

.017

3.8

Dry

Tes

t49

13:1

707

:00

13:2

410

284

64.0

8463

.049

54.2

4953

.611

.23

4954

.449

53.8

173.

6D

ry T

est

Dep

th (

Ft)

All

pres

sure

s in

PSI

A

MDT/CMR JOB-LOG Calleva-10A 1

Stag Oil Company Ltd.

JOB LOG FIELD: Berkshire WELL: Calleva-10A

RIG: Land -1 WITNESS: Dave Kitson

DESCRIPTION: MDT / CMR DATE TIME RUN NO.1 LATCH 1. 28/09/00 00:15 Rig up sheaves 01:00 Rig up tools (MDT/CMR), total length 178.7 ft 03:00 Power up tools at surface and test, OK. 03:45 Start RIH (Drift Pipe) 06:35 At Shoe, 4,371 ft, circ pipe volume 06:50 Resume RIH to 4749 ft 07:10 Make up SES and RIH w/ PWCH 08:10 Latch and Test – OK 08:35 R/U Snatch Pulley 08:16 Clamp cable and Pull Test to 3000 lbs 08:48 Start RIH to Station 1 09:05 STATION 1 at 4,780 ft, allow Hydrostatic to stabilise 09:10 Inflate Packer with 24.57 ltrs / 800 psi / Hole Dia 9.1 ins 09:28 Set Observation Probe 09:30 Probe Pre-test 1b, draw 10 cc 09:34 Probe Pre-test 1c, draw 10 cc 09:38 Packer Pre-test 1a, Pump out of packer 585 cc, pulse seen on Observation

probe 10:06 Packer Pre-test 1d, Pump out of packer 585 cc, pulse seen on Observation

probe 10:49 Retract Observation Probe 10:50 Pre-test 1e, Pump out of packer 500 cc 11:04 Deflate Packer, Establish Hydrostatic 11:15 End Station 1. Move down to next station 12:10 STATION 2 at 5,500 ft, allow Hydrostatic to stabilise 12:12 Inflate Packer with 23.9 ltrs / 900 psi / Hole Dia 9.1 ins 12:25 Set Observation Probe 12:26 Set Resistivity Probe 12:29 Probe Pre-test 2c, draw 10 cc 12:30 Probe Pre-test 2b, draw 10 cc 12:33 Probe Pre-test 2d, draw 9.5 cc 12:36 Probe Pre-test 2e, draw 9.66 cc 12:42 Packer Pre-test 2a, Pump out of packer 585 cc, large pulse seen on

Observation probe 13:00 Packer Pre-test 2f, Pump out of packer 585 cc, large pulse seen on

Observation probe 13:36 Reflate packer to 1000 psi 13:40 Start pump-out for Interference Test at 350 rpm speed mode. See drop in

pressure at Observation probe immediately. See drop in pressure at Resistivity probe after 10 mins.

13:51 Increase pump speed to 380 rpm 14:10 First water on OFA after 8.1 ltrs pumped 14:30 Increase pump speed to 400 rpm 14:38 Increase pump speed to 420 rpm 14:45 Increase pump speed to 450 rpm 15:06 Stop pump-out, Start Build up. Pumped 24.5 ltrs (25.7 ltrs cum) in 86 mins.

MDT/CMR JOB-LOG Calleva-10A 2

16:19 Start pump-out for clean-up / PVT samples at 600 rpm 16:57 Packer pressure at 1403 psia after 18.7 ltrs (44.4 ltrs cum), decrease pump

rate to 570 rpm. 17:02 Packer pressure at 1401 psia after 20.5 ltrs (46.2 ltrs cum), decrease pump

rate to 565 rpm. 17:04 Packer pressure at 1400 psia after 21.6 ltrs (47.3 ltrs cum), decrease pump

rate to 560 rpm. 17:51 First oil (40%) after 39.1 ltrs (65.8 ltrs cum), packer pressure = 1433.32 psia 18:14 Packer pressure = 1428.2 psia, after 48.5 ltrs (74.2 ltrs cum): 70% oil 18:46 Packer pressure = 1424.6 psia, after 59.7 ltrs (85.4 ltrs cum): 80% oil (70%

green, 10% white on OFA) and 20% water 19:00 Packer pressure = 1422.7 psia, after 64.3 ltrs (90.0 ltrs cum): 80% oil (70%

green, 10% white on OFA) and 20% water. Open PVT bottle # 326 for low shock PVT sample #1

19:04 Close bottle # 326 (1st PVT sample), min pressure 1422.7 psia, final pressure = 1552.29 psia (+4000 psi sealing pressure). Continue pump out

19:15 Packer pressure = 1433.3 psia, after 69.6 ltrs (95.3 ltrs cum): 80% oil (70% green, 10% white on OFA) and 20% water

19:35 Packer pressure = 1427.14 psia, after 77.2 ltrs (102.9 ltrs cum): 80% oil (70% green, 10% white on OFA) and 20% water. Open PVT bottle # 327 for low shock PVT sample

19:37 Close bottle # 327 (2nd PVT sample), min pressure 1359.22 psia, final pressure = 1507.01 psia (+4000 psi sealing pressure).

19:38 Open PVT bottle # 328 for low shock PVT sample 19:40 Close bottle # 328 (3rd PVT sample), min pressure 1368.66 psia, final

pressure = 1519.07 psia (+4000 psi sealing pressure). 19:43 Continue pumping with inc pump rate of 1200 rpm Packer pressure = 1220 psia, after 84.3 ltrs (110 ltrs cum): 80% oil (70%

green, 10% white on OFA) and 20% water. Inc to 2000 rpm w/ a minimum pressure of 1060 psia at packer and 70%oil / 30% water, no gas.

19:53 Stop pump out after 93 ltrs (118.7 ltrs cum): 70%oil / 30% water, no gas. 19:55 Pretest 2g at Observation probe 20:01 Pretest 2h at Resistivity probe, 2g still building 20:10 Pretest 2h stable at 1601.34 psia, 2g still building 20:25 Retract Resistivity probe, stable at 1601.35 psia 20:27 Retract Observation probe, not quite stable at 1604.48 psia, final packer

pressure 1596.72 psia 20:28 Deflate packer, establish final hydrostatic pressures, unable to get good

mobility results from probe tests due to length of test and interference from pump out.

20:42 Set Observation Probe for Pretest 2i for mobility data 20:52 Unset probe, obtain hydrostatic and a good mobility 20:55 End of Station 2. Move down to next station 21:57 STATION 3 at 6,550 ft., allow hydrostatic to stabilise 22:02 Pretest 3a on observation probe for mobility data: 14.4 md/cp 22:13 End pretest 3a, unset probe 22:17 Start Packer inflation at 6,550 ft MDRT 22:28 Packer inflated with 19.89 ltrs / 1000 psi / Hole Dia 8.7 ins 22:29 Set Observation Probe 22:30 Set Resistivity Probe 22:31 Probe Pre-test 3d, draw 5.4 cc 22:32 Probe Pre-test 3c, draw 5.6 cc 22:36 Packer Pre-test 3b, Pump out of packer 2340 cc, interference seen on

Observation Probe 22:59 Repeat Packer pre-test (3e), interference seen on Observation Probe 22:02 Observation Probe Pre-test 3f, draw 5.4 cc 22:03 Resistivity Probe Pre-test 3g, draw 5.4 cc and allow all three pre-tests to

stabilise. 23:30 Start pump-out for Interference Test at 700 rpm speed mode. See drop in

pressure at Observation Probe immediately. Packer pressure 1516.6 psia 23:30 Increase pump speed to 1200 rpm 23:37 Increase pump speed to 2000 rpm 23:39 Pumped 11.11 ltrs (15.2 ltrs cum). Switch pump from constant speed mode

to constant power mode at 70% duty cycle 23:44 Pumped 7.0 ltrs (22.2 ltrs cum). Increase duty cycle to 75% 23:47 Pumped 13.0 ltrs (28.2 ltrs cum). Increase duty cycle to 80%

Observation Probe at 1609.41 psia. Resistivity Probe 1614.97 psia

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33.0

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26.4

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86.0

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86.0

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79.5

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89.5

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86.0

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S

Formation Pressure Concepts


Pore Pressure Evaluation

IntroductionA knowledge of formation pressure is necessary to drill the well safely and eco-nomically. Mud weight has to be optimized to provide enough safety margin andyet allow drilling to proceed at a reasonable rate.

Rock Fracture Pressure must not be exceeded otherwise mud will be lost,damaging the formation and risking inducing kicks and blowouts by the loss ofhydrostatic pressure. Extensive use of offset and petrophysical data is madeduring the planning phase to identify pressure profiles and produce a workabledrilling proposal. However, this data may be insufficient, particularly if there areno nearby wells.

During drilling, data will be obtained and the well observed to identify the onsetof pressure transition zones and to monitor the implementation of planned mudweight increases. Wellsite geologists, mud loggers and specialist Pressure Engi-neers can be used to evaluate formation pressures whilst drilling.

Measuring Pore PressureVarious methods exist to obtain measured values of Pore Pressure. All of themrequire an established borehole and will only provide pressures in permeable for-mations. The results are important and will confirm pressure estimates in reser-voir rocks, but will not indicate pressures in clays and shales which, whilst notproducing kicks or blowouts will produce severe drilling problems if signifi-cantly abnormally pressured. The methods include:

• Wireline Pressure Tests (RFT, MDT etc.)The RFT tool is normally run at casing points and can provide unlimitedpressure readings whilst obtaining one or two actual fluid samples. Thetool will only sample porous, permeable rocks, and over a very limitedarea. Pressure build up in clays, very common in the North Sea, will notbe sampled due to the lack of permeability.

• LWD Pressure TestsLWD presure testing tools have recently been introduced by some of themajor service companies. Thes include Testrak from BHI, Geotap fromHalliburton and Stethoscope from Schlumberger. All of these tools areable to take pressure readings from permeable formations without theneed to trip the pipe. This aids mud density optimization, ECD manage-ment and borehole stability whilst drilling.



• Production Pressure Tests (Drill Stem Tests) A full scale DST performed at the end of the well will provide a greatdeal of useful pressure data. However only potential reservoir zones willbe tested and the data will, therefore, be incomplete. Again its best use isas a means of planning future wells.

• Kick The shut in pressures recorded after taking a kick allow calculation offormation pore pressure, which is necessary in order to produce the cor-rect kill mud. This is a last resort however, and no wells are allowed tobe drilled "for kicks" for safety reasons.

Indirect means for Pore Pressure EstimationIndirect methodologies require the monitoring of borehole stability, mud -gasrelationships and drilling, mudlogging, wellsite geological and petrophysicaldata to identify pressure transition zones or closely balanced drilling situations.Long pressure transition zones in clays and shales can be monitored using thefollowing procedures:

• Evaluate Normally Pressured Sections and Establish Trends

• Identify Variations from Normal Trends

• Quantify Pore Pressure from those changes

It should be remembered that any values of pore pressure reported from wellsiteevaluation of drilling and logging data are estimates only, and not measuredvalues. The classic techniques using drilling exponents and other data such asresistivity and sonic log information are only applicable to abnormal pressurecaused by undercompaction of clays and shales.

Normal Pore PressureA rock is said to have normal pore pressure if only hydrostatic pressure of thepore fluid column is the force acting on the fluids. In sedimentary rocks thispressure will be established if, during burial, excess fluids are allowed to escapeto a low pressure environment as compaction proceeds. In this case the rockmatrix material will provide a self supporting structure and the pore fluids willmerely be filling the spaces and under their own pressure. The value of thisexpected normal pressure can be computed for any depth in the formation byknowing the average density of the pore fluids to the depth of interest and the truevertical height of the fluid column.



Units of MeasurementThe internationally recognised unit of measurement for pressure is the Pascal(Pa). This is equal to a force of one Newton per square metre (in turn, a Newtonis the force required to give a 1 kilogram mass an acceleration of 1 metre persecond per second.) The Pascal is quite a small unit of pressure, so we often useKiloPascals (kPa), equal to one thousand Pascals. 101.325 kPa equals one atmos-phere.

The Bar is widely used in industry, and is still often used to specify the pressurein compressed gas cylinders, so many gas regulators are calibrated in Bar. OneBar is 100,000 Pa, and for most practical purposes can be approximated to oneatmosphere (more precisely, 1 Bar = 0.9869 atm).

The original units of pressure were the Torr (named after Torricelli.) This is thepressure produced by a column of mercury 1 mm high, and equals 1/760th of anatmosphere.

Pounds per square inch (psi) is a common oilfield unit of pressure in British orAmerican (USA) dominated operations. One atmosphere is approximately 15psi.



Figure 1: Normal Pore Pressure

Normal Pore Pressure Rock is grain supported

Pore fluid pressure ishydrostatic

Fluid density: 10.00 lb/gal

Hydrostatic Pressure: 5190 psi



Absolute and Gauge PressureThe letters g and a often printed after pressure measurements refer to gauge orabsolute pressure. Since atmospheric pressure (roughly 14.7 psi and 1.013 bar) isrelatively constant it is often ignored in pressure work, and values are recordedas gauge pressure above atmospheric pressure. Absolute pressure includesatmospheric pressure.

Calculation MethodsSimple equations can be used to calculate pressures and pressure gradients usingoilfield units.

Pressure (Psi) = ppg x 0.0519 x TVDft

Using SI units:

Pressure (Bar) = gm/cc x 0.0981 x TVDm

The resulting pressure may be expressed in reports or drawn on logs as:

• Pressure: psi, bar

• Pressure Gradient: psi/ft, bar/m

• Pressure Gradient EMW: ppg, S.G., gm/cc

When computing expected normal pore pressures the average density of forma-tion fluids must be known. Offshore, the pore fluids are initially deemed to be thesame as the sea water, whilst onshore a sample of formation water may beobtained.

With depth however, the pore fluid density will change. Salty and fresh waterhorizons may be encountered, from normal environmental changes or because oflater diagenesis and variations in geothrmal gradient will cause changes to saltwater densities. The nature and extent of these fluid density changes may bedetected from log evaluation or from samples collected from MDT and DSTtests. Hydrocarbons will also alter the normal fluid gradients and can be detectedby routine wellsite geological and mudlogging operations.

The calculation of normal pore pressure begins at sea level offshore and watertable onshore.



• Fresh water:1.0 S.G. or 8.33 lb/gal

• North Sea water:1.04 S.G. or 8.66 lb/gal

Formation Balance GradientOnce the expected normal pore pressure has been calculated, the mud densityrequired to balance this pressure needs to be calculated. Offshore, the requireddensity will be less than the average density of the pore fluids because the mudcolumn is longer than the formation fluid column. Onshore, the situation willvary with the relative positions of the mud return flowline and the effective headof water.

For example, offshore the top of the mud column is at the return flowline,normally a few meters below the rig floor level. This may be 30m or so aboveMean Sea Level which is the top of the formation fluid column. At shallowdepths this difference in height can be significant and can lead to extensive over-balance in the early part of the well.

Figure 2: Normal Pore Pressure Gradient Calculation

0

325

SeawaterDensity1.04 g/cc

Pore-waterDensity1.04 g/cc

25MSL

Sea Bed

Depth belowFlowline - m

Depth Fluid density Pore Pressure PPG PPGbar bar/m EMW: g/cc

0325 1.04 30.61 0.10 1.04400 1.04 38.26 0.10 1.04500 1.04 48.46 0.10 1.04600 1.04 58.66 0.10 1.04700 1.04 68.87 0.10 1.04800 1.04 79.07 0.10 1.04900 1.04 89.27 0.10 1.04

1000 1.04 99.47 0.10 1.041100 1.04 109.68 0.10 1.041200 1.04 119.88 0.10 1.041300 1.04 130.08 0.10 1.041400 1.04 140.28 0.10 1.041500 1.04 150.49 0.10 1.041600 1.04 160.69 0.10 1.041700 1.04 170.89 0.10 1.041800 1.04 181.09 0.10 1.041900 1.04 191.30 0.10 1.042000 1.04 201.50 0.10 1.042100 1.04 211.70 0.10 1.042200 1.04 221.90 0.10 1.042300 1.04 232.10 0.10 1.042400 1.04 242.31 0.10 1.042500 1.04 252.51 0.10 1.04

Pore Pressure Gradient

0

500

1000

1500

2000

2500

3000

1 1.1 1.2 1.3 1.4 1.5

EMW - g/cc

Dept

h -

m



Sometimes the effective head of formation fluids may be greater than the heightof the mud column. This can occur onshore where aquifers may be drilled thatoutcrop at a higher elevation than the rig. In this case the Normal FormationBalance Gradient, (NFBG), will be greater than the Normal Pore Pressure Gra-dient, (NPPG).

Where oil and/or gas are part of the fluid column, the normal hydrostatic pressurewill increase at a rate consistent with the particular fluid type. This will lead to astepped pressure/depth plot. The slope of each individual segment of the plot willbe constant. This pressure gradient is a measure of the rate of pressure changeover depth and will be constant where the fluid density is constant.

Where oil, water and gas are present the mud density gradient required to balancethe three fluid pressures at depth will be an average gradient of all the individualfluid gradients, depending on the lengths of the columns.

Remember that Pressure Gradients and Equivalent Fluid Densities are averagevalues from the point of interest back to a pre-defined starting depth such asflowline, rig floor or sea level. Mostly we reference pressure gradients toflowline in order to have a direct comparison with mud density.

Figure 3: Normal Formation Balance Gradient Calculation

0

325


Pore-waterDensity1.04 g/cc

25MSL

Sea Bed

Depth belowFlowline - m Depth Fluid density Pore Pressure PPG PPG FBG

bar bar/m EMW: g/cc EMW: g/cc0

325 1.04 30.61 0.10 1.04 0.9600400 1.04 38.26 0.10 1.04 0.9750500 1.04 48.46 0.10 1.04 0.9880600 1.04 58.66 0.10 1.04 0.9967700 1.04 68.87 0.10 1.04 1.0029800 1.04 79.07 0.10 1.04 1.0075900 1.04 89.27 0.10 1.04 1.0111

1000 1.04 99.47 0.10 1.04 1.01401100 1.04 109.68 0.10 1.04 1.01641200 1.04 119.88 0.10 1.04 1.01831300 1.04 130.08 0.10 1.04 1.02001400 1.04 140.28 0.10 1.04 1.02141500 1.04 150.49 0.10 1.04 1.02271600 1.04 160.69 0.10 1.04 1.02381700 1.04 170.89 0.10 1.04 1.02471800 1.04 181.09 0.10 1.04 1.02561900 1.04 191.30 0.10 1.04 1.02632000 1.04 201.50 0.10 1.04 1.02702100 1.04 211.70 0.10 1.04 1.02762200 1.04 221.90 0.10 1.04 1.02822300 1.04 232.10 0.10 1.04 1.02872400 1.04 242.31 0.10 1.04 1.02922500 1.04 252.51 0.10 1.04 1.0296

Normal Formation Balance Gradient

0

500

1000

1500

2000

2500

3000

0.9400 0.9600 0.9800 1.0000 1.0200 1.0400

EMW - g/cc

Dept

h - m



When multiple fluid densities are present in the rock, because of changes in geo-thermal gradient, variations in fluid type or because of stratigraphic changes acumulative approach is taken to the normal pore pressure calculation. NormalPore Pressure Gradient, or (NFBG), is averaged from the point of interest backto the flowline.

Figure 4: Formation Balance Gradient

Figure 5: Multiple Fluid Densities

Drilling Fluid Gradient

Formation Fluid Gradient

Required Drilling Fluid Gradient less than Formation (Pore) Pressure Gradient

Formation Balance Gradient

Mean Sea Level

Flowline

Air gap

Water Table

DrillingFluid

FormationFluid

A

B

C

AA

A+B

A+B+C

D

Average gradientof fluids A+B+C

Individual fluid gradients



Effective Circulating DensityWhen the drilling fluid is being circulated extra pressure is created in the annulusdue to the frictional effects of the borehole and drillstring. This pressure is partof the total standpipe or pump pressure recorded on the standpipe pressure gaugeon the rig floor. Until recently this extra pressure has had to be calculated usingone of the hydraulics models such as Bingham or the Power Law.

Since the drilling fluid is flowing along the borehole the annular pressure lossesare a maximum at total depth and a minimum at the surface. The bottom hole cir-culating pressure is the sum of the hydrostatic pressure and the total annularpressure losses. Effective Circulating Density, (ECD), is this pressure expressedas an average pressure gradient and related to an equivalent fluid density.

As the value of the annular pressure losses reduces towards the surface, so theECD also reduces and approaches the drilling fluid density.

ECD is normally calculated at:

• Total Depth

• Casing Shoe

• Weakest Point (if lower than casing shoe)

Figure 6: Circulation System

Annulus

Drill pipe

Open hole

Casing & cement

Drill collar

Mud pump

Mud pit

Drill bit

Annulus

Drill pipe

Open hole

Casing & cement

Drill collar

Mud pump

Mud pit

Drill bit



ECD is important in well planning and whilst monitoring real-time drilling oper-ations. Casing seat selection will be influenced by the ECD-Fracture realtion-ship. When drilling HPHT wells there can often be a very small drilling windowbetween the mud weight and the fracture gradient, into which the ECD has to bepositioned. It is not unusual for loss-gain scenarios to be present where thehydrostatic mud weight is insufficient to balance the pore pressure but the ECDis enough to fracture the formation. Setting an extra casing string or abandoningthe well may be the only alternatives.

As mentioned above, until recently ECD had to be estimated from calculating thevalue of the annular pressure losses using one of the hydraulics models.However, these estimations are not always accurate enough since the effects ofsuch variables as cuttings, drillstring rotation, barite sag, inclined boreholes andmodern drilling fluids are rarely modelled adequately.

If it is important to have very accurate estimations of ECD then an MWDPressure-While-Drilling tool need to be used. This has external pressure trans-ducers that measure annular pressures directly and thus enable real-time esti-mates of ECD to be made.

Figure 7: Effective Circulating Density



It is important that the ECD is compared with the fracture pressure at the weakestpoint in the borehole, as well as at T.D. The weakest point is often taken as thecasing shoe depth since sedimentary rocks tend to become stronger with depth ofburial because of compaction. However, the casing is normally set in strong,impermeable formations to ensure an adequate cement job around the shoe; it isnot inconceivable, therefore, that weaker rocks, such as poorly cemented sand-stone stringers, might be present at deeper depths. This will potentially lead tofracturing, lost circulation and differential sticking problems if mud weights andECD values are high. Measurement of ECD with a PWD tool will help identifyproblems at an early stage.

It should be remembered that, when drilling ERD or long horizontal wells, ECDwill continue to increase as the well is extended (because the length of theannulus will be increasing), whilst pore pressures and fractures may remain rel-atively constant.

Overburden PressureOverburden Pressure is computed at the wellsite since it is an input parameter toFracture Pressure calculations and also provides a means of quantifying porepressure studies. Overburden Pressure is the total pressure acting on the rock andis produced by both fluid and rock matrix pressures. It may be defined as:

S = M + P

Where

S = Overburden Pressure

M = Matrix Pressure

P = Pore Pressure

It is necessary to know the average bulk density of the formation in order tocompute Overburden Pressure. Normally this is broken into like sections andcumulatively calculated.

Obtaining values for rock bulk density can be difficult and depends upon theavailability of suitable data. Available data sources are:

• Wireline Formation Density Log• MWD Formation Density Log• Sonic Log• Cuttings Density



The most accurate of these are the wireline/MWD data sources since these aredownhole measured values of rock properties unaffected by drilling processes.The Formation Density Log provides information on rock bulk density directly.Unfortunately density logs are not usually available over the whole well, beingmostly reserved for reservoir sections. Even MWD versions are not normally runin the sections.

In the absence of density log data, calculating bulk density from sonic log data isan option. The sonic log again provides downhole measured values of rock prop-erties, in this case interval travel time, (∆t), in µsec/ft or msec/m. Bulk densityhas to be derived from porosity which has firstly to be calculated from theinterval travel time.

Calculation of cuttings density is least accurate method of evaluating rock bulkdensity. The mudloggers are able to measure cuttings (shale) density which isthen used as an aid in pore pressure evaluation. Since undercompaction of claysand shales is an important mechanism for the production of overpressures,plotting the trend of changes in shale density with TVD can identify undercom-pacted, and hence potentially overpressured, zones. Since they are looking attrends any inaccuracy in the actual cuttings density values is not a major problemas long as drilling and methodology remain consistent.

Measured values of cuttings density are not especially accurate, and this is aproblem if we use the data for overburden gradient calculations.

Methods of measuring cuttings density are:

• Single Solution• Multi Solution• Pycnometer

The single and multi solution methods use the Archimedes Buoyancy Principleto measure density by immersing the cuttings in fluids of known density.

The single solution method uses two partially miscible fluids (such as zincbromide and water) in a graduated cylinder. The heavier fluid is added firstfollowed by a small quantity of water. The boundary between them is stirred toproduce a gradational density between the fluids. This process is repeated untilthe graduated cylinder contains a fluid of variable density from top to bottom.Glass beads of known density can be placed in the column to help obtain a lineargradient.

Multiple solutions of known density fluids can also be used. Here the cuttings areimmersed in the fluids (in a wire basket) and they will either float or sink. Thedensity of the cuttings can be estimated between two fluid densities.



Bulk density values obtained from cuttings are usually too low, reflecting surfacetension characteristics. The drilling process will also influence the results sincethe cuttings have been damaged by the bit and carried to the surface by thereturning drilling fluid. The action of the fluid and the bit will perhaps havechanged some of the inherent rock properties, including bulk density.

The use of cuttings density values for the construction of overburden gradientcurves should be restricted to those occasions when no in-situ measured valuesof bulk density are available.

The pycnometer method requires the use of the mud balance and a bulk volumeof cuttings. The cup is filled with sufficient cuttings (with the lid attached) toread the density of fresh water (8.34 ppg, 1.0 S.G.). Fresh water is then added tofill the cup, (with the lid attached). The new density (W2) is measured. A com-parison of the two density readings with reference to the density of fresh waterallows the bulk density of the cuttings to be determined as in the formula below.

Bulk Density from the Sonic Log Bulk density may be obtained from the sonic log where Wireline or LWDdensity log data are poor or absent. The technique involves first calculating theporosity and then using the formula below to calculate the bulk density. Porositymay be calculated from sonic travel times (∆t) using the Wyllie time-averageformula:

Where:

∆t= Travel time at the point of interest∆tm= Matrix Travel Time∆tf= Fluid Travel Time

Bulk Density (g/cc) = 8.3416.68 W2–---------------------------

φ∆t ∆tm–( )∆tf ∆tm–( )

---------------------------=



Bulk density, ρb, is defined as:

Where:

ρb = Bulk Density gm/cc

ρf = Fluid Density gm/cc

ρm = Matrix Density gm/cc

φ = Porosity %

Bellotti & Giacca (1978) published an empirically derived formula to determineporosity from sonic log data where there is difficulty in establishing clay matrixdensities or travel times.

Lithology/Fluid Density (g/cc) ∆T (µsec/ft)

Sandstone (Quartz) 2.65 55

Limestone (Calcite) 2.71 48

Dolomite (Dolomite) 2.87 44

Anhydrite 2.93 52

Salt (Halite) 2.04 67

Gypsum 2.35 50

Clay/Shale 2.5-2.8 47-170

Fresh Water 1.00 218

Salt Water 1.03 189

Figure 8: Rock, Mineral & Fluid properties

ρb φρf ρm 1 φ–( )+=

ρb 2.75 2.11∆t 47–( )∆t 200+( )

-------------------------⎝ ⎠⎛ ⎞–=



Pressure may be calculated in the same manner as for Normal Pore Pressure andrecorded in imperial or SI units.

Overburden gradient is normally plotted with reference to the return flowline tomaintain compatibility with mud density information. Offshore the gradient willbe very low initially due to uncompacted sediments and the sea water and air gapinfluences. Onshore with more compacted rocks, the OBG will often approach astraight line at an average gradient of around 2.3 gm/cc Equivalent FluidDensity.

The average density of a thick sedimentary sequence approaches 2.3 S.G, whichis equivalent to about 19.2 lb/gal or 1.0 psi/ft. It was commonplace in earliertimes to assume a constant overburden gradient of 1.0 psi/ft and few actual cal-culations were made. In offshore drilling environments however the averagedensity of the sedimentary sequence is much less than this because of theseawater cover, air gap (when plotting overburden gradient with reference to theflowline) and relatively low compaction rates, compared with onshore situations.If the data is to be used in pore pressure estimations or fracture pressure calcula-tions then accurate calculations of overburden pressure are required.

Figure 9: Overburden Gradient Calculation

0


Rock BulkDensity1.95 g/cc

25MSL

Sea Bed

Depth belowFlowline

Depth Bulk Density Overburden Pressure OBGbar EMW: g/cc

0325 1.04 30.61 0.9600400 1.95 44.95 1.1456500 2.05 65.06 1.3265600 2.05 85.18 1.4471700 2.05 105.29 1.5332800 2.05 125.40 1.5978900 2.05 145.51 1.6481

1000 2.05 165.62 1.68831100 2.15 186.71 1.73021200 2.15 207.80 1.76521300 2.15 228.89 1.79481400 2.15 249.98 1.82021500 2.15 271.07 1.84221600 2.15 292.17 1.86141700 2.15 313.26 1.87841800 2.15 334.35 1.89351900 2.2 355.93 1.90962000 2.2 377.51 1.92412100 2.2 399.10 1.93732200 2.2 420.68 1.94922300 2.25 442.75 1.96232400 2.25 464.82 1.97432500 2.25 486.89 1.9853

Overburden Gradient

0

500

1000

1500

2000

2500

3000

0.0000 0.5000 1.0000 1.5000 2.0000 2.5000

EMW - g/cc

Dept

h - m







Figure 10: Overburden Gradients

Pore Pressure Detection

IntroductionEvaluation of pore pressure is limited by current technology and the rocks them-selves. Direct pressure measurement using Wireline RFT/MDT type tools orDrillstring Pressure tests can only be made in permeable formations such assands and some carbonates. No direct readings can be made in impermeable for-mations such as shales. Whilst kicks or blowouts are unlikely to occur in shalesbecause of the limited permeability, severe drilling problems can result fromdrilling close to or underbalance. Contained permeable formations within shalescould lead to kicks or blowouts if the pore pressure profile within shales is notunderstood.

Most indirect detection techniques are based around the Compaction Disequilib-rium (Rapid Loading) model for clays since this produces a gradual increase inpore pressure with depth (Transition Zone) which can, hopefully, be recognisedand evaluated before an underbalanced condition exists. Quantification of porepressure can be made by evaluating behavioural trends in normal pressured situ-ations and looking for diagnostic changes.

Other causes of pore pressure, particularly those that require a better seals, suchas aquathermal pressuring, gas generation or lateral transfer will require recog-nition of the seal and identification of anomalies when drilling through the sealsuch as drill breaks, increases in background gas and connection gas andborehole stability problems. Quantification of pore pressure in these cases is dif-ficult and normally requires comparison of drill rate, gas readings etc. withdrilling fluid characteristics.

MethodologyCompaction disequilibrium in shales can be recognised by a long pressure tran-sition zone. In the North Sea for example there may be many hundreds of metresof gradually increasing pore pressure in Tertiary clay sections from the onset ofoverpressure to the point of maximum development. It is possible to monitor theincrease of pore pressure with depth whilst still maintaining mud overbalanceand making the required changes to mud density before the point of equilibriumwith the static and dynamic (ECD) mud pressure.

The techniques available are:

Rate of Penetration (ROP) When drilling a normally pressured claystone/shale sequence with a constantmud density, ROP would normally be expected decrease with depth. This is dueto compaction and increasing bottom hole differential pressure. The compactingrock will become denser with depth and be more difficult to drill. If a constant



mud weight is used differential pressure on the bottom of the hole will increasemaking it more difficult for drill cuttings to be released into the returning mudstream. Roller cone bits are particularly sensitive to differential pressure; PDCbits less so.

A pressure transition zone will tend to make drilling easier because of the trappedwater reducing compaction and the increase in pore pressure reducing differen-tial pressure; again roller cone bits will tend to show this effect more readily thanPDC bits which will not slow down as much when drilling a normally compact-ing section or speed up as much when drilling the pressure transition zone.

Significant variations in ROP should always be investigated. They may representthe first indications of changing formations, of developing drilling problems ordrilling through a pressure transition zone. It is necessary to evaluate all thepossible causes of ROP variations before reporting any pore pressure changes.As Sir Arthur Conan Doyle’s fictional detective, Sherlock Holmes, said:

“When you have eliminated the impossible, whatever is left, however improbable, must be the truth”.

Factors affecting ROP include:

• Rock Type

• Bit Type

• Dulling Bit

• WOB

• RPM

• Hole Size

• Pump Pressure

• Bit Hydraulics

• Mud Weight/ECD



Drilling Exponents (Dxc)A number of mathematical models have been developed to normalise the drillingrate to a standard set of conditions and to filter out the lithological and drillingengineering variables. This produces a dimensionless drillability index whichindicates whether the rock is becoming easier or more difficult to drill. Drillinginto a pressure transition zone with a constant mud weight would be expected toresult in easier drilling; all other things being equal.

The drilling exponent (Dxc), described below, has been the industry standardtool for a number of years but is not the only one. Geoservices and AGIP devel-oped the SIGMA Log to provide better results in mixed lithologies, includingcarbonates, and Baker Hughes developed the Drilling Model in order to betterreflect the way in which PDC bits drill pressure transition zones.

Figure 1: Differential Pressure

De

pth

Pressure

Differential Pressure

Increasing Differential Pressurewith depth when mud weight &pore pressure gradient remain

constant



Nevertheless, it should be remembered that the Dxc is designed to work withroller cone bits drilling vertical holes through pressure transition zones in under-compacted clays and shales. Outside of these parameters use of the Dxc shouldproceed with extreme caution and results verified with other techniques.

D-exponentThe D-exponent was initially developed by Bingham in 1965 and included some,but not all, of the main influences on ROP when drilling with a roller cone bit.

Bingham (1965)

Bingham’s D-exponent was refined by Jordan and Shirley the following year.They added constants and solved Bingham's original equation for "d", and alsoadded log functions. The most important change made by Jorden and Shirley,however is that they let Bingham's matrix strength constant, "a", be equal to 1.This solved the problem of attempting to define a value for rock strength whencomputing d, but means that changes in formation type will cause shifts in the d-exponent plot which have to be interpreted by the operator.

Jorden and Shirley (1967)

Where:

R = Penetration Rate (ft/hr)

N = RPM

a = Matrix Strength Constant

W = Weight on Bit (lbs)

B =Hole Size (ins)

d =Drilling Exponent

RN---- a W

B-----⎝ ⎠⎛ ⎞ d

=

d

R60N----------log

12W106B------------log

---------------------

⎝ ⎠⎜ ⎟⎜ ⎟⎜ ⎟⎛ ⎞

=



In order to accommodate changes in ROP caused by variations in mud density,Rehm and McClenden proposed the following correction in 1971. This isreferred to as the corrected drilling exponent, or Dxc.

Rehm and McClenden (1971)

Dxc is normally calculated at regular intervals at least every meter, or 5 feet andplotted against TVD on a logarithmic scale. This is done to help make it possibleto use straight trend lines for evaluation since, on a linear scale the normal com-paction trend line in clays would be a curve, (similar to the overburden gradientcurve). Values of Dxc range from about 0.5 to 3.0, and show increasing valuesas drilling becomes more difficult. Easier drilling, as found when penetrating thetransition zone to abnormal pressure in claystones, produces lower values.

Interpretation of Dxc requires the early establishment of a normal formationcompaction trend line to which Dxc values are compared. If the formationremains normally pressured then Dxc values, in claystone, should remain on ornear the normal trend line. Any variation to the left, (lower values), may indicatea transition zone.

Much skilled interpretation is required to be done by the operator, however, sincenot all the drilling parameter variables are included in the Dxc equation, andthose that are do not work perfectly. Changes in lithology will also cause shiftsin the Dxc plot because no matrix strength constant is included. Major changesin rock type will cause obvious shifts which can be ignored (Dxc is respondingto claystone compaction only), but interbedded or mixed lithologies will causescatter of data points making interpretation difficult.

Potential overpressured zones can only be recognised from the Dxc by compar-ing the behaviour of data points in a claystone sequence against the normal com-paction trend line for claystone.

Apart from lithology, the other major causes of trend line shift are:

• Casing Points (hole size; BHA changes)

• Bit Changes

• Bit Types

• Dulling Bits

• Major Changes to Mud Properties

Dxc d Normal FBGECD

-------------------------------⎝ ⎠⎛ ⎞=



• Changes to Mud Hydraulics

• Borehole Inclination

All of the above factors will require the operator to make changes to the normal

compaction trend line in order that proper evaluation be made. It should also berealised that the normal compaction trend line will still be a curve, even whenplotted on logarithmic paper, and that the early, shallow trends established in theupper parts of the borehole will need to be steepened as drilling proceeds. When,and by how much, to steepen trends requires skilled and experienced operatorsotherwise significant errors can be introduced.

Figure 2: Drilling Data Plot



Figure 3: Dxc Plot



Quantitative assessment of Dxc is possible by comparing the actual values tothose that would apply on the normal trend line at that depth. The Ratio Methodcompares the actual and expected values of Dxc multiplied by the Normal For-mation Balance Gradient to estimate the actual FBG.

Dxc Ratio Method:

Where:

FBGactual = Actual (estimated) Formation Balance Gradient

NFBG = Normal Formation Balance Gradient

Dxco = Dxc Observed Value

Dxcn = Dxc Normal Trend Value

FBGactual NFBGDxcnDxco------------⎝ ⎠⎛ ⎞=



Figure 4: Dxc Ratio Method

Normal Shale Trend Line

Equivalent FBG Lines ppg

17 15 13 11 10

Pore Pressure = 12 ppg

Dxc semi-log scale

Dep

th

Sandstone

Dxc Ratio Method

Dxco Dxcn

Dxcn x N.FBG = FBGo Dxco



Figure 5: Dxc Interpretation Problems



Borehole BehaviourDrilling a transition zone will normally result in borehole instability which canbe detected by observing a number of drilling parameters. Drilling close tobalance or even underbalanced may be possible in clays due to their lack of per-meability. Whilst a kick or blow out may not happen immediately, sloughing,spalling and general borehole instability will result.

Increased torque, drag and overpull are all signs of potential abnormal pressure,though they could also indicate mechanical or other formation problems.Whilstthe well may not kick, the borehole walls may be pushed inwards due to thepressure imbalance producing large, curved cavings in much greater volume thanduring normal drilling. Typical these are long, curved, twisted, with concavecross-section, very distinctive from normal cavings. They are sometimes referredto as helicopter blade shaped cavings.

Figure 6: Pressure Cavings

Scale

O.5" to 1.5"

Typically cracked

Blocky Rectangular Shapes

Plan View

Front Side

Front Side

May be striated

Delicate shape

Concave Profile

Plan View

A Typical shale caving caused by underbalanced drilling

B Typical shale caving produced by stress relief



Formation Gas EvaluationThe mud logger's gas detection system can also play a vital role in pressure eval-uation. Background gas values would normally decrease with depth whendrilling a normally pressured claystone sequence because of compaction,increased differential pressure and reduced ROP. Drilling a transition zoneusually leads to a stabilization or slight increase in background gas as the porepressure increases.

As a balanced condition approaches a combination of the loss of ECD when thepumps are turned off, and swabbing pressure when the string is pulled up duringconnections and other off bottom conditions can lead to a small amount of gasbleeding into the borehole. When the pipe is returned to bottom and pumpingresumed a balanced condition exists once again. The gas influx however will becirculated to the surface and detected in the mud logging unit roughly one lagtime after pumping recommenced.

The positive detection of this Connection Gas is a sure indicator that a nearbalance condition exists with respect to the current mud weight, since the loss ofECD and any swabbing pressure reductions produced during the short time of theconnection are likely to be fairly small.

Connection gas peaks usually arrive at the surface one lag time followingresumption of pumping, but may come from a permeable zone near to but not atthe bottom of the hole, and therefore slightly before the normal expected bottomsup time.

Similar gas peaks will occur following trips (Trip Gas) but since the trip has beenongoing for a much longer time interval (many hours perhaps) the significanceof trip gas is not so great. Nevertheless care needs to be taken with detection andevaluation of trip gas peaks since a significant increase in value may also indicatepore pressure increase.

The increased use of top drive rotary systems has lead to increased drilling effi-ciency and enhanced safety (ability to circulate more readily than with kelly sys-tems). However since drilling proceeds with stands of pipe rather than withsingles only one connection is made per stand with a top drive compared withthree per stand when using a kelly system. Thus pressure evaluation using con-nection gas may not be so effective with top drives. Some operators performdummy connections or long connection tests (LCTs) each 30ft (10m) whenapproaching known pressure transition zones to simulate connection gas.



Figure 7: Background & Connection Gas



Gas Ratio AnalysisAnalysis of gas ratios may also be able to help in the detection of overpressures,particularly where compaction disequilibrium is not the dominant mechanism.Holm (1998) has suggested that data from several HPHT wells drilled in theCentral Graben of the North Sea shows gas anomalies with the onset of overpres-sure.

Increasing background and connection gasses are observed in the transition zonebut there is also an increasing wetness to the gas as the very high pressures areapproached. Holm suggests that the gas is migrating from the Jurassic (Kim-meridge Clay) source rocks on an episodic basis as micro fractures occur withvery high pore pressures within the source rocks caused by gas generation andfluid expansion. As the gas migrates away from the source rocks then it becomesincreasingly drier as the lighter gasses are more mobile and thus will travelfurther.

Gas within the Lower Cretaceous rocks such as the Rodby, Hydra, and HerringFormations show very similar gas ratios to the Jurassic source rocks whereas theoverlying Herring Formation has much different ratios indicating generally driergas.

Shale Density Evaluation of drill cuttings density, whilst not accurate enough for overburdengradient calculation is useful to identify clay undercompaction. A plot of shaledensity against true vertical depth can pick out transition zones very effectively,by looking for areas of lower than expected density.

The following diagram illustrates the procedure. The overpressured zone haslower than expected bulk density values. The minimum bulk density value(which represents the maximum overpressure) would normally be expected at amuch shallower depth, the Equilibrium or Equivalent Depth, which can be foundby drawing a vertical line from the depth of interest to the intersection with thenormal compaction trend line.The Equivalent Depth and the depth of interestboth have the same bulk density values and hence the same value of matrix stress(effective stress).

This type of plot can be used to help identify overpressured by qualitative means(looking for low density anomalies) but also quantitatively using Terzaghi’s rela-tionship:

Soverburden pressure σeffective stress Ppore pressure+=



Since the effective stress is the same at both depths we can substitute the valueat the equivalent depth for that at the depth of interest in order to calculate thepore pressure. The effective stress at the equivalent depth can be calculatedbecause we know the overburden pressure and the pore pressure (it’s normal).

Geothermal GradientAbnormally pressured zones will usually cause a disturbance to geothermalgradient since the trapped water is a more effective insulator than rock matrix

Figure 8: Shale Density

P S σ–=



material. A cooling effect will be seen above the overpressured zone as theescaping heat is trapped within.

It is very difficult to measure formation temperature, and in any case equilibriumis disturbed by the drilling process. Mud temperature though is thought toincrease at the same rate as formation temperature as the borehole gets deeperand the mud comes into contact with hotter rocks. A plot of mud temperatureagainst true vertical depth may pick out the cooling effect above and the highergradient within the overpressured zone.

A temperature probe situated in the mud return flowline or the header box behindthe shale shakers will continuously measure the temperature of the returningmud. This Temperature Out measurement is the basis of the evaluation. A plotof Temperature Out should show gradually increasing values according to thelocal geothermal gradient. As the pressure transition zone is approached a reduc-tion in this gradient should be observed. It may, in exceptional circumstanceslead to lower mud temperature readings. On entering the actual overpressuredzone the geothermal gradient increases to a much higher value than the normaltrend for the area. Underneath the overpressured zone, if the pore pressuredeclines to near normal, a normal geothermal gradient is re-established.

This reduction in geothermal gradient occurs above the overpressured zone andtherefore provides some advanced warning of high formation pressures below. Itis the only technique available that can be used a s a predictive tool. All othertechniques require us to be in the overpressured zone observing some change inbehaviour of drilling or geological data.

Whilst overpressured zones can be identified qualitatively by this method, littlecan be done to make any quantitative assessment as to the size of the overpres-sure.

Raw flowline temperature data is subject to fluctuation and error from drillingpractices. Changes in surface temperature caused by pit transfers, mixing mud,adding water or from natural diurnal ambient temperature variations (onshore)will lead to difficulties in the establishment of trends and the interpretation of thedata. Deep, cold water in offshore drilling situations can lead to substantialcooling of the returning mud which may mask any heating that has been applied.Riser cooling may, though, be fairly consistent and, if not drilling in extreme sit-uations, may not have a discernable effect on interpretation.

Tripping, and other non-circulating time will lead to variations in mud tempera-ture. The mud will heat up in the bottom part of the borehole, cool in the marineriser or conductor pipe and in the mud tanks and take some time to reach temper-ature equilibrium on resumption of circulation. Long trips and short drillingintervals will lead to a very segmented plot of raw flowline temperature data.



Some of these problems can be overcome by calculating and plotting lagged tem-perature difference, (∆T). With a dual probe system, the temperature of the mudis measured in the suction pits as well as at the flowline and thus the actualheating that has been applied to a particular packet of mud can be measured. Anysurface influences with therefore be negated. End-to-end and trend-to-trend plotsof flowline temperature data may also help in interpretation. With MWD tools,downhole measured values of mud temperature may be obtained which willovercome problems of riser cooling.

Figure 9: Geothermal Gradient



Wireline and MWD LogsDownhole measured data from petrophysical logs provides powerful back updata for overpressure detection. Wireline data is only available after drilling butwill confirm theories established from drilling and logging parameters, whilstMWD is available real-time alongside traditional data.

Figure 10: Cooling Effect



Resistivity, Density and Sonic logs are the most useful, all providing informationon compaction and porosity for use with the rapid loading model. Care must betaken when using resistivity data since changes in pore water density will changenormal pore pressure gradients which should not be confused with abnormalpressure effects.

Resistivity LogsIn a normally compacting claystone sequence, formation resistivity valuesshould generally increase as the rock becomes less porous. A pressure transitionzone will, therefore, tend to show decreasing values of resistivity as increasedporosity allows the more effective transmission of electrical signals.

Figure 11: Resistivity Log



As with Dxc, a normal trend line can be established for claystone and values ofresistivity compared to it. Caution needs to be taken though as variations in porefluid type will cause shifts in the normal trend. For example, changing from freshto slightly salty pore water will cause a reduction in resistivity values which maylead the operator to suspect, erroneously, that an overpressured zone was beingpenetrated.

Assuming that a normal trend can be established, Eaton's method can be used toquantify changes in pore pressure from resistivity data. This is a combination ofthe Ratio Method and Equivalent Depth Method that uses data only from thedepth of interest.

Eaton's Method:

Where:

P = Pore Pressure

S = Overburden Pressure

Pn = Normal Pore Pressure

Ro = Observed Resistivity value

Rn = Normal trend Resistivity value

1.2 = Exponent (variable)

Sonic LogsSonic log data is some of the best data available for evaluation of formationpressure in claystone sections. The log measures rock compaction and recordsinterval travel time in m sec/foot. A normally compacting claystone showsincreasing density with depth and therefore increased sonic velocity and lowertravel times. Again, a normal compaction trend line can be established andcompared to actual data. Potential overpressured zones will show as areas ofhigher than expected m sec/foot. The equivalent depth method is usually used toquantify changes to pore pressure, assuming that the formation is constant andrepresents a continuous sequence back to the equivalent depth.

P S S P– n( )RoRn------⎝ ⎠⎛ ⎞

1.2–=



Equivalent Depth Method:

Where:

P = Pore Pressure

S = Overburden Pressure at depth of interest

σ = Effective Stress (matrix pressure) at Equivalent Depth

The Equivalent Depth method is used by drawing a line vertically from the pointof interest until it intercepts the normal compaction trend line, thus defining theEquivalent or Equilibrium Depth. The pore pressure and overburden pressurevalues at this depth are used to define the effective overburden pressure, σ1,which, assuming Compaction Disequilibrium to be the dominant cause of theabnormal pressure, has remained constant during burial. The value of σ1 is there-fore the same at the point of interest.

P S σ–=



Figure 12: Sonic Log

4000

5000

6000

7000

8000

9000

10000

11000

10 100 200D

ep

th

∆ µt sec/ft


Fracture Pressure


IntroductionA knowledge of Formation Fracture Pressure is necessary in order to drill thewell both safely and economically. The optimum mud density is sufficient tobalance pore pressure but not so high that hydrostatic, circulating or surge pres-sures would cause the rock to fracture. Measured values of fracture pressure canbe obtained from Leak-Off Tests (LOT) which are normally performed justbelow the casing shoe. With the well shut in, a small volume of mud is pumpedat a low flowrate into the borehole. The imposed pressure within the boreholewill increase as the mud is pumped and will be recorded on a pressure gauge asa linear increase above hydrostatic pressure. As the fracture pressure isapproached fluid will begin to be lost to the formation and the rate of increase ofimposed pressure will reduce. At the point at which the straight line increasebecomes a curve, the mud hydrostatic pressure plus the imposed pumpingpressure is equal to the rock fracture pressure and the test is terminated beforefractures are propagated and irreparable damage is done to the formation.

Figure 1: Leak - Off Test

Gau

ge P

ress

ure

psi

Pump StoppedC

DB

Bleed Off

BBL Mud Pumped1 2 3 Time, minutes

1 2 3 4

Total Pressure at B: Gauge Pressure + Mud Hydrostatic Total Pressure at C: B + Crack Extension Pressure Total Pressure at D: B = D

Leak - Off Test

Fracture Pressure


There is a general tendency for sedimentary rocks to become stronger with depthdue to compaction, so that, mostly, fracture pressure also increases with depth.This is an over simplification however since changes in lithology and porepressure can both cause significant fracture pressure variations. In order not tohave to take further LOTs, (which is both time consuming and potentiallydamaging to the formation), mathematical models are used to estimate variationsin fracture pressure as the well is drilled. All the models used are calibrated fromLOTs, causing pessimistic results when only Formation Integrity Tests (FIT) aremade rather than true leak-off tests. They also suffer by being too simple inapproach and by using empirically derived data that may not always have wide-spread geographical applicability. When used wisely however, and by skilledoperators, the models give useful in-formation and a more accurate view offracture pressure than from LOT data taken at the casing shoe.

Evaluation of Fracture PressureIn a relaxed sedimentary environment, with horizontally bedded rocks and noexternal tectonic stress, the forced acting on a point in the subsurface can beresolved as follows:

• Pore Pressure (P)A non-directional stress which has to be exceeded by the mud pressureif hydraulic fracturing is to be produced

Figure 2: Downhole Stresses

Horizontal stress

Pore Pressure

Effective Stress

Fracture Pressure


• Effective Stress (σ1)This is the matrix or grain stress component of the overburden pressureand will be a vertical stress

• Horizontal StressHorizontal stresses are produced as a result of the vertical effectivestress. In the sub-surface in a confined setting these can be resolved intotwo, mutually perdendicular, stresses. In the absence of any external di-rectional tectonic stresses the magnitude of the horizontal stresses will bethe same, but will be less than the effective stress.

In order to break the rock each of the above stresses has to be exceeded by themud pressure. The pore pressure is known from Wireline or Drillstem Tests,from indirect methods using drilling, geological and petrophysical data or as aresult of the analysis of pressure during well control operations. The effectivestress is computed from the difference between the overburden pressure and porepressure.

The minimum horizontal stress is the most difficult component to quantify, butis usually thought of as being related to the effective stress. Thus a stress ratioco-efficient, F, is included in most models to relate the effective stress to theminimum horizontal stress

The assumptions given above provide the basis for all the commonly usedmodels, and give the general formula:

Where:F = Fracture Pressure k = Effective Stress Ratio S = Overburden Pressure P = Pore Pressure

Hubbert and Willis (1957) These authors worked on data from US Gulf Coast wells, assuming relaxed bedson the point of extensional (normal) faulting. In this case, and determined empir-ically, the effective stress ratio, K, is assumed to be between 1/2 and 1/3 of theprinciple vertical stress, σ1. Fracture Pressure is normally defined as:

F S P–( )k P+=

F S P–( )3

----------------- P+=

Fracture Pressure


Matthews and Kelly (1967) Matthews and Kelly introduced a variable stress coefficient, Ki, into the generalformula as shown above. Values of Ki were obtained by back calculating fromknown LOT results and the establishment of regional values for future wells.

It should be noted that the value of Ki is determined from the depth at which σ1is normal, i.e. the Equivalent Depth, and that alternate calibration curves need tobe established for areas outside the US Gulf Coast region.

Figure 3: Stress Ratio Co-efficient (ki)

F S P–( )ki P+=

Fracture Pressure


Eaton (1969)Eaton decided that rock deformation was elastic, and therefore linked the calcu-lation of K to Poisson’s Ratio. Eaton’s equation for Fracture Pressure is:

Figure 4: Ki using Equilibrium Depth

F S P–( ) µ1 µ–------------⎝ ⎠⎛ ⎞ P+=

Fracture Pressure


Where:µ = Poisson’s Ratioσ1 = Effective Stress

Poisson’s Ratio is the ratio of the lateral unit strain to the longitudinal strain in abody that has been stressed longitudinally within its elastic limits. Eaton decidedthat Poisson’s Ratio for the formation of interest would be mostly controlled bydepth rather than material. Different materials though have specific values ofPoisson’s Ratio which can be determined by acoustic testing looking at thebehaviour of shear waves and compressional waves.

It is difficult however to obtain accurate values for Poisson’s Ratio in the fieldso Eaton’s assumption of a depth related response allows the estimation of Pois-son’s Ratio values once some regional data from offset wells has been estab-lished. Unfortunately, since rock fracture pressure tends to increase with depthEaton’s method tends to show a fairly uniform increase in fracture pressure withdepth in response to gradually increasing Poisson’s Ratios. The values of Pois-son’s Ratio range from about 0.25 - 0.5 (the theoretical upper limit of a liquid).Back calculating values of Poisson’s Ratio from offset data often gives values>0.5 suggesting some error has been introduced or that, perhaps in Eaton’smethod, some other force is being ignored.

Other Methods

Anderson et al. (1973) Having seen that fracture pressure gradients could vary considerably in differentformations at similar depths, Anderson tried to find some way of putting litho-logical variation into his equation. Working from US Gulf Coast data, Andersonthought that the major control on rock deformation was the elastic nature of thematerials, expressed by Poisson’s Ratio.

Rather than assume that Poisson’s Ratio increased uniformly with depth, (asEaton), Anderson attempted to measure it in situ by using wireline log data. Hemade a further assumption that elastic fracture would be primarily controlled, (insandstones at least), by the shale or clay content.

His method involves calculating the shale content from variations in porosityfrom density and sonic logs and using this to calculate a value for m. The methodis somewhat cumbersome to use in the field, and only sand lithologies are con-sidered. It has not, therefore, found widespread application at the wellsite.

Fracture Pressure


Pilkington (1978); Cesaroni et al. (1981); Breckels and van Eekelen (1981) All of these authors were trying to find more accurate ways of determining thestress coefficient, K. The methods are related to specific basins and requireextensive offset data and local knowledge to use their methods successfully.

Daines (1982) This is now one of the most widely used models, albeit with certain limitations.Daines took up the work of Eaton, as uses a similar equation, with certain keyvariations:

• Poisson’s Ratio This is now calculated for rock material rather than depth of burial.Lab-oratory derived data are used, and it is necessary to equate the formationof interest to results shown in the tables given below.

• Tectonic Stress Any additional tectonic stress imposed on the system and not yet ac-counted for can be determined from the results of LOTs and Poisson’sRatio values obtained as above.

Daines’ equation for Fracture Pressure is:

Where:

σt = Superimposed Tectonic Stress σ1 = Effective Stress (S - P) µ = Poisson’s Ratio

The superimposed tectonic stress, σt, is computed from the first LOT usingvalues of µ derived from the tables. To calculate σt at other depths, Dainessuggests a relationship with σ1 that increases uniformly with depth, provided therocks remain in the same geological setting:

F S P–( ) µ1 µ–------------⎝ ⎠⎛ ⎞ P σt+ +=

Fracture Pressure


Suggested Default Poisson’s Ratio DataClay Wet/Soft 0.5

Claystone/Shale Indurated 0.17

Claystone/Shale Calcareous 0.20 - 0.28

Claystone/Shale Sandy 0.1 - 0.14

Limestone Hard 0.28

Limestone Argillaceous 0.17 - 0.25

Sandstone Moderate Cement 0.05

The above figures for Poisson’s Ratio are based on data produced by Weurker inthe 1960s and are for guidance only. Offset or recently derived laboratory or logdata should be used wherever possible.

Inclined BoreholesFracture Pressure determination in inclined boreholes is more complicated anddifficult to evaluate. A knowledge of the stress regime is required and also theanisotropy of the rocks. In general terms, fracture pressure will decrease withincreasing hole angle and mud density requirements to prevent borehole collapsewill increase. This tends to narrow the drilling window between the pore pressureand fracture pressure, especially with horizontal drilling as the ECD willcontinue to increase along the length of the borehole even though TVD (andtherefore fracture pressure and pore pressure) remains essentially constant.

Evaluation of fracture pressure in inclined boreholes is normally established bymini-frac tests and observation rather than by mathematical interpretation.

Fracture Pressure


The above diagram shows the theoretical variation of fracture pressure withincreasing hole angle. The fracture initiation pressure is that force required toinitiate new fractures. The propagation pressure is the force required to extendthese fractures. In low inclination boreholes (<55o) the fracture propagationpressure, once fractures have been initiated and the original force released, is lessthan the original initiation pressure. As the hole angle increases the fracture ini-tiation pressure drops below the fracture propagation pressure. The practicalfracture gradient however will remain at the propagation pressure value sincesmall fractures will only cause a slight and finite volume loss.

Figure 5: Fracture Gradient & Mud Weight in inclined boreholes

18.3

16.3

14.3

12.3

10.3

8.30 30 60 90

Well Deviation (degrees)

Minimum Mudweight Fracture Initiation

Frac

ture

Gra

dien

t ppg

Variation of Fracture Gradient and Minimum Mud Weight with Well Deviation

Fracture Pressure


Inclined Borehole FormulaThe following formula can be used to calculate fracture pressure for inclinedboreholes:

Where:

σ1, σ2 and σ3 are the maximum, intermediate and miniumum stresses;θ is the borehole inclination;T is the tensile strength of the rockP is the pore pressure

Figure 6: Effective Fracture Gradient in inclined boreholes

18.3

16.3

14.3

12.3

10.3

8.30 30 60 9055

Well Deviation (degrees)

Fracture Gradient Fracture Initiation Fracture Propagation

Frac

ture

Gra

dien

t ppg

Variation of Fracture Gradient with Well Deviation

F σ3 3 θ2cos–( ) σ1 θ2sin( )– T P+ +=


Example Reporting Procedures


UK

Revision AApril 2008

APPENDIX 1: Reporting Procedures 3.1 DAILY REPORTING The Morning Geological Report and the Lithlog form the basis of the Wellsite Geologists’ reporting requirements. The report, formatted as a Microsoft WORD document, covers all facets of the rig operations over a 24 hour period and an example of this is shown at the end of this appendix. The report is sent on a daily basis, seven days a week and covers the period 0600 hours to 0600 hours. 3.1.1 Daily Geological Report and Lithlog Information displayed on the front page of the report is largely derived from the Daily Drilling Report. It is essential that no discrepancies exist between the Drilling and Geology reports, especially with respect to depths, daily footage, costs and operational activity. Pay special attention to documentation of hole problems. Obtain a copy of the Drilling Report immediately upon completion after 06:00hrs to assist completion of the relevant sections. Ensure that the Geology Report is complete within one hour of the report time as this will enable transmission to the office within 1 ½ hours of the specified report time (06:00hrs for UKCS operations). The wellsite litholog (refer to Section 2) should as up to date as possible and transmitted to the office at the same time as the Geology Report. 3.1.2 Nomenclature A computerised web-based data and reporting transmission system which is currently provided. The listing below uses the standard nomenclature used for the data types and plots that are posted on the website, and it remains important that it is strictly adhered to for the sake of consistency and facilitating data searches. Daily Drilling Report Daily Geological Report Deviation Survey Digital Data Engineering Log Plot Information

Mud Log Digital Data Mud Log Plot Pressure Log Plot Progress Log PWD Digital Data

Lithlog LWD Digital Data LWD Log Plot LWD Memory Digital Data LWD Memory Log Plot MDT Data

PWD Log Plot Time v Depth Graph Welltest Data Wireline Digital Data Wireline Log Plot

Regional offices may adopt specific guidelines on file naming, and it is the responsibility of the Wellsite Geologist to clarify with the responsible Operations Geologist the exact requirement. Such guidelines should be issued in writing. The generic file naming convention should be as follows; (WELLNAME)_(Data or Report Type)_(Date or Depth) Abbreviations for Data/Report Types Daily Drilling Report DDR (Report number) Date Daily Geological Report DGR (Report number) Date Deviation Survey Digital Data SD Depth Engineering Log Plot MLEL Interval Information info Date Lithlog GL Depth LWD Digital Data LWD_DRT Interval LWD Log Plot LWD_LRT (500 or 200) Interval LWD Memory Digital Data LWD_DM Interval LWD Memory Log Plot LWD_LM (500 or 200) Interval MDT Data MDT Depth Mud Log Digital Data MLDD Interval Mud Log Plot MLML Interval Pressure Log Plot MLPL DepthTVD PWD Digital Data PWDD Depth PWD Log Plot PWDL Depth Time v Depth Graph TDG Date Welltest Data WTD Date Wireline Digital Data WD (Run #_ Tooltype) Depth Wireline Log Plot WL (Run #_ Tooltype) Depth Examples For example, a memory LWD ascii data set from the “12/34-5a” between 2700m and 3100m would be labelled 12/34-5a_LWD_DM_2700-3100m. A realtime 1:500 logplot from the same well and depths would be labelled 12/34-5a_LWD_LRT500_2700-3100m Wireline PEX LAS data from Run 3d from the “Titan-8” well at 12115ft would be labelled Titan-8_WD3d_PEX_12115ft The mudlog from “Saturn-13” between 11000ft and 13000ft would be Saturn-8_MLML_11000-13000ft

The Wellsite Geologist’s Lithlog should commence from the start of the phase with a 100 ft overlap. Mudlogging contractors should supply logs and ASCII data from the start of the phase with a 100ft overlap. LWD contractors should supply logs and ASCII data from at least the start of the drilling run with an initial 100ft overlap, though ideally data should commence also from the start of the phase (note however that slight tool component changes may complicate generation of a consistent data suite). In the event of digital communications not be possible, the Daily Geological Report, Geologists Lithlog and the Mudlog should be transmitted by fax as priority, with digital copies following resumption of communications. 3.1.3 Verbal Reporting During weekdays the Wellsite Geologist will call the Operations Geologist in both the morning and afternoon at prearranged times to be advised by the Operations Geologist, normally 08:00hrs and 15:15hrs. Weekend verbal reporting will be as agreed with the duty Operations Geologist. 3.2 WEEKLY REPORTING A Weekly Geological Report and Weekly Service Company Review should be prepared and issued electronically for Friday 12:00 hrs with a 06:00hrs cut-off, though this can be adjusted dependant on operations. Examples are included at the end of this Appendix. The Weekly Report should contain summaries as opposed to detailed descriptions and include the following: a) Basic well information b) Depth, previous and present, and weekly progress c) Concise operations summary d) Formation tops: prognosed, actual, nature of picks, high or low e) Brief lithology description f) Hydrocarbon shows g) Logging/coring/testing details No logs are normally required specific to the Weekly Report. The Operations Geologist will advise separately otherwise.

Daily Geological Report

Well Information Well Rig Date Report DSS

ABCDEF -1 South Seas Driller 20 March 2009 32 27 RT-MSL (ft) Water Depth Latitude Longitude Pred.Days PTD (ft)

85 295 ft 0 18,478

MD-RT (ft) TVDSS (ft) Progress (ft) Hole Section Section PTD (ft)

17,960 -8999 258 12 ¼” 17,787 Casing OD (ins) Type MD (ft) TVD (ft)

30”/20” -- 600.6 ft 600.6 ft

13 3/8” L-80 72# 3437 ft 3437 ft Costs Dry Hole Test/Completion Total

AFE GBP 4,670,000 GBP GBP 4,670,000

Daily GBP 95,000 GBP GBP 95,000

Cumulative GBP 2,960,000 GBP GBP 2,960,000

Projected GBP 4,670,000 GBP GBP 4,670,000 Present Operation Circulating hole clean & bottoms up sample from 17,960’, to comfirm 9 5/8” casing shoe setting of 17,935’ equal to 35-45’ into the Maureen formation.

Operations Summary Controlled drilled from 17,602 - 17,960’, to pick 9 5/8” casing point in the Maureen formation. Circulated sample as required.

24 Hour Forecast Circulate hole clean for 17,960’ if section TD. Pump out or POOH to 16200’ just above the Balder formation. RIH. Circulate bottoms up. Drop EMS survey barrel. Circulate 30 bbls fordacal LCM pill to bit. POOH two stands pumping & placing LCM on bottom. POOH 3 stands & pump slug. POOH taking surveys to the 13 3/8” casing shoe & take 2 x cluster shots in open hole. Circulate bottoms up & shale shakers clean. Continue to POOH & recover EMS survey barrel. Pull wear Bushings. Rig up to run 9 5/8” - 10 3/4” casing.

Drilling Supervisor: K.Doyle/M. Mateyovsky

Geology Stratigraphy Formation Tops Prognosed (ft) Actual (ft) High

Low Lith Log MDRT TVDSS MDRT TVDRT TVDSS

Top Utsira sandstone 4,646 4,250 4,470 4,223 4,138 112H Lith

Base Utsira sandstone 4,798 4,350 4,638 4,338 4,253 97H Lith

Top Eocene 12,902 7,300 13,065 7,440 7,355 55L MWD

Balder 16,259 8,447 16,163 8,485 8,381 66H MWD

Sele 16,405 8,497 16,307 8,532 8,428 69H MWD

Lista 16,999 8,700 17,100 8,790 8,703 3L MWD

Maureen 17,705 8,941 17,877 9,056 8,970 29L MWD

Maureen sandstone 17,757 8,959 18,000 9,101 9,012 53L MWD

Chalk 18,228 9,120 18,449 9,254 9,168 48H MWD

TD 18,478 9,205 18,700 9,347 9,261 MWD Lithology Summary Interval (ft) Rate of Penetration (ft/hr) Total

Gas (%)

Lithology From To Minimum Maximum Average

17,702 17,890 14.50 95.00 35.00 1.00 Claystone

17,890 17,960 10.70 49.00 23.00 1.16 Claystone, Siltstone Lithology and Show Description 17692 - 17890 CLAYSTONE and TUFFACEOUS CLAYSTONE, with INTERBEDS LIMESTONE and TUFF. CLAYSTONE (90 - 100%): predominantly moderate to dark greenish grey, moderate bluish grey, soft to firm, sub-blocky to blocky, crumbly - flakey, non-calcareous, silty to very finely arenaceous in part, tuffaceous. Also locally greyish brown, dusky brown, soft to firm, sub blocky, non-calcareous, dispersive, silty in part. LIMESTONE (Trace to 40%): pale to moderate yellowish brown, occasional pale grey, firm, blocky, crumbly, brittle in part, microxln, slightly argillaceous in part. TUFF (Trace): pale grey, very light grey, occasional speckled I mottled soft, flakey, ashy, non-calcareous, trace dispersed finely xln pyrite. SANDSTONE (Trace): very fine to occasional fine grain, moderately sorted, sub-rounded to rounded, friable, calcareous cement. 17890 - 17945 ft CLAYSTONE with INTERBEDDED SANDY SILTSTONE. CLAYSTONE (50 - 100%): predominantly dark grey to grey black, also olive black, greenish grey, firm, blocky, brittle, non-calcareous, non to slightly silty, common microlaminae black ?carbonaceous material and disseminated pyrite. SILTSTONE (0 - 50%): light grey, pale yellowish brown, firm, blocky, brittle, very calcareous, very finely arenaceous in part, grading to silty limestone. Slight trace black carbonaceous material. LIMESTONE: (trace): white, pale grey, firm, crumbly, micritic. TUFF (Trace): medium bluish grey, firm, ashy, laminated with dark gry streaks. I -1

Gas Data Interval (ft) Total

Gas Chromatograph

From To Av Max C1 C2 C3 iC4 nC4 C5

17,702 17,890 .995 1.284 7762 160 63 10 21 -

17,890 17,945 1.16 1.279 15118 698 141 13 22 -

Est. Pore Pressure: 11.5 ppg Mud Weight: 14.45 ppg Mud Type: NOVADRIL Remarks Circulated bottoms up from 17702 ft Drilled 17702 to 17712 ft Circulated bottoms up Drilled 17712 17762 ft Circulated bottoms up Drilled 17762 to 17812 Circulated bottoms up Control drilled 17812 to 17900 at 30 ft/hr Circulated bottoms up Drilled 17900 to 17945 ft Circulated bottoms up Drilled 17945 to 17960 ft Circulated bottoms up Top of Lista Formation ‘Hot Shale’ 17776 ft (-8936 ft) Top Maureen Formation from micropalaeo. 17890 ft (-8975 ft) Top Maureen from MWD GR log 17879 ft (-8971 ft) Biostratigraphy Descriptions Samples Taxa Encountered Interpretation 17700 Saccarnmina complanata, Cystammina

globigeriniforrnis, S. spectabilis with massive Oligocene cavings

Late Palaeocene, Lista Formation

17713 Cystammina globigeriniformis common, Rzehakina epigona. Sphaerosiderite

as above

17760 C. globigeriniformis prominent, sphaerosiderite prominent

Basal Lista Formation. suggesting proximity to basal warm shale

17810 C. globigeriniformis common, sphaerosiderite dominant

17880 C. globigeriniformis dominant Basal Lista Formation warm shale microfauna earliest Late Palaeocene. Zone PM14. indicating penetration of the Maureen Formation.

17900 Cenosphaera lenticulans prominent

17910 Cenosphaera lenticularis present as above Survey Data

MDRT (ft) Type INC

(deg) AZI

(deg) TVDRT

(ft) Co-ordinates Vertical

Section (ft)

Dog Leg (deg/100

ft) North (ft) East (ft)

17,723 MWD 70.1 209.1 9,002.9 -11,673.7 -6,284.6 13,259.7 0.1

17,822 MWD 69.9 208.9 9,036.7 -11,755.1 -6,329.8 13,352.7 0.3

17,888 MWD 70.0 208.9 9,059.2 -11,809.3 -6,359.8 13,414.7 0.1

Wellsite Geologist: A. Bikey

ABCDEF-1 : WEEKLY GEOLOGICAL REPORT Friday 25th to Monday 7th March 2009 ( Delayed end-date to incorporate TD logging )

Well : ABCDEF-1 Area : Madejski Report No : 5 Rig : South Seas Driller DSS : 35.875 RT-MSL/WD : 25.9m / 90.1m Depth

: 3235m MD (-3209.1m TVDSS) Last Casing : 9 ⅝" @ 2964m

Progress : 267m – Final well TD OPERATIONS SUMMARY The 9 ⅝” casing was RIH to 2843m, filling every 10 joints and breaking circulation every 500m, prior to landing out at 2964m shoe depth on 5” WDP with the hanger HOP at 114.44m. After circulating the casing volume and pressure testing the cement lines, cementation proceeded thus;

• 40 bbl drill water spacer. • Launch lower dart, mix and pump 49 bbls Class “G” & 35% SiO2 at 12.8 ppg. Mix and pump 55 bbls Class G & 35% SiO2. • Displace surface lines with 10 bbls mud, observe wiper plug shear off. No losses observed. • Displace cement with 674 bbls on rig pumps. No plug bumping observed. No backflow observed, plugs holding.

The seal assembly couldn’t be set and upon pulling out with the CHSART to replace the assembly, some cuttings were observed in the running tool. A mill and flush tool was RIH to clean the hanger seal area and the seal assembly rerun and successfully set, with a 5000 psi pressure-test for 10 minutes. The BOP was pressure-tested as per Dolphin procedures and the wear-bushing set prior to laying out the cement head and 12 ¼” BHA. Surface tests were then performed to the TIW valve, IBOP, kelly hose and mud manifold to 300 / 5000 psi.

8 ½” phase operations commenced with the make up of the 8 ½” phase BHA incorporating a Smith MW9342 Rock bit with 3x15 nozzles (no MWD). The assembly was RIH on 5” drillpipe to 2880m and washed down to the Top of Cement (ToC) at 2930m with 500 gpm. Shoe-track drilling commenced from 2930m with 2-15 klbs WOB, 30-60 rpm and 300-700 gpm flowrate for 1500-3200 psi SPP, making slow initial progress whilst spinning on the unbumped plug. Firm cement was drilled to 2942m followed by a successful casing pressure-test performed to 4200 psi with full returns. The remaining cement, rathole and 2m of new formation was drilled out for the LOT, this being made to 2242 psi with a conditioned 9.5 ppg mud (13.93 ppg EMW).

Drilling in the calcareous claystone of the San Carlos Marls Member continued from 2970m with 15-25 klbs WOB, 80-140 rpm and 400 gpm for 1500 psi SPP averaging a consistent 2-3 m/hr. The lithology became increasingly silty with occasional thin very fine sandstone horizons which caused the penetration rate to become more erratic. From 3071m, drill-rates increased from 3 to 9 m/hr and the drill-break was flowchecked (static) prior to circulating bottoms-up for geological samples. These confirmed the Amposta Formation limestone, the primary reservoir objective of the well, and following surface analysis and consultation with asset and operations team, an additional 10m were drilled with a second bottoms-up circulation. Further UK and Columbian discussions from the evaluation of cuttings and data resulted in drilling operations resuming using parameters of 15-25 klbs WOB, 80-100 rpm and 400 gpm for 1850-2150 psi SPP.

The well final TD was reached at 3235m MDBRT, -3209.1m TVDSS, upon instruction from UK and Colombia, at 08:00hrs, 3rd March 2005. The Tarraco Formation (Casablanca Formation regional equivalent) was penetrated at 3212m, -3186.1m TVDSS from drilling parameter and cuttings analysis, observing 2-4 m/hr drill-rates in the clastic lithology which compared to 4-6 m/hr in a basal dolomitic carbonate band. Upon circulating the hole clean, a wiper trip was made to the 9 ⅝” casing shoe – backreaming the interval 3224m to 3081m – with no hole problems noted running to TD for final circulation, Totco surveying (2° at 3235m) and POOH to surface, racking back the BHA.

Logging operations with Schlumberger wireline commenced as follows;

• Run 3A (PEX-HRLA-GR-HTEN) Log interval: 3235m – 2964m • Run 3B (DSI-FMI-GR-HTEN) Log interval: 3232m – 2964m • Run 3C (VSI-GR) Log interval: 3230m – 1630m

Full details of the operational progress are enclosed in the file ABCDEF-1_Run3_logReport.doc, attached with this report. No operational downtime was recorded. The initial wireline TD was 3239m MD with the 9 ⅝” casing shoe at 2964m.

With maximum bottom-hole thermometer temperatures of 131°C, 137°C and 143.3°C successively recorded from the three runs, a wiper trip was performed to reduce the mud temperature in anticipation of a MDT pretest program to complete the wireline evaluation program. A maximum trip gas of 17.8% was recorded from the Datalog GasWizard. Two further logging runs were performed thus ;

• Run 3D (MDT-GR, 28 pretests) Log interval: 3077m – 3203m • Run 3E (MDT-GR, 1 fluid sample) Log interval: 3080m – 3094m

Temperatures of 148°C were recorded from the thermometers. The fluid sample was analysed on surface and upon consultation with UK and Columbia, the well was formally abandoned. Cementing operations commenced with the running of the 3 ½” stinger on 5” drillpipe. Summary concluded.

GEOLOGICAL SUMMARY

Formation Tops

Prognosed (m) Actual (m) High/ Low (m)

Lith/ Log MDRT TVDS

S MDRT TVDRT

TVDSS

Ebro Sandstone 115.9 -90 116 116 -90.1 0.1L BHA Ebro Claystone 975.9 -950 965 965 -939.1 10.9H Lith

Castellon Shale 2775.9 -2750 2561 2561 -2535.1 214.9H Lith

Amposta 3230.9 -3205 3071 3071 -3045.1 154.9H Lith Tarraco 3336.9 -3311 3212 3215 -3186.1 124.9H Lith Alcanar Conglomerate 3401.9 -3376 Not encountered

Cretaceous 3431.9 -3406 Not encountered TD 3461.9 -3436 3235 3235 -3209.1

LITHOLOGY SUMMARY

Alcanar Group, San Carlos Marls eqv. Member 2968m – 3071m MDBRT Calcareous and increasingly silty CLAYSTONE with thin silty SANDSTONE horizons. Increase in argillaceous SILTSTONE from 2996m to 3050m, then becoming argillaceous. 40% - 80% CLAYSTONE: Light to medium grey, minor brownish grey, soft to moderately firm, predominantly amorphous and dispersed, sub blocky, low silt content, very calcareous to marly, with traces of carbonaceous matter disseminated pyrite and rare glauconite growths, locally abundant planktonic foraminifera – occasionally pyritised, no show. (except 3002m: no visible staining, no direct fluorescence, very slow streaming yellow white / yellow green cut fluorescence with intermittent green white residual ring, no visible residue.) Becoming medium to dark grey brown, dark grey, firm to very firm, blocky to trace subplaty, earthy, slightly mottled, homogenous, very calcareous, micromicaceous with rare trace pyrite, occasional clear angular silty quartz - grading to argillaceous siltstone. 10 – 20% SILTY SANDSTONE: Medium grey with light brownish grey hues, slightly mottled, moderately firm, friable; quartz, silty to very fine, angular to subangular, elongate to subelongate, moderately sorted, calcite grading to matrix

supported calcareous argillaceous cement, very silty in parts, disseminated pyrite and rare traces of carbonaceous matter, rare ferruginous staining, micromicaceous, very poor to no visible porosity, no show. Rare fine to medium, clear and angular loose quartz grains. 10 – 60% ARGILLACEOUS SILTSTONE: Medium grey to grey brown, firm, subblocky to blocky, slightly friable, earthy, homogenous, micromicaceous and calcareously cemented, rare argillaceous matrix, common very fine sand, trace disseminated pyrite, rare trace carbonaceous specks, rarely grading to silty sandstone. Alcanar Group, Amposta Limestone Formation 3071m – 3167m MDBRT Firm packestone, highly fossiliferous biocalcarenitic LIMESTONE with variable bituminous staining. 100% LIMESTONE: Mudstone to generally packestone, common grainstone, recrystallised in parts, off white to very light grey, firm to hard, blocky, brittle in parts with angular fracture, cryptocrystalline matrix when present, dull to pearlescent, occasional discrete dark green glauconite grains, abundant forams, possible recrystallised coral debris, echinoids. No significant visible fractures, poor to no visible porosity. ( Grains formed by bioclasts and reworked limestone, recrystallised, abundant bio calcarenites and biocalciradites, well cemented, common pressure / dissolution seams lined with dark brown to black tarry organic deposits, minor stains in moldic porosity and microfractures. ) SHOWS: 3071-3080m: Traces of dark red-brown to black bituminous staining and flakes only, no visible or cut fluorescence, no odor or residue. 3080-3089m: 20-30% of grains coated with black to brown heavy/tarry organic staining, no direct fluorescence, weak to fair slow pale white streaming cut from cuttings with brown organic stains in microfractures, pale green white UV ring, no visible residue. 3089-3101m: Weak very slow pale green white streaming cut, no direct fluoresence, no UV or visible ring. Below 3101m, no significant cuts. Stain diminishes to 10-15% with rare staining from 3113 - 3122m, trace below 3122m. 3167m – 3212m MDBRT Packstone Limestone with Grainstone to very finely crystalline Dolomitic Limestone. From 3203m to 3215m, strong development of Calcarenite Limestone. 10-30% DOLOMITIC LIMESTONE: Grainstone to crystalline, light brown grey, translucent, hard, blocky and well consolidated, very fine sucrosic crystallinity with loss of original texture, trace calcite cement, grain/crystal supported, non to rarely fossiliferous with undifferentiated debris, very poor to no visible porosity, no fluorescence. Rare trace of light to dark brown intergranular staining from 3182m.

70-90% LIMESTONE: becoming increasingly fossiliferous, biocalcarenite with common recrystallisation. SHOWS: Trace only of dark brown-black bituminous staining, no live oil. No fluorescence. (From 3203m) Trace-80% CALCARENITE LIMESTONE: Cream to off white, firm, occasionally hard, friable, crumbly, coarse quartz grains and occasional dolomite. Quartz: translucent, very fine to medium, angular to subangular, subspherical, poorly sorted. Common bio- and dolomite clasts, strong calcareous cement, clast supported, trace benthonic forams. Alcanar Group, Tarraco Formation (“Casablanca Formation” Eqv Frm) 3212m – 3224m MDBRT Very calcareous, very fine to medium grained, poorly sorted glauconitic SANDSTONE gradational to calcareous sandy SILTSTONE. Glauconite in upper 3m. 10-70% CALCAREOUS SANDSTONE: Light cream brown to brown, rarely dark brown, firm to hard, blocky aggregate, fine to medium, occasionally coarse, subangular, moderately spherical, poorly sorted, strong dolomitic and calcareous cement, cement supported, minor calcareous bioclasts, common coarse glauconite grains in uppermost 3m, rare argillaceous matrix, slightly micaceous, trace pyrite, very poor to no visible porosity, no shows. Trace-80% CALCAREOUS SANDY SILTSTONE: Brown to dark brown, very firm to hard, blocky, earthy, homogenous, strong calcareous cement – dolomitic in parts, rare argillaceous matrix, common very fine sand, micromicaceous in parts. Trace-20% CALCARENITE LIMESTONE: As per previous description. Probable contaminant. 3224m – 3235m MDBRT Calcareous, very fine to fine grained, poorly sorted and well cemented SANDSTONE overlying highly DOLOMITIC LIMESTONE with good traces of CALCAREOUS CLAYSTONE. 25-100% CALCAREOUS SANDSTONE: Light brown, buff to beige, translucent, very firm, friable, quartzose aggregate, very fine to fine, trace medium, angular to subangular, elongate to rarely subspherical, very poorly sorted, strong calcareous and dolomitic cement, grain and cement supported, rare disseminated micropyrite, trace micromicaceous, trace discrete glauconite nodules, rarely grading to arenaceous siltstone, very poor visible porosity, no stain, no shows. 0-30% CALCAREOUS SANDY SILTSTONE: Brown to dark brown, very firm to hard, blocky, earthy, homogenous, strong calcareous cement - dolomitic in parts, rare argillaceous matrix, common very fine sand, micromicaceous in parts. 0-70% DOLOMITIC LIMESTONE: Grainstone to crystalline, translucent very light brown cream, rare off white, developing pale orange hue in basal 1m, hard, blocky to slightly brittle, angular break, dull to glassy, homogenous, trace discrete glauconite fragments, reworked & recrystallised in parts with hydrated soft, amorphous cryptocrystalline mud matrix, trace undifferentiated forams, very poor visible porosity, no shows. Trace-15% CALCAREOUS CLAYSTONE: Light grey, soft, amorphous, plastic, very calcareous, dull, homogenous, hygroturgid, common silty quartz

GAS Interval (m) Total Gas Chromatograph (ppm)

From To Av (%) Max

C1 (AV)

C2 (AV)

C3 (AV)

iC4 (AV)

nC4 (AV)

C5 (AV)

2993 3071 Trace 22 7 3 Trace -- -- Maximum

3031 0.006 45 6 3 3 -- --

3071 3097 0.05 117 15 5 6 Trace -- Maximum

3078 0.103 233 31 10 7 -- 4

3097 3167 0.075 30 3 1 2 -- Trace Maximum

3159 0.110 121 6 -- Trace -- --

3167 3212 0.115 166 7 2 2 Trace -- Maximum

3172 0.153 368 14 Trace -- -- --

3212 3224 0.104 36 5 Trace -- -- -- Maximum

3223 0.132 89 9 3 3 -- --

3224 3235 0.12 100 6 1 -- -- -- Maximum

3231 0.23 170 12 3 -- -- --

Please refer to the lithology descriptions for SHOW INFORMATION. CORING None

WIRELINE LOGGING Please refer to ABCDEF-1_Run3_logReport.doc for full details on the wireline logging operations.

Geologists D. Kitson / Carlos Alberto/ B. Moore

WEEKLY SERVICE COMPANY REVIEW

06:00hrs, Monday 7th March 2009

Wellsite Geologists: D. Kitson / Carlos Alberto Mud logging: SA Logging Inc. MWD None Wireline Schlumberger Well: ABCDEF Country: Colombia Datalog

EQUIPMENT RIGGED UP

COMMENT

Gas Chromatograph Yes C1 – C5 in a 30 second cycle. Calibrated 27/02.

Total Gas Yes Catalytic combustion <5%, >5% TCD. Calibrated 27/02. Part of the Total Gas module Integral to the Total Gas

CO2 Detector Yes

Sample Pump Yes

Gas Wizard Yes Operational below 1600m, on 8th Feb. Factory calibration and checked 27/02.

H2S Detector Yes 1 sensor in ditch line only. On daily basis.

pH and pS Detector Yes Factory calibrated

Depth System Yes Crown block encoder and compensator pulleys

Pit level sensors Yes 6 pits plus Trip tank (ultrasonic sensors). Calibrated 27/02.

Pump stroke counters Yes Proximity switches outside pump body – not ideal

Mud temp sensors Yes In / Out. Daily check. Mud Density sensors Yes In / Out. Daily check.

Mud flow out Yes Flow show sensor (paddle)

RPM sensor Yes Direct from rig TDS Rotary torque sensor Yes On TDS supply

Hook-load sensor Yes OK – Potentiometer clamped onto deadline

Standpipe pressure Yes OK 0 – 5,000-psi

Casing pressure Yes 0 – 10,000 psi, from 8th Feb

Gas Trap Yes One regular gas trap with a spare agitator

Unit pressurisation Yes OK, air intake on top of unit, recommend a longer duct run. 60 seconds depressurisation warning time, 25 minutes purge.

Microscope & light Yes Zoom and Halogen

Geologist’s Monitor Yes PC on SA Logging LAN Company Man’s Monitor Yes PC on SA Logging LAN

Toolpusher’s Monitor Yes PC on SA Logging LAN

Drill Floor Monitor Yes Explosion proof housing Flowback Monitoring software

Yes Based on pit level sensor input, rather than return flow

Mudlogging comments:

No equipment problems reported. The crew are performing well and complying with all requests quickly and efficiently. Data delivery and self-QC of data has been most satisfactory. Morale remains good despite long and tiring rotations.

Correspondance on the correlation between Total Gas Detector and Gas Wizard data has been noted. This is ongoing, illustrated by the 17.8% / 1.3% GW / TGD ratio observed from an intermediary logging wiper trip. The total gas detector position is poor, located in a wide area gumbo-box allowing excessive natural degassing prior to extraction and measurement. The wizard extracts gas from an enclosed conventional flowline.

The logging cabin door needs urgent attention (highlighted by David earlier). However the cabin is being removed from the rig, thus enabling repairs to be made.

Current personnel on-board: Data Engineers : Gabriel Mpensa (replaced Christian Smith 03/03/05) Tiberi Trovia Mud Loggers : Richard Jones

Valentin Viera (replaced Joe Bloggs 03/03/05)

Datalogs’ attempt to minimise personnel utilisation on the project to 3 engineers and 3 mud-loggers has resulted in excessive rotations being worked by Gabriel and Joe in particular (the latter’s crew-change delayed 2 weeks due to the non-appearance of his relief). Whilst appreciating the difficulty of maintaining sufficient crew numbers during busy periods, this is nevertheless poor planning by SA Logging’s management.

Wireline Logging Comments Five runs were successfully completed (see ABCDEF-1_Run3_logReport.pdf ) with zero recorded downtime. Crew members performed their duties efficiently and safely with only minor QC issues resulting from the program. All are recommended. Personnel Engineer on-board during Log suite 3: Engineers: Juan Antonio/Antonio-Twoo Operators : Roger Federer/Andy Murray

Ivan Camacho. VSP Operator : Alan Stubbs MDT Operator : Jason Lee Data Transmission: www.securedata.com

DATE: 26th Feb 27th Feb 28th Feb 1st Mar 2nd Mar 3rd Mar 4th Mar Geo. Morning

report Yes Yes Yes Yes Yes Yes Yes

Geological Field Log No No Yes Yes Yes Yes Yes

Formation Evaluation Log No No Yes Yes Yes Yes Yes

Surface ASCII data (LAS) No No Yes Yes Yes Yes Yes

Pressure Evaluation log No No No No No No No

Drilling Data log No No No No No No No Hydocarbon

Evaluation Log No No No No No No No

Received at the rig:

Mud logging reports Yes Yes Yes Yes Yes Yes Yes

Data transmission Status • Satellite system has been reliable. • Full functionality with POP3 server bgspain.petrolink.net since 2nd Feb 2009. • No direct external line to Geologist. There are two lines present in the Geology /

Mud engineer’s office (+55 977 743325/6 ex 216/9), which are extensions from the office exchange in San Siro. The only direct dial line to the rig is hooked up to a fax in the Company Man’s office (+55 977 744523).


Example Wellsite Geologist’sEnd-of-Well Report


UK

STAG NORTH SEA (UK) Co.

Well: 15/19-6a

Calleva Field

Wellsite Geological Report

Horizontal Production Well

Stag Geological Services Ltd. July 20013 Fortuna Court WELLSITE GEOLOGISTSCalleva Park Cliff Becker Aldermaston Ralph SpoonerReading. RG7 8UB UK Tel: (0118) 982 0151 OPERATIONS GEOLOGISTFax: (0118) 982 0152 David Martin

1

CONTENTS

Page No. 1. INTRODUCTION ................................................................................................................. 2

2. WELL DATA SUMMARY ..................................................................................................... 3

3. FORMATION TOPS ............................................................................................................ 7

4. LITHOSTRATIGRAPHY ...................................................................................................... 8

5. WELL SURVEY DATA......................................................................................................... 14

2

1. Introduction Stag well 15/19-6a was drilled as a horizontal oil producer from slot #4. The well was drilled to access

reserves from the furthest South Eastern part of Area A within the Headley Sandstone. Geological

supervision commenced from 4180ft MDBRT (-2564ft TVDSS).

The 12 1/4” section was kicked-off at 1778ft MDBRT (-1588ft TVDSS) & drilled to 9017ft then a north-

seeking gyro was run to confirm and verify the MWD surveys. The well drilled into the Headley

Sandstone reservoir to a section TD of 9795ft MDBRT (-2905ft TVDSS). This was designed in order to

prevent having shale exposed in the “ratty” section of the top Headley Sandstone in the completed

reservoir section and thus aid a successful gravel pack.

The 8 1/2” section was drilled horizontally from 9795ft to 10884ft. This wellpath drilled a course with

considerable build and turned right to some 100ft right of the planned azimuth by a depth of 10884ft MD.

This resulted in an equivalent “moving up” sequence within the Headley Sandstone, into a more

interbedded or shaly sand and siltstone sequence. The well was therefore sidetracked from 10500ft in the

form of Hz. This wellpath was drilled from 10500ft to 12316ft dropping TVD to find good reservoir sand.

It drilled predominantly through sandy siltstone, therefore the well was sidetracked from 11110ft as Hy

(to a depth of 11675 ft). This well was also sidetracked from 11270ft as Hx, essentially due to the

perceived TVD elevation being too high in the structure, an inability to turn the wellbore left and move

down structure, and encountering the Mid Headley Shale in the roof of LCS. This final wellpath was

drilled from 11270 ft to 12681 ft, the well being swung back “leftwards” to the optimum track through

the Headley Sandstone structure, and maintaining a TVDSS of around –2931 ft. Again more silty

sandstones and siltstones were encountered than anticipated, the well being terminated at 12618 ft (-2932

ft TVDSS), having produced a net sand length of 1645 ft. Having cleaned up the well with a short wiper

trip to the shoe an MDT and calliper log was run on drill pipe.

3

2. WELL DATA SUMMARY Well: 15/19-6a, Hz, Hy and Hx Well Class: Development Well Type: Horizontal Oil Producer Operator: Stag North Sea (UK) Co Partners: NESPC, 15% Location: North Sea, Offshore UK Area: Block # 15/19 Licence: P 234 Field: Headley Slot: #4 Surface: Latitude: 57° 19’ 29.786” N Longitude: 02° 48’ 7.655” E UTM: Zone 31 (CM 3° W) E: 582168.231m N: 6463887.807m Primary Target: Headley Sandstone Rig: Sensco WPP “A” Rig Contractor: Sensco Type: Platform RT - MSL: 155ft. RT - SEABED: 500ft. Water depth: 345ft. H Spud date: 13th March 2001 02:30hrs Hz Spud date: 18th April 2001 08:30hrs Hy Spud date 21st April 2001 02:30hrs Hx Spud date 22nd May 2001 11:00hrs

4

TD Reached: 27th May 2001 11:00hrs. Total depth: Drilled: 12681ft MD (-2932ft TVDSS) HOLE SIZE & CASING DATA: Hole Size Depth Casing Point Casing Diam ppf/wall/grade 26” 500 - 677ft 677ft 26” 270ppf/1.0/X52 20” 677 - 1800ft 1778ft 16” 75ppf/0.395/K55 BTC 12 1/4” 1800 - 9795ft 9747ft 10.3/4 x 55ppf/0.49/L80 NVAM 9.5/8” 40ppf/0.39/L80 NVAM H 8 ½” 9795 - 10882ft - Hz 8 ½” 10500 - 12316 Hy 8 ½” 11110 - 11675 Hx 8 ½” 11270 - 12681

MUD SYSTEM: Interval Mud Weight (ppg) Viscosity(YP) Filtrate (1) Spud Mud; sea water with Gel/Guar Gum Sweeps (Baroid) 500 - 1800ft 8.6 (10.3) --- --- (2) KCl Polymer/Glycol Barite Weighted (Baroid) 1800 - 9795ft 9.6 (11.9) 14 (27) 3.0 (6.0) (3) Baradrill calcium carbonate weighted (Baroid) 9795 – 12681ft 9.2 (9.6) 45(60) 2.0(2.8)

SURVEY LOGS: A Gyrodata pump down gyro was run in inside 16” casing and 12 ¼” open hole section and gave the TD as 13ft TVD low to MWD and 50ft to the right of the MWD.

Run No. Tools run Interval (ft) Date 1 Cased Hole Gyro 500-1778 02/03/01 1 Open Hole Gyro 1778-8750 02/03/01

5

MEASUREMENT WHILE DRILLING LOGS:

LWD: ANADRILL

Run no. Tools Run Interval (ft) Logged Date From - to 20” Hole 1 MWD/GR 1135 – 1735 14/03 – 15/03/01 12-1/4” 2 MWD/GR 1735 – 5537 17/03 – 21/03/01 3 MWD/GR 5537 – 6646 22/03 – 25/03/01 4 RAB/ADN6/MWD/GR 6646 – 9758 28/03 – 03/04/01 8-1/2” 5 RAB/GST/ADN6/MWD 9758 – 10462 15/04/01 – 16/04/01 6 RAB/ADN6/MWD 10462 – 11711 17/04/01 – 25/04/01 7 RAB/ADN6/MWD 11711 – 12661 25/04/01 – 27/04/01 RUN REPORT - MWD Run 6 ran out of memory in the RAB tool at 11520ft so only telemetry data was recorded at surface essentially due to the need to sidetrack in open hole during the run. Run 7 lost communication at 11770ft with the near bit inclination being transmitted from the “short hop” electronics of the Powerdrive in addition to this an apparent failure in communication of the ADN tool, turned out to be a complete tool failure and hence no memory data or telemetry data was acquired from 11951ft to TD of the last side track Hx. CUTTINGS SAMPLES: Drill cuttings samples were collected for 15/19-6a from below the 16” casing shoe at 1778ft to 10880ft in the 8½” hole section. Thereafter they were collected in the 8½” section for wellpath Hz from 10500ft to 12316ft, from 11110ft to 11675ft for wellpath Hy and 11270ft to 12681ft for wellpath Hx. Hole Size (in) Depth Interval (ft) Type Sample Interval 12 ¼” & 8 ½” 1778-10880 1 x 100g 20ft

Washed & Dried 2 x 500g 20ft Unwashed & Wet

Hz Hole Size (in) Depth Interval (ft) Type Sample Interval

8 ½” 10500-12316 1 x 100g 20ft Washed & Dried 2 x 500g 20ft Unwashed & Wet

Hy Hole Size (in) Depth Interval (ft) Type Sample Interval

8 ½” 11120-11675 1 x 100g 20ft Washed & Dried 2 x 500g 20ft Unwashed & Wet

Hx Hole Size (in) Depth Interval (ft) Type Sample Interval

8 ½” 11270-12681 1 x 100g 20ft

6

Washed & Dried 2 x 500g 20ft Unwashed & Wet

SAMPLE DESTINATIONS: Hays Information Management 1 set unwashed & wet Set A Wellheads Crescent Dyce Industrial Park Aberdeen AB2 0HG (Attn: Alan Scott) RPS Palaeo 1 set unwashed & wet Set B Unit 2 Robert Leonard Centre Kirkhill Industrial Estate Dyce AB2 0GL (Attn: P. Mears) The Curator 1 set washed & dried Set C BGS/DTI Core Store 276 Gilmerton Road Edinburgh EH17 7QS. HOT SHOT BIOSTRAT: Hotshot samples that were sent off for analysis were taken 10400ft from the H wellbore, 10860ft, 11060ft, 11760ft, 12000ft, 12180ft from the Hz wellbore. The full biostratigraphy report performed by RPS Palaeo will be included later. BIT DATA: Bit No. Type Size Depth in Depth out Ftg

1RR Smith DSJC 23” 667 709 42

2 HTC GTX-CG1 20” 709 1200 491

2RR HTC GTX-CG1 20” 1200 1800 600

3 Geodiamond MRS89PX 12-¼" 1800 5589 3789

4 Smith M50SPX 12-¼" 5589 6713 1124

5 Smith M50SPX 12-¼" 6713 9795 3082

6 Hycalog DS71 HGJ 8-½” 9795 10462 667

7 Hycalog DS130 DF H 8-½” 10462 10884 422

Hycalog DS130 DF Hz 8-½” 10500 12316 1816

Hycalog DS130 DF Hy 8-½” 11110 11675 565

Hycalog DS130 DF Hx 8-½” 11270 11731 461

7RR1 Hycalog DS130 DF Hx 8-½” 11731 12681 950

7

3. FORMATION TOPS

DEPTH (ft) UTM 3deg W (m) MD TVDSS X Y

Mean Sea Level 155 0

Sea Bed 500 -345

15/19-6aWell

UPPER CRETACEOUS

Top F1 Formation 2570 -2212 572354.69 6463631.35

Top RC Marker 2618 -2241 572364.46 6463625.11

Base RC Marker 2816 -2347 572407.57 6463598.01

Top LF 3503 -2518 572578.27 6463492.14

Top H 5521 -2657 573093.72 6463159.92

LOWER CRETACEOUS

Base S-R 9070 -2880 573983.82 6462551.44

Top Upper Headley Sand 9107 -2882 573993.22 6462545.10

Top Mid Headley Shale 9260 -2889 574031.55 6462518.64

Top Headley Sandstone 9612 -2897 574119.45 6462457.24

Top Intra shale#1 10278 -2902 574288.61 6462339.88

Base Intra shale#1 10439 -2903 574316.10 6462320.17

15/19-6a

Base Mid Headley Shale 11519 -2917 574609.7 6462148.17

TD (in Hx) 12681 -2932 574923.31 6461983.97

8

4. LITHOSTRATIGRAPHY All depths are drilled depths, unless otherwise stated, referred to the rotary table. A top drive system was used. CRETACEOUS Chalk Group LF Formation: 3503ft to 5521ft MDBRT (-2518ft to -2657ft TVDSS) This section consists of chalk limestone, mudstone, and wackestone, more homogeneous, and less

argillaceous than the UF.

The limestone is off white to white, occasionally light to medium grey, rarely red pink, rarely very light

green, soft to firm, locally hard, blocky to subblocky, crumbly, generally cryptocrystalline, also

microcrystalline with no visible porosity, with rare calcite crystals and quartz grains. Minor limestone is

variably argillaceous, as inter-laminations and grades into marl, and there are rare traces of glauconite

and pyrite.

GAS VALUES:

Total Gas (%) C1(ppm) C2(ppm) C3(ppm) IC4(ppm) NC4(ppm)

Maximum Gas 1.70 11084 0 0 0 0

Background Gas 0.20 2500 0 0 0 0

H Formation: 5521ft to 9070ft MDBRT (-2657ft to -2880ft TVDSS) Limestone in this section is commonly argillaceous and marly, is much more variable than the F

Formation, and consequently has more gamma ray character to enable correlation.

The limestone is dominantly off white to cream, locally light brown-yellow to light blue-green, locally

grey, generally soft to firm, locally hard, crumbly in places, subblocky to subangular, mudstone to

wackestone, microcrystalline to cryptocrystalline, with local argillaceous laminations and trace

glauconite. The marl is soft to firm, slightly glauconitic & in places inter-laminated with the limestone.

The marl is more abundant & argillaceous with depth.

Thin variously calcareous claystone stringers are present, predominantly towards the top of the section

and are generally grey to dark grey-brown and locally blue-green and red-brown whilst the darker

varieties are moderately silty, increasingly so with depth.

GAS VALUES:


Maximum Gas 0.74 7425 204 0 0 0


9

LOWER CRETACEOUS CK Group Base Chalk S_R Formation: 9070ft to 9107ft MDBRT (-2880ft to -2882ft TVDSS) This interval consists of a varicoloured claystone. The samples were heavily contaminated with chalk

limestone from the above formation.

The claystone is green, light green, very pale green, yellow-brown, brick red, purple, soft to firm,

amorphous to subblocky, slightly silty, and none calcareous.

GAS VALUES:


Maximum Gas 0.156 1194 0 0 0 0


Valhall Formation Upper Headley Sand: 9107ft to 9260ft MDBRT (-2882ft to –2889ft TVDSS) Though not anticipated, a thin section of the Upper Headley Sand was encountered on the well track. It

comprises clean unconsolidated friable sand.

The sand is colourless quartz, locally very pale brown-pink, is transparent to translucent, fine to medium

grained, though locally coarse or very coarsely grained, is subangular to rounded, though generally

subrounded to rounded and has moderate sphericity. It has moderate to poor sorting, has weak calcareous

cement, and shows very good visual porosity. A light brown oil stain is observable on most grains, these

showing a pale yellow fluorescence and produce a slow diffuse blue-white cut.

GAS VALUES:


Maximum Gas 7.383 21966 2823 572 101 12

Background Gas 0.48 4922 65 0 0 0

10

Mid Headley Shale: 9260ft to 9612 ft MDBRT

(-2889ft to –2897ft TVDSS)

This section is one of claystone with minor sandstone between 9325 ft and 9340 ft MD, which did show a

poor hydrocarbon show and dull yellow fluorescence.

The claystone is grey to dark grey, locally grey-green to dark grey-green, and is very silty, locally grading

to fine sand. It is locally slightly calcareous, locally micaceous, and contains carbonaceous fragments.

The sand is colourless quartz, locally very pale brown-pink. It is transparent to translucent, generally fine

to medium grained, though locally coarse or very coarse. In shape the grains are subangular to rounded,

though generally subrounded to rounded, exhibit moderate sphericity, and are moderately to poorly

sorted. Sandstone occasionally appears in cuttings, with weak calcareous cement and exhibiting good

visual porosity. No oil stain was noted. 40% of cuttings have pinpoint dull to moderate yellow

fluorescence, and there is no cut.

GAS VALUES:


Maximum Gas 1.606 11521 671 65 6 0

Background Gas 0.348 4736 65 0 0 0

Headley Sandstone: 9612ft to 10884ft MDBRT (-2897ft to –2888ft TVDSS) This section comprises generally clean, unconsolidated, sand however towards the top of LHS2 there is a

“shaly” interbedded sequence in which siltier sand grades to a silty claystone.

The sand is primarily quartz, which is clear or very pale brown, locally very pale grey and pale pink.

Very rarely slightly feldspathic seen as pink-orange to light grey grains. It is transparent to translucent,

locally with polished and frosted grains, is generally fine to medium grained, though is rarely coarse. The

grains are subangular to subrounded, generally subrounded to rounded, exhibit good sphericity, and are

moderate to well sorted. Sandstone occasionally appears with weak calcareous cement, shows good visual

porosity, excellent inferred porosity, and has traces of glauconite and pyrite. Moderate light brown oil

stain, good to fair pale yellow to bright yellow fluorescence, slow to very slow diffuse cut of blue-white

to yellow-white.

GAS VALUES:


Maximum Gas 9.008 22227 2291 570 13 6

Background Gas 0.537 8079 152 4 0 0

11

Headley Sandstone:

Intra Shale#1 10278ft to 10439ft MDBRT (-2902ft to –2905ft TVDSS) This section comprised soft grey silty claystone.

The claystone is generally grey-brown locally dark grey-brown, generally soft, rarely firm, predominantly

exhibiting a subblocky break. Generally silty throughout but locally increasingly silty and locally grades

to siltstone. Varying from slightly to moderately calcareous, trace minerals included varying amounts of

glauconite and mica.

GAS VALUES:


Maximum Gas 0.435 6266 64 0 0 0

Background Gas 0.25 2800 15 0 0 0

SIDETRACK Hz

Headley Sandstone: 10500ft to 12316ft MDBRT (-2903ft to –2920ft TVDSS) This section comprises generally clean unconsolidated sand however towards the top of LHS2 there is a

“shaly” interbedded sequence in which more silty sands grade to a silty claystone.


Very rarely slightly feldspathic seen as pink-orange to light grey grains. The sand grains are transparent

to translucent, locally with polished and frosted grains, are generally fine to medium sized, though are

locally coarse to very coarse with rare granules. The grains are subangular to subrounded, generally

subrounded to rounded, exhibit good sphericity, and are moderate to well sorted. It occasionally occurs as

sandstone with weak calcareous cement, shows good visual porosity and excellent inferred porosity, and

has traces of glauconite and pyrite. Having a moderate light brown oil stain, good to fair pale yellow to

bright yellow fluorescence, slow to very slow diffuse cut of blue white to yellow white.

GAS VALUES:


Maximum Gas 5.97 19946 2034 325 0 0

Background Gas 1.53 11323 536 23 0 0

12

SIDETRACK Hy

Headley Sandstone: 11110ft to 11519ft MDBRT (-2906ft to –2917ft TVDSS) This section comprises interbedded clean unconsolidated sand with silty claystone. Good shale was

observed at 11519ft to 11580ft which having had a provisional micropalaeontological analysis of shale’s

in the previous Hz well bore placed those as basal Mid Headley Shale or Topmost Headley Sandstone.


Very rarely slightly feldspathic seen as pink-orange to light grey grains. The sand grains are transparent

to translucent, locally with polished and frosted grains, is generally fine to medium sized, though it is

locally coarse to very coarse with rare granules. The grains are subangular to subrounded, generally

subrounded to rounded, exhibit good sphericity, and are moderate to well sorted. It occasionally occurs as

sandstone with weak calcareous cement, shows good visual porosity and excellent inferred porosity, and

has traces of glauconite and pyrite. Having a moderate light brown oil stain, good to fair pale yellow to

bright yellow fluorescence, slow to very slow diffuse cut of blue-white to yellow-white.

GAS VALUES:


Maximum Gas 6.66 21762 2338 421 10 12

Background Gas 2.25 7875 402 45 0 0

Mid Headley Shale: 11519ft to 11675ft MDBRT (-2917ft to –2918ft TVDSS) This section is predominantly claystone that grades to siltstone at the very base. It was encountered from

below as the well bore moved up section into the Mid Headley Shale.

The claystone is grey to dark grey, predominantly soft with an amorphous break. Much of the claystone is

sandy/silty and micaceous in parts, and slightly calcareous. Locally the claystone graded to siltstone.

The siltstone is grey to dark grey and locally grey green, generally soft with an amorphous break. In parts

it is very sandy and very micaceous, non- to slightly calcareous.

GAS VALUES:


Maximum Gas 1.50 9311 357 57 0 0

Background Gas 0.39 3335 31 0 0 0

13

SIDETRACK Hx

Headley Sandstone: 11270ft to 12681ft MDBRT (-2914ft to –2932ft TVDSS) This section comprises a predominantly sand rich sequence with local interbeds of siltstone, which are

interpreted as the “shaly” interbedded top-most Headley Sandstone. However below a 160ft thick

siltstone drilled between 11890ft and 12050 ft, the character of the LHS changes from predominantly

sand rich to a siltstone rich sequence with small interbeds or stringers of sand.

The sand is primarily quartz, which is clear or very pale brown, locally very pale grey and pale pink. It is

very rarely slightly feldspathic, seen as pink-orange to light grey grains in cuttings samples. The sand

grains are transparent to translucent, locally with polished and frosted grains, is generally fine to medium

sized, though it is locally coarse to very coarse with rare granules. The grains are subangular to

subrounded, rarely subplatey, exhibit good sphericity, are moderate to well sorted. Sandstone

occasionally occurs as with weak calcareous cement, shows good visual porosity and excellent inferred

porosity, and has traces of glauconite and pyrite. There is a trace to moderate to light brown oil stain,

pinpoint to uniform, good to fair, pale yellow to bright yellow fluorescence, very slow to moderate

diffuse cut of blue-white to yellow-white.

The siltstone is grey to dark grey and locally grey-green, generally soft with an amorphous break. In parts

it is very sandy and very micaceous, none to slightly calcareous becoming moderately calcareous below

12000ft.

GAS VALUES:


Maximum Gas 4.92 19364 2206 360 42 780

Background Gas 0.70 5131 155 0 0 0

14

WELL SURVEY DATA

Stn Depth INC AZI TVD Vert Sect Northing Easting DLS

TIP 1729 24.74 121.64 1698.33 222.68 6463714.01 572227.82 MWD 1990 31.18 124.54 1929.57 343.36 6463694.00 572258.67 2.85 MWD 2084 34.14 123.46 2008.70 394.07 6463685.36 572271.48 3.21 MWD 2180 37.46 123.90 2086.55 450.21 6463675.87 572285.72 3.47 MWD 2268 39.99 123.07 2155.20 505.25 6463666.62 572299.71 2.93 MWD 2367 43.09 122.61 2229.29 570.90 6463655.77 572316.52 3.15 MWD 2463 46.85 122.69 2297.20 638.73 6463644.62 572333.92 3.92 MWD 2559 50.95 122.50 2360.29 711.06 6463632.75 572352.49 4.27 MWD 2653 54.92 122.68 2416.94 786.05 6463620.44 572371.74 4.23 MWD 2748 59.03 121.75 2468.70 865.67 6463607.51 572392.27 4.40 MWD 2842 62.84 122.03 2514.36 947.81 6463594.29 572413.52 4.06 MWD 2937 66.70 121.84 2554.84 1033.72 6463580.44 572435.74 4.07 MWD 3031 70.54 122.07 2589.11 1121.22 6463566.33 572458.36 4.09 MWD 3126 74.55 121.62 2617.60 1211.81 6463551.76 572481.82 4.25 MWD 3220 78.43 121.88 2639.55 1303.18 6463537.11 572505.49 4.14 MWD 3315 82.34 121.92 2655.42 1396.81 6463522.03 572529.72 4.12 MWD 3408 85.11 121.54 2665.58 1489.23 6463507.22 572553.67 3.01 MWD 3503 85.62 121.47 2673.26 1583.89 6463492.14 572578.27 0.54 MWD 3599 86.08 121.29 2680.20 1679.60 6463476.95 572603.18 0.51 MWD 3687 86.37 121.22 2686.00 1767.38 6463463.07 572626.05 0.34 MWD 3779 86.51 120.87 2691.71 1859.15 6463448.64 572650.02 0.41 MWD 3882 86.48 120.62 2698.01 1961.89 6463432.63 572676.94 0.24 MWD 3977 86.23 120.90 2704.05 2056.63 6463417.85 572701.77 0.39 MWD 4074 85.85 121.85 2710.75 2153.36 6463402.50 572726.94 1.05 MWD 4167 85.62 121.64 2717.66 2246.09 6463387.63 572750.97 0.33 MWD 4264 85.59 122.32 2725.10 2342.79 6463372.03 572775.97 0.70 MWD 4357 85.71 122.41 2732.15 2435.52 6463356.90 572799.83 0.16 MWD 4451 85.68 123.28 2739.21 2529.25 6463341.41 572823.83 0.92 MWD 4546 85.82 123.42 2746.25 2623.99 6463325.54 572847.94 0.21 MWD 4642 86.25 123.97 2752.89 2719.75 6463309.35 572872.22 0.73 MWD 4733 86.37 124.29 2758.74 2810.54 6463293.83 572895.12 0.37 MWD 4826 86.66 124.52 2764.39 2903.33 6463277.85 572918.46 0.40 MWD 4924 86.74 124.64 2770.04 3001.13 6463260.93 572943.00 0.15 MWD 5017 86.54 124.66 2775.49 3093.92 6463244.84 572966.28 0.22 MWD 5113 86.34 124.04 2781.45 3189.71 6463228.37 572990.38 0.68 MWD 5207 86.05 123.94 2787.69 3283.48 6463212.39 573014.07 0.33 MWD 5302 85.68 123.46 2794.54 3378.22 6463196.38 573038.09 0.64 MWD 5396 85.54 123.25 2801.73 3471.94 6463180.67 573061.95 0.27 MWD 5489 85.05 123.02 2809.36 3564.63 6463165.24 573085.59 0.58 MWD 5539 84.53 123.54 2813.90 3614.42 6463156.91 573098.28 1.47 MWD 5630 86.20 124.59 2821.25 3705.10 6463141.43 573121.17 2.17 MWD 5723 86.54 124.57 2827.14 3797.87 6463125.38 573144.46 0.37 MWD 5810 86.54 124.61 2832.39 3884.68 6463110.36 573166.24 0.05 MWD 5899 86.63 124.69 2837.69 3973.48 6463094.97 573188.51 0.14 MWD 5989 86.88 124.87 2842.79 4063.28 6463079.35 573211.00 0.34

15


MWD 6080 87.17 124.67 2847.51 4154.11 6463063.56 573233.74 0.39 MWD 6173 87.40 125.04 2851.92 4246.95 6463047.38 573256.97 0.47 MWD 6263 87.57 124.57 2855.87 4336.81 6463031.75 573279.46 0.55 MWD 6356 87.80 125.03 2859.62 4429.68 6463015.59 573302.71 0.55 MWD 6449 87.14 124.01 2863.73 4522.55 6462999.54 573326.04 1.31 MWD 6540 87.34 124.45 2868.11 4613.42 6462983.97 573348.94 0.53 MWD 6631 87.17 124.04 2872.47 4704.29 6462968.38 573371.83 0.49 MWD 6782 86.22 122.73 2881.17 4855.03 6462943.11 573410.18 1.07 MWD 6874 86.16 122.49 2887.29 4946.82 6462928.03 573433.74 0.27 MWD 6964 85.93 122.74 2893.49 5036.61 6462913.29 573456.79 0.38 MWD 7056 85.93 122.09 2900.02 5128.37 6462898.30 573480.39 0.70 MWD 7147 86.04 121.71 2906.40 5219.14 6462883.68 573503.87 0.43 MWD 7237 85.93 121.52 2912.70 5308.89 6462869.34 573527.17 0.24 MWD 7327 85.62 121.47 2919.33 5398.62 6462855.05 573550.49 0.35 MWD 7417 85.24 121.99 2926.50 5488.32 6462840.68 573573.74 0.71 MWD 7506 85.21 122.36 2933.91 5577.00 6462826.29 573596.61 0.42 MWD 7598 85.36 122.63 2941.47 5668.69 6462811.28 573620.17 0.33 MWD 7693 85.70 122.27 2948.87 5763.40 6462795.80 573644.53 0.52 MWD 7784 87.99 122.20 2953.88 5854.25 6462781.03 573667.94 2.52 MWD 7870 88.99 121.43 2956.15 5940.20 6462767.22 573690.20 1.47 MWD 7966 88.42 121.65 2958.32 6036.15 6462751.92 573715.13 0.64 MWD 8057 87.85 122.61 2961.28 6127.09 6462737.18 573738.59 1.23 MWD 8145 87.48 124.09 2964.86 6215.01 6462722.46 573760.97 1.73 MWD 8234 87.16 124.66 2969.03 6303.89 6462707.16 573783.33 0.73 MWD 8325 86.79 124.54 2973.83 6394.72 6462691.44 573806.12 0.43 MWD 8415 86.39 123.93 2979.19 6484.52 6462676.04 573828.75 0.81 MWD 8510 86.11 123.86 2985.39 6579.30 6462659.93 573852.73 0.30 MWD 8606 86.22 123.57 2991.82 6675.08 6462643.73 573877.01 0.32 MWD 8692 86.31 123.48 2997.42 6760.89 6462629.29 573898.80 0.15 MWD 8783 86.02 123.61 3003.50 6851.69 6462614.00 573921.86 0.35 MWD 8874 86.22 123.95 3009.66 6942.47 6462598.62 573944.85 0.43 MWD 8962 86.56 123.85 3015.20 7030.28 6462583.70 573967.07 0.40 MWD 9054 86.73 124.12 3034.30 7118.21 6462554.18 573979.89 0.35 MWD 9147 87.73 124.62 3038.80 7211.07 6462538.20 574003.25 1.20 MWD 9238 87.45 124.66 3042.62 7301.95 6462522.45 574026.04 0.31 MWD 9327 88.39 124.67 3045.85 7390.84 6462507.04 574048.33 1.06 MWD 9415 88.96 125.00 3047.89 7478.77 6462491.73 574070.33 0.75 MWD 9508 88.99 125.20 3049.55 7571.68 6462475.44 574093.51 0.22 MWD 9598 88.68 124.93 3051.38 7661.60 6462459.68 574115.95 0.46 MWD 9692 87.28 124.58 3054.70 7755.49 6462443.37 574139.47 1.54 MWD 9717 87.19 125.04 3055.90 7780.45 6462439.02 574145.72 1.87 MWD 9740 87.68 125.14 3057.61 7803.27 6462435.00 574151.44 0.00 MWD 9825 90.00 124.53 3059.33 7888.19 6462420.21 574172.70 2.82 MWD 9918 90.83 124.39 3058.66 7981.15 6462404.18 574196.06 0.91 MWD 10010 92.29 125.53 3056.15 8073.05 6462388.12 574219.02 2.01 MWD 10108 90.63 124.15 3053.66 8170.95 6462371.07 574243.52 2.20 MWD 10199 87.60 124.53 3055.06 8261.89 6462355.43 574266.41 3.36

16


MWD 10292 89.34 125.53 3057.54 8354.79 6462339.17 574289.61 2.16 MWD 10384 89.91 125.74 3058.15 8446.67 6462322.84 574312.39 0.66 MWD 10459 90.14 125.44 3058.11 8521.58 6462309.54 574330.97 0.50 MWD 10547 91.89 122.35 3056.55 8609.54 6462294.59 574353.22 4.03 MWD 10640 93.17 119.65 3052.45 8702.39 6462280.02 574377.48 3.21 MWD 10726 92.34 117.17 3048.31 8788.03 6462267.56 574400.50 3.04 * 10884 91.20 114.00 3043.43 8944.68 6462246.79 574443.90 2.13

*Projection at TD of H original wellbore

SIDETRACK Hz Stn Depth INC AZI TVD Vert Sect Northing Easting DLS

MWD 10459 90.14 125.44 3058.11 8521.58 6462309.54 574330.97 0.50 MWD 10551 89.37 123.15 3058.51 8613.54 6462293.75 574354.13 2.63 MWD 10641 88.34 119.89 3060.31 8703.49 6462279.42 574377.50 3.80 MWD 10730 88.23 118.17 3062.97 8792.25 6462266.26 574401.20 1.94 MWD 10822 88.66 117.30 3065.47 8883.86 6462253.22 574426.00 1.05 MWD 10913 91.26 116.68 3065.53 8974.38 6462240.64 574450.70 2.94 MWD 11003 92.00 116.19 3062.97 9063.79 6462228.44 574475.25 0.99 MWD 11081 90.66 115.82 3061.16 9141.22 6462218.02 574496.60 1.78 MWD 11181 90.49 117.56 3060.16 9240.64 6462204.34 574523.82 1.75 MWD 11277 94.58 121.03 3055.91 9336.34 6462190.04 574549.30 5.58 MWD 11365 90.57 120.30 3051.96 9424.17 6462176.39 574572.34 4.63 MWD 11456 91.31 122.09 3050.46 9515.12 6462162.03 574596.05 2.13 MWD 10551 89.37 123.15 3058.51 8613.54 6462293.75 574354.13 2.63 MWD 10641 88.34 119.89 3060.31 8703.49 6462279.42 574377.50 3.80 MWD 10730 88.23 118.17 3062.97 8792.25 6462266.26 574401.20 1.94 MWD 10822 88.66 117.30 3065.47 8883.86 6462253.22 574426.00 1.05 MWD 10913 91.26 116.68 3065.53 8974.38 6462240.64 574450.70 2.94 MWD 11081 90.66 115.82 3062.71 9141.26 6462218.00 574496.61 0.62 MWD 11181 90.49 117.56 3061.71 9240.68 6462204.32 574523.83 1.75 MWD 11277 94.58 121.03 3057.46 9336.38 6462190.03 574549.30 5.58 MWD 11365 90.57 120.30 3051.96 9424.17 6462176.39 574572.34 4.63 MWD 11456 91.31 122.09 3050.46 9515.12 6462162.03 574596.05 2.13 MWD 11545 88.86 121.17 3050.33 9604.09 6462147.81 574619.14 2.94 MWD 11637 89.03 120.20 3052.03 9696.01 6462133.50 574643.24 1.07 MWD 11729 87.34 118.67 3054.94 9787.80 6462119.74 574667.64 2.48 MWD 11805 87.91 117.02 3058.09 9863.45 6462108.93 574668.10 2.30 MWD 11907 90.06 117.70 3059.90 9964.96 6462094.65 574715.69 2.21 MWD 12000 89.69 119.42 3060.10 10057.71 6462081.10 574740.58 1.89 MWD 12091 89.57 120.04 3060.69 10148.57 6462067.35 574764.66 0.69 MWD 12182 86.57 117.99 3063.75 10239.31 6462053.91 574788.89 3.99 * 12316 84.19 118.00 3074.54 10372.39 6462034.81 574824.82 1.78

* Projected survey at TD of well track 13/22a-Hz.

17

SIDETRACK Hy

Stn Depth INC AZI TVD Vert Sect Northing Easting DLS MWD 11186 86.71 116.19 3063.57 9245.44 6462204.00 574525.34 3.78 MWD 11277 86.83 120.04 3068.70 9335.97 6462190.96 574549.76 4.23 MWD 11368 89.30 125.45 3071.77 9426.88 6462175.97 574573.05 6.53 MWD 11456 90.74 128.12 3071.74 9514.65 6462159.92 574594.53 3.45 MWD 11545 90.26 127.07 3070.97 9603.34 6462143.38 574616.01 1.30 * 11675 87.60 124.00 3073.39 9733.14 6462120.36 574648.23 3.12

* Projected survey at TD of well track 15/19-6a.

SIDETRACK Hx Stn Depth INC AZI TVD Vert Sect Northing Easting DLS

MWD 11278 86.40 119.52 3069.10 9336.91 6462190.93 574550.08 3.63 MWD 11366 85.25 120.60 3075.51 9424.58 6462177.53 574573.22 1.79 MWD 11456 87.97 121.93 3080.83 9514.38 6462163.33 574596.62 3.36 MWD 11546 89.31 119.85 3082.96 9604.30 6462149.25 574620.15 2.75 MWD 11636 88.29 118.81 3084.85 9694.11 6462135.82 574644.05 1.62 MWD 11694 86.71 118.97 3087.38 9751.96 6462127.29 574659.51 2.74 MWD 11792 87.11 119.45 3092.66 9849.62 6462112.74 574685.53 0.64 MWD 11884 88.11 119.34 3096.50 9941.37 6462099.00 574709.93 1.09 MWD 11976 91.00 118.51 3097.21 10033.13 6462085.44 574734.46 3.27 MWD 11976 91.00 118.51 3097.21 10033.13 6462085.44 574734.46 3.27 MWD 12069 95.13 114.48 3092.24 10125.39 6462072.82 574759.78 6.20 MWD 12158 94.17 115.78 3085.02 10213.28 6462061.34 574784.25 1.81 MWD 12249 92.57 117.67 3079.67 10303.59 6462048.90 574808.97 2.72 MWD 12340 90.31 118.00 3077.39 10394.20 6462035.95 574833.48 2.51 MWD 12434 90.09 118.94 3077.06 10487.92 6462022.30 574858.65 1.03 MWD 12522 87.60 119.71 3078.83 10575.73 6462009.17 574882.02 2.96 MWD 12614 86.36 121.91 3083.68 10667.53 6461994.84 574906.07 2.74 * 12681 87.40 122.50 3087.33 10734.43 6461983.97 574923.31 1.78

* Projected survey at TD of well track 13/22a-Hx.

SmithToolIADC 111

Type

DSJSize

24"(609.6mm)

10464;Drilling ApplicationsDrilling ApplicationsDesigned for soft-formation, top-hole drilling in low-strength, unconsolidated clays, sands and silty marine sediments. Typically usedas a spud bit.

9744;Design SpecificationsDesign SpecificationsBearing Type Open RollerSeal TypeJournal Angle 32-1/2ºOffset 3/8"Number of Rows 11Number of Teeth 144Bit Connection Type 7-5/8" Reg.

9744;General Operating ParametersGeneral Operating ParametersWeight-on-bit Lbs. 20,000 to 45,000 daN 8,896 to 20,017 Tonnes 9 to 20Rotary Speed 70 to 180 rpm

3240|360|6144;Features||Benefits;Features BenefitsAggressive cutting structure Maximizes ROP in medium-soft formations and maintains cutting structure integrity in

formation changes.

Maximum offset Allows drilling at high ROP in speed-responsive formations.

Non-sealed roller Low-cost bearing capable of high speeds for short runs.

DbP970820140250 - Smith Tool Technical Services Rock Bit Database v 3. 1. 24

Options

Special options are available upon request.

Picture may one or more of the available options.

12-1/4" M50IADC Code: M433

Design Specifications

Total Cutters: 70

Cutter Size: 13mm (1/2")

Face: 64

Gage: 6

Nozzles: 6 Series 60N

Junk Slot Area: 36.3 in. sq.

Gage Length: 3.0"

Gage Protection: Options Available

Make-Up Length: 12.6" Overall: 18.1"

Bit Connection: 6-5/8" API Regular

Fishing Neck: Diameter 8.0" / Length 5.6”

Operating Parameters

Rotary Speed: Suitable for Rotary, PDM & Turbine

Weight-on-Bit: 6,000 - 50,000 LBS

Flow Rate: 500-800 GPM

Hydraulic Horsepower: 1.0 - 6.0 HSI

Features

Advanced Cutter Placement

Force Balanced

Unsymmetrical Blade Layout

Spiraled Blades and Gage

Geo-data.0365-01.03981998 Smith International. All rights reserved.©

ER 906

The M50 is a matrix body bit designed with stability enhancing features. Applications ranging from

medium soft to medium hard formations. Good for transitional and directional drilling.

Reed-Hycalog Steerable Rotary Bits Brochure

Control and performance for steerable rotary drilling

The Reed-Hycalog Steerable Rotary Bit (SRB) family provides PDC performance and roller cone control in steerable rotary drilling applications. The design is engineered to meet the unique requirements of rotary steerable systems based on thrust pads, today's market leading technology.

Building on the success of the Hycalog DS130, the industry's first rotary steerable bit, the SRB series enhances tight radius drilling with aggressive, durable bits that yield high rates of penetration.

Product Features

• Low Aspect

Reed-Hycalog Steerable Rotary Bits Drill tight-radius wellbores with rotary steerable systems

Tight radius wellbores The SRB family of PDC bits for steerable rotary drilling employs the Hycalog Low Aspect Ratio (LAR*) design for a very short overall length and a short, aggressive gauge to provide a distinct advantage in drilling tight radius wellbores.

The 8 1/2 in. DS130, for example, has an overall length of only 6.8 inches. Because the bit is shorter, the distance between the displacement pads on the steering tool and the bit force on the rock is reduced. The distance between these points defines the hole's curvature. When this distance is as short as possible, control and dogleg potential are maximized.

This tight radius capability is critical when using steerable rotary tools such as the Schlumberger PowerDrive* system, which "pushes" the bit laterally to deviate the wellbore.

Aggressive side cutting action During tight radius drilling, control and efficiency are reduced by the angle created between the bit axis and the borehole axis. Overcoming this angle requires a side force delivered by the steering tool and a bit that applies this force to cutters on the inside of the hole curvature.

Hycalog Steerable Rotary Bits address this requirement with a very short, aggressive gauge which converts lateral steering force into positive lateral deviation. The result is a very capable bit for addressing difficult dogleg requirements.

The short gauge focuses the energy that is transferred from the bit to the formation. This energy is applied to PDC cutters on the gauge. These uniquely placed cutters actively cut the formation to allow maximum lateral wellbore deviation. Cutter angle and orientation are

vibration to provide greater bit stability.

Aggressive PDC back rake SRB bits take advantage of the inherent capabilities of steerable rotary systems to provide a much more aggressive cutting structure.

Because conventional steering systems using motors are required to slide and retain tool face orientation, reactive torque is a problem. The solution has been to compen-sate for this reactive torque by employing less aggressive bits. This was accomplished by increasing the back rake, or angle at which the PDC cutters meet the rock. This solution, although effective, caused penetration rates to be reduced.

Steerable rotary systems do not have to address this problem of reactive torque because the drilling assembly continuously rotates. As a result, the bit can be much more aggressive. The SRB design has re-duced the back rake of the PDC

efficiency and ROP with steerable rotary systems.

High durability Optional DiamondBack* cutters provide a secondary cutting structure that improves the ability of the PDC bit to drill faster and further into harder, more abrasive formations. These durable cutters provide higher localized cutter density on the critical shoul-der area to extend bit life. As a result, tor-que response is smoother, which improves stability and control when drilling long-reach or tortuous well paths.

Optimum hydraulic design SRB bits are designed to meet the specific hydraulic requirements of steerable rotary systems. By providing the pressure drop these systems require, the SRB design makes more effective use of the available hydraulic horsepower.

The large junk slot area and open face volume of the SRB design significantly reduce reworking of cuttings to increase efficiency and ROP. In addition, the large open face volume allows the

silicate muds, for an advantage in applications where swelling formations are a concern.

Reed-Hycalog enhances bit performance with leading-edge technology Reed-Hycalog, a Schlumberger company, is a global provider of drilling solutions. Featuring Reed roller cone and Hycalog diamond bit technologies, Reed-Hycalog offers a wide range of bits to meet the requirements of your drilling application. To learn more about the advantages Hycalog Steerable Rotary Bits can provide in your drilling program, or for information on any Reed-Hycalog drilling bit, please contact your Reed-Hycalog representative.

Eastern Hemisphere Headquarters Stonehouse, England Phone: 44-1-453-826061 Fax: 44-1-453-825833

Western Hemisphere Headquarters Houston, Texas USA Phone: 713-934-6600 Fax: 713-934-6609

Legal Information © 2000 Schlumberger Limited.

http://192.23.80.151/legal/index.html

DAILY REPORT

To : Attention of : Fax/e-mail/address

WELL INFORMATION Well : Rig : Planned TD: MD TVDSS

Date : Report No : Days : Cost to date (STG) :

AFE No : Operator interest : CI WI AFE (STG) :

RT - MSL (ft)

Final Rig Co-ordinates UTM Zone, CM

Water Depth (ft, MSL)

Latitude : UTM (N) :

Longitude : UTM (E) :

Status at 0600 hrs

MD TVDSS Progress (24 hr) Hole size Current formation

Present Operation :

CASING OD MD TVDSS LOT/FIT (identify which)

OPERATIONS SUMMARY (last 24hrs)

Mud type : MW : Vis : FL : Cl : O/W :

Bit type : Motor : MWD : Weather : Wind : Seas :

PLANNED OPS (next 24 hrs)

GEOLOGY Lithology

ROP (ft/hr)

GAS

Interval TG % C1 ppm C2 ppm C3 ppm iC4 ppm nC4 ppm

SHOWS

PORE PRESSURE

Est. pore pressure at current TD : Max. est. pore pressure in open hole : at MD : TVDSS :

STRATIGRAPHY

Formation Tops Prognosed (ft) Actual (ft) ft High/ Pick method :-Cuttings/ MD TVDSS MD TVDSS Low MWD/Wireline etc

SURVEY DATA

Depth Inclination Azimuth TVD Vert Section N/S E/W

REMARKS

1

Daily Geology Report CONFIDENTIAL

Well: 28/05/02 Report Date: 28/05/02 Report No: MBS-22 Status at 06.00 hrs (1st January) Current Depth ft MDBRT ft (-TVDSS) Formation Operation: 9560 ft -9474 ft Butler Fm. Wireline logging Operations Update 00.00 to 06.00 hrs: Pumped out from 8938 ft, tool plugged after pumping 30 litres. Pumped out from 8936ft, plugged after 27 minutes of pumping, correlation log for sample at 8664 ft, pumped out from 8664 ft for 1.5 hrs, o/w ratio was 50/50, aborted sampling since 95% pure sample could not be obtained. Attempted sample at 8561 ft, aborted sampling after dry pretest. Attempted sample at 8563 ft, aborted sampling after MDT tool plugged. Attempted sample at 8559 ft, aborted sampling after dry pretest. Attempted sample at 8600 ft, aborted sampling after MDT tool plugged. Pull out of hole for inspection of tool & servicing. Lithology Update: no new lithology Interval Descriptions Update: (Penetration Rate, Lithology, Oil Shows) Interval (ft) MDBRT ROP (ft/hr) Lithology, Oil Shows No new lithology Drilling Gas Indications Update: Type Interval ft Total % C1 ppm C2 ppm C3 ppm C4 ppm C5 ppm Background No new drilling N/A Peaks Survey Data Update: Survey MDBRT

(ft) TVD BRT (ft)

Inclination deg

Azimuth Deg

North (+ ft) East (+ ft) Vert. Sect. (ft)

None to Report 24 hour Operations Summary 00.00 to 24.00 hrs (to midnight on 31st Dec) Midnight Depth: 9560 ft MDBRT, -9474 ft TVDSS Drilled Interval: none Progress: 0 ft Summary: Continue running in with MDT, stabilize tool temperature at 8565 ft, conduct pressure tests: 49 attempted, 26 pressures, 16 dry, 7 lost seals, POOH w/ MDT. Wash & flush MDT probe, rigged up additional sampling modules, RIH to 8450 ft. Perform stick tests & allow tool to warm up, pull correlation log, sample at 8468 ft, pumped out 39.7 litres and filled 1 gal sample chamber. Correlate for sample at 8938 ft. Drilling Data: Country: UKCS Block: 28/05 Prospect: Calleva Rig: Borgny Dolphin Spud Date: 1 Dec 2001 Days from Spud: 30 RT above MSL: 82ft Water Depth: 319 ft MSL Well Data: Hole Size: 12 ¼” Last Casing: 13 3/8”@ 3322 ft FIT 13.4ppg EQMW: Bit Type: BB657XA Drill Mode: Rotary Mud Type: KCL/Silicate WBM M.W: 11.3 ppg E.C.D: 11.6 ppg Vis: 69 pH: 11.7 F.L.3.3 cc/30min Cl: 59k mg/l Stratigraphy: Formation Tops

Actual (ft) MDBRT

Actual (ft) -TVDSS

Prognosed (ft) –TVDSS

Hi(-)/Lo (+) (ft) Pick Criteria

Top Tor Formation 3361.0 -3279.0 -3280 -1.0 GR/Cuttings Top Hod Formation 3601.0 -3519.0 -3510 +9.0 Cuttings/GR Top Herring Formation 4765.5 -4683.5 Not Picked GR/Cuttings Top Plenus Marl 5103.5 -5021.5 -5020 +1.5 GR/Cuttings Top Hidra Formation 5140.0 -5058.0 -5075 -17.0 GR/Cuttings Top Rodby Formation 5381.0 -5299.0 -5230 +69.0 GR/Cuttings Top Sola Formation 5649.0 -5567.0 -5330 +237.0 Cuttings/GR Top Valhall Formation 6454.0 -6372.0 -6405 -33.0 Cuttings/GR/ROP Top Kimmeridge Clay Fm. 7983.0 -7901.0 -7930 -29.0 Cut./GR/ROP/Gas Top Calleva Sandstone 8548.0 -8465.0 -8537 -72.0 ROP/Cut./Gas/Torq Top Heather marker 9100.0 -9016.3 -9021 -4.7 GR (LWD memory data) Top Sgiath Formation -9250 Absent

2

Base Upp. Jurassic 9415.0 -9329.6 -9511 -181.4 GR (LWD memory data) TD 9560.0 -9473.5 -9641 -167.6 130 ft below base U. Jur. WIRELINE Formation Tops

Actual (ft) MDBRT

Actual (ft) -TVDSS

Prognosed (ft) –TVDSS

Hi(-)/Lo (+) (ft) Pick Criteria

Top Ekofisk 3150 3067.8 No prognisis ~ Wireline logs Top Tor Formation 3350 3267.8 -3280 -12.2 Wireline logs Top Hod Formation 3856 3773.8 -3510 +263.8 Wireline logs Top Herring Formation 5001 4918.8 No prognosis ~ Wireline logs Top Plenus Marl 5138 5055.8 -5020 +35.8 Wireline logs Top Hidra Formation 5146 5063.8 -5075 -11.2 Wireline logs Top Rodby Formation 5396 5313.8 -5230 +83.8 Wireline logs Top Sola Formation 5656 5573.8 -5330 +243.8 Wireline logs Top Valhall Formation 6160 6077.8 -6405 -327.2 Wireline logs Top Kimmeridge Clay Fm. 7996 7913.4 -7930 -16.6 Wireline logs Top Calleva Sandstone 8560 8476.9 -8537 -60.1 Wireline logs Top Heather marker 9110 9026.3 -9021 +5.3 Wireline logs Top Sgiath Formation -9250 Absent Wireline logs Base Upp. Jurassic 9431 9345.5 -9511 -165.5 Wireline logs TD 9575 9488.4 -9641 -152.6 Wireline logs Interval Descriptions: (Penetration Rate, Lithology, Oil Shows) Interval (ft) MDBRT ROP (ft/hr) Lithology, Oil Shows No new lithology Drilling Gas Indications: Type Interval ft Total % C1 ppm C2 ppm C3 ppm C4 ppm C5 ppm Background None N/A Peaks None N/A Connection/Trip Gas Indications: Type Interval ft Total % C1 ppm C2 ppm C3 ppm C4 ppm C5 ppm Trip None N/A Connection None N/A LWD Tool data: Tool Name Directional sensor (ft) GR Sensor (ft) Resistivity (ft) Neutron (ft) Temp (°F) Not applicable Survey Data: Survey MDBRT

(ft) TVD BRT (ft)

Inclination deg

Azimuth deg

North (+ ft) East (+ ft) Vert. Sect. (ft)

None Remarks: Regards Jamie Cureton Wellsite Geologist Onboard Borgny Dolphin Stag geological Services Ltd.

End of Report

Wireline Logging Summary 12 ¼” Hole Section

Calleva 28/05/02 Total Depth 9560 ftCasing 3320 ft

Start Time

Stop Time Elapsed Time Wireline Activity

22:00 22:05 0:05 toolbox talk22:05 23:45 1:40 begin rig up of Run #1: SP-DSI-HRLA-PEX23:45 0:40 0:55 toolbox talk for next crew

0:40 1:20 0:40 check toolstring1:20 1:30 0:10 load RA sources1:30 4:10 2:40 RIH4:10 4:30 0:20 on bottom, repeat pass4:30 6:40 2:10 main pass6:40 7:40 1:00 at casing shoe7:40 8:00 0:20 finish GR log8:00 8:15 0:15 unload RA sources8:15 9:15 1:00 finish after cals, Max Recorded Temps: 182, 181 degF9:15 9:30 0:15 finish rigging down Run #1, head changed, wait on crane lifts9:30 10:30 1:00 begin rigging up Run #210:30 10:45 0:15 operational check tool string10:45 12:18 1:33 RIH with FMI-HNGS-CMR12:18 12:20 0:02 at 8940 ft, open caliper Run #2 pass 1: FMI-HNGS12:20 12:38 0:18 log up repeat section, 900 fph, all buttons active12:38 12:40 0:02 at 8700 ft, close calipers12:40 12:47 0:07 RIH to 9250 ft, 12:47 12:49 0:02 open calipers12:49 12:57 0:08 log up main pass, 900 fph, pad press. 17%, every 2nd button on one pad & flap inactive12:57 13:01 0:04 abort log at 9160 ft, close caliper & RIH to 9250 ft, to try again13:01 13:10 0:09 log up main pass 2nd attempt, 900 fph, pad press. 50%, same pad/flap problem13:10 14:25 1:15 at 8200 ft, stop log, retract arms, RIH14:25 15:15 0:50 log up main pass Run #2 pass 2: CMR after tuning tool, 850 fph15:15 16:32 1:17 stop log at 8200 ft, RIH to 8732 ft, 16:32 16:37 0:05 tune CMR16:37 16:42 0:05 RIH to 8850 ft16:42 16:45 0:03 start repeat section at 8778 ft16:45 17:10 0:25 end repeat section & drop down to 8732 ft to tune tool17:10 17:15 0:05 tune CMR17:15 17:20 0:05 POOH17:20 19:00 1:40 perform after cals, rig down FMI-HNGS-CMR, MRT 183, 182 degF19:00 20:30 1:30 rig down FMI-CMR complete20:30 21:10 0:40 rig up Run #3: MDT pressure tests21:10 21:30 0:20 RIH21:30 23:24 1:54 Turn on motion compensator23:24 23:34 0:10 stick test23:34 0:00 2:18 1st correlation pass

0:00 1:50 1:50 stabilize temperature of MDT tool in hole at 8565 ft1:50 13:24 11:34 MDT pressure profile. 49 pressures attempted, 26 obtained, 16 dry tests, 7 lost seals13:24 15:30 2:06 POOH with MDT, Pressure survey completed15:30 16:00 0:30 wash down & flush out single probe16:00 16:45 0:45 rigged up additional MDT sampling modules to run #3 MDT tool16:45 17:00 0:15 surface check Run #4: MDT samples17:00 19:25 2:25 RIH to 8450 ft19:25 21:00 1:35 perform stick tests & allow, MDT to warm up21:00 21:15 0:15 correlation log to position for sample at 8468 ft21:15 23:10 1:55 Pumped out 39.7 litres and filled 3.74 litre sample chamber at 8468 ft with water23:10 23:35 0:25 correlation log to position for sample at 8938 ft23:35 0:43 1:08 Pumped out from 8938 ft, MDT tool plugged up after pumping 30 litres

0:43 1:17 0:34 Pumped out from 8936 ft, MDT tool plugged up after pumping 27 mins of pumping1:17 1:27 0:10 correlation log to position for sample at 8664 ft1:27 2:59 1:32 pumped out from 8664 ft. After pumping for 1.5 hrs O/W ratio was 50/50. Aborted sampling

since a 95% pure sample could not be obtained.2:59 3:15 0:16 Attempted to sample at 8561 ft, Aborted sampling after dry pretest3:15 3:36 0:21 Attempted to sample at 8563 ft, Aborted sampling after MDT tool plugged3:36 3:45 0:09 Attempted to sample at 8598 ft, Aborted sampling after dry pretest3:45 4:45 1:00 Attempted to sample at 8600 ft, Aborted sampling after MDT tool plugged4:45 6:40 1:55 Pull MDT tool out of the hole for inspection & servicing6:40 7:10 0:30 Turn off motion compensator, toolbox talk7:10 8:40 1:30 drain SC#1, sample from 8468 ft, volume 3750 psi8:40 9:00 0:20 probe plugged, took 3000 psi to clear, service tool9:00 10:00 1:00 begin making up MDT toolstring for run #510:00 11:00 1:00 surface check Run #5: MDT samples11:00 11:25 0:25 operational check11:25 11:55 0:30 Set compensator, RIH11:55 12:03 0:08 correlation run for sample at 8563 ft, add 3.5 ft12:03 12:45 0:42 Attempt sample at 8563 ft, aborted as sample not cleaning up above 50% oil12:45 12:52 0:07 Attempt sample at 8620 ft, telemetry failure, tool retracted automatically.12:52 13:00 0:08 Drop down to 8635 ft, no communication with tool.13:00 16:15 3:15 POOH, found short in cable head, rehead, lay out MDT (program cancelled)16:15 Rig up Run #6: VSI

29th December 2001

30th December 2001

31st December 2001, New Year's Eve

1st January 2002, New Year's Day

Page 1 of 1

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CORING DECISION SUMMARY

WELL NAME 05/28/2002 GEOLOGIST M. ButlerDATE 12/16/2001 TIME START/ FIN 3:25

DRILLING DATA

DEPTH DRILL BREAK 8548/-8465 CURRENT DEPTH 8560/-8477(mddbrt/ mtvdss) (mddbrt/ mtvdss)LENGTH OF BREAK 12ftROP Pre-break (ft/hr) 25 - 35 ROP during break (ft/hr) 66 - 105Torque Pre-break (klbs) 6 - 8 Torque during break (klbs) 8 - 9Mud weight in (ppg) 11.3 Mud weight out (ppg) 11.3ECD (ppg) 11.6 Estimated O/B ppg 8.7Pit gain (bbl) None Controlled drilling? Yes - using WOBEst pore pres Pre-break 8.7 Est pore pres during break 8.7

GEOLOGY

Lithology after circulating 40% Sandstonebottoms up 60% SiltstoneVisible porosityNature of cuttings, e.g. Sandstone: generally loose, locally well cementedangular, loose grains, size, Siltstone: normal subblockyshape

SHOW DESCRIPTION

FLUIDS

Oil/ condensate Fluorescencestain Light brown colour moderate yellowbleed % of sample 100colour intensity (weak, etc.) Moderatewax cut fluor colour Blue whitelive cut speed slow to moderatecut colour and stain crush cut fluor colour Blue whitecrush cut speed solvent used Isopropanolcrush cut colour and stain

GAS

Pre-break From breakTotal gas 0.35 Total gas (0.35 b'grnd) 1.35 peakC1 1355 C1 4314C2 157 C2 649C3 136 C3 975iC4 28 iC4 108nC4 41 nC4 421C5 N/A C5 N/AH2S 0 H2S 0CO2 N/A CO2 N/A

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CORELOGWELL INFORMATION EQUIPMENT PERFORMANCECompany Core BBL Type & NO: HT 60 Core no: 2Contractor Core BBL Size 180'X 9 1/2" X 5 1/4" Interval Cored-FFinish 8798 FtRig Name I.T. Type JAMBUSTER Start 8,675.0 FtWell No Stab. Size 12 7/32" Amount Cored 123.0 FtField L. Shoe & Catcher PILOT SHOE & SPRING Core Recovery 120.7 FtArea Bit Style & Size RC 478 C3 12 1/4" X 5 1/4" % Recovery 98% %Hole Temp Bit ser # 322935 Coring Hours 30.70 Hrs.Hole Size TFA 1.06 ROP 4.01 Ft/hrHole Angle IADC Dull Grade-Start 0/0/NO/A/X/IN/PN/PR Reaming WASHED/REAMED LAST STANDFormation IADC Dull Grade- Finish 3/7/WT/N&T/X/IN/CT/PR Service Engineer Name TOM/JOHNLithology SPP on/off bottom 725--1000 Date 18/19-12/01Mud Type K/CL Liner Size 6 1/2" RemarksWT.PPG 11.3 SPM WL 2% Tr GPM 200--400% Solids 6.8 LCM n/a OPERATING PARAMETERS

8,675

8,680

8,685

8,690

8,695

8,700

8,705

8,710

8,715

8,720

8,725

8,730

8,735

8,740

8,745

8,750

8,755

8,760

8,765

8,770

8,775

8,780

8,785

8,790

8,795

0 10 20 30 40 50 60 70 80

8,675

8,680

8,685

8,690

8,695

8,700

8,705

8,710

8,715

8,720

8,725

8,730

8,735

8,740

8,745

8,750

8,755

8,760

8,765

8,770

8,775

8,780

8,785

8,790

8,795

0 5 10 15 20 25 30 35 40 45 50

8,675

8,680

8,685

8,690

8,695

8,700

8,705

8,710

8,715

8,720

8,725

8,730

8,735

8,740

8,745

8,750

8,755

8,760

8,765

8,770

8,775

8,780

8,785

8,790

8,795

0 20 40 60 80 100

120

ROP Ft/hr PRESSUREpsi

TORQUEKft.lbs

8,675

8,680

8,685

8,690

8,695

8,700

8,705

8,710

8,715

8,720

8,725

8,730

8,735

8,740

8,745

8,750

8,755

8,760

8,765

8,770

8,775

8,780

8,785

8,790

8,795

0 2 4 6 8 10

WOB Klbs

8,675

8,680

8,685

8,690

8,695

8,700

8,705

8,710

8,715

8,720

8,725

8,730

8,735

8,740

8,745

8,750

8,755

8,760

8,765

8,770

8,775

8,780

8,785

8,790

8,795

0 200

400

600

800

1000

1200

RPM

Prepared By Billy Roy

Biostratigraphic and Palaeoenvironmental Analysis of Core Samples from Wells 1 and 2, Caspian Sea.

[A FICTICIOUS REPORT BASED ON AN ACTUAL CLIENT-REPORT SUBMITTED IN WEB-READY FORMAT]

by Michael D. Bidgood MSc PhD

Michael D. Simmons PhD Patrice A.R. Brenac MSc

GSS International Unit 39, Howe Moss Avenue

Kirkhill Industrial Estate Dyce, Aberdeen, UK

AB21 0GP

date

Prepared For:

client's name address

This report presents and discusses the results of micropalaeontological and palynological analysis of core samples from 2 unnamed wells.

Samples were collected from cores laid out at ?? Ltd., Aberdeen on a number of different visits. The following depths (in metres) were sampled and analysed:

Well 1 Well 2

depths confidential depths confidential

The aims of this study were:

i. To provide information on the environment of deposition of the sediments from these cores, the sediments being reservoir intervals.

ii. To provide information on the age and biozonal potential of the sediments for future correlation to other wells and to place the sediments in a regional context.

Within this site-report, the methodology of the study is outlined, followed by a discussion of the results. All the raw palaeontological data pertaining to the study is included within the Enclosures of the paper copy of this study. However images of the stratigraphic summary logs are included on this web site. This site-report includes a summary of conclusions and recommendations for future work.

Personnel involved with this project were:

Dr. Michael D. Simmons : project co-ordination, integration, regional geology

Dr. Michael D. Bidgood : micropalaeontological analysis

Mr. Patrice A.R. Brenac : palynological analysis

Summary

Management Summary

Drawing on the experience of previous biostratigraphic studies in the South Caspian Basin, 32 samples from reservoir intervals within the Red Coloured Series of wells 1 and 2 were studied for their palynomorph and calcareous microfossil content in order to provide information on environment of deposition and potential biostratigraphic subdivision.

The results are encouraging in that it has been possible to determine that all the studied sediments were deposited in a fluvial environment with samples from well 2 showing evidence for periods of standing water between somewhat more meandering rivers/streams in a more low relief distal setting compared with 1, perhaps delta plain as opposed to alluvial plain. Samples from well 1 shows evidence for a constantly flowing freshwater river/stream system with little or no apparent standing water bodies (lakes, ponds etc.). The change in depositional setting between wells 2 and 1 (which is stratigraphically higher) suggests a prograding deposition system.

Fingerprinting of various stratigraphic intervals is possible using changes in palaeoclimate (and hence vegetation belts) reflected in the in situ palynomorph assemblages, coupled with variations in the pattern of reworking of palynomorphs. The potential for biostratigraphic correlation now needs to be tested by examination of the same stratigraphic intervals (reservoir zones) in other adjacent wells.

Methodology

The sediments sampled from the cores from wells 1 and 2 are from the "??? Series", the major hydrocarbon reservoir interval in the ?? part of the South Caspian Basin. The cores are from reservoir zones within the ?? Series and it is known that the cores from well 1 lie stratigraphically above those from well 2.

Regional data (Jones & Simmons, 1996) indicates that the ?? Series is essentially Pliocene in age. For the coeval "Productive Series" sediments on the western (Azerbaijani) side of the South Caspian Basin, preliminary studies (Zubakov & Borzenkova, 1990; Jones & Simmons, 1996; Reynolds et al., 1997) have indicated that biostratigraphic subdivision of these sediments is possible using changes in palynomorph assemblages which can be related to high frequency changes in palaeoclimate. Coupled with this, a broad biostratigraphic subdivision is possible using changes in ostracod assemblages and changes in the pattern of reworking of

microfossils found within the sediments (Khalilov, 1946; Agalarova, 1956). It was hoped that such biostratigraphic subdivisions could be applied to the ?? Series sediments from the wells of this study, and biostratigraphically "fingerprint" individual reservoir zones, thus assisting in future correlation studies.

Additionally, information on palaeoenvironments was sought. It is well known (Jones & Simmons, 1996; Reynolds et al., 1997) that the ?? Series represents the deposits of the large delta of the Palaeo-Uzboy (= Palaeo-Anu Darya) river which flowed into the South Caspian Basin during the Pliocene. However, less clear is the precise palaeoenvironment that local sediments represent. Given that ostracod faunas are known to occur within the ?? Series (Agalarova, 1956), and these assemblages of these fossils often have useful palaeoenvironmental significance, it was hoped that by coupling micropalaeontological and palynological studies with the sedimentological studies being carried out in the cores that some reasonably detailed information on palaeoenvironments could be obtained.

Given the aims of the study and the background noted above, 32 of the more muddy intervals (i.e. those most likely to have recovery of microfossils and palynomorphs) were sampled and then processed and analysed for palynology and calcareous microfossils.

Discussion

General Remarks

Microfossil recovery from the samples studied is highly variable. In well 1 assemblages of calcareous microfossils are relatively poor with only sparse reworked Cretaceous and Tertiary microfossils being recorded. In well 2 a few cores yielded some in situ ostracods and charaphytes. Palynomorph recovery was also variable and is dominated by reworked taxa. However, many samples yield enough in situ taxa to make some comments on palaeoenvironment, palaeoclimate and biostratigraphy. Although, the more muddy intervals from the cores were selected for sampling and analysis, it should be noted that many of these samples could not be termed mudstones. Rather they were siltstones or fine sandstones. Typically microfossil and palynomorph recovery is relatively poor in such lithologies.

Palaeoenvironment

The overall palaeoenvironmental setting for the two wells is within a fluvial system with sediments from well 1 relatively proximal to source and well 2 in a more distal (i.e. the overall succession represents progradation – sediments from well 2 are known to be stratigraphically below those of well 1), yet still within the non-marine part of the overall system. No "marine" indicators are noted, even accounting for the low/non-salinity of the Caspian Basin at the time of deposition. The overall climate was warm and dry (but see possible subdivision below), with a notably low proportion of conifer-derived pollen.

Samples from well 1 shows evidence for a constantly flowing freshwater river/stream system with little or no apparent standing water bodies (lakes, ponds etc.), as shown by the lack of fungal spores and ostracods.

Samples from well 2, with more prominent fungal spore and ostracod recovery, shows evidence for periods of standing water between somewhat more meandering rivers/streams in a more low relief distal setting compared with well 1, perhaps delta plain as opposed to alluvial plain.

Some palaeoclimatic signatures can also be picked out. These include samples with common non-arboreal herbaceous taxa (e.g. Echitricolporites spinosus and Fenestrites spinosus) which are thought to represent occurrences of low lying vegetation in a relatively warm, dry, open landscape – perhaps steppe-like conditions. These appear to alternate with samples with common arboreal taxa (e.g. Inaperturopollenites spp.) which indicate a more forested landscape – again with relatively dry, warm temperatures. These two types of assemblages can be seen from the following intervals:

Well 1

???m - ???m: mixed steppe & forest

???m - ???m: steppe

???m: forest

???m: forest

???m (*): mixed steppe & forest

Well 2

???m - ???m: steppe

???m: ?forest

???m - ???m: forest

???m - ???m: forest

(*) The sample at ???m also contains common Pteridophyte (fern) spores (e.g. Deltiodospora spp.) and palm-like pollen (e.g. Psilamonocolpites spp.) which together suggest more humid conditions associated with the arboreal taxa over this interval.

Samples suggestive of standing water bodies are noted only from well 2. These are picked out by the presence of abundant fungal spores, common ostracods and sporadic charaphytes (Chara spp.) and include the intervals/samples:

???m

???m (though with no ostracods recorded)

???m - ???m

???m - ???m (though with no ostracods recorded)

The reduced amount of gymnosperm pollen in the well 2 material may also reflect a broad meandering fluvial depositional environment, where the amount of these taxa is diluted by the presence of large amounts of other palynomorphs.

Biostratigraphy

The overall age of the section as indicated by the in situ taxa is Pliocene (undifferentiated). However, potentially local correlative events can be picked out by -

a. the in situ assemblage patterns reflecting climatic signatures b. the pattern of reworking

These, in turn, can potentially be used to "fingerprint" discrete reservoir units and consequently as a correlation tool for those units.

Zubakov & Borzenkova (1990) and Jones & Simmons (1996) have demonstrated that during the Pliocene, high frequency alternations between glacial and inter-glacial conditions affected the climate of areas which were the source of sediments in the South Caspian Basin (such as those in the well 1 and 2 cores). Climate belts and thus vegetation belts moved with changes from glacial to interglacial conditions. In the well 1 and 2 cores glacial conditions are represented by forest-dominated palynomorph assemblages and interglacial conditions by steppe-dominated assemblages. The table given in the palaeoenvironments section above shows that certain stratigraphic intervals have a particular climate-related palynomorph assemblage. This may prove useful in correlating these intervals to other wells in the nearby area and in the South Caspian Basin.

Reworking shows some potentially useful variation, with the proportion of Palaeogene vs. Cretaceous reworking of palynomorphs being moderately variable. Of particular note is sample well 2; ???m which is completely dominated by Cretaceous spores (so much so it has all the appearance of really being Cretaceous!). This can be contrasted with samples such as well 1; ???m and well 2; ???m which are very rich in Palaeogene dinoflagellates.

The potential climatic signatures and reworking patterns to provide biostratigraphic correlation needs to be tested by examination of the same stratigraphic intervals (reservoirs zones) in other adjacent wells.

Conclusions

1. Both the sets of samples from wells 1 and 2 represent deposition in a fluvial system.

2. Samples from well 1 show evidence for a constantly flowing freshwater river/stream system with little or no apparent standing water bodies (lakes, ponds etc.).

3. Samples from well 2 show evidence for periods of standing water between somewhat more meandering rivers/streams in a more low relief distal setting compared with well 1, perhaps delta plain as opposed to alluvial plain. The change in depositional setting between 2 and 1 (which is stratigraphically higher) suggests a prograding deposition system. These results are in keeping with what

is generally known about the progradation of the Palaeo-Uzboy into the South Caspian Basin during the Pliocene.

4. The samples are of Pliocene age. Fingerprinting of various stratigraphic intervals is possible using changes in palaeoclimate (and hence vegetation belts) reflected in the in situ palynomorph assemblages, coupled with variations in the pattern of reworking of palynomorphs.

5. The results from this study given encouragement to the use of biostratigraphy (palynology and calcareous micropalaeontology) in future studies of wells from the area and/or wells sampling the ?? Series elsewhere in the region. The fossil assemblages have proved themselves useful in determining environment of deposition (with implications for reservoir architecture, connectivity, etc) and for providing a fingerprint of reservoir zones which can be used to assist in well to well correlation within and outside the immediate area by providing a check of wireline log correlations.


Wellsite Geological Processes


UK

Revision D

January 2008

Introduction to Mudlogging

IntroductionHydrocarbon exploration begins with basin studies and geochemical, mag-netic, gravity and seismic surveying on a grand scale which is furtherrefined as information is gathered and processed. Potential hydrocarbonplays are developed as structures are interpreted and the models are fine-tuned.

However, despite major advances in exploration processes over the years,the development of 3D and 4D seismic and visualisation software prospectsstill have to be drilled to confirm the presence of oil and gas in sufficientquantities with suitable reservoir conditions to promote development plans.The exploitation process still requires the drilling of boreholes to physicallyextract the hydrocarbons from their reservoir rocks.

During the drilling of exploration, appraisal and development wells forma-tion evaluation is required to:

• Drill through the overburden to the target formation

• Land the well in the optimum position in the target

• Drill the reservoir section in the optimum manner

• Call T.D. correctly

However, the drilling practices that are necessary for the accomplishment ofthese ends often act as a barrier to the discovery of hydrocarbons. Forexample, in normal drilling it is essential that the hydrostatic pressurecreated by the density of the drilling fluid in the hole be sufficient toovercome the pressure exerted by the fluids in the formation; the alternativecan be a costly and extremely dangerous kick or blowout. Yet this same over-balance causes filtration of the drilling fluids into the formations and pushesthe formation fluids (where permeability exists) away from the wellbore.Thus the composition and concentration of formation fluids can be deter-mined only with difficulty.

Underbalanced drilling is an increasingly used process whereby the mudpressure is deliberately kept less than the pore fluid pressure in order tospeed up drilling and minimise formation damage. Of course this requiressophisticated techniques, specialised equipment and highly trained person-nel to be successful and is not within the scope of this document.

Wellsite Geological Processes 1-1


Formation EvaluationIt is necessary to have a group of methods and tools capable of locating andevaluating formations penetrated by the drill bit and their fluid content. Wecall the use and interpretation of these methods Formation Evaluation. For-mation evaluation methods can be classified broadly according to whetherthey are used:

• As drilling is in progress Drill Returns Logging

Measurement While Drilling

Coring and core analysis (although of course most analysis ispost-drilling)

• After the hole (or at least a portion of it) has been drilled.Wireline Logging

Sidewall Coring

Wireline Formation Testing

Drillstem Testing

Most of the above methods must be used together to complement the others;by themselves each has limitations and shortcomings.

Drill Returns LoggingDrill Returns (or Mud) logging is the continual inspection of the drilling mudand cuttings for traces of oil and gas and, in part, serves as a primary leadto coring and testing. The Formation Evaluation Log or Mudlog is a graphi-cal portrayal of this data. And contains such information as:

• Depth/ROP

• Cuttings Percentage Log

• Total Gas and Chromatograph Data

• Oil show information

• Cored Intervals

• Casing Points

• Bit Data

• Drilling Fluid Information

• Sample Descriptions

Wellsite Geological Processes1-2


Drill returns logging has an added usefulness as a safety measure for theearly detection of hazardous drilling conditions which could result in ablowout. Rates of penetration, the amount and type of recorded drilled gasand return mud flow variations are all routinely monitored in order to high-light any potential reductions in differential pressure (between the mudpressure and pore pressure).

Drill Returns Logging was introduced as a commercial service in 1939. Itprovides continuous onsite inspection, detection, and evaluation of the rockunits as they are being drilled with regard to potential oil and gas produc-tion. Correct methods of obtaining this data and its subsequent evaluationare very important factors in all exploratory programs, and their effective-ness depends primarily upon the wellsite geological team.

Data collection is often performed by geological technicians called Mudlog-gers. Equipped with a field laboratory and drilling and formation evaluationsensors mudloggers are able to collect drill cuttings, lag them for their depthof origin and, mostly by means of visual inspection, record the key data ofthe formations penetrated and their contained fluids. Gas data is measuredand recorded automatically.

Figure 1: Mud Logging Unit



From bit to surfaceThe crushed cylinder of formation which is drilled to make the hole isreleased into the mud stream. Once released, the formation and any con-tained fluids, gas or oil are carried to the surface by the mud. Mud logginglargely becomes a matter of extracting this information in terms of restoring(recording on the Mud Log) the original in-place characteristics of the forma-tion as much as possible. The first disturbance of the subsurface strata as aresult of being drilled is that of varying amounts of flushing by the mud fil-trate. Ordinarily, the drilling mud exerts a hydrostatic pressure on the for-mation in excess of the formation pressure. The formation serves as a filtermedium upon which wall cake is deposited and through which the filtratewater permeates, flushing interstitial fluids away from the wellbore. On thebottom of the hole where new formation is being continuously exposed andwall cake is not permitted to accumulate, the rate of filtration of mud fluidsis always at a maximum.

Factors that affect the amount of oil and gas remaining in the formationafter flushing and which, in turn, affect the amount of oil and gas entrainedin the drilling mud are listed below.

• Depth

• Rate of Penetration

• Size of hole

• Volume of drilling fluid circulated

• Physical properties of the formation

• Properties of the drilling mud

It is reasonable to assume that formations have often been flushed to theextent of being completely depleted of producible hydrocarbons before beingdrilled, though more often flushing will be to a lesser degree than this. Afterundergoing flushing, the formation is subjected to the bit action, beingreleased into the mud stream in the form of rock chips or cuttings. These aresubjected to the dynamic hydrostatic pressure of the mud column. Duringtheir travel time from the bottom of the hole to the surface, the cuttingsundergo a normal production cycle in that the pressure on them, caused bythe hydrostatic pressure of the mud, is reduced to atmospheric.

Gases, if present, and liquids (to a lesser degree) expand due to this pressurereduction and cause the cuttings to release into the drilling mud any fluidswhich they contained permeability permitting. Thus, upon reaching thesurface, the cuttings will have been depleted, either by flushing or produc-



tion. For this reason a great deal of importance is placed on the hydrocarboncontent of the mud as the source of the information for evaluating the pro-ductive possibilities of the formation being drilled.

The fluids released from the cuttings and conveyed to the surface by the mudare the basis for several measurements by well logging instruments andmethods. These readings are important considerations in the continuousevaluation of the productive possibilities of the formation as it is being pen-etrated. This is not to discount the importance of cuttings in formation eval-uation. The cuttings are samples of potential reservoir rock. Aside from theirimportance as a basis for correlation and stratigraphic purposes, they affordthe means of the first study of the reservoir characteristics of the formation.However, they must be studied and evaluated, bearing in mind that theymay have been extensively flushed and produced.

The Formation Evaluation Log Mud Logging is not complex in principle and does not interfere with thedrilling process, and the results are available a short time after the rock hasbeen drilled. The Mud Log is recorded simultaneously with the drilling of thehole. Detailed data on the physical characteristics of the subsurface strata is

Figure 2: Mud Logging Unit Interior



collected and analysed as it becomes accessible at the surface. This informa-tion is continuously evaluated, and control of certain phases of the drillingoperation is exercised by the Operator based on the interpretation of theresults. Besides almost immediately indicating the presence of any poten-tially productive zone, the mud log serves as a basis for modifying thedrilling program efficiently and is an important corroborative and correla-tive tool. A comprehensive mud log contains the following information:

• Total combustible hydrocarbon gases from the drilling mud

• Chromatographic analysis for individual gas content (methane- pentanes)

• Total combustible gas from drill cuttings

• Oil from drilling mud and drill cuttings

• Detailed rate of penetration curve

• Lithology composition and description

• (including estimated visual porosity)

• Drilling mud characteristics

• Data pertinent to the well’s operation coring points, trips for new bit, drillstem tests, bit data, carbidelag information, deviations, and other pertinent engineering in-formation.



Figure 3: Formation Evaluation Log



History and Development of MudloggingAs noted above Mudlogging developed in the 1930s as engineers and geolo-gists began to realise that cuttings samples and released fluids could betracked as they made their way to the surface carried by the drilling fluid.Estimations of the bit-to-surface travel time, the Lag Time, could be madeby calculating the time taken for the mud to travel along the annulus, takinginto consideration borehole geometry (the annular volume) and the volumet-ric discharge of the mud pumps. With accurate knowledge of lag timecuttings samples could be collected and lagged to their depth of origin thusenabling lithology and gas logs to be produced, plotted against depth.

GeologyInitially mudlogging was very much a geologically oriented service with atwo-man logging crew working 12 hour shifts (or tours) and thus relievingthe rig crew of having to make ad hoc and, mostly, not very useful samplecollections. In order to correctly lag the samples the mudloggers needed tohave accurate and continually updated estimates of total depth (and there-fore ROP) from reliable sensors. They also installed gas extraction machinesin the ditch behind the shale shakers linked to a detection and analysissystem via plastic tubing and a vacuum pump. This was routed to a con-tainer-sized laboratory or Mudlogging Unit which also housed cuttingssample washing, processing and testing equipment.

Safety MonitoringMudlogging now gave the rig a new team of data collection and monitoringpersonnel equipped with a laboratory and sophisticated sensors. Whilst gas

Figure 4:



detection was initially concerned with formation evaluation its use for safetymonitoring was growing in importance. Increases in gas readings at thesurface could indicate changing bottom-hole conditions and the first indica-tions of potentially unstable conditions. Thus the early mudloggers also tookon a safety monitoring role, and could provide this around the clockwhenever the borehole was not shut-in.

Another prime, early warning sign of unstable bottom-hole conditions ismud pit volume monitoring. This still provides the rig crew with early indi-cations of a kick developing. When formation fluids enter the borehole mudis displaced from the borehole and finds its way back to the storage tanks.This is a kick and, left to develop, could lead to these fluids reaching thesurface in an uncontrolled manner which is termed a blow-out. For manyyears the mudlogging crew had much better electronic sensors for monitor-ing pit volume changes than rig crews and therefore this form of safety mon-itoring has always been a major part of mudloggers duties andresponsibilities. Now that the rigs themselves have state-of-the-art datamonitoring systems the mudloggers provide valuable back-up assistance.

Formation Pressure EvaluationWhilst the early detection of kicks via pit volume changes, increases inreturn flow and total gas readings remains vitally important, it was soonrealised that if better knowledge of pore pressure and rock fracture pressurewas acquired correct drilling optimisation could lower the number of kicksand blowouts that were occurring and make the whole operation much safer.

Direct knowledge of pore pressure is available from wireline logging and pro-duction tests, although only after a portion of the well has been drilled andonly in permeable rocks. If a kick is taken pore pressure can be calculatedbut of course this is not recommended drilling practice in order to find outthe magnitude of the pore pressure.

Pressure build up in clays and shales cannot be measured directly becauseof low permeability and therefore has to be estimated from indirect means.It is unlikely that a kick will develop in shales but high pressures in imper-meable rocks can lead to severe drilling problems such as impaired holecleaning and stuck pipe. It only needs a thin permeable stringer to producea kick.

Overpressure in clays often results from rapid loading and under-compac-tion resulting in a formation that has low density and high porositycompared with normally pressured rocks at the same depth. Geological ordrilling engineering data that can identify under-compacted rocks can,therefore, help to recognise potentially overpressured rocks. Increases in gaslevels, higher ROP, reduced shale density, low formation resistivity, longersonic travel times, and lower than expected density values may all indicateincreasing pore pressure in clays. In the late 1960s and early 1970s tech-



niques were developed to use this information quantitatively to makeindirect estimations of pore pressure while drilling. Mudlogging companiestook on the lead role of performing this service but required access to drillingdata in order, for example, to normalise ROP for the effects of changingWOB, RPM etc. Thus extra, drilling engineering, sensors were installed onthe rig and wired up to the mudlogging unit linked to a computerised dataacquisition system to store and process the information.

Thus computerised mudlogging began in the early 1970s, primarily as apressure evaluation enhancement to normal mud logging services. An expe-rienced mudlogger (or pressure engineer) normally took on these dutiesleaving the sample collection and processing to the more junior of a now 2-man logging crew.

Drilling Engineering AssistanceAs well as routinely collecting and processing geological data mudloggersnow had access to a wealth of drilling engineering information; mostly stilldenied to the rig crew who, during the 1970s, were still mostly reliant onanalogue chart recordings of basic drilling data.

The collection of drilling data rapidly became another important part of themudlogging service and with it the development of drilling engineeringassistance software covering hydraulics optimisation, drilling efficiency, tripmonitoring, kick and kill analysis and directional drilling applications.

The modern mudlogging service now incorporates geology, safety monitor-ing, safety planning and drilling engineering assistance and is often the datacollection and distribution hub of the rig or platform



Figure 5: Drill Returns Logging


Lag Time

Lag Time CalculationWhen collecting drill cuttings it is necessary to relate them to their depth oforigin in order to accurately compile the lithology log. Cuttings and releasedfluids are brought to the surface with the returning mud; by calculating thetime taken for the mud to be circulated around the borehole the lag time canbe determined.

Hole cleaning, however, is not a totally efficient process. Even in verticalwells cuttings will slip through the mud and become sorted much as theywould do when travelling in a river or stream. The cuttings slip velocitydepends on mud properties, density and viscosity, and the size, shape,density and orientation of the solid particles. Gases will tend to permeatethrough the mud and may, therefore, arrive earlier than cuttings. Whilstrecognising these limitations, however, cuttings lag time is normallyreferred to mud travel time.

In high angle, ERD and horizontal wells hole cleaning can be very inefficientand accurate estimations of lag time can be very difficult. For example, inhorizontal wells, the cuttings have only to slip a very small distance throughthe mud before collecting on the bottom of the hole.

Calculations of lag time are based upon:

• Annular Volume

• Pump Output

This provides a reasonably accurate estimation in cased hole but open holesections may wash out leading to uncertainties about actual hole size.Calculations are normally supplemented with tracer tests or natural lagindications from drilling breaks.

Tracer TestsThe lag can best be determined by placing a tracer in the drillpipe at thesurface when the kelly or top drive is broken off at a connection. The traceris pumped through the drillstring into the hole and back to the surface, andthe number of strokes required of the circulating pump to make thiscirculation is determined. From this total pump stroke count, the number ofstrokes required to pump the tracer down the pipe to the bottom of the holeis subtracted. This figure is calculated on the basis of the capacity of thedrillstring and the displacement of the circulating pump. The result is thelag time in pump strokes.


Lag Time

Various materials (such as whole oats, rice, barley or lentils) may be used astracers and picked up on the shaker screen for approximating the lag. Careneeds to be taken when using solid tracers as downhole motors and MWDtools, for example, will have specific tolerances for the amount and size ofsolids that can be circulated through them. Mudloggers and WellsiteGeologists should check with the drilling engineers before using any solidstracers.

Calcium CarbideUnder normal circumstances the best tracer is calcium carbide which reactswith the water in the mud to form acetylene gas. This will be picked up bythe mud gas detector.

A fixed amount of calcium carbide is made into a small parcel using a singlesheet of kitchen paper and a small amount of sticky tape to hold it together.The package is placed in the top of the drill string during a connection, justbefore the new stand or single length of pipe is stabbed in. The water in themud reacts with the calcium carbide to evolve the acetylene gas which iscirculated down the drillstring. When using oil based muds or syntheticfluids a small amount of water can be poured into the top of the drillstringto facilitate the reaction.

The acetylene is automatically detected by the mud gas equipment and canbe differentiated from drilled gas by the lack of associated methane. Thearrival of the gas peak will indicate the total circulating time; the time takenfor the mud to travel down the inside of the drillstring has to be subtractedfrom this value. The downtime is an accurate calculation since the exactinternal diameters and section lengths of the drillstring are known.

A comparison of the carbide lag with the theoretical lag can give anindication of the amount of borehole washout. Since it is only the open holesection that is eroded then the time difference represents the amount ofenlargement of the open hole. The amount of mud pumped during that timeenables a calculation of average hole diameter to be made.

Of course, it may be that only a part of the open hole is being enlarged; thewellsite geologists and mudloggers may be able to predict the likelyformations and a revised calculation of the average hole diameter of thosesections may be made. If part of the open hole is significantly enlarged thenthe hydraulics may be no longer optimised and the drilling engineers willneed to be appraised of the situation if excessive torque, drag and perhapsstuck pipe problems are to be avoided.


Lag Time

Pump StrokesDetermining and using the lag in terms of pump strokes has distinctadvantages over lag determined on a time basis. The counters tracking thecuttings up the hole stop automatically when the pump is stopped. Clockscontinue to run, and some subtractive factor would have to be introduced.The most important advantage, however, lies in accuracy. A lag determinedin terms of an interval of time is correct for only one speed of the circulatingpump (that speed at which the lag determination was run), whereas the lagin pump strokes is accurate for any pump rate. Thus, changing pumps orrunning one pump rather than two does not interfere with the laggingprocess.

Incremental LagIt is important to continuously recalculate the lag between carbide checks.This is done by calculating the theoretical increase in annular volume asdrilling proceeds and adding to the carbide lag. Eventually, of course, thislag will become inaccurate as some hole washout occurs, and a new carbidecheck should be performed.

This can be done every 100ft or 30m when the annulus will have beenchanged by the length of hole drilled and the addition of drill pipe at thesurface. Note that, once a calculation has been made the drill collars havealready been accounted for and have merely changed their location. Someoperators make the mistake of assuming that the drill collars have grown by100ft or 30m; this is not the case.

The importance of an accurate lag to drill returns logging dictates that allmud pumps should be monitored for pump strokes and that the logging unitbe capable of displaying the individual strokes for each pump, as well as thetotal strokes and strokes per minute.

Multiple Carbide PeaksIf more than one acetylene peak is found on running a carbide tracer test itmay suggest that some of the gas is taking a short cut and thus arrivingearly. This could indicate that a small crack or hairline fracture isdeveloping in the drillstring that, left to develop, could cause the pipe tobreak. Other indications of pipe washout would be an increase in pumpstrokes or a decrease in pump pressure.

The drilling engineers need to be informed at the earliest opportunity sothat, having confirmed the possibility of pipe washout, they can trip thestring and remove the damaged joint(s). This may necessitate a wet trip inorder to identify the location of the damaged joint which a is a slow process.


Lag Time

The multiple carbide peaks can allow an estimation of the depth to thewashout to be calculated based upon the difference in time between therecorded peaks.

Natural Lag IndicationsWhen a drill-break occurs, (a significant increase in drilling rate), this mayindicate that a different formation is being drilled. This may happen, forexample, on drilling through a shale cap rock into a porous, permeablesandstone reservoir. Since changes in ROP are seen in real time the cuttingsfrom the new formation, (and associated gas), will be seen one lag time later.careful observation at the shale shaker and interpretation of the mud gasanalysis can give a very accurate “natural” lag time estimate without theneed to use a carbide bomb.

Lag Time CalculationCalculation of lag time can be done in one of two ways:

• Volumetric

• Annular Velocity

The volumetric calculation is usually preferable since the time, (andtherefore the annular velocity) will vary with changes in pump output.Annular velocity will be important in hydraulics optimisation work forefficient hole cleaning.

Calculation requires detailed knowledge of the wellbore geometry, (lengthsand hole diameters) and drillstring displacement. First principles may beused but useful information can be found in many drilling engineering datahandbooks and there are some short-cut calculation methods available usingcommon oilfield units.

The mudlogging unit software will automatically calculate downtime, lagtime and be able to track events such as carbides, connection gas, trip gas,survey gas and drill break bottoms up. However mistakes can be made ondata entry so confirmation calculations should be made from time to time aspart of a thorough quality control procedure.


Lag Time

The Calculation ProcessThere are many ways to make a lag time calculation; one method is tocalculate the total hole volume and subtract the drillstring displacement togive the annular volume. This is related to the pump output to give the lagtime.

Mud PumpsMost oilwell pumps will be single acting triplex pumps. Each pump consistsof a cylindrical sample chamber of a specific length, the stroke, but with avariable inside diameter, the liner size. Smaller liners are used in smallerhole sizes to maintain pump pressure with reduced flowrates.

Single acting triplex pumps draw mud into the chamber and then send it tothe flowline; a forward and backward movement (x1 cycle or x1 pumpstroke), of the pump piston therefore producing x1 volume of one sample

Figure 1: Casing data


Lag Time

chamber. Since there are three sample chambers acting in parallel, the totalvolume of mud produced per stroke is x3 volume of a single chamber.

The mudlogging unit will have a sensor mounted on the pump to countstrokes per minute (spm). The sensor needs to be installed correctly so thatit doesn’t double count, otherwise the lag time will be incorrect.

Data for the stroke length and liner size are available from the drilling crewor for data handbooks. Typically the stroke length for a triplex pump will be11”-12”; the liner size will be from 5”-7”. Using this data the pump output ingallons, barrels or litres per stroke can be determined. A volumetricefficiency value (typically 95%) also needs to be factored. From time to timethe rig crew may actually measure the amount of mud discharged from thepumps. Close attention has to be paid to the pumps since the liners will,periodically, be changed, perhaps at casing points, which will affect thedischarge volume, and hence the lag time.

Figure 2: Mud Pump


Lag Time

A pulsation dampener, attached to the pump, smooths out the flow andregulates the pressure, by means of high pressure nitrogen and adiaphragm.

Hole VolumeEstimates of hole volume can be made using:

• First principles

• Engineering Data Handbooks

• Mathematical short-cutsUsing common oilfield units

Using Engineering Data Handbooks information for hole size capacity anddrill string displacement can be obtained. The hole size capacities need to beinternal diameters; the correct casing has to be identified from O.D. andweight per foot information. For the drill string displacement the O. D. of thepipe or collar will be required. In the case of drill pipe an allowance for tooljoints has to be made. Some handbook data include tool joints in theirdisplacement and capacity tables and others do not. The mudlogging unitsoftware will include this information.

Figure 3: Pump Output Figures


Lag Time

Mathematical short-cuts using common oilfield units are useful for manualcalculations, particularly when checking software results.

The following short-cut can be used to calculate the volume of a cylinderusing oilfield units, (where d2 = cylinder or pipe diameter in inches):

bbls/ft

bbls/ft

d2 0.000971×=

d2

1029.4----------------=

Drilling Engineering CourseRig Maths Examples

Lag Time

OD" ID" Length ft Volume bbls

Hole VolumeRiser 16 450 111.86

Casing 9.625 8.681 10825 792.11

Open Hole 8.5 1849 129.72

Total Hole Volume 1033.69

Drill String DisplacementDrill Pipe 5 4.276 12524 304.02

Collars 6 3 600 20.97

Total Drillstring Displacement 324.99

Annular Volume 708.69

Oump Output spm bbl/stroke gal/min bbl/min100 0.12 504 12

Lag Time 5906 strokes59.06 minutes


Lag Time


Mud logging Equipment & Sensors

Unit ConstructionThe mudlogging unit is normally a purpose built Zone 1 certified steel cabin,8-9 metres long and 2-3 metres wide. Occasionally on large productionplatforms the unit may be built into the infrastructure of the rig with thedata engineer and computer system located with the driller, directionaldriller and MWD personnel.

The units are air conditioned and pressurised to minimise the chance of gasentering the interior. An alarm linked to an emergency shut-down systemwill shut off all unit power in the event of gas invasion.

The unit needs to provide adequate work-space for the data engineer,mudlogger and sample catcher, and wellsite geologist and, in somesituations MWD personnel and equipment in order to serve as an office,laboratory and data acquisition centre.

Figure 1: Baker Hughes INTEQ Mudlogging Unit



The equipment is stored in racks within the unit and linked to acomputerised data acquisition system. Data from sensors, computed valuesand 3rd party clients is imported into the system for storage, editing anddata distribution via the computer network and hard copy logs, prints andreports. Raw data is fed to chart recorders to provide a record of un-adulterated information which is particularly useful in the event of anincident such as a kick occurring.

SensorsSensors are provided to monitor drilling parameters, mud and circulationinformation and gas data. These are situated on the rig floor, in the pumproom, shaker house and at other locations. They include:

Figure 2: International Logging Interior



Drilling Equipment Sensors

• Block Height: (Depth, ROP) Independent sensors may be mounted on the:

Drawworks drumCrown block Swivel

• Pump Pressure

• Casing Pressure

• Choke Pressure

• Rotary Torque

• RPM

• Hookload (WOB)

Mud Sensors

• Pit Volume

• Mud Conductivity (in and out)

• Mud Density (in and out)

• Mud Temperature (in and out)

• Mud Flow Out

• Pump SPM

Gas Detection

• Gas Trap

• Vacuum System

• Continuous Total Hydrocarbon Detectors

• Chromatograph

• H2S Detectors AmbientSample gas stream

• CO2 Detector



Geological Evaluation

• Binocular microscopes (variable zoom)

• Fiber optic microscope light

• Auto-Calcimeter

• Ultra-violet light box

• Sample drying oven and hood

Figure 3: Rig Sensor Locations (EXLOG)



Depth and Rate of PenetrationDepth increments and therefore rate of penetration are measured bymonitoring the movement of the drillstring as it passes through the rig flooror rotary table. An allowance for rig heave has to be made on floating vessels.

Sensors may be attached to the swivel, the crown block or directly to thedrawworks drum.

Drawworks DrumThe sensor fits directly onto the drawworks drum and relates rotation of thedrum to vertical movement of the drillstring. A proximity sensor records thedrum rotation and sends the information to the mudlogging unit. This typeof sensor is easy to install, accessible and requires little maintenance oradjustment.

The computer software does, however, need to recognise when the wrappingof the cable around the drum passes onto a different layer as this will affectthe calibration.

On some floating rigs, where this sensor is installed ahead of the drillstringcompensator, there can also be some operational problems.

Figure 4: Drawworks sensor



Crown Block SensorSome mudlogging companies install a sensor on the crown block to directlymeasure the rotation of the sheaves and, again, relate this to vertical pipemovement. With correct calibration this provides a very accuratemeasurement of pipe movement since there are no additional wraps of cablearound the sheaves. Floating vessels may still be a problem, however.

Swivel Mounted SensorsDuring the 1970s and 1980s, and in some locations still today, a hydraulicsensor mounted on the swivel also provided an indication of pipe movement.This can be traced back to the driller’s geolograph which, until fairlyrecently, was the main data acquisition and chart recording system for therig crew.

GeolographHere a wire cable was attached to the swivel, in turn fixed to a small springloaded rotation drum. The wire cable was reeled out an in as the pipe wasreciprocated and rotation of the drum related to pipe movement. The datawas output on a multi-channel chart recorder mounted on a steel drum inthe driller’s dog-house. The pen on the chart recorder made a markwhenever one foot of pipe movement was recorded. Whilst this gavereasonably accurate results the driller had to manually reset the pen duringreaming and when moving pipe until the bit was on bottom in order not torecord non-drilling episodes.

Figure 5: Crown Block



Figure 6: Geolograph Chart



Hydraulic SensorThis type of sensor uses changes in hydraulic pressure to monitor drillstringmovement. A length of rubber welder’s hose is attached to a steel bottlewhich is connected to the swivel. The hose is filled with water and strappedto the rubber mud inlet hose back to the standpipe and to a service box onthe rig floor. The service box contains a pressure transducer to convertchanges in hydraulic pressure into electrical current.

The signal is fed to a chart recorder and also to the computerised dataacquisition system. It was this sensor that first provided a continuous traceof pipe movement against time and that did not need to pen to be manuallycontrolled to monitor depth and ROP changes.

In cold climates the water is replaced by a water-glycol mixture to preventfreezing. This will affect the calibration and care has to be taken to use thesame water-glycol concentration and to re-calibrate when the hose is re-filled. An artificial atmosphere is created using a double-tube system inorder to overcome excessive U-tube problems.

Figure 7: Driller & Geolograph



Figure 8: Hydraulic Depth Sensor



Heave and Tide CompensationOn floating rigs allowances have to be made for heave and excessive tidevariations. We want to monitor the drillstring movement with respect to thesea level or sea bed (and thus bottom-hole) and not to the rig which is movingup and down.

The rig heave is measured from the riser tensioner cables as the piston rodsmove. This is added to or taken from the depth sensor in order to filter outrig movement.

Rate of PenetrationIncrements to total depth are continually recorded as pipe movement isdetected. The pipe tally provides calibration points for the depth whenconnections are made and is ultimately the definitive approximation ofmeasured depth. Inaccuracies in pipe measurement, pipe stretch due toWOB and temperature effects and tally transcription data can result in poorestimates of measured depth.

Figure 9: Marine Riser Slip Joint



ROP can be measured over various time and depth increments, includinginstantaneous values. For reproduction on logs it is normally recorded asfeet/hour, minutes/foot, minutes/5 feet, metres/hour or minutes/metre.

Linear or logarithmic scale can be used; log plots result in fewer scalechanges making the log easier to read and also emphasise changes in ROPmore effectively. It is the normal API standard to record fast drilling to theleft of the plot scale; this provides compatibility with gamma ray curves insand-shale sequences to make interpretation and correlation easier.

Figure 10: Circular depth Chart



Figure 11: Multi-channel Chart Recording



Drilling BreaksDrilling breaks are sharp increases in ROP which may represent differentbottomhole drilling conditions. Typically this happens when drilling throughan impermeable cap rock into porous and permeable reservoir rock such assandstone. Whether or not the new formation is significantly hydrocarbonbearing or part of the main target horizon a drilling break usually indicatesat the very least a change in lithology and is important as a geologicalcorrelation tool.

Reverse drilling breaks are a significant reduction in ROP such as happenswhen drilling out of the reservoir into shales.

Drilling breaks need to be shown accurately on logs and data is recorded bythe Wellsite Geologist for inclusion in morning reports. They may haveassociated oil and gas shows.

ROP is important as a correlation tool because it is a recording of real-timechanges downhole. As soon as the bits drills into a harder or softer formationthe movement of the drillstring speeds up and is recorded by the depthsensor. We will have to wait for at least one lag time before the cuttings andoil or gas appear at the surface. This may be too late if we need to core thereservoir or if the lithology change indicates a casing point.

Drilling breaks need to be identified as they happen, (all mudlogging sensorsand data are alarmed) and the information communicated immediately tothe Driller, Company Representative and Wellsite Geologist. Operationalguidelines should have been issued by the Operator and Drilling Contractorto the mudloggers detailing the parameters for recognising drilling breaksand the lines of communication to be followed thereafter.

Flow CheckIf the drilling break does represent drilling into a reservoir type rock thenthere is also the chance of high formation pressure being present. Whereuncertainties exist, such as when drilling exploration and appraisal wells, itis usually necessary to check if it is safe to continue drilling before exposingtoo much of the new formation.

A flow check involves ceasing drilling, stopping the pumps and waiting forat least 15 minutes for the mud to stop moving and to look for anyindications of the well flowing. The pit levels are monitored together withthe return flowline and bell nipple area beneath the rig floor. If the well isflowing then the BOPs can be activated, the well shut-in and safely killed. Ifthe well is not flowing then drilling can resume.

Extra care, and time, needs to be taken when using Oil Based Muds since agas kick can flow into the mud at high bottomhole temperatures withoutimmediately causing a pit volume or return flow increase.



If the drilling break represents a target formation which is required to becored then the Operations and Wellsite Geologists will evaluate thesituation to determine whether to pull out of the hole to pick up the corebarrel or not.

If any uncertainties are present concerning the stratigraphy or if the logand/or drilling parameter signatures are inconclusive then a bottom holesample may be circulated to the surface without further drilling to confirmany lithology changes or oil shows.

Figure 12: Drilling Break



Figure 13: Mud Log - ROP Curve



Drilling Engineering Sensors

Standpipe (Pump) Pressure & Casing PressurePressure transducers are attached to the standpipe and the choke line. TheStandpipe pressure gauge measures the pump pressure which is the forcerequired to move the mud all the way around the circulating system.Sufficient pump pressure is required to have adequate bit pressure drop forhydraulics optimisation, to power downhole motors and MWD tools and toproduce ECD in the annulus.

Casing pressure is recorded when the well is shut induring kicks or pressuretesting operations and measures the imposed pressure in the annulus.

The sensors typically measure pressures from 0 - 351.5 kgf/cm² or 0-5000 psi,with accuracies of 0.1%.

Rotary TorqueThe sensor is designed to detect the magnetic field generated by currentflowing in the DC power. The sensor is designed to detect themagnetic fieldgenerated by current flowing in the DC power cable to the rotary motor driveunit, it converts the magnetic field strength to a 4-20 mA signal.

It clamps on the rotary torque power distribution cable going to drive motor,drawworks power distribution motor or the top drive unit.

Torque is an indication of how much work is required to turn the drillstringand/or bit. It provides information on stalling and potential stuck pipe andtwist-offs as well as providing the wellsite geologists with real-timedownhole indications of changing lithologies.

RPMAn RPM sensor is attached to the rotary table or top drive to measure thedrillstring rotation. This necesary to monitor drilling efficiency and providesfeedback, (with rotary torque), on downhole conditions. It is used by themudloggers to normalise ROP values when performing formation pressureevaluation services.

The rotary speed sensor assembly consists of a clamp-on, multi position axisdevice assembly. The sensor consists of a non-contacting proximity sensorelement. The target is of a ferrous metal design to mount to any rotatingshaft geared directly to the rotary table or top drive unit. The RPM assemblyis secured by any convenient means (C-clamps, bolts), close enough to therotating target to be activated once every turn.



When a downhole motor is being used, the service company personnel willprovide information on performance based upon motor configuration andpump output. This is added to the measured RPM values when used inconjunction with the rotary table or top drive.

HookloadThe Hookload Wireline Tension Sensor is used to indicate the amount of drillstring free hanging total weight and calculated bit weight of the drill string.The sensor features two fixed points at each end and one clamping point inthe center of the sensor. The dead line is clamped tightly to this point,causing a slight bend in the line. With increased weight on the blocks, thedead line has a tendency to straighten. This tension force causes the sensorto provide a corresponding signal; that is, the greater the tension force on thesensor, the greater the hookload.

The WOB is calculated from the difference between the maximum hookloadwhen the bit is just off bottom and the observed hookload with WOB applied.

Figure 14: BHI Mach 1 PDM Motor Specifications



Mud Sensors

Pit Volume SensorsPit level and/or pit volume is monitored for all the rig’s mud pits. The activesystem is particularly important since losses or gains downhole will indicateexcessive permeability or the first indications of a kick. Otherwise it isnecessary for inventory control and environmental impact to monitor theamount of fluid in allthe storage tanks.

Ultrasonic SensorThe probe emits a series of ultrasonic pulses from the transducer. Eachpulse is reflected as an echo from the mud and sensed by the transducer. Theecho is processes by proven ‘Sonic Intelligence’ techniques. Filtering isapplied to help discriminate between true echoes from the mud and falseechoes from acoustic and electrical noise and agitator blades in motion. Thetime for the pulse to travel to and from the mud is measured, temperaturecompensated and then converted in to distance for display and 4-20 mAoutput.

The probe is light and easy to install by means of a 2” NPT thread or wherenecessary, a specially designed bracket. The intrinsically safe 4-20 mAcurrent loop makes the wiring simple, quick and reliable. Calibration iseasily performed by means of two tactile keys and a LCD display, thecalibration is maintained in EEPROM which protects the data in the eventof power loss. Frequent re-calibration is not necessary and only need to bechecked during periodic maintenance and configured.

Figure 15: Hook-load Sensor



Float Pit Level SensorFloats, linked to potentiometers or electronic micro-switches can measurefluid levels in mud tanks. They may be more difficult to install, less suitableon floating vessels and require more maintenance than ultra-sonic devices.

Some of the rotary potentiometer based sensors with long arms may alsosuffer from linearity problems.

Mud Measurements

Mud ConductivityMud conductivity or resistivity measurements are used to monitor the mudfor contamination from formation fluids or dissolved solids. It can give earlywarning of salt water kicks into a water based drilling mud, for example.

Probes are placed in the mud pits and at the end of the return flowline toprovide measurements of Conductivity In and Out for comparison.

Mud DensityAgain this is continually monitored, In and Out to check that the mud iswithin specification as it is circulated into the borehole and to check forcontamination as it returns to the surface.

Excessive solids retention can lead to increases in mud density and loss ofdrilling efficiency and high ECD values; gas contamination produces loweffective mud density and reduced bottom hole leading to potential kicks.

A differential pressure sensor consists of two pressure sensors positioned inthe mud a fixed distance apart. The variation in hydrostatic pressure

Figure 16: Ultrasonic Pit Volume Sensor



readings over the known difference in vertical height between the sensorsenables the mud density to be calculated.

Gamma Ray sensors, similar to those used in wireline and MWD formationevaluation, can also be used. These sensor do, however, require nuclearsource handling, storage and personnel safety issues to be addressed.

Mud TemperatureMud temperature is also continually measured, In and Out. This gives anindicatio of geothermal gradient which is useful in log interpretation, testingand formation pressure evaluation work.

Return Flow SensorThe mud flow into the borehole is calculated from the pump output data.Return flow is measured by a sensor in the flowline.

Historically this information has been very difficult to obtain accurately dueto sensor limitations and variations in the flow type along the returnflowline. On floating rigs flow surges occur with rig heave which makesaccurate measuremnts difficult.

Paddles, pressure sensing devices, electromagnetic flowmeters and Corioliseffect devices are all used.

PaddlesThese sit in the return flowline and are either pushed through an arc by theflowing mud, connected to a potentiometer which measures the flow or justrecord the pressure being applied to a target.

ElectromagneticThe rig flowline has to be modified since the sensor is installed in a by-passcircuit and only works in conductive drilling fluuids.

The sensor consists of a pair of cicular electrodes flush with the inside of thepipe. When the sensor is energised a magnetic filed is produced at rightangles to the pipe axis creating a potential difference that is proportional tothe mud flow.

Coriolis EffectAgain this sensor is installed on a by-pass circuit. The mud flows throughtubes which twistand vibrate under the influence of fluid flow. The amountof twist in the tubes is proportional to the mass flowrate of the fluid.



Pump Stroke SensorThe Pump Stroke sensor assembly consists of a clamp-on, multi position axisdevice assembly. The sensor consists of a non-contacting proximity sensorelement. The target can be any ferrous metal component of the pump, andcan either be temporarily mounted close to the pump or permanentlymounted inside the main gear enclosure close enough to a rotating bolt. ThePump Stroke assembly is secured by any convenient means (C-clamps,bolts), close enough to the Pump target to be activated once every cycle.

Gas Detection

Floating Gas TrapThe Fixed Volume Floating Gas Trap is a robust and newly proven means ofextracting well bore gases from the drilling fluid (either water or oil based).It’s design ensure a proper submerge level in the mud is continuouslymaintained. The Floating Gas Trap can be mounted in either the openReturn Flow line or the Shaker Header box.

Application:The drilling fluid flows through the Gas-trap by means of the 70mmdiameter hole in the bottom of the Gas-trap. The drilling fluid inside the trapis agitated by a reliable air driven motor mounted on top of the box section.

The liberated gases are then extracted out of the box section by means of avacuum produced by the pumps in the pneumatics assembly inside the SLScabin.

The mud inlet is automatically kept below the surface of the drill-mud. Thisprevents outside air or other contamination with hydrocarbons fromentering the gas-trap.

This simple design ensures reliability with only basic maintenancenecessary, which can easily be performed by the Surface Logging crews. It’sspecial chamber design ensures that the gas trap floats and thus maintainsit required partially submerged level in the drill mud.



Figure 17: Floating Gas Trap



QCM Gas TrapThe QGM (Quantitative Measurement) gas trap was developed in a jointventure between Texaco and GRI (Gas Research Institute) in an effort tostandardise different company’s gas traps and to find the best design forconstant volume and linearity measurements.

A cylindrical design with mud entering from below, filling up to an outletport about halfway up with the air-gas mixture being taken off from above,all agitated with a tripod device proved to be the ideal solution.

Gas Permeable MembraneDatalog have introduced their GasWizardTM dveice which dispenses with atraditional gas trap and uses a small gas permeable membrane to detect gasin the mud. Unlike traditional traps it is not affected by positioning orvariations in flow and produces very accurate estimations of gas in mudvolume. It is small enough to be mounted on the bell-nipple or return flow

Figure 18: QGM Gas Trap



line which minimises gas losses before detection and is potentially moreaccurate for quantitative gas ratio analysis.

Vacuum SystemWith traditional gas traps the air-gas mixture is brought to the logging unitvia plastic tubing and a vacuum system. The vacuum pump and variousfilters and flow meters make up the system which has to be regularly andcorrectly maintained by the mudlogging personnel for optimum gasevaluation efficiency.

Figure 19: Datalog Gas Wizard



Figure 20: Vacuum System



Gas DetectorsOnce separated from the mud and brought into the mudlogging unit the airgas mixture is analyzed for its hydrocarbon, H2S or CO2 content.

The total amount of combustible hydrocarbons is recorde as Total Gas andthe make up of the gas is determined from chromatographic analysis. TheTotal Gas reading is continuous but the chromatograph takes a certainamount of time to process a sample, during which time no new informationis processed. Thus, the shorter the processing time the better the resolution.Older chromatographs may take 4-5 minutes to detect as far as Pentane;modern machines may only take 30 seconds or so.

Figure 21: Total gas & Chromatograph



Geological AssistanceThe mudlogging unit is equippped with zoom binocular microscopes, Ultra-Violet light box and Hydrochloric Acid for cuttings evaluation. Otherspecialist equipment is also available such as:

AutocalcimeterThis device measures the rate of response of dilute Hydrochloric Acid on rocksamples to give an indication of the total carbonate content and the relativeamounts of limestone and dolomite in the sample. This is useful in complexcarbonate sequences where subjectivity can be a problem.

The device is calibrated with a fixed amount of 100% CaCO3 and the sameweight of sample used for testing. Dilute hydrochloric Acid is added to thesample and the CO2 given off given off during the carbonate-acid reaction ismeasured by a pressure transducer and converted to an electrical signal.The information is output digitally to a databas and also to a chart rcorder.The first, very fast reaction indicates the amount of calcite (limestone)content and the continued, slower reaction indicates the dolomite content.

Figure 22: Auto calcimeter



Cuttings CatcherUsing a cuttings catcher machine, the system measures the raw mass ofsolids coming over the shaker. The system removes the calculated mass ofmud additives and attached fluid to give an online value for actual formationsolids being removed from the hole. Comparing this measurement to theanticipated values provides a real-time indicator of hole-cleaning, holeconditions, mud conditioning and overall drilling efficiency.

Figure 23: Autocalcimeter chart



Figure 24: Cuttings Catcher


Gas Detection & Evaluation

Gas CompositionHydrocarbon compounds consist of hydrogen and carbon atoms classifiedinto two types depending on the molecular bonding of the carbon atoms:

• Saturated (Alkanes)One single covalent bond between the carbon atoms

• Unsaturated (Aromatics)Double bonds between the carbon atoms

Saturated Hydrocarbons (Alkanes)These consist of short chains of carbon atoms saturated with hydrogenatoms that occupy all available sites. Chains may be straight, branched orcyclic.

Straight and Branched Chains (Paraffins)The straight chained, normal, alkanes have the general formula:

CnH2n+2

Where n ranges from 1-10 the members are:

• Methane (C1)

• Ethane (C2)

• Propane (C3)

• Butane (C4)

• Pentane (C5)

• Hexane (C6)

• Heptane (C7)

• Octane (C8)

• Nonane (C9)

• Decane (C10)



Wellsite chromatography usually goes as far as Pentane since the heaviermembers will tend to retain liquid state at surface pressure and tempera-ture. Pentane condenses to a liquid at 36ºC and so may not be a gas at veryhigh mud temperatures.

Figure 1: Hydrocarbon Structures



The branched chain series begins from Butane (C4) and wellsite analysiswill usually detect iso-Butane and iso-Pentane.

Closed Chains (Napthenes)In this group of alkanes the carbon atoms are arranged in a closed chain andsaturated with hydrogen atoms. The normal paraffin series names areprefixed with cyclo-, and have the general formula:

CnH2n

Napthenes are slightly lighter than paraffins since they have two fewerhydrogen atoms. They are usually indistinguishable from Butanes andPentanes at the wellsite because of their similar molecular weights.

Unsaturated Hydrocarbons (Aromatics)The aromatics are closed chain structures but, unlike the alkanes, are notsaturated with hydrogen. They are usually only minor constituents of mostcrudes but benzene is, nevertheless, quite common.

Crude Oil ClassificationWhilst basic density can be used to classify crude oils the API Gravity valueis normally used. This is related to the density of the crude at 16ºC asfollows:

The larger the API value the lighter the oil, thus low API gravity oils arehigh density. API values are estimated by the wellsite geologists and mud-loggers by observing natural fluorescence under UV light and, occasionally,by using refractometers.

Natural fluorescence ranges from dull brown through yellow gold and bluewhite to colourless as the API gravity increases. Oils at the end of the scalecan be difficult to detect by visual fluorescence methods alone.

API Gravity 141.5S.G. at 16°C------------------------------- 131.5–⎝ ⎠⎛ ⎞=



Gas Detection & EvaluationMud logging is performed by using the returning mudstream as a mediumof communication with the bottom of the hole (bottomhole). There is a rela-tionship between the kind and amount of gas or oil (or both) in the drillingmud arriving at the surface, and the gas and oil (or both) that was in placein the formation being drilled at the time that portion of mud was passingbottomhole. The gases, if present, are released by the cuttings into the mud-stream and entrained, probably in solution, in the drilling mud. It remains,then, to remove and detect this parameter from the mudstream. To do this,the following equipment is used:

The Gas TrapTo meet the unique requirements of mud logging, this device must performimportant functions:

• Extract the gas contained in the drilling mud, independent of such variables as density, viscosity, and gel strength of the mud

• Sample consistently, regardless of the flowrate of mud through the circulating system

The gas trap is a steel container that sits in the mud ditch (as near to theflowline exit as possible, but before the shakers) and allows the drilling fluidto continuously pass through it by means of slots in the base. An agitatormotor sits on top of the gas trap and has a propeller shaft extending into it.The propeller continually agitates the drilling fluid as it passes through thetrap. A continuous flow of air enters through a vent in the top of the trap andis whipped through the mud where the maximum mud surface is exposed. Itis this air-gas mixture that is subsequently drawn into the gas detector.

The Vacuum SystemAfter the gases are removed from the mud, they are transported to the gasdetector in the logging unit. This is accomplished by a vacuum pump whichis connected to the trap by a length of hose. Through this hose the pumppulls a continuous measured stream of fresh air through the vent in the trap.Because the gases, if present, are being continuously extracted from the mudin the trap, they are mixed with this stream of air and carried into thelogging unit via a condensate bottle, where water vapour is extracted. Theflow of air, or air-gas mixture, passes through additional flow-regulationequipment, plumbing, and instruments and arrives at the detector where acontinuous gas reading is obtained.



Figure 2: Basic Gas Trap

Figure 3: QGM Gas TRap



The Gas Detection System

Catalytic (Hotwire) Gas DetectorThis instrument functions on the principle of catalysis, i.e., the catalytic oxi-dation of gases on a filament in the presence of air. It is an application of theWheatstone bridge measuring circuit in which a resistance (the detector fil-ament), which varies according to the concentration of gas, is balancedagainst a fixed standard (the reference filament). The reference filament iscoated with an inert compound to seal the catalytic surface from the atmos-phere, and the imbalance is measured. With the normal voltage appliedacross the entire bridge, both filaments are heated sufficiently to oxidise allgaseous hydrocarbons.

Before the gas detector is placed in operation, it is calibrated using air as astandard. A valve (zero adjust) is opened to admit fresh air to the system,

Figure 4: Vacuum System



which places both filaments in a like atmosphere in which the gas concen-tration is zero. By adjusting the zero potentiometer, the gas meter, which isa sensitive milliammeter, is adjusted to read zero. Electrically, the gasdetector is then said to be in balance. The zero adjust valve is then closed,and the filaments will be in whatever atmosphere is being created in thetrap. As long as no gas is being liberated from the mud, the filaments remainin an atmosphere of air and the detector reads zero units of gas. However, assoon as any gas from the mud becomes mixed with the air being drawnthrough the detector, the filaments are surrounded by this atmosphere.Having free access to the detector filament, this mixture oxidises. The oxi-dation creates heat; the detector filament temperature is increased (increas-ing resistance); the electrical balance is upset; and current flows through themilliammeter.

Figure 5: Catalytic Detector



The greater the gas content present, the greater the electrical imbalance andthe resultant gas reading will increase. To quantify the gas reading, a knownconcentration of combustible gas, usually methane at 1% by volume in air ispassed over the filament and the gas reading is adjusted to reflect the con-centration. Older style gas detectors may display gas concentration in“units” and various mud logging companies use different definition of whatconcentrates a “unit”.

Traditionally, API has used 50 units equals 1% with catalytic gas detectorand each log heading explains what calibration has been used.Because of thevarying values of the term unit, it is common to report gas readings on theMud Log in terms of percent-methane-in-air, or parts per million, as well asin units, in order that well to well comparisons can be made of gas read-ings.In the catalytic system, if the gas concentration becomes greater than 2percent, the mixture must be diluted so that the readings will be on-scale.This is accomplished by introducing air from the atmosphere into the air-gasmixture and is controlled volumetrically by air flowmeters. When thevolume of air-gas mixture is reduced by one-half, the scale of the milliamme-ter (and the recorder) is effectively doubled and the gas reading shown mustbe multiplied by two.

Flame Ionisation Gas Detector (FID) With this system a continuous sample is fed into a regulated, constant-tem-perature hydrogen flame. The flame is situated in a high-potential (300volts) atmosphere between two electrodes. As combustion occurs, the gasionises into charged hydrocarbon resides and free electrons. A predictablyconstant ratio of these charged particles moves immediately to the positiveelectrode, inducing a current at that probe. The amount of current inducedis proportional to the total ion charge produced in the flame and increases asthe percentage of hydrocarbons in the sample increases. The ion chargebecomes essentially a measure of the total number of carbon to hydrogenbonds present in the air-gas mixture.

The FID detector meter displays the percentage of methane-equivalent (C1)hydrocarbons present in the ditch sample. It is calibrated to read 1.00 whena 1% methane calibration gas burns in the FID. When burning a ditchsample containing heavier petroleum vapours (those with a greater numberof carbon-hydrogen bonds in the molecular structure than in methane), themeter displays a reading reflecting the proportionately greater number ofcarbon-hydrogen bonds.

For example, when burning a 1% concentration of pentane (C5), the meterreads 5.00; when burning a 2% pentane or a 10% methane mixture, themeter reads 10.00 (2% pentane = 2 x 5 =10 carbon-hydrogen bonds; 10%methane = 10 x 1 = 10 carbon-hydrogen bonds. Each of these readings indi-



cates that the relative concentration of combustible hydrocarbons is 10 timesgreater than that in the calibration gas.

Cuttings Gas AnalyserThe blender gas analyser is used to check the combustible hydrocarboncontent of the drilling mud and cuttings. It differs from the ditch gasanalyser in that it is a batch system. Samples of the drilling fluid andcuttings are collected and checked periodically - and always during any ditchgas shows. These samples (approximately 100 cm, but always a consistentamount) are placed in the blender jar and agitated for a standard length oftime, and the resultant air-gas mixture is drawn through the catalytic gasdetector. The gas combustion, air dilution, milliammeters, voltmeters andflowmeters are all identical to (and are employed in the same manner as)those in the ditch gas analyser. But as this is a batch system, no recorder isused and the gas readings are read directly from the milliammeters as gasreadings.

On prospective gas wells the blender gas results are used mainly as a checkon the ditch gas analysing system. On prospective oil wells and wildcatwells, the cuttings gas is extremely important as it may form the basis for

Figure 6: FID Detector



further evaluation as an indicator of reservoir porosity and permeability, orof source rock.

ChromatographyThe chromatograph separates and analyses hydrocarbons in the ditch gassample to determine how much of each hydrocarbon is contained in thesample. There are two common types of chromatograph: the catalytic detec-tor, and the flame ionisation detector (FID). Each separates and records thegases in a similar manner, but the difference between the two is the way inwhich the various gases are detected once separation has occurred.

Catalytic ChromatographThe catalytic chromatograph separates the hydrocarbons by passing thesample through a tube containing a compound of hexadecane and firebrick.The compound is housed in coiled aluminium columns, and a predeterminedquantity of the sample is cycled through the columns at 5-minute intervals.The principle of chromatography is that, when forced through a certainmedium, different compounds move at different rates depending on theirmolecular weight.

Lighter hydrocarbons pass through the columns first, followed by theheavier molecules. The order in which these hydrocarbons arrive at the

Figure 7: Cuttings Gas Detector



detector are: methane (C1), ethane (C2), propane (C3), isobutane, (iC4), andnormal butane (C4). The columns are held at a constant temperaturebetween 100 to 150 degrees F inside the oven to ensure a constant flowratethrough the columns. The hydrocarbons flowing to the filament blockcatalyse on the active filament.

When the hydrocarbon to be tested enters the chamber, the carrier air andthe hydrocarbon combine on the filament. The filament remains unchanged,but the catalysis causes the filament to heat in proportion to the hydrocar-bon concentration in the sample. The active filament is an integral part of abalanced resistance (Wheatstone) bridge which has a normal output of 0volts. When catalysis occurs, both the current through, and resistance of, thefilament change, and the output of the bridge varies. The output of thebridge then goes to the recorder.If higher than butanes analyses arerequired (e.g. pentanes (C5)), the chromatograph can be set to HOLD and

Figure 8: Chromatograph Schematic



the cycle is extended beyond the normal 5 minutes. There are a few disad-vantages to the catalytic chromatograph:

• The theoretical upper limit of sensitivity of the hot-wire filament for methane is 9.5%.

At higher concentrations, reversals occur due to insufficient oxy-gen being available for complete combustion, and the excessmethane cools the filament.

• It has a negative response to carbon dioxide.

• It is affected by large amounts of nitrogen and suffers thermal drift due to temperature changes.

FID ChromatographOnce separation has occurred, the individual hydrocarbons go to a circularchamber inside an aluminium block for detection. This chamber (the FIDchamber) completely encloses a hydrogen flame which is not affected bylogging unit pressure or by normal amounts of carbon dioxide and nitro-gen.The hydrocarbons are mixed with the hydrogen flow and heated in thechamber. The detector response is essentially proportional to the carboncontent of a molecule and depends upon the quantity of gas entering theflame per unit of time. Mixing hydrocarbons with the hydrogen flameproduces ions which are attracted to a probe in the FID chamber. The ionsthen flow to a high-gain amplifier, then to a chart recorder and digital meter.

The FID has a greater dynamic range and has a wider linear range than thecatalytic chromatograph. It is also less likely to be affected by temperaturechange.

The ChromatogramThe chart recording of the gas-air mixture is termed a chromatogram. Thesensitivity of the detector to each gas is established on a regular basis bypassing a calibrated sample through the column. This calibration mixturecontains known concentrations of methane through pentane.



Gas Show Evaluation

Origin of Gas ShowsA gas show can be defined as a significant occurrence of hydrocarbon gasesdetected from the mudstream and identifiable as being the result of thedrilling of a specific increment of formation.The object of good mud loggingis to plot those gas readings produced by gases liberated from cut formationin conjunction with those data relevant to their interpretation. The object isto reconstruct from these data the composition and mobility of reservoirhydrocarbons. In order to reconstruct a picture of the fluids in place in a for-mation and the type of fluid the formation may produce, it is necessary tostudy gas magnitude and composition in the mudstream and cuttings, geo-logical and physical character of the cuttings themselves, and changes in the

Figure 9: Chromatogram



drilling process and circulation system which may affect or be affected byformation fluid behaviour. Prior to examining the factors affecting gasshows, some definitions are in order:

True Zero Gas

Figure 10: Total Gas Chart Recording



This is the value seen by the gas detector when pure air is passed across thedetecting element. Some gas is seen by a gas detector when circulating withthe bit off-bottom and with no vertical movement. Under such normal condi-tions, meaning a clean, balanced borehole, some gas will be present in thesample drawn from the mudstream, but it will represent only contaminationor recycled hydrocarbons in the mud. This value is taken as the baselineabove which all gas readings are taken for drafting on the mudlog. The back-ground zero will vary continually with additions to the mud system, andwith mud and ambient temperature. The value must be regularly re-estab-lished to allow accurate, consistent gas logging.

Background GasWhen drilling through a consistent lithology, it is common for a consistentgas value to be recorded. Certain lithologies (for example, overpressuredshales) may show considerable rapid variation in Background Gas butusually with some consistent average value.

Gas ShowThis is any deviation in gas, amount or composition, from the establishedbackground. This may or may not accompany a change in lithology, may ormay not be as a result of the drilling process, may or may not indicate a sig-nificant or economic hydrocarbon accumulation. It is the responsibility of theLogging Geologist to interpret the gas show to determine it’s cause and sig-nificance.

Types of Gas Show“What is a good gas show?” is a common question asked of the logger. Theanswer to this is complex and relates to many factors beyond the simplenumber of gas units seen. To decide whether a gas show is good or poor, i.e.whether or not a significant hydrocarbon accumulation is indicated, requiresa total evaluation of all mud log parameters plus consideration of the manyvariable system conditions.

Sources of Gas in MudGas detected in the mud stream may originate from the formation via anumber of mechanisms. It is necessary for the geologist to isolate andattribute these causes in order to draw the appropriate conclusions. Gasoriginating from other sources or only indirectly from the formation will alsobe seen in the mudstream. This must, if possible, be recognised and removedfrom consideration.Drilled Gas This is often referred to as liberated gassince it is liberated into the mudstream from the crushed cylinder of forma-tion produced by the drilling process.



Post-drilling Gas Sometimes referred to as produced gas, since it is gas which has flowed fromthe formation into the borehole in the same manner as if the formation wereto be produced. Post-drilling gas, i.e. gas entering the borehole from theborehole wall or bottom when drilling is not taking place, is of two distincttypes:

SwabbingWhen pipe is pulled from the hole, or circulation halted, a condition of under-balance may exist at some point in the borehole. The differential pressure tothe advantage of the formation will cause fluid to flow into the borehole fromthe formation.

Figure 11: Sources of Gas



FiltrationIn a condition of balance or even with some overbalance there will be a con-tinual diffusion of fluids between the formation and the borehole. This willbe encouraged by removal of filter cake by pipe movement and by the flow ofdrilling fluid past the exposed borehole wall.

Recycled Gas Not all of the gas entrained in the mudstream will be liberated at the gastrap. If insufficient degassing takes place in the surface mud system, drillingfluid containing gas may be pumped back into the borehole. Travel of thelight gas-cut mud past gas-bearing formations in the borehole may encour-age diffusion of more gas into the mud.

Contaminants Gas resulting from the addition of petroleum products to the drilling fluid orfrom the degradation of normally inert mud additives may result in anoma-lous gas shows. Similar anomalies may result from the presence in the cir-culating system of crude oil from previously drilled or tested formations

Factors Affecting Gas ShowsAlthough the crushed cylinder of formation produced by drilling releases aquantity of gas which may be detected at the surface, this gas undergoesmany influences between the formation and the gas detector.

Downhole Influences

FlushingIt is well known that where borehole pressure exceeds formation pressure,and permeability exists, the drilling fluid will tend to flush into the forma-tion. If the solids diameter is sufficiently high, filtration will result. Suchflushing commonly causes little formation damage since invasion takesplace only a short distance into the formation. However, where effectiveporosity is low, only a small volume of flushing may give a large diameter ofinvasion. Displacement of gas some distance from the borehole in this waymay reduce the reservoir’s gas saturation and effective permeability to gasclose to zero in the vicinity of the borehole. Thus a zone which gives good gasshows when drilled will appear water-bearing or recover only mud filtratewhen logged or tested.

Flushing will also take place at the bottom of the hole when an overbalanceexists. In this circumstance no permanent mud filter cake can be formed dueto the continuous action of the bit. Flushing below the drill bit will have mosteffect when the reservoir has high permeability and effective porosity. Thedifferential pressure to the advantage of the borehole combined with high



impact force due to the jet nozzle pressure drop will force mud filtrate intothe formation ahead of the bit.

When the formation is eventually drilled, little or no gas will be liberated. Atthe surface, a flat unresponsive gas curve will be seen which may evenindicate less gas than in nearby lithologies. Since permeability is high, thereservoir will return to it’s natural state soon after drilling, and an appar-ently water-bearing reservoir will later be logged or tested as productive.

Figure 12: Flushing



Common good drilling practice in minimising mudweight and water loss willbe advantageous in reducing flushing. On the Mud Log, the following infor-mation should be recorded for proper interpretation of possible flushing:

• Pump Pressure

• Jet Nozzle Sizes

• Mud Rheology/Mud Weight & ECD

• Estimate of Pore Pressure

• Water Loss

• Lithology Description including visual porosity.

A formation indicating high porosity and permeability confirmed by a goodrate of penetration, which shows little or no gas in either mud or cuttings,should be strongly suspected of being flushed prior to drilling - especiallywhere an overbalance exists. However, the possibility does exist that the for-mation contains only water without even gas in solution. This possibilitymay be confirmed or rejected by monitoring mud salinity.

Fluid IncursionThe incursion of fluid into the borehole may result from a number of causes,some but not all of which result from an underbalanced condition of either atemporary or permanent nature. Where an underbalanced condition exists,there is a natural tendency for fluid to flow from the formation into the bore-hole. Where a formation exists having good porosity and permeability, thisflow may be massive and a kick could occur.

Where an underbalance sufficient to cause a kick exists but there is insuffi-cient permeability to sustain a massive fluid influx, a steady fluid feed-inmay result. If this minor flow is from discrete formation already cut, it willbe noticeable- producing a sustained minimum gas background even whencirculating, but not drilling. If the feed-in is from the formation currentlybeing drilled, then as a greater and greater area of formation in the boreholewall is exposed by drilling, increasing flow will take place.

If this is the case, the mud gas will exhibit a sustained minimum when cir-culating but will consistently rise as drilling proceeds. Cuttings gas willinevitably be high relative to mud gas since is only lack of permeabilitywhich is preventing the feed-in from becoming a kick.

When permeability i.e. effectively absent, e.g. in clays and shales, evenminor feed-in cannot take place. Fluid pressure in the rock will gain accessto the borehole by the opening of pre-existing microfractures and partings in



the rock. The result will be the caving or sloughing of rock fragments intothe borehole, accompanied by a small amount of gas. As above, a minimumgas background and, in this case, cavings recovery will exist even when cir-culating without drilling.

Figure 13: Connection Gas



At connections and trips, the reduction in bottom hole pressure may causethere to be a temporary underbalance condition. Downtime gas or connec-tion gas is a gas show resulting from this momentary underbalance due topump shutdown and/or pipe movement. It can be recognised by the occur-rence of discrete gas show appearance at, or slightly less than, the lag timeafter circulation recommences.Fluid incursion into the borehole may alsooccur when there is a balanced or even slightly overbalanced condition. Thissituation is associated with the flushing effect already mentioned. Where asufficient thickness of formation has been cut and vertical permeabilityexists, it is possible for these displaced formation fluids to be displaced backinto the borehole at some point above bit turbulence. The effect of this duringnormal drilling will be to effectively delay the appearance of a gas show untilsome time after the formation is cut. Such a mechanism is termed sweeping.

Figure 14: Kelly Cut Gas



Formation Porosity and SaturationThe amount of gas released to the mudstream from a specific interval of for-mation will depend on:

• Total Porosity

• Effective Porosity

• Effective Permeability

• Gas Saturation

• Drill Rate

Assuming that all other formation, mud and drilling considerations are heldconstant, the amount of gas liberated to the mudstream by drilling will be afunction of the total volume of effective porosity exposed to the mudstreamby the cutting action of the bit. This will be dependent upon the volume ofthe cylinder of formation cut. It will also vary with bit selection since differ-ent bits provide different sizes of cuttings.A formation identical in all wayswill produce higher mud gas readings if drilled at a higher rate of penetra-tion.

Bit Size and TypeThe second factor controlling the volume of the cylinder of formation cut isthe hole diameter. Also the size of the teeth on the bit, which is governed byboth bit type and size, will control the size of cuttings produced. Wherecuttings are smaller and more numerous, formation fluids will be moreeasily liberated from non-effective porosity and inferior permeability, givingimproved gas shows.

Flow RateThe volume of gas or cuttings entering any volume of mud passing bottomwill be a function of mud flowrate. Since mud logging gas analysis dependsupon the analysis of gas extracted from the mud, changes in flowrate willaffect the apparent gas show magnitude. As mud flowrate increases, thevolume of gas and cuttings contained in a fixed volume of mud will decrease.Conversely, the volume of mud passing through the gas trap will increase.The net effect should be zero. In fact, the complex geometries and variableefficiencies of the various parts of the system will introduce some variations,but the overall effect is probably not great. Furthermore, mud flow rate willnot vary greatly within any hole size or in relation to hole size within holesections. This further removes the severity of this effect.



Borehole ContaminationA common source of gas contamination is the degradation of organic-basedmud additives, e.g. lignosulphonate dispersant. These will degrade due tothe effect of heat and with the catalytic support of the clay ion exchange siteson the mineral matrix. The common product of degradation is methane,although more complex hydrocarbons may also be present.

The second major cause of contamination is the addition of small amounts ofcrude or diesel oil to the mud as a lubricant. Crude oil may be a seriousproblem since it will mask later oil or gas shows. The more commonly useddiesel oil is much less of a problem since the gases liberated from it and it’sappearance in samples are atypical for a natural crude oil.The gas content,due to contamination of the mud, will continually vary. As oil additions aremade and recycles occur, peaks will develop in the system. It is importantthat the logging geologist regularly re-establish the background zero abovewhich gas shows are read.

Figure 15: Bit Size



Surface InfluencesAlthough there are many factors which can affect the liberation and trans-port of gas to the surface, it is readily observed that the most importantfactors controlling the final magnitude of a gas show are the rig’s surfacesystem and the extraction, pneumatic, and detection systems of the mudlogging unit.

FlowlineIt is well known that a high degree of degassing takes place in the conductorand flowline. Loss of gas in the flowline will be especially important where:

• Flowline is not filled with mud

• Changes in slope promote turbulence

• Sections of the flowline are open to the atmosphere

• Flowline enters the possum belly above the mud level. Geometry of the ditch will be of considerable effect in the volumeof mud and gas available to the gas trap. Location of flowline en-try, direction of major flow and degree of turbulence will all affectthe efficiency of the gas collection system.



Gas Trap

The efficiency of the gas trap can vary between 30% and 70% dependingupon design, location and mud properties, but most importantly uponcareful maintenance and good operation. The trap and it’s immediate sur-roundings should be kept clear of cuttings debris, settled debris, or mudcaking, all of which may restrict or modify the flow of mud and air throughthe trap.

Figure 16: Rate of Penetration



Mechanical efficiency of the trap is controlled by the rotational speed andsurface blade area of the trap impeller, strength of vacuum and flowrate ofair from the trap.

Even when installation and maintenance of the gas extraction systemensures maximum mechanical efficiency, there will be variations in theoverall efficiency of the extraction and the magnitude of gas shows. This willdepend on the composition of gas present, distribution of gas in the mud, vis-cosity and gel strength of the mud, and flowrate.

Summary the magnitude of gas shows recorded on the logging unit’s gas detectionsystem and their interpretation will depend on numerous factors, including:

• Formation characteristics - porosity, permeability, satu-rations

• Flushing effects - controlled by overbalance, mud waterloss, formation porosity/permeability

• Volume of formation cut - controlled by drill rate, bit di-ameter

• Size and nature of cuttings - controlled by bit design

• Flowrate - to a small degree

• Produced, recycled and contamination gas in mud

• Loss of mud at surface - flowline, ditch characteristics

• Gas Trap Efficiency

• Vacuum System

• Gas Detection Equipment efficiency and calibration.

In order to account for a number of variables so that gas readings can bebetter compared between wells, Gas Normalisation techniques can beemployed.



Gas Ratio AnalysisGas ratio techniques are based on the theory that an increasing hydrocarbonfluid density in the reservoir will manifest itself at the surface as an increas-ing gas density. Thus, while a quantitative analysis of surface gas to reser-voir fluid is not possible, a qualitative analysis is possible.The most commonmethod used today was developed by Baker Hughes INTEQ, and comprises:

• Gas Wetness Ratio

• Light-Heavy Ratio

• Oil Character Qualifier

Gas Wetness Ratio (GWR, Wh)

Note: The ratio is multiplied by 100 only to obtain a percentage; thus it canbe plotted alongside other ratios (e.g. LHR). The Gas Wetness ratio has beenextensively used in the past, especially for geochemical soil sampling.TheGWR value increases with increasing fluid density, and setpoints have beenestablished as follows:

Gas Wetness Ratio Fluid Character

0.5 Very dry gas

0.5 - 17.5 Gas, increasing density

17.5 - 40 Oil, increasing density

>40 Residual oil

Figure 17: Hydrocarbon Types from Wetness Ratio

C2 C3 C4 C5+ + +C1 C2 C3 C4 C5+ + + +-------------------------------------------------------------- 100×



Light-Heavy Ratio (LHR, Bh)

This ratio has an inverse relationship with the GWR, and decreases withincreasing fluid density. Methane and ethane are included in the numeratorto place the two primary coal gases together. This removes the coal-bedeffects that could cause anomalies in the GWR ratio. The relationship of theGWR and LHR curves gives a visual interpretation of the fluid nature asfollows:

• If LHR is greater than 100, the zone is excessively dry gas (probably unproductive).

• If GWR is in the gas phase and LHR is greater than GWR, then as the curves get closer, the gas gets denser.

• If GWR is in the gas phase and LHR is less than GWR, then gas/oil or gas/condensate is indicated.

• If GWR is in the oil phase and LHR is less than GWR, then the greater the separation, the greater the density of oil.

• If GWR is in the residual oil phase (GWR 40) and LHR is less than GWR, then residual oil is indicated.

Oil Character Qualifier (OCQ, Ch)

Anomalies caused by methane occur if there is low permeability, water, a gascap, or dual gas/oil production with a higher gas-to-oil ratio. These anoma-lies cause a dampening effect on the movement of the GWR and LHR curves,impeding the interpretation of fluid density. The OCQ ratio was chosen tooffset this anomaly. The relative increase in methane that occurs in thesesituations accompanies a relative increase in C4 rather than C3. Althoughnot fully studied, this occurrence probably represents the increasing iC4rather than the nC4 isomer.

After the GWR and LHR curves are compared, the OCQ curve must bechecked. If OCQ is less than 0.5, gas potential is indicated and GWR versusLHR interpretation is correct. If OCQ is greater than 0.5, gas associatedwith oil is indicated.

C1 C2+C3 C4 C5+ +----------------------------------

C4 C4 C5+n+iC3

--------------------------------------



Figure 18: Gas Ratios and Fluid Tying



Figure 19: Gas Ratio Log



Gas NormalisationAbsolute quantification of a gas show is not possible in mud logging; thereare too many in situ and drilling variables to calculate during the initialevaluation. The in situ variables include porosity, relative permeability, gassaturation, temperature, pressure, solubility, and compressibility of thegases. Once the formation has been penetrated by the drill bit, other varia-bles come into effect - flushed saturation, rate of penetration, pump rate,hole size, rock and gas volume, differential pressure and temperature, phasechanges, and surface losses.

Normalisation is a mathematical treatment of parameters that affect gasshows. Although attempts have been made to cover downhole effects such assaturation, temperature, pressure etc., normalisation do not try to coversurface losses caused by the variations in flowline and ditch geometries andgas trap efficiencies.

The most common form of normalisation involves correction for drill rate,hole size, and pump (flow) rate. Since these three parameters are continu-ously monitored while drilling, their values can be used immediately in nor-malisation calculations.Ideally, there should be a universal set of standardparameters for hole size, drill rate and flow rate. In reality, however, anideal situation in one area may not be ideal in another.

Another problem is the quantitative use of carbide data. Some authoritieslike to normalise for the carbide gas peak. Sometimes, though, this can intro-duce more variables than the quantity it corrects.

The basic normalisation formula which corrects for drill rate, hole diameter,and flowrate is:

Where:

ROPo = observed drill rate (ft/hr)

Qn = normalised flow rate (gpm)

Qo = observed flow rate (gpm)

dn = normalised hole diameter (inches)

Gn

Gd ROPn πDn2

------⎝ ⎠⎛ ⎞

2Qo 1××××

ROPo πDo2

------⎝ ⎠⎛ ⎞

2Qn E×××

---------------------------------------------------------------------------=



do = observed hole diameter (inches)

Gd = ditch gas reading (units)

Gn = normalised ditch gas (units)

E = Gas Trap Efficiency

This formula represents an approach to gas normalisation. There may beother factors that can be included such as mud density or ECD and porepressure which may make the normalisation more useful.


Sedimentary Petrology

Classification of Sedimentary Rocks

Grain Size ParametersThe basic descriptive tool for all sedimentary rocks is grain size. The mostwidely used is the Udden-Wentworth scale which divides sediments intoseven grades:

• Clay

• Silt

• Sand

• Granules

• Pebbles

• Cobbles

• Boulders

Furthermore the silts and sands are sub-divided into intermediate classes.The full scale is shown below.

These sedimentary rocks are also referred to by descriptive names, alsobased on grainsize, for example:

• Clays: Argillaceous

• Sands: Arenaceous

• Pebbles etc.: Rudaceous

At the wellsite, grain size is determined by visual inspection and estimatedaccordingly. There are several methods for accurate determination in thelaboratory, but these are not applicable for wellsite use due to time andequipment limitations, although some software is becoming available tohelp.

Within the major grain size based classifications listed above there is a needfor more detailed notation in order to address variations in content (rockfragments and mineralogy) and environments of deposition.



Classification of SandstonesThe classification produced by Pettijohn splits sandstones according to theproportion of grains to matrix and also by content of the relative amounts ofQuartz, Feldspar and Rock fragments.

Figure 1: Udden-Wentworth Grain Size Scale

Boulder

Cobble

Pebble

Granule

Very Coarse Sand

Coarse Sand

Medium Sand

Fine Sand

Very Fine Sand

Coarse Silt

Medium Silt

Fine Silt

Very Fine Silt

Clay

256.00

64.00

4.00

2.00

1.00

0.50

0.25

0.125

0.0625

0.031

0.016

0.008

0.004

mm Clastic Sediments Rock Names Other Names

Conglomerates

Sandstones

Siltstones

Claystones

Gravel

Rudite

Rudaceous Sediments

Breccias

Sandstone

Arenaceous Sediments

Arkose

Siltstone

Mudstone

Shale



Quartz ArenitesThese represent sandstones with at least 95% quartz grains and are there-fore the most mature sandstones. Frequently they are also well rounded andwell sorted.

ArkosesThese are sandstones containing more than 25% feldspar, with the restbeing quartz grains and rock fragments. They are typically red or pinkbecause of the feldspar colour, and also due to iron staining.

They are derived from granite and gneiss and typically are deposited closeto the source. Texture is typically poorly sorted with angular to sub roundedgrains. They are often indicative of arid conditions since moisture willpromote the weathering and destruction of feldspar.

LitharenitesThese are composed mainly of rock fragments. cements are usually calcite orquartz. They indicate fairly rapid deposition and short transport distances.

GreywackesCharacteristically they are composed of quartz grains held by a fine grainedmatrix. Many rock fragments are also usually present. They are often darkcoloured, even black rocks, sometimes resembling dolerite. Many grey-wackes were deposited by turbidity currents on continental shelves, oftenassociated with volcanic activity.

Classification of MudrocksThese are the most abundant of all sedimentary rocks, constituting almosthalf of all sedimentary sequences. Major depositional sites are floodplains,lagoons, lakes, deltas and ocean floors.

The main constituents are clay minerals and silt sized quartz. According tograin size, clay is less than 4mm in diameter, though by mineralogy it is ahydrated aluminium silicate with a specific sheet structure. Terminologyapplied to mudrocks can be confusing, and in the oil industry is largely con-trolled by the specific operator and the system of classification that theyhave adopted.

ClaystoneThis is a general term describing fine grain rocks composed mainly of clayminerals.



MudstoneSynonymous with claystone but can be confusing if the Dunham classifica-tion of carbonates is being used since there is a limestone also referred to asmudstone.

SiltstoneAn argillaceous rock composed mostly of silt sized particles, between 4 and62 mm.

ShaleThis is a much abused term at the wellsite, being used by most “non-geolo-gists” to describe any mudrock. The term shale has a specific meaninghowever, and refers to a mudrock that, because of composition, compactionand burial, shows lamination and fissility. It should not be used as a genericdescriptive term for all mudrocks.

Classification of LimestonesThere are many classification schemes for limestones, but all differ signifi-cantly from those adopted for clastic sediments. Most limestones are formedin situ and thus textural features, based on grain size and shape as a resultof erosion, transportation and deposition, do not really apply. The importantfeatures are the nature and type of component grains and the cement ormatrix which holds them together.

The most commonly used classification scheme in the oil industry is theDunham Classification. This splits limestones according to the amount ofgranular material, whether or not it is self supporting, and the type ofmatrix or cement holding it together. These features provide an indicationof environment and energy levels present at formation. The descriptiveterms used are:

MudstoneRocks composed mainly of fine grained carbonate mud with less than 10%grains.

WackestonePredominately mud supported grains,, which comprise more than

10% of the total volume.



PackestoneGrain supported limestones held by a fine grained carbonate mud matrix.

GrainstoneGrain supported rock held by crystalline calcite cement. No carbonate mudis present. The terms floatstone or rudstone are used if 10% of more of thegrains are greater than 2mm in diameter.

BoundstoneOrganically bound rocks produced by algae or other encrusting or bindingorganisms.


Mudrocks

Textures and StructuresFine grained argillaceous rocks do not show the variety of textures andstructures that are present in sandstones and limestones. Colour, bedding

Figure 2: Dunham Classification (Limestones)



and lamination, mineralogy, accessories and organic content are the keyareas to describe when dealing with mudrocks.

ColourThe colour of a mudrock is a function of its mineralogy and geochemistry,with the main controls being organic content and oxidation state.

Red/Purple Oxygen rich environment

Ferric oxide - Haematite

Green/Grey Reducing environment

Ferrous Iron - Pyrite

Blue/Multi Often volcanic tuffs composed ofmontmorillonite/bentonite

Bedding/LaminationLamination is mainly due to variations in grain size or component types.Size graded lamination may be a result of turbidity action or from suspen-sion characteristics following storm currents. Compositional variation maybe a result of seasonal changes in sedimentation or biological activity. Varvedeposits of glacial lakes representing spring deposits are typical examples.Siltstone deposits may show small scale ripples and wavy bedding charac-teristics. Many mudrocks are massive, showing no signs of bedding or lami-nation. They may however contain concretions or nodules of calcite, siderite,pyrite or chert. These are probably formed at or just below the surfaceduring deposition, and often show evidence of boring or other organic distur-bance.

CompositionClay minerals are hydrous aluminosilicates with a sheet or layered struc-ture. The most common is built from silicon-oxygen tetrahedra linkedtogether to form a hexagonal network. Aluminium and magnesium mayreplace some of the silica.



Smectite Group Montmorillonite Al4(Si4O10)2(OH)4nH2O

Illite (related to muscovite mica) KAl2(OH)2[AlSi3 (O, OH)10]

Chlorite Substitution by Fe2+ gives green colour

Figure 3: Bedding & Lamination



Glauconite Substitution by Fe3+ gives green colour

Kaolinite (OH)4Al2Si2O5

Sandstones and Conglomerates

TexturesThe texture of a sandstone or conglomerate is largely a reflection of the dep-ositional process. Consideration is given to grain size, grain morphology,surface texture and fabric. The size, shape and degree of sorting are impor-tant reservoir characteristics, controlling porosity and permeability.

Grain Size and SortingThis is the basic descriptive element of all sedimentary rocks. The Udden-Wentworth grain size classification is most commonly used. Whilst grainsize does not affect porosity, it has a major bearing on permeability togetherwith grain size distribution, or sorting. When describing sandstones at thewellsite it is important to accurately note these features so that some indi-cation of reservoir characteristics may be inferred from the rock description.

Cuttings evaluation produces the first available information regarding thelithology, unless MWD Gamma Ray and/or Resistivity is being run, and,depending on future circumstances, may be the only reservoir informationavailable if logs, cores or formation tests don’t go quite according to plan.

In the laboratory grain size and distribution can be measured and statisti-cally interpreted. Neither time nor facilities are available at the wellsite todo this, so visual estimations have to be made, but which nonetheless needto be as accurate as possible and convey the correct information to thereader.

Grain size comparator cards are available that can be used under the micro-scope to assist in this evaluation. Key information to be reported is:

• Size of individual grains

• Mean grain size of specific cuttings

• Mean grain size of the entire lithology

Where there is a large variety of grain size, maximum and minimum valuesshould be noted and, where there are perhaps two distinct, but differentgrain sizes present, it should be referred to as bi-modal. Sorting is generallydescribed using the following terms:



• Very Well Sorted

• Well Sorted

• Moderately Well Sorted

• Poorly Sorted

• Very Poorly Sorted

Sorting is determined by parent material, grain size and transportation.Sandstones derived from granites are usually more poorly sorted than thosederived from sands because of less working being applied. Similarly con-glomerates and gravels, having a large grain size will also be more poorlysorted because of the relative lack of transportation compared with sand sizegrains.

Figure 4: Grain size card



Grain MorphologyThe shape of sand grains is another important factor in reservoir analysis.Both porosity and permeability will be affected. Well rounded, perfectlyspherical grains will show the best porosity and angular, elongated grains,the worst. it is necessary, therefore, to describe both these features accu-rately at the wellsite to give the best possible early indication of potentialreservoir quality. Roundness is to do with the curvature of the corners of agrain. The following terms are used:

• Very Angular

• Angular

• Sub-angular

• Sub-rounded

• Rounded

• Well-rounded

Sphericity will have some bearing on how well packed the grains maybecome. Perfectly spherical grains of the same size will show greaterporosity than elongate grains.

Grain Surface TextureThe surface of sand size grains often have a distinctive texture and givemajor clues to environments of deposition. The dull, frosted and pittedsurfaces of desert sand grains are a distinctive example. Beach sands oftenshow V-shaped percussion marks. Crescent shaped impact marks are some-times visible on river channels and also some beach sands. Glacial depositsshow conchoidal patterns and striations.

FabricThis describes how the grains are packed together. It concerns the nature ofboundaries between grains and any preferred alignment. Fluviatile depositsmay show alignment with, or sometimes normal to, the prevailing currents.Glacial deposits may also show orientation of clasts parallel to ice move-ment.

It is unlikely that fabric will be able to be determined from drill cuttings oreven cores, unless very small scale.



Cement or MatrixThe nature of the material holding the grains together is another importantdiagnostic feature. The amount and type of cement or matrix will have aneffect on porosity and permeability and also influence drilling rate and drillbit selection. Common cements are calcite, silica or iron minerals. Whereverpossible the type of cement should be established using visual inspection,colour criteria and dilute HCl. Calcite cements will show a reaction to diluteHCl, whereas silica and iron cements will not. Red/Brown colouration is verydistinctive of ferric iron cements such as haematite.

PorosityPorosity has been mentioned above as an important criteria in reservoiranalysis. Some estimation of visual porosity needs to be made from drillcuttings analysis. This will be a subjective opinion as again there is not thetime or equipment available to make accurate measurements at the wellsite.

Experience obviously plays a part here, and so does the analysis of graintexture already made. Clearly a coarse grained, well sorted sandstone withspherical grains showing poor cementation should have good visible poros-ity. Perfectly spherical, equi-sized grains packed loosely together would havea maximum porosity of 47.6%. This can drop to 26% for a compacted

Figure 5: Grain shape card



sediment and less when cemented or poorly sorted. The following descriptiveterms are used to represent the associated porosity values:

Porosity Description Amount (%)

Good >15

Fair 10

Poor 5 - 10

Trace 5

Figure 6: Porosity Terminology

Figure 7: Porosity (cubic Packing) 47%



It should be noted that very fine grained sandstones may have good inter-granular porosity but it may be too small to be visible, even under the micro-scope, and therefore cannot be recorded in the rock description.

Carbonate RocksCarbonate Rocks (Limestones and Dolomites) occur throughout geologicaltime and are geographically widespread. They form in warm shallow seas,free of siliciclastic deposition where calcareous skeletal organisms can flour-ish. Very few carbonates have been produced in temperate latitudes.

MineralogyTwo calcium carbonate minerals are predominant:

• Calcite

• Aragonite

Calcite is the stable form at normal temperatures and pressures and is theprimary constituent of all limestones. It has a rhombohedral crystal formand a density of 2.71 gm/cc.

Aragonite is unstable and readily converts to calcite, although it is often theprimary precipitate and main component of organic skeletons. It has anorthorombic crystal habit, with a density of 2.71 gm/cc.

Figure 8: Porosity (rhombic packing) 26%



Dolomite is a mixed carbonate in the form CaMg(CO3)2. It consists of alter-nating layers of calcite and magnesite, in varying percentages and has adensity of 2.86 gm/cc. Dolomite rocks are predominately secondary in originresulting from the reaction of magnesium compounds with calcite or arago-nite. Dolomitisation is a very selective process depending on temperatureand the nature of the rock. After lithification for example, only shell frag-ments may be replaced, or at other times only matrix. Dolomitisation oftenresults in enhanced porosity.

Carbonate ComponentsWhilst the mineralogy of carbonate rocks is fairly straightforward, the con-stituent particles and matrices can be very variable. Unlike siliciclastics,where classification is made from grain size characteristics and environmen-tal interpretation and reservoir properties determined from texture andstructure, it is the nature of the grains and cement that give these answerswhen dealing with carbonates. They are produced at or near the site of dep-osition with little or no transportation involved. Carbonates are generallymade from four components:

• Skeletal grains

• Non-skeletal grains

• Matrix

• Cement

Most carbonates are lithified sediments made of discreet and originally looseparticles. In some carbonates original grains, cement or structures are notrecognisable due to re-crystallisation or other diagenetic activity.

Skeletal GrainsThese are a major contributor to carbonate rocks, and they represent a widevariety of organisms. Most are present as broken shells and fragments butsome smaller forms, particularly forams, may show the entire shell.

Blue-green algae are common plants, living as either planktonic or sessileforms. Stromatolites are lithified carbonate rocks made by the trapping ofsand, silt and mud by algal mats binding the whole

structure together. Forams are single celled marine and brackish wateranimals living either as planktonic or bottom dwelling forms. They are oftenpreserved intact and, because of widespread diversification they areextremely important for dating purposes. During the drilling of high angleand horizontal wells bio-stratigraphers are often retained at the wellsite in



order to help the directional driller stay within the reservoir or oil bearingsection. Accuracy to within centimetres can be achieved in certain cases.

Corals, Bryozoans, Brachiopods, Cephalopods, Gastropods, Bi-valves,Worms, Insects, Echinoids and Crinoids are all represented.

The nature of the fossil assemblage can give very clear indications on envi-ronments of deposition and energy levels.

Non-Skeletal GrainsOoids are spherical to sub-spherical grains consisting of concentric laminaeof calcium carbonate formed around a nucleus. They are produced byprimary precipitation around the nucleus in shallow marine waters with agentle rolling action by current or tide activity. By definition ooids are lessthan 2mm in diameter. Larger than this and they are termed pisoids. A rockformed predominately of ooids is called an oolitic limestone or oolite. Largergrains are sometimes composite ooids that have formed by small ooids beingenveloped by concentric laminae.

Figure 9: Fossiliferous Limestone



Oncoids are sand to pebble sized particles with a concentric, but irregularmulti-layered structure. Often they are coated with algae or algal mats.

Peloids are spherical, cylindrical or angular grains made of microcrystallinecalcite showing no internal structure. The origin of these grains is diverseand often doubtful. They may have originated as faecal pellets, calcareousalgae, altered and broken shell fragments or re-crystallised mud clasts.

Lithoclasts are fragments of rock which have been transported and re-worked prior to deposition. Their presence suggests the proximity of anoutcrop from which the clasts are eroded.

Microcrystalline Calcite (Lime Mud)This is fine grained dark coloured matrix, equivalent to argillaceous mud. Itmay form from direct precipitation as grey-white aragonite crystals or fromthe fragmentation and bio-erosion of grains and pellets.

CementThis is the term for crystalline carbonate acting as the bonding agent ormatrix and coarse grained enough to show crystal structures and featuresunder the microscope. In ancient sediments it is almost always calcite ratherthan the unstable aragonite.

Figure 10: Ooids



DolomitePartial or complete dolomitisation of ancient sediments is a common feature.The conversion of calcite or aragonite to dolomite may take place soon afterdeposition or a long time later. The formation of dolomites is still somewhatuncertain, but seepage-reflux of seawater by capillary action and flooding isone proposed mechanism. Evaporative pumping in lagoonal supra-tidalenvironments is another.

PorosityPorosity in Carbonate rocks can be divided into two main types:

• PrimaryFramework porosity formed by rigid carbonate skeletons such ascoral

Interparticle porosity in carbonate sands

Fenestral porosity in carbonate muds

• SecondaryMoulds, vugs, cavernsIntercrystalline porosity (dolomitisation)

Fracture porosity



Most carbonate reservoirs are important because of secondary porosity sinceprimary inter granular or intra granular porosity is often very small orirregular and isolated. The chalk reservoirs of southern Norway andDenmark have hydrocarbons in vertical fractures caused by shallow doming.

This type of porosity is almost impossible to detect in drill cuttings or evencores, but can be inferred from drill rate, rotary torque characteristics, MWDand surface mounted drilling mechanics instrumentation and from MWDand wireline logs.

Sonic logs will only detect primary porosity since the fastest compressionalsound wave is the one that will be detected and evaluated. This wave willhave travelled through the most dense part of the rock and will show regularinterparticle porosity. The density and neutron porosity logs however, willshow all types of porosity so that a comparison of apparent results with theseand the sonic log should show areas dominated by secondary porosity.

Figure 11: Carbonate Porosity



EvaporitesEvaporites are chemical sediments which have precipitated directly fromwater following salt concentration caused by evaporation. Common evapor-ite minerals are halite (Rock salt), gypsum and anhydrite, but there aremany others depending on climate and chemical availability.

Evaporites are of great economic importance, having a wide range of appli-cations. They are important in the oil industry by acting as seals to hydro-carbon reservoirs, or overpressured zones, and by acting as climaticindicators and marker horizons.

Salt deposits are commonly cyclic, ranging from very thin beds to some tensof metres thick. They usually consist of massive gypsum and anhydrite,alternating with limestones, marls and infrequent salts.

The Permian Zechstein sequence of NW Europe shows many repeated cyclesof anhydrite/gypsum passing upwards into halite with thin beds of highlysoluble bittern salts (potassium and magnesium chlorides and sulphates) atthe top. Precipitation is thought to occur in two modes:

• Subaqueous precipitation from moderately deep standingbodies

• Subaerial precipitation form shallow pools and salinas,with subsequent replenishment.

Mineral Composition

Halite NaCl

Gypsum CaSO4.2H2O

Anhydrite CaSO4

Sylvite KCl

Carnalite KMgCl3.6H2O

Figure 12: Evaporites



Gypsum and AnhydriteThese minerals possess distinctive structures and textures and are prone toreplacement, recrystallisation and solution. Both minerals may precipitatedirectly, but on burial to depths of more than a few hundred metres, onlyanhydrite is present. With subsequent uplift, all anhydrite is converted tosecondary gypsum. The main differences between gypsum and anhydrite forfield recognition are in hardness and density.

HaliteHalite commonly infills large sedimentary basins, and is the main evaporitemineral of many saline lakes. Rock salt may be massive, layered, bedded ormixed with siliciclastic sediments. It has a cubic form and is often visible incuttings samples as white to colourless grains, although impurities canproduce mottling or banding of greys, blacks, reds and pinks. It is verysoluble in water and obviously has a distinctive salty taste.

Other EvaporitesPotassium and magnesium salts are highly soluble and the last to precipi-tate in the evaporite sequence. Because of their solubility, diageneticchanges when in contact with residual brines and fresh groundwater is inev-itable. Indeed many of theses mineral assemblages are probably secondaryin origin.

Drilling PracticesIt is common to drill massive salt sequences with salt saturated, or even oilbased mud systems. In these cases evaporite cuttings will be seen at thesurface, and samples can be treated in a normal manner. If thin or partiallysaline formations are drilled with non saturated muds then most of thesamples will be lost to solution. It is then necessary to look for secondarysigns of evaporites:

Mineral Moh’s Hardness Specific GravityGypsum 1 - 2 2.37 gm/cc

Anhydrite 3.5 2.9



• Change in ROP

• Smooth ROP for massive sequences

• increased mud salinity

• Increased mud viscosity

• Reduction in background gas

• Remaining cuttings eroded and reworked

Other Chemical Rocks

ChertChert is a general term for fine grained siliceous sediment of chemical, bio-chemical or biogenic origin. It is usually a dense, very hardrock which splin-ters with a conchoidal fracture when hit.Other names, such as Flint, repre-senting nodules found in Cretaceous Chalk, or Jasper, signifying a redvariety due to haematite content, are commonly used.Cherts are usuallydivided into bedded and nodular varieties. Most chert encountered in hydro-carbon drilling operations is of the nodular type, present in carbonate hostrocks. Nodules vary in size and shape from small to large and sub sphericalto irregular. They may be concentrated along bedding planes. Many suchnodules are secondary features, perhaps starting out as calcareous grainssuch as peloids or ooids. Biogenic silica may dissolve and re-precipitate byfilling in holes or pores and later replacing grains and shell fragments.These represent growth points which subsequently become nodules.

CoalMost coals are humic, formed from woody plant material. Others are calledsapropelic from algae, spores and other plant debris. There is a natural pro-gression of humic coals from peat, through brown and bituminous to anthra-cite. Most of the changes are temperature induced. Increasing rank leads toincreased carbon and reduced volatile content.

Coals are typical of the late Devonian and Carboniferous periods and oftenoccur at the top of coarsening upward deltaic cycles.


Cuttings Sampling & Evaluation

IntroductionThe importance of the cuttings samples cannot be over-stressed. There is nosubstitute for representative cuttings samples accurately correlated to thedepth from which they came.

Sample Collection & PreparationEvery rig has shaker screens for separating the cuttings from the mud asthey reach the surface. If the screen mesh is small enough to remove smallcuttings and the job is in an area where there is reason to believe that nounconsolidated sands will be encountered, the shaker screen will provide acollection point for composite sampling (i.e. interval sampling). However,when unconsolidated sands pass through the screen, they can be extractedfrom the mud by desanders and desilters and a sample collected from themfor examination. This sample should be considered along with the shakerscreen and composite samples when making an overall evaluation.

Cuttings samples should be taken at regular intervals as often as possible,and never at intervals greater than 15 minutes. The sample bags should befilled progressively to give a representative sample of the whole interval.Samples should also be taken when changes in drill rate or background gasare noticed as these often indicate a change in formation lithology or poros-ity.

Figure 1: Shale Shaker



Care should be taken at the shale shaker to ensure that a representativesample is collected with minimum cavings. The desander and desilteroutlets should be checked regularly for fine sand which might pass throughthe shaker screen.

Washing and preparing the cuttings are probably as important as the exam-ination itself. In hard rock areas, the cuttings are usually quite easilycleaned, in which case it is a matter of washing the sample in a sieve toremove the mud film. In many areas, however, particularly areas and zonesof loose sands and shales, it is more difficult and requires several precau-tions. Primarily, the clays and shales are often soft and of a consistencywhich goes into suspension and makes mud. Care must be taken to washaway as little of the clay as possible; and, in determining the sample compo-sition, account must be taken of any clay that is washed away.

After the cuttings have been washed to remove the mud, they are washedthrough a 5-mm sieve. It is generally considered that newly drilled cuttingswill go through the 5-mm sieve and that material which does not is cavingsand may be discarded.

Cuttings from wells drilled with oil-based or oil-emulsion muds are usuallymore representative of the drilled formation than cuttings drilled withwater-based mud because the oil emulsion prevents sloughing and disper-sion of clays and shales into the mud. At the same time, washing andhandling cuttings drilled with this type of mud poses somewhat of aproblem; they cannot be cleaned by washing in water alone. It is usually nec-

Figure 2: Sample Collection



essary to wash the cuttings first in a detergent solution to remove the oilmud. Naturally, oil show evaluation can be complicated when oil-basedmuds are used.

An oven mounted in the logging unit is used to dry a portion of the cuttingssample after it has been washed, while a representative sample of thewashed cuttings are examined under the microscope.

Cuttings ExaminationSamples are examined under the microscope primarily for lithology,staining and porosity; the objective is to depict changes of formation and theappearance of new formational materials. The microscope and ultravioletlight are used as complementary tools in reconstructing the characteristicsof the originating strata. An estimate of the percentages of lithology,staining and porosity are made with great care since factors such as grainshape and size, colour, distribution, etc., may affect the apparent relativepercentages.

There are many potential sources of contamination to consider when under-taking estimates of lithology percentages, examples of which are:

CavingsCuttings from previously drilled intervals rather than from the currentinterval. Although ditch cuttings are first washed through a coarse sieve to

Figure 3: Cuttings Examination



remove cavings, some may remain in the sample. Cavings may be recognisedas generally large, splintery rock fragments that are often concave or convexin cross-section. They are lithologically identical with formations fromhigher sections of the open hole. If found in large quantities, this mayindicate a serious underbalanced mud condition or a situation whererotation is too fast and the stabilisers are catching on the side of the hole.

Recycled CuttingsIf cuttings are not efficiently removed from the drilling fluid at the shaleshakers, desanders and desilters, they may be recycled through the mudsystem. Recycled cuttings may be recognised as small, abraded, roundedrock fragments in the sample.

Mud chemicalsSome mud chemicals may be confused with rock types. Lignosulphonate, forexample, may resemble lignite, and bentonite gel may erroneously be iden-tified as Montmorillonite clay in a poorly mixed mud system. Moreover, lostcirculation material (LCM) such as nut shells, fibres and mica flakes, is acommon source of contamination in lost circulation zones.

CementCement contamination is usually encountered when drilling after casing orwhile sidetracking. Cement may be mistaken for siltstone but can be readilyidentified by testing with phenolphthalein solution in which cement stainspurple due to its high pH.

MetalMetal is occasionally found in samples and frequently originates from wearof the inside of casing by the drillstring. This is often remedied by the use ofrubber drillpipe protectors.

Unrepresentative samplesIn some cases, samples may be totally unrepresentative of the formation atbottomhole. For example, in evaporite sections drilled with a water-basedmud, salts dissolve and there is no lithological indication of their presence inlagged samples. However, evaporites can still be recognised by good loggingpractice:

• Evaporites generally drill at rates of 40 to 60 ft/hr

• Gas values through evaporites will be very low if not zero



• There will be poor or no returns at the shale shakers

• Limestones and dolomites are frequently found in associ-ation with evaporite deposits

• Anhydrite sections can usually be identified by BaCl solu-tion which produces BaSO4 precipitate

• The chlorides content of the drilling fluids should in-crease very significantly.

A single layer of cuttings should be used for percentage estimation, and careshould be taken to select a representative sample from the sieve because alarge degree of shape and density sorting occurs during washing. Once thepercentages of the various constituents have been estimated, the sampledescription is made in a logical order similar to that detailed below:

Figure 4: Sample Washing



Figure 5: Shaker Screen and Sieve sizes



Sample Descriptions

Name

ClasticsClaystone blocky, amorphous

Shale Indurated, hard, fissile

Siltstone

Sandstone

CarbonateLimestone fast reaction to acid. Violent,

grain moves around, abundant CO2

Dolomite slow, less violent reaction to acid

May use a classification scheme according to Operator requirements, suchas:

Dunham

Mudstone, Packestone, Wackestone, Grainstone, Boundstone

ColourDescribe as is or use American Geological Society Rock Colour Chart. Thecolour chart has the benefit of consistency and, like any coding scheme,enables both the author and the recipient to fully understand the message;in this case the rock colour. As well as the colour other information shouldbe included:

Intensity: bright, dull

Distribution: even, spotted, banding etc.

Hardnessof the rock, not the mineral(s), indicating compaction and/or cementation.Use the sample probe to evaluatehow easily the rock breaks

Typical descriptive terms are:

Soft, friable, firm, moderately hard very hard



Claystones: Check reaction to 10% HCl and Water

Acid: Breaks Hygrofissile

Water: Breaks Hydrofissile

Swells Hydroturgid

Cement

Amount: Poor, moderate, well (cemented)

Type calcite, silica, iron (commonly red.brown colour) etc.check reaction to acid for calcareous content

TextureClastics: Use grain size chart to evaluate:

Grain size, shape, sorting

Carbonates: Types of grains Shell fragments, pellets

Type of cement Crystalline calcite, lime mud

PorosityTrace, fair, good estimates of visual porosity

Accessories

Fossils

MineralsIron: Limonite, haematite, glauconite

(green, indicates marine conditions)

Calcite: white, reacts with acid



Pyrite: gold, reducing conditions

Carbonaceous: black

Chlorite: green

Biotite mica: brown/black

Muscovite mica: colourless

Oil Show EvaluationStain Colour Brown

Intensity light medium dark

Odour (Smell)

Fluorescence Colour Brown – Yellow/gold – blue/white – white – colourless

Intensity dull, bright etc.

Distribution even, spotted, banding

Solvent Cut Reaction yes/no

Colour yellow/gold - milky whiteor equivalent)

Speed slow, fast, instantaneous

Style Diffuse: no shape

Streaming: rivers/stream

Blooming: dense, viscous

White light Stain colourlight – dark brown



Oil Show EvaluationEvaluation of oil in the cuttings (and mud) should proceed from inspectionunder the microscope to inspection in the ultraviolet-light box. Tests andvisual inspection should be performed upon mud, unwashed and washedbulk cuttings, as well as individual grains.

Oil StainingAny stain or colouration that is not just superficial, except in the case of oilfrom fractured reservoirs, warrants checking with a fluoroscope or solventtest. The amount, degree and colour of the staining should be noted, such as:

Figure 6: Oil Show Evaluation



• No visible oil stain

• Spotty oil stain

• Streaky oil stain

• Patchy oil stain

• Uniform oil stain

Colour and intensity of the stain should also be included as this will give anindication of API Gravity. A black asphaltic residue is indicative of dead,residual oil lacking volatile components.

Sample chips that bob to the top in water or acid should be checked with afluoroscope. This bobbing may be due to a surface coating of oil on the cut-tings, and a check should be made to see whether oil staining goes rightthrough the chips. Note that oil-base muds will cause the sample chips to beoil soaked.

Natural FluorescenceAt the microscope, the geologist should select those cuttings that havevisible oil staining and place a representative selection on a spot plate. Theyare then transferred to the UV light box where they are inspected for fluo-rescence and solvent cut.

The intensity and colour of oil Fluorescence is a most useful indication of oilgravity and mobility. Decreased intensity and darker colour will commonlyaccompany decreases in gravity. Water-wet or residual oils, which tend to bepoorer in lighter, more volatile hydrocarbons, will have the fluorescencecolour representative of their gravity, but will commonly be paler in colourand less intense.In all fluorescence tests, it is important to observe a freshsurface. Since fluorescence may also be caused by certain minerals or con-taminants such as pipe dope, care must be taken not to confuse these withtrue formation hydrocarbons. A mineral fluorescence will not leach in asolvent, therefore no cut fluorescence will be seen. The intensity of the fluo-rescence may yield important clues on the fluid content of the rock; forinstance, though a series of samples are uniformly fluorescent, a lesseningof intensity may indicate a transition from oil- to water-producing zones.

When fluorescence is not attributable to minerals or contaminants in asample, then this is taken as proof of oil being present in a rock and allowsan estimation and description of the amount of oil in the rock cuttings. Thecolour of crude-oil fluorescence can be used to make quantitative identifica-tion of the approximate API gravity of the crude. Colours range from brownto gold to green, yellow to blue-white with a variety of colours and shades



between. The darker colours, browns and oranges are associated with theheavier crudes, the lighter colours are indicative of the lighter oils. Refinedoils such as diesel and pipe-dope will give a bluish-white fluorescence, andoften very light oils or condensates and heavy tars will not fluoresce at all.Experience shows the following rough correlation:

The degree of oil fluorescence should be immediately noted and may bedescribed as:

• None

• Spotty

• Streaky

• Patchy

• Uniform

The colour should be noted along with the percentage of the sample fluoresc-ing, and more precisely, the percentage of the reservoir rock fluorescing. Thebrightness of the fluorescence is important. Below the oil/water interface,the cuttings, while still carrying a lot of oil and gas, may show a markedchange in intensity- the fluorescence becoming dull and losing it’s originalbright sharp colour. Fluorescence checks should be done immediately on asample. If the cuttings are left exposed to the atmosphere, the fluorescencetends to dull appreciably due to the loss of volatiles. This is acceleratedunder heat lamps and even under the microscope.

Along with the above description of the fluorescence a note should be madeof how the fluorescence is distributed throughout the rock. In most cases thefluorescence will be found around the grains in the matrix of the rock, but insome areas the reservoir rock may be of low porosity but highly fractured,with all of the fluorescence and staining occurring along the fractures andoften never entering the parent rock more than a few millimetres (if at all).This is the case in fractured granite and dense fractured limestone anddolomite reservoirs. Care must be taken in the evaluation, as the porosityand permeability of the parent rock are no longer important in the determi-nation of a field’s producing capabilities. The production is dependent uponthe amount of fracturing present, it’s interconnection, and the amount ofrecrystallisation along them. A true idea of the possibilities of such a reser-voir can be obtained only from taking cores - not from drill cuttings.Themineral fluorescence given by specific rock types are given below and willnot give a solvent cut:



Solvent Cut FluorescenceSolvent cut is valuable in assessing fluorescence and allows deductions to bemade of oil mobility and permeability of the reservoir. By removing the oilfrom the coloured background of the cutting, the solvent allows a betterestimate of fluorescence. The way in which the solvent cut occurs, e.g.instantly for high gravity oils, more slowly for more viscous lower gravityoils, or irregularly streaming from limited permeability, also yields usefulinformation. If no cut can be obtained from a washed cutting, the test shouldbe repeated on a dried cutting, crushed cutting or after application of dilutehydrochloric acid. This will produce the required cut and yield furtherevidence on permeability or effective porosity. After the cut solvent hasevaporated, a residue of oil remains in the cut dish, displaying the oil’snatural colour.

Examination of mud and unwashed cuttings for oil may not be so discrimi-nating as individual cuttings, but it can yield general information on oiltype. 200 cc of mud is poured into a dish and observed for fluorescence in theUV box. Droplets of oil may be seen popping at the surface. Then, 100 cc ofwater is added and the sample is observed again. This helps lower the mud’sviscosity to aid oil escape. It also separates the mud and oil, allowing a smalloil sample to be skimmed off the water surface. Finally the mud and waterare stirred together, and the sample is left for 30 seconds or longer to allowall of the oil present to accumulate at the surface. If a high gravity oil or con-densate is suspected, the sample should be observed throughout this period.Otherwise evaporation due to the heat of the UV light may lead to a pessi-mistic or false conclusion.

This procedure is repeated with 200 cc of unwashed cuttings. In this case,working the sample with the fingers can help to free oil droplets. Thedroplets rise through the water and appear to pop on the surface as gas isreleased.

Oil effects observed from mud or unwashed cuttings under UV light arecommonly classified into five characteristic types, as follows:

Type 1: 1mm pops, scattered and few in number; this type is frequentlyassociated with oil found in shale, along bedding planes, fractures, and sand-stone containing very slight traces of residual oil.

Type 2: 2mm pops or larger, few in number commonly noted in large frac-tures and residual oil in sandstone; may be dull and streaky, associated withlow gas readings.



Type 3: Pinpoints common, along with 2mm or larger pops; this type of flu-orescence frequently observed from sections with fair amounts of oil.

Type 4: Common to abundant pinpoint; normally associated with good tofair shows of oil.

Type 5: Abundant pops 2mm and larger, are frequently found associatedwith good shows. In higher gravity oil, the pops surface and spread rapidly.Gas can usually be seen escaping as the oil pops to the surface.

The show, once fully evaluated, should be graphically displayed on the MudLog. An accompanying description should include:

Free Oil In Mud: colour, fluorescence, amount

Sample Odour: type, strength

Visible Staining: colour, amount, evidence of surface wetting

Cut: rate, colour, fluorescence (colour/intensity) residual stain

Salinity or conductivity measurements should be taken continuouslythroughout the show. The reservoir evaluation presented on the Mud Logmay be augmented by a Show Report.

Hydrocarbon Analysis ScorechartAnother method for quantifying a show, rather than simply describing it asgood - poor etc., is to use a method of scoring the various parameters used inevaluation. The scorechart shown on the following page is an example of thismethod.

The logger evaluates each of the show parameters and adds up the pointsaccording to the chart, arriving at a total which can then be translated to arating and a descriptive form as shown in the table below. In a sense, thismethod takes away some of the subjective nature of show evaluation, wheredifferent geologists would weigh the parameters differently and perhapsarrive at different conclusions.



Hydrocarbon Scorechart



Point Range Score Show Rating

0-15 1 No Show/Poor Trace

16-30 2 Poor Trace

31-45 3 Trace

46-60 4 Good Trace

61-75 5 Moderately Fair

76-90 6 Fair

91-105 7 Moderately Good

106-120 8 Good

121-130 9 Very Good

131-143 10 Excellent




Figure 7: Hydrocarbon Evaluation

Oil Show Descriptions, based on dry cuttings, using spot plates and hexane

Oil Stain %

Direct NaturalFluor

%

SolventCut

Fluor%

NaturalCut

Colour

UV ResidueColour

NaturalResidue Colour

ShowRating

Comments

Pchy 20-100% v pa crm

Pchy 30-100% pa yel/wh

Slowdiff pa Blu/wh

Sli discol-ext. wktea

Fnt blu/yel

Fnt yel/brn

1 In a gas zone the solvent colour is generally clear, with small amounts of oil the solvent starts to take colour. Use this as your lower show rating.

Still pchy but w/incrsg stn, 60-100% pa-lt crm

Variable from 50-100% dull-pa yel

Fast inst diff blu/wh

Wk-lt tea Bcmg brighter yel/wh

V lt brn 2 Basic change from 1-2 is presence of discernable Lt tea Natural Cut Colour. Occasionally traces of free oil droplets.

Bcmg more uniform 80-100% lt-mod crm

From 80-100% yel/wh-mod yel

Inst diff pa wh w/com. Strmg mlky wh

Lt-m tea Bright pa yel

Lt brn 3 Natural cur colour and residue becoming darker. The residue fluor becomes more intense described as bright, pale yellow. Common free oil droplets

Uniform mod-dk crm

Uniform can vary from bri-dull yel

Inst diff pa-wh, com strgm, solvent willslowlyturn mlky wh

Good m tea

Bri yel M brn 4 Good cuts with well-developed residue ring/fluorescence. Free oil droplets.

Dk crm to almost brn in some fields.Abdt free oil

100% bri-mod yel

Inst diff mlky wh, bcmg yel/wh

Dk to v dk tea

Deep yel-gold

Dk brn 5 Strong tea Natural Cut with dark residue

Brn to dk brn usually with abdt free oil

100% mod- deep yel

Inst diff yel/wh

Coffee Gold-dk brn

V dk brn- black

6 Coffee black Natural Cut

These are basic guidelines for Oil Shows. The Natural Cut Colour and Natural Residue are the most reliable indicators, the lower the Sw the darker the colour. DO NOT simply increase/decrease the show rating based on LWD quick-look. This form is standardised and should be used as a guide by all well site geologists.

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Petrophysics 1-1

MWD/LWD Services

Measurement While Drilling is a technique for measuring directional survey andpetrophysical rock properties downhole, during drilling, and transmitting thisdata to the surface for real-time evaluation. The service developed during the late1970s and is now an integral part of formation evaluation in complex and diffi-cult wells.

Applications for MWD services include:

• Survey Data

• Open Hole Petrophysics

• Real Time Data

• Tough logging conditions (TLC) where traditional wireline logging is not possible

• Alternative to tubing conveyed logging operations

Measurements

There are generally two types of measurement while tools: those which take directional surveying data and those which take formation evaluation data:

• MWDInclinationAzimuthTool face

Figure 1: General MWD Tool

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• LWDGamma RayResistivityFormation DensityPhotoelectric EffectNeutron DensitySonic

• Pressure While DrillingAnnular PressureFormation Pressure

• Wellbore Stability

• Acoustic Caliper

• Drilling MechanicsVibration Downhole TorqueDownhole WOBMud Temperature

General Features

Drill CollarMWD and LWD sensors are housed in a drill collar with an OD suitable for thehole size being drilled. Typically these have been 6¾” and 8½” to enable opera-tion in 8½” to 17½” hole sizes. Recently however most companies have intro-duced slimhole versions of their tools in 4¾” drill collars for use in 6½” andsmaller hole sizes. Indeed Baker Hughes Inteq have been field testing a 3?”diameter Rotary Steerable drilling tool with associated LWD sensors for 3?” to4¾” holes.

Sensor & Control UnitThe sensors are located in the centre of the drill collar to allow mud flow. Amicroprocessor unit is included along with downhole memory for storing datawhich is unable to be transmitted in real time.

Power SupplyPower supply comes from batteries or downhole generation. Batteries are usuallylithium-chloride types. Lithium provides the highest capacity (ampere-hours or"Ah") per unit weight of all metals, making it an ideal material for a lithiumanode. Lithium systems offer distinct advantages over other battery systems,

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especially with respect to long life, reliability and capacity. Batteries also enablelogging while tripping if mud is not being circulated and independently of mudflow and hydraulics variations.

Battery PowerA lithium power source offers a significant advantage if:

• A high voltage is needed (i.e. 3.0 to 3.9 volts per cell)

• A recharging circuit is not available or too costly

• The power source has to be as light weight as possible

• Long shelf life is required

• A wide temperature range is required

• Reliability is crucial

• Extremely high energy density is needed

• Environmental concerns such as temperature, vibration orshock are especially severe

Figure 2: Basic Tool Configuration

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• Your application demands a continuous source of power for ex-tensive periods of time

Disadvantages with battery power include:

• Finite life so compromises with real-time transmitted data have to be made concerning data types and frequency related to expected continuous drilling time

• Not re-chargeable so disposal is a problem as they are classified as hazardous waste:

• These batteries are a characteristic hazardous waste due to toxicity, ignitability and reactivity.

• The temperature range on a lithium battery is 40°F to 185°F.

Generated PowerPower can be generated using the mud flow driving a turbine to power an alter-nator. This has the advantage of having no time limits although it requires mudflowrates between certain, pre-set ranges, to function. Some MWD tools use acombination of both power supply systems.

Data Transmission SystemDuring the early development stage of MWD services many alternative forms ofdata transmission systems were investigated.

During the 1970s there were drill collar mounted MWD sensors (accelerometersand magnetometers) to measure inclination and azimuth connected to the surfaceby a wire cable which exited the collar via a side-entry sub and provided a con-tinuous, real time surface display. This could only work if there was no drillstringrotation which was the case with early bent-sub and motor directional drillingtools which used a mud-driven turbine to turn the bit which was attached to abent housing above the motor. Because of the long overhang below the motorand the amount of offset of the bit from the centreline of the drillstring, no stringrotation was possible. Thus the tool could only build or drop hole angle whilstturning right or left and was unable to drill straight. Using this early form ofMWD was very useful for geometric steering of these build or drop sections.

With developments in directional drilling tools, however, it became possible todrill in either rotary (drillstring rotation) mode for straight drilling or oriented(using the motor only) mode for drilling build or drop sections. This meant thatthe hardwire cable form of data transmission became untenable.

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Petrophysics 1-5

Other data transmission systems were then investigated and these included thepotential of using the drillstring as a conductive medium or of embedding a con-ductive wire within the wall of the drillpipe.

Drillstring Data TransmissionAt least 10 patents have been issued during the last 50 years in attempts to createdrill pipe telemetry, using both hardwired and induction-based transmissionacross connections, but both of these have failed. Like all hard-wired jointedsystems thus far, the electric contacts at the drill pipe joints proved too difficultto reliably align, allow perfect contact, and not leak under field conditions.Induction across couplings has a host of problems, most notably signal/fieldlosses and downhole power-boosting.

It was realized early on that hard-wired drill couplings, no matter how welldesigned, would probably always be prone to failure as the number of connec-tions and the many connect/disconnect cycles grew. Therefore, induction waschosen as the means to transmit data from joint to joint for more serious reach.This, however, carried with it many problems to overcome. It is only veryrecently that Grant Prideco has developed IntelliPipe which is currently under-going research and development including field trials. Whilst very fast datatransmission rates can be achieved, any hard-wired or induction based drillstringtelemetry system is likely to be very expensive to initiate and, of course, requiresthe total replacement of the existing drillstring.

Figure 3: Grant Prideco Intellipipe

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Mud Pulse TelemetryBecause of the cost and technical difficulties associated with developing drill-string data transmission systems, mud pulse telemetry has been used by all thecommercial vendors over the last twenty-five years.

Downhole valves or modulators are used to create pressure pulses or carrierwaves which are superimposed on the normal pump pressure (or standpipe pres-sure) signal and transmitted through the mud to the surface where they are seenby very sensitive standpipe pressure transducers as a form of binary code. Thedata is sent to sophisticated decoding computers for analysis.

The mud pulses are carried through the mud at roughly the speed of sound in mud(i.e. 4000-5000 ft./sec or 1200-1500 m/sec), giving virtually instantaneous datatransmission. However data transfer rates with mud pulse telemetry are veryslow. Early tools worked at 1 – 3 bps; more recent tools work at around 10-12bps whilst the latest generation Schlumberger tools from their EcoScope™system works at around 16bps which is enough for 2 data points/ft at loggingspeeds of up to 450ft/hr. This needs to be compared with hard-wired systemsthough which are capable of 2 million bps (2Mbps).

Typical current operational specifications:

Figure 4: IntelliPipe Surface Swivel

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Mud Pulse Telemetry Systems

Positive Mud Pulse TelemetryPositive mud pulse telemetry (MPT) uses a hydraulic poppet valve to momentar-ily restrict the flow of mud through an orifice in the tool to generate an increasein pressure in the form of a positive pulse or pressure wave which travels back tothe surface and is detected at the standpipe.

Survey Time 44seconds - 92seconds

Toolface Update 15 seconds

Gamma Ray Update 28 seconds

Collar Size 4¾- 9½ ins

MTBF 300 hrs +

Maximum Temp (operating) 300°F (150°C)

Maximum Temp (survival) 350°F (175°C)

Figure 5: Positive Mud Pulse Telemetry

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Negative Mud Pulse TelemetryNegative MPT uses a controlled valve to vent mud momentarily from the interiorof the tool into the annulus. This process generates a decrease in pressure in theform of a negative pulse or pressure wave which travels back to the surface andis detected at the standpipe.

Continuous Wave TelemetryContinuous wave telemetry uses a rotary valve or “mud siren” with a slottedrotor and stator which restricts the mud flow in such a way as to generate a mod-ulating positive pressure wave which travels to the surface and is detected at thestandpipe.

Figure 6: Negative Mud Pulse Telemetry

Figure 7: Continuous Wave Telemetry

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Electromagnetic TelemetryThe electromagnetic telemetry (EMT) system uses the drill string as a dipoleelectrode, superimposing data words on a low frequency (2 - 10 Hz) carriersignal. A receiver electrode antenna must be placed in the ground at the surface(approximately 100 meters away from the rig) to receive the EM signal. Off-shore, the receiver electrode must be placed on the sea floor.

Currently, besides a hardwire to the surface, EMT is the only commercial meansfor MWD data transmission in compressible fluid environments common inunderbalanced drilling applications. While the EM transmitter has no movingparts, the most common application in compressible fluids generally leads toincreased downhole vibration. Communication and transmission can be two-wayi.e. downhole to uphole and uphole to downhole. The EM signal is attenuatedwith increasing well depth and with increasing formation conductivity.

MemoryMost commercial real-time and recorded only formation evaluation tools have anenhanced memory capability. This system provides for storage of raw data andpermits storage of data at higher rates than is possible with real-time transmis-sions. The memory system is also used for retrieval of formation data if onlytoolface data are transmitted when steering. Data storage also provides datarecovery in case of transmission problems. For example, if real-time data are lost

Figure 8: Electromagnetic Wave Telemetry

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due to surface detection problems, memory data can be used to fill in the missinginformation. The chances of memory filling up on long bit runs is a possibilitybut rare in today’s market.

MWD Services (Directional Survey Data)MWD tools use solid state accelerometers and magnetometers to measure:

• Borehole Inclination

• Borehole Direction (Azimuth)

• Tool Face Orientation (Azimuth)

AccelerometerAccelerometers are used to measure the earth’s local gravitational field. Eachaccelerometer consists of a magnetic mass (pendulum) suspended in an electro-magnetic field. Gravity deflects the mass from its null position. Sufficient currentis applied to the sensor to return the mass to the null position. This current isdirectly proportional to the gravitational force acting on the mass.

The gravitational readings are used to calculate the hole inclination, toolface, andthe vertical reference used to determine dip angle.

MagnetometerMagnetometers are used to measure the earth’s local magnetic field. Each mag-netometer is a device consisting of two identical cores with a primary windingaround each core but in opposite directions. A secondary winding twists aroundboth cores and the primary winding. The primary current (excitation current)produces a magnetic field in each core. These fields are of equal intensity, butopposite orientation, and therefore cancel each other out such that no voltage isinduced in the secondary winding. When the magnetometer is placed in anexternal magnetic field which is aligned with the sensitive axis of the magnetom-eter (core axis), an unbalance in the core saturation occurs and a voltage directlyproportional to the external field is produced in the secondary winding.

The measure of voltage induced by the external field will provide precise deter-mination of the direction and magnitude of the local magnetic field relative to themagnetometer’s orientation in the borehole.

In the MWD drilling environment, there are many sources of magnetic interfer-ence that can cause inaccurate directional measurements. A ferromagnetic steelobject that is placed in a magnetic field will become magnetized. The amount ofinduced magnetism is a function of the external field strength and magnetic per-meability of the object. In order to prevent magnetic interference, the directional

MWD Overview

Petrophysics 1-11

survey instrument is housed in a nonmagnetic stainless steel collar. The MWDtool is usually arranged in a section of the bottom-hole assembly (BHA) whichis made up of a series of non-magnetic collars to reduce the impact of the drillingassembly's steel components on the magnetic field at the location of the surveysensor.

Other sources of magnetic interference may be caused by proximity to iron andsteel magnetic materials from previous drilling or production operations,magnetic properties of the formation, and concentrations of magnetic minerals(iron pyrites, etc.) in excess of six percent. Local magnetic anomalies may alsobe present and the strength of local magnetic interference may change withmagnetic storms for example.

LWD (Formation Evaluation Logging While Drilling)

Gamma RayThe Gamma Ray log has been a fundamental part of the petrophysical loggingsuite for many years. It is used as a basic geological correlation tool, for depthmatching and for general geological interpretation. In LWD tools it is importantfor geosteering in that it gives primary information about finding and drilling res-ervoir sections.

Most vendors tools use scintillation detectors to make gamma ray counts ofemitted radiation from rocks and minerals in the subsurface. Scintillation detec-tors use a crystal of thallium-doped sodium iodide which emits light flashes orscintillations when a gamma ray interacts with the crystal. A high voltage pho-tomultiplier tube captures the scintillations, amplifying them into an electricalsignal in the form of a count rate. Gamma rays are measured over a specified timein order to collect enough counts to reduce statistical scatter. The data is normallyrecorded and presented as API Gamma Ray Units as used in Wireline Loggingoperations.

Gamma rays are produced from the radioactive decay of isotopes of Uranium,Thorium and Potassium. Typical reservoir rocks, (sandstones, limestones anddolomites) are usually deficient in these elements whilst many clay mineralshave high concentrations of all three. Mudrocks therefore tend to give highgamma ray counts whilst reservoir rocks tend to have low values. This is com-plicated with variations in rock mineralogy which calls for more detailed andcareful interpretation.

Environmental factors will also affect gamma count rates. Mud types, muddensity, thin beds and hole size will all affect the response.

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MWD and Wireline Gamma Ray ComparisonsSome fundamental differences exist between MWD and wireline gamma raydata, and only rarely do the logs overlay exactly. Statistical variations associatedwith MWD logs are often considerably less than those of wireline becausewireline logging speeds are greater (1800 ft/hr) than MWD average rates of pen-etration (200 ft/hr). MWD bed resolution is improved, compared with wireline,because of the slower logging speeds. MWD formation measurements arecarried out before significant hole enlargement occurs, resulting in data requiringless correction. Also, MWD logs suffer less mud volume attenuation since thegamma sensors are housed in drill collars that typically have larger OD's than thewireline sondes. Differences are often noticed in run-by-run comparisons ofwireline gamma ray logs due to centralization practices.

Detected radiation, particularly the lower energy gamma rays of thorium anduranium, is more attenuated by the thick metal housing of the MWD collar.MWD collars range from wall thicknesses of 1" to 3", while wireline gamma raytool housings are typically 1/8” to 3/8”. Thus, the MWD measured gamma rayspectrum is biased to enhance potassium relative to thorium and uranium. Forthis reason, the MWD gamma ray data will be lower than wireline values in for-mations rich in thorium and/or uranium. After borehole correction, the two typesof logs may have identical values, particularly in formations with spectral char-acteristics similar to the API pit.

It should also be noted that the logging speed of LWD Gamma tools may bevariable within the same formation even though the ROP may have been consist-ent. This depends of the offset of the Gamma ray sensor from the bit and thethickness of the bed being drilled. For example, if the gamma ray sensor is 5mbehind the bit and there is a 5m sandstone bed in between shales then the sand-stone will be logged by the gamma ray tool at the ROP of the shales and not ofthe sandstone. If the sandstone were 10m thick then half the bed would be loggedat the sandstone ROP and half at the shale ROP. Variations in logging speedaffects resolution so that it might look, just from the gamma curve, that there issome variation in lithology which may not be the case. In some Geosteeringapplications ROP is controlled to facilitate data integrity so this will also have tobe taken into consideration when interpreting LWD data.

Baker Hughes INTEQ, with their OnTrak MWD system have an azimuthalgamma ray tool. Which can be used for making estimations of apparent forma-tion dip. The tool has two detectors that are oriented 180° apart with the samesensor depth offset. Any depth differences are a result of the relationshipbetween the well inclination and bed dip.

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Resistivity LogsElectrical resistance is the ability of a material to impede the flow of an electricalsignal. The formation matrix materials, or grains,are normally thought of asbeing insulators and therefore do not contribute to formation conductivity. Themain electrical conductor in the formation is saline water which is mostlyconfined to the pore space. Hydrocarbons, oil and gas, are also deemed to beelectrical insulators. Hence, low formation resistivity is usually indicative ofsalty water filled porosity whilst high formation resistivity can either indicate thepresence of hydrocarbons or that the rock has low porosity. Resistivity tools are,therefore, fundamental in the search for sub-surface hydrocarbons.

Resistivity logs can also indicate the presence of permeability within the forma-tion, whether water or hydrocarbon filled. This requires an array of curves with

Figure 9: MWD Gamma Ray Logging Speed Response

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different depths of investigation which will indicate variations in fluid type awayfrom the borehole.

When drilling high angle or horizontal wells resistivity information becomesimportant in geosteering applications. Deep reading resistivity tools can indicatevariations in lithology or fluid type before the boundary is crossed and the wellcan be steered away. This is most useful when azimuthal tools are used whichcan indicate whether the tool is looking up, down, left or right.

A major benefit of MWD resistivity over wireline data is the formation exposuretime. Wireline logs may be run days or even weeks after the section has beendrilled, resulting in significant invasion of permeable zones by mud filtrate. Thisinvasion makes log interpretation difficult and requires resistivity tools withdeep depths of investigation to identify hydrocarbon bearing zones. MWD toolslog within minutes of the section being drilled when invasion might be thoughtof as minimal, thus enhancing the interpretation process.

Short Normal ResistivityDuring the late seventies, MWD companies looked for a resistivity measurementwhich could be easily made using existing technology. The 16-inch short normalmeasurement was chosen as it was thought to have very useful applications forpore pressure evaluation in the Gulf of Mexico. The short normal (SNR) tool hasa typical operating range from 0.2 to 50 ohm-m and provides a basic resistivitymeasurement in water based fluids where formation resistivity is close to mudresistivity.

Figure 10: Short Normal Theory

Generator

Meter

B

A

M

N

Spacing O

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Focused Current Resistivity (FCR)The laterolog technique, commonly used in wireline logging, provided the basisfor improvements to short normal MWD. In 1987, Exploration Logging(EXLOG) introduced a laterolog-style MWD tool. This Focused Current Resis-tivity (FCR) tool added focusing current electrodes above and below the meas-urement electrode to force the measurement current deeper into the formation.The focused current resistivity (FCR) sensor was designed to perform optimallyin salt saturated muds, providing excellent thin bed resolution and improvedresponse in formations where Rt is in excess of 200 ohm-m

Measurement PrincipleThe FCR sensor uses the same measurement principle as the guard or laterologtool of the wireline industry. The sensor utilizes three current emitting elec-trodes: two focusing and one measurement current electrode. Current is focusedinto the formation by forcing the voltage of both the focusing electrodes and themeasurement electrode to have the same potential. A disc of investigatingcurrent perpendicular to the axis of the tool, is focused horizontally into the for-mation. The current from the

Figure 11: Electrode Type Resistivity Tools

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Petrophysics1-16

focusing electrodes prevents the measurement current, from flowing vertically inthe borehole. Like the SNR the FCR is a series measuring device. The currentdisc passes through the borehole fluid, then into the formation. Both outputvoltage and current from the measurement electrode are measured. Formationresistivity is calculated from Ohms's Law using the current and voltage of themeasurement electrode. The resistivity is converted to an apparent formationresistivity using the “K” factor of the tool.

Toroidal ResistivityToroidal Resistivity is offered commercially by Halliburton and Anadrill/Sch-lumberger also use the toroidal principle in the RAB tool. The toroidal resistivitytool is based on a proposal by JJ Arps. The tool utilizes the collar as an electrodeto provide two resistivity measurements: a focused lateral resistivity measure-ment and a trend resistivity at the drill bit. The tool utilizes four toroidal coilscovered and protected by insulating shells. A voltage applied from the drivetoroid induces an alternating current in the drillstring, which is reversed inpolarity about the drive toroid. Current leaving the drillstring flows through theannulus and formation and returns to the drillstring at a point where the polarityis opposite. Essentially, induction drives a current along the collar and two setsof receivers measure this current. Tool performance in lateral mode depends onthe length of BHA below the receivers. As the distance from the lower toroid tothe bottom of the hole increases, the bit measurement becomes less distinctive,and at lengths of 20 feet or more the bit resistivity almost ceases to respond tochanges in formation resistivity (K factor is therefore BHA dependent). With oilbased muds an axial bit measurement is still possible, because of the contact of

MWD Overview

Petrophysics 1-17

the drill bit with the formation (interstitial water). However, it should be notedthat axial bit measurement will not be possible with the bit off bottom.

Electromagnetic Wave Propagation ResistivityElectromagnetic waves propagated through the formation are affected by resis-tivity variations rather than the nature of the rock. The waves are slowed as theconductivity of the formation increases causing the amplitude of the wave tobecome attenuated. In order to maintain the same frequency the wavelengthchanges. Measurement of amplitude attenuation and phase shift (difference) asseen by a pair of receivers some distance from the transmitter enables the forma-tion resistivity to be calculated.

Figure 12: Schlumberger RAB Tool

MWD Overview

Petrophysics1-18

The standard WPR tool used by most vendors is a 2-Mhz device that providestwo resistivity measurements at different depths of investigation. For example,the Baker Hughes INTEQ tool contains two receiving antennas which are spaced27.5 and 34.5 inches (69.85 and 87.63 cm) from the single transmitting antenna.

Phase Difference MeasurementThe DPR sensor measures these signal changes by detecting the difference inphase, or phase shift, between the two receivers which are spaced 7 inches (177mm) apart. This receiver spacing is only a small fraction of a wavelength in highresistivity formations, resulting in small phase differences in high resistivity for-mations. Conversely, larger phase differences occur in low resistivity forma-tions.

Amplitude Ratio MeasurementThe transmitted DPR signal is dramatically attenuated (signal amplitudedecreases) as it propagates through a conductive formation. The signal is atten-uated very quickly in low resistivity formations, and to a lesser extent in highresistivity formations. By comparing the signal amplitude at the near and farreceivers, the DPR sensor measures the attenuation that occurs between the tworeceivers. This attenuation or amplitude ratio measurement, like the phase differ-ence measurement, is subsequently converted to resistivity.

Figure 13: Electromagnetic Wave Propagation

MWD Overview

Petrophysics 1-19

Depth of InvestigationBy measuring both the phase difference and attenuation between the two receiv-ers, the DPR sensor provides two resistivity measurements with different depthsof investigation: a shallow phase difference and a deep attenuation measurement.The lines of constant amplitude around the transmitter are very wide, resulting inthe depth of investigation of the amplitude ratio measurement being greater thanthe transmitter to receiver spacing, (namely 27.5"). In contrast, the lines ofconstant phase form a sphere radiating from the transmitter. This results in adepth of investigation approximately equal to the transmitter to receiver spacing.Depth of investigation (DOI, expressed as a diameter) for propagation resistivityMWD measurements is strongly dependent on and positively related to forma-tion resistivity. For the DPR phase difference measurement, depth of investiga-tion ranges from 23 inches in low resistivity formations to over 50 inches inhigher resistivities. For the amplitude ratio measurement, the DOI range isroughly 40 to 60 inches, depending on resistivity.

Figure 14: 2MHz response

MWD Overview

Petrophysics1-20

Figure 15: 400 kHz response

Figure 16: EWR Log

MWD Overview

Petrophysics 1-21

Borehole CorrectionsBorehole size and mud resistivity will affect the response and need to be cor-rected. Dialetric factors, (the ability of the formation to store an electrical charge)are often responsible for variations in response, particularly separation of theamplitude and phase curves. In thinly bedded reservoirs, resistivity measure-ments may be adversely affected by overlying and underlying lithologies. Tooleccentricity and formation invasion can also be corrected.

Current SystemsHalliburton, under its Sperry Sun product line has a tool called the EWR-Phase4™ which has four radio-frequency transmitters and a pair of receivers. Bymeasuring both the phase shift and the attenuation for each of the four transmit-ter-receiver spacings, eight different resistivity curves with differing depths ofinvestigation can be provided. These are referred to as Extra Shallow, Shallow,Medium and Deep giving depths of investigation from 19” to 141” depending onthe resistivity of the formation being investigated.

Schlumberger and Baker Hughes INTEQ also have tools which produce electro-magnetic waves at 400kHz. Amplitude Attenuation and Phase Difference resis-tivities are again computed but the 400kHz wave produces deeper investigationthan the corresponding 2Mhz curves.

The original Dual Propagation (DPR) devices have also been supplemented, aswith the Sperry Sun tool, with additional transmitters and receivers to producemultiple wave propagation tools (MPR). The Baker Hughes INTEQ MPR tool,for example, is characterized by a compensated antenna design. A pair of receiv-ing antennas spaced 8 inches apart are bounded above and below by a pair of

Figure 17: Sperry Sun EWR Phase4

MWD Overview

Petrophysics1-22

transmitting antennas, which are spaced 23 and 35 inches from the measure point(halfway between the receiving antennas). Measurements are taken in both direc-tions (transmitting signal above and below) and averaged to cancel any boreholeeffects or drifting of electronics (drifting electronics are typically caused byincreasing temperature and pressure downhole and is a problem which plaguessingle transmitter or uncompensated designs).

This produces Long Spacing and Short Spacing resistivity measurements derivedfrom Amplitude Attenuation and Phase Difference responses from both the2Mhz and 400kHZ wave forms. This gives a total of eight resistivity curves ofvarying depths of investigation and vertical resolution. Data processing of all thisinformation can be done to produce a set of resistivity curves of nominally setdepths of investigation at 10”, 20” 35” and 60”

Generally speaking, amplitude attenuation resistivity gives deeper depth ofinvestigation but poorer vertical resolution than phase Difference derived resis-tivity.

Generally, electromagnetic wave propagation resistivity has the following char-acteristics:

• Tools measure more accurately in conductive media.

• Improved vertical resolution in conductive media.

• Depth of investigation increases with increasing formation resistivity.

• Depth of investigation is deeper for the 400 kHz resistivities than the 2 MHz resistivities.

• Depth of investigation for attenuation resistivities is deeper than phase difference resistivities.

• Depth of investigation for long spaced resistivities is deeper than for short spaced resistivities.

• Depth of investigation for ratio and difference resistivities is deeper than for raw measurements.

• Depth of investigation order is as follows:⇒ 400 kHz Rat > 2 MHz Rat > 400 kHz Rpd > 2 MHz Rpd⇒ long spaced > short spaced⇒ attenuation > far amplitude > near amplitude⇒ phase difference > far phase > near phase

MWD Overview

Petrophysics 1-23

• Vertical resolution is better for 2 MHz resistivities than for 400 kHz resistivities.

• Vertical resolution is better for phase difference resistivities than attenuation resistivities.

• Vertical resolution is better for differences and ratios than for raw measurements.

Typically wireline resistivity data is used to identify hydrocarbons, estimate Rt(true formation resistivity) for saturation calculations and model invasionprofiles (separation of multi-depth of investigation tools). This is still possiblewith MPR measurement while drilling devices although estimates of Rt arepossibly less accurate and invasion is almost certainly less developed.

One of the main benefits of MWD resistivity is its assistance in Geosteeringapplications. Modelling the resistivity response can help in target finding and indrilling the reservoir, providing adequate offset data is available or a pilot holeis drilled before any high angle sidetracks are drilled. When drilling shallowdipping beds at a high borehole angles, or even horizontally, MWD resistivitytools will pick out bed boundaries and fluid contacts according to the depth ofinvestigation of the tools. Deeper investigation will allow earlier confirmation ofbed boundaries or fluid contacts and result in lower doglegs when drilling awayfrom undesirable features.

Figure 18: Distance to bed confirmation

MWD Overview

Petrophysics1-24

Formation AnisotropyShale and thinly laminated sand-shale sequences can exhibit anisotropy. Thisresults in one resistivity horizontally, Rh (assuming a flat lying formation), andanother generally higher resistivity vertically, Rv. Whereas a propagation resis-tivity or induction tool in a vertical hole would detect the horizontal resistivity,any well deviated from the normal to the bedding plane (the extreme case is ahorizontal well through flat lying formations) would measure an average of thehorizontal and vertical resistivities. Hence, anisotropy effects are highly depend-ent on the relative dip between the formation and the borehole. Generally, asrelative dip increases from 45 to 90 degrees anisotropy effects in anisotropic for-mations range from small to significant.

Given sufficient relative dip, anisotropy almost always causes the phase differ-ence based resistivity to be greater than the attenuation based resistivity and bothwill be greater than Rh and less than Rv. Also, anisotropy will cause higher fre-quency measurements (2 MHz) to have greater resistivity values than equivalentlow frequency measurements (400 kHz). Both of the above described effectsproduce a pattern that is similar to resistive invasion i.e. Rxo greater than Rt.However, an anisotropy effect which is not consistent with resistive invasion is

Figure 19: Vertical Well

MWD Overview

Petrophysics 1-25

long spacing measurements will show greater resistivity than equivalent shortspacing measurements.

Neutron Porosity - Density MeasurementsMWD measurements of porosity and density came along some time after gammaray and resistivity data were included. The tools function in much the same wayas their wireline log equivalents but with a little more data processing requiredto overcome borehole and tool rotation/eccentricity effects.

Figure 20: Horizontal Well

MWD Overview

Petrophysics1-26

Neutron Porosity

Most tools use a chemical source (americium-beryllium) and a lithium scintilla-tion detector to measure the passage of emitted neutron particles through the for-mation.

When a neutron is captured, the resulting lithium-6 nucleus is unstable anddecays to triton and an alpha particle with a combined kinetic energy of 4.78MeV. These high energy particles ionize the glass matrix and produce lightflashes or scintillations. A photomultiplier tube converts the scintillations intoelectrical pulses which are proportional to the energy of the scintillation.

They are slowed down from energies of several million electron volts (e.g. 4.5MeV) to a thermal energy of 0.025 eV (electron volts) through a process calledelastic collision (they are scattered from the nuclei). The material most responsi-ble for this slowing process is Hydrogen since this has a mass most equivalent tothat of the emitted neutrons. In effect, therefore, the tool is measuring thehydrogen content, or index, of the formation; since most hydrogen is present inore fluids (gas, oil, water) then the hydrogen index is converted directly into a

Figure 21: Neutron Porosity Tool

MWD Overview

Petrophysics 1-27

porosity value. API calibration is done with respect to the original test calibrationborehole at the University of Houston but with specially constructed calibrationrigs. Most Neutron Porosity logs are therefore output in Limestone porosityunits, although this doesn’t have to be the case.

Formation DensityAgain the MWD formation density tool works in a similar manner to its wirelineequivalent. High energy gamma rays are emitted from a chemical source(Caesium-137) and are slowed by and counts measured by near and far detectors(to correct for mud cake effects). The high energy gamma rays are initiallyslowed by Compton Scattering type interactions where the incident gamma rayloses some, but not all, its energy on particle collision and is deflected to moveoff and be subject to more collisions. Sodium Iodide scintillation detectors countthe incoming gamma rays.

At energy levels below 100 keV the dominant gamma interaction process is pho-toelectric absorption. In this process, the incident gamma ray is absorbed andtransfers its energy to a bound electron. A Pe measurement clearly distinguishesbetween different elements within the formation, making it possible to discrimi-nate between sandstone (Pe=1.8), dolomite (Pe=3.1), and limestone (Pe=5.1).Thus, this is an important mechanism by which the density tool is made sensitiveto the lithology of the formation.

Figure 22: MWD Density Tool

MWD Overview

Petrophysics1-28

Sonic LogsMWD sonic logs have only been available relatively recently but are useful inproviding real-time data for identifying compaction trends for pore pressureanalysis and provide information about over-pressured zones. A synthetic seis-mogram can be constructed to tie into the surface seismic section along thewellbore trajectory, although this is not usually done in real-time.

MWD sonic tools work in a similar manner to wireline tools. An acoustic sourceis linked to an array of (usually) four receivers with a spacing similar to that usedin long-spaced wireline tools. This allows for greater time separation betweencompressional, shear (in fast formations) and fluid modes and the ability tomeasure beyond formation damage and invasion.

Figure 23: Stand-off Binning

MWD Overview

Petrophysics 1-29

Pressure While DrillingTwo types of Pressure While Drilling MWD tools are now available. For anumber of years tools with external pressure transducers have been able tomeasure downhole annular pressure in order to derive circulating (ECD) andstatic (ESD) mud pressure information which are both crucial in drilling per-formance and operational safety.This information can be used in real time tooptimize performance and minimize risk by identifying hole cleaning, boreholestability and well control issues.

During 2004/2005 formation pressure measuring tools have also become availa-ble which supplement traditional drillpipe and wireline conveyed pressuretesting tools. In permeable formations accurate measurements of pore pressurecan be made to help optimize drilling performance and safety and to help cali-brate any indirect estimates of formation pressure that have been made. They canalso help identify formation fluids and contacts by obtaining pressure gradientinformation.

Drilling MechanicsVibration analysis and downhole weight on bit and torque measurements canalso be obtained in order to optimize drilling performance and to reduce possibledrillstring damage. Downhole longitudinal and lateral strain gauges and shockmeasurements provide the data to help identify such things as ledges, highfriction coefficients, BHA whirl and stick-slip effects.

Figure 24: Sperry Sun BAT Tool

MWD Overview

Petrophysics1-30

LWD Imaging Logs

Petrophysics 2-1

OverviewModern LWD tools can provide detailed borehole and formation images usinghigh resolution, azimuthal resistivity, density and acoustic data. The imagesprovide two-dimensional geological, petrophysical and geomechanical informa-tion to help optimize geosteering and drilling performance.

Azimuthal measurements are taken as the borehole rotates. Linked to a direc-tional sensor this provides full 360° coverage. A graduated colour scale isassigned to the data and the images are oriented by tool magnetometers. The360° data are plotted on two-dimensional paper by unwrapping the image fromthe top of the hole when drilling high angle/horizontal beds. The log track there-fore has the bottom of the hole in the centre, with left to the right and right to theleft centre. The right and left extremes of the track correspond to the top of thehole.

The graduated colour scale usually has low resistivities shown by dark coloursand high resistivities shown by light colours. When drilling the reservoir thisshows shales as dark and hydrocarbon bearing reservoir rocks as light. Similarly,low densities are shown as dark colours and high densities as light colours.

Figure 1: Imaging Log Overview

LWD Imaging Logs

Petrophysics2-2

Using LWD imaging tools when drilling a borehole at an angle to dipping bedsthe bed boundaries will intersect the borehole at different levels when looking indifferent azimuthal directions. When 360° data is opened up and plotted in two-dimensions the dipping bed intersecting the borehole will show as a sinusoidalcurve. The amplitude of the curve will show the apparent (relative) dip of thebeds and the curves will point up or down the log depending on whether theborehole is drilling up or down section. Drilling at a high angle to the beddingwill give horizontal images and drilling parallel to the bedding will give parallelimages.

Additionally, fractures, borehole breakout and secondary porosity features maybe identified from the images. Conductive drilling fluid filled fractures andbreakout will show as dark features while cemented fractures will show as lightcoloured features.

Resistivity ImagesThe Schlumberger GeoVISION resistivity tool contains three one-inch buttonsmeasuring azimuthal resistivity. This compares with the wireline FMI tool whichhas 192 buttons. The sensor spacing between the three buttons produces differentdepths of investigation and images are available from each spacing. The imagescan be used to identify thin beds, invasion, structural dip and stratigraphic fea-tures.

Figure 2: Schlumberger Vision Density Image

LWD Imaging Logs

Petrophysics 2-3

Density ImagesDensity and photoelectric effect tools can provide images in non-conductivedrilling fluids and are available for hole sizes down to 5¾”. They are usuallymeasured and plotted by quadrant (up, down, left, right) or, in the case of theSchlumberger ADNVision tool, in 16 sectors around the borehole. They provideenough detail to identify structural dip, faults and large scale stratigraphic fea-tures. Information is provided about drilling up or down section and modelleddensity responses can be used to identify bed boundaries or fluid contacts.

Figure 3: Schlumberger ADN Tool

LWD Imaging Logs

Petrophysics2-4

Wellbore StabilityReal time LWD measurements, including acoustic caliper, and cuttings, cavingsanalysis and drilling fluid solids content can be used to help interpret themechanical stability of the borehole. High ECD values may cause mud inducedfeatures such as fracturing whilst anisotropic tectonic stress may cause boreholebreakout along certain azimuths. This data together with pore pressure and kicktolerance information is important in optimizing drilling fluid pressures andhydraulics to maximise drilling effciency and safety.

Figure 4: Schlumberger ADN Log

LWD Imaging Logs

Petrophysics 2-5

Geosteering ApplicationsImaging logs can be used for a variety of geosteering applications such as theidentification of:

• Lithological Boundaries

• Fluid Contacts

• Borehole - Bedding angles

• Drilling attitude: up section or down section

• Faults

Figure 5: Schlumberger GeoVISION Borehole Breakout

LWD Imaging Logs

Petrophysics2-6

Figure 6: Drilling up or down section

Figure 7: Geosteering Applications

LWD Imaging Logs

Petrophysics 2-7

Figure 8: Fault Identification

LWD Imaging Logs

Petrophysics 2-8

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Geosteering Techniques

1Copyright Stag Geological Services Ltd. 2006

Geosteering

• Those activities designed to place the wellbore in a pre-determined location

• Location being defined by both its spatial coordinates, in three dimensions, & by its position in the geological column.

• Proper geosteering will optimise wellbore placement in the productive reservoir, maximising both drilling efficiency & hydrocarbon production.

Introduction



M-05

M-18

M-37

M-13

surfacelocation

horizontal

Contour Map with Geosteering Well Prospect

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M-13

x700SP Resistivity

sand thickness 22 ft

M-05

M-18

x500

x600 x600SP Resistivity

SP Resistivity

SP Resistivity




M-37Fence Plot for Geosteering Well Prospect



6800

6900

7000

1500 2000 2500 3000

actual well

gas

original plan

3500 4000 4500 5000

gasoilwater

Vertical section (AZI = 325) (ft)

6920

6940

6960

6980

7000

7020

7040

1500 2000 2500 3000 3500 4000 4500 5000

Faults

Pilot

Actualpath

OriginalPlan

ModifiedPlan

OWC

Shale

a

b c

N2L

N3

N2LN3

N2L

N3

True Scale Section Plot and Section Schematic

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• Rate of Penetration (ROP)

• Cuttings Evaluation

• Oil Show Evaluation

• Gas Ratio Analysis

• Logging While Drilling (LWD)Gamma Ray (GR)ResistivityDensity-Neutron Porosity

• Biostratigraphy

• Chemostratigraphy

Introduction



Rate of Penetration

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Rate of Penetration

• Variations in ROP may indicate lithology changes

• Variations in ROP may indicate reservoir heterogeneity

• Variations in ROP may indicate faults



ROP is the first indication we have that changes haveoccurred downhole:

• Before a sample reaches the surface

• or LWD tools reach the zone (unless RAB for example)

ROP will indicate immediately if the well has:

• Left the reservoir

• Crossed a fault

Rate of Penetration

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ROP must be consistent throughout the reservoir • Consistency will be obscured if sliding is needed to alter the trajectory

• Drilling parameters such as WOB, RPM & pump pressure mustbe constant

• If a reservoir consistently drills fast, then lower limits can be applied.

For example if the well has been drilling at 500 ft/hr average then anything below 350 ft/hr will indicate that something has changed. However if it is a particularly tight reservoir which depends primarily on fractures for its permeability, then an average ROP will be difficult to determine. Here a good ROP may be 80 ft/hr, but a zone at 30 ft/hr may have a high fracture density.

• It is not always clear cut & depends on the reservoir being drilled.

Rate of Penetration



ERD / Horizontal Well Issues:

• The weight indicator does not always reflect the exact weight being applied to the bit

• But it is clear from the addition of extra weight that the WOB does have an effect.

• Often in sand reservoirs with high torque it is difficult to get all the weight to the bit & as a result the ROP decreases.

• Short wiper trips to reduce torque will often help to increaseROP.

Rate of Penetration

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Rate of Penetration

ERD / Horizontal Well Issues (contd.):

•Look at the ROP to see if there is a correlation with changes in shows

• ROP will reflect visible porosity (among other variables!). Obviously the faster the formation drills the more porous it is. In friable grainstones or loose sands the ROP will be very fast & using this as a first line guide efforts can be made to keep the well path within this zone

• Correlation with LWD will invariably show that high ROP’s will occur in the optimum reservoir.

• Exceptions to this will be in lithologies with low matrix or granular porosity but a high fracture density



ERD / Horizontal Well Issues (contd.):

• Regular plots of the ROP trace should be provided by the mudloggers

• A certain pattern in the ROP from the pilot hole will provide avaluable tool in recognition of certain zones within the reservoir & can be combined with biostratigraphy & shows to give a type zone. This is very important in fault recognition

• Sometimes the ROP observed in the pilot hole may be higher in the horizontal hole simply because the bit has found the optimum ‘drillability’ layer. A vertical well will probably miss this

Rate of Penetration

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Very porous reservoir such as a loose Tertiary sand:• WOB will decrease and the ROP increase. • There will also be a change in torque.

In the event of having to orient a mud motor by sliding the RPM will be reduced and the ROP will drop.

These factors play an important part in geosteering the well.It is therefore important to be aware of the intervals where slidingtakes place. In a very porous reservoir the ROP will still be relatively high in a sliding mode.

Increases in drag will increase the torque & ROP’s will be lower asthe well path increases. However after a wiper trip or the addition of a lubricant ROPs will more properly reflect the reservoir type.

Rate of Penetration



Oil Show Evaluation

• Offset logs or pilot hole data will provide information on type of shows to be expected in the reservoir

• First determine preliminary layering based on shows. This couldbe colour of natural cut, intensity, rate of cut. Natural cut is the bestmethod of show identification.

• It is advisable where possible to observe example cuttings or core data. If these are not available a thorough study of a type example of show variation should be attempted. This will involve detailed notes on sample descriptions from mud logs or final well reports.

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• For speed of access to the information so that decisions can quickly be made, it is important to take natural cuts first

This is the new wet technique (Simpson 1991)

• Place a specified amount of wet washed sample, usually 3cc and cover with twice the volume with solvent.

• This is then agitated for a minute by shaking & then siphoned into a second test tube. The colour of the cut will then be readily apparent.

• It is important to keep a reference set of samples in a test tube whilst drilling.

Oil Show Evaluation



Oil staining is also important

• In the optimum reservoir this might appear as very dark amber tan

• Immediately outside the optimum the stain may decrease to a medium tan

• For this reason it is very important to keep a reference set of samples whilst drilling in order to observe local changes in the oil stain

• When the well bore leaves the optimum zone an immediate change in colour will normally be observed

• If the well is bouncing across the boundary, the staining may vary little; thisis why all other methods are important

Oil Show Evaluation

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• The speed of the fluorescence cut will act as a back up indicator

• It will nearly always be slower in tighter formations with low ROP & faster in more porous, higher ROP sections

• In optimum areas the cut may occur instantly & generally diffuse indicating good porosity

• In areas with less porosity the cut may be streaming; even less porous formations may yield the cut over a period of minutes in a slow diffuse manner.

• The behaviour of the cuts will need to be examined in detail to determinehow they behave in the optimum part of the reservoir.

Oil Show Evaluation



• In optimum reservoirs the oil residue left in the spot tray after the solvent has evaporated will be a more rich & deeper brown colour

• In areas approaching the water zone this will appear as a weaker & thinner pale brown rim

• In tighter areas within the oil column, say immediately above the optimum zone the oil residue will normally be a rich brown butvery thin.

Oil Show Evaluation

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Gas Ratio Analysis

Gas Ratio Analysis techniques are based on the theory that an increasing hydrocarbon fluid density in the reservoir will manifest itself at the surface as an increasing gas density

Thus, while a quantitative analysis of surface gas to reservoir fluid is not possible, a qualitative analysis is the most common method used today was developed by Baker Hughes INTEQ, & comprises:

• Gas Wetness Ratio• Light-Heavy Ratio• Oil Character Qualifier

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Gas Ratio Analysis

Gas Wetness Ratio (GWR, Wh)

GWR Fluid Character0.5 Very Dry Gas0.5 - 17.5 Gas, increasing density17.5 -40 Oil, increasing density> 40 Residual Oil

Light-Heavy Ratio (LHR, Bh)

Oil Character Qualifier (OCQ, Ch)

10054321

5432×

+++++++

CCCCCCCCC

54321CCC

CC++

+

3544

CCnCiC ++

Gas Ratio Analysis



Gas Ratio Analysis

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Gas Ratio Analysis



Gas Ratio Analysis

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Inclinometer positionInclinometer position

downhole motor MWDDirectional Sensor Typical 15 - 20 m

Motor

Inclination

NBI 4.1 mDirectional Sensor 18 m

NaviGator

• TELECO patent from 1988 – signal transmission from sensor sub to MWD through cable in stator housing

• Geosteering contracted in 1993, instrumented motor supplied to G-4AH – August 1994.• NaviGator geosteering motor became the standard drilling tool at Troll and other Hydro

operations • TVD control requirements were met from the first well• The Thruster/NaviGator combination increased the drillable length of horizontal section from 1800m

to 2300 m

• Directional- and LWD sensors 15-20 meters behind the bit.• Drilling efficiently at Troll West with “blind zones” (inclination, GR and Resistivity) is not possible



LWD (Gamma Ray)

Gamma Ray tools used for:

• Geological Correlation

• Bed Boundaries

• Geosteering

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Logging While Drilling (Gamma Ray)

Oriented Gamma Ray

• The Baker Hughes INTEQ “OnTrak” MWD System provides an Oriented Gamma measurement that can be used to calculate apparent dip.

• This tool is integral to the revised Autotrak G3 tool

• The tool has two detectors that are oriented 180º apart with the same sensor depth offset

• Any depth differences are a result of the relationship between the well inclination & bed dip



Logging While Drilling (Gamma Ray)Bed dip calculated from

measured depth differencebetween the two GR values

Typical Sensor Specifications:

Sensor Type: Scintillation

Measurement: API GR

Range: 0-250 APIAccuracy: ±2.5 API @100 API

& ROP = 60ft/hr

Vertical Resolution: 6 ins (15.3cm)

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Resistivity Logs



Baker Hughes INTEQ MPR Logging While Drilling (Resistivity)

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Distance to ContactDistance to Contact



Pay

Drilling distance to contact

At-the-bitelectrical resistivity

uthalelectrical resistivity

Azim

Inductive propagationdeep resistivity

InductivePropergationShallowResistivity

f

Non-Pay

Projecting Distance to Contact

pp31

3 ft depth of investigation at 2 deg means 85 ft look ahead of the bit?

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vertical well vertical well

low resshale

high resoil/gas

very lowreswater

Inductive devices read in groundloops perpendicular to the tool.The measurement effectively seeseach layer.

Electrical devices readin current paths parallelto the tool. The measurementsees each layer dependingon focusing.



horizontal wellslow resshale

high resoil/gas

very lowreswater

Inductive device loops are“opened” by the higher resistivity layers and readhigh.

Electrical devices “short circuit”through the lower resistivity layersand read low.

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Recovery DistanceRecovery Distance

• Angle of incidence• Bit-to-sensor distance• Maximum permissible curve rates• Anticipated changes in geology



Recovery Distance TermsRecovery Distance Terms

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GeosteeringGeosteering Well ExampleWell Example



AzimuthalAzimuthal MeasurementsMeasurements

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45Copyright Stag Geological Services Ltd. 2006 pp46

0

90

180

-90

High Side

Low Side

01020304050

0123456

Azimuthal Button Resistivity

Azimuthal Focused Gamma Ray

Resistivity(ohm-m)

Depth 9145Depth 9083 Depth 9173

Gamma ray(gapi)

Geosteering Well Example: Azimuthal Test Results



D11

Current depth= 9160

D14

RESGR

RESGR

Gamma ray

Resistivitydata

Vertical section (AZI=330) (ft)

True

verti

cal d

e pth

(ft)

7250

7300

7350

7400

1200 1600 2000 2400 2800

D11Current depth

= 9160

D14

RESGR

RESGR

Gamma ray

Resistivitydata

Vertical section (AZI=330) (ft)

True v

ertic

al de

pth

(ft)

7250

7300

7350

7400

1200 1600 2000 2400 2800

Geology StructureInterpretationBefore AZI Tests

Geology StructureInterpretationAfter AZI Tests

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BHI DeepTrak™MPR Resistivity

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Logging While Drilling (Imaging Logs)



Logging While Drilling (Density/Porosity)

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Schlumberger ADN BHA and Image Log



Schlumberger ADN Image Log

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Schlumberger Vision Tools



Schlumberger GVR Tool

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Schlumberger Geovision Resistivity Image (GVR)



Schlumberger Geovision RAB Image

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Schlumberger WellEye™

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Schlumberger WellEye™Hole Shape



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Anadrill Vision 675



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90.6

265.4inclination

azimuth

LAST SURVEY

1.5û BH motorconfiguration

UP

RIGHT

DOWN

LEFT

Tool Face Display

++++++++

++++

+ 1.4 RLAST TOOL FACE

degrees

pp27

MWD Operations: Tool Face Angle showing good directional control



90.6

265.4inclination

azimuth

LAST SURVEY

1.5û BH motorconfiguration

UP

RIGHT

DOWN

LEFT

Tool Face Display

++ +

+

+

++

++ +

++

+

-82.4LLAST TOOL FACE

degrees

MWD Operations: Tool Face Angle showing poor directional control

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40



MWD INCLMWD AZI

"Official Survey"

"GST New"

MWD tool

CDR tool

GeoSteering Tool

O

OBit INCL

"GST Old"

OBit INCL

currentTD

6454

TD at previousconnection

6423

Geosteering Tool Surveying OperationsWhat it takes to maintain trajectory control within +/- 18”



Model Sketch• Create formationdescription from offsetwells (layer cakes)

• Model tool responsethrough formation alongproposed trajectory

• Create look-up table forwellsite monitoring

• Tool response modeledfor changes in formationand/or trajectory

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Geosteering Screen with Density Image



TVD control in the reservoirTVD control in the reservoir1576

1577

1578

1579

1580

1581

1582

1583

1584

1585

15861700 1900 2100 2300 2500 2700 2900 3100 3300 3500 3700 3900 4100 4300

G-3 H Motor

1580

1581

1582

1583

1584

1585

1586

1587

1588

1589

15901700 1900 2100 2300 2500 2700 2900 3100 3300 3500 3700 3900 4100 4300

G-4 AH Instrumented motor

1574

1575

1576

1577

1578

1579

1580

1581

1582

1583

15841700 1900 2100 2300 2500 2700 2900 3100 3300 3500 3700 3900 4100 4300

S-13 AH Rotary Steerable System

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Schlumberger Periscope™Deep EWR Resistivity




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05/10/2005

1

Geosteering Strategies


Geosteering• Fundamentals• Strategy• Tools• Roles & Responsibilities• Communications

GeosteeringGeosteering



Geosteered or Geometric?• If the reservoir is a massive sand, geometric wells are likely to

be adequate & the cheapest option • For interbedded reservoirs, an element of geosteering (perhaps

just landing the well) is probably required• Drillers prefer geometric wells

How?Biostratigraphy

Suitable fossils & well developed zonation schemeLithostratigraphy

Important if there are permeability barriers - need to be in the correct sand for sweep efficiency

LithologyMay only need to be good reservoir, but it is necessary to know where you are to make informed decisions

Geosteering Geosteering -- FundamentalsFundamentals

05/10/2005

2



Strategy•Needs to be workable & clear•Detailed drill on paper will help to prepare team

How unique are intra reservoir markers?How good is the geological model?How good is the seismic?What are you going to do if (when) you get lost?How are you going to react to raised water?Alternative targets?What are you going to do if directional control is lost?

•ContingenciesCase & cement for unexpected waterSidetrack - open hole or mechanical

Geosteering Geosteering -- StrategyStrategy



Strategy – contd.Vertical Constraints

•Top of reservoir, Zone of Interest•Base of reservoir, Zone of Interest•Stand-off (SO) from OWC, GOC•Make sure that you understand what the real SO is - push Reservoir Engineers for their minimum SO at various positions in the well. This can avoid unnecessary steering.

Geosteering Geosteering --StrategyStrategy

05/10/2005

3



ToolsFor finding apparent bed dip

•Correlation of repeated sections •Azimuthal tools - logging wipes, time consuming•Apparent vertical thickness - in areas with consistent unit thickness•Seismic may help

Correlation •Need to be able to produce True Stratigraphic Thickness (TST) logs at the wellsite

Geosteering Geosteering -- ToolsTools



Cross Section & Decision TreeWhen used in conjunction with a cross-section it helps to

communicate the Geosteering Strategy & the Well Objectives to the entire team.

Provides a view of the well progress & flags upcoming potential decision points

Should be adapted to the requirements of the job

Geosteering Geosteering -- ToolsTools

05/10/2005

4



0

20

40

60

80

100

120

140

0 50 100 150 200 250 300

Vertical Section (ft) Plus x ft

Dep

th (f

t) P

lus

y ftWell

Objectives

‘Landing the Well’

DecisionTree

‘Drilling the Horizontal Section’

Decision Tree

‘Calling TD’Decision

Tree

Geosteering Decision TreesGeosteering Decision TreesGeosteering Geosteering -- ToolsTools

Decision Trees do not have the answers, but they can help structDecision Trees do not have the answers, but they can help structure the ure the decision making process.decision making process.



0

20

40

60

80

100

120

140

0 50 100 150


Dep

th (f

t) P

lus

y ft

Drill pre-reservoirsection

Monitor correlation

Yes

Correlation on plan?

YesContinue drilling

Continue on plan

Trip to change BHA, this may add another

additional trip

No

Yes

Agree newstratigraphicallydeeper target

Adjust trajectoryto land in planned

target

No

No No

No

No

Yes

Yes

Yes

YesYes

TAKE TIME OUTTrip to change BHA

Reconsider target options Plug back

Continuouslymonitor

correlation&

trajectory

Deep- Adjust trajectory?

Able to decreasebuild rate?

Adjust trajectoryto land in planned target

LAND WELL

No

SOME CONSIDERATIONSSand distribution- massive, thin beddedWater movement- k barriersAvoid sump at heel of well- coning, slugging

Acceptlanding

position?

Able to Increasebuild rate?

Adjust trajectory?

Targetformation

shallow toplan?

Able toachieve planned

build rate?

Agree newstratigraphicallyshallower target

No

Decision Tree: Landing the WellDecision Tree: Landing the Well

05/10/2005

5



0

20

40

60

80

100

120

140

0 50 100 150 200 250 300


Dep

th (f

t) Pl

us y

ft

SOME CONSIDERATIONSSand distribution- massive, thin beddedWater movement- k barriersContinuously assess status with respect to Well ObjectivesFacies development

Examine azimuthal data, TST sections,

seismic data

Continue drilling ahead

continuouslyassessing Sw &faulting/structure

Adjust trajectory to move into target

sandstone

Continue drilling

horizontally

No

No No

Yes

YesYes

YesYes

Knowstratigraphic

position?

Targetunit above min.

standoff?

Water fromisolated high

permzone

Relatedto local faulting

and runningcasing?

Low Sw?

Targetsandstone with

good Phi &K?

No

Continue drilling ahead

continuouslyassessing Sw &

zonation

No

No

Yes

TAKE TIME OUTConsider relaxing

stand-off

TAKE TIME OUTLook at alternative

higher targets

Assess data & make best estimate of

position w.r.t. target sand

Make bold move in preferred direction

FindTarget

sandstone?

Yes

TAKE TIME OUTTarget sand not developed

Run out of section

Wrong Direction?

Yes

Is there

Room To Reverse direction?

Make bold move in reverse direction to

Target sand

Yes

NoAt

TD decisionpoint?

Go back to Start of Horizontal section

Decision Tree

Go toTD Decision Tree

No

Yes

TAKE TIME OUTTarget sand not developed

Run out of section

Decision Tree: the Horizontal Decision Tree: the Horizontal SectionSection



0

20

40

60

80

100

120

140

0 50 100 150 200 250 300


Dep

th (f

t) Pl

us y

ft

Confirm TD

Performance criteria

No

Yes

Assess well performance using preferred measures

E.g. mD.ft.& fractional flow

PerformanceMeasures

Met ?

Yes

At plannedTD?

PerformanceMeasures

Met ?

TD

TD?TD?TD?

No

Can TDBe extended ?

TAKE TIME OUTOH Sidetrack?

No

No

Yes Drill aheadReturn to Start ofTD Decision Tree

Addedvalue by more

PI?

No

Drill aheadReturn to Start ofTD Decision Tree

Drill aheadReturn to Start ofTD Decision Tree

YesYes

Decision Tree: Calling TDDecision Tree: Calling TD

05/10/2005

6



Real clarity of Roles & Responsibilities is required to ensure that people know what is expected of them, that team members are not by-passed, & that the Well Objectives are met.

Strategic Decisions•Operations Geologist•Business Unit Geologist / Reservoir Engineer / Geophysicist•Wellsite Geologist

Tactical Decisions – need to be defined•Wellsite Geologist•Operations Geologist

Geosteering Geosteering -- Roles & Roles & ResponsibilitiesResponsibilities



Wellsite Geologists & Directional Drillers MUST be talking frequently

Wellsite Geologist to Directional Driller:

•How the correlations are looking

•What the bed dip is

•Likely upcoming trajectory changes

•How do FE parameters look; their impact on the rest of the well

Directional Driller to Wellsite Geologist:

•Upcoming nudges to maintain current target TVD

•Directional trends

•Torque, drag, hole cleaning, ledges

Geosteering Geosteering --CommunicationsCommunications

05/10/2005

7



Wellsite Geologists & Operations Geologists MUST be talking frequently

Wellsite geologist to Operations Geologist

•How the correlations are looking

•What the bed dip is

•Likely upcoming trajectory changes

•How do FE parameters look; their impact on the rest of the well

•Directional trends

•Torque, drag, hole cleaning, ledges

Operations Geologist to Wellsite geologist

•Thoughts about correlation & well position

•Feedback from BU any thoughts on structure / faults in the rest of the well

Geosteering Geosteering –– Communications Communications contd.contd.

Case Study Objectives 1. To construct a lithology log from offset wireline, MWD and cuttings information; this to be used by the drilling department to assist in writing the Detailed Drilling Plan.

Wellsi

W

2. To construct a Pressure Profile log to include Pore Pressure, Fracture Pressure and Overburden Pressure Gradient curves from offset wireline, MWD and drilling data. 3. To provide information about potential geological hazards and drilling problems to the drilling department. 4. To perform real-time geosteering co-ordination and practice decision making techniques to land the well and drill the horizontal reservoir section. Well Data North Sea, HPHT horizontal oil producer.

• Target is dome structure, trending NW-SE. Well to enter target from south-azimuth, into Calleva Sandstone reservoir dipping at 2.5º SE. Objective is tmuch of the reservoir as possible, following the gentle dome structure and sthe oil bearing window.

• Oil water contact is prognosed at 4780m TVD

• Target Information: (from one 1980s drilled exploration well)

Upper Jurassic fluvial sandstone reservoir

Operations &

te Geologist

ell Planning & Geosteering Case Study

east at 315º o drill as taying within

Target

Operations &

Wellsite Geologist

Well Planning &

Geosteering Case Study

MD: 5880m TVD: 4770m Inclination: 90º (well to have reached 90º inclination on entering the target sandstone) Azimuth: 315º Well Profile: KOP: 3030m BUR: 1º/30m (to 90º) Data Provided

1. Offset log comprising Drilling & Wireline Log Information. 2. Offset log comprising Drilling & Wireline Log Information. 3. Drill Cuttings

Tasks

1. Interpret expected lithologies using log information 2. Use cuttings to confirm lithology profile 3. Suggest mud systems and identify geological hazards 4. Estimate expected pore pressure and fracture pressure from logs and offset data 5. Participate in drilling the well on paper exercise: Choose appropriate geosteering drilling tools Choose appropriate LWD tools Land the well Drill reservoir

Operations

& Wellsite

Geologist

Well Planning & Geosteering Case Study

Formation Prognosed Actual MD TVD VS Incl MD TVD Incl Rodby (Marl) 4962 4580 977.42 65º Kimmeridge 5418 4720 1408.00 80º Calleva (Sst) 5850 4770 1845.49 90º Oil/water contact 4780

Survey Data

MD TVD VS Incl 5220 4673.77 1216.32 73º 5250 4682.29 1245.09 74º 5280 4690.3 1274.00 75º 5285 4691.59 1278.5 75º

PROPOSAL LISTING Minimum Curvature method epoc98

WELL: Calleva RKB-MSL 25.00 UNITS: m DLS per 30.00 m

Location Proj Azim 315.00 North 0.00 East 0.00MD INCL AZI TVDBRKB TVDSS LAT DEP VS DLS

Comments m Deg Deg m m N/S E/W m deg/30m

Tie-In 0.0 0.00 0.0 0.00 -25.00 0.00 0.00 0.00 0.00150.0 0.00 0.00 150.00 125.00 0.00 0.00 0.00 0.00 180.0 0.00 0.00 180.00 155.00 0.00 0.00 0.00 0.00 210.0 0.00 0.00 210.00 185.00 0.00 0.00 0.00 0.00 240.0 0.00 0.00 240.00 215.00 0.00 0.00 0.00 0.00 270.0 0.00 0.00 270.00 245.00 0.00 0.00 0.00 0.00 300.0 0.00 0.00 300.00 275.00 0.00 0.00 0.00 0.00 330.0 0.00 0.00 330.00 305.00 0.00 0.00 0.00 0.00 360.0 0.00 0.00 360.00 335.00 0.00 0.00 0.00 0.00 390.0 0.00 0.00 390.00 365.00 0.00 0.00 0.00 0.00 420.0 0.00 0.00 420.00 395.00 0.00 0.00 0.00 0.00 450.0 0.00 0.00 450.00 425.00 0.00 0.00 0.00 0.00 480.0 0.00 0.00 480.00 455.00 0.00 0.00 0.00 0.00 510.0 0.00 0.00 510.00 485.00 0.00 0.00 0.00 0.00 540.0 0.00 0.00 540.00 515.00 0.00 0.00 0.00 0.00 570.0 0.00 0.00 570.00 545.00 0.00 0.00 0.00 0.00 600.0 0.00 0.00 600.00 575.00 0.00 0.00 0.00 0.00 630.0 0.00 0.00 630.00 605.00 0.00 0.00 0.00 0.00 660.0 0.00 0.00 660.00 635.00 0.00 0.00 0.00 0.00 690.0 0.00 0.00 690.00 665.00 0.00 0.00 0.00 0.00 720.0 0.00 0.00 720.00 695.00 0.00 0.00 0.00 0.00 750.0 0.00 0.00 750.00 725.00 0.00 0.00 0.00 0.00 780.0 0.00 0.00 780.00 755.00 0.00 0.00 0.00 0.00 810.0 0.00 0.00 810.00 785.00 0.00 0.00 0.00 0.00 840.0 0.00 0.00 840.00 815.00 0.00 0.00 0.00 0.00 870.0 0.00 0.00 870.00 845.00 0.00 0.00 0.00 0.00 900.0 0.00 0.00 900.00 875.00 0.00 0.00 0.00 0.00 930.0 0.00 0.00 930.00 905.00 0.00 0.00 0.00 0.00 960.0 0.00 0.00 960.00 935.00 0.00 0.00 0.00 0.00 990.0 0.00 0.00 990.00 965.00 0.00 0.00 0.00 0.00 1020.0 0.00 0.00 1020.00 995.00 0.00 0.00 0.00 0.00 1050.0 0.00 0.00 1050.00 1025.00 0.00 0.00 0.00 0.00 1080.0 0.00 0.00 1080.00 1055.00 0.00 0.00 0.00 0.00 1110.0 0.00 0.00 1110.00 1085.00 0.00 0.00 0.00 0.00 1140.0 0.00 0.00 1140.00 1115.00 0.00 0.00 0.00 0.00 1170.0 0.00 0.00 1170.00 1145.00 0.00 0.00 0.00 0.00 1200.0 0.00 0.00 1200.00 1175.00 0.00 0.00 0.00 0.00 1230.0 0.00 0.00 1230.00 1205.00 0.00 0.00 0.00 0.00 1260.0 0.00 0.00 1260.00 1235.00 0.00 0.00 0.00 0.00 1290.0 0.00 0.00 1290.00 1265.00 0.00 0.00 0.00 0.00 1320.0 0.00 0.00 1320.00 1295.00 0.00 0.00 0.00 0.00 1350.0 0.00 0.00 1350.00 1325.00 0.00 0.00 0.00 0.00 1380.0 0.00 0.00 1380.00 1355.00 0.00 0.00 0.00 0.00 1410.0 0.00 0.00 1410.00 1385.00 0.00 0.00 0.00 0.00 1440.0 0.00 0.00 1440.00 1415.00 0.00 0.00 0.00 0.00 1470.0 0.00 0.00 1470.00 1445.00 0.00 0.00 0.00 0.00 1500.0 0.00 0.00 1500.00 1475.00 0.00 0.00 0.00 0.00 1530.0 0.00 0.00 1530.00 1505.00 0.00 0.00 0.00 0.00 1560.0 0.00 0.00 1560.00 1535.00 0.00 0.00 0.00 0.00 1590.0 0.00 0.00 1590.00 1565.00 0.00 0.00 0.00 0.00 1620.0 0.00 0.00 1620.00 1595.00 0.00 0.00 0.00 0.00 1650.0 0.00 0.00 1650.00 1625.00 0.00 0.00 0.00 0.00 1680.0 0.00 0.00 1680.00 1655.00 0.00 0.00 0.00 0.00 1710.0 0.00 0.00 1710.00 1685.00 0.00 0.00 0.00 0.00 1740.0 0.00 0.00 1740.00 1715.00 0.00 0.00 0.00 0.00 1770.0 0.00 0.00 1770.00 1745.00 0.00 0.00 0.00 0.00 1800.0 0.00 0.00 1800.00 1775.00 0.00 0.00 0.00 0.00 1830.0 0.00 0.00 1830.00 1805.00 0.00 0.00 0.00 0.00 1860.0 0.00 0.00 1860.00 1835.00 0.00 0.00 0.00 0.00 1890.0 0.00 0.00 1890.00 1865.00 0.00 0.00 0.00 0.00 1920.0 0.00 0.00 1920.00 1895.00 0.00 0.00 0.00 0.00 1950.0 0.00 0.00 1950.00 1925.00 0.00 0.00 0.00 0.00 1980.0 0.00 0.00 1980.00 1955.00 0.00 0.00 0.00 0.00

Page 1

2010.0 0.00 0.00 2010.00 1985.00 0.00 0.00 0.00 0.00 2040.0 0.00 0.00 2040.00 2015.00 0.00 0.00 0.00 0.00 2070.0 0.00 0.00 2070.00 2045.00 0.00 0.00 0.00 0.00 2100.0 0.00 0.00 2100.00 2075.00 0.00 0.00 0.00 0.00 2130.0 0.00 0.00 2130.00 2105.00 0.00 0.00 0.00 0.00 2160.0 0.00 0.00 2160.00 2135.00 0.00 0.00 0.00 0.00 2190.0 0.00 0.00 2190.00 2165.00 0.00 0.00 0.00 0.00 2220.0 0.00 0.00 2220.00 2195.00 0.00 0.00 0.00 0.00 2250.0 0.00 0.00 2250.00 2225.00 0.00 0.00 0.00 0.00 2280.0 0.00 0.00 2280.00 2255.00 0.00 0.00 0.00 0.00 2310.0 0.00 0.00 2310.00 2285.00 0.00 0.00 0.00 0.00 2340.0 0.00 0.00 2340.00 2315.00 0.00 0.00 0.00 0.00 2370.0 0.00 0.00 2370.00 2345.00 0.00 0.00 0.00 0.00 2400.0 0.00 0.00 2400.00 2375.00 0.00 0.00 0.00 0.00 2430.0 0.00 0.00 2430.00 2405.00 0.00 0.00 0.00 0.00 2460.0 0.00 0.00 2460.00 2435.00 0.00 0.00 0.00 0.00 2490.0 0.00 0.00 2490.00 2465.00 0.00 0.00 0.00 0.00 2520.0 0.00 315.0 2520.00 2495.00 0.00 0.00 0.00 0.00 315.002550.0 0.00 315.0 2550.00 2525.00 0.00 0.00 0.00 0.00 0.002580.0 0.00 315.0 2580.00 2555.00 0.00 0.00 0.00 0.00 0.002610.0 0.00 315.0 2610.00 2585.00 0.00 0.00 0.00 0.00 0.002640.0 0.00 315.0 2640.00 2615.00 0.00 0.00 0.00 0.00 0.002670.0 0.00 315.0 2670.00 2645.00 0.00 0.00 0.00 0.00 0.002700.0 0.00 315.0 2700.00 2675.00 0.00 0.00 0.00 0.00 0.002730.0 0.00 315.0 2730.00 2705.00 0.00 0.00 0.00 0.00 0.002760.0 0.00 315.0 2760.00 2735.00 0.00 0.00 0.00 0.00 0.002790.0 0.00 315.0 2790.00 2765.00 0.00 0.00 0.00 0.00 0.002820.0 0.00 315.0 2820.00 2795.00 0.00 0.00 0.00 0.00 0.002850.0 0.00 315.0 2850.00 2825.00 0.00 0.00 0.00 0.00 0.002880.0 0.00 315.0 2880.00 2855.00 0.00 0.00 0.00 0.00 0.002910.0 0.00 315.0 2910.00 2885.00 0.00 0.00 0.00 0.00 0.002940.0 0.00 315.0 2940.00 2915.00 0.00 0.00 0.00 0.00 0.002970.0 0.00 315.0 2970.00 2945.00 0.00 0.00 0.00 0.00 0.003000.0 0.00 315.0 3000.00 2975.00 0.00 0.00 0.00 0.00 0.003030.0 0.00 315.0 3030.00 3005.00 0.00 0.00 0.00 0.00 0.003060.0 1.00 315.0 3060.00 3035.00 0.19 -0.19 0.26 1.00 1.00 0.003090.0 2.00 315.0 3089.99 3064.99 0.74 -0.74 1.05 1.00 1.00 0.003120.0 3.00 315.0 3119.96 3094.96 1.67 -1.67 2.36 1.00 1.00 0.003150.0 4.00 315.0 3149.90 3124.90 2.96 -2.96 4.19 1.00 1.00 0.003180.0 5.00 315.0 3179.81 3154.81 4.63 -4.63 6.54 1.00 1.00 0.003210.0 6.00 315.0 3209.67 3184.67 6.66 -6.66 9.42 1.00 1.00 0.003240.0 7.00 315.0 3239.48 3214.48 9.06 -9.06 12.81 1.00 1.00 0.003270.0 8.00 315.0 3269.22 3244.22 11.83 -11.83 16.73 1.00 1.00 0.003300.0 9.00 315.0 3298.89 3273.89 14.96 -14.96 21.16 1.00 1.00 0.003330.0 10.00 315.0 3328.48 3303.48 18.47 -18.47 26.11 1.00 1.00 0.003360.0 11.00 315.0 3357.98 3332.98 22.33 -22.33 31.58 1.00 1.00 0.003390.0 12.00 315.0 3387.37 3362.37 26.56 -26.56 37.56 1.00 1.00 0.003420.0 13.00 315.0 3416.66 3391.66 31.15 -31.15 44.05 1.00 1.00 0.003450.0 14.00 315.0 3445.83 3420.83 36.10 -36.10 51.06 1.00 1.00 0.003480.0 15.00 315.0 3474.88 3449.88 41.41 -41.41 58.57 1.00 1.00 0.003510.0 16.00 315.0 3503.79 3478.79 47.08 -47.08 66.59 1.00 1.00 0.003540.0 17.00 315.0 3532.55 3507.55 53.11 -53.11 75.11 1.00 1.00 0.003570.0 18.00 315.0 3561.16 3536.16 59.49 -59.49 84.13 1.00 1.00 0.003600.0 19.00 315.0 3589.61 3564.61 66.22 -66.22 93.65 1.00 1.00 0.003630.0 20.00 315.0 3617.89 3592.89 73.30 -73.30 103.66 1.00 1.00 0.003660.0 21.00 315.0 3645.99 3620.99 80.73 -80.73 114.17 1.00 1.00 0.003690.0 22.00 315.0 3673.90 3648.90 88.50 -88.50 125.16 1.00 1.00 0.003720.0 23.00 315.0 3701.62 3676.62 96.62 -96.62 136.64 1.00 1.00 0.003750.0 24.00 315.0 3729.13 3704.13 105.08 -105.08 148.60 1.00 1.00 0.003780.0 25.00 315.0 3756.43 3731.43 113.88 -113.88 161.05 1.00 1.00 0.003810.0 26.00 315.0 3783.50 3758.50 123.01 -123.01 173.96 1.00 1.00 0.003840.0 27.00 315.0 3810.35 3785.35 132.47 -132.47 187.35 1.00 1.00 0.003870.0 28.00 315.0 3836.96 3811.96 142.27 -142.27 201.20 1.00 1.00 0.003900.0 29.00 315.0 3863.33 3838.33 152.39 -152.39 215.51 1.00 1.00 0.003930.0 30.00 315.0 3889.44 3864.44 162.84 -162.84 230.29 1.00 1.00 0.003960.0 31.00 315.0 3915.29 3890.29 173.60 -173.60 245.51 1.00 1.00 0.003990.0 32.00 315.0 3940.86 3915.86 184.69 -184.69 261.19 1.00 1.00 0.004020.0 33.00 315.0 3966.17 3941.17 196.08 -196.08 277.30 1.00 1.00 0.004050.0 34.00 315.0 3991.18 3966.18 207.79 -207.79 293.86 1.00 1.00 0.00

Page 2

4080.0 35.00 315.0 4015.91 3990.91 219.81 -219.81 310.85 1.00 1.00 0.004110.0 36.00 315.0 4040.33 4015.33 232.13 -232.13 328.28 1.00 1.00 0.004140.0 37.00 315.0 4064.44 4039.44 244.74 -244.74 346.12 1.00 1.00 0.004170.0 38.00 315.0 4088.24 4063.24 257.66 -257.66 364.38 1.00 1.00 0.004200.0 39.00 315.0 4111.72 4086.72 270.86 -270.86 383.06 1.00 1.00 0.004230.0 40.00 315.0 4134.87 4109.87 284.36 -284.36 402.14 1.00 1.00 0.004260.0 41.00 315.0 4157.68 4132.68 298.13 -298.13 421.62 1.00 1.00 0.004290.0 42.00 315.0 4180.15 4155.15 312.19 -312.19 441.50 1.00 1.00 0.004320.0 43.00 315.0 4202.27 4177.27 326.52 -326.52 461.77 1.00 1.00 0.004350.0 44.00 315.0 4224.03 4199.03 341.12 -341.12 482.42 1.00 1.00 0.004380.0 45.00 315.0 4245.43 4220.43 355.99 -355.99 503.45 1.00 1.00 0.004410.0 46.00 315.0 4266.45 4241.45 371.12 -371.12 524.84 1.00 1.00 0.004440.0 47.00 315.0 4287.10 4262.10 386.51 -386.51 546.60 1.00 1.00 0.004470.0 48.00 315.0 4307.37 4282.37 402.15 -402.15 568.72 1.00 1.00 0.004500.0 49.00 315.0 4327.25 4302.25 418.04 -418.04 591.19 1.00 1.00 0.004530.0 50.00 315.0 4346.73 4321.73 434.17 -434.17 614.00 1.00 1.00 0.004560.0 51.00 315.0 4365.82 4340.82 450.53 -450.53 637.15 1.00 1.00 0.004590.0 52.00 315.0 4384.49 4359.49 467.14 -467.14 660.63 1.00 1.00 0.004620.0 53.00 315.0 4402.75 4377.75 483.96 -483.96 684.43 1.00 1.00 0.004650.0 54.00 315.0 4420.60 4395.60 501.02 -501.02 708.54 1.00 1.00 0.004680.0 55.00 315.0 4438.02 4413.02 518.29 -518.29 732.97 1.00 1.00 0.004710.0 56.00 315.0 4455.01 4430.01 535.77 -535.77 757.69 1.00 1.00 0.004740.0 57.00 315.0 4471.57 4446.57 553.46 -553.46 782.71 1.00 1.00 0.004770.0 58.00 315.0 4487.69 4462.69 571.35 -571.35 808.01 1.00 1.00 0.004800.0 59.00 315.0 4503.36 4478.36 589.44 -589.44 833.59 1.00 1.00 0.004830.0 60.00 315.0 4518.59 4493.59 607.71 -607.71 859.44 1.00 1.00 0.004860.0 61.00 315.0 4533.36 4508.36 626.18 -626.18 885.55 1.00 1.00 0.004890.0 62.00 315.0 4547.68 4522.68 644.82 -644.82 911.91 1.00 1.00 0.004920.0 63.00 315.0 4561.53 4536.53 663.63 -663.63 938.52 1.00 1.00 0.004950.0 64.00 315.0 4574.91 4549.91 682.62 -682.62 965.37 1.00 1.00 0.004980.0 65.00 315.0 4587.83 4562.83 701.77 -701.77 992.45 1.00 1.00 0.005010.0 66.00 315.0 4600.27 4575.27 721.07 -721.07 1019.74 1.00 1.00 0.005040.0 67.00 315.0 4612.23 4587.23 740.52 -740.52 1047.26 1.00 1.00 0.005070.0 68.00 315.0 4623.71 4598.71 760.12 -760.12 1074.97 1.00 1.00 0.005100.0 69.00 315.0 4634.71 4609.71 779.86 -779.86 1102.88 1.00 1.00 0.005130.0 70.00 315.0 4645.21 4620.21 799.73 -799.73 1130.98 1.00 1.00 0.005160.0 71.00 315.0 4655.23 4630.23 819.72 -819.72 1159.26 1.00 1.00 0.005190.0 72.00 315.0 4664.75 4639.75 839.84 -839.84 1187.71 1.00 1.00 0.005220.0 73.00 315.0 4673.77 4648.77 860.07 -860.07 1216.32 1.00 1.00 0.005250.0 74.00 315.0 4682.29 4657.29 880.41 -880.41 1245.09 1.00 1.00 0.005280.0 75.00 315.0 4690.30 4665.30 900.85 -900.85 1274.00 1.00 1.00 0.005310.0 76.00 315.0 4697.82 4672.82 921.39 -921.39 1303.04 1.00 1.00 0.005340.0 77.00 315.0 4704.82 4679.82 942.02 -942.02 1332.21 1.00 1.00 0.005370.0 78.00 315.0 4711.31 4686.31 962.73 -962.73 1361.50 1.00 1.00 0.005400.0 79.00 315.0 4717.29 4692.29 983.51 -983.51 1390.90 0.00 1.00 0.005430.0 80.00 315.0 4722.76 4697.76 1004.37 -1004.37 1420.39 0.00 1.00 0.005460.0 80.00 315.0 4727.97 4702.97 1025.26 -1025.26 1449.94 0.00 0.00 0.005490.0 80.00 315.0 4733.18 4708.18 1046.15 -1046.15 1479.48 0.00 0.00 0.005520.0 80.00 315.0 4738.39 4713.39 1067.04 -1067.04 1509.03 1.00 0.00 0.005550.0 80.00 315.0 4743.60 4718.60 1087.93 -1087.93 1538.57 1.00 0.00 0.005580.0 81.00 315.0 4748.55 4723.55 1108.86 -1108.86 1568.16 1.00 1.00 0.005610.0 82.00 315.0 4752.98 4727.98 1129.84 -1129.84 1597.83 1.00 1.00 0.005640.0 83.00 315.0 4756.90 4731.90 1150.87 -1150.87 1627.57 1.00 1.00 0.005670.0 84.00 315.0 4760.29 4735.29 1171.94 -1171.94 1657.38 1.00 1.00 0.005700.0 85.00 315.0 4763.17 4738.17 1193.06 -1193.06 1687.24 1.00 1.00 0.005730.0 86.00 315.0 4765.52 4740.52 1214.21 -1214.21 1717.15 1.00 1.00 0.005760.0 87.00 315.0 4767.36 4742.36 1235.38 -1235.38 1747.09 1.00 1.00 0.005790.0 88.00 315.0 4768.66 4743.66 1256.57 -1256.57 1777.06 1.00 1.00 0.005820.0 89.00 315.0 4769.66 4744.66 1283.57 -1283.57 1815.25 1.00 1.00 0.005850.0 90.00 315.0 4769.93 4744.93 1304.78 -1304.78 1845.24 1.00 1.00 0.00

Page 3

Gen

General

Symbols Used in Log InterpretationGen-1

(former Gen-3)

1

dhHole

diameter

di

dj

h

∆rj

(Invasion diameters)

Adjacent bed

Zone of transition

or annulus

Flushed zone

Adjacent bed

(Bedthickness)

Mud

hmc

dh

Rm

Rs

Rs

Resistivity of the zoneResistivity of the water in the zoneWater saturation in the zone

Rmc

Mudcake

Rmf

Sxo

Rxo

Rw

Sw

Rt

Ri

Uninvadedzone

PurposeThis diagram presents the symbols and their descriptions and rela-tions as used in the charts. See Appendixes D and E for identifica-tion of the symbols.

DescriptionThe wellbore is shown traversing adjacent beds above and below thezone of interest. The symbols and descriptions provide a graphicalrepresentation of the location of the various symbols within the well-bore and formations.

© Schlumberger

General

3

Gen

General

Estimation of Formation Temperature with DepthGen-2

(former Gen-6)

80 100 150 200 250 300 350 60 100 150 200 250 300 350

27 50 75 100 125 150 175

16 25 50 75 100 125 150 175

Temperature (°F)

Temperature (°C)

Temperature gradient conversions: 1°F/100 ft = 1.823°C/100 m 1°C/100 m = 0.5486°F/100 ft

Depth(thousands

of feet)

Depth(thousandsof meters)

Annual meansurface temperature

Annual meansurface temperature

5

10

15

20

25

1

2

3

4

5

6

7

8

0.6 0.8 1.0 1.2 1.4 1.6°F/100 ft

1.09 1.46 1.82 2.19 2.55 2.92°C/100 m

B

A

Geothermal gradient

© Schlumberger

10 20 50 100 200 500 1,000 2,000 5,000 10,000 20,000 50,000 100,000 300,000

2.0

1.5

1.0

0.5

0

–0.5

2.0

1.0

0

Total solids concentration (ppm or mg/kg)

Multiplier

† Multipliers that do not vary appreciably for low concentrations (less than about 10,000 ppm) are shown at the left margin of the chart

Li (2.5)†

NH4 (1.9)†

Na and CI (1.0)

NO3 (0.55)†

Br (0.44)†

I (0.28)†

OH (5.5)†

Mg

Mg

K

K

Ca

Ca

CO3

CO3

SO4

SO4

HCO3

HCO3

General

5

Gen

PurposeThis chart is used to approximate the parts-per-million (ppm) con-centration of a sodium chloride (NaCl) solution for which the totalsolids concentration of the solution is known. Once the equivalentconcentration of the solution is known, the resistivity of the solutionfor a given temperature can be estimated with Chart Gen-6.

DescriptionThe x-axis of the semilog chart is scaled in total solids concentrationand the y-axis is the weighting multiplier. The curve set representsthe various multipliers for the solids typically in formation water.

ExampleGiven: Formation water sample with solids concentrations

of calcium (Ca) = 460 ppm, sulfate (SO4) = 1,400 ppm,and Na plus Cl = 19,000 ppm. Total solids concentration= 460 + 1,400 + 19,000 = 20,860 ppm.

Find: Equivalent NaCl solution in ppm.

Answer: Enter the x-axis at 20,860 ppm and read the multipliervalue for each of the solids curves from the y-axis: Ca = 0.81, SO4 = 0.45, and NaCl = 1.0. Multiply each concentration by its multiplier:

(460 × 0.81) + (1,400 × 0.45) + (19,000 × 1.0) = 20,000 ppm.

Equivalent NaCl Salinity of SaltsGen-4

(former Gen-8)

© Schlumberger

General

8

Gen

Resistivity of NaCl Water SolutionsGen-6

(former Gen-9)

°F 50 75 100 125 150 200 250 300 350 400°C 10 20 30 40 50 60 70 80 90 100 120 140 160 180 200

Temperature

Resistivityof solution(ohm-m)

ppm

10

8

6

5

4

3

2

1

0.8

0.60.5

0.4

0.3

0.2

0.1

0.08

0.060.05

0.04

0.03

0.02

0.01

200

300

400

5006007008001,0001,2001,4001,7002,000

3,0004,0005,0006,0007,0008,00010,00012,00014,00017,00020,000

30,00040,00050,00060,00070,00080,000100,000120,000140,000170,000200,000250,000280,000

Conversion approximated by R2 = R1 [(T1 + 6.77)/(T2 + 6.77)]°F or R2 = R1 [(T1 + 21.5) /(T2 + 21.5)]°C

300,000

NaClconcentration

(ppm orgrains/gal)

grains/galat 75°F

10

15

20

2530

40

50

100

150

200

250300

400

500

1,000

1,500

2,0002,5003,000

4,0005,000

10,000

15,00020,000

© Schlumberger

Gamma Ray and Spontaneous PotentialSchlumberger

2-5

SP

0.01

0.02

0.040.06

0.1

0.2

0.4

0.6

1

2

4

6

10

20

40

60

100

0.001

0.005

0.01

0.02

0.05

0.1

0.2

0.5

1.0

2.0

Rmfeq

(ohm-m)

Rmfeq /Rweq

aw/a

mf or

Rm

fe /R

we

Rweq

(ohm-m)

+50 0 –50 –100 –150 –200

ESSP, static spontaneous potential (mV)

250°C200°C150°C

100°C

50°C

0°C

500°F400°F300°F

200°F

100°F

Formation temperature

0.3

0.4

0.6

0.8

1

2

4

6

8

10

20

40

0.3

0.4

0.50.6

0.8

1

2

3

4

6

8

10

20

30

40

50

5

Rweq Determination from ESSPClean formations SP-1

© Schlumberger

This chart and nomograph calculate the equivalent forma-tion water resistivity, Rweq, from the static spontaneouspotential, ESSP, measurement in clean formations.

Enter the nomograph with ESSPin mV, turning throughthe reservoir temperature in °F or °C to define theRmfeq/Rweq ratio. From this value, pass through the Rmfeq

value to define Rweq.For predominantly NaCl muds, determine Rmfeq as

follows:

a. If Rmf at 75°F (24°C) is greater than 0.1 ohm-m,correct Rmf to formation temperature using ChartGen-9, and use Rmfeq = 0.85 Rmf.

b. If Rmf at 75°F (24°C) is less than 0.1 ohm-m, useChart SP-2 to derive a value of Rmfeq at formationtemperature.

Example: SSP = 100 mV at 250°F

Rmf = 0.70 ohm-m at 100°F or 0.33 ohm-m at 250°F

Therefore, Rmfeq = 0.85 × 0.33 = 0.28 ohm-m at 250°F

Rweq = 0.025 ohm-m at 250°F

ESSP= –Kclog(Rmfeq/Rweq)

KC = 61 + 0.133 T°F

KC = 65 + 0.24 T°C

PurposeThis chart is used to convert equivalent water resistivity (Rweq) fromChart SP-1 to actual water resistivity (Rw). It can also be used to con-vert the mud filtrate resistivity (Rmf) to the equivalent mud filtrateresistivity (Rmfeq) in saline mud. The metric version of this chart isChart SP-3 on page 49.

DescriptionThe solid lines are used for predominantly NaCl waters. The dashedlines are approximations for “average” fresh formation waters (forwhich the effects of salts other than NaCl become significant).

The dashed lines can also be used for gypsum-base mud filtrates.

ExampleGiven: From Chart SP-1, Rweq = 0.025 ohm-m at 250°F in

predominantly NaCl water.

Find: Rw at 250°F.

Answer: Enter the chart at the Rweq value on the y-axis and movehorizontally right to intersect the solid 250°F line. Fromthe intersection point, move down to find the Rw valueon the x-axis. Rw = 0.03 ohm-m at 250°F.

Rweq versus Rw and Formation TemperatureSP-2

(customary, former SP-2)

0.005 0.01 0.02 0.03 0.05 0.1 0.2 0.3 0.5 1.0 2 3 4 5

0.001

0.002

0.005

0.01

0.02

0.05

0.1

0.2

0.5

1.0

2.0

Rw or Rmf (ohm-m)

Rweq or Rmfeq

(ohm-m)

500°F400°F

300°F

200°F

150°F

100°F

75°F

Saturation

400°F300°F200°F150°F100°F75°F

500°F

NaCl at 75°F

Spontaneous Potential—Wireline

48

SP

© Schlumberger

continued on next page

201

Por

GeneralPorosity—Wireline, LWD

Sonic ToolPorosity Evaluation—Open Hole

PurposeThis chart is used to convert sonic log slowness time (∆t) values into those for porosity (φ).

DescriptionThere are two sets of curves on the chart. The blue set for matrixvelocity (vma) employs a weighted-average transform. The red set is based on the empirical observation of lithology (see Reference20). For both, the saturating fluid is assumed to be water with a velocity (vf) of 5,300 ft/s (1,615 m/s).

Enter the chart with the slowness time from the sonic log on the x-axis. Move vertically to intersect the appropriate matrix velocityor lithology curve and read the porosity value on the y-axis. For rockmixtures such as limy sandstones or cherty dolomites, intermediatematrix lines may be interpolated.

To use the weighted-average transform for an unconsolidated sand,a lack-of-compaction correction (Bcp) must be made. Enter the chartwith the slowness time and intersect the appropriate compactioncorrection line to read the porosity on the y-axis. If the compactioncorrection is not known, it can be determined by working backwardfrom a nearby clean water sand for which the porosity is known.

Example: Consolidated FormationGiven: ∆t = 76 µs/ft in a consolidated formation with

vma = 18,000 ft/s.

Find: Porosity and the formation lithology (sandstone,dolomite, or limestone).

Answer: 15% porosity and consolidated sandstone.

Example: Unconsolidated FormationGiven: Unconsolidated formation with ∆t = 100 µs/ft in

a nearby water sand with a porosity of 28%.

Find: Porosity of the formation for ∆t = 110 µs/ft.

Answer: Enter the chart with 100 µs/ft on the x-axis and movevertically upward to intersect 28-p.u. porosity. Thisintersection point indicates the correction factor curveof 1.2. Use the 1.2 correction value to find the porosity forthe other slowness time. The porosity of an unconsoli-dated formation with ∆t = 110 µs/ft is 34 p.u.

Lithology vma (ft/s) ∆tma (µs/ft) vma (m/s) ∆tma (µs/m)

Sandstone 18,000–19,500 55.5–51.3 5,486–5,944 182–168Limestone 21,000–23,000 47.6–43.5 6,400–7,010 156–143Dolomite 23,000–26,000 43.5–38.5 7,010–7,925 143–126

Porosity—Wireline, LWD

Sonic ToolPorosity Evaluation—Open Hole Por-1

(customary, former Por-3)

30 40 50 60 70 80 90 100 110 120 130

Interval transit time, ∆t (µs/ft)

vf = 5,300 ft/s50

40

30

20

10

0

50

40

30

20

10

0

Porosity, φ (p.u.)

Porosity, φ (p.u.)

Time averageField observation

1.1

1.2

1.3

1.4

1.5

1.6

Dolomite

26,00

021

,000

18,00

0

vma(ft/s)

Bcp

23,00

019

,500

Calcite(lim

estone)

Quartzsandstone

202

Por

© Schlumberger

Por

203


Sonic ToolPorosity Evaluation—Open Hole Por-2

(metric, former Por-3m)

100 150 200 250 300 350 400

Interval transit time, ∆t (µs/m)

vf = 1,615 m/s50

40

30

20

10

0

50

40

30

20

10

0

Porosity, φ (p.u.)

Porosity, φ (p.u.)

1.1

1.2

1.3

1.4

1.5

1.6

Dolomite

8,000

6,400

5,500

5,950

vma(m/s)

Bcp


7,000

Calcite

Quartzsandstone

Dolomite

Calci

teQua

rtzsa

ndsto

ne

Cemen

ted qu

artz

sand

stone

PurposeThis chart is used similarly to Chart Por-1 with metric units.

© Schlumberger

204

Por

Por-3(former Por-5)

Density ToolPorosity Determination—Open Hole

PurposeThis chart is used to convert grain density (g/cm3) to density porosity.

DescriptionValues of log-derived bulk density (ρb) corrected for borehole size,matrix density of the formation (ρma), and fluid density (ρf) are usedto determine the density porosity (φD) of the logged formation. Theρf is the density of the fluid saturating the rock immediately sur-rounding the borehole—usually mud filtrate.

Enter the borehole-corrected value of ρb on the x-axis and movevertically to intersect the appropriate matrix density curve. From theintersection point move horizontally to the fluid density line. Followthe porosity trend line to the porosity scale to read the formation

porosity as determined by the density tool. This porosity in combina-tion with CNL* Compensated Neutron Log, sonic, or both values ofporosity can help determine the rock type of the formation.

ExampleGiven: ρb = 2.31 g/cm3 (log reading corrected for borehole

effect), ρma = 2.71 g/cm3 (calcite mineral), and ρf = 1.1 g/cm3 (salt mud).

Find: Density porosity.

Answer: φD = 25 p.u.

2.8 2.6 2.4 2.2 2.02.31

1.0 0.9 0.8

1.1

1.2

Porosity, φ (p.u.)

Bulk density, ρb (g/cm3)

ρ ma= 2.8

7 (dolomite)

ρ ma= 2.7

1 (calci

te)

ρ ma= 2.6

5 (quar

tzsa

ndsto

ne)

ρ ma= 2.8

3ρ ma

= 2.68

ρma – ρb

ρma – ρfφ =

ρf (g/cm3)

40

30

20

10

0


*Mark of Schlumberger© Schlumberger


205

Por

PurposeThis chart is used for the apparent limestone porosity recorded by theAPS Accelerator Porosity Sonde or sidewall neutron porosity (SNP)tool to provide the equivalent porosity in sandstone or dolomite for-mations. It can also be used to obtain the apparent limestone poros-ity (used for the various crossplot porosity charts) for a log recordedin sandstone or dolomite porosity units.

DescriptionEnter the x-axis with the corrected near-to-array apparent limestoneporosity (APLC) or near-to-far apparent limestone porosity (FPLC)and move vertically to the appropriate lithology curve. Then read theequivalent porosity on the y-axis. For APS porosity recorded in sand-stone or dolomite porosity units enter that value on the y-axis andmove horizontally to the recorded lithology curve. Then read theapparent limestone neutron porosity for that point on the x-axis.

The APLC is the epithermal short-spacing apparent limestoneneutron porosity from the near-to-array detectors. The log is auto-matically corrected for standoff during acquisition. Because it isepithermal this measurement does not need environmental correc-tions for temperature or chlorine effect. However, corrections formud weight and actual borehole size should be applied (see ChartNeu-10). The short spacing means that the effect of density andtherefore the lithology on this curve is minimal.

The FPLC is the epithermal long-spacing apparent limestone neu-tron porosity acquired from the near-to-far detectors. Because it isepithermal this measurement does not need environmental correc-tions for temperature or chlorine effect. However, corrections formud weight and actual borehole size should be applied (see ChartNeu-10). The long spacing means that the density and thereforelithology effect on this curve is pronounced, as seen on Charts Por-13and Por-14.

The HPLC curve is the high-resolution version of the APLC curve.The same corrections apply.

Example: Equivalent PorosityGiven: APLC = 25 p.u. and FPLC = 25 p.u.

Find: Porosity for sandstone and for dolomite.

Answer: Sandstone porosity from APLC = 28.5 p.u. and sandstoneporosity from FPLC = 30 p.u.

Dolomite porosity = 24 and 20 p.u., respectively.

Example: Apparent PorosityGiven: Clean sandstone porosity = 20 p.u.

Find: Apparent limestone neutron porosity.

Answer: Enter the y-axis at 20 p.u. and move horizontally to the quartz sandstone matrix curves. Move verticallyfrom the points of intersection to the x-axis and readthe apparent limestone neutron porosity values. APLC = 16.8 p.u. and FPLC = 14.5 p.u.

APS* Near-to-Array (APLC) and Near-to-Far (FPLC) LogsEpithermal Neutron Porosity Equivalence—Open Hole

Resolution Short Spacing Long Spacing

Normal APLCFPLCEpithermal neutron porosity (ENPI)†

Enhanced HPLCHFLCHNPI†

† Not formation-salinity corrected.

Porosity—Wireline

206

Por

Porosity—Wireline

APS* Near-to-Array (APLC) and Near-to-Far (FPLC) LogsEpithermal Neutron Porosity Equivalence—Open Hole Por-4

(former Por-13a)

40

30

20

10

0 0 10 20 30 40

Apparent limestone neutron porosity, φSNPcor (p.u.) Apparent limestone neutron porosity, φAPScor (p.u.)

True porosity for indicated

matrix material, φ (p.u.)

Calcite(lim

estone)

Dolomite

APLCFPLCSNP

Quartzsa

ndstone


Thermal Neutron ToolPorosity Equivalence—Open Hole

207

Por

GeneralPorosity—Wireline

PurposeThis chart is used to convert CNL* Compensated Neutron Log porositycurves (TNPH or NPHI) from one lithology to another. It can also beused to obtain the apparent limestone porosity (used for the variouscrossplot porosity charts) from a log recorded in sandstone or dolomiteporosity units.

DescriptionTo determine the porosity of either quartz sandstone or dolomiteenter the chart with the either the TNPH or NPHI corrected apparent limestone neutron porosity (φCNLcor) on the x-axis. Movevertically to intersect the appropriate curve and read the porosity for quartz sandstone or dolomite on the y-axis. The chart has a built-in salinity correction for TNPH values.

ExampleGiven: Quartz sandstone formation, TNPH = 18 p.u. (apparent

limestone neutron porosity), and formation salinity =250,000 ppm.

Find: Porosity in sandstone.

Answer: From the TNPH porosity reading of 18 p.u. on the x-axis,project a vertical line to intersect the quartz sandstonedashed red curve. From the y-axis, the porosity of thesandstone is 24 p.u.

40

30

20

10

0 0 10 20 30 40

Apparent limestone neutron porosity, φCNLcor (p.u.)

True porosityfor indicated

matrix material,φ (p.u.)

Quartz

sand

stone

Calcite(lim

estone)

Dolomite

Formation salinity

TNPH

NPHI

0 ppm

250,000 ppm

NPHI Thermal neutron porosity (ratio method)NPOR Neutron porosity (environmentally corrected and

enhanced vertical resolution processed)TNPH Thermal neutron porosity (environmentally corrected)

Por-5(former Por-13b)


213

Por


CNL* Compensated Neutron Log and Litho-Density* Tool (fresh water in invaded zone)Porosity and Lithology—Open Hole

Por-11(former CP-1e)

0 10 20 30 40Corrected apparent limestone neutron porosity, φCNLcor (p.u.)

1.9

2.0

2.1

2.2

2.3

2.4

2.5

2.6

2.7

2.8

2.9

3.0

Bulkdensity,

ρb (g/cm3)

Densityporosity,φD (p.u.)

(ρma = 2.71 g/cm3,ρf = 1.0 g/cm3)

45

40

35

30

25

20

15

10

5

0

–5

–10

–15Anhydrite

SulfurSalt

ApproximategascorrectionPorosity

Calcite (lim

estone)

0

5

10

15

20

25

30

35

40

45

Quartz sandstone

0

5

10

15

20

25

30

35

40

Dolomite

0

5

10

15

20

25

30

35

Liquid-Filled Borehole (ρf = 1.000 g/cm3 and Cf = 0 ppm)


214

Por


PurposeThis chart is used similarly to Chart Por-11 with CNL CompensatedNeutron Log and Litho-Density values to approximate the lithologyand determine the crossplot porosity in the saltwater-invaded zone.

ExampleGiven: Corrected apparent neutron limestone porosity =

16.5 p.u. and bulk density = 2.38 g/cm3.

Find: Crossplot porosity and lithology.

Answer: Crossplot porosity = 20 p.u. The lithology is approxi-mately 55% quartz and 45% limestone.

CNL* Compensated Neutron Log and Litho-Density* Tool (salt water in invaded zone)Porosity and Lithology—Open Hole

Por-12(former CP-11)

0 10 20 30 40

Corrected apparent limestone neutron porosity, φCNLcor (p.u.)

1.9

2.0

2.1

2.2

2.3

2.4

2.5

2.6

2.7

2.8

2.9

3.0

Bulkdensity,

ρb (g/cm3)

Densityporosity,φD (p.u.)

(ρma = 2.71 g/cm3,ρf = 1.19 g/cm3)

45

40

35

30

25

20

15

10

5

0

–5

–10

–15

Liquid-filled borehole (ρf = 1.190 g/cm3 and Cf = 250,000 ppm)

0

5

10

15

20

25

30

35

40

45

0

5

10

15

20

25

30

35

0

5

10

15

20

25

30

35

40

45

Approximategascorrection

Porosity

Quartz sandstone

Calcite (limestone)

SulfurSalt

Dolomite

Anhydrite


215

Por


APS* and Litho-Density* ToolsPorosity and Lithology—Open Hole Por-13

(former CP-1g)

PurposeThis chart is used to determine the lithology and porosity from theLitho-Density bulk density and APS Accelerator Porosity Sonde porositylog curves (APLC or FPLC). This chart applies to boreholes filledwith freshwater drilling fluid; Chart Por-14 is used for saltwater fluids.

DescriptionEnter either the APLC or FPLC porosity on the x-axis and the bulkdensity on the y-axis. Use the blue matrix curves for APLC porosityvalues and the red curves for FPLC porosity values. Anhydrite plotson separate curves. The gas correction direction is indicated for for-mations containing gas. Move parallel to the blue correction line ifthe APLC porosity is used or to the red correction line if the FPLCporosity is used.

ExampleGiven: APLC porosity = 8 p.u. and bulk density = 2.2 g/cm3.

Find: Approximate quartz sandstone porosity.

Answer: Enter at 8 p.u. on the x-axis and 2.2 g/cm3 on the y-axisto find the intersection point is in the gas-in-formationcorrection region. Because the APLC porosity value wasused, move parallel to the blue gas correction line untilthe blue quartz sandstone curve is intersected at approx-imately 19 p.u.

Liquid-Filled Borehole (ρf = 1.000 g/cm3 and Cf = 0 ppm)

Bulk density,ρb (g/cm3)

Corrected APS apparent limestone neutron porosity, φAPScor (p.u.)

1.9

2.0

2.1

2.2

2.3

2.4

2.5

2.6

2.7

2.8

2.9

3.0 0 10 20 30 40

APLCFPLC

Anhydrite

DolomiteCalcite (lim

estone)

Quartz sandstone

Porosity


0

5

5

10

10

15

15

20

20

25

25

35

3530

30

40

40

45

0

5

40

35

30

25

20

15

10

0

35

30

25

20

15 15

10

5

0

0

10

20

30

35

40

5

25


216

Por


PurposeThis chart is used similarly to Chart Por-13 to determine the lithologyand porosity from Litho-Density* bulk density and APS* porosity logcurves (APLC or FPLC) in saltwater boreholes.

ExampleGiven: APLC porosity = 8 p.u. and bulk density = 2.2 g/cm3.

Find: Approximate quartz sandstone porosity.

Answer: Enter 8 p.u. on the x-axis and 2.2 g/cm3 on the y-axis tofind the intersection point is in the gas-in-formation cor-rection region. Because the APLC porosity value wasused, move parallel to the blue gas correction line untilthe blue quartz sandstone curve is intersected at approx-imately 20 p.u.

APS* and Litho-Density* Tools (saltwater formation)Porosity and Lithology—Open Hole Por-14

(former CP-1h)

Liquid-Filled Borehole (ρf = 1.190 g/cm3 and Cf = 250,000 ppm)


Corrected APS apparent limestone neutron porosity, φAPScor (p.u.)

1.9

2.0

2.1

2.2

2.3

2.4

2.5

2.6

2.7

2.8

2.9

3.00 10 20 30 40

Anhydrite

Porosity


0

0

5

5

10

10

15

15

20

20

25

25

35

3530

30

40

40

45

0

5

40

35

30

25

20

15

10

0

40

35

30

25

20

15

10

5

0

4545

APLCFPLC

5

10

15

20

25

30

35

40

Quartz sandstone

DolomiteCalcite (limestone)


217

Por

GeneralPorosity—LWD

adnVISION475* 4.75-in. Azimuthal Density Neutron ToolPorosity and Lithology—Open Hole Por-15

PurposeThis chart is used to determine the crossplot porosity and lithologyfrom the adnVISION475 4.75-in. density and neutron porosity.

DescriptionEnter the chart with the adnVISION475 corrected apparent lime-stone neutron porosity (from Chart Neu-31) and bulk density. Theintersection of the two values is the crossplot porosity. The positionof the point of intersection between the matrix curves represents therelative percentage of each matrix material.

ExampleGiven: φADNcor = 20 p.u. and ρb = 2.24 g/cm3.

Find: Crossplot porosity and matrix material.

Answer: 25 p.u. in sandstone.


1.9

2.0

2.1

2.2

2.3

2.4

2.5

2.6

2.7

2.8

2.9

3.0

Anhydrite

Salt

Corrected apparent limestone neutron porosity, φADNcor (p.u.)

–5 0 5 10 15 20 25 30 35 40 45

Fresh Water, Liquid-Filled Borehole (ρf = 1.0 g/cm3)

DolomiteCalcite (lim

estone)Quartz

sandstone

Porosity

0

0

5

10

10

15

15

20

20

25

25

35

3530

30

40

40

40

35

30

25

20

15

10

5

05


Por

218


PurposeThis chart uses the bulk density and apparent limestone porosity fromthe adnVISION 6.75-in. Azimuthal Density Neutron tool to determinethe lithology of the logged formation and the crossplot porosity.

DescriptionThis chart is applicable for logs obtained in freshwater drilling fluid. Enter the corrected apparent limestone porosity and the bulkdensity on the x- and y-axis, respectively. Their intersection pointdetermines the lithology and crossplot porosity.

ExampleGiven: Corrected adnVISION675 apparent limestone porosity =

20 p.u. and bulk density = 2.3 g /cm3.

Find: Porosity and lithology type.

Answer: Entering the chart at 20 p.u. on the x-axis and 2.3 g /cm3

on the y-axis corresponds to a crossplot porosity of 21.5 p.u. and formation comprising approximately 60% quartz sandstone and 40% limestone.




1.9

2.0

2.1

2.2

2.3

2.4

2.5

2.6

2.7

2.8

2.9

3.0–5 0 5 10 15 20 25 30 35 40 45


DolomiteCalcite

(limestone)

Quartz sandstone

0

0

10

10

15

20

25

5

5

5

10

15

20

0

25

35

30

15

20

25

35

30

30

35

4 0

40

Porosity


219

Por


PurposeThis chart is used similarly to Chart Por-15 to determine the lithologyand crossplot porosity from adnVISION825 8.25-in. Azimuthal DensityNeutron values.




1.9

2.0

2.1

2.2

2.3

2.4

2.5

2.6

2.7

2.8

2.9

3.0–5 0 5 10 15 20 25 30 35 40 45


Calcite (lim

estone)

Quartz sandstone

0

10

5

Dolomite

5

10

15

20

0

25

35

30

15

20

25

35

30

40

0

10

15

20

5

30

35

40

25

Porosity 40


220

Por


Sonic and Thermal Neutron CrossplotPorosity and Lithology—Open Hole, Freshwater Invaded

PurposeThis chart is used to determine crossplot porosity and an approxi-mation of lithology for sonic and thermal neutron logs in freshwaterdrilling fluid.

DescriptionEnter the corrected neutron porosity (apparent limestone porosity)on the x-axis and the sonic slowness time (∆t) on the y-axis to findtheir intersection point, which describes the crossplot porosity andlithology composition of the formation. Two sets of curves are drawnon the chart. The blue set of curves represents the crossplot porosityvalues using the sonic time-average algorithm. The red set of curvesrepresents the field observation algorithm.

ExampleGiven: Thermal neutron apparent limestone porosity = 20 p.u.

and sonic slowness time = 89 µs/ft in freshwater drilling fluid.


Answer: Enter the neutron porosity on the x-axis and the sonicslowness time on the y-axis. The intersection point is atabout 25 p.u. on the field observation line and 24.5 p.u.on the time-average line. The matrix is quartz sandstone.

221

Por

GeneralGeneralPorosity—Wireline

Sonic and Thermal Neutron CrossplotPorosity and Lithology—Open Hole, Freshwater Invaded Por-20

(customary, former CP-2c)

0 10 20 30 40

110

100

90

80

70

60

50

40

Corrected CNL* apparent limestone neutron porosity, φCNLcor (p.u.)

Sonic transit time,∆t (µs/ft)

tf = 190 µs/ft and Cf = 0 ppm

Salt

Anhydrite

Dolomite

Calci

te (li

mesto

ne)

Quartz

sand

stone


Poros

ity

0

5

55

00

10

15

20

25

35

40

40

3535

30

3535

30

20

15

25

20

15

10

10

15

20

25

3030

0

5

10

10

15

15

20

2025

2530

30

0

5

0

5

25

10


222

Por


Sonic and Thermal Neutron CrossplotPorosity and Lithology—Open Hole, Freshwater Invaded

Por-21(metric, former CP-2cm)

0 10 20 30 40

360

340

320

300

280

260

240

220

200

180

160

140

Corrected CNL* apparent limestone neutron porosity, φCNLcor (p.u.)

Sonic transit time,∆t (µs/m)

tf = 620 µs/m and Cf = 0 ppm

Salt

Anhyd

rite

Dolomite

Calci

te (li

mesto

ne)

Quartz

sand

stone


Poros

ity

0

5

55

00

10

15

20

35

40

40

35

30

353530

20

15

10

25

20

15

10

10

15

20

3030

0

5

10

10

15

15

20

20

25

2530

30

0

5

0

5

2525

35

25

PurposeThis chart is used similarly to Chart Por-20 for metric units.



223

Por

GeneralGeneralPorosity—Wireline, LWD

Density and Sonic CrossplotPorosity and Lithology—Open Hole, Freshwater Invaded

PurposeThis chart is used to determine porosity and lithology for sonic anddensity logs in freshwater-invaded zones.

DescriptionEnter the chart with the bulk density on the y-axis and sonic slow-ness time on the x-axis. The point of intersection indicates the typeof formation and its porosity.

ExampleGiven: Bulk density = 2.3 g /cm3 and sonic slowness

time = 82 µs/ft.


Answer: Limestone with a crossplot porosity = 24 p.u.

224

Por


Density and Sonic CrossplotPorosity and Lithology—Open Hole, Freshwater Invaded Por-22

(customary, former CP-7)

40 50 60 70 80 90 100 110 120

1.8

1.9

2.0

2.1

2.2

2.3

2.4

2.5

2.6

2.7

2.8

2.9

3.0

Sonic transit time, ∆t (µs/ft)


tf = 189 µs/ft and ρf = 1.0 g/cm3

Dolomite

Calcite

(limes

tone)

Anhydrite

Polyhalite

Gypsum

Trona

Salt

Sylvite

Sulfur

0

10

10

10 20

30

4040 40 40

40

3030

20

0

0

0

0

10

0

Porosity


30

30

30

2020

20

1020

10

Quartz

sand

stone

© Schlumberger

225

Por

General

PurposeThis chart is used similarly to Chart Por-22 for metric units.


Density and Sonic CrossplotPorosity and Lithology—Open Hole, Freshwater Invaded Por-23

(metric, former CP-7m)

150 200 250 300 350 400

1.8

1.9

2.0

2.1

2.2

2.3

2.4

2.5

2.6

2.7

2.8

2.9

3.0

Sonic transit time, ∆t (µs/m)


tf = 620 µs/m and ρf = 1.0 g/cm3

Dolomite

Calcite

(limes

tone)

Anhydrite

Polyhalite

Gypsum

Trona

Salt

Sylvite

Sulfur

0

10

10

10 20

20

20

30

40

30

40 40

40

3030

20

0

0

10

0

Porosity

30

0

0

10


30

10

Quartz

sand

stone

20

20

40

© Schlumberger

230

Por

General

PurposeThis nomograph is used to estimate porosity in hydrocarbon-bearingformations by using density, neutron, and resistivity in the flushedzone (Rxo) logs. The density and neutron logs must be corrected forenvironmental effects and lithology before entry to the nomograph.The chart includes an approximate correction for excavation effect,but if hydrocarbon density (ρh) is <0.25 g /cm3 (gas), the chart maynot be accurate in some extreme cases:

■ very high values of porosity (>35 p.u.) coupled with medium to high values of hydrocarbon saturation (Shr)

■ Shr = 100% for medium to high values of porosity.

DescriptionConnect the apparent neutron porosity value on the appropriateneutron porosity scale (CNL* Compensated Neutron Log or sidewallneutron porosity [SNP] log) with the corrected apparent densityporosity on the density scale with a straight line. The intersectionpoint on the φ1 scale indicates the value of φ1.

Draw a line from the φ1 value to the origin (lower right corner) of the chart for ∆φ versus Shr.

Enter the chart with Shr from (Shr = 1 – Sxo) and move verticallyupward to determine the porosity correction factor (∆φ) at the inter-section with the line from the φ1 scale.

This correction factor algebraically added to the porosity φ1 givesthe corrected porosity.

ExampleGiven: Corrected CNL apparent neutron porosity = 12 p.u.,

corrected apparent density porosity = 38 p.u., and Shr = 50%.

Find: Hydrocarbon-corrected porosity.

Answer: Enter the 12-p.u. φcor value on the CNL scale. A line fromthis value to 38 p.u. on the φDcor scale intersects the φ1

scale at 32.2 p.u. The intersection of a line from thisvalue to the graph origin and Shr = 50% is ∆φ = –1.6 p.u.Hydrocarbon-corrected porosity: 32.2 – 1.6 = 30.6 p.u.

GeneralGeneralPorosity—Wireline

Density, Neutron, and Rxo LogsPorosity Identification in Hydrocarbon-Bearing Formation—Open Hole

231

Por

GeneralGeneralGeneralPorosity—Wireline

Density, Neutron, and Rxo LogsPorosity Identification in Hydrocarbon-Bearing Formation—Open Hole Por-26

(former CP-9)

–5

–4

–3

–2

–1

0100 80 60 40 20 0

Shr (%)

∆φ (p.u.)

φDcor

50

40

30

20

10

0

φ1

50

40

30

20

10

0

φcor

(SNP)

50

40

30

20

10

0

φcor

(CNL*)

50

40

30

20

10

0

(p.u.)


General

182

GeneralLithology—Wireline

Density and NGS* Natural Gamma Ray Spectrometry ToolMineral Identification—Open Hole

PurposeThis chart is a method for identifying the type of clay in the wellbore.The values of the photoelectric factor (Pe) from the Litho-Density*log and the concentration of potassium (K) from the NGS NaturalGamma Ray Spectrometry tool are entered on the chart.

DescriptionEnter the upper chart with the values of Pe and K to determine thepoint of intersection. On the lower chart, plotting Pe and the ratio of thorium and potassium (Th/K) provides a similar mineral evalua-tion. The intersection points are not unique but are in general areasdefined by a range of values.

ExampleGiven: Environmentally corrected thorium concentration

(ThNGScorr) = 10.6 ppm, environmentally correctedpotassium concentration (KNGScorr) = 3.9%, and Pe = 3.2.

Find: Mineral concentration of the logged clay.

Answer: The intersection points from plotting values of Pe and Kon the upper chart and Pe and Th/K ratio = 10.6/3.9 = 2.7on the lower chart suggest that the clay mineral is illite.

Lith

183

Lith

Lithology—Wireline

Density and NGS* Natural Gamma Ray Spectrometry ToolMineral Identification—Open Hole Lith-1

(former CP-18)

Potassium concentration, K (%)

Thorium/potassium ratio, Th/K

Photoelectricfactor, Pe

Photoelectricfactor, Pe

Glauconite

Glauconite

Chlorite

Chlorite

Biotite

Biotite

Illite

Illite

Muscovite

Muscovite

Montmorillonite

Montmorillonite

Kaolinite

Kaolinite

Mixed layer

0 2 4 6 8 10

0.1 0.2 0.3 0.6 1 2 3 6 10 20 30 60 100

10

8

6

4

2

0

10

8

6

4

2

0



NGS* Natural Gamma Ray Spectrometry ToolMineral Identification—Open Hole Lith-2

(former CP-19)

184

PurposeThis chart is used to determine the type of minerals in a shale formation from concentrations measured by the NGS NaturalGamma Ray Spectrometry tool.

DescriptionEntering the chart with the values of thorium and potassium locatesthe intersection point used to determine the type of radioactive min-erals that compose the majority of the clay in the formation.

A sandstone reservoir with varying amounts of shaliness andillite as the principal clay mineral usually plots in the illite segmentof the chart with Th/K between 2.0 and 3.5. Less shaly parts of thereservoir plot closer to the origin, and shaly parts plot closer to the70% illite area.

0 1 2 3 4 5

Potassium (%)

25

20

15

10

5

0

Thorium(ppm)

Mixed-layer clay

IlliteMicas

Glauconite

Potassium evaporites, ~30% feldspar

~30% glauconite

~70% illite

100% illite point

~40%mica

Mon

tmor

illonit

e

Chlorite

Kaolinite

Possible 100% kaolinite,montmorillonite,illite “clay line”

Th/K

= 2

5

Th/K

= 12

Th/K = 3.5

Th/K = 2.0

Th/K = 0.6

Th/K = 0.3Feldspar

Heav

y th

oriu

m-b

earin

g m

iner

als

Lith


Lith

PurposeThis chart is used to determine the lithology and porosity of a forma-tion. The porosity is used for the water saturation determination andthe lithology helps to determine the makeup of the logged formation.

DescriptionNote that this chart is designed for fresh water (fluid density [ρf]= 1.0 g/cm3) in the borehole. Chart Lith-4 is used for saltwater(ρf = 1.1 g/cm3) formations.

Values of photoelectric factor (Pe) and bulk density (ρb) from thePlatform Express Three-Detector Lithology Density (TLD) tool areentered into the chart. At the point of intersection, porosity andlithology values can be determined.

ExampleGiven: Freshwater drilling mud, Pe = 3.0, and bulk density =

2.73 g/cm3.

Freshwater drilling mud, Pe = 1.6, and bulk density =2.24 g/cm3.

Find: Porosity and lithology.

Answer: For the first set of conditions, the formation is adolomite with 8% porosity.

The second set is for a quartz sandstone formation with 30% porosity.


Platform Express* Three-Detector Lithology Density ToolPorosity and Lithology—Open Hole


185


Platform Express* Three-Detector Lithology Density ToolPorosity and Lithology—Open Hole Lith-3

(former CP-16)

186

1.9

2.0

2.1

2.2

2.3

2.4

2.5

2.6

2.7

2.8

2.9

3.0 0 1 2 3 4 5 6

Photoelectric factor, Pe

Bulk density, ρb(g/cm3)

4030

2010

0

4030

2010

0

0

40

30

2010

0

0

Quar

tz s

ands

tone

Dolo

mite

Calc

ite (l

imes

tone

)Sa

lt

Anhy

drite

Fresh Water (ρf = 1.0 g/cm3), Liquid-Filled Borehole

Lith


187

Lith


Platform Express* Three-Detector Lithology Density ToolPorosity and Lithology—Open Hole Lith-4

(former CP-17)

1.9

2.0

2.1

2.2

2.3

2.4

2.5

2.6

2.7

2.8

2.9

3.0 0 1 2 3 4 5 6


Bulk density, ρb(g/cm3)

4030

2010

0

4030

2010

0

0

Quar

tz s

ands

tone

Dolo

mite

Anhy

drite

40

30

2010

0

Calc

ite (l

imes

tone

)

0Salt

Salt Water (ρf = 1.1 g/cm3), Liquid-Filled Borehole

This chart is used similarly to Chart Lith-3 for lithology and poros-ity determination with values of photoelectric factor (Pe) and

bulk density (ρb) from the Platform Express TLD tool in saltwaterborehole fluid.


GeneralLithology—Wireline, Drillpipe

Density ToolApparent Matrix Volumetric Photoelectric Factor—Open Hole Lith-5

(former CP-20)

PurposeThis chart is used to determine the apparent matrix volumetric photoelectric factor (Umaa) for the Chart Lith-6 percent lithologydetermination.

DescriptionThis chart is entered with the values of bulk density (ρb) and Pe froma density log. The value of the apparent total porosity (φta) must alsobe known. The appropriate solid lines on the right-hand side of thechart that indicate a freshwater borehole fluid or dotted lines thatrepresent saltwater borehole fluid are used depending on the salinityof the borehole fluid. Uf is the fluid photoelectric factor.

ExampleGiven: Pe = 4.0, ρb = 2.5 g/cm3, φta = 25%, and freshwater

borehole fluid.

Find: Apparent matrix volumetric photoelectric factor (Umaa).

Answer: Enter the chart with the Pe value (4.0) on the left-handx-axis, and move upward to intersect the curve for ρb = 2.5 g/cm3.

From that intersection point, move horizontally right tointersect the φta value of 25%, using the blue freshwatercurve.

Move vertically downward to determine the Umaa valueon the right-hand x-axis scale: Umaa = 13.

Lithology—Wireline, LWD

188

6 5 4 3 2 1 4 6 8 10 12 14

3.0

2.5

2.0

0

10

20

30

40


Bulk density, ρb

(g/cm3)

Apparent total porosity, φta (%)

Apparent matrixvolumetric photoelectric factor, Umaa

Fresh water (0 ppm), ρf = 1.0 g/cm3, Uf = 0.398Salt water (200,000 ppm), ρf = 1.11 g/cm3, Uf = 1.36

Lith

© Schlumberger


189

Lith

GeneralGeneralGeneralLithology—Wireline, LWD

PurposeThis chart is used to identify the rock mineralogy through comparisonof the apparent matrix grain density (ρmaa) and apparent matrix volu-metric photoelectric factor (Umaa).

DescriptionThe values of ρmaa and Umaa are entered on the y- and x-axis, respec-tively. The rock mineralogy is identified by the proximity of the pointof intersection of the two values to the labeled points on the plot.The effect of gas, salt, etc., is to shift data points in the directionsshown by the arrows.

ExampleGiven: ρmaa = 2.74 g/cm3 (from Chart Lith-9 or Lith-10) and

Umaa = 13 (from Chart Lith-5).

Find: Matrix composition of the formation.

Answer: Enter the chart with ρmaa = 2.74 g/cm3 on the y-axis andUmaa = 13 on the x-axis. The intersection point indicatesa matrix mixture of 20% dolomite and 80% calcite.

Density ToolLithology Identification—Open Hole

General

190

Lith

GeneralLithology—Wireline, LWD

Apparent matrix volumetric photoelectric factor, Umaa

Apparent matrixgrain density,ρmaa (g/cm3)

2 4 6 8 10 12 14 16

2.2

2.3

2.4

2.5

2.6

2.7

2.8

2.9

3.0

3.1

Salt

K-feldspar

Quartz

Dolomite

Kaolinite

Illite

Anhydrite

Heavy minerals

Barite

Calcite

Gas

dire

ctio

n

% calcite

% dolomite

% quartz

2060

8040

60

40

20

80

60

40

20

80

Density ToolLithology Identification—Open Hole Lith-6

(former CP-21)

© Schlumberger


191

Lith

PurposeThis chart is used to help identify mineral mixtures from sonic, density, and neutron logs.

DescriptionBecause M and N slope values are practically independent of porosityexcept in gas zones, the porosity values they indicate can be corre-lated with the mineralogy. (See Appendix E for the formulas to calcu-late M and N from sonic, density, and neutron logs.)

Enter the chart with M on the y-axis and N on the x-axis. Theintersection point indicates the makeup of the formation. Points forbinary mixtures plot along a line connecting the two mineral points.Ternary mixtures plot within the triangle defined by the three con-stituent minerals. The effect of gas, shaliness, secondary porosity,etc., is to shift data points in the directions shown by the arrows.

The lines on the chart are divided into numbered groups by poros-ity range as follows:

1. φ = 0 (tight formation)2. φ = 0 to 12 p.u.3. φ = 12 to 27 p.u.4. φ = 27 to 40 p.u.

ExampleGiven: M = 0.79 and N = 0.51.

Find: Mineral composition of the formation.

Answer: The intersection of the M and N values indicates dolomitein group 2, which has a porosity between 0 to 12 p.u.


Environmentally Corrected Neutron CurvesM–N Plot for Mineral Identification—Open Hole


Environmentally Corrected Neutron CurvesM–N Plot for Mineral Identification—Open Hole Lith-7

(former CP-8)

192

1.1

1.0

0.9

0.8

0.7

0.6

0.5

Approximate shale region

Anhydrite

Dolomite

Gypsum

Calcite (limestone)

vma = 5943 m/s = 19,500 ft/s

vma = 5486 m/s = 18,000 ft/s

Sulfur

Quartz sandstone

324 1

1 2 34

Secondaryporosity

Gas or

salt

N

M

0.3 0.4 0.5 0.6 0.7 0.8

Freshwater mudρf = 1.0 Mg/m3, t f = 620 µs/mρf = 1.0 g/cm3, t f = 189 µs/ft

Saltwater mudρf = 1.1 Mg/m3, t f = 607 µs/mρf = 1.1 g/cm3, t f = 185 µs/ft

Lith

© Schlumberger


193

Lith

GeneralGeneralGeneralLithology—Wireline

PurposeThis chart is used to help identify mineral mixtures from APSAccelerator Porosity Sonde neutron logs.

DescriptionBecause M and N values are practically independent of porosityexcept in gas zones, the porosity values they indicate can be corre-lated with the mineralogy. (See Appendix E for the formulas to cal-culate M and N from sonic, density, and neutron logs.)

Enter the chart with M on the y-axis and N on the x-axis. Theintersection point indicates the makeup of the formation. Points forbinary mixtures plot along a line connecting the two mineral points.Ternary mixtures plot within the triangle defined by the three con-stituent minerals. The effect of gas, shaliness, secondary porosity,etc., is to shift data points in the directions shown by the arrows.

The lines on the chart are divided into numbered groups by poros-ity range as follows:

1. φ = 0 (tight formation)2. φ = 0 to 12 p.u.3. φ = 12 to 27 p.u.4. φ = 27 to 40 p.u.

Because the dolomite spread is negligible, a single dolomite pointis plotted for each mud.

ExampleGiven: M = 0.80 and N = 0.55.

Find: Mineral composition of the formation.

Answer: Dolomite.

Environmentally Corrected APS* CurvesM–N Plot for Mineral Identification—Open Hole

General

194

1.1

1.0

0.9

0.8

0.7

0.6

0.5

Approximate shale region

Anhydrite

Dolomite

Gypsum

Calcite (limestone)

vma = 5943 m/s = 19,500 ft/s

vma = 5486 m/s = 18,000 ft/s

Sulfur

Quartz sandstone

12 3,4

Secondaryporosity

Gas or

salt

N

M

0.3 0.4 0.5 0.6 0.7 0.8

Freshwater mudρf = 1.0 Mg/m3, t f = 620 µs/mρf = 1.0 g/cm3, t f = 189 µs/ft

Saltwater mudρf = 1.1 Mg/m3, t f = 607 µs/mρf = 1.1 g/cm3, t f = 185 µs/ft

Lith

GeneralLithology—Wireline

Environmentally Corrected APS* CurvesM–N Plot for Mineral Identification—Open Hole Lith-8

(former CP-8a)



195

Lith

PurposeCharts Lith-9 (customary units) and Lith-10 (metric units) providevalues of the apparent matrix internal transit time (tmaa) and appar-ent matrix grain density (ρmaa) for the matrix identification (MID)Charts Lith-11 and Lith-12. With these parameters the identificationof rock mineralogy or lithology through a comparison of neutron,density, and sonic measurements is possible.

DescriptionDetermining the values of tmaa and ρmaa to use in the MID ChartsLith-11 and Lith-12 requires three steps.

First, apparent crossplot porosity is determined using the appro-priate neutron-density and neutron-sonic crossplot charts in the“Porosity” section of this book. For data that plot above the sand-stone curve on the charts, the apparent crossplot porosity is definedby a vertical projection to the sandstone curve.

Second, enter Chart Lith-9 or Lith-10 with the interval transit time (t) to intersect the previously determined apparent crossplotporosity. This point defines tmaa.

Third, enter Chart Lith-9 or Lith-10 with the bulk density (ρb) to again intersect the apparent crossplot porosity and define ρmaa.

The values determined from Charts Lith-9 and Lith-10 for tmaa andρmaa are cross plotted on the appropriate MID plot (Charts Lith-11and Lith-12) to identify the rock mineralogy by its proximity to thelabeled points on the plot.

ExampleGiven: Apparent crossplot porosity from density-neutron = 20%,

ρb = 2.4 g /cm3, apparent crossplot porosity from neutron-sonic = 30%, and t = 82 µs/ft.

Find: ρmaa and tmaa.

Answer: ρmaa = 2.75 g/cm3 and tmaa = 46 µs/ft.


Bulk Density or Interval Transit Time and Apparent Total PorosityApparent Matrix Parameters—Open Hole


Bulk Density or Interval Transit Time and Apparent Total PorosityApparent Matrix Parameters—Open Hole Lith-9


196

3.0 2.9 2.8 2.7 2.6 2.5 2.4 2.3 2.2 2.1 2.0

130 120 110 100 90 80 70 60 50 40 303.0

2.9

2.8

2.7

2.6

2.5

2.4

2.3

2.2

2.1

2.0

130

120

110

100

90

80

70

60

50

40

30

Fluid Density = 1.0 g/cm3

Apparent matrix density, ρmaa (g/cm3)


Intervaltransittime,

t (µs/ft)

Apparent matrix transit time, tmaa (µs/ft)

40

30

20

10

10

20

30

40

Apparentcrossplotporosity

Density-n

eutron

Neutron-so

nic

Lith

© Schlumberger

197

Lith

PurposeCharts Lith-9 (customary units) and Lith-10 (metric units) providevalues of the apparent matrix internal transit time (tmaa) and appar-ent matrix grain density (ρmaa) for the matrix identification (MID)Charts Lith-11 and Lith-12. With these parameters the identificationof rock mineralogy or lithology through a comparison of neutron,density, and sonic measurements is possible.

GeneralGeneralGeneral

3.0 2.9 2.8 2.7 2.6 2.5 2.4 2.3 2.2 2.1 2.0

350 325 300 275 250 225 200 175 150 125 100 3.0

2.9

2.8

2.7

2.6

2.5

2.4

2.3

2.2

2.1

2.0

350

325

300

275

250

225

200

175

150

125

100

Fluid Density = 1.0 g/cm3

Apparent matrix density, ρmaa (g/cm3)


Intervaltransittime,

t (µs/m)

Apparent matrix transit time, tmaa (µs/m)

40

30

20

10

10

20

30

40

Apparentcrossplotporosity

Density-n

eutron

Neutron-so

nic


Bulk Density or Interval Transit Time and Apparent Total PorosityApparent Matrix Parameters—Open Hole Lith-10


© Schlumberger

General

198

PurposeCharts Lith-11 and Lith-12 are used to establish the type of mineralpredominant in the formation.

DescriptionEnter the appropriate (customary or metric units) chart with the values established from Charts Lith-9 or Lith-10 to identify thepredominant mineral in the formation. Salt points are defined fortwo tools, the sidewall neutron porosity (SNP) and the CNL*Compensated Neutron Log. The presence of secondary porosity in the form of vugs or fractures displaces the data points parallel to the apparent matrix internal transit time (tmaa) axis. The presence of gas displaces points to the right on the chart. Plotting some shalepoints to establish the shale trend lines helps in the identificationof shaliness. For fluid density (ρf) other than 1.0 g/cm3 use the tableto determine the multiplier to correct the apparent total densityporosity before entering Chart Lith-11 or Lith-12.

ExampleGiven: ρmaa = 2.75 g/cm3, tmaa = 56 µs/ft (from Chart Lith-9),

and ρf = 1.0 g/cm3.

Find: The predominant mineral.

Answer: The formation consists of both dolomite and calcite,which indicates a dolomitized limestone. The formationused in this example is from northwest Florida in the Jay field. The vugs (secondary porosity) created by thedolomitization process displace the data point parallel to the dolomite and calcite points.

Lith

GeneralLithology—Wireline, LWD

Density ToolMatrix Identification (MID)—Open Hole

ρf Multiplier

1.00 1.001.05 0.981.10 0.951.15 0.93

199

Lith

GeneralGeneralGeneral

30 40 50 60 70

2.0

2.1

2.2

2.3

2.4

2.5

2.6

2.7

2.8

2.9

3.0

3.1

tmaa (µs/ft)

ρmaa(g/cm3)

Calcite

Dolomite

Anhydrite

Quartz

Gas direction

Salt (CNL* log)

Salt (SNP)


Density ToolMatrix Identification (MID)—Open Hole Lith-11




Density ToolMatrix Identification (MID)—Open Hole Lith-12


200

PurposeChart Lith-12 is used similarly to Chart Lith-11 to establish the mineraltype of the formation.

2.0

2.1

2.2

2.3

2.4

2.5

2.6

2.7

2.8

2.9

3.0

3.1

100 120 140 160 180 200 220 240

tmaa (µs/m)

ρmaa(g/cm3)

Calcite

Dolomite

Anhydrite

Quartz

Gas direction

Salt (SNP)

Salt (CNL* log)

Lith


ResistivitySchlumberger

6-7

Rint

Dual Laterolog–Rxo DeviceDLT-D/E LLD–LLS–Rxo device Rint-9b

1.11.2

1.3 1.41.6

1.8

100

80

60

40

30

20

15

10

8

6

4

3

2

1.5

1

0.8

0.6

0.4

0.3

0.2

RLLD/Rxo

RLLD/RLLS

Thick beds, 8-in. [203-mm] hole, no annulus, no transition zone, Rxo/Rm = 50,

use data corrected for borehole effect

20 30

80

100

120

0.500.75 1.01 1.27

1.522.03

3.04

40 50 60100

70

50

30

20

15

10

7

5

3

1.5

2

0.4

0.2

10060

403020

2.54

1.52

1.010.75

0.50

0.4 0.6 0.8 1.0 1.5 2 3 4 6 8 10 15 20 30 40 50

di (in.)

di (m)

di (in.)

di (m)

Rt

Rxo

Rt

Rxo

Rt

RLLD

© Schlumberger

Appendix B

B-5

Logging Tool Response in Sedimentary Minerals

Name FormulaρLOG φSNP φCNL φAPS† t c t s

Pe Uε tp GR Σ

(g/cm3) (p.u.) (p.u.) (p.u.) (µsec/ft) (µsec/ft) (farad/m) (nsec/m) (API units) (c.u.)

Silicates

Quartz SiO2 2.64 –1 –2 –1 56.0 88.0 1.8 4.8 4.65 7.2 4.3

β-Cristobalite SiO2 2.15 –2 –3 1.8 3.9 3.5

Opal (3.5% H2O) SiO2 (H2O).1209 2.13 4 2 58 1.8 3.7 5.0

Garnet‡ Fe3Al2(SiO4)3 4.31 3 7 11 48 45

Hornblende‡Ca2NaMg2Fe2

AlSi8O22(O,OH)23.20 4 8 43.8 81.5 6.0 19 18

Tourmaline NaMg3Al6B3Si6O2(OH)4 3.02 16 22 2.1 6.5 7450

Zircon ZrSiO4 4.50 –1 –3 69 311 6.9

Carbonates

Calcite CaCO3 2.71 0 0 0 49.0 88.4 5.1 13.8 7.5 9.1 7.1

Dolomite CaCO3MgCO3 2.85 2 1 1 44.0 72 3.1 9.0 6.8 8.7 4.7

Ankerite Ca(Mg,Fe)(CO3)2 2.86 0 1 9.3 27 22

Siderite FeCO3 3.89 5 12 3 47 15 57 6.8–7.5 8.8–9.1 52

Oxidates

Hematite Fe2O3 5.18 4 11 42.9 79.3 21 111 101

Magnetite Fe3O4 5.08 3 9 73 22 113 103

Geothite FeO(OH) 4.34 50+ 60+ 19 83 85

Limonite‡ FeO(OH)(H2O)2.05 3.59 50+ 60+ 56.9 102.6 13 47 9.9–10.9 10.5–11.0 71

Gibbsite Al(OH)3 2.49 50+ 60+ 1.1 23

Phosphates

Hydroxyapatite Ca5(PO4)3OH 3.17 5 8 42 5.8 18 9.6

Chlorapatite Ca5(PO4)3CL 3.18 –1 –1 42 6.1 19 130

Fluorapatite Ca5(PO4)3F 3.21 –1 –2 42 5.8 19 8.5

Carbonapatite (Ca5(PO4)3)2CO3H2O 3.13 5 8 5.6 17 9.1

Feldspars—Alkali‡

Orthoclase KAISi3O8 2.52 –2 –3 69 2.9 7.2 4.4–6.0 7.0–8.2 ~220 16

Anorthoclase KAISi3O8 2.59 –2 –2 2.9 7.4 4.4–6.0 7.0–8.2 ~220 16

Microcline KAISi3O8 2.53 –2 –3 2.9 7.2 4.4–6.0 7.0–8.2 ~220 16

Feldspars—Plagioclase‡

Albite NaAlSi3O8 2.59 –1 –2 –2 49 85 1.7 4.4 4.4–6.0 7.0–8.2 7.5

Anorthite CaAl2Si2O8 2.74 –1 –2 45 3.1 8.6 4.4–6.0 7.0–8.2 7.2

Micas‡

Muscovite KAl2(Si3AlO10)(OH)2 2.82 12 ~20 ~13 49 149 2.4 6.7 6.2–7.9 8.3–9.4 ~270 17

GlauconiteK0.7(Mg,Fe2,Al)

(Si4,Al10)O2(OH)2.86 ~38 ~15 4.8 14 21

Biotite K(Mg,Fe)3(AlSi3O10)(OH)2 ~2.99 ~11 ~21 ~11 50.8 224 6.3 19 4.8–6.0 7.2–8.1 ~275 30

Phlogopite KMg3(AlSi3O10)(OH)2 50 207 33

†APSporosity derived from near-to-array ratio (APLC)‡Mean value, which may vary for individual samples

For more information see Reference 41.

Appendix B

B-6

Logging Tool Response in Sedimentary Minerals

Name FormulaρLOG φSNP φCNL φAPS† t c t s

Pe Uε tp GR Σ

(g/cm3) (p.u.) (p.u.) (p.u.) (µsec/ft) (µsec/ft) (farad/m) (nsec/m) (API units) (c.u.)

Clays‡

Kaolinite Al4Si4O10(OH)8 2.41 34 ~37 ~34 1.8 4.4 ~5.8 ~8.0 80–130 14

Chlorite(Mg,Fe,Al)6(Si,Al)4

O10(OH)82.76 37 ~52 ~35 6.3 17 ~5.8 ~8.0 180–250 25

IlliteK1–1.5Al 4(Si7–6.5,Al1–1.5)

O20(OH)42.52 20 ~30 ~17 3.5 8.7 ~5.8 ~8.0 250–300 18

Montmorillonite(Ca,Na)7(Al,Mg,Fe)4(Si,Al)8O20(OH)4(H2O)n

2.12 ~60 ~60 2.0 4.0 ~5.8 ~8.0 150–200 14

Evaporites

Halite NaCl 2.04 –2 –3 21 67.0 120 4.7 9.5 5.6–6.3 7.9–8.4 754

Anhydrite CaSO4 2.98 –1 –2 2 50 5.1 15 6.3 8.4 12

Gypsum CaSO4(H2O)2 2.35 50+ 60+ 60 52 4.0 9.4 4.1 6.8 19

Trona Na2CO3NaHCO3H2O 2.08 24 35 65 0.71 1.5 16

Tachhydrite CaCl2(MgCl2)2(H2O)12 1.66 50+ 60+ 92 3.8 6.4 406

Sylvite KCl 1.86 –2 –3 8.5 16 4.6–4.8 7.2–7.3 500+ 565

Carnalite KClMgCl2(H2O)6 1.57 41 60+ 4.1 6.4 ~220 369

Langbeinite K2SO4(MgSO4)2 2.82 –1 –2 3.6 10 ~290 24

PolyhaliteK2SO4Mg

SO4(CaSO4)2(H2O)22.79 14 25 4.3 12 ~200 24

Kainite MgSO4KCl(H2O)3 2.12 40 60+ 3.5 7.4 ~245 195

Kieserite MgSO4H2) 2.59 38 43 1.8 4.7 14

Epsomite MgSO4(H2O)7 1.71 50+ 60+ 1.2 2.0 21

Bischofite MgCl2(H2O)6 1.54 50+ 60+ 100 2.6 4.0 323

Barite BaSO4 4.09 –1 –2 267 1090 6.8

Celestite SrSO4 3.79 –1 –1 55 209 7.9

Sulfides

Pyrite FeS2 4.99 –2 –3 39.2 62.1 17 85 90

Marcasite FeS2 4.87 –2 –3 17 83 88

Pyrrhotite Fe7S8 4.53 –2 –3 21 93 94

Sphalerite ZnS 3.85 –3 –3 36 138 7.8–8.1 9.3–9.5 25

Chalopyrite CuFeS2 4.07 –2 –3 27 109 102

Galena PbS 6.39 –3 –3 1630 10,400 13

Sulfur S 2.02 –2 –3 122 5.4 11 20

Coals

Anthracite CH.358N.009O.022 1.47 37 38 105 0.16 0.23 8.7

Bituminous CH.793N.015O.078 1.24 50+ 60+ 120 0.17 0.21 14

Lignite CH.849N.015O.211 1.19 47 52 160 0.20 0.24 13

†APSporosity derived from near-to-array ratio (APLC)‡Mean value, which may vary for individual samples

For more information see Reference 41.

Appendix A

A-3

0.20

0.25

0.30

0.35

0.40

0.45

0.50

0.60

0.70

0.80

0.90 1.0

1.2

1.4

1.6 1.82.0

2.5

3.0

4.05.06.0

8.0 10

15 203040 50100200

∞

5000

4000

3000

2500

2000

1500

1000

500

400

300

200

150

100

50

25

10

0

Resistivity scale may be multiplied by 10 for use in a higher range

Con

duct

ivity

Res

istiv

ity

t, ρb

φ

FR

For FR =0.62 φ2.15

Water Saturation Grid for Porosity Versus Resistivity

CompanyWell

IntervalCreated

: FEL 4 : : 15800.00 - 16035.00 feet :

FORMATION EVALUATION LOG

INTERPRETED

LITHOLOGY

Cuttings Lithology Description CORE

OIL

FLUOR CUT

MD feet 1:500

Rate of Penetration ft/hr 500 400 300 200 100

Methane ppm 5 500000

Ethane ppm 5 500000

Propane ppm 5 500000

iso-Butane ppm 5 500000

n-Butane ppm 5 500000

iso-Pentane ppm 5 500000

n-Pentane ppm 500000 50000 5000 500 50

Ditch Gas % 10 8 6 4 2

Ditch Gas % (Backup) 110 90 70 50 30

GAMMA API 150 120 90 60 30

RESISTIVITY Ohm.m 2000 200 20 2

Ohm.m

80015850

1590015950

16000

MDST: m gry-m dk gry-olv blk, occ brn blk, mod frm-frm, occ hd, sb blky-blky, pred sb blky, sli-occ slty, microcarb, n calc

ISOTUBE TAKEN @ 15800' DEPTH: 15800' WOB: 8-24 klbs PPRESS: 3817 psi SPM: 117 GPM: 585 TORQ: 40 kft.lbs RPM: 22

MD: 15828', INC: 9.40 deg, AZM: 65.27 deg, TVD: 15053.71'

CG: 0.3%


ISOTUBE TAKEN @ 15952' FM: 8.9%

CIRCULATE GAS THROUGH CHOKE C1, C2, C3, IC4, NC4, IC5,

NC5 INCREASE MUD WEIGHT FROM 14.0 ppg TO 14.5 ppg @ 15975' MD

Sun 1st May 2005 Mon 2nd May 2005

MW: 14.5 ppg, PV/YP: 39/23, Vis: 59sec, Gels: 20/27/28, E.S: 670 V

DRILLER'S DEPTH @ 16034' MD (TVD 15256.28')

FORMATION EVALUATION LOG

INTERPRETED

LITHOLOGY

Cuttings Lithology Description CORE

OIL

FLUOR CUT

MD feet 1:500

Rate of Penetration ft/hr 500 400 300 200 100

Methane ppm 5 500000

Ethane ppm 5 500000

Propane ppm 5 500000

iso-Butane ppm 5 500000

n-Butane ppm 5 500000

iso-Pentane ppm 5 500000

Ditch Gas % 10 8 6 4 2

Ditch Gas % (Backup) 110 90 70 50 30

GAMMA API 150 120 90 60 30

RESISTIVITY Ohm.m 2000 200 20 2

Ohm.m

CompanyWell

IntervalCreated

: HEL 4 : : 15800.00 - 16035.00 feet :

Gas Ratio PlotCHROMATOGRAPH DATACORE

OIL CHARACTER OIL CHARACTER C1 RATIOS ANALYSISCDANAL

UNPRODUCTIVE

GAS

GAS/LIG

HT OIL

OIL

RESIDUAL OIL

MD feet 1:500

INTERPRETED

LITHOLOGY

C1 ppm 10 10000

C2 10 10000

C3 10 10000

iC4 10 10000

nC4 10 10000

iC5 10 10000

nC5

10000 1000 100

C1C2 1 1000

C1C3 1 1000

C1C4 1 1000

C1C5 1 1000

GAS

100 10 1 %

ROP

1000 100 10 1 ft/hr

LHR 1 100

GWR 1 100

80015850

1590015950

16000

DEPTH: 15800' WOB: 8-24 klbs PPRESS: 3817 psi SPM: 117 GPM: 585 TORQ: 40 kft.lbs RPM: 22

CG: 0.3%

FM: 8.9%

Gas Ratio PlotCHROMATOGRAPH DATACORE

OIL CHARACTER OIL CHARACTER C1 RATIOS ANALYSISCDANAL

UNPRODUCTIVE

GAS

GAS/LIG

HT OIL

OIL

RESIDUAL OIL

MD feet 1:500

INTERPRETED

LITHOLOGY

C1 ppm 10 10000

C2 10 10000

C3 10 10000

iC4 10 10000

nC4 10 10000

iC5 10 10000

nC5

10000 1000 100

C1C2 1 1000

C1C3 1 1000

C1C4 1 1000

C1C5 1 1000

GAS

100 10 1 %

ROP

1000 100 10 1 ft/hr

LHR 1 100

GWR 1 100

CompanyWell

IntervalCreated

: DDL 4 : : 15800.00 - 16035.00 feet :

ENGINEERING SUMMARY PLOT

MD feet 1:500

INTERPRETED

LITHOLOGY

PUMP PRESS

5000 4000 3000 2000 1000 psi

WEIGHT ON BIT

50 40 30 20 10 klbf

RATE OF PENETRATION

500 400 300 200 100 ft/hr

AVG TORQUE

50 40 30 20 10 kft.lb

HOOKLOAD

400 320 240 160 80 klbf

MUD FLOW IN

1500 1200 900 600 300 USgl/min

MAX TORQUE

50 40 30 20 10 kft.lb

RPM BIT

300 225 150 75 RPM

RPM TABLE

300 225 150 75 RPM

TOTAL GAS

20 16 12 8 4 %

ECD TD

18 16 14 12 10 ppg

80015850

1590015950

16000



CG: 0.3%


FM: 8.9%


ENGINEERING SUMMARY PLOT

MD feet 1:500

INTERPRETED

LITHOLOGY

PUMP PRESS

5000 4000 3000 2000 1000 psi

WEIGHT ON BIT

50 40 30 20 10 klbf

RATE OF PENETRATION

500 400 300 200 100 ft/hr

AVG TORQUE

50 40 30 20 10 kft.lb

HOOKLOAD

400 320 240 160 80 klbf

MUD FLOW IN

1500 1200 900 600 300 USgl/min

MAX TORQUE

50 40 30 20 10 kft.lb

RPM BIT

300 225 150 75 RPM

RPM TABLE

300 225 150 75 RPM

TOTAL GAS

20 16 12 8 4 %

ECD TD

18 16 14 12 10 ppg

CompanyWell

IntervalCreated

: PDL 4 : : 15800.00 - 16035.00 feet :

PRESSURE DATA PLOTROTARY SPEEDPENETRATION RATE GAS DATATORQUE DXC DATA INTERPRETED

LITHOLOGY

MD feet 1:500

DXC 0.2 2 TOTAL GAS

100 10 1 0.1 %

ROP 1000 0

ft/hr

SURFACE RPM

500 400 300 200 100 RPM

BIT RPM

500 400 300 200 100 RPM

WEIGHT ON BIT 50 0

klbf

AVERAGE

50 40 30 20 10 kft.lb

MAXIMUM

50 40 30 20 10 kft.lb800

1585015900

1595016000



CG: 0.3%


FM: 8.9%

CIRCULATE GAS THROUGH CHOKE INCREASE MUD WEIGHT FROM 14.0 ppg TO 14.5 ppg @ 15975' MD


MW: 14.5 ppg, PV/YP: 39/23, Vis: 59sec, Gels: 20/27/28, E.S: 670 V

PRESSURE DATA PLOTROTARY SPEEDPENETRATION RATE GAS DATATORQUE DXC DATA INTERPRETED

LITHOLOGY

MD feet 1:500

DXC 0.2 2 TOTAL GAS

100 10 1 0.1 %

ROP 1000 0

ft/hr

SURFACE RPM

500 400 300 200 100 RPM

BIT RPM

500 400 300 200 100 RPM

WEIGHT ON BIT 50 0

klbf

AVERAGE

50 40 30 20 10 kft.lb

MAXIMUM

50 40 30 20 10 kft.lb

CompanyWell

IntervalCreated

: ECD TIME LOG : : 21/Apr/2005 20:00:00 to 24/Apr/2005 06:00:40 : 24/Apr/2005 13:00:52

COMMENTS TM hours 1:3600

Block Height 0 110

ft

Mud Weight In 10 15

ppg

Mud Flow In 0 1500

USgl/minStandpipe Pressure 0 5000

psi

Surface Torque 0 15

kft.lb

Actual ECD Flow Off [RWD] 10 15

ppgActual ECD [RWD] 10 15

ppg

CDS Temperature [RWD] 0 250

degF

21:00:00

22:00:00

23:00:00

00:00:00

01:00:00

02:00:00

03:00:00

04:00:00

22/Apr/2005

Start MWD Run 3

Drilling @ 12638 ftDownlinkSlow Circ Rates

Repair hose leak

Survey

Downlink

Downlink

Downlink

Downlink

DownlinkDownlink

Survey

CompanyWell

IntervalCreated

: : : 10935.00 - 13247.19 feet : 9/2/2005 2:09:28 PM

TVD feet 1:500

Bulk Density Comp [RWD] 1.65 2.65

g/cc

Caliper 12 22

inCDS Temperature [RWD] 100 250

degF

DRHM [RWD] -0.25 0.25

g/ccGamma Ray App [RWD] 0 150

APINPSM 60 0

puRate of Penetration 1000 0

ft/hr

Resistivity [AT] [LS] 2MHz [RWD] 0.2 20

Ohm.mResistivity [AT] [LS] 400 kHz [RWD] 0.2 20

Ohm.mResistivity [PD] [LS] 2MHz [RWD] 0.2 20

Ohm.mResistivity [PD] [LS] 400kHz [RWD] 0.2 20

Ohm.m

Time Since Drilled 0 600

min

10950

11000

11050

11100

11150

11200

11250

CompanyWellFieldRig

CountyStateCountry

Log as of:ABC1/2-3

OffshoreNorth SeaUnited Kingdom

AZIMUTHAL GAMMA RAYRESISTIVITY

REALTIME IMAGE LOG

CompanyWell

IntervalCreated

: : : 9950.00 - 13190.00 feet UP : 01/12/2005 04:57:54

MD feet 1:500

CDS Temperature [MWD] 0 250

degF

Resistivity [PD] [LS] 2MHz [MWD] 0.2 2000

Ohm.mResistivity [AT] [LS] 400 kHz [MWD] 0.2 2000

Ohm.m

Gamma Ray UP [MWD] 0 150

APIGamma Ray DOWN [MWD] 0 150

APIGamma Ray LEFT [MWD] 0 150

APIGamma Ray RIGHT [MWD] 0 150

APIRate of Penetration 200 0

ft/hr

Azimuthal Gamma Image 0 150

10000

10050

TCDX

10100

10150

10200

10250

10300

10350

10400

10450

10500

10550

CompanyWellFieldRig

CountyStateCountry

Log as of: OffshoreNorth SeaUnited Kingdom

GAMMA RAYRESISTIVITYBULK DENSITYNEUTRON POROSITY

REALTIME LOG

1:500

Baker Hughes INTEQ does not guarantee the accuracy or correctness of interpretations provided in or from this log. Since allinterpretations are opinions based on measurements, Baker Hughes INTEQ shall under no circumstances be held responsible forconsequential damages or any other loss, costs, damages or expenses incurred or sustained in connection with the use of anysuch interpretations. Baker Hughes INTEQ disclaims all expressed and implied warranties related to its service which isgoverned by Baker Hughes INTEQ's standard terms and conditions.

CompanyWell

IntervalCreated

: : : 7250.00 - 13190.00 feet UP : 01/12/2005 04:57:54

MD feet 1:500

CDS Temperature [MWD] 0 250

degF

Bulk Density Compensated (MWD) 1.95 2.95

g/ccNeutron Porosity (LS) (MWD) 45 -15

pu

Resistivity [PD] [LS] 2MHz [MWD] 0.2 2000

Ohm.mResistivity [AT] [LS] 400 kHz [MWD] 0.2 2000

Ohm.m

GRIX

Delta RHO (MWD) -0.25 0.25

g/cc

Rate of Penetration 200 0

ft/hrGamma Ray App [MWD] 0 150

API

7300

7350

7400

> Run 1

RPCHX

RACLX

GRAX

TCDX

ROP

> Run 1

9900

9950

10000

10050

10100

10150

10200

10250

10300

10350

ABDCLX

BDCX

GR1AX

GRADX

Company

WellField

Rig

CountyStateCountry

Log as of:

OffshoreSouthern North SeaUnited Kingdom

GAMMA RAYRESISTIVITYDENSITYNEUTRON POROSITYREALTIME LOG

1:500 MEASURED DEPTH

15:00 18/08/05

Baker Hughes INTEQ does not guarantee the accuracy or correctness of interpretations provided in or from this log. Since all

interpretations are opinions based on measurements, Baker Hughes INTEQ shall under no circumstances be held responsible for

consequential damages or any other loss, costs, damages or expenses incurred or sustained in connection with the use of any

such interpretations. Baker Hughes INTEQ disclaims all expressed and implied warranties related to its service which is

governed by Baker Hughes INTEQ's standard terms and conditions.

CompanyWell

IntervalCreated

: : .19 feet UP : 18/Aug/2005 3:30:12 PM

MD feet 1:500

Gamma Ray App [MWD] 0 150

API

GRIX

Rate of Penetration 100 0

ft/hrCDS Temperature [MWD] 0 250

degF

Resistivity [AT] [LS] 400 kHz [MWD] 0.2 2000

Ohm.mResistivity [PD] [LS] 2MHz [MWD] 0.2 2000

Ohm.m

Bulk Density Compensated Down (MWD) 1.95 2.95

g/ccBulk Density Compensated Left (MWD) 1.95 2.95

g/ccBulk Density Compensated Right (MWD) 1.95 2.95

g/ccBulk Density Compensated Up (MWD) 1.95 2.95

g/ccBulk Density Compensated (MWD) 1.95 2.95

g/ccNeutron [NPLX] 45 -15

puDelta RHO (MWD) -0.25 0.25

g/cc

11600

11650

11700

11750

11800

11850

11900

11950

12000

12050

12100

ops & wsg manual

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