Winter 2004/2005

Viscoelastic Surfactants

Ocean Drilling for Science

Fault-Seal Analysis

Measuring Multiphase Flow

Oilfield Review

05_OR_001_0

In the oil and gas industry, economic and health, safety and environmental (HSE) realities force us to be objectivein developing and deploying technology. The rapid develop-ment of individual technologies requires constant attentionand objectivity from decision makers in exploration andproduction (E&P) companies. Among the most rapidlyevolving technologies available to E&P companies arerotary steerable drilling systems.

Shell Exploration & Production in Europe (Shell)became interested in the potential of the earliest direc-tional drilling systems to improve drilling efficiency—a keyconcern for well-delivery teams to fulfill the Drilling theLimitTM philosophy that is central to all of our projects.Although positive-displacement motors offered steeringcapability and directional control, the motors were not efficient. Steerable motors allowed rotation or sliding ofthe drillstring from surface, which improved directionalcontrol, but this technology was risky because the hightorque and drag limited drilling capability in sliding androtating modes. In addition, the wellbore tortuosity producedby steerable motors in the sliding mode often causes otherproblems: tortuosity makes future sliding more difficult andcan impede critical operations for formation evaluation andrunning casing.

Rotary steerable technology eliminated most disadvantagesof previous directional drilling methods. Because these systems drill directionally with continuous rotation fromthe surface, there is no need to slide the tool. Continuousrotation transfers weight to the bit more efficiently, whichincreases the rate of penetration (ROP). Rotation alsoimproves hole cleaning by agitating drilling fluid and cut-tings, allowing them to flow out of the borehole rather thanaccumulating as a cuttings bed. Efficient cuttings removalreduces the chance for the bottomhole assembly to becomestuck or to pack off.

Service providers have developed a wide variety of fit-for-purpose rotary steerable systems to improve the economicsof nearly any drilling project. These include tools that facilitate drilling long horizontal sections; systems forharsh, rugged environments, which support drilling withbicenter bits and drilling in soft formations; and even systemsspecifically designed to drill vertical wellbores.

Shell found that drilling from one casing shoe to the nextwith a rotary steerable system (RSS) provided more efficiency,better performance and improved safety than directionaldrilling with a downhole motor. The newest RSS, whichincludes an integrated downhole power section to achievegreater ROP, benefits drilling projects in inhabited areas(see “Powering Up to Drill Down,” page 4). In the Groningenfield in The Netherlands, for example, use of this system

Rotary Steerable Technology: Pushing the Limit

allowed a topdrive to be run at 10 to 20 rpm to drill a water-injection well, greatly reducing the environmental impactof sound generated by the drilling rig. Nevertheless, theROP increased 50% compared with other wells in the area.

Perhaps the biggest economic impact of rotary steerabledrilling technology occurs in mature fields whose productivelife can be extended by quickly drilling directional wells ina single bit run through highly depleted reservoirs. To thisend, Shell pioneered use of a 6-in. powered RSS in maturefields to create smaller boreholes. Cost reductions of atleast 25% are typical in our mature-field drilling projectsbecause the performance of the 6-in. tool matches that ofthe 8.5-in. tool. In addition, the smaller hole sizes reducethe costs of drilling fluids, cuttings removal and disposalwithout constraining flow rates.

Within Shell, the value of using an RSS is well recognized.Our “shoe2shoe drilling” initiative reflects the optimaldrilling process, and RSS technology is a key enabler. Wehave also instituted a Common Interest Network (CIN) onrotary steerable technology, whereby well engineers withRSS expertise in all Shell regions share RSS learning andpractices to collectively advance the learning curve. TheCIN also challenges industry providers to deliver additionalRSS advancements, such as different tool sizes.

We expect the next important milestone, successfuldeployment of a superslim 3.125-in. through-tubing rotarydrilling (TTRD) system for 3.875- to 4.5-in. holes, to beachieved in 2005, thanks to development by Shell, BP, Statoiland Schlumberger. Although TTRD work has already beencompleted through larger completions, the capability todrill sidetracks though 4.5-in. tubing will further reduce thecost of draining marginal accumulations in mature fields—a vital concern for companies large and small.

Chris Kuyken Team Leader, Well Engineering and Well Services TechnologyShell Exploration & Production in EuropeAberdeen, Scotland

Chris Kuyken has more than 22 years of experience in oil- and gas-well drillingwith Shell and has worked onshore and offshore in many well engineeringpositions in Oman, Brunei and, since 1999, in Scotland. He is an energetic proponent of Shell’s Drilling the LimitTM philosophy, whereby people, HSE andtechnology are the keys to success. A European Engineer (EUR ING) registeredwith European Federation of National Engineering Associations (FEANI) and aChartered Engineer (C Eng) through the British Engineering Council, Chrisearned a BS degree in chemical engineering technology from Hogere TechnischeSchool (HTS), The Hague.

1

Drilling the Limit is a trademark of Shell.

Schlumberger

Oilfield Review4 Powering Up to Drill Down

A new rotary steerable drilling system includes an integratedpower section that converts the hydraulic power of circulatingfluid to rotational torque. This supplements rotational torquesupplied by the drilling rig and produces unprecedented highrates of penetration, making it ideal for drilling hard formations.Like other advanced rotary steerable systems, this high-performance technology offers the advantages of continuousrotation at drillstring speed to minimize stick/slip phenomenaand improve efficiency.

10 Expanding Applications for Viscoelastic Surfactants

Viscoelastic surfactants (VES) revolutionized fracture stimulations in the mid-1990s. Today, continued advances inVES chemistries allow engineers to apply these unique materialsin new ways that dramatically improve and optimize well-completion techniques. Case studies from South America,North America, the North Sea and the Caspian Sea demonstratethe effectiveness of VES fluids in difficult gravel-packing,hydraulic fracturing and acidizing operations.

24 Scientific Deep-Ocean Drilling: Revealing the Earth’s Secrets

Drilling for science has contributed to an understanding of thedynamic processes that affect climate, natural disasters andthe creation and distribution of resources on Earth. This articlereviews the history of scientific deep-ocean drilling, technologicaldevelopments and plans for the 21st Century.

Executive EditorMark A. Andersen

Advisory EditorGretchen M. Gillis

Senior EditorsMark E. TeelMatt Garber

EditorsDon WilliamsonRoopa GirMatt Varhaug

Contributing EditorsRana RottenbergJoan MeadJoel Parshall

Design/ProductionHerring DesignSteve Freeman

IllustrationTom McNeffMike MessingerGeorge Stewart

PrintingWetmore Printing CompanyCurtis Weeks

Address editorial correspondence to:Oilfield Review1325 S. Dairy Ashford Houston, Texas 77077 USA(1) 281-285-7847Fax: (1) 281-285-1537E-mail: editorOilfieldReview@slb.com

Address distribution inquiries to:Matt GarberSchlumberger Cambridge ResearchHigh Cross, Madingley RoadCambridge, England CB3 0EL(44) 1223 325 377Fax: (44) 1223 361 473E-mail: mgarber@cambridge.oilfield.slb.com

Useful links:

Schlumbergerwww.slb.com

Oilfield Review Archivewww.slb.com/oilfieldreview

Oilfield Glossarywww.glossary.oilfield.slb.com

On the cover:

The riserless drillship JOIDES Resolutionrecovered cores of sediments, basalt andmicrobial samples at Juan de Fuca ridge,offshore Oregon, USA, in August 2004.This scientific ocean drilling Expedition301 marked the beginning of the IntegratedOcean Drilling Program (IODP). Duringthis expedition, one borehole observatorypenetrating the upper oceanic crust wasreplaced and two new observatorieswere established. (Photographs courtesyof John Beck, IODP at Texas A&MUniversity, College Station, USA.)

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Winter 2004/2005Volume 16Number 4

64 Contributors

68 New Books and Coming in Oilfield Review

70 Annual Index

3

38 Reducing Uncertainty with Fault-Seal Analysis

Faulting can have an enormous impact on oil and gas exploita-tion. Faults are often responsible for trapping hydrocarbonsand compartmentalizing reservoirs. They can also introduce ahigh degree of uncertainty in both the exploration and development stages. This article describes how geoscientistsand engineers are improving their understanding of faults insiliciclastic reservoirs, and how they analyze, model and simulatethe effects of faults on subsurface fluid flow. Examples fromHibernia, Newfoundland, Canada, and Prudhoe Bay, Alaska,USA, illustrate the successful application of modern fault-sealanalysis methods.

52 A New Horizon in Multiphase Flow Measurement

Measuring three-phase flow without separation increases theaccuracy of gas, oil and water measurements. This technologyhelps engineers quantify changing fluid phases over time tobetter understand dynamic flow. Case studies from Australia,the Gulf of Mexico and Africa illustrate the benefits of advancedmultiphase meters and show how they help enhance production,improve field operations and optimize reservoir management.

Syed A. AliChevronTexaco E&P Technology Co.Houston, Texas, USA

Abdulla I. Al-KubaisySaudi AramcoRas Tanura, Saudi Arabia

George KingBPHouston, Texas

Anelise LaraPetrobrasRio de Janeiro, Brazil

Eteng A. SalamPERTAMINAJakarta, Indonesia

Y.B. SinhaOil & Natural Gas CorporationNew Delhi, India

Sjur TalstadStatoilStavanger, Norway

Richard WoodhouseIndependent consultantSurrey, England

Advisory Panel

Oilfield Review subscriptionsare available from:Oilfield Review ServicesBarbour Square, High StreetTattenhall, Chester CH3 9RF England(44) 1829-770569Fax: (44) 1829-771354E-mail: orservices@t-e-s.co.ukwww.oilfieldreview.comAnnual subscriptions, including postage,are 180.00 US dollars, subject toexchange-rate fluctuations.

Oilfield Review is published quarterly bySchlumberger to communicate technicaladvances in finding and producing hydro-carbons to oilfield professionals. OilfieldReview is distributed by Schlumberger toits employees and clients. Oilfield Reviewis printed in the USA.

Contributors listed with only geographiclocation are employees of Schlumbergeror its affiliates.

© 2005 Schlumberger. All rights reserved.No part of this publication may be repro-duced, stored in a retrieval system ortransmitted in any form or by any means,electronic, mechanical, photocopying,recording or otherwise without the priorwritten permission of the publisher.

4 Oilfield Review

Pierantonio CoperciniFarag SolimanBelayim Petroleum Company (Petrobel)Cairo, Egypt

Mohamed El GamalKattamia, Egypt

Wayne LongstreetJon RoddMark SarssamDragon Oil Plc.Dubai, United Arab Emirates

Iain McCourtBaku, Azerbaijan

Barry PersadMike WilliamsSugar Land, Texas, USA

For help in preparation of this article, thanks to Emma Bloor,Phil Coffman, Liz Hutton, Steve Siswanto and Pipine Widjaya,Sugar Land, Texas, USA; Erik Christiaansen, Calgary, Alberta,Canada; Tony Pink, Bottesford, England; and Brian Stevensand Paul Wilkie, Stonehouse, England.adnVISION (Azimuthal Density Neutron tool), NODAL, PowerDrive vorteX and SlimPulse are marks of Schlumberger.

Economics, efficiency, environmental protectionand safety are the most important targets in theoil industry. New technology is often the key tohitting these targets, particularly for thoseinvolved in well drilling. Drillers pursue newtechnology as relentlessly as anyone in the oilfield. Even though rotary steerable systems areevolving rapidly and delivering unprecedentedrates of penetration, drillers nevertheless seektechnology that speeds the drilling process evenmore. Their motivations are many, and includethe obvious reductions in rig time and expensethat result from using a rotary steerable systemthat provides more power to the bit.

Advanced drilling technology provides addi-tional, more subtle advantages, such as reducingcasing wear by preventing contact betweendrillpipe and the casing for long periods of time(next page, left). New technology also helpsdrillers decrease formation-exposure time—thetime between drilling and formation evaluation.This minimizes invasion of drilling fluids andcan simplify petrophysical evaluation. Less timebetween drilling and running casing means lesstime during which a borehole can degrade;beyond a certain point, running casing becomesdifficult. Ultimately, in many cases, faster wellconstruction means that wells produce oil andgas sooner.

Against these advantages, however, drillingengineers weigh the drawbacks of faster drilling,chief among them the potential for poor bore-hole quality if drilling operations are notperformed carefully. In addition, the drillingrig’s mud system and pumps have an inherentcapacity for hole cleaning that should not beexceeded. Using high flow rates to clean theborehole might cause hydraulic erosion. Mudproperties and flow velocities must be balancedto ensure hole stability. Finally, directional control might sometimes be lost if speed over-rides all other concerns.

Articles in recent issues of Oilfield Reviewdescribed a rotary steerable system (RSS) thatfacilitates drilling long horizontal sections withexcellent directional control; a system devel-oped for harsh, rugged environments, whichsupports drilling with bicenter bits and drillingin soft formations; and a vertical drillingsystem.1 A common feature of all Schlumbergerrotary steerable systems is the continuous rota-tion of all external components (next page, right).

The latest RSS adds an integrated downholemotor to increase the rate of penetration (ROP).This system is ideal for quickly drilling long vertical or directional sections. In this article,we discuss the special technical demands onpowered rotary steerable systems and the way

Powering Up to Drill Down

A new rotary steerable drilling system includes an integrated power section that

converts the hydraulic power of circulating fluid to rotational torque. This produces

unprecedented high rates of penetration. Like other advanced rotary steerable

systems, this high-performance technology offers the advantage of continuous

rotation at drillstring speed to minimize stick/slip phenomena and improve efficiency.

Winter 2004/2005 5

tool developers satisfied those demands. Examples from the Caspian Sea, Egypt andCanada demonstrate the advantages now obtain-able with an advanced rotary steerable system.

The Need for SpeedEarly directional drilling systems paired downholemotors with an adjustable bent housing, a compo-nent of the drillstring that allowed drillers tochange the well trajectory. These bottomholeassemblies (BHAs) tended to produce poor-qualityor spiral boreholes as drilling alternated betweensliding and rotating modes. In the sliding mode,the drillstring is not rotated by the drilling rig;instead, the drill bit is rotated downhole by thedownhole motor. Frictional forces, known as drag,build as the nonrotating drillstring is pushedalong the low side of the borehole.2 Drilling ratesin sliding mode typically are slow, and both

mechanical and differential sticking of the drill-string are ever-present concerns.

The earliest rotary steerable systems dramat-ically improved ROPs and borehole quality whilelimiting mechanical sticking. These observationsled drilling engineers to consider joining adownhole motor to a rotary steerable tool. Thiscombination is not trivial: the bearings andtransmission of the downhole motor must bestrong enough to support the additional weightof the rotary steerable tool below. In addition,the power section of the downhole motor mustbe configured to keep the rotation rate fromexceeding the limits of the RSS. At excessiverates, steering control becomes difficult and thewell path might be compromised.

Successful integration of a downhole motorand a rotary steerable system promised manyadvantages, from higher ROP to facilitating useof more aggressive drill bits. In areas of high

environmental sensitivity, driving the RSS withonly downhole power eliminates excess rig noise.

Given these myriad motivations, Schlumbergerscientists and engineers began to tackle the challenges of building a powered rotary steerabledrilling system. The PowerDrive vorteX poweredrotary steerable system is the result of their efforts.

1. Williams M: “Better Turns for Rotary Steerable Drilling,”Oilfield Review 16, no. 1 (Spring 2004): 4–9.Brusco G, Lewis P and Williams M: “Drilling StraightDown,” Oilfield Review 16, no. 3 (Autumn 2004): 14–17.

2. For more on drilling in the sliding mode: Maidla E andHaci M: “Understanding Torque: The Key to Slide-DrillingDirectional Wells,” paper IADC/SPE 87162, presented atthe IADC/SPE Drilling Conference, Dallas, March 2–4, 2004.

Improved directional control Continuous pipe rotationfor cleaner hole

Powered rotary steerable system

Improved steering to reducewellbore tortuosity

Less risk ofstuck pipe

Less drag to improvecontrol of weight on bit

Lower cost per barrel

Time saved by drillingfaster while steering and

by fewer wiper trips

Longer extended reachwithout excessive drag

Reducedcompletion cost

and easierworkovers

Longerhorizontalrange with

good steering

Lower cost per footFewer wells and platforms needed to develop a field> Fit for purpose in boreholes large and small.Various types of rotary steerable systems areavailable to drill holes with diameters from 5.75 to 26 in.

> Advantages of advanced drilling technology. Ultimately, advanced drilling technology, such as poweredrotary steerable systems, leads to lower cost per barrel.

Powerful Drilling TechnologyThe PowerDrive vorteX system offers a uniqueset of capabilities for faster directional drilling(above). Its four main components are the powersection; the filters, bearings and transmission;the control unit; and the steering section. Theintegration of the power section and the rotarysteerable tool required engineers to developbearings and a transmission for the downholemotor that support the additional weight of the

rotary steerable tool and take the extra weighton bit (WOB), or load, from surface to drill morequickly. The other components of the PowerDrivevorteX system incorporate proven technologyfrom earlier systems.

The power section converts the hydraulicpower of the drilling fluid to mechanical powerat the bit. As drilling fluid enters the power sec-tion, it turns the rotor (above). A transmissionshaft, made more rugged for the demands of thisRSS, supplies torque from the rotor to the driveshaft, which in turn powers the rotary steerabletool and the drill bit. A specially developed elas-tomer, which seals the rotor, offers increasedfluid efficiency. The elastomer also provides betterchemical resistance to drilling muds and is ratedto higher temperatures than previous elastomers.

The power-section configuration can bechanged by using a rotor with a different num-ber of lobes. More lobes allow the rotor to turnat slower speeds with higher torque. The mostcommon configuration now in use, a 7:8 power

section in which the rotor has seven lobes, oper-ates at or below 130 rotations per minute (rpm)and generates approximately 20,000 ft-lbf[27.12 J] of torque in addition to the torque generated at surface by the drilling rig.

The bearings and transmission in any RSStransfer torque from the rotor and stator to thecontrol unit. The PowerDrive vorteX systemincludes larger bearings that transmit highertorque and load from the rotor to the bit. A filtersub prevents debris in the circulating fluid fromcoming in contact with the control unit andinterfering with reliable tool operation.

The control unit and steering section set thedrilling trajectory. Various stabilization optionsallow engineers to tailor the BHA to the desireddirectional response.

Given these powerful adaptations, it is notsurprising that approximately 90% of PowerDrivevorteX system deployments to date involve performance-drilling applications in which engineers seek higher ROPs by using the exceptionally high power of the system.

In about 5% of deployments, the PowerDrivevorteX system is desirable because low torque,restricted rotation rate or small circulatingpumps limit the capabilities of the drilling rig.The system is also useful for limiting casing wearby reducing the surface rotation rate of thedrilling rig while allowing the downhole powersection to rotate the bit. Minimal contactbetween the rotary steerable tool and the bore-hole wall also decreases casing wear.

The system also excels in shock-managementapplications, in which drillers strive to increase efficiency. For example, stick/slipeffects might occur at the bit, causing it tobecome stuck momentarily before freeing itself.Minimizing these and other effects that tend toslow the drilling process and damage the BHAimproves efficiency.

The problem of mechanical sticking involvesthe entire drillstring, not just the bit. Having a toolthat makes minimal contact with borehole wallsreduces the likelihood of mechanical sticking, butgood borehole cleaning is key in avoiding mechan-ical sticking. Use of the PowerDrive vorteX systemreduces the risk of sticking because everythingrotates at least as fast as the drillstring.3

In addition to the typical performanceattributes of an RSS—for example, high ROP,high efficiency and excellent directional control—the PowerDrive vorteX system optimizes performance of polycrystalline diamond compact (PDC) bits.4 Higher torqueoutput allows more aggressive PDC bits to beused, further increasing penetration rates.

6 Oilfield Review

Power section

Multiplestabilization pointsto customizeBHA response

Control unit

Steering section

Bearings andtransmission

Integratedfilter assembly

> Power section. The rotor turns within the statorto convert hydraulic energy into mechanicalenergy. The speed and torque output of the rotorcan be changed by using a rotor with a differentnumber of lobes. The rotor shown in this 5:6power section has five lobes.

Power section

Housing

Rotor

Stator

> Components of a powered rotary steerabledrilling system. The 9.625-in. tool is designed todrill 12.25- to 22-in. boreholes, and the 6.75-in.system drills 8.5-in. holes.

Winter 2004/2005 7

Avoiding Differential Sticking in the Caspian SeaAdvanced rotary steerable systems are playing akey role for Dragon Oil Plc. in the redevelop-ment of the LAM field in the Cheleken blockoffshore Turkmenistan in the Caspian Sea. Thisfield was initially developed using Russiandrilling technology in the 1980s. Dragon Oilbegan redevelopment with infill drilling in 2001and has recently drilled four wells as part of acontinuous drilling program initiated in November 2003.

S-shaped wells are drilled from the LAM 21production platform to access oil reserves in theRed Series reservoir, which comprises lateMiocene to early Pliocene interbedded sandstonesand claystones. Schlumberger was selected to provide directional drilling, measurement-while-drilling (MWD), logging-while-drilling (LWD) andwireline-logging services for the developmentwells. Drilling in the Cheleken block commonlyrequires high pressure overbalance in the upperpart of each hole section when that section nearsits total depth (TD). This is due largely to theoverpressured nature and thickness of the reservoir. Problems with differential sticking aretherefore common.

For the second of four development wells,LAM 21/107, Dragon Oil selected a conventionaldirectional drilling assembly with a downholemotor. Directional drilling assemblies tend tobuild angle in the Red Series reservoir, so the rigcrew reduced the weight on bit (WOB) to bettercontrol borehole trajectory. The reduction inWOB decreased ROP, which in turn increased therisk of differential sticking, especially whendrilling in the sliding mode. Eventually, all slidingwas stopped because of concerns about potentialdifferential sticking. Furthermore, a natural ten-dency for the well to drift 3°/30 m [3°/100 ft]during drilling meant that the well trajectory washeading outside the original target tolerances.

Dragon Oil invited Schlumberger to optimizethe drilling procedure for the next three wells.Schlumberger engineers proposed using thePowerDrive vorteX system to alleviate severalproblems. First, the powered RSS would main-tain the high rotation rates Dragon Oil specified.Higher ROP and the resultant reduction indrilling days would limit casing wear in uppersections of the wellbores. Finally, using a fullyrotating drilling system would greatly reduce thepotential for differential sticking by eliminatingdrilling in the sliding mode.

In the third well, LAM 21/108, Dragon Oildrilled 772 m [2,533 ft] of 8.5-in. hole in 66 hoursusing the PowerDrive vorteX system. By compari-son, a standard positive-displacement motor(PDM) assembly would have required approxi-mately 10 days to drill this section (above).

In addition to the high ROP, the poweredRSS maintained verticality in a 600-m [1,970-ft]borehole section through the reservoir, with 90%of the hole having less than 0.5° inclination. Thewells are typically planned with a vertical orlow-angle trajectory through the reservoir tominimize wellbore-stability problems. In theLAM 21/108 well, use of the PowerDrive vorteXsystem saved approximately seven days of rig time.

The PowerDrive vorteX system was alsodeployed in the fourth well drilled from the LAMplatform, LAM 21/109. In this well, ROP in the12.25-in. section was 204 m/d [669 ft/D] and175 m/d [574 ft/D] in the 8.5-in. section. In this case, the powered RSS saved approximatelynine days of rig time.

Dragon will continue its drilling program onthe LAM 10 platform, and the company plans tobuild on the gains made while drilling theLAM 21 redevelopment wells. PowerDrive vorteXsystems will be used in the 12.25-in. and 8.5-in.hole sections. Further upgrades to the rig anddrillpipe might also allow the use of PowerDrivevorteX technology in 6-in. hole sections.

Developing a Mature Field in EgyptBelayim Petroleum Company (Petrobel), a jointventure between Eni and Egyptian GeneralPetroleum Corporation (EGPC), has been usingPowerDrive vorteX technology to provide moreenergy and sufficient rotation rate to drill hard

3. Components of the bottomhole assembly below the power section rotate at the sum of drillstring and surface-rotary speed.

4. Besson A, Burr B, Dillard S, Drake E, Ivie B, Ivie C, Smith R and Watson G: “On the Cutting Edge,” OilfieldReview 12, no. 3 (Autumn 2000): 36–57.

> Faster drilling in the Caspian Sea. Development drilling with the PowerDrivevorteX system in the LAM field saved a number of days of rig time. The LAM21/107 (black curve) was drilled with a conventional downhole motor. Thepowered RSS used for the 8.5-in. section of the LAM 21/108 well (green curve)and the 12.25-in. and 8.5-in. sections of the LAM 21/109 well (red curve)drilled more quickly than the conventional PDM used in the LAM 21/107.

5,0000 105 15 2520 30 40

Number of days35 45 5550 60 7065 75 80

4,500

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LAM 21/107LAM 21/108LAM 21/109

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8.5-in. section

6-in. section

anhydrite stringers in the mature BelayimMarine field, offshore Egypt in the Gulf of Suez.This oil field, discovered in 1961, consists ofinterbedded sands and shales that have pre-sented a variety of challenges, such as severemud losses and differential sticking during wellconstruction, and formation damage thatbecame evident during production.5

Over the course of 40 years of developing andproducing this field, Petrobel has deployednumerous advanced technologies to improveproduction, including optimized drilling fluids,drill bits and well-placement technologies,NODAL production system analysis, stimulationand reperforating.6

The operator recently drilled several newdirectional wells to drain the field more effi-ciently. Key to adding new wells is constructingthem within the economic constraints of thefield. To meet the technical and financial objec-tives of the wells, Petrobel selected PowerDrivevorteX technology. Before drilling the wells,engineers simulated the performance of a con-ventional mud motor and the PowerDrive vorteXsystem, and they determined that the poweredRSS would offer a boost of more than 123% inROP compared with the mud motor. These oper-ations, which began in January 2003, were thefirst deployment of PowerDrive vorteX technol-ogy in Egypt, and the powered RSS proved vitalin avoiding stick/slip problems.

In the 113M-86 well, which targeted oil inthe Kareem formation, use of the PowerDrivevorteX system saved more than 10 days of rigtime—a total of US$ 600,000. The ROP was 47%higher than the best previous performance inthe field. In addition, the 12.25-in. section wasdrilled in a single trip, and the trajectory closelymatched the plan. The powered RSS saved atleast five rig-days per well in three other wells(left). Based on these results, Petrobel plans touse the PowerDrive vorteX system in the future.

Drilling Long Laterals in Steeply Dipping BedsIn a field in the foothills area of Alberta,Canada, an operator is drilling long horizontalwells that produce gas. The plan for one suchwell involved drilling out of the surface-casingshoe with an assembly capable of building inclination to 15° at a rate of 1.0°/30 m, andthen drilling a 2,260-m [7,415-ft] tangent sectionthrough steeply dipping formations.

To drill the build and tangent section moreefficiently, Schlumberger proposed using thePowerDrive vorteX system in combination withthe SlimPulse third-generation slim MWD toolsystem. Although the higher penetration ratesachieved with a powered RSS were an importantconsideration, the operating company alsowanted a system capable of maintaining thedesired trajectory through steeply dipping bedswithout drilling in the sliding mode as with aconventional PDM assembly. In addition, thecompany wanted to keep surface rotationsbetween 30 and 60 rpm to minimize the casingwear caused by rotation.

8 Oilfield Review

5. Elshahawi H, Siso S, Samir M and Safwat M: “ProductionEnhancement in the Belayim Fields: Case Histories,”paper SPE 68688, presented at the SPE Asia Pacific Oil and Gas Conference and Exhibition, Jakarta, April 17–19, 2001.Eissa WM: “Optimizing Drilling Parameters EnhancesHorizontal Drilling Performance,” paper IADC/SPE 72881,presented at the IADC/SPE Middle East Drilling Technology Conference and Exhibition, Bahrain, October 22–24, 2001.

6. An analytical tool used in forecasting the performance of the various elements comprising the completion andproduction system, NODAL analysis is used to optimizethe completion design to suit the reservoir deliverability,identify restrictions or limits present in the productionsystem and identify any means of improving production efficiency.

7. For broader discussions of RSS technologies and applications: Ghiselin D: “Steering Technology Takes a Leap,” Hart’s E&P 76, no. 10 (October 2003): 79.Hartley F: “Rotary Steerable Systems Provide Advan-tages, Opportunities,” Offshore 64, no. 4 (April 2004): 66,67–70, 72, 74.

8. “Working Together To Solve Problems,” in The New Ageof Drilling: From Art To A Science, a supplement to Hart’sE&P. Houston: Hart Energy Publishing LLP (February2004): 16.

> Directional drilling in the Belayim Marine field. The S-shaped Petrobel 113M-86 well (bottom) reacheda true vertical depth (TVD) of 2,730 m [8,960 ft] just below the oil-productive Kareem formation. In fourwells drilled with the PowerDrive vorteX system, Petrobel estimated that it saved more than five rig-days per well, with total savings of US$ 272,000 to US$ 600,000 per well (top).

2,3000 100 200 300 400 500 600 700 800 900 1,000 1,100

Vertical section, mAzimuth = 215.65° Origin = O N/S, O E/W

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Winter 2004/2005 9

The PowerDrive vorteX system providedmore efficient weight transfer to the drill bit andallowed the use of a much more aggressive bitdesign, increasing the ROP (left).

This powered RSS saved time and money inseveral ways. Higher penetration rates saved12 days of rig time, valued at more than CAD 400,000. The powered RSS produced asmoother borehole than a downhole motor, andallowed casing to be run quickly and easily (belowleft). Compared with experience in offset wells,this borehole required 56 fewer hours of reaming.

As in many successful oilfield operations, useof a single tool is not the only contributing factor. In this case, careful planning, optimalBHA design and teamwork in the office werealso factors in the positive outcome.

Driving AheadThe PowerDrive vorteX system combines anintegrated power section with a BHA thatrotates at least as fast as the drillstring. Theresulting increases in ROP are especially valu-able in areas where rig rates are high, yet thistechnology also provides a vital performanceboost in lower-cost operating arenas when rigcapabilities limit drilling performance. The PowerDrive vorteX system augments the capabil-ities of other rotary steerable systems by drillingcomplicated wells in tightly defined targetswithin formations that are hard, unstable, ordeep, or a combination of these.7

Development of additional rotary steerablesystems will likely continue at a rapid pace. Asdescribed in this article, the PowerDrive vorteXsystem, first deployed as a 9-in. tool for drilling12.25-in. holes in 2001 and deployed with fullyintegrated components in 2003, is already avail-able as a 6.75-in. system to drill 8.5-in. boreholes.

A high-output performance drilling motor, indevelopment for integration with PowerDrivevorteX systems, features a thin layer of elastomeron metal to maintain a more consistent shapethan elastomer alone, regardless of fluid pres-sure within the motor. This allows the new motorto effectively transmit even greater WOB fromsurface for faster, more efficient drilling. How-ever, the new motor will require a rig rated tohigher pressure and pumps capable of handlingthe cuttings volumes produced at higher ROPs.

In addition to Schlumberger research anddevelopment efforts, BP, Shell and Statoil arefunding development of a superslim rotary steer-able system based on PowerDrive vorteXtechnology (see “Rotary Steerable Technology:Pushing the Limit,” page 1).8 Technology develop-ers are proving to be as relentless as drillingengineers when it comes to pushing the limits oftechnology. —GMG

0

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> Directional drilling performance. This time versus depth plot compares thePowerDrive vorteX runs (black) with one of the faster drilling operationscarried out by a conventional PDM (gold) in the foothills area. The RSSsaved about 12 days of drilling time when it reached the end of the long tangent section.

> Smoother boreholes from the powered RSS. Density images of boreholeshapes from the adnVISION Azimuthal Density Neutron tool confirm that ahole drilled with a PDM (top) exhibits much more tortuousity than thesmooth borehole drilled with the PowerDrive vorteX system (bottom).

10 Oilfield Review

Expanding Applications for Viscoelastic Surfactants

Slaheddine KefiCambridge, England

Jesse LeeTimothy L. PopePhil SullivanSugar Land, Texas, USA

Erik NelsonConsultantHouston, Texas

Angel Nuñez Hernandez Petróleos de Venezuela S.A. (PDVSA)Barinas, Venezuela

Tom OlsenDenver, Colorado, USA

Mehmet Parlar Rosharon, Texas

Brian PowersBPBaku, Azerbaijan

Alistair RoyAllan WilsonBPAberdeen, Scotland

Allan Twynam BPSunbury, England

For help in preparation of this article, thanks to Curtis Boney,Ernie Brown, Steve Davies and George Hawkins, Sugar Land,Texas, USA; Jorge Gonzalez and Arthur Milne, Caracas,Venezuela; Satyaki Ray, Calgary, Alberta, Canada; and David Schoderbek, Burlington Resources Canada, Calgary.

ClearFRAC, ClearPAC, CoalFRAC, FMI (Fullbore FormationMicroImager), FracCADE, NODAL, OilSEEKER andPERMPAC are marks of Schlumberger. Alternate Path is a mark of ExxonMobil Corp.; technology licensed exclusively to Schlumberger. FANN is a mark of the Fann Instrument Company.

Recent developments in viscoelastic surfactants have expanded application of these

unique materials in new and challenging environments. From well completions to

stimulations, viscoelastic surfactant systems are improving well productivity and

hydrocarbon recovery.

Minute objects can have a disproportionateimpact on large-scale endeavors. A drop of inkcan darken a full glass of water, while splitting anatom causes a significant release of energy.Micelles—microscopic structures of water boundtogether by surfactant—are obscure to thenaked eye, but only a few volume percent areneeded to improve the efficiency and effective-ness of reservoir stimulation operations.1

Surfactants are used in many oilfield opera-tions, such as drilling and reservoir stimulation.2

Before 1950, stimulation treatments relied onflammable mixtures of napalm and gasoline tocreate viscous fluids capable of initiating andpropagating a hydraulic fracture.3 In the 1950s,engineers believed that introducing water into areservoir during a fracturing treatment causedformation damage, so wells were stimulated withviscous, or gelled, oils.

Researchers later found that water-base fracturing fluids were not as damaging to produc-tion as they first thought. In the 1960s, engineersturned to viscous solutions of guar, or guarderivatives, in brine.4

In the 1970s, the exploration and production(E&P) industry experienced an increase in

fracture stimulation as less permeable reservoirswere exploited. To stimulate deeper and hotterwells in these reservoirs, engineers needed fracturing fluids with higher viscosity and greaterthermal stability. In response, scientists developed a new generation of polymer-base fracturing fluids. Most often, guar polymers werecrosslinked with borate, zirconate or titanateions to generate high levels of viscosity.5

The 1980s saw advancements in laboratoryformation-damage evaluation techniques, alongwith a greater awareness of the fracture permeability damage caused by polymer-basefracturing fluids. To minimize polymer-inducedconductivity impairment, engineers began usingfoamed fracturing fluids. This reduced therequired polymer concentration by as much as50%. Formation damage from polymer residuewas reduced, and wells cleaned up faster andproduced with greater efficiency.

The next step occurred in the 1990s, whenscientists developed polymer-free aqueous frac-turing fluids based on viscoelastic surfactant(VES) technology. Since the first generation ofVES fluid systems, this technology has evolvedconsiderably. New chemical adaptations enhance

Winter 2004/2005 11

performance, and have been used to address awide variety of well environments and to createentirely new applications.

In this article, we review the evolution of VESchemistry in the oil field over the last decade asit progressed from a relatively obscure technol-ogy to mainstream use. Case histories from SouthAmerica, North America, the North Sea and theCaspian Sea demonstrate how these novel mate-rials help engineers optimize oil and gas assetperformance and improve hydrocarbon recovery.

From the BeginningIn 1983, the Dow Chemical Company introduceda family of surfactants later known as VES.6 They

were used as thickeners in consumer products,such as bleach, liquid dishwashing detergent andcosmetics. Their intriguing performance led

1. Micelle structures refer to a colloidal aggregation ofamphipathic molecules that occur at a well-defined critical micelle concentration.

2. Chase B, Chmilowski W, Marcinew R, Mitchell C, Dang Y,Krauss K, Nelson E, Lantz T, Parham C and Plummer J:“Clear Fracturing Fluids for Increased Well Productivity,”Oilfield Review 9, no. 3 (Autumn 1997): 20–33.

3. Chase et al, reference 2.

4. Guar is a hydrophilic polysaccharide derived from seedsof the guar plant. Highly dispersible in water and brinesof various types, it can be crosslinked by borax and othercompounds to yield high gel strength for suspendingsolids, such as sand and other proppants. Guar is com-monly used in fracturing fluids to generate the requiredviscosity. Guar has low thermal stability, is pH sensitive,and is subject to bacterial fermentation.

5. Ely JW: Stimulation Engineering Handbook. Tulsa: PennWell Publishing Company (1994): 79–97.

6. Chase et al, reference 2.

engineers at the Dowell Tulsa Technology Center,now Schlumberger, to explore ways of applyingVES technology in the oil and gas industry.

Surfactants are compounds whose molecularstructures contain both hydrophilic (waterattracting) and hydrophobic (water repelling)groups. Most surfactants consist of a hydrophilichead group and a hydrophobic tail group (aboveleft). When added to an aqueous fluid, surfactantmolecules combine to form structures known asmicelles. The hydrophobic tails of the micellesassociate to form a core that is surrounded bythe hydrophilic heads, isolating the tails fromcontact with water. Typically, micelles are spheri-cal in shape.

In the case of VES surfactants, when certainsalts are present in the aqueous fluid within aparticular concentration range, the micellesassume a rod-like structure similar to polymerstrands (above). These rod-like micelles becomeentangled, viscoelastic behavior develops, andfluid movement is hindered (left). A significantincrease in viscosity occurs as does the develop-ment of pseudosolid elastic behavior.7

12 Oilfield Review

> The molecular level. Viscoelastic surfactants exhibit a well-defined, hydro-philic head structure (right) attached to an articulated tail section with ahydrophobic end (left). When dispersed in specific brine solutions, tailsections associate, ultimately forming a worm-like micellular structure.

Hydrophobic tail group

Hydrophilic head group

> Chemomechanical effects and viscoelasticity.When blended with salt solutions at the correctconcentration, VES materials form rod-shapedmicelles that become entangled under staticconditions (top), thus imparting fluid viscosity andpseudosolid elasticity. When exposed to evensmall amounts of shearing energy, such as thatprovided by pumping the fluids, micelles readilybecome disassociated (bottom). Elasticity andviscosity decrease.

Static

Dynamic

Flow

dire

ctio

n

> Micrograph of micelles. Viewed through an environmental scanningelectron microscope, VES molecules dispersed in an aqueous solution areshown to associate, form rod-like structures and entangle, ultimatelygenerating viscosity.

0.1 micron

Winter 2004/2005 13

When micelles are disassociated by shearenergy, the rheological behavior of VES fluids is similar to water, or nearly Newtonian; yet viscosity and elastic behavior recover when thedisrupting energy is removed (right). The uniquechemomechanical properties that create VES viscosity readily lend themselves to shear thin-ning, static suspension, low static to dynamic transition-energy requirements and high particle-transport efficiency. VES fluids requireless energy to pump than more conventionalpolymer fluids, effectively reducing wellsitepump-horsepower requirements.

The viscosity of VES fluids may decrease withtemperature. However, increasing the surfactantconcentration or adjusting the salt concentrationcan reduce this temperature-related thinning.Unlike conventional polymer systems, VES viscosity does not degrade with time, and is predictable and easily modeled, coupling opera-tional simplicity with an efficient and effectivefluid design (middle right).

Early laboratory experiments showed that theviscosity of VES fluids is easily broken by contactwith hydrocarbons or dilution by formationwater. Produced oil or condensate alters theelectrical environment in the fluid causing themicelle shape to revert from rods to spheres (bottom right). Fluid viscosity falls because thenow-spherical micelles cannot become entan-gled. Alternatively, when VES fluids are dilutedby formation water, the surfactant concentrationeventually falls to a level at which insufficientnumbers of micelles are present to entangle, andviscosity is lost. Simple laboratory tests are oftenperformed to confirm the compatibility of VESfluids with specific produced hydrocarbons.

In the early 1990s, Schlumberger first appliedVES chemistry in PERMPAC viscoelastic surfactant gravel-packing fluid. New to the oil-field, this cationic surfactant was able toviscosify common completion brines—potassiumchloride, ammonium chloride, calcium chlorideor calcium bromide—to suspend and transportgravel.8 The VES concentration varied from 2.5 to6% by volume, depending on the anticipated tem-perature in a well.

Unlike gravel-packing fluids based on polymer viscosifiers, such as guar or hydrox-yethylcellulose (HEC), VES fluids leave little

> Improved viscosity. When compared with more conventional hydraulicfracturing-fluid systems like hydroxyethylcellulose (HEC) (blue), VES systems(red curve) provide higher viscosity at shear rates that are experiencedduring fracturing (left), while providing similar viscosity at the lower shearrates that are typical in tubulars and perforations (right).

10

0.01 0.1 1 10 100 1,000

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Flow regime

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osity

, cp

Viscosity Profile at 75°F [24°C]

2.5% viscoelastic surfactant

40-lbm/1,000 gal hydroxyethylcellulose

> Viscosity over time. ClearFRAC polymer-free fracturing fluids have sufficientviscosity for fracturing and other applications up to 275°F [135°C]. Whenexposed to elevated temperatures in laboratory tests, ClearFRAC HT fluidshows little loss of viscosity over time. The viscosity spikes shown at 25, 58,92 and 125 minutes are artifacts of the testing process.

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> Breaking viscosity. VES fluids can lose their viscosity in several ways. Oncontact with breakers, formation water or liquid hydrocarbons, micelles losetheir rod-like shape, collapsing into spheres. Once this occurs, micelles canno longer entangle; viscosity is lost and is generally unrecoverable.

Breaker or contact with

liquid hydrocarbon

Worm-like micelles Spherical micelles

+ =

7. Pseudosolid is a term describing materials that develophighly viscous gel structures, that may exhibit elasticbehavior and that require little energy to reduce the gel to liquid.

8. Cationic surfactants are surface-active agents typicallycomposed of fatty amine salts. They have a net positivecharge, and they are stable over a range of pH levels andin various salt solutions.

residue, which significantly reduces gravel-pack damage.9

PERMPAC surfactant was eventually used inhydraulic fracturing applications, forming thebasis for subsequent development of ClearFRACpolymer-free fracturing fluid. However, cost andtemperature limitations—140°F [60°C]—precluded widespread use in fracture treatments.

Schlumberger introduced the original ClearFRAC surfactant system in 1997. LikePERMPAC fluids, the system was built oncationic surfactant chemistry. The ClearFRACsurfactant proved to be stable in low-densitybrines at temperatures up to 200°F [93°C]. Witha high percentage of fracturing operations occur-ring at temperatures below 200°F, the market forVES fluids in fracturing was broad. In addition,the surfactant could be mixed continuously withbrine, and the resulting fluid system could befoamed, or energized, with nitrogen [N2].

The Challenge of Green Chemistry From the beginning, VES fracturing and gravel-packing fluids improved well performance.Building on this early success, these fluids havecontinued to evolve. By the late 1990s, the questfor new oil and gas reserves led operators to drilland complete wells in more challenging andenvironmentally sensitive areas.

The VES fluids introduced in the early 1980s were based on cationic surfactant chem-istry. Although effective from both an operationaland cost perspective, and environmentallyacceptable in most land-based locations, cationicsurfactants are not always dischargeable inmarine environments.

To address discharge concerns, Schlumbergerengineers and scientists began the developmentof noncationic viscoelastic surfactants. By early2000, researchers had discovered new anionicsurfactants capable of meeting both environmen-tal and functional demands.10

The result, ClearFRAC EF polymer-free frac-turing fluid, improved performance in somesituations, while providing a fluid that could bedischarged in environmentally sensitive areas,such as the Lake Maracaibo region of Venezuela.

In South America, many wells have beendrilled and completed in Lake Maracaibo, innorth-central Venezuela. Today, discharges from oil and gas operations are limited to products and materials that meet strict environ-mental standards.

Wells in the Bachaquero field of Lake Maracaibo generally produce from unconsoli-dated, highly permeable, Miocene sandstones. In

many cases, hydraulic fracturing stimulation hasproved effective for improving well performance.

Engineers at the Schlumberger field supportlaboratory in Las Morochas, Venezuela, evaluatedvarious ClearFRAC surfactants, ultimately select-ing ClearFRAC EF for its environmentalacceptability in marine environments, its low ten-dency to form emulsions with locally produced oiland its viscosity profile under predicted downholeconditions (top).

To improve well performance on steam injector Well BA-2233, engineers performed a fracturing operation generating a 0.6-in. [15.2-mm] fracture (above). Using a ClearFRAC EFcarrier fluid, just under 60,000 lbm [27,215 kg] of20/40 fracturing proppant was placed in the formation. Tip screenout (TSO) was observed10 minutes after pumping began, or two minutesafter the proppant entered the perforations.11

14 Oilfield Review

> Ensuring viscosity on Lake Maracaibo. Engineers evaluated the rheologyperformance of ClearFRAC EF fracturing fluid in laboratory tests using aFANN 50 rheometer. Tests assured engineers that the fluid would performsatisfactorily. Fluid viscosity (blue) remained stable as temperature increasedfrom ambient to 150°F [65°C]. Seven minutes into the test, a change in shearrate (orange) caused a shift in viscosity. Once the shear rate was reduced,viscosity returned to normal for the duration of the 40-minute test. Thestability of the viscosity while the fluid heats up simplifies fracturingengineering. Unlike polymer fluids that lose viscosity with temperatureincrease, the proppant-transport efficiency of VES fluids does not vary as the fluid heats during pumping.

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> Results of fracturing operations. The image generated by FracCADEfracturing design and evaluation software shows an estimate of fracture heightand width (left). The fracture extends about 80 ft [24 m] from the borehole(right). About 60,000 lbm [27,215 kg] of fracturing proppant was placed in theBA-2233 well in the Lake Maracaibo area. Most regions of the fracturereceived over 14 pounds of proppant, producing an effective fractureconductivity of 19,746 mD/ft [6,019 mD/m].

-1.00 0 1.00 0

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Winter 2004/2005 15

NODAL production system analysis predicted that oil production after fracturing andprior to steam injection would be around 200 B/D[32 m3/d]. Actual production after stimulationwas 209 B/D [33 m3/d], in line with NODAL analysis predictions.

Returning Thinner FluidsFracturing fluids serve two primary purposes: first,to provide the hydraulic energy that generates and

opens a fracture; and second, to place transportedproppant materials in the open fracture to main-tain a conductive pathway, or conduit, for linearflow into the wellbore. Once these tasks are performed, pressure in the wellbore falls and thefracturing fluid flows to the surface.

In field tests, engineers found that, comparedwith more conventional polymer fluids, signifi-cantly lower viscosity levels were required with

VES fluids to efficiently transport and place fracturing proppant (left). However, in somecases, even minimal viscosity levels could slowfracturing-fluid flowback during well cleanup.

By shortening the time required to clean up awell, commercial production can be achievedsooner. With this in mind, developers beganresearch on breaker chemistry for VES fluidsthat would provide in-situ viscosity reduction in acontrollable and predictable manner.

Viscosity reduction in VES suspensionsdepends on various factors, including the ionicenvironment, the temperature and surfactant-packing parameters.12 Early experiments showedthat, like produced hydrocarbons, chemicalbreakers cause the VES micelles to change shapefrom rods to spheres, collapsing the entangledmicellular structure that generates viscosity.

By late 1999, developers discovered breakersthat could be encapsulated and blended withproppant for delivery in a uniform and effectivemanner across the length of the fracture (belowleft). In a typical fracturing operation, once theproppant has been placed in the fracture,hydraulic pressure is removed and the fracturebegins to close. Capsules containing the ClearFRAC breaker are crushed inside the closing fracture, releasing the breaker. Thebreaker alters surfactant-packing parameters ofthe fracturing fluid: the micelles collapse, andviscosity is reduced, effectively improving fracturing-fluid flowback.

In field applications, the use of VES breakersimproves well cleanup and increases early gasproduction. Unwanted fluid foaming is reducedat surface, gas and liquid separation improves,and fracture conductivity is optimized. Whencomparing production curves from wells fracturedwith older polymer-base systems with wells frac-tured with VES incorporating breaker chemistry,production curves often become similar withtime. However, in the first 60 days or so, quickercleanup of VES fluids using encapsulated

> Outperforming polymers. In both laboratory and field evaluations,ClearFRAC HT fluids outperformed polymer-base fluids (red) in transportefficiency. At low shear rate, ClearFRAC HT fluids provide higher viscositiesthan polymer fluids (blue – left), while at higher shear rate (blue – right),much lower viscosities are observed.

Visc

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> Effectiveness of VES breakers. The viscosity of ClearFRAC fluids (blue) can be reduced by adding breaker compounds. Most often, breakers areencapsulated, coming in contact with the VES fluid as the capsules arecrushed during the postfracture period. On exposure to encapsulatedbreakers, as much as a 10-fold reduction in VES fluid viscosity is seen (gold–left). The performance of increasing breaker concentration at increasingtemperature is shown.

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6% ClearFRAC surfactant in potassium chloride(KCl) solution6% ClearFRAC KCl solution + 7 ppt* breaker6% ClearFRAC KCl solution + 10 ppt breaker6% ClearFRAC KCl solution + 15 ppt breaker

* ppt is parts per thousand

9. Parlar M, Nelson EB, Walton IC, Park E and DeBonis VM:“An Experimental Study on Fluid-Loss Behavior of Fracturing Fluids and Formation Damage in High Permeability Porous Media,” paper SPE 30458, presented at the SPE Annual Technical Conference and Exhibition, Dallas, October 22–25, 1995.

10. Anionic surfactants are surface-active agents having a net negative charge.

11. Tip screenout fracturing involves deliberately causingproppant to bridge at the fracture tip through pad depletion. Further fracture propagation ceases and continued pumping increases the fracture width.

12. The surfactant-packing parameter is affected by solution conditions such as temperature and surfactantconcentration. It may also be influenced by changes inmicellular chain length and dissymmetry that cause anincrease in the surfactant’s spontaneous curvature, ultimately determining whether surfactant’s molecules will form spherical or cylindrical micelles.

breakers produces substantial incrementalgas—wells go online faster enhancing return on investment (top).

Extending Thermal LimitsEngineers, scientists and developers applying

VES fluids achieved several milestones, includingenvironmental acceptance and engineered viscosity control. Now, as drilling environmentsextend into more extreme conditions of tempera-ture, depth and pressure, VES systems are alsoevolving to meet these challenges.

The versatility of viscoelastic surfactantsmakes possible the development of fluid systemsfor specific applications. In Canada, a new VES system was needed to address drilling challenges in the shallow-gas development areasin southern Alberta (below left). Marginal economics, stringent environmental regulationsand cold wellbore temperatures made it necessary for operators to seek new fracturing-fluid technologies.

Schlumberger engineers responded by developing ClearFRAC LT polymer-free fracturingfluid, a VES-base fluid designed to meet severalrequirements including use in low-temperatureenvironments. While performing in cold wellbores at temperatures below 100°F [38°C],the new fluid also proved economical in situa-tions demanding low-cost hydraulic fracturingsolutions. To meet Canadian environmentalrequirements, developers designed the ClearFRAC LT system to be compatible withnonchloride salt solutions, such as ammoniumnitrate and nitrogen foam fracturing methods.ClearFRAC LT fluids can also be formulated withpotassium chloride and ammonium chloride.

As with other ClearFRAC products, the ClearFRAC LT surfactant is mixed continuously,saving considerable time on location. Costs arereduced and more zones can be stimulated eachday. Field tests conducted on multiple wells inCanada showed improved well economics andlogistics, and the ability to stimulate marginalpay zones in low-temperature environments.

Modifications of the ClearFRAC LT VESchemistry have found application beyond low-temperature wellbores, for example inunconventional reservoirs such as coalbedmethane (CBM) deposits and fractured carbon-iferous, or carbon-rich, shales, which can bedifficult to produce. Globally these types of reser-voirs represent as much as 3,500 to 9,500 Tcf [99 to 269 trillion m3] of natural gas.13

Permeability is one of the most critical factors in CBM recovery. Without intervention,fluid and pressure transmission is, for the mostpart, dependent on coal cleats and the associatednatural coalbed fracture system (next page, top).14

Unlike gas in a conventional sandstonematrix, CBM gas is entrained in the coal systemby adsorption onto the internal surfaces of coal.In sandstone systems, reducing pore pressure to500 psi [3,447 kPa] often releases all entrainedgas, while in a CBM deposit, pressures as low as100 psi [689 kPa] are often required.

Whether fractures are natural or induced dur-ing drilling or completion, the combination of low permeability and low drawdown pressures

16 Oilfield Review

> Incremental gas. Data from field tests show that ClearFRAC fluids clean up faster (blue), producingmore gas in the first month of production than polymer-base fluids (red). This incremental gas(shaded box) can offset stimulation cost and improve return on investment.

Field Test of ClearFRAC Fluid with Encapsulated BreakerAv

erag

e pr

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Production curves

Shaded area indicates incremental gas production in first 35 days

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> Shallow-gas plays in southern Alberta. Low-temperature ClearFRAC LTfluid was first designed to help operators economically and efficientlystimulate wells in areas of southern Alberta (gold), Canada.

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Winter 2004/2005 17

makes CBM reservoirs sensitive to any restrictionsin flow. Conventional horizontal completions havedemonstrated some success in producing tightCBM reserves. However, producibility drops dramatically as natural permeability falls below 10 mD. Damage from drilling or fracturing fluidsfurther reduces producibility.15

When a coal seam is exposed to drilling orfracturing fluids, swelling can result from sorp-tion of water, gelled fluids or water containinglow concentrations of friction-reducing agentssuch as partially hydrolyzed polyacrylamide(PHPA). This often leads to substantial reductionof cleat porosity and permeability (right). Five-to tenfold irreversible reductions have beenreported.16 Further permeability damage canresult from the failure to remove fracturing-fluidviscosifiers or gells from natural microfractures.

The postfracturing removal of these materialsis dependent on initiating a pressure drop andproducing the fluid from the coal. At the lowpressures inherent in CBM reservoirs, sufficientenergy may not be available to efficiently cleanup residual polymer-base fracturing fluids.

When preparing to hydraulically fracture aCBM deposit, engineers must also consider sensi-tive environmental issues. As much as one-thirdof US CBM reserves are located in areas where

13. Fredd CN, Olsen TN, Brenize G, Quintero BW, Bui T,Glenn S and Boney CL: “Polymer-Free Fracturing FluidExhibits Improved Cleanup for Unconventional NaturalGas Well Applications,” paper SPE 91433, presented atthe SPE Eastern Regional Meeting, Charleston, West Virginia, USA, September 15–17, 2004.For more on CBM gas production: Anderson J, Simpson M, Basinski P, Beaton A, Boyer C, Bulat D, Ray S, Reinheimer D, Schlachter G, Colson L, Olsen T,John Z, Khan R, Low N, Ryan B and Schoderbek D: “Producing Natural Gas from Coal,” Oilfield Review 15,no. 3 (Autumn 2003): 8–31.

> New gas from shallow coal. Although challenging to produce, coal seams provide a source of unconventional natural gas in the form of coalbedmethane (CBM). CBM exists as gas adsorbed on the coal matrix or as free gas in coal fractures, or cleats. Cleats may vary in size from microscopic to those large enough to be seen with the naked eye (left). Cleats generally orient perpendicular to natural bedding planes. Good quality wireline FMI Fullbore Formation MicroImager images can define larger coalbed outcrop cleats. In this image, abundant cleats are seen (right). Bright colors on the static images indicate more resistive lithologies, such as coals, while dark colors are either shales, silts, ash or open fractures. Natural shearfractures within coal may also be present and are usually rotated at variable angles with respect to bedding planes. (Photo and FMI image courtesy ofDavid Schoderbek, Burlington Resources Canada, Calgary, and Satyaki Ray, Schlumberger Canada Ltd, Calgary; used with permission.)

COAL

Static Image Dynamic Image

FMI Fullbore Formation MicroImager Log

Dip Tadpoles0° 90°

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Traces of bedding

CoalSubvertical cleats

Rotated shear fractures Shaly coal

> Coalbed retained permeability. In laboratory return-permeability testing ona simulated coalbed, the nondamaging characteristics of polymer-free VESfluids (blue) are shown in comparison with polymer fluids (green and purple).

Coalbed Retained Permeability

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14. A cleat is a breakage plane found in coal deposits thatprovides natural conductivity through the coalbed.

15. Osman EA and Aggour MA: “Determination of DrillingMud Density Change with Pressure and TemperatureMade Simple and Accurate by ANN,” paper SPE 81422,presented at the 13th SPE Middle East Oil Show and Conference, Bahrain, June 9–12, 2003.

16. Puri R, King GE and Palmer ID, “Damage to Coal Permeability During Hydraulic Fracturing,” paper SPE 21813, presented at the SPE Rocky MountainRegional Meeting and Low-Permeability Reservoirs Symposium, Denver, April 15–17, 1991.

stringent environmental regulations control thecomposition of fluids that might come in contactwith potable groundwater.

Engineers at the Schlumberger Sugar LandProduct center (SPC) developed CoalFRAC nondamaging fracturing fluids specifically forCBM fracturing. CoalFRAC fluids are most oftennitrogen foamed and cause minimal sorptivedamage to coal cleats. As with other VES-basefluids, CoalFRAC fluids readily return to surfaceafter fracturing, avoiding potential permeabilitydamage associated with polymer-base fracturing-fluid residue.

Field tests in central Wyoming, USA, demon-strated VES fluid performance in unconventionalreservoirs. Initially, a six-stage fracture treatmentplaced 330,000 lbm [149,680 kg] of 16/30 meshproppant in the coalbed using a combination offoamed and nonfoamed conventional, polymer-base fracturing fluids that were not crosslinked.17

Since results were below expectations,Schlumberger and client engineers designed arefracturing program for the 600-ft [183-m]coalbed interval. Coalbed permeabilities rangedfrom 0.6 to 2 mD. Gas reserves were estimated at350 to 450 scf/ton [11 to 14 m3/t] of coal. Pumping

nine fracturing stages through coiled tubingusing CoalFRAC techniques, Schlumberger engineers placed 260,000 lbm [118,000 kg] of16/30 fracturing proppant using a nitrogen-foamed CoalFRAC fluid.

A combination of new fracturing techniquesand CoalFRAC VES fluid technology produced afivefold increase in initial production. More than100 CoalFRAC treatments have now been per-formed in North America. When compared withthe more common polymer-base fracturing-fluidtreatments, on average, production rates usingCoalFRAC fluids have improved 30 to 60% in bothCBM and carboniferous shale applications.

Operator interest in efficient fracturing fluidscontinued to expand from low-temperature appli-cations to much deeper and higher temperatureenvironments. Through 2002, VES stimulationfluids had proved effective at temperatures rang-ing from 40°F [4.5°C] to an upper limit of around220°F [104°C].

To address the need for VES fluids that could work effectively in high-temperature environments, scientists at SPC developed ClearFRAC HT polymer-free fracturing fluid, azwitterionic-base VES fracturing fluid specifically

for elevated temperature applications.18 TheClearFRAC HT system extends the operatingenvelope of VES surfactants to 275°F [135°C]while maintaining other attributes common toother VES fluids, such as low friction pressureand excellent proppant-carrying capacity. ClearFRAC HT fluids have low emulsion-formingtendencies, allowing them to be used in a broadrange of oil reservoir applications.

As with other VES-base fracturing fluids, theviscosity of ClearFRAC HT fluids is substantiallyreduced by dilution with formation brines, contact and mixing with hydrocarbons, or by theaddition of chemical breakers.

Improving Gravel-Pack PerformanceSand production is a serious problem in manyreservoirs, and operators go to great expense to minimize the effects of uncontrolled sandflow. Gravel packing, in its various forms, is commonly used to control sand flow into the production system.19

Increases in thermal stability, improvedbreaker technology and expanded compatibilitywith a variety of salt solutions have extended theapplications of VES fluids. Since their first intro-duction as a gravel-packing fluid, VES fluids areagain receiving attention from both sand-controland gravel-packing specialists.

In openhole gravel-packing operations, a carrier fluid transports and places specificallysized gravel in the annular space between thereservoir rock and the production assembly,often a slotted liner or wire-wrapped screen (left). The gravel acts as a filter, allowing formation fluid to flow from the formation to theproduction string while filtering out sand grainsand other formation fines. As with fracturingoperations, the conductivity, or ability of fluids to flow through the gravel pack, is key to maximizing well productivity.

Gravel packs must also be designed to provide uniform flow across the productionassembly. Poorly designed or implemented gravelpacks may subject the production assembly toareas of concentrated flow, or hot spots. In thecase of wire-wrapped screens, concentrated flowerodes the wire mesh, resulting in sand break-through and a shortened completion life thatmay lead to costly remedial workover or recompletion operations.

For prolonged gravel-pack life, engineersmust achieve uniform gravel placement and produced-fluid flow across the entire completion.Conductivity through a gravel pack can beimpaired by residual drilling or carrier-fluid

Oilfield Review

> Gravel placement with VES fluids. Placing gravel in extended-reach highly deviated wellbores is always difficult. Using VES fluids for proppant transport along with Alternate Path technology,engineers can minimize the risk of an incomplete openhole gravel pack. Shunt tubes attached to theoutside of the screen (top right) provide a path for the gravel-packing slurry to flow in the event of apremature screenout, or plugging.

CasingHeel Toe

Shunt tube NozzlesSlurry

Washpipe Blankpipe Gravel Screen Open hole Filtercake

Shunttube

Nozzle

WashpipeScreen

18

Winter 2004/2005 19

material left behind after flowback. Unlike manypolymer fluids, VES carrier fluids optimize graveltransport while leaving no damaging residue toimpair production.

During well construction, drillers attempt tominimize formation damage and drilling-relatedcomplications, such as stuck pipe, by reducingthe amount of fluid lost to a formation. Drillingfluids have multiple phases, often described ascontinuous and discontinuous phases. The continuous phase consists of a carrier fluid, mostoften water or oil along with salts and other compounds soluble in the carrier fluids. The discontinuous phase contains insoluble materials,such as weighting agents, drilled solids, polymersand solid-particulate fluid-loss reducers such ascalcium carbonate.

During drilling operations, the borehole isgenerally overbalanced—hydrostatic pressure isgreater than pore pressure. As the drilling fluidpushes against permeable reservoir rock, the formation acts as a filter and the continuousphase is forced into the rock pore spaces.Depending on the permeability and the size ofthe pore throats within the formation beingdrilled, small amounts of the discontinuousphase are deposited in the near-wellbore area,forming a filtercake, both internal and externalto the borehole face. As the fluid in the boreholecirculates, this process continues in a dynamiccycle of erosion and deposition.

Once the borehole is drilled, engineers usemechanical tools and chemical sweeps to pre-pare the borehole for an openhole completion.Regardless of the cleanup method, some quantityof residual filtercake and pore-throat solidsremains. If not removed, these materials migratefrom the reservoir rock into the gravel pack,potentially plugging flow paths, reducing conduc-tivity, impairing production and creating hotspots that shorten the life of the completion (above right).

To remove internal and external filtercakematerial, high drawdown pressures, greater than200 psi [1.38 MPa], may be required to initiateflow when filtercake is trapped between graveland formation. Industry data indicate that, with-out treatment, retained permeability afterflowback may be extremely low, sometimes lessthan 1% of original reservoir permeability.20

In the past, treatments to remove filtercakewere performed after the completion assembly andgravel packs were installed. This approachinvolved multiple trips into the hole to displace thegravel-pack carrier fluid and spot chemicals thatattack filtercake and other residual compounds.21

Today, engineers combine VES gravel-packcarrier fluids such as the ClearPAC fluid systemfor gravel packing, with enzymes and chelatingagent solutions (CAS) to attack the primary filtercake components—starches and calciumcarbonate [CaCO3] bridging agents. Removing ordegrading these compounds significantly reducesflowback-initiation pressure and allows degradedfiltercake material to pass through the gravelpack, minimizing permeability impairment andimproving well performance.

Implementation of a single-step gravel-packing and cleanup operation requires integration of well-construction and completiontechnologies. Through careful selection andengineering of the reservoir drilling-fluid design,

> Filtercake removal. Filtercake (left) can severely damage a gravel pack. If notproperly removed by mechanical and chemical means, the filtercake can flowback into the gravel pack during production, plugging flow paths and reducingpermeability and conductivity (right).

Mud

flow

Oil m

ud

Filtercakedepositedwhiledrilling

Completionfluid

Screens

Nondisplacedoil mud

Screensplugged byaggregatedcake fromborehole wall

Drilling Completion

17. Fredd et al, reference 13.18. A zwitterionic, or dipolar, compound carries both a

positive and negative charge. 19. For more on sand production and its control: Acock A,

ORourke T, Shirmboh D, Alexander J, Andersen G,Kaneko T, Venkitaraman A, López-de-Cárdenas J, Nishi M, Numasawa M, Yoshioka K, Roy A, Wilson A andTwynam A: “Practical Approaches to Sand Management,”Oilfield Review 16, no. 1 (Spring 2004): 10–27.

20. Brady ME, Bradbury AJ, Sehgal G, Brand F, Ali SA, Bennett CL, Gilchrist JM, Troncoso J, Price-Smith C, Foxenberg WE and Parlar M: “Filtercake Cleanup inOpen-Hole Gravel-Packed Completions: A Necessity or a Myth?,” paper SPE 63232, presented at the SPE Annual Technical Conference and Exhibition, Dallas,October 1–4, 2000.

21. For more on gravel packs and related technology: Ali S,Dickerson R, Bennett C, Bixenman P, Parlar M, Price-Smith C, Cooper S, Desroches L, Foxenberg B,Godwin K, McPike T, Pitoni E, Ripa G, Steven B, Tiffin Dand Troncoso J: “High-Productivity Horizontal GravelPacks,” Oilfield Review 13, no. 2 (Summer 2001): 52–73.

laboratory evaluation of cleanup chemistries,and evaluation of potential borehole conditions,VES fluids are helping engineers to uniformlyplace gravel and obtain consistent filtercakeremoval, particularly across long horizontal-borehole sections.

Deepwater Openhole Gravel PackingReaching for deep oil reserves in the Foinavenfield, about 190 km [118 miles] west of the Shetland Islands, in the UK sector of the NorthSea, BP operates two blocks in 400 to 600 m[1,312 to 1,969 ft] of water. Development of thefield began in late 1994. By 2003, BP had drilledand completed the world’s longest deepwateropenhole shunt-tube gravel-pack completion, thefirst step in accessing oil reserves estimated atmore than 250 million bbl [40 million m3].22,23

Initial development of the T25 reservoir in the Foinaven field consisted of a single horizontal-wellbore completion. The P110 wellreaches across 937 m [3,075 ft] of open hole,spans two sand bodies separated by a 162-m[532-ft] shale section, and accesses an estimated42 million bbl [6.7 million m3] of oil.

Various types of openhole completion designswere available to BP engineers when field development began in 1997. However, no develop-ment had been as challenging as the P110 well.With the high cost of operations and the riskinvolved in deepwater operations, considerableresources were dedicated to the planning anddesign of the P110 completion.

Engineers first examined whether more than900 m [2,952 ft] of horizontal borehole could beeffectively gravel packed, and if so, how. Usingnumerical simulations and friction data from anearlier large-scale yard test, engineers determinedthat openhole shunt-tube gravel-packing technol-ogy could ensure effective gravel placement inwellbores exceeding 900 m and potentially as longas 1,524 m [5,000 ft]. However, to stay below friction-pressure limits, flow rates during gravelplacement would need to be low, around 2.5 bbl/min [0.4 m3/min].

Effectively delivering gravel-pack sand at lowflow rates across a long horizontal boreholerequires a properly constructed borehole and acarrier fluid that is shear thinning, to minimizepressure loss while placing gravel across thesandface. Engineers determined that to minimize risk, and improve efficiency and production potential, a single-step gravel-packand cleanup completion was required.

Limited reservoir information and a lack ofcore data presented a variety of challenges, fromgravel and screen selection to developing synergistic, nondamaging drilling, gravel-packingand cleanup fluids.

The first challenge was to drill a high-qualityborehole avoiding excessive washouts and deviation since these could interfere with propersand placement during gravel-packing operations.Before drilling could begin, however, a detailedfluid-design program was initiated to select thecorrect reservoir drilling fluid (RDF).

This fluid-design program included a wellbore-stability study to determine zones ofweakness and the mud-weight, fracture-gradientwindow. Sidewall core samples from offset wellswere used to study shale characteristics andresponse to RDF exposure. Formation-damagepotential was also evaluated along with cakequality and liftoff pressure requirements usingstandard laboratory return-permeameter evalua-tion techniques.

Compatibility with completion and cleanup-fluid chemistries was key to the RDF design.Engineers selected components of the drilling-fluid system based on drilling efficiency, wellborestability and susceptibility to enzyme breakersand chelating agents.

Gravel selection was based on extensive offset-well sidewall core studies and laboratorysimulations. Dry-sieve, laser particle-size analysisand scanning electron microscopy techniqueswere combined to estimate the gravel grain sizein the Foinaven T25 sand. These results werethen used to develop a laboratory-analog artificial core-pack material.

Technicians used the artificial core materialfor slurry injection and prepack testing. Slurry-injection tests simulated formation sandmigration into the gravel pack during oil produc-tion. Prepack tests simulated the effects ofborehole collapse that could cause significantamounts of formation sand to migrate onto thegravel-pack face. Based on these test results, a30/50-mesh synthetic proppant was selected asthe best material to effectively control sand production and optimize production efficiency.

Gravel placement across the two horizontalproduction intervals was the next challenge. AVES-base ClearPAC gravel-pack carrier fluid wasselected for its shear-thinning, cleanup and prop-pant-transport characteristics, and its ability toincorporate and deliver filtercake cleanup chemi-cals uniformly across both gravel-packed sections.

The VES fluid allowed engineers to transportand place gravel across both production zones,

20 Oilfield Review

> Low skin with oil-base mud. The use of oil-base drilling fluids, water-basecompletion fluids and greater borehole inclinations produces lower mechanicalskin factors. Shown are theoretical changes in mechanical skin factors (red)from the vertical to horizontal where at about 60° deviation, the geometriceffect begins to dominate skin factors as indicated by the convergence of themechanical skin lines. When properly designed, an oil-base reservoir-drillingfluid followed by a VES gravel-packing fluid in combination with drilling high-angle wells with respect to bedding planes effectively delivers low mechanicalskin factor completions. In field tests, wells drilled with water-base mudsshow higher mechanical skin factors than did those drilled with oil-base muds.Oil-base drilling fluids may also mitigate low-angle skin damage.

10

89

7

56

4

23

1

-10

-2

-4-3

-50 10 20 30 40

Wellbore inclination, degrees50 60 70 80

Tota

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ion

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Water-base drilling fluidOil-base to water-base VES completions

Winter 2004/2005 21

together spanning 937 m [3,074 ft] of open hole.More than 36,300 kg [80,000 lbm] of gravel were placed in the well, covering 100% of theopenhole volume.

During well tests, the P110 well initial oil production rate was 20,500 B/D [3,258 m3/d],about 8,500 B/D [1,351 m3/d] above expectations.The well is currently producing sand free.

Extensive sidewall core analysis and laboratory tests allowed engineers to successfullysize gravel and completion screens. Results fromthese tests also guided RDF and VES transportand cleanup system design. Integrating welldesign, construction and completion processesproduced positive results—successful drillingwith water-base mud (WBM), 100% gravel-packplacement, effective filtercake cleanup, zero skin values, and production rates that wereabove expectations.

When Oil-Base Mud Is RequiredEven though water-base muds have improvedsubstantially since the mid-1980s, engineers andscientists have struggled to design cost-effectiveWBMs capable of emulating the inhibitive quality, lubricity and thermal stability performance of oil-base fluids.

Problematic openhole gravel-pack comple-tions in Azerbaijan led BP to switch fromwater-base RDF to synthetic oil-base mud(SOBM).24 Prior to 2003, six wells had beendrilled using water-base RDF, and then gravel-packed. In reservoir sections drilled with 81⁄2-in. bits, washouts of up to 18 in. [45.7 cm] were observed. Ledges in the irregular hole made borehole cleaning difficult, and ulti-mately resulted in a poor gravel-pack completion(previous page, top).

Working with service providers, BP engineerscarried out extensive laboratory testing todevelop a system of nondamaging RDFs and completion fluids capable of controlling the borehole during drilling and of providing a lowskin factor during completion.25

The reservoir consists of poor to moderatelysorted, fine to very fine-grained sands with amedian diameter of 85 to 200 microns requiring20/40 gravel-pack sand and 12-gauge screens tocontrol sand and fines migration.

Four reservoir sections were drilled withSOBM, ranging from 200 to 650 m [656 to 2,133 ft]thick and spanning two productive sands separated by a 120-m [394-ft] thick reactive shalesection. Reservoir pressure averaged 32 MPa at3,500-m [4,650 psi at 11,483-ft] true vertical depth (TVD).

Engineers drilled each reservoir section with10.5-lbm/gal [1,258-kg/m3] SOBM. As drilling progressed, technicians controlled filtercakequality by maintaining the drilled solids concentration below 2% and performed tests toensure that the RDF would flow through a 10-gauge completion screen, two sizes smallerthan required.

Once the driller completed the reservoir sec-tion, a wiper trip was made using mechanical-and chemical-cleaning systems to remove solidsand debris from the casing. The open hole belowthe casing was displaced with high-viscositywater-base fluid containing calcium carbonatesized to control losses into the reservoir rock, yetstill allowing passage through a 10-gauge wire-wrap completion screen. The cased-holesection was then displaced to completion brine.

To ensure complete gravel packing acrossmultiple zones, engineers recommended anAlternate Path completion. After the sandfacecompletion assembly was run into the hole, thewater-base calcium carbonate fluid was dis-placed with a sequence of completion fluids,optimized for this application through laboratorytesting. A ClearPAC carrier fluid provided adequate gravel transport, minimal friction pressure and good performance with the Alternate Path gravel-packing design.

At a rate of 6 to 7 bbl/min [0.9 to 1.1 m3/min],80 bbl [12.7 m3] of VES carrier fluid were pumped,followed by a 6-ppa (pounds of proppant added),20/40-mesh gravel-packing slurry, a 40-bbl [6.4-m3] VES postpad stage and an appropriatedisplacement volume of filtered brine.

After testing, two of the four wells were sus-pended for later production. However, initialwell-test results showed an average productionindex (PI) of 45, indicating excellent productionpotential.26 The other two wells were put on production after tests indicated skins of +2.2 and+2.4, 30 to 50% less than those seen with previous openhole gravel-pack completions.

Compared with other wells in the area, engineers calculated that 550 to 600 B/D [87 to95 m3/d] of incremental oil production wasachieved using an oil-base RDF followed by completion techniques using ClearPAC gravel-packing fluids.

Here and elsewhere in the world, ClearPACgravel-pack carrier fluids have contributed to thesuccessful outcome of difficult completions.Although sensitive to hydrocarbon contact, properly designed VES gravel-pack completionsystems can improve well productivity even whenapplied in conjunction with oil-base RDFs.

Less Water—More oilVirtually every oil reservoir is swept at least partially by water, from either natural aquiferpressure or waterflooding. Water movement dis-places oil and often determines the oil recoveryefficiency in a field. Although critical to the oil-production process, water production sometimesbecomes excessive.

Even the best field-management techniqueshave a limited ability to control excessiveamounts of produced water. In mature fields,water production may increase to the point thatit represents a majority of the liquid volumereaching the surface. Reports indicate that glob-ally, at least three barrels of water are generatedwith every barrel of oil produced.27 Liquid-handling systems often become overloaded,impacting efficiency and productivity. Eventually,the cost of dealing with produced water precludes field profitability.28

22. Shunt-tube, or Alternate Path technology, is used toensure a complete gravel pack around screens. If theannular space packs off prematurely, the shunt tubesattached on the outside of screens provide conduits forthe gravel-pack slurry, allowing gravel packing to proceedpast any blockage, or bridges, that may form around thescreens. For more on shunt-tube gravel packing: Acock etal, reference 19.

23. Wilson A, Roy A, Twynam A, Shirmboh DN and Sinclair G: “Design, Installation, and Results from theWorld’s Longest Deep-Water Openhole, Shunt-TubeGravel-Pack West of Shetlands,” paper SPE 86458, presented at the SPE International Symposium and Exhibition on Formation Damage Control, Lafayette,Louisiana, USA, February 18–20, 2004.

24. Parlar M, Twynam AJ, Newberry P, Bennett C, Elliott F,Powers B, Hall K, Svoboda C, Rezende J, Rodet V andEdment B, “Gravel Packing Wells Drilled with Oil-BasedFluids: A Critical Review of Current Practices and Recom-mendations for Future Applications,” paper SPE 89815,presented at the SPE Annual Technical Conference andExhibition, Houston, September 26–29, 2004.

25. The skin factor is a numerical value used to define the difference between the pressure drop predicted byDarcy’s law and actual values. Skin factors typically rangebetween negative 6 for stimulated high conductivity, suchas that obtained by hydraulic fracturing, to 100 or more forextreme damage and poor conductivity.

26. The productivity index (PI) is a mathematical means ofexpressing the capacity of a reservoir to produce fluids.PI is usually expressed as the volume of fluid producedat a given drawdown pressure at the reservoir face.

27. Veil JA, Puder M, Elcock D and Redweik R Jr: “A WhitePaper Describing Produced Water from Production ofCrude Oil, Natural Gas, and Coalbed Methane,“http://www.ead.anl.gov/pub/dsp_detail.cfm?PrintVersion=true&PubID=1715 (accessed April 16, 2004).

28. Arnold R, Burnett DB, Elphick J, Feeley TJ III, Galbrun M,Hightower M, Jiang Z, Khan M, Lavery M, Luffey F andVerbeek P: “Managing Water—From Waste to Resource,”Oilfield Review 16, no. 2 (Summer 2004): 26–41.

In late 1999, engineers and scientists atSchlumberger discovered a new application forVES fluids, acid diversion. During standardacidizing treatments, stimulation fluids follow the path of least resistance, preferentiallystimulating zones of higher permeability. Theseare often zones with higher water saturationswhere the relative permeability to water-basestimulation fluids, such as acids, is also higher.Hydrocarbon zones with lower permeabilities arestimulated to a lesser degree. Consequently,water production increases disproportionatelycompared with oil.

Frequently, the permeability contrastbetween water- and oil-bearing zones makesselective stimulation difficult. Earlier divertingtechniques relied on polymers and solids to plughigh-permeability zones. Unfortunately, both low-and high-permeability zones became plugged,doing more harm than good to production rates.

Research led to the development ofOilSEEKER acid diverter, a VES-base system thatcan be engineered for either sandstone or

carbonate reservoirs. In each case, OilSEEKERfluid selectively reduces injectivity in water-ladenzones, forcing the acid to enter zones with high oilsaturation (below).

During the development of OilSEEKER fluids,laboratory tests demonstrated effective diversionwhen the rheology of the diverting fluid isdirectly affected by the chemistry of formationfluids. In the case of OilSEEKER fluids, the aciddiverter maintains a gelled state while in contactwith water, but viscosity degrades when exposedto liquid hydrocarbon. Laboratory core-floodexperiments have shown that VES-base diversiontechniques can effectively divert acid from a20,000-mD sandpack to a 200-mD core used tosimulate a zone with lower permeability. Afterseveral treatment cycles, about 40% of the acidwas injected into the low-permeability core.29

In the Barinas field, located in southwestVenezuela, Petróleos de Venezuela S.A. (PDVSA)produces oil from low-permeability carbonatereservoirs containing a high percentage of sandand shale. High amounts of produced water, or

water-cut, are common, and the wells haveproved difficult to stimulate without increasingthe amount of produced water.

Completed in 1984, Well SMW9 initially produced 116 BOPD [18 m3/d] with 25% basicsediment and water (BS&W). In 1997, a matrixstimulation treatment was performed, increasingoil production to 250 B/D [40 m3/d], but alsoincreasing water production.

PDVSA and Schlumberger engineers evaluated the well in early 2003. At that time, thewell was producing about 51 B/D [8 m3/d] of oilwith a water/oil ratio (WOR) of about 75% (next page, top). As with many high water-cutwells, engineers believed that a reduction inWOR would substantially increase oil production.

The hydrocarbon-productive reservoir interval is a calcareous matrix with hard andcompacted dolomites, streaks of glauconite andhard limestone. Because of this geology, engineers were concerned that the use of common acids, such as hydrochloric acid [HCl],could damage the remaining productive zones.

22 Oilfield Review

Stimulating oil zones. During acid stimulations, OilSEEKER acid diverter (left – yellow) is pumped ahead of the acid solution (red). On contact with water-bearing zones, the diverting fluid increases in viscosity, forming a plug that effectively blocks access to water zones. In contrast, on contact withhydrocarbon-bearing zones, the OilSEEKER diverter thins, allowing the subsequent acidizing step to preferentially treat oil-bearing zones not blocked bythe diverting fluid (right – green oil zone).

Productionline

Production tankInjection line Open

Shale

Shale

Closed

Productionline

Production tankInjection line Open

Shale

Shale

Closed

Water Oil OilSEEKER acid diverter

OilSEEKER Viscosity

Acid

LM

H

VIS

LM

H

VIS

29. Chang FF, Acock AM, Geoghagan A and Huckabee PT:“Experience in Acid Diversion in High Permeability DeepWater Formations Using Visco-Elastic-Surfactant,” paperSPE 68919, presented at the SPE European FormationDamage Conference, The Hague, May 21–22, 2001.

30. For more on viscoelastic surfactant acid diversion: Al-Anzi E, Al-Mutawa M, Al-Habib N, Al-Mumen A, Nasr-El-Din H, Alvarado O, Brady M, Davies S, Fredd C,Fu D, Lungwitz B, Chang F, Huidobro E, Jemmali M,Samuel M and Sandhu D: “Positive Reactions in Carbonate Reservoir Stimulation,” Oilfield Review 15,no. 4 (Winter 2003/2004): 28–45.

Winter 2004/2005 23

Therefore, careful attention was paid to acid-stimulation design.

Schlumberger engineers designed an HCl-free, organic-acid formulation composed offormic and acetic acids. Bottomhole static temperatures were estimated at 270°F [132°C],so engineers selected the high-temperature version of the OilSEEKER fluid to divert the acidtreatment away from water-bearing zones.

In the field, engineers first pumped a solutionof oil and solvents, followed by viscosified brine,to clean up the wellbore. Next, the OilSEEKER

treatment was pumped into the formation, followed by organic acid. This process wasrepeated to assure adequate stimulation acrossthe 30-ft [9.1-m] production zone. The pressureprofile during pumping gave little indication ofexcessive fluid loss, suggesting that the acid wasmost likely being pumped into the oil-bearingzones of lower permeability.

During the first two months following simula-tion, engineers recorded an 253% increase in oilproduction coincident with a 24% decrease inBS&W production (above).

Whether used to simulate wells in new fieldsor in mature areas, selective acid stimulation canimprove well performance. Today, engineers cantreat only the oil-bearing zones by designing fluidtreatments using VES-base diversion, such as theOilSEEKER system.

A New Generation for VES Since their first use more than 20 years ago, VESsurfactants have evolved significantly, findingnew applications and benefits in the E&P indus-try. Today, engineers use VES fluids for hydraulicfracturing, gravel packing, acid diversion and ahost of other applications.30

New VES fluids are continually being devel-oped. One area of interest is polymer-free liquidcarbon dioxide [CO2] fracturing. The future willinclude ClearFRAC products specificallydesigned to stimulate wells in which hydraulicfracturing with liquid CO2 and the inherently lowdamage characteristics of VES fluids will signifi-cantly improve well productivity.

Engineers expect the intrinsically low frictionpressure of CO2 and VES systems to improvethrough-tubing stimulation by allowing higherpump rates at maximum treating pressure, partic-ularly when compared with older polymer-basefracturing systems.

As oil and gas operations reach greater depthsand increasingly treacherous environments, scientists and engineers are working to expandthe performance limits of VES-base systems. Eventhough these materials have been used for aquarter of a century, they continue to promisethe potential for new and exciting developmentsthat will improve operational efficiency andenhance hydrocarbon recovery. —DW> Effective stimulation with OilSEEKER acid diverter. After stimulation, oil production increased by

253% and basic sediment and water (BS&W) declined by 24%, demonstrating the effectiveness ofOilSEEKER acid diversion.

Beforestimulation 190 51 73

Barrels of fluidper day (BFPD)

Barrels of oilper day (BOPD)

Basic sediment andwater, % (BS&W)

BFPD increase, % BOPD increase, %

330 74 8293 72Design

350 49 84 253180Afterstimulation

> Increasing water production. With time, water production from mature wells often increases. ThePDVSA SMW9 well is no exception. By 2003, water represented 75% of the produced fluid from thiswell (purple).

Fluids Production Chart

1997 1998 1999 2000

Year

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24 Oilfield Review

Scientific Deep-Ocean Drilling: Revealing the Earth’s Secrets

Tim BrewerUniversity of LeicesterLeicester, England

Tatsuki EndoMasahiro KamataFuchinobe, Japan

Paul Jeffrey FoxTexas A&M UniversityCollege Station, Texas, USA

Dave GoldbergGreg MyersLamont-Doherty Earth ObservatoryPalisades, New York, USA

Yoshi KawamuraShin’ichi KuramotoJapan Agency for Marine-EarthScience and Technology Yokosuka, Japan

Steve KittredgeWebster, Texas

Stefan MrozewskiHouston, Texas

Frank R. RackJoint Oceanographic Institutions, Inc.Washington, DC, USA

adnVISION (Azimuthal Density Neutron tool), AIT (ArrayInduction Imager Tool), APS (Accelerator Porosity Sonde),DSI (Dipole Shear Sonic Imager), Formation MicroScanner,GeoFrame, geoVISION, GPIT (General Purpose InclinometryTool), HLDT (Hostile Litho-Density Tool), proVISION, RAB (Resistivity-at-the-Bit), SFL (Spherically Focused Resistivity), SlimXtreme, VSI (Versatile Seismic Imager) and WST (Well Seismic Tool) are marks of Schlumberger.For help in preparation of this article, thanks to John Beckand Ann Yeager, Texas A&M University, College Station,Texas, USA; Rosalind Coggon, Southampton OceanographyCentre, England; Javier Espinosa and Nathan Frisbee,

Webster, Texas; Agus Hadijanto, Tokyo, Japan; MartinJakobsson, Stockholm University, Sweden; Robert Kleinbergand Lisa Stewart, Ridgefield, Connecticut, USA; Herbert Leyton, Belle Chasse, Louisiana, USA; Dave McInroy, British Geological Survey, Edinburgh, Scotland; and Kerry Swain, NASA, Houston, Texas.Thanks also to the Integrated Ocean Drilling Program, andto Joint Oceanographic Institutions (JOI), Washington, DC,USA; Lamont-Doherty Earth Observatory, Palisades, NewYork, USA; and Texas A&M University, College Station, USA,for providing the Ocean Drilling Program material used inthe preparation of this article.

The oceans and their underlying sediments and rocks act as natural laboratories that

record the Earth’s dynamic processes from past to present. Scientific deep-ocean

drilling, sampling and borehole measurements collected during the past 40 years are

enhancing our knowledge of the Earth, giving clues to the distribution of mineral

resources, to global climate change and to potential natural disasters. While some

technologies used in the oil and gas industry are deployed for scientific research,

other methods and tools developed specifically for deep-ocean drilling are also

finding applications in the energy industry.

Understanding the past is critical to predictingthe future. The ocean floors and their underlyingsediments and rocks contain a high-resolutionrecord of both the Earth’s history and its currentconditions. Information locked within thesestrata has the potential to answer fundamentalscientific questions. Scientific ocean-drillingprograms provide keys to unlock this buriedtreasure trove of data, which leads to a betterunderstanding of climatic changes, natural haz-ards such as earthquakes, volcanic eruptionsand floods, and mineral and energy resources.Technologies commonly used in the oil and gasindustry for drilling, borehole measurementsand sampling play a major role in scientificocean drilling.

Seafloor drilling during the past 40 years hasled to exciting scientific discoveries. For exam-ple, in 1968, drilling confirmed that sedimentsand rocks flooring the south Atlantic becameincreasingly older with distance from the axis ofthe mid-Atlantic oceanic ridge, thereby verifyingthe plate tectonics hypothesis.1

Scientific deep-ocean drilling recovered evidence of massive marine gas hydrates in1982, in deepwater sediments offshore CentralAmerica.2 Gas hydrates are crystallized waterand gas, mostly methane [CH4], that form under

> Gas hydrate core sample recovered duringOcean Drilling Program Leg 204. The samples areabout 2.56 in. [6.5 cm] in diameter.

Winter 2004/2005 25

1. Le Pichon X: “Sea-Floor Spreading and Continental Drift,”Journal of Geophysical Research 73, no. 12 (June 1968):3661–3697.

2. Kvenvolden KA and McDonald TJ: “Gas Hydrates of theMiddle America Trench, Deep Sea Drilling Project Leg 84,”in Von Huene R, Aubouin J, Arnott RJ, Baltuck M, Bourgois J, Filewicz M, Helm R, Lienert B, McDonald TJ,McDougall K, Ogawa Y, Taylor E and Winsborough B: Initial Reports of the Deep Sea Drilling Project 84.Washington, DC: US Government Printing Office (1985):667–682.

3. Kleinberg LR and Brewer PG: “Probing Gas HydratesDeposits,” American Scientist 89, no. 3 (May-June 2001):244–251.

4. Collett T, Lewis R and Uchida T: “Growing Interest in GasHydrates,” Oilfield Review 12, no. 2 (Summer 2000): 42–57.

5. Kerr RA: “Signs of a Warm, Ice-Free Arctic,” Science 305,no. 5691 (September 2004): 1693.

6. Schlumberger logs were acquired since the beginning of scientific deep-ocean drilling with Project Mohole (reference 10). Schlumberger has also been involved inonshore scientific drilling programs, leading to new technology for the oil and gas industry, for example, anew drilling technology that combined rotary drilling andsandline core retrieval techniques. For more on continentalscientific drilling: Bram K, Draxler J, Hirschmann G, Zoth G,Hiron S and Kühr M: “The KTB Borehole—Germany’sSuperdeep Telescope into the Earth’s Crust,” OilfieldReview 7, no. 1 (January 1995): 4–22.

7. IODP is a global partnership of scientists, research institutions and government agencies. The US NationalScience Foundation (NSF) and Japan’s Ministry of Education, Culture, Sports, Science and Technology(MEXT) are lead members who make equal financial contributions. The balance of the funding is provided bythe contributing member European Consortium for OceanResearch Drilling (ECORD), and the Ministry of Scienceand Technology (MOST), China, an associate member.

conditions of high pressure and low tempera-tures (previous page).3 Hydrates have steadilygained recognition in the oil and gas industrybecause they are both a drilling hazard and apotential energy resource for the future.4

More recently, in 2004, drilling in the ice-covered Arctic Ocean at the crest of theLomonosov Ridge has provided preliminary evidence that the Arctic was ice-free and warmabout 56 million years ago.5 Scientists analyzingthe cores and log data hope to determine when,why and how the Arctic climate changed fromhot to cold, and to gain insight on current globalwarming trends. Scientists are also speculatingabout the possibility of oil and gas prospects inthe Arctic Ocean.

Important facilitators to these discoverieshave been advances in drilling, coring and logging technology. Borehole measurements,routinely collected in oil and gas wells, also playa major role in scientific ocean research by providing data in sections with poor or no corerecovery, and in linking core measurements withlarger scale seismic data. Schlumberger hasbeen involved in scientific deep-ocean drillingprograms since 1961, providing borehole measurements and working closely with scientists to develop technology to support theirscientific objectives.6

While many tools and techniques developedfor oilfield use are being applied in scientificresearch, technologies that advanced under sci-entific drilling programs are also useful in drillingfor oil and gas, particularly deepwater drillingand in logging-while-drilling (LWD) applications.

In this article, we first review the historicalcontext for scientific deep-ocean drilling andthen examine current and emerging technolo-gies, particularly for downhole measurements,that are essential to achieving the goals of scientific drilling. Finally, we describe the newIntegrated Ocean Drilling Program (IODP),which will offer flexibility in its use of diversedrilling capabilities in all ocean basins regard-less of water depth and geographic location.7

Historical ContextSeveral scientific deep-ocean drilling programspreceded the IODP. The earliest research program began with Project Mohole, followed bythe Deep Sea Drilling Project (DSDP) and theOcean Drilling Program (ODP), covering all theoceans with the exception of the ice-covered Arc-tic Ocean (next page, top). Seafloor sedimentswere sampled from 1,279 sites. Each of these pro-grams achieved significant milestones (belowand next page, bottom).

Project Mohole, conceived in 1958 and activefrom 1961 to 1966, utilized a converted US Navybarge, Cuss 1.8 The objective was to sample themantle by drilling through the Earth’s crust toreach the Mohorovicic discontinuity (Moho).9

This ambitious goal would require a drillstringlength of about 9,100 m [29,860 ft] to reach theMoho in water depths of 3,566 m [11,700 ft]between Guadeloupe Island, Mexico, and thecoast of Baja California, Mexico.10 This targetexceeded the deepest penetration achieved onland by 1,500 m [4,920 ft], and the water depthsexceeded the capabilities of offshore drillingoperations at that time. While the project didnot come close to reaching the Moho, it did set

the stage for scientific ocean drilling and led todevelopment of deepwater drilling technology,dynamic ship-positioning and new ship designsthat were later used in DSDP and ODP.

The DSDP began operations in 1968 with theGlomar Challenger drillship operated byScripps Institution of Oceanography.11 TheGlomar Challenger pioneered and refined theuse of dynamic positioning with multipointretractable thrusters to maintain ship position.This technology is still being used in oil and gasdrillships today. Borehole measurements werenot considered essential in those days—fewerthan 90 boreholes were logged, and then only ifcore recovery was poor and if time permitted.

The first DSDP scientific cruise, called a leg,uncovered evidence of salt domes, throughrecovery of core and wireline data, which alsocontained evidence of hydrocarbons below saltat abyssal water depths of 2,927 to 5,361 m[9,603 to 17,590 ft] in the Gulf of Mexico.12 Dis-coveries of tectonically active salt and deephydrocarbons encouraged oil and gas explo-rationists. Since the first commercial subsaltdiscovery by Phillips, Anadarko and Amoco in1993, exploration and production (E&P) in theGulf of Mexico continues to blossom.13

26 Oilfield Review

8. Project Mohole was funded by the US National ScienceFoundation and the US National Academy of Sciences.

9. The Mohorovicic discontinuity is the boundary betweenthe Earth’s crust and mantle. Oceanic crustal thickness,interpreted from seismic refraction results, ranges from3.6 to 5.5 km [11,800 to 18,045 ft].

10. Horton EE: “Preliminary Drilling Phase of Mohole Project 1, Summary of Drilling Operations,” Bulletin of the American Association of Petroleum Geologists 45,no. 11 (November 1961): 1789–1792.

11. DSDP was funded by the National Science Foundationand managed by the Joint Oceanographic Institutions for Deep Earth Sampling (JOIDES), a consortium of USoceanographic institutions. In 1976, the program wasexpanded to include other countries—France, Japan,Soviet Union, UK and West Germany.

12. Ewing M, Worzel JL, Beall AO, Berggren WA, Bukry D,Burk CA, Fischer AG and Pessagno EA Jr: Initial Reportsof the Deep Sea Drilling Project, Joint OceanographicInstitutions for Deep Earth Sampling (JOIDES). Universityof California, Scripps Institution of Oceanography, Vol 1.(August-September 1968).

13. Farmer P, Miller D, Pieprzak A, Rutledge J and Woods R:“Exploring the Subsalt,” Oilfield Review 8, no. 1 (Spring 1996): 50–64.

1961 1962 1963 1964 1965 1966 1967 1968 1969 1970 1971 1972 1973 1974 1975 1976 1977 1978 1979 1980 1981 1982 1983

DSDPMohole

1968DSDP Leg 1: discovery of salt domes in the Gulf of Mexico in 1,067 m [3,500 ft] of water depth

DSDP Leg 3: conclusive evidence of seafloor spreading and continental drift

1970Sonar-guided borehole reentry

DSDP Leg 13: first solid evidence of Mediterraneansea-drying events

1973Trials of heave compensation system

1974DSDP Leg 39: causal link between Earth’s 23,000-year processional cycle and large-scale climate change

1975Use of reentry cone to reenter borehole in 5,519 m [18,108 ft] of water depth

1979Trials of hydraulic piston corer to recover undisturbed sediment cores

1981Cores from DSDP Leg 82 (1981) and ODP Leg 148 (1993) giving evidence for microbes in oceanic basalt

1982DSDP Leg 84: recovery of 1-m long massive gas hydrate core offshore Costa Rica

1976Releasable bit to allow larger ID wireline sondes to log open hole in riserless environment

1978DSDP Leg 60 in Mariana Trench in 7,034 m [23,079 ft] of water depth

1961Positioning drillship in 3,570 m [11,713 ft] of water and testing drillpipe integrity with internal magnetic sondes

Mohole test hole confirms ability to sample pelagic sediment and basement rock in deep waters

> Time line of scientific ocean-drilling milestones. Important scientific discoveries (blue) andtechnological advances (black) during the Mohole project, Deep Sea Drilling Project (DSDP) andOcean Drilling program (ODP) are highlighted.

Winter 2004/2005 27

> Scientific deep-ocean drillsites from 1961 to 2003. The Mohole project (green) initiated in 1958, used a converted naval barge Cuss I to drill at two sitesnear La Jolla, California, USA, and Guadeloupe, Mexico, from 1961 to 1966. The Deep Sea Drilling Project (black) used the drillship Glomar Challenger todrill at 624 sites, from 1968 to 1983. During the Ocean Drilling Program (red) between 1984 and 2003, the drillship JOIDES Resolution sailed as far north as80° and as far south as 71° latitude, and drilled the next 653 sites.

DSDPODP

Mohole

1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004

ODP

1985Reentry of an 8-year-old borehole in 5,511 m [18,080 ft] of water depth

1989Openhole logging in 5,980 m [19,620 ft] of water depth

Leg 124E: use of diamond coring bits to drill through hard ocean crust

ODP Leg 125: discovery of serpentine mud volcanoes emanating from the mantle

ODP Legs 158 and 193: revealing the size and structure of active massive sulfide deposits, like those that form the basis of world-class mining sites

1991CORK borehole seals deployed for true in-situ borehole monitoring

1992ODP Leg 146: highest resolution record of oceanic environmental and biotic changes over the last 160,000 years; evidence of climate change cycles with periods as low as 50 years

1999ODP Leg 186: two seismic/ crustal deformation observatories installed in 2,000 m [6,562 ft] of water at 1,000 m [3,280 ft] below seafloor. Only 50 km [31 miles] apart, one area ends up being seismically active, the other not

1995Pressure core sampler recovery of core at high in-situ pressures

ODP Legs 164 (1995) and 204 (2002) revolutionize understanding of natural gas hydrate deposits

1996LWD in 5,056 m [19,214 ft] of water depth

1997ODP Leg 171B: recovery of pristine soft-sediment cores of the Cretaceous/Tertiary extinction boundary

2000ODP Leg 189: confirmed findings from DSDP Leg 29 (1973) that the separation of Australia from Antarctica produced massive ocean current and climate change– including the development of the Antarctic ice sheet

2001Real-time LWD in 4,791 m [15,718 ft] of water depth

2002Successful test of RAB Resistivity-at-the-Bitlogging-while-coringsystem

IODP

Geophysicslaboratory

Moon pool

Downhole measurements and auxiliary laboratories

Core, physical properties and paleomagnetism laboratories

Microbiology, paleontology and chemistry laboratories

Computer laboratory and lounge

Photography laboratory

Shipboard Laboratories

28 Oilfield Review

< Drillship JOIDES Resolution with seven floorsof on-board laboratories. The 143-m [466-ft]drillship features a seven-story laboratorycomplex to analyze the wide variety of coresand logs collected worldwide. The ship ispositioned over the drillsite by 12 computer-controlled thrusters that support the mainpropulsion system. Near the center of the shipis the moon pool, a 7-m [23-ft] opening in thebottom of the ship, through which the drillstringis lowered. The drillship is a virtual universitythat can house 50 scientists and techniciansand 65 crew members, with a stack of labora-tories on seven floors. The bottom two floors(not shown) have core-storage facilities. Atthe fantail of the ship, on the left, is a geo-physics laboratory, which contains equipmentthat gathers ship position, water depth andmagnetic information used in studying theseafloor topography.

> A Schlumberger engineer acquiring real-time LWD data in the downholemeasurements laboratory.

> An ODP scientist working on core descriptions. (Photographcourtesy of Texas A&M University.)

Winter 2004/2005 29

The ODP, the next phase of the scientificdeep-ocean drilling programs, used the JOIDESResolution drillship operated by Texas A&M University in College Station (previous page).14

The ODP drilled 1,700 boreholes in water depthsranging from 91 to 1,828 m [300 to 6,000 ft] withmore than 213,000 m [699,000 ft] of core recov-ery.15 With successful well-logging results, wirelineacquisition became an integral part of the ODP,with more than 56% of the boreholes logged.16

The past four decades of scientific oceandrilling have benefited from numerous technolog-ical advances in wireline logging, drilling andmeasurement technologies, coring and samplingtechniques and long-term borehole-monitoringdevices. The development of technologies toaddress challenges in scientific deep-oceandrilling was the result of close collaboration bythe scientific community and the service industry.

Challenges in Scientific Deep-Ocean DrillingThere are many challenges associated withdrilling in deepwater and ultradeepwater areas,where water depths exceed 183 m [600 ft] and1,524 m [5,000 ft], respectively. The scientificobjectives of the ocean-drilling programsrequired drilling in water depths far greaterthan those common in E&P operations. The pro-gram had to develop technology to drill withouta riser—a large-diameter pipe that connects thesubsea blowout preventer (BOP) stack to a float-ing surface rig—commonly used in offshore oiland gas drilling (right). When drilling with ariser, drilling fluid circulates down the pipe,through the bit, and returns back to the surfacealong with rock cuttings through the exterior ofthe drillpipe.

14. The Ocean Drilling Program was managed by JointOceanographic Institutions, Inc. (JOI)—a consortium of US oceanographic institutions. The operation andstaffing of the drillship and core retrieval from sitesaround the world were managed by Texas A&M University(TAMU). The Lamont-Doherty Earth Observatory (LDEO) atColumbia University, New York, USA, managed the loggingservices and site survey data bank. The funding for ODP was initially provided by the US National ScienceFoundation (NSF) and later expanded to include otherinternational partners including Australia, Belgium,Canada, China, Denmark, Finland, France, Germany, Iceland, Ireland, Italy, Japan, Korea, The Netherlands,Norway, Portugal, Spain, Sweden, Switzerland, Taiwanand UK.

15. ODP core repositories are located at Lamont-DohertyEarth Observatory, Palisades, New York, USA; ScrippsInstitution of Oceanography, California; Texas A&M University; and Bremen University, Germany.

16. Goldberg D: “The Role of Downhole Measurements in Marine Geology and Geophysics,” Reviews of Geophysics 35, no. 3 (August 1997): 315–342.

> Riser drilling. The riser is a pipe that extends from the drilling platformdown to the seafloor. Drilling mud and cuttings from the borehole arereturned to the surface through the riser. The top of the riser is attached tothe drillship, while its bottom is secured at the seafloor. A blowout preventer(BOP) placed at the seafloor between the wellhead and the riser providesprotection against overpressured formations and sudden release of gas. Theriser pipe diameter of up to 21 in. [53.3 cm] is large enough to allow thedrillpipe, logging tools and multiple casing strings to pass through.

Drillpipe

Seafloor

Drilling fluid is pumpeddown through drillpipe.

Riser

Blowoutpreventer

Drilling fluid and cuttingsflow up between thedrillpipe and the riser.

Surface casing

LWD tool

Drilling fluid and cuttingsflow up between thedrillpipe and the boreholeor casing.

Second casing

Open hole

Without a riser, the drilling fluid spills out ofthe top of the borehole onto the seafloor, anddoes not return to the surface (above left). Thisdoes not create a problem for the seafloor environment, because seawater is used as thedrilling fluid. However, because no solids areadded, no mudcake forms. Without mudcake, the

borehole is less stable, which may lead to bore-hole collapse. Technology and solutions had tobe developed to deal with problems of shipheave, wellbore stability, reentry of wells inmore than 5,000-m [16,405-ft] water depth,along with other technical issues.

In conventional drilling for oil and gas, compensation devices treat the riser as the nonmoving reference to correct for depth uncertainties. A major improvement for loggingin riserless wells was the development of a large-displacement heave compensator to reducedepth uncertainties arising from ship heave. The

30 Oilfield Review

> Riserless drilling. Seawater is pumped down through the drillpipe to cleanand cool the bit. The drilling fluid and the cuttings flow up between thedrillpipe and the borehole or casing, where they spill onto the seafloor and donot return to the surface.

Cuttings flow into ocean.

Drillpipe

Cuttings

Seafloor

Seawater is pumpeddown through drillpipe.

Surface casing

Drill bit

Second casing

Open holeLWD tool

Seawater and cuttingsflow up between thedrillpipe and the boreholeor casing.

> The reentry cone. A large 3.7-m [12-ft]diameter, funnel-shaped installation on theseafloor serves as a conduit for relocating apreviously drilled hole and for landing andsupporting the surface casing string. The reentrycone is released through the moon pool (top).(Photograph courtesy of Texas A&M University.)

10 3⁄4-in. casing

16-in. casing

Seafloor

Mud skirt

Reentry cone

13 3⁄8-in. casing

20-in. casing

Winter 2004/2005 31

wireline heave compensator (WHC) system measures the vertical motion of the ship with anaccelerometer and automatically displaces thehydraulic piston and unspools logging cable bythe required amount.17 The WHC can adequatelycompensate for heaves of up to 6 m [20 ft]. Anew programmable rotary winch compensationsystem, developed by Schlumberger, is currentlybeing tested on the JOIDES Resolution.

With flexible drillpipe more than 5,000 mlong hanging in tension from the derrick, start-ing a borehole in bare rock is quite a challengewithout a riser. In hard-rock settings such as themid-oceanic ridges, spudding a hole and keepingit open becomes trickier due to the brittle, fractured nature of the rocks encountered. ODPdeveloped the hard-rock reentry system to spudholes in difficult environments using a hydraulichammer drill. The hammer drill is run inside thecasing, and it simultaneously drills a hole andadvances the casing.18 In the oil field today, technology using standard oilfield casing to drillthe well and then leave it in place to case thewell eliminates drillstring tripping and canincrease drilling efficiency by 20 to 30%.

Another challenge in riserless drilling wasreentry into preexisting boreholes. Reentry maybe required for several reasons, such as replacing a bit, or when returning to the bore-hole on multiple legs. To replace the bit, forexample, the drillstring must be raised, a newbit attached, and the string lowered back to thebottom into the same drill hole. The formidabletask of reentering a borehole on the ocean floorwas accomplished with the use of sonar scanning equipment and a reentry cone. Thereentry cone assembly comprises a reentry funnel mounted on a support plate that rests onthe seafloor and a housing to support multiplecasing strings (previous page, right). The reen-try system is wide at the top, above the seafloor,and narrows at the bottom near the base of theseafloor, thereby making it easy for the funnel toguide the drillpipe into the borehole.

The reentry cone allows a borehole to bereentered on multiple legs to deepen the hole orto install a borehole observatory for long-termdownhole measurement and sampling.

ODP developed two primary types of bore-hole observatories. Downhole broadbandseismometers with a bandwidth from 0.001 to10 Hz and strainmeters were deployed atselected sites, primarily in seismogenic, orearthquake-prone, zones near Japan and in theeastern Pacific Ocean. The other type of bore-hole observatory consists of instrumentation toobtain in-situ recordings of formation temperature

and pressure, and sampling of fluid geochemicalproperties. Similarly, permanent downholegauges to monitor flow rate, pressure and tem-perature are routine in the oil field for real-timeproduction optimization.19

However, effective utilization of boreholes ashydrogeological laboratories required sealingthem from the overlying ocean water, and allowing the formation to return to a state ofequilibrium. This was made possible by a circu-lation obviation retrofit kit (CORK) system, first deployed in 1991, which isolates boreholes from the ocean water above the seabed (above).

Temperature and pressure data recorded over aperiod of months to several years are recoveredusing manned or unmanned submersibles.

17. Lorsignol M, Armstrong A, Rasmussen MW andFarnieras L: “Heave Compensated Wireline LoggingWinch System and Method of Use,” US Patent no. 6,216,789 (April 17, 2001).

18. Shipboard Scientific Party, 2000: “Leg 191 PreliminaryReport: West Pacific ION Project/Hammer Drill Engineering,” ODP Preliminary Report 191, http://www-odp.tamu.edu/publications/prelim/191_prel/191PREL.PDF(accessed December 10, 2004).

19. Acock A, ORourke T, Shirmboh D, Alexander J, Andersen G,Kaneko T, Venkitaraman A, López-de-Cárdenas J, Nishi M,Numasawa M, Yoshioka K, Roy A, Wilson A and Twynam A: “Practical Approaches to Sand Management,”Oilfield Review 16, no. 1 (Spring 2004): 10–27.

> Circulation obviation retrofit kit (CORK). After coring and logging operations are completed, theborehole is isolated from the ocean water above by placing a CORK—a mechanical borehole sealretrofitted to a reentry cone (top). The seal prevents circulation of fluid into or out of the borehole.The CORK can be fitted with a sensor assembly that extends down into the borehole to measure in-situ temperature, pressure, and chemical and biological properties over several years. An advancedCORK incorporates multiple seals to enable recording of time-series observations in several isolatedzones (bottom). A submarine or an ROV (remotely operated vehicle) is deployed to download the dataperiodically. (Photograph courtesy of Texas A&M University.)

Mud skirt

Reentry cone

Datalogger forpressure recording

Hydraulic samplingports (from screens)

CORK head

Casing

Screens

Bridge plug

Packer inflation line

Packers

Hydraulic sampling lines(from screens)

A new generation of advanced CORKs willincorporate multiple packers to isolate subsurface zones in the borehole to measuretemperature, pressure, fluid chemistry andmicrobiology in each zone.

Although the water depths and borehole conditions are extreme, ODP and Schlumbergerhave engineered methods and tools for boreholemeasurements to satisfy scientific goals and tooperate effectively in hostile environments.

Advances in Borehole MeasurementsBorehole logging measurements are now consid-ered as vital to the scientific goals of scientificdeep-ocean drilling as they are to the E&Pindustry. They provide a continuous record offormation properties under in-situ conditions, alink between core data and larger scale regionalseismic data, and are sometimes the only usabledata when core recovery is poor or nonexistent.

The need for tools in slimhole, high-pressure,and high-temperature environments and the

need for high-resolution tools to characterizethin beds have been the driving forces behindthe customization and development of new borehole tools.

Sometimes logging sondes have to be conveyed through a pipe diameter as small as3.8 in. [9.7 cm] to make measurements in holesizes exceeding 11.8 in. [30 cm] in diameter. Toovercome this difficulty, some oilfield tools havebeen made slimmer. In 1988, the FormationMicroScanner device, with an outside diameter(OD) of more than 4.5 in. [11.4 cm], was modi-fied to 3.7-in. [9.4-cm] OD. Another tool, theslimhole WST Well Seismic Tool, was customizedby addition of two horizontal geophones. Thisenabled determination of shear-wave velocityand anisotropy of underlying rocks from a vertical seismic profile survey.

The goal of increasing vertical resolution ofdownhole measurements prompted scientists atLamont-Doherty Earth Observatory in Palisades,New York, USA (LDEO) to develop the multi-sensor gamma ray tool (MGT) in 2001. This toolincreases resolution by common-depth stackingand summing of the data received from an arrayof four gamma spectrometry sensors spaced 2 ft[61 cm] apart.20 The MGT increases the verticalresolution of natural gamma ray log data by afactor of three to four over conventional loggingtools, improving characterization of thin layersand their correlation with core data.

Typically, a wireline-conveyed system cannotlog the top interval just beneath the seafloorbecause the drillpipe has to be lowered about 50 to 100 m [164 to 328 ft] to ensure wellborestability. Additionally, long tool strings oftencannot log the bottom of the borehole. Also, incertain difficult environments, for example,alternating layers of hard and soft rock such aschert-chalk sequences, the rocks deteriorateafter drilling, resulting in both poor core recovery and poor logs. In such cases, LWD toolsare of critical importance and provide the onlyin-situ measurements.21

For safety in unstable holes and to decreasedrilling time, an innovative solution of logging-while-coring (LWC) was developed during theODP. The RAB Resistivity-at-the-Bit tool was modified by incorporating annular batteries inthe drill collar wall and a new resistivity buttonsleeve. This allows an existing ODP core barrel topass through the RAB tool to carry out coringoperations while making azimuthal resistivityand gamma ray measurements (left). The LWC system provides precise core-log depth calibration and core orientation without anadditional trip, producing both time savings andunique scientific advantages.22

Obtaining Core SamplesImproving core recovery and obtaining uncon-taminated and unaltered samples are importantscientific objectives. Contamination from thedrilling process can affect studies of magneticproperties, fluid chemistry, microbiology, sedi-ment structure and core-sample texture. As withE&P operations, drilling and sampling technolo-gies in scientific ocean-drilling programs havebeen adapted to rock hardness and lithology.Specific innovations include advanced pistoncoring for sampling soft to medium-hardnessrocks, and an extended core barrel or a diamondcore barrel for coring medium to hard rocks.

Gas hydrate research, in particular, requiresretrieving samples at in-situ conditions. Duringconventional coring of hydrates, substantial volumes of gas escape as sediments are broughtto the surface. DSDP and ODP, respectively,developed the wireline pressure core barrel and

32 Oilfield Review

20. Goldberg D, Meltser A and the ODP Leg 191 ShipboardScientific Party, 2001: “High Vertical Resolution SpectralGamma Ray Logging: A New Tool Development and FieldTest Results,” Transactions of the SPWLA 42nd AnnualLogging Symposium, Houston, June 17-20, 2001, paper JJ.

21. Goldberg, reference 16.22. Goldberg D, Myers G, Grigar K, Pettigrew T, Mrozewski S

and Shipboard Scientific Party, ODP Leg 209: “Logging-While-Coring—First Tests of a New Technology forScientific Drilling,” Petrophysics 45, no. 4 (July-August2004): 328–334.

23. Pettigrew TL: “Design and Operation of a Wireline Pressure Core Sampler,” ODP Technical Note 17.College Station, Texas: Ocean Drilling Program (1992).

24. The European HYACINTH consortium developed thehydrate autoclave coring equipment (HYACE) system.Two types of wireline pressure coring tool, a percussiontool and a rotary tool, were developed together with themeans of transferring the core without loss of pressureinto a laboratory chamber.

25. Tréhu AM, Bohrmann G, Rack FR, Torres ME, Delwiche ME,Dickens GR, Goldberg DS, Gràcia E, Guèrin G, Holland M,Johnson JE, Lee YJ, Liu CS, Long PE, Milkov AV, Riedel M,Schultheiss P, Su X, Teichert B, Tomaru H, Vanneste M,Watanabe M and Weinberger JL: Proceedings of theOcean Drilling Program, Initial Report, Vol 204.http://www-odp.tamu.edu/publications/prelim/204_prel/204toc.html (accessed December 12, 2004).

26. Some of the wireline tools used on Leg 204 include the APS Accelerator Porosity Sonde, DSI Dipole ShearSonic Imager, Dual-Induction Tool (DIT), FormationMicroScanner, GPIT General Purpose Inclinometry Tool,HLDT Hostile Litho-Density Tool, Hostile EnvironmentNatural Gamma Ray Sonde (HNGS), Scintillation GammaRay Tool (SGT), SFL Spherically Focused Resistivity, VSI Versatile Seismic Imager and WST-3. Drilling andmeasurement tools were adnVISION, geoVISION, proVISION and the modified RAB-8 tool for use with the logging-while-coring system.

27. When gas hydrates disassociate from a sediment interval, cold spots can be felt with the hand and can be measured with thermal infrared cameras.

28. Kleinberg and Brewer, reference 3.29. Dickens GR: “Rethinking the Global Carbon Cycle with a

Large, Dynamic and Microbially Mediated Gas HydrateCapacitor,” Earth and Planetary Science Letters 213,no. 3 (August 25, 2003): 169–183.

30. Arroyo JL, Breton P, Dijkerman H, Dingwall S, Guerra R,Hope R, Hornby B, Williams M, Jimenez RR, Lastennet T,Tulett J, Leaney S, Lim T, Menkiti H, Puech J-C,Tcherkashnev S, Burg TT and Verliac M: “Superior Seismic Data from the Borehole,” Oilfield Review 15,no. 1 (Spring 2003): 2–23.

> Logging-while-coring system (LWC). The motor-driven core barrel (MDCB) passes through themodified RAB Resistivity-at-the-Bit tool to collectcore samples while acquiring resistivity andgamma ray measurements. (Adapted fromGoldberg et al, reference 22.)

Retrievable motor-drivencore barrel (MDCB), innercore tube OD = 2 7⁄8 in.

Annular battery

RAB ID = 3.45 in.

Azimuthal resistivityelectrodes on button sleeve,OD = 9 1⁄2 in.

Field-replaceable stabilizer

Bit-resistivity electrode

Core OD = 2.5 in.

Gamma ray sensor

Winter 2004/2005 33

the pressure core sampler to recover samples atin-situ pressures up to 10,000 psi [70 MPa].23

These tools are particularly useful for samplinggas hydrates and for measuring the volume ofgas released from these samples. The need forpressurized sampling, which maintains the coreat downhole pressure in an autoclave chamber,inspired a European consortium to develop anew suite of tools known as the hydrate auto-clave coring equipment—the next generation ofpressurized coring systems.24

ODP Leg 204, conducted from July to August2002, provided the opportunity to test a widevariety of new technologies and measurementtechniques.25 The scientific objective of the mission was to understand the occurrence anddistribution of gas hydrates offshore Oregon,USA. It marked the first use of simultaneous logging and coring with the LWC system andextensive tests of pressurized coring tools. Leg204 also deployed a wide range of Schlumbergerwireline tools and logging-while-drilling (LWD)tools, and included tools developed by ODP tomeasure in-situ pressure.26 Digital infrared cameras were used for the first time in an ODPoperation to scan core samples. This is done assoon as they are retrieved from the gas hydrateinterval to record the temperature anomalies.27

Focus on Gas Hydrates Gas hydrates have been known to exist inmarine sediments since the early days of DSDP,but they were judiciously avoided in the pastbecause of drilling safety issues. However, agrowing interest in hydrates as a potentialresource for energy and in their possible influ-ence on climate change has made hydrates oneof the focus areas in scientific ocean drilling.

Hydrates found in deepwater sediments atouter continental margins are usually stable.Gas hydrates become unstable when ocean temperature rises or depressurization occursdue to a reduction in confining pressure, causedfor example by a decrease in sea level or a lossin sediment overburden.28 This triggers therelease of methane—a powerful greenhousegas—into the Earth’s oceans and atmosphere.Scientists have raised questions about theimpact of gas hydrates on the carbon cycle andon global climate.29 However, there is greatuncertainty about how much hydrate and freegas are actually contained in marine sediments.It is therefore important to know where and howhydrates accumulate, and to monitor conditionsthat could change their stability.

To reduce this uncertainty, 45 boreholeswere drilled at nine sites on the bathymetrichigh known as Hydrate Ridge, in about 790 m

[2,592 ft] of water, offshore Oregon, USA (top). Several geophysical measurements thatcan help quantify gas hydrates were performedduring Leg 204. These include nuclear magneticresonance, resistivity imaging, sonic logging andvertical seismic profiles (VSPs). Borehole seis-mic data were acquired with the VSI VerticalSeismic Imager tool, which can record simulta-

neously at multiple stations. With differentsource-receiver configurations, offset VSP andwalkaway VSPs were acquired to image the sub-surface away from the borehole.30

The three-dimensional (3D) seismic dataacquired over the nine drilled sites on the southern Hydrate Ridge provide a regional structural and stratigraphic setting (above). A

> ODP Leg 204 drillsites on Hydrate Ridge, offshore Oregon, USA. (Adapted from Tréhu et al, reference 25.)

1250

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> East-west vertical slice through the three-dimensional seismic data. The seismic data show thestructural and stratigraphic setting of Hydrate Ridge at Sites 1244, 1245, 1246 and 1252. The high-amplitude reflector below the seafloor is the bottom-simulating reflector (BSR), and it corresponds tothe base of the gas hydrate stability zone. The BSR has a negative polarity, indicating high-velocitysediments containing gas hydrate that overlie low-velocity sediments containing free gas. Below theboundary AC, the seismic data are incoherent, and represent older, highly deformed sediments of theaccretionary complex at the core of Hydrate Ridge. Seismic reflections marked as A, B, B', Y and Y'are anomalously bright stratigraphic events. The depth scale in meters below seafloor (mbsf) is based on the assumption of a velocity of 1,550 m/s [5,085 ft/s] above 150 mbsf [492 ft] and 1,650 m/s[5,413 ft/s] below 150 mbsf. The reddish-orange lines indicate the depth of penetration at each site.(Adapted from Tréhu et al, reference 25.)

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high-amplitude reflector referred to as the bottom-simulating reflector (BSR) results from astrong velocity contrast between the high-velocity sediments containing gas hydrates anddeeper low-velocity sediments containing freegas. This reflector is interpreted as the base ofthe gas hydrate stability zone. Seismic velocitiesfrom the VSPs clearly resolve this velocitydecrease, indicative of the presence of free gasbeneath the BSR that occurs 129 to 134 m [423 to440 ft] below the seafloor.

Because hydrates are nonconductive, theelectrical resistivity of hydrate-saturated sedi-ments is higher than that of water-saturatedsediments. Resistivity images acquired by theRAB tool showed the azimuthal distribution ofhydrates in the drilled sediments (below). TheRAB data, in conjunction with 3D seismic data,guided subsequent coring, permitting an accurate sampling of zones rich in gas hydrate.31

Integrating cores with well logs and boreholeseismic and surface seismic data, each with different spatial resolution and sensitivity to gas

hydrate content, yields an estimate of the three-dimensional distribution of gas hydrate withinan accretionary ridge system.

The percentage of gas hydrate was estimatedusing different methodologies. While boreholemeasurements provide continuous spatial sampling, there are assumptions involved in theestimation of gas hydrate. Assuming that onlywater and gas hydrate fill the pore space, thepercentage of gas hydrate can be deduced byusing Archie’s relation to determine water saturation; the remainder being gas hydrate.32

This technique does not distinguish between gas hydrate and free gas.

Another approach used a controlled releaseof pressure from the core sample to enable measurement of the volume of gas stored withinan interval of sediment. This volume was thenused with established gas equilibrium curves toestimate the amount of gas hydrate or free gasin the core.

Results showed that high gas hydrate content—30 to 40% of pore space—is restricted

to the upper tens of meters below the seafloor at the crest of the Hydrate Ridge, while at theflanks of the ridge, the hydrates extend deeper.33 Understanding the heterogeneous distribution of gas hydrate is an important factorin modeling gas hydrate formation in marinesediments and the changes due to tectonics andenvironmental impact.

In 2000, the US Department of Energy(DOE), in consultation with other governmentagencies began an active effort to commencefundamental and applied research to identify,assess and develop methane hydrates as anenergy resource. Many countries, includingJapan, Canada and India, are also interested inthe potential of gas hydrates as an energy sourceand have established large gas hydrate researchand development projects, while China, Korea,Norway, Mexico and others are investigating theviability of forming government-sponsored gashydrate research projects.34

The US DOE gas hydrate joint industry project, led by ChevronTexaco, plans to drill two

34 Oilfield Review

> Data from Ocean Drilling Program Leg 204. Data acquired in Borehole 1249B include a deep-resistivity image from the RAB-8 tool (Track 2), resistivity(Track 3), gamma ray (Track 4), and core density (Track 5). Core photographs are shown on the left. High-resistivity intervals indicate the presence of gashydrate. Note that core recovery (Track 1) is intermittent and poor, whereas LWD measurements are continuous. (Adapted from Tréhu et al, reference 25.)

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Winter 2004/2005 35

sites in the deepwater Gulf of Mexico in 2005.Some of the techniques and lessons learned fromLeg 204 will be applied. While the primary goal isto learn how to safely exploit conventional hydrocarbon reservoirs beneath hydrate, theresults of the program will also allow a betterassessment of the commercial viability of marinegas hydrates.

All these technological achievements willadvance scientific ocean drilling studies in the21st century, although specific technologies areneeded in the next decade to address challengessuch as measuring high temperatures and pres-sures in seismogenic zones, conducting in-situsampling of fluids, retrieving uncontaminatedsediments and microbial life at in-situ conditions,developing enhanced downhole measurementsand installing long-term or permanent sensors.

As more data are acquired, data manage-ment is becoming another critical issue. In 1996,Schlumberger and ODP collaborated to test astabilized mount for the antennae utilized for high-speed data transmission from theJOIDES Resolution to shore-based data centers.An advanced version of this very small apertureterminal (VSAT) system is now common in IODP operations, offering almost total globalcoverage for data transmission and electronicand voice communications.

Finally, the enormous volumes of data andinformation produced by the ocean drilling pro-grams create the same issues that challengeE&P data management.35 These include legacydata gathered during the DSDP and ODP, anddata from the newly launched IODP. In additionto raw measurements, the copious volume of digital information, such as drilling reports, mudlogging data and cutting descriptions, must bemanaged properly and associated with the rawmeasured data to maintain contextual informa-tion and ensure integrity and validity of datamanaged by the system. Schlumberger has beencollaborating closely with JAMSTEC—the Japan Agency for Marine-Earth Science andTechnology—to design and build the prototypeof such a data management system. Integratingdata analysis capability into the data manage-ment system using GeoFrame integratedreservoir characterization system softwareallows users to directly access data from aremote site.

A New Era in Ocean Drilling The Integrated Ocean Drilling Program (IODP),a new program that began in 2004, builds uponthe experience and knowledge gained duringprevious scientific ocean drilling campaigns.

IODP is a global partnership of scientists,research institutions and government agenciesthat provides a more focused approach toexplore at greater depths and in previously inac-cessible areas (above). The scientific goals ofIODP are outlined in the initial science plan.36

Like their predecessors, IODP expeditions areproposal-driven and are planned after extensiveinternational scientific and safety reviews.

However, IODP differs significantly from anyof the previous programs because it uses multi-ple ships with diverse drilling capabilities. Themultiple platforms—riserless, mission-specificand riser—will enable drilling in areas thatwere previously inaccessible, such as on the continental margins, in shallow water less than20 m [66 ft] deep, in ice-covered regions of theArctic and in the ultradeep oceans.37

31. Tréhu AM, Long PE, Torres ME, Bohrmann G, Rack FR,Collett TS, Goldberg DS, Milkov AV, Riedel M, Schultheiss P, Bangs NL, Barr SR, Borowski WS, Claypool GE, Delwiche ME, Dickens GR, Gràcia E, Guerin G, Holland M, Johnson JE, Lee Y-J, Liu C-S, Su X,Teichert B, Tomaru H, Vanneste M, Watanabe M andWeinberger JL: “ Three-Dimensional Distribution of GasHydrate beneath Southern Hydrate Ridge: Constraintsfrom ODP Leg 204,” Earth and Planetary Science Letters 222, no. 3–4, (June 15, 2004): 845–862.

32. Archie’s experiments established an empirical relationshipbetween resistivity, porosity and water saturation. Formore on Archie’s equation: Log Interpretation Principles/Applications. Houston: Schlumberger Educational Services, 1989.

33. Milkov AV, Claypool GE, Lee Y-J, Torres ME, Borowski WS,Tomaru H, Sassen R, Long PE and the ODP Leg 204 Scientific Party: “Ethane Enrichment and Propane Depletion in Subsurface Gases Indicate Gas HydrateOccurrence in Marine Sediments at Southern HydrateRidge Offshore Oregon,” Organic Geochemistry 35, no. 9(September 2004): 1067–1080.

> Integrated Ocean Drilling Program (IODP). IODP is a multiple-platform operation involving ariserless drilling vessel, a riser drilling vessel and variety of mission-specific platforms. Japan, theUSA and Europe will support the implementing organizations for the various ships and platforms (see reference 7). (Photographs courtesy of JOI alliance, JAMSTEC and ECORD.)

Riserless drillship JOIDES Resolution

Joint OceanographicInstitutions (JOI Alliance)

The Japan Agencyfor Marine-Earth Science and

Technology (JAMSTEC)

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USA Japan Europe

Milkov AV, Claypool GE, Lee YJ, Dickens GR, Xu W,Borowski WS and the ODP Leg 204 Scientific Party, “In Situ Methane Concentrations at Hydrate Ridge Offshore Oregon: New Constraints on the Global GasHydrate Inventory from an Active Margin,” Geology 31(2003): 833–836.

34. Collett TS: “Gas Hydrates as a Future Energy Resource,”Geotimes 49, no. 11 (November 2004): 24–27.

35. Beham R, Brown A, Mottershead C, Whitgift J, Cross J,Desroches L, Espeland J, Greenberg M, Haines P, Landgren K, Layrisse I, Lugo J, Moreán O, Ochoa E,O’Neill D and Sledz J: “Changing the Shape of E&P DataManagement,” Oilfield Review 9, no. 2 (Summer 1997):21–33.

36. For more on the initial science plan: http://www.iodp.org/downloads/IODP_Init_Sci_Plan.pdf (accessed September 30, 2004).

37. Coffin MF: “Expeditions to Drill Pacific, Arctic, andAtlantic Sites,” American Geophysical Union, EOSTransactions 85, no. 2 (January 2004): 13–18.

The current US vessel, JOIDES Resolution,will be used in the first operational phase ofriserless operations, which lasts through 2005.38

The mission-specific platforms (MSPs) operatedby the European Consortium for Ocean ResearchDrilling will operate in shallow waters and ice-covered regions.39 As the name mission-specificsuggests, these drilling platforms could bedrilling barges, jackup rigs or seafloor drillingsystems, depending on the drilling environment.

The construction of the riser platform anddevelopment of related technologies were initi-ated in 1990 by MEXT (Ministry of Education,Culture, Sports, Science and Technology) inJapan. This program, called Ocean Drilling inthe 21st Century, was integrated into the IODP.40

The Japanese vessel, the Chikyu, meaning“Earth” will be a state-of-the-art, riser-equipped,dynamically positioned drillship. Chikyu willinitially reach a total depth of 10,000 m[32,800 ft], in water depths of up to 2,500 m[8,200 ft]. In riserless operations, Chikyu willbe able to drill in water depths of up to 7,000 m[22,970 ft].

In the future, Chikyu will be able to drillwith a riser in 4,000-m [13,120-ft] water depth toreach a total depth of 12,000 m [39,370 ft],allowing access to regions where the presence ofhydrocarbons or other fluids has previously pre-vented scientific drilling. Although riser drillingis commonly used for hydrocarbon explorationand development, it has never been used in suchultradeep environments. It will be possible todrill boreholes that are more stable, and thatcan penetrate zones with different pressures.Seismogenic zones in particular are difficult todrill because of heavy fluid losses associatedwith fractured intervals. Using this vessel,researchers can drill and install permanent sensors in seismogenic zones. Chikyu is expectedto be operational in late 2006 or early 2007.

IODP began its operations in 2004, with Expedition 301 using the riserless drillship andExpedition 302 using a mission-specific platform.The goal of Expedition 301 was to research thehydrogeology within the oceanic crust, determinefluid distribution pathways, establish linkagesbetween fluid circulation, chemical alterationand microbial processes and to determine therelationship between seismic and hydrologicalproperties.41 Expedition 301 was completed inAugust 2004, at the Juan de Fuca ridge, easternPacific Ocean. At this active hydrothermal system, molten lava from the Earth’s interior isreleased into colder ocean waters. Several hostile-environment wireline tools developed forthe oil and gas industry to explore deeper reser-voirs at extreme temperatures and pressureswere used in Expedition 301.42

Expedition 301 also collected sediments,basalt, fluids and microbial samples. Two new borehole observatories were established as deep as 583 m [1,913 ft] beneath the seafloor. Hydrogeologic tests were conducted in these boreholes.

In the future, a network of such boreholeobservatories will enable the study of fluid move-ment. Water circulation through the oceaniccrust has implications on land, particularlywhere oceanic plates sink beneath the continen-tal plates. For example, the recent volcanicactivity at Mount St. Helens, Washington, USA, inOctober 2004, is due to the combining of waterwith molten rock when the oceanic plate subducted into the Earth’s interior. Water indeep subduction zones is geochemically reactivewith the surrounding rocks, and may also affectdeep faulting.43

Expedition 302, completed in September2004, used multiple vessels in the Arctic (nextpage). The heavy ice-breaker, Sovetskiy Soyuz,provided upstream protection for the drilling

vessel and ice testing for the expedition, whileOden provided close ice protection, communications and scientific staging. Both vessels accompanied the converted drilling vessel Vidar Viking.

Expedition 302 focused on short-term climate changes. The past 56 million years ofArctic climatic history has been recovered from339 m [1,112 ft] of cores and about 150 m[492 ft] of wireline logs of marine sediments.Preliminary examination of the cores suggeststhat the ice-covered Arctic Ocean was once awarm place. Further research will provide cluesto climate changes that occurred when theEarth changed from a hot planet to a cold one.44

Some scientists believe that a brief spike in temperature could have been due to a largerelease of methane from gas hydrate deposits.45

The exact cause of this possible massive releaseof greenhouse gas is yet to be understood.

Cores from Expedition 302 have provided thefirst evidence of extensive organic material created by plankton and other microorganismsin ocean floor sediments, suggesting a favorableenvironment for oil and gas deposits.

Challenges AheadIn the coming decade, drilling and samplingtechnologies, borehole observatories and borehole measurements will play a pivotal role in answering questions about global climate change, natural disasters, and the occurrence and distribution of mineral andhydrocarbon resources.

The need for increased core recovery, whilemaintaining sample quality, is important for allIODP scientific objectives. Directional drillingand stress-orientation measurements may berequired to optimize core recovery.46

Contamination caused by drilling and sampling processes can jeopardize studies of

36 Oilfield Review

38. The Joint Oceanographic Institutions (JOI), Texas A&MUniversity, Columbia University, and Lamont-DohertyEarth Observatory compose the JOI alliance. The JOIcollectively provides coring, logging, laboratory outfitting,staffing, engineering, curation, data distribution and logistics for the riserless vessel. Texas A&M subcontractsthe riserless vessel, and Lamont-Doherty Earth Observatory subcontracts the logging services.

39. The mission-specific platforms are operated by the European Consortium for Ocean Research Drilling(ECORD), and are managed by the ECORD Science Operations (ESO), a consortium of European scientificinstitutions. The British Geological Survey (BGS) isresponsible for the overall ESO management. The University of Bremen in Germany is contracted by BGSfor curation, core repositories and data management.Logging and petrophysical activities are contracted byBGS to the European Petrophysical Consortium, comprising the University of Leicester, England; the Université de Montpellier, France; RWTH Aachen, Germany; and Vrije Universiteit of Amsterdam.

40. For more on Ocean Drilling in the 21st Century (OD21):http://www.jamstec.go.jp/jamstec-e/odinfo/iodp_top.html(accessed December 2, 2004).

41. Shipboard Scientific Party, 2004: “Juan de Fuca Hydrogeology: The Hydrogeologic Architecture ofBasaltic Oceanic Crust: Compartmentalization,Anisotropy, Microbiology, and Crustal-Scale Propertieson the Eastern Flank of Juan de Fuca Ridge, EasternPacific Ocean,” IODP Preliminary Report 301,http://iodp.tamu.edu/publications/PR/301PR/301PR.PDF(accessed November 3, 2004).

42. In addition to standard wireline tools, several hostileenvironment tools deployed on Expedition 301 include theAPS Accelerator Porosity Sonde, Hostile EnvironmentNatural Gamma Ray Sonde (HNGS), HLDT Hostile Litho-Density Tool and SlimXtreme AIT Array InductionImager Tool. For more on high-pressure, high-temperaturelogging: Baird T, Fields T, Drummond R, Mathison D,Langseth B, Martin A and Silipigno L: “High-Pressure,High-Temperature Well Logging, Perforating and Testing,”Oilfield Review 10, no. 2 (Summer 1998): 50–67.

43. http://www.iodp-usio.org/Newsroom/releases/exp_301_end.html (accessed November 7, 2004).

44. Kingdon A, O’Sullivan M and Gaffney O: “Arctic CoringExpedition (ACEX) Retrieves First Arctic Core,” posted on August 25, 2004, http://www.eurekalert.org/pub_releases/2004-08/sprs-ace082504.php (accessedDecember 10, 2004).

45. Revkin CA: “Under All That Ice, Maybe Oil,” The NewYork Times: posted on November 30, 2004,http://www.iodp.org/education_outreach/press_releases/nytimes_acex_article.pdf (accessed December 10, 2004).

46. Goldberg et al, reference 22.

Winter 2004/2005 37

microbiology, fluid composition and paleo-magnetism. The occurrence and distribution ofmicrobial populations are a focus of futureresearch. Samples will be collected from a rangeof tectonic and environmental settings that willutilize the multiple platforms in IODP. With riserdrilling, for the first time, direct samples will beobtained from the area of coupling between thecontinental and oceanic plates. Contamination-free samples are crucial to the success of thesestudies. Finally, pressurized coring techniqueswill need to be developed further to retrievesamples at in-situ conditions, maintaining thepressure and temperature. This is particularlyimportant in sediments containing hydrocarbonsand gas hydrates.

Another prime goal of future expeditions willbe to study seismogenic zones by drilling to theepicenter of earthquakes and placing permanentmonitoring devices that track temporal changesin temperature, pore pressure, fluid chemistry,tilt, stress and strain. Temperatures can reach

250°C [482°F] in seismogenic zones and 400°C[752°F] in hydrothermal areas. However, current downhole sensors can withstand temperatures only up to 150°C [302°F] for long-term monitoring.

Schlumberger Kabushiki Kaisha (SKK) Technology Center in collaboration with JAMSTEC has performed a feasibility study onpermanent monitoring technology and its appli-cability for long-term monitoring in scientificdeep-ocean wells. Generally, the temperatureand pressure ratings of the scientific instru-ments used in the past are not suitable. Anothermajor problem is the amount of power requiredto monitor seismicity continuously, for periodslonger than a year, and the reliability of thedownhole monitoring system. Schlumberger hasbegun a new project to develop low-powertelemetry and a power-delivery system for next-generation permanent monitoring sensors.

Scientific research on marine gas hydratescontinues to be a focus area in the IODP pro-

gram. Knowing the occurrence and distributionof gas hydrates, understanding their role in theglobal carbon cycle and evaluating their potential as an energy resource continue to beimportant objectives. The diverse drilling platforms will enable sampling and boreholemeasurements from different depths and envi-ronments. New technology will be needed, notonly to directly measure gas hydrate properties,but also to monitor pressure, temperature andfluid flow over extended time periods. Boreholeobservatories will play a vital role in the future.

Finally, the enormous quantity of data gathered over the coming years—seismic surveys, logs, cored samples, data from boreholeobservatories, documents and reports—must bestored in databases for easy access by the global scientific community. A continuing close partnership between the scientific communityand service providers is necessary to developtools and processes to address these challengesin the years ahead. —RG

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< An example of an MSP operation (Expedition 302) in the Arc-tic. The first Arctic coring expedition (ACEX) was conductedfrom August to September 2004, at the crest of the LomonosovRidge in the central Arctic Ocean (left). The Vidar Viking drill-ship (right) was protected by two icebreakers Oden andSovetskiy Soyuz. Vidar Viking drilled five boreholes at four sites,and a 339-m [892-ft] long sedimentary sequence was recoveredin the cores. (Photograph courtesy of M. Jakobsson, IODP.)

38 Oilfield Review

Reducing Uncertainty with Fault-Seal Analysis

Kip CervenyBP AlaskaAnchorage, Alaska, USA

Russell DaviesRock Deformation Research (RDR) USA Inc.Dallas, Texas, USA

Graham DudleyRichard FoxBPAberdeen, Scotland

Peter KaufmanCambridge, Massachusetts, USA

Rob KnipeRock Deformation Research LtdUniversity of LeedsLeeds, England

Bob KrantzConocoPhillipsHouston, Texas

For help in preparation of this article, thanks to Karen Dawe,Geological Association of Canada, St. John's, Newfoundland,Canada; Jayne Harnett, RDR, Leeds, England; and DavidMcCormick, Cambridge, Massachusetts, USA.FMI (Fullbore Formation MicroImager), MDT (Modular Formation Dynamics Tester), OBMI (Oil-Base MicroImager),Petrel and RFT (Repeat Formation Tester) are marks of Schlumberger.

Oil and gas reservoirs in faulted siliciclastic formations are difficult to exploit. By

integrating seismic data, detailed core information, and wellbore and production

data, geoscientists can now model fault behavior and incorporate the results into

reservoir fluid-flow simulators. This integrated process improves prediction of fault

behavior, and reduces the uncertainty and risk associated with complex traps.

A fault can be a transmitter of or barrier to fluidflow and pressure communication. Categorizingfault behavior within these extremes is important for hydrocarbon drilling, explorationand development. Modern fault-seal analysismethods utilize seismic data, structural and microstructural information from high-resolution core analysis, and wellbore and production data to predict fault behavior and toreduce uncertainty and risk in faulted silici-clastic reservoir exploitation.

Sealing faults may be a primary control onthe trap in many hydrocarbon reservoirs, butthey may also transform a relatively large andcontinuous hydrocarbon reservoir into compart-ments that then behave as a collection of smallerreservoirs. Each compartment may have its ownpressure and fluid characteristics, hamperingefficient and effective field development and subsequent hydrocarbon recovery.

Faults that do not form a seal may prevent oiland gas from accumulating as hydrocarbons formand migrate through structures in the sub-surface. Open and permeable faults within anestablished reservoir may also cause serious lost-circulation problems during drilling operations.The loss of drilling mud can be expensive anddangerous, and can result in the abandonment ofwells. Whether detrimental or beneficial, faultsand their behavior need to be understood bygeologists and engineers to successfully exploreand extract hydrocarbon reserves.

Recent developments in fault-seal predictionhave focused on two separate but interrelatedaspects of faulting: fault architecture and fault-rock properties. The fault architecture refers tothe fault shape, size, orientation and inter-connectivity. It also refers to the distribution ofthe overall fault displacement into multiple subfaults. Horizontal fault length may rangefrom millimeters, in the case of microfaults, tohundreds of kilometers. For example, the SanAndreas fault in California, USA, is more than800 miles [1,290 km] long. Detailed studies inoutcrops and in the subsurface have shown thatlonger faults usually comprise interconnectedshorter faults. The fault clusters form a fault-damage zone or an interconnected halo of faultsat a range of scales that may have a large cumulative impact on reservoir behavior. Thedisplacement of the major and minor fault segments within the reservoir juxtaposes thereservoir across the fault against dissimilarlithologies, which may impact the fluid flow.

The rock properties that develop within thefault zones affect a fault’s ability to seal. Theseproperties are affected by the local facies, reservoir-fluid types and saturations, pressuredifferentials across faults, fault-zone architec-tures, burial and fault histories, andjuxtaposition of the lithologies across faults.1 Inaddition, pressure and phase changes duringreservoir development compound the complexityof analyzing fault-seal behavior.2

Winter 2004/2005 39

Modern methods in fault-seal analysisimprove the prediction of fault behavior in thesubsurface and reduce the uncertainty inexploiting faulted siliciclastic reservoirs. Thisarticle summarizes methods of fault-seal prediction and the associated uncertainties. Abrief introduction to basic fault theory helpsdefine the fundamental causes, types and characteristics of faults before presenting amore detailed characterization of the process offault-seal behavior and prediction. Also dis-cussed are oilfield technologies that are used tomeasure and predict fault characteristics. Case

studies from Hibernia, Newfoundland, Canada,and Prudhoe Bay, Alaska, USA, demonstrate howa better understanding of fault sealing improvesclastic reservoir simulation and development,thereby reducing uncertainty and risk.

Basic Fault Mechanics, Architecture and PropertiesWhen rocks or rock layers are subjected to tectonic stress, they bend, break, or do both. Inits simplest form, a fault is a planar break, or failure surface, in rock across which there isobservable displacement, or slip. Contraction

1. Facies designations represent the overall characteristicsof a rock unit that reflect its origin and differentiate theunit from others around it. Mineralogy and sedimentarysource, fossil content, sedimentary structures and texture distinguish one facies from another.

2. Davies RK and Handschy JW: “Introduction to AAPG Bulletin Thematic Issue on Fault Seals,” American Asso-ciation of Petroleum Geologists Bulletin 87, no. 3 (March2003): 377–380.Yielding G, Øverland JA and Byberg G: “Characterizationof Fault Zones for Reservoir Modeling: An Example fromthe Gullfaks Field, Northern North Sea,” AmericanAssociation of Petroleum Geologists Bulletin 83, no. 6(June 1999): 925–951.Jev BI, Kaars-Sijpesteijn CH, Peters MPAM, Watts NLand Wilkie JT: “Akaso Field, Nigeria: Use of Integrated 3-D Seismic, Fault Slicing, Clay Smearing and RFT PressureData on Fault Trapping and Dynamic Leakage,” AmericanAssociation of Petroleum Geologists Bulletin 77, no. 8(August 1993): 1389–1404.

and extension induce shear failure in rocks. Thedirection of the principal stresses dictates theorientation of the failure plane, or fault. Thestrength of the rock controls the magnitude ofthe shear stress necessary to break the rock.

Although oversimplified, the Andersoniantheory of faulting, developed by geologist E.M. Anderson in 1951, is still widely used as abasis to describe the fundamentals of fault orientation in failure.3 Anderson described thethree basic fault types—normal, reverse andwrench, or strike-slip—relative to the maximumregional stress orientations. This theory assumesthat one of the principal stresses—σ1, σ2 or σ3

in order from greatest to least magnitude—orthe lithostatic load, is always vertical, and thatthe others are orthogonal and horizontal. Thetheory predicts that faults will form as two con-jugate planes with the following threerelationships between fault orientation andprincipal stresses:• faults form at ± 30° to the σ1 direction• faults form at ± 60° to the σ3 direction• the line formed by the intersection of

conjugate fault planes will be parallel to σ2.These relationships are significant because if

geologists know the principal stress directions,they can predict fault orientations. If the relative magnitudes of the principal stresses arealso known, geologists can predict fault types(above left).

At the seismic map scale, however, faults arerarely planar because of perturbations in thestress field caused by heterogeneities andanisotropy in the rocks. More commonly, faultsare composed of separate segments with distincttips defined by lines of zero displacement. Thelinkages may occur as hard links where thefaults tips connect, or soft links where the fault-tip geometry is influenced by an adjacent faultthat lacks a physical connection.4 The displace-ment of the stratigraphy across a fault varies ina systematic pattern from zero displacement atthe fault tips to a maximum near the fault center. Anomalies in the systematic distributionin throw reflect the complexities in the lithologyand adjacent fault segments.5 Fault complexitiespreclude a simple interpretation of the fault orientation, geometry and architecture.

A fundamental step in evaluating faultbehavior and sealing properties is mapping thefaults and constructing fault-plane throw andjuxtaposition maps at the seismic scale (left).6

The limits of seismic resolution, however, intro-duce uncertainty in the throw mapped acrossthe fault and do not allow the mapping

40 Oilfield Review

> Relating fault types to stress orientation. The Andersonian theory explains the three main fault typesrelative to the principal stress orientation. These include the normal-fault style, in which σ1, thelargest in-situ stress, is vertical (top); the reverse-fault type, in which σ1 is horizontal, and σ3, thesmallest in-situ stress, is vertical (middle); and the wrench, or strike-slip, fault type, in which both σ1and σ3 are horizontal (bottom).

Normal-Faulting Stress Regime

Reverse-Faulting Stress Regime

Wrench-Faulting Stress Regime

σ1

σ2 σ3

σ3

σ2 σ1

σ2

σ3 σ1

> Interpreting faults from seismic data and modeling using software tools. Complex fault architecturein exploration and development scenarios can be made more understandable with the use ofpowerful mapping and imaging software such as the Petrel workflow tools application. In thisexample, color-coded stratigraphic intervals in the hanging wall and footwall are juxtaposed againstthe modeled fault surfaces in three dimensions.

5 15 25 35 45 55 65

Clay content, %

0.6

km0 1.0

0 miles

Winter 2004/2005 41

of faults whose throw is less than the seismicresolution. The total mapped throw across aseismic-scale fault may also include the summedthrows of numerous faults that are too small tobe detected individually at the seismic scale.The volume of closely spaced fault segments isknown as the fault-damage zone.

The mapped throw across a seismic-scalefault displaces the rock layers on a single faultor on a collection of multiple faults, each ofwhich is below the seismic resolution. The offsetinfluences the fault sealing and properties of thefault rocks within the fault zone. A sealing faultmay result, for example, if a fault intersectingdifferent lithologies places permeable, reservoir-quality rocks against less permeable rock, suchas shale. This is known as a juxtaposition seal. A fault seal may also form if the reservoir is still juxtaposed against itself—where the throw is less than the reservoir thickness—oragainst another reservoir. This occurs becausethe rock within the fault zone may develop lower permeability.

Different fault rocks develop under differentdeformation conditions, and their sealing properties are related to the conditions of deformation and lithologic factors, such as claycontent.7 Faults that cut porous sandstones withlow clay content—less than 15%—may developlow-permeability seals from porosity reductionassociated with the mechanical crushing of thequartz grains. These are called cataclastic ordeformation bands. Disaggregation bands can alsodevelop in clean sandstones, but without the asso-ciated reduction in porosity and grain crushing.

Faults in impure sandstones form phyllosilicate-framework fault rocks (PFFR),with higher clay contents—from 15 to 40%—thatreduce the porosity and permeability by com-pacting and mixing the clay particles and quartzgrains. Clay smear occurs along faults that cutrocks with greater than 40% clay. The clay layersor shales are dragged and deformed along thefault plane, forming a low-permeability barrier tofluid flow. Cementation may also occur along afault plane, forming nearly impermeable barriersto flow. These cemented zones, however, arerarely continuous unless they are associated witha regional change, such as an increase in temper-ature above 90°C [194°F] at which the rate ofquartz precipitation increases (above right).8

The most common faults found in oil and gasfields are normal faults, and most have somecomponent of oblique movement. Complex,three-dimensional (3D) fault geometries stemfrom the nucleation, growth and linking of

3. Anderson EM: The Dynamics of Faulting and Dyke Formation with Applications to Britain. Edinburgh, Scotland: Oliver and Boyd (1951): 206.For more on failure-plane orientation: http://www.naturalfractures.com/1.1.3.htm (accessed January 15, 2005).

4. Walsh JJ and Watterson J: “Geometric and KinematicCoherence and Scale Effects in Normal Fault Systems,”in Roberts AM, Yielding G and Freeman B (eds): TheGeometry of Normal Faults, Geological Society of London,Special Publication 56. Bath, England: The GeologicalSociety Publishing House (1991): 193–203.

5. The throw of a fault is the generalized elevation differenceof the same bed on the opposing sides of the fault, or thevertical component of displacement. Fault displacement

> Fault-rock classification relating clay content, fragmentation and lithification. The original host rocksinclude clean sandstones with less than 15% clay, impure sandstones with 15 to 40% clay, andclaystones and shales with greater than 40% clay. Fragmentation and lithification progress throughouta fault’s history and produce one of the three types of fault rocks from each host as shown in thelower portion of the diagram. Photographs at bottom illustrate different forms of fault rocks, including(A) disaggregated and cemented (left), (B) phyllosilicate-smear framework (center) and (C) clay-smearfault rocks (right).

Cataclasite

(intermediate

clay content)

Proto-cataclasite

(intermediate

clay content)

Ultra-cataclasite

(intermediate

clay content)

Disaggregation

zone(intermediate

clay content)Disaggregation

zone(clay-poor)

Proto-cataclasites

(clay-poor)

Cataclasite

(clay-poor)

Ultra-cataclasite

(clay-poor)

Ultra-cataclasite

(clay-rich)

Cataclasite

(clay-rich)

Proto-cataclasite

(clay-rich)

Disaggregation

zone(clay-rich

hydroplastic)

Clay content

Quartz-rich

lithologies

(deformation

band) fault-

rock series

Phyllosilicate

framework

fault-rock

series

Clay-smear

series

~15%

40%

100%

10%

50%

90%

Lithification

Poorly lithified

Partly lithified

Well lithified

Fragm

entat

ion

Cleansandstones,

silts

Impuresandstones,

silts

Claystones,

shales

Lithificationstate

Fragm

entat

ion

Clay content

A

B

C

A

C

cm

1 mm

CataclasiteUndeformedsandstone

B

in.cm

is the full distance across which a bed is separated oneach side of a fault and defined as:displacement = throw/sine (fault-plane dip).

6. Knipe RJ: “Juxtaposition and Seal Diagrams to Help Analyze Fault Seals in Hydrocarbon Reservoirs,” American Association of Petroleum Geologists Bulletin 81,no. 2 (February 1997): 187–195.

7. Davies and Handschy, reference 2.8. Fisher QJ and Knipe RJ: “Fault Sealing Processes in Sili-

ciclastic Sediments,” in Jones G, Fisher QJ and Knipe RJ(eds): Faulting, Fault Sealing and Fluid Flow in HydrocarbonReservoirs: Geological Society Special Publication 147.Bath, England: The Geological Society Publishing House(1998): 117–134.

faults, and give rise to damage zones. An under-standing of fault-damage zones is crucial inmodeling fault behavior and its impact on reservoir performance.

Fault-Zone Architecture CharacteristicsAn appreciation of fault-damage zone complex-ity can be obtained through careful study offaults in outcrops. Surface exposures allow geoscientists to observe fault architecture indetail and in a 3D spatial context and scale not afforded by subsurface investigation. Importantly, much of what determines fault-sealing properties occurs at subseismic scalesand within the fault-damage zone. Consequently,

the study of damage zones in outcrops hasbecome crucial in modeling fault seals and inpredicting how they affect subsurface fluid flow.

The damage zone is the volume of deformedrocks around a major fault that has resultedfrom the initiation, propagation, interaction andbuildup of slip along small faults between faultblocks.9 The deformed volume radiating awayfrom a main fault segment can be divided intoinner and outer damage zones. The inner dam-age zone typically consists of intensely deformedfault rocks that are difficult to map discretely,while the outer zone has a high density of small-throw faults that often maintain an orientationsimilar to the principal fault segment.

The damage-zone geometry can also bedefined along the strike of a fault, or faults, asthree distinct zones (below left). The first zoneis called the tip-damage zone and is associatedwith the stress concentration at the tip of themain fault segment, where the displacementgoes to zero. The second zone is called the link-ing-damage zone, and refers to the volumeaffected by the interaction between two subpar-allel, noncoplanar fault segments. Thewall-damage zone, the third zone, is locatedalong the fault surface and is a result of damagefrom continued fault slip or from damage by pre-viously abandoned fault tips as fault propagationcontinued through time.10 Secondary, subseismic-scale faults, natural fractures and cementationmay occur in all three zones.

Intensive investigation of fault exposures,like the Moab fault in southeast Utah, USA, hasallowed geoscientists to characterize fault-damage zones and make analogies to majorfaults in the subsurface. The Moab fault hasbeen extensively studied by geoscientists,including scientists from Schlumberger-DollResearch (SDR), Ridgefield, Connecticut, USA,and Rock Deformation Research (RDR) Ltd,Leeds, England.11 Located in the northeast

42 Oilfield Review

> Fault-zone classifications. A 3D conceptual diagram illustrates the inner and outer damage volumesassociated with faults. The map view overlay of the fault propagation through the host rocksindicates three distinct zones, which are the tip-damage zone (red), the linking-damage zone (lightblue) and the wall-damage zone (green). Fault tip lines are shown in black.

Tip-damage zone

Linking-damagezone

Wall-damagezone

Inner damage zone

Outerdamage zone

> High-precision mapping of the Moab fault-damage zone. Global positioning systems (GPS)and rover units, which determine exact surveylocations, were used to record discrete featuresand position them with high precision.Secondary structural elements, such as faultsand fractures, were tagged with key geologicattributes to capture the complexity and scale ofthe fault damage.

Winter 2004/2005 43

portion of the Paradox basin, the Moab fault is anormal fault approximately 28 miles [45 km]long with a northwest to southeast strike. Thefault comprises several linked segments. Thelongest segment has a throw of 3,150 ft [960 m]to the south, as observed from surface displace-ment and erosion of Pennsylvanian to Cretaceoussedimentary rocks.12 The Moab fault was activefrom at least the Triassic period until at least themid-Cretaceous period. The canyon landscapesurrounding Moab is ideal for mapping the faultexposure in three dimensions (above).

SDR and RDR scientists set out to capturedetailed outcrop data along a segment of theMoab fault-damage zone at Bartlett Wash as ananalog to similar structures expected but notimaged in the subsurface. Within the study area,

the throw along the main fault segment is 690 ft[210 m]. The older, Jurassic-age Slick Rockmember of the Entrada sandstone is wellexposed on the footwall and exhibits a densenetwork of small-throw faults within a narrowzone adjacent to the main fault segment.

The geoscientists employed a sophisticatedmapping technique, using a high-precision, differ-ential global positioning system (GPS) and roverunits to map discrete features to within 0.8 in.[2 cm] (previous page, right). Data coordinateswere tagged with key geologic attributes at manystations to capture the complexity and scale ofthe fault-damage zone. The positions and geome-tries of major and secondary structural elements,such as faults and natural fractures, were alsorecorded. Scientists created a digital geologic

model to use as an analog for subsurface fault interpretation to facilitate visualizationthrough innovative techniques, such as virtual

9. Kim Y-S, Peacock DCP and Sanderson DJ: “Fault-DamageZones,” Journal of Structural Geology 26 (2004): 503–517.

10. Kim et al, reference 9.11. Kaufman PS, McAllister E and Smallshire R: “Collection

and Visualization of 3D Digital Geologic Data Sets: An Example from the Moab Fault Zone, UT,” presented at the American Association of Petroleum GeologistsAnnual Meeting, New Orleans, April 16–19, 2000.McAllister E, Smallshire R, Knipe R and Kaufman P: “Geometry of Fault-Damage Zones from High ResolutionMapping of the Moab Fault Zone, UT,” presented at theAmerican Association of Petroleum Geologists AnnualMeeting, New Orleans, April 16–19, 2000.

12. “Quantification of Fault-Related Diagenetic Variation of Reservoir Properties at Outcrop,” http://www.fault-analysis-group.ucd.ie/Projects/UTAH.html (accessedJanuary 15, 2005).

> The Bartlett Wash study area, Moab, Utah, USA. A photographic cross section along the Moab fault allows illuminating viewsof the complex fault-zone architecture within the detailed mapping area (top). An aerial view (bottom) from the footwall to thehanging wall shows another perspective of the sharp contact formed by the Moab fault.

Detailed mapping area

Entradasandstone

Footwall

Hangingwall

Entradasandstone

SW NE

Vantage point ofupper photo

Approximate

328

m0 100

0 ftNE

Moab,Utah USA

field trips, and to use the fault population distribution as an input to flow models (right).

Although the static geometry and fault-rockproperties are the principal controls on cross-fault flow in the subsurface, fault reactivation isanother phenomenon that influences the flowproperties along the fault. Changes in tectonicstress regimes over geological time, for example,may reactivate a fault, opening pathways thatdid not exist previously, and allowing hydrocar-bons to leak. On a reservoir-production timescale, changes in pore-pressure regimes as aresult of current production or injection in andaround fault systems can initiate fault reactiva-tion and cause loss of seal.

Local pressure increases near or within thefault plane resulting from injection decrease theeffective normal stress, which may cause thefault to reactivate.13 Also, pressure changes inthe rocks surrounding faults, for example fromdepleting a reservoir, alter the in-situ stressesacting on fault planes and, depending on faultalignment relative to the principal stresses, maylead to reactivation and subsequent seal failure.This behavior has been documented in suchareas as the North Sea, the Gulf of Mexico andthe Bight basin, Australia.14

These pressure changes have major implica-tions in production, enhanced oil recovery (EOR)and pressure maintenance, and in subsurface gasstorage, including carbon dioxide [CO2] storagefor the reduction of greenhouse-gas emissions.15

The reactivation of reservoir-bounding faults compromises fault-sealing mechanisms, shearswell casings, and causes compaction and subsi-dence. The integration of fault-rock strengthproperties, the fault geometry and in-situ stressconditions provides valuable input for modelingand assessing the reactivation risk.16 The in-situstress orientations are interpreted with boreholeimaging devices, like the FMI Fullbore FormationMicroImager or OBMI Oil-Base MicroImagertools, and from the acquisition of pore pressuredata, using sampling tools such as the MDT Modular Formation Dynamics Tester or the RFT Repeat Formation Tester devices.

The Roles of Pressure and Timing in Fault SealingAn important concept in estimating the sealingcapacity of faults relates to the threshold pressure (Pt). In water-wet rocks, Pt is the lowestcapillary pressure (Pc) at which hydrocarbonsform a continuous path through the largest inter-connected pore throats in the fault rock.17 Knowingthe Pt of different fault rocks, generated underdifferent conditions, allows geoscientists to calculate

the maximum petroleum-column height (Ht) orsealing capacity of the fault rock that preventshydrocarbon migration across the fault. The capil-lary pressure of hydrocarbons under hydrostaticconditions against a fault seal increases upwardfrom zero at the free-water level (FWL), which is at the base of the hydrocarbon column. A capillary or membrane seal prevents hydrocarbonmigration across the fault for a hydrocarbon column height measured from the FWL to wherePc equals Pt. Membrane sealing occurs because ofthe surface tension between water and hydrocar-bon, so the effective permeability to hydrocarbonis zero when Pc is less than Pt (next page, top).

A hydrocarbon column with Pc greater thanPt of the fault rock will migrate slowly across thefault. The flow is retarded by the hydraulic resis-tant sealing of the fault rock. Hydraulic resistantsealing occurs when the relative permeability tohydrocarbon is low because of the water-wetfault rock and low pressure potential across the

fault for small hydrocarbon columns. The hydro-carbons may migrate at a slow rate, but hydraulicresistant sealing provides an effective seal overgeological time. At the base of the hydraulic-resistance zone, Pc is equal to Pt. Relativepermeability to hydrocarbon at this elevation iszero, but increases above this point in a transitionzone from membrane sealing up to geologicallysignificant leakage because of an increase in therelative permeability. Geologists considerhydraulic-resistance seal failure significant once the leakage rate exceeds the hydrocarbon-charge rate, at which point hydrocarbons stop accumulating.

Water-pressure differences in the reservoiracross a fault or in fault fill influence the heightof the resulting hydrocarbon column. Higherwater pressure in the aquifer outside the trap,for example, leads to water flow into the reservoir if the hydrocarbon saturation in thefault zone is less than the irreducible water

44 Oilfield Review

> Mapping the Moab fault zone. More than 70,000 structural features were mapped at the BartlettWash site to populate an analog model of the fault-damage zone (top). The density of small faultswithin the damage zone of the main segment of the Moab fault decreases as distance from the main fault increases. Red fault traces are within the inner damage zone, while yellow features arewithin the outer damage zone (bottom). Powerful software tools allow geologists to use innovativetechniques like virtual field trips, capturing the knowledge and experiences of team members at the site.

NApproximate

82

m0 225

ft0

Winter 2004/2005 45

saturation, Swirr. These conditions improve thefault-seal potential and increase hydrocarbon-column height. Lower pressures in the aquiferoutside the trap and in the fault fill at irre-ducible water saturation will lead to decreasedhydrocarbon-column heights in the trap. Theseinterrelationships between fluids, pressures androck properties are important controls for predicting fault behavior and sealing capabilities.

Fault architecture, throw distributions,lithologies, fault-rock distributions and proper-ties all impact the flow properties of faults. Faulthistory, however, is equally important when considering the sealing potential of fault traps inexploration and production. The burial history,deformation timing and hydrocarbon-charge history influence fault-rock properties and theirimpact on fault-seal capacity.

Successful reservoir-development strategiesmust incorporate the faulting and burial historyto more accurately predict the fault-seal risk.For example, separate tectonic events createnew faults and reactivate existing faults. Fractures may propagate, potentially changingthe reservoir permeability characteristics. Fault-rock properties also change with burialand uplift. Permeability across faults and in surrounding rocks generally decreases withburial depth (below right). Increases in temper-ature boost the rate of quartz precipitation,which can significantly reduce the transmissibil-ity across a fault.

13. Hsieh PA and Bredehoeft JD: “A Reservoir Analysis ofthe Denver Earthquakes: A Case of Induced Seismicity,”Journal of Geophysical Research 86 (1981): 903–920.

14. Wiprut D and Zoback MD: “Fault Reactivation and FluidFlow Along a Previously Dormant Normal Fault in theNorthern North Sea,” Geology 28, no. 7 (2001): 595–598. Zoback MD and Zinke JC: “Production-Induced Normal Faulting in the Valhall and Ekofisk Oil Fields,”http://www.geomi.com/images/PDFs/MDZ-Zinke_PAG_2002.pdf (accessed January 15, 2005).“Wetland Subsidence, Fault Reactivation, and Hydrocarbon Production in the U.S. Gulf Coast Region,”USGS Fact Sheet FS-091-01, http://pubs.usgs.gov/fs/fs091-01/ (accessed January 15, 2005).Hillis RR and Reynolds SD: “In Situ Stress Field, FaultReactivation and Seal Integrity in the Bight Basin,”http://ftp.petroleum.pir.sa.gov.au/products/data/rb2003_2.pdf (accessed January 15, 2005).

15. Bennaceur K, Gupta N, Monea M, Ramakrishnan TS,Randen T, Sakurai S and Whittaker S: “CO2 Capture andStorage—A Solution Within,” Oilfield Review 16, no. 3(Autumn 2004): 44–61.Hawkes CD, McLellan PJ, Zimmer U and Bachu S:“Geomechanical Factors Affecting Geological Storage ofCO2 in Depleted Oil and Gas Reservoirs,” paper 2004–258,presented at the Canadian Petroleum Society 55thAnnual Technical Meeting, Calgary, June 8–10, 2004.

16. Jones RM and Hillis RR: “An Integrated, QuantitativeApproach to Assessing Fault-Seal Risk,” AmericanAssociation of Petroleum Geologists Bulletin 87, no. 3(March 2003): 507–524.

17. Brown A: “Capillary Effects on Fault-Fill Sealing,” American Association of Petroleum Geologists Bulletin87, no. 3 (March 2003): 381–395.

> Capillary pressure diagram. The pressure-depth plot (left) shows thecapillary pressure, Pc, as the difference between the pressures of water andhydrocarbon with depth. The hydrocarbon has a steeper pressure gradientthan the water, so the capillary pressure increases above the free-water level (FWL) where the capillary pressure is zero. The plot on theright shows a typical mercury-injection capillary pressure curve asmeasured in the laboratory. The entry pressure, Pe, is the pressure at whichthe hydrocarbons first enter the sample. A hydrocarbon-column height, Ht,can be trapped below the threshold capillary pressure, Pt, and seals bymembrane sealing. Trap geometries may allow hydrocarbon columns toexceed this height. The hydrocarbon flow across the seal above Ht ispossible at a rate dependent on the relative permeability of the seal.

Dept

h

Pc = Pt

Pc

Ht

Pressure

Free-water level

Hydrocarbonpressure

Hydrostaticpressure

Fractionalmercury [Hg] saturation

Log

capi

llary

pre

ssur

e

Membraneseal

1 0

Hydraulicresistantseal

Swirr

Pt

Pe

Hydraulicseal failure

> Permeability reduction in a cataclastic fault zone with increased burialdepth in three different basin examples. Permeability reductions occur incataclastic fault zones primarily because of mechanical grain crushing andincreased quartz cementation at greater depths. In basins having a highmean-effective-stress, strong cataclasis in fault zones (blue) would occur,resulting in lower permeabilities at greater burial depths. In basins havinglower mean-effective-stresses, moderate cataclasis in faults zones (red)would result, making permeability in those fault zones higher. In basinswhere quartz-cementation occurs in fault zones (green), fault-zonepermeabilities would be higher at shallower burial depths but become veryimpermeable below 3 km [9,840 ft] of depth because of increased quartzcementation. Other factors, such as geologic history and host-rocklithology, play a significant role in determining which processes dictatefault-zone permeability.

Max

imum

bur

ial d

epth

, km

1

2

3

4

50.0001 0.001 0.01 0.1

Average permeability, mD

Basin A - quartz-cementation influence at depth > 3 kmBasin B - moderate cataclasisBasin C - strong cataclasis

Fault-activity maps that color-code the geological timing of structural development helpasset teams quantify the risk of developing aprospect or of taking subsequent developmentsteps, such as initiating an EOR process. Knowledge of the geologic history and its impact is also important when predicting fault-sealing properties.

Fault-Seal Analysis MethodsSuccessful fault-seal analysis methods integratefundamental information on the fault-zone

architecture, fault-rock properties and pressuredata. An important tool for evaluating the flowpotential across a fault is a strike view, or map ofthe fault plane with the hanging wall and foot-wall intersections superimposed on the modeledfault surface.18 Allan diagrams use this tech-nique to show possible fluid-migration pathways,leak points or sealing areas across the fault, and have also helped explain the location ofhydrocarbon/water contacts in various fieldsworldwide. Allan diagrams typically use the seismically interpreted horizons to define the

hanging wall and footwall offset across the faultand lithology interpreted from well logs to identify the stratigraphic changes between theseismic horizons. Sophisticated mapping toolsallow the development of Allan diagrams as 3D models. (left) These models require signifi-cant amounts of data and can be time-consumingto develop, although new software tools, such asthe Petrel workflow tools application, havereduced the processing time significantly.

An alternative to the complicated evaluationof the distribution of the stratigraphy across thefault plane, as used in Allan diagrams, is a simplified juxtaposition triangle diagram, whichenables a quick initial examination and predic-tion of fault-seal capacity. This technique imagesthe hanging wall and juxtapositions for varyingthrows and allows an evaluation of the juxta-posed stratigraphic intervals for a given throw(below left). These diagrams simplify the analy-sis of juxtaposition for a single fault plane. Theeffects of multiple small-throw faults may alsobe quickly evaluated using these diagrams. Thejuxtaposition is simply evaluated at the smallerthrows for each fault.

In the initial analysis, triangle diagramsshow the juxtaposition of the stratigraphy acrossthe fault. Reservoirs juxtaposed against low-permeability rocks such as shales are expectedto seal, whereas reservoir-to-reservoir juxtaposi-tions across the fault are more likely to leak.Juxtaposition diagrams may also be used to eval-uate the fault rocks present and their associatedproperties that develop within the fault zone.For instance, the distribution of clay smearsfrom clay-rich layers in the fault zone can bedetermined and their effects on the seal quanti-fied. Also, critical throws can be assessed whenhigher permeability cataclastic faults may repre-sent a crossfault flow risk. This occurs wheretwo permeable siliciclastic reservoirs are juxta-posed across the fault—one in the hanging wall(HW) and one in the footwall (FW) (next page).

Several methods have been developed toestimate the distribution of fault rocks within afault zone. Two of the most commonly appliedmethods are shale-gouge ratio (SGR) and claysmear.19 Researchers at RDR have also recentlyintroduced a modified SGR, or effective shale-gouge ratio (ESGR), that permits a greatercontrol on the architecture and distribution ofthe fault rocks along the fault surface during the analysis.

The SGR method estimates the percentage ofclay from the host lithology mixed within thefault zone. The algorithm calculates the net claywithin the lithology that is displaced past each

46 Oilfield Review

> Allan diagram. Based on seismic data and wellbore information, Allandiagrams demonstrate the juxtaposition relationships across a fault plane.These diagrams are often used to identify potential petroleum leak points(red) along the fault strike.

Dept

h

Vertical projection plane

Potential leaka b

c d

a b

c d

> Analyzing juxtaposition. A juxtaposition triangle diagram (left) allows simple and quick evaluation of stratigraphic juxtaposition scenarios, for example when a reservoir, Sand A, is juxtaposed againstan impermeable shale that provides a seal. Another scenario might identify a sand-against-sandplacement that fails to provide an adequate seal for hydrocarbon trapping. Lithology is shown on the left; the horizontal axis shows the amount of throw; and the diagonal, dashed arrows show thejuxtaposition scenario at a specified throw and layer. The block diagram (right) is presented to show a 3D representation.

Throw, m0 50 100 150 200

Dept

h

Sand A

Sand ASand A

Triangle Diagram

BlockDiagram

Shale

Shale

SandA

Sand

Sand

Winter 2004/2005 47

point in the fault by taking the sum of the layerthickness times the clay percentage divided bythe fault throw. This calculation is derivedacross a modeled fault surface with a calculatedthrow distribution and clay-percentage estimatesfrom well logs. The ESGR uses a weighted SGRthat allows a nonuniform distribution of theclays within the section dragged past each pointon the fault surface to model a more complex fault-zone process.

Outcrop studies of fault zones have alsorevealed that clay smearing is a common fault-zone process in which clay is smeared along thefault zone from a local shale bed. The thicknessof the clay smear along the fault increases withthe thickness of the source shale bed anddecreases with distance from the source shale.

Multiple shale layers tend to combine to producea continuous smear, enhancing fault sealing.

The basic method for modeling the fault-rockdistributions involves calculating the throw distribution on a gridded fault surface from thehorizon intersections on the fault, infilling thedetailed stratigraphy with the estimated thick-nesses and clay contents, and contouring thederived fault-seal properties onto the fault surface. Contours of capillary pressure measuredalong the fault provide a calibration to the sealing capacity for the estimated fault-rockproperties. These pressure data are oftenacquired in open hole using formation-samplingtools, such as the MDT or RFT devices.

While the calculation of fault-seal potentialacross a fault seems straightforward, it may

be an oversimplification. From outcrop andexhumed fault studies, geoscientists find thatshale smears are not distributed evenly withinfault zones; they may be interrupted, creatingmultiple gaps, which reduce the sealing effectover geologic time scales. One study of the Calabacillas normal fault in New Mexico, USA,

18. Allan US: “Model for Hydrocarbon Migration and Entrapment Within Faulted Structures,” AmericanAssociation of Petroleum Geologists Bulletin 73, no. 7(July 1989): 803–811.

19. Yielding G, Freeman B and Needham DT: “QuantitativeFault Seal Prediction,” American Association ofPetroleum Geologists Bulletin 81, no. 6 (June 1997):897–917.Bretan P, Yielding G and Jones H: “Using CalibratedShale Gouge Ratio to Estimate Hydrocarbon ColumnHeights,” American Association of Petroleum GeologistsBulletin 87, no. 3 (March 2003): 397–413.Yielding et al, reference 2.

> Integration of fault-rock data with juxtaposition triangle diagrams. Incorporating stratigraphic information, log data and coredata (left) with juxtaposition information (right) provides fault-rock types and distribution for a range of fault throws. In thisnormal-fault example, the diagram identifies a smear from impure sandstone from Zone C that forms a seal across from thehigh-permeability sandstone reservoir in Zone E.

SandNet/Gross

mD

Nophyllosilicate

data

Reservoir againstolder stratigraphyin footwall

Reservoir againstyounger stratigraphyin hanging wall

The leaky zone has been sealedby a potential phyllosilicate smearof Reservoir Unit C

High-permeabilitysandstoneSandstoneImpure sandstonePhyllosilicate-rich(including shale)Cemented sandstone

Host-Rock Lithology

Cataclastic seals (sand on sand)Cataclastic seals (sand on sandpast other lithologies)Cataclastic seals (high-permeability sand onhigh-permeability sand past other lithologies)Cataclastic on phyllosilicate frameworksmear seals (impure sands in FW or HW)High potential for cataclastic on phyllosilicateframework smear (impure sand past other lithologies)Cement seal (cemented in FW or HW)High potential for cement seal (cementedsection past other lithologies)Phyllosilicate smear (phyllosilicate-rich units or shale in FW or HW)High potential for phyllosilicate smear(phyllosilicate-rich units past other lithologies)

Fault-Rock/Seal Type

PhyllosilicatePlug Permeability

Host-Rock

Lithology

3,60

0

Core

dep

th, m 3,

580

3,56

0A

3,54

03,

520

3,62

03,

640

3,66

03,

680

B

C

D

E

F

G

A

B

C

D

E

F

G

Hang

ing

wal

l (HW

) res

ervo

ir lit

holo

gy

0 20 40 60 80 0 10 100 1,000%

0.5

Zone

A

B

C

D

E

F

G

1007550250 125 150Fault throw, m

Plug Porosity, %0 10 20 30 40 50

Foot

wal

l (FW

) res

ervo

ir lit

holo

gy

0 1.0

found that clay smears tend to be continuous fora distance of two to six times the clay source-bedthickness, but then thin significantly away fromthe base of the clay source-bed on the footwall.20

Moreover, smears are frequently breached by small-throw faults. Consequently, smear-estimation and seal-calibration techniques canoverestimate fault-seal potential, especially nearthe base of a clay source-bed.

The contours of capillary pressure and fault-rock property estimates over a fault surface areundercalibrated using the methods described. Amore accurate analysis should include the calibration of fault-rock properties estimatedfrom core measurements. Measured thresholdpressure and permeability across small faults incore help predict the sealing capacity and flowproperties of the estimated fault-rock distribu-tion. Fault rocks in core also define the range offault-rock types, created by processes such ascataclasis or grain crushing, and allow evalua-tion of the impact of the geologic history andfault timing.

Fault-rock databases from specific basins arekey to the calibration of the fault-rock sealingpotential. Fault-rock data are a crucial input tosuccessful reservoir simulations, which also relyon field data, including seismic surveys, well logs,core logs and studies, and field pressure-data.These data are also important in reducing therisk in an exploration setting, where there maybe significantly less data available.

Increased Knowledge, Reduced UncertaintyFaults in core provide not only a calibration to fault-rock properties such as porosity, permeability and threshold pressures, but alsofault distribution and density at a scale belowthat of seismic resolution. Recent advances inseismic interpretation methods, such as automatic fault-picking and attribute-mappingsoftware, help geophysicists interpret large seis-mic volumes in less time and in greater detailthan manual methods. However, much of thefault detail still exists at a scale below the seis-mic resolution, so detection of these small faultsmust rely on high-resolution borehole-imagingtools and the detailed study of fullbore cores.

The highly compartmentalized Hibernia field in the Jeanne d’Arc basin offshore Newfoundland, Canada, demonstrates theimportance of detailed core examinations.21 TheHibernia field is situated in a sedimentary basinwithin the greater Jeanne d’Arc basin that hasundergone multiple rifting events associatedwith the breakup of the supercontinent Pangeaand the formation of the Atlantic Ocean fromthe late Triassic to the early Cretaceous period.

Since first production in 1997, geologists andengineers with the Hibernia Management andDevelopment Company knew that the two mainHibernia reservoirs were compartmentalized byfaults. An estimated 30 fault blocks were identi-fied from observed variations in fluid-contactheights and in pressures. As development of thefield continued, there were indications that thefield might be even more compartmentalizedthan originally thought.22 However, the assetteam was uncertain about the degree to whichthe faults were diminishing individual well production and injection performance.

Fullbore cores were taken from the lowerreservoir in the hanging-wall section in two wells,the B-16 2 in Block Q and the B-16 4 in Block R,to characterize the deformation and the fault-zone architecture (above). The cores wereexamined for geologic structures, and sampleswere collected for analysis of microstructural andpetrophysical properties. The fault rocks wereclassified according to clay content.

Fault rocks with less than 15% clay exhibitedboth disaggregation bands, which are localizedzones of particulate flow with little grain fracturing, and deformation bands with cata-clastic seams with variable amounts of grain-sizereduction due to mechanical crushing of thegrains. Despite the lack of clay, these fault rockshave an average permeability of 0.06 mD, whichis almost five orders of magnitude lower than

the host-rock permeability. Fault rocks contain-ing an intermediate amount of clay—15 to40%—are classified as phyllosilicate-frameworkfault rocks, and they exhibited even lower permeabilities than their low-clay counterparts.The high clay-content rocks, characterized bygreater than 40% clay, formed clay smears.These fault rocks typically have permeabilitiesof less than 0.001 mD, equivalent to the host-rock properties. The analysis of the fault rocksin core showed that the fault-rock types arecapable of significantly reducing the permeabil-ity across the faults in Hibernia field.

To evaluate the sealing potential of the faultscompartmentalizing the reservoir, the fault-rocktypes and properties are integrated with thefault-rock distribution estimates from the juxta-position diagrams. These diagrams show thatwhere the fault throw is less than the individuallayer thickness and the reservoir is juxtaposedagainst itself, the sealing properties are dictatedby the cataclastic fault-rock properties. Conversely, where the fault throw exceeds theindividual layer thickness, juxtaposition sealingof reservoir against nonreservoir rock is theprincipal seal.

A juxtaposition triangle diagram of theHibernia formation at Well B-16 2 demonstratesthe predicted fault-rock distributions and theirinterpreted effects on the fluid flow (next page).

48 Oilfield Review

Fault trendN-SW-dip

E-dip

NW-SENE-dip

SW-dip

Compartments

JI

H

E

K

C

FD

PM

L NA

B

QR

S

V

T

XY Z

G

FF

EE

AABB WCC

DD

O

Bonavistaplatform

Mur

re fa

ult

Nautilus fault

P

V

T

Q R

S

B-16 16

B-16 17

B-16 2B-16 4

1.2

km0 2

0 miles

N

Hibernia

St. John’s

Halifax

CANADA

USA> Hibernia structural map and the location of twocored wells, the B-16 2 well and the B-16 4 wellin Blocks Q and R, respectively.

Winter 2004/2005 49

20. Doughty PT: “Clay Smear Seals and Fault Sealing Potential of an Exhumed Growth Fault, Rio Grande Rift,New Mexico,” American Association of Petroleum Geologists Bulletin 87, no. 3 (March 2003): 427–444.

21. Porter JR, McAllister E, Fisher QJ, Knipe RJ, CondliffeDM, Kay MA, Stylianides G and Sinclair IK: “Impact ofFault-Damage Zones on Reservoir Performance in theHibernia Oilfield (Jeanne d’Arc Basin, Newfoundland):An Analysis of Structural, Petrophysical and DynamicWell Test Data,” special paper 43 in Hiscott R and Pulham A (eds): Petroleum Resources and Reservoirs ofthe Grand Banks, Eastern Canadian Margin. St. John’s,Newfoundland, Canada: Geological Association ofCanada (2004): 129–142.

22. Gormley JR, Andrews RJ, Baskin DK and Stokes R: “An Integrated Study of Reservoir Compartmentalizationin the Hibernia Formation, Hibernia Field,” Abstracts,Vol 26. Geological Association of Canada, MineralogicalAssociation of Canada Annual Meeting, St. John’s, Newfoundland (2001): 52–53.

> Juxtaposition (top) and fault-seal (bottom) diagrams for Hibernia Well B-16 2. The juxtaposition diagram identifies a sand-against-sand juxtaposition at a75-m [246-ft] throw. In this scenario, a Layer 2 sandstone in the hanging wall (HW) is dragged past other lithologies—impure sandstones and a medialshale—in the footwall (FW) and is juxtaposed against the basal sandstone in the upper Layer 3 interval. This represents a possible leak area. However,when clay smearing is taken into account, the predicted potential leak area is reduced significantly.

Layer 2

Layer 1

Medial shale

Uppersandstone

Basalsandstone

Shale

Shale

Uppe

rM

iddl

eLa

yer 3

Sandstone

Shale

Sandstone

Basa

l

Shale-rich against shale-rich pastother lithologies

Sand in FW and HWSand against sand past other lithologiesImpure sand in FW and HWImpure sand against impure sandpast other lithologiesShale-rich in FW and HW

Juxtaposition

Note: At 75-m throw, Layer 2sandstone juxtaposed againstUpper Layer 3 basal sandstone

0 100 200Fault throw, m

Lithofacies (volume-shale derived)Sandstone-dominatedMixed heterolithicShale/mudstone dominated

Sand in FW and HWSand against sand past other lithologiesImpure sand in FW and HWImpure sand against impure sandpast other lithologiesHigh potential for PFFR(shale-rich in FW and HW)Phyllosilicate-rich fault rocks (clay smears)High potential for phyllosilicate-rich(clay smears)

Fault-Seal Types (using clay-smear factor 3.0)

Cataclasites

Phyllosilicate-frameworkfault rocks

(PFFR)

Phyllosilicate-rich

Note: Reduction in windowsize due to smear potential ofintervening impure sandstonesand medial shale

Layer 2

Layer 1

Medial shale

Uppersandstone

Basalsandstone

Shale

Shale

Uppe

rM

iddl

eLa

yer 3

Sandstone

Shale

Sandstone

Basa

l

0 100 200Fault throw, m

This diagram shows that for throws less than 30 m [98 ft], fault rocks are predominantly cata-clasites or zones of grain crushing. On the otherhand, where throws are greater than 30 m, thelower permeability, clay-rich, phyllosilicate-richfault rocks are present. These results show thatfault rocks in the Hibernia field have the poten-tial to degrade the performance of bothproduction and injection wells.

When combined with production history-matching models, which yield nonuniquesolutions from many possible geologic scenarios,the fault-seal analysis calibrated to the faultdata from core bolstered the interpretation ofhow faults affect fluid flow in the field. This ledto the drilling of the injector well B-16 21, whichwas positioned to avoid dangerous fault-damagezones. The new injector well improved reservoirsweep and provided additional pressure supportfor nearby producing wells.

Fault-Seal Analysis Aids DrillingOpen, conductive fault systems may be as chal-lenging as sealing faults in field development,especially where they pose a serious drilling hazard. Since development drilling began in1970, the highly faulted Prudhoe Bay field,Alaska, USA, has produced more than 10 billionbarrels [1.6 billion m3] of oil. Throughout thefield’s history, lost-circulation problems havebeen commonplace and directly related to thenumber of faults crossed while drilling wells.With substantial remaining recoverablereserves, continued development by BP andConocoPhillips requires drilling into smaller

fault blocks and through more faults. As a result,lost-circulation problems have increased dramatically, even as total drilled footage hasdecreased in recent years (above).

Problems reached critical levels in 1998,when 66 out of 120 wells and sidetracks experi-enced lost-circulation problems, costing overUS$10 million. Trouble-time costs added 50% to100% to well costs. In some cases, loss ratesexceeded 1,000 bbl/hr [159 m3/hr], raising serious safety concerns and risking the loss ofwells. BP and ConocoPhillips, then Arco Alaska,considered several options to address the fault-related lost-circulation problems. The Prudhoe Bay asset team could choose not to drillrisky targets, reducing development options andrecoverable reserves, or could employ expensivedrilling contingencies that may have mitigatedthe problem, but at the expense of understandingits cause.

The Prudhoe Bay partner companies, alongwith RDR, decided to investigate the cause ofthese lost-circulation problems—faults that actas conduits for drilling mud. In Prudhoe Bay field,more than 5,400 faults have been interpreted byseismic surveys. The faults range in strike lengthfrom 500 to 15,000 ft [152 to 4,570 m] with throwsfrom 20 to 200 ft [6 to 60 m] (next page, top).First, the existing seismic data were reprocessedto improve the fault interpretation. The mappedfaults were then added to a database, whichincluded fault parameters such as orientationand length. Along with geologic data, drilling datafor all wells in the field were compiled, includinglost-circulation volumes and rates, and the

location of losses. Wellbore data and productionhistory-matching were also used to gain a morethorough understanding of fault, fluid and reser-voir behavior. Although this analysis helpedexplain 80% of the lost-circulation problems, it showed that a more detailed exploration offault-rock properties across the Prudhoe Bay field was warranted.

Analysis of the fault distributions and fault-rock properties from thousands of feet of corefrom 14 wells provided the necessary calibrationto evaluate fault behavior. Open vuggy fracturesin the core identified conductive zones thatcould pose potential drilling hazards. Full-fieldand local-stress modeling, integrated with the tectonic history, showed a preferential orientation of conductive faults parallel to themaximum in-situ stress direction. An integrateddatabase of fault styles and architecture, fault-rock properties, and lost-circulation datafacilitated the study of fault-damage zones andthe analysis of fault sealing.

The database properties calibrated to juxtaposition and fault-rock distributions fromclay-content of individual faults helped reducethe risk of drilling development wells in PrudhoeBay field. Predrill well planning now incorporatesthe data from the database to avoid hazardousdrilling areas (next page, bottom).

In the year following this integrated fault-characterization project, 65 wells and sidetrackswere drilled. The number of problematic wells,those losing more than 100 bbl [16 m3] ofdrilling fluid, dropped from 32 to 16% of the totalwells. Lost-circulation zones were anticipatedand accounted for, reducing trouble-time anddecreasing drilling costs by US$2 to 5 millionduring that year. Only two wells had significantproblems. A more thorough knowledge of faultsin Prudhoe Bay field reduced drilling risk,improved well planning and increased assetteam confidence in further development. Thesignificant reduction in drilling risk has openedup more drillable targets that were once deemed too risky, while potentially increasingrecoverable reserves.

Complex Problem, Simple AnswerFaults and their influences on fluid flow withinreservoirs are complex. Technological advance-ments have improved our ability to measurethese influences, both directly and indirectly.Well-testing techniques, production history-matching and the injection of tracers, forexample, help assess whether reservoir compart-ments exist, and if they do, whether they are incommunication or are isolated. Wellbore

50 Oilfield Review

> Increase in lost-circulation problems in Prudhoe Bay field. Even as totaldrilled footage (blue) declined during the last two decades, lost-circulationproblems (red) became more serious and costly. As smaller fault blockswere drilled using horizontal wells, more faults were crossed than duringearly development drilling. It was observed that the increased horizontalfootage drilled in the late 1990s directly correlated to mud losses, identifyingfaults as the predominant source of drilling problems.

Tota

l dril

led

foot

age,

ft

140,000

120,000

100,000

80,000

60,000

40,000

20,000

0

1,600,000

1,400,000

1,200,000

1,000,000

800,000

600,000

400,000

200,000

0

Tota

l los

t circ

ulat

ion,

bbl

1965 1970 1975 1980 1985 1990 1995 2000Year

Total drilled footageTotal lost circulation

Winter 2004/2005 51

measurements and sampling tools also are usedto evaluate reservoir rocks, fluids and pressuresto determine compartmentalization. Recently,engineers have successfully identified fluid compositional variances related to compartmen-talization using the Schlumberger MDT device.23

The evaluation, calibration and prediction of thefaults that compartmentalize reservoirs requirea systematic analysis that should include inte-grating datasets from properties measured inconventional core, to subsurface well and production data, seismic interpretation and outcrop and subsurface analogs.

Poorly resolved subsurface fault complexitiesmay be incorporated into reservoir fluid-flow simulators using the results from detailedoutcrop analog studies. In simulators, the effectsof faults are represented as effective trans-missibility factors across defined traverses.Fault-related transmissibility depends on thenumber of faults, the thickness of the associateddamage zones and the fault properties, such asfault-rock permeability and pressure thresholds.

Incorporating the fault-rock properties fromdatabases has improved history-matching andfluid-flow modeling across faults.24 These resultsstill contain risk and uncertainty. In fault-sealanalysis, there will always be uncertainties relating to the internal architecture of faults,the host-rock properties, the definition of stratigraphic units from seismic surveys, capillary pressure effects and how far to projectthe model given the limited amount of well data.Fault-rock property databases provide the rangeand magnitude of the uncertainty that can beincorporated into risk modeling using MonteCarlo techniques, for example.

In fault-seal analysis, the complexity of faultsmust be captured and modeled, but the answermust be simple enough to be used effectively inreservoir simulations to reduce uncertaintywhen exploring and developing enigmatic,faulted siliciclastic reservoirs. —MGG

23. Mullins OC, Hashem M, Elshahawi H, Fujisawa G, Dong C, Betancourt S and Terabayashi T: “HydrocarbonCompositional Analysis In Situ in Openhole Wireline Logging,” Transactions of the SPWLA 45th Annual Logging Symposium, Noordwijk, The Netherlands, June 6–9, 2004, paper FFF. Fujisawa G, Betancourt SS, Mullins OC, Torgerson T,O’Keefe M, Terabayashi T, Dong C and Eriksen KO:“Large Hydrocarbon Compositional Gradient Revealed byIn-Situ Optical Spectroscopy,” paper SPE 89704, presentedat the SPE Annual Technical Conference and Exhibition,Houston, September 26–29, 2004. Elshahawi H, Hashem M, Mullins OC, Fujisawa G, Dong C,Betancourt S and Hegeman P: “In-Situ Characterization

of Formation Fluid Samples: Case Studies,” paper SPE90932, presented at the SPE Annual Technical Conferenceand Exhibition, Houston, September 26–29, 2004. Betancourt S, Fujisawa G, Mullins O, Carnegie A, Dong C, Kurkjian A, Eriksen KO, Haggag M, Jaramillo ARand Terabayashi H: “Analyzing Hydrocarbons in the Borehole,” Oilfield Review 15, no. 3 (Autumn 2003): 54–61.

24. Knai TA and Knipe RJ: “The Impact of Faults on FluidFlow in the Heidrun Field,” in Jones G, Fisher QJ andKnipe RJ (eds): Faulting, Fault Sealing and Fluid Flow inHydrocarbon Reservoirs: Geological Society SpecialPublication 147. Bath, England: The Geological SocietyPublishing House (1998): 269–282.

> Fault map of Prudhoe Bay field. The structural complexity of Prudhoe Bay field is demonstrated bya fault map that shows extensive faulting throughout much of the field.

Prudhoe Bay Fault Map

Prudhoe Bay

Anchorage

AlaskaCANADAUSA

5

km0 8

0 miles

> Improved well planning. With improved knowledge of fault behavior inPrudhoe Bay field, high-loss areas (pink) can now be avoided or plannedfor while drilling to reach the target. Specific information, such as shale-gouge ratio along individual faults, allows the asset team to identify theoptimal points at which to cross faults to minimize mud losses and reducedrilling costs.

Kickoff point

Targ

et

Example ofprevious well plan

Plan forlosses

Crossfault at highshale-gouge ratio

Targ

et

Plan View

52 Oilfield Review

A New Horizon in Multiphase Flow Measurement

Ian AtkinsonBertrand TheuvenyCambridge, England

Michel BerardMoscow, Russia

Gilbert ConortRosharon, Texas, USA

Joel GrovesPrinceton, New Jersey, USA

Trey LoweHouston, Texas

Allan McDiarmid Apache Energy LimitedWest Perth, Western Australia, Australia

Parviz MehdizadehConsultantScottsdale, Arizona, USA

Patrick PerciotClamart, France

Bruno PinguetGerald Smith Bergen, Norway

Kerry J. WilliamsonShell Exploration and Production Company New Orleans, Louisiana, USA

For help in preparation of this article, thanks to Alain Chassagne, Luanda, Angola; Dan Deznan, Apache Energy Limited, Aberdeen, Scotland; Richard Kettle, Ahmadi, Kuwait; Donald Ross, Rosharon, Texas, USA; Jon Svaeren, Framo Engineering AS, Bergen, Norway; Eric Toskey, Bergen, Norway; and Laurent Yvon, Douala, Cameroon. 3-Phase, LiftPRO, NODAL, PhaseTester, PhaseWatcher,Platform Express and Vx are marks of Schlumberger.

A quiet revolution has taken place in the technology for measuring three-phase

fluids at the surface. Advanced multiphase meters provide production and reservoir

specialists with the data required to understand and optimize well performance

without separating a flowstream into individual gas, oil and water phases.

56105schD11R1.qxp 4/8/05 6:23 PM Page 52

Winter 2004/2005 53

A new surface flowmeter is fundamentallychanging the way we measure complex flow fromproducing wells. This transformation is driven bynew technology that accurately measures rapidvariations in three-phase fluids, including slugflow, foams and stable emulsions that previouslywere difficult to quantify. The capability tometer multiphase fluid in real time increasesoperational efficiency, saving both time and money.

It is now possible to allocate production with-out conventional phase separation and toovercome processing constraints, or bottlenecks,in existing surface facilities. Accurately quantify-ing individual fluid phases in a productionstream allows operators to make more informeddecisions about well performance. Engineers cannow better identify, understand and remediatemultiwell flow problems, optimize artificial liftoperations and build dynamic reservoir models.

This article discusses recent advances in multiphase metering and examines the use ofthis technology for permanent-measurement, artificial lift and mobile well-testing applica-tions, both onshore and offshore. Case histories from Australia, the Gulf of Mexico and Africa highlight the benefits of advanced measurement technology.

Conventional Separation and Well Testing Conventional test separators are scaled-downversions of the large production separators thatsegregate and measure gas, oil and water at

surface processing facilities. In established fieldoperations, test separators are permanent instal-lations. For exploratory and field-delineationwells, companies must deploy modular testseparators. Several test separators in series or parallel are sometimes needed to handlehigh-rate wells, heavy oils or condensate-rich—wet—gas.

Typically, test separators are cylindrical vessels that are deployed horizontally. These vessels vary from 15 to 30 ft [4.6 to 9.1 m] inlength, 8 to 13 ft [2.4 to 4 m] in height andweigh up to 10 tons [9,072 kg]. Separatorsreceive produced effluent from individual wellsand segregate the different fluid phases througha gravity-based process (above).

Two-phase vessels separate gas from liquids,and three-phase vessels further separate the liquids into oil and water. These systems meterthe separate fluid phases individually as theyleave the vessel before commingling and return-ing the fluids to a flowline. Normal operatingconditions for a test separator are limited topressures between 200 and 1,000 psi [1.4 and6.9 MPa] with maximum working pressures up to1,440 psi [9.9 MPa].

Test separators are not designed for specificwells, but instead must handle a wide range offlow rates. At the time of installation, test separators are often intentionally oversized toserve as backup or supplemental production separators and to accommodate future increasesin field output.

Obtaining reliable measurements from a testseparator requires relatively stable conditionswithin the vessel, which can take several hours.Well-test protocols associated with these unitsgenerally emphasize operational efficiency—aone-size-fits-all approach—rather than settingthe measurement instruments and controllingflow rates based on individual well conditions.Time constraints and personnel limitations oftenpreclude optimization of the separation process.

In addition, operating conditions sometimesprevent complete separation of the fluid phases.Some oil remains in the water, some water in theoil, some gas in the liquids and some liquids inthe gas. These conditions cause errors in separa-tor instruments, which are designed to measurestreams of single-phase gas, oil or water. Testseparators also have difficulty measuring certainanomalous flow regimes because of the need for stable processing conditions and the factthat response to dynamic flow conditions isalways delayed.

Problematic flow regimes include fluid slugs,in which one phase is interrupted by anotherphase; foams, which conventional separatorscannot handle; and stable emulsions thatrequire additional heat or chemical treatment toseparate the one phase that is suspended inanother. In addition, viscous fluids, such asheavy oil, make separation and accurate testmeasurements extremely difficult.

> Conventional separators and fluid measurements. Production separation begins with well flowstreamsentering a vessel horizontally and hitting a series of perpendicular plates. This causes liquids to dropto the bottom of the vessel while gas (red) rises to the top. Gravity separates the liquids into oil(brown) and water (blue). The gas, oil and water phases are metered individually as they exit the unitthrough separate outflow lines. Mechanical meters measure fluids; an orifice meter measures the gas.Both devices require periodic recalibration.

Pressure-reliefvalve

Secondpressure-relief

valveCoalescing

platesFoam breakerbaffle plate

Gas outlet to orifice meter

Mist extractor

Accessdoor

Oil-level controller

Vortex breaker

Vortex breaker

Oil outlet to mechanical meterWeir baffle plate

Water outletto mechanical meter

Water-level controller

Deflectorplates

Additionaloutlet

Effluent inlet

Multiphase MeasurementsUnlike conventional separators, multiphasemeters continuously measure gas, oil and waterflow without physically separating the flow-stream into individual fluid phases. Multiphaseflowmeters accept three-phase fluids directlyfrom a flowline, make measurements and imme-diately return fluids to the flowline (left). Thesemeters yield measurement results within min-utes of being placed in operation.1

Pressure drop across multiphase flowmetersis significantly less than for conventional separa-tors, which allows wells to be tested close toactual producing conditions. In permanentmetering applications, these devices have mini-mal footprints at surface locations or on offshoreplatforms. At this time, there are more than1,300 multiphase meter installations worldwide,reflecting sharp increases during the pastsix years (below left).2

Third-party testing and joint-industry projectshave helped prove multiphase measurement tech-nology. Developers of three-phase flowmetershave also demonstrated the effectiveness of thesesystems through extensive flow-loop testing. Aflow-loop test consists of accurately measuringsingle-phase fluids—gas, oil and water—in acontrolled environment, mixing them to create amultiphase stream and then flowing themthrough a multiphase meter.

Flow-loop measurement results are com-pared with the individual volumes of constituentfluids that formed the test flow.3 These testsassess meter performance over a wide range offluid mixtures and flow conditions. Meterperformance under anticipated field conditionscan be extrapolated from flow-loop test data.

Users conduct extensive testing of multi-phase flowmeters to qualify the systems forspecific field applications. Qualification isfrequently necessary because various meteringsystems react differently to changes in processconditions, such as flow rates, fluid properties,the presence of scale or paraffin, and sand orgas volumes in a flowstream.4

To date, there is no commonly accepted testprocedure. Project partners, government entitiesand other joint-interest owners must agree onappropriate qualification procedures each time ametering system is used to allocate, or apportion,commingled production according to ownership.However, several industry and regulatorybodies—the American Petroleum Institute (API),

54 Oilfield Review

> Multiphase flow measurements. Metering three-phase flow in wellbore tubulars or facility piping(left) requires continuous measurement of changing gas (g), oil (o) and water (w) compositions(Ag, Ao, Aw) and velocities (Vg, Vo, Vw). Advanced multiphase production monitoring units can beintegrated with facility piping (top right) or skid mounted (bottom right).

Ag

Ao

Aw

Vg

Vo

Vw

VgVoVwAgAoAw

======

gas velocityoil velocitywater velocityarea occupied by gasarea occupied by oilarea occupied by water

1,200

1,400

1,000

800

600

400

200

0

Year

Multiphase Meter Installations

Num

ber o

f Ins

talla

tions

1994 to 1996 1997 to 1998 1999 to 2000 2001 to 2002 2003 to 2004

Subsea

OnshoreOffshore

> The expansion of multiphase meter technology. Although multiphase meterinstallations began in about 1994, the estimated number of installationsincreased dramatically beginning in about 1999 (top). In permanent-measurement applications, these devices take up less space than conventionaltest separators (bottom).

Winter 2004/2005 55

American Society of Mechanical Engineers(ASME), Oil & Gas Conservation Commission(OGCC), International Organization for Stan-dardization (ISO), United Kingdom Departmentof Trade and Industry (DTI) and Norwegian Soci-ety for Oil and Gas Measurement (NSOGM)—aredeveloping guidelines for the application andqualification of multiphase flowmeters.5

In addition to flow-loop tests, testing underfield conditions is another means of qualifyingmultiphase flowmeter systems for specific appli-cations. Flowmeter performance is comparedwith measurements from test separators in afield where fluid composition, line pressure andflow rates closely approximate those of anintended application. Testing under actual fieldconditions often establishes a higher level ofacceptance for multiphase meter performance.6

However, field tests consume more time than typical flow-loop tests and tend to be more costly.It is also essential that operators pay close atten-tion to the calibration and operation of testseparators to ensure high-quality reference data.7

For subsea developments with wellheads, ortrees, and production-control equipment locatedon the seabed, field tests are often impractical.

In addition, flow-loop procedures may not becapable of replicating the extreme pressuresand temperatures prevalent in some projects,such as deepwater and ultradeepwater develop-ments. Often, the best option in these cases is to compare data from an accelerated program ofpostinstallation monitoring with conventionalsingle-phase process-stream data at exportpoints during monthly production testing.8

A New Flowmeter DesignBecause of the limitations inherent in conven-tional test separators, Schlumberger and FramoEngineering AS developed the Vx multiphasewell testing technology through the joint-venture company 3-Phase Measurements AS.This multiphase flowmeter system is applicablefor permanent installations, mobile testing andartificial lift optimization.9 Vx technology hasbeen qualified in more than 1,500 flow-loop testsconducted by third parties at five independentfacilities that generated about 5,000 flow-regimetest points.

The principal components of the Vx multi-phase flowmeter are a venturi meter equippedwith absolute- and differential-pressure sensors,and a dual-energy spectral gamma ray detectorpaired with a single, low-strength, radioactivechemical source to measure total mass flow rateand the holdups, or fractions, of gas, oil andwater (left).

Vx technology functions without the need foran upstream flow-mixing device, which mini-mizes the size and weight of the unit.10 Thesesystems have no moving parts and are essen-tially maintenance-free. In-line flow passesthrough an inlet into a short, straight length ofhorizontal pipe leading to an inverted tee with one horizontal end closed. This blind teepreconditions and directs the flow upwardthrough a venturi section in the Vx meter. Pressure is measured just before fluids enter theventuri and as the flowstream passes throughthe narrow venturi throat.

1. Letton W, Svaeren J and Conort G: “Topside and SubseaExperience with the Multiphase Flow Meter,” paper SPE 38783, presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, October 5–8, 1997.

2. Mehdizadeh P: “Qualifying Wet Gas and MultiphaseMetering for Deep Water Well Allocations,” presented at the Deep Offshore Technology International Conference and Exhibition, New Orleans, November 30–December 2, 2004.

3. Mehdizadeh, reference 2.4. Mehdizadeh, reference 2. 5. State of the Art Multiphase Flow Metering, API

Publication 2566, First Edition. Washington, DC: American Petroleum Institute, 2004. Use of Subsea Wet-Gas Flowmeters in Allocation Measurement Systems, API Recommended Practice RP 85, API Upstream Committee, Subsea Equipment Subcommittee, Upstream Measurement Technical Advisory Group. Washington, DC: American PetroleumInstitute, 2004. Allocation of Gas and Condensate in the Upstream Area,draft version, Technical Report ISO/TC193/SC3/WG1.Delft, The Netherlands: Nederlands Normalisatie-Instituut (NEN), 2002. Amdal J, Danielsen H, Dykesteen E, Flølo D, Grendstad J,Hide HO, Moestue H and Torkildsen BH: Handbook ofMultiphase Metering. Oslo, Norway: The NorwegianSociety for Oil and Gas Measurement, 1995. Guidance Notes for Petroleum Measurement Under thePetroleum (Production) Regulations, Issue 7-Final Draft.London, England: Department of Trade and Industry,Licensing and Consents Unit, 2003.

6. Mehdizadeh, reference 2. 7. Hasebe B, Hall A, Smith B, Brady J and Mehdizadeh P:

“Field Qualification of Four Multiphase Flowmeters onNorth Slope, Alaska,” paper SPE 90037, presented at the SPE Annual Technical Conference and Exhibition,Houston, September 26–29, 2004.

8. Mehdizadeh, reference 2. 9. Al-Asimi M, Butler G, Brown G, Hartog A, Clancy T,

Cosad C, Fitzgerald J, Navarro J, Gabb A, Ingham J, Kimminau S, Smith J and Stephenson K: “Advances inWell and Reservoir Surveillance,” Oilfield Review 14,no. 4 (Winter 2002/2003): 14–35.

10. Atkinson I, Berard M, Hanssen B-V and Segeral G: “New Generation Multiphase Flowmeters from Schlumberger and Framo Engineering AS,” presented at the International North Sea Flow Measurement Workshop, Oslo, Norway, October 25–28, 1999.

> Vx multiphase well testing technology. The venturi shape is based on theindustry standard. Absolute- and differential-pressure measurements aremade at the same location in the venturi throat. Nuclear-transparentwindows in the venturi allow gamma rays to pass from source to detectorwith negligible loss caused by the hardware, enhancing measurementaccuracy. The nuclear source is barium-133 with a half-life of about 10.5years. A flow computer provides sensor processing and flow-rate data plusmore than 30 other parameters at standard and line conditions. It storesmore than 200 well profiles that include well-specific fluid characteristics,enabling multiple wells to be flowed through the same meter.

Nuclear detector

Flow computer

Nuclear source

Differential-pressure

transmitter

Flow

Venturi

Pressuretransmitter

The dual-energy spectral gamma ray detectoris mounted on one side of the venturi section,directly across from a barium source, which emitsgamma rays at various energy levels—approxi-mately 32, 81 and 356 keV. The detector measuresradioactive count rates, which are related togamma ray attenuation through the fluid mixtureat the 32- and 81-keV energy levels.11 The higherenergy level chiefly measures mixture density,which is affected by the gas/liquid ratio; the

lower energy level corresponds to fluid composi-tion, which is influenced by the water/liquidratio (below left).

Because total mass flow rate and holdup aremeasured at the same time and same place—the venturi throat—the dual-measurementsystems in Vx meters evaluate the same flow.This configuration and stringent equations for the fluid dynamics associated with flow conditioned by a venturi throat provide a robust

measurement capability unaffected by upstreamflow regimes.12

The detector makes complete calculations ofgas, oil and water fractions every 22 millisec-onds, or slightly more than 45 measurements of fluid-mixture density and three-phase holdup per second.

The rapid sampling and measurement speedallow the flowmeter to derive the velocity of liquid and gas phases in a flowstream and tocompensate for high-frequency instabilities inthe venturi throat. As a result, the Vx meter canmeasure flow conditions caused by downholeconditions and surface piping, including slugflow, foams and emulsions (next page, top).13

The PhaseWatcher fixed multiphase well production monitoring service is the main permanent monitoring application of Vx tech-nology. This system is available with venturithroat sizes of 29 mm [1.1 in.], 52 mm [2 in.]and 88 mm [3.5 in.], depending on flow rate.14

For mobile well-testing applications, thePhaseTester portable multiphase periodic well testing equipment is available in 29-mm or52-mm throats. This compact system weighsabout 3,750 lbm [1,700 kg] and can be trans-ported easily on a truck, trailer or modular skid (next page, bottom). A gas-testing modulealso is available for permanent-monitoring andmobile-testing applications.15

Continuous Measurement Opportunities Multiphase flow measurements help allocateproduction among working- and royalty-interestowners or record volumes for custodial transferat pipeline stations or port terminals. This infor-mation is essential for project partners and alsofor governments, which have testing require-ments for accurate computation of taxes androyalty payments. For example, measurementsmight be made on a given well during a one-week period so the results can be extrapolatedto allocate production over a longer time.

56 Oilfield Review

> Gamma ray attenuation. Different fluids attenuate gamma rays to varyingdegrees. The high-speed detector produces a signature count rate over thehigher and lower energy bands that are a function of the measured medium(top). These count rates permit a triangular solution of phase holdup (bottom).For each phase, the ratio of high-energy count rate versus source strength,or empty pipe count rate, is plotted against the ratio of low-energy countrate versus source strength on an x-y chart. These points become theapexes of a triangle. Phase holdup is determined by the intersection of twolines inside the triangle. The first line represents the gas/liquid ratio (green);the second connects the 100% gas point to the oil/water ratio point (red).

Coun

ts

Low-energy peaks

High-energy peaks

Gas

40%

Oil

60%Water

High

-ene

rgy

peak

cou

nt ra

te

Low-energy peak count rate

17,500

15,000

10,000

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032 KeV 81 KeV

Gas

OilDistilled water5% saline water10% saline water15% saline water

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Winter 2004/2005 57

11. Al-Asimi et al, reference 9. 12. Atkinson et al, reference 10. 13. Williamson J and Mehdizadeh P: “Alaska Regulatory

Guidelines for Qualification of Multiphase Metering Systems for Well Testing” paper SPE 94279, prepared for presentation at the 2005 SPE Western Regional Meeting, Irvine, California, USA, March 30–April 1, 2005.

14. Maximum flow rates:29-mm [1.1-in.] venturi: liquid, 12,900 B/D [2,051 m3/d];gas, 0.17 MMcf/D [48,086 m3/d];52-mm [2-in.] venturi: liquid, 39,500 B/D [6,281 m3/d];gas, 0.57 MMcf/D [161,229 m3/d ]; 88-mm [3.5-in.] venturi: liquid, 112,000 B/D [17,808 m3/d];gas, 1.6 MMcf/D [452,271 m3/d].

15. Atkinson DI, Reksten Ø, Smith G and Moe H: “High-Accuracy Wet-Gas Multiphase Well Testing and Production Metering,” paper SPE 90992, presented at the SPE Annual Technical Conference and Exhibition,Houston, September 26–29, 2004.

> Multiphase flowmeter and separator data comparison. Continuous measurement data from amultiphase meter clearly identify the presence of periodic slug flows in the well. The data pointsfrom the test separator show that the separator may or may not detect these slugs, depending onthe frequency of data capture.

Gas

and

liqui

d fl

ow ra

tes

Wat

er c

ut, %

2,000

4,500

Gas slugs

4,000

3,500

3,000

2,500

1,500

1,000

500

0

11:02 12:14 13:26

Time

14:38 15:50

0

20

40

60

80

100Multiphase meter

Gas, Mcf/D

Liquid, B/D

Water cut

Conventionalseparator

Gas, Mcf/D

Water cut

Liquid, B/D

> Periodic well testing. The PhaseTester portable multiphase periodic well testing system can beskid-mounted for transport to onshore wellsites on the back of a small truck or as a modular packagefor crane lifts onto offshore platforms. The PhaseTester unit is significantly smaller and more compactthan temporary conventional test separators.

Test-separator data also provide a basis forproduction optimization strategies. However, asfield developments progress and more wells goon stream, test-separator capacity often becomesinadequate, and production has to be deferred toperform well tests (above). These limitations area disincentive to test wells more often than commercially or legally required.

A similar situation arises when new productionis added, such as completing previously bypassedzones or performing remedial treatments in exist-ing wells, or when implementing pressure-maintenance and enhanced recovery methods. Inthese cases, bottlenecks at test separators limitfield evaluation and production optimization.

Adding separation capacity is one option, buta single separator costs up to US$500,000. Installation of a multiphase flowmeter costsabout 40% of that amount. Multiphase meteringsystems do not store, separate or treat flow-streams, but instead measure fluids under in-lineconditions and return them immediately to aflowline. This eliminates process bottlenecks.

In some cases, multiphase meters allowoperators to convert test separators for use asproduction separators. This added capacityincreases field production rates and enhancesoperational flexibility. Positioning multiphaseflowmeters next to a flowline and operatingthem with a minimal pressure loss allow meter-ing at conditions that are close to the actualfunctioning point or production setting of eachwell. Another application for multiphase flowmeasurements is the subsea environment.

The PhaseWatcher subsea systems providesubstantial cost savings through down-scaling orelimination of surface well-testing facilities andsubsea test lines (next page, top). Since test sep-arators cannot be deployed in this setting, surfacemeasurement of production from subsea wellsrequires the installation of expensive subsea testlines. In addition, platform-based facilities oftenhave insufficient capacity for subsea wells to betied into existing topside test separators thatwere initially designed to accommodate only theproduction from platform wellheads.

Platform facility expansions may not be anoption because of space or economic limitations.Furthermore, long subsea test lines increase separator stabilization times, hampering the abil-ity to track dynamic producing conditions fromthe surface and reduce well-testing frequency.Commingled production from several subseawells obscures individual well performance.

If commingling occurs through a subsea pro-duction manifold with no test line, measuringindividual well performance requires “testing bydifference.” This means periodically shutting in one of the wells while measuring the othersand eventually deriving individual well data by inference. Deferred production and pooraccuracy inevitably result.

Reducing bottlenecks is not always the majorjustification for installing permanent multiphaseflowmeters. Sometimes the problem is acces-sibility. This is true of unmanned offshoreplatforms and certain remote onshore wells.Wells located far from the nearest productionbattery with a test separator may be tied directlyinto a flowline and commingled with productionfrom other wells, especially if the wells are notmajor producers.

The only way to measure multiphase flowfrom these wells is testing by difference. As apractical matter, some wells may never betested. However, planning, designing and bring-ing new wells on line with permanentmultiphase monitoring offer new possibilities forobtaining additional data about gas, oil andwater flow from development wells, includingthose in remote locations.

Multiphase metering systems increase well-testing frequency, but also enhance measurement quality. Flow from some wells is sounstable that it cannot be measured accuratelywith a conventional test separator. Multiphaseflowmeters are more accurate than conventionaltest separators and are less affected by complexflow regimes (next page, bottom).

Multiphase measurements also identify phaseconditions that might not be detectable by theexclusively volumetric measurements of conven-tional test separators. Furthermore, unlike testseparators, multiphase flowmeters have no moving parts and associated maintenancerequirements to maintain measurement accuracy.

Multiphase flowmeters enhance operationalsafety by eliminating the need for high-pressurevalves and relief lines. Also avoided is storage ofsubstantial volumes of hydrocarbons under potentially unstable conditions in test separa-tors. This is an important issue if well testingtakes place in environmentally sensitive areas.

58 Oilfield Review

> Undersized test separators. As operators increase well flow rates with larger choke sizes (red),there are significant differences between the liquid flow rates measured by a multiphase flowmeter(green) and a conventional test separator (blue). At high rates, test separators that are too small oftenfail to achieve complete separation. A large amount of liquid remains in the gas and is no longermetered with the liquids. Separator operation can even become unstable and have to be bypassed,resulting in short periods of zero flow. Correlation between liquid rates measured by the multiphaseflowmeter and choke settings provides confidence in the quality of flow-rate measurements.

Liqu

id ra

te a

t sta

ndar

d co

nditi

ons,

B/D

PhaseTester liquid rateConventional separator liquid rateChoke setting

Chok

e si

ze, i

n.

24-Aug 12:00 24-Aug 18:00 25-Aug 00:00 25-Aug 06:00 25-Aug 12:00 25-Aug 18:00 26-Aug 00:00

0

2,000

4,000

6,000

8,000

10,000

13/41/21/40

Winter 2004/2005 59

Moreover, there are no fluid-disposal problemsassociated with multiphase flowmeters, whichenhances safety and environmental protection.

Multiphase flowmeters not only eliminateobstacles to greater measurement consistency,reliability and quality, but the measurement process itself essentially becomes a continuousmonitoring function. Even when wells are notmetered all the time, measurements are typically more frequent and conducted overlonger time periods.

Because of this, operators are now obtainingdynamic multiphase flow data. This ability toobserve in-line multiphase flows over anextended period in real time affords a step-change improvement in the quantity and qualityof data available for production-optimizationdecisions. The PhaseWatcher unit can interfacesecurely with the Internet to allow monitoringand remote decision-making about well and fieldoperations from anywhere in the world.

Multiphase flowmeter data allow operators todetermine whether wells are flowing as expectedand whether to schedule remedial workoversbased on individual gas, oil and water productionrates. If field production is limited by bottle-necks in surface gas- and water-handlingfacilities, multiphase flowmeters help identifywhich wells to optimize and which to choke back.

Another significant optimization opportunityinvolves artificial lift operations, typically whereelectrical submersible pump (ESP) or gas-injection systems lift fluids to the surface. TheSchlumberger LiftPRO service for improvingunderperforming artificially lifted wells addressesthis need, with applications for both permanentmeasurement and periodic mobile testing. Individual wells can be monitored with multi-phase flowmeters, while pump or gas-injectionrates are separately monitored by differentinstrumentation to identify optimal levels.

Optimizing Artificial Lift OperationsApache Energy Limited used the PhaseWatcher system to optimize artificial lift operations while developing offshore fields in Australia. TheVx system achieved several important objectives,including reduced capital and operating expen-ditures, and improved production allocation andfield management.

> Subsea flowmeter. The PhaseWatcher subsea monitoring unit is lowered to seafloor for installationon a wet production tree or in a manifold (right). This system significantly reduces field-developmentcosts by eliminating surface testing facilities and subsea test-line installation (left).

Venturi

Nuclearsource

Nucleardetector

> Testing the untestable. Multiphase flowmeters can test wells that previouslywere difficult or, for practical purposes, impossible to test. Data from a typicalwell with slug flow show the oil rate abruptly rising from 1,000 B/D [159 m3/d]to more than 6,000 B/D [953 m3/d], conditions that conventional separatorscannot accurately measure because response time is too slow. In addition toslug flows such as these, multiphase flowmeters can measure flows consistingof foams and emulsions that also pose essentially untestable conditions forconventional separators.

7,000

6,000

Oil slugs

5,000

4,000

3,000

2,000

1,000

00

2

Tota

l oil

rate

, B/D

Time, hours4 6 8 10 12

A key element of these development effortswas the installation of five unmanned platformswith minimal facilities with no processingcapacity, and therefore no topside separation(below). Production from each platform wascommingled into a single production flowline,which required accurate measurement of

each component fluid in the flowstream. Wells in each field are produced using a common gaslift system.

Web-enabled PhaseWatcher metering at eachwellhead allowed Apache to quickly optimize gaslift and production systems, and make immedi-ate operational adjustments in response tochanges in choke settings or well productivity.

This eliminated the waiting period for inventorytank flows to stabilize, which is necessary with atest separator.

The optimization process began during wellcleanup, so the Vx systems provided continuousproduction monitoring. Wells reached their target rates within hours of startup. Multiphasemonitoring also helped eliminate productioninterruptions by immediately identifying risingwater cuts and slug flows, which enhanced theability to maintain a stable production process.Rapid identification of dynamic flow factors by the PhaseWatcher meters improved well diagnostics on a continuing basis.

By equipping each flowline with a multi-phase meter, Apache eliminated the need for atest separator in the field production systems. Atabout 815 lbm [370 kg], the PhaseWatcher systems represented nearly a 90% weight savingscompared with the alternative of conventionaltest separators that weigh about 3.5 tons[3,175 kg] each, excluding structural supportand utility components.16

This weight reduction helped minimize capital expenditures, which were further reducedby limiting the size of platform structures and theextent of piping. Still other capital savings inlogistics resulted from this structure minimiza-tion. The reduced size, weight and complexity ofthe topsides for each platform allowed transportto the loadout site by road in a single trip.

Elimination of test separators and minimalmultiphase flowmeter maintenance also reduceoperating costs. Remote operating capabilitiesachieved by integrating metering and telemetrysystems further minimized the need for intrusivemaintenance and personnel visits. Installationof multiphase meter systems played an impor-tant role in optimizing gas lift operations andreducing capital and operating expenses, criticalobjectives in the development of these fields.

Improving the Allocation ProcessRegulatory and petroleum industry bodies, includ-ing the United States Minerals ManagementService (MMS), API, ASME, Norwegian PetroleumDirectorate (NPD) and United Kingdom DTI, recognize the role of high-quality data frommultiphase meters for well testing and are devel-oping standards for this equipment. As a result,multiphase flowmeter technology is increasinglyused for allocating oil and gas production.

New deepwater projects increasingly reflectdevelopment strategies with a processing hubthat receives production from one or more satellite reservoirs with subsea completions. Thenumber of outlying fields often increases as newdiscoveries are developed and tied directly orindirectly into the host facility (left).

60 Oilfield Review

> Optimized gas lift. These unmanned miniplatforms were among several such facilities offshore Australia where Apache Energy Limited installed thePhaseWatcher multiphase metering system. PhaseWatcher technologyallowed Apache to optimize gas lift operations, while saving capital andoperating expense.

> Deepwater satellite development strategy. A production hub, or host, facility receives additionalproduction directly or indirectly through subsea manifolds from one or more satellite fields withsubsea wells. As this scenario evolves, bottlenecks in test-separation capacity result in less frequentwell testing and lower quality measurements as flow distances increase. Multiphase flowmetersystems eliminate these bottlenecks, which improves measurement quality and allows wells to betested as often as needed. These factors improve production allocation and increase opportunitiesto optimize production.

Satellite field subsea wells

Satellite field subsea wells

Subsea manifolds

Production hub

Winter 2004/2005 61

For these types of developments, allocationis often more complex because ownership maybe different for each field or reservoir. The useof hub-based test separation for multiphase flowmeasurements can become increasingly prob-lematic. First, there is the issue of test separatorsize and weight, which affects host-facility costand operating parameters, such as number ofplatform wellhead slots and operational safety.

In addition, expansion of production throughsatellite tie-ins can cause well-testing demandsto exceed test-separator capacity and availability,resulting in less frequent testing of individualwells. Adding separation capacity at a hub isoften impractical or impossible. Furthermore, asdistance from the wells to a hub increases,metering and measurements with test separatorsbecome more difficult.

Stabilization time for test separatorsincreases when test lines are longer. Long sub-sea test lines can mask well-flow dynamics andcontribute to slug flow as water accumulates inlow points along their path. As the availabilityand effectiveness of test-separation facilitiesdecline, so does the quality of data obtained for allocation and production optimization.17

By contrast, multiphase flowmeter systems eliminate concerns about measurement qualityand well-test frequency.

The number of multiphase flowmeters currently deployed in deepwater developmentsis small, but their effectiveness for improvingproduction allocation creates potential deep-water applications. Multiphase meters can beeconomically designed into new productionfacilities as satellite fields are developed. Inlight of these factors, Vx technology becomes apractical necessity in many offshore develop-ments and essentially an enabling technology forsome deepwater projects.18

Allocation Measurements at Offshore HubsShell installed the PhaseWatcher system at theGulf of Mexico Auger complex to overcome test-separation bottlenecks and related alloca-tion difficulties resulting from productiongrowth. Several subsea fields in the area had been tied into the Auger complex for production processing.

The Auger field produces from a tension-leg platform (TLP) that began operation in 1994with the capacity to process 50,000 B/D[7,950 m3/d] of oil and 140 MMcf/D [39.6 million m3/d] of gas from direct-vertical-access (DVA) wells. As development activitiesprogressed, production soon exceeded expectations. The Auger TLP facilities wereupgraded and expanded.

In addition, the development of severalnearby subsea fields led to a series of tiebacks atthe Auger platform in 2000, 2001 and 2004. Thistransformed the Auger facilities into a productionprocessing and export hub that today handlesproduction from six different fields (above).

Through the various tiebacks and expansions,processing capacity more than doubled, and thefacilities network became more complex.Because of limited test-separator capacity andthe complexity of measurement and allocationneeds, well testing began to require productiondeferment and downtime on some wells. This further increased susceptibility to a system shutdown. With platform space at a premium,adding separation capacity was both difficult and expensive.

By installing four multiphase flowmeters,Shell reduced both flow interruptions and theneed to divert and defer production because ofwell testing. Utilizing Vx technology in a continu-ous producing environment provided a simplerconcept for new subsea production wells. Shellinstalled six additional PhaseWatcher meteringdevices on incoming production flowline tiebacksand the DVA production manifold. This allowscontinuous flow-rate monitoring of subsea flow-lines without the need for individual separators.

The use of multiphase flowmeter technologyat the Auger complex led to MMS approval ofthis technology in combination with NODAL production system analysis for measurementand allocation applications.19 Multiphase meter-ing solved important problems at the Augerplatform and established an economic means ofmeasuring future production at this hub facility.

Improving Onshore Development Planning In North Africa, surface facilities for five satelliteoilfields are located on 12 onshore well padsspread throughout the development area. Pro-duction is allocated among various partnersbased on the ownership and royalty percentagesof each company.

The operator faced difficulties planning forfuture development because of increasing com-plications associated with integrating new wellsinto the existing test-separation system and thehigh costs of expanding that system. Test-separa-tor operation periodically caused significant pressure losses in the surface gathering systemthat required the use of field compressors tocompensate for these losses. Gas flaring wasoccasionally necessary to control the resultingpressure increases.

16. The weight figure applies to a Vx metering system withan 88-mm [3.5-in.] diameter venturi throat. A smallerdiameter version of the system was also used in some of the applications.

17. Mehdizadeh, reference 2. 18. Mehdizadeh, reference 2. 19. An analytical tool for forecasting the performance at

various points, or nodes, in a production system, NODALanalysis is used to optimize well-completion and surfacefacility designs, maximize well performance and reservoir deliverability, identify restrictions or limitationsin the system and improve operating efficiency.

> Subsea field-development strategies. Higher-than-anticipated production at the Shell Augerplatform in the Gulf of Mexico led to facility expansions, followed by a series of tiebacks from nearbysubsea fields that required additional facilities. This transformed the Auger facility into a high-volumeprocessing and export hub. Multiphase flowmeters helped eliminate costly bottlenecks at the Auger hub, enabling Shell to economically meet complex measurement and allocation needs.

Pink sand development,

1995

Facility expansions,1995, 1997 and 2000

Peak production, 1998 to 2000

Macaroni field,first subsea tieback, 2000

Satellite field exploration

Cardamon fielddiscovery, 1996

Auger field production

Time

The Auger Transition to a Subsea Host

Serrano and Oregano fieldtiebacks, 2001

Auger hub processing

Habanero and Llano field

tiebacks, 2004

Firstproduction,

1994

The operator installed a series of 12 PhaseWatcher multiphase metering systems,including 52- and 88-mm meter sizes, throughoutthe field. Seven of the meters were dedicated tofiscal allocation and five to well testing for reser-voir management. Key specifications for the newmeters included internal data storage, directlinkage to a service computer and compatibilitywith the existing supervisory control and dataacquisition (SCADA) systems. The operatorimplemented the Vx Fluid ID module with a set of field-specific fluid property data loadedinto the meter setup parameters. The deploy-ment of Vx meters simplified field developmentplans considerably.

The first four PhaseWatcher systems weredelivered and commissioned in October 2004.The site-acceptance process incorporated sev-eral field tests to evaluate meter performance.To date, the Vx systems have proved highly accurate with demonstrated measurementrepeatability. By using these meters, the opera-tor avoids production pumping and flaring.Delivery and commissioning of the remaining Vx multiphase flowmeter systems were slated for the end of 2004 and early 2005.

Streamlining Field InfrastructureAt another North Africa location, several partnershold working interests in three satellite fields,which are being developed and tied back to a cen-tralized host production facility. Installation ofPhaseWatcher 52-mm multiphase well productionmonitoring systems achieved considerable costsavings by eliminating the need for remote sepa-ration and metering stations (above).

To address a growing need to improve multi-phase flow measurement for production andfiscal allocation, and for field optimization, Theoperating company commissioned the firstPhaseWatcher metering system in August 2003.This meter initially allocated productionbetween the partners in Well 1 during develop-ment of the first field. Six months later, theoperator brought Well 2 on stream through thesame meter. The two wells are about 7.5 miles[12 km] from the main gathering station.

The PhaseWatcher monitoring system savedan estimated US$10 million by eliminating theneed for an intermediate field station. Numerousfield tests compared meter performance againstconventional measurements made by three third-party test separators and associated gauge tanks.Results indicated a maximum difference of lessthan 1.7% with daily oil production rates thatranged from 4,500 to 6,000 B/D [715 to 954 m3/d].

Based on this record, a second, identicalPhaseWatcher device was installed in January2004 to meter two wells in the second field. Per-formance has been comparable to the initialsystem. A third PhaseWatcher 52-mm flowmeterwas commissioned in November 2004 to monitor production from the third field. Data from thismetering system facilitate operation of a wellequipped with an intelligent completion thatincorporates four downhole flow-control valves.The second well in this field is scheduled tocome on stream in 2005 and flow through thesame meter.

Mobile Testing OpportunitiesMultiphase flowmeters have transformed perma-nent flow measurement and are also creatingnew opportunites in mobile and periodic welltesting. In many instances, it is uneconomic toretrofit existing production wells with perma-nent multiphase flowmeters. The PhaseTestermobile system acquires the same high-quality,dynamic data as the permanent PhaseWatchersystem. Measurements can be obtained relatively frequently, which is an ideal solutionin locations where multiphase flow data were previously obtained infrequently or not at all.

For the first time, there is no overridinglogistical or technical obstacle to testing anyproduction well an operator needs to evaluate. Production wells can be tested at any time, but apotentially advantageous time for mobile testingis during the cleanup stage just after drilling. Inthis way, testing can be integrated into thelarger package of well services to establish optimized production from the very beginning.

Additionally, by combining a full complementof downhole production-logging measurementswith the surface measurements of a multiphaseflowmeter, it is possible for the first time toobtain a complete well diagnosis. The mobilePhaseTester flowmeter plays an essential role indiagnosing the source of water encroachment incommingled producing wells.

62 Oilfield Review

>Minimal multiphase meter installation. The PhaseWatcher 52-mm production-monitoring system was installed in a North Africa field to streamline thesurface infrastructure for measuring and allocating production.

20. Mus EA, Toskey ED, Bascoul SJF and Barber EC: “Development Well Testing Enhancement Using a Multiphase Flowmeter,” paper SPE 77769, presented atthe SPE Annual Technical Conference and Exhibition,San Antonio, Texas, September 29–October 2, 2002. Mus EA, Toskey ED, Bascoul SJF and Norris RJ: “AddedValue of a Multiphase Flow Meter in Exploration WellTesting,” paper OTC 13146, presented at the OffshoreTechnology Conference, Houston, April 30–May 3, 2001.

21. A floating production, storage and offloading (FPSO) system is an offshore facility, typically ship-shaped, thatstores crude oil in tanks located within the vessel hull.The oil is periodically offloaded to shuttle tankers orocean-going barges for transport to receiving and processing facilities. An FPSO can be used to developand produce marginal reservoirs and fields in deep wateror remote from existing pipelines.

Winter 2004/2005 63

Cleanup Well TestingTotal used the PhaseTester system to performcleanup tests on subsea development wells in the deepwater Girassol field, Angola. The Vx system obtained complete flow data coveragethat was more accurate than with a conventionalseparator (right). Data obtained by multiphasemetering were instrumental in helping the oper-ator bring these wells on stream economically atplanned levels of production.

This approach ensured that the wells wouldflow as projected on a sustained basis, enhancedoperational efficiency, safety and environmentalprotection in well-testing operations, and avoidedthe need for a conventional test separator. Inaddition, multiphase flow data established a valu-able foundation for ongoing field and reservoirmanagement decisions.20

All wells had to reach optimal production levels as they came on stream to ensure that theprojected plateau for field production could beattained with the number of planned wells. Addi-tionally, flow-assurance considerations imposedelaborate startup procedures for these wells.

Each well needed to reach an immediate oil production level of 10,000 to 15,000 B/D[1,590 to 2,385 m3/d] to create a slug-free, stabilized flow in the subsea flowlines. At thesame time, it was necessary to maintain sand-control integrity through a graduated startupthat was not possible from the floating produc-tion, storage and offloading (FPSO) systembecause of equipment constraints and flowline-stability concerns.21

To perform these startups without risk to thewells required execution from the drilling rig.That meant setting strict limits on budgeted rigtime to control this considerable expense andidentifying any additional rig interventionsquickly. After the first two wells were thoroughlytested, all subsequent wells were allotted minimal cleanup time, and performance evaluations had to be completed during thecleanup stage.

The mobile PhaseTester system providedcontinuous flow-measurement data during wellcleanup that were unobtainable with conven-tional measurements. Dynamic flow-rate dataallowed the operator to optimize the cleanupperiod and avoid unnecessary rig time. The multiphase data confirmed the precise point atwhich fluids and debris were completelyremoved and unimpeded production was flowingfrom all wells.

The multiphase meter data formed the basisfor pressure-buildup interpretations that wouldnot have been possible with only test-separator

data. These interpretations led to key analyses ofwell and completion performance. Permeabilityand skin measurements derived from these pressure-transient data confirmed the selectionof sand-control completion designs in a numberof wells and facilitated the choice of tool-running procedures.

The data were also valuable for formation-evaluation and dynamic reservoir modeling,which, in turn, increased confidence in well-behavior predictions. In one case, using dynamicmultiphase flow measurements to track the estimated transient productivity index (PI) of ahorizontal well led to a timely decision to sus-pend and reenter the well, which had respondedpoorly to cleanup. After the intervention, the PIimproved dramatically to meet expectations,

>Mobile well testing. Total connected thePhaseTester system to a downstream choke and bypass valve during the cleanup phase afterdrilling and completing development wells indeep water offshore Angola, West Africa (top).The productivity index (PI) derived frommultiphase measurements on eight wells wasvalidated by subsequent PI calculations duringthe production phase (bottom).

Prod

uctiv

ity in

dex

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durin

g pr

oduc

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PI during well cleanup

and production logging confirmed that theentire horizontal section was producing.

Complete coverage of cleanup rates made animportant contribution to interference testingconducted prior to first oil in key areas of thefield. Monitoring production from one well during cleanup of a nearby offset well providedvaluable data about pressure and fluid trans-missibility through formation layers and geologicfaults (see “Reducing Uncertainty with Fault-Seal Analysis,” page 38).

These data led Total to revise the drillingpattern and eliminate one of the proposed devel-opment wells. Data from a multiphase flowmeterand downhole gauges also expedited decision-making that led to slickline and coiled-tubingintervention on another well, which opened apartially closed completion valve and allowedthe well to flow normally.

The multiphase flowmeter system improvedpersonnel safety by eliminating the test separa-tor with its safety valves and relief lines. Inaddition, multiphase metering reduced cleanupflow periods and hydrocarbon flaring, whichhelped protect the environment.

Future Multiphase Technology As utilization increases, multiphase flowmeterswill replace conventional separators in manywell-testing applications and eliminate the needfor costly, space-consuming facilities at someproduction sites. Future demand for conven-tional test separators will increasingly be drivenby fluid-sampling requirements. Some sampling,however, particularly for pressure-volume-temperature (PVT) analysis, will be performedwith multiphase flowmeters.

Technological innovations are likely to pushmultiphase flowmeters into higher pressure and temperature environments. This could significantly expand subsea applications for Vx technology, while spawning additional appli-cations onshore in heavy-oil thermal recoveryand in natural gas markets.

Another possibility for future growth is intelligent multiphase flowmeter systems that,in addition to providing flow-rate information,diagnose meter health and measurement quality. In all, growing demand and new insightsinto potential applications for multiphaseflowmeters are virtually certain to spur continu-ing, competitive innovations and enhancementsto meet new challenges. —JP/MET

Ian Atkinson is Engineering Advisor, SchlumbergerCambridge Research (SCR), England, where he workson multiphase flow research. He joined the company in1984 in Farnborough, England, where he designed anddeveloped single-phase fluid pressure, density andflowmeters. In 1990, he transferred to SCR to work onmultiphase flowmetering and later to SchlumbergerRiboud Product Center (SRPC) in Paris, where heworked on developing Vx* multiphase well testingtechnology, which later led to PhaseWatcher* fixedmultiphase well production monitoring equipment andPhaseTester* portable multiphase periodic well testingequipment. Ian holds a BS degree in physics from theUniversity of Bristol, and a PhD degree in materialsscience from the University of Warwick, both in England.

Michel Berard, Scientific Advisor for SchlumbergerMoscow Research, earned a Diplome Grand Ecole inphysics from Ecole Normale Supérieure de Paris, adoctoral degree in physics from Université Pierre etMarie Curie, Paris, and a PhD degree in molecularphysics from University of Paris. He joined the com-pany in 1984 as head of the sensor physics lab atSchlumberger Montrouge Research, France, afterspending 13 years in academia. Since then, he hasworked as head of the flow measurement and telemetrydepartment at Flopetrol in Melun, France, and at theSchlumberger Riboud Product Center in Clamart,France, where he was head of flow measurement andphysics métier manager. Prior to transferring toMoscow, he was scientific advisor at SchlumbergerDhahran Carbonate Research in Saudi Arabia. A prolificauthor, Michel also holds 6 patents.

Tim Brewer is Senior Lecturer in the Department ofGeology, University of Leicester, England, and Directorof the University of Leicester Borehole ResearchGroup. Before assuming his current post, he worked asa geochemist for the British Antarctic Survey, as a con-sultant geologist and geochemist for Midland EarthScience Associates, and as a geology lecturer at theUniversity of Nottingham in England. Tim has a BSdegree from Portsmouth Polytechnic in England, and a PhD degree from the University of Nottingham,England, both in geology.

Kip Cerveny is Development Lead, Greater PrudhoeBay Satellites Team, for BP Alaska, based inAnchorage. Prior to joining the company as a geologistin 2000, he began his career with ARCO as a researchgeologist in Plano, Texas, USA, and later worked as anAlaska-based geoscience consultant on projects inAlaska, Russia and Kazakhstan. Kip received BA andMS degrees from Dartmouth College, Hanover, NewHampshire, USA; and a PhD degree from the Universityof Wyoming in Laramie, USA.

Gilbert Conort is Well Testing Marketing Manager for Schlumberger Well Completions and Productivityheadquarters in Rosharon, Texas. He is responsible fordeveloping strategies and launching new products andservices for well testing, tubing-conveyed perforatingand slickline businesses. He joined the company as anelectronics engineer in Clamart, France, and subse-quently transferred to Flopetrol Engineering in Melun,France, as pressure gauges program manager and lateras early production systems pressure measurementsengineering manager. After various management positions in France and the USA, he assumed his current position in 2004. He is a cofounder of 3-Phase*Measurements AS, a joint venture betweenSchlumberger and Framo Engineering AS, to developVx technology. Gilbert earned a diploma in electronicsengineering from Ecole Supérieure d’Informatique-Electronique-Automatique in Paris.

Pierantonio Copercini, Deputy Drilling and WorkoverGeneral Manager, Belayim Petroleum Company(Petrobel), an Eni operating company, is based inCairo. He manages all activity of the company’s drillingand workover rigs. He began his career with Agip as anonshore drilling supervisor and worked in several posi-tions including drilling engineer, drilling manager andwell operations manager, before taking his currentassignment. Pierantonio has a technical schooldiploma in mechanics issued in Milan, Italy.

Russell Davies, who is based in Dallas, is the USOperations Manager and consulting geologist for Rock Deformation Research (RDR) USA Inc. He holds a PhD degree in structural geology from TexasA&M University in College Station, and has worked in the oil and gas industry for more than 14 years. At RDR, he manages projects at the regional andprospect scale from basins worldwide, develops andteaches training courses, and participates in appliedresearch. He is also an adjunct professor at theUniversity of Texas in Dallas. Prior to working for RDR,Russell spent three years with Shell Oil Company onexploration and development projects in the Gulf ofMexico before joining the structural geology researchgroup at ARCO. There, he was responsible for researchand consulting on structural interpretation and valida-tion, fault and fracture analysis and fault-seal analysis.He worked on fault-related problems in basinsthroughout the world and recently edited a specialissue of the AAPG Bulletin on fault seals.

Graham Dudley is North Sea Technology Manager forBP in Aberdeen. Since joining the company in 1985, heworked from exploration to production as a geologistand later as a team leader and field development man-ager of E&P business throughout the North Sea, UK,Norway, Alaska, Ukraine and other project locations.Graham earned a BS degree in geology from Universityof Liverpool, England.

Mohamed El Gamal, Sales Manager for theSchlumberger Libya GeoMarket*, is responsible forintroducing new technology including AIM* At-BitInclination Measurement tool, VISION* FormationEvaluation and Imaging While Drilling tools andPowerDrive* rotary steerable systems. Previously, hewas Drilling and Measurements (D&M) sales managerfor the Schlumberger East Africa & East MediterraneanGeoMarket, based in Cairo. He joined the company in1997 as a sales and applications engineer and laterworked as a D&M account manager. He has alsoworked as a petroleum geologist, pressure evaluationgeologist, wellsite geologist and technical sales repre-sentative for EXLOG and Milpark throughout the MiddleEast and the North Sea. Mohamed holds a PhD degreein petroleum geology from Cairo University in Egypt.

Tatsuki Endo, Marketing Manager for SchlumbergerKK Technology center, Fuchinobe, Japan, is responsiblefor coordination of all client collaboration projects. Hejoined the company in 1981 as a field engineer inIndonesia. He later worked in Norway and in Brazil asa log analyst before returning to Japan, where hejoined the field support staff and managed several projects. Prior to his current position, Tatsuki workedas a project manager of VSI* Versatile Seismic Imagertool development. He received a BS degree in physicsfrom Sophia University in Tokyo.

Paul Jeffrey Fox is Director of Science Operations,US Implementing Organization, Integrated OceanDrilling Program at Texas A&M University, CollegeStation, and a Professor in the Geology, Geophysicsand Oceanography Departments. He has participatedin 36 oceanographic expeditions and has served aschief scientist on 26 of those. His primary researchinterests include investigation of the volcanic andstructural processes that create oceanic lithospherealong the mid-oceanic ridge system. A prolific author,Paul has served on advisory committees for theNational Science Foundation, University NationalOceanographic Laboratory System and other major USoceanographic research programs. He obtained a BAdegree in geology from Ohio Wesleyan University inDelaware, Ohio, USA; and a PhD degree in marinegeology/geophysics from Columbia University in NewYork City.

Richard Fox, based in Aberdeen, is Lead Geologist,North Sea Portfolio Quality Team for BP. He joined thecompany in 1991 as a research geologist and helpeddevelop BP’s fault, fracture and stress analysis capabil-ities. He later worked around the world—Alaska, Gulfof Mexico, Colombia, Venezuela, North Sea, Norwayand the Middle East—as part of BP’s structural geologyteam and as structural network leader. Prior to takinghis current post, he worked as subsurface team leader for BP Appraisal and Development. Richard earned aBS degree from Kingston Polytechnic, London; and aPhD degree from University College, Cork, Ireland,both in geology.

Contributors

64 Oilfield Review

Dave Goldberg is a Doherty Senior Scientist at theLamont-Doherty Earth Observatory of ColumbiaUniversity in Palisades, New York. He is also director ofits Borehole Research Group, which managed loggingservices for the Ocean Drilling Program and now forthe US component of the Integrated Ocean DrillingProgram. Dave received BS and MS degrees in marine geophysics from Massachusetts Institute ofTechnology, Cambridge, USA; and a PhD degree inborehole geophysics from Columbia University, NewYork City. He has written more than 100 scientific publications on topical research in borehole andmarine geophysics.

Masahiro Kamata is Schlumberger KK SeismicAdvanced Studies Project Leader in Fuchinobe, Japan,where he is developing new seismic sensors for down-hole, seabed and land seismic applications. Since joining the company in 1976, he has worked on down-hole seismic tools in Japan and on acoustic telemetryresearch while based in Sugar Land, Texas, withAnadrill. He also worked on seismic instrument devel-opment and seismic while drilling for Geco-Prakla inDallas, and in Hannover, Germany. Masahiro is theinventor of the downhole seismic array and the geo-phone accelerometer. He has a BS degree in mechani-cal engineering from Tohoku Gakuin University, Sendai,Japan; and MS and PhD degrees, also in mechanicalengineering, from Rice University, Houston.

Peter Kaufman, Principal Research Scientist, works atSchlumberger Research in Cambridge, Massachusetts.Since taking this position in 1998, he has worked as astructural geologist in the Geology program, performingdetailed field characterizations of fault-damage zonesusing differential global positioning system mapping.He also developed 3D visualizations of outcrop andsubsurface data using a variety of software programsand developed Web-based visualization of fault juxtaposition. Peter began his career as a petroleumgeologist in basin modeling with Amoco ProductionCompany in 1995, after earning a BS degree in geologyfrom Case Western Reserve University, Cleveland,Ohio; and a PhD degree in geology from theMassachusetts Institute of Technology. He joinedSchlumberger-Doll Research, Ridgefield, Connecticut,USA, in 1998, and also worked at the AbingdonTechnology Center in England, where he wrote specifications documents for several FloGrid* reservoirmodeling software modules.

Yoshi Kawamura, based at the Japan Agency forMarine-Earth Science and Technology (JAMSTEC) inYokosuka, is responsible for international relationshipsand coordination with the Integrated Ocean DrillingProgram (IODP) for the Center for Deep EarthExploration (CDEX). He joined JAMSTEC in 2001 afterholding several positions including wireline field ser-vice manager, wireline location manager and oilfieldservice marketing manager for Schlumberger Wireline.Yoshi earned a BS degree in applied physics fromTokyo University of Agriculture and Technology.

Slaheddine Kefi, Senior Research Scientist atSchlumberger Cambridge Research, England, isresponsible for the development of new formulationsin oilfield stimulation and cementing. Since taking thisposition in 2004, he has researched the developmentof new oil-base muds and worked on matrix acidizingin mature-field conditions. He joined the company in1998 as a development engineer for Dowell in Clamart,France, and has also worked in Sugar Land, Texas, ona variety of projects including OilSEEKER* aciddiverter, CemCRETE* concrete-based oilwell cementingtechnology and LiteCRETE* slurry systems. Slaheddineholds MS and PhD degrees from l’Université Paris Sud,Orsay, France; and an MS degree from Ecole Supérieurede Physique et de Chimie Industrielles, Paris, all in chemistry.

Steve Kittredge is a General Field Engineer for theHouston Offshore District Ocean Drilling Program(ODP) of Schlumberger Well Services, based inWebster, Texas. He is currently working on Expedition304 of the Mid-Atlantic Ridge. Previously, he was thesenior engineer for ODP, responsible for providing log-ging services and maintaining all logging equipmentfor Lamont-Doherty Earth Observatory and its projects.Steve has a BS degree in mechanical engineering fromthe Georgia Institute of Technology, Atlanta, USA.

Rob Knipe is Professor of Structural Geology andDirector of Rock Deformation Research (RDR), aresearch/consultancy spin-out company, at Universityof Leeds in England. He formed this group of geoscien-tists in 1992, to provide specialist structural geologyservices to the oil and mining industries, includingnew methods to evaluate the impact of fault structureson the flow processes associated with hydrocarbonexploration and production. He has led research intothe physical and chemical behavior of rocks duringdeformation, and has focused on evaluating the dualrole of faults as enhanced permeability zones for concentrated fluid migration and as low-permeabilitybarriers to fluid flow. The author of more than 70research papers, Rob frequently presents keynote lectures at international conferences and has wonawards from the Geological Society of London and theAAPG for his research. He is a member of the steeringcommittee for the National Environment ResearchCouncil (NERC) Micro to Macro Fluid Flow in Rocksresearch program and has been chairperson of theAAPG Reservoir Deformation Research Group. Robwas recently awarded the William Smith Medal of theGeological Society of London.

Bob Krantz is a Structural Geologist, UpstreamTechnology, for ConocoPhillips in Houston. There hefocuses on the impact of faults and fractures on reservoirperformance, and trap effectiveness and the relation-ships of small structures to regional deformation.Previously, he worked in Alaska for ConocoPhillips,ARCO Exploration Research, ARCO InternationalExploration and ARCO Alaska. He holds a BS degree in geology from the University of Utah, Salt Lake City,USA; and MS and PhD degrees in geology from theUniversity of Arizona, Tucson, USA. Bob has also donepostdoctoral research at the University of Arizona andat the University of Rennes, France. He is chairman ofthe AAPG Reservoir Deformation Research Group.

Shin’ichi Kuramoto is the Science Service andInformation Service Group Leader at the JapanAgency for Marine-Earth Science and Technology(JAMSTEC). Before this, he worked as a seniorresearcher for the Geological Survey of Japan in theAdvanced Industrial Science and Technology group.Shin’ichi has a PhD degree in marine geology and geophysics from Tokyo University, Japan.

Chris Kuyken, Team Leader, Well Engineering andWell Services Technology for Shell Exploration &Production in Europe, has more than 22 years of expe-rience in oil- and gas-well drilling with Shell. He hasworked onshore and offshore in many well engineeringpositions in Oman, Brunei and, since 1999, inScotland. He is an energetic proponent of Shell’sDrilling the LimitTM philosophy, whereby people, HSEand technology are the keys to success. A EuropeanEngineer (EUR ING) registered with EuropeanFederation of National Engineering Associations(FEANI) and a Chartered Engineer (C Eng) throughthe British Engineering Council, Chris earned a BSdegree in chemical engineering technology fromHogere Technische School (HTS), The Hague.

Jesse Lee, Schlumberger Program Manager for oilfieldchemical products in Sugar Land, Texas, is responsiblefor ClearFRAC* polymer-free fracturing fluid, coalbedmethane fluid projects and high-value polymer fracturingfluids. He joined the company in 1997 as a develop-ment engineer for Dowell in Sugar Land, and becamesenior development engineer for surfactant-based viscoelastic fracturing fluids before taking his currentpost. Jesse has a BS degree in natural products chem-istry and analytical chemistry from National TaiwanUniversity, Taipei; and PhD degrees in inorganic chem-istry from Yale University, New Haven, Connecticut;and in polymer/organometallic chemistry fromMassachusetts Institute of Technology, Cambridge.

Wayne Longstreet is Drilling Advisor for Dragon OilPlc., based in Dubai, UAE. He has worked for the company for four years.

Trey Lowe, International Account Manager forSchlumberger Well Completions and Productivity(WCP), is based in Houston. He is responsible for sup-porting international testing and multiphase meteringoperations for Houston-based customers. Since joiningthe company in 1998, Trey has worked in various fieldmanagement and sales positions including productchampion for PhaseWatcher products and services. He holds a BS degree in chemical engineering fromOklahoma State University in Stillwater, USA.

Winter 2004/2005 65

Iain McCourt, Drilling and Engineering Manager for the Schlumberger Caspian GeoMarket in Baku,Azerbaijan, is responsible for all drilling and engineer-ing design work performed for clients in the CaspianSea area. He joined the company after earning a BSdegree in geology from Queen’s University in Belfast,Northern Ireland. He began his career as a mud loggerin the North Sea and worked throughout Asia, theMiddle East, Australia and New Zealand in positions ofvarying responsibility including measurements-while-drilling (MWD) and logging-while-drilling (LWD) engineer, directional driller, product champion, fieldservice manager, instructor for drilling engineeringand rotary steerable systems and knowledge managerfor measurements training. Before taking his currentposition, Iain was based in Midland, Texas, as operationsmanager for West Texas.

Allan McDiarmid is Senior Petroleum Engineer forApache Energy Ltd in Perth, Western Australia,Australia. He was graduated from the University ofStrathclyde, Glasgow, Scotland, in 1985, with a BSdegree (Hons) in mining and petroleum engineering.Allan has held various reservoir and petroleum engineering positions at Soekor in South Africa, and at Santos and Helix Well Technologies in Australia.

Parviz Mehdizadeh, Consultant, ProductionTechnology Inc., in Scottsdale, Arizona, began hiscareer in 1962 with Conoco Inc. During his 30 yearswith the company, he worked on technology develop-ment programs and production development applicationprojects, including those dealing with the processingand measurement of fluids offshore. He also directedthe construction of the Conoco multiphase field test facility in Lafayette, Louisiana, USA. From 1993 to 1996, he worked as a consultant for the AgarCorporation, directing the development, marketing andfield installation of multiphase meters for well testing.Since then, as a consultant, he has provided technicaladvice on selection and specification of multiphasemeters to operating companies. He cochaired the TexasA&M University Multiphase Metering Users Roundtableand is currently working with the American PetroleumInstitute Committee on Petroleum Measurements ondevelopment of specifications for multiphase meteringsystems. Parviz received a BS degree in physics, an MS degree in metallurgical engineering, and a PhDdegree in chemical engineering and material science,all from the University of Oklahoma in Norman.

Stefan Mrozewski is a Schlumberger Drilling andMeasurements DESC* design and evaluation servicesfor clients in-house sales and support engineer for BPin Houston. He coordinates MWD and LWD operationsfor BP’s Gulf of Mexico (GOM) shelf and deepwaterdevelopment groups. He joined Schlumberger in 2000as a field engineer in Youngsville, Louisiana. He sailedas lead LWD engineer on Ocean Drilling Program Legs204 and 209, drilling for gas hydrates and testing RAB*Resistivity-at-the-Bit logging-while-coring technology.Stefan earned his BS degree in geophysics from theUniversity of Waterloo, Ontario, Canada.

Greg Myers is Manager of Engineering and TechnicalServices for the Borehole Research Group at theLamont-Doherty Earth Observatory in Palisades, New York. Since graduating from Rutgers, The StateUniversity of New Jersey, New Brunswick, USA, in 1991,he has been involved in many aspects of borehole geophysics such as field service, data analysis, toolresearch and development, new technology integrationand program management. His areas of engineeringfocus are new measurements, heave compensation, log-ging while coring, and new core-collection techniques.In addition to his shore-based management and designresponsibilities, Greg has participated in many scientific ocean drilling expeditions.

Erik Nelson retired from Schlumberger in 2004 after27 years of service, and is now an independent consul-tant in Houston. Before his retirement he was an engineering advisor with Schlumberger in Sugar Land,Texas, where he worked on the development of newchemical products for cementing, fracturing and sandcontrol. Erik has a BS degree in chemistry and an MSdegree in geochemistry, both from the Colorado Schoolof Mines in Golden. He is chief editor of the textbookWell Cementing, currently in its third printing.

Angel Nuñez Hernandez is Technical Manager, SouthCentral District for Petróleos de Venezuela SA(PDVSA), located in Barinas, Venezuela. He began hiscareer in 1987 at Corpoven, a PDVSA subsidiary, in theSan Tomé District and specialized in production opera-tions, production engineering, chemical stimulations,perforation operations and workover wells. In 1997,Angel was transferred to the Barinas District as reser-voir leader and later supervised reservoir developmentin the production management unit for PDVSA. Heholds a BS degree in petroleum engineering from theUniversity of Zulia, Maracaibo, Venezuela.

Tom Olsen, Schlumberger US Land UnconventionalGas Business Development Manager, is based inDenver. He has been with Schlumberger since joiningDowell in 1980. His first assignments involving well-bore stimulation, production enhancement and projectengineering took him to postings in the North Sea, the former Soviet Union (CIS), Canada, and, in theUSA, Alaska, Texas, Oklahoma and Colorado. He thenserved as technical manager of production enhance-ment for Europe and the CIS. After serving as Dowellwell production services manager for Europe and theCIS, he moved to Sugar Land, Texas, as marketingmanager for the Well Services Product Center. Beforetaking his current assignment, he managed theSchlumberger Consulting Services Group. Tom has aBS degree in geology from the University ofConnecticut in Storrs.

Mehmet Parlar, Business Development ManagerSandface Completions-Fluid Systems with theSchlumberger Sand Control Business Developmentteam in Rosharon, Texas, provides technical and marketing input to sand-control product developmentand sand control and stimulation fluids support. Afterreceiving MS and PhD degrees in petroleum engineer-ing from the University of Southern California at LosAngeles, he joined Dowell in Tulsa, as a developmentengineer. From 1996 to 1999, he was a reservoir engineer with the Dowell Sand Control BusinessDevelopment team in Lafayette, Louisiana. Before his current posting, Mehmet was principal engineer,horizontal completion solutions in Rosharon and well

production specialist and technical coordinator inSugar Land, Texas. Author of many publications, healso holds a BS degree in petroleum engineering fromIstanbul Technical University in Turkey.

Barry Persad, based in Sugar Land, Texas, is ProductChampion, Motors and Drilling Tools, for SchlumbergerDrilling and Measurements. He works as liaison for theintroduction of PowerEdge* high-output performancedrilling motors as well as the implementation of newthin-wall stator technology to other powered rotarysteerable drilling tools. After earning a BS degree inenvironmental science from the University of Guelph,Ontario, Canada, he began his career with BakerHughes Inteq in Trinidad, West Indies, as a mud-log-ging specialist. Barry joined Schlumberger Anadrill ofCanada in 1997 as an MWD specialist and also workedas a directional driller and as field service manager,directional drilling, in Canada before taking his current position.

Bruno Pinguet, Technical Advisor Multiphase FlowMetering for Schlumberger International OilphaseDBR, is located in Aberdeen, Scotland, and Bergen,Norway. He is charged with defining and developingthe business and the technical transfer of knowledge.He also represents Schlumberger in the Wet Gas JointIndustrial Project with other companies includingSaudi Aramco, BP, Shell, Total, BG Group andConocoPhillips. He began his career with SchlumbergerResearch & Engineering Flopetrol in England andFrance, designing a new sensor to measure flow structure in diphasic flows. He transferred to theSchlumberger Riboud Product Center engineeringdepartment where he worked on production loggingand modeling measurement in multiphase flows. Healso worked in Kuwait, Indonesia and Malaysia as afield engineer and in Norway as product developmentmanager for 3-Phase Measurements AS. Bruno has aPhD degree (Highest Hons) in fluid mechanics fromEcole Normale Supérieure de Paris, and a postgraduatedegree (Hons) in physics of liquids from UniversitéPierre et Marie Curie, Paris.

Timothy L. Pope, Schlumberger Product Championfor ClearFRAC fracturing fluids in Sugar Land, Texas,works with product development teams on testing,product evaluation and field support. He joined thecompany in Vernal, Utah, after earning a BS degree inpetroleum engineering from the University of Wyomingin Laramie. He will also obtain an MS degree in petro-leum engineering, pending defense of his thesis, fromthe University of Wyoming. Prior to taking his currentposition in 2003, he worked as a DESC engineer atTalisman Energy in Calgary.

Brian Powers is a Senior Completions Engineerresponsible for completion design and execution in theAzeri-Chirag-Gunashli (ACG) fields offshore Baku,Azerbaijan, for BP. He joined Amoco in 1982, and sub-sequently worked for BP after the 1998 merger of thetwo companies, in various production engineering andcompletions engineering assignments in the USA,Egypt and the UAE before transferring to Baku in 2001.Brian received a BS degree in geological engineeringfrom South Dakota School of Mines and Technology,Rapid City, USA.

66 Oilfield Review

Frank R. Rack is Director, Ocean Drilling Programs(ODP) and Director, Department of Energy/NationalEnergy Technology Laboratory (DOE/NETL) programsat the Joint Oceanographic Institutions (JOI), Inc.based in Washington, DC. He is responsible for pro-gram management and oversight of JOI contracts withthe US National Science Foundation for preserving thelegacy of the ODP and systems integration activities ofthe US Implementing Organization for the IntegratedOcean Drilling Program. Frank is also responsible formanagement and oversight of the DOE/NETL projectsrelated to gas hydrates and provides project manage-ment for new ventures related to scientific oceandrilling. Frank has participated in more than 12research cruises as staff scientist, physical propertiesspecialist and marine specialist. He holds a BS degreein natural resources from the University of RhodeIsland, Kingston, USA; and a PhD degree in geological/geophysical oceanography from Texas A&M University,College Station.

Jon Rodd, Petroleum Development Manager forDragon Oil Plc. in Dubai, UAE, oversees all field devel-opment, drilling and workover operations, 3D seismicoperations, production management and subsurfacereservoir geology and geophysics. Before joiningDragon Oil more than 20 years ago, he worked in theUK North Sea, The Netherlands, Syria, Oman, Fiji,Qatar and Pakistan for several major operators. Jonhas a BS degree from University of Wales, Swansea,and a PhD degree from the University of Reading,England, both in geology.

Alistair Roy, BP Senior Completion Engineer for theRhum gas field in the North Sea, is based in Aberdeen.He is responsible for the design and installation ofthree high-pressure, high-temperature subsea comple-tions in early 2005. Prior to joining BP in 2000, heworked as a petroleum engineer for several companiesincluding Marathon Oil, Monument Oil and BritishGas. Alistair obtained a BS degree (Hons) in appliedgeology from University of Strathclyde, Glasgow,Scotland; and an ME degree in petroleum engineeringfrom Heriot-Watt University in Edinburgh, Scotland.

Mark Sarssam is Head of Reservoir Development andProduction for Dragon Oil Plc. in Dubai, UAE. Beforejoining the company this year, he worked for ShellOman, Shell Brunei, Fina and Amerada Hess. Markreceived an MS degree in petroleum engineering fromImperial College in London.

Gerald Smith is Schlumberger Business DevelopmentManager–Multiphase Well Testing, in Bergen, Norway.He is responsible for the creative development of the multiphase well testing field including meteringand reservoir monitoring. He joined FlopetrolSchlumberger in 1979 after earning a BE degree(Hons) in engineering from the University of Bradford,England. Gerald worked throughout Europe and Africaas an engineer, product manager, account managerand business development manager before moving toHouston as marketing manager for wireline and testingproduction and completion. Prior to taking his currentposition, he was international account manager, multiphase well testing marketing in Houston.

Farag Soliman, Drilling and Workover GeneralManager for Belayim Petroleum Company (Petrobel),is based in Cairo. He holds a BS degree in petroleumengineering from Cairo University.

Phil Sullivan, Principal Engineer for Schlumberger inSugar Land, Texas, is currently developing fluid-lossadditives to improve the efficiency of fracturing fluids,and collaborating with researchers at SchlumbergerCambridge Research, England, and at PrincetonUniversity, New Jersey. Since joining the company in1994 as a development engineer for Dowell, he hasworked on fluid systems, fiber-assisted transport fluids,ClearFRAC fracturing fluids and coiled tubingcleanout operations. Phil has a BS degree from theUniversity of Virginia, Charlottesville, USA; and MSand PhD degrees, all in mechanical engineering, fromPurdue University, West Lafayette, Indiana, USA. A prolific author, he also holds several patents.

Bertrand Theuveny, Production Real-Time ProductChampion/Production Domain Manager based atSchlumberger Cambridge Research, England, isresponsible for the rationalization of production andreservoir collection of answer products and for sup-porting the Real Time infrastructure. He has beeninvolved in well testing since joining Flopetrol in 1985.He has worked in various wireline and testing positionsincluding testing engineer, field service manager,country manager and testing marketing coordinator inBrazil, Algeria and Libya. He transferred to Norway assupport manager for 3-Phase Measurements AS, andbefore taking his current post in 2002, worked asworldwide business development manager for multi-phase well testing. Bertrand earned a BS degree inocean engineering from Ecole Centrale Paris, and MS degrees in petroleum engineering and geophysicsfrom the University of Alaska in Fairbanks.

Allan Twynam, BP Senior Drilling Engineer (Fluids),is based in Sunbury, England, in the Exploration andProduction Technology Group. There he manages thefluid laboratories and is responsible for technical support and development projects in all aspects ofreservoir drilling and completion fluids and formation-damage mitigation. He joined the drilling and comple-tions branch at the BP Research Centre in 1990 afterserving as a wellsite drilling fluid engineer and basemanager in Great Yarmouth for BW Mud, UK. He sub-sequently worked as fluids technical support engineerfor BP International operations and managed fluids,cement and waste-management contracts for BPVenezuela. He returned to Sunbury in 1998 to leadtechnology development projects in drilling wastemanagement. Following the BP-Amoco merger, hemanaged fluids and formation-damage projects for BP.Allan received a BS degree (Hons) in geology andgeography from University College, Cardiff, Wales.

Mike Williams, Schlumberger Global Sales Managerfor Drilling and Measurements in Sugar Land, Texas,helps ensure that client partners employ the mostcost-effective drilling, well placement and formationevaluation technology. He began his career withSchlumberger in 1987 as a mud logger in the southernNorth Sea. He has worked as a directional drillingsupervisor on many projects for various clients in theNorth Sea and on the record-breaking extended-reachdrilling program at Wytch Farm, and as business development manager for drilling-related services in the UK North Sea. The author of several papers,Mike has a BS degree (Hons) in earth sciences fromthe University of Birmingham, England.

Kerry J. Williamson, Senior Process Engineer forShell Exploration and Production Company (SEPCo)EP Americas region, is based in New Orleans, wherehe provides process-engineering support to the ShellGulf of Mexico (GOM) assets and projects. He joinedthe company in New Zealand in 1997 and has workedin the GOM since 2001. He was the facilities engineerfor the Auger tension leg platform where he managedthe installation of multiphase measurement for welltesting of onboard subsea flowlines using Vx multi-phase well testing technology. Kerry obtained a BS degree in engineering from the University ofAuckland, New Zealand.

Allan Wilson is a BP Senior Completions Engineer,based in Aberdeen, where he works in the DeepwaterProduction Unit, covering the Foinaven, Schiehallionand Loyal fields, West of Shetlands. He is responsiblefor completions delivery in those areas and is the technical authority for completion issues. Allan joinedBP in 2000 after working five years for Wellserv plc invarious positions from engineer to project manager.Allan earned a BE degree (Hons) in mechanical engi-neering from The Robert Gordon University, Aberdeen.

Winter 2004/2005 67

An asterisk (*) is used to denote a mark of Schlumberger.Drilling the Limit is a trademark of Shell.

Development ofPetroleum ReservoirsJózsef PápayAkadémiai Kiadó P.O. Box 245H-1519 Budapest, Hungary(Also available from InternationalSpecialized Book Services, Inc.920 NE 58th AvenueSuite 300Portland, Oregon 97213 USA)2003. 939 pages. $89.00ISBN 693-05-7927-8

This book deals with both conventionaland enhanced recovery methods ofcrude oil and natural gas, including discussion of geological principles andsuch topics as reservoir classification,numerical simulation and temperaturemanagement. Also featured are under-ground gas-storage processes in porousrocks, reservoir-model construction,and planning and analysis methods.

Contents:

• Basic Geology for Petroleum Recovery

• Conventional Recovery Processes:Methods of Planning and Analysis

• Enhanced Petroleum Recovery Processes

• Classification of Petroleum Reservesand Resources

• Index

The author does provide a valuable service in bringing togetherliterature from Western, Eastern European (mainly Hungarian), Russian, and other former SovietUnion sources. Reservoir engineeringis not my field, but this book does seemto provide a good reference book tomany aspects of reservoir engineering.Many simple relevant equations can befound within.

Most geophysicists would get littleuse out of this book. Someone workingheavily in development geology/geophysics or reservoir modeling may find it useful as a reference.

Bartel DC: The Leading Edge 23, no. 5

(May 2004): 496, 508.

Coming in Oilfield Review

Carbonate Reservoirs. For all theirhydrocarbon wealth, carbonatereservoirs are notoriously difficult toproduce. To recover these hydrocarbonsas safely and efficiently as possible,scientists and engineers perform formation evaluation, reservoir characterization and completionoptimization at the wellbore scale.At the reservoir scale, operatingcompanies strive to optimize production and the placement ofnew wells. Field examples willdemonstrate how new technologyenhances carbonate evaluation; simpler rock classification schemesfacilitate reliable interpretations ofpore-size distributions and serve asuseful frameworks for reservoir-management decisions.

Subsea Production Assurance.Subsea completions are often tiedback to production facilities throughmiles of flowline and riser.Temperature, pressure and chemistryof the produced fluids must be regu-lated in these subsea productionlines to prevent formation of depositsthat could impede flow between thereservoir and the host facility. Thisarticle describes the roles that fluidtesting, flow boosting and monitoringsystems play in managing the flowof oil, gas and water from one end ofthe production system to the other.

Managing Gas-CondensateReservoirs. A retrograde gas-condensate fluid drops out liquidhydrocarbon when the fluid dropsbelow its dewpoint pressure. Thecondensation can occur in the formation and create a condensatebank that decreases production; or it can happen in the wellbore, loadingup the well with the heavier phaseand often requiring intervention tomaintain production. This articledescribes efforts to maintain wellproductivity despite declining reservoir pressure.

68 Oilfield Review

NEW BOOKS

Corrosion and ProtectionEinar Bardal Springer-Verlag175 Fifth AvenueNew York, New York 10010 USA2004. 336 pages. $89.95ISBN 1-85233-758-3

Intended as a guide for mechanical,marine and civil engineering studentsand also as a reference for practicingengineers, the book combines a practi-cal description of corrosion problemswith a theoretical explanation of thevarious types and forms of corrosion.Exercises for each of the 10 chaptersemphasize the relationship betweenpractical problems and basic scientific principles.

Contents:

• Introduction

• Wet Corrosion: Characteristics, Prevention and Corrosion Rate

• Thermodynamics—Equilibrium Potentials

• Electrode Kinetics

• Passivity

• Corrosion Types with DifferentCathodic Reactions

• Different Forms of Corrosion Classified on the Basis of Appearance

• Corrosion in Different Environments

• Corrosion Testing, Monitoring and Inspection

• Corrosion Prevention

• Index

Although the book was originallywritten in Norwegian, the style is directand the explanations easily followed.The theoretical material is not over-whelming but is adequate for a strongfoundation. Many clear and effectivefigures and diagrams are included.

The book is recommended forintroductory courses in corrosion andas a practical reference for practicingengineers and technicians who want aclear description of basic principlesand applications.

Darby R: Choice 41, no.10 (June 2004): 1911-1912.

Power to the People: How theComing Energy Revolution WillTransform an Industry, ChangeOur Lives and Maybe EvenSave the PlanetVijay V. VaitheeswaranFarrar, Straus and Giroux19 Union Square WestNew York, New York 10003 USA2003. 358 pages. $25.00ISBN 0-374-23675-5

To produce his assessment of the eco-nomic, political and technologicalforces that are reshaping the world’smanagement of energy resources,Vaitheeswaran, an energy reporter forThe Economist, interviewed executivesof oil and utility companies, regulators,chiefs of environmental groups andadvocates of alternative fuels.

Contents:

• Introduction

• Market Forces: The Invisible HandAscendant: Micropower—ThomasEdison’s Dream Revived; Enron vs.Exxon—or, The Sleeping GiantsAwaken; Why California WentB.A.N.A.N.A.s; Oil—The Most Dangerous Addiction

• Environmental Pressures: The GreenDilemma: Welcome to Global Weirding; Clearing the Air; Adam Smith Meets Rachel Carson

• Energy Technology: Bigger than theInternet: The Future of Fuel Cells;Rocket Science Saves the Oil Industry; A Renaissance for Nuclear Power? Micropower Meets Village Power

• Epilogue: The Future’s a Gas

• Notes, Bibliography, Index

Vaitheeswaran (energy and environment correspondent, TheEconomist) has prepared the bestreview of the world’s energy situationthat this reviewer has read.

Comer JC: Choice 41, no. 9 (May 2004): 1696.

The book is entertaining (anotherquality that is unusual in a book aboutenergy policy).

Blair PD: American Scientist 92, no. 3

(May-June 2004): 271.

Fuzzy Logic in GeologyRobert V. Demicco and George J. Klir (eds) Academic Press525 B Street, Suite 1900San Diego, California 92101 USA2004. 347 pages. $95.00ISBN 0-12-415146-9

Aimed at geoscientists, this book out-lines the role of fuzzy logic, a system ofconcepts and methods for exploringmodes of reasoning that are approximaterather than exact. The authors introducethe use of fuzzy set theory with individ-ual chapters on topics relevant to earthscientists: sediment modeling, fracturedetection, reservoir characterization,clustering in geophysical data analysis,groundwater movement and time series analysis.

Contents:

• Introduction

• Fuzzy Logic: A Specialized Tutorial

• Fuzzy Logic and Earth Science: An Overview

• Fuzzy Logic in Geological Sciences:A Literature Review

• Applications of Fuzzy Logic toStratigraphic Modeling

• Fuzzy Logic in Hydrology and Water Resources

• Formal Concept Analysis in Geology

• Fuzzy Logic and Earthquake Research

• Fuzzy Transform: Application to theReef Growth Problem

• Ancient Sea Level Estimation

• Acknowledgments, Index

The book serves as an excellentstarting point for any geophysicistinterested in learning about soft computing techniques, and applyingthem to seismic processing and inter-pretation. I soon hope to see someapplications of this technology in our industry, and be able to review avolume on fuzzy logic in geophysics in the not too distant future.

McCormack M: The Leading Edge 23, no. 6

(June 2004): 606-607.

69Winter 2004/2005

The Travels and Adventuresof Serendipity: A Study inSociological Semantics and theSociology of ScienceRobert K. Merton and Elinor Barber Princeton University Press41 William StreetPrinceton, New Jersey 08540 USA2004. 328 pages. $29.95 ISBN 0-691-11754-3

The book traces the history of the wordserendipity—that happy combination of knowledge and luck by which a discovery is made that is not quite accidental. Tracing the word from itsmid-18th century coinage into the 20thcentury, the authors chronicle much of what is now the natural and socialsciences. The book also represents theargument against the rhetoric of purescience that defines discovery as onlythe result of rigid research planning.

Contents:

• The Origins of Serendipity

• Early Diffusion of Serendipity

• Accidental Discovery in Science:Victorian Opinion

• Stock Responses to Serendipity

• The Qualities of Serendipity

• Dictionaries and “Serendipity”

• The Social History of Serendipity

• Moral Implications of Serendipity

• The Diverse Significance ofSerendipity in Science

• Serendipity as Ideology and Politics of Science

• A Note on Serendipity as a Political Metaphor

• A Note on Serendipity in the Humanities

• Afterword, References, Index

…and this biography of serendipity is a humane, learned and very wise book.

It is a pity that we had to wait so long for it, since [the book] is [Merton’s] greatest achievement.

Shapin S: American Scientist 92, no. 4

(July-August 2004): 374-376.

Petroleum GeoscienceJon Gluyas and Richard Swarbrick Blackwell Publishing Company350 Main StreetMalden, Massachusetts 02148 USA2004. 288 pages. $83.95ISBN 0-632-03767-9

Intended as a comprehensive introduc-tion to the application of geology andgeophysics to the search for, and pro-duction of, oil and gas, this textbook is structured to reflect the sequentialand cyclical processes of exploration,appraisal, development and production.Case histories of wells drilled aroundthe world and examples from petroleumsystems ranging in age from latePrecambrian to Pliocene are providedat the end of each chapter.

Contents:

• Introduction

• Tools

• Frontier Exploration

• Exploration and Exploitation

• Appraisal

• Development and Production

• References, Index

A very nice feature of the book isthe extensive case histories—15 in all,included at the end of each chapter….

The book is well illustrated,though with a couple of qualifications…the quality of reproduction of many of the seismic lines and the half-tone photographs is, frankly, appalling….

Nevertheless, the book is warmlyrecommended, at a very competitiveprice, to its target market—and, indeed,to all petroleum geoscientists.

Parker J: Petroleum Geoscience 10, no. 2

(May 2004): 184.

The Isaac Newton School ofDriving: Physics and Your CarBarry Parker The Johns Hopkins University Press2715 North Charles StreetBaltimore, Maryland 21218 USA2003. 250 pages. $26.95ISBN 0-8018-7417-3

Written by a physics professor, the bookdescribes nearly every aspect of physicsin terms of its relationship to auto-mobiles—from basic mechanics includ-ing velocity, acceleration, momentumand torque, to more advanced conceptssuch as heat transfer and efficiency,electricity and magnetism, and aerody-namics. The generously illustrated book is intended to appeal to both carenthusiasts and aficionados of science.

Contents:

• Introduction

• The Open Road: Basic Physics of Driving

• All Revved Up: The Internal Combustion Engine

• When Sparks Fly: The Electrical System

• Give ‘Em a Brake: Slowing Down

• Springs and Gears: The SuspensionSystem and the Transmission

• What a Drag: Aerodynamic Design

• A Crash Course: The Physics of Collisions

• Checkered Flags: The Physics ofAuto Racing

• Rush Hour: Traffic and Chaos

• The Road Ahead: Cars of the Future

• Epilogue: The Final Flag

• Bibliography, Index

[The book] has a definite flair andkeeps the reader interested. Despite afew minor flaws, the book should havebroad appeal and could provide agood resource for those who teach elementary physics.

Smith HJP: The Industrial Physicist 10, no. 2

(April-May 2004): 33-34.

ARTICLES

Advancing DownholeConveyanceAlden M, Arif F, Billingham M,Grønnerød N, Harvey S, Richards ME and West C.Vol. 16, no. 3 (Autumn 2004): 30–43.

Better Turns for Rotary Steerable DrillingWilliams M.Vol. 16, no. 1 (Spring 2004): 4–9.

CO2 Capture and Storage—A Solution WithinBennaceur K, Gupta N, Monea M,Ramakrishnan TS, Randen T, Sakurai S and Whittaker S.Vol. 16, no. 3 (Autumn 2004): 44–61.

Coiled Tubing: The Next GenerationAfghoul AC, Amaravadi S, Boumali A,Calmeto JCN, Lima J, Lovell J, Tinkham S, Zemlak K and Staal T.Vol. 16, no. 1 (Spring 2004): 38–57.

Drilling Straight DownBrusco G, Lewis P and Williams M.Vol. 16, no. 3 (Autumn 2004): 14–17.

Expanding Applications forViscoelastic SurfactantsKefi S, Lee J, Pope TL, Sullivan P, Nelson E, Nunez Hernandez A, Olsen T,Parlar M, Powers B, Roy A, Wilson A and Twynam A.Vol. 16, no. 4 (Winter 2004/2005): 10–23.

Managing Water—From Waste to ResourceArnold R, Burnett DB, Elphick J, Feeley TJ, Galbrun M, Hightower M,Jiang Z, Khan M, Lavery M, Luffey F and Verbeek P.Vol. 16, no. 2 (Summer 2004): 26–41.

The Many Facets ofMulticomponent Seismic DataBarkved O, Bartman B, Compani B,Gaiser J, Van Dok R, Johns T, Kristiansen P, Probert T and Thompson M.Vol. 16, no. 2 (Summer 2004): 42–56.

A New Horizon in MultiphaseFlow MeasurementAtkinson I, Theuveny B, Berard M, Conort G, Lowe T, McDiarmid A,Mehdizadeh P, Pinguet B, Smith G and Williamson KJ.Vol. 16, no. 4 (Winter 2004/2005): 52–63.

Optimizing Frac PacksGadiyar B, Meese C, Stimatz G, Morales H, Piedras J, Profinet J and Watson G.Vol. 16, no. 3 (Autumn 2004): 18–29.

Perforations on TargetBersås K, Stenhaug M, Doornbosch F,Langseth B, Fimreite H and Parrott B.Vol. 16, no. 1 (Spring 2004): 28–37.

Powering Up to Drill DownCopercini P, Soliman F, El Gamal M,Longstreet W, Rodd J, Sarssam M,McCourt I, Persad B and Williams M.Vol. 16, no. 4 (Winter 2004/2005): 4–9.

Practical Approaches to Sand ManagementAcock A, ORourke T, Shirmboh D,Alexander J, Andersen G, Kaneko T,Venkitaraman A, López-de-Cárdenas J,Nishi M, Numasawa M, Yoshioka K, Roy A, Wilson A and Twynam A.Vol. 16, no. 1 (Spring 2004): 10–27.

Profiling and QuantifyingComplex Multiphase FlowBaldauff J, Runge T, Cadenhead J, Faur M, Marcus R, Mas C, North R and Oddie G.Vol. 16, no. 3 (Autumn 2004): 4–13.

Reader Survey HighlightsAndersen M and Stewart L.Vol. 16, no. 2 (Summer 2004): 4–5.

Reducing Uncertainty withFault-Seal AnalysisCerveny K, Davies R, Dudley G, Fox R,Kaufman P, Knipe R and Krantz B.Vol. 16, no. 4 (Winter 2004/2005): 38–51.

Reversible Drilling-FluidEmulsions for Improved Well PerformanceAli S, Bowman M, Luyster MR, Patel A,Svoboda C, McCarty RA and Pearl B.Vol. 16, no. 3 (Autumn 2004): 62–68.

Scientific Deep-Ocean Drilling:Revealing the Earth’s SecretsBrewer T, Endo T, Kamata M, Fox PJ,Goldberg D, Myers G, Kawamura Y,Kuramoto S, Kittredge S, Mrozewski Sand Rack FR.Vol. 16, no. 4 (Winter 2004/2005): 24–37.

Taking the Pulse of ProducingWells—ESP SurveillanceBates R, Cosad C, Fielder L, Kosmala A,Hudson S, Romero G and Shanmugam V.Vol. 16, no. 2 (Summer 2004): 16–25.

Time Will Tell: New Insightsfrom Time-Lapse Seismic DataAronsen HA, Osdal B, Dahl T, Eiken O,Goto R, Khazanehdari J, Pickering S and Smith P.Vol. 16, no. 2 (Summer 2004): 6–15.

Virtual Testing: The Key to aStimulating ProcessAli S, Frenier WW, Lecerf B, Ziauddin M,Kotlar HK, Nasr-El-Din HA and Vikane O.Vol. 16, no. 1 (Spring 2004): 58–68.

NEW BOOKS

The Chicago Guide toCommunicating Science Montgomery SL.Vol. 16, no. 2 (Summer 2004): 60.

Corrosion and Protection Bardal E.Vol. 16, no. 4 (Winter 2004/2005): 68.

Development of Petroleum ReservoirsPápay J. Vol. 16, no. 4 (Winter 2004/2005): 68.

The Dynamic Structure of the Deep Earth: An Interdisciplinary Approach Karato S.Vol. 16, no. 1 (Spring 2004): 72.

Elastic Wave Propagation andGeneration in SeismologyPujol J.Vol. 16, no. 2 (Summer 2004): 61.

Energy at the Crossroads: GlobalPerspectives and UncertaintiesSmil V.Vol. 16, no. 3 (Autumn 2004): 72.

Environmental Magnetism:Principles and Applications ofEnviromagnetics, InternationalGeophysical Series Volume 86Evans ME and Heller F.Vol. 16, no. 3 (Autumn 2004): 72.

Evaluating the MeasurementUncertainty: Fundamentals and Practical GuidelinesLira I.Vol. 16, no. 2 (Summer 2004): 60.

Foundations of Risk Analysis: A Knowledge and Decision-Oriented PerspectiveAven T.Vol. 16, no. 3 (Autumn 2004): 72.

Fuzzy Logic in GeologyDemicco RV and Klir GJ (eds).Vol. 16, no. 4 (Winter 2004/2005): 69.

The Guide to Oilwell FishingOperations: Tools, Techniques,and Rules of ThumbDeGeare J, Haughton D and McGurk M.Vol. 16, no. 2 (Summer 2004): 62.

International Handbook ofEarthquake and EngineeringSeismology, Part ALee WHK, Kanamori H, Jennings PC and Kisslinger C (eds).Vol. 16, no. 2 (Summer 2004): 61.

International Handbook ofEarthquake and EngineeringSeismology, Part BLee WHK, Kanamori H, Jennings PC and Kisslinger C (eds).Vol. 16, no. 2 (Summer 2004): 61.

The Isaac Newton School ofDriving: Physics and Your CarParker B.Vol. 16, no. 4 (Winter 2004/2005): 69.

Mind over Magma: The Story of Igneous PetrologyYoung DA.Vol. 16, no. 2 (Summer 2004): 60.

Origin and Prediction ofAbnormal Formation Pressures,Developments in PetroleumScience 50Chilingar GV, Serebryakov VA andRobertson JO Jr.Vol. 16, no. 2 (Summer 2004): 62.

Petroleum GeoscienceGluyas J and Swarbrick R.Vol. 16, no. 4 (Winter 2004/2005): 69.

Power to the People: How theComing Energy Revolution WillTransform an Industry, ChangeOur Lives and Maybe Even Save the PlanetVaitheeswaran VV.Vol. 16, no. 4 (Winter 2004/2005): 68.

A Short History of Nearly EverythingBryson B.Vol. 16, no. 1 (Spring 2004): 72.

Soft Computing and IntelligentData Analysis in Oil ExplorationNikravesh M, Aminzadeh F and Zadeh LA (eds).Vol. 16, no. 2 (Summer 2004): 61.

The Travels and Adventures of Serendipity: A Study inSociological Semantics and the Sociology of ScienceMerton RK and Barber E. Vol. 16, no. 4 (Winter 2004/2005): 69.

Well Test Analysis: The Use ofAdvanced Interpretation ModelsBourdet D.Vol. 16, no. 1 (Spring 2004): 72.

Women in Science: CareerProcesses and OutcomesXie Y and Shauman KA.Vol. 16, no. 2 (Summer 2004): 62.

70 Oilfield Review

Oilfield Review Annual Index—Volume 16