eni well testing manual

SPEO Eni S.p.A. E&P Division

IDENTIFICATION CODE PAG 2 OF 80

REVISION STAP-P-1-M-14520 0

INDEX

1. INTRODUCTION.........................................................................................................4 1.1 PURPOSE OF THE MANUAL.................................................................................... 4 1.2 UPDATING, AMENDMENT, CONTROL & DEROGATION ........................................ 4

2. THE PRINCIPLE OF WELL TESTING........................................................................5 2.1 WELL TESTING DEFINITION .................................................................................... 5 2.2 MAIN TARGETS......................................................................................................... 5

3. TYPE OF WELL TESTS .............................................................................................8 3.1 OPTIMAL WELL TEST SELECTION ......................................................................... 8 3.2 WIRELINE FORMATION TESTER (WFT) .................................................................. 8 3.3 DRILL STEM TEST (DST).......................................................................................... 9 3.4 STANDARD PRODUCTION TEST........................................................................... 10 3.5 LONG PRODUCTION TEST (LIMIT TEST) .............................................................. 11 3.6 INTERFERENCE TEST............................................................................................ 12

3.6.1 AREAL INTERFERENCE ............................................................................................12 3.6.2 VERTICAL INTERFERENCE.......................................................................................14 3.6.3 PULSE TESTING .........................................................................................................14

3.7 INJECTION TEST..................................................................................................... 15

4. DESIGN.....................................................................................................................17 4.1 FOCUS ON MAIN OBJECTIVES ............................................................................. 17 4.2 WELL TESTING SEQUENCE .................................................................................. 18

4.2.1 FLOW RATES ..............................................................................................................18 4.2.2 DRAWDOWN AND BUILD-UP DURATION ................................................................18

4.3 SAMPLING............................................................................................................... 20 4.4 TEST DESIGN FOR AN OIL BEARING FORMATION............................................. 22 4.5 TEST DESIGN FOR A GAS BEARING FORMATION.............................................. 25

5. INPUT DATA.............................................................................................................30 5.1 GEOMETRICAL/SEDIMENTOLOGICAL INFORMATION........................................ 30 5.2 PETROPHYSICAL PARAMETERS.......................................................................... 31

5.2.1 POROSITY ...................................................................................................................31 5.2.2 NET PAY ......................................................................................................................32 5.2.3 FLUID SATURATIONS ................................................................................................32 5.2.4 COMPRESSIBILITY.....................................................................................................33

5.3 PVT DATA................................................................................................................ 34




5.3.1 REFERENCE DEPTH ..................................................................................................34 5.3.2 USE OF PVT REPORTS (LABORATORY ANALYSIS)..............................................35 5.3.3 USE OF EMPIRICAL CORRELATIONS......................................................................37

5.4 PRODUCTION DATA............................................................................................... 41 5.4.1 PRODUCED FLUIDS ...................................................................................................41

5.4.1.1 TESTS IN GAS CONDENSATE WELLS ......................................................41 5.4.1.2 TESTS WITHOUT SURFACE FLOW ...........................................................42

5.5 PRESSURE AND TEMPERATURE DATA............................................................... 43 5.5.1 WELLHEAD DATA ......................................................................................................43

5.5.1.1 WELLHEAD PRESSURES ...........................................................................43 5.5.1.2 WELLHEAD TEMPERATURES....................................................................43

5.5.2 BOTTOM HOLE DATA ................................................................................................44 5.5.2.1 BOTTOM HOLE PRESSURES AND TEMPERATURES .............................44

5.6 OTHER INFORMATION (PLT, RFT, MDT, LOGS, CORES) .................................... 44

6. GAUGE SPECIFICATIONS ......................................................................................46 6.1 SURFACE AND DOWN-HOLE EQUIPMENT REQUIREMENTS ............................. 46 6.2 TECHNOLOGY REQUIREMENTS ........................................................................... 46

6.2.1 SURFACE READ OUT (SRO) GAUGES.....................................................................46 6.2.2 MEMORY GAUGES .....................................................................................................47 6.2.3 MAIN PROPERTIES ....................................................................................................48

6.3 DATA ACQUISITION PROGRAMME....................................................................... 50 6.3.1 FILE FORMAT STANDARDIZATION OF DATA RECORDED DURING WELL

TESTING ......................................................................................................................50 6.3.1.1 PRESSURE AND TEMPERATURE HISTORY FILES .................................50 6.3.1.2 SURFACE & DOWNHOLE DATA.................................................................52

7. WELL TEST INTERPRETATION..............................................................................55 7.1 WELLHEAD PARAMETERS.................................................................................... 55 7.2 VALIDATE RATES: DEFINITION OF PRODUCTION HISTORY ............................. 56 7.3 VALIDATE GAUGES ............................................................................................... 59 7.4 WELL TEST INTERPRETATION PROCESS ........................................................... 61

8. WELL TEST INTERPRETATION PACKAGE...........................................................63 8.1 INTERPRET 2003 (PARADIGM) .............................................................................. 63 8.2 SAPHIR (KAPPA ENGINEERING)........................................................................... 66

8.2.1 ANALYTICAL ANALYSIS............................................................................................67 8.2.2 NUMERICAL ANALYSIS (LINEAR) ............................................................................69 8.2.3 NUMERICAL ANALYSIS (NON-LINEAR)...................................................................69

9. REPORT ...................................................................................................................71 9.1 MEASUREMENT SYSTEM ...................................................................................... 71 9.2 STRUCTURE OF THE REPORT .............................................................................. 73




1. INTRODUCTION

1.1 PURPOSE OF THE MANUAL

The purpose of this manual is to guide technicians and engineers involved in Drilling & Completion activities through the requirements, methodologies and rules pertinent to Well Testing Design and Interpretation. Well Testing Design and Interpretation shall be performed uniformly and in compliance with Eni E&P Principles and according to the laws and environmental constraints of the Country where the tested well is located.

This manual defines guidelines and procedures for both exploration and production wells.

The final aim is to improve the Well Test performance and efficiency in terms of safety, quality and costs, while providing all personnel involved in Drilling & Completion activities with common guidelines in all areas where Eni E&P operates.

This manual should not to be intended as an interpretation manual where methodology and general criteria for interpretation of well testing data are presented. For this reason, all the mathematical concepts, as well as the theoretical reservoir models of the well testing transient analysis, are not part of this manual.

Readers who would like to improve their personal knowledge on these topics can refer to Technical Literature or address to the ENI in house “Well Testing” (see link: http://wwwdsc.sd.agip.it/intranetdsc/Reservoir/Production/Well-Test/index.htm).

1.2 UPDATING, AMENDMENT, CONTROL & DEROGATION

This manual is a “live” controlled document and, as such, it will only be amended and improved by the Company, in accordance with the development of Eni E&P operational experience. Accordingly, it will be the responsibility of everyone involved with the use and application of this manual to review the policies and the related procedures on an ongoing basis.

Derogations from the manual shall be approved solely in writing by the Company Well Operations Manager after the Company Manager and the Corporate Drilling & Production Optimisation Services Department, in the Eni E&P Division Head Office, have been advised in writing.

The Corporate Drilling & Production Optimization Services Standards Department will consider such approved derogations for future amendments and improvements of the Corporate manual, when the updating of the document will be advisable.

Feedback for manual amendment is also obtained from the return of completed “Feedback and Reporting Forms” compiled by well operations personnel.

http://wwwdsc.sd.agip.it/intranetdsc/Reservoir/Production/Well-Test/index.htm




2. THE PRINCIPLE OF WELL TESTING

2.1 WELL TESTING DEFINITION

In its simplest form, Well Testing is a powerful tool to describe an unknown system (i.e: well + reservoir) by indirect measurements. During a well test, the principle is to analyse the “output“ signal of a well to which a known “input“ signal has been applied.

In most cases, the “input“ signal is represented by surface producing (or injecting) flow rates while the “output“ signal is the associated downhole pressure measurements.

Figure 2.1.1 - Principle of Well Testing

The interpretation of the pressure signal coupled to the flow rate sequence allows the identification of model(s) whose behaviour is consistent with the behaviour of the actual reservoir. This is a typical inverse problem and its solution is usually not unique because different reservoir models can provide the same response if sollecitated with the same input.

In order to avoid uncertainties it is important that any solution obtained from dynamic well test interpretation be coherent with all static information such as geological, geophysical and petrophysical data.

All the available static information should always be used in conjunction with the well test data to build a consistent reservoir model for a proper prediction of the future well/field performance.

2.2 MAIN TARGETS

Well Testing analysis provides information on the reservoir characteristics and on the interaction between the well and the reservoir.

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Bottom hole pressure

Production/Injection flow-rate

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In general terms, the main well testing targets could be summarised as follows:

• to define the nature and the amount of produced reservoir fluids (expecially for exploration/appraisal wells);

• to estimate reservoir properties such as static pressure (PS), permeability-thickness product (kh), and the average formation permeability (k) (this permeability must be regarded as the effective permeability);

• to quantify the permeability damage near the wellbore as well as the major skin components;

• to assess the well productivity (Productivity Index for oil wells – Flow equation for gas wells);

• to evaluate any areal/vertical heterogeneity (i.e: change in lithological properties, layering, natural fractures);

• to determine the presence of permeabilty barriers (i.e: sealing boundaries, pinch outs) in the rock volume investigated during the test;

• to evaluate the reservoir size (Long Production Test or Limit–Test);

• to confirm hydraulic communication between existing wells (Interference Test).

Well test objectives should be clearly defined before planning a test with respect to budget and operational requirements. Environmental constraints must be kept into due account too.

Depending on the type of well to be tested, the following priorities for the main targets can be indicated:

Exploration wells

On the first exploration well, well testing is used to confirm the exploration structure, establish the nature of the produced fluids as well as the initial reservoir pressure and its consistency with the RFT/MDT trend when available.

Other common targets are both the evaluation of the main reservoir properties (kh, Skin) and the assessement of the well productivity. In addition, any reservoir heterogeneity as well as the presence of potential boundaries should be investigated.

A proper reservoir characterization through testing of an exploration well is crucial for any future action/decision and, for this reason, it is strongly recommended to maximise the value of the information achieved by the testing phase.




Appraisal wells

The reservoir description can be refined by testing appraisal wells to confirm average properties, productivity, reservoir heterogeneities, and boundaries as well as drive mechanism if detected.

In order to identify representative reservoir fluids, surface/bottom samples are collected for PVT laboratory analysis.

Production / Development wells

On producing wells, periodic tests are scheduled to confirm and/or re-adjust the existing 3D-dynamic reservoir model and to evaluate the need for well treatment (re-perforation, acid stimulation, sand control, fracturing, etc) with the target to maximise the well production life.

In addition, interference testing is a quite common methodology to confirm possible communication between existing wells.

During the well testing time a quite large volume of reservoir rock can be investigated. As a consequence, the main reservoir parameters, such as permeability, should be considered as average values.




3. TYPE OF WELL TESTS

3.1 OPTIMAL WELL TEST SELECTION

Different types of well testing could be planned either on exploration, appraisal and/or production wells.

Well test targets definition leads to the proper selection of test type and, therefore, to the most appropriate test design procedures (see Chapter 4 - Design).

The main well test types can be summarised as follows:

• Drill Stem Test (DST);

• Standard Production Test;

• Long Production Test (or Limit Test);

• Inteference Test;

• Injection Test;

The previous test types are described in details in Chapters 3.3, 3.4, 3.5, 3.6, 3.7, respectively.

Even if it is not considered as a conventional well test, the Wireline Formation Tester technique will be also discussed in the next Chapter because of its importance with respect to the conventional well tests.

3.2 WIRELINE FORMATION TESTER (WFT)

It is not the purpose of this manual to discuss extensively the Wireline Formation Tester (WFT*) applications and, as a consequence, only some general concepts are here presented. In particular WFT is one of the most used tools in formation evaluation and reservoir studies due to its ability of:

• collecting samples of reservoir fluids;

• obtaining formation pressure measurements at different depths.




The pore pressure regime, the fluid mobility as well as the in-situ fluid contacts within the formation are provided by WFT.

Due to the very short duration of WFT, generally ranging from tens of seconds up to few minutes, the investigated volume is very limited and, therefore, the major parameters (i.e fluid mobility) are considered reliable only close to the tool depth.

Information obtained from WFT interpretation is very useful especially in designing a consistent testing programme for a new exploration and/or for appraisal wells.

In particular:

• the sampling of fluids from WFT allows the first characterization of the initial PVT properties;

• the WFT pressure regime is assumed as the initial static pressure of the reservoir. A cross–check between this value and the extrapolated pressure from well testing analysis should always be made;

• the fluid mobility allows a first evaluation of the effective reservoir permeability;

• the vertical permeability (kz) can be estimated if spherical flow regime is clearly detected from WFT analysis.

3.3 DRILL STEM TEST (DST)

This technique was quite common in the past especially for testing new exploration wells. It consisted of using a drill string (drill pipe) controlled by a down hole shut-in valve. This testing methodology is not used anymore.

In most cases the testing duration was limited to few hours and, as a consequence, the production period was very short and no hydrocarbons were produced at the surface.

The main targets to be achieved were basically the following:

• the measurement of the static formation pressure;

• the collection of a representative reservoir fluid sample. The reservoir fluid was recovered by reverse circulation and thus the risk of contamination of hydrocarbon by mud or completion fluid was quite high.

The evaluation of the other reservoir properties, such as permeability and skin, could not be very accurate because the interpretation approach was not strictly conventional. This was particularly true when tight reservoirs and/or viscous oil reservoirs were tested and when no flow at the surface was observed.




In a conventional DST, flow and shut-in were operated by the down hole shut-in valve located below the drill pipe. The wellhead always remained open to the atmosphere, whether directly or through a flare.

If the wellhead, equipped with a pressure gauge, remains closed during the flow phase, the DST becomes a Closed Chamber Test (CCT) for the tested flow period.

3.4 STANDARD PRODUCTION TEST

A Standard Production Test (SPT) can be applied to both exploration/appraisal and production wells. In general, production tests performed during the exploration and appraisal phase are conducted by using a temporary completion string (DST string). On the other side, a final completion string is utilized when testing wells already in production.

The configuration of the DST string is very flexible and depends on the test requirements and of the targets to be achieved.

Testing a well with the DST completion string allows several advantages:

• the shut-in of the well is performed downhole by operating the tester valve. As a consequence, the distorsion on thr pressure response due to Wellbore Storage effects is strongly minimized.

• Perforations can be made in underbalance conditions with TCP gun (Tubing Conveyed Perforating). As a result, the damage of the formation is strongly reduced.

• Downhole samples can be collected by activating dedicated sampling tools, which are components of the string. The use of any wireline cable for collecting downhole sampling is not needed.

• The use of the data latch-system allows real time acquisition and interpretation of downhole pressure data, thus optimising the original programme with a considerable saving of time and money.

The duration of a conventional production test ranges from a couple of days to one week or more.

The main objectives of a Production Test are:

• to define the nature and the amount of the produced reservoir fluids (expecially for exploration/appraisal wells);

• to estimate reservoir properties such as static pressure (PS), permeability-thickness product (kh) and the average formation permeability (k);




• to quantify the well damage as well as the major skin components;

• to assess the well productivity (Productivity Index for oil wells – Flow equation for gas wells);

• to evaluate any areal/vertical heterogeneity (i.e change in lithological properties);

• to determine the presence of permeability barriers (i.e sealing faults) in the rock volume investigated during the test.

In order to meet the planned targets and thus maximise the VOI (Value Of Information), it is a crucial issue that a big effort be devoted to design and interpret any test in agreement with all the available information such as seismic and geological data, core analysis, logs, etc.

Production tests require a great effort in planning and obtaining authorization, since they have a relevant impact on HSE issues. Therefore, well testing procedures shall be compliant with the Eni E&P and Statutory regulations in order to ensure safe operations.

3.5 LONG PRODUCTION TEST (LIMIT TEST)

The long production test (LPT) is a long term test which consists of a single rate drawdown followed by a final build-up. Due to the long test duration, a large portion of the reservoir is investigated.

The main objectives can be summarized as follows:

• investigation of multiple boundaries,

• identification of the main drive mechanism,

• evaluation of the overall reservoir limits (pseudo-steady flow regime is reached).

This last point is of crucial importance because the reservoir size can be estimated and, thus, based on simple material balance calculations, a first estimation of the volume of fluid in place is obtained.

Other targets such as the identification of lateral hydrocarbon–water contacts are generally complex, especially when the mobility contrast between the fluids is not very large. For the same reason, on the opposite, lateral gas–water contacts are quite easy to detect due to extremely high mobility contrast.




This type of test is not very common because of the extremely high associated costs and also because of the large amount of hydrocarbon to be flared.

In most cases long term tests, especially in off-shore enviroments, are confined to particular situations where the confirmation of the reservoir extension is critical to make decision on possible development strategies.

3.6 INTERFERENCE TEST

Three types of interference tests are presented in this manual :

Areal Interference

Vertical Interference

Pulse Testing

3.6.1 AREAL INTERFERENCE

In its simplest form the areal interference test involves two wells:

• a producer (or injector). Sometime the producer (or injector) is also called “active well”.

• an observation well located at some distance form the producer. Accurate pressure gauges are placed in the observation well.

The reservoir is assumed to be homogeneous and isotropic.

To perform an interference test, the involved wells should first remain shut-in until their bottom hole pressure stabilizes. Then the producer (or injector) is opened to production (or injection) at a costant rate.

If the two wells interfere, a pressure drop (or rise) is recorded at the observation well within a reasonable interval of time. The time for the pressure disturbance to reach the observation well is called “lag time”.

Analysis is then made on the pressure response by applying the “line source solution“ theory, where the effects of wellbore storage and skin are considered negligible at the two wells.

The production (or injection) flow rate does not affect the distance reached by the pressure disturbance within the reservoir, but only the amplitude of the pressure signal.

Interference tests are generally carried out for the following reasons :




• to recognise areal continuity between wells;

• to determine the average reservoir properties such as the permeability thickness product (kh) and the apparent storage capacity (φCth), especially because the latter can not be estimated from convention production tests;

• if more observation wells located in different directions are involved, it is also possible to estimate the areal permeability anisotropy within the reservoir.

In the design phase of an interference test, depending on the average reservoir permeability, special attention must be paid to the following items:

• in low permeability reservoirs the time for the pressure response to reach the observation well can be very long (even several weeks). Time could be even longer when the distance between the wells is very large (more than 1 km). Thus, both low k reservoirs and large distances could be critical because the duration of the interference test and thus its economical impact could be prohibitive.

• in high permeability reservoirs the critical issue is represented by the gauge selection. In fact, when testing such reservoirs a very small pressure amplitude (sometimes less than 1 psia) is recorded at the observation well. For this reason high quality quartz gauges with no drift should be selected.

When reservoirs are not considered homogeneous there are several scenarios that could make the analysis of an interference test more complex.

The most common scenarios are:

• composite reservoirs;

• reservoirs with permeability barriers and/or faults;

• double permeability/double porosity reservoirs;

• presence of a gas cap (or free gas within the reservoir).

In these scenarios additional care is needed in the design phase, even if in theory interpretation of interference tests should be possible with the standard analitical well testing software (i.e Interpret/2003, Saphir).

Design and interpretation of interference tests in production wells generally require great skill because the pressure response at the observation well could be strongly affected by




the other producing (or injecting) wells. In order to design and/or analyze an interference test in such a scenario a numerical model is needed.

3.6.2 VERTICAL INTERFERENCE

The knowledge of the vertical permeability is of great importance for a field development strategy.

During a vertical interference test, the well is perforated and completed on two different layers which are in hydraulic communication within the reservoir, but generally show different lithological properties.

The two zones are isolated at the wellbore by mechanical devices (i.e., packer). Pressure gauges are located in the well at different depths, thus monitoring the pressure of each of the layers. Only one layer is active (flowing or injecting), while the other layer is shut-in.

With the combined analysis of the two different pressure responses, the average horizontal permeability of the active layer, as well as the vertical permeability between the two layers involved in the test, can be determined.

Some examples of decisions based on vertical permeability are:

• completion decisions, such as the evaluation of potential increase in productivity by horizontal wells;

• production strategy, to predict gas and/or water coning.

The same approach is extremely useful also in detecting vertical interference between layers which are isolated in the reservoir, but in communication at the wellbore due to mechanical leakage or poor cementation behind the casing.

3.6.3 PULSE TESTING

This method is an effective alternative to the conventional interference test.

A sequence of relatively short flow (production or injection) and shut-in periods is applied to the active well. The rate and the duration of the each flow are the same. Also the shut-in periods have the same duration, but not necessarily the same as the flow periods.

Three or four pulses are generally enough to analyse the pressure response at the observation well.

This sequence generates a pulsing pressure response at the observation well, which is analyzed in terms of amplitude and time lag. The measured parameters are compared to the theoretical simulated responses and, as a result, the average permeability and storativity (φCth) are estimated.

Even if they are more difficult to interpret, pulse tests should be preferred because the oscillating response is easier to identify in a noisy reservoir environment (field under production).




3.7 INJECTION TEST

Injection well testing has its application in water injection wells for pressure maintenance as well as in water disposal wells.

The main targets of this test are:

• the evaluation of the injectivity index of the well;

• the ability for these well to receive large volumes of water.

Injection well testing involves the following methods :

1. Step rate test: these tests are specifically made to evaluate the pressure at which fracturing could be induced in the reservoir rock. A series of injection test rates are applied to the well. The rate should be constant during each step; the observed pressure is plotted versus rate. If fracturing conditions have been reached, two different straight lines are present and their intersection defines the fracturing pressure.

2. Injectivity/falloff test: in this test, a constant flow rate is injected into the well while the downhole pressure is recorded at the sandface. Then the well is shut-in for a final falloff.

The interpretation of such a test would be similar to a conventional production test provided that physical properties (viscosity, density, etc.) of the injected fluid and those of the reservoir fluid are compatible. This would be the case when water is injected into an aquifer. As a result, standard well testing objectives can be easily achieved including heterogeneities and/or permeability boundaries if investigated.

However, because the properties of the injected fluid are usually different from those of the actual reservoir fluids, the interpretation of the injection/falloff tests is much more complex than the interpretation of a conventional injection test.

Moreover the pressure behaviour during the injection phase is different from the observed one during the falloff.

Injection Phase

During the injection period the flooded region increases in time and a “movable front“ exists in the reservoir.

The evaluation of the skin from injection tests is difficult to interpret because the total (or apparent) skin is made of two components: the conventional well skin and the two-phase skin. As a consequence, a proper interpretation of the injection phase can only be performed with advanced tools (i.e numerical simulator) provided that the two-phase relative permeability curves are available.




Artificial fractures potentially induced during the injection phase represent another important factor that heavily complicate the interpretation. To avoid fracture induction, it is strongly recommended to inject fluid into the reservoir in “matrix conditions”.

Falloff phase

Due to the different pressure response during injection and falloff, the principle of superposition is, in theory, not applicable. In practice, it has been noticed that, when a Radial Composite model with stationary front is used, no significant error is introduced.

As a result, the following main targets can be achieved with the usual approach:

• formation Pressure,

• mobility contrast between the water and the oil,

• permeability in the (inner) water region,

• permeability in the (outer) oil region,

• skin components.

The derivative response describes the change of saturation in the transition zone separating the inner water region and the uncontaminated, outer oil region.

However, in practice, due to wellbore storage effects the response of the inner region is generally masked. Therefore, only the permeability of the outer oil region and the otal skin can be evaluated.




4. DESIGN

4.1 FOCUS ON MAIN OBJECTIVES

To design a well test the first step is to know which are the main objectives to be achieved. They must be established a priori in order to plan a suitable well test procedure.

In fact, the well testing sequence as well as the total test duration are strongly dependent on the targets to be achieved. In the planning phase all other external limitations, such as environmental constraints, should be accounted for. The optimal well testing schedule should be able to maximise the value of the information by obtaining the expected goals respecting all the existing constraints (budget limitation included).

Based on both the reservoir properties (when available) and the well testing duration different flow regimes as well as potential heterogeneity and reservoir boundaries can be investigated within the testing time.

Courtesy of Baker Hughes

Figure 4.1.1 - Test duration and flow regimes for WFT and Production Test PT

0.01 0.1 1 10 100 seconds 1 10 100 hours 1 10 100 days

Derivative, b

ar/(S

m3/d

ay)

Spherical

Radial

Wellbore Storage

Horizontal Well/Fractures

Reservoir Boundaries

WFTPT

Time (k = 750 mD)




Different kind of results can be obtained by a well test analysis, depending on:

• the type of mineralization (oil, gas, condensate gas),

• the type of test (production or injection test),

• the kind of well (exploration/appraisal or development well),

• the geological/sedimentological environment.

4.2 WELL TESTING SEQUENCE

The well test sequence is evaluated on the basis of the objectives to be achieved.

4.2.1 FLOW RATES

The flow rates depend on the well response. They can be estimated considering the production of previously tested nearby wells draining the same formation. In exploration wells the flow rate sequence can be selected and tuned on the basis of the clean up response.

4.2.2 DRAWDOWN AND BUILD-UP DURATION

A well test programme can be structured as follows:

1) Clean-up: it is suggested to stress the well with different increasing chokes in order to remove non representative fluids (i.e., drilling and completion fluids). It is important to underline that a proper clean-up phase is essential for a consistent well test interpretation. The duration of the clean-up can be variable depending on the well response. In general the cleaning phase will be terminated when the main wellhead parameters (pressure and rates) are stabilised for at least 3-4 hours. The final BSW should not exceed 5%. Any evidence of sand and/or fines production must be monitored. In addition, all the physical parameters of the produced fluids such as Ph, salinity, density, gas SG, etc. must be acquired.

2) Build-up: the duration of the first build-up should be the same as the clean-up phase.

3) Main Flow: in the case of oil bearing formations a flow after flow sequence




consisting of two isochronal increasing flow rates is recommended. In general each step should last 8 to 12 hours (Figure 4.2.1).

In the case of gas bearing formations a flow after flow sequence of isochronal increasing rates is suggested. A minimum of two flow rates is necessary to estimate the turbulence factor and the flow equation. However, three flow rates are highly recommended. Each step should last 8 hours (Figure 4.2.2).

It is suggested that the maximum flow rate does not exceed the greater flow rate achieved during the clean-up phase.

4) Final Build-up: The duration of the main build-up should be 1.5-2 times the duration of the main flow.

Remarks: choke sizes and testing time should be adjusted according to the well behavior.

3000

4000

5000

0 10 20 30 40 50 60 70 80 90 100 110 120

0

2000

4000

History plot (Pressure [psia], Liquid Rate [STB/D] vs Time [hr])

Figure 4.2.1 – Well test sequence for an oil bearing formation

Main Build-up

1st Drawdown

Clean-up

2nd Drawdown

1st Build-up




4750

4850

4950

0 10 20 30 40 50 60 70 80 90 100 110 120

0

10000

20000

30000

History plot (Pressure [psia], Gas Rate [Mscf/D] vs Time [hr])

Figure 4.2.2 – Well test sequence for a gas bearing formation

4.3 SAMPLING

The objective of reservoir fluid sampling is to collect representative samples of the reservoir fluids at the time of sampling. In general terms oil, gas and even water samples are required to properly characterise the formation fluids.

Sampling is generally performed in the initial exploration and/or appraisal phase when the fluid is still characterized by its original composition. This is a crucial step for reliably predicting the future reservoir behaviour.

Two methods are used for sampling reservoir fluids. They are referred to as “subsurface sampling“ and “surface sampling”. In this second method, sampling can be made at the separator (most likely) as well as at the wellhead. When sampling exploration wells, subsurface sampling is always associated with surface sampling.

As a general procedure, sampling operations can be planned either during the main flow phase or at the end of the test after the final build-up.

All the surface/downhole sampling must be properly validated at the wellsite before sending the fluid samples to the labs. In the case of samples inconsistency the operation must be repeated.

Clean-up

Main Build-up

1st Drawdown

2nd Drawdown

3rd Drawdown

1st Build-up




The choice of the sampling method is influnced by several factors, such as :

• type of reservoir fluid;

• volume of sample required by lab analysis;

• mechanical conditions of the well;

• limits of the available gas-oil separators equipment.

The key factor to collect a representative reservoir fluid sample is the preliminary conditioning of the well. This consists of producing the well, for a certaint time, at a rate which removes all the altered (non representative) fluid from the wellbore.

The recommended procedure to reach such a situation, consists of producing the well in a series of “step by step” flow rate reduction. A stabilized gas-oil ratio (GOR) should be achieved and measured at each step. The well is considered to be sufficiently conditioned when further rate reductions have no effect on the GOR which remains constant over time. Monophasic flow conditions are then basically achieved and sampling can be successfully performed.

Special attention must be dedicated when sampling oil reservoirs (light - volatile oil) if the saturation pressure (or dew point pressure for gas condensate) is closed to the initial static pressure.

During the sampling phase the following parameters should be stabilized and properly monitored:

• Fluid flow rates (Qoil, Qgas, Qwater),

• Bottom Sediment & Water (BSW),

• Gas Oil Ratio (GOR),

• Wellhead pressure and temperature,

• Separator pressure and temperature.

In addition, the main physical fluid properties, such as oil and average gas gravity as well as the presence of CO2/H2S, should be carefully evaluated.

As a general procedure, all the surface/downhole samples collected during the production test must be properly validated at the wellsite before they are sent to the labs. In the case of samples inconsistency, the operation must be repeated.




Readers who would like to improve their personal knowledge on these topics can refer to the “API RECOMMENDED PRACTICE FOR SAMPLING PETROLEUM RESERVOIR FLUIDS“.

For futher information see the “Well Test Procedures Manual” STAP-P-1-M-7130 (see link: http://wwwdsc.in.agip.it/drilling/manuals/pagdrill/pagdrill.html).

4.4 TEST DESIGN FOR AN OIL BEARING FORMATION

After the well test objectives have been defined, the following steps are required to design a test:

1) Acquisition of input data:

Input data Source of input data

Geological information Geologist

Sedimentological information Sedimentologist

Petrophysical data Geologist

PVT data PVT analyst

P, T reservoir Subsurface geologist /Reservoir eng.

For production wells additional information is necessary:

• production history of the tested well (oil, gas, water rates), • completion history, • workovers due to sand and/or water production, • acidizing, hydraulic-fracturing operations, well washing due to asphaltens &

paraffins presence, • wells status at current testing time • other injecting or producing wells into the tested layer.

2) Acquisition of information about possible constrains relative to:

• maximum testing time, • maximum fluid volumes to be treated (flared or stored); • environmental constraints.

http://wwwdsc.in.agip.it/drilling/manuals/pagdrill/pagdrill.html




3) selection of the optimal test sequence;

Generation of the theoretical pressure response to be used as the reference case with the interpretation software (Interpret/2003 and/or Shaphir);

4) Performance of sensitivity analyses by modifying the relevant parameters:

• permeability, • skin, • duration of the build-up (drawdown), • theoretical reservoir model.

5) Display the obtained results, i.e.:

• Productivity Index (PI) vs. permeability (k) (Figure 4.2.1) at different skins; • Productivity Index (PI) vs. permeability (k) (Figure 4.2.2) considering

different models; • Investigation radius (Ri) vs. Time (t) (Figure 4.2.3) at different permeability

values.

Productivity Index vs Permeability

0

1

2

3

4

5

6

7

8

0 0.5 1 1.5 2 2.5 3

k [mD]

PI [m

3 /d/b

ar]

S=0S=-3S=3

Figure 4.2.1 - Sensitivity PI vs. k




DESIGN (S=0)

0

20

40

60

80

100

120

140

160

180

100 1000 10000

k [mD]

PI [m

3 /d/k

g/cm

2 ] Wedge modelRectangle modelInfinite model

Figure 4.2.2 - Sensitivity PI vs. k

Investigation radius vs Time

0

200

400

600

800

1000

1200

1400

1600

1800

2000

0 10 20 30 40 50 60 70 80 90 100

Time (hr)

Ri (

m)

k=25 mD

k=50 mD

k=10 mD

k=100 mD

Figure 4.2.3 – Sensitivity Ri vs. Time




4.5 TEST DESIGN FOR A GAS BEARING FORMATION

After the well test objectives have been defined, the following steps are required to design a test:

1) acquisition of input data:

Input data Source of input data

Geological information Geologist

Sedimentological information Sedimentologist

Petrophysical data Geologist

PVT data PVT analyst

P, T reservoir Subsurface geologist /Reservoir eng.

For production wells additional information is necessary:

• production history of the tested well (oil, gas, water rates), • completion history, • workovers due to sand and/or water production, • acidizing, hydraulic fracturing operations, well washing due to

asphaltens/paraffins presence, • wells status at current testing time • other injecting or producing wells into the tested layer.

2) Acquisition of information about possible constrains relative to:

• maximum testing time, • maximum fluid volumes to be treated (flared or stored); • environmental constraints.

3) Selection of the optimal test sequence;

Generation of the theoretical pressure response to be used as the reference case with the interpretation software (Interpret/2003 and/or Shaphir);

4) Performance of sensitivity analyses by modifying the relevant parameters:

• permeability, • skin,




• duration of the build-up (drawdown), • theoretical reservoir model.

5) display the obtained results, i.e.:

• Investigation radius (Ri) vs. permeability (k); • Log (∆p2) vs. Log(q) (Figure 4.3.1) at different skins; • Log (∆p2) vs. Log(q) (Figure 4.3.2) considering different models; • Investigation radius (Ri) vs. Time (t) at different permeability values.

Back Pressure Test

5.9

6

6.1

6.2

6.3

6.4

6.5

6.6

6.7

6.8

6.9

3.9 4 4.1 4.2 4.3 4.4 4.5 4.6

logqSC

log(

p i2 -

p wf2 )

S=0S=5S=10

Figure 4.3.1 - Log (∆p2) vs. Log(q)




Back Pressure Test

5.9

6

6.1

6.2

6.3

6.4

6.5

6.6

6.7

3.9 4 4.1 4.2 4.3 4.4 4.5 4.6

logqSC

log(

p i2 -

p wf2 )

Homo Infinite model

One Fault model

Rectangle model

Figure 4.3.2 - Log (∆p2) vs. Log(q)

The rigorous approach to evaluate the deliverability for gas wells relies on the pseudo-pressure function m(p):

m(p) = 2 dpzmpp

p∫ 0

Therefore, the rigorous equation for gas flow under pseudo-steady state conditions is the following:

∆m(p) = aqSC + bqSC2

However, for practical purposes, the difference of the squared pressure ∆p2 is generally used:

∆p2 = (pr2 – pwf

2)

The approximation is acceptable when p<2000 psi




The empirical relationship of Rowlins-Schellardt, often referred to as the backpressure equation, is (with 0.5<n<1):

qSC = C(pr2 – pwf

2)n

In the case of condensate gas, the procedure is the same as for gas reservoirs, provided that the condensates are transformed into equivalent gas and that the proper Gas Gravity is used.




INPUT DATA

Design Approach

3000

4000

5000

0 10 20 30 40 50 60 70 80 90 100 110 120

0

2000

4000

History plot (Pressure [psia], Liquid Rate [STB/D] vs Time [hr])

4750

4850

4950

0 10 20 30 40 50 60 70 80 90 100 110 120

0

10000

20000

30000

History plot (Pressure [psia], Gas Rate [Mscf/D] vs Time [hr])

Productivity Index vs Permeability

0

1

2

3

4

5

6

7

8

0 0.5 1 1.5 2 2.5 3

k [mD]

PI [m

3 /d/b

ar] S=0

S=-3S=3

Back Pressure Test

5.9

6

6.1

6.2

6.3

6.4

6.5

6.6

6.7

6.8

6.9

3.9 4 4.1 4.2 4.3 4.4 4.5 4.6

logqSC

log(

p i2 -

p wf2 )

S=0S=5S=10

Geological data

Sedimentological data

Petrophysical data

PVT data

Reservoir P & T

Liquid rates

Flow Period duration

Well Test Sequence

Graphs

Sensitivity (S, kh)

Oil Gas

Oil Gas




5. INPUT DATA

5.1 GEOMETRICAL/SEDIMENTOLOGICAL INFORMATION

The main geometrical parameters considered in the interpretation are the following:

Rw = well radius

It is the radius of the bit that has drilled the producing formation. This is valid both in the case of cased hole and open hole wells.

hp = flowing interval

This parameter is used only in the case of test analyses in wells characterised by “Partial Completion or Partial Penetration”. It allows the evaluation of near-well permeability. In the absense of other information (PLT, dynamic profiles), the flowing interval shall coincide with the lenght of the perforated interval in cased hole or with the formation thickness in open-hole wells.

If several perforated intervals are open to production, the distance between the top of the first perforated interval and the bottom of the last one is considered.

However, if direct well information is available, the actual flowing thickness shall be used.

Lh = horizontal length

In horizontal wells it defines the horizontal length drilled in the producing formation.

The whole length of the perforated portion shall be used for cased hole wells. If several perforated intervals are open to production, the distance measured between the first perforated interval and the last one will be considered.

The whole open hole length will be used in the case of open hole wells.

D = Distance between the wells

Distance between the producer and the observation well. It is used only in the case of interference tests.




5.2 PETROPHYSICAL PARAMETERS

When defining petrophysical parameters, it is important to stress that, though evaluated at the well, they are considered as average reservoir values.

The hypothesis of homogeneous formation might be in contrast with the actual reservoir characteristics. Only numerical models allow the discretisation of the reservoir volume into blocks, to which specific values of petrophysical parameters and saturations can be assigned.

Only large scale reservoir heterogeneities can be taken into account in both analytical and 2-D numeical models.

5.2.1 POROSITY

Øt = porosity (%)

Total (communicating) porosity of the producing formation. In the case of fractured carbonate formations, total porosity is defined as the sum of primary (or matrix Øm) and secondary (or fracture Øf) porosity:

Øt = Øm + Øf

Matrix porosity is generally higher than the fracture one. Fracture porosity is generally lower than 1.0% of the total porous volume. Depending on the type of rock, degree of fracturation and fracture spacing the most probable Øf values are as follows:

• System of fractures : 0.01 - 0.5% • System of microfractures : 0.01 - 1.5%

When the total porosity is greater than 5-6%, as a first approximation, it can be assumed:

Øt = Øm

When the test investigates several layers with different petrophysical characteristics (multilayers) or zones inside the same producing formation, it is possible to define an “average” porosity value calculated as follows:

Øm = (Ø1 h1 + Ø2 h2 +… +Øn hn) / hTot – Net

where hTot - Net is the sum of the net thicknesses of the considered layers or zones.

The porosity value is evaluated on the basis of the compared analysis of logs and cores.




5.2.2 NET PAY

hTot - Net = Net-Pay

Net thickness of the producing formation. It is defined as the sum of the single layer thickness actually contributing to production.

It is evaluated starting from the total reservoir gross thickness ‘‘hGROSS” considered as the difference between the bottom and the top of the structure. The average net thickness is calculated by multiplying the total vertical thickness by the net/gross ratio, which is evaluated by the compared analysis of logs and cores.

However, when interpreting a test, the total net-pay (orthogonal with respect to the dip of the formation) must be used. When present, the dynamic response of a PLT (Production logging tool) represents a further information to characterize the actual producing pay.

This parameter enables the user to evaluate the effective permeability of the fluid considered when the kh of the formation is known.

5.2.3 FLUID SATURATIONS

Sw = water saturation (%)

Water saturation of the producing formation. It is evaluated by log analysis. When the test involves several layers with different petrophysical characteristics (multilayers with or without cross-flow) or zones inside the same producing formation, it is possible to define an average water saturation value calculated as follows:

Swm = (Sw1 Ø1 h1 + Sw2 Ø2 h2 + … + Swn Øn hn) / hTot - Net Øm

where hTot -Net and Øm represent the net total thickness and the average formation porosity.

So = oil saturation (% )

Oil saturation of the producing formation. It is evaluated by log analysis. As before, in the case of multilayers formations, an average oil saturation calculated is calculated:

Som = (So1 Ø1 h1 + So2 Ø2 h2 + … + Son Øn hn) / hTot - Net Øm

Sg = gas saturation (%)

Gas saturation of the producing formation. This case is similar to oil saturation. i.e.:




Sgm = (Sg1 Ø1 h1 + Sg2 Ø2 h2 + … + Sgn Øn hn) / hTot - Net Øm

When the producing formation is characterized by the co-existence of the three phases, the following equation must be satisfied:

Sg + So + Sw = 100

5.2.4 COMPRESSIBILITY

Fluid saturations are used to define the total compressibility of the system, i.e.:

Ct = Co So + Cg Sg+ Cw Sw+ Cf

being Co, Cg, Cw the oil, gas and water compressibility, respectively.

These values are evaluated by PVT analyses or by suitable empirical literature correlations (see paragraph 5.3 PVT data). Cf represents the actual formation compressibility.

For reservoirs with primary or matrix porosity:

Cf = Cfm

where Cfm is the pore volume compressibility by lab measurements.

If no experimental data are available, interpretative softwares directly calculate the pore compressibility as a function of the matrix porosity (Hall diagram).

In fractured reservoirs with secondary porosity, the formation compressibility takes into account the contribution of the matrix, fractures and possible communicating vuggy systems (Karst phenomena):

Cf = Cfm + Φfrac Cfrac +Φv Cv

where:

• Cfm : matrix pore compressibility • Cfrac : fracture compressibility in the range 1.0 – 6.0 x 10-4 (kg/cm2)-1 • Cv : vug compressibility • Øfrac : secondary porosity (fractures) • Øv : vuggy porosity (vugs) comprised in the range 0.1 – 3.0 %.

In this case, the total value of the rock compressibility shall be evaluated with respect to its components and shall be manually introduced into the interpretative softwares.

All the compressibility values are referred to the average static conditions of reservoir pressure and temperature.

As a first approximation it can be assumed Cv = 3 Cfm




5.3 PVT DATA

The evaluation of PVT parameters is always made based on reservoir bottomhole pressure and temperature:

Reservoir pressure

It defines the average static pressure of the reservoir during the test. When a remarkable depletion occurs during the test, average PVT parameters are calculated on the basis of an average pressure value, comprised between the initial and the final value.

Reservoir temperature

It defines the average reservoir static temperature. It is assumed that reservoir phenomena are isothermal. As a consequence, the reservoir temperature is always considered constant. In the case of gas wells, the average static value shall be considered. The highest value measured during the test (usually recorded during the drawdown phases) shall be used for oil wells.

5.3.1 REFERENCE DEPTH

The above defined average static values, as well as all the other pressure and temperature values recorded during the test, are referred to the depth at which the gauge is located.

On the other side, all the corresponding PVT parameters must always be referred to the pressure evaluated at the depth of the middle point of the producing interval. (Reference depth). The PVT parameters should be corrected also for the temperature of the middle point depth. However, the PVT corrections due to temperature variations are negligible in most practical cases.

The gauge is generally located close to the producing zone and hence the variation of the PVT parameters is absolutely negligible. When the producing formation has a remarkable thickness (order of magnitude of many hundreds of meters) there can be significant differences in the PVT.

This is particularly evident in the case of oil bearing formations where it is also possible to encounter a vertical distribution of the oil physical properties due to gravitational effects.

Correction of pressure "at well level"

If the actual vertical distribution of the fluids inside the well is not known, the correction of the reservoir average static pressure at a conventional depth can generate remarkable errors. The error is directly proportional to the distance between the measurement point and the reference depth at which the static pressure and the corresponding PVT parameters are evaluated.




In these cases, it is recommend to verify the fluid nature and the possible fluid distribution in the wellbore and to carry out some static profiles, generally at the end of the final pressure build-up, with numerous steps along the producing formation. The knowledge of the parameters (P,T) measured during the static profiles allows the evaluation of the distribution, nature and density of the different phases in the well.

Where no information on the real well fluid distribution is available, the pressure at which the PVT parameters are referred can be calculated according to different hypotheses (two simple situations are generally considered):

1) Single phase oil: it is assumed that the fluid is single phase oil from the measurement point to the reference depth. Based on the average oil gradient γo (kg/cm2/m) and on the difference ∆h (m) between the reference and the gauge depths the reference pressure Pr is calculated as follows:

Pr (kg/cm2) = Pgauge + γo ∆h

2) Single phase gas: assuming that the fluid is dry gas and based on the average gas gradient the reference pressure Pr is calculated as follows:

Pr (kg/cm2) = Pgauge + γg ∆h

A significant control on field data and particularly on the nature of the produced fluids can be useful to support the adopted hypothesis. For example, the presence of water, also in minimum percentages, found during the flowing phases can be (but not necessarily) a sign of the presence of liquid levels in the well. On the contrary, dry flowing phases do not a priori exclude the presence of liquid levels.

However, the assumptions made to calculate the reference pressure and the value of the average gradient of the fluid must be expressly mentioned.

Correction of the pressure in the reservoir

In this report the correction of pressure from a reference depth in the well to a general “datum”, which must be the same for all the wells of the reservoir, is not discussed.

5.3.2 USE OF PVT REPORTS (LABORATORY ANALYSIS)

When laboratory fluid analysis are available, the required parameters to be used in the interpretation can be directly obtained from PVT reports. These parameters are specific and representative of the reservoir fluids at different pressure and temperature conditions. For this reason, they replace any empirical correlation.

The PVT parameters to be used during an interpretation are those obtained in laboratory tests and particularly:




Oil volume factor, Bo

Considered as the ratio between the measured oil volume at static reservoir conditions at the time of the test and the corresponding oil volume measured at Stock Tank conditions (P = 0.1013 Mpa , T = 288 °K ). The oil volume factors at Stock Tank conditions are obtained in laboratory by flashing a sample at the bubble pressure through Test Separator ("Flash Liberation" (*) type). Between the different tests of pressure separator, the oil volume factor must be selected on the basis of the field separator data, possibly interpolating laboratory data. The correct Boi value at the reservoir pressure must be calculated through the equation:

Boi (corrected) = Bob (flash) x [ Boi ( diff ) / Bob (diff ) ]

where:

• Boi (diff ): differential volume factor at reservoir Pi and T • Bob (diff ): differential volume factor at Pb and reservoir T • Bob ( flash ): flash volume factor at Pb ( Separator Test )

Oil viscosity, µo

Oil viscosity at static reservoir conditions at the time of the test. The viscosity value obtained by a transformation of the type “Differential Liberation" at reservoir temperature shall be used in the interpretation. In the case of saturated oil (Pi = Pbubble), the oil viscosity at the saturation pressure µob shall be used.

Oil compressibility, Co

Oil compressibility at static reservoir conditions at the time of the test. Laboratory analyses measure the average value of oil compressibility from the initial static pressure (Coi) to the saturation pressure (Cob) at reservoir temperature. For pressures lower than Pbubble, taking into account that there are generally no Co laboratory measurements, the oil compressibility can be preliminarily evaluated according to the following equation:

Co (P) = Cob x [ Pb/P ] x [ Rs (P)/Rsb]0,5

where:

(*) The “Differential Liberation” is representative of the phenomena which take place in the reservoir at a constant temperature and is characterised by gas development and production due to the progressive pressure depletion. In contrast, “Flash Liberation” is more consistent with the production process. In fact the oil (and the possible free gas) is produced from the reservoir at surface with a gradual decrease of both pressure and temperature. Then the oil is sent to one more separators in sequence (high and low pressure) and it is then measured, completely deposited, in storage tanks at atmospheric pressure. In each separation stage, gas is separated from oil and measured.




• Co(P): oil compressibility at the pressure P < Pbubble • Cob: oil compressibility at the pressure Pbubble

• Rs(P): laboratory value at the pressure P ("Composite" transformation)

• Rsb: laboratory value at the pressure Pbubble ("Flash” transformation - Separator Test)

The value obtained by the equation is to be considered as a first approximation since the Specific gravity variations of the gas separating from oil due to reductions of pressure δp = Pbubble - P and oil density in API degrees are not taken into account.

The empirical correlation used for the evaluation of the oil compressibility below the bubble point is the following:

Co = 6,8257 x 10-6 x Rs0.5002 x P-1 x T0.76606 x S.G-0.35505 x API0.3613

where the parameters are expressed in the Oil Field System, except for temperature T expressed in F degrees.

5.3.3 USE OF EMPIRICAL CORRELATIONS

Field Data

Due to the lack of PVT reports, the reservoir fluid parameters are obtained from empirical correlations provided by the literature. In any case, field data evaluated at the surface during the test and presented in the test reports of the Service Companies are used. The reports provide:

for gas wells: the average value of the Specific Gravity ( air = 1.0 ) of the gas mixture at Standard Conditions (P = 0.1013 MPa, T = 288 °K).

for oil wells: the oil density expressed in API degrees, the Specific Gravity of the gas separating from oil and the GOR gas/oil ratio from test at Standard Conditions. They also include the separation conditions at different stages. The oil Shrinkage coefficient for converting the measurements from separator conditions to ST conditions, is also presented.

In both cases, the field evaluation of the Specific Gas Gravity is referred to the total gaseous mixture, i.e. the measurement takes specifically into account the presence of H2S, CO2, N2.




Choice of the correlations: Main Phase GAS

Starting from field data, both Interpret/2003 and Saphir directly calculate all the PVT parameters necessary for the test analysis (Z factor, Bg volume factor, Cg compressibility) based on the static reservoir pressure and temperature and the Specific Gravity by using their internal correlations. In the case of laboratory analysis the gas composition shall be directly introduced.

The Lee- Gonzales - Eakin correlation must be used for the calculation of gas viscosity.

Condensate case

In gas condensate reservoirs, the fluid at reservoir pressure and temperature conditions is in the gaseous phase. At constant reservoir temperature and after pressure depletion, the dew point can be reached and the liquid phase can precipitate (retrograde condensation phenomenon). During production gas is the dominant phase. The liquid phase which condensates at the surface is gathered and measured in the test separator. In the gas condensate test, the GOR has a wide range (from 5000 to 10000 Scf/STb) while the Specific Gravity of the condensate is generally greater than 45 API degrees.

The PVT calculation for tests in condensate gas reservoirs with retrograde condensation is made by using the average specific gravity SGaverage at initial reservoir conditions. From a conceptual point of view, this value is completely different from the one measured at the surface since its composition varies after the separation of the liquid component.

The average specific gravity is defined by the relationship ("Applied Petroleum Reservoir Engineering" - Craft and Hawkins):

SGaverage = (GOR x SGgas + 4584 x SGoil) / (GOR + 132800 x SGoil / Moil)

where:

• GOR : test gas-oil ratio, Scf for Stb of condensate • SGgas: specific - gravity of the surface gas (air = 1.0) • SGoil: specific - gravity of the surface condensate (water = 1.0) • Moil : molecular weight of the condensate

where:

SGoil= 141.5 / (131.5 + APIcond)

Moil = 6084 / (APIcond - 5.9)

For the evaluation of the PVT parameters (Z, Bg, µg), the interpretative softwares consider the SGaverage value calculated using the internal correlation of Lee-Gonzales-Eakin.




Choice of the correlations: Main Phase OIL

The internal Interpret/2003 and Saphir correlations are deemed insufficient to cover all the different types of reservoir oils. The conclusions of the “Reliability Study” of the correlations that estimate the properties of the reservoir oils (RIIN - September 1994) listed the optimal empirical correlations for reconstructing the main thermodynamic parameters with respect to the experimental PVT data assumed as the reference values. The most reliable correlation was selected, for each physical property, as a function of the oil API gravity.

The results are presented in the following tables:

Table 5.3.3.1

Type of oils API range Bubble

pressure, PB Solution gas,

Rs Volume Factor,

BoB Compressibility,

Co

Super heavy < 10 STANDING STANDING GLASO VASQUEZ-BEGGS

Heavy 10<AP<22.3 STANDING VASQUEZ-BEGGS

VASQUEZ-BEGGS VASQUEZ-BEGGS

Medium 22.3<API<33.1 KARTOATMODJO KARTOATMODJO KARTOATMODJO VASQUEZ-BEGGS

Light > 33.1 GLASO KARTOATMODJO KARTOATMODJO LABEDI

In the previous table the evaluation of the oil volume factor Bob is referred to the reservoir temperature and bubble pressure. Since both Interpret/2003 and Saphir requires the Bo, volume factor at the reservoir average static pressure at the time of the test, the following relationship shall be used ( P ≥ Pb ):

Bo = Bob x e-Co (Pi - Pb) (1)

where Co represents the oil compressibility at the average reservoir static conditions.

The oil viscosities under the different conditions have been evaluated through the following correlations:




Table 5.3.3.2

Type of oils API range Dead oil viscosity,

µod Saturated oil viscosity, µob

Undersaturated oil viscosity, µo

Super heavy < 10 EGBOGAH-JACK KARTOATMODJO LABEDI

Heavy 10<API<22.3 EGBOGAH-JACK KARTOATMODJO KARTOATMODJO

Medium 22.3<API<33.1 KARTOATMODJO KARTOATMODJO LABEDI

Light > 33.1 EGBOGAH-JACK BEGGS-ROBINSON LABEDI

where:

• µod: viscosity of the dead oil at the atmospheric pressure and at reservoir temperature;

• µob : viscosity of the saturated oil at bubble pressure and at reservoir temperature;

• µo: viscosity of the undersaturated oil at reservoir pressure and temperature.

The application software "Predator ver. 1.0" ( APSERIIN - 9/94 ) allows the evaluation of the PVT parameters by automatically selecting the option which always gives the most reliable correlation.

The parameters obtained are manually introduced into the interpretative software independently from its internal correlations. In particular, the program requires: µo, Bo, Co at the average reservoir static conditions at the time of the test. The Bo value is calculated based on the Bob via equation (1).

Note: The correlations developed by Gorini-Palma, which give both the Bo and µo curves as a function of pressure and temperature, can be used as an alternative. These correlations shall be introduced into a program already existing in MODI ("Mbal") or developed in an ad hoc application.

Two phase/three phase flow

In addition to the single phase flow condition, there is the possibility of analysing tests with multiphase flow both at the well (i.e.: flowing pressures lower than Pb with gas phase development) and in the formation (i.e. gas development, as mobile phase, in the reservoir where Sg > Sgcritical). In all cases the PVT calculation imposes the selection of the dominant flow phase.

It is important to underline that the test interpretation will have to be reviewed afterwards when the PVT data obtained through laboratory analysis are available.




In fact, as previously stated, the empirical correlations cannot replace laboratory parameters. An additional further weakness of any correlation is due to the fact that corralations are based on field measurements affected by uncertainty. In particular, the GOR evaluation, from which the bubble pressure value Pb and the oil volume value Bo depend, can be difficult due to the instability of the gas phase during the flowing periods. The average error on the measurement is at least 5% in the case when the surface equipments are perfectly calibrated. The phenomenon is remarkable in the case of saturated or very volatile oils due to the high gas rates. This results in large errors in the determination of the other PVT parameters and, as a consequence, in the evaluation of the results of the interpretation.

5.4 PRODUCTION DATA

The surface data, relevant to production data, define the information recorded at wellhead during a test. Practically, they reflect the nature, quantity and petrophysical properties of the fluids produced as well as wellhead pressures and temperatures.

5.4.1 PRODUCED FLUIDS The flow rates of the fluids produced at the surface or injected in the formation are given during any test. The measurement is carried out through three phases separators which can give the flow rates of the condensate, oil, and water produced (or injected) at Stock Tank conditions and of gas at Standard conditions. The specific physical properties are defined for each fluid phase. The surface monitoring takes place at various time steps. In the initial phase, immediately after the well opening, pressure measurements are taken every 5-10 minutes. This allows a better monitoring of the well flowing profile which is sometimes characterised by remarkable oscillations. The first flow rate value is generally given after 30 minutes. Then, after a stabilisation trend of the flowing parameters, the measurement is made every 30, 60 minutes. This discrete monitoring describes the evolution in time of each observed parameter.

Two different situations may occur. These are showed in the following paragraphs.

5.4.1.1 TESTS IN GAS CONDENSATE WELLS

The correct interpretative approach consists in adding the contribution of the condensate volume, transformed into equivalent gas, to the corresponding gas flow rates.

The equivalent gas volume expressed in Scf referred to a barrel of condensate measured at Stock Tank conditions is given by the following relationship (“Applied Petroleum Reservoir Engineering" – “Craft and Hawkins"):

GE = 13300 x SGoil / Moil




where:

• GE = Gas equivalent expressed in Scf/STb

• SGoiI = 141.5 / (131.5 +API) Specific gravity of the oil (water = 1 .0)

• Moil = 6084 / (API - 5.9) Molecular weight of the oil

5.4.1.2 TESTS WITHOUT SURFACE FLOW

No surface flow may occur in tests, generally DST's, reflecting high viscosity heavy oil in very low permeability formations. In this situation, it is necessary to reconstruct the oil rate history during the filling of the string. Two simple procedures can be followed:

The total recovery is known

The total vertical length of the oil column in the string is known and an average oil rate can be estimated through the relationship:

Qo = Hov x Cstring x 24 / TP

where:

• Qo : average oil rate (Stb/day);

• Hov: oil column in the string (ft);

• Cstring: string capacity (bbl/ft);

• TP: production time (hours)

The recovery is not known

If the recovery is not known or it is only partial, it is always possible to estimate the oil rate history in time provided that the oil API gravity is known and a bottomhole gauge is available.

During the different filling phases, the oil column will exert a pressure on the gauge which will increase in time.

It is thus possible to divide the whole production period in discrete time intervals ∆t; a pressure increase ∆p will correspond to each of them. The average oil rate in the i-th interval is calculated through the following relationship:




Qoi = ∆pi x Cstring x 24 / (∆ti x Fluid Gradient)

where:

• Qoi: average oil rate in the i-esim time interval (STb/day);

• ∆ti = ti+1 – ti: i-esim time interval during the filling of the string (hours);

• ∆pi =pi+1 - pi: i-esim pressure increase recorded by the gauge (psi);

• Fluid gradient: 0.433 x SGoil average fluid gradient (psi/ft).

5.5 PRESSURE AND TEMPERATURE DATA

5.5.1 WELLHEAD DATA

5.5.1.1 WELLHEAD PRESSURES

Monitoring of wellhead pressure and temperature is carried out. The pressure measurement is made through a Dead Weight Tester (DWT) which hydraulically balances the well pressure. Its accuracy is of the order of 0.1% of the measured value. Electric sensors are seldom used.

The wellhead pressure data are not directly used in analysing the test, but they allow a comparison with the pressure data recorded by bottomhole electronic gauges (Quality Control).

5.5.1.2 WELLHEAD TEMPERATURES

The measurement of the temperature of the produced fluid is generally made by thermometers located on the production line. The surface temperature measurement at static conditions is not meaningful from a physical point of view. The temperatures measured under dynamic conditions have a low degree of reliability since they are affected by the external temperature. However, they have not a specific value in the interpretation. In the absence of measured gas rates, the Twf is used only to estimate the theoretical gas rate at critical flow conditions (see Chapter 7.2 - empirical formula). The dynamic wellhead temperatures have a remarkable importance in dimensioning and planning the surface facilities.

The wellhead dynamic parameters are reporte at the same sampling rate of the produced fluids. This means that, at a certain time of the test, there is always a direct correspondence between the rate value and the dynamic pressure.

The final test report provided by the Service Companies presents all the surface data according to a chronological sequence that includes all the testing sequence and the main operations carried out (profiles, drillings, acid jobs and gravel packs).




5.5.2 BOTTOM HOLE DATA

The Well Testing principle is to analyse the reservoir response to an input signal (the imposed rate) to which an output signal (the bottomhole pressure) corresponds. The identification of the flow regimes in the formation, the main petrophysical properties, the potentialities and the physical limits of the reservoir are based on the bottomhole pressure response.

5.5.2.1 BOTTOM HOLE PRESSURES AND TEMPERATURES

The recording of bottomhole data during the test is possible by using electronic gauges. Mechanical gauges (Amerada) are obsolete due to their poor performances with respect to electronic gauges.

In accordance with the operation constraints and depending on the string-well system, the gauges are located as close as possible to the producing formation in order to reduce errors in referring the values from the measurement point to a reference depth.

The electronic gauges can provide the bottomhole temperature and pressure with variable sampling rates (from a minimum of 2 seconds between the measured data).

However, it is recommended to use sampling intervals higher than 5 seconds since lower values can lead to wrong temperature measurements. This is due to the thermic inertia of the tool which is not able to adapt to fast temperature variations.

A general criteria to be followed is to decrease the sampling rate at each phase modification (from flowing to shut-in and vice versa). At longer times, the sampling interval can be gradually increased. However, for tests shorter than 10-15 days it is suggested not to select sampling rates longer than 15 minutes so as to have a suitable data management without affecting the continuity of the measurement.

As a common procedure, the Service Company provides the results of the instrumental monitoring such as cumulative times, pressure and temperatures organised in ASCII files.

Paragraph 6.2 gives the main properties and “performances” of the different types of instruments.

5.6 OTHER INFORMATION (PLT, RFT, MDT, LOGS, CORES)

The well test interpretation must be integrated with other information provided by measurements taken before and/or after the production test. This data allow a complete validation of the well test results.

The main additional information are obtained by the following tools:

• PLT (Production Logging Tool): it is used to evaluate the real fow profile vs depth at different rates and the presence of possible cross-flow under shut-in conditions. The PLT is strongly recommended when testing heterogeneous reservoirs (multi-layer or multi-zone formations, etc...)




• RFT (Repeat Formation Test) and MDT (Modular Formation Dinamic Tester): they are used to collect reservoir fluid samples and to measure reservoir pressure at different depth along the well profile.

• LOGS: all the information obtained from logs related to geology, sedimentology, stratigrafy etc. are useful for a correct interpretation and must be taken into account when available.

• CORES: all the information obtained from lab analyses on cores must be integrated with other available information for a complete rock characterization.




6. GAUGE SPECIFICATIONS

6.1 SURFACE AND DOWN-HOLE EQUIPMENT REQUIREMENTS

Readers who would like to improve their knowledge about surface and down-hole equipment can refer to the well test operative manual (“Well Test Procedures Manual” STAP-P-1-M-7130; see link: http://wwwdsc.in.agip.it/drilling/manuals/pagdrill/pagdrill.html)

6.2 TECHNOLOGY REQUIREMENTS

Apart from technical specifications, the measurement instruments can be subdivided into two main types:

1) SRO Gauges (Surface Read Out),

2) Memory Gauges

6.2.1 SURFACE READ OUT (SRO) GAUGES

During the various test phases SRO gauges allow a real time monitoring of the data being measured. This is because the gauges are run in the well by a monoconductor cable allowing the transmission of the signal from the bottom to the surface.

Advantages:

• Direct reservoir control for optimization of the testing sequence and thus

minimization of costs (very high if the tests are carried out with the rig on site or in offshore operations).

• Real time well monitoring in any phase of the test by making dynamic or static profiles to assess the real flow distribution and the nature of the fluids along the wellbore. It is also possible to have relevant information on the portion of the formation that actually contributes to production (thermometry).

• Direct action on sampling times during the data acquisition when the original test programme needs to be modified.

http://wwwdsc.in.agip.it/drilling/manuals/pagdrill/pagdrill.html




Disadvantages:

• High monitoring costs due to the use of surface equipment and personnel

provided by Service Companies.

• SRO gauges are generally run in the well in a stand alone mode. As a consequence, in the case of malfunctioning, there is no way to verify the reliability of the instrument response.

Use:

Recommended in exploration wells to have an immediate verification of the reservoir response and in all situations requiring real time monitoring and immediate decision making for peculiarity and importance.

6.2.2 MEMORY GAUGES

These gauges are run in the well by a harmonic steel cable (slick-line) and placed in nipples in the completion string. Alternatively, they are directly run with the testing string in a tool called "bundle carrier”. At the end of the test they are retreived from the well.

The main difference with respect to the SRO gauges is that it is not possible to monitor the pressure response in real time; only at the end of the test the collected data can be analysed. In fact, the acquisition is guaranteed by a battery pack (generally lithium based) located below the gauges. All the relevant data are stored in the tool internal memory. Only at the end of the test the gauges are retreived and the data recorded unloaded and availble for interpretation.

Advantages:

• At least two gauges (tandem) are run into the well to guarantee a safer data

acquisition.

• Possibility to compare the data recorded by each gauge. For redundancy in some cases (especially in exploration wells) a third memory gauge is added, also to solve potential inconsistencies between measurements.

• Less expensive since they do not require the use of surface facilities and support personnel during the test.

Disadvantages:

• It is not possible to modify the sampling rate during the test and control the

test in real time.




• Limited test time due to the battery efficiency that depends on the sampling rate and on the number of data recorded (times, pressures and temperatures). Moreover, the battery duration is a function of the bottomhole temperature: the higher the temperature the lower the duration of the batteries.

Use:

Combined with SRO in exploration wells and, generally, in development wells with definitive completion.

6.2.3 MAIN PROPERTIES

When planning a test, the gauge is the key element to reach the designed targets.

The main gauge properties are: stability, resolution, accuracy, and stabilization time.

Stability

Property related to the drift phenomenon. It defines the shift in measured pressure compared to the actual value. Drift phenomena tend to amplify in time and are generally positive.

Drift does not depend on the magnitude of the measured pressure.

The importance of the drift varies from gauge to gauge and for the same type of gauge there are different types of drifts.

As an example, the indicative laboratory drift values for different types of gauges are reported:

• Mechanical Gauges (Amerada) : 10 psi/first day, then 10 psi/week;

• Strain Gauges: < 3 psi/first day, then < 1.5 psi/week;

• Quartz Gauges: ~0.2 psi/first week, then < 0.1 psi/week.

It can be noted that quartz gauges are very stable and do not have drift problems. Long tests, of the order of several weeks, require the application area of Quartz Gauges.

Resolution

The resolution of an instrument represents the amplitude of the smallest step detectable in monitoring the real pressure. Thus, all the gauges reproduce the real physical pressure behaviour in a reservoir by steps. The resolution is a property varying from gauge to gauge. A high resolution gauge can be an efficient choice for tests carried out in very high




permeability formations. Indicative laboratory resolution values are as follows:

• Mechanical Gauges (Amerada): 0.05% full scale (i.e. 5 psi @ 10000 psi);

• Strain Gauges: 0.2 psi @ 15000 psi;

• Quartz Gauges: 0.001 psi @ 10000 psi.

Accuracy

For a given pressure, it defines the relationship between the gauge pressure measure and the actual value.

Accuracy laboratory values for the different gauges are as follows:

• Mechanical Gauges: 0.4% full scale (i.e. 40 psi @ 10000 psi);

• Strain Gauges: 0.1 % full scale (i.e. 10 psi @ 10000 psi);

• Quartz Gauges: 0.02% full scale (i.e. 2 psi @ 10000 psi).

Stabilization times

Time necessary to stabilize a gauge after abrupt pressure and temperature variations (i.e. during the steps when carrying out static and/or dynamic profiles). It is defined as the time necessary so that the difference between the gauge value and the actual value is smaller than 1 psi. It can vary from more than 10 minutes in the case of Amerada to less than 1 minute (quartz gauge).

All the above values provided by Manufacturers were obtained under laboratory conditions by submitting the gauges to increasing pressure steps from 1000 psi to 10000 psi. The temperature was kept constant at a value of 150 °C for the testing time.

Based on the existing technology, all the electronic gauges are suitable to work at reservoir temperature up to 150°C. Special gauges must be required when testing HP-HT environment with reservoir temperature greater than 150°C. The current technological limit is some of 185-190°C.




6.3 DATA ACQUISITION PROGRAMME

6.3.1 FILE FORMAT STANDARDIZATION OF DATA RECORDED DURING WELL TESTING

The release of ASCII files containing the following information is generally required:

• a few heading lines - information notes, numerical values of quantities not depending on time;

• lines relevant to the required numerical values recorded as a function of time.

Each line, either relevant to information data or recorded values, must be concluded by a carriage return (<CR>). The recorded values must always be reported starting from a defined line number. As far as the information data are concerned, it should be noted that a well-defined meaning is associated to each line: the information shouldn’t be available, the line must be left empty , and a <CR> typed.

The last line of the file should contain the last values recorded, and not special characters or indicators of end of file. A <CR> is always necessary.

Note : the use of <CR> or <CR><LF> as the line ender is absolutely indifferent. The following pages present details concerning the file format for the in-hole recordings – paragraph 6.3.1.1 - bottom hole recordings (Pressure and temperature history files) - and surface recordings - paragraph 6.3.1.2 (Surface & Downhole data) -.

As far as the system of units is concerned, note that in all cases the recorded values are implicitly referred to pre-arranged units, which can be reported in one of the file heading lines for information purposes only.

6.3.1.1 PRESSURE AND TEMPERATURE HISTORY FILES

History files must contain the pressure and temperature values recorded by the tool in the well. If pressure and temperature profiles have been carried out, the values recorded during the run-in hole and pull-out of hole operations must be also included. The recommended file format is shown in the following pages.

<FILE HEADER> <from line 1 to line 21: the description of the line content can occupy

the first 24 positions; the corresponding value must be specified from position 25 on, without length limit; the line must NOT contain <tab>, but spaces > only

line 1------------------------24 25----------------------------------

<CR>




1 Service Company xxxxxxxxxxxxxx... 2 Representative xxxxxxxxxxxxxx... 3 Well name xxxxxxxxxxxxxx... 4 Test identification xxxxxxxxxxxxxx... (as indicated in Eni E&P - SPARE reports) 5 Period (since) MM/DD/YYYY hh:mm:ss 6 (to) MM/DD/YYYY hh:mm:ss 7 Tested interval (from mRT) 0.000 8 (to mRT) 0.000 9 Instrument depth (mRT) 0.000 10 Instrument type xxxxxxxxxx...(SRO/Memory/...) 11 Sensor type xxxxxxxxxx...(quartz/strain gauge/...) 12 Trade name xxxxxxxxxx... 13 N° series xxxxxxxxxx... 14 Date of last calibration mm/dd/yyyy 15 Work. pressure(kg/cm2 rel.) 0.000 16 Working temperature (°C) 0.00 17 Resolution xxxxxxxxxx... 18 Accuracy xxxxxxxxxx... 19 DWT THP (kg/cm2 rel.) 0.00 (pressure measured at well head with the Dead Weight Tool) 20 Gauge THP (kg/cm2 rel.) 0.00 (pressure measured at well head with the instrument) 21 Date/hour recording start MM/DD/YYYY hh:mm:ss <from line 22 to line 25: notes, if any, can be specified from position 1

on, without length limits; line 26 must be empty - containing a <CR> only -> line 1---------------------------------------------------------------

<CR> 22 xxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxx.....(Note) 23 xxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxx.....(Note) 24 xxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxx.....(Note) 25 xxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxx.....(Note) 26 <RAW DATA ROWS> <from line 27 on: data must be organised into 5 columns, the first 4 must

have a fixed length. The last column, to be used for notes, must start from position 66 and doesn’t have length limit; it does not contain <CR>, except the one

INDICATING THE END OF THE LINE. If there are no notes, the <CR> at the end of the line MUST be typed after position 65.

This is valid also when no temperature values have been recorded; the line must NOT contain <tab>, but only spaces.

There are no limits on the number of decimals for the recorded numerical values.

Lines 27 and 28 must always contain the description of the variables and the reference measurement units and are not

considered as containing data; the recorded values start from line 29. line 1-----------------20 21-------------35 36----------50 51----------

65 66----------------------------------<CR>




27 date time elapsed time pressure temperature remarks 28 MM/DD/YYYY hh:mm:ss hours dec. kg/cm2 r. °C 29 01/01/0001 00:00:00 0.0000 0.000 0.00 xxxxxxx 30 01/01/0001 00:00:00 0.0000 0.000 0.00 xxxxxxx

6.3.1.2 SURFACE & DOWNHOLE DATA

Surface data files must contain values of the significant variables as a function of time, i.e. pressure, temperature, flow rates, and fluid properties, recorded by tools/equipment located at surface, notes, and a set of pressure and temperature data downhole recorded (based on variable sampling time intervals, coinciding with the monitoring at the well head). Find here below the variables which have been identified, together with their relevant units, and the order according to which they must be reported inside the file:

1) date time MM/DD/YYYY hh:mm 2) elapsed time min 3) choke size inch 4) BHP kg/cm2 rel. 5) BHT °C 6) THP kg/cm2 rel. 7) THT °C 8) CHP kg/cm2 rel. 9) separator pressure kg/cm2 rel. 10) separator temperature °C 11) gas flow rate Sm3/day 12) oil rate STm3/day 13) water rate m3/day 14) cumulative oil m3 15) cumulative water m3 16) G.O.R. Sm3/STm3 17) W.O.R. m3/STm3 18) B.S.W. % 19) oil density °API 20) gas grav. - air = 1 ad 21) water density g/l 22) NaCl g/l 23) pH ad 24) shrink factor ad 25) H2S ppm 26) remarks (events) notes




The proposed file format is presented in the following pages.

<FILE header> <from line 1 to line 9 : the description of the line content can occupy

the first 24 positions; the corresponding value must be specified from position 25 on, without

length limits; the line must not contain <tab>, but only space line 1------------------------24 25----------------------------------<CR> 1 Service Company xxxxxxxxxxxxxx... 2 Representative xxxxxxxxxxxxxx... 3 Well name xxxxxxxxxxxxxx... 4 Test identification xxx.(as indicated in Eni E&P - Spare

1 reports) 5 Period (from) MM/DD/YYYY hh:mm:ss 6 (to) MM/DD/YYYY hh:mm:ss 7 Tested interval (from mRT) 0.000 8 (to mRT) 0.000 9 Gauge depth. (mRT) 0.000 <from line 10 to line 13: notes, if any, can be specified from position 1

on,without length limits; line 14 must be empty - it contains only a <CR> line 1--------------------------------------------------------------

<CR> 10 xxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxx.....(Note) 11 xxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxx.....(Note) 12 xxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxx.....(Note) 13 xxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxx.....(Note) 14 xxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxxx.....(Note) <DATA ROWS> <from line 15 on: the data must be reported in the order already

described in the previous page, starting from position 1, and separated by “ ; “ If a value is lacking, “ ; “ must be typed in any case to allow the

correct identification of the next value unless it is the last data of the list- the remarks which must contain

neither “ ; “ nor <CR>, except the one indicating the end of the line. Lines must not be broken; there is no limit on the number of decimals of

the numerical values. Lines 15 and 16 must always contain the description of the

variable and reference unit and are not considered as containing data; the recorded values start from line 17.




line 1---------------------------------------------------<CR> 15 date time; elapsed; choke; BHP; BHT;(the variables must be reported;

26 columns are normally expected separated by “ ; “) 16 MM/DD/YYYY hh:mm;min;inch;kg/cm2 rel.; °C;.......(the units of each

variable must be all reported; 26 columns are normally expected separated by “ ; “)

17 01/01/0001 00:00;0;0.0;0.0;0.0;0.0;0.0;0.0;0.0;0.0;0.0;0.0;0.0;0.0;0.0;0.0;0.0;0.0;0.0;0.0;0.0;0.0;0.0;0.0;0.0;xxxxx.....

18 01/01/0001 00:00;0;0.0;0.0;0.0;0.0;0.0;0.0;0.0;0.0;0.0;0.0;0.0;0.0;0.0;0.0;0.0;0.0;0.0;0.0;0.0;0.0;0.0;0.0;0.0;xxxxx.....




7. WELL TEST INTERPRETATION

Before interpreting a test, a fundamental step is the quality control of the raw data ( Q.C.). This operation is complex and important at the same time. In fact, possible anomalies are sometimes well masked and not identifiable; moreover, the choice of parameters which are not representative of the real system leads to conclusions unrelated with the physical reality of the reservoir phenomena.

It is fundamental that the control and validation of all the data recorded is carried out on site. This quality control allows for a rapid modification of the operations in order to remedy to possible failures in the surface equipments and in the electronic gauges measurements.

Should the Q.C. be carried out at a later time, just before the interpretation, and data found to lack representativeness, the necessity to repeat the test would involve much higher additional costs; moreover, there is the risk that the well performances are no longer the same as those at the time of the original test.

7.1 WELLHEAD PARAMETERS

Wellhead pressure readings are not directly used in the analysis of a test, because they only take part in the estimation of the deliverability of gas wells through the (empirical) wellhead flow equation.

However, the wellhead pressure is used for comparison with the pressure data recorded by the electronic bottomhole gauges. In fact, when the electronic gauges are at wellhead before being run into the well, they must read a pressure measurement consistent with that of the D.W.T. The difference shall not exceed 0.2 - 0.4%. To obtain a valid quality control, the comparison must be repeated at the end of the test at the same conditions and the error must be of the same magnitude as the one found at the beginning of the test. Significant differences can indicate an inadequate calibration of the gauge (hysteresis and drift phenomena in long duration tests), which can invalidate the response of the bottomhole gauges.

Obviously, in the case of SRO gauges, the control takes place in real time, whereas in the case of memory gauges, the control is possible only after unloading the data.

It is also recommendable to compare the measurements when the well is under static conditions in order to avoid effects due to the fluid flow.




7.2 VALIDATE RATES: DEFINITION OF PRODUCTION HISTORY

The rates of the produced fluids must be adequately controlled so that they are consistent with the corresponding bottomhole pressure trends.

In the case that test flow rate data is missing or anomalous, surface rates can be estimated on the basis of the dynamic wellhead data. In particular:

Gas wells

The gas rate is estimated according to the following equation (See Frick – Vol.1 – pag. 12-42):

Qgas = C x Pwf / ( SGgas x Twf )0.5 (a)

where:

• Qgas: gas rate at standard conditions (MScf/day);

• C: calibrated orifice coefficient, given as a function of the choke diameter (inches);

• Pwf: wellhead flowing pressure (psia);

• SGgas: gas specific gravity (air = 1.0);

• Twf: wellhead flowing temperature (Rankine degrees).

In the table below the values of the C coefficient are reported as a function of the diameter of the measurement line and as a function of the calibrated orifice (choke).




Table 8.2.1 – C coefficient

Choke diameter C coefficient C coefficient

inches 2 inches pipe 4 inches pipe

1/16 1.524

3/32 3.355

1/8 6.301

3/16 14.47

7/32 19.97

¼ 25.86 24.92

5/16 39.77

3/8 56.68 56.01

7/16 81.09

½ 101.8 100.2

5/8 154.0 156.1

¾ 224.9 223.7

7/8 309.3 304.2

1 406.7 396.3

1 1/8 520.8 499.2

Oil wells

The oil rate is estimated by an empirical relationship (W.E.Gilbert) which relies on the GOR and on the wellhead flowing pressure:

Qoil = Pwf x Ø1.89 / [ 435 x ( GOR/1000 )0.546 ] (b)

where:

• Qoil: oil rate at Stock Tank conditions (STb/day);

• Ø: dimensionless choke diameter, expressed as a fraction of 64” (i.e.: for choke 12/64", Ø = 12),




• Pwf: wellhead flowing pressure (psiG);

• GOR: gas-oil ratio from test (Scf/STb).

Both equations (a) and (b) are valid in the case of critical flow. Critical flow conditions occur when the upstream pressure is at least twice the downstream pressure. In this case the fluid velocity reaches a maximum value and then keeps constant, apart from pressure variations downstream. However, the values obtained from equations (a) and (b) must be considered as a first approximation of the real rate data: the average error can be greater than 10 - 12%.

In particular, equation (a) is affected by the uncertainty in the Twf temperature measured at well head under dynamic conditions. When temperature dynamic profiles are available, the wellhead Twf value obtained by interpolating the average temperature gradient in the string shall be used. In the absence of any measurement, the value of 520° Rankine (15.5°C) can be assumed as a first approximation.

Before the interpretation, it is important to define the production rate history during the test. The definition of a correct production profile is made as follows:

• Reconstruction of the real production trend according to discrete steps; a constant flow rate value, representing the average value, is assigned to each step. Each step defines the corresponding flow period.

• The discretisation adopted should reproduce the actual production trend. The constraints to be satisfied are the real beginning and ending time of each flowing phase and the cumulative produced fluid.

• Interpret/2003 and Saphir present the “Validation rates” option which enables the user to check whether the flow rate data and the corresponding bottom ∆p is homogeneous. Practically this means that all the flow periods should show the same radial flow and, hence, that the Kh of the formation is constant. However, it is a delicate operation since the model automatically corrects the flow rate values in the different phases starting from a reference value which must be considered by the interpreter as the most reliable value. The main difficulty consists in the identification of this reference value, especially when the well has not been cleaned up enough or is characterised by very high wellbore storage that might hide the total kh of the formation. Moreover, especially in multilayer formations, great attention must be paid to the automatic correction of the rate values since, in this case, it is not possible to exclude variations of the total kh. In fact, higher rates generate bottom ∆p which can activate layers that previously did not contribute to production.

• In the case of tests carried out in wells already completed and producing for a long time, it is important not only that the average rates during each time step of the test be defined, but also that the total volume of the produced fluids and the total flowing duration before the test be known.




In fact, should the production history prior to the test be disregarded and the test analysis be based on the testing rates only, false trends in the derivative shape might be induced. On the other hand, it is not necessary to describe the past production profile in details since they do not affect the derivative response too much. Possible shut-in periods must always be taken into account.

7.3 VALIDATE GAUGES

The quality control on bottomhole parameters has a remarkable impact on the test interpretation.

In fact the definition of the most suitable reservoir model starts from the analysis of the log-log plot (diagnostic -plot) which describes the behaviour of the bottomhole pressure and of its derivative.

The acquisition of bottomhole data, as far as pressure and temperature are concerned, is made by using high precision electronic gauges located just above the producing formation. As already mentioned, they can be of the two types: Memory or SRO Gauges, the latter allowing for real time readings.

It is fundamental that the gauges, independently from the type, are accurately calibrated in laboratory. For this reason, the Service Company must provide the certification and the specifications found in the last calibration.

In the case of a single gauge the quality check of the recorded data is essentially based on the double comparison (pre and post job) with the reference D.W.T. as previously described. The control is made only against the wellhead pressure with the well shut-in.

In case two or more gauges are used, their responses must always be compared not only in terms of pressure, but also of bottomhole temperatures.

The "validate gauges" option is very useful in this case. Possible time shifts due to an imperfect synchronisation of the gauges can be evaluated and corrected. The pressure differences due to the distance between the measurement points allow the definition of the fluid phase (liquid or gas). If the ∆p is almost constant, this means that the gauges are immersed in the same fluid for the whole test duration.

In the case of discrepancy between the gauges, the comparison between wellhead data and D.W.T. is of great importance since, in many cases, it helps identifying the most correct gauge response.

The safest method to carry out a reliable quality control on the recorded data is the evaluation of the calibration specifications. This must be made by laboratory tests before the operation. Then these specifications must be compared to the one obtained in the same laboratory conditions at the end of the operation. This also allows identification of small deviations with respect to the initial response. For example, problems induced by drift phenomena of the order of magnitude of some psi/week only, which are hardly recognisable by the D.W.T, can be correctly taken into account.




Important: particular attention must be paid when correcting the raw data, since even minimal variations of the original parameters might have a high impact on the shape of the derivative which could show false trends that are not representative of the reservoir response.

Smoothing The smoothing option available in interpretative softwares implies the application of a mathematical algorithm, which enables the user to adjust the shape of the derivative curve. The smoothing is used when the pressure values are of low quality (poor resolution) and/or are affected by remarkable instrumental noise.

The smoothing enables the user to average the raw data, reducing the scattering to obtain better recognizable trends on the pressure derivative. This operation is very problematic since very high smoothing values can mask the reservoir response.

Interpret/2003 offers two types of algorithm for the evaluation of the smoothing1:

• N-Points Algorithm;

• Windows Algorithm (used by default).

The following procedure is recommended:

• always start by displaying of the raw data without any smoothing. This means to impose N = 1 in the first case and Smoothing = 0 in the second case. If the quality of the data is good, the interpretation can be made directly.

• Otherwise, the smoothing value can be progressively increased up to a maximum value of 0.2-0.25. The scattering is reduced without significant changes in the general shape of the derivative.

• It is recommendable, since more immediate, to use the N-Points algorithm with even numbers greater than 1 (raw data) to obtain an interpretable shape. Compared to the Windows Algorithm, this algorithm has the advantage of being independent from the length of the flow period considered. Very high smoothing values reveal a poor quality of the data recorded.

1 Manual INTERPRET/2003: Option “Validate Gauges”




Saphir features only one type of algorithm for smoothing evaluation. It uses a 3 point central derivative obtained from the weighted average of the slopes between the given point, a point before and a point after. For the first and last data points a 3 points right and a 3 points left derivative is used to reduce end effects. With no smoothing, consecutive points are used to calculate the derivative. Saphir accepts smoothing of up to 2, but values over 0.2 distort the shape of the curve.

In the case of doubt in the interpretation of the derivative shape, it is always recommendable to make a check with other tests previously carried out on the same layer, since they must reasonably reproduce the same reservoir response.

7.4 WELL TEST INTERPRETATION PROCESS

Provided that a Quality Control has been carefully performed on all geometrical, petrophysical and dynamic data (pressure & rates), the interpretation can be started.

Well test analysis consists of a three step process:

• Identification of the theoretical interpretation model. The derivative plot is the primary identification tool. In this step all the characteristic flow regimes are identified as well as any change in fluid/rock properties, presence of boundaries, etc. All the other specialized plots are also of a great help in selecting the proper model.

• Evaluation of the interpretation model. The log-log pressure and derivative plot is used to make the first match and first-attempt parameters are found.

• Verification on the interpretation model. The simulation is adjusted on the three common plots: semi-log superposition, log-log and complete rate history on a linear scale.

The complete well testing interpretation process is represented on the following workflow chart (Courtesy by A.Gringarten):




Courtesy of A. Gringarten Figure 7.4.1 – Well Test interpretation Process




8. WELL TEST INTERPRETATION PACKAGE

In ENI Exploration and Production Division two well test interpretation softwares are available:

Interpret/2003 by Paradigm (ex Baker Atlas);

Saphir by Kappa Engineering.

Both of them are Pressure Transient Analysis softwares.

Their methodology is based on the use of the pressure derivative. This methodology consists in matching the pressure data using simulation models which takes into account the detailed well production history.

The aim of this chapter is to briefly describe the main potentialities of these softwares and the advantages/disadvantages experienced with their use. Furthermore, indications on the best approach for software use and continuous learning is given.

This chapter is not intended as a manual for the use of the described software and can not – by no means - replace the software manuals for detailed description of features, theoretical background and user interface.

8.1 INTERPRET 2003 (PARADIGM)

The software Interpret 2003 is a commercial package by Paradigm.

Tool description

Interpret/2003 is based on the conventional Horner analysis and advanced type curves analysis techniques which use the pressure derivative curves as the main diagnostic tools.

The analysis is performed using analytical models for early, middle and late time effects.

The software is structured into 6 functional sections:

1) Data section: allows the input of basic data, fluid type and PVT parameters (including a simple window for PVT estimation via correlations), bottom hole pressure and temperature data from multiple gauges, produced fluids rates. Options such as multiphase flow at the wellbore and in the reservoir are also available. Temperatures can also be loaded. Rates can be loaded as measured rates or analysis rates, the latter being the averaged values to be used for the interpretation.




2) Validate gauges: if more than one gauge is loaded, this section allows the user to compare recorded pressures and to perform a pressure and time shift on gauges. Gauge combination is also allowed. Gauges can also be compared by displaying pressure differences and, if rates are already loaded, log-log and superposition function for different flow periods. 3) Validate rates: for a single selected gauge diagnostic plots (Log-Log and Superposition function) relative to different flow periods (draws-down and builds-up) can be compared for consistency. Automatic rate adjustment can be performed even on subset data. 4) Diagnose: this section presents on the same windows the main diagnostic plots (Log-Log and Horner) and the diagnostic tools (trend lines for pressure derivative for early, middle and late time models). Partial results are also presented.

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Log-Log Diagnostic - Flow Period 3

Figure 8.1.1 – Interpret 2003 – Diagnostic Plot

5) Matching: after setting the diagnose lines the matching option generates the corresponding analytical model. Real data and model lines are compared in Log-Log, Horner and Pressure History plots. Interpretation refinement can be done using the Model Controls window where different combinations of the interpretation models can be chosen and model parameters can be manually set. Varible storage and variable skin options are also available. Regression in the different plots and for selected parameters and data subsets can be done in order to automatically improve the match. Using the regression option care should be taken to the meaningfulness of output parameters, even if the matching is satisfactory. Results of the model can be viewed also. Different analysis can be saved, re-loaded (file menu) and compared (select display).




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Horner Match - Flow Period 3

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Figure 8.1.2 – Interpret 2003




6) Design: this section allows generation of the theoretical pressure response of a test performed in a well with certain characteristics, inputting flow rates and test sequence. Input data (see data section) must be loaded. The Model Control window allows selection of the model, input model parameters and definition of the gauge properties. The designed test is plotted in the usual Log-Log, Horner and Pressure History plots. The pressure response can be saved as a gauge (file menu) for conventional analysis.

Web site for informations and support is: www.paradigmgeo.com/products/interpret.php

Learning: the main reference for software self-learning is the online help and the tutorials.

8.2 SAPHIR (KAPPA ENGINEERING)

The software Saphir v3.20 is a commercial package by Kappa Engineering.

Tool description:

A well test analysis performed by Saphir software may enhanced its reliability by using the following features:

• a wide QA/QC section with, in particular, the tidal effect correction tool;

• development of a numerical linear model based on understructured (Voronoi) automatic grids with a modelling flexibility far beyond that of an analytical model;

• visualization options of numerical analysis on animated 2D map (pressure/saturation fields);

• development of a numerical non-linear model with advanced features near to reservoir simulation.

A more detailed description of the features of analytical analysis and numerical analysis (linear and non-linear) is provided in the following chapters.

Web site for informations and support is: http://www.kappaeng.com/Saphir/index.asp

http://www.paradigmgeo.com/products/interpret.php

http://www.kappaeng.com/Saphir/index.asp




Learning: the main reference of the software self-learning is the online help, the manuals and the tutorials. The download area of Saphir web site provides the manuals with guided interpretation and exploration of software capabilities, basic theoretical background and software user guide.

8.2.1 ANALYTICAL ANALYSIS

The analytical method of Saphir software is based on the same approach as in Interpret/2003 (Figure 8.2.1).

Nevertheless it presents some additional features as:

• Multilayer analysis: allows the simulation of individual layer rates and the regression on zone contributions;

• Multiple flow period analysis: allows to analyze multiple flow periods considering superposition effect.

• Flexible plot analysis: besides standard Log-Log- and superposition function, Saphir offers the possibility to plot Horner, MDH, user defined graphs. Analysis can also be performed on selected plots.

• Changing well model: this options allows the simulation of the production history of a well whose behavior has changed at a certain time (due to acidizing, fracturing, …) in a single analysis.

• Linear composite model: allows the simulation of changes in the

petrophysical or fluid properties in a linear direction.




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History plot (Pressure [bara], Liquid Rate [STB/D] vs Time [hr]) Figure 8.2.1 Saphir: Analytical model




8.2.2 NUMERICAL ANALYSIS (LINEAR)

The 2-D numerical module can extend the modelling capabilities to simulations which takes into account a number of factors that cannot be considered in analytical analysis.

The model is set up defining a understructured (Voronoi) grid scaled on the reservoir map.

The numerical model allows to consider the following items:

• Irregular outer boundary shape;

• Fault trayectories and leakage factor of each fault;

• Irregular composite zones;

• Reservoir thickness and porosity variation by a discrete set of values using grids and other interpolations;

• Evaluation of the pressure response of a well when other production/injection wells are active in the same reservoir at the same time;

• 2-D and 3-D display and animations of pressure and/or saturation fields (Figures 8.2.2 and 8.2.3).

8.2.3 NUMERICAL ANALYSIS (NON-LINEAR)

Saphir Numerical v3.20 covers the same 2-D geometries as the numerical module of Saphir; however, the assumption of slightly compressible fluids and the pseudo-pressure funcion are replaced by the exact solution of the diffusion equation.

Saphir Numerical takes into account non-linearities such as:

• real gas diffusion;

• non-Darcy flow into gas reservoir;

• real dead oil diffusion;

• multiphase flow (water + oil or water + gas) in reservoir using relative permeabilities curves;

• water injection in oil reservoir.




Figure 8.2.2 – Saphir: Numerical model

Figure 8.2.3 – Saphir: Numerical model

Well A

Well B




9. REPORT

The interpretation of a production test will result in a final report which will include all the information necessary to obtain a complete and reliable vision of the parameters used and the results obtained.

Here below is a proposal of a final report structure to be followed.

9.1 MEASUREMENT SYSTEM

The final report will make reference to a precise system of measurement units which will have to be selected between the following:

• Oil Fields Units;

• Practical Metric System;

• International System (S.I.).

After selecting the measurement system, the physical parameters must be consistent with the choice adopted.

The following table shows the most widespread parameters as concerns Well Testing and their units of measurement in the different systems.




Table 9.1.1 – System of Units

Parameter Symbol Oil Fields Metric Practical International (S.I.)

Oil rate Qo STb/day STm3/day STm3/sec

Gas Rate Qg MScf/day Sm3/day Sm3/sec

Water Rate Qw STb/day STm3/day STm3/sec

Gas/Oil Ratio GOR Scf/STb Sm3/STm3 Sm3/STm3

Pressure P psia kg/cm2 Pa

Temparature T Rankine degrees, R Kelvin degrees, K Kelvin degrees, K

Time t hours minutes seconds

Lenghts rw, re h, L ft m m

Viscosity µo, µg, µw cp cp Pa·sec

Compressibility Cc, Cg, Cw, Ct

1/psia 1/kg/cm2 1/Pa

Permeability k md md m2(*)

Oil Volume Factor Bo Rb/STb Rm3/STm3 Rm3/STm3

Gas Volume Factor Bg RScf/STcf Rm3/Sm3 Rm3/Sm3

Water Volume Factor Bw Rb/STb Rm3/Sm3 Rm3/Sm3

Z Factor Z adimensional adimensional adimensional

Skin Factor S adimensional adimensional adimensional

In the Oil Fields System: M = 103 MM = 106 B = 109

In the Metric System / SI: K = 103 M = 106 G = 109

(*) For practical resaons, permeability will be expressed in md (1 md = 9.86923·10-16 m2). See the convertion table: pag. 10 – Vol. 1 – “Principi di ingegneria dei Giacimenti Petroliferi” – G.L. Chierici.




9.2 STRUCTURE OF THE REPORT

The report should be completed with the following main items:

List of Contents

Introduction

Conclusions

Discussion of the test

Well flow deliverability

Figures

Annexes

a) List of Contents

It defines the list of the different paragraphs and sub-paragraphs composing the report.

b) Introduction

It must contain the following general information for the well characterisation:

• Location and Concession;

• Possible Joint - Venture with shares;

• Type of well (exploration/development; production/injection);

• Type of mineralization (gas/oil);

• Test completion (test or definitive string);




• Intervals tested and testing periods;

• Objective of the test/s.

c) Conclusions

The reservoir physical model used in the test interpretation (Interpret/2003 - Saphir) and all the main results of the model adopted will be presented. All the main conclusions will be discussed with respect to the original well testing objectives to be achieved.

The chosen reservoir model must be consistent with the other information available such as seismic sections, geological maps, electric or production logs and tests previously carried out on the same well or made on the near wells etc.

All the operations which can be carried out during the test such as acidifications, gravel-packs, partialisations, PLT, static and dynamic pressure and temperature profiles must also be cited. They will be discussed and analysed in function of their impact on the results.

The presence of sand and/or fine sediments (typical of gas wells) and the possible contamination of the gas phase for H2S, CO2, N2 must also be mentioned in this paragraph.

At Iast, an evaluation of the well deliverability must be evaluated. This program will estimate the bottomhole and/or wellhead flow equation (gas wells) or the productivity-index (oil wells). The calculation can be carried out either at “Transient” conditions for a predefined observation time or at "Pseudo Steady-State” conditions if the pressure perturbance reaches the drainage radius re of the well being tested.

d) Discussion

This paragraph will be subdivided into the following parts:

• Chronology of test operations;

• Summary of the data recorded during the test;

• Input data used;

• Test analysis.

d.1) Chronology of test operations

The series of events, as well as the different operations composing the test, must be presented. For this reason, only the most significant phases, disregarding secondary events, will be discussed.




d.2) Summary of the data recorded during the test

The main static and dynamic parameters recorded during the test at surface and bottomhole conditions will be summarised in a general table (for example in the Practical Metric System):

Table 9.2.1 – Static and dynamic parameters

Period Time Choke Qo Qg GOR BSW BHP BHT THP ∆pbottom ∆pwellhead

type minutes 1/64” STm3/d Sm3/d Sm3/STm3 % kg/cm2 Kelvin kg/cm2 % %

Clean-up

Build-up

Drawdown

Build-up

For gas tests the pressure values will always be expressed in absolute measurement units.

The reference parameters for each flow-period are referred to the end of the period considered.

The other information to be specified are as follows:

• Rotary table (ssl);

• Measurement gauge depth (RT and ssl);

• In the case of several gauges, mention the one used for the interpretation;

• Oil total volume produced in the test and relevant properties (Np, density, API Degrees);

• Gas total volume produced during the test and relevant properties (Gp, SG, H2S, CO2, N2 content);

• Volume of the produced fluids and their properties (Wp, PH, NaCl, density);

• Remark the possible presence of sands and/or fine sediments.

The injection rates in each period, the total volume injected in the formation and its petrophysical properties must be indicated in the case of water injection.




d.3) Input data used

In the most general case, the data used in the analysis of the production test can be subdivided as follows:

• Geometrical data:

1) Well Radius, rw; 2) Flowing interval, hp (Partial Penetration/Partial Completion: spherical flow); 3) Horizontal length, L (horizontal wells); 4) Distance between the wells, d (Interference test).

• Petrophysical data:

1) Total net thickness of the formation, hnet; 2) Total porosity of the formation, Ø; 3) Oil saturation, So; 4) Gas saturation, Sg; 5) Water saturation, Sw.

Interference Test: in the case of interference tests, it is necessary to introduce the petrophysical parameters and the fluid saturations. These parameters are estimated as arithmetical average between the values evaluated at the observation well and the values evaluated at the nearby active wells.

• PVT parameters

• For test in oil/gas/water injection wells PVT parameters will be presented in the following table:




Table 9.2.2 – PVT parameters

PVT Parameters Oil wells Gas wells Water Injection

Bubble Pressure Pb - -

Volume Factor Bo Bg Bw

Viscosity µo µg µw

Adimensional Factor - Z -

Fluid Compressibility Co Cg Cw

Rock Compressibility Cr Cr Cr

Total Compressibility Ct Ct Ct

Interference Test: in the case of interference tests between one or several wells, the PVT parameters of the observation well must be introduced during the interpretation phase.

The source (PVT studies/Literature correlations) must be defined for each of the parameters presented. The definition of the petrophysical parameters is exhaustively illustrated in the present report.

• Production history

The production history is used to simulate the test with interpretative softwares. It is the chronologic sequence of the different phases or flow periods in which the test is subdivided. Each flow period is characterised by its length and an average rate value assumed as constant during the phase considered ( See Chapter 8.2).

Interference Test: the production history to be used in the interpretation will be the one of the active wells.

d.4) Test analysis

This paragraph shows the main results of the final simulation. Particularly, it should be defined the flow period on which the analysis was built (generally the final build up), the reservoir model used and its consistency with the previous flow periods.

The main parts of the model used, i.e. early middle and late times is briefly discussed. The known flow regimes (radial, linear, spherical etc.), possible boundaries and/or closures and the relevant results is presented for each of them.

If present, all the information (geological, geophysical, previous tests) supporting the choice adopted must be cited.




Particular operations carried out before or during the test as acid-job, gravel pack, production log such as PLT, temperature measurements, static and/or dynamic profiles are analysed taking into account the general results obtained.

e) Well flow deliverability

The test report must include the evaluation of the well production potential.

For gas wells we must define:

• the bottomhole flow equation :

(∆p2)bottom = A x Q + B x Q2 (1)

where the A and B coefficients must always be positive;

• the wellhead flow equation (empirical):

Q = C x [(∆p2)wellhead]n (2)

where: 0.5 < n < 1.0 ;

n = 0.5: turbulent flow

n = 1.0: laminar flow

The evaluation of the well deliverability is characterised also by the value of the Absolute Open Flow (A.O.F.), which represents the maximum theoretical gas rate if the maximum bottom ∆p is imposed (Pwf = 0.1013 MPa).

The previous relationships can be considered as "Transient" conditions at a defined time t.

Assuming a certain drainage radius re, it is possible to estimate the bottomhole flow equation (1) at "Pseudo Steady-State" conditions.

For oil wells: the well production capacity is more simply defined through its Productivity - Index (P.I.) considered as:

P.I. = Q / (∆p)bottom




The P.I. calculated from a conventional well test is a function of time and as such, is referred to “Transient” conditions. Assuming a drainage radius re, it will be possible to estimate also productivity at "Pseudo Steady-State" conditions.

f ) Figures

The list of the figures to be included in the report is as follows:

• Index map - Concession;

• Isobath map - Top of the formation;

• Completion scheme of the well at the test time (provisional or definitive);

• Formation logs (CPI);

• Test history linear plot P & Q vs. time;

• Diagnostic plot: Log-log/Horner;

• Reference Flow Period: Log - log match;

• Reference Flow Period: Horner match;

• General simulation of the whole test,

• Flow/P.I. equation and flow capacity of the formation (gas/oil).

If any, it must also be introduced:

• Formation production profiles: Production Logging Tool (PLT);

• Static and/or dynamic profiles carried out during the test.




g) Annexes

The annexes must include:

• Reference to tests already interpreted on the same well;

• PVT laboratory study.

eni well testing manual

Documents

back pressure

maximum fluid

theoretical

wireline formation

oil bearing

gas bearing

drill stem

initial static