document4

Integration of Wireline Formation Testingand Well Testing Evaluation—An Example

From the CaspianS. Ramaswami and H. Elshahawi, Shell International E&P, and A. El Battawy, Schlumberger

Summary

Well testing has long been a valuable tool for the petroleumindustry. The practice continues to be widely used today, butincreasingly more situations arise in which conventional well testscan be impractical because of cost, logistical, or environmentalconstraints. For instance, weather conditions may dictate a timewindow beyond which operations have to cease, as in Arctic con-ditions. In such cases, a wirelineformation testing (WFT) maypresent a viable alternative to acquire formation-fluid samples andpressure-transient data [WFT-PTA, commonly known as a mini-drillstem test (mini-DST)].

WFT a or mini-DST uses a probe or a straddle packer to test aselected reservoir interval. Downhole pumps are used to cleanupmud filtrate invasion and flow formation fluids at a stable rate.Downhole fluid analysis (DFA) is used simultaneously to monitorclean up and measure fluid properties such as fluid color, density,and gas—oil ratio (GOR) in real time. As part of the sequence,one or more pressure-buildup periods may be performed on eachmini-DST station. Similar to classic well-test analysis, transient-pressure interpretation of the drawdown and buildup responses isused to derive the mobility thickness product and skin relevant tothe rock volume investigated by the test. The permeability of thatflow unit can be then calculated using the thickness of the flowunit and viscosity of the formation fluid as inputs.

In this paper, we present field data from the Caspian region inwhich WFT—mini-DST results are compared with conventionalwell testing using DST results. We show that, as long as the scaleof measurement is taken into account, reservoir parametersobtained are in close agreement over the same interval. In addi-tion, the mini-DST reveals differences in permeability betweenindividual flow units.

Two case studies are presented to compare independentlyderived productivity parameters of the reservoirs. Permeabilityand thickness from mini-DST results are used to construct reser-voir models to represent individual zones.

In the first field case, we have shown where mini-DSTs areable to provide detail that a DST cannot, and we show an exampleof how nuclear-magnetic resonance permeability can be used toupscale mini-DST results to estimate the total permeability-thick-ness of a reservoir.

In the second field case, we have shown that with adequatesampling using mini-DSTs, it is possible to estimate the total per-meability-thickness across several reservoir sands. Additionally,nodal analysis is used to predict downhole flow rates. Individual-zone parameters are used to predict zonal contributions and henceconstruct a composite inflow profile response for comminglingselective zones. These have then been compared with actualresults from production logs performed during the well test.

This integrated approach can be used to complement and cali-brate well testing (DST) results or to acquire sufficient reservoirinformation when a full well test is not feasible and/or notrequired. The advantages and limitations of this approach are dis-

cussed to assist the proper selection of test types depending ondesired objectives.

Introduction

Tests on oil and gas wells can be categorized as either productiv-ity or descriptive tests. Productivity well tests aim to identify/sample produced fluids and determine well/reservoir deliverability.They usually involve flowing the well at several flow rates usingdifferent choke sizes while measuring the stabilized bottomholepressure and temperature at each corresponding production rate.

Descriptive well tests on the other hand, induce pressure dis-turbances in the wellbore and surrounding rock but focus on ana-lyzing the associated transient changes in sandface pressure toevaluate reservoir parameters such as permeability and skin andto characterize reservoir heterogeneities. Extended well tests areused to assess reservoir continuity and architecture. Whateverthe objectives, well-test data are essential for the analysis, predic-tion and improvement of reservoir performance (Schlumberger2003).

Because of a combination of financial, logistical, environmen-tal, and safety constraints, well testing has become less common-place in exploration and appraisal settings in recent years (Whittleet al. 2003). Fortunately, several alternative testing methods havebecome available to bridge that gap. Elshahawi et al. (2008) pro-vide a general overview of the “optimal value testing” concept,which describes three main alternative methods to conventionalwell tests. These are WFT-PTA, closed chamber testing, andInjection Testing. Depending on the objectives and cost or opera-tional limitations of the test, one or more methods can be used toachieve those objectives. By inspecting the results of past welltests, Elshahawi et al. (2008) conclude that with the exception oftesting reservoir boundaries, the collection of large volumes (bar-rels) of fluid samples, or investigating completion efficiency,WFT is able to meet or exceed most well-testing objectives insome play types.

In this paper, we focus on WFT methods to extract productiv-ity parameters of formations through the use of pressure-transient-analysis. Also known as mini-DSTs, the pressure buildup infor-mation obtained from WFT stations are presented in the classicalPressure Transient Analysis log-log plot (Bourdet et al. 1983),where the pressure rise during the buildup and its derivative areplotted against superposition time.

The model generally used for performing pressure-transientanalysis on WFT tests is a limited entry model. There can be upto four flow regimes observed with a limited entry test—wellborestorage, an early radial flow, a spherical-flow regime, and a finalradial-flow regime. The early-radial-flow regime is generally notobserved. While conventional pressure-transient-analysis startswith three matching parameters—a wellbore storage coefficient,skin, and horizontal permeability—the limited-entry model hasthree additional parameters—thickness of the open inflow inter-val, the location of the interval within the flow unit, and thepermeability anisotropy ratio, Kv/Kh. The first two additional pa-rameters are usually known and not part of the matching process.With the inclusion of this additional matching parameter, a uniquesolution can also be obtained when infinite-acting radial flow(IARF) is not observed, but spherical flow is, through the use ofan observation probe to match Kv/Kh.

Copyright VC 2012 Society of Petroleum Engineers

This paper (SPE 139837) was accepted for presentation at the SPE Caspian CarbonatesTechnology Conference, Atyrau, Kazakhstan, 8–10 November 2010, and revised forpublication. Original manuscript received for review 9 December 2010. Revised manuscriptreceived for review 1 November 2011. Paper peer approved 16 January 2012.

300 June 2012 SPE Reservoir Evaluation & Engineering

A mini-DST typically starts by stationing the tool at somedepth and then either setting a probe against the sandface or inflat-ing the straddle-packer elements using mud from the wellbore.Packers are inflated to a few hundred psi above hydrostatic pres-sure to maintain a seal against the mud cake. A pretest is then per-formed with either device to measure formation pressure, and toconfirm the integrity of the seal that the device has obtained, pre-venting pressure communication with the wellbore. In the case ofstraddle packers, the downhole pump is then used to clean up theinterval between the packers, initially filled with mud, followedby mud filtrate and formation fluid. With the probe, there is nointerval to evacuate, and so mud filtrate is flowed immediately,gradually followed by formation fluid. Throughout, pressure andflow rate are recorded, and the effluent is monitored using down-hole fluid analyzers. Once formation fluid has been flowed at astable rate for a sufficient time, the pump is stopped, and a pres-sure buildup is recorded. One or more intermediate buildups aretypically performed while cleaning up, with a final buildup per-formed at the end of the station, usually after samples are cap-tured, if any are taken on that station. Then, a final pretest isperformed, and the straddle packer is deflated and/or the probesare retracted. Now the tool string can be moved to the next stationdepth.

Well A Case Study

Mini-DST on Well A. Well A is a vertical exploration welldrilled in a clastic reservoir in the Caspian with water-based mud(WBM). Conventional wireline openhole logs were run, and anextensive pressure-profiling program was carried out using themodular formation-dynamics tester (MDT). More than 110 pre-tests were recorded in order to identify the different reservoirzones and the fluid content therein.

This was followed by wireline sampling and downhole fluidanalysis, with 16 pressure/volume/temperature (PVT) qualitysamples collected from 5 different zones. The sampling stringused a probe module equipped with a large- diameter probe(LDP) as the sampling source. Filtrate cleanup was monitored bya combination of the live-fluid analyzer and the compositionalfluid analyzer, giving real time measurements of the in-situ GORand hydrocarbon composition.

Fig. 1 shows the petrophysical interpretation of the zone of in-terest using conventional open hole wireline logs. The nuclear-magnetic resonance (NMR) permeability curve and the separationof the resistivity curves indicate flow units with higher permeabil-ity on top and bottom and lower permeability in the middle.

Two flow units were tested in conjunction with sampling sta-tions using the LDP. Intermediate buildups while cleaning up anda final buildup after capturing samples were acquired in each ofthe sampling stations.

Three further flow units were tested with the straddle packerduring dedicated mini-DST stations using the tool string presentedin Fig. 2. The lower pump was used to inflate the packer elementsand evacuate the interval between the packer elements. The upperpump was then used to clean up and obtain stable flowing periods.

Mini-DSTs 1 and 4 were acquired with the LDP, and mini-DSTs 2, 3, and 5 were acquired with the straddle packer.

Mini-DST1 tested the interval 74.5–75.3 m. Several shortbuildups were performed while cleaning up and capturing sam-ples, and a long buildup was performed at the end of the station.Fig. 3 shows the pressure plot and the model history match formini-DST1. The intermediate buildups and final buildup alongwith the model match on a log-log plot are shown in Fig. 4. Theestimated horizontal permeability from this test was 583 md.

A similar procedure while sampling was followed for mini-DST4, which tested the interval 85.45– 7.6 m.

Mini-DST2 tested the interval 77.0–79.4 m. The pressure-his-tory plot, Fig. 5, shows that three buildup periods were carried outto confirm the repeatability of results.

The pressure change and derivative of the three buildup peri-ods are presented in Fig. 6. The estimated reservoir properties forthis sand unit from the three buildup periods are in close agree-ment with a horizontal permeability of 608 md.

A similar procedure was followed for the other two flowunits tested with the straddle packer where mini-DST3 and mini-DST5 tested the intervals 82.5–84.25 m and 88.8–91.4 m,respectively.

Table 1 lists the results from the mini-DSTs. The sum of thepermeability-thicknesses of the five mini-DST stations acquired is5268 md.m, and the averaged permeability-thickness product forthe three zones yields an average permeability of 570 md. For allmini-DST interpretations, the cleanest buildup was taken as thereference for the model match. It should be noted that for some ofthe mini-DSTs in Well A, there was distortion in the derivative,particularly during the transition from spherical to radial flow. Inall cases, radial flow was present, hence the IARF match of thedominant radial flow remains unchanged.

Production Test on Well A. Following the completion of WellA with a 7-in liner, the interval 75–92 m was perforated, and aproduction well test (DST) was performed with a full surface

GR, CAL RES DEN-NEU PORO SW PERMGR, CAL RES DEN-NEU PORO SW PERM

Fig. 1—Conventional openhole logs over the zone of interest in Well A.

June 2012 SPE Reservoir Evaluation & Engineering 301

testing setup across the same formations as tested earlier with themini-DSTs.

During the well test, a multiphase meter was used to providesurface oil-, gas-, and water-flow-rate measurements. Conven-

tional well-test separation units with associated metering werealso used to estimate rates of oil, gas and water.

The pressure-rate history match for the well test is shown inFig. 11, while the pressure buildups and derivative on a log-log plotfor the four main buildups are shown in Fig. 12. The model matchused for the interpretation of the final build up is shown in Fig. 13.

Unlike a mini-DST test, which is capable of evaluating eachflow unit separately, the DST averages the properties of all zones.Interpretation of the DST yields a permeability-thickness of 6948md.m, resulting in an average horizontal permeability of 421 mdand a skin factor of 0.8, using an effective flow thickness of 16.5 m.

Comparison Between Mini-DSTs and DST in Well A. Fig. 14shows the intervals that were tested by the mini-DST (green) andDST (red) plotted over the NMR permeability curve (blue). It canbe clearly seen that while the DST averages the permeability acrossthe tested interval, mini-DSTs are able to evaluate each zone sepa-rately and identify variations in permeability across differentzones. The figure also shows the photographs of the core across theintervals tested by mini-DSTs 3 and 5. The interval tested by mini-DST 3 is highly laminated with a very low Kv/Kh, and hence thethickness of the reservoir that is sensed is almost the same as theinflow thickness, which is the interval between the straddle-packerelements, 1 m. This is likely true for the interval 79.4–85.5 m inFig. 14, and apart from the 1m tested in mini-DST 3, contributionfrom the rest of this laminated section is not reflected in the sum ofpermeability-thicknesses from the mini-DSTs. In order to make asensible comparison between the mini-DST permeability-thick-nesses and that of the DST, the NMR curve can be used to estimatethe permeability-thickness of the intervals within the laminatedsection that were not tested, calibrated to mini-DST results, henceeffectively upscaling the mini-DST results to a larger interval, asdepicted by the orange lines in the permeability track of Fig. 14.The intervals that were added are tabulated in Table 2.

The addition of these intervals yields a total permeability-thickness estimate of 6149 md.m. The effective flowing thickness,permeability-thickness, and average permeability obtained fromthe upscaled mini-DST results and from the DST are tabulated inTable 3.

Taking into account small variations in flow thicknesses con-tributing to flow, the agreement between mini-DST and DSTresults is remarkable for permeability.

Well B Case Study

Mini-DST on Well B. Well B was drilled to appraise a discoverywell in the same general prospect as Well A using WBM. Geolog-ical sampling and petrophysical logs indicate that twelve sandswere penetrated and identified in Well B, seven of which were oilbearing. A comprehensive WFT program was carried out usingthe WFT tool.

An extensive pressure-acquisition program resulted in 108pressures, measured using an LDP. The pressures were used toidentify the different reservoir zones and fluid content. Fig. 15

Fig. 2—mini-DST/VIT tool string used on Well A.

2500

3500

0 2000 4000 6000 8000 10000 12000 140000

5E-6

1E-5

History plot (Pressure [psia], Liquid Rate [m3/sec] vs Time [sec])

Fig. 3—History match for mini-DST1 performed on top sand of Well A.


shows the pressure profile, including gradients and contacts inWell B, plotted against petrophysical logs.

MDT sampling and fluid-identification stations were thenacquired using the tool string in Fig. 16. Finally, the remaining sam-ples and dedicated mini-DST stations were acquired using the toolstring shown in Fig. 17. In total, 29 sample bottles were filled in ninestations, eight of them oil and one water. Two fluid-identificationstations and six dedicated mini-DST stations were also performed.Pressure-transient-analysis data were acquired at 17 stations in total.

This paper will discuss the results of the pressure-transient-analysis data acquired in the zones corresponding to the DSTintervals in Fig. 15 and comparison of those results with results ofthe DST production tests.

Four separate flow units were tested using WFT. These alsooverlapped with the DST production test interval.

Mini-DST1 tested the interval 01.8–04.8 m using the straddle-packer. The pressure-history plot, Fig. 18 shows that two buildupperiods were carried out. An industry standard program for

0.01 0.1 1 10 100 1000 100000.1

1

10

100

1000

build-up #4build-up #5build-up #7build-up #9 (ref)

Log-Log Plot: dp and dp' Normalized [psi] vs dt

Fig. 4—Model match on log-log plot and derivatives of buildupsof Well A mini-DST1.

2930

2970

3010

0 1000 2000 3000 4000 5000 6000 7000 8000 9000 100000

5E-6

1E-5

1.5E-5

History Plot (Pressure [psia], Liquid Rate [m3/sec] vs Time [sec])

Fig. 5—History match for mini-DST 2 performed on top sand of Well A.

0.010.1

1

10

dp a

nd d

p’ N

orm

aliz

ed [p

si]

100

0.1 1 10

build-up #2 (ref)build-up #5build-up #10

dt100 1000 10000

Fig. 6—Model match on log-log plot and derivatives of buildups of Well A mini-DST 2.

TABLE 1—RESULTS OF MINI-DST IN WELL A

Mini-DST

Top of

Interval (m)

Bottom of

Interval (m)

Position of

Probe/Packer (m)

Permeability

Thickness (md.m)

Thickness

(m)

Permeability

(md)

1 XX74.5 XX75.3 XX74.8 467 0.8 583

2 XX77.0 XX79.4 XX78.5 1460 2.4 608

3 XX82.5 XX83.5 XX83.2 91 1.0 91

4 XX85.45 XX87.6 XX87.0 1354 2.1 630

5 XX88.5 XX91.4 XX90.5 1895 2.9 654


pressure-transient analysis was used to interpret the derivativeresponse, and Fig. 19 shows the two buildups and derivatives on alog-log plot and the match obtained for the interpretation. Thepermeability-thickness obtained from this interpretation was 1224md.m. Petrophysical logs and cores were used to determine thethickness of the flow unit as 3 m, resulting in an average perme-ability of 408 md. The average permeability obtained from an

early buildup of the DST production test, assuming that onlyZone 1 contributed during the test resulted in, an average perme-ability-thickness of 1265 md.m. The agreement is remarkable.

Mini-DST2 tested the interval 18.3–20.4 m using the single-probe module in conjunction with a sampling station. Mini-DST3tested the interval 32.3–33.2 m using the straddle- packer module,and mini-DST4 tested the interval 41.8–43.2 m using the single-

2900

3000

0 2000 4000 6000 8000 10000 12000 14000 16000 18000

0

1E-5

2E-5


Fig. 7—Pressure-history plot and model match for mini-DST3 performed on middle sand of Well A.

0.1 1 10 100 10001

10

100

build-up #1build-up #2build-up #3 (ref)


Fig. 8—Model match on log-log plot for mini-DST3.

2970

2980

2990

0 2000 4000 6000 8000 10000 12000 14000

0

1E-5

2E-5


Fig. 9—History match of Mini-DST5 performed on bottom sand of Well A.


probe module in conjunction with a sampling station. Figs. 20through 25 show the flow history match as well as pressurebuildup and derivatives for mini-DSTs 2, 3 and 4.

Table 4 lists the results from mini-DSTs 1, 2, 3, and 4. Thetotal permeability-thickness from the four zones tested with WFTis 2566 md.m. The interpretation of the corresponding DST pro-duction test yielded a permeability-thickness of 3163 md.m.

Well B Production Test. Following the completion of Well Bwith a 7-in liner, a production well test was performed over theDST interval in Fig. 15. Tubing Conveyed Perforating (TCP)guns were used to perforate interval 01–06 m (Fig. 26). This isthe same interval as mini-DST zone-1 (Table 4).

Two buildups were performed while only flowing from thisZone. Fig. 26 shows the flow history and two buildups performed.Fig. 27 shows the pressure buildup and pressure derivative in alog-log plot. The pressure-transient-analysis interpretation yieldeda permeability-thickness of 1265 md.m for Zone 1, in excellentagreement with the mini-DST result.

The well was then killed to add perforations to test the inter-vals tested during mini-DSTs 2, 3, and 4. Before perforating, thewell was flowed to determine the effect that killing the well hadon the productivity index (PI) of Zone 1. The PI changed from2 STB/D/psi to 1.35 STB/D/psi.

Intervals 16–21 (B), 31.5–36.5 (C), and 40–45 m (D) were thenadditionally perforated through tubing on wireline, and the wellwas flowed. A PLT run was performed at 3 different flow rates,corresponding to 20/64, 28/64, and 36/64 choke sizes at the chokemanifold. From the PLT, it appeared that the perforation from 31.5to 36.5 was not contributing. This corresponded to the zone testedin mini-DST 3, which appeared potentially productive. The zonewas therefore reperforated, and the well was flowed again and aPLT was rerun while flowing the well at 36/64 choke.

Fig. 28 shows the flow history throughout the DST. Fig. 29shows the pressure buildup and pressure derivative of the lastbuildup on a log-log plot, which corresponds to all four zones

0.1 1 10 100 10000.01

0.1

1

build-up #2build-up #3build-up #4 (ref)


Fig. 10—Log-log-type curve match for mini-DST5.

History Plot (Pressure [kPa, Liquid Rate [m3/D] vs Time [hr])

Fig. 11—History match for the Well A well test.

Clean up and Main Buildup

BHSPLT

Clean up and Main Buildup

Log-Log Plot: dp and dp' Normalized [kPa] vs dt

1E-310

100

1000

0.01 0.1 1 10

BHSPLT

Fig. 12—Log-log analysis and model match for the first buildupof Well A well test.

Log-Log Plot: p-p@dt=0 and Derivative [kPa] vs dt [hr]

Fig. 13—Log-log analysis and model match for the mainbuildup of Well A well test.


flowing. The interpretation of this buildup yielded a permeability-thickness of 3163 md.m.

Nodal Analysis of Mini-DST Results for Well B. A nodal-anal-ysis model was created to simulate the production of the intervaltested by the four mini-DST zones. The nodal-analysis point wasplaced just above Zone 1. The purpose of this model was to pre-dict downhole oil rates in res bbl/D, independent of DST results,by describing each of the mini-DST intervals as a pseudosteady-state model reservoir using the outputs from the mini-DST inter-

pretations: permeability, thickness, and skin. Fluid properties foreach of the models were taken from PVT analysis of samplesobtained during the WFT sampling run. PVT quality sampleswere available from the zones tested by mini-DSTs 1, 2, and 3,

Geological layer with inter-bedded sand & silt -low Kv

Geological layer with more massive sand unit –high Kv

XX

XX

GR Porosity Sw Core PhotoProduction LogsRXOIPermeability

Geological layer with inter-bedded sand & silt -low Kv

Geological layer with more massive sand unit –high Kv

XX

XX

GR Porosity Sw Core PhotoProduction LogsRXOI

Permeability –Blue:NMR Perm; Red:DST Perm; Green:MiniDST Perm;

Orange:Additional permeability thickness upscaled using NMR Perm

Permeability

Fig. 14—Permeability results from Well A.

TABLE 2—INTERVALS ADDED USING NMR PERMEABILITY

Interval

Top of

Interval

(m)

Bottom of

Interval

(m)

Thickness

(m)

Permeability

(md)

Permeability

Thickness

(md�m)

1 XX79.4 XX81 1.6 150 240

2 XX81 XX82.5 1.5 91 137

3 XX83.5 XX85.45 2.0 120 234

4 XX87.6 XX88.5 0.9 300 270

TABLE 3—COMPARISON OF PERMEABILITY-THICKNESS

AND PERMEABILITY BETWEEN MINI-DST AND DST

RESULTS IN WELL A

Upscaled Mini-DST DST

Thickness, m 15.2 16.5

Permeability Thickness, md.m 6149 6948

Average Permeability, mD 405 421 Fig. 15—Pressure profile, gradients, and contacts from Well B.


Fig. 16—Sampling and fluid-identification tool string featuringa single extra-large-diameter probe.

Fig. 17—Sampling and mini-DST tool string featuring straddlepacker and two probes.

0

0

1E-5

2E-5

3E-5

16200

16400

16600

2000 4000 6000

Pressure [kPa], Liquid Rate [m3/sec] vs [sec]

[m3 /

sec]

[kP

a]

8000 10000 12000 14000

Fig. 18—Well B mini-DST 1 history match at XX03.2 m.

0.1 1 10 100 1000

Time [sec]

0.1

1

10

Pre

ssur

e [p

si]

build-up #6build-up #10 (ref)


Fig. 19—Well B mini-DST 1 pressure buildup and derivativeresponse at XX03.2 m.


and exhibited similar fluid properties. The zone tested by mini-DST 4 was therefore assumed to have the same properties also.

Because of killing the well after the first flow period, whereZone 1 was tested, we needed to correct for the effect that wellkill had on productivity of the zone tested by mini-DST 1. The

observed PI during the flow period pre- and post-well kill wasused to reduce the productivity of the zone tested by mini-DST 1in the nodal-analysis model.

Nodal analysis was then run to predict the inflow profileresponse, in terms of downhole oil rates in res bbl/D for a given

0

0 2000 4000 6000 8000Pressure [kPa], Liquid Rate [m3/sec] vs Time [sec]

[m3 /

sec]

[kP

a]

10000 12000 14000 16000 18000 20000

1E-5

2E-5

10000

12000

14000

16000

18000


0

1E-5

2E-5

3E-5

16250

16450

16650

2000 4000 6000

Pressure [kPa], Liquid Rate [m3/sec] vs Time [sec]

[m3 /

sec]

[kP

a]

8000 10000 12000 14000


0.1 1 10 100 1000

Time [sec]

0.1

1

10

Pre

ssur

e [p

si]




0

0 2000 4000 6000 8000Pressure [kPa], Liquid Rate [m3/sec] vs Time [sec]

[m3 /

sec]

[kP

a]

10000 12000 14000

1E-5

2E-5

15500

16500


0.10.01

0.1

1

10

100

1000

1 10dt [sec]

p-p@

dt=

0 an

d D

eriv

ativ

e [p

s]

100 1000 10000 1E+5


0.01 0.1 1 10 100 1000Time [sec]

0.01

0.1

1

10

100

Pre

ssur

e [p

si]





flowing pressure for all four zones. The analysis was then runagain deactivating Zone 3 to simulate production from Zones 1, 2,and 4. Fig. 30 shows a schematic of the nodal-analysis modelused for both cases. Analysis results refer to the downhole oil rateat the nodal-analysis node, just above Zone 1. The observeddownhole flowing pressure and corresponding downhole oil ratefrom the PLT for different choke sizes were then plotted on the re-sultant inflow-profile response from the nodal analysis models(Figs. 31 and 32). The agreement between the predicted rates andobserved rates is very good for all the rates, except while flowingZones 1,2, and 4 at a 36/64 choke.

The inflow profile results from the nodal-analysis allow theprediction of the total downhole oil rate resulting from the cumu-lative contribution of the active zones at any given flowing pres-sure at the nodal-analysis point. The observed flowing pressurefrom the PLT for the different choke sizes was then used to pre-dict the total downhole oil rate using the inflow-profile responsesfrom the two nodal analyses.

An effective relative PI for each of the reservoirs modeled canalso be extracted from the reservoir models in the nodal analysis,and hence contribution in terms of downhole oil rate can be deter-mined. This is tabulated in Table 5.

Using the total predicted downhole oil rate and relative contri-butions of each zone, the inflow response of each zone can thenbe predicted for any given flowing pressure. Comparison of thepredicted oil rates and the oil rates observed during the PLT run istabulated in Table 6 and displayed in Fig. 33. Note that all com-parison of downhole rates are expressed in res bbl/D.

Finally, 31=2-in production tubing was used to simulate surfaceproduction rates in STB/D, imposing the wellhead pressureobserved while flowing all four zones, which was 28 bar. The re-sultant total surface flow rate predicted by the nodal-analysismodel was 2,140 STB/D, compared with the observed surface liq-uid rate of 1,859 STB/D during the DST. By imposing a downholeflowing pressure of 1905 psi, the predicted surface flow rate is1,763 STB/D.

Comparison of Various Permeability Results From Well B.

Using the permeability-thickness obtained from the pressure-tran-sient analysis of the DST while flowing from all zones and thezonal contributions measured during the PLT run, individual

TABLE 4—RESULTS OF MINI-DST 1, 2, 3, AND 4

Zone

Top of

Interval (m)

Bottom of

Interval (m)

Position of

Probe/Packer (m)

Permeability

Thickness (md.m)

Thickness

(m)

Permeability

(md)

1 XX01.8 XX04.8 XX03.2 1224 3.00 408

2 XX18.3 XX20.4 XX18.X 338 3.10 109

3 XX32.27 XX33.1 XX33.0 178 0.83 214

4 XX41.8 XX43.2 XX42.0 826 1.40 590

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

Rat

e [S

TB

/D]

Pre

ssur

e [p

sia]

-19700

1000

1800

2200

2600

-1960

FP1-clean-up

FP2-main flow period main build up

-1950 -1940 -1930Time [hr]

-1920 -1910 -1900

Fig. 26—History match of Well B production test with only Zone1 flowing.

1E-4 1E-3 0.01 0.1 1 10Time [hr]

1

10

100

Pre

ssur

e [p

si]

Kh =1265 mD·m

Fig. 27—Pressure buildup and derivative log-log analysis ofDST in Well B while flowing only Zone 1.

8/19/2009 8/20/2009 8/21/2009

Pressure [psia], Liquid Rate [STB/D] vs Time [To D]

[psi

a][S

TB

/D]

0625

1250

1000

2000

3000

8/22/2009 8/23/2009 8/24/2009 8/25/2009

Fig. 28—History match for DST in Well B while flowing all fourzones.

1E-4 1E-3 0.01 0.1 1 10

Time [hr]

1

10

100

1000

Pre

ssur

e [p

si]

Log-Log Plot: p-p@dt=0 and Derivative [psi] vs dt [hr]

Fig. 29—Pressure buildup and derivative log-log analysis ofDST in Well B while flowing all four zones.


permeability-thicknesses (kh) can be assigned for each of thezones. The permeability of each zone was then extracted byassigning an effective thickness of contributing layers using petro-physical logs and core, as was done for the mini-DSTs. The re-sultant permeability for each of the layers was then plottedalongside the estimated permeability from the mini-DSTs, NMRpermeability, and core permeability. There is a very good agree-ment between the different sources of permeability, as can beseen in Fig. 34.

Discussion

Several methods have been used in this paper to compare resultsfrom mini-DSTs and DSTs. This section discusses the differentparameters that were compared and the uncertainty associatedwith each of them.

Permeability and Permeability-Thickness. The reliability ofobtaining the permeability and permeability-thickness of reser-voirs using mini-DSTs depends on three main factors:� The quality of the data obtained during the mini-DST is very

important in order to perform sensible interpretations, and henceestimate reservoir parameters. Real-time monitoring and controlof the acquisition of data are critical to ensure that the data are ofsufficient quality to be useable and that the lengths of buildups areoptimized to obtain the required data without spending excessivetime on station. A good handle of the PVT properties of the for-mation fluid is also critical. Sufficient formation fluid should beflowed such that the buildups used for pressure-transient-analysisis sensing predominantly formation fluid, hence negating any ra-dial viscosity variation. The assumption that the viscosity of thefluid affecting the pressure-transient response is the same as vis-cosity measured in the PVT laboratory at in-situ conditions is rea-sonable if the fluid being flowed is mainly formation fluid.� Estimation of the flow thickness being sensed by the WFT

device is key to assigning permeability and permeability-thick-nesses to individual flow units. This is not trivial, and inspectionof all data available is required to be able to reduce this uncer-tainty. Some of the data that are commonly used to estimate thisinclude petrophysical logs, core photographs, and mud logs.� Adequate coverage across the reservoir is required to accu-

rately describe permeability and permeability-thicknesses of thereservoirs being investigated. In situations where Kv/Kh is verylow for example, in highly laminated sands, the straddle-packer isrequired to test several interval across the laminated sand, and thetotal permeability-thickness across the laminated sand must beupscaled with the aid of calibrated continuous permeability

Inflow Profile at Nodal Analysis Point - Production From 3 Zones

0

500

1000

1500

2000

2500

0 1000 2000 3000 4000 5000 6000 7000 8000 9000

Downhole Oil Rate (bbl/day)

Flo

win

g P

ress

ure

(p

si)

MiniDST CompositePLT 36/64 ChokePLT 28/64 ChokePLT 20/64 ChokePLT Shut In

Fig. 31—Comparison of predicted cumulative production fromnodal-analysis based on mini-DST results with observed down-hole oil rate and flowing pressures from the PLT while flowingthe well from three zones.

Nodal Analysis model for production from Zones 1,

2 and 4

Nodal Analysis model for production from all four

zones

Nodal Analysis model for production from Zones 1,

2 and 4

Nodal Analysis model for production from all four

zones

Fig. 30—Nodal-analysis models to predict production from allfour zones, and selectively from only 3 zones based on mini-DST results.

Inflow Profile at Nodal Analysis Point - Production From

all 4 Zones

0

500

1000

1500

2000

2500

0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000

Downhole Oil Rate (bbl/day)

Flo

win

g P

ress

ure

(p

si) MiniDST Composite

PLT 36/64 Choke

PLT Shut In

Fig. 32—Comparison of predicted cumulative production fromNodal analysis based on mini-DST results with observed down-hole oil rate and flowing pressures from the PLT while flowingthe well from all four zones.

TABLE 5—RELATIVE CONTRIBUTIONS OF EACH ZONE

FROM MINI-DST RESULTS

Relative PI

(bbl/D/psi)

Zones 1, 2,

and 4

All

Zones

MiniDST1 1.38 41% 38%

MiniDST2 0.62 19% 17%

MiniDST3 0.35 - 10%

MiniDST4 1.33 40% 36%


curves, such as NMR permeability. In stacked reservoirs, in orderto sensibly compare mini-DST results with DST results, sufficientcoverage of the individual packages is necessary.

Downhole and Surface Flow Rates. Assuming the permeabilityand thickness of a particular flow unit are known, the largestuncertainty associated with predicting downhole flow rates fromthat flow unit is the effective skin. Generally, the model used inpressure-transient analysis of mini-DST data is a limited-entrymodel where the actual flow thickness, h, of the flow unit beingsensed is a few times that of the thickness of the inflow interval,hw (Fig. 35). This usually results in a skin that is higher thanwould be expected in open hole. Conversely, skin effectsobserved during a DST are affected by mechanical skin intro-duced by the perforations and completion string. Correcting foreither of these would be introducing additional variables, andhence the data presented in this paper have used the skin (hw)taken from mini-DST results as a direct input to the pseudos-teady-state reservoir models used in the nodal analysis. The agree-ment between downhole flow rates predicted by the mini-DSTresults and that observed during the DST suggest that this assump-tion yields results that are within the acceptable range of error.

Generating a composite inflow-profile response for selectedzones using mini-DST results allows prediction of total downholeflow rates at any given flowing pressure at the nodal-analysispoint. Predicting surface flow rates introduce additional varia-bles—namely, the lift behavior of the fluid being produced and

effects of the completion string modeled. Because these parame-ters are highly uncertain, it is recommended that predicted sur-face-flow-rate results be treated with caution, and be used onlyindicatively. Although there are methods available in the industryto do so, accurate modeling of the lift behavior and completioneffects is not covered in this paper.

Conclusions

• The use of WFT tool to describe the fluid and pressure distribu-tion in a reservoir as well as to collect fluid samples is by nowwell established and accepted by industry.

• Although the use of wireline formation testers to describe theproductivity of wells is becoming more commonplace, compari-sons between WFT and conventional DSTs for the purpose ofproductivity assessment are relatively few and recent. In homo-geneous clastic reservoirs, such as the two examples presented inthis paper, the position of the sampling device radially (forexample a single probe) is irrelevant because the flow regimeeventually develops radially, and is bounded by the vertical bar-riers of the flow unit. It has been shown that the responses of adual packer and single probe in these environments are similar.Care should be taken, however, when attempting to interpretpressure-transient-analysis responses in heterogeneous forma-tions, such as carbonates. The position of the probe may affectthe response because of radial heterogeneity.

• Describing the permeability of individual zones can beachieved reliably using WFT.

TABLE 6—COMPARISON OF PREDICTED DOWNHOLE OIL RATES FROM THE MINI-DSTS AND

RATES OBSERVED DURING THE PLT RUN

Downhole Oil Rate Contribution (bbl/D)

36/34 Choke 3 zones 28/64 Choke 3 zones 36/64 Choke 4 zones

1,844 psi 1,986 psi 1,905 psiFlowing

Pressure at NA MiniDST DST MiniDST DST MiniDST DST

Mini-DST1 912 667 679 501 811 38% 725 36%

Mini-DST2 410 475 305 325 364 17% 380 19%

Mini-DST3 - - - - 206 10% 233 11%

Mini-DST4 879 811 654 777 782 36% 687 34%

Total 2200 1953 1637 1604 2163 - 2026 -

PIPESIM Project:

00

200

400

1,000

1,200

1,400

1,600

1,800

2,000

2,200

2,400

600

800

1,000 2,000 3,000Stock-tank Liquid at NA point (STB/d)

Pre

ssu

re a

t N

A P

oin

t (p

sia)

Pressure at NA Point :: Inflow: Inflow = : Y = 1807.091 : X = 2140.681

4,000

Inflow: Inflow= Outflow: Outflow=

5,000 6,000 7,000 8,000

Fig. 33—Predicted surface flow rates from all four zones using nodal analysis by using a standard production tubing and imposinga wellhead pressure of 28 bar.


• It is important that sufficient formation fluid is flowed during amini-DST station to negate effects of viscosity changes to thepressure buildup and derivative response.

• Upscaling of mini-DST results can be achieved using continu-ous permeability responses, such as NMR permeability.

• WFT cannot replace conventional well tests if the objective ofthe test is to examine reservoir boundaries or to take large vol-ume samples.

• WFT results can be used to construct a composite inflow profileresponse by selectively including individual zones.

• The relative production of each zone can be accurately describedand downhole flow rates can be estimated using WFT.

• Absolute downhole flow rate prediction carries a larger errorwith it owing to uncertainty of skin.

Nomenclature

h ¼ thickness of flowing unithw ¼ thickness of inflow intervalKh ¼ horizontal permeability, mdKv ¼ vertical permeability, md

Kv/Kh ¼ permeability anisotropy

References

Bourdet, D.L., Whittle, T.M., Douglas, A.A., and Pirard, Y.M. 1983. A

new set of type curves simplifies well test analysis. World Oil 196 (6):

95–106.

Elshahawi, H., Hite, R.H., and Hows, M.P. 2008. The State of Optimum

Value Testing—The Vision and the Reality. Paper IPTC 12075 pre-

sented at the International Petroleum Technology Conference, Kuala

Lumpur, 3–5 December. http://dx.doi.org/10.2523/12075-MS.

Whittle, T.M., Lee, J., and Gringarten, A.C. 2003. Will Wireline Forma-

tion Tests Replace Well Tests? Paper SPE 84086 presented at the SPE

Annual Technical Conference and Exhibition, Denver, 5–8 October.

http://dx.doi.org/10.2118/84086-MS.

Shyam Ramaswami is a Petrophysicist with the Fluid Evaluationand Sampling Technologies (FEAST) team in Shell based in theNetherlands, advising on Shell operations worldwide, particu-larly in the exploration and appraisal domain. His current rolefocuses on the integration of fluid data across disciplines,incorporating advanced mud gas, petrophysical logs, wirelineformation testing, well testing, production logging, and fluidanalysis. He also works on field-development studies and is anexperienced operations petrophysicist. Before joining Shell in2009, Shyam worked with Schlumberger Wireline for 7 years in

MiniDST 3 zones

Predicted

DST 3 zones

Measured

MiniDST 4 zones

Predicted

DST 4 zones

MeasuredPermeabilityPorosity SwGR

XX

XX

MiniDST 3 zones

Predicted

DST3 zones

Measured

MiniDST 4 zones

Predicted

DST4 zones

MeasuredPermeabilityPorosity SwGR

XX

XX

Fig. 34—Comparison of predicted inflow profile from mini-DST results compared to profile of measured downhole rates duringDST flow periods.

hwh

Zw

Fig. 35—Schematic of the limited-entry model used for pres-sure-transient analysis of mini-DST stations.


the field and in operations management. He holds an MEngdegree in aeronautical engineering from the University of Bristol.

Hani Elshahawi is currently a Deepwater Technology Advisorfor Shell. Previously, he led FEAST, responsible for the planning,execution, and analysis of formation testing and fluid-sam-pling operations. email: [email protected]. He has over 25years of oil industry experience with both service and operat-ing companies in more than 10 countries around the world. Hehas held various positions in interpretation, consulting, opera-tions, marketing, and technology development. He holdsseveral patents and has authored over 100 technical papersin various areas of petroleum engineering and the geoscien-ces. Elshahawi has been active with the SPE and the

SPWLA. He is a former Distinguished Lecturer for both SPE andSPWLA.

Ahmed El Battawy is a Principal Reservoir Engineer withSchlumberger based in Kazakhstan. He started his career inthe oil industry with Schlumberger in 1993 as a Wireline FieldEngineer, with assignments in Libya, Kazakhstan, and Equato-rial Guinea. He later continued his career with SchlumbergerData and Consulting Services. His roles included productionenhancement in Indonesia, reservoir simulation in Azerbaijanand Turkmenistan, and then, since 2004, supporting wirelineoperations as the reservoir domain champion in the Caspianregion. El Battawy holds an MSc degree in petroleum engi-neering from Heriot-Watt University.


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