SPWLA 57th Annual Logging Symposium, June 25-29, 2016

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FORMATION TESTING AND SAMPLING IN LOW-MOBILITYFORMATIONS: AN EXAMPLE OF NEW TECHNOLOGY SOLUTIONS

M. ÅSLY, VNG NORGE AS, G. SIBBALD, W. ORRELL, BAKER HUGHES

Society of Petrophysicists and Well Log Analysts

Copyright 2016, held jointly by the Society of Petrophysicists and Well LogAnalysts (SPWLA) and the submitting authors.This paper was prepared for presentation at the SPWLA 57th Annual LoggingSymposium held in Reykjavik, Iceland June 25-29, 2016.

ABSTRACT

A wireline formation pressure testing and samplingprogram was planned for a new exploration well in asandstone reservoir. Using information from six offsetwells, the reservoir was expected to exhibit reasonableporosity and permeability with either oil and/or gaspresent.

The well was drilled with oil-based mud (OBM) acrossthe reservoir section. Whilst drilling one of the uppersands, significant mud losses occurred, requiring the useof loss control material (LCM) to cure the losses. A fullevaluation suite was performed over the reservoirsection, including the zone that encountered losses. Logresults indicated the presence of formation water and oil.The wireline-formation-pressure testing and samplingprogram used a pump-through system and fluid analyserto monitor the flowing fluids over this zone of interest.The real-time analysis identified a mix of OBM filtrateand formation water. The formation testing tool wasconfigured with a standard probe and an elongatedpacker. A fluid sample was acquired, and when analysed,it contained hydrocarbons and formation water. Based onthe results from the fluid sample, the real-time fluidanalysis was re-evaluated. An emulsion likely developedacross the mud-loss zone, affecting the fluid analyserdata.

The well was side-tracked as per the original plan.Because of the low mobilities encountered in the lowersection of the main bore, changes were made to theformation testing and sampling equipment. Thesechanges incorporated a new concentric flow packer thatwas designed to evaluate the low-mobility zones withoutneeding large-flow-area inflatable packers. The extra-elongated packer was used for pressure testing instead ofthe standard packer.

Use of advanced deployment-risk-management

technologies prevented a costly fishing operation inchallenging hole conditions after completion of thepressure testing program. The pressure data set showeda very low permeable formation, where mobilities werebetween 0.3 and 3.0 mD/cP, and thus very challengingfor any fluid and pressure sampling configuration. Aftera wiper trip, the fluid sampling run was conducted usingthe new, large-flow-area concentric packer to obtain awater sample, completing the pressure and fluidsampling program. The use of the new concentric packersubstantially reduced the breakthrough time of theformation fluid compared to the conventional packersystem used on the main bore and resulted in lowcontamination samples.

Low-permeability reservoirs can be extremely difficultto acquire reliable data and evaluate it; in particularchallenging for pressure stabilisation and the quality ofthe pressure data point. However, the new technologysolutions, using the extra-elongated packer ensuredsubstantial pressure data collection and more pressurestations with higher reliability and quality. Fluid sampleswere collected using the new concentric packer, andcontained low contamination levels, enabling a fullevaluation of the reservoir, a task that would be verychallenging using conventional formation testing andsampling equipment.

INTRODUCTION

An exploration well with a main bore and a sidetrack wasplanned to test the presence of upper Jurassic sands andhydrocarbon in a prospect in the Norwegian Sea,Norwegian Continental Shelf. An extensive wirelinedata-gathering program was planned for both wellboresincluding extensive formation pressure and fluidsampling. Based on information from six offset wells,the reservoir was expected to exhibit reasonable porosityand permeability with either oil and/or gas present. Thedata gathering program was planned accordingly to theseexpectations.

The reservoir sections of both wellbores were drilledwith OBM and an 8.5-in bit. Whilst drilling the main

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bore, losses were encountered in the upper section of thewell. The losses were cured before the well was drilledto a depth of XX85 m. Because of well and operationalconditions, an intermediate wireline data-gatheringprogram was performed before further extending thewell to a total depth of XX85 m. One of the keyobjectives of the well was to identify reasonable upperJurassic sands; however, the reservoir quality was poorerthan expected in the lower section of the main bore.

CASE HISTORY

The main wellbore was drilled with 1.5 g/cc OBMinitially with an 8.5-in bit and reached a depth of X065m.The initial logging campaign comprised five loggingruns to evaluate the formation properties. Acoustic andresistivity imaging and petrophysical and acoustic logswere logged prior to the formation testing and samplingrun. Those were followed by nuclear magnetic resonanceand elemental spectroscopy logs, and rotary side wallcoring. The logs were run down to XX60m andformation pressure and sampling points were pickedfrom them. The formation testing and sampling runcomprised of two conventional probes equipped with astandard packer and the elongated packer (Fig. 4), whichhas a flow area three times larger than the standardpacker. The fluid analysis was conducted by the fluidsanalyser, which measures optical density, fluorescence,refractive index, density, viscosity, sound speed andcalculates GOR and compressibility of the flowing fluidthrough the tool. The tool was equipped with three tankcarriers enabling eighteen fluid capturing chambers to berun. Forty two stations were planned for pressure testingwith twenty seven good tests and repeats, twelvetight/supercharged, three no seals and four post-sampletests.

Whilst drilling through the upper part of the upperJurassic sands, losses occurred. Large amounts of LCMwere required to cure the losses and the mud weight wasreduced to 1.4 g/cc before drilling further. The pressuretesting through the zone resulted in difficulty validatinga useable gradient because of the losses unseating the“initial” fluid conditions and association saturationlevels. The mobilities observed were reasonable;

however, the dominating fluid density was questionableand the losses meant the potential to get a representablesample became even more difficult in this affected zone.One sample station was collected in the zone.

In the lower section of the well, three sample stationswere collected. Because of very poor mobilities, thesampling times were long, up to 9 hrs. One particular

problem was the length of time it took to observe the firstwater slugs, This problem occurred because the pumpspeed was very slow because of the low mobility anddepth of invasion (DOI), and it took more than 130minutes before a full water slug appeared through theFluid Analyser (Fig. 1).

Fig.1 Oil (green)/water (blue) optical density vs timeplot – slug flow

The loss zone sampling from the upper section of themain bore resulted in an extremely interesting andcomplex fluid analysis. The initial pumpout showed anincreasing water cut after approximately 2,000 seconds;however, the typical oil/water slug effect that occurs inthis type of environment, which was seen on the previouspoints didn’t occur (Fig 1.). The oil fraction decreased(Fig. 2) and the density measurement increased steadilyto approximately 0.95g/cc (Fig. 3). The densitymeasurement became fairly flat and three consecutivesample bottles were filled. Upon opening the tanks,formation oil was seen along with the other fluids andsolids. The real – time data was reevaluated and foundthat an emulsion of formation oil, water, OBM filtrateand LCM was flowing at the time of sampling.

Fig.2. Oil (green)/water (blue) optical density vs timeplot.

Fig.3. Tuning fork density vs time plot, highlightingstabilisation at the time of filling the tanks.

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The well was extended deeper after the intermediatelogging program, and further evaluation was conductedin the deeper section. The mobility of the lower sectionwas very low; therefore, the formation testing andsampling string was subsequently revised and configuredwith two conventional probes, one with an elongatedpacker and the other with an extra-elongated packer (Fig.4 and 5). Eighteen depth stations were conducted,resulting in eight good tests (including five repeats), fivetight/supercharged tests, four still building up pressureand one test with no seal. The sampling was conductedin a 1mD/cP rock and pumping took approximately 7.5hrs with pumping rates of approximately 1cc/sec. Waterbreakthrough occurred after 5.5 hrs into the pump out.The overall logging from both sections was 190operating hours, with excellent operating efficiency andhigh-quality data acquisition.

Fig.4. Elongated packer.

Fig.5. Extra-elongated packer.

With the sidetrack already planned, a full re-evaluationof the pressure testing and sampling techniques andequipment was based on learnings from the main bore.After having all the data from the main bore, extensivesimulation work was performed to evaluate thepossibility of using the new, large, flow-area packer thatwas designed for use on a concentric flowing formationtester. The new, large flow packer, enables the formationtester to pump faster and concentrically in low-mobilityformations, where previously the standard concentric

packer (Fig. 6) would struggle to maintain a concentricflow.

Fig.6. STD and XR Concentric Flow Packers.

The simulation was conducted with an in-house near-wellbore numerical simulator based on a black oilreservoir simulator (Liu et al, 2004), which had beenused for pre-job planning of single probe fluid sampling(McCalmont et al, 2005). The simulator was used to firsthistory match the response from the main bore andextension, and then used for concentric-focused fluidsampling (Wu et al, 2013). Concentric-probe sampling isparticularly difficult in low-mobility rock because of thelow pump rates and high differentials that are seen on theinner and outer lines. The problem on the main bore wasthe pump speed was restricted because of the differentiallimit on the standard probe/elongated packer and thepump capability. The modelling showed that the largeflow area concentric packer would be able to maintain an8:1 ratio in the 2mD and 5mD rock. The modelling wasconducted for formation oil and OBM properties (Fig.7), which showed substantial reduction in pumping time,and results in a cleaner sample obtained in a muchquicker time.

The modelling results showed that the best pumpconfiguration for the formation tester was the 434cc -434cc, both of which have a working differential of5,200psi. The pump speed could be maintained at 1cc/son the sample line and 8.2cc/s on the perimeter line. Aconventional probe was run with an extra elongatedpacker. The large-area-flow concentric packer was runon the focused fluid formation tester with two 434ccpumps and only one fluid analyser on the sample linebecause of weight constraints which were modelled inthe Deployment Risk Management (DRM) system. The434cc pumps, pump the maximum differentialdrawdown that is necessary to overcome the highoverbalance and potential low mobility, and highdrawdown expectancy.

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Fig.7. Volume and contamination plot for the simulationwork done for the XR packer.

The tension modelling used to determine the optimumdeployment strategy was performed using Baker Hughesproprietary Cerberus software prior to the job. Tooptimize the maximum available overpull in a stuck toolscenario, the Baker Hughes powered capstan systemshould be utilized in combination with a 0.490 in extra-high-strength cable. To further minimize deploymentrisk, wireline jars and multi-axial rotating flywheelswere run in the tool string as well as using motorisedreleaseable cablehead (MRCH) to maximize themechanical weak point. The unique derrick-mountedpositioning of the powered capstan ensured the highesttensions only pulled vertically over the well and notacross the deck. This not only reduces risk to personnel,but also the potential for drum crush and damage to thewireline.

The sidetrack was drilled with 1.5g/cc OBM and reacheda depth of XX58 m. To evaluate the formation properties,acoustic and resistivity imaging, petrophysical andacoustic logs, nuclear magnetic resonance and elementalspectroscopy logs, and vertical seismic profile werelogged prior to the formation testing and sampling run.

The formation tester was equipped with twelve samplingtanks and pressure testing was conducted with theconventional probe dressed with an extra-elongatedpacker, (Fig.5). The packer has an 8x flow area of aconventional probe/packer and has a differential pressureof 10kpsi. Forty-four pressure stations were conductedwith eleven good tests, eleven tight tests, onesupercharged test, three aborted tests, eleven are buildingand seven have no seals for a total of forty seven pressuretests conducted. The mobility range was between 0.3 and3 mD/cP. Therefore, it is a very challenging environmentto acquire accurate, repeatable pressures and a sample in

a fast operational time period. Upon moving to the firstsampling the point, challenging hole conditions wereexperienced where upon the DRM program outlinedearlier became a critical component of the operation.Deployment risk analysis planning and technologiesused included MRCH, jars, flywheels and extra-high-strength cables that enabled the successful conveyanceof tool string which ultimately avoided a costly fishingoperation for the client.

Using the derrick-mounted-powered capstan andrunning a high-rated mechanical weak point in theMRCH, the crew were able to maximize the overpull,working to the maximum safety limit of the extra-high-strength logging cable. By progressively increasing therunning speed on the powered capstan up to themaximum safe working load, it was possible to move thetool string. The tools were pulled up to the CSG,however power was lost, which resulted in POOH tochange the string over and perform a wiper trip throughthe section. Back on the surface it was determined thatthe wireline jars had fired, which helped move the toolstring.

After the wiper trip, the same configuration was run backin-hole to the first sample point. The mobility wasapproximately 0.6mD/cP from the initial pressure testwith the XR packer. To initialize the samplingprocedure, it is important to verify the seal integrity ofthe inner and outer seal on the packer. After the sealintegrity is verified, a pumpout was performed with acommingled flow to check the maximum flow from bothinlets. Afterward, a pumpout was performed in the downdirection to establish the maximum flow capability onthe perimeter only. When the seal and flow capacity wasfinished, a commingle pump-up sequence began and thetool pumped out 5.2 litres (Fig. 8 and 9). The first waterslugs appeared in the commingle flow period atapproximately 6,000 secs. The commingle pump speedwas brought up to approximately 1.2cc/sec after whichsplit flow was commenced at approximately 8,500 secs.A flow rate of 0.28 to 0.32 cc/sec was establishedthrough the sample line and a rate of approximately 1.13cc/sec was observed through the perimeter line (Fig. 10).When the rates stabilized, the available sensors in thefluid analyser were used to establish the dominantformation fluid.

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Fig.8. Pressure and volume plot.

Fig.9. Commingle and split flow periods and tank fillingperiods (purple lines).

Fig.10. Rate and ratio plot, ~3:1 ratio achieved.

One problem of pumping so slowly on the sample line isthat the optical density response can look rather dirty andunclear. The optical density showed that the formationfluid was water; however, the signal was noisy (Fig. 11and 12).

Fig.11. Oil/water optical density vs time plot.

Fig.12. Spectrum plot change over time, highlightingwater peaks (blue ch. 14 and 17) on the fluid analyser.

The density measurement was very choppy because ofthe two-phase flow (Fig. 13), so the best measurementavailable to indicate constant water flow was the SoundSpeed measurement, (DiFoggio, 2006). The SoundSpeed measurement indicated a constant slowness of 188to 189 us/ft, which gave good assurance that a lowcontamination sample was achievable (Fig. 14).

Fig.13. Tuning fork density vs time plot.

Fig.14 .Sound Speed measurement vs time plot.

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When the sound speed measurement was stabilized thedecision was made to fill three single phase sampletanks. The tanks were nitrogen-charged with a volumeestimated at approximately 400 cc per bottle. The fillingtime was fairly long because of the slow pumping speedon the sample line. After the tanks were filled, the pumpover-pressurized the samples and the tanks werehydraulically shut in on the tank carrier. The PVTanalysis and contamination estimates were carried out onthe samples and the results showed contamination as lowas 2%. The results, in comparison to the main bore,where the contamination was upwards of 95%, showedthe effectiveness of the concentric probe to acquirequality samples in this type of environment.

CONCLUSION

Formation testing and sampling in low-mobilityformations using conventional packers and pump-outtechniques can result in poor data collection and qualityas well as highly contaminated samples. The use oflarger flow, concentrically formed packers cansubstantially lower the time needed to observe theformation fluid breakthrough, thus giving confidence tothe openhole evaluation and improving the samplepurity. With the correct pre-job planning, and not just onthe deployment side, the concentric flow XR packerenables the flexibility to acquire samples in relativelylow mobility and still work in higher mobilitieseffectively. The flexibility to contain the “correctequipment” in-hole when expectations are different fromthe actual results gives the operation a wider range ofproperties to work within, and thus, better data collectionand analysis can be performed at a significantly lowercost.

ACKNOWLEDGEMENTS

The authors would like to express their gratitude to theoperator, partners and service provider in explorationwell for permission to publish and present this paper.As well, authors would like to thanks members of bothVNG Norge AS and Baker Hughes organizations forhelp and support in preparation for this paper.

REFERENCES SECTION

DiFoggio, R., 2006, Method and Apparatus for anAcoustic Pulse Decay Density Determination, USPatent, 7,024,917.

Liu, W., Hildebrand, M.A., Lee, J., and Sheng, J.J., 2004,High-Resolution Near-Wellbore Modeling and Its

Applications in Formation Testing, SPE paper 90767,SPE Annual Technical Conference and Exhibition, 26-29 September 2004, Houston, Texas.

McCalmont, S., Onu, C., Wu, J., Kiome, P., Sheng, J.J.,Adegbola, F., Rajasingham, R., and Lee, J., 2005,Predicting Pump-Out Volume and Time Based onSensitivity Analysis for an Efficient SamplingOperation: Prejob Modeling Through a Near-WellboreSimulator, SPE paper 95885, SPE Annual TechnicalConference and Exhibition, 9-12 October 2005, Dallas,Texas.

Wu, J., Sibbald, G., Pre-job Modeling and Real-TimeMeasurements of Insitu Fluid Properties Enable EfficientFocused-Fluid Sampling, SPWLA 54th Annual LoggingSymposium, June 22-26, 2013, New Orleans, Louisiana.

ABOUT THE AUTHOR

Margaret Åsly is the senior reservoir engineer for VNGNorge, based in Stavanger. She holds an MSc inPetroleum Engineering from Heriot Watt University.

Gavin JG Sibbald is the EARC regional reservoirengineering advisor for Baker Hughes based in London.He holds an MSci with Honours in Geoscience fromRoyal Holloway, University of London and PGDip inPetroleum Engineering from Heriot Watt.

William Orrell is the sales manager for Baker HughesWireline Norway, based in Stavanger. He holds a BEngwith Honours in Mechanical Engineering & Design fromthe University of Huddersfield

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