Hpht Focus Jpt

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Industry focus on high-pressure/high-temperature (HP/HT) operations seemsto go in cycles as exploration successes identify new hydrocarbon resourcesthat can be developed commercially and as technical advances allow wells to bedrilled and completed that extend prior capabilities. When production of HP/HTreservoirs becomes dependent upon the development of a particular technology,business incentives create both a substantial momentum and a sharp focus thatdrives technology development to a successful end.

Historically, this drive has been the case with HP/HT developments. With thepassage of time, some may be unfamiliar with the substantial foundation of HP/ HT technologies that were created by the hard work of our predecessors. Forexample, the Association of American Wellhead Equipment Manufacturers(AWHEM) started work on 15,000-psi wellhead equipment in 1952. Thatresearch resulted in AWHEM Standard No. 6 in 1957, which would later becomepart of the API 15K wellhead standards. The first 20,000-psi wellhead systemwas developed in 1972, which was followed quickly with the development of thefirst 30,000-psi wellhead system in 1974. These developments were in responseto Shell’s discovery of the Thomasville field in Mississippi, USA, in 1969. Inaddition to Thomasville and Piney Woods fields in Mississippi, other substantialHP/HT developments include the Tuscaloosa fields in Louisiana, USA, and theCentral Graben fields in the North Sea.

Currently, the industry is pursuing new generations of HP/HT fields includingdeeper wells in deep water and deep gas wells on the outer continental shelf (OCS). Relative to the deepwater operations, well pressures may approach15,000 psi at the mudline, and, hence, 20,000-psi subsea equipment is beingpursued. Relative to the deep gas wells on the OCS, 20,000-psi surface wellheadsand trees, such as those used in Mississippi, Louisiana, and elsewhere, will againbe needed, and discussions are active on 25,000-psi equipment.

Just as the industry addressed the new HP/HT requirements successfully andsafely that appeared in the 1950s and onward, the industry’s current engineer-ing rigor, innovation, and advanced technical capabilities will again convergeto address today’s HP/HT challenges. These challenges should invigorate ourengineers as they lay the foundations and groundwork for the next generationof HP/HT capabilities.

HP/HT Challenges additional readingavailable at OnePetro: www.onepetro.org

SPE 123681 • “Elgin/Franklin: What Could We Have Done Differently?” by Eric Festa, Total E&P (See JPT, January 2010, page 54)

SPE 118904 • “First Application of High-Density Fracturing Fluid To Stimulatea High-Pressure/High-Temperature Tight Gas Producer Sandstone Formationof Saudi Arabia” by K. Bartko, Saudi Aramco, et al.

SPE 124713 • “Depletion-Induced Stress Changes in an HP/HT Reservoir:Calibration and Verification of a Full-Field Geomechanical Model” by M.H.H.Hettema, StatoilHydro, et al.

HP/HT Challenges

TECHNOLOGY FOCUS

70 JPT • APRIL 2010

JPT

Mike Payne, SPE, is a Senior Advisor

in BP’s Exploration and Production

Technology group. He has 28 years’

experience including drilling opera-

tions, computing, technology, and

consulting. Payne holds BS and PhD

degrees in mechanical engineering fromRice University, an MS degree in petro-

leum engineering from the University

of Houston, and an Executive Business

Education degree from the University

of Chicago. He has extensive industry

publications and has held key lead-

ership positions with the American

Petroleum Institute and the International

Organization for Standardization. Payne

has been an SPE Distinguished Lecturer

and received the SPE InternationalDrilling Engineering Award in 2000.

He has chaired or cochaired several SPE

Advanced Technology Workshops and

serves on the JPT Editorial Committee.



New drilling opportunities require tech-nological innovations to increase effi-ciencies and optimize production. Somenewer drilling operations, particularly indeep water, involve extreme environ-ments such as ultrahigh pressures thatrequire new approaches. With down-hole pressures approaching 30,000 psiand escalating rig costs, rotary-steerable

systems (RSSs) and advanced formation-evaluation technologies are needed.

IntroductionAdvances in rig design, in downholetools, in data communications, and inother areas result from challenges associ-ated with pushing and extending limits.

While in the planning stages of a deep-water high-pressure well, risk mitigationand contingency planning are critical inmaking technology advances. It is impor-tant to balance the drive to advance tech-nology with the value created.

Solution PotentialIn many cases, wellbore constructioncan be accomplished with standard off-the-shelf products and services. Whenthe location moves into deep water, thecomplexity, risks, and costs of thoseoperations require fit-for-purpose orapplication-based solutions.

In this case, early in the design phaseof the well, increased potential of a

high-pressure situation was evidentthat would require equipment that wasunavailable at the time. Therefore, theoperator approached a selected vendorand began a feasibility study. Open com-munication between the companies wascritical. After developing an understand-ing of the operator’s critical success fac-tors, the service company gained clearerinsight into the challenges at hand andwas able to address the effects and risksassociated with “new” technology.

Development StageTypically, well-construction planning

involves a few key individuals fromboth companies. For this case, it wasimportant to involve additional sup-port and expertise to ensure success.Expanded teams from the operatorincluded the drilling, geology, andpetrophysical disciplines, along withasset-management and offshore-oper-ations experts. The vendor expandedits operations, applications-engineer-ing, and technical-support functions toinclude reliability engineering, prod-

uct development, quality management,repair, and maintenance.

A variety of tools was used to ascertainexisting pressure limitations and theability to upgrade and develop solutionsto increase limitations to a 30,000-psipressure rating. The two main compo-nents of the analysis were the finite-element method and pressure testing of components and seals in an autoclaveto determine limits and verify designratings and field suitability. After allengineering analysis was completed anddesigns were deemed fit-for-purpose andapproved by the operator, the engineer-

ing team focused on developing parts,delivering specifications to manufactur-ing, and producing maintenance proce-dures for the building, qualifying, anddeployment of the downhole tools.

Well ChallengesThe subject well is in Green CanyonBlock 434 in the Gulf of Mexico. It isin deep water and has multiple riserlesssections. Fig. 1 shows typical challengeswhen drilling through these salt sections.

This article, written by Senior Technology

Editor Dennis Denney, contains highlightsof paper SPE 124324, “Drilling andEvaluation Technologies Extend OperatingLimits in Challenging High-PressureDeepwater Environments,” by Waitus

Denham, SPE, Shell, and BrianDonadieu , SPE, Ernest Lee, SPE, Rohit

Mathur, SPE, and Ananth Srinivasan, Baker Hughes, prepared for the 2009 SPE Annual Technical Conference and Exhib-ition, New Orleans, 4–7 October. The paper has not been peer reviewed.

Drilling and Evaluation Technologies Extend Operating Limits

in Challenging High-Pressure Deepwater Environments

HP/HT CHALLENGES

For a limited time, the full-length paper is available free to SPE members at www.spe.org/jpt.

JPT • APRIL 2010 71

Fig. 1—Typical salt challenges.




This well penetrates more than 13,000 ftof salt section and has pore-pressureuncertainty subsalt, a rubble and tar zonebelow the salt, tight-margin drilling, deepdirectional work, and extremely highdownhole pressures. Early in the well-design stage, the vendor was brought intothe planning process to assist in devel-oping solutions for the critical success

factors that would have to be met beforereaching the high-pressure section.

Some initial concerns for the wellincluded how to maintain verticality,predict and manage rate of penetra-tion (ROP) for riserless sections, andeliminate directional issues in the shal-low sections to ensure that torque anddrag, along with casing wear, wouldnot be an issue later. For the jet-in,drill-ahead, and subsequent two riser-less sections, ROP and verticality werethe primary concerns.

After setting the 22-in. casing, theriser was run and the well convertedto a synthetic-based-mud system. Thecombination of weight and stiffnesshelped maintain a vertical hole andallowed setting the 18-in. casing asclose to bottom as possible.

The next hole section was drilledwith an automated RSS and a concentricreamer for running 16-in. casing. Thissection was set up to have the 16-in. cas-ing set into the top of the salt zone and toprepare for drilling through the salt zone.The bit, bottomhole assembly (BHA),and reamer combination was set up todrill a controlled ROP because of a cut-tings-handling-equipment limiting fac-tor. Salt creep, irregular borehole, and/ordoglegs could prevent running a 135 / 8-in.string into the hole. The RSS technologyprovided steering capability, vertical con-trol, and the ability to minimize vibrationwhen entering the salt section.

With the plan in place to set the 135 / 8-in.casing within approximately 2,000 ft of the expected salt exit, planning for theunknown became more critical. The

121 / 4×14 in. section would exit salt andencounter an unpredictable combinationof potential obstacles (e.g., high-deforma-tion rubble at the base of salt, pore-pres-sure regression, and tar). By use of a fit-for-purpose integrated BHA including the RSSand formation-evaluation technology, thepore-pressure uncertainty could be elimi-nated while drilling. The BHA incorporat-ed formation-pressure-testing capabilitiesalong with the standard gamma ray, resis-tivity, directional, and annular-pressuremeasurements coupled with the steering

unit to deliver the desired directional con-trol for kicking off the well. Equivalent-circulating-density (ECD) managementbecame critical and was addressed by con-trolling the ROP throughout the remain-der of the well to minimize cuttings loadsand the vibration potential associated with“holding back” on ROP. The intention forthis section was to set the 113 / 4-in. liner

below salt at the base of the expected pore-pressure-regression zone.

In the 105 / 8×121 / 4-in. section, thedownhole-pressure regime was expect-ed to be in excess of 20,000 psi, whichrequired elevated-pressure capabilitiesin the BHA. This section was expectedto be relatively straightforward, and thecasing point was selected on the basisof pore pressure, or the observance of pressure regression if it came in late.

To manage the expected reservoir pres-sure, a 93 / 8-in. liner point was required

and planned to be set ahead of the tar-get zones, and an 81 / 2-in. hole wouldbe drilled to total depth. The BHA forthe 81 / 2-in. section required formation-pressure testing, standard logging-while-drilling tools, and the RSS. All of thisequipment was evaluated by risk assess-ment, and design upgrades were devel-oped to deliver the 30,000-psi require-ment projected in the final section.

Results

• Three hole sections were drilledriserless with reamers and split flow.

• The integrated drilling and evalua-tion BHA delivered shoe-to-shoe perfor-mance drilling, with only one hole sec-tion requiring more than a single run.

• A vertical hole was maintainedthrough the salt section, and a 135 / 8-in.string was set in a tight-tolerance143 / 4-in. hole.

• Vibration potential was minimizedthrough BHA design, parameter man-agement, and ROP control.

• More than 13,000 ft of salt wasdrilled.

• The subsalt kickoff started at26,000 ft true vertical depth with noissues.

• Formation-pressure testing whiledrilling showed an absence of the pore-pressure regression, which eliminatedthe need for the 93 / 8-in. liner.

• Tool capabilities were upgraded to30,000 psi one hole size early, with noeffect on rig operations.

• ROP improvements in the105 / 8×121 / 4-in. section resulted in sig-nificant savings.

• Formation-pressure tests wereobtained in a high-annular-pressureenvironment that exceeded 25,000 psi.

• Full directional control was enabledby use of RSS in a 25,000-psi environ-ment.

• The well was drilled to 30,000 ft in90 days, 27 days ahead of schedule.

Lessons LearnedA critical success factor was minimiz-ing the risks of nonproductive time.Balancing the drilling risks coupledwith the geologic uncertainty (i.e.,optimizing ROP to minimize vibration,ECD spikes, cuttings handling, andevaluation) was a key consideration.It was important to find an economic“maximum” to achieve drilling goalsand to then adhere to it. The involve-ment culture established by open com-munications between the operator and

vendor was instrumental in designingfit-for-purpose drilling and evalua-tion solutions that enhanced decisionmaking while drilling and spotlighteddownhole conditions.

Annular pressure was only one factorthat determined tool limits. Bore pres-sure played a large role in the “limita-tion” of tools and pressure capabilities.The drillstring, BHA, bit, and annulusform a series of pressure losses. The borepressure was higher than the annularpressure by default, and tool compo-nents had to meet the additional pres-sures experienced in the bore of theBHA. Bit-pressure drop, motor differen-tial, and turbine losses must be addedto the downhole annular pressure withan allowance for ECD spikes. If nuclearsources are mounted internal to theBHA, they must be evaluated for con-servative pressure estimates, includingmotor stalls and other pressure anoma-lies, to prevent any collapse issues.

Formation-pressure testing belowthe salt was a very effective tool indetermining the pore-pressure regime,

and data were used in real time to makedecisions regarding casing points andoptimizing hole stability. When casingpoints were pushed successfully, thepotential to drill to total depth with alarger hole size became real.

The success case as a contingency mustbe considered, as well as contingencyliners and smaller hole at total depth.Success also can present problems; thiswell was subsequently sidetracked, and ahigher volume of tools was needed thanoriginally planned. JPT



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An integrated borehole-seismic tech-nique was used to access and miti-gate drilling risk on a high-pressure/high-temperature (HP/HT) exploration well offshore Sabah, Malaysia. Theapproach combined wireline verticalseismic profiling (VSP) with logging- while-drilling (LWD) seismic surveys topredict pore pressure, determine geo-

stopping, and obtain high-resolutionseismic imaging beyond the well path.This high-resolution image was used toselect the sidetrack path. The final rig-source VSP was logged at total depth(TD) to complement the pore-pressureprediction and seismic imaging.

IntroductionIntegrating wireline and LWD bore-hole-seismic information for drilling isa new technique in Malaysia. In thisapproach, borehole-seismic data, whichare used conventionally for geologic andgeophysical interpretation, have addedvalue for drilling and well planning.

The well, drilled in 2008, is off thecoast of Sabah, East Malaysia. Thetarget reservoir, in contrast to mostother reservoirs in the region, is deeper,hotter, and at much higher pressures

than normal. Pore-pressure ramps anddepleted sands in the field had madedrilling difficult previously, generatinghazardous incidents including stuckand in-hole-lost pipe, fluid losses, andkicks. These incidents had resulted instopping drilling prematurely, resultingin ultradeep targets remaining unex-plored. Studies by the sedimentologistsuggested that this overpressure haz-ard is associated with undercompactedbathyal mudstone, and the well-casingdesign required accurate prediction.

The well path was designed to avoidthe regional fault that could compli-cate pore-pressure prediction. Existing

surface-seismic and distant-well-basedvelocity control were inadequate forthis purpose.

Primary well objectives were the light-ly explored, stacked, lowstand UpperMiocene turbidite-reservoir sequences.The deepest of these were expected to beat approximately 4000- to 5000-m sub-sea (SS) depth. The shallow units, whichare depleted because of production fromother locations, were at approximately2500- to 4000-m SS depth.

Data Acquisition and ProcessingThe workflow for this integrated approachfor risk mitigation is depicted in Fig. 1. An intensive seismic-logging campaignwas conducted on this well, comprisingthree intermediate wireline-VSP runs,one LWD-seismic acquisition, and oneTD wireline-VSP run. The wireline-VSPdata were acquired in both openhole andcased-hole sections through the surveyby use of four shuttle-imaging tools,each of which had three orthogonallyopposed nongimbaled accelerometersensors. A triple air-gun cluster was usedas the seismic source. Real-time monitor-ing and fast interpretation at the wellsite

were performed to ensure high dataquality for reliable interpretation.

The LWD-seismic operation was sim-ilar to the wireline operation in that itused an active surface source (air guns)and downhole receivers as shown inFig. 2. The key difference with this ser-vice is that the receivers are included inthe drilling assembly. Therefore, drill-ing does not have to be stopped to takemeasurements, ensuring transparencyto drilling operations by acquiring data

This article, written by Senior TechnologyEditor Dennis Denney, contains highlightsof paper IPTC 13083, “CombiningWireline and LWD Borehole Seismic Datafor Drilling an HP/HT Well: A Novel

Approach,” by T.K. Lim, SPE, and Aqil Ahmed, SPE, Schlumberger, andGunawan Taslim and Muhammad Antonia Gibrata, SPE, Petronas, prepared for the 2009 International PetroleumTechnology Conference, Doha, Qatar,7–9 December. The paper has not been peer reviewed.

Copyright 2009, International PetroleumTechnology Conference. Used with per-mission.

Combining Wireline and LWD Borehole-Seismic

Data for Drilling an HP/HT Well

HP/HT CHALLENGES


Fig. 1—Workflow for pore-pressure management with integrated bore-hole-seismic solution.

Initial Geomechanics Study

– Mechanical Earth-model baseline

Real-Time Measurements

– LWD Pressures during drilling

Integrated Borehole Seismic

– Wireline VSP look-ahead information

– VSP inversion ahead of bit

– Constrain inversion with real-time check

shots while drilling with LWD seismic

– High-resolution seismic images, well planning

Real-Time Pore-Pressure Updates

– LWD data in workstation

– 24-hour monitoring




JPT • APRIL 2010 75

at connections. Acquiring data in realtime mitigates the additional risk of borehole damage and stuck tools asso-ciated with running a wireline survey.

True-amplitude processing was car-ried out to optimize reflectivity infor-mation. The final deconvolved wavefield provided higher-resolution imagesfor look-ahead information and veloc-ity inversion ahead of bit.

The LWD-seismic tool delivered real-time check shots and interval velocitieswhile drilling, with no effect on drillingtime. The real-time time/depth pairshelped to position the bit while drillingand aided in constraining pore pressureahead of the bit. The processed-wave-form results compared favorably withconventional wireline surveys.

Benefits• Both wireline and LWD vertical-inci-

dent VSP showed minor faults that werenot apparent on the surface 3D seismic;the presence of the faults explained anunusual kick that was encountered.

• The real-time check-shot-while-drilling survey helped drilling stopwithin one stand above the key forma-tion top and assisted in coring and cas-ing decisions.

• The real-time check-shot updateallowed refinement of the pore-pres-

sure model, enabling critical drillingdecisions being made before encoun-tering the high-pressure ramp duringthe drilling process.

• High-quality seismic imaging alongthe well plane supported drilling-riskmitigation and well design.

• The technique improved seismicreservoir characterization and reducedstructural uncertainty in a challengingenvironment.

Conclusions

This combined wireline VSP and LWDseismic-vertical-incident VSP yieldedhigh-resolution seismic imaging belowthe well path enabling drilling-riskmitigation and sidetrack-well plan-ning and providing look-ahead infor-mation for pore-pressure prediction.

The large amount of borehole-seis-mic data collected in this campaignprovided vital information for seis-mic imaging around the well path. Acrucial subfault system, which wasnot present on the surface 3D seis-mic, was revealed by the wireline-VSPruns and the LWD-seismic images.The subfault system also revealedthat the supercharging effect was theroot cause of the well encounteringa kick earlier than predicted with theVSP inversion. JPT

Fig. 2—Simplified vertical-well models for wireline- and LWD-loggingmethods. LWD seismic is similar to wireline service and uses the same surface source (air guns) coupled with a gun controller. The main dif-ference is no direct cable connection between the tool and surface.Instead, information is transmitted by mud-pulse telemetry.

Surface

System

Surface

System

Source Source

Seafloor Seafloor

Mud-pulse

telemetry

Wireline toolLWD-seismic

tool

Seismic reflector



High-pressure/high-temperature (HP/HT) gas reservoirs have pressures great-er than 10,000 psia and temperatureshigher than 300°F. Modeling the per-formance of these reservoirs requiresunderstanding gas behavior at elevatedpressure and temperature. Gas viscos-ity is used to model the gas mobility inthe reservoir and can have a significant

effect on reserves estimation duringfield-development planning. Accuratemeasurements of gas viscosity atHP/HT conditions are extremely diffi-cult. Public-domain databases of hydro-carbon-gas viscosity were reviewed for validity of gas-viscosity correlations andtheir applicability range.

IntroductionThe growing demand for natural gasis driving the search for new deepersources of gas, many of which encoun-ter HP/HT conditions. Among gasproperties, viscosity is seldom mea-sured in the laboratory and, typically,is estimated by use of correlations. AtHP/HT conditions, reservoir fluids willbe very lean gases, typically methanewith some level of impurity, and there-fore the gas properties may be differentfrom those of gases at lower pressuresand temperatures.

A review of large databases of pub-lished viscosity data for pure methane

and mixed hydrocarbons revealed limi-tations in terms of experimental condi-tions, data quantity, and in some casesaccuracy. The full-length paper detailsmany of these limitations. A reviewof available gas-viscosity correlationsalso was performed, which showedthat these correlations were devel-oped from experimental data taken at

low-to-moderate pressures and tem-peratures and that their applicability atHP/HT conditions could be limited.

Available CorrelationsNational Institute of Standardsand Technology (NIST). NIST devel-oped computer software to predictthermodynamic and transport proper-ties of hydrocarbon fluids. The soft-ware program uses the principle of “extended corresponding states” andwas developed from pure-componentand mixture data. The maximum pres-sure and temperature that can be usedin the program are 44,100 psia and1,340°F, respectively. The NIST gas-viscosity values closely match mostof the published data, and the pre-dictions generally are reliable forHP/HT conditions in the absence of realHP/HT gas-viscosity measurements.

Lee, Gonzalez, and Eakin (LGE)Correlation. The LGE correlation isbased on measured data of pure-com-ponent gases and eight natural gases

with specific gravities less than 0.77.The correlation can be used to estimategas viscosity, provided that the molecu-lar weight and density at the relevantconditions are known.

The LGE correlation can be used topredict gas viscosities at temperaturesfrom 100 to 340°F and pressures from100 to 8,000 psia. Although this cor-relation does not take into accountnatural gases containing high quanti-ties of nonhydrocarbon components,

it is considered reliable for predictingthe viscosity of natural gases belowHP/HT conditions.

Viswanathan Correlation. This cor-relation is a modified LGE correlationbased on NIST values of viscosity of pure methane at pressures from 5,000to 30,000 psia and temperatures from

100 to 400°F. However, these resultscannot be extrapolated directly to situ-ations in which impurities exist in thegas. The Viswanathan correlation canbe used with confidence whenever theNIST values are assumed to be valid.For HP/HT conditions, the validity of both NIST values and the modifiedLGE correlation must be proved againstactual measurements.

Gas Viscosities Measuredat HP/HT ConditionsA project to characterize the viscosity of gas at HP/HT conditions was initiated.Two types of gases were used: nitrogenas a calibration fluid and pure methane.The investigation was performed witha device that works on the basis of thefalling-body principle.

All performed tests were comparedwith the reported NIST values. At highpressure, all measured viscosities werelower than the NIST values, although inthe moderate range (3,000 to 8,000 psia),values match exactly. These results wereexpected because the NIST values were

calculated from existing databases withvery few points above 15,000 psia.

Fig. 1 compares measured data fromthis project with NIST values and otherexisting databases for nitrogen at 134°F.Test 1 was run from low to high pres-sure, while Test 2 was run from highto low pressure. Between 3,000 and8,000 psia, a good match exists betweenmeasurement and NIST values. At high-er pressure, the measured viscositieswere less than those provided by NIST,

This article, written by Senior Technology

Editor Dennis Denney, contains highlightsof paper SPE 124734, “More-AccurateGas-Viscosity Correlation for Use at HP/HT Conditions Ensures Better ReservesEstimation,” by Ehsan Davani, SPE,Kegang Ling, Catalin Teodoriu, SPE,William D. McCain Jr., SPE, and Gioia

Falcone, SPE, Texas A&M University, prepared for the 2009 SPE AnnualTechnical Conference and Exhibition,New Orleans, 4–7 October. The paperhas not been peer reviewed.

Accurate Gas-Viscosity Correlation for Use at HP/HT

Conditions Ensures Better Reserves Estimation

HP/HT CHALLENGES





although they show a similar trend. Thesame behavior was observed for morethan 100 tests conducted at the timethis paper was written.

On the basis of these measurements,it can be inferred that the maximumerror against the NIST values is –7.48%at pressures greater than 20,000 psia.

At increased temperature, the differ-ence between project data and theNIST values decreased.

Fig. 1—At pressures between 3,000 and 8,000 psia, there is a good match between study measurements and

the NIST values. However, at higher pressure, study data fall below the NIST values.

Temperature=134°F

Pressure, psi

V i s c o

s i t y , c p

High-

pressure

error

Good correlation

with NIST values

Study Data (Test 1)

Study Data (Test 2)

Other Investigators’ Data

NIST Data. T =134°F

0.05

0.045

0.04

0.035

0.03

0.025

0.02

0.015

0 1,500 3,000 4,500 6,000 7,500 9,000 10,500 12,000 13,500 15,000



Sensitivity The effect of gas-viscosity uncertaintyon cumulative field production wasinvestigated by use of numerical reser-voir simulations performed for a simplesynthetic case consisting of one wellin a pure-methane-gas reservoir havinghomogeneous rock and fluid proper-ties. Viscosity was defined as an input

function of pressure and temperature.The input values were set equal to theNIST values and then perturbed by ±1%to ±10%. The aim was to investigatehow the difference between NIST valuesand measurements at HP/HT conditionscould affect reserves estimates. Thesimulator performs an interpolation of the discretized input viscosity values toobtain a continuous viscosity functionof pressure and temperature. The uncer-tainty associated with this interpolationprocess can be minimized by providing

a sufficiently large number of input val-ues, as was the case for this study.The software package uses an implic-

it-calculation procedure and black-oilmodeling of the fluid properties. No

water flow was simulated, and theruns were performed assuming isother-mal conditions.

A small difference in gas viscositybetween NIST values and actual mea-surements influenced estimates of cumulative gas production from the sim-ple HP/HT gas reservoir. An interestingresult was that underestimating the gas

viscosity yielded slightly worse resultsthan overestimating the gas viscosity.

A −10% error in gas viscosity pro-duced an 8.22% error in cumulativeproduction. A +10% error in gas viscos-ity yielded a 5.5% error in cumulativeproduction. These preliminary resultssuggest that an inaccurate estimationof gas properties may have a significanteffect on the predicted reservoir perfor-mance of an HP/HT gas field.

Conclusions

Accurate measurements of natural-gasviscosity under HP/HT conditions areyet to be obtained. Gas-viscosity cor-relations derived from data obtainedat low-to-moderate pressures and tem-

peratures cannot be extrapolated confi-dently to HP/HT conditions.

Gas-viscosity correlations that areavailable to the petroleum indus-try were derived from data obtainedwith gases having limited impurities.Therefore, their accuracy for use withgases containing large quantities of impurities is unknown.

The laboratory investigations withnitrogen showed a consistently nega-tive error compared with the reportedNIST values, with a maximum errorof −7.48% at 134°F. On the basis of the results from a synthetic HP/HTgas-reservoir model, a −10% error ingas viscosity would produce an 8.22%error in cumulative production, anda +10% error in gas viscosity wouldlead to a 5.5% error in cumulativeproduction. These preliminary resultsstress the importance of obtaining an

exhaustive range of measurements of the viscosity of natural gases underHP/HT conditions to ensure betterreserves estimation. To this aim, fur-ther tests are ongoing. JPT

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