7/21/2019 SPE-57886-PA.pdf

1/5

Uncertainties in Reservoir Fluid Descriptionfor Reservoir Modeling

K.K. Meisingset, SPE, Statoil

SummaryThe objective of the present paper is to communicate the basicknowledge needed for estimating the uncertainty in reservoir fluidparameters for prospects, discoveries, and producing oil and gas/

condensate fields. Uncertainties associated with laboratory analy-sis, fluid sampling, process description, and variations over thereservoirs are discussed, based on experience from the North Sea.

IntroductionReliable prediction of the oil and gas production is essential forthe optimization of development plans for offshore oil and gasreservoirs. Because large investments have to be made early in thelife of the fields, the uncertainty in the in-place volumes and pro-duction profiles may have a direct impact on important economi-cal decisions.

The uncertainties in the description of reservoir fluid composi-tion and properties contribute to the total uncertainty in the reser-voir description, and are of special importance for the optimiza-

tion of the processing capacities of oil and gas, as well as forplanning the transport and marketing of the products from thefield. Rules of thumb for estimating the uncertainties in the reser-voir fluid description, based on field experience, may therefore beof significant value for the petroleum industry. The discussion inthe present paper is based on experience from the fields and dis-coveries where Statoil is an operator or partner, including almostall fields on the Norwegian Continental Shelf,1,2 and all types ofreservoir oils and gas condensates except heavy oils with stock-tank oil densities above 940 kg/m3 below 20 API.

Fluid Parameters in the Reservoir ModelThe following parameters are used to describe the reservoir fluidin a black oil reservoir simulation model:

densities at standard conditions of stabilized oil, condensate,

gas, and water; viscosity (O), oil formation volume factor (B O), and gas-oil

ratio (RS) of reservoir oil; viscosity (G) gas formation volume factor (B G) , and

condensate/gas ratio (R SG ) of reservoir gas; viscosity (W), formation volume factor (BW), and com-

pressibility of formation water; and saturation pressures: bubblepoint for reservoir oil, dew point

for reservoir gas.

The actual input is usually slightly more complex, with saturationpressure given as a function of depth, with R Sand R SG defined asa function of saturation pressure, and with oil and gas viscositiesand formation volume factors given as a function of reservoirpressure for a range of saturation pressure values. However, minorchanges in saturation pressure versus depth are usually neglected,

and the oil dissolved in the reservoir gas can also be neglected(R SG0) when the solubility is small.

Uncertainties in the modeling of other fluid parameters inter-facial tension may for instance be of importance, because of itseffect on the capillary pressure, or compositional effects like re-vaporization of oil into injection gas, are not discussed here. Un-certainties in viscosity, formation volume factor and compressibil-ity of formation water, and density of gas at standard conditions,

are judged to be of minor importance for the total uncertainties inthe reservoir model. The uncertainty in the salinity of the forma-tion water is discussed here instead, because it is used for calcu-lations of water resistivity for log interpretation, and therefore,

affects the estimates of initial water saturation in the reservoir.In a compositional reservoir simulation model, the composition

of reservoir oil and gas with, typically, 4 to 10 pseudocompo-nentsis given as a function of depth, while phase equilibria andfluid properties are calculated by use of an equation of state. How-ever, the uncertainties in the fluid description can be described inapproximately the same way as for a black oil model.

Quantified uncertainty ranges in the present paper are coarseestimates, aiming at covering 80% of the probability range foreach parameter estimated value plus/minus an uncertainty esti-mate defining the range between the 10% and 90% probabilityvalues3.

Prospect EvaluationAssessments of the uncertainties in the reservoir description, as a

basis for economic evaluation, are made in all phases of explora-tion and production. Of course, the complexity in the fluid de-scription increases strongly from prospect evaluation through theexploration phase and further into the production phase, but themain fluid parameters in the reservoir model are the same.

The prediction of fluid parameters in the prospect evaluationphase, before the first well has been drilled, is based on reservoirfluid data from discoveries near by, information about sourcerocks and migration, and empirical correlations. The uncertaintiesvary strongly from prospect to prospect. The probability as a func-tion of volume for the presence of reservoir oil and gas is usuallythe most important fluid parameter. The probability for predictingthe correct hydrocarbon phase varies from 50% equal probabilityfor reservoir oil and gas to 90% in regions where either oil orgas reservoirs are strongly dominating, or when the reservoir fluid

can be expected to be the same as in another discovery near by .For formation volume factors, gas/liquid ratios, viscosities, anddensities, an estimate for the most probable value as well as for ahigh and low possible value is commonly given. The range be-tween the high and low value is often designed to include 80% ofthe probability range for the parameter, but accurate uncertaintyestimates can seldom be made. The ratio of the high and lowvalue is, typically, 1.5 to 50 for R SG , 1.1 to 1.5 for B G, 1.1 to 2.5for G; 1.2 to 3 for R S, 1.1 to 2 for B O, 1.5 to 5 for O, and1.03 to 1.1 for densities of stabilized oil and condensate.

From Discovery to Production

After a discovery has been made, the fluid description is based onlaboratory analyses of reservoir fluid samples from drill-stemtests, production tests, and wireline sampling RFT, FMT, MDT

in exploration and production wells. Pressure gradients in the res-ervoirs from measurements during wireline and drill-stem tests,analysis of residual hydrocarbons in core material from variousdepths, measurements of gas/oil ratio during drill-stem and pro-duction tests, and measurements of product streams from the field,give important supplementary information.

Variations in Fluid Properties Over the Field. Early in the ex-ploration phase, when 1 to 2 exploration wells have been drilled,we have usually little information about contrasts in fluid proper-ties over sealing faults and changes in fluid properties with depthor position in the reservoirs. Great contrasts in fluid propertiesmay exist between formations and fault blocks without pressurecommunication. The possibility of such contrasts may give a sig-

Copyright 1999 Society of Petroleum Engineers

This paper (SPE 57886) was revised for publication from paper SPE 38112, first presentedat the 1998 SPE Asia Pacific Conference on Integrated Modeling for Asset Management,Kuala Lumpur, 2324 March. Original manuscript received for review 7 November 1996.Revised manuscript received 7 July 1999. Paper peer approved 8 July 1999.

SPE Reservoir Eval. & Eng. 2 5, October 1999 1094-6470/99/25/431/5/$3.50

0.15 431

7/21/2019 SPE-57886-PA.pdf

2/5

nificant contribution to the total uncertainty in the fluid descrip-tion, depending on how well the reservoir fluids in different for-mations have been mapped, and the sealing probability of layersand faults in the reservoirs. The uncertainties can be handled bytreating undrilled fault blocks as prospects, with estimated prob-abilities for the presence of reservoir oil and gas, and with esti-mated uncertainties in fluid properties.

In gas/condensate reservoirs with an underlying oil leg, signifi-cant contrasts may exist with respect to the thickness of the oilcolumn in different formations and fault blocks, even when pres-sure communication is assumed to exist both within the overlyinggas cap and within the underlying aquifer. Such a situation exists

in several fields offshore Norway examples, Gullfaks South,Heidrun, Troll, Midgard1,2. The possibility of variations in thethickness and fluid properties of the oil leg should be taken intoaccount in the uncertainty evaluation, whenever a direct commu-nication within the oil zone between different formations and faultblocks may be prevented by partly sealing layers or faults. Thesignificance for the total uncertainty is again dependent on howwell the fluid contacts and oil properties in different formationsand fault blocks have been mapped. Uncertainties in depth mea-surements in deviated wells and contact definitions from well logsmay also be of importance.

Variations in the composition and properties of the reservoirfluid are also observed within reservoirs with good pressure com-munication. Generally, the dewpoint pressure and content of dis-solved condensate in reservoir gas increases with increasing res-ervoir depth, while the bubblepoint pressure and gas-oil ratio ofreservoir oil decreases with increasing depth. In most reservoirsoffshore Norway, the change in saturation pressure versus depth isless than 0.3 bar per meter typical examples, The Statfjord andGullfaks oil fields, and the Sleipner and Huldra gas condensatefields2. It is, therefore, often difficult to prove that a depth gradi-ent exists, since lateral variations as well as uncertainties in testseparator gas-oil ratio measurements may be of the same order ofmagnitude. The observed depth variations in the gas-oil ratio areusually less than 25%. Neglecting the depth gradient on the Sleip-ner East field2 was still experienced to cause a 10% error in theestimate of the average condensate-gas ratio, because a majorityof the drill-stem tests in the exploration wells were relatively closeto the gas-water contact.

Greater changes in bubble-point pressure versus depth, of theorder of magnitude 1 bar/m, have been observed just below the

gas-oil contact in some reservoirs offshore Norway, for instance,in the Gullfaks South field.1 Very large depth gradients are alsoobserved in the Brent field offshore Britain,4,5 where the fluidcomposition changes continuously from reservoir oil at the bottomof the reservoir to gas condensate on the top, without any tradi-tional gas-oil contact with saturation pressures equal to the reser-voir pressure. Within an oil column, the change in stock-tank oildensity and viscosity with depth is usually relatively small; pos-sible exceptions from this rule are observed on the Heidrun fieldoffshore Norway1 and the Claymore field offshore Britain.6

Compositional depth gradients can be calculated on the basis ofthe reservoir fluid composition, by including the effect of gravita-tion in an equation of state.5 Although the degree of correspon-dence with observed depth gradients has been found to varystrongly from reservoir to reservoir, the method is still an impor-

tant tool for the modeling of depth variations and uncertainties influid parameters. The method may also give some indication onthe probable distance to a gas-oil contact, on the basis of pressure-volume temperaturePVTand compositional data for a represen-tative PVT sample at a given depth. The error in the prediction ofsuch a contact depth can, however, often be more than a hundredmeters.

The uncertainty in the fluid description, which is due to pos-sible variations in fluid properties over a field, varies stronglyfrom field to field, depending on data acquisition, production ex-perience, and geological complexity. In the exploration phase, thetypical uncertainties due to possible variations in fluid parametersover the field can be estimated to be 15 to 30% for R SG , 5 to 10%for B G , 5 to 30% for G , 10 to 20% for R S , 5 to 10% for B O,

10 to 30% for O, 0.5 to 2% for the density of stabilized oil andcondensate, and 5 to 20% for the salinity of formation water. Theuncertainty is somewhat greater when the water resistivity has tobe determined from well logs due to the lack of representative

formation water samples.Data acquisition in the production phase usually includes accu-

rate measurements of the export of sales products from the field,periodical measurements of test separator gas-oil ratios in the pro-duction wells, and laboratory analyses of PVT samples from allwells where the well stream gas-oil ratio or the density of stabi-lized oil is found to be different from the predictions. On the basisof such measurements, we will usually have reliable informationabout the most important variations in fluid properties over thefield after some years of production. For instance, after 15 yearsof production from the Statfjord field,2 the contributions from pos-sible variations over the main reservoirs to the total uncertainty inaverage fluid parameters were estimated to 1% for BO , 2% for

R S, 5% forO , 5 bar for the bubblepoint pressure of the reser-voir oil, and 1% for the salinity of the formation water. Similar

estimates for the Gullfaks field,2

which is geologically more com-plex than Statfjord, would be at least doubled. For a gas conden-sate field like Sleipner East,2 which like Statfjord has a relativelyhomogeneous reservoir fluid and a relatively low geological com-plexity, it should be possible to reduce the contribution to the totaluncertainty from possible variations over the field to approxi-mately 5% for R SG , 2% forB G, and 5% for G. The numbers inthe text are illustrated in Fig. 1.

Representativity of PVT Samples. The most important types ofpressurized samples from PVT sampling during well testing andopenhole logging are described briefly in Table 1.

Bottomhole Samples. For oil reservoirs, bottomhole samplesare generally judged to be the most representative, provided that

Fig. 1 Illustration of the uncertainty in modeling of averagefluid parameters due to possible variations over the field forgas condensate aboveand reservoir oil below.

432 K.K. Meisingset: Reservoir Fluid Description SPE Reservoir Eva l. & Eng., Vol. 2, No. 5, October 1999

7/21/2019 SPE-57886-PA.pdf

3/5

the reservoir pressure at the time of sampling is higher thanthe initial bubblepoint pressure of the reservoir oil;

the well has been properly conditioned before sampling, witha low rate flow with low pressure drawdown;

the pressure at the sampling depth is higher than the initialbubblepoint pressure of the reservoir oil; and

PVT laboratory studies show that at least two bottomholesamples from the same reservoir depth are equal, and also similarto recombined separator samples.

The same criteria are valid for single-phase wellhead samples,which are often taken instead of bottomhole samples when thebubblepoint pressure of the reservoir oil is lower than the well-head pressure.

Separator Samples. The representativity of separator samplesis dependent on the uncertainty in the gas-oil ratio measurementsin the test separator typically, 5 to 10%, because the gas-oil ratiois used for recombination of separator gas and oil samples toreconstruct a sample of the well stream. Usually, separatorsamples are still regarded as the most representative samples forgas-condensate reservoirs, because the experience with bottom-hole samples is less positive than for oil reservoirs, and becausethe volume of a bottomhole sample often is insufficient for agas-condensate PVT analysis program. Separator samples are

judged to be of acceptable quality when the reservoir pressure at the time of sampling is higher than

the initial saturation pressure of the reservoir fluid; test separator measurements show that the gas-oil ratio is con-

stant and the separator conditions are stable for 4 to 6 hours beforesampling; and

laboratory measurements show that the bubblepoint pressureof the separator oil sample, as well as the opening pressure of theseparator gas bottle, is as expected no leakage.

Very high gas production rates may result in liquid carry-overthrough the test separator gas outlet, which may cause significanterrors in the gas-oil ratio measurements. Such an error may bedifficult to avoid for very lean gas/condensate reservoirs, becausethe separator liquid rate often will be too low to be measured

exactly with conventional liquid meters if the gas rate is reduced.A typical example is the Troll field offshore Norway,2 whereisokinetic split-stream sampling proved to be a great improve-ment compared to conventional test separator sampling. With

modern split-stream sampling methods,7 the uncertainty in thegas/oil ratio measurements has been experienced to be 5 to 10% at

high gas rates above 0.5 million Sm3 per day, while greatererrors have been observed at lower gas rates.

Wireline Samples. Drill-stem tests have usually given morerepresentative PVT samples than wireline sampling, which aretaken from the near-well region where the reservoir fluid mayhave been more or less affected by contact with well fluids.

Wireline samples from wells where oil-based or oil solubledrilling mud has been used, has been experienced to contain at

least 2 to 3% mud filtrate contamination often much more, some-times 80 to 100% mud filtrate. The problem is similar with wire-line samples of water from wells with water-based mud, whichseldom have proved to give reliable formation water data.

With all types of drilling fluids, some diffusion of lightercomponents from the reservoir fluid into the drilling fluid must beexpected. Laboratory analyses have shown that the CO2content in

most wireline samples has been significantly altered. Indicationson minor changes in the C6 to C8 fractions are also often de-tected.

Measurements of the H2S content in wireline samples areusually unreliable, because H2S reacts with the metal in thesample chambers. High H2S concentrations are sometimes causedby bacterial degradation of certain types of drilling mud.

Great deviations from representativity may be caused by pres-sure drawdown during sampling, or leakage from the chambers inthe well or during storage and transfer.

The representativity of samples with no obvious indicationson sampling problems or leakage, has been experienced to varyfrom being perfect to giving deviations of 20 to 30% in gas-oil orcondensate-gas ratios from the actual reservoir fluid.

Still, wireline samples have given useful information in the explo-ration phase for most Statoil-operated fields, in combination withsamples and data from drill-stem tests. Wireline sampling is farless expensive than drill-stem testing, and the sampling equipmenthas been improved during the last years. But, wireline samples arestill hardly reliable enough to be the only basis for very large andexpensive field developments offshore.

Uncertainty in Laboratory Analyses. The uncertainties in com-positional analyses and volumetric measurements in the PVTlaboratory are usually small compared to the uncertainties withrespect to the representativity of PVT samples and the variationsin fluid parameters over a field.

With capillary gas chromatography,8 the relative uncertainty inthe compositional analysis should vary from about 1% for meth-

ane, ethane, or propane, to about 10% for inorganic componentsnitrogen and carbon dioxide, heavier fractions C7 to C10 forgas samples, C10 for oil samples, and pure components in verylow concentrations 0.1%, provided that the operator is experi-enced and the procedures for calibration and operation have beenoptimized. Somewhat greater deviations between different servicelaboratories are, however, often observed.

The reservoir fluid composition is often used as the basis forcalculation of reservoir fluid properties, by use of equations ofstate and empirical methods. Examples from the Statfjord field2

indicate that the uncertainties in the compositional analysis corre-spond to 2 to 3% variation in calculated R Svalues and about 1%in B O. The uncertainties in a reservoir gas composition, espe-

TABLE 1 ALTERNATIVE PVT SAMPLING METHODS

Sample Type Fluid Sampled Sampling Point

Wireline samples(RFT,FMT,MDT)

Formation fluid close to the well Pressurized chamber on wirelineduring openhole logging

Bottomhole samples Single-phase well stream Pressurized chamber on wirelineduring well testing

Single-phase wellheadsamples

Single-phase well stream Upstream chokeduring well testing

Isokinetic wellheadsplit-stream samples

Homogenized well stream, oroil and gas from a small separator

Upstream or downstream chokeduring well testing

Separator samples Gas and oil at test separatorconditions

At the gas and oil outlet on thetest separator during well testing

K.K. Meisingset: Reservoir Fluid Description SPE Reservoir Eval. & Eng., Vol. 2, No. 5, October 1999 433

7/21/2019 SPE-57886-PA.pdf

4/5

cially for lean gas condensates, would correspond to greater volu-metric uncertainties of the order of magnitude 5 to 15% for R SGand 1 to 4% for B G.

The uncertainties in other PVT laboratory measurements areusually 1 to 2 bar for a bubblepoint pressure, 1 to 10 bar for adewpoint pressure, and approximately 3% for the Z factor of areservoir gas sample, 2% for the density of a reservoir oil sample,0.05% for the density of a stabilized liquid sample at atmosphericpressure, and 2% for the salinity of formation water samples. Foroil viscosity measurements, the uncertainty with the rollingball method used by most service laboratories is expected to beabout 10% for viscosities between 0.3 and 5 cP, with optimal

routines for calibration and operation. 30% deviation from theaverage has, however, often been observed in multilaboratory ringtests.* For reservoir oils with very low viscosity 0.1 to 0.3 cP,the deviations between different laboratories have been experi-enced to be even greater often 30 to 50%. Two other methods,falling sinker and capillary viscometry, have proved to givemore accurate results for viscosities below 0.2 cP.

The viscosity of reservoir gas is usually calculated from thereservoir fluid composition and not measured. The error in calcu-lated gas viscosities is relatively small 10% for lean gas con-densates at low reservoir pressures 300 bar, while alternativecalculation methods can give differences up to 30% for very richgas condensates at high reservoir pressures 500 bar.

Uncertainty in Process Description.The condensate-gas ratio

for most reservoir gases is strongly dependent on the design of theprocessing plant. One example is the Sleipner East field,2 wherethe condensate volumes were more than doubled compared toearly estimates, by using turboexpanders to separate the reservoirgas into dry gas and unstabilized condensate on the productionplatform instead of processing to wet gas and stabilized conden-sate. Early estimates of R SG for other gas/condensate fields off-shore Norway have also proved to be too pessimistic because ofan unrealistic process description.

In the PVT laboratory, B O and R S for reservoir oil can bemeasured at approximate process conditions in multistage separa-tor tests, which have been experienced to give reliable results forreservoir oils with a low content of volatile liquid components C3to C7. Typical uncertainties in the laboratory measurements forsuch oils are 1% for B O and 3% for R Sexamples, The Gullfaks,Troll, and Heidrun fields1,2.

For multistage separator tests of oils with higher contents of C3to C7, the uncertainties have been experienced to be somewhatgreater. Examples, for reservoir oil from the Statfjord and Vesle-frikk fields,1,2 deviations of 3% in B O and 10% in R S betweendifferent laboratories have not been unusual. Furthermore, the R Svalues from simulated separator tests are systematically 2 to 5%higher than for the complete process simulations, because the pro-cessing plant contains gas scrubbers which are not represented inthe laboratory experiment. Multistage separator tests for reservoirgas are usually not performed, because the results would deviateeven more from actual processing data.

The process description in the reservoir model is, therefore,usually based on simulations and not on laboratory measurements,as soon as a realistic process simulation study has been performedas a part of the development planning.

What Should Be Done to Reduce the Uncertaities? The accept-able levels of uncertainty are, in principle, the levels where acost/benefit estimate of further efforts to reduce the uncertaintywould give a negative result. These levels vary from field to field,depending on the need and cost for reducing the uncertainties. Theimportance of reliable reservoir fluid data is often greatest duringdevelopment planning and process design for expensive offshorefield developments.

The cost of offshore drilling and testing of exploration wells isgenerally much higher than the cost of sampling, laboratory stud-

ies, and data evaluation. Extensive routines for wireline and sur-face sampling and evaluation of test separator gas-oil ratio mea-

surements, PVT sample representativity, and PVT analysis resultshave thus proved to be cost effective. A full PVT analysis pro-gram should usually not be performed unless the reservoir fluidsamples are judged to be representative; PVT simulation based onthe composition may give equally reliable results when the samplerepresentativity is questionable.

The results from uncertainty analysis should be used in theplanning of further data acquisition. The need of a reduction of theuncertainties in fluid parameters is, for instance, often a strongargument for drilling an exploration well or performing a drill-stem test.

Timing and combined use with other types of data should alsobe evaluated in relation to cost. If, for instance, a well test includ-ing PVT sampling can be postponed until the field is on produc-tion, the cost may be strongly reduced. Detailed compositional

results from the PVT analysis are often used together withgeochemical data in the mapping of probable barriers in the res-ervoirs. Test separator gas-oil ratio measurements and stock-tankanalysis results may also contribute to the mapping of the varia-tions in PVT data over the field.

SummaryEstimates of the uncertainties in the reservoir fluid descriptionmay have an impact on important economical decisions regardingdevelopment of oil and gas condensate fields.

Lack of representative samples from important reservoir zones,and possible variations in fluid parameters over the reservoirs, areusually identified as dominating uncertainty factors in the explo-ration phase. The uncertainty with regard to the representativity ofKeith Sawdon, BP, U.K., personal communication, 1996.

Fig. 2Illustration of the total uncertainty in modeling of aver-age fluid parameters for gas condensate aboveand reservoiroil below.

434 K.K. Meisingset: Reservoir Fluid Description SPE Reservoir Eva l. & Eng., Vol. 2, No. 5, October 1999

7/21/2019 SPE-57886-PA.pdf

5/5

wireline samples or PVT samples from drill-stem tests with ques-tionable sampling conditions, is often significant. The same is thecase for measured and calculated viscosities. Uncertainties in thedescription of the processing plant for gas condensate fields maycontribute significantly to the uncertainty in the condensate-gasratio, until the processing concept has been chosen.

The uncertainties in the reservoir fluid description are usuallyreduced significantly during the production phase Figs. 1 and 2,

not only due to additional PVT sampling and laboratory analysis,but also on the basis of test separator gas-oil ratio measurementsfor each production well, and measurements of product streamsfrom the field. Estimated ranges for the contribution from differ-ent sources to the total uncertainty for relevant fluid parameters,are shown in Table 2.

Nomenclature

B O oil formation volume factor, defined as the ratio ofthe oil volume at reservoir conditions and the oil vol-ume at standard conditions after the processing plant

B G gas formation volume factor, defined as the ratio ofthe gas volume at reservoir conditions and the gasvolume at standard conditions after the processingplant, not including condensed liquid

B W

formation water volume factor, defined as the ratio ofthe water volumes at reservoir and standard condi-tions

RS solution gas-oil ratio, defined as the ratio of the gasand oil volumes at standard conditions after the pro-cessing plant

RSG condensate-gas ratio, defined as the ratio of the con-densate and gas volumes at standard conditions afterthe processing plant

O oil viscosity at reservoir conditionsG gas viscosity at reservoir conditionsW formation water viscosity at reservoir conditions

AcknowledgmentsI thank Statoil for the permission to publish this paper, Ann Lis-beth Blilie for providing formation-water field examples, and Jan

Ole Aasen and Adolfo Henriquez for advice and encouragement.

References

1. Norwegian Petroleum Directorate: Annual report 1996 Stavanger,

1997. ISBN 82-7257-526-4.

2. Geology of the Norwegian Oil and Gas Fields, Norwegian Petroleum

Society, A.M. Spencer et al. ed., Graham & Trotman, Ltd., U.K.

1987 ISBN 08-6010-908-9.3. Caldwell, R.H. and Heather, D.I.: How To Evaluate Hard-To-

Evaluate Reserves, JPTAugust 1991 998 .

4. Kingston, P.E. and Niko, H.: Development Planning of the Brent

Field, JPTOctober 1975 1190.5. Schulte, A.M.: Compositional Variations Within a Hydrocarbon

Column Due to Gravity, paper SPE 9235 presented at the AnnualTechnical Conference and Exhibition, Dallas, 2124 September

1980.

6. Chen, H.K., Robinson, T., Harker, S.D., and Mayer, C.E.: The Main

Area Claymore Reservoir, a Review of Geology and Reservoir Man-

agement, SPEFEJune 1989 231 ; Trans., AIME, 287 .

7. Dixon, L.A.: The Importance of Sampling and Analysis of NaturalGas for the Design of Production and Downstream Facilities, in

Proceedings of the 10th Annual Convention of the Indonesian Petro-

leum Association, Jakarta, May 1981, pp. 495500.

8. Osjord, E.H., Rnningsen, H.P., and Tau, L.: Distribution of

Weight, Density and Molecular Weight in Crude Oil Derived from

Computerized Capillary GC Analysis, J. High Res. Chrom. Chrom.

Commun.1985 8 , 683.

SI Metric Conversion Factors

bar 1.0* E05 Pacp 1.0* E03 Pa s

*Conversion factors are exact. SPEREE

Knut Kristian Meisingset is a technical advisor for composi-tional reservoir simulation at Statoil, where he has worked withPVT simulation and evaluation of reservoir fluid data since1983. He holds an MS degree in biophysics from the U. of Oslo.

TABLE 2 TYPICAL CONTRIBUTIONS TO THE UNCERTAINTYOF RELEVANT FLUID PARAMETERS

Fluid Parameter

Typical Contributions to the Uncertainty in Fluid Parameters From:

VariationsOver the Field

Fluid Samples ofNormal Quality

From Well Testing

Uncertainty inPVT LaboratoryMeasurements

Uncertaintiesin The Process

Description

Rs 2 to 20% 1 to 10% 3 to 10% 2 to 10%

BO 1 to 10% 0.5 to 3% 1 to 3% 1 to 3%

O 5 to 30% 2 to 10% 10 to 30%

RSG 5 to 30% 5 to 10% 5 to 15% 5 to 50%

BG 2 to 10% 2 to 4% 1 to 4% 2 to 15%G 5 to 30% 5 to 10% 10 to 30%

Salinity ofFormation Water

1 to 20% 2 to 20% 2%

K.K. Meisingset: Reservoir Fluid Description SPE Reservoir Eval. & Eng., Vol. 2, No. 5, October 1999 435