integrated oil pvt characterization

Special Edition 1999, Volume 38, No. 13 Journal of Canadian Petroleum TechnologyPAPER: 97-05

Introduction

Integrated reservoir studies are usually initiated after the reser-voir in question has been on production for many years. This pro-vides sufficient data on field performance to ensure that somematching of calculations to actual history can be done. To conductsuch studies, engineers generally have to use available dataincluding existing PVT data. In most cases the existing PVT data,which may have been collected right after completion of the initialdevelopment wells before field production or after many years ofproduction, can show considerable inconsistency. In addition,some key data may not have been measured or some of the datamay not reflect actual reservoir performance, such as gas-oil ratio(GOR). It is, therefore, important from the outset of a project tocheck the consistency of available PVT data with the productiontest data and with the geological description before using it in areservoir simulation study.

EOS models are used by engineers to identify such inconsisten-cies in the PVT data and to calculate data which may not havebeen measured or is obviously incorrect. Before an EOS can beused, one must first correctly tune its parameters(1), that is, charac-terize the oil. Hence oil characterization plays an important role inthe integrated reservoir study. Correct fluid characterizationenables accurate EOS fluid property predictions which can pro-vide useful information about reservoir description and compart-mentalization, as well as properly defining fluid behaviour forengineering calculations. In this paper we use four actual fieldexamples to illustrate the procedures used.

EOS Oil CharacterizationReservoir fluids are comprised of a very complex mixture of

naturally occurring compounds. These compounds are principallyhydrocarbons ranging from methane to asphalt. There are no fixedrules on the distribution of hydrocarbons in reservoirs. Fluids inreservoirs can exist as either single phase (gas or liquid), twophase (gas and liquid) or multi-phase (gas, liquid, liquid) fluidsdepending on the reservoir conditions and the components pre-sent. The ability to predict production rates, optimize productionstrategies and design production facilities depends on a knowl-edge of the properties of the reservoir fluid, not just at the originalreservoir conditions, but also at a great many conditions on thesubsequent depletion and production path.

It is usually impractical, due to cost, time or lack of sufficientsample, to conduct laboratory analyses for such a wide range ofconditions. In order to predict typical fluid properties and phasebehaviour of hydrocarbon fluids, engineers have increasingly beenusing predictive EOS techniques. But EOS’s are semi-empiricalcorrelations which require some physical PVT data to tune theirparameters. Unfortunately, the measured PVT data can be in erroror some of it may be missing. A very good understanding of PVTanalysis procedures and of the parameters needed to correctly tunethe EOS is, therefore, needed.

In this study the reservoir fluids were characterized(1) using onepseudocomponent (C7+). The reason is that under conditions nor-mally encountered in production and facility operations, the C7+concentration in the gas phase is usually less than 1 mole per cent,especially at reservoir conditions. This means that the C7+ in theliquid phase generally stays there. All EOS packages using morethan one pseudocomponent use correlations to generate therequired parameters which are derived from grouping of pseudo-components based on boiling point range(2) and this data is gener-ally not available for old PVT analyses. The procedure(1) requiresonly C7+ MW (molecular weight) and C7+ SG (specific gravity).A commercially available PVT package was used in this studyand in this PVT package, four different correlations were avail-able to generate the heavy end properties. They are Kesler-Lee(3),Edmister(4), Cavett(5) and Riazi-Daubert(6).

Field ApplicationsFour practical field applications are used here to illustrate:1. How to identify small pools and zones in one geological

structure,2. How to sort out representative fluid properties for each

formation,3. How to check for consistency and accuracy of fluid sam-

pling procedures and laboratory fluid property measure-ments, and

Integrated Oil PVT Characterization—Lessons From Four Case Histories

R. WU, L. ROSENEGGERTeknica Petroleum Services Ltd.

AbstractOil characterization plays an important role in integrated geo-

physical, geological and reservoir engineering studies. Fromproject inception, correct fluid characterization can provide use-ful information about reservoir description and compartmental-ization as well as properly defining fluid behaviour for engineer-ing calculations. In this paper four field examples are presentedto illustrate (1) how to use equation of state (EOS) oil character-ization to check the accuracy of fluid sampling procedures andlaboratory fluid property measurements, and (2) how to use EOSoil characterization to check for consistency between the geolog-ical/geophysical reservoir description and actual field perfor-mance (e.g., produced gas-oil ratio). This results in a betterreservoir model and makes further engineering and simulationtasks much easier.

4. The difference between C30+, C20+, and C7+ characterization.

How to identify small pools and zones in one geological structure

Six PVT reports, two for each of the three producing wells (#1,#6, and #8), were available for Reservoir 1 (Figure 1). There weresome minor differences between the two reports for each well, butthere were large differences between the three wells. The first taskwas to identify whether these three wells were in three differentpools separated by sealing faults and, if so, to select the most rep-resentative PVT for each well.

The three wells (Figure 1) penetrate a deep sandstone reservoirin what has been postulated as a wrench fault system. Due to thedepth of the structure and the quality of the seismic data it wasdifficult to accurately interpret the normal faults usually associat-ed with such a system. Well spacing is 0.82 and 0.69 milesbetween wells #1 and #8 and between wells #8 and #6, respective-ly. Based on the available static reservoir pressures for wells #1,#6, and #8 (Figure 2), it was initially thought that the three wellswere in a single reservoir with some restricted communicationbetween the wells, since their pressure was declining at approxi-mately the same rate. However, the PVT data revealed that thefluids from these three wells were behaving differently. The fol-lowing outlines the procedure that was used to resolve these differences.

Table 1 lists the bubble point pressure (Pb), gas-oil ratio(GOR), sample type, and sample depth for the six available PVTtests. The fluids were all sampled between 4,223 to 4,375 m(13,852 to 14,350 ft.) SS, but the saturation pressures ranged from35,405 to 22,360 kPa (5,135 to 3,243 psia) and the GOR varied

from 295 to 137 m3/m3 (1,658 to 772 scf/bbl). Note that Pb in eachtest is consistent with the GOR (i.e., GOR increases with increas-ing Pb). Both the Pb and GOR data indicate that these three fluidsare different reservoir oils. However, as noted above, the staticreservoir pressures show that the three wells declined as if in onereservoir, especially wells #1 and #8 (Figure 2). Based on this itwas difficult to say with certainty that the three well fluids weredifferent. Calculations showed that the expected difference in sat-uration pressure due to the elevation differences between thesewells should only be about 1,379 kPa (200 psi), much less thanthe observed differences in the PVT data. To check the consisten-cy of the PVT measurements, the three reservoir fluids were char-acterized(1) using the Peng-Robinson equation of state (PREOS).We were able to match both the Pb and the GOR with the givenC7+ MW and C7+ SG, so we believe that these PVT data are accu-rate. Figures 3 to 5 demonstrate the accuracy of the tuned PREOSwith very good agreement between the predicted oil density, thepredicted oil formation factor (Bod), and the predicted solutiongas-oil ratio (Rsd) with the measured experimental data in the dif-ferential liberation tests for wells #1, #6, and #8. Table 2 furthershows the good agreement of the predicted flash gas compositionsat different stages in the differential liberation with measuredexperimental data for well #1.

To confirm the PVT data and PREOS predictions, data fromwell test reports, as summarized in Table 3, was used. The welltest conditions were similar and the duration of the tests was longenough to be reliable. Based on the GORs of the early tests, whichwere all run with the reservoir(s) above the indicated Pb, one canclearly separate well #6 from wells #1 and #8 since its GOR issignificantly lower than the other two (125 vs. 214 m3/m3).

2 Journal of Canadian Petroleum Technology

FIGURE 1: Structure map for Reservoir 1. FIGURE 2: Static pressure history for Reservoir 1.

FIGURE 3: Comparison of oil densities for Reservoir 1 measuredand EOS predicted.

FIGURE 4: Comparison of oil formation volume factor forReservoir 1 measured and EOS predicted.

The GOR and static pressures from the production historieswere plotted for each of the three wells in Figures 6 to 8. Figure 6shows the static pressure and produced GOR for well #1. The pro-duced GOR started to increase in June to December 1987, just alittle after the reservoir pressure declined below its saturationpressure and was also consistent with the well test data in Table 3.At that date the corresponding static pressure was about 35,163kPa (5,100 psia). This indicates that the Pb of 35,198 to 35,400kPa (5,105 to 5,135 psia) from PVT data is correct. The last GORtest for well #1 (1991) is very high. While the bottom hole pres-sure (BHP) was not recorded, the high GOR of this well test alsoagrees with the produced GOR. Separating the data above andbelow 35,163 kPa (5,100 psia), one can see two trends in the staticpressure data. The slope of the pressure data above Pb is steeperthan that below Pb. The first slope is due to reservoir declineunder fluid and rock expansion, while for the second, after thepressure drops below Pb, solution gas expansion is the dominantproduction mechanism.

Figure 7 shows the produced GOR and static pressure for well#8. Although the pressure is similar to well #1, the produced GORonly started to increase after June 1992, having remained constantuntil then. The corresponding reservoir pressure is about 27,580kPa (4,000 psia). While this is below Pb (29,260 kPa or 4244 psia)from PVT data, the delay could be due to the time needed to build

up a critical gas saturation. Test data of Table 3 was too early inthe life of the well. The last reservoir pressure point at 26,062 kPa(3,780 psia) and the increased GOR to about 256 m3/m3 (1,440scf/bbl) further verify the saturation pressure. The producedGORs for wells #1 and well #8 are, therefore, consistent with thePVT data and, thus, indicate that the wells are in different pools.That is, they are separated by sealing faults and contain differentoils, even though they are in the same geological formation.

Figure 8 shows the produced GOR and static pressure for well#6. The produced GOR remained constant at about 139 m3/m3

(780 scf/bbl) up to the end of 1989 when the well was shut-in. Thelast pressure at that time was about 27,579 kPa (4,000 psia), wellabove the PVT measured Pb of 22,360 to 25,180 kPa (3,243 or3,652 psia). Tests after this date show a rising pressure trend, indi-cating that this well is also in a separate pool with a good edgewater drive from the east. The GORs for this well remained con-stant because it always produced above Pb and thus both the PVTdata and the well test GORs are consistent. This implies that well#6 is separated from, and does not communicate with, well #8.

Based on the above analysis and EOS characterization, Table 4summarizes the PVT data, fluid compositions, C7+ MW, and C7+SG that were used for each well in the ensuing integrated reser-voir study (1986, 1968, and 1982 PVT reports for well #1, #6, and#8 respectively).

Special Edition 1999, Volume 38, No. 13 3

TABLE 1: Comparison of bubble point pressure and GOR for PVT tests from Reservoir 1.

Well # 1 1 6 6 8 8

Year 1966 1986 1968 1986 1982 1986

Top (m SS) 4,272 4,223 4,318 4,271 4,223 4,223

Bottom (m SS) 4,291 4,299 4,375 4,375 4,334 4,334

Pb (kPa) 35,198 35,405 22,360 25,180 31,468 29,261

GOR (m3/m3) 295 295 137 156 226 195

Sample Type Surface BHS Surface BHS BHS BHS

Used in Study Yes Yes Yes

TABLE 2: Comparison of measured and PREOS predicted gas compositions—Well #1.

P (kPa) 33,440 2,9523 23,635 17,754 11,866 5,985

Component Meas EOS Meas EOS Meas EOS Meas EOS Meas EOS Meas EOS

CO2 3.26 3.14 3.29 3.20 3.36 3.32 3.45 3.49 3.64 3.77 3.95 4.20

N2 0.91 0.88 0.89 0.84 0.82 0.78 0.70 0.67 0.56 0.52 0.30 0.32

C1 71.47 73.54 72.25 73.76 72.94 76.64 73.01 72.79 71.57 70.46 65.70 63.62

C2 11.94 11.77 11.97 11.97 12.11 12.41 12.50 13.16 13.62 14.62 16.70 18.00

C3 5.13 4.88 5.04 4.92 4.97 5.06 4.99 5.34 5.40 5.98 7.70 7.92

C4 2.70 2.31 2.59 2.20 2.45 2.48 2.38 2.71 2.48 2.71 3.24 3.61

C5 1.29 1.07 1.15 1.01 1.08 1.00 1.02 1.04 0.98 1.04 1.22 1.31

TABLE 3: Well test data summary—Reservoir 1 .

Well # Date Depth Duration BHP WHP Separator GOR

(m) (hrs) (kPa) (kPa) T (˚ C) P (kPa) (m 3/m3)

1 Jan-83 4,225 48.5 37,645 9,170 48.9 2,034 212

1 Jun-87 4,223 29.3 25,993 7,653 60.0 2,068 247

1 May-91 5,550 51.7 2,103 531

6 Feb-81 4,314 27.0 30,268 46.1 1,586 137

6 Mar-83 4,314 39.0 31,440 6,543 43.3 1,862 125

6 May-84 4,314 31.3 30,544 5,929 67.2 3,827 102

6 May-84 4,314 20.0 28,296 5,929 64.4 1,069 149

8 Jul-84 4,103 26.2 31,674 8,618 71.1 2,413 206

8 Dec-84 4,103 29.5 31,674 10,053 71.1 2,413 224

8 Mar-87 4,334 24.5 22,587 5,323 47.8 2,448 201

How to sort out representative fluid properties for each formation

Sixty-five wells were drilled in Reservoir 2 (Figure 9) which isa carbonate reservoir with two main producing horizons (Upperand Lower). The field itself is split into two distinct areas (North

and South) and all evidence points to hydraulic separationbetween the two horizons while the two areas may be connectedthrough common aquifers.

Eight sets of PVT data were available, all from bottom-holesamples, from three of the four producing zones (Upper South,Lower South, Lower North and one commingled Upper & LowerSouth sample from well #1). This data is summarized in Table 5.For the reservoir study we needed to decide whether the fluids inthe Upper and Lower horizons and in the North and South werethe same or different and to determine the most representativePVT sample for each zone. We used the eight available sets offluid compositions and their measured bubble point pressures toidentify each zone. Then the Peng-Robinson equation of state wasused to check this PVT data for consistency.

From the eight data sets, we can readily identify the Upper andLower North zones. There are 4 PVT data sets (wells #2, #3, #27,and #50) from the Upper North and these seem to be good sincethe basic indicators (Pb, GOR, and C7+ concentration) are consis-tent between the 1963 and 1988 data. Two data sets (wells #10and #14) from the Lower North zone also show like Pb and GOR.The difference between Upper and Lower North is the variation ofPb (2,413 vs. 3,585 kPa or 350 vs. 520 psia) and GOR (68 vs. 91m3/m3 or 380 vs. 510 scf/bbl) so we can easily say that they aredifferent oils. Other evidence is that the oil from Lower Northcontained H2S (hydrogen sulphide) while that of the Upper Northzone did not. This interpretation of separate horizons with differ-ent oil is consistent with the geological description.

The problem occurs in trying to separate the PVT for the Southarea. Only two sets of PVT data were available from this area.


FIGURE 5: Comparison of solution gas-oil ratio for Reservoir 1measured and EOS predicted. FIGURE 7: Pressure and gas-oil ratio for Well#8—Reservoir 1.

FIGURE 6: Pressure and gas-oil ratio for Well#1—Reservoir 1. FIGURE 8: Pressure and gas-oil ratio for Well#6—Reservoir 1.

TABLE 4: Summary of PVT data for Reservoir 1 .

Well No. 1 6 8

N2 0.0049 0.0047 0.0047

CO2 0.0277 0.025 0.0275

C1 0.5319 0.4317 0.4759

C2 0.1169 0.1149 0.113

C3 0.0585 0.0654 0.0617

IC4 0.0124 0.0138 0.0133

NC4 0.0226 0.028 0.0256

IC5 0.0084 0.0101 0.0094

NC5 0.0102 0.0134 0.0119

C6 0.0223 0.0297 0.0257

C7+ 0.1842 0.2633 0.2313

C7+SG-EOS 0.8655 0.8518 0.8645

C7+MW-EOS 252 240 240

C7+MW-Meas 250 240 240

Pb-EOS(kPa) 35,411 25,193 29,234

Pb-Meas(kPa) 35,198 22,360 29,261

One sample (well #11) was from the Upper South zone and onewas commingled from the Upper and Lower South zones (well#1). These two data sets showed some inconsistency in Pb andGOR in that the GOR was higher with a lower Pb for the UpperSouth. The details of the eight sets of fluid compositions are givenin Table 6.

To resolve the problem, we needed to carefully consider theH2S concentration (last column of Table 5). H2S content is one ofthe most important parameters for identifying reservoir fluid com-positions. Samples from wells #1, #10, #11, and #14 all containedH2S. Wells #11 and #14 are from the Lower North zone with H2Sdefinitely present. Samples from the Upper North zone from wells#2, #3, #27 and #50 contain no H2S in contrast to the South wheretwo samples (wells #1 and #11) both contain H2S. But the H2Sconcentration in well #11 (Upper South only) is very small, 0.02mole per cent. On other hand, the sample from well #1 contains ahigher H2S concentration, 0.51 mole per cent. One could therefore

consider that the H2S content in well #11 was due to contamina-tion. Assuming no H2S in well #11 (Upper South), then the Pb andGOR data of well #11 are the same as those of samples from theUpper North zone. Hence one PVT data set can be used to repre-sent both the Upper North and South reservoir zones. As therewas no separate sample from the Lower South zone and based onthe H2S concentration of well #1, we had to assume that the fluidin the Lower South was the same as in the Lower North zone. Toconfirm this conclusion we requested a sample from a non-com-mingled well in the Lower South zone.

With a small adjustment of C7+ MW and C7+ SG, we were ableto match Pb and GOR simultaneously for these PVT data. Table 6summarizes the fluid compositions and shows the measured C7+MW and C7+ SG and the values used in the EOS. Note that onecan also use the C7+ MW to separate the Upper and Lower zones


FIGURE 9: Structure map for Reservoir 2.

TABLE 5: Summary of PVT data—Reservoir 2.

PVT Prod Test Viscosity

Well T Pb GOR GOR (cp) H 2S

# Sample Date Zone (˚ C) (kPa) (m 3/m3) (m3/m3) API @Pb B ob Mole%

1 Oct-61 U&L-S 64.4 2,432 25.3 33.5 1.77 1.135 0.51

2 Apr-60 U-N 53.3 2,597 22.1 11.8 33.8 3.04 1.102 0

3 Dec-63 U-N 60.6 2,618 19.1 11.8 36.6 2.66 1.107 0

10 Dec-63 L-N 65.0 3,487 17.3 11.8 32.4 3.30 1.087 1.41

11 Dec-63 U-S 62.8 2,577 20.1 36.2 2.72 1.108 0.02

14 Dec-63 L-N 63.3 3,583 16.9 11.8 32.1 3.69 1.080 0.49

27 Aug-88 U-N 58.9 2,482 21.2 11.0 36.3 1.86 1.110 0

50 Aug-88 U-N 56.7 2,392 22.1 11.2 37.0 1.95 1.117 0

FIGURE10: Comparison of solution gas-oil ratio for Reservoir 2measured and EOS predicted.

FIGURE 11: Comparison of oil formation factors for Reservoir 2measured and EOS predicted.

(220 vs. 255). To demonstrate that the tuned EOS can match othermeasured properties, Figures 10 and 11 compare the differentialliberation (DL) measured and the calculated oil formation volumefactor (Bod) and solution gas-oil ratio (Rsd) for well #1.

How to check for consistency and accuracy of fluid sampling pro-cedures and laboratory fluid property measurements

Reservoir 3 contains 15 wells. This clastic reservoir is highlyfractured and faulted and all parts of the reservoir appear to be inpressure communication. Four surface sample analyses wereavailable from three different labs as shown in Table 7. The Pb ofthese samples varies from 25,010 to 28,655 kPa (3,627 to 4,156psia) and the solution GOR ranges from 346 to 683 m3/m3 (1,943to 3,833 scf/bbl). Hence, the Pbs are consistent with the GOR’s. Itappears however that the surface samples were recombined to dif-ferent GORs, this being the only explanation for the difference inthe Pbs among them. The questions then were (1) how accurate arethe recombined PVT measurements and (2) which PVT data set(i.e., what recombination GOR) can be used to best represent thereservoir fluid.

To check the laboratory fluid property measurements, we usedthe same procedure as in the previous two applications. Weadjusted the given C7+ MW and C7+ SG to match the measured Pband then predicted the GOR. With only a slight or no change tothe measured C7+ properties, we were able to match the measuredPbs (Table 7). Note that in the EOS, the C7+ MW used only variedfrom 175 to 180 while the C7+ SG ranged from 0.83 to 0.856.With such small variation of these parameters, one can considerthat the characterization of these fluids is similar. This agrees withthe geological description. However, as summarized in Table 7,there is a large difference between the measured and EOS calcu-lated solution GOR (Rsd) for differential liberation (DL) processesfor wells #1, #9, and #14. The difference is greater than 50%.

To resolve this, we compared two available single stage flashGORs, one from the first stage of DL and the other from the sepa-rator test results (Table 8). The parameter used in this table is thepressure drop (∆P). Note that the smaller ∆P from the DL mea-surement gives a much higher evolved GOR per kPa of ∆P thanthe larger ∆P from the separator test data. In well #1 for example,a ∆P of 4,282 kPa (621 psi) from the DL produced a GOR of 220m3/m3 (1,233 scf/bbl) while a ∆P of 22,856 kPa (3,315 psi) only


TABLE 6: Oil compositions and characterization summary—Reservoir 2.

Well # 1 2 3 10 11 14 27 50

T (˚ C) 64.4 53.3 60.0 64.4 62.2 62.8 58.9 56.7

N2 0.0021 0.0088 0.003 0.0035 0.0031 0.0029 0.0033 0.0041

CO2 0.0075 0.0134 0.0001 0.0056 0.0028 0.0046 0.0035 0.0026

H2S 0.0051 0 0 0.0141 0.0002 0.0049 0 0

C1 0.0605 0.0563 0.0714 0.0999 0.068 0.1075 0.0672 0.0614

C2 0.0259 0.0251 0.0154 0.0145 0.0198 0.0111 0.0219 0.0238

C3 0.0583 0.046 0.0371 0.0187 0.0401 0.0158 0.0404 0.0471

IC4 0.0186 0.015 0.0119 0.01 0.0115 0.0107 0.0129 0.0147

NC4 0.0583 0.0581 0.0612 0.0264 0.0547 0.0261 0.0425 0.048

IC5 0.0288 0.0264 0.0307 0.0205 0.0282 0.0242 0.0237 0.0253

NC5 0.0326 0.0335 0.0358 0.0242 0.0375 0.0161 0.0293 0.0311

C6 0.0542 0.0471 0.0619 0.0523 0.0665 0.0475 0.0447 0.0468

C7+ 0.6481 0.6703 0.6715 0.7103 0.6676 0.7286 0.7106 0.6951

C7+SG-EOS 0.857 0.852 0.863 0.8575 0.858 0.858 0.8526 0.857

C7+SG-Meas 0.857 0.855 0.8595 0.8722 0.8579 0.8612 0.858 0.86

C7+MW-EOS 220 225 220 255 220 250 225 225

C7+MW-Meas 231 224 233 258 237 261

Pb-EOS (kPa) 2427 2599 2620 3489 2579 3585 2482 2406

Pb-Meas (kPa) 2427 2599 2620 3489 2579 3585 2482 2392

FIGURE 12: Gas-oil ration and pressure history—Reservoir 3.FIGURE 13: Rsd and Bod for recombined reservoir fluid—Reservoir 3.

yielded a GOR of 289 m3/m3 (1,622 scf/bbl) from the separatortest. Similar results were noted for wells #9 and #14. Physically,one would have to suspect some measurement error in the DLexperiments. The error was likely induced because the amount ofgas phase present was small at the high pressure for the first stageof the DL experiment. During the process of removing the gasphase, some amount of oil was likely displaced out of the cell.Counting some of the oil as gas volume would result in a highermeasured GOR from this first stage of the DL process. If thiswere the case, we would believe in the EOS prediction rather thanthe measured results. To verify our observation, Table 9 showstwo and three stage separator flash GORs. The EOS calculatedGORs generally compare very well with the measured separatorflash GORs, leading us to accept the flash rather than the differen-tial data.

Figure 12 shows all available field produced GORs and themeasured pressures and can be used to resolve the second pointabout which PVT data should be used for the reservoir study. TheGOR varies from 249 to 392 m3/m3 (1,400 to 2,200 scf/bbl) withan average produced GOR around 321 m3/m3 (1,800 scf/bbl). Asshown in Table 8, except for the data from well #3, all the otherDL data sets had measured GOR’s greater than 434 m3/m3 (3,000scf/stb) and thus should not be used. The separator test gas andliquid compositions from well #3 were used for a mathematicalrecombination to a GOR of 321 m3/m3 (1,800 scf/bbl). The EOScalculated oil formation factor (Bod) and solution gas-oil ratio(Rsd) data is shown in Figure 13.

The difference between C30+, C20+, and C7+ characterization

Reservoir 4 is a broad reef rimmed carbonate buildup covering


TABLE 7: Oil compositions and characterization results—for Reservoir 3.

Well No 1 3 9 14

Date Sep-89 Jul-87 Mar-93 Feb-93

T (˚ C) 146.1 154.4 156.7 153.9

N2 0.0003 0.0052 0.0034 0.0038

CO2 0.0839 0.0647 0.071 0.0703

C1 0.4743 0.3958 0.4843 0.4873

C2 0.1029 0.1068 0.0924 0.0893

C3 0.0612 0.0727 0.0584 0.0548

iC4 0.0123 0.0173 0.0139 0.0128

nC4 0.0297 0.0355 0.03 0.0277

iC5 0.0134 0.0185 0.0147 0.0139

nC5 0.0155 0.018 0.0174 0.0161

C6 0.0205 0.029 0.0228 0.0214

C7+ 0.1861 0.2367 0.1917 0.2026

Meas EOS Meas EOS Meas EOS Meas EOS

C7+SG 0.83 0.83 0.858 0.856 0.805 0.835 0.805 0.8335

C7+MW 180 180 178 176 183 175 181 175

Pb (kPa) 27,579 27,579 25,007 25,014 28,144 28,151 28,654 28,654

GOR@std (m3/m3) 416 388 278 296 368 367 391 364

GOR(DL)(m3/m3) 632 417 346 323 648 406 683 393

Sample Type Surface Surface Surface Surface

Sep.Conditions

Sep Pres (kPa) 1620

Sep T(˚ C) 57.2

Reservoir P (kPa) 38,601 35,446 35,446

Company Lab #1 Lab #2 Lab #3 Lab #3

TABLE 8: Comparison of single stage flash (m 3/m3).

Well #1 Well #3 Well #9 Well #14

Source ∆P GOR ∆P GOR ∆P GOR ∆P GOR

1st Stage of DL 4,282 220 2,848 102 1,717 180 2,365 248

Separator 22,856 289 22,146 243 23,814 227 24,311 256

TABLE 9: Two or three stage flash GOR (m 3/m3).

Well #1 Well #3 Well #9 Well #14

P (kPa) Meas EOS P (kPa) Meas EOS P (kPa) Meas EOS P (kPa) Meas EOS

4,619 289 347 2,861 243 221 4,240 227 252 4,240 256 251

103 40 37 103 32 60 793 42 43 793 42 41

103 24 25 103 24 24

about 32 square miles. Over 230 exploration and developmentwells were drilled in this field which has been on production sincelate 1964. Ten PVT reports were available from nine wells assummarized in Table 10. The measured bubble point pressurefrom these tests varies from 3,709 to 9,770 kPa (538 to 1,417psia) and the solution GOR varies from 39 to 86 m3/m3 (219 to

484 scf/bbl). Some of the oil compositional analyses are up toC30+ and they were conducted by 2 different laboratories. Hence,this data set provides a good opportunity to see the difference inC30+, C20+, and C7+ characterization. In addition, a representativefluid composition for simulation and enhanced oil recovery appli-cation had to be selected.


TABLE 10: EOS characterization of reservoir fluid composition summary—Reservoir #4 .

Well N5 N118B N118S N134 N51 S4 S26 S59 S65 S84

T (˚ C) 68.9 69.4 68.9 69.4 68.9 68.9 68.9 68.9 65 71.4

N2 0.0053 0.0078 0.0060 0.0113 0.0037 0.0054 0.0139 0.0068 0.0039 0.0102

CO2 0.0012 0.0010 0.0012 0.0013 0.0002 0.0018 0.0028 0.0016 0.0014 0.0012

C1 0.2280 0.2064 0.2371 0.2545 0.1728 0.2162 0.2132 0.2284 0.2140 0.1976

C2 0.0645 0.0580 0.0718 0.0699 0.0611 0.0603 0.0621 0.0628 0.0640 0.0552

C3 0.0851 0.0705 0.0871 0.0960 0.0823 0.0839 0.0811 0.0783 0.0743 0.0689

IC4 0.0116 0.0151 0.0146 0.0155 0.0121 0.0158 0.0139 0.0142 0.0109 0.0102

NC4 0.0544 0.0539 0.0539 0.0632 0.0426 0.0552 0.0498 0.0482 0.0397 0.0385

IC5 0.0210 0.0264 0.0229 0.0263 0.0164 0.0204 0.0274 0.0206 0.0184 0.0187

NC5 0.0261 0.0331 0.0288 0.0330 0.0212 0.0271 0.0110 0.0257 0.0250 0.0262

C6 0.0424 0.0511 0.0285 0.0188 0.0396 0.0385 0.0545 0.0344 0.0445 0.0267

C7+ 0.4604 0.4767 0.4481 0.4102 0.5480 0.4754 0.4703 0.4790 0.5039 0.5466

C7+SG-EOS 0.8596 0.8571 0.8514 0.8507 0.8400 0.8597 0.8683 0.8683 0.8418 0.8496

C7+SG-Meas 0.8638 0.8680 0.8509 0.8627 0.8699 0.8636

C7+MW-EOS 242 237 238 237 250 239 257 226 245 247

C7+MW-Meas 242 238 242 236 257 226

Pb-EOS (kPa) 9,135 8,336 9,563 9,767 5,787 8,667 8,412 9,698 7,751 7,943

Pb-Meas (kPa) 9,136 8,336 9,563 9,770 3,709 8,667 8,412 9,701 7,750 7,943

GOR@std (m3/m3) 62 62 69 86 39 58 55 64 57 49

Additional Information

Sample Date May-63 Jan-95 Dec-89 Jan-95 Jan-70 Oct-67 Nov-75 May-94 Jan-95 Jan-95

Sample Type BHS BHS Sep S. BHS BHS Flowing BHS Sep S. BHS BHS

Sample Depth (m) 1,423 1,680 1,680 1,678 1,560 1,593 1,665

Sample P (kPa) 1,7092 13,341 11,969 15,003 17,168 13,996 8,915 11,204

Sep. P (kPa) 545 448 531 531

Sep. T (˚ C) 30.6 24.4 16.7 16.7

Sep GOR (m3/m3) 63 80 67 50 49

Lab #1 #2 #1 #2 #2 #1 #2 #1 #2 #2

TABLE 11: Comparison the EOS results with separator gas compositions .

Well No. S43 S65 N124 S60 S4 S4 S4Sample Date 12-Jul 6-Feb 12-Jul 12-Jul 24-Feb 24-Feb 24-FebSep T (˚ C) 56 9 52 53 27 38 49Sep P (kPa) 393 414 448 434 552 552 552

EOS Meas. EOS Meas. EOS Meas. EOS Meas. EOS Meas. EOS Meas. EOS Meas.

N2 0.0145 0.0167 0.0179 0.0214 0.0150 0.0160 0.0148 0.0166 0.0173 0.0200 0.0164 0.0196 0.0156 0.0175

CO2 0.0027 0.0050 0.0031 0.0072 0.0028 0.0094 0.0028 0.0150 0.0030 0.0067 0.0029 0.0067 0.0029 0.0065

C1 0.5623 0.5466 0.6816 0.6520 0.5793 0.5659 0.5736 0.5602 0.6573 0.6608 0.6281 0.6258 0.6016 0.5990

C2 0.1540 0.1492 0.1555 0.1600 0.1552 0.1484 0.1548 0.1447 0.1553 0.1465 0.1562 0.1455 0.1556 0.1461

C3 0.1520 0.1619 0.1039 0.1169 0.1468 0.1553 0.1486 0.1507 0.1154 0.1108 0.1284 0.1295 0.1386 0.1366

IC4 0.0184 0.0195 0.0081 0.0098 0.0169 0.0168 0.0174 0.0181 0.0102 0.0111 0.0126 0.0134 0.0150 0.0159

NC4 0.0582 0.0602 0.0215 0.0225 0.0522 0.0551 0.0542 0.0550 0.0285 0.0293 0.0367 0.0380 0.0451 0.0466

IC5 0.0148 0.0139 0.0037 0.0033 0.0126 0.0126 0.0133 0.0131 0.0055 0.0055 0.0077 0.0078 0.0104 0.0106

NC5 0.0155 0.0139 0.0034 0.0031 0.0130 0.0123 0.0138 0.0134 0.0053 0.0051 0.0077 0.0076 0.0105 0.0103

C6 0.0075 0.0129 0.0012 0.0028 0.0061 0.0077 0.0066 0.0126 0.0021 0.0026 0.0033 0.0041 0.0048 0.0064

C7+ 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0016 0.0000 0.0020 0.0000 0.0045

H2S 0.0003 0.0006 0.0005

First, we used the given C7+ MW and C7+ SG to match themeasured Pbs and then predicted the GORs(1). We had no problemmatching both the Pb and GORs for eight of the nine wells, but wehad difficulty matching both of these parameters for well N51.After discussion with the client, it was agreed that the well N51PVT was likely in error. After eliminating this data the range of Pbwas from 7,750 to 9,770 kPa and the variation in GOR was from53 to 86 m3/m3 (300 to 484 scf/bbl). An increase of Pb consistentwith increasing GOR was noted. The variation could be due tosampling procedures since the geological data indicates that thesewells are in same formation.

The C7+ MW varies from 237 to 257 while the C7+ SG rangesfrom 0.840 to 0.870. Based on the C7+ MW variation of morethan 5% it is difficult to justify that these samples represent thesame reservoir fluid. These differences could be due to samplingprocedures as was postulated for the GOR data. To clarify this,Figures 14 and 15 plot available separator test average GORs for1994 and 1995 respectively. Taking into account the variation ofseparator conditions, the range of scatter of this GOR data is simi-lar to the PVT GOR (i.e., from 53 to 86 m3/m3 or 300 to 450scf/bbl). We, therefore, averaged the separator test GOR datawhich yielded 69 m3/m3 (385 scf/bbl). This GOR was also usedfor the N118 recombined surface sample which in turn was usedto analyse many of the EOR laboratory tests. Finally, we selectedthe N118S sample for our reservoir study.

To verify the selection, Table 11 compares gas analyses during1968, 1994, and 1995 with those predicted by EOS. The matchwas very good except for the H2S component. H2S was not pre-sent in the original samples but there was a small amount of H2S

in the gas analyses from 1994 and 1995. This likely resulted frominadequate treatment of the injected water.

As noted above we used the available C30+ oil analyses todemonstrate that the C7+ grouping is adequate for reservoir man-agement purpose. The oil analyses from Lab #2 for wells N118B,N134, S65, and S84 include the aromatics and napthenes in the C5to C9 components. Lab #1 on other hand separates the aromaticsand napthenes from the C5 to C9 components for wells N118S andS59 which results in lower concentrations of the C6 to C10 compo-nents as shown in Figure 16. The reason for separating these twogroups from the C7 to C9 components is that the MW of these twogroups (aromatics and napthenes) is less than the MW of the C7 toC9 components which are used in the EOS package. Without sepa-ration, the concentration, and hence the MW of the C7 to C9 com-ponents, would be too high resulting in erroneous critical proper-ties generated from the correlations of the PVT package.

To verify the inadequacy of Lab #2 data, one can calculate theC7+ molecular weight using molar weighting given in the EOSpackage. The result shows that the calculated C7+ MW from Lab#2 for wells N118B, N134, S65, and S84 varies from 149 to 168which is less than the C7+ MW calculated by EOS of 240. Onother hand, the agreement between the measured and calculatedC7+ MW is very good for N118S from Lab #1 data. For well S59,the difference is less than 5%, well within acceptable range.

Figures 17 to 19 compare the oil formation factors, the solutionGOR, and the oil density from DL measurements to the EOS cal-culated values using C7+ and C20+ characterization for wellN118S. The difference between the EOS predicted values usingC7+ or C20+ characterization is small. However, it seems that theC7+ grouping predicts better the measured values than the C20+grouping. This could be due to the fact that the correlations usedto generate the critical properties and accentric factor for the C7 toC19 components in the C20+ characterization are based on normalalkane rather than the individual components.

Conclusions and RecommendationsFrom this study we conclude and recommend the following:1. It is very important at the outset of a project to analyse all

available PVT data together with the well test data, thereservoir static pressures, and the production informationsuch as GOR (Application 1).

2. With proper oil characterization, one can better predictreservoir fluid properties which, in turn, can be used to bet-ter describe the reservoir and to identify compartmentaliza-tion in a formation (Application 2).

3. It is very important to interpret laboratory measurementswith physical reasoning when there is inconsistent data(Application 3).


FIGURE 14: Average production test GOR—North Reservoir 4. FIGURE 15: Average production test GOR—South Reservoir 4.

FIGURE 16: Oil analysis up to C20+—Reservoir 4.

4. The existence of H2S in the reservoir fluid can play animportant role in identifying the formation and in reservoirmanagement (Application 2).

5. One heavy end (C7+) characterization is adequate for fluidproperty prediction for reservoir engineering applications(Application 4).

References1. WU, R.S., and FISH, R.M., C7+ Characterization for Fluid

Properties Predictions; Journal of Canadian Petroleum Technology,July – August, 1989.

2. WHITSON, C.H., ANDERSON T.F., and SOREIDE I., C7+Characterization of Related Equilibrium Fluid Using the GammaDistribution, Paper in C7+ Characterization;edited by MansooriG.A., and Chorn L.G., Taylor and Francis, New York, 1989.

3. LEE, B.I., and KESLER, M.G., Improved Vapour PressurePrediction; Hydro. Proc., pp. 163-179, April 1958.

4. EDMISTER, W.C., Applied Hydrocarbon Thermodynamics;Petroleum Refiner, pp. 173-179, April 1958.

5. CAVETT, R.H., Physical Data for Distillation Calculations—Vapour-Liquid Calculations; Proceedings 27 API Meeting, SanFrancisco, pp. 351-366, 1962.

6. RIAZI, M.R. and DAUBERT, T.E., Simplify Property Predications;Hydro. Proceedings, pp. 115-116, March 1980.

Provenance—Original Petroleum Society manuscript, IntegratedOil Characterization—Lessons from Four Case Histories, (97-05), first presented at the 48th Annual Technical Meeting, June 8-11, 1997, in Calgary, Alberta. Abstract submitted for reviewNovember 13, 1996; editorial comments sent to the author(s)November 19, 1998; revised manuscript received December 17,1998; paper approved for pre-press December 18, 1998; finalapproval November 8, 1999.M


FIGURE 17: Comparison of oil formation factors using C7+ andC20+ characterization —Reservoir 4.

FIGURE 18: Comparison of solution gas-oil ration using C7+ andC20+ characterization —Reservoir 4.

FIGURE 19: Comparison of oil densities using C7+ and C20+characterization —Reservoir 4.

Authors’ Biographies

Ray Wu is currently a senior engineer withTeknica Petroleum Services Ltd. Beforejoining Teknica, he was involved in oilrecovery research, both conventional andthermal, with Imperial Oil Ltd. He receivedM.A.Sc. in 1972 from the University ofWindsor, Ontario and a Ph.D. in 1976 fromthe University of Alberta. Dr. Wu is amember of APEGGA and the PetroleumSociety.

Lothar Rosenegger is currently engineer-ing manager with Teknica PetroleumServices Ltd. and has 25 years of diversepetroleum engineering experience, bothdomestic and international. He received hisB.Eng. and M.Eng. degrees in mechanicalengineering from McGill University in1971 and 1973 and MBA from theUniversity of Calgary in 1980. Mr.Rosenegger is a member of APEGGA, thePetroleum Society, and the SPE.

integrated oil pvt characterization

Documents