PVT Reportdd

Laboratory for Exploration and Production

OMV Exploration & Production GmbH Laboratory

Gerasdorfer Strae 151, A-1210 Vienna, Austria, Europe Tel. +43 (1) 40440-23315, Fax +43 (1) 40440-20995

C

E R T

I F I E D

Report

Reservoir Fluid

(PVT) Properties Block S2 (Al Uqlah), Yemen

Vienna, November 2006


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Contents 1 Executive Summary ............................................................................. 4

1.1 Aim of the work ........................................................................... 4 1.2 Scope of work.............................................................................. 4 1.3 Reports provided .......................................................................... 4 1.4 Description of the reservoir fluid. .................................................... 4

2 Staff of Project and Responsibilities ....................................................... 5 3 Nomenclature, Abbreviations ................................................................ 6 4 Tables, Figures.................................................................................... 8 5 Introduction........................................................................................ 9 6 Key PVT-data ................................................................................... 10 7 Fluid compositions............................................................................. 13 8 Modeling of the phase behavior with an EOS......................................... 15 9 Reservoir fluid summary, experimental data .......................................... 18 10 Reservoir fluid summary, EOS modeling................................................ 22

10.1 Parameters of the EOS ............................................................. 26 10.2 Variations of GOR.................................................................... 26

11 Summary ......................................................................................... 31


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1 Executive Summary

1.1 Aim of the work To date in total 4 PVT samples were investigated. The objective of this work was to determine compose a unified data set for the reservoir engineer to calculate the reserves and the production. The facility engineer should be likewise able to design the necessary surface installations.

1.2 Scope of work The work included the following points:

Survey the existing data. Create the most likely hydrocarbon distribution of the reservoir fluid. Create the most likely formation volume factor for oil, the solution gas

ratio and the composition of the associated gas during production. Determination of the viscosity of oil. Calculation of the formation volume factor and viscosity for gas. Group the components in order to describe the fluid behavior with an

equation of state. This is a necessary step for compositional simulation. Characterize the groups of components.

1.3 Reports provided The reports provided are listed below.

Tab. 1 Existing PVT-reports

Well Kharwah-1 Al-Nilam-1 Al-Nilam-1 Habban-1a Zone Kohlan Kohlan Lam Date of sample

29.3.2001 12.8.2003 30.6.2005

Laboratory WCP Oilphase-DBR (SLB), Dubai

WCP Oilphase-DBR (SLB), Dubai

WCP Oilphase-DBR (SLB), Dubai

LEP (OMV)

report 01/LJA/169 LJA24016A LJA24016B RES20050057

1.4 Description of the reservoir fluid. The reservoir fluid is an undersaturated oil. The hydrocarbon distribution extends up to C120. The summary of the fluid data can be found in Tab. 5-Tab. 8.


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1.5 Summary The task of normalizing the existing PVT data could be achieved. All points of the scope of work were covered. The data of all 4 PVT reports lead to the conclusion that

o The reservoir fluids of the samples taken have the same composition. o An analysis led to the identification of some outliers. o A description of the phase behaviour with an EOS through 10 component

groups is possible and will provide the basis for a fast compositional simulation.

o Variations in the surface GOR were calculated successfully.

2 Staff of Project and Responsibilities Activities and Experiments Name Data analysis Klaus Potsch EOS modeling Klaus Potsch reporting Klaus Potsch proof reading August Burisch


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3 Nomenclature, Abbreviations B ...............formation volume factor BHS...........bottom hole sample BIC ............binary interaction coefficient CCE ...........constant composition expansion (flash) C...............compressibility CT..............thermal expansion oil DLP ...........differential liberation process EOS ...........equation of state GC.............gas chromatography GOR ..........gas oil ratio HTGC.........high temperature gas chromatography M, Mm ........molecular mass MPa...........Megapascal Nc .............carbon number of a component OF .............oil field p ...............pressure pabs ............absolute pressure PR .............Peng-Robinson PS .............pseudocomponent Psc ............pseudocomponent Rs ..............gas oil ratio Sf ..............shrinkage factor Sf= 1/Bo SI ..............Systme International dUnits SRK ...........Soave-Redlich-Kwong T ...............temperature Vs..............volume at separator conditions Vrel.............V/Vb in the CCE Y...............Y function = (p/pb-1)/(Vb/V-1) Z ...............compressibility factor Greek symbols: ...............viscosity ...............density Indexes: a ...............ambient conditions (1.01325 bar, 20 C) b ...............bubble point c ...............critical d ...............data from DLP f................data from CCE or flash g ...............gas o ...............oil r ................reduced


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res.............at reservoir conditions t................total 0 ...............standard conditions (1 bar, 0 C)


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4 Tables, Figures Fig. 1 Well locations................................................................................. 9 Fig. 2 Pressure versus depth ................................................................... 11 Fig. 3 Temperature versus depth.............................................................. 11 Fig. 4 Gas solution ratio Rs versus saturation pressure psat .......................... 12 Fig. 5 Gas solution ratio Rs versus formation volume factor Bo .................... 12 Fig. 6 Reservoir fluid distributions ............................................................ 13 Fig. 7 Saturation pressure versus depth .................................................... 15 Fig. 8 Formation volume factor of oil vs. pressure ...................................... 16 Fig. 9 Gas-oil ratio vs. pressure ............................................................... 16 Fig. 10 Oil viscosity vs. pressure ............................................................. 16 Fig. 11 Gas compressibility factor vs. pressure .......................................... 17 Fig. 12 DLP, composition of solution gas. ................................................. 25 Tab. 1 Existing PVT-reports ...................................................................... 4 Tab. 2 Formation data, OF units .............................................................. 10 Tab. 3 Formation data, SI units ............................................................... 10 Tab. 4 Reservoir fluid distributions ........................................................... 14 Tab. 5 Reservoir fluid summary, SI-units @ T=Tres..................................... 18 Tab. 6 Reservoir fluid summary, SI-units @ T=20C ................................... 18 Tab. 7 Reservoir fluid summary, OF-units @ T=Tres.................................... 18 Tab. 8 Reservoir fluid summary, OF-units @ T=60F .................................. 18 Tab. 9 Volumetric experimental data, DLP (SI units) ................................... 19 Tab. 10 Volumetric experimental data, DLP, (OF units) ............................... 20 Tab. 11 Experimental gas analyses of well stream, volumetric units ............. 21 Tab. 12 Experimental gas analyses of well stream, molar units .................... 21 Tab. 13 Volumetric calculated data, DLP (SI units) ..................................... 23 Tab. 14 Volumetric calculated data, DLP, (OF units)................................... 23 Tab. 15 Calculated gas analyses of well stream, volumetric units................. 24 Tab. 16 Calculated gas analyses of well stream, molar basis ....................... 24


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5 Introduction The samples were taken at different wells and depths. A map shows the location of the wells within Block S2.

Fig. 1 Well locations

For the purpose of getting an overview, the main parameters of the wells were summarized in Tab. 2 and plots were made to detect inconsistencies as a first step. If the data cannot be harmonized then the conclusion has to be made that the reservoir consists of different compartments. Secondly, the distribution of components will be looked at. A grouping of components, especially of the heavy ends will lead to a shortened description of the fluid by means of which the experiments will be matched. The dependence of the saturation (bubble point) pressure with depth will be calculated. That allows for a consistency check of the PVT reports.

Al Nilam-1

Habban-1a Khawarah-1


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6 Key PVT-data The key PVT-data are listed in both systems of units SI (Tab. 2) and OF (Tab. 3).

Tab. 2 Formation data, OF units

well Al Nilam 1 Al Nilam 1 Habban-1a Kharwah 1 formation Lam Kohlan Kohlan sample SEP SEP BHS SEP sampling date 15.12.03 08.12.03 30.06.05 29.03.01 report date May 2004 May 2004 Oct 2005 Jul 2001 depth SS ft 4858.9 5516.7 5387.8 6190.9 initial pressure psia 3738 3905 3865 4067 reservoir temperature F 180.6 193.7 199 221 saturation pressure, pb psi 3450 3595 3364 3600 solution gas, Rsi pb,Tres scf/stb 1198 1210 1155 1588 formation factor oil Bo pb,Tres bbl/stb 1.68 1.683 1.744 1.953 oil viscosity pb,Tres mPas 0.3 0.27 0.398 0.29 gas viscosity pb,Tres mPas 0.022 0.022 0.0224 0.022 gas gravity (air=1) pb,Tres 0.775 0.79 0.761 rel oil density stc 0.836 0.838 0.8352 0.833 rel oil density pb,Tres 0.4976 0.4979 0.4789 0.4265

Tab. 3 Formation data, SI units

well Al Nilam 1 Al Nilam 1 Habban-1a Kharwah 1 formation Lam Kohlan Kohlan depth m 2293.0 2493.5 2450.0 2722.0 elevation m 812.0 812.0 807.8 835.0 depth SS m 1481.0 1681.5 1642.2 1887.0 initial pressure bar 257.6 269.1 266.4 280.3 reservoir temperature C 82.6 89.8 92.8 105.0 saturation pressure, pb bar 237.8 247.8 231.8 248.1 solution gas, Rsi pb,Tres scf/stb 213.4 215.5 205.7 282.8 formation factor oil Bo pb,Tres bbl/stb 1.68 1.683 1.744 1.953 oil viscosity pb,Tres mPas 0.3 0.27 0.398 0.29 gas viscosity pb,Tres mPas 0.022 0.022 0.0224 0.022 gas gravity (air=1) pb,Tres 0.775 0.79 0 0.761 rel oil density stc 0.836 0.838 0.8352 0.833 rel oil density pb,Tres 0.4976 0.4979 0.4789 0.4265 The most useful plots are pressure (Fig. 2) and temperature (Fig. 3) versus depth, gas solution ratio Rs versus saturation pressure psat (Fig. 4) and versus formation volume factor Bo (Fig. 5).


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Fig. 2 Pressure versus depth

3000

3200

3400

3600

3800

4000

4200

4000 4500 5000 5500 6000 6500

depth [ft]

pres

sure

, [ps

ia]

p resp satregression p resregression p sat

Al N

ilam

-1, L

am

Al N

ilam

-1, K

ohla

n

Hab

ban-

1a

Kha

rwah

-1

Fig. 3 Temperature versus depth

150

160

170

180

190

200

210

220

230

4000 4500 5000 5500 6000 6500

depth [ft]

tem

pera

ture

[F]

Al N

ilam

-1, L

am

Hab

ban-

1a

Al N

ilam

-1, K

ohla

n

Kha

rwah

-1


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Fig. 4 Gas solution ratio Rs versus saturation pressure psat

1000

1100

1200

1300

1400

1500

1600

1700

3350 3400 3450 3500 3550 3600 3650

p sat [psia]

Rs

[scf

/stb

]

Al N

ilam

-1, L

am

Hab

ban-

1a

Al N

ilam

-1, K

ohla

n

Kha

rwah

-1

Fig. 5 Gas solution ratio Rs versus formation volume factor Bo

1000

1100

1200

1300

1400

1500

1600

1700

1.65 1.7 1.75 1.8 1.85 1.9 1.95 2

formation volume factor Bo [bbl/stb]

Rs [s

cf/s

tb]

Al N

ilam

-1, L

am

Hab

ban-

1a

Al N

ilam

-1, K

ohla

n

Kha

rwah

-1

Observations from the plots are that


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o the first two plots show a correct trends. o The saturation pressure of Habban-1a could be a little bit too low. o The reservoir temperature of the Kohlan formation in the well Al Nilam

seems to be too low. The gas solution ratio Rs is tied to the formation volume factor of oil, Bo. The more gas is in solution the more the volume of the oil grows. A linear relationship is expected. With the present data it is difficult to determine outliers. That the two Al Nilam-1 values are close together can be considered specific for the way the well was operated. The low value of Habban-1a or the high value of Kharwah-1 has to be checked via EOS (see later chapter).

7 Fluid compositions The fluid compositions of all well streams are known for every well to a different extent: Kharwah-1 to C12+, the Al Nilam-1 samples to C30+ and the Habban-1a to C120+. The distributions are only tabulated up to C30+. Concluding from the graphical display (Fig. 6) one can see that the hydrocarbon distributions are sufficiently close together so that an average distribution can be reasonably calculated. The data is found in Tab. 4.

Fig. 6 Reservoir fluid distributions

0.1

1

10

1000 5 10 15 20 25 30

carbon number

perc

enta

ge

Al-Nilam-1, LamAl-Nilam-1, KuhlanHaban-1aKharwah-1, Kohlan


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Tab. 4 Reservoir fluid distributions

well Al-Nilam-1 Al-Nilam-1 Haban-1a Kharwah-1 average group formation Lam Kohlan Kohlan

comp mol% mol% mol% mol% mol% CO2 0.69 0.73 0 1.37 0.71 H2S 0 0 0 0 0.00 N2 0.44 0.54 0.57 0.68 0.52 C1 44.71 46.89 43.07 45.9 44.89 C1+N2 C2 8.68 8.08 8.33 8.47 8.39 C2+CO2 C3 6.76 6.19 6.54 6.58 6.52 C3 iC4 1.21 1.12 1.09 1.04 1.12 C4

nC4 3.49 3.24 3.40 3.11 3.31 C4 iC5 1.27 1.19 1.22 1.03 1.18 C5

nC5 1.75 1.63 1.82 1.47 1.67 C5 C6 2.28 2.16 2.31 2.17 2.23 psc1 C7 3.48 3.36 4.48 3.83 3.79 psc1 C8 3.78 3.68 3.76 4.47 3.92 psc1 C9 2.4 2.35 3.18 2.77 2.68 psc2

C10 2.09 2.06 2.78 2.22 2.29 psc2 C11 1.56 1.55 1.92 1.62 1.66 psc2 C12 1.34 1.32 1.63 13.28 1.43 psc2 C13 1.28 1.27 1.63 1.39 psc3 C14 1.11 1.1 1.50 1.24 psc3 C15 1.11 1.08 1.31 1.17 psc3 C16 0.89 0.9 1.04 0.94 psc3 C17 0.76 0.75 0.96 0.82 psc3 C18 0.75 0.73 0.91 0.80 psc4 C19 0.66 0.64 0.85 0.72 psc4 C20 0.56 0.54 0.59 0.56 psc4 C21 0.51 0.5 0.53 0.51 psc4 C22 0.47 0.46 0.57 0.50 psc4 C23 0.43 0.42 0.42 0.42 psc4 C24 0.39 0.39 0.40 0.39 psc4 C25 0.39 0.37 0.39 0.38 psc4 C26 0.31 0.3 0.33 0.31 psc4 C27 0.32 0.32 0.32 0.32 psc4 C28 0.29 0.28 0.27 0.28 psc5 C29 0.29 0.29 0.29 0.29 psc5

C30+ 3.55 3.57 1.58 2.65 psc5 The last column of Tab. 4 indicates the grouping of the components for the modelling exercise. The total number of components was limited with 10 in order to keep the potential compositional reservoir simulation time short. The divisions of the pseudocomponents were made in such a way that they had equal mass.


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8 Modeling of the phase behavior with an EOS Assuming one common fluid composition allows for checking the PVT data of the different reports on consistency by using an EOS. In the present case the Peng-Robinson EOS with non-zero BICs was employed, for the liquid viscosity the Pederson model was used. The data against which the EOS was tuned was the data set of Habban-1a. The reason of this decision was that they originate from the only bottom hole sample and it was also the most recent data. If the reservoir fluids are from the same pool, then the data of the PVT-studies with the separator samples should be able to be reproduced by a compositional grading calculation. That calculation takes care of the dependence of the PVT parameters with depth. The plot of the saturation pressure versus depth Fig. 7 gives us a valuable insight into the quality of the available PVT data.

Fig. 7 Saturation pressure versus depth

3150

3200

3250

3300

3350

3400

3450

3500

3550

3600

3650

4700 4900 5100 5300 5500 5700 5900 6100 6300

depth [ft]

satu

ratio

n pr

essu

re [p

sia]

psat claculated psat experimental

Hab

ban-

1a

Kha

rwah

-1

Al-N

ilam

-1, K

ohla

n

Al-N

ilam

-1, L

am

The calculation shows a decreasing trend of the saturation pressure with depth. Al-Nilam-1, Lam formation is following this trend. Al-Nilam-1, Kohlan formation and Kharwah-1 seem to have a saturation pressure that is too high. The cause can be that the GOR at the separator was measured too high or there was simply a miswriting of a number. The next step was to match the experimental PVT data Habban-1a with an EOS. After the match was achieved the reservoir temperature was changed to the ones of the other samples and the PVT data were calculated. The results of that exercise are displayed in Fig. 8 - Fig. 11.


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Fig. 8 Formation volume factor of oil vs. pressure

1

1.2

1.4

1.6

1.8

2

2.2

0 500 1000 1500 2000 2500 3000 3500 4000

absolute pressure [psia]

Bo

Kharw ah-1, exp.

Al-Nilam-1, Kuhlan, exp.

Al-Nilam-1, Lam, exp.

Habban-1a, exp.

Kharw ah-1, EOS

Al-Nilam-1, Kuhlan, EOS

Al-Nilam-1, Lam, EOS

Habban-1a, EOS

Fig. 9 Gas-oil ratio vs. pressure

0

200

400

600

800

1000

1200

1400

1600

1800

0 500 1000 1500 2000 2500 3000 3500 4000


Rs [s

cf/s

tb]

Kharw ah-1, exp.



Habban-1a, exp.

Kharw ah-1, EOS



Habban-1a, EOS

Fig. 10 Oil viscosity vs. pressure


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0

0.2

0.4

0.6

0.8

1

1.2

1.4

1.6

0 500 1000 1500 2000 2500 3000 3500 4000


[m

Pas

]

Kharw ah-1, exp.



Habban-1a, exp.

Kharw ah-1, EOS



Habban-1a, EOS

Fig. 11 Gas compressibility factor vs. pressure

0.8

0.82

0.84

0.86

0.88

0.9

0.92

0.94

0.96

0.98

1

0 500 1000 1500 2000 2500 3000 3500 4000


Z

Kharw ah-1, exp.



Habban-1a, exp.

Kharw ah-1, EOS



Habban-1a, EOS


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9 Reservoir fluid summary, experimental data

Tab. 5 Reservoir fluid summary, experimental data, SI-units @ T=Tres

p0 abs pb abs pres abs 1.01325 232 284 bar Formation volume factor oil (DLP) Bod 1.0682 1.7441 1.7182 m/m Formation volume factor oil (CCE) Bof 1.0682 1.652 1.6261 m/m Formation volume factor gas (DLP) Bg 1.3577 0.00515 m/Sm Gas oil ratio (DLP) Rsd 0 205.88 205.88 Sm/m Gas oil ratio (CCE) Rsf 0 198.00 198.00 Sm/m Compressibility oil Co*104 1.250 2.658 1.658 1/bar Compressibility factor gas Z 0.9998 0.8755 Viscosity oil o 1.203 0.398 0.437 mPas Viscosity gas g 0.0130 0.0224 mPas Thermal expansion (Tres) Ct *10 1.243 1/C

Tab. 6 Reservoir fluid summary, experimental data, SI-units @ T=20C

Density of STO (DLP) @ 20 C ST 835.2 kg/m H2S content of produced gas n.a ppm Compressibility of STO @ 20 C n.a. 1/bar

Tab. 7 Reservoir fluid summary, experimental data, OF-units @ T=Tres

p0 abs pb abs pres abs 14.7 3364.9 4119.1 psia Formation volume factor oil (DLP) Bod 1.0682 1.7441 1.7182 bbl/bbl Formation volume factor oil (CCE) Bof 1.0682 1.652 1.6261 bbl/bbl Formation volume factor gas (DLP) Bg 1.3577 0.00515 0.00441 ft/scf Gas oil ratio (DLP) Rsd 0 1155.98 1155.98 scf/bbl Gas oil ratio (CCE) Rsf 0 1111.73 1111.73 scf/bbl Compressibility oil Co*105 0.086 0.183 0.114 1/psi Compressibility factor gas Z 0.9998 0.8755 Viscosity oil o 1.203 0.398 0.437 mPas Viscosity gas g 0.0130 0.0224 mPas Thermal expansion (Tres) Ct *10 0.691 1/F

Tab. 8 Reservoir fluid summary, experimental data, OF-units @ T=60F

Density of STO (DLP) @ 60 F ST 38.4 API H2S content of produced gas n.a. ppm Compressiblity of STO @ 60F n.a. 1/psi


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Tab. 9 Volumetric experimental data of , DLP (SI units)

p abs Bod Bof Rsd Rsf Bt Co*104 Z Bg o g bar m/m m/m Nm/m Nm/m m/m 1/bar m/m mPas Pas

301 1.7115 1.6194 205.88 198.0 1.7115 0.451 26.43 284 1.7182 1.6261 205.88 198.0 1.7182 0.437 25.49 271 1.7238 1.6317 205.88 198.0 1.7238 0.426 24.75 241 1.7374 1.6453 205.88 198.0 1.7374 0.403 23.00 235 1.7407 1.6486 205.88 198.0 1.7407 0.399 22.71 232 1.7441 1.6520 205.88 198.0 1.7441 2.658 0.8755 0.00515 0.398 22.42 211 1.6777 1.5940 183.90 176.7 1.7998 2.486 0.8630 0.00555 0.425 21.24 181 1.5968 1.5251 155.88 149.7 1.9185 2.256 0.8512 0.00638 0.471 19.50 151 1.5251 1.4653 130.64 125.5 2.1073 2.041 0.8498 0.00764 0.533 17.85 121 1.4595 1.4117 107.62 103.5 2.4209 1.860 0.8611 0.00966 0.601 16.35 91 1.3995 1.3637 86.08 83.0 2.9898 1.723 0.8839 0.01319 0.678 15.09 61 1.3428 1.3189 65.46 63.4 4.1953 1.628 0.9162 0.02039 0.762 14.09 31 1.2793 1.2673 43.99 43.0 7.9508 1.502 0.9556 0.04185 0.870 13.37 11 1.2142 1.2102 25.32 25.0 22.7410 1.373 0.9848 0.12153 1.028 13.05 1 1.0682 1.0682 0 0.0 278.0361 1.250 0.9980 1.35770 1.203 12.95


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Tab. 10 Volumetric experimental data, DLP, (OF units)

p abs Bod Bof Rsd Rsf Bt Co*105 Z Bg o g psia bbl/bbl bbl/bbl scf/bbl scf/bbl bbl/bbl 1/psi scf/scf mPas Pas

4365.6 1.7115 1.6194 1155.8 1111.6 1.7115 0.451 26.43 4119.1 1.7182 1.6261 1155.8 1111.6 1.7182 0.437 25.49 3930.5 1.7238 1.6317 1155.8 1111.6 1.7238 0.426 24.75 3495.4 1.7374 1.6453 1155.8 1111.6 1.7374 0.403 23.00 3408.4 1.7407 1.6486 1155.8 1111.6 1.7407 0.399 22.71 3364.9 1.7441 1.6520 1155.8 1111.6 1.7441 1.832 0.8755 0.00515 0.398 22.42 3060.3 1.6777 1.5940 1032.4 992.2 1.7998 1.713 0.8630 0.00555 0.425 21.24 2625.2 1.5968 1.5251 875.1 840.7 1.9185 1.555 0.8512 0.00638 0.471 19.50 2190.1 1.5251 1.4653 733.4 704.7 2.1073 1.407 0.8498 0.00764 0.533 17.85 1755.0 1.4595 1.4117 604.2 581.2 2.4209 1.282 0.8611 0.00966 0.601 16.35 1319.8 1.3995 1.3637 483.3 466.0 2.9898 1.187 0.8839 0.01319 0.678 15.09 884.7 1.3428 1.3189 367.5 356.0 4.1953 1.122 0.9162 0.02039 0.762 14.09 449.6 1.2793 1.2673 247.0 241.2 7.9508 1.035 0.9556 0.04185 0.870 13.37 159.5 1.2142 1.2102 142.1 140.2 22.7410 0.946 0.9848 0.12153 1.028 13.05 14.5 1.0682 1.0682 0.0 0.0 278.0361 0.861 0.9980 1.35770 1.203 12.95


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Tab. 11 Experimental gas analyses of well stream, volumetric units

p abs N2 C1 C2 C3 iC4 nC4 iC5 nC5 C6 C7 C8 C9 C10+ p bar vol% vol% vol% vol% vol% vol% vol% vol% vol% vol% vol% vol% vol% psia

211 1.775 79.383 8.843 4.831 0.660 1.727 0.491 0.631 0.515 0.575 0.374 0.153 0.042 1682.4 181 1.653 80.108 8.914 4.708 0.623 1.609 0.441 0.561 0.442 0.482 0.309 0.127 0.024 1319.8 151 1.454 80.530 9.163 4.693 0.599 1.529 0.403 0.506 0.379 0.399 0.238 0.098 0.009 1029.8 121 1.227 80.457 9.618 4.822 0.593 1.493 0.384 0.467 0.333 0.338 0.196 0.070 0.003 739.7 91 0.924 79.448 10.544 5.234 0.625 1.555 0.375 0.459 0.308 0.304 0.164 0.058 0.002 449.6 61 0.568 76.492 12.398 6.267 0.727 1.790 0.418 0.502 0.324 0.304 0.156 0.051 0.002 232.1 31 0.264 67.359 16.735 9.386 1.095 2.707 0.613 0.731 0.449 0.406 0.197 0.057 0.002 14.5 11 0.000 44.448 23.923 17.981 2.309 5.918 1.369 1.646 0.993 0.881 0.412 0.115 0.006 159.5 1 0.000 2.206 9.141 25.584 6.668 22.288 6.897 9.289 6.503 6.326 3.176 1.043 0.880 14.5

Tab. 12 Experimental gas analyses of well stream, molar units

p abs N2 C1 C2 C3 iC4 nC4 iC5 nC5 C6 C7 C8 C9 C10+ p bar mol% mol% mol% mol% mol% mol% mol% mol% mol% mol% mol% mol% mol% psia

211 1.758 78.699 8.848 4.908 0.673 1.781 0.511 0.665 0.652 0.735 0.503 0.208 0.057 3060.3 181 1.639 79.498 8.928 4.789 0.636 1.661 0.459 0.591 0.561 0.616 0.415 0.173 0.033 2625.2 151 1.443 79.989 9.185 4.777 0.612 1.580 0.421 0.534 0.481 0.511 0.320 0.133 0.013 2190.1 121 1.218 79.960 9.647 4.911 0.606 1.544 0.401 0.493 0.423 0.432 0.264 0.096 0.004 1755.0 91 0.918 78.966 10.577 5.332 0.639 1.608 0.392 0.485 0.392 0.389 0.221 0.080 0.002 1319.8 61 0.564 75.983 12.429 6.380 0.743 1.851 0.436 0.530 0.412 0.389 0.210 0.070 0.002 884.7 31 0.261 66.731 16.732 9.529 1.116 2.791 0.638 0.769 0.569 0.519 0.264 0.078 0.003 449.6 11 0.000 43.632 23.701 18.089 2.332 6.045 1.412 1.716 1.246 1.115 0.548 0.156 0.008 159.5 1 0.000 2.089 8.739 24.836 6.573 21.971 6.942 9.349 6.781 6.863 3.578 1.217 1.063 14.5


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10 Reservoir fluid summary, EOS modeling


p0 abs pb abs 1.01325 232 bar Formation volume factor oil (DLP) Bod 1.0632 1.742 m/m Formation volume factor gas (DLP) Bg 1.3190 0.00510 m/Sm Gas oil ratio (DLP) Rsd 0 193 Sm/m Compressibility oil Co*104 1.200 2.658 1/bar Compressibility factor gas Z 0.9807 0.8833 Viscosity oil o 1.088 0.295 mPas Viscosity gas g 10.23 25.35 Pas Thermal expansion (Tres) Ct *10 1.243 1/C

Tab. 14 Reservoir fluid summary, experimental data, SI-units @ T=20 C

Density of STO (DLP) @ 20 C ST 835.2 kg/m H2S content of produced gas n.a ppm Compressibility of STO @ 20 C n.a. 1/bar


p0 abs pb abs 14.7 3364.9 psia Formation volume factor oil (DLP) Bod 1.0632 1.742 bbl/bbl Formation volume factor gas (DLP) Bg 1.3190 0.00510 ft/scf Gas oil ratio (DLP) Rsd 0 1149 scf/bbl Compressibility oil Co*105 1.200 0.1833 1/psi Compressibility factor gas Z 0.9807 0.8833 Viscosity oil o 1.088 0.295 mPas Viscosity gas g 10.23 0.0224 Pas Thermal expansion (Tres) Ct *10 1.243 1/F

Tab. 16 Reservoir fluid summary, experimental data, SI-units @ T=60 F

Density of STO (DLP) @ 60 F ST 38.4 API H2S content of produced gas n.a. ppm Compressiblity of STO @ 60F n.a. 1/psi


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Tab. 17 Volumetric calculated data, DLP (SI units)

p abs Bod Rsd Bt Co*104 Z Bg o g bar m/m Sm/m m/m 1/bar m/Sm mPas Pas

232 1.7419 192.98 1.7419 2.658 0.8833 0.00510 0.295 25.35 211 1.6804 172.61 1.7950 2.486 0.8709 0.00562 0.318 23.26 181 1.6003 146.01 1.9045 2.256 0.8600 0.00648 0.355 20.61 151 1.5275 121.92 2.0777 2.041 0.8578 0.00774 0.398 18.42 121 1.4602 99.83 2.3669 1.860 0.8641 0.00973 0.449 16.67 91 1.3972 79.39 2.8922 1.723 0.8787 0.01316 0.510 15.28 61 1.3368 60.18 4.0107 1.628 0.9012 0.02013 0.585 14.15 31 1.2744 41.29 7.4865 1.502 0.9318 0.04095 0.685 13.10 11 1.2199 26.78 20.9242 1.373 0.9579 0.11856 0.791 11.94

1.013 1.0632 0.00 255.6110 1.200 0.9807 1.31903 1.088 10.23

Tab. 18 Volumetric calculated data, DLP, (OF units)

p abs Bod Rsd Bt Co*105 Z Bg o g psia bbl/bbl scf/bbl bbl/bbl 1/psi ft/SCF mPas Pas

3364.7 1.7419 1148.7 1.742 1.833 0.8833 0.0048 0.295 25.35 3060.7 1.6804 1027.4 1.795 1.714 0.8709 0.00530 0.318 23.26 2624.7 1.6003 869.1 1.905 1.556 0.8600 0.00611 0.355 20.61 2189.7 1.5275 725.7 2.078 1.408 0.8578 0.00730 0.398 18.42 1754.7 1.4602 594.2 2.368 1.283 0.8641 0.00918 0.449 16.67 1319.7 1.3972 472.5 2.893 1.188 0.8787 0.01241 0.510 15.28 884.7 1.3368 358.2 4.012 1.123 0.9012 0.01899 0.585 14.15 449.7 1.2744 245.8 7.491 1.036 0.9318 0.03862 0.685 13.10 159.7 1.2199 159.4 20.938 0.947 0.9579 0.11182 0.791 11.94 14.7 1.0632 0.0 255.786 0.828 0.9807 1.24402 1.088 10.23


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Tab. 19 Calculated gas analyses of well stream, volumetric units

p [bar] 3046 2610 2175 1740 1305 870 435 145 0 C1 67.311 68.717 69.634 69.818 68.799 65.455 55.952 35.193 3.453 C2 12.612 12.921 13.320 13.910 14.873 16.578 19.806 22.575 5.972 C3 8.038 8.136 8.321 8.696 9.466 11.152 15.702 26.423 20.657 PS-1 2.655 2.448 2.258 2.111 2.047 2.163 2.859 5.434 20.512 PS-2 1.655 1.518 1.395 1.301 1.260 1.331 1.766 3.380 13.459 PS-3 4.790 4.154 3.583 3.114 2.796 2.728 3.336 6.089 30.855 PS-4 2.154 1.632 1.211 0.892 0.669 0.538 0.538 0.855 4.841 PS-5 0.639 0.405 0.245 0.144 0.084 0.052 0.039 0.050 0.246 PS-6 0.128 0.064 0.030 0.013 0.005 0.002 0.001 0.001 0.005 PS-7 0.018 0.005 0.001 0.000 0.000 0.000 0.000 0.000 0.000

Tab. 20 Calculated gas analyses of well stream, molar basis

p [bar] 3046 2610 2175 1740 1305 870 435 145 0 C1 80.287 80.798 81.022 80.783 79.729 76.980 69.311 50.376 8.424 C2 10.547 10.651 10.866 11.284 12.084 13.670 17.201 22.656 10.215 C3 4.916 4.905 4.964 5.159 5.624 6.725 9.973 19.392 25.842 PS-1 1.301 1.183 1.080 1.004 0.975 1.045 1.455 3.197 20.566 PS-2 0.690 0.624 0.568 0.526 0.511 0.548 0.765 1.692 11.486 PS-3 1.587 1.357 1.158 1.001 0.900 0.891 1.148 2.420 20.907 PS-4 0.537 0.401 0.294 0.216 0.162 0.132 0.139 0.256 2.468 PS-5 0.117 0.073 0.044 0.026 0.015 0.009 0.007 0.011 0.092 PS-6 0.017 0.008 0.004 0.002 0.001 0.000 0.000 0.000 0.001 PS-7 0.001 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000


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Fig. 12 DLP, composition of solution gas.

1.E-02

1.E-01

1.E+00

1.E+01

1.E+020 25 50 75 100 125 150 175 200 225

exp C1exp C2exp C3exp C4exp C5exp PS-1exp PS-2calc C1calc C2calc C3calc C4calc C5calc PS-1calc PS-2

The comparison of the composition of the associated gas (Fig. 12) shows a good agreement between experiment and calculation. Differences occur with the components C4, C5 and PS-2. But note, the scale of the concentration is logarithmic. The accuracy of the experimental gas analyses decreases with higher carbon numbers.


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10.1 Parameters of the EOS The software applied here was PVTP from Petroleum Experts. The Peng-Robinson EOS with non-zero binary interaction parameters was employed. Specific parameters are needed for setting up the EOS. They are listed in Tab. 21.

Tab. 21 Parameters of components and pseudo components for EOS

Tc pc Vc M Tb Zc rel mol% K bar m/kmol kg/kmol K

C1 44.90 190.7 46.41 0.011 0.099 16.04 111.6 0.2905 0.4150 C2 8.55 305.4 48.84 0.099 0.148 30.10 184.6 0.2854 0.5460 C3 6.80 369.8 42.57 0.153 0.203 44.10 231.1 0.2810 0.5850 C4 5.14 486.0 29.54 0.366 0.415 58.40 333.0 0.3031 0.6209 C5 3.02 496.1 30.88 0.298 0.402 72.15 333.0 0.3006 0.6529 psc1 9.76 551.3 30.21 0.294 0.430 101.5 370.4 0.2836 0.7295 psc2 8.53 631.0 23.91 0.406 0.559 144.2 445.1 0.2544 0.7792 psc3 5.76 711.8 18.62 0.542 0.742 206.8 526.7 0.2336 0.8211 psc4 4.76 793.7 14.32 0.713 0.979 301.5 616.3 0.2125 0.8602 psc5 2.80 892.9 8.28 0.972 1.528 556.6 773.1 0.1704 0.9177

10.2 Variations of GOR If one assumes that the GOR at the surface is subject to errors, looking at the effect on the PVT parameters is of interest to see what effect a wrong reading can have. The zero case is the one that represents the actual experimental data (Tab. 23). A 10% higher GOR (plus case, Tab. 24) and a 10% lower GOR (minus case, Tab. 22Tab. 1) was investigated. As a consequence of varying GOR the saturation pressure is also subject to variation. For each PVT parameter the variations can be found in Fig. 13-Fig. 18. The EOS software does not compute the oil compressibility, therefore no variation is tabulated or displayed.

Tab. 22 Lower GOR (minus case)

p Bo Rs o Bg Zg g Bt Co bar m/m Sm/m mPas m/Sm Pa.s 1/bar

242 1.8194 214.08 0.272 1.819 3.020 232 1.7878 203.62 0.281 0.00517 0.8808 25.67 1.842 2.924 211 1.7208 181.72 0.304 0.00561 0.8681 23.47 1.902 2.735 181 1.6347 153.45 0.341 0.00645 0.8571 20.74 2.026 2.482 151 1.5569 127.99 0.383 0.00772 0.8549 18.50 2.221 2.245 121 1.4855 104.78 0.433 0.00970 0.8615 16.71 2.546 2.046 91 1.4190 83.40 0.493 0.01312 0.8764 15.29 3.134 1.895 61 1.3554 63.39 0.566 0.02009 0.8993 14.15 4.383 1.791 31 1.2898 43.75 0.664 0.04090 0.9303 13.08 8.256 1.652 11 1.2323 28.60 0.768 0.11854 0.9568 11.89 23.218 1.510

1.01325 1.0638 0.00 1.074 1.31851 0.9803 103.88 283.325 1.320


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Tab. 23 Actual GOR (minus case) same as Tab.17

pabs Bo Rs o Bg Zg g Bt Co bar m/m Sm/m mPas m/Sm Pa.s 1/bar

232 1.7419 192.98 0.295 0.00510 0.8833 25.35 1.742 2.658 211 1.6804 172.61 0.318 0.00562 0.8709 23.26 1.795 2.486 181 1.6003 146.01 0.355 0.00648 0.8600 20.61 1.904 2.256 151 1.5275 121.92 0.398 0.00774 0.8578 18.42 2.078 2.041 121 1.4602 99.83 0.449 0.00973 0.8641 16.67 2.367 1.86 91 1.3972 79.39 0.510 0.01316 0.8787 15.28 2.892 1.723 61 1.3368 60.18 0.585 0.02013 0.9012 14.15 4.011 1.628 31 1.2744 41.29 0.685 0.04095 0.9318 13.10 7.487 1.502 11 1.2199 26.78 0.791 0.11856 0.9579 11.94 20.924 1.373

1.013 1.0632 0.00 1.088 1.31903 0.9807 10.23 255.611 1.2

Tab. 24 Higher GOR (plus case)

p Bo Rs o Bg Zg g Bt Co bar m/m Sm/m mPas m/Sm Pa.s 1/bar

242 1.8194 214.08 0.272 1.819 3.020 232 1.7878 203.62 0.281 0.00517 0.8808 25.67 1.842 2.924 211 1.7208 181.72 0.304 0.00561 0.8681 23.47 1.902 2.735 181 1.6347 153.45 0.341 0.00645 0.8571 20.74 2.026 2.482 151 1.5569 127.99 0.383 0.00772 0.8549 18.50 2.221 2.245 121 1.4855 104.78 0.433 0.00970 0.8615 16.71 2.546 2.046 91 1.4190 83.40 0.493 0.01312 0.8764 15.29 3.134 1.895 61 1.3554 63.39 0.566 0.02009 0.8993 14.15 4.383 1.791 31 1.2898 43.75 0.664 0.04090 0.9303 13.08 8.256 1.652 11 1.2323 28.60 0.768 0.11854 0.9568 11.89 23.218 1.510

1.013 1.0638 0.00 1.074 1.31851 0.9803 10.39 283.325 1.320


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Fig. 13 Variation of FVF oil with GOR

1.0

1.1

1.2

1.3

1.4

1.5

1.6

1.7

1.8

1.9

0 25 50 75 100 125 150 175 200 225 250

absolute pressure [bar]

form

atio

n vo

lum

e fa

ctor

oil

[bbl

/stb

]

zero caseminus caseplus case

Fig. 14 Variation of solution gas ratio with GOR

0

50

100

150

200

250

0 25 50 75 100 125 150 175 200 225 250


solu

tion

gas

ratio

[scf

/stb

]



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Fig. 15 Variation of oil viscosity with GOR

0.0

0.2

0.4

0.6

0.8

1.0

1.2

0 25 50 75 100 125 150 175 200 225 250


visc

osity

oil

[mP

as] zero case

minus caseplus case

Fig. 16 Variation of FVF gas with GOR

1.E-03

1.E-02

1.E-01

1.E+00

1.E+010 25 50 75 100 125 150 175 200 225 250


form

atio

n vo

lum

e fa

ctor

gas

[bbl

/stb

]



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Fig. 17 Variation of compressibility factor for gas with GOR

0.84

0.86

0.88

0.90

0.92

0.94

0.96

0.98

1.00

0 25 50 75 100 125 150 175 200 225 250


com

pres

sibi

lity

fact

or g

as [c

ft/sc

f]


Fig. 18 Variation of gas viscosity with GOR

1.0

6.0

11.0

16.0

21.0

26.0

31.0

0 25 50 75 100 125 150 175 200 225 250


gas

visc

osity

[P

as]



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11 Summary The task of normalizing the existing PVT data could be achieved. All points of the scope of work were covered. The data of all 4 PVT reports lead to the conclusion that

o The reservoir fluids of the samples taken have the same composition. o An analysis led to the identification of some outliers. o A description of the phase behaviour with an EOS through 10 component

groups is possible and will provide the basis for a fast compositional simulation.

o Variations in the surface GOR were calculated successfully.

Documents

PVT Reportdd