determining reservoir characteristics and drive...

RESERVOIR AND PETROLEUM ENGINEERING

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This study presents the application of practical methods that can be used to determine the performance and the drive mechanisms of a selected oil reservoir (Block 7, SP Reservoir) in the Gum Deniz Oil Field, Azerbaijan. It demonstrates the importance of monitoring field performance on a regular basis and gathering all relevant rock and fluid data. The oil in place, average reservoir pressure, amount of water encroachment, fluid saturations, recovery factor and the type of reservoir drive mechanisms were estimated based on field production data. The estimated oil in place was 38.5 MMstb by volumetric method and 35.39 MMstb by material balance analysis. It was verified that the fluids were mainly produced from the SP reservoir within the well-defined boundaries of Block 7. Initially, the dominant reservoir drive mechanism was depletion drive together with compaction drive and fluid expansion mechanisms. After water encroachment, both water drive and depletion drive mechanisms played important roles in fluid production. The current recovery factor was obtained as 25.0% of OOIP. The ultimate recovery was predicted as 37.0% of OOIP. Knowledge of reservoir characteristics, which include drainage area, permeability, porosity, pore compressibility, change in pore volume, amount of water influx and type of reservoir drive mechanisms, gives insight into recovery efficiency and the need for reservoir development strategies that lead to possible improved oil recovery activities.Keywords: Gum Deniz Oil Field, material balance analysis, pore compressibility, reservoir drive mechanisms, loose sandE-mail: [email protected], [email protected]��10.5510/OGP20120400129

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DETERMINING RESERVOIR CHARACTERISTICS AND DRIVE MECHANISMS FOR AN OIL RESERVOIR

��Gumrah, ��Aliyev, ��Guliyeva, ��Ozavci("Bahar Energy" Operating Company)

FIELD DESCRIPTION Gum Denizi (GD) was one of the important

oil fields of Azerbaijan at Caspian Sea. The GD Oil Field lies in shallow water approximately 20 km southeast of Baku immediately off the coast of Azerbaijan. Following discovery in the early 1950’s, production began from the GD oil Field in 1955. As of the end of 2009, ~32.9 million m3 (207 million bbls) of oil and ~16.5 Bm3 (581Bcf) of gas were reported as having been produced from the field. The company reported that 484 wells have been drilled historically, with 61 wells reported on production at the end of September 2010 using gas lift. The GD Oil Field is a faulted anticline (16 fault blocks) located up dip from the Bahar Gas Field. Of the fault blocks (Figure 1), 11 are reported as having established commercial production (Blocks 2, 3, 4, (5+6), 7, 8, 10, 11, 13, 14, 15). 12 separate pay zones over ~1525 m (IV, V, VI, VII, VIII, IX, X, SP, NKP, KS, PK, KaS) have been identified in the field, with three to four found (on average) in each of the productive fault blocks. These intervals are composed of alternating sandstones and shales. Average crude from the field has 36° API gravity; although this ranged from 30° API to 45° API. Similar to the Bahar Gas Field, the reservoir rocks (sandstone and siltstones) are of good quality, with 10% to 22% porosity and 10 mD to 1,200 mD permeability. Note however that most of the producing zones display permeability in the 100 mD to 230 mD range. Historical peak production from the field was achieved to 7,378 m3/d (46,400 bpd) in 1964.

SOURCE ROCK AND RESERVOIRDESCRIPTIONMature source rocks are proven by the many

discoveries of oil and gas in the South Caspian Basin. The balance of expert opinion favours the Maikop Suite of the Oligocene-Lower Miocene as the primary source rock for the oil and gas discovered in the Productive Sequence. The intra-formational shales of the Productive Sequence are also considered to have significant source potential. In global terms, the South Caspian is a very young basin and is relatively cool. As a consequence, the Oligo-Miocene source rocks continue to generate oil at burial depths in excess of six kilometres. Only in the deeper parts of the basin are the source rocks sufficiently deeply buried to generate significant volumes of gas. The relative proportions of oil and gas generated in the deeper parts of the South Caspian Basin remain highly uncertain but the discovery of gas in Shah Denizi has led many industry experts to predict the same for many of the prospects in the deeper-water basin.

The primary reservoir sands are contained in the upper and middle parts of the Productive Sequence - the Surakhany, Sabunchi, Balakhany and Pereryva suites (Fig.2). The main productive sands are attributed ‘horizon’ numbers. The lower parts of the Middle Miocene consist primarily of mudstone with thin impersistent sandy units. The constituent Supra-Kirmaku, Kirmaku, Sub-Kirmaku and Kala Suites are reservoir horizons in several fields. Reservoir quality in the Productive Sequence is a function of three main criteria - reservoir facies, the provenance of the sands

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RESERVOIR AND PETROLEUM ENGINEERING 7

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and burial depth. Sands sourced from the north and the Paleo Volga delta are more quartzitic and less prone to diagenetic alteration on burial than the more argillaceous and lithic sands deposited from the Paleo Kura and, to a lesser extent, the Paleo Amudarya deltas (western and eastern provenance respectively).

With the exception of the Paleo Volga derived sands, reservoir quality is good at depths shallower than 3000 metres, but becomes moderate to poor at depths beyond 4000 metres. Relatively few wells have effectively tested reservoir productivity deeper than 4500 metres, and the Shah Denizi wells (which penetrated sands from the Paleo Volga delta) were the first to do so offshore. Sandstone and siltstone reservoirs of the Productive Sequence are sealed by numerous intra-formational mudstones and shales [1].

Rock and Fluid PropertiesPermeability-Porosity RelationshipThe wells on the field have been logged using

various Russian logging tools. Permeability was estimated from routine porosity and permeability measurements performed on cores. From the available data, the following relationship between permeability and porosity was established as shown on Figure 3.

Pore CompressibilityStrength is the ability of rock to resist stress

without yielding or fracturing. Rock strength is estimated from two common laboratory techniques; unaxial compressive strength (UCS) tests, and triaxial or confined compressive strength tests. UCS tests is used to determine

the ultimate strength of a rock, i.e., the maximum value of stress attained before failure [2].

UCS [3] was calculated for unconsolidated (loose) sand with the following equation having modified coefficients;

(1)

Where c1 is 1.29 and c2 is 1.05 for loose sand. Vsh is the percentage of shale volume.

(2)

Where q is an internal friction angle for unconsolidated (loose) sand. q is 30° or 0.52 in radian. The calculated “a” coefficient by Equation 2 is 3.46.

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9 2

1 28.7 10

[ (1 ) ](1 2 ) sh shx a E

UCS c V c Vv

�

� � ��

GumDeniz Field- SP Horizon

y = 0.0434e0.4028x

R2 = 0.6807

0.010.1

110

1001000

10000

0 10 20 30 40

Porosity, %

Per

mea

bilil

ity,

mD

)1(2

��

SinCosa�

�

3000

2500

2000

1500

1000

500

0

Thic

knes

s, m

PLIO

CEN

EPR

OD

UC

TIV

E SE

RIES

Kal

insk

(KaS

)Ba

lakh

any

Sura

khan

y Seal

Sour

ce

VV

IX

KaS sand unit

KaS clay unit

Nadkirmaku Clay Fm. (NKG)

SP sand unit

SP clay unit

X clay unit

VIII clay unitVIII sand unit

V clay unit


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The pore compressibility was calculated with Equation 3 [4]. The parameters are given in Table 1.

(3)

Newman (1973) used core samples for consolidated sandstones and limestones to develop a correlation between the formation compressibility and porosity. The proposed generalized hyperbolic form of the Newman’s equation is [5];

(4)

The coefficients were modified for the loose sand of Gum Denizi oil reservoir.

The tri-axial or thick-walled cylinder (TWC) test equation for loose sand is;

TWC = 62UCS0.53 (5)

Figures 4 through 8 show the relationship between rock parameters of a typical Gum Denizi oil reservoir. The properties can also be used for estimating sand failure problem during production [6].

The change in porosity with reservoir depletion is

(6)

Pore compressibility of SP reservoir (loose sand) is calculated with Equation 7 that was derived from the

data plotted on Figure 10. (7)

The change in porosity with reservoir depletion for SP horizon was calculated with Equation 6. Figure 10 shows both porosity and pore compressibility variations with reservoir depletion. The average reservoir pressure was predicted from material balance (MB) analysis based on production data. This methodology is described in the following sections.

PVT DataKnowledge of the PVT parameters is a requirement

for determination of hydrocarbon flowing properties, predicting future performance, designing production facilities and planning methods of enhanced oil recovery. The PVT properties can be obtained from a laboratory experiment using representative samples of the crude oils.

However, the values of reservoir liquid and gas properties must be computed when detailed laboratory PVT data is not available. Correlations on PVT which is commonly used in the oil industry are important tools in reservoir-performance calculations. For developing PVT correlation, the chemical composition of crude oil must be considered [7]. Because of the availability of a wide range of correlations, it is beneficial to analyze them for a given set of PVT data belonging to a certain

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)21(3 vE

c f ��

))(*1( initfinit PPc ��

21

Cf cc ��

LOOSE SAND

E, psi 12000 16250 21000 32000 72000

v 0.478 0.467 0.456 0.425 0.300

UCS, psi 117 145 178 238 437

TWC, psi 774 867 966 1127 1555

C*>��/!(�5@B/�3 1.115E-05 1.218E-05 1.257E-05 1.406E-05 1.666E-05

C*>��/!(�5@B/�� 1.143E-05 1.206E-05 1.275E-05 1.388E-05 1.700E-05

C*>��/!(�5@B/� 1.199E-05 1.264E-05 1.334E-05 1.450E-05 1.776E-05

Porosity, % 24.0 22.7 21.3 19.4 15.4

Vshale, % 34.0 37.0 46.0 55.0 71.5

Loose Sand

y = 2.7821x-0.357R² = 0.9028

0.000

0.100

0.200

0.300

0.400

0.500

0.600

0 100 200 300 400 500

UCS, psi

Poi

sson

's ra

tio,

v

Loose Sand

y = 18.525x1.36R² = 0.9998

1 000

10 000

100 000

0 100 200 300 400 500

UCS, psi

Youn

g's

Mod

ulus

, E, p

si

1 2 3/ [1 ]fc c c c ��

��


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geological region. Therefore, PVT correlations need to be modified prior to their applications to account for regional characteristics.

PVT correlations [7] were modified for Gum-Denizi Field’s SP reservoir oil. Table 2 shows these coefficients for the PVT properties of SP reservoir oil. Figures 11 and 12 show Bt, Bo, Rs and z-factor as a function of pressure, respectively.

Solution gas-oil ratio;

(8)

Formation volume factor for SP formation water;

(9)Formation volume factor for SP oil;

When bubblePP � (10)

When bubblePP � (11)

Oil compressibility; (12)

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��Z��&/��/�!&��&.!��((�4�%��)��/9�!&�&(��)�*&��(��2&��

Block 7 (Horizon SP)

0.163

0.164

0.165

0.166

0.167

0.168

0.169

0.170

1-Se

p-60

22-F

eb-6

6

15-A

ug-7

1

4-Fe

b-77

28-Ju

l-82

18-Ja

n-88

10-Ju

l-93

31-D

ec-9

8

22-Ju

n-04

13-D

ec-0

9

Por

osit

y, fr

acti

on

1.635E-051.640E-05

1.645E-051.650E-05

1.655E-051.660E-05

1.665E-051.670E-05

1.675E-051.680E-05

1.685E-05

cf, p

ore

com

pres

sibi

lity,

1/p

si

Porosity cf

32 459.67

1

APICTC

S gR c p e

� ��

21 2 3 4( )wB c c c P c P� � �

Loose Sand

y = 0.0165x1.0736R² = 0.9379

0.0000.1000.2000.3000.4000.5000.600

14 16 18 20 22 24 26

Porosity, %

Poi

sson

's ra

tio,

v

Loose Sand

y = 0.0165x1.0736R² = 0.9379

0.0000.1000.2000.3000.4000.5000.600

14 16 18 20 22 24 26

Porosity, %

Poi

sson

's ra

tio,

v

y = 0.0002x-0.885R² = 0.9863

5.00E-06

9.00E-06

1.30E-05

1.70E-05

10.0 15.0 20.0 25.0 30.0

Porosity, %

Por

e C

ompr

essi

bilit

y, 1

/psi Loose Sand-Eqn 3

Loose Sand-Eqn 4Sandstone

( )obp bpc P Po obpB B e ��

31 / 2 3 /( ) / ( )o o g cc g s o lbm ft

B c c R c � ��

1 2 3 4 5 6( ) / ( )o s g APIc c R c T c c c c P � � � � �

Loose Sand

y = 38.856e0.0336xR² = 0.9912

0

100

200

300

400

500

0 20 40 60 80Vshale, %

UC

S, p

si


��

10

��

Oil viscosity (cP) T is in °C;Tc

o ec 21��

(13)Formation water compressibility;

(14)

Where P is in psi, T in °F, ø (porosity) in percent and S (salinity) in ppm.

RESULTS AND DISCUSSIONIn this study, SP oil pay horizon in Block 7 was

chosen. The hydrocarbon in place was estimated by two methods. The volumetric method based on area, porosity, saturation and thickness was conducted. Then, the material balance method was applied with the use of field production data. Figure 13 shows the

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C� C� C3 C� C� C

PVT data

Rs (scf/stb) 0.0178 1.18705 23.931

Bw (rb/stb) 1.000584 1.01708553 -2.98729e-06 1.91482e-11

Bo (rb/stb), P<Pbp 350 0.0764 5.616

Cw (1/psi) 7.033 0.5415 -537 403300

Co (1/psi) 5 17.2 -1180 12.61 -1433 105

μo (cP) 32.432 -0.031

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UCS (psi), Eqn-1 1.29 1.05

Cf (1/psi), Eqn-7 0.0002 -0.885

Cf (1/psi), Eqn-4 1.355E-04 0.620 72.850

Reservoir data

gg 0.60

Treservoir (°F) 145.3 °F (63 °C)

gAPI 34.6 °API (0.852 g/cc) (53.114 lbm/ft3)

Oil viscosity, cp 4.6

Water viscosity, cp 0.459

Water Salinity (ppm) 14214

Pbubble, psi 4127 Sor 0.22

Pinitial, psi 4427 Swir 0.24

øinit, (%) 16.9

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)( 24321 PcPcccBw ��

1 2 3 41 / ( )wc c P c S c T c� � � �

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

4.5

0 1 000 2 000 3 000 4 000 5 000

Pressure (psia)

Bo

& B

t (rb

/stb

o)

0

100

200

300

400

500

600

700

Solu

tion

Gas

/oil

Rat

io (s

cf/s

tbo)

Bt Bo Rs

0.80

0.90

1.00

1.10

1.20

1.30

1.40

1.50

1.60

0 2 000 4 000 6 000 8 000 10 000

Pressure (psia)

Z F

acto

r

��


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existing wells produced from SP reservoir in Block 7. Figure 14 shows the drainage area for the wells produced from SP horizon.

@(��.��/��`)9�&��4&/�b/�!%��4)Volumetric MethodThe average reservoir parameters for SP horizon are

presented in Table 3. The bulk volume was determined from the isopach map of the reservoir, average porosity and oil saturation values from log and core analysis data, and oil formation volume factor from correlations. The estimated initial oil in place and recovery factors is also given.

In reserve calculations there are many uncertainties with regard to reservoir parameters. The oil-water contact (net pay), areal extent, water saturation and porosity are average values for the reservoir. Uncertain values may for instance include the size of the initial gas-cap, the initial amount of oil in the reservoir and the influx of the aquifer. Probabilistic analysis (e.g., Monte

Carlo simulation) can be used to bracket uncertainty by describing a range of possible values for each unknown parameter. The repetitive calculations can be performed to generate the full range of possible outcomes and their associated probability of occurrence.

@(��.��/��`)9�&��4&/�b/�!%��4)��%�$�%�/��/�%)(�(One tool the reservoir engineer uses to monitor

field/well performance quickly and accurately is the material-balance plots. The material balance method for solutions gas drive reservoir is given below in a linear from. In this type of reservoir, the principal source of energy is a result of gas liberation from the crude oil and the subsequent expansion of the solution gas as the reservoir pressure is reduced. As pressure falls below the bubble-point pressure, gas bubbles are liberated within the microscopic pore spaces. These bubbles expand and force the crude oil out of the pore

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SI Units Field UnitsPorosity (fraction) 0.169Water Saturation (fraction) 0.24Oil density/API Gravity 0.852 ton/m3 34.6 °APINet Thickness 30.9 m 101.3 ftBulk Volume 60472 Mm3 49025 Acre-ftArea 1957530 m2 483.7 AcreNp, cum. oil production (April,2012) 1.414 MMsm3 8.895 MMstbN, original oil in place (OOIP) 6.122 MMsm3 38.547 MMstbCurrent Recovery Factor (% of OOIP) 23.1 181.4 stb/acre-ft

;�4%��3�Average SP reservoir parameters used in volumetric method


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space. As the reservoir pressure declines, the rock and fluids expand due to their individual compressibility.

The summation of production terms (F);

F = Np[Bo2 + (Rp - Rso2)·Bg2] + WpBw2 (15)

Oil and Dissolved gas expansion terms (Eo);

Eo = (Bo2 - Bo1) + Rso1 - Rso2)Bg2 (16)

Gas cap expansion term (Eg);

(17)

Rock and water compression/expansion terms (Ef,w)

(18)

Both of the above two factors are the results of a decrease of fluid pressure within the pore spaces, and both tend to reduce the pore volume through the reduction of the porosity (Figure 15). This driving

mechanism is considered the least efficient driving force and usually results in the recovery of only a small percentage of the total oil in place.

The complete material balance equation (MBE) is

F = N(Eo + mEg + Ef,w) + (Wi + We)Bw2 + GiBg2 (19)Equation 19 can be modified as equations of straight

lines, which can be applied to different types of reservoirs. In our case, without water injection (Wi=0), gas injection (Gi=0) and no initial gas cap (m=0), the equation becomes;

F=N(Eo +Ef,w) + WeBw2 (20)

The calculated initial oil in place was 35 MMstb that is less than 38.5 MMstb obtained by volumetric estimation. The effect of rock and water expansion on N value was insignificant.

Pressure History MatchingHistorical data goes back to1960 and are updated

occasionally. Material Balance (MB) study was done based on gas, oil and water production data. The

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CASE I: Without rock and water compression/expansion terms (Ef,w), (Figure 16).

y = 1.006x + 35.475R2 = 0.9992

0

50

100

150

200

0 10 20 30 40 50 60 70 80 90 100

110

120

130

140

150

160

170

We/Eo, MMstb

F/Eo

, MM

stb

N=35.475 05

101520253035404550

9/1/60

2/22/6

6

8/15/7

12/4

/77

7/28/8

2

1/18/8

8

7/10/9

3

12/31/

98

6/22/0

4

12/13/

09

F/(E

o)-(W

e/Eo

)

N=35.47


0.160

0.162

0.164

0.166

0.168

0.170

1-Se

p-60

22-F

eb-6

6

15-A

ug-7

1

4-Fe

b-77

28-Ju

l-82

18-Ja

n-88

10-Ju

l-93

31-D

ec-9

8

22-Ju

n-04

13-D

ec-0

9

Por

osit

y, fr

acti

on

7.95

8.00

8.05

8.10

8.15

8.20

8.25

Vpo

re, M

Mm

3

Porosity Vpore, MMm3

��


��

average reservoir and aquifer pressures were predicted through MB analysis by matching the recorded well static pressures. Figure 18 shows the predicted average reservoir and aquifer pressures with solid lines. The measured well pressures are red circles on the graph.

Figure 19 shows the measured production rates and predicted average reservoir pressures from MB calculation. Figure 20 shows the cumulative production and water encroachment.

The average reservoir pressures were compared with measured data by changing the water influx rate till getting reasonable match. The aquifer influx rate (J) was obtained as 2 bbl/psi. The total water encroachment was 25.95 MMstb. The cumulative oil production was 8.895 MMstb. The cumulative water production was 7.99 MMstb and the cumulative gas production was 21.04 Bcf. The estimated initial oil in place and recovery factors is given in Table 4.

Figures 21 and 22 show produced gas-oil ratio and water cut and the bubble map for water production

from SP reservoir, respectively. The water production was higher in few wells; this might be attributed to the possible locations of water entrance into the SP reservoir.

Since the calculated N by MB method is less than that of volumetric method, the fluid production from SP reservoir within the boundaries of Block-7 was verified. The faults or boundaries set for Block-7 were defined well.

The current recovery factor (RF) reached to 25% of OOIP. The ultimate oil recovery factor of individual reservoirs under primary and/or conventional recovery methods may range from 5 % of OOIP for the poorest reservoir characteristics or for viscous oil, to as high as 55% of OOIP for the best reservoir characteristics or for light oil. The oil reservoirs are classified by several models according to the average of the ultimate oil recovery possibly attained by the respective recovery mechanism on Table 5.

Oil, Water and Gas Saturations

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CASE II: With rock and water compression/expansion terms (Ef,w), (Figure 17)

y = 1.01x + 35.39R2 = 1.00

0

50

100

150

200

0 10 20 30 40 50 60 70 80 90 100

110

120

130

140

150

160

170

We/(Eo+Efw), MMstb

F/(E

o+Ef

w),

MM

stb

N=35.39005

101520253035404550

9/1/

60

2/22

/66

8/15

/71

2/4/

77

7/28

/82

1/18

/88

7/10

/93

12/3

1/98

6/22

/04

12/1

3/09

F/(E

o+Ef

w)-

We/

(Eo+

Efw

)

N=35.390

0

500

1 000

1 500

2 000

2 500

3 000

3 500

4 000

4 500

5 000

0 2 000 4 000 6 000 8 000 10 000 12 000 14 000 16 000 18 000 20 000

Days

Pre

ssur

e (p

sia)

Measured Aquifer Reservoir


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14

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The fluid saturations were calculated with the following equations and the results are shown on Figure 23.

Oil saturation;

(21)

Water saturation;

(22)

Gas saturation;

(23)

and So+Sw+Sg = 1 (24)

Relative PermeabilityThe relative permeability for oil, water and gas

was calculated by using correlations based on field production data. The recorded water-cut values (Figure 21) were used for estimating the relative permeability ratio (kro/krw)field by Equation 25.

(25)

These field values are plotted on Figure 24 as a function of water saturation. Then the equations for kro and krw values were developed by optimizing their coefficients till the good matching was obtained between the results of field and models.

Dimensionless saturations are;

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� �1 22 1

1 1 2

1(1 )1

w ww o i e p

w w p

S BS m NB W W W

S B V� � � �

� � � � ��

� � � � 212 1 2 2

2 2

gog so so p p so i

g p

BBS N R R m N R R G

B V

� ��

� � ��

GD: BLOCK-7 (Horizon-SP)

0

2 000

4 000

6 000

8 000

10 000

12 000

1-Sep-60 22-Feb-66 15-Aug-71 4-Feb-77 28-Jul-82 18-Jan-88 10-Jul-93 31-Dec-98 22-Jun-04 13-Dec-09

Mon

thly

Gas

, Oil

and

Wat

er P

rodu

ctio

n R

ate

0

50

100

150

200

250

300

350

Ave

rage

Res

ervo

ir P

ress

ure,

atm

Pavg,MBE,atm OIL,m3/m GAS,Mm3/m WATER,m3/m Measured-P,atm

GD-352

GD-116

GD-116

GD-116

GD-385

GD-146

GD-146

Pbubble

Pinitial

GD: BLOCK-7 (Horizon-SP)

-

5

10

15

20

25

30

1-Sep-60 22-Feb-66 15-Aug-71 4-Feb-77 28-Jul-82 18-Jan-88 10-Jul-93 31-Dec-98 22-Jun-04 13-Dec-09

Cum

ulat

ive

Oil

(Np)

, Gas

(Gp)

, Wat

er (W

p) P

rodu

ctio

n an

d W

ater

Influ

x,(W

e)

0

50

100

150

200

250

300

350

Ave

rage

Res

ervo

ir P

ress

ure,

atm

Measured-P,atm Np,MMstb Gp,Bscf Wp,MMstb We,MMrbbl Pavg,MBE,atm

Gp

WeNp

Wp

2

22

)(

p

opo V

BNNS

��

+��$j��q5 �<`&��0&/5��=

+��$j��q5 �<`&��0&/5��=

1

1

ww

w o ro wfield

rw ofield

qf

q q kk

��

��

� ��

��


��

, and (26)

The oil and water relative permeability equations are;

and (27)

Equation 27 was used to calculate the relative permeability ratio (kro/krw)model to compare with the results of field on Figure 24. Figure 25 shows the calculated kro and krw with Equation 27. Figure 26 shows the calculated krg and kro with Equations 27 and 29.

The instantaneous gas-oil ratio (GOR) and solution

gas-oil ratio (Rs) field data were used with PVT data to estimate (krg/kro)field and the results are shown on Figure 26.

(28)

Equation 28 was reorganized to calculate (krg/kro)field and the values are plotted on Figure 27.

and (29)

Equation 29 was used to calculate krg and it was shown on Figure 27. The oil relative permeability, kro, was obtained with Equation 27. The ratio of (krg/kro)model was calculated and the values are plotted on Figure 28.

;�4%��@(��.��9��/��%�&�%�b/�!%��*&��(��2&��/�$%&�'5

Reservoir type/Drive mechanism 1�/��&*��&2��)�*��&�<x�&*��b�=

Tight oil reservoirs, slightly fractured or heavy oil reservoirs 5-10 Oil reservoirs produced mainly by solution gas drive 10-25

Oil reservoirs producing under partial water drive, gas injection or gravity drainage 25-40 Oil reservoirs produced by conventional water-flood 40-55

;�4%��1��&2��)�*��&�(�*&��9�**��/��(��2&��(

��3��%>��(��/9�"��(��&/(�&*��(��2&��>�$%&�'5

( )(1 )

o oroD

wir or

S SS

S S�

��

( )(1 )

w wirwD

wir or

S SS

S S�

�� (1 )

ggD

wir or

SS

S S�

� �

mod

1.597530.601elrw wDk S�

mod

1.37(1 )elro wDk S� �


0.00

0.10

0.20

0.30

0.40

0.50

0.60

0.70

0.80

0.90

1.00

1-Se

p-60

22-F

eb-6

6

15-A

ug-7

1

4-Fe

b-77

28-Ju

l-82

18-Ja

n-88

10-Ju

l-93

31-D

ec-9

8

22-Ju

n-04

13-D

ec-0

9

Ave

rage

Sat

urat

ions

(fra

ctio

n)

0

5

10

15

20

25

30

Rec

over

y Fa

ctor

(RF)

, %

of O

OIP

RF

So

Sw

Sg

��%��/��%��(��.��&/�<$%&�'5 ��1�(��2&��=Volumetric ��%�4�%�/��<�Y�5��=

N 38.547 MMstb N 35.390 MMstb Soi 0.760Current recovery

*��&��<�!��%��= ��/��&2��)�*��&� So-current 0.552 ��/��&2��)�*��&�

Npcurrent 8.895 MMstb Npcurrent 8.895 MMstb Boi (rb/stb) 1.1212 RF=((Soi/Boi)-(So/Bo))/(Soi/Boi)RF=Np/N 23.1 % OOIP RFcurrent=Np/N 25.1 % OOIP Bo (rb/stb) 1.0934 �� 25.4

��%�/��2��/�%)(�(�<��5�� =

Ultimate recovery factor Soi 0.760 Pres-future, atm 130.6Npreserve 4.246 MMstb So-future 0.445 7%��.��&2��)�*��&�Npultimate 13.141 MMstb Boi (rb/stb) 1.1212 RF=((Soi/Boi)-(So/Bo))/(Soi/Boi)

RFultimate=Np/N 37.1 % OOIP Bo (rb/stb) 1.0508 �� 37.5

mod 1

1.202981.00665elrg gDk S�

mod 2

1.36906(1 )elrg oDk S� �

� � o orgsfield

ro g gfield

BkGOR R

k B�

�

� ��


��

16

��

Depletion Drive Index (DDI) (25)

Segregation Drive Index (SDI) (26)

Compaction Drive Index (CDI) (27)

Water Drive Index (WDI) (28)

Reservoir Drive MechanismsTable 6 shows the indices for depletion drive (DDI),

segregation drive (SDI), compaction drive (CDI) and water drive (WDI) mechanisms [8]. The denominator for each index is the same; total cumulative oil-zone production on a reservoir volume basis. This is the factor to normalize the energy (expansion) associated with each of the drive mechanisms. When production begins from a new reservoir, the pressure declines. So, every reservoir operates, in the beginning, predominantly by expansion drive. Whether much water drive occurs depends upon the proximity of water (bottom or edge),

the volume of water, and the permeability-area product available to the water. A drive index may be considered as the fraction of total oil zone withdrawals due to a particular drive mechanism.

��<kro/krw=�2(�"��(��&/ ��+�(5&�%��%��2��!��.��4�%��)

��%5"��%��2��!��.��4�%��)

� �� 1g

oigi

p o p s g

BNB m

B

N B R R B

��

� �


0.00

0.20

0.40

0.60

0.80

1.00

0.00 0.20 0.40 0.60 0.80 1.00Sw, fraction

kro

0.00

0.20

0.40

0.60

0.80

1.00

krw

kro

krw


0.00

0.20

0.40

0.60

0.80

1.00

0.00 0.20 0.40 0.60 0.80 1.00

So, fraction

kro

0.00

0.20

0.40

0.60

0.80

1.00

krg

krokrg

� �� gspop

wpe

BRRBNBWW��

�

;�4%��Reservoir drive mechanism indices

� ��

� ��

11

oiW WC f

WC

p o p s g

m NBc S c p

S

N B R R B

��

�

� �

� � � ��

o oi si s g

p o p s g

N B B R R B

N B R R B

� � �

� �


y = 6.4847e-7E-05x

R2 = 6E-06

y = 3453.4e-15.243x

R2 = 0.987

0.1

1.0

10.0

100.0

1 000.0

0.00 0.20 0.40 0.60 0.80 1.00Sw, fraction

kro/

krw

(kro/krw)Field

(kro/krw)model

��


��

Since the initial gas cap (m) for SP reservoir is zero, SDI is also zero. The reservoir drive mechanism indices were calculated with production and PVT data. In early production time, depletion drive together with compaction drive and fluid expansion mechanisms were dominant. After water entrance into the reservoir, water drive mechanism played an important role together with depletion drive mechanism (Fig.29). This type of information will be useful for the reservoir development strategies that lead to possible improved oil recovery activities.

The summation of all reservoir drive indices is one.

DDI + SDI + CDI + WDI = 1 (29)

Ultimate Recovery FactorThe current recovery factor was obtained as 25% of

OOIP. The decline curve analyses for the wells were done to estimate the remaining recoverable reserve from SP Horizon in Block-7. The past average annual decline was 0.18 1/year. The project time is 15 years after 2012 and the remaining recoverable reserve was estimated as 4,246 MMstb. Therefore, the ultimate oil production was estimated as 13,141 MMstb. It corresponds to the ultimate recovery factor of 37.0% of OOIP. The additional production from SP reservoir was planned to be provided by drilling new wells. This recovery factor is within the recovery range of combined drive mechanisms of solution gas drive and partial water drive. The relation between oil saturation and the recovery factor is shown on Figure 30. Figure 31 shows the additional oil production and predicted average reservoir pressure after 2012.

CONCLUSIONS1. In volumetric method, the net pay, areal extent,

water saturation and porosity data were taken as average values and there are many uncertainties with regard to these parameters. Since the calculated oil in place (N) by material balance method is 35 MMstb less than that of volumetric method (38.5 MMstb), the fluids might be mainly produced from SP reservoir within the boundaries of Block-7. The faults or boundaries set for Block-7 were defined well.

2. In early production time, compaction drive and fluid expansion mechanisms were dominant. After water encroachment, water drive mechanism played an important role together with depletion drive mechanism. The current recovery factor was obtained as 25.0% of OOIP. The ultimate recovery factor was estimated as 37.5% of OOIP by decline curve analysis of well data.

3. Knowledge of reservoir characteristics, which include drainage area size, rock and fluid properties, change in pore volume, amount of water influx and type of reservoir drive mechanisms, gives insight into well spacing efficiency and the need for reservoir development strategies that lead to possible improved oil recovery activities.

4. All rock and fluid properties gathered in this study will be used for reservoir simulation project of SP reservoir in Block-7.

�� <krg/kro=�2(��(�(��&/� ��Q��krg vs gas saturation


y = 1.2664x + 0.0001R2 = 0.177

y = 1.2664x + 0.0001R2 = 0.9016

0.001

0.010

0.100

1.000

0.00 0.02 0.04 0.06 0.08 0.10

Sg, fraction

krg/

kro

(krg/kro)field

(krg/kro)fmodel1


y = 1.0487x + 0.0001R2 = 0.3358

y = 1.0497x + 0.0001R2 = 0.9838

y = 1.0487x + 0.0001R2 = 0.9075

0.001

0.010

0.100

1.000

0.00 0.02 0.04 0.06 0.08 0.10

Sg, fraction

krg

krg-fieldkrg-model1krg-model2


��

18

��

��Y��1�(��2&��9��2��/9��(�*&��(��2&��>�$%&�'�

Block 7 (Horizon-SP)

0.000.100.200.300.400.500.600.700.800.901.00

1-Sep

-60

22-Feb

-66

15-A

ug-71

4-Feb

-77

28-Ju

l-82

18-Ja

n-88

10-Ju

l-93

31-D

ec-98

22-Ju

n-04

13-D

ec-09

Res

ervo

ir D

rive

Indi

ces DDI CDI WDI

DDI

WDI

CDI

ACKNOWLEDGENMENTSThe authors would like to acknowledge technical

support and field data provided for this study and encouragement to publish by Bahar Energy Operating Company.

NOMENCLATUREProduction datafw = Water-cut (fraction) Gp = cumulative gas produced (scf)Np = Cumulative oil produced (stb)Rp = Gp/Np = Cumulative produced gas-oil ratio (scf/stb)Wp = Cumulative water produced (stb)

Reservoir Datacf = Compressibility of formation (psi-1)pi = Initial mean pressure in the reservoir (psi)p = Current average pressure in the reservoir, (psi)Swc = Connate water saturation, (fraction)So = Oil saturation, (fraction)Sg = Gas saturation, (fraction)

Fluid PVT DataBgi = Initial gas volume factor at Pi (ft3/scf)Bg = Gas volume factor at current pressure P (ft3/scf)Boi = Initial oil volume factor at pi (rb/stb)Bo = Oil volume factor at current pressure P (rb/stb)Bt = Total volume factor at current pressure P (rb/stb)cw = Compressibility of water (psi-1)Bw = Formation volume factor of water at current pressure P (rb/stb)Rsi = solution gas-oil ratio at initial pressure Pi (scf/stb)Rs = solution gas-oil ratio at current pressure P (scf/stb)

�44��2��&/(CDI: Compaction Drive Index DDI: Depletion Drive Index GD: Gum DeniziMB: Material BalanceOOIP: Original Oil In PlaceSDI: Segregation Drive IndexTWC: Triaxial or Thick Wall Compressive StrengthUCS: Unaxial compressive strength WDI: Water Drive Index

��3��%�(��&/�2(��&2��)�*��&�� 3��Np and Pavg


0

2 000 000

4 000 000

6 000 000

8 000 000

10 000 000

12 000 000

14 000 0001-

Sep-

60

2-A

pr-7

0

1-N

ov-7

9

1-Ju

n-89

31-D

ec-9

8

31-Ju

l-08

1-M

ar-1

8

30-S

ep-2

7

Np,

stb

0500100015002000250030003500400045005000

Ave

rage

Res

ervo

ir P

ress

ure,

ps

i

Np

Pavg

New Wells


y = -0.0084x + 0.76

R2 = 0.9957

0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0 5 10 15 20 25 30 35 40 45 50Oil Recovery Factor, % OOIP

Oil

Satu

rati

on, f

ract

ion

��


��

Reference

1. V.Abreu, D.Nummedal. Miocene to Quaternary sequence stratigraphy of the South and Central Caspian Basins /in "Oil and gas of the greater Caspian area" AAPG Studies in geology. -2007. -P.65-86.

2. E.Fjaer, R.M.Holt, P.Horsud, A.R.Raen, R.Risnes. Petroleum related rock mechanics. Amsterdam: Elsevier Science Publishers BV, 1992.

3. S.Bruce. A mechanical stability log //SPE/IADC Drilling Conference. Texas:Houston. -1990. -P.276-281

4. J.Geertsma. The effect of fluid pressure decline on volumetric changes of porous rocks //Transactions IME. -1957. -Vol.210. -P.331-339.

5. G.H.Newman. Pore volume compressibility of consolidated, friable and unconsolidated reservoir rocks under hydrostatic loading //Journal of Petroleum Technology. -1973. -Vol.25. -No.2. -P.129-134.

6. P.M.Collins. Geomechanics and wellbore stability design of an offshore horizontal well, North Sea //SPE International Thermal Operations and Heavy Oil Symposium and International Horizontal Well Technology Conference. Canada: Calgary, Alberta. -2002.

7. M.A.Mahmood, A.Al-Marhoun. Evaluation of empirically derived PVT properties for Pakistani crude oils //Journal of Petroleum Science and Engineering. -1996. -Vol.16. -Issue 4. -P.275-290.

8. C.R.Smith, G.W.Tracy, R.L.Farrar. Applied reservoir engineering. OK, USA: Oil&Gas Consultants International Inc., 1992.

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