reservoir engineering job!!!

7/30/2019 Reservoir Engineering Job!!!

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The description of reservoir and its contained is theMost important phase of Reservoir Engineering job .

More precisely reservoir description , known asformation evaluation involves:

Gathering of appropriate and accurate data on thephysical characteristics of the Formation rocks and onthe characteristics of fluid within these rocks.

Interpretation of these data for accuracy and reliability

Evaluation of potential sources of reservoir producingenergy such as an Aquifer or Gas cap.

Reservoir Engineering job!!!


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A Data gathering program for a newlydiscovered field should be designed to

answer two fundamental questions :

Oil or Gas present in the Formation is in economicquantities or not .

How can the reservoir be developed and producedfor maximum economic return?



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Kinds of data :

Original reservoir pressure and temperature

Gross reservoir thickness at the well and the thickness of other

productive zones penetrated

The lithology of the reservoir rock

The stratigraphic sequence of the rock encountered in the well

Reservoir porosity and initial fluid saturations

The natural productivity index of the well

Characteristic of the reservoir fluid



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sources of data :

Cores

Logs including Fullset logs and MDT,XPT,PLT &FMI

Fluid samples

DST & Production tests



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Other data that should be obtained from wells drilled afterdiscovery:

Areal variation in reservoir permeability , porosity and water saturation

Continuity of reservoir zones between wells

Vertical permeability variations within the reservoir

The subsea depth of the top and base of the reservoir for structure maps

Structural position of the reservoir Gas-Oil and Water-Oil contacts

Variation in reservoir fluid composition within the reservoir



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CLASIFICATION OF RESERVOIR ANDRESERVOIR FLUID

Petroleum reservoirs are classified as oiland gas reservoirs.

This clasification is subdivided dependingon :

The composition of the reservoir Hydrocarbon mixture

Initial reservoir pressure and temperature

Pressure and temperature of the surface production


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PRESSURE TEMPERATURE DIAGRAM

Although differentHydrocarbon systemwould have a different

phase diagram ,thegeneral configurationis similar.

These diagrams areessentially used to:1. Classify the reservoir

2. Describe the phase behaviorof reservoir fluid


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OIL RESERVOIR

Depending upon initial

reservoir pressure oilreservoirs can besubclassified into thefollowing categories :

Undersaturated oil reservoir

Saturated oil reservoir

Gas cap reservoir

1

2

3


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OIL RESERVOIR

Crude oils arecommonly classified

into the followingtypes:

Ordinary black oil

Volatile oil

Near critical crude oil


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GAS RESERVOIR

On the basis of phase diagram andreservoir condition Natural gases are

classified into four categories:

Retrograde gas condensate

Near critical gas condensate Wet gas

Dry gas


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GAS RESERVOIR


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COMPOSITION OF VARIOUS RESERVOIR FLUIDTYPE


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RESERVOIR FLUID PROPERTIES

To understand and predict of volumetric behavior of oil and gasreservoirs as a function of pressure, knowledge of physicalproperties of reservoir fluid must be gained.

These fluid properties are usually determined by laboratoryexperiments on reservoir fluid.

In the absence of experimentally measured properties , it isnecessary for the petroleum engineers to determine properties

from empirically correlations.


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LABORATORY ANALYSIS FOR RESERVOIR FLUID

SAMPLING :

Samples of reservoir fluid arecollected and dispatch to a

laboratory for the full PVTanalysis.

There are basically two wayof collecting PVT samples.

1. Direct subsurface sampling

2. Recombination of surfacesamples

quality of the samplesshould be checked


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Accurate laboratorystudies of PVTexperiments are

necessary forcharacterizing thereservoir fluids andevaluating their

volumetric performanceat various pressurelevels.


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PVT sampling

Three main type oflaboratoryexperiments are asfollows:

Primary tests

Routin laboratory tests

Special laboratoryPVT tests


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Primary tests

including routin onsite field

tests involving themeasurement of specific gravity& GOR of the producedhydrocarbon fluids.



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Routin laboratory testsAfter checking the samples There are several laboratory tests that

are routinely conducted to characterize the reservoirhydrocarbon fluid which is included:

Compositional analysis of the system

Constant composition expansion

Differential liberation

Separator tests

Constant volume depletion


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Compositionalanalysis of thesystem

Most of the parametersmeasured in a reservoirfluid study can becalculated with somedegree of accuracyfrom the composition.

It is the most completedescription of thereservoir fluid that can bemade

Stock Tank Oil Solution Gas Reservoir Oil

(mol%) (mol%) (mol%)

H2S 0.00 9.69 5.78

N2 0.00 0.02 0.01

CO2 0.00 4.07 2.43

C1 0.00 59.21 35.35

C2 0.16 10.74 6.48

C3 0.99 6.98 4.56

iC4 0.58 1.67 1.23

nC4 1.87 3.51 2.85

iC5 1.31 1.25 1.27

nC5 1.37 1.27 1.31

C6 9.84 1.17 4.66

C7 8.82 0.35 3.76

C8 8.35 0.08 3.41

C9 8.69 0.01 3.51

C10 8.01 0.00 3.23

C11 6.05 0.00 2.44C12+ 43.96 0.00 17.71

241

414

89

0.8962Sp.Gr. of C12+ Fraction @ 60/60 oF

* Recombined oil separated at atmospheric condition( 0 psig and T=70OF)

Reservoir F lu id Compositi on

Components

100.00GOR* : 669.33 SCF/STB

Molecular weight of residual oil

Molecular weight of C12+ fraction

Molecular weight of Reservoir oil

-Relative Density - 0.6865

FLUID - - -

Reservoir Flu id(g/cm

3)

3-DensitySep a ra t or L iq u i d Sep a ra t or Ga s

FLUID 82.94 19.90 25.33

C12+ - - -

C7+ - - -

0.55

Total 100.00 100.00 100.00

C12+ 6.43 0.00

Pseudo C11 2.73 0.00 0.23

Pseudo C10 4.41 0.00 0.38

Pseudo C9 7.12 0.02 0.63

Pseudo C8 9.84 0.06 0.90

Pseudo C7 9.77 0.09 0.92

10.82 83.68 77.38

C2H6 4.62 4.19 4.23

CH4

4.87

H2S 8.49 4.24 4.61

2.18CO2 5.12

RESERVOIR FLUID ANALYSIS

1-COMPOSITION (mol % )

C om p on en t S ep ar at or L iq ui d S ep ar at or G as R es er vo ir f lu id

N2 0.11 0.10 0.10

C3H8 6.24 1.49 1.91

iC4H10 2.68 0.25 0.46

nC4H10 7.03 0.42 1.00

iC5H12 5.10 0.11 0.54

Pseudo C6 8.43 0.13 0.84

nC5H12 4.00 0.11 0.45

2-Molar Mass S ep ar at o r L i qu id S ep ar at o r G as R es er v oi r F lu i d g /mo l

C12+ - - -

C7+ - - -


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Constant compositionexpansion


Press. Total F.V.F Compressibility

psia Bt E-6

8535 0.8625 2.0857 29.34

8036 0.8752 2.1163 29.63

7537 0.8881 2.1476 29.95

7038 0.9014 2.1797 30.29

6543 0.9149 2.2123 30.66

6046 0.9288 2.2460 31.06

5548 0.9432 2.2808 31.50

5049 0.9580 2.3166 32.00

4550 0.9733 2.3536 32.55

4150 0.9860 2.3843 33.05

4050 0.9893 2.3921 33.18

3950 0.9925 2.4001 33.32

3849 0.9959 2.4082 33.46

3749 0.9992 2.4162

3724 1 .000 0 2.4181

3608 1.0156 2.4558

3592 1.0178 2.4611

3576 1.0200 2.4664

3561 1.0219 2.4712

3547 1.0238 2.4756

3532 1.0258 2.4806

3508 1.0291 2.4885

3472 1.0338 2.4998

3424 1.0404 2.5158

3353 1.0509 2.5412

3254 1.0668 2.5795

3120 1.0905 2.6369

2940 1.1262 2.7233 2.1134 2.1148 1.1261

2719 1.1798 2.8528 2.0567 2.0546 1.1591

2454 1.2609 3.0490 1.9841 1.9824 1.2339

2155 1.3836 3.3456 1.8985 1.9009 1.3469

1835 1.5680 3.7915 1.8127 1.8138 1.5186

1515 1.8453 4.4621 1.7252 1.7266 1.7768

1212 2.2594 5.4634 1.6459 1.6440 2.1643

1142 2.3915 5.7828 1.6251 1.6250 2.2750

Constant M ass Expansion @ 287 F

** Y = 2.7240E-04 P + 1.3139

Smoothed VtSmoothed Y**Vt Y Function

*

2.0000

2.0500

2.1000

2.1500

2.2000

2.2500

2.3000

0 1 0 00 2 0 0 0 3 0 0 0 4 0 0 0

ii

tt

t

iO

PP

VV

VC

ii

i1

11

STOCK

TPt V

VB &

1*

t

b

VP

PPY


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Constant volumedepletion

Press. Total F.V.F Compressibility

psia Bt E-6

8535 0.8625 2.0857 29.34

8036 0.8752 2.1163 29.63

7537 0.8881 2.1476 29.95

7038 0.9014 2.1797 30.29

6543 0.9149 2.2123 30.66

6046 0.9288 2.2460 31.06

5548 0.9432 2.2808 31.50

5049 0.9580 2.3166 32.00

4550 0.9733 2.3536 32.55

4150 0.9860 2.3843 33.05

4050 0.9893 2.3921 33.18

3950 0.9925 2.4001 33.32

3849 0.9959 2.4082 33.46

3749 0. 9992 2. 4162

37 24 1.00 00 2.41 81

3608 1. 0156 2. 4558

3592 1. 0178 2. 4611

3576 1. 0200 2. 4664

3561 1. 0219 2. 4712

3547 1. 0238 2. 4756

3532 1. 0258 2. 4806

3508 1. 0291 2. 4885

3472 1. 0338 2. 4998

3424 1. 0404 2. 5158

3353 1. 0509 2. 5412

3254 1. 0668 2. 5795

3120 1. 0905 2. 6369

2940 1.1262 2.7233 2.1134 2.1148 1.1261

2719 1.1798 2.8528 2.0567 2.0546 1.1591

2454 1.2609 3.0490 1.9841 1.9824 1.2339

2155 1.3836 3.3456 1.8985 1.9009 1.3469

1835 1.5680 3.7915 1.8127 1.8138 1.5186

1515 1.8453 4.4621 1.7252 1.7266 1.7768

1212 2.2594 5.4634 1.6459 1.6440 2.1643

1142 2.3915 5.7828 1.6251 1.6250 2.2750

Constant M ass Expansion @ 287 F

** Y = 2.7240E-04P + 1.3139

Smoothed VtSmoothed Y**Vt Y Function

*

2.0000

2.0500

2.1000

2.1500

2.2000

2.2500

2.3000

0 1 0 00 2 0 0 0 3 0 0 0 4 0 0 0

ii

tt

t

iO

PP

VV

VC

ii

i 1

11

STOCK

TPt V

VB &

1*

t

b

VP

PPY



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Differential liberationOil

Density

g/cc

8535 2.0857 0.6194

8036 2.1163 0.6105

7537 2.1476 0.6016

7038 2.1797 0.5927

6543 2.2123 0.5840

6046 2.2460 0.5752

5548 2.2808 0.5665

5049 2.3166 0.5577

4550 2.3536 0.5489

4150 2.3843 0.5419

4050 2.3921 0.5401

3950 2.4001 0.5383

3849 2.4082 0.5365

3749 2.4162 0.5347

3724 0.00 1953.10 2.4181 0.5343

3047 501.68 1451.42 2.0603 0.5821

2543 768.44 1184.67 1.8669 0.6162

2039 992.88 960.23 1.7187 0.6453

1534 1182.42 770.68 1.5947 0.6733

1028 1370.90 582.21 1.4852 0.6985

520 1601.63 351.47 1.3700 0.7208

14.7 1953.10 0.00 1.1118 0.7456

Bo@ 60oF = 1.0

Pressure psia

Cumulative

Lib.GOR(2)

SCF/STB

Bo(3)

Bbl/STB

Solution GOR(1)

SCF/STB

3-Barrel of oil @ indicated pressure & temperature per barrel of residual oil @60oF Ii

2-Cubic feet of liberated gas @ 14.696 psia & 60

o

F per barrel of residual oil @60

o

F

1-Cubic feet of solution gas @ 14.696 psia & 60oF per barrel of residual oil @60

oF

Di ff erential Vapor ization @ 287 F



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Special laboratoryPVT testsSlim tube test


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Coring and core analysis

Coring is the most basic formation evaluation

tools. Core analysis provide the only initial means of

determining the wettability ,capillary andrelative permeability characteristics of a

reservoir. The successful use of quantitative logs

requires core analysis data for log calibration.

RESERVOIR ROCK PROPERTIES


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There are basically two main categories of coreanalysis tests that are performed on coresamples:

Routin core analysis tests Porosity Permeability SaturationSpecial core analysis

Capillary pressure Relative permeability Wettability Surface and interfacial tension



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1- POROSITY =Vp/Vb

Is a measure of the spaceavailable for fluid storage

ABSOLUTE POROSITY EFFECTIVE POROSITY

- The percentage of isolated poresis usually rather unimportant for

good reservoir rocks

- Effective porosity shows a bettercorrelation with permeabilitythan the absolute porosity


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Absolute porosity:

a =total pore volume/bulk volume

Effective porosity:

e =interconnected pore volume/bulk volume


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PERMEABILITY

-The fluid conductancecapacity in the porousmedium.

-Permeability is the propertyof a porous material thatcharacterized the ease withwhich fluids can go throughthe material by a givenpressure gradient.

-For horizontal linear flow ofan incompressible fluidDarcys law is used :

Q=KAdP/ dL



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Saturationis defined as that fraction or percent of porevolume occupied by a particular fluid.

fluid saturation= total volume of thefluid/pore volume

So=volume of oil/pore volume

Sg=volume of gas/pore volumeSw=volume of water/pore volume



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Wettabilitywettability is defined as the tendency

of one fluid to spread on a solidsurface in the presence of otherimmiscible fluid.

As the contact angle decrease thewetting characteristic of the fluidincrease.

Complete wettability is at zero contactangle and a complete non wetting is

by 180contact angle The wettability of reservoir rock to

the fluids in the porous media is afunction of wettability



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Surface and interfacial tensionIn multiphase system it is

necessary to consider theeffect of the forces at the

interface where twoimmiscible fluid are in contact.When the interface is between a

liquid and a gas it is namedsurface tension and if it isbetween two liquid is namedinterfacial tension.

Tensiometer and Pendent Drop istwo tools for measuringsurface and interfacialtension.


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Capillary pressureThe capillary forces in a petroleum reservoir are the results of the

combined effect of the surface and interfacial tension of therock and fluids.

The pore size and geometry and the wetting characteristics of thesystem.

The displacement of one fluid by another in the pores of a porousmedium is either aided or opposed by the surface forces ofcapillary pressure.

Capillary pressure can be expressed as:

Pc=Pnw-Pw



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The capillary pressure that exist within aporous medium between two immiscible

phases is a function of the interfacial tensionsand the average size of the capillaries whichcontrol the curvature of the interface.

The curvature is also a function of the

saturation distribution of the fluid involved.



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The capillary pressure saturation data can beconverted into height-

saturation data byarranging an equationand solving for a heighth above the free-water

levelh=144*Pc/



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Calculating reservoir capillary pressure datafrom laboratory data:

Laboratory Pc should be corrected before usingfor reservoir condition :

Pcl= 2(COS)L/r

PcR= 2(COS)R/r

PcR= Pcl * (COS)R/(COS)LThe contact angles are usually unknown so

PcR= Pcl * ()R/()L


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Variation of transition zone withfluid gravity:

The height above FWL increases withdecreasing the density difference

From a practical standpoint , this meansthat in a gas reservoir having aGWC , the thickness of thetransition zone will be a minimumsince will be large.

If all other factors remain unchanged ,

a low API gravity oil reservoir withan OWC will have a longer transitionzone than a high API gravity oilreservoir.



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Variation of transition zone withpermeability:

The reservoir pore size can oftenbe related approximately topermeability, and where thisapplies, it can be stated that highpermeability reservoirs will haveshorter transition zones than low

permeability reservoirs .So a tiltedOWC could be caused by a changein permeability across a reservoir



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Relative permeabilityeffective permeability of any reservoir fluid is a function of

the reservoir fluid saturation and the wettingcharacteristic of the formation . Ko,Kg and Kw are theaccepted symbols for the effective permeability tooil,gas and water.

The absolute permeability is a property of porous mediumand is a measure of the capacity of the medium totransmit fluids.

When two or more fluids flow at the same time, therelative permeability of each phase at a specificsaturation is the ratio of the effective permeability ofthe phase to the absolute permeability

Kro=Ko/KKrg=Kg/KKrw=Kw/Ksince the effective permeabilities may range from zero to K then:0Kro, Krg, Krw 1


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Normalization and averaging relativepermeability data

Results of relative permeability testsperformed on several core samplesof a reservoir rock often vary.

It is necessary to average the relativepermeability data obtained onindividual rock samples.

For usage this data for oil recoveryprediction , the relative permeabilitycurves should first be normalized toremove the effect of different initialwater and critical oil saturations.

The relative permeability can then bede-normalized and assigned todifferent regions of the reservoirbased on the existing critical fluidsaturation for each reservoir region.



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LOGS

Logging tools provide dataon the lithology of formationpenetrated by the well andon the porosity and water

saturation of reservoir rocks. Logs provide the primary

basis for determining bothGross and Net formationthicknesses.

Correlation of the logs showthe degree of continuity ofthe reservoir.


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Other logs

1. Production log tools

2. Image loges

3. MDT/XPT

LOGS


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PLT TOOLS

Through measuring pressure, densityand temperature will show the

productive zone.

LOGS


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FMI

This tool can give an image ofthe wellbore and some

information about deep ofthe formation and presenceof vugs and fractures and avalue for porosity of thefracture.

LOGS


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LOGS

MDT/XPT

Best method of taking reservoirpressure, fluid gradient and

type of layering of thereservoir is using MDT/XPTtools.


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DST AND PRODUCTION TESTS

A formation test of a well is a production testdesigned to determine the fluid content andthe productivity of the reservoir.

Drill stem testing can establish theproductivity index , determine the truereservoir pressure and locate gas oil & wateroil contacts.

Formation permeability and limitation of thereservoir can be detected by a reasonableproduction test.


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RESERVOIR VOLUMETRICS

Material balance methodThe data gathering program for any reservoir should

include the collection of pressure, production andfluid sample data which is needed for materialbalance calculations.

It is routin to accurately measure and record oilproduction,water and gas produced in associationwith the oil.

For material balance calculations,water and gasvolumes are as important as oil volume.

OOIP can be calculated through material balanceequation.


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Volumetric methodThe volume of stock-tank oil originally inplace in a

reservoir can be calculated from the net reservoir

rock volume , porosity , connate water and oilformation volume factor by the following equation :OIP= V(N/G)(1-Swc)/ Bo

V(N/G) is called the pore volume and is the total volume in the reservoirwhich can be occupied by fluids.

V(N/G)(1-Swc) is called the hydrocarbon pore volume at reservoircondition

OIP= V(N/G)(1-Swc)/ Bo is called the hydrocarbon pore volume atstandard condition



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OIP calculation could be carried outthrough two software:

1. Petrel for reservoir rock volumecalculation

2. Mont carlo(REP) software through

using probablistic analysis.



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robabilistic GIIP Calculations:Key Results Golshan Gas: P

G11, Kangan& U Dalan -

Top Kanganspillpoint (-3500m)

G14, L Dalan - Zakeen - inferred FWL (-3755m)

(Petrel display artefact)

G11, Kangan& U Dalan -

Top Kanganspillpoint (-3500m)

G14, L Dalan - Zakeen - inferred FWL (-3755m)

(Petrel display artefact)

Golshan all Dehram reservoirs

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

0 7'20014'40021'60028'80036'00043'20050'40057'60064'80072'000

GIIP/AGIIP in Bscf

Cummulativeprobability

0

50

100

150

200

250

300

350

400

450

Nr.ofoutcomes

Dependent Cumulative P robability

Independent Cumulative ProbabilityBscf

p10 All Volumes 57882.5



EXP = Mean All Volumes 45310.3

P50: 44.2 TCF


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FLUID PRESSURE REGIMES

The total pressure at any depth, resultingfrom the combined weight of the formationrock and fluids , whether water,oil or gas isknown as the overburden pressure.in thesedimentary basins the overburden pressureincreases linearly in depth and typically hasa pressure gradient of 1 psi/ft .

At a given depth , the overburden pressurecan be equated to the sum of the fluidpressure(FP) and the grain or matrixpressure(GP)

OP=FP+GP Since the overburden pressure remains

constant at any particular depthd(FP)=-d(GP)

Then a reduction in fluid pressure will lead to acorresponding increase in the grainpressure.


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Fluid pressure regimes in hydrocarbon columns aredictated by formation water of the reservoir.

In a perfectly normal case the water pressure at any

depth can be calculated as :Pw = (dP/dD)water *D +14.7 (psi)

In which dP/dD , the water pressure gradient , isdependent on the chemical composition (salinity) ,and for pure water has the value of 0.4335 psi/ft

The above equation assumes that there is bothcontinuity of water pressure to the surface and thatthe salinity does not vary with depth.



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In contrast to normal hydrostaticpressure , abnormal hydrostatic

pressure are encountered and definedby:

Pw = (dP/dD)water *D +14.7 +C

Where C is a constant and could bepositive if the water is overpressuredand negative if underpressured.



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Range of pressure gradient

(dP/dD)w=0.45-0.52 psi/ft

(dP/dD)0=0.21-0.41 psi/ft

(dP/dD)g=0.08-0.12 psi/ft

At the oil-water contact , thepressure in the oil and watermust be equal otherwise astatic interface would notexist .


reservoir engineering job!!!

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