EVALUATION OF VIABILITY OF A CRUDE OIL … OF... · most economical means of evaluating the viability of a crude oil ... related petro-physical parameters, the stock tank oil ...

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NGWU JAPHET IFEANYI

PG/M.ENG/2007/42922

EVALUATION OF VIABILITY OF A CRUDE OIL RESERVOIR USING

PETROPHYSICAL PARAMETERS (A CASE STUDY OF AGBARA OIL

WELL RESERVOIR IN THE NIGER-DELTA BASIN)

Mechanical Engineering

A THESIS PRESENTED IN PARTIAL FULFILMENT OF THE REQUIREMENTS FOR THE AWARD OF DEGREE OF MASTER OF ENGINEERING (M.ENG) IN

MECHANICAL ENGINEERING.

Webmaster

2009

UNIVERSITY OF NIGERIA

2

EVALUATION OF VIABILITY OF A CRUDE OIL RESERVOIR

USING PETROPHYSICAL PARAMETERS

(A CASE STUDY OF AGBARA OIL WELL RESERVOIR IN

THE NIGER-DELTA BASIN)

BY

NGWU JAPHET IFEANYI

PG/M.ENG/2007/42922

DEPARTMENT OF MECHANICAL ENGINEERING

UNIVERSITY OF NIGERIA, NSUKKA

SUPERVISOR: PROF A.O.ODUKWE

NOVEMBER,2009

1

EVALUATION OF VIABILITY OF A CRUDE OIL

RESERVOIR USING PETROPHYSICAL PARAMETERS

(A CASE STUDY OF AGBARA OIL WELL RESERVOIR IN

THE NIGER-DELTA BASIN)

BY

NGWU JAPHET IFEANYI

PG/M.ENG/2007/42922

A THESIS PRESENTED IN PARTIAL FULFILMENT OF THE

REQUIREMENTS FOR THE AWARD OF DEGREE OF MASTER OF

ENGINEERING (M.ENG) IN MECHANICAL ENGINEERING.

DEPARTMENT OF MECHANICAL ENGINEERING

UNIVERSITY OF NIGERIA, NSUKKA

NOVEMBER,2009.

2

CERTIFICATION

Ngwu Japhet Ifeanyi, a post-graduate student in the department of

Mechanical Engineering, with registration number PG/M.ENG/2007/42922, has

satisfactorily completed the requirements for the course and research work of the

degree of master of engineering in mechanical engineering with option in Industrial

Engineering and Management.

The work embodied in this thesis is original and has not been submitted in

part or in full for any other diploma or degree of this or any other university.

_____________________ _______________________

Ngwu Japhet Ifeanyi Engr. Prof. A. O. Odukwe

Student Project Supervisor

Date…………………….. Date……………………….

_____________________ _______________________

Engr. Prof. S. O. Onyegegbu External Examiner

Head of Department Date………………………..

Date…………………

3

ACKNOWLEDGEMENTS

My sincere gratitude goes to the Almighty God for the enablement and guidance, for

he alone is the source of all knowledge in the mystery of the trinity.

Unique appreciation goes to my project supervisor, Prof. A. O. Odukwe, for the

excellent supervisory skills provided during the planning and review of every phase

of this work. My sincere thanks goes to my sub-supervisor, Engr. Dr. Stephen

Nwanya for his total commitment and guidance in actualizing this noble task.

I am deeply indebted to my immediate family members, especially my elder brother,

Mr. Clifford Emeka Ngwu, whom without his encouragement and financial support,

this work should have died in my mind.

I also wish to express my deep gratitude to the management and staff of Chevron

Nigeria Limited, and Schlumberger Nig Ltd, for their immense corporation given to

me, especially in obtaining their individual data.

Special thanks also goes to some of my postgraduate course mates for their

wonderful encouragements rendered to me at some difficult stages of this work.

It is my fervent hope that every reader of this work will be motivated to know the

most economical means of evaluating the viability of a crude oil reservoir.

4

5

ABSTRACT

This research work is aimed at determining the most economical means of estimating the

quantity of hydrocarbon saturations in a particular reservoir and the evaluation of oil ultimate

recovery using the recovery factor (RF) equations that have been developed. In order to

achieve this aim, a model called Area-depth concept model was developed using Agbara oil

well reservoir in Niger-Delta as a case study. This model is an extension of the existing

volumetric model which has been found insufficient in the evaluation of reservoir viability.

The method considers a reservoir as an enclosed volume element and to planimeter the

isopachous or horizon map drawn from a reservoir cross-section. The integral of the reservoir

volume was taken and the values of bulk gas sand volume, Vg, and bulk oil sand volume,

VO, were analytically estimated from the cumulative bulk volume plot (CBV plot). Using the

collected field data and the necessary related petro-physical parameters, the stock tank oil

initially in place (STOIIP) in the reservoir and the recoverable quantity were analytically

estimated from the CBV Plot. In this study, an evaluation of actual log readings from Niger-

Delta were collected and used to calculate the connate water saturations in order to determine

the productive oil zones in a reservoir by using Achie’s Equations. Equilibrium initialization

algorithm was also used to determine pressure gradient in a particular reservoir . The

research also covered the basic economic measures that are related to oil production.

Considering the related petrophysical parameters involved in the evaluation, the

reservoir was found to contain an oil deposit of 295.8 x 106 stock tank barrel (stb).

The amount recovered for a case where there is a strong aquifer influx was 153.82 x

106 stb. The amount of recovery for a case where there is no aquifer influx was 136.1

x 106 stb. These results showed that the reservoir investigated was economically

viable. It is hoped that this study will be helpful for efficient, quick collection, processing

and interpretation of drilling data to analytically give the accurate estimation of recoverable

hydrocarbon in a particular reservoir in order to achieve optimum yield.

6

TABLE OF CONTENTS

Title page i

Approval page ii

Acknowledgement iii

Abstract iv

Table of contents v

List of figures viii

List of tables ix

List of symbols x

CHAPTER ONE

1.0 Introduction 1

1.1 Objectives of the Study 2

1.2 Significance of the Study 2

1.3 Limitations of the Study 2

1.4 Methodology 3

CHAPTER TWO

2.0 Literature Review 5

2.1 Background of the Study 5

2.2 Petrophysical Evaluation 9

CHAPTER THREE

3.0 Research Methodology 33

3.1 Area-Depth Concept Model 33

3.2 Modification of Formula for Estimation using Volumetric Method 36

3.3 Mathematical Analysis of Reservoir Geometry by Area-Depth

Concept Model using Horizon or Isopachous Map 36

3.4 Assumptions in the Application of Area –Depth Concept Model 38

7

3.5 Limitations of Area- Depth Concept Model 38

3.7 Calculation of the Cumulative Bulk Volume From

The Area-Depth Graph 40

3.8 Petrophysical Data of the Agbara Oil Well Reservoir 43

3.9 Model For Estimation of Oil Ultimate Recovery from the Reservoir 45

3.9.1 Parameters for Recovery Factor Derivation 47

3.9.2 Saturation and Sweep Efficiencies 48

3.9.3 Analysis of oil Ultimate Recovery Using Results from

the Area-Depth Concept Model (cbv – dept plot) 51

3.9.4 Archie’s Law 53

3.9.5 Formation Factor and Archie’s Equation 53

3.9.6 Archie’s Water Saturation Equation 54

3.9.7 The Ratio Method 56

3.9.8 Using Archie’s Equation to Determine Water Saturations 58

3.9.10 Equilibrium Initialization Algorithm for Determining

Pressure in a reservoir 62

3.4.1 Basic Economic Concept of Reservoir Management 65

3.4.2 Definitions of selected economic measures 65

3.4.3 Evaluation of Economic Measures in Relation to Oil Production 65

3.4.4 Evaluation of NPV and Breakeven Oil Price 66

3.4.5 Analysis of Capital Expenditure, Operating Expenditure

and Discount Rate 66

CHAPTER FOUR

Results and Analysis 69

CHAPTER FIVE

5.0 DISCUSION 74

5.1 Exploration Economics 75

5.2 Specific Cost breakdown of an offshore Exploration Well 76

8

5.3 Analysis of the Economic viability of Agbara oil well reservoir

using the total cost expenditure 78

5.4 Formation Evaluation 78

5.5 Well Test Analysis 79

5.6 Importance of Well Test Analysis 80

5.7 Common Types of Reservoir 81

5.8 Application of Fluid Pressure To Determine Gas Oil Contact(GOC),

Gas Water Contact(GWC), Oil Water Contact(OWC) 82

5.9 Pressure and Temperature Gauge Placement 83

5.9.1 Gauge Performance Check 84

5.9.2 Pressure Programming and Interpretation for RFT Analysis 85

5.9.3 Laboratory Analysis of Oil Samples 86

CHAPTER SIX

6.0 Conclusion 87

6.1 Recommendations 88

References

Appendix

9

LIST OF FIGURES

Fig. 4.1. Disciplinary Contributions to Reservoir Flow Modeling 24

3.1 Horizon Map 36

3.2 Cross-Section of an Oil Reservoir 36

3.3 (A) Dome Shaped Structure of a Reservoir with

Top and Base Areas 37

(B) Plan View of a Reservoir Cross Section. 37

3.4: Area – Depth Graph 40

3.5: Cumulative Bulk Volume Plot 42

3.6 Initial Condition of a reservoir 46

3.7 Abandonment Condition of a Reservoir 46

3.8 Saturations and Sweep Efficiency 48

3.9: Data from Actual Log Readings Taken in the Niger-Delta 59

3.10 Depths for Initialization Algorithm 62

10

LIST OF TABLES

Table 2.1: Quick check sand and shale indicator 31

(Resistivity and Gamma Ray)

2.2 Measurement corrections 32

3.1 Values of top and bottom areas 39

3.2 Cumulative bulk volume plot 41

11

LIST OF SYMBOLS

gastheofsSaturationSg S

oiltheofsSaturationSo

F= Net- to – gross ratio

Boi = Initial oil formation volume factor

Ei = Initial gas expansion factor

Ew = Sweep efficiency to water drive

Ssw = connate water saturation

Eg = Sweep efficiency to gas drive

Sorw = Residual oil saturation to water drive

Sorg = Residual oil saturation to gas drive

Ha =Abandonment Oil Column,

= porosity,

Ct = electrical conductivity of the fluid saturated rock.

Cw = the brine saturation

m = Cementation exponent of the rock (usually in the range 1.8-2.0).

n = saturation exponent (usually close to 2).

Rt = Fluid saturated rock resistivity

Rw = the brine resistivity

Sw = fraction of pore volume occupied by water,

F = formation factor, a coefficient equal to the ratio of the resistivity of a 100%

saturated rock to the resistivity of the water solution contained in that rock

Rt = True resistivity of the un-invaded zone.

Rw= Resistivity of the formation water.

ℓ = Density

g = Acceleration due to gravity

12

h = Change in Height

i = Annual inflation rate

Q = Number of times interest is compounded each year

N = Number of years of the expenditure schedule

ΔE(k) = expenses incurred during a time period k

ΔNp(k) = incremental oil production during period k

ROR = Rate of Return

Pun = price per unit quantity produced during year n,

Qn = Quantity produced during year n

Po = present price of oil

)(kNo

p = incremental oil production during period K

rateoductionq Pr

tyPermeabiliK

ityVis cos

AreationalCrossA sec

gradientessureL

PPr

BVg =Gas flooded zone

BVw = Water flooded zone

BVo = Abandonment oil zone

Boa = Formation volume factor at abandonment condition

Vb = Bulk vo

typermeabiliAbsoluteK

oiltotypermeabiliEffectiveK

oiltotypermeabililativeK

o

ro

Re

13

SCFbblfactorvolumeformationgasInitialB

SCFgasreservoirInitialG

STBbblfactorvolumeformationOilB

STBoilproducedCumulativeN

STBbblfactorvolumeformationoilInitialB

STBoilreservoirInitialN

gi

o

p

oi

/,

,

/,

,

/,

,

bblwaterreservoirInitialW

SCFbblfactorvolumeformationGasB

STBSCFratiooilgasSolutionR

STBSCFratiooilgasproducedCumulativeR

STBSCFratiooilgassolutionInitialR

SCFreservoirtheingasfreeofAmountG

g

so

p

soi

f

,

/,

/,

/,

/,

,

1

1

,

,

,

,

,intinf

/,

,

PsiilitycompressibisothermalFormationC

bblspacevoidInitialV

saturationwaterInitialS

PsiapressurereservoiraverageinChangeP

PsiilitycompressibisothermalWaterC

bblreservoiroluxWaterW

STBbblfactorvolumeformationWaterB

STBwaterproducedCumulativeW

f

f

wi

w

e

w

p

14

CHAPTER ONE

1.0 INTRODUCTION

Generally, the major oil companies maintain their own research and

development (R&D) records and also, nurture in-house technological and

engineering skills acquisition schemes. For this reason, some companies see the core

activities needed before oil exploration as unrealistic if carried out, externally.

They now preserve only what is essential to evaluating the cost of exploration

from a particular reservoir.

These core activities include the formation evaluation technique, which is

applied to determine hydrocarbon saturation in a given reservoir, the determination

of oil- in- place (OIP) or stock Tank Oil initially in Place (STOIIP) and the application

of ultimate Recovery Factor (URF), based on analysis of some petrophysical

parameters using current technology.

This research work gives attention to determining the most economical means

of estimating the percentage of hydrocarbon saturation in a particular reservoir, and

its recovery factor. A model called, Area – Depth concept model was developed to

analytically estimate the quantity of crude oil deposits in a reservoir, using Agbara

oil well reservoir as a case study. The basic economic measures that are related to oil

production were evaluated. In this research, Archies’ Law was applied in the

determination of water saturations at different zones in a particular reservoirs based

on the log data of the petrophysical parameters from the Agbara oil well reservoir,

in the Niger-Delta basin. This helps to determine the productive oil zones by

estimating the percentage of hydrocarbon saturations in the reservoir. This study

would help reduce considerably the overall cost involved in executing recovery

process from a particular reservoir in order to achieve optimum yield.

There is no doubt in the fact that the world has consumed approximately 40

percent of the estimated recoverable reserves, i.e. more than one- third of the easily

recoverable reserves have been found and consumed (Stela Shamon,1998).

15

When 50 percent of recoverable reserve is reached, production will inevitably

go down because of the difficulty of extracting the rest. The only hope of extending

the world’s oil reserve is to make a quantum leap in production from 35% to 60%.

1.1 OBJECTIVES OF THE STUDY

1. To estimate the quantity of recoverable hydrocarbon in a reservoir and

evaluate the recovery factor, by using the related petrophysical parameters.

2. To improve the efficacy of volumetric method in reservoir evaluation by

using the area-depth concept model.

3. To determine the productive oil zones in a particular reservoir , by the use of

Archie’s equations.

4 To develop initialization algorithm for determination of

pressure gradient in a reservoir.

5 To evaluate the basic economic measures in relation to oil production.

1.2 SIGNIFICANCE OF THE STUDY

The significance of this research work will include:

Provision of a background for easy interpretation of resulting drilling data

before and during exploration.

Reduction in the overall drilling costs from a reservoir.

Improvement on the quality and quantity of crude oil recovered from a

particular reservoir

Reduction in the cost of energy to consumers

1.3 LIMITATIONS OF THE STUDY

1. First, it would be impossible within the short time frame of this study to

conduct extensive oral or written interviews outside Port Harcourt

2. Secondly, time factor would also not permit to deal exhaustively with the

issues of management views arising from the first constraint.

3. Thirdly, the values of the petrophysical parameters from log readings used

for these evaluations are only dependent upon the precision and accuracy of

the instrument used.

16

1.4 METHODOLOGY

The information for this study will be obtained from the following sources;

Publications such as: Learned journals ,Internet and Seminars.

Research findings from Schlumberger oil services Ltd and Chevron Nigeria Ltd, in

Port Harcourt.

Data collected from actual drill samples during fieldwork was used for the

analysis of formation evaluation. They were collated and analyzed. These data

include the petro-physical parameters like porosity, permeability, resistivity,

shaliness, lithology and formation temperature. These data would be used to

evaluate the viability of a reservoir, by the use of formation factor and Archie’s

Equation. Also, information on economic and management considerations would be

obtained from interviews and observations during a visit to some selected

companies in the Niger- Delta area.

The processes, economics and management of enhanced drilling techniques

are pre-requisite for the actualization of these objectives.

Formation evaluation (Otherwise referred to as log Interpretation) is the

process whereby physically measurable properties are translated into petrophysical

parameters of interest. Some of the major petro-physical parameters that would be

used in this research work, to determine and evaluate the viability of a crude oil

reservoirs are as follows:

Resistivity (R) :- The reluctance of a unit volume of formation (matrix + fluid)

to the flow of electrical current

Porosity (ø):- This is the percentage of void space in a unit volume of rock.

Hydrocarbon saturation (S): This is the percentage of pore space filled with

hydrocarbons (gas or oil).

Permeability (K):- This is the measure of the specific flow capacity or ease

with which fluid flows.

Lithology (L):- This is the study of rocks to determine their character and

composition

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Shaliness (Vsh):- The fraction of a very fine grained detrital sedimentary rock

composed of silt and clay. It is the volume of shale in a particular rock

formation.

Water saturation (Sw)-: The percentage of the porous fraction of formation

that contains water.

18

CHAPTER TWO

2.0 LITERATURE REVIEW

2.1 BACKGROUND OF THE STUDY

The volumetric method for estimating oil in place is based on log and core analysis

data to determine the bulk volume, the porosity and the fluid saturations, and on

fluid analysis to determine the oil volume factor. Under initial condition 1 ac-ft of

bulk oil productive rock contains:

1.2)1(7758tan SwxxOilkStock

But for oil reservoirs under volumetric control there is no water influx to replace the

produced oil, so it must be replaced by gas, of which its saturation increases as the

oil saturation decreases. If Sg is the gas saturation and Bo is the oil formation volume

factor at abandonment conditions, then 1 a c-ft of bulk rock contains;

2.2

)1(7758tan

0

gw SSxxOilkStock

Where 7758 barrels is the equivalent of 1 ac-ft (Allan and Sun, 2003).

The volume element of a reservoir that is considered porous is called the rock

porosity and the fraction of the pore space that is occupied by connate water is

called the connate water saturation Swc. Hence the pore space filled by hydrocarbon

called the hydrocarbon pore volume (HCPV), is given by;

3.2)1( wcSxxVHCPV

The summation of the hydrocarbon pore volume over the gas occupied region will

give the volume of the gas initially in place while the summation over the oil region

will give the oil initially in place all being in reservoir volume (Green and Whillite,

1998). In a reservoir evaluation using the volumetric method, the reservoir system is

considered to be a container whose volume represents the quantity of oil in place.

The porosities and fluid saturation are obtained from core analysis.

For an oil system, there is an amount of water present from origin called connate

water. This is the water in the oil and gas bearing parts of a petroleum reservoir

19

above the transition zone. This water is important because it reduces the amount of

pore space available to oil and gas and it also affects their recovering. Connate water

is generally not uniformly distributed throughout the reservoir but varies with the

permeability and lithology. (Schlumberger Well Evaluation Conference, (SWEC),

1997).

Thus, the fluid saturation with the systems is given by:

.1.:

1

WCSS

SS

o

WCO

A volumetric balance states that since the volume of a reservoir (as defined

by its initial limits) is a constant, the algebraic sum of the volume changes of the oil,

free gas, water, and rock volumes in the reservoir must be zero(Everdingen et al,

1953). For example if both the oil and gas reservoir volumes decrease, the sum of

this two decreases must be balanced by changes, equal in magnitude to the water

and rock volumes.

The ratio of the initial gas cap volume to the initial oil volume, symbol is

given as: volumeoilreservoirInitial

m volumegas freereservoir initial

The value of m is determined from log and core data and from well completion data,

which frequently helps to locate the gas oil and water oil contacts. The ratio m is

known in many instances much more accurately than the absolute values of the gas

cap and the oil zone volume (Firroozabadi, 1996). In the evaluation of the reservoirs

that are produced simultaneously by the three major mechanisms of depletion drive,

segregation or gas cap drive and water drive, it is of practical interest to determine

the relative magnitude of each of these mechanisms that contribute to the

production of oil in the reservoir.

The principal problems in preparing the contour map are the proper

interpretation of net sand thickness from the well logs and the outlining of the

productive area of the field as defined by the fluid contacts, faults, or permeability

barriers on the subsurface contour map.

20

In the evaluation of the approximate volume of the productive zone in a

reservoir with the application of a planimeter, the reservoir is considered to be in the

form of a container. The entire reservoir may be taken to be in the form of a

pyramid, of which the oil volume is taken to be the volume enclosed by the

pyramid. The volume of the frustum of a pyramid is given by

4.2)(3

1 nn AAAAh

Vb ntIn

Also, the second evaluation is to consider a reservoir to be in form of

trapezium. The volume of a trapezoid is given by

5.2.2 1ntnb AAhV

Or for a series of successive trapezoids;

6.22...22(2 1210 AntAAAAAhV avgnnb

These equations are used to determine the volume between successive isopach lines

and the total volume is the sum of these separate volumes (Craft, et al, 1991).

But in area-depth concept model, the reservoir is considered to be in form of a

cone, and the gas oil contact and water oil contact, are determined using resistivity

formation test (RFT) analysis. The bulk volume at each depth can be properly

estimated with minimal percentage error.

Gas fills a reservoir structure from the crest down to the Gas oil contact, GOC. This

shows that the total bulk gas sand volume Vg is equal to the cumulative bulk

volume at the GOC.

GOCg CBVV 2.7

Also oil fills the structure from the Gas Oil contact down to the oil water contact.

This shows that the total bulk oil sand volume Vo, is equal to the cumulative bulk

volume at the oil water contact, OWC, Less the cumulative bulk volume at the Gas

Oil contact, GOC (SWEC, 1997).

GOCOWCo CBVCBVV 2.8

The total free gas saturation to be expected at abandonment condition can be

estimated from the oil and water saturations as reported in core analysis. The

21

expectation is based on the assumption that, while being removed from the well, the

core is subjected to fluid removal by the gas expansion liberated from the residual

oil. This process is somewhat similar to the depletion process in the reservoir.

In the case of reservoirs under hydraulic control, where there is no

appreciable decline in reservoir pressure, water influx is either inward and parallel

to the bedding planes as found in thin, relatively steep dipping beds (edge-water

drive), or upward where the producing oil zone (column) is underlain by water

(bottom water drive). Also, no free gas saturation develops in the oil zone and the

oil volume at abandonment remains the initial oil formation volume factor, Bo

(Green and Whilhite, 1998).

The above equations do not take into account the major petrophysical

parameters to be considered in the evaluation of ultimate recovery and recovery

factors. For example, the gas flooded zone, BVg, which consists of the gross bulk

volume for gas, sweep efficiency to gas drive, and the residual oil saturation to gas

drive. Water flooded zone, BVw, which consists of gross bulk volumes for water,

sweep efficiency to water drive and residual oil saturation to water drive.

Abandoned oil zone, BVa, which consist of the gross bulk volume to oil and the

abandonment oil column, Ha.

In petrophysics, Archie’s law relates the in-situ electrical conductivity of

sedimentary rock to its porosity and brine saturation.

)9.2(SCCm

ww

m

t

Reformulated for electrical resistivity, the equation reads;

10.2S

RR n

wm

wt

It is purely empirical law attempting to describe ion flow (mostly sodium and

chlorine) in clean, consolidated sands, with varying intergranular porosity. Electrical

conduction is assumed not to be present within the rock grains or in fluids other

than water.

22

To evaluate a physical formation, the parameters that are needed are its

porosity, hydrocarbon saturation, bed thickness, and permeability. Resistivity

measurement along with porosity and water resistivity allows to infer the water

saturation (Sw) of a formation’s pore space and thus to derive its hydrocarbon

content (1-Sw). (Frank Shray, 1997). The resistivity of a clean formation is

proportional to the brine with which it is fully saturated. The constant of

proportionality is called the formation resistivity factor, F. If Ro is the resistivity of a

non-shaly formation sample saturated with brine of resistivity, Rw, then

)11.2(w

o

R

RF

For a given porosity, the ratio w

o

R

Rremains nearly constant for all values of Rw

below about one ohm. However, the more the resistive waters, the value of F is

reduced as the Rw rises, and the grain size of the sand decreases. This phenomenon

is attributed to a greater proportionate influence of the surface conductance of the

grains in fresher waters. The formation factor is a function of the porosity, the pore

structure and pore size.(Archie, 1982). In a formation containing oil or gas the

resistivity is a function not only of the formation factor F, and water resistivity Rw,

but also of water saturation Sw.

2.2 PETROPHYSICAL EVALUATION

A Petrophysical evaluation of a reservoir requires the followings:

1. an estimate of the volume of hydrocarbons present and,

2. the rate at which they can be produced.

Volume of hydrocarbons present at any point in reservoir is dependent on porosity

(ø) (volume of pores between rock minerals) and fluid distribution within the pores.

Rate of production is dependent on permeability which is controlled by the

number, size and interconnection of pores.

2.3 POROSITY

This is the pore space available for hydrocarbon accumulation. Porosity, ø is defined

as the ratio of the void space in a rock formation to the bulk volume of the rock. It is

23

a measure of the space in a rock not occupied by the solid structure or framework of

the rock.

Mathematically,

p

p

VvolumeBulk

VvolumePorePorosity

,

, (2.12)

gp

p

VVolumeGrainVVolumePore

VVolumePore

,,

,

b

gb

b

p

V

VV

V

V )( (2.13)

Formulated in terms of densities:

)(

)(.:

fg

bgPorosity

(2.14)

Where ℓf = Density of the saturating fluid. Porosity measurement is necessary to

enable us identify lithology and calculate saturation water while or after drilling

(Allan and Sun,2003)

TYPES OF POROSITY

A). Primary porosity: This is sometimes called “original porosity” because it is an

inherent characteristic of the rock and established during initial deposition. It

is influenced by particle size, shape, sorting, packing and amount of

cementing. Sandstone, shale, chalks, crystalline rocks and oolitic limestone

generally have primary porosity. Primary porosity is responsible for almost

all economical accumulation of oil in sandstone.

B). Secondary Porosity: these results from various types of geological activities

that occur after sediment had been deposited. In this type of porosity, the

shape and size of the pores, their position in the rock and their mode of

interconnection bear no direct relation to the form of the sedimentary

particles. It may result from and be modified by solution, traction, fractures

and joints, recrystallization and dolomitization ,cementation and compaction.

24

Most of the reservoirs characterized by secondary porosity are composed of

carbonate rocks,(e.g. limestone and dolomite).

C) Absolute porosity: This is a measure of the total Pore spaces in a rock as a

function of the Bulk volume regardless of whether the pores are connected or

not. It is also called total porosity.

D) Effective porosity: A measure of the interconnected pore spaces as a function

of bulk volume. It is defined as the ratio of the volume of interconnected pore

space to the total bulk volume of the rock. It is this type of porosity that is

responsible for the migration of oil to well bore. Only this allows crude oil to

flow and be produced.

2.4 FORMATION VOLUME FACTOR FOR OIL, β0

Formation volume Factor of oil is the volume occupied at reservoir conditions

by one stock tank barrel (STB) of oil plus all the gas originally dissolved in it.

conditionsdardsatoilkstockofVolume

conditionsreservoiratgasdissolvedoilofVolumeO

tantan

Oil formation Volume Factor (FVF) is required for both reservoir and production

system calculations. The reservoir engineer must be able to relate stock tank

volumes to reservoir volumes at various pressures under constant reservoir

temperatures.

The volume of oil entering the stock tank at the surface is less than the

volume of oil which flows into the well bore from the reservoir.

The most important factor is the evolution of gas from the oil as pressure is

decreased from reservoir pressure to surface conditions. This causes a large decrease

in oil volume if there is a significant amount of dissolved gas.

Other minor changes include the expansion of the remaining oil due to

reduction in pressure. But this is somewhat offset by the contraction of the oil due to

the reduction in temperature.

25

2.5 TOTAL FORMATION VOLUME FACTOR

The total amount of gas produced at the surfaces can of course exceed the solutions

gas since, in addition to dissolved gas, some free gas may also be produced.

The produced gas ratio, R, may therefore be split into two components,

)( ss RRRR (2.15)

The first component, Rs Scf/STB is the solution gas oil ratio, GOR< which when

taken down to the reservoir with one STB of oil will dissolve in the oil at the

prevailing reservoir conditions to yield β0 reservoir with one STB of oil will dissolve

in the oil at the prevailing reservoir conditions to yield β0 reservoir barrels (RB or

res. bbL) of oil plus dissolved gas.

The second component, R- Rs, Scf/STB, is the free gas which when taken

down to the reservoir will occupy a volume of:

(R-Rs) Scf

BRRBx

STB

scf gsg

)( res.bbls (2.16)

:. The total reservoir ( underground) hydrocarbon with withdrawal associated with

one STB of oil is:

gsot BRRBB )( (1.17)

This is called the total formation volume factor, βt

2.6 PERMEABILITY

The permeability of a porous rock is a measure of its ability to transmit fluids. The

magnitude of this fluid- passing property known as permeability is related to the

number, size, shape and continuity of the pores within the rock. A medium of high

permeability will pass fluids with relative ease, while one of low permeability will

pass fluids with difficulty.

A darcy of permeability defined as one in which one centilitre of fluid of one

centipoise ( i.e the viscosity of water at 680F) would flow through a portion of sand

one centimeter in length and having one square centimeter of areas through which

to move if the pressure drop across the sand is one atmosphere.

Permeability is represented by the letter K, and it is usually measured in

millidarcies, md.

26

The permeabilities of hydrocarbon – bearing rocks like sandstone range from a few

millidarcies to several thousand millidarcies. Generally, a sandstone with

permeability lower than one millidarcies is considered to be a non- producer

( Craft, et al.,1991).

Base on experiments by a French engineer, Henry Darcy, permeability is the

constant K in the equation.

L

PKAq

(2.18)

TYPES OF PERMEABILITY

A. Absolute permeability: This is a measure of the Ease of flow of a single fluid

through the porous medium, K.

B. Effective permeability: This is the permeability of a rock to a particular fluid

in the presence of other fluids.

Relative Permeability: This is the ratio of Effective permeability to the Absolute permeability

K

KK

oro . (2.19)

2.7 ROCK COMPRESSIBILITY

Rock compressibility depends on its

- Grain compressibility, Cr and

- Pore compressibility, Cp and

The external bulk of the rock is subjected to constant overburden pressure which the

internal fluid pressure is gradually reduced.

Accordingly, the grains (rock matrix) expand causing a corresponding

reduction in pore space. More fluid would be expelled from the pore spaces than

would be expected from fluid expansion alone.

Rock compressibility also known as formation compressibility Cf may be

given as prf CCC (2.20)

Where Cr = rock grain compressibility and Cp = pore volume compressibility

From most petroleum reservoirs, the change in rock grain volume is much less than

the change in porosity .

27

Accordingly, Cf = Cp = -

dp

dv

v

1 (2.21)

Total compressibility, Ct, The compressibility of Rock and Fluids Together is Given

as ; fggwwoot CCSCSCSC (2.22)

The total compressibility ranges from 10-5 to 10-4 psi-1 for systems above the

bubble point pressure( Green and Wilhite,1998).

When the system drops below the bubble point, the compressibility increases as the

pressure drop

Rock compression affects

- rock matrix, Cr

- pore space, Cp

Formation compression Cf = Cr + cp O

:. Cf = C (2.23)

dp

dv

vv

dvC

10 (2.24)

2.8 DETERMINATION OF OIL –IN-PLACE

OIL- IN- PLACE (OIP): The oil – in- place is the total volume of oil accumulated in

the pores of the reservoir. It could be measure in Stock Tank Barrel, STB or Reservoir

Barrels, RB.

The methods for determination of oil- in- place are:

1 Volumetric method (2) Material Balance method (3) Simulation modeling and (4)

decline curve Analysis method.

2.9 VOLUMETRIC METHOD OF ESTIMATING INITIAL OIL IN PLACE IN

RESERVOIR

The method considers a reservoir system to be a container whose volume

represents the quantity of oil in place. If there is a reservoir with a given porosity ,

then the volume of oil, water and gas in the system is given by:

sg

sw

o

volumeunitporosityGas

volumeunitporosityWater

SvolumeunitporosityOil

)(

)(

)(

28

The porosities and fluid saturations are obtained from core analysis. The area extent

of the reservoir is measured in Acre and the oil column is measured in Feet.

Hence from dimensional analysis, initial oil in place,

= 3615.5

343560

ft

Ibbl

ftacreI

ftXXso

3615.57758

ft

bbiso Xplaceinoilinitial

If the reservoir area is A acres and the oil column is lft, then the initial oil is

place in given by:

Initial oil in place =ftacre

bblftxacrexAxh so

7758

=> Initial oil in place = bblAh so7758 (2.25)

#For an oil system, there is an amount of water present from origin called connate

water. This is the water in the oil- and gas bearing parts of a petroleum reservoir

above the transition zone. It is also called interstitial water. Connate water is

important primarily because it reduces the amount of pore space available to oil and

gas and it also affects their recovering. Connate water is generally not uniformly

distributed throughout the reservoir but varies with the permeability and lithology.

(Schlumberger Well Evaluation Conference,(SWEC),1997).

Thus, the fluid saturation within the system is given by:

1 weo SS (2.26)

:. weo SS 1

Thus initial oil in place is given by;

Initial oil in place= stbShA we)1(7758 (2.27)

Bringing this quantity down to atmospheric condition, we have that the

hydrocarbon in place, which is commonly called the Stock Tank Oil Initially In Place

(STOIIP) is given as:

stbB

SwhASTOIIP

o

)1(7758 (2.28)

Refer To Appendix B for Conversions

29

2.9.1 MATERIAL BALANCE METHOD FOR ESTIMATION OF CRUDE OIL

RESERVE IN A RESERVOIR

The Material Balance Equation, MBE, is the balancing of inventory such as rig

platforms and other rig facilities in the reservoir. The general MBE is of the form:

TOTAL PRODUCTION = TOTAL EXPANSION

The general material balance equation is simply a volumetric balance, which

states that since the volume of a reservoir (as defined by its initial limits) is a

constant, the algebraic sum of the volume changes of the oil, free gas, water, and

rock volumes in the reservoir must be zero (Everdingen, Timmerman and

McMahon,1953). For example, if both the oil and gas reservoir volumes decrease, the

sum of these two decreases must be balanced by changes equal in magnitude to the

water and rock volumes. If the assumption is made that complete equilibrium is

attained at all times in the reservoir between the oil and its solution gas, it is possible

to write a generalized material balance expression relating the quantities of oil, gas

and water produced, the average reservoir pressure, the quantity of water that may

have encroached from the aquifer, and finally the initial oil and gas content of the

reservoir. In developing this mathematical model, the following production,

reservoir and laboratory data are involved.

1. The initial reservoir pressure and the average reservoir pressure at successive

intervals after the start of production.

2. The stock tank barrels of oil produced, at any time or during any production

interval.

3. The total standard cubic feet of gas produced.

When gas is injected into the reservoir, this will be the difference between the total

gas produced and that returned to the reservoir.

4. The ratio of the initial gas cap volume to the initial oil volume, symbol m.

volumeoilreservoirInitial

volumegasfreereservoirInitialm

30

If this value can be determined with reasonable precision, there is only one

unknown (N) in the material balance on volumetric gas cap reservoirs, and two (N

and We) in water-drive reservoirs. The value of m is determined from log and core

data and from well completion data, which frequently helps to locate the gas-oil and

water oil contacts. The ratio in is known in many instances much more accurately

than the absolute values of the gas cap and oil zone volumes(Firoozabadi,1996).

5. The gas the oil volume factors and the solution gas-oil ratios. These are

obtained as functions of pressure by laboratory measurements on bottom-hole

samples by the differential and flash liberation methods.

6. The quantity of water that has been produced.

7. The quantity of water that has been encroached into the reservoir from the

aquifer.

For simplicity, the derivation is divided into the changes in the oil, gas, water,

and rock volumes that occur between the start of production any time t. the change

in the rock volume is expressed as a change in the void space volume, which is

simply the negative of the change in the rock volume. In the development of the

general material balance equation, the following terms are used:

CHANGE IN THE OIL VOLUME

Initial reservoir oil volume = oiNB

Oil volume at time, t, and pressure, op BNNP )( (2.29)

change in oil volume = opoi BNNNB )( (2.30)

CHANCE IN FREE GAS VOLUME

NBoi

GBgim

volumeoilinitialto

gasfreeinitialofRatio

Initial free gas volume = GBgi = NmBoi (2.31)

solutionin

remainingSCF

produced

gasSCF

produced

gasSCF

dissolvedandfree

gasinitialSCF

tatgas

freeSCF ,

31

]SOSoi RNpCNRpNpNRBgi

NmBoiGf

(2.32)

BgNpNRpNpBgi

NmBoi

ttimeatvolumegas

freeservoirRNR SOiSOi

Re

BgNpNRpNpBgi

NmBoiNmBoi

volumegasfree

inChangeRNR SOSOi

(2.33)

CHANGE IN WATER VOLUME

pwwBwPwwBwww

cwpwecwpwevolumewater

inChange

e

(2.34)

CHANGE IN THE VOID SPACE VOLUME

Initial void space volume = Vf

)35.2(PCVPCVVV ffffffvolumespace

voidinChange

Or, because the change in void space volume is the negative of the

change in rock volume:

)36.2(PCV ffvolumerock

voidinChange

Combing the changes in water and rock volumes into a single, term, yields the

following:

i.e. change in water volume + change in rock volume

PCVPWWBW ffcwpwe

Recognizing that Swi

NmBoiNBoifthatandwifW VSV

1and by substitution,

then:

32

Change in water volume + change in rock volume

Pfwiw

wi

oioipwe

cscS

NmBNBWBW

1

)37.2(

11 P

wi

fwiwoipwe

s

cscNBmWBW

Equating the changes in the oil and free gas volumes to the negative of the changes

in the water and rock volumes and expanding all terms,

NpBgRsoNBgRsoNpRpBg

NRsoiBgBgi

NmBoiBgNmBoiNpBoNBoNBoi

)38.2(

11 P

wi

fwiwoipwe

s

cscNBmWBW

Now, adding and subtracting the term soigp RBN then;

gppsoi

gi

goi

oiopooiBRNBgNR

B

BNmBNmBBNNBNB

soigpsoigpsogpsog RBNRBNRBNRNB

)39.2(P

wi

fwiwsoippwe

sI

cscRNmIWBW

Then grouping the terms:

gsosoiopgsosoioooioi BRRBNBRRBBNNmBNB (

)40.2(PsI

cscNBmIWBW

B

BNmBNBRR

wi

fwiw

oipwe

gi

goi

pgsoip

33

Now writing tgsosoiotitioi BBRRBandBBB where Bt is

the two phase formation volume factor, as defined by the equation,

sooigot RRBBB

gi

g

tigoiptpttiB

BINmBBRRBNBBN

)41.2(PsI

cscBNmIWBW

wi

fwiwtipwe

This equation is the general volumetric material balance equation. ( Green and

Wilhite,1998).

It can be rearranged into the following form that is useful:

PsI

cscBNmIBB

B

NmBBBN

wi

fwiw

tigig

gi

titit

)42.2(pwgsoipppe WBBRRBNW

Each term on the left-hand side of equation 2.42 accounts for a method of

fluid production, and each term on the right-hand side represents an amount of

hydrocarbon or water production. The first two terms on the left-hand side account

for the expansion of any oil and/or gas zones that might be present. The term

accounts for the change in void space, which is the expansion of the formation and

cannot water. The fourth term is the amount of water influx that has occurred into

the reservoir. On the right-hand side, the first term represents the production of oil

and gas and the second term represent the water production. The mathematical

model by material balance method can be arranged to apply to any of the different

types of reservoirs.

For example, in an undersaturated oil reservoir, m=o, and thus, equation

(2.42), reduces to:

e

wi

fwiw

titit WPsI

cscBNBBN

34

pwgsoiptp WBBRRBN (2.43)

For gas reservoirs, equation 2.42, can be modified by recognizing that

gitippp GBNmBthatandGRN and substituting these terms into

equation (2.43), then:

ewiSI

fCwiSwC

gitigigtit WPGBNBBBGBBN

pwgoiptp WBBNRGBN (2.44)

When working with gas reservoirs, there is no initial oil amount, therefore, N and

Np are equal to zero. Therefore, the general material balance equation for a gas

reservoir can be obtained as the form;

pwgpewiSI

fCwiSwC

gigigWBBGWPGBBBG

(2.45)

In the study of reservoirs that are produced simultaneously by the three

major mechanisms of depletion drive, segregation or gas cap drive and water drive,

it is of practical interest to determine the relative magnitude of each of these

mechanisms that contribute to the production. Pirson(1958), rearranged the material

balance equation (2.42), to obtain three fractions whose sum in one. That is, the

Depletion Drive Index (DDI), the Segregation Drive Index (SDI), and the Water-

Drive Index (WDI) ( Pirson,1958).

When all the three drive mechanisms are contributing to the production of oil

and gas from the reservoirs, the compressibility term in equation 2.45, is negligible

and can be ignored. Moving the water production term to the left-hand side of the

equation, the following is obtained:

pwegiggiB

tiBmN

tit WBWBBBBN

p

gsoiptp BRRBN

Dividing through by the term on the right hand side of the equation:

35

gsoiptp

giggiB

tiNmB

gBsoiRpRtBpNtiBtBN

BRRBN

BB

46.21

gBsoiRpRtBpN

pWwBeW

The numerators of these three fractions that result on the left hand side of

equation (2.46) are the expansion of the initial oil zone, the expansion of the initial

gas zone, and the net water influx, respectively. The common denominator is the

reservoir volume of the cumulative gas and oil production expressed at the lower

pressure, which evidently equals the sum of the gas and oil zone expansions plus

the net water influx, then using the abbreviations of Prof. Pirson:

1 WDISDIDDI (2.47)

Finally, the general schilthwise material balance equation (2.42), can be

rearranged and solved for N, the initial oil in place:

PwiSI

fCwiSwC

tiBmIgiBgBgiBtimB

tiBtB

pWwBeWgBsoiRpRtBpN

N

(2.48)

If the expansion term due to the compressibilitie’s of the formation and

connate water can be neglected, as they usually are in a saturated reservoir, then

equation 2.48 becomes:

giBgBgiBtimB

tiBtB

pWwBeWgBsoiRpRtBpN

N

(2.49)

2.9.2 ADVANTAGES OF APPLYING MATERIAL BALANCE METHOD FOR

ESTIMATION OF OIL IN A RESERVOIR

1. Determination of initial oil in place

2. Calculation of water influx

3. Calculation of fluid contact movement

4. Prediction of the future recoveries

36

5. Prediction of reservoir pressures

6. Prediction of effect of production rate and/or injection rate (gas or water) on

reservoir pressure

7. Aquifer match of historical production leads to performance prediction.

2.9.3 RESERVOIR SIMULATION MODEL

Modern reservoir simulators are computer programs that are designed to

model fluid flow in porous media. Applied reservoir simulation is the use of these

programs to solve reservoir flow problem.

Modern reservoir management is generally defined as a continuous process

that optimizes the interaction between data and decision making during the life

cycle of a field. More specifically, reservoir management of hydrocarbon reservoirs

is defined as the allocation of resources to optimize hydrocarbon recovery from a

reservoir while minimizing capital investments and operating expenses

(Firoozabadi,1996). The primary objective in a reservoir management study of

hydrocarbon reservoir is to determine the optimum conditions needed to maximize

the economic recovery of hydrocarbons from a prudently operated field.

2.9.4 REASON FOR RESERVOIR SIMULATION

1. Corporate impact

Cash flow prediction

Need economic forecast of hydrocarbon price

2. Reservoir Management

Coordinate Reservoir management activities

Evaluate project performance

Interpret/ understand Reservoir behavior

Model sensitivity to estimated Data

Determine need for additional data

Estimate project life

Predict Recovery versus time

Compare different recovery processes

37

Plan Development or operational changes

Maximize Economic recovery

2.9.5 CONSENSUS MODELLING

This is the application of a computer simulation to the description of fluid flow in a

reservoir. The computer simulator, and the input data set is called the reservoir flow

model.

Many different disciplines contribute to the preparation of the input data set

of a flow model. The information is integrated during the reservoir flow modeling

process, and the concept of the reservoir is qualified in the reservoir simulator.

Fig 2.1 Disciplinary contributions to reservoir flow modeling

(Haldorsen and Damsleth, 1993).

Refer to Appendix C for planning of reservoir simulation

Seismic Petrophyscis Fluid

Properties

Geological

model

Numerical

Simulation

Model

Wells

Wells

Calibration of observations and production

data interpretations

Facilities

Model GRID

Effects

38

2.9.6 ESTIMATION OF OIL RESERVE IN A RESERVOIR USING DECLINE

CURVE ANALYSIS

The relationship between flow rate and time for producing wells assuming constant

flowing pressure, is found as;

1 n

t

qaq

d

d (2.50)

where a and n are empirically determined constants. The empirical constant n

ranges from 0 to 1(Arps, 1945).

Solutions to E.g. (2.50) shows the expected declined in flow rate as the production

time increase. Fitting an equation of the form of Eq (2.50) to flow rate data is

referred to as decline curve analysis. Three decline curves have been identified

based on the value of n.

the exponential decline curve corresponds to n= o. It has the solution

at

ieqq (2.51)

Where qi is initial rate and a is a factor that is determined by fitting Eq (2.51) to well

or field data.

The hyperbolic decline curve corresponds to a value of n in the range 0 < n< 1. The

rate solution has the form.

n

i

n qnatq (2.52)

where qi is initial rate and a is a factor that is determined by fitting Eq (2.52) to well

or field data.

The harmonic decline curve corresponds to n = 1. The rate solution is equivalent to

Eq (2.52) with n= 1, thus;

11 iqnatq (2.53)

where qi is initial rate and a is a factor that is determined by fitting Eq (2.53) to well

or field data.

Decline curves are fit to actual data by plotting the logarithm of observed rates

versus time t. The semilog plot yields the following equation for exponential decline:

atqq i lnln (2.54)

39

Eq (2.54) has the form bmxy , for a straight line with slope m and intercept b. In

the case of exponential decline, time t corresponds to the independent variable x, lnq

corresponds to the dependent variable y, Inqi is the intercept b, and – a is the slope

m of the straight line. Cumulative production for decline curve analysis is the

integral of the rate from the initial rate qi at time t = 0 to the rate q at time t.

For example, the cumulative production of oil in a reservoir, Np, for the

exponential decline case is given as:

t

itp

a

qqqdN

0 (2.55)

The decline factor a is for the exponential decline case and is found by rearranging

Eq (2.55)

Thus:itq

qa

ln1 (2.56)

2.9.7 RECOVERY FACTORS (RF)

The Recovery factor is the fraction of the Hydrocarbon initially in place (HCIIP), that

is deemed recoverable. Thus:

)57.2()( RFHCIIPURRECOVERYULTIMATE

The recovery factor is dependent on reservoir/ hydrocarbon characteristics,

recovery method, operating conditions and economics

( Schlumberger Well Evaluation Conference, 1997)

1. Reservoir characteristics as they affect RF

(a) Hydrocarbon column: This is the initial vertical distance between the

shallowest and deepest hydrocarbon points in the structure. At

abandonment, a certain minimum column will be left behind. This is called

the abandonment column. Ha. This is because a finite thickness of

hydrocarbon column must exist in the reservoir for the hydrocarbon to flow

into the producing well. This minimum depends on the type of well and

whether or not there is simultaneous presence of water and gas in the case of

an oil reservoir. The smaller the abandonment column, the higher the

recovery factor.

40

Other reservoir characteristics which affect recovery factor are:

(a) Presence or absence of gas

(b) Aquifer strength

(c) Residual saturations

(d) Permeability

(e) Heterogeneity

(f) Initial Reservoir pressure

Hydrocarbon characteristics as they affect RF

a) Viscosity

b) Density

c) Gas oil Ratio, GOR

2.9.7 RECOVERY FACTORS (RF)

There are different types of Recovery method which are normally applied during

exploration process. The method to be adopted depends on the nature of the

reservoir.

Primary recovery method: In primary oil recovery method, the recovery factor is

dependent on the natural reservoir energy. These are mainly the strength of aquifer

support and gas cap drive available. In the absence of these, the only energy

available would be due to the dissolved gas (solution gas drive) and reservoir

compaction. Both of these would usually result in recovery factors less than 10%.

However, the presence of a strong aquifer support or gas cap drive could lead to

recovery factors of 30 to 60%(Roman Talamantaz,1996).

ECONOMICS

The economic factors that affect Recovery Factor are:

- Location: The location of a hydrocarbon field affects the recovery

factor as the cost of production from certain remote areas will make

the production of certain volumes uneconomical while the same

volumes in a favourable location will have a non zero recovery factor.

- Price: This determines to a large extent not only the cut off for volumes

to be developed but also the cut off oil rate that can be allowed. Both of

41

these impact on the amount of oil that can be recovered and hence on

the recovery factor.

2.9.8 OPERATING CONDITIONS

The operating conditions that affect the recovery factor are:

- Government Regulations: These include minimum well spacing

requirements, duration of license and abandonment policy. All these

impact on the recovery factor.

- Environmental Regulations: This mainly affects disposable water

quality and gas fanning rules. The more stringent these regulations,

the lower the recovery factor.

- Overhead/operating cost: This affects the economic cut off oil rate. The

lower the operating cost, the lower the cut off oil rate and hence the

higher the recovery factors.

2.9.9 FORMATION EVALUATION

Until the drill bit penetrates the formation through the process of drilling a well, the

presence of petroleum in any formation remains unknown. At best, our geologists

and geophysicists can only suggest a probable structure (spot) where petroleum is

thought to exist. In the oil industry, there are methods the petroleum engineer

employs to locate and determine the quantity of petroleum in formation. In

addition, the evaluation and analysis of the information from the methods also

enable the petroleum engineer to determine and design the most efficient

programme to deplete the reservoir. The use and interpretation of these methods

and information provided by them is referred to as formation evaluation. The sole

objective of formation evaluation is to determine hydrocarbon saturation in a given

reservoir. Different formation Evaluation techniques are applied during the course

of well completion with the sole purpose of achieving one or more of the followings:

1. Identify a potential pay zone – by well log and core analysis.

2. The formation properties such as porosity, permeability and

fluid saturation – By well log and core analysis.

3. The fluid type – By well log, core log and well testing.

42

2.9.10 QUALITATIVE METHOD IN FORMATION EVALUATION

The first step in log interpretation should be to become familiar with the overall

aspects of the log in order to determine which areas are potential zones of interest.

This is done best through qualitative log interpretation.

To do this, the log analyst must try to gather information about typical

responses in the area being drilled. By knowing what tool responses are expected for

various lithologies, it is possible to view the log quite quickly and identify possible

areas of interest which can then be scrutinized more closely.

The log analyst should have in mind some criteria based on experience that

will allow him to identify the zones of interest and to divide the log into zones

which can be used for more detailed scrutiny (typically these will be hydrocarbon

and water bearing sands).

The resistivity of any formation is a function of the fluid type present in the

pore spaces of the matrix. Resistivity is mainly the function of the amount of water

in that formation and the resistivity of the water itself. Salt water is conductive,

while the rock grains and fresh water usually have very low conductivities. In the

Niger-Delta, saline water usually has a resistivity of 0.6 to 2 ohmm, depending on

the concentration of ions and the presence of hydrocarbons. Fresh water is not

common at depths more than 4000ft True Vertical Depth(TVD) and a resistivity

greater than approximately 3 ohmm may indicate a potential hydrocarbon-bearing

zone( Baker,1996).

Gamma ray baselines in the area are usually around 100 – 120 API and any

gamma ray drop below 65% of the shale baseline is generally a good indication of a

sand. Obviously, the cut-off value of the criteria may vary depending on the local

conditions and expected lithologies.

The combination of resistivity, gamma-ray neutron porosity, and rotational

density give a good indication of lithology, except in the presence of a gas. Tight

limestone is characterized by the density overlying the neutron porosity, with

Maximum Rotational Density (ROMT) = 2.71 g/cm3 and Thermal Neutron Porosity

(TNPH) = 0 (the tool is calibrated to match a water filled limestone). A tight

43

sandstone would give maximum Rotational Density (ROMT) = 2.65 g/cm3 and

Thermal Neutron Porosity (TNPH) of approximately -4.0 PU.

In porous formations, the Thermal Neutron Porosity (TNPH) and Maximum

Rotational Density (ROMT) curves separate and move to the left. Thermal Neutron

Porosity (TNPH) in the direction of the higher porosity and Maximum Rotational

Density (ROMT) in the direction of lower densities. If gas is present, the separation

between the curves increases with Thermal Neutron Porosity (TNPH) moving

distinctly to the right (lower porosity) and Maximum Rotational Density (ROMT) to

the left (lower density), this is often referred to as the gas effect.

Shales give high neutron porosity readings, up to 45 Porosity Unit(P.U) as a

result of bound water in their structure. Consequently, the Thermal Neutron

Porosity (TNPH) curve will cross over to the left of the density curve in shale

(Schlumberger Well Evaluation Conference,2000) .

For a Triple Combo Log (Toolstring containing three logging tools), the

following criteria may be used.

1) Low Gamma Ray Reading (GR < 65% of shale baseline)

2) High resistivity (Rad > 3 ohmm).

3) Cross over of neutron and density curves (with porosity and density

decreasing from that of a shale).

The table below shows a typical resistivity and gamma-ray log responses in

shales and sands . The table can be used as a quick look guide for determining

lithology.

44

Table 2.1: Quick Check Sand and Shale Indicator (Resistivity and Gamma Ray).

FORMATION AND

FLUID TYPE

CURVES COMMENTS

Shale Generally low resistivity and

high gamma ray counts

Gas filled clean sand Usually very high resistivity.

Low gamma ray counts

Oil filled clean sand Usually high resistivity low

gamma ray counts

Fresh water filled clean

sand

Usually high resistivity. Low

gamma ray counts

Salt water filled clean

sand

Usually low resistivity. Low

gamma ray counts

Fresh water filled silty

sand

Usually high resistivity. Low

gamma ray counts

Radioactive fresh water,

Gas or oil filled sand

Elevated gamma ray counts.

High resistivity.

KEY: Gamma Ray Curve (GR): (), Reistivity Curve (RES): ( )

Special notes: Possible pay sands or zones of interest generally have high resistivity

and low gamma ray. It is difficult to distinguish between fresh water, oil and gas

filled sands with resistivity and gamma ray only. It is therefore useful to consider

porosity and density to solve this problem. Shaly sands tend to have elevated

gamma ray counts and may be difficult to spot at first glance. Radioactive sands

have high gamma ray counts and may appear similar to shales, a spectral gamma

ray tool is advised if these type of sands are expected.

2.9.14 QUANTITATIVE METHODS

The data usually presented on final logs for client are usually corrected for

borehole effects, so that the measurements more accurately represent the physical

properties of the formation. The usual correction that apply up to this point are

shown below.

45

TABLE 2.2 MEASUREMENT CORRECTIONS

Measurement Symbol Corrections applied

Gammay Ray GR Hole size (bit), tool size, mud

weight

Attenuation Deep Resistivity Rad Borehole Compensated

Phase Shallow Resistivity Rps Borehole compensated

Thermal Neutron Density TNPH Hole size (bit), tool size,

borehole salinity, formation

salinity, matrix type, mud

hydrogen index

Bulk density RHOB Spine and ribs correction

Maximum Rotational

Density

ROMT Spine and ribs correction

SOURCE: Adaptation from “People and Technology”; A Directional Drilling

Training manual by Schlumberger.

At this point, a qualitative analysis is performed (as described in the previous

section) to determine the general properties of the log. Once the log has been

divided into zones by the qualitative analysis and the engineer has identified the

areas of interest, it is possible to undertake a more thorough and detailed numeric

analysis of the data (Texier and Alger,1965).

Several steps are usually taken to improve the accuracy of the data and to

employ empirical or theoretical relationships to the measured parameters to come

up with useful results which can be used to assess the potential of hydrocarbon

recovery from the formation. The steps that are taken usually involve determining

the quantity of hydrocarbon present in the formation and the economic viability of

producing it. Three other important economic factors usually considered before

embarking on production of hydrocarbon from a given reservoir include;

1) Estimation of the quality of recoverable hydrocarbon in the reserviour

2) Estimation of the recovery factor

3) And the evaluation of the financial potential of producing the reservoir

46

CHAPTER THREE

3.0 RESEARCH METHODOLOGY AND DATA ORGANIZATION

3.1 AREA-DEPTH CONCEPT MODEL

This model is developed in order to improve the efficacy of the volumetric

method in reservoir evaluations. Area-Depth concept involves a mathematical

analysis of the reservoir geometry. It uses subsurface and isopachous (horizon) map

based on the data from the electric logs, cores, drill stem and production tests. A

subsurface contour map shows lines connecting points of equal elevations on the top

of a marker bed and therefore shows geologic structure. The engineer uses this map

to determine the bulk productive volume of the reservoir. The volume is obtained

by planimetering the areas between the isopach lines of the entire reservoir or of the

individual units under consideration.

3.2 MODIFICATION OF FORMULA FOR ESTIMATION USING VOLUMETRIC

METHOD

The fraction of the volume element V that is porous is called the rock porosity

ø, and the fraction of the pore space that is occupied by connate water is called the

connate water saturation, Swc.

wcgwcg SSSS 11

Also, 1 wco SS

wco SS 1

Therefore, the saturations of gas or oil in any of the regions in a reservoir is given by

the factor , )1( wcS

Hence, the pore space that is filled by hydrocarbon (Called the Hydrocarbon

Pore Volume (HCPV) is;

)1.(. wcSVHCPV (3.1)

But in practice, there may be some parts of the sand that are not porous and

are discounted with what is called the net-to-gross ratio F where F is the fraction of

the total sand volume that is considered to be porous.

47

sandgrosstheofThickness

sandnettheofThicknessFratiogrosstoNet

Hence,

)1.(.. wcSFVHCPV (3.2)

The summation of this HCPV over the gas occupied region will give the

volume of gas initially in place while the summation over the oil occupied region

will give the oil initially in place, all being in reservoir volume. However, the gas

volume will be multiplied by the initial gas expansion factor Ei. This is because

under pressure in the trap, gas is compressed. As pressure is released, gas expands.

The relationship between reservoir conditions and standard conditions is called gas

expansion factors. And the oil volume will be divided by the initial oil formation

volume factor Boi. Formation volume factor of oil is the volume occupied at reservoir

conditions by one stock tank barrel (STB) of oil plus all the gas originally dissolved

in it. Each of the results will give the corresponding surface volumes initially

in place.

Thus;

Free gas initially in place (FGIIP) = G

= )3.3(1.... wc

gas

SFVE

= )4.3(,)1(43560 scfSFV wcg

where Vg = gas

V is the bulk gas sand volume in ac-ft.

also, Stock Tank Oil Initially in Place (STOIIP) = N

= oi

oil

B

SwcxxFxV )1(

= oi

wc

B

SVoF )1(7758 , stb (3.5).

where Vo = oil

V is the bulk oil and volume in ac-ft

cuftbblftacnote 4356077581:

48

Considering equations 3.4 and 3.5 ,the petrophysical parameters like the gas

expansion factor, E, porosity ,ø, connate water saturation, Swc ,net-to-gross ratio, F

and initial formation volume factor, Boi can easily be determined by the use of

electronic log recording tools. For example, ø, Swc, F are derived from petrophysical

analysis of well logs and cores.

The fluid properties Ei and Boi are derived from Pressure-Volume-

Temperature (PVT) analysis of fluid samples and correlations.

The fluid contacts, GOC, OWC are determined from petrophysical logs or

Resistivity Fluid Test (RFT) pressure analysis.

The major problem in reservoir evaluations for determination of STOIIP and

FGIIP has always been the difficulty in resolving the quantities Vg and Vo in a

particular reservoir . Area – Depth concept model is then developed to analytically

estimate these parameters Vg and Vo and also used to resolve the oil ultimate

recovery by evaluation of the recovery factor.

49

3.3 MATHEMATICAL ANALYSIS OF RESERVOIR GEOMETRY BY AREA-

DEPTH CONCEPT MODEL USING HORIZON OR ISOPACHOUS MAP

9000

Fig. 3.1 Horizon Map.

Source: Drilling Profile Map in Agbara oil Well Reservoir by Chevron Nig. Ltd.

GOC

OWC

water water 8800ft

Consider the dome shaped structure of a reservoir with top and base areas in

fig. 3.12 whose horizon map is shown in fig. 3.10. Take a horizontal elemental

volume slice, Dv of thickness Δft at say a depth of dft. This volume element would

be approximately a hollow cylinder of height dΔft (section view). The inner hollow

area (almost circular surrounded by dots in plan view) will be equal to Abase which is

the area of the base surface at the depth of the slice. The outer area (shaded in plan

view) will be equal to Atop which is the area of the top surface at the depth of the

Free Gas

Oil + Solution Gas

8560ft

Fig. 3.2 Cross-Section of an oil reservoir

(B)

(A)

well

50

slice. The reservoir elemental volume is equivalent to the annular volume of the

cylinder. Thus,

HeightareaAnnulardV

ftacredAAdV basetop )(.: (3.6)

Atop

dD

Abase dD

Section x-x

dV = (Atop – Abase) dD

CBV1 =

d

crestD

basetop

d

crest

dDAAdV

(a) (b)

Fig. 3.3: (a) Dome Shaped structure of a reservoir with top and base areas

(b) Plan view of a reservoir cross section.

X X

Plan

51

3.4 ASSUMPTIONS IN THE APPLICATION OF AREA –DEPTH CONCEPT

MODEL

1) The areas enclosed by the lines of the top and base areas in the area -depth graph

assume to be the cumulative bulk sand volume of the hydrocarbons at

corresponding depths in the reservoir.

dCBV =

d

crestD

basetop

d

crest

ftacredDAAdV )7.3(,

2) By the evaluation of the CBV at different depths, a graph of CBV against depth

gives the volume enclosed by the structure from the crest to any depth d.

3.5 LIMITATIONS OF AREA- DEPTH CONCEPT MODEL

1. Zero-Dimensional: Entire reservoir is treated as tank characterized by one

pressure point.

2. Effect of area-pressure gradients, temperature and flow rates are not

considered (space and time not in equation).

3. Uncertainties in the ratio of the initial free gas volume to the initial reservoir

oil volume also affect the calculations.

4. Accuracy only depends on the precision of the equipment used in calculating

the petrophysical parameters.

52

TABLE 3.1 VALUES OF TOP AND BOTTOM AREAS OF THE RESERVOIR

DEPTH PLANIMETER

UNITS FOR TOP

AREA

TOP AREA FROM

P. UNITS

CONVERSION

PLANIMETER

UNITS FOR

BOTTOM AREA

BOTTOM AREA

FROM P. UNITS

CONVERSION

Ft P. UNITS Mac P. UNITS Mac

8400 0.00 0.00

8500 90.00 0.49

8600 200.00 1.08 0.00 0.00

8700 320.00 1.73 90.00 0.49

8800 420.00 2.27 200.00 1.08

8900 520.00 2.81 320.00 1.73

9000 600.00 3.24 420.00 2.27

Refer to Appendix B for Planimeter readings and conversions

53

Fig 3.4: Area – Depth graph

3.6 CALCULATION OF THE CUMULATIVE BULK VOLUME FROM THE

AREA-DEPTH GRAPH IN FIGURE 3.4

(1) CBV8500

Macft

ABBCABCAbyenclosedAreaCBV

50.2410049.05.0

5.08500

(2) CBV8600

MacftCBV

Macft

BDDEBCbyBCEDBenclosedareaBut

BCEDBbyenclosedAreaCBV

BCEDBbyenclosedAreaABCAAreaADEAbyenclosedAreaCBV

1035.785.24

5.78100)08.149.0(5.0

)(5.0

8600

8500

8600

Refer to Appendix B for CBV Calculations at subsequent depths.

AREA DEPTH GRAPH

0

0.49

1.08

1.73

2.27

2.81

3.24

0

0.49

1.08

1.73

2.27

0

0.5

1

1.5

2

2.5

3

3.5

8300 8400 8500 8600 8700 8800 8900 9000 9100 DEPTH(FT)

AREA(MAC)

TOP AREA BASE AREA

A B

C

D

E

F

G

H

I

J

K

L

M

TOP AREA

BASE AREA

54

Table 3.2

SUMMARY TABLE OF THE CUMULATIVE BULK VOLUME CALCULATED

FROM THE AREA-DEPTH PLOT

DEPTH

(ft)

CBV VALUES

(Macft)

8400 0.00

8500 24.50

8600 103.00

8700 219.00

8800 340.5

8900 454.00

9000 556.50

Finally, the cumulative bulk volume (CBV) – Depth plot is then plotted as in

fig. 3.5 below.

55

Fig 3.5: Cumulative bulk volume plot

Since gas fills the structure from the crest down to the Gas Oil Contact, GOC,

it follows that the total bulk gas sand volume Vg is equal to the cumulative bulk

volume at the GOC.

GOCg CBVV (3.8)

Also, since oil fills the structure from the GOC down to the OWC, it follows

that the total bulk oil sand volume Vo is equal to the cumulative bulk volume at the

OWC less the cumulative bulk volume at the GOC.

GOCOWCo CBVCBVV (3.9)

From the graph of the cumulative bulk volume (CBV) in fig. 3.5. Cumulative bulk

volume, CBV at Gas Oil Contact (GOC) is found to be 64.3 ma-cft, while CBV at Oil

Water Contact (OWC) is found to be 340.5 Macft.

But from equation (3.8),

Bulk gas sand volume , GOCg CBVV

CUMULATIVE BULK VOLUME PLOT

0

24.5

103

219

340.5

454

556.5

0

100

200

300

400

500

600

8300 8400 8500 8600 8700 8800 8900 9000 9100 DEPTH(FT)

BULK

VOLUME

(macft)

Series1

(64.3)

(340.5)

GOC

OWC

56

But CBVGOC is at 8560 ft, from the RFT pressure analysis of GOC indicated on

the horizon map.

Then from the CBV-Depth graph,

Bulk gas sand volume MacftCBVV GOCg 3.64

Also, in equation (3.9);

Bulk oil sand volume

GOCOWCo CBVCBVV

But CBVowc is at a depth of 8800f, from the RFT pressure analysis of OWC indicated

on the horizon map.

CBVowc = 340.5macft (From the CBV – Depth Graph ).

Vo = 340.5– 64.3 = 276.2 Macft.

3.7 PETRO-PHYSICAL DATA OBTAINED FROM AGBARA OIL WELL

RESERVOIR .

Porosity (Ф) 25%

Connate water saturation swc 15%

Initial oil formation volume factor 1.23 rb/stb

Initial gas expansion factor 250 5cf/cf

Sand considered tight (non-porous) 20%

Sweep efficiency to water drive 0.8

Sweep efficiency to gas drive or gas expasion 0.7

Residual oil saturation to gas Sorg 0.15

Residual oil saturation to water, Sorw 0.2

Gas saturation 0.02

Initial oil formation volume factor, Boi 1.23rb/stb

Net – to – gross sand ratio (F) 0.8

57

Then, using the equation (3.4),

scfESFVFGIIP wcg ,)1(43560 .

=> FGIIP = 43560 x 250 x 64.3 x 106 x 0.8 x 0.25 x (1-0.15)

= 119.0 x 106scf.

Also, from equation (3.15),

stbB

SFVSTOIIP

oi

wco ,)1(7758

stb6

6

108.295

23.1

)15.01(25.08.01020.2767758

58

3.8 MODEL FOR ESTIMATION OF OIL ULTIMATE RECOVERY FROM THE

RESERVOIR

RECOVERY FACTOR (RF)

The recovery factor is the fraction of the hydrocarbon initially in place

(HCIIP) that is deemed recoverable. Thus:

)10.3()(covRe RFHCIIPUReryUltimate

VOLUMETRIC ESTIMATION OF OIL RECOVERY FACTOR

These estimates are obtained by making certain assumptions regarding

displacement efficiency, residual saturations, abandonment columns and drive

mechanism based on experience in an operating area. Usually, these are by

correlations based on reservoir and crude properties. The estimation is done using

the area-depth graph for the reservoir.

Consider the structural cross section of the reservoir of fig. 3.6 which is at

initial condition with an original gas cap, an oil column and a water leg. Also, fig. 3.7

shows the condition of the reservoir at the end of the reservoir’s producing life. Due

to production, the gas has expanded from the level of the original GOC to the

position of the final GOC sweeping a gross bulk volume of BVg. At the same time,

the water expanded from level of the original OWC to the position of the final OWC,

sweeping a gross bulk volume of BVw. The remaining or abandonment oil bulk

volume is BVa, and has a height Ha. It can be seen that Ha is the distance between the

final GOC and the final OWC.

59

STRUCTURAL CROSS SECTION OF RESERVOIR Area-Depth Graph

Original GOC

Depth

Original OWC

Fig. 3.6

Area

ABANDONMENT CONDITION

STRUCTURAL CROSS SECTION OF RESERVOIR

Ha

fig. 3.7 Area

Original GOC BVg

Final GOC BVa

Final OWC BVw

Original OWC BVw

INITIAL CONDITION

60

3.9.1 PARAMETERS FOR RECOVERY FACTOR DERIVATION

A) Gas Flooded Zone BVg . In the gas flooded zone, the following exist:

* Gross bulk volume for gas, BVg: This is the gross bulk volume between the original

GOC and the final GOC.

* Sweep efficiency to gas drive Eg. This is the fraction of BVg in which the displacing

gas enters the pores to reduce the oil saturation to Sorg. The other fraction (1-Eg) of

BVg is bypassed and no advancing gas enters any of its pores.

* Residual oil saturation to gas drive Sorg: This is the minimum (irreducible) oil

saturation that is achieved in the process of displacing the oil by the gas. In this

model, it is assumed to be the oil saturation throughout the fraction of BVg into

which gas enters the pores i.e. Eg of BVg.

B) Water Flooded Zone BVw. The water flooded zone consists of parameters such

as:

* Gross bulk volume for water, BVw: This is the gross bulk volume between the

original OWC and the final OWC.

* Sweep efficiency to water drive Ew: This is the fraction of BVw in which the

displacing water enters to the pores to reduce the oil saturation to Sorg. The other

fraction (1 – Eg) of BVg is bypassed and no advancing gas enters any of its pores.

* Residual oil saturation to water drive Sorw: This is the minimum (irreducible) oil

saturation that is achieved in the process of displacing the oil by the water. In this

model, it is assumed to be the oil saturation throughout the fraction of BVw into

which water enters the pores i.e. Ew of BVw.

C) Abandoned Oil Zone BVa

* Gross bulk volume BVa: This is the gross bulk volume between the final GOC and

the final OWC occupied by the remaining oil at abandonment. No part of this zone

has experienced any flooding by gas or water.

* Abandonment Oil Column, Ha: This is the vertical height of the abandoned oil

zone. Hence, it is the vertical distance between the final GOC and the final OWC.

D) Trapped Gas Saturation Sg: This is the saturation of the gas liberated from the oil

as a result of reservoir pressure decline that is still trapped in the oil zones. It is

61

equal to the liberated gas saturation as long as this gas saturation is less than the

critical gas saturation. Thereafter, it is equal to the critical gas saturation since this is

the maximum gas saturation that can remain trapped in the oil zone.

3.9.2 SATURATION AND SWEEP EFFICIENCIES

From the definitions of the above parameters for recovery factor, the oil

saturation in the three zones, BVg, BVa and BVw are as shown below.

1) GAS FLOODED BULK

VOLUME BVg

Eg BVg (1-Eg) BVg

2) REMAINING OIL BULK

VOLUME BVa

BVa

3) WATER FLOODED

BULK VOLUME BVw

EwBVw (1-Ew) BVw

Fig. 3.8 Flooded and by-passed regions for recovery evaluations

GAS FLOODED BULK VOLUME, BVg

This zone is divided into two parts. The flooded part which has a volume

EgBVg has an oil saturation Sorg. The bypassed part has a volume (1-Eg) BVg. In this

bypassed area, the oil saturation has only been reduced by the value of the liberated

trapped gas saturation and hence has an oil saturation of 1-Swc – Sg. Therefore, the

remaining oil volume in this zone is:

)1()1( gwcggorgggog SSBVESBVEFV

So = Sorg So =

1- Swc - Sg

By passed volume

So = 1- Swc - Sg Not affected

So = Ssro So =

1- Swc - Sg

62

)1)(1( gwcgorggg SSESEBVF (3.11)

WATER FLOODED BULK VOLUME, BVw

This zone is divided into two parts. The flooded part which has a volume

EwBVw, has an oil saturation of Sorw The bypassed part has a volume (1-Ew)BVw and

has an oil saturation of gwc SS 1

Hence, the remaining oil volume in this zone is:

)12.3()1)(1(

)1()1(

gwcworwww

gwcwworwwwow

SSESEBVF

SSBVESBVEFV

THE ABANDONMENT OIL ZONE, BVa

No part of this zone is flooded by gas or water. The oil saturation in this zone

has only been reduced from the initial value of 1 - Swc to 1 – Swc – Sg, only by oil

remaining trapped gas saturation. Therefore, the oil remaining in this zone is:

)13.3()1( gwcaoa SSBVFV

But the Recovery Factor, RF is given by

placeininitiallyOil

OilmainingplaceininitiallyOil

placeininitiallyOil

oducedOilRF

Re

Pr

placeininitiallyOil

OilmainingRF

Re1.: (3.14)

With all the oil volumes expressed at stock tank conditions by dividing the oil

initially in place and remaining oil in reservoir volumes by Boi and Boa respectively.

Boi and Boa are the initial and abandonment oil formation volume factors

respectively.

oi

wc

B

SBVFSTOIIPplaceininitiallyOil

)1(

oa

oaowog

B

VVVOilmaining

)(Re

(3.15)

63

)16.3(1

111111

wcoa

gwcagwcworwwwgwcgorgggoi

SBVB

SSBVSSESEBVSSESEBVBRF

volumebulksandoilgrossinitialTotalBVBVBVBVNote awg :

It is the assignment of values to the sweep efficiencies, residual saturations,

the size and location of the abandonment oil column that forms the subjects of

reservoir engineering.

Ew and Eg: These depend mainly on the oil viscosity (or actually mobility

ratio) and the level and trend of heterogeneity. Companies usually have a

correlation based on oil viscosity, rock types and net to gross ratio for these

parameters. These are usually based on field experience and simulation

studies.

Sorw and Sorg: These depend on the rock type and average values for each rock

type should be available based on past measurements on cores.

BVg/BVw: The relative values of BVg and BVw depends on the aquifer

strength and the amount of excess gas that has been produced.

If there is no aquifer influx, then BVw is zero and the final OWC is equal to

the original OWC while the final GOC is equal to the original OWC less Ha.

If there is a strong aquifer with little or no reservoir pressure drop and there

was no excess gas production, then BVg is zero and the final GOC is equal to the

original GOC while the final OWC is equal to the original GOC plus Ha.

Apart from these two unequally defined conditions, all other values of BVg

and BVw are possible. BVg can even be negative. Hence at the initial stage,

assumptions have to be made regarding the likely relative values of BVg and BVw

based on the experience in the area. In the Niger-Delta, most fields enjoy strong

aquifer support and BVg is usually of the order of 0 to 20% BVw.

Ha: The thickness of the abandonment column is dependent mainly on the

type of production wells, oil viscosity and the reservoir type. The presence of a large

gas cap together with an active aquifer will result in a larger value of Ha, than a

reservoir without a gas cap with only a strong aquifer. Also, horizontal wells will

64

result in smaller Ha than conventional wells. The lower the oil viscosity, the smaller

the Ha.

3.9.3 ANALYSIS OF OIL ULTIMATE RECOVERY USING RESULTS FROM THE

AREA-DEPTH CONCEPT MODEL (CBV – DEPT PLOT)

(Related Petro-physical Parameters used are The core Analysis and Log Reading

from Agbara Oil Well Reservoir)

The recorded reservoir log readings:

Sweep efficiency to water drive, Ew = 0.8, connate water saturation Ssw = 0.15

Sweep efficiency to gas drive, Eg = 0.7

Residual oil saturation to water drive, Sorw = 0.2.

Residual oil saturation to gas drive, Sorg = 0.15.

Abandonment oil column, Ha = 40ft.

Trapped gas saturation Sg = 0.02.

a) It was found that at the GOC section, Gas flooded zone BVg = 0, and

Abandonment Oil Formation volume factor, Boa = 1.21rb/stb

b) Also, at OWC section, water flooded zone, BVw = 0, and Abandonment Oil

Formation Volume Factor, Boa = 1.17 rb/stb.

Initial oil formation volume factor, Boi = 1.23 rb/stb.

If there is a strong aquifer with little or no reservoir pressure drop and

there is no excess gas production, then Bvg = 0, and final GOC =

Original GOC, and Final OWC = Original GOC + Ha. If there is no

aquifer influx, then BVw = 0, and Final OWC = Original OWC, and

Final GOC = Original OWC – Ha.

OIL ULTIMATE RECOVERY FOR CASE WHERE THERE IS

STRONG AQUIFER.

a) Since BVg = O, final GOC = Original GOC = 8560ft, Final OWC = Final GOC + Ha

= 8560 + 40 = 8600ft.

Using the relation BVa = CBVowc – CBVaoc

BVa = CBV8600 – CBV8560 = 103 – 64.3 = 38.3 Mac ft (from CBV-Depth graph).

Also, BVw = CBV8800 –CBV8600 = 340.5 – 103 = 237.5 Mac-ft

65

But BV = BVa + BVw + BVg = 38.3 + 237.5 = 275.8 Mac-ft.

Applying the recovery factor equation (3.26), we have;

RF = 1 - Boi BVg [EgSorg+ (1-Eg) (1-Swc-Sg)]+BVw [EwSorw+(1-Ew)(1-Swc-Sg)]+BVa(1-Swc-Sg)

BoaBV(1-Swc)

RF = 1 – 1.25 237.5 [0.8x0.2+ (1-0.8)x(1-0.15-0.02)]+38.3x(1-0.15-0.02) = 0.52

1.21x275.8x0.85

Therefore, Oil Ultimate Recovery, UR = STOIIP x RF = 295.8x106x0.52

= 153.82 x 106 Mstb.

Refer to Appendix B for a Case Where There is no Aquifer Influx

66

3.9.4 ARCHIE’S LAW

In petrophysics, Archie’s law relates the in-situ electrical conductivity of

sedimentary rock to its porosity and brine saturation:

)17.3(SCCm

ww

m

t

Reformulated for electrical resistivity, the equation reads.

)18.3(S

RR n

wm

wt

The factor m

1 is also called formation factor.

It is purely empirical law attempting to describe ion flow (mostly sodium and

chlorine) in clean, consolidated sands, with varying intergranular porosity. Electrical

conduction is assumed not to be present within the rock grains or in fluids other

than water.

3.9.5 FORMATION FACTOR AND ARCHIE’S EQUATION

It has been established experimentally that the resistivity of a clean formation

is proportional to the brine with which it is fully saturated. The constant of

proportionality is called the formation resistivity factor, F.

If Ro is the resistivity of a non-shaly formation sample saturated with brine of

resistivity, Rw, then

)19.3(w

o

R

RF

For a given porosity, the ratio w

o

R

Rremains nearly constant for all values of Rw

below about one ohm. However, experiments show that in more resistive waters, the

value of F is reduced as the Rw rises, and the grain size of the sand decreases. This

phenomenon is attributed to a greater proportionate influence of the surface

conductance of the grains in fresher waters. The formation factor is a function of the

porosity, the pore structure and pore size. Archie proposed the following

relationship.

67

maF

(Archie’s equation). (3.20).

Where m is the cementation factor, and the constant of proportionality, a, are

obtained empirically.

Satisfactory results are usually obtained with;

,

62.015.2

F (3.20a).

2

1

F (3.20b)

Equation (3.30a) is often referred to as the Humble Formula and in order to

eliminate the fractional cementation exponent, it is sometimes shortened to;

)20.3(81.02

cF

3.9.6 ARCHIE’S WATER SATURATION EQUATION

To evaluate a physical formation, the parameters that are needed are its

porosity, hydrocarbon saturation, bed thickness, and permeability. Resistivity

measurement along with porosity and water resistivity allow us to infer the water

saturation (Sw) of a formation’s pore space and thus to derive its hydrocarbon

content (1-Sw).

Neither oil nor gas conducts electrical current; both are excellent insulators.

Indeed, oil is widely used as an insulator in some electrical equipment. Thus, in a

formation containing oil or gas, the resistivity is a function not only of the formation

factor, F, and water resistivity Rw, but also of water saturation, Sw.

Water saturation Sw, is the fraction of the pore volume occupied by formation

water and the hydrocarbon saturation Sh is the fraction of the pore volume occupied

by hydrocarbons.

in sands

In compacted formations

68

All water saturations from resistivity logs in clean (non-shaly) formations

with homogenous intergranular porosity are based on Archie’s formula or

variations thereof.

Archie determined experimentally that the water saturation of a clean

formation could be expressed in terms of its true resistivity as:

)21.3(t

wxn

w R

RFS

m

aF

(3.22)

For water saturation in the flushed zone, Sxo, then;

)23.3(xo

mfnxo

R

FxRS

n is usually 2, although laboratory measurement do snow some variation in

the value of n. Therefore, in log interpretation practice, n is taken to be 2 unless it is

actually known to be otherwise.

The values of ,a, and ,m, in equation (3.20) however are subject to more

variations as follows:

- In carbonates, use, )24.3(12

F

- In sands, use )25.3(62.015.2

F

Equation (3.25) is referred to as the Humble Formula, or ;

)26.3(81.02

F

This is a simpler form practically equivalent to the Humble Formula.

Formation water resistivity, Rw, is obtained from the formula:

69

wtt

wFxRR

F

RR (in shale) (3.27).

)28.3()( sandwetInRFROr wo

For clean water bearing zones, i.e. 100% water saturated formations,

wot RFRR (3.29)

And Sw = 1.

Combining equation (3.21) and (3.24) yields:

t

ww

R

RxS 2

2 1

(in carbonates) (3.30).

Combining equations (3.21) and (3.26) yields

t

ww

R

RxS 2

2 81.0

(in sands) (3.31)

As previously noted, Ro is a special case of Rt, i.e. if wet sand is being considered.

Instead of shale, Archie’s equation will be rewritten as;

02

2 81.0

R

RxS

ww

(in wet sands) (3.32).

3.9.7 THE RATIO METHOD

If n = 2 and divide equation (3.21) by (3.23), this gives;

w

mf

t

xo

xo

w

R

R

RR

SS

/2

(3.33).

This equation gives the ratio of Sw to Sxo and no knowledge of F or porosity is

needed. Rxo can be found from, say, the compensated Dual Resistivity (CDR) tool

after invasion has occurred, Rt from induction tools like CDR and the ratio Rmf/Rw

from measured values or charts.

The ratio Sw/Sxo is valuable in itself as an index of oil movability.

70

If Sw/Sxo = 1, then no hydrocarbon have been moved by invasion whether or

not the formation contains hydrocarbons. If Sw/Sxo is almost 0.5 or less, movable

hydrocarbons are indicated.

To determine Sw, from equation (3.33), Sxo must be known. For moderate

invasion and average residual oil saturation, an empirical relation between Sw and

Sxo has been found useful as follows:

Sxo = (Sw)1/5, inserting this into equation (3.33), gives;

)34.3(

85

w

mf

t

xo

wR

R

R

RS

The values of Sw/Sxo along with and Sw are useful in evaluating the

reservoir.

From this set of equations, water resistivity, Rw can be calculated using

equation (3.27) and (3.28).

Water saturation, Sw can be calculated using equations (3.30), (3.31), (3.32),

(3.43).

The true resistivity of the formation, Rt and the porosity can be calculated

or more accurately measured using a Compensated Dual Resistivity (CDR) and a

compensated Density Neutron (CDN) tool respectively.

And the hydrocarbon saturation can easily be obtained using the equation:

)35.3(1 wh SS

Any log can thus be interpreted using the obtained values of:

The water saturation, Sw

The hydrocarbon saturation, Sh,

The Resistivity Rt, Ro, Rxo or Rw

The porosity from CDN measurement and the ratio Sw/Sxo.

71

3.9.8 USING ARCHIE’S EQUATION TO DETERMINE WATER SATURATIONS

From fig 3.9 below (all the indicated values are obtained from actual log

readings), the following interpretations would be in order:

A) Zone A and C are potential Hydrocarbon bearing zones.

B) Zones B and D are water bearing zones

C) Zone B and from 7300ft downwards are hydrocarbon (oil) water contact

(OWC) zones.

Since the formation is homogenous, we can analyze the log by calculating the

formation water resistivity Rw for zone D, the water saturation, Sw, for zones A, B,

and C and hence the hydrocarbon saturation Sh for zones A, B and C as follows:

72

GR

0 API 150

RESISTIVITY

0 m 10

POROSITY

50 %

A

7350’

Rt

=4m

Sand

Shale

B

C

7400’

Rt=0.4m

Rt=8m

=0.3

=0.07

Shale

Sand

D

7500’

Ro=0.3m

=0.35

Fig. 3.9: Data from actual log readings taken in the Niger-Delta

Source: Chevron Nigeria Limited, Port Harcourt.

Note: Before using the values of resistivities indicated in the diagram to calculate for

water saturation, there is need to make use of the appropriate correction charts to

correct for borehole and shoulder bed (bed-thickness) effects.

- Calculation of formation water resistivity Rw for zone D.

Zone D is predominantly wet sand, therefore from equation (3.29),:

wo RFR

73

For sandy formations, using equation (3.26), :

2

81.0

F

Substitute F, into equation (3.28),then;

2

81.0

wo

RxR

)36.3(81.0

2

ow

xRR

From the log readings of Fig 9,

R0 = 0.3, and = 0.35

=> Rw = 045.081.0

3.035.0 2

x

0hm-m

Calculation of water saturation Sw for Zone A. Using equation (3.31) Archie’s

Equation for sandy Formations, gives;

t

w

w R

RxS 2

2 81.0

From fig. 3.9, Rt = 4 ohm-m, = 0.3 and Rw = 0.045 ohm-m as calculated for

the homogenous formation.

=> 32.04

045.0

3.0

81.02

2 ww

SxS

%32 wS

Calculation of water saturation Sw, for zone B

Again, using equation (3.31), (Archie’s equation for sandy formation), gives:

t

ww

R

RxS

2

2 81.0

From fig 3.9, Rt = 0.4 ohm-m, = 0.3 Rw = 0.045 ohm-m as calculate for the

homogenous formation.

=> %10014.0

045.0

3.0

81.02 SS ww

x

74

Calculation of water saturation Sw, for Zone C

Also, using equation (3.31), (Archie’s equation for sandy formations):

t

w

w R

RxS 2

2 81.0

Where Rt = 8ohm-m, from fig 3.9 = 0.35 and Rw = 0.045ohm-m as calculated

for the homogenous formation.

%95

96.04.0

045.0

35.0

81.02

2

SS wwx

75

3.9.10 EQUILIBRIUM INITIALIZATION ALGORITHM FOR DETERMINING

PRESSURE IN A RESERVOIR

Fig. 3.10 Depths for Initialization Algorithm

Suppose a grid block (reservoir cross section) has a gas-oil contact (GOC) and

a water-oil contact (WOC) as shown in figure 3.10 above. The pressure at GOC is

PGOC. Similarly, the pressure at WOC is PWOC. The initial oil phase pressure

assigned to the grid block is determined by PWOC, PGOC and the depth of the node

(midpoint) relative to the respective contact elevations.

The oil density ROwoc and water density RWwoc at WOC are calculated using

the pressure PWOC. The water-oil capillary pressure PCOW is calculated for the

gridblock at the midpoint elevation EL using the densities at WOC.

Considering the equation for pressure,

)47.3(hgP

From the gridblock in figure 3.10, analogously,

PCOW = )48.3(.144

1ELWOCRORW wocwoc

The initial water saturation SWI for the gridblock is calculated at the

midpoint elevation using PCOW and the following algorithm:

EL(+) (+)

(+)

y

x

Datum

WOC

GOC

76

1) IF PCOW ≥ PWOC at irreducible water saturation Swr, Set SWI = Swr

2) If PCOW ≤ PCOW at water saturation, Sw = 1, set SWI = 1.

3) If PCOW (Sw=1) < PCOW < PCOW (Sw=Swr), then interpolate the value of

SWI from the user-input water-oil capillary pressure curve.

The notation PCOW (Sw=1) should be read as the variable (PCOW) is

evaluated at Sw=1, since PCOW is a function of Sw. Similarly, the notation PCOW

(Sw=Swr) says that the variable PCOW is evaluated at Sw=Swr.

A similar calculation is performed to determine initial oil phase pressure at

the GOC using gas and oil densities. The gas density RGGOC and Oil Density ROGOC

at GOC are calculated using the pressure PGOC. The gas-oil capillary pressure

PCGO is calculated for the gridblock at the midpoint elevation EL using the

densities at GOC, thus:

PCGO = ).49.3().(144

1ELGOCRGRO GOCGOC

The initial gas saturation (SGI) and initial oil saturation (SOI) for the

gridblock are calculated at the midpoint elevation using PCGO, the previous

calculation of SWI, and the following algorithm.

a) If PCGO ≤ PCGO at total liquid saturation S1 = 1, set SGI = 0.

b) If PCGO ≥ PCGO at SL = Swr, set SGI = 1 – SWI

c) If PCGO (SL = 1) < PCGO < PCGO (SL=Swr), then, interpolate the value of SGI

from the user-input water-oil capillary pressure curve.

The notation PCGO (SL = 1) should be read as the variable PCGO is evaluated

at SL = 1 since PCGO is a function of SL. Similarly, the notation PCGO (SL = Swr) says

that the variable PCOW is evaluated at SL = Swr

Oil saturation is obtained from equation ; S0 + Sw + Sg = 1

The initial oil phase pressure is calculated using the saturations determined

above to define the appropriate pressure gradient. The algorithm for calculating P

follows:

CASE 1: IF SWI = 1, then,

77

P = PWOC +

)50.3()1(

144

1

S

RW

w

woc

PCOW

WOCEL

CASE 2: If SOI > O, then

P = PWOC - )51.3(.144

1ELWOCROwoc

CASE 3: If SGI>O and SOI = O, then

P = PWOC + WOCELROwoc 144

1

ELGOCROGOC 144

1

)52.3()1(144

1 gGOCc SPCGOGOCELRO

A natural gas-water system can be initialized by setting PWOC = PGOC and

WOC = GOC + E, where E is an incremental displacement such as 1ft.

78

3.4.1 BASIC ECONOMIC CONCEPT OF RESERVOIR MANAGEMENT

Economic analyses are an essential aspect of a reservoir management study.

The economic performance of a prospective project is often the deciding factor in

determining whether to undertake a project. Consequently, it is important to be

aware of basic economic concepts and factors that may affect the economic

performance of a project.

3.4.2 DEFINITIONS OF SELECTED ECONOMIC MEASURES

1. Discount Rate – Factor to adjust the value of money to a base year.

2. Net Present Value (NPV) – Value of cash flow at a specified discount rate.

3. Discounted Cash Flow Return On Investment (DCFROI) or Internal Rate of

Return (IRR) – Discount rate at which NPV = 0

4. Discount Payout Time – Time when NPV = 0

5. Profit-to-Investment (PI) Ratio – Undiscounted cash flow without capital

investment divided by total investment.

3.4.3 EVALUATION OF ECONOMIC MEASURES IN RELATION TO OIL

PRODUCTION

NPV is the difference between the present value of revenue R and the present

value of expenses E,

i.e.

)53.3(ERNPV

Taking Δ (K) as the expenses incurred during a time period K, then E may be written

as

NXQ

OKk

E )54.3(

Q

i1

E(K)

Also, for revenue R, ;

79

NXQ

OKk

E )55.3(

Q

i1

R(K)

where ΔR(k) is revenue obtained during time period K, and i is the annual

interest or discount rate. Equations (3.54) and (3.55) include the assumptions that i

and i' are constants over the life of the project, but i and i' are not necessarily equal.

These assumptions help to compute the present value of money expended relative to

a given inflation rate i' and compare the result to the present value of revenue

associated with a specified interest or discount rate i.

3.4.4 EVALUATION OF NPV AND BREAKEVEN OIL PRICE

The NPV and breakeven oil price for an oil production project can be

obtained from the above analysis as an illustration of the concepts. The base year

can be specified for present value calculations as the year when the project begins. In

this case, no initial revenue and the initial expense is just initial investment II, thus,

ΔR(o) = 0 and ΔE (o) = 11 (3.56)

Substitute Eq (3.53) and (3.55), into Eq (3.52) gives;

NXQ

OK

NXQ

kkk

IINPV )57.3(

Q

i'1

E(K)

Q

i1

R(K)

1

But revenue from the sale of oil during period K has the form,

ΔR(k) = Po )58.3()(Q

i1 KNP

k

Notice that the value of produced gas is assumed negligible in the case.

Combining Eq (3.56), (3.57), and (3.58) yields NPV for this project.

)59.3(

Q

i'1

)(11

Q

i1

)(Q

i'1

;11

NXQ

kk

NXQ

kk

k

okE

kNP

NPVthusP

80

where Po k

Q

i'1 ΔNP (k) = ΔR(k)

The incremental oil production in Eq. (3.59) is typically obtained as a forecast

using reservoir engineering methods like decline curve analysis, material balance

analysis, or reservoir simulation. The oil production profile used in the economic

analysis may represent both historical and predicted oil recovery.

A balance oil price Poe for a specified rate of return = ROR and production

profile is calculated by setting NPV = 0, as the breakeven conditions in Eq. (3.59).

Rearranging the resulting equation and setting Po=Poe gives the estimate of

breakeven oil price as:

)60.3(

)(1

1

1

)(11

1

'

1'

NXQ

k

pk

QROR

k

Qi

NXQ

kk

Qi

oe

kN

kE

P

3.4.5 ANALYSIS OF CAPITAL EXPENDITURE, OPERATING EXPENDITURE

AND DISCOUNT RATE

Revenue can be expressed as ;

R = )61.3()1(1

N

nn

nn

r

QPNPV

The quantity produced can be volume of oil or gas, kilowatt – hours of

electricity or any other appropriate measure of resource production.(Sharma,2003).

Expenses include capital expenditure, CAPEXn during year n, operating

expenditure, OPEXn during year n, and taxes TAXn during year n. Capital

expenditures are the cost of facilities such as offshore platforms and pipelines.

Operating expenses include on-going expenses such as salaries and maintenance

costs.

Then, the resulting expression for expenses is;

)62.3()1(1

N

nn

nnn

r

TAXOPEXCAPEXE

Substituting equations (3.60) and (3.61), into equation (3.52) gives;

81

)63.3()1(1

N

nn

nnnnn

r

TAXOPEXCAPEXQPNPV

Equation 3.62 above shows that NPV depends on the price of the resources,

the quantity of the produced resource, discount rate, capital expenditures, operating

expenditures and taxes.

82

CHAPTER FOUR

RESULTS AND ANALYSIS

The Agbara oil well reservoir investigated using the area-depth concept model was

viable. This is because, considering the related petrophysical parameters involved in

the evaluation, the reservoir was found to contain an oil deposit of 295.8 x 106 stb.

Also, for the recovery factor evaluation of the reservoir, it was found the amount of

oil recovered, out of this deposit depends on the presence or absence of aquifer

influx. This was seen from the calculation of the ultimate recovery (UR) of the oil

from the reservoir. For example, the amount recovered for a case where there is a

strong aquifer influx was 153.82 x 106 stb. The amount of recovery for a case where is

no aquifer influx was 136.1 x 106 stb. These results showed that the reservoir

investigated was economically viable.

This method of evaluating reservoir viability is believed to be more economical

and direct in the calculation of Stock Tank Oil Initially In Place(STOIIP) and the

Ultimate Recovery Factor (URF) analysis. Although it depends on the type of the

reservoir equipment used and other uncertainties in measurements of the

petrophysical parameters.

ANALYSIS OF THE MAJOR PETROPHYSICAL PARAMETERS IN THE

RESERVOIR EVALUATION

EFFECTIVE POROSITY

This is a measure of the interconnected pore spaces as a function of bulk volume. It is the

ratio of the volume of interconnected pore space to the total volume of the rock. Effective

porosity is responsible for the migration of oil to the well bore.

b

gb

b

p

V

VV

V

VPorosity

Where Vb = Bulk volume of rock, Vp = pore Volume of rock Vg = Grain Volume of Rock.

The porosity of rock for the reservoir evaluated was 0.25. In the calculation of porosity of a

reservoir rock, sample of the core was measured to determine its length and diameter. Then,

the bulk volume, Vb, was calculated from the relation; Bulk volume,

pVVwherev

m ,1

83

Considering the mass of the oil sample and its gravity, Vp was then determined.

In another reservoir with different value of porosity, the oil deposit would be different

depending on its value. The higher the effective porosity of the rock in any reservoir, the

higher the yield and vice versa.

PERMEABILITY (K)

The absolute permeability K, of a rock is a measure of its ability to transmit a fluid when

saturated fully by the fluid as defined through Darcy’s law. It is a property of the rock and is

independent of the fluid.

The effective permeability of rock to a fluid K (Sf) is a measure of the ability of the rock to

transmit the fluid in the presence of other fluids. This depends on the saturation of the fluid

with Kf B(Sf) increasing from zero at critical saturation.

The relative permeability of a fluid krf (Sf) is the ratio of the ability of a rock to

transmit the fluid when partially saturated by the fluid to its ability to transmit the same fluid

when fully saturated by it.

Thus;

oilforK

SKSK

waterforK

SKSK

fluidanyforK

SKSK

wowro

wwwrw

ff

frf

,

,

,)(

Application of Darcy’s Law

The basic law governing fluid flow in a porous medium is Darcy’s law. The law states that

the average velocity of flow through a porous medium is proportional to the rate of pressure

change in the direction of flow l

p

d

d, and inversely proportional to the fluid viscosity, µ.

Mathematically ,L

pKAq

The negative sign is because flow is positive in the direction of reducing pressure

PA

LqK

The permeability is directly proportional to the rate of production of oil from the reservoir

rock, area of the reservoir rock and pressure change. It is also inversely proportional to the

viscosity and the rock gradient.

84

The permeability of Agbara oil well reservoir was very high. That was the reason

why there was an ultimate oil recovery of up to 153.82x106

stb. The fluid flow between the

rock interconnected pores was high because of the low viscosity of the oil.

FORMATION VOLUME FACTOR

This is the volume occupied at reservoir conditions by one stock tank barrel of oil plus all the

gas originally dissolved in it. The volume of oil entering the stock tank at the surface is less

than the volume of oil which flows into the well bore from the reservoir.

This change is due to the following factors.

The most important factor is the evolution of gas from the oil as pressure is decreased

from reservoir pressure to surface conditions. This causes a large decrease in oil

volume if there is a significant amount of dissolved gas.

Other minor changes include the expansion of the remaining oil due to reduction in

pressure. But this is somewhat offset by the contraction of the oil due to the reduction

in temperature.

The evaluated Agbara Oil well has an initial formation volume factor of 1.23 rb/stb. The

lower the amount of formation volume factor, the higher the amount of stock tank oil initially

in place (STOIIP). And if the FVF is high, this will considerably lead to a lower yield of oil

in place in the reservoir. The same is applicable to another type of reservoir, regardless of the

values of other petrophysical parameters of the reservoir in question.

Net-To- Gross Ratio

In the reservoir rocks, there are some parts of sand that are not porous. These sands are

discounted with what is known as the net-to-gross ratio, F, where F is the fraction of the total

sand volume that is considered to be porous.

sandgrosstheofThickness

sandnettheofThicknessFRatioGrossToNet ,

The estimation of net-to-gross ratio on a field wide scale was accomplished by integrating

rock property trends and high quality 3-Dimensional Seismic Data. Accurate estimates of

sand volume fraction (1-Vsh) are obtainable from a simple linear interpolation between the

Acoustic Impedance (A1) – Shear Impedance (S1) trends. Four angle range stacks from a 3-

dimensional survey over the reservoir were calibrated and constrained by available well

control and simultaneously inverted to A1-S1 cross plot. The impedance volume closely

matches the upscale log data and were combined using linear interpolation between the sand

85

and shale trends to create a sand fraction volume. Integration of the sand fraction over the

gross reservoir thickness provides an estimate of Net –To – Gross ratio at any x-y Location.

Net –To – Gross evaluation is often a key issue in reservoir characterization projects.

In Agbara oil well reservoir, the Net – To – Gross Ratio, F, was found to be 0.8. This

high value of F accounted for the high yield of oil deposit in the reservoir and also

contributed to high recovery factor evaluation.

In most cases, if F is not considered and effectively measured, it normally affects the

oil yield.

HYDROCARBON POTENTIAL PAY ZONES IN A RESERVOIR USING

ARCHIES’ LAW

From the results obtained in the application of Archie’s law by combining the

related petrophysical parameters in calculating water and hydrocarbon saturations,

the different zones can be analyzed as follows;

ANALYSIS OF DIFFERENT ZONES

ANALYSIS OF ZONE A

Analysis of this zone shows that the hydrocarbon saturation of zone A is;

1-Sw = 1-0.32 = 0.68 = 68%.

This implies that zone A is hydrocarbon bearing formation. This can be

attributed to the very high porosity of 0.3 for Zone A.

ANALYSIS OF ZONE B

The calculated water saturation for Zone B is 99%, implying that it contains

100% water.

ANALYSIS OF ZONE C

The hydrocarbon saturation for zone C is 1-Sw = 1-0.96 = 0.04 = 4%. This

implies that this is not a hydrocarbon bearing formation despite the high resistivity.

This is because of the very low porosity of 0.07 for zone C.

86

EQUILIBRIUM INITIALIZATION ALGORITHM

From the algorithm developed for pressure determination in a reservoir, it was

shown that the major factors to consider in this algorithm are;

A, The initial water saturation of the reservoir(SWI).

B, The pressure at the water oil contact (PWOC).

C, The initial gas saturation of the reservoir (SGI).

D, The initial oil saturation of the reservoir (SOI).

E, The pressure at the gas-oil contact (PGOC).

F, The application of user-input water – oil capillary

87

CHAPTER FIVE

5.0 DISCUSION

In the evaluation of a reservoir, the contractor has to consider the viability of

the reservoir. This is done by estimating the quantity of stored oil in the reservoir.

That is , the calculation of the Stored Tank Oil Initially In Place (STOIIP), by taking

into account , the geometry and the related petrophysical parameters of the

reservoir. It is not feasible to extract all the oil stored in a reservoir, no matter the

sensitivity or accuracy of equipment used and the experience of the drilling

contractors. At abandonment condition, oil is still left in the well. So, before drilling

a particular well, the engineers have to justify the economic level of the reservoir.

This is achieved by estimating the recovery factor, which is the amount of hydro-

carbon that is deemed recoverable from a particular reservoir. This recovery factor

(RF) analysis helps companies to know the maximum quantity of oil that can be

drilled out from the well. It also helps to now the budget estimates to be made

before production starts. Also in a reservoir with variable quantity of hydrocarbon

at different zones, the stored oils in these zones can be calculated by the combination

of related petrophysical parameters using Archie’s law.

In this study, area-depth concept model was used to estimate the STOIIP in a

reservoir. The recovery factor of Agbara oil well was properly analyzed by this

concept. It was shown that the reservoir is economically viable. This model was

developed to analytically estimate the initial oil in place and the recovery factor in a

particular reservoir. This method of reservoir evaluation could be seen to be more

economical and direct although its efficacy depends solely on the sensitivity and

accuracy of the equipment used for the analysis of the well logs and cores. It also

depends on the experience of the drilling engineers and the reservoir conditions, if

the related petrophysical parameters are considered and measured accurately. In

this research, initialization algorithm was developed for determination of pressure

gradient in a reservoir. This pressure check helps the engineers to have an idea of

the reservoir conditions in order to prevent lost circulation and kick effects, during

drilling.

88

On the economic analysis of a reservoir, if the production quantity N, is

known, the expenses to be incurred are the capital expenditure which are the cost

facilities such as off sure platforms and pipeline arrangement. Also, the operating

expenses like the salaries of workers and maintenance costs are to be analyzed.

5.1 EXPLORATION ECONOMICS

For the optimization of drilling operations, there is need to specify the yardstick by

which performance is measured. The most relevant yardstick is cost per meter or foot drilled.

Overall cost must be looked at since individual costs can be misleading. To optimize drilling

economics, the objectives of the well must be achieved as economically as possible. In order

to do this, the cost allocations and proportions in drilling operations must be understood. The

need is to reduce the expenditure without affecting safety or efficiency.

COST SPECIFICATIONS

Exploration cost can be broken down into three groups:

1. Fixed cost

2. Daily cost

3. Unit cost

Fixed costs: These are the costs that are determined mainly by the nature of the well and

include the following:

i. Wellheads

ii. Site preparation

iii. Casing

iv. Cementing

v. Tubing

vi. Packers

89

Daily cost: Daily costs are related to the time spent on the operation. On offshore rigs, they

are usually the largest items of expenses and are listed below:

i. Payments to drilling contractors

ii. Tool rental (iii) Payments to specialist services

iv. Lubricating wages etc. (v) Fuel

vi. Drilling consumables (rope, soap and dope)

vii. Transport of materials

Unit Costs: This is the price of a unit or a commodity such as the price per tonne of barryte

or benetonite. This can be optimized in the tending process and good site supervision can

ensure that consumption is not excessive.

5.2 SPECIFIC COST BREAKDOWN OF AN OFFSHORE EXPLORATION

WELL

This is a breakdown of costs associated with a typical exploration well. The total time

spent on the well is 60 days.

FIXED COSTS

Fixed item Cost in Naira (N) (Thousands) % of Well Cost

Location survey 1600 6.20

Rig Mob/demob 2700 10.40

Casing 5700 21.90

Wellheads 1800 6.90

Drill bits 1400 5.40

Cementing 1700 6.50

Electric Logging 3200 12.30

Coring 600 2.30

Testing Equipment 1000 3.80

Rig Positioning 80 0.30

Total =N20500 Total =76.00%

90

DAILY ITEM COSTS

Daily Item

Cost in Naira (N)

(Thousands)

% of Well Cost

Rig (60 days @ 250000) 15000 57.70

Drilling Equipment Rental 500 1.92

Mud Logging 1600 6.20

Directional control 2400 9.20

Supply boats 3700 14.20

Standby boats 1600 6.20

Helicopters 2120 8.10

Diving/Rov 1300 5.00

Storage Onshore transport 260 1.00

Contract Staff 2500 9.60

Base Office O/H 410 1.60

MWD Tools 140 0.54

Weather forecasting 40 0.15

Medical Service 30 0.12

Total N3223 Total=121.53%

From the figure above for daily costs, the average daily cost can be calculated for the 60

days.

dayN /5371760

3223000CostDaily Average

UNIT ITEM COSTS

Unit item Cost in Naira (N) (thousand) % of well cost

Mud 2200 8.50

Fishing Tools 90 0.35

Total N2290 Total = 8.85%

000,013,26#

000,290,2000,223,3000,500,20

cos

TC

CostUnitCostDailytFixednExploratioofCostTotal

The real meaning of these costs values shows that saving a day on the well will save 1/60 of

N3223000, and not 1/60 of the overall well cost of N26, 013,000. It also means that an extra

day spent on tripping, directional correction, treating the mud, waiting on weather and

making spurious trips will cost the operator a minimum of N53717.

91

5.3 ANALYSIS OF THE ECONOMIC VIABILITY OF AGBARA OIL WELL

RESERVOIR USING THE TOTAL COST EXPENDITURE

Considering the amount of oil Ultimate Recovery for the case where there is a strong aquifer

influx, UR= 153.82 x 106 stb.

But assuming that in the oil market, 1stb of oil is sold at a price of 0.4k, i.e. N.4, this shows

that the selling price of the crude oil for the company is 153.82 x 106 x 0.4k.

000,427,28

26013000000,440,54

000,400,544.0101.136

101.136

000,515,35

2601300061528000

Pr61528000

6

6

N

NNGainNet

NSP

stbNURthewherecaseaFor

N

NNGainNet

ofitGrossNSP

In this case, the reservoir is said to be economically viable.

5.4 FORMATION EVALUATION

Broadly speaking, well logs have two general uses: (1) Correlation and

stratigraphic studies , and (2) the evaluation of formation fluids and lithology.

Almost all oil and gas produced today comes the accumulation in the pore spaces of

reservoir rocks.

The amount of oil or gas contained in a unit volume of the reservoir is the product of

its porosity by the hydrocarbon saturation. Porosity is the pore volume per unit

volume of formation while hydrocarbon saturation is the fraction or % of the pore

volume filled with hydrocarbons.

In addition to the porosity and hydrocarbon saturation, the volume of the

formation containing the hydrocarbons is needed in order to determine if the

accumulation can be considered commercial. Knowledge of the thickness and the

area of the reservoir are needed for the computation of its volume.

To evaluate the productivity of a reservoir, it is useful to know how easily fluid can

flow through the pore system. This property of the formation, which depends on the

manner in which the pore spaces are interconnected, is its permeability.

92

This project has shown mainly the determination of water saturation using fix

values of porosity. It also explains how logs are used to obtain valuable information

about permeability, lithology, and producibility and to distinguish between oil and

gas.

Among the major parameters obtained directly from logs, resistivity is of

particular importance. It is essential to saturation determinations. Resistivity

measurements are used singly and in combination, to deduce formation resistivity

in the uninvaded formations. That is, beyond the zone contaminated by borehole

fluids, and also close to the borehole, where mud filtrate has largely replaced the

original fluids. Resistivity measurements, along with porosity and water resistivity ,

are to obtain values of water saturations. Saturation values from both shallow and

deep resistivity measurements are to evaluate the producibility of a formation.

5.5 WELL TEST ANALYSIS

Well test analysis as the name implies is the analysis of reservoir pressure

response.

These pressure responses are obtained from Pressure Recorders.

In the past, pressure recorders are lowered to the bottom of the well with the

aid of Amerada within the lubricator. Recently the practice is to place electronic

recorders permanently to retrieve information on the reservoir pressure and

temperature response.

STANDARD TESTS

The main purpose of test design is to plan a dynamic measurement sequence

and to select hardware to ensure that data acquired at the well site satisfies the test

objective and is cost efficient.

Some common well test types are; closed-chamber test,

Constant-pressure flow,

Formation-test, horizontal well test, impulse test, multilayer transient test,

multiwell interference test, pumped-well test, stabilized-flow test, step-rate test,

resistivity formation test etc.

93

5.6 IMPORTANCE OF WELL TEST ANALYSIS

Conducting well test enables us to;

Obtain reservoir fluid (oil, gas and water) samples for analysis.

Measure the maximum flow rate deliverable from the formation.

Determine reservoir and well conditions representative of the production

performance.

Analysis of the well test data enables the determination of

Average reservoir pressure

Well bore static and flowing gradients

Permeability (K)

Reservoir extent (boundary) and architecture

Skin factor (damage or stimulation)

Average pressure I’

Productivity indices.

94

5.7 COMMON TYPES OF RESERVOIR

There are three main types of reservoirs which includes

Oil reservoir

Gas reservoir

Geothermal reservoir (steam, super heated aquifer)

Test carried out on oil reservoir is called OIL WELL TEST, and test carried out on

gas reservoir is called GAS WELL TEST.

Common types of test

The choice of test type depends on test objective but the common test types includes;

a) Drawdown test (FG/DD/SG)

b) Buildup test (FG/BU/SG)

c) Drill stem test

d) Interference test

e) Back pressure test (Gas well)

FG flowing gradient, DD drawdown

SG static gradient,

BU builds up.

WELL TEST ANALYSIS HELP TO EVALUATE;

Production potential

Well damage

Average reservoir pressure

Formation characteristic

Collection of fluid samples

BASIC DATA REQUIREMENT

Rate, pressure and tune

Core/log data

RFT plots

Structural map

Well completion diagram

95

Near by test results

5.8 APPLICATION OF FLUID PRESSURE TO DETERMINE GOC, GWC, OWC.

(a). Contact (Hydrocarbon Column) Determination

Where the fluid contacts (OWC, GWC, GOC) are not obtainable directly from

well log either due to tool failure, poor hole conditions (washouts) shaly formations

or the structural location of the well then well pressure can be measured to

determine them.

The first step is to establish an appropriate water line by measuring water

pressures in the vicinity of the hydrocarbon region. Then:

(1). To determine Oil-Water Contact (OWC) or Gas-Water Contact (GWC) in any

sand-Measure pressure from at least 3 depths in the hydrocarbons in that

send to establish the oil or gas line as the case may be. The intersection of the

oil line with the water the given the position of the OWC while the

intersection of the gas line with the water line gas the GWC. Remember that if

only gas and water have been seen then there is the possibility for an oil film

in between. Smaller the effect of errors due to tool positioning and accuracy.

So choose depths as far apart as possible within the zone under evaluation.

Attempt to take pressures especially for contact determination in one run. Re-

runs/calibrations/depth correlations could make some difference.

Give regard to hole conditions-washouts. Tight formations, etc while

selecting depths for pressure measurement. Also avoid depths too close to

contacts and formation boundaries.

All depths must be converted to a common vertical reference depth. Usually

TVDs which is the vertical depth below the mean sea level. Place more

confidence in points requiring less deviation corrections due to possible

errors in calculating these corrections as well as errors in the deviation data

themselves.

While hydrostatics implies straight line relation of pressure with depth.

Graphical solutions are preferred to algebraic solutions as there are many

96

subtle revelations that usually only appear on plots. Be careful not to regress

out useful trends! Be contions about joining pressure points across barriers.

Always be guided by typical gradients. Do not just get the best line through

the points (the best line may be the wrong line). There may be more straight

line and totally different interpretation.

Be aware that as in all extrapolations, the farther away from the region of

measured data you are the less the confidence in the results. Remember spill

points and other structural limits.

Make sure the water line is applicable to the hydrocarbon region you are

evaluation (SITP,2000).

5.9 PRESSURE AND TEMPERATURE GAUGE PLACEMENT

The following procedure are observed for down-hole gauge or recorder

placement;

1) Fro offshore well tests two sets of electronic recorder called upper and lower

gauges are run below the Tester Valve. These gauges are usually placed 4ft or

6ft apart as the case may be. Generally for onshore, one recorder is enough.

2) In both onshore and offshore at least one recorder should be run above, the

chokes or above the tester valve if no chokes are available.

3) All the electronic recorders is use mush have mechanical pressure recorders

as a back-up. A minimum of one mechanical temperature recorder should

also be used for back-up.

4) At least one pressure recorder should be ported so as record annular

pressure.

5) One recorder set consisting of electronic pressure/temperature recorder

should be run as close to the perforation as possible (Bottom gauge).

6) One recorder set consisting of electronic pressure/temperature recorder and

mechanical pressure recorder should be run approximately midway between

the tester value and perforation, if this distance is significant (top gauge).

7) Pressure and temperature elements should be selected such that formation

pressure and temperatures fall within the application range to enable

97

recorder survive bull-heading pressure if required. In absence of better data,

bull-heading pressure may be assumed to be 1.0 to 1.2 psi per foot of depth.

8) Recorder operating times (mechanical check and operating frequencies)

should be selected, to allows for the total running-in time plus the total of all

the anticipated flow and shut-in times. Running-in time should be based on

similar tests offsetting walls. When data are unavailable running-in time can

be approximated as 1 hour per 1000 it of depth per 4 hours for final rig-up.

9) Time delays of pressure switch start should not be relied on for all electronic

recorders.

10) Pressure STOPS should be made near the vicinity of gas lift Mandrels, close to

the top and bottom of sand to capture contacts and around the perforation

intervals. Stop duration should be at least 15 minutes for all electronic

recorders.

5.9.1 GAUGE PERFORMANCE CHECK

Once the recorders have been retrieved a qualitative analysis of the pressure

charts is performed to verify that the test was successful. This is otherwise referred

to as Quality Check.

Points to be examined includes the following;

a) Did the recorder work?

b) Were all the flow and build-up period recorded?

c) Are the top and bottom recorder charts similar appearance?

d) Is the final hydrostatic pressure similar to the initial hydrostatic pressure?

e) Do the recorded pressures correlated to what actually occurred.

f) Are the charts and data analyzable?

GAUGE PERFORMANCE CHECK PROCEDURE

1) Load the pressure test data from the diskette (ASCII FILE) for the top and

bottom gauges.

2) From the menu command, zip on difference and activate the difference plot.

3) For the table of data locate

i) Flow period

98

ii) Early build-up

iii) Late build-up

iv) Static period

4) With the zoom facility pick ranges on each of the selected flow periods and

examine the responses of both gauges.

5) Repeat the process for temperature gauges.

5.9.2 PRESSURE PROGRAMMING AND INTERPRETATION FOR RFT ANALYSIS

Fluid pressures are measured using the open hole RFT tool run wire line

usually after the resistivity and porosity logs. To a limited extent, cased hole

RFT is carried out where sever hole problems prevent open hole RFT logging.

The tool is normally fitted with both a strain gauge and quartz crystal gauge.

Always use the quartz gauge for interpretation. The strain gauge (less

susceptible to failure but less accurate) should be a health check that all is

well with the quartz gauge. Ensure that all gauges are properly calibrated

before use.

State clearly the objectives of the pressure programme and make sure how all

the pressure points relate to these objectives. Try to see how points could

fulfill multiple objectives to minimize the total number of points. RFT is very

expensive because apart from the logging costs. The pressure readings are

taken while the tools is not only stationary but properly pressed (could say

clamped) to the formation. This greatly increases the chance of getting the

tool stuck after making a pressure reading. The last thing you want to

imagine is getting stuck and possibly loosing the entire well that has been

drilled at considerable cost while making a pressure measurement that could

have been avoided.

Establish a water line in the vicinity of the hydrocarbon bearing sands at any

opportunity of running the tool regardless of the specific objectives of the

particular well. This could be used in interpreting pressures in other well in

99

the field where water intervals are not encountered. It may indeed save the

drilling of an appraisal well.

Two points always form a straight line so you need at last a third point to

confirm the existence of the line.

5.9.3 LABORATORY ANALYSIS OF OIL SAMPLES

Data usually obtained from laboratory analysis include;

1) Original reservoir temperature of person

2) Pressure volume relation at one or more temperature are of which is always

the reservoir temperatures

3) Variation of surface separator pressure with and amounts of gas liberated as

shrinkage of oil resulting from separator process.

4) Differential gas liberation and oil shrinkage data

5) Density and specific volume of reservoir fluid.

6) Variation of oil viscosity with pressure at reservoir pressure to atmospheric

pressure also viscosity of stock tank oil.

100

CHAPTER SIX

6.0 CONCLUSION

Almost all oil and gas produced today comes from accumulation in the pore spaces of

reservoir rocks. The amount of oil or gas contained in a unit volume of the reservoir is the

product of its porosity and the hydrocarbon saturation. In addition to the porosity and

hydrocarbon saturation, the volume of the formation containing the hydrocarbons is needed

in order to determine if the accumulation can be considered commercial.

In this study, the initial oil and gas volumes was calculated from depth contour maps

(horizon maps), reservoir rocks and fluid properties of the Agbara oil well reservoir, which

was used as a case study. The results obtained from the analysis of the area – depth graph and

cumulative bulk volume graph, shows that the fluid saturations in the reservoir structure was

clearly estimated. Also, the recovery factor estimates was done. These estimates are obtained

by making certain assumptions regarding displacement efficiency, residual saturations,

abandonment columns and drive mechanisms based on experience in an operating area.

Usually, these are by correlations based on reservoir and crude properties. Sweep efficiencies

depend on oil and reservoir properties obtained from correlations based on local experience

and simulation studies. Residual saturations depend on rock type obtained from measured

averages from different rock types. Abandonment column height depend on reservoir/ oil

characteristics and well type.

To evaluate the viability of a reservoir, it is useful to know how easily fluid can flow

through the pore system. This property of the formation, which depends on the manner in

which the pore spaces are interconnected, is its permeability. This project has shown the

determination of initial oil reserve in a reservoir and the recovery factor estimates, using fix

values of related petrophysical parameters. It also explains how logs are used to obtain

valuable information about permeability, lithology and connate water saturations, and to

distinguish between oil and gas.

Resistivity measurements, along with porosity and water resistivity, are used to obtain

values of water saturation. Saturation values from both shallow and deep resistivity

measurements were compared to evaluate the viability of an oil reservoir formation.

The results obtained from the evaluation of Agbara oil well showed that the reservoir is

economically viable.

101

6.1 RECOMMENDATIONS

From the findings of this research, I wish to recommend as follows:

(A) There is need to carry out intensive research on reservoir evaluations in order to explore

and evaluate the economic and technological improvements and advantages of alternative

energy sources like oil shales and the biomass-fuel plants over fossil fuels.

(B) I also recommend that more drilling related areas be covered in the future with a more

comprehensive view on oil management.

(C) In reservoir evaluations, I recommend that there is need to improve on the quality of the

scientific log reading tools as the reservoir data needed for evaluation depend on the accuracy

and precision of this equipment.

REFERENCES

Allan J. and Q. Sun (2003): Controls on Recovery factor in Fractured

Reservoirs. SPE Annual Technical Conference.

Archie, E.G. (1982):The Electrical Resistivity Log. As an aid in

Determining some Reservoir Characteristics. Pet Tech, vol.5.

Arps, J.J. (1945): Analysis of Define Curves. Transaction of AIME, Volume

160

Craft, B.C. M.F. Hawkins and R.E. Terry (1991): Applied petroleum

Reservoir Engineering. Second Edition, Englewood Cliffs, New

Jersey Prentice Hall.

Firoozabadi, A (1996), :Recovery Mechanism In Fractured Reservoir And Field

Performance. Journal of Candian petroleum Engineers Formation

Evaluation.

Frank Shray (1997): Logging While Drilling Interpretation. The Four

Dimensions; Seminar Manual, Nigeria.

102

Green, D. W. and G.P. Whihite (1998): Enhanced Oil Recovery Richardson.

Texas Society of Petroleum Engineers.

Halderson. H.H. and Damsleth E. (1993): Challenges in Reservoir

Characterization. American Association of Petroleum Geologist Bulletin,

Volume 77, No. 4.

Lecture Note from Shell Intensive Training Program, SITP, (2000), In Nigeria.

Roman Talamantez (1996): Log Interpretation Principles and Applications.

Seminar Manual. USA.

Ron Baker (1996): A Primal of Oil Well Drilling. 5th Edition, Petroleum

Extention Services, Austin Texas, in Cooperation with international

association of drilling contractors, Houstin, texas.

Schlumberger Wire Line and testing (1993): People and Technology. A

directional Drilling Training manual by Schlumberger, Houston.

Schlumberger Wire Line and testing (1997): Well Evaluation Conference in

Nigeria.

Schlumberger Wire Line and testing (2000): Well Evaluation Conference in

Nigeria.

Sharma P.C. (2003): “A Textbook of Production Engineering. S.Chand and

Company LTD, 7361, New Delhi.

Sylvain Pirson J. (1958): Elements of Oil Reservoir Engineering (2nd

Ed). Ed.

New York: McGraw Hill

Texier, M.P. and Alger R. P (1965): Combine Logs Pinpoint Reservoir and

Resistivity. Biggs, R. P. Carpenter, B.N. PET TECH.

The Times: Weekened Money by Stella Shemon (1998): http//www. the times.

Co.uk/news.

Timmerman E.H. Mcmahon J.J. and Everdinen A.F. (1953): Application of the

Material Balance Equation to a partial water- Drive Reservoir. Trans.

AIME.

103

SAMPLE

QUESTIONNAIRE

AND

APPENDIX

104

APPENDIX A

QUESTIONARE

SAMPLE OF QUESTIONNAIRE

Dear Respondent,

My name is Ngwu Japhet Ifeanyi. I am a postgraduate student of University

of Nigeria, Nsukka Department of Mechanical Engineering. I am carrying out a

project work on reservoir evaluation.

The questions below are intended to provide information about the use of

petrophysical parameters in the evaluation of a crude oil reservoir.

Please, fill the boxes or fill in relevant information in the gap provided. Also

where necessary, kindly provide data in the spaces provided. Your kind co-

operation in sincerely answering the questions will provide a basis for the use of

petrophysical parameters in the evaluation of a crude oil reservoir

A: GENERAL INFORMATION

1. Respondent’s position in the company:

2. Name and address of your company:

3. Number of years you have worked in the company

4. Year the company is established 19

5. Types of ownership:

Sole proprietorship

Partnership

Public limited company

Public liability company

Joint venture

6. Describe your company ownership structure;

1) Wholly indigenous

105

2) Wholly expatriate

3) Indigenous %

4) and expatriate %

7. Indicate the engineering services offered by your company:

Engineering design/consultancy

Engineering construction/installation

Maintenance and calibration company

Engineering services, design, installation and maintenance

Exploration and mining company

Oil servicing company

Others (specify):

B: QUESTIONS ON RESERVOIR EVALUATION

8. What is an oil reservoir?

9. What is the mechanism behind the production of oil in a reservoir?

10. What are the main petrophysical parameters needed for reservoir

evaluations?

11. Does this company have standard established methods for determination of

STOIIP? Yes: No:

12. If yes, which type of method does the company normally use and why the

method?

13. Are there established methods of analyzing petrophysical logs from a

particular reservoir by your company? Yes: No:

14. If yes, name the petrophysical parameter and the method of analysis

________________________________________________

15. Does your company have electronic log tools for petrophysical analysis or

do they hire external contractors? ? Yes: No:

16. If yes, what are the name of the tools and how are they used specifically?

106

17. During the estimation of oil reserve in a reservoir, does it purely depend

on the precision and accuracy of the equipment used?

Yes: No:

18. What are the terms GOC and OWC and how are they determined in a

particular reservoir?

19. How is planimeter used in the determination of area at a particular reservoir?

20. What is a net-to-gross sand ratio and how is it determined in a particular

reservoir?

21. Does connate water saturation have a standard value or does it differ

according to the nature of a reservoir?

22. Please Sir, what is RFT analysis?

23. Why is the net-go-gross ratio F, important in oil estimation in a reservoir?

24. How is the net-go-gross sand ratio, F, porosity Ø, and connate water

saturations Swc determined in a particular reservoir?

25. What are the necessary petrophysical parameters needed for recovery

factor evaluations?

26. What happens at the Gas zone, Oil zone and Water zone in the

abandonment conditions?

27. Is there any laboratory test analysis of an oil sample from a particular

reservoir before drilling?

28. What is well test analysis?

29. What are the different test analysis conducted on well and type of

equipment used?

30. Do you people apply the volumetric method of estimation in

determination of STOIIP? Yes: No:

31. If no, does it mean that volumetric method is insufficient?

107

32. What need to be added in this method for it to be applicable in reservoir

evaluation?

33. How is the pressure gradient determined in a reservoir and the need for pressure

analysis before drilling? ________________________________________________

34. How can Archie’s law be applied in the analysis of hydrocarbon zones in a

particular reservoir? ____________________________________

35 What are the basic economic factors to consider during exploration from a

particular reservoir? ___________________________________________________

108

APPENDIX B

CONVERSION

43560FT2 = 1 ACRE – Ft

43560Ft3 = 1 acre ft = 1

1 acre ft 43560Ft3

Vo = Ah ø S0 acre – ft x 43560ft3

1 acre – ft

:. V0 = 43560 Ah ø S0 – Ft3

But 5.615ft3 = 1bbl

V0 = 43560 Ah ø S0 – ft3 x 1bbL

5.615ft3

:. Vo = 7758 Ah ø S0- rb .

From Equation (1.6), we have

Sw + S0 + Sg = 1,

where Sg 0 (vaporizes)

:. Sw + S0 = 1

S0 = 1- Sw

Therefore, V0 = 7758Ah ø (1-Sw) stb

β0

Where Vo = Volume of Oil

A = Area of the reservoir

h = Height of the reservoir

ø = Porosity of the reservoir

β0 = Formation volume factor

Unit stb = stock Tank Barrel

109

PLANIMETERING OF THE HORIZON MAP FOR EVALUATION OF TOP AND

BOTTOM AREAS

From the scale of the horizon map, it was found that 183 planimeter units on

the horizon map is equivalent to 4Km2 on the ground.

CONVERSIONS

Planimeter readings are converted to actual subsurface areas in acres.

1 km2 = 247.1 acres, (1km2 = 247.1027206 acres)

Therefore, 4km2=988.4 acres. Since this is equivalent to 183 planimeer units on

map, then 1 planimeter unit on map = 5.4 acres on the ground. Thus, the planimeter

readings are then converted to actual ground area values. The top and bottom area

Vs depth are calculated as in the table 3.10 below.

CUMULATIVE BULK VOLUME CALCULATIONS

(3) CBV8700

CBV8700 = Area enclosed by ADFGA

= Area enclosed by ADEA + Area enclosed by DEGFD

But area enclosed by DEGFD = 0.5 x (DE + FG) x 100

= 0.5 x (1.08+(1.73-0.49)) x 100 = 116macft

:- CBV8700 = 103 + 116 = 219 Macft.

(4) CBV8800

CBV8800 = Area enclosed by ADHIA

= Area enclosed by ADFGA + Area enclosed by FGIHF

= CBV8700 + Area enclosed by FGIHF

But area enclosed by FGIFH

= 0.5 x (FG + HI) x 100

= 0.5 x ((1.73 – 0.49) + (2.27 – 1.08) x 100.

= 121.5 Macft.

:- CBV8800 = 219 + 121.5 = 340.5 Macft.

(5) CBV8900

CBV8900 can also be analyzed using the relation.

110

Bulk volume = (sum of the difference in TOP & Base) x (8900-8800)

2

= (2.81 – 1.73) + (2.27-1.08) x (8900 x 8800)

2

= 113.5 Macft

:- CBV8900 = BV8900 + CBV8800

= 113.5 + 340.5 = 454.00Macft.

(6) CBV9000

CBV9000 is analyzed as:

Bulk volume = (3.24-2.27) + (2.81-1.73) x (9000-8900)

2

= 102.5macft

:- CBV9000 = BV9000 + CBV8900

= 102.50 + 454.00 = 556.50 Macft

OIL ULTIMATE RECOVERY FOR CASE WHERE THERE IS NO AQUIFER

INFLUX

A case where there is no aquifer and BVw=0.00, Boa = 1.17 rb/stb

Since BVw = O, Final OWC = Original OWC = 8800ft, Boa=1.23 rb/stb

Final GOC = final OWC – Ha = 8800-40 = 8760ft

But BVa = CBVowc – CBVaoc

BVa = CBV8800 – CBV8760 = 340.5 – 291.5 = 49Macft (from graph)

BVg = CBV8760 – CBV8560 = 291.5 – 64.3 = 227.3 Mac-ft.

But BV = BVa + BVg + BVw = 49 + 227.3 + O = 276.3 Mac-ft.

Applying the recovery factor equation (3.26)

RF = 1 – Boi {BVg[Eg Sorg + (1-Eg)(1-Swc-Sg)] + BVw [Ew Sorw+(1-Ew)(1-Swc-Sg)]+BVa(1-Swc-Sg)}

BoaBV(1-Swc)

:- RF = 1 – 1.23 {227.3[0.7 x 0.15 + (1-0.7) x (1-0.15-0.02)]+49 x (1-0.15-0.02)] = 0.46

1.17 x 276.3 x 0.85

=> Oil Ultimate Recovery = STOIIP x RF

= 295.8 x 106 x 0.46 = 136.1 x 106 Mstb.

111

112

APPENDIX C

PLANNING OF RESERVOIR SIMULATION

PROBLEM DEFINITION

Clear statement of objectives and scope of the simulation study.

Well studies – coning/well testing

Cross section (2D) studies – cupping, vertical heterogeneity, pseudo, landing

depths/completing intervals.

Element studies – vertical /horizontal well completion, well interference,

fault scal, arcal sweep

Full field studies – HCIIP, key appraisal parameters, development options,

reservoir management.

DATA GATHERING

Structural – formation tops, fault sealing potentials

Maps/geological model.

Reservoir description – Rock types/distribution correlations, baffle extent –

logs, cores and deposition model.

Rock properties per type -, Kn, Ky- Logs/cores/ wells tests /RFT- MDT

(Resistively formation Test multiple Dimensional Test) – Kr, S0r Pc, Cf- special

core analysis

Fluid properties – PVT studies

Fluid contacts – Logs,RFT

Aquifer Data – material balance.

MODEL CONSTRUCTION

GIRDING – grid block size just enough to capture variation 1-20k

Averaging /assignment of rock properties

Input of fluid properties

Initialization Data- original fluid contacts

Aquifer data input

Well data input – location, kn, skw, lift and constraints, production data.

113

MODEL VALIDATION

Limitalization – check values of STOIIP, FGIIP and contacts

History matching in honesty + common sense

- matching parameters

- Pressure profile ( time/arcal)

- Well GOR

- Fluid contacts

- Rates

- Matching variables ( what to adjust within honest realistic ranges,

discuss with geologist).

K, Kv/Kh values and profiles

Relative permeabilities – Block/ well

Fault seals

Aquifer parameters

FORECASTING

Reward of development activities/decisions

off take level

Well type, number and location

fluid injection type, location and volumes

Surface facility constraints

Tiring of activities – infill, recompletion, artificial lift, injection, etc.

REPORTING

Objectives

Model description

Model validity – quality of match /sensitivity, further data requirement and

assumptions.

Results of scenario studies

Optimum development option and forecast

114

PRODUCTION FORECATING

True production forecast should be from one or more of the techniques considered

so far:

Material balance analysis

Analytical recovery calculations

Numerical reservoir simulation studies.