“Comparative Performance Analysis of Water and Gas

Flooding in a Saturated Volumetric Oil Reservoir

Using Black Oil Simulator”

Session 2006

Internal Examiner

Amanat Ali Bhatti

Submitted By

Muhammad Umar Javeed 2006-PET-18

Bilal Amjad 2006-PET-22

Ehsan Ali Arif 2006-PET-28

Hassan Tahir Cheema 2006-PET-31

DEPARTMENT OF PETROLEUM AND GAS ENGINEERING UNIVERSITY OF ENGINEERING AND TECHNOLOGY

LAHORE-PAKISTAN

(August 2010)

2

“Comparative Performance Analysis of Water and Gas

Flooding in a Saturated Volumetric Oil Reservoir

Using Black Oil Simulator”

Dissertation

Submitted to the Department of Petroleum and Gas Engineering, University of

Engineering and Technology Lahore in the partial fulfilment of the requirement for

the Bachelor`s Degree in Petroleum and Gas Engineering.

Submitted By

Muhammad Umar Javeed 2006-PET-18

Bilal Amjad 2006-PET-22

Ehsan Ali Arif 2006-PET-28

Hassan Tahir Cheema 2006-PET-31

APPROVED ON: _______________________

__________________ _______________________

Amanat Ali Bhatti Yawar Saeed Assistant Professor Reservoir Engineer

Internal Examiner Schlumberger Information Solutions

External Examiner

_____________________

Prof. Dr. Syed Muhammad Mahmood

Chairman

DEPARTMENT OF PETROLEUM AND GAS ENGINEERING

UNIVERSITY OF ENGINEERING AND TECHNOLOGY

LAHORE-PAKISTAN

(August 2010)

3

لرحيم١لرحمن ١لله١بسم

4

To our

Parents & Teachers

5

Nomenclature

GOC: Gas oil contact

WOC: Water oil contact

GOR: Gas-oil ratio

WOR: Water-oil ratio

BHP: Bottom hole pressure

G&G: Geological and geophysical

IMPES: Implicit pressure and explicit saturation

AIM: Adaptive Implicit

RC: Resistance-capacitor

MMP: Minimum miscibility pressure

DST: Drill-stem testing

PVT: Pressure-volume-temperature

API: American Petroleum Institute/ Unit for oil gravity measurement

CSP: Comparative solution project

Vb: Bulk volume

OIIP: Oil initially in place

Soi: Initial oil saturation

Swc: Connate water saturation

PV: Pore volume

cf: cubic feet at given conditions

FVF: Formation volume factor

Rs: Solution gas-oil ratio

INJ: Injection well name

PROD: Production well name

Np: Recoverable oil

Vp: Swept pore volume

Sor: Residual oil saturation

Es Areal sweep efficiency

Ei Vertical sweep efficiency

H: Capillary transition zone thickness

h: Reservoir thickness

kro, krw: Relative permeability of oil and water

6

A: Cross-sectional area of flow

k: Absolute permeability

ρo, ρw: Density of oil and water

μo, μw: Viscosity of oil and water

qt, qo, qw: Flow rates total, oil and water

g: Gravitational constant

fw: Fractional flow of water

: Gravity change

krow: Relative permeability of oil in oil-water system

krowg: Relative permeability of oil in gas-oil-water system

α: Dip angle

IFT: Interfacial tension

EOR: Enhanced oil recovery

FCM: First contact miscibility

LPG: Liquefied petroleum gas

MCM: Minimum contact miscibility

Pc: Capillary pressure

Ed: Microscopic sweep efficiency

Ev: Vertical sweep efficiency

E: Overall displacement efficiency

WAG: Water alternating gas

MME Minimum miscibility enrichment

FOPR: Field oil production rate

FGOR: Field gas-oil ratio

FPR: Field pressure

BHP; PROD Bottom hole pressure of production well

BHP; INJ Bottom hole pressure of injection well

FWCT: Field water cut

FWPR: Field water production rate

FOPT: Field oil production total

7

List of Tables

Table Description Page #

Table 1.1: Data required for simulation 23

Table 1.2: Layer properties of reservoir A-1 26

Table 1.3: Gas-oil PVT properties 27

Table 2.1: Water saturation functions 41

Table 2.2: Gas saturation functions 41

Table 2.3: Oil saturation functions 42

Table 3.1: Water saturation functions 57

Table 3.2: Gas saturation functions 57

Table 3.3: Oil saturation functions 58

Table 4.1: Gas saturation functions 73

Table 4.2: Oil saturation functions 73

8

List of Figures

Figure Description Page #

Fig 1.1: Decline curve analysis for short term production forecasting 19

Fig 1.2: Basic reservoir simulation models 22

Fig 1.3: 2D areal view showing INJ and PROD location 28

Fig 2.1: Production history of Bradford fields 31

Fig 2.2: Waterflooding mechanism 31

Fig 2.3: Frontal displacement of injected water 33

Fig 2.4: Injection rate affect on recovery 35

Fig 2.5: Approximation to diffuse flow condition 37

Fig 2.6-15: 3D illustration of waterflooding 43

Fig 3.1: Schematic x-sectional view of anticlinal reservoir of thickness h and

dip α angle with gas cap overlying oil column 52

Fig 3.2-11: 3D illustration of immiscible gas flooding (b) 58

Fig 4.1: FCM displacement 62

Fig 4.2: Vaporising gas displacement process 63

Fig 4.3: Condensing gas drive process 64

Fig 4.4: A comparison of phase behaviour for CO2 and CH4 65

Fig 4.5: Factors affecting miscible recovery 68

Fig 4.6: Effect of pressure on phase behaviour 70

Fig 4.7: Effect of pressure and gas enrichment on oil recovery 71

Fig 4.8-17: 3D illustration of miscible gas flooding 74

Fig 5.1: Waterflood performance profile 76

Fig 5.2: HC gas flood (a) performance profile 77

Fig 5.3: HC gas flood (b) performance profile 78

Fig 5.4: Miscible gas flood performance profile 79

Fig 5.5: Field pressures (FPR) comparison 80

Fig 5.6: Field oil production rates (FOPR) comparison 81

Fig 5.7: Field gas-oil ratios (FGOR) comparison 82

Fig 5.8: Field gas production rates (FGPR) comparison 83

Fig 5.9: Field oil production totals (FOPT) comparison 84

Fig 5.10: Oil recovery factors comparison 84

Fig 5.11: Cumulative oil recovered comparison 85

9

Fig 5.12: Field pressures comparison 86

Fig 5.13: Field oil production rates comparison 86

Fig 5.14: Field water cut comparison 87

Fig 5.15: Field oil production total comparison 87

Fig 5.16: Oil recovery factors comparison 88

Fig 5.17: Cumulative oil recovered comparison 88

10

Contents

Acknowledgment

Abstract

Reservoir Simulation – Fundamentals

1.1 Introduction ................................................................................................... 15

1.1.1 Basic Concept of Simulation ............................................................. 17

1.1.2 Methodology of Reservoir Simulation............................................... 17

1.1.3 Traditional Analysis Techniques ....................................................... 17

1.2 When to Run a Simulation Model? ............................................................... 18

1.3 Why ―Run‖ a Simulation Model? ................................................................. 19

1.4 Designing the Simulation Model................................................................... 20

1.4.1 Black Oil Model ................................................................................. 22

1.4.2 Data Required for Model Construction .............................................. 23

1.4.3 Sources of Data for Reservoir Simulation ......................................... 24

1.5 Recommendation and Final Advice for a Simulation Engineer .................... 25

1.6 Reservoir A-1 (Case Study) .......................................................................... 26

References ............................................................................................................... 28

Water Injection in Oil Reservoirs

2.1 Introduction ................................................................................................... 30

2.2 Development of Waterflooding ..................................................................... 30

2.3 How Does Water Injection Work? ................................................................ 31

2.3.1 Water Injection Procedure ................................................................. 32

2.4 Technical Factors .......................................................................................... 32

2.5 Economic Factors .......................................................................................... 33

2.6 Displacement Mechanics............................................................................... 33

2.6.1 Homogeneous Reservoirs .................................................................. 33

2.6.2 Heterogeneous Reservoirs ................................................................. 34

2.7 Water Injection Performance Calculations ................................................... 35

2.8 The Fractional Flow Equation ....................................................................... 36

11

2.9 Optimum Time for Waterflooding ................................................................ 38

2.10 Selection of Flooding Patterns ...................................................................... 38

2.11 Limitations of Waterflooding ........................................................................ 39

2.12 Conclusion ..................................................................................................... 40

2.13 Reservoir A-1 (Case Study) .......................................................................... 40

References ............................................................................................................... 44

Immiscible Gas Injection in Oil Reservoirs

3.1 Introduction ................................................................................................... 45

3.2 Factors affecting performance of gas injection ............................................. 47

3.2.1 Reservoir Pressure ............................................................................ 47

3.2.2 Fluid Composition ............................................................................ 47

3.2.3 Reservoir Characteristics .................................................................. 47

3.2.4 Relative Permeability ........................................................................ 48

3.3 Geological Considerations ............................................................................ 48

3.4 General Immiscible Gas/Oil Displacement Techniques ............................... 49

3.4.1 Types of Gas-Injection Operations ................................................... 50

3.4.2 Optimum Time to Initiate Gas Injection Operations ........................ 51

3.4.3 Efficiencies of Oil Recovery by Immiscible Gas Displacement ................ 51

3.5 Vertical or Gravity Drainage Gas Displacement........................................... 52

3.6 Immiscible Gas Displacement and Reservoir Simulation ............................. 53

3.6.1 Calculating Immiscible Gas Injection Performance ......................... 54

3.7 Conclusion ..................................................................................................... 54

3.8 Immiscible Gas-flood Monitoring ................................................................. 55

3.9 Reservoir A-1 (Case Study) .......................................................................... 56

References ............................................................................................................... 60

Miscible Gas Injection in Oil Reservoirs

4.1 Introduction ................................................................................................... 61

4.2 Types of Miscible processes ......................................................................... 62

4.3 Forces Responsible for Oil Trapping ............................................................ 65

4.3.1 Capillary forces ................................................................................. 65

12

4.3.2 Viscous Forces .................................................................................. 67

4.4 Factors Affecting Miscible Recovery ........................................................... 67

4.4.1 Microscopic Displacement Efficiency .............................................. 67

4.4.2 Macroscopic Displacement Efficiency ............................................. 68

4.5 Designing a Miscible Flood .......................................................................... 69

4.5.1 Determining Miscibility .................................................................... 70

4.5.2 Choosing a Candidate Reservoir ....................................................... 71

4.6 Economic Considerations for Implementing Miscible Gas Injection Process

71

4.7 Conclusion ..................................................................................................... 72

4.8 Reservoir A-1 (Case Study) .......................................................................... 73

References ............................................................................................................... 75

Analysis and Screening

5.1 Individual Project Analysis ........................................................................... 76

5.1.1 Waterflood Performance ................................................................... 76

5.1.2 HC Gas (Immiscible) Flood Performance ........................................ 77

5.1.3 Miscible Gas Flood Performance...................................................... 79

5.2 Comparative Project Analysis ....................................................................... 79

5.2.1 Field Pressure .................................................................................... 79

5.2.2 Oil Production Rate........................................................................... 80

5.2.3 Gas-oil ratio ..................................................................................... 81

5.2.4 Gas Production Rate ......................................................................... 82

5.2.5 Oil recovered and the Recovery Factor ............................................ 83

5.3 Extending simulation time to 30 years .......................................................... 85

5.4 Conclusion ..................................................................................................... 89

5.5 Recommendation ........................................................................................... 89

13

Acknowledgment

We bow our head before Almighty Allah, the most compassionate and merciful, who

blessed us with sound health, respectable teachers and sincere friends. We express our

deepest gratitude to Almighty Allah for enabling us to complete this challenging

work. We also offer our humblest thanks to Holy Prophet (P.B.U.H) who is forever a

model of guidance for humanity, enlightens the hearts of believers in their life and

graves. We are greatly indebted to our supervisor Assistant Professor Amanat Ali

Bhatti for his precious guidance, inspiring suggestions and constructive criticism

which evoked critical thinking at the writers work. We are also thankful to our worthy

Chairman S. M. Mahmood for his support, encouragement, and invaluable guidance

for the successful completion of this project report. We also want to thank our

professors, staff and friends at the University who made our stay a very enjoyable

one. We also want to thank our parents, who were always there to pray for us and

encourage us.

Much of the material on which this project is based was drawn from the publications

of the Society of Petroleum Engineers. Tribute is due to the SPE and the petroleum

engineers, scientists, and authors who have made numerous and significant

contributions to the field of reservoir engineering.

14

Abstract

The aim of this project is to examine the performance and effectiveness of various

recovery mechanisms on a reservoir using a commercial black oil simulator;

ECLIPSE 100. After reviewing the concerned literature a hypothetical reservoir

model has been developed and various recovery mechanisms have been compared

using various worth considered parameters. At the end, a comparison is drawn for all

the recovery methods and the most effective is recommended to be applied on the

subject reservoir.

15

Reservoir Simulation – Fundamentals

1.1 Introduction

Reservoir Simulation is the most reliable to date process available to the reservoir

engineers for predictive purposes despite of conventional material balance and decline

curve analysis techniques. The main reason supporting its ever rising success is its

availability to account for reservoir heterogeneity or geology. Reservoir simulators

are developed to do these calculations for simulation study using hi-fi computers

because to solve lengthy equations for millions of cells by human minds is a tedious

job.

Defining reservoir simulation as, “It is the study of how fluids flow in a hydrocarbon

reservoir when put under production conditions. The objective is usually to predict

the behaviour of a reservoir to different production scenarios or to increase the

understanding of its geological properties by comparing known behaviour to a

simulation using different geological representations1”.

The potential of simulation was developed in the late 1940’s and early 1950’s by a

number of companies. Their effort and determination in the field of advanced

numerical analysis resulted in the development of reservoir simulators by the mid

1950’s or by the beginning of 1960’s 2, 3

. The basic purpose behind this development,

in the area of reservoir management, was to reduce the large cost of studying

reservoirs for reliable predictions and long-term planning by continuously updating

the previous study rather than start from the initial.

Defining reservoir simulator as, “It is a tool for predicting hydrocarbon reservoir

performance under various operating strategies developed by combining physics,

mathematics, reservoir engineering, and computer programming1.”

1

16

With the passage of time and the evolution of high speed processors simulation got

more fame and became practical for even bigger reservoirs and day-to-day decision

making. Summarising below the answers for why we need reservoir simulation.1, 4, 5

Well placement Optimization

Drilling a well, costs millions of dollars and wrong placement means the loss of

whole investment. Simulation study of well placement in a developing field can

prevent this loss.

Perforation Interval

Simulation allows the determination of optimum perforation interval offset from GOC

or WOC in vertical and horizontal wells.

Critical Production rates

Coning can be avoided by the critical rate determination from single well simulation

models.

Producing zone identification

Portion of the reservoir from which the production is coming can be determined using

the 3D models and thus provide guidance in drilling the additional wells.

Optimum production strategies

Production rates, tubing sizes, GOR/WOR and BHP limits can be selected in order to

maximize the recovery from the reservoir.

Reservoir size determination

Estimating reservoir size helps in cash flow predictions.

Recovery mechanism

Natural recovery mechanism is determined from material balance technique only if

production data is available. Simulation allows determination of optimum recovery

technique to be applied and the time for application during/after natural production.

Infill drilling

To maximize the revenue by increasing the production is the foremost objective of

any company. This can be achieved by drilling appraisal and development wells in the

producing reservoir especially when already producing wells met some problem that

can’t be recovered. Question of when and where we will need to drill additional well

is answered by a simulation run.

17

1.1.1 Basic Concept of Simulation

There are three basic laws the subject simulation is based on; mass, momentum and

energy conservation. Mass conservation making the foundation stone of simulation,

momentum and energy conservation accounts for the spatial fluid dynamics and

thermal variations respectively in the reservoir.

1.1.2 Methodology of Reservoir Simulation

The reservoir is divided into a number of grid blocks, populated with real reservoir

heterogeneity and static reservoir properties by G&G (Geological and Geophysical),

production data (well rates, pressures as function of time) by reservoir engineers and

then the appropriate equations (Fully implicit or IMPES or AIM) are selected and

solved to give pressure and saturations for each grid block for pre-decided time span.

1.1.3 Traditional Analysis Techniques

Before the development of reservoir simulation three conventional approaches were

used primarily for reservoir modelling and analysis6.

a. Analogical

b. Experimental

Analog Models

Physical Models

c. Mathematical

Analogical Modelling is the oldest technique when a limited number of data sources

were available. The target reservoir was analysed by comparing with the reservoirs in

the same geological feature or basin. Reservoir engineers took help from production

and pressure trends of these reservoirs and developed production schemes for their

target zones. For example Potwar basin in Pakistan contains the Sakessar (Naturally

fractured limestone) formation which is found productive in many fields. A company

exploring in this region if found this formation can rely on previously exposed

potential of bearing hydrocarbons, and can adopt the same development strategies for

the drilling and production. Analogical modelling is efficient where problem causing

zones baffles the field economics. For example Murree formation is usually

18

encountered while drilling in Potwar basin in Pakistan, which is potentially unwanted

zone, so company planning to drill in this region will be aware of the risk and outfit

for confronting with the help of appropriate technology.

Experimental Modelling approaches as compared to analogical played a key role in

understanding petroleum reservoirs. Analog Models (RC-Networks, Potentiometric

and Hele Shaw Models) were first developed then the trend shifted towards the

physical models (core floods, Sobocinski and Cornelius’s single well coning model).

Slim tube models used for the minimum miscibility pressure (MMP) estimation are

the latest example.

Mathematical Modelling is the approach probably most commonly used by expert

petroleum engineers. It includes material balance, decline curve, Buckley Leverett

(waterflood), Marx Langenheim (steam) and analytical (well testing) etc. of which

well testing in form of DST is considered the mandatory tool for capacity estimation

of hydrocarbon reservoir before completion.

1.2 When to Run a Simulation Model?

In petroleum practices the prevalent exploitation and recognition of reservoir

simulation is not free from danger, of course. The restrictions of the technique and its

misuse have been highlighted many times through the years, in some cases by those

experts who are considered among the initiators of the technique; Coats K. H.7and

Arfonovsky J. S.

The project manager must evaluate all the aspects involved in the decision of running

a reservoir simulation model before initiating any research work. The basic question

is always: is it really worth? Sometimes or most of the times it happens that problem

can be solved by the conventional, simplest, faster and least expensive approach that

will provide an adequate answer, in such cases it is highly recommended that not to

go for simulation. For example, when the short-terms production profiles are to be

evaluated, decline curve analysis (Fig 1.1 ) represents a reliable and cost-effective

tool, while simulation would prove to be a long and expensive alternative2.

19

Fig 1.1 Decline curve analysis for short term production forecasting 8.

In an old but evergreen paper about the use and misuse of reservoir simulation, Coats7

stated that valid applications should fulfil the following three features:

1. A well posed question of economic importance. A typical question would

challenge for example the choice of a waterflooding project over a natural

depletion scheme, location for additional wells to increase incremental field

deliverability per dollar.

2. Adequate accuracy of reservoir description and other required input data.

3. Strong dependence of the answer upon non-equilibrium, time-dependent

spatial distributions of pressure and fluid saturations. This dependence will

rule out traditional analytical techniques like material balance.

1.3 Why “Run” a Simulation Model?

There are many answers to this question; why ―run‖, most of them are presented in

Section 1.1. Perhaps the most important, from a commercial outlook, is the ability of

this technique to generate hydrocarbon production profiles under various exploitation

options and hence cash flow predictions. Simpler techniques like material balance are

particularly used for appraising reservoir mechanics but can’t be suitable for the

reservoir forecasting.

0

500

1000

1500

2000

2500

3000

3500

4000

4500

Oil

Pro

d. R

ate

(b

op

d)

Decline Curve Analysis

20

Reservoir simulation, on the other hand, offers engineer the required flexibility to

study the performance of the field under defined production management routines and

operating conditions at the levels of producing interval, well, well group, reservoir

and field. In its simplest definition, these well-management routines assign specified

rates and pressures to the wells, but they can also perform much more complex tasks,

like shut-in or work-over a well according to some GOR or WOR criteria, optimise

individual well production to match facilities capacity, control gas production or

injection rates and so on. This is why reservoir simulation is considered the best

technique for reservoir management. No other engineering tool offers such diversified

capabilities.

1.4 Designing the Simulation Model

Once the assessment to run a simulation study is done, the next step is to construct the

simulation model. This phase involves the selection of the geometry type to utilise

and the choice of the simulator. In this respect, a number of factors have to be taken

into consideration, some of which are listed below and described briefly2.

The recovery process of the reservoir. This is the most important parameter,

since the model must be able to correctly reproduce the main reservoir drive

mechanisms. This influences the type of model to be used and also the degree

of resolution to arrive at. For example, when a water-oil displacement process

is the main driving mechanism, a black-oil simulation will be adequate, but on

the other hand the model must be sufficiently refined both areally and

vertically to properly reproduce the complex geometry of the displacement

fronts. On the other hand when steam flood for heavy oils and tar sand

recovery is the subject, thermal simulation accounts for the heat energy

transfer to the rock and fluid.

Quality and type of the available information. These influence the level of

detail to be used in the model. Complex reservoir and fluid descriptions based

on few and/or poor quality data may be seriously misleading and generate un-

realistic solutions.

Objective of run. In most studies, relatively simple outputs are required,

typically oil, gas and water production profiles. In such cases, a black-oil

simulator may be sufficient even when complex hydrocarbon interactions

21

happen in the reservoir. However if for the same reservoir the composition of

the produced phases is required, then a compositional model must be run. The

desired accuracy of the expected results will also influence the design of the

simulation model.

Available resources. The study must be measured against the human,

economic and technological resources available. It is dangerous to start

complex studies, without assessing the global effort required, in terms of

expert level, software, hardware and the budget limits.

This preliminary analysis will help in defining the degree of complexity required for

the particular study. The bottom-line is that the model design phase should always

lead to the construction of the simplest model able to meet the objective of the study.

Final Advice at the end of this chapter will help to understand such bottom-lines.

Simulation model design2 consists of following two steps:

1. Selecting type of geometry and grid system

Mattax Dalton9 and Leonard F. K.10 defined different geometry types (Fig

1.2) for use in simulation study. One misuse of simulation model, reported

by Coats7, I would like to quote here is ―Overkill‖; the use of too many

grid blocks. Almost the same results are obtained using much simpler grid

system or using half or one third of number of grid blocks. Selecting type

of grid is also a worth considered process. Khaled Aziz11

in his publication

discussed it in detail.

2. Selecting simulator type

Different types of simulators are used to represent the mechanisms related

to different types of reservoirs. The selection basically depends on the

nature of the original reservoir fluids and the predominant recovery

process. These include black oil model, compositional model, thermal

model, chemical model and streamline models. In our project we have

dealt with black oil model so we thought it necessary to only describe

criteria under which Black Oil model is used.

22

1.4.1 Black Oil Model

As stated early this type of isothermal model applies to reservoirs containing

immiscible oil, gas and water phases. The black oil model is the earliest most

development in the field of reservoir simulation treating hydrocarbons as if they had

two components, i.e., oil and gas, with a simple, pressure-dependent solubility law of

the gas in the liquid phase. No variations are allowed for gas and oil compositions as a

function of pressure or time. These models can be used to reproduce most reservoir

mechanisms, including solution gas-drive, gas-cap drive, water drive, water injection,

and immiscible gas injection. They can deal with vertical variations of the PVT

properties, by defining a saturation pressure/depth relationship. They can also deal

with lateral PVT variations, through the definition of different equilibrium regions.

Current practice in the industry is the ―API Tracking‖12

; alternative method of PVT

regional definition. This facility enables the mixing of different types of oil, having

different surface densities and PVT properties while PVT region method cannot

model the mixing of different oil types.

Tank Model 1D Model

Cross-sectional 2D Model Areal 2D Model

3D Model

Radial Model

Fig 1.2 Basic Reservoir Simulation Models9 (Reproduced)

23

1.4.2 Data Required for Model Construction

The phase of designing a simulation model requires the availability of corresponding

data. The simulation team should review the data to see if enough data is available to

meet the objectives of the modelling. If data is missing, team should determine if

missing data can be obtained by a more thorough search of the existing database, by

using data from analogous reservoirs (Section 1.1.3), or by using correlations to

generate missing data. A complete set of data must be provided to run the simulator. It

is prudent to select data values that can be justified.

The typical rock and fluid property data normally required in model construction is

listed in Table. 1.1. The table also constitutes the keywords required in our simulator

for the corresponding data assignment.

Table. 1.1 Data Required for Simulation9, 13

Theoretical

Symbol

ECLIPSE Keyword Description

For Initial/static Condition

Rock

D TOPS Depth to formation top

structure

ht

NTG =hn/ht

Gross formation

thickness

hn Net pay thickness

Φ PORO Formation porosity

kx,y,z PERM (X,Y,Z) Absolute permeability

S Initial Saturation of

fluid

Fluid

Bo Oil FVF

Bw Water FVF

Bg Gas FVF

ρo

ρw

ρg

DENSITY or

GRAVITY

Oil density

Water density

Gas density

For Dynamic Condition

Rock

kr vs. S & Pc SWFN, SGFN, SOFN, SOF2, SOF3

or SWOF, SGOF

Multiphase relative

permeability of flowing

phase w.r.t. saturation.

ct ROCK rock compressibility

Fluid

FVF, Rs, μ, ρ vs. P PVTO, PVDO, PVDG, PVTW, PVTG HC PVT properties as

function of pressure

24

co, cw Oil and water

compressibility

respectively

Production/Injection

Name (i, j) WELLSPECS Well name & location

(i, j, k1) ~ (i, j, kn) COMPDAT Well completion

interval

Q (STB/D) WCONPROD WCONINJ Well control data &

Phase flowing (O, G,

W, L)

Time DATE or TIMESTEP Time span divided into

durations of interest

1.4.3 Sources of Data for Reservoir Simulation

Reservoir engineering and reservoir simulation are not exact sciences. Input data are

results obtained from geophysics, geology, petrophysics, fluid behaviour studies and

production engineering techniques. Each of these techniques has their limitations due

to necessary interpretation methods based on physical indirect measurements.

However we have explained some parameters and their sources of origin3.

a) Porosity and Permeability: Core Analysis, well logs, well test are three

sources of porosity and permeability, however now the trend is shifting

towards well log data because of chances of core property alteration during

handling, and economical reasons in case of well tests. In the end because

there is never enough data to remove uncertainties therefore consideration

should be given to each and every available set of data9. However there exist

certain correlations for estimation of permeability, widely using in the

industry. Of them we have used Corey14

, Corey and Brook Method15

and Stone

3 phase Model II 6.

b) Capillary Pressure: Special core analysis is the mostly used technique to

measure capillary pressure. Gas-oil capillary pressure data can be measured

with either porous-plate or centrifuge equipment. One approach for obtaining

gas-oil relative permeability data is the viscous displacement method in which

gas displaces oil. A second method is the centrifuge method, which is

generally used to obtain capillary pressure and relative permeability

information simultaneously. However it is expensive and time consuming but

it is relatively easier to measure capillary pressure as compared to relative

25

permeability especially when mercury-intrusion approach is applied16

. And

relative permeability is then generated from these capillary pressure curves

using a mathematical model chosen from several available like Wyllie and

Gardner Model.

c) Reservoir Description: Heterogeneities, faults, reefs, pinch outs, fissures are

pooled into structured coordinated programme by the team effort of

geologists, geophysicists, log analysts and engineers to define the depositional

environment as a basis for continuity in productive and non-productive zones

in the reservoir 6, 9

.

d) Reservoir Fluid: PVT analysis on crude oil sample is the sources of fluid

description require to be used in simulation model.

e) Production Parameters: Production rates, pressures, WOR and GOR limits are

defined on the basis of certain economic and technical constraints (Surface

handling equipments, water disposal facilities etc.)

We have adopted grid and PVT data and some other parameters for our work from

CSP 8 17

.

1.5 Recommendation and Final Advice for a Simulation Engineer

Large experience in reservoir engineering is necessary to take full advantage of the

technology offered in reservoir simulation. A minimum investment in the technology

is required to understand and master the ―tool‖. Many assumptions are necessary to

build a reservoir model therefore calculations are approximate and a good engineering

judgment is required to evaluate input data and interpret calculation results3.

Khaled Aziz18

reported 10 golden rules in this regard. They are very briefly quoted

here but can be have directly from the original article.

1. Understand your objective and define the problem.

2. Keep it simple.

3. Understand interaction between different parts of reservoir.

4. Don’t assume bigger is always better.

5. Know your limitations and trust your judgment.

6. Be reasonable in your expectations.

7. Question data adjustments for History matching.

26

8. Don’t smooth extremes.

9. Pay attention to the measurement and Use scales.

10. Don’t skimp on necessary laboratory work.

1.6 Reservoir A-1 (Case Study)

Using computer modelling to simulate hydrocarbon reservoir behaviour prediction is

a laborious task. We have used this tool to simulate the performance of recovery

techniques applied on a saturated oil reservoir A-1, the whole procedure is divided

among proceeding chapters followed by concerned literature review and a complete

comparison in Chapter 5. However general reservoir data is presented below.

Reservoir Description: A saturated oil reservoir A-1 with areal extent of 574 ac. (Vb

= 186523 ac.ft) is initially at bubble point pressure of 3814.7 psia. The formation

compressibility is assumed to be approximately 6E-6 sip. OIIP is 137.41 MMSTB and

Rsi is 770 SCF/STB.

Initial saturation distributions at 7,100-ft depth are assumed to be

and . At the reference depth of 7,100 ft., initial formation pressure is

assumed to be 3814.7 psia.

Porosity and Permeability: The reservoir A-1 consists of four formations with

porosity, permeability and thickness shown in Table 1.2 Assuming vertical

permeability to be 1/10th

of horizontal permeability. PV is 233766231 RB

Table 1.2 Layer properties of reservoir A-1

Layer Porosity kH (md) kv (md) h (ft)

A 30% 500 50 25

B 20% 50 5 75

C 20% 20 2 75

D 10% 10 1 150

Fluid Properties: The reservoir A-1 will be set to produce by 3 recovery

mechanisms; water, HC gas, miscible gas floods. The formation produces 35 API

gravity oil with no sulphur at isothermal conditions of 220F. The connate water has

specific gravity of 1, formation volume factor of 1.02, compressibility of 6E-6 sip and

viscosity of 0.7 cp. at reference pressure of 4500 psia. Table 1.3 gives comprehensive

description of the fluid PVT data17

to be used during this simulation study.

27

Relative Permeability: Data is generated through Corey, Stone and Corey and Brook

correlations and results will be presented subsequently in the proceeding chapters.

Grid System: Reservoir A-1 is modelled as follows

Model Dimensions : 10x10x4

Grid Type : Cartesian

Geometry Type : Block centred

Grid Dimensions

Layer 1 : 500x500x25 cf

Layer 2 and 3 : 500x500x75 cf

Layer 4 : 500x500x150 cf

Table 1.3 Gas-Oil PVT Properties

Gas Oil

Pressure FVF Viscosity Rs FVF viscosity

Psig bbl/Mscf Cp Mscf/stb bbl/stb cp

1200 13.947 0.0124 0.137 1.172 1.970

1400 7.028 0.0125 0.195 1.200 1.556

1600 4.657 0.0128 0.241 1.221 1.397

1800 3.453 0.0130 0.288 1.242 1.280

2200 2.240 0.0139 0.375 1.278 1.095

2600 1.638 0.0148 0.465 1.320 0.967

3000 1.282 0.0161 0.558 1.360 0.848

3400 1.052 0.0173 0.661 1.402 0.762

3800 0.890 0.0187 0.770 1.447 0.691

4200

1.4405 0.694

4614

1.434 0.697

The reservoir has two diagonally completed wells; injector (INJ) and a producer

(PROD) shown in Fig 1.3. Internal diameter available for fluid flow is 0.33 ft. for

both wells. Time span for simulation is 10 years.

28

Fig 1.3 2D areal view showing INJ and PROD Location.

References

1. Prem Dayal Saini, ―Overview of Reservoir Simualation‖. Infosys (2008) –

Energy Utilities Services

2. Cosentino, ―Integrated Reservoir Studies‖. Institut Franḉais Du Pétrole (2001).

TECHNIP. France 248

3. Pierre Donnaz. ―Essentials of Reservoir Engineering‖. Institut Franḉais Du

Pétrole (2007) TECHNIP, France.

4. Teknica, ―Reservoir Simulation”, Teknica Petroleum Services, Alberta (2001)

8.

5. Aziz, K., A. Settari.: ―Petroleum Reservoir Simulation‖. Applied Science

Publishers Limited (1979). London. 3

6. J. H. Abou Kassem, T. Ertekin, ―Basic Applied Reservoir Simulation‖ SPE

Textbook Series (2001), 1-2, 26, 33, 311

7. Coats KH, ―Use and misuse of reservoir simulation‖. JPT (1969). 1398

8. Production Data Acquired from OGDCL, Fimkassar Oil Field. (2010)

PROD

INJ

29

9. Mattax, Dalton, ― Reservoir Simulation‖ SPE Monograph (1990) 30

10. Leonard F. Koederitz., ―Lecture Notes on Applied Reservoir Simulation‖.

University of Missour Ralla (2004) USA

11. Aziz, K. “Reservoir Simulation grids: Opportunities and Problems”. JPT

(1993). 658

12. ECLIPSE 2009.1, ―Technical Description‖. (2009) 69

13. ECLIPSE 2009.1, ―Reference Manual‖. (2009)

14. Ahmed. T., “Reservoir Engineering Handbook” 4th

Edition (2010). Gulf

Professional Publishing. 301-303

15. Richard L. Christiansen., ―Petroleum Engineering Handbook – General

Engineering‖ 2th

Edition. (2006) SPE Richardson TX. 746-747

16. Kewen Li, ―Determination of Resistivity Index, Capillary Pressure and

Relative Permeability‖ Stanford U. (2010) CA. USA.

17. Phillppe Quandalle, ―Gridding techniques in reservoir simulation”. 8th

SPE

comparative solution project. 1993

18. Aziz, K. ―Ten Golden Rules for Simulation Engineers,‖ JPT (November

1989). 1157

30

Water Injection in Oil Reservoirs

2.1 Introduction

Water injection is one of the most common methods used in oil industry in which

water is injected into the reservoir, usually to increase pressure and thereby stimulate

the production1.Water injection, the oldest recovery method, remains the most

common of all other recovery methods (80% of the oil produced in the United States

in 1970 was produced by water injection). Oil recovery is increased by an

improvement in sweep or displacement efficiency.

In addition to the enhanced recovery objective, water injection may also be used in

order to:

1. Maintain the reservoir pressure when the expansion of the aquifer or gas cap is

insufficient for the purpose. In this instance the process should be regarded as

one of pressure maintenance rather than of enhanced recovery.

2. Dispose of the brine produced with the oil if surface discharge is not possible

(e.g. into lakes or fresh water sources).

2.2 Development of Waterflooding

The discovery of crude oil by Edwin L. Drake at Titusville, PA, on Aug. 27, 1859,

marked the beginning of petroleum era. Although the first oil well produced about 10

bbl/day, within 2 years other wells were drilled that produced thousands of barrel per

day2.

The practice of waterflooding apparently began accidently. Many wells were

abandoned in the Bradford field following the flush production period of the 1880’s.

In this situation fresh water from shallower horizons apparently entered the producing

2

3

31

interval and the operators were realized that water entering the productive formation

was stimulating production. The first flooding pattern, termed as circle flood,

consisting of injected water into a well until surrounding producing wells watered out.

These wells were converted to injectors to create an expanding circular wave front.

Waterflooding was quite successful in the Bradford field. Figure 2.1 shows the

production history of the Bradford field for more than 100 years of producing life.

Fig 2.1 Production History of Bradford fields2

2.3 How Does Water Injection Work?

While primary production refers to oil that is recovered naturally from a producing

well, Improved Oil Recovery (IOR) improves the amount of oil recovered from a well

by using some form of additional engineering technique3. Water injection, also known

as waterflood, is a form of this secondary production process. (Fig 2.2)

Fig 2.2 Waterflooding Mechanism10

32

2.3.1 Water Injection Procedure

In this section we will discuss the basic procedure for the water injection. The water

used for injection is usually some sort of brine, but it can also be made up of other

treated components. For example, in some reservoirs water is produced with the

hydrocarbons, removed from the production and re-injected into the formation.

Filtration and processing of the water that will be injected are sometimes necessary to

ensure that no materials clog the well pores and that bacteria is not permitted to grow.

Deoxidisation of water is done in an effort to reduce any corrosion within the

wellbore and the piping system. In waterflooding process production wells can be

converted into injection wells and water-injection wells are also drilled specifically

for this purpose.

There are a number of techniques for determining where the water-injection wells

should be drilled, as well as established patterns for water-injection wells in relation

to production wells. One popular pattern, called the five-spot pattern, involves drilling

four water-injection wells in a square around a production well. This is repeated

around each production well on the reservoir, resulting in four production wells

surrounding each water-injection well.3

2.4 Technical Factors

When the natural reservoir energy is judged to be insufficient, the choice of enhanced

recovery method is made according to both technical and economic criteria. Water

injection is to be preferred in all cases where there are no practical constraints, due to

the more favourable mobility ratio obtained. In reservoirs containing highly under-

saturated oil, water injection is all the more suitable since the low gas-oil ratios would

result in only small volumes of gas being available for gas injection. In reservoirs

containing saturated oil, water is the preferred injection fluid as long as the

permeability to water is sufficiently high. However, in reservoirs containing volatile

oil (very high GOR) other methods such as miscible gas injection may yield a higher

recovery. In heterogeneous water-wet reservoirs water injection is more efficient than

gas injection due to the spontaneous imbibitions of water, which does not occur with

gas injection4.

33

2.5 Economic Factors

The various economic factors to be considered being:

a) The cost of studies and laboratory work.

b) The cost of drilling additional wells.

c) The cost of converting producers into injectors.

d) The capital and operating costs of the surface equipment: pumps, lines, tanks,

filters etc.

2.6 Displacement Mechanics

2.6.1 Homogeneous Reservoirs

Here we shall assume that the reservoir consists of a single homogeneous bed in

which fluids move horizontally and the saturation remains constant. Now at start we

Fig 2.3 Frontal displacement of injected water4

34

will get natural depletion during the first phase of primary production and then water

injection to increase the pressure4.

By increasing pressure the free gas tends to re-dissolve into the oil. Initially there is a

"fill-up" period during which a volume of water approximately equal to the volume of

free gas initially present in the reservoir is injected. During the fill up period a large

proportion of the gas will be re-dissolved, the remainder being produced at the

production wells. The fill-up can be represented by an oil front travelling ahead of and

much faster than the water front, behind the oil front the gas saturation is at its

residual value; the arrival of the oil front at the production wells marks the end of the

fill-up period. (Fig 2.3) Behind the water front the oil saturation is reduced as more

and more oil particles are caught in the moving stream of water, until finally the

residual oil saturation is attained and it will increase the swept area after break-

through. The project will come to an end once the operating costs exceed the income

from the oil produced.

2.6.2 Heterogeneous Reservoirs

It is the property of the reservoir which is dependent upon the depositional

environment and on the nature of particles constituting the sediment5. These

reservoirs may be divided into three basic types:

a) Reservoirs with random heterogeneities, in which two or more types of

porosity are distributed randomly.

b) Layered reservoirs, in which there are several parallel beds whose extent is

usually great compared to their thickness, and which may or may not be in

communication.

c) Fissured reservoirs, in which one or more fracture systems divide the

formation into more or less regular blocks and provide highly conductive fluid

paths.

In these types of reservoirs water tends to invade the less permeable zones and

displace oil from them. As the rate of imbibitions is not dependent upon the rate of

water injection, it becomes more significant when it has more time to take place, thus

when the rate of displacement is slow.

35

Typical plots of oil recovery by water injection in heterogeneous reservoirs are

shown in Fig 2.4.

2.7 Water Injection Performance Calculations

Typical values of residual oil and connate water saturations indicate ultimate

displacement efficiency should normally be between 50% and 80% of the contacted

oil in a waterflood6. The results required are estimates of final oil recovery and the

oil and water production rates. The amount of oil recoverable by water injection

can be calculated by the equation:

( )

Where,

is the swept pore volume. This may be rather smaller than the pore volume which

contributed to the natural recovery phase. This is especially true for reservoirs with

lenticular zones. Other parameters are:

Initial oil saturation at the start of water injection,

Residual oil saturation at the end of water injection,

Areal sweep efficiency,

Oil Recovery

Very slow

displacement

Rapid displacement

Volume of water injected

(pore volume)

0.5 1

Fig 2.4 Injection rate affect on recovery4

36

Vertical sweep efficiency

In general, recovery by water injection is of the order of 30 to 50 % of the initial oil in

place for reservoirs consisting only of matrix porosity and containing under-saturated

oil4. Recovery can be much lower than this in fissured reservoirs. Prediction of oil

and water production rates may be made manually or by the use of analogical or

mathematical models.

2.8 The Fractional Flow Equation

In this part oil displacement will be assumed to take place under the so-called diffuse

flow condition. This means that fluid saturations at any point in the linear

displacement path are uniformly distributed with respect to thickness as it permits the

displacement to be described in one dimension and this provides the simplest model

of the displacement process.

The diffuse flow condition can be encountered under two extreme physical

conditions7:

a) when displacement takes place at very high injection rates so that the

condition of vertical equilibrium is not satisfied and the effects of the capillary

and gravity forces are negligible, and

b) For displacement at low injection rates in reservoirs for which the measured

capillary transition zone greatly exceeds the reservoir thickness (H >> h) and

the vertical equilibrium condition applies.

It can be visualized by considering the capillary pressure curve, (Fig. 2.5) Since, H

>> h then it will appear that the water saturation is uniformly distributed with respect

to thickness in the reservoir7.

37

Fig 2.5 Approximation to the diffuse flow condition7 for H>>h

It should also be noted that relative permeability is measured in the laboratory under

the diffused flow condition. Consider then, oil displacement in a tilted reservoir block,

which has a uniform cross sectional area A. Applying Darcy's law, for linear flow, the

one dimensional equations for the simultaneous flow of oil and water are

(

)

and

(

)

By expressing oil rate as

The subtraction of the above equation gives:

(

)

(

)

the capillary pressure gradient in the direction of flow, and

The fractional flow of water, at any point in the reservoir, is defined as

38

this equation can be expressed in field units as

(

)

both of these being fractional flow equations for the displacement of oil by water, in

one dimension.

2.9 Optimum Time for Waterflooding

The procedure to determine optimum time, for waterflooding includes the

calculation of:

• Anticipated oil recovery

• Fluid production rates

• Monetary investment

• Availability and quality of water supply

• Costs of water treatment and pumping equipment

• Costs of maintenance and operation of the water installation facilities

• Costs of drilling new injection wells or converting existing production wells

into injectors

Anticipated oil recovery can be calculated with the frontal flow equation and also the

fluid production rate with other tests. Investment pays an important part here, as the

costs of different equipment which is needed for pumping and treatment are

necessary. Also a lot of amount is needed on the maintenance and operation. In some

cases we have to drill new injection wells, otherwise we convert the same old

production wells into the injectors, which is more suitable economically. For

waterflooding process availability of water and the kind or quality of water is also

very important and it also defines the optimum time to waterflood.

These calculations should be performed for several assumed times and the net income

for each case is determined8.

2.10 Selection of Flooding Patterns

The very first step in designing a waterflooding project is flood pattern selection.

The selection of a suitable flooding pattern for the reservoir depends on the number

39

and location of existing wells. In some cases, producing wells can be converted to

injection wells while in other cases it may be necessary or desirable to drill new

injection wells.

Essentially four types of well arrangements are used in fluid injection projects8:

1. Irregular injection patterns

2. Peripheral injection patterns

3. Regular injection patterns

4. Crestal and basal injection patterns

The main purpose is to select the proper pattern that will provide the injection fluid

with the maximum possible contact with the crude oil system. When making the

selection, the following factors must be considered:

• Reservoir heterogeneity

• Direction of formation fractures

• Availability of the injection fluid

• Desired and anticipated flood life

• Maximum oil recovery

• Well spacing, productivity, and injectivity

2.11 Limitations of Waterflooding

Primary production usually recovers some 30 to 35% of the oil in place3. Although

the effectiveness of water injection varies according to the formation characteristics, a

waterflood can recover anywhere from 5% to 50% of the oil that is remaining in the

reservoir, greatly enhancing the productivity and economics of the development. The

process becomes uneconomical when the water cut reaches to 90 ~ 98%. Some

waterflood may take up to two years of injection before production is increased.

Waterflooding can increase the volume of oil recovered from a reservoir; however it

is not always possible to use. Evaluation should include waterflooding in the options

that are analysed both technically and economically. Those evaluation factors are the

compatibility of the planned injected water with the reservoir rock, injection water

40

treatment to remove oxygen, bacteria and undesirable chemicals, naturally occurring

radioactive materials (NORMs) and various scale forming minerals.

2.12 Conclusion

This chapter has described the technical aspects of waterflooding, but only briefly

compared to the vast amount of SPE technical literature on this subject.

The

conclusions concerning waterflooding are:

• It is the most commonly used secondary-oil-recovery method. As water is

inexpensive and easily available in large volumes, so water is very effective at

increasing oil recovery.

• The effectiveness of the waterflooding process depends on the mobility ratio

between the oil and water, and the geology of the reservoir.

• Waterflooding takes several decades to complete. So we should have to take

continuous routine field production and pressure data for monitoring and

analysing waterflood performance.

• Waterfloods performance can be improved by modification of operations by

the technical team. Such modifications include changing the allocation of

injection water among the injection wells and the waterflooded intervals,

drilling additional wells at infill locations, and modifying the pattern style.

• Waterflooding has been used successfully in oil fields of all sizes and all over

the world, in offshore and onshore oil fields.

2.13 Reservoir A-1 (Case Study)

On reservoir A-1 water is set to inject at constant rate of 20,000 STB/D and

production well was controlled by liquid rate at 20,000 STB/D. Maximum oil

production rate was given 18,700 STB/D. Production BHP economic limit was set to

1000 psia. Table 2.1, 2.2 and 2.3 shows the water, gas and oil relative permeability

behaviour respectively, calculated from Corey’s 2 phase11, 12

and Stone’s 3 Phase

Model II 11

. Injected water PVT properties are same as that of formation water.

41

Table 2.1 Water Saturation Functions

Sw krw

0.15 0

0.2 6.25E-6

0.25 0.0001

0.3 0.00050625

0.35 0.0016

0.4 0.00390625

0.45 0.0081

0.5 0.01500625

0.55 0.0256

0.6 0.04100625

0.65 0.0625

0.7 0.09150625

0.75 0.1296

0.8 0.17850625

0.85 0.2401

0.9 0.31640625

0.95 0.4096

1 0.52200625

Table 2.2 Gas Saturation Functions

Sg krg

0 0

0.05 0

0.1 0

0.15 0

0.2 0.00024375

0.25 0.0019

0.3 0.00624375

0.35 0.0144

0.4 0.02734375

0.45 0.0459

0.5 0.07074375

0.55 0.1024

0.6 0.14124375

0.65 0.1875

0.7 0.24124375

0.77 0.32889264

0.82 0.40001479

0.85 0.4459

42

Table 2.3 Oil Saturation function (3 phase)

So krow krowg

0 0 0

0.05 1.1973E-5 0

0.1 0.000191569 0

0.15 0.000969816 0

0.2 0.003065097 0

0.25 0.007483148 0

0.3 0.015517056 0.0593232

0.35 0.028747261 0.13158438

0.4 0.049041558 0.21082154

0.45 0.078555094 0.29960625

0.5 0.11973037 0.4009564

0.55 0.17529723 0.51818507

0.6 0.24827289 0.65476406

0.65 0.3419619 0.81420985

0.7 0.45995618 1

0.75 0.60613498 1

0.8 0.78466494 1

0.85 1 1

Simulation was run with the above described strategy and the results in the form of

3D are shown in Fig. 2.6 through 2.15. From Report Generator Module following

information was extracted after the 10 years of injection.

Average Reservoir Pressure = 4011.00 PSIA

Oil Currently in Place = 88.05 MMSTB

Oil Recovered = 49.37 MMSTB

Ration of oil Recovered to OIIP = 35.924 %

Gas Dissolved Currently = 64.99 MMMSCF

Free Gas currently in place = 8.71 MMMSCF

Cumulative Water Injected = 63 MMSTB

Water in place after Injection = 97.42 MMSTB

43

Fig 2.6 Fig 2.7

Fig 2.8 Fig 2.9

Fig 2.10 Fig 2.11

Fig 2.12 Fig 2.13

Fig 2.14 Fig 2.15

44

References

1. http://en.wikipedia.org/wiki/Waterflooding, (Extracted on 05/08/2010)

2. G. Paul Willhite: ―Waterflooding”, SPE Textbook Volume 3, Society of

Petroleum Engineers, Richardson TX, 1986.

3. http://www.rigzone.com/training/insight.asp?i_id=341M., (Extracted on

07/08/2010)

4. Latil, C. Bardon, J. Burger, P.Sourieau: ―Enhanced Oil Recovery‖, Petroleum

Institute of France, 1980.

5. Russel Jhons: ―Fundamentals of Enhanced Oil Recovery”,

6. Forrest F. Craig, Jr.: ―The Reservoir Engineering aspects of Waterflooding”,

SPE, New York, 1971.

7. L.P. Dake: ―Fundamentals of Reservoir Engineering‖, Elsevier, Amsterdam,

Netherlands, 1998.

8. Tarek Ahmad: ―Reservoir Engineering Handbook, 2nd

edition‖, (2001) Gulf

Publishing Company, Houstan, Texas.

9. Edward D. Holstein: “Reservoir engineering and petrophysics, Petroleum

Engineering Handbook Vol: 5” SPE series Richardson TX, 2007.

10. www.waterdropcycle.com/companies.html, (Extracted on 06/08/2010)

11. Jamal H. Abou Kassem, “Basic Applied Reservoir Simulation”. SPE (1999)

Richardson TX. USA. 25-27

12. T. Ahmed, ―Reservoir Engineering Handbook, 4th

Edition‖, (2010) Gulf

Publishing Company, Houstan, TX. USA. 300

45

Immiscible Gas Injection in Oil Reservoirs

3.1 Introduction

This chapter concerns gas injection into oil reservoirs to increase oil recovery by

immiscible displacement. A variety of gases can and have been used for immiscible

gas displacement, with lean hydrocarbon gas used for most applications to date

(Section 3.1.5). Historically, immiscible gas injection was first designed for reservoir

pressure maintenance. The first such projects were initiated in the 1930’s and used

lean hydrocarbon gas. Over the decades, a considerable number of immiscible gas

injection projects have been undertaken, some with excellent results and others with

poor performance1. Reasons for this range of performance are discussed in this

chapter.

3.1.1 Sources of Injection Gas

Gas injection projects are undertaken when and where there is a readily available

supply of gas. This gas supply typically comes from following sources

Produced solution gas or gas-cap gas

Gas produced from a deeper gas-filled reservoir

Gas from a relatively close gas field.

3.1.2 Why we need gas injection?

What are the cases which preferably validate the application of gas injection projects?

Such projects take a variety of forms, including the following:

To re-inject the produced gas into existing gas caps overlying producing oil

columns causing partial or complete pressure maintenance of reservoir

pressure.

3

3

46

Injection into oil reservoirs of separated produced gas for pressure

maintenance, for gas storage, or as required by government regulations.

To prevent migration of oil into a gas cap because of a natural water drive,

down dip water injection, or both.

To increase recoveries from reservoirs containing volatile, high-shrinkage oils.

Injection gas prevents their shrinkage and increase in viscosity and thus

recovery will be increased.

Injection into gas-cap reservoirs containing retrograde gas condensate causing

re-vaporization of lighter hydrocarbon components.

Gas injection into very under saturated oil reservoirs for the purpose of

swelling the oil and hence increasing oil recovery.

To provide gravity drainage in high dip reservoirs where vertical/gravity

aspects increase the efficiency of the process and enhance recovery of up dip

oil residing above the uppermost oil-zone perforations.

3.1.3 Candidate reservoir selection

The decision to apply immiscible gas injection is based on a combination of technical

and economic factors1. Deferral of gas sales is a significant economic deterrent for

many potential gas injection projects if an outlet for immediate gas sales is available.

Nevertheless, a variety of opportunities still exist;

First are those reservoirs with characteristics and conditions particularly

conducive to gas/oil gravity drainage and where attendant high oil recoveries

are possible.

Second are those reservoirs where decreased depletion time resulting from

lower reservoir oil viscosity and gas saturation in the vicinity of producing

wells is more attractive economically than alternative recovery methods that

have higher ultimate recovery potential but at higher costs.

Third are reservoirs where recovery considerations are augmented by gas

storage considerations and hence gas sales may be delayed for several years.

3.1.5 Injection gases

Non-hydrocarbon gases such as CO2, H2S and nitrogen can and have been used. In

general, calculation techniques developed for hydrocarbon-gas injection and

47

displacement can be used for the design and application of non-hydrocarbon,

immiscible gas projects. Valuing the use of such gases must include any additional

costs related to these gases, such as corrosion control, separating the non-hydrocarbon

components to meet gas marketing specifications, and using the produced gas as fuel

in field operations1. H2S has credit for higher sweep efficiency even than that of CO2

but elevated environmental risks associated with it hamper its fame as an injecting

gas.

3.2 Factors affecting performance of gas injection

Lawrence et. al 2 stated the factors that impact performance of gas injection

projects are reservoir pressure, fluid composition, reservoir characteristics, and

relative permeability.

3.2.1 Reservoir Pressure

Pressure is a major factor in determining whether or not the injected gas will be

miscible with the in-situ oil that will be contacted in the reservoir. Oil recoveries for

gas injection processes are usually greatest when the process is operated under

conditions where the gas can become miscible with the in-place oil. Gas injection can

also be used to immiscibly displace oil and for reservoir pressure maintenance. Also,

because gas injection will require compression, the pressures of both the source gas

and the receiving reservoir are important for facilities cost and design reasons.

3.2.2 Fluid Composition

Lighter oils are generally more amenable to displacement by gas injection because

they develop miscibility with injected gas more readily than heavier oils. In addition,

the mobility ratio is generally more favourable for lighter oils due to lower viscosity

and there is less potential for precipitation of heavier ends and asphaltenes after

contact of the oil with injected gas

3.2.3 Reservoir Characteristics

The sweep efficiency of gas injection is usually poorer than that of water injection

because gas has a greater tendency to finger through the more viscous in-place fluids,

channel through high-permeability streaks, and break through prematurely to

48

producing wells. In general, to accurately represent gas fingering and channelling

behaviour, the distribution and connectivity of permeability must be represented in

the simulation model on a finer scale than in waterflood simulation.

Gravity override may occur in horizontal floods because the gas is usually less dense

than the oil it is displacing. When vertical communication is high, gas "floats" to the

top of the reservoir and sweeps only the top part of that zone. In situations where

gravity override may be expected, it is important that the simulation model include a

sufficient number of layers to accurately represent the vertical segregation process.

Stone's analytical model can be used to guide layering of the simulation model when

gravity override is expected.

Reservoir characteristics that can favour gas injection include:

high dip angles (gravity stable displacement)

lower degree of permeability heterogeneity

the presence of vertical permeability barriers or baffles to slow the rate of

vertical segregation of injected gas

fining upwards deposits (low permeability overlying higher permeability)

3.2.4 Relative Permeability

The occurrence and severity of both viscous fingering and gravity override depend, at

least in part, on the mobilities of the displacing and in-place fluids, which in turn

depend on the relative permeability. Saturation history can have a significant impact

on relative permeabilities, especially in WAG processes.

3.3 Geological Considerations

As with any oil recovery process involving the injection of one fluid to displace oil in

the reservoir, the internal geometries of the reservoir interval have a controlling effect

on how efficiently the injected fluid displaces the oil from the whole of the reservoir.

For the immiscible gas/oil displacement process, the key factors are stratigraphy and

structure. However some factors are discussed in the proceeding paragraphs.

Thick reservoirs (> 600 ft of oil column) are the best for application of the immiscible

gas/oil drainage process with gas injection at the crest of the structure and oil

production from as far down dip as possible. Dip angle is important to the efficiency

49

of the displacement process because a higher dip angle generally means that the

effective vertical permeability is increased.

The relative size of the oil column compared with the gas cap affects the performance

of a particular reservoir. The gas/oil gravity drainage process has been applied to

reservoirs that have, relative to the size of the oil column, very small gas caps and to

some with very large gas caps. Success has been achieved over the full range of ratios

of gas cap to oil column size. The advantage of having a large initial gas cap is that

the reservoir pressure drops very slowly as the oil is produced compared with a

situation with a relatively small gas cap in which the reservoir pressure falls quite

rapidly until the secondary gas cap grows sufficiently.

Within the reservoir sandstone layers, the nature of the sand layering can strongly

affect the efficiency of the gas/oil displacement. In those depositional environments in

which the highest-permeability sands are on the bottom of the reservoir interval, the

gas/oil displacement process will be far more efficient, especially compared with the

situation in which the depositional environment results in the highest permeability

toward the top of the reservoir interval. The reason is that, in the first situation, the

gravity override of the gas is slowed by the vertical distribution of permeability, but in

the latter situation, the gas gravity override is enhanced.

Even if the reservoir were totally homogeneous, a horizontal gas/oil displacement

process would not be very efficient because the gas will strongly override the oil and,

because of its high mobility, will rapidly travel from the injection wells to the

production wells. For reservoirs with much ―random‖ heterogeneity, the gas/oil

displacement process will be aided because heterogeneities inhibit growth of low-

viscosity fingers by forcing them to travel a more circuitous path between the injector

and producer1.

3.4 General Immiscible Gas/Oil Displacement Techniques

In this section, the general technical features of the various immiscible gas injection

projects are discussed.

50

3.4.1 Types of Gas-Injection Operations

Immiscible gas injection is usually classified as either crestal or pattern, depending on

the location of the gas injection wells1. The same physical principles of oil

displacement apply to either type of operation; however, the overall objectives, type

of field selected, and analytical procedures for predicting reservoir performance vary

considerably by gas injection method.

Crestal Gas Injection: Crestal gas injection, sometimes called external or gas-cap

injection, uses injection wells in higher structural positions, usually in the primary or

secondary gas cap. This manner of injection is generally used in reservoirs with

significant structural relief or thick oil columns with good vertical permeability.

Injection wells are positioned to provide good areal distribution and to obtain

maximum benefit of gravity drainage. The number of injection wells required for a

specific reservoir depends on the injectivity of individual wells and the distribution

needed to maximize the volume of the oil column contacted.

Crestal injection, when applicable, is superior to pattern injection because of the

benefits of gravity drainage. In addition, crestal injection, if conducted at gravity-

stable rates e.g., less than the critical rate will result in greater volumetric sweep

efficiency than pattern injection operations.

Pattern Gas Injection: Pattern gas injection, sometimes called dispersed or internal

gas injection, consists of a geometric arrangement of injection wells for the purpose of

uniformly distributing the injected gas throughout the oil-productive portions of the

reservoir. In practice, injection-well/production-well arrays often vary from the

conventional regular pattern configurations e.g., five-spot, seven-spot, nine-spot to

irregular injection-well spacing. The selection of an injection arrangement is a

function of reservoir structure, sand continuity, permeability and porosity levels and

variations, and the number and relative locations of existing wells.

This method of injection has been applied to reservoirs having low structural relief,

relatively homogeneous reservoirs with low permeabilities, and reservoirs with low

vertical permeability. Many early immiscible gas-injection projects were of this type.

The greater injection-well density results in pattern gas injection, rapid pressure and

production response, and shortened reservoir depletion times2.

51

There are several limitations to pattern-type gas injection. Little or no improvement in

recovery is derived from structural position or gravity drainage because both injection

and production wells are located in all areas of the reservoir. Low areal sweep

efficiency results from gas override in thin stringers and by viscous fingering of gas

caused by high flow velocities and adverse mobility ratios. High injection-well

density increases installation and operating costs. Typical results of applying pattern

injection in low-dip reservoirs are rapid gas break-through, high producing GORs,

significant gas compression costs to re-inject the gas into the reservoir, and an

improved recovery of < 10% of original oil in place (OOIP). Note that gas

inefficiently displaces oil in gas-swept areas. Attempts to subsequently waterflood

such areas result in rapid water breakthrough and little, if any, additional oil

displacement.

3.4.2 Optimum Time to Initiate Gas Injection Operations

The optimum time to begin gas injection is site specific and depends on a balance of

risks, gas market availability, environmental considerations, and other factors that

affect project economics. When only oil recovery and improvements in reservoir

producing characteristics are considered, reservoir conditions for gas injection

operations are usually more favourable when the reservoir is at or slightly below the

oil bubble point pressure, unless the bubble point pressure is low compared with the

initial reservoir pressure. Near the oil bubble point pressure, non-recovered oil

represents the smallest volume of stock-tank oil, oil relative permeability is high, and

oil viscosity is low.

3.4.3 Efficiencies of Oil Recovery by Immiscible Gas Displacement

It is customary in most displacement processes to relate recovery efficiency to

displacement efficiency and volumetric sweep efficiency. The product of these factors

provides an estimate of recoverable oil expressed as a percentage of OOIP. Analytical

procedures are available for evaluating each efficiency factor. For the purposes of this

chapter, the two components describing the overall recovery efficiency are defined as

follows:

Displacement efficiency is the percentage of oil in place within a totally swept

reservoir rock volume that is recovered as a result of viscous displacement and

52

gravity drainage process4.

Volumetric sweep efficiency is the percentage of the total rock or PV that is swept

by gas. This factor is sometimes divided into horizontal and vertical components, with

the product of the two components representing the volumetric sweep4.

Recovery efficiencies increase with continued gas injection, but the rate of recovery

diminishes after gas breakthrough occurs as the GOR increases. The overall result is

that the ultimate oil recovery efficiency is a function of economic considerations, such

as the cost of gas compression and the volume and availability of lean residue gas or

potentially more expensive alternatives like N2 from a nitrogen rejection plant5.

3.5 Vertical or Gravity Drainage Gas Displacement

In this section, the primary manner in which the immiscible gas/oil displacement

process has been used is discussed in qualitative terms. This is the use of gas injection

high on structure to displace oil down dip toward the production wells that are

completed low in the oil column. In many cases, an original gas cap was present, so

the gas was injected into that gas-cap interval (see Fig. 3.1 for cross-sectional view of

anticlinal reservoir with gas cap over oil column with dip angle α and thickness h). In

this situation, the force of gravity is at work, trying to stabilize the downward gas/oil

displacement process by keeping the gas on top of the oil and counteracting the

unstable gas/oil viscous displacement process. If the oil production rate is kept below

the critical rate, then the gas/oil contact (GOC) will move downward at a uniform

rate.

Fig. 3.1 Schematic cross-sectional view of anticlinal reservoir of thickness h and

dip angle α with gas cap overlying oil column6.

53

There are likely to be local variations in the GOC caused by reservoir heterogeneities

and near-wellbore pressure gradients. The most notable of these results is gas coning

caused by high pressure gradients around the perforated interval of each wellbore.

Here, the controlling factors are the oil and gas production rates, the distance from the

top of the perforations to the overlying GOC, and the horizontal and vertical

permeabilities6. In this situation, the presence of a small shale interval between the

GOC and the top of the perforated interval can have a very beneficial effect on the

maximum oil production rate before gas coning occurs. For a particular reservoir

situation, gas-coning calculations are best made with a numerical reservoir simulation

model6.

3.6 Immiscible Gas Displacement and Reservoir Simulation

Techniques described in this chapter are classic methods for describing immiscible

displacement assuming equilibrium between injected gas and displaced oil phases

while accounting for differing physical characteristics of the fluids, the effects of

reservoir heterogeneities, and injection/production well configurations. The reservoir

is treated in terms of average properties for volume of rock, and production

performance is described on the basis of an average well. Black oil type reservoir

simulation models use essentially these same techniques but, by means of 1D, 2D, or

3D cell arrays, account for areal and vertical variations in rock and fluid properties,

well-to-well gravity effects, and individual well characteristics. More complex

compositional models account for non-equilibrium conditions between injected and

displaced fluids and can be used to describe individual well streams in terms of the

compositions of the produced fluids.

The increasing capability of desktop computers and the growing amount of affordable

simulation software are making it possible to use numerical reservoir simulation more

often. However, results obtained from simulation will be directly dependent on the

quality of data to describe the reservoir rocks and fluids. It is also important to

comprehend the physics of displacement to understand the simulation results and to

identify incorrect results. The fundamentals of the displacement process presented in

54

this section are intended to provide the background needed to produce good-quality

predictions of oil recoveries.

3.6.1 Calculating Immiscible Gas Injection Performance

Numerical simulation represents the best way to predict the performance of

immiscible gas injection if there are sufficient data to characterize the reservoir rocks

and fluids adequately. Even simple 2D and 3D black-oil models provide insight into

the more important aspects of oil recovery for reservoirs in which compositional

effects are not a major concern. When adequate data are unavailable or when

screening work is being done, simple models may suffice7, 8

.

3.7 Conclusion

In this chapter, the technical aspects of immiscible gas/oil displacement have been

described. The conclusions concerning immiscible gas/ oil displacement are listed

below:

1. Immiscible gas/oil viscous displacement is an inefficient oil displacement

process because gas is a highly mobile fluid.

2. The immiscible gas/oil process becomes efficient and desirable when gravity

works to keep the very-low-density gas on top of the higher-density oil and/or

there is significant mass transfer of components from the oil to the gas.

3. The most successful immiscible gas/oil injection projects are the vertical

gravity drainage projects in which gas is injected into the crestal primary or

secondary gas cap, with the oil wells producing from as far down dip as

possible to maximize this distance from the gas cap both vertically and

laterally. To maximize the efficiency of this approach, the overall oil pro-

duction rate has to be restricted to the critical displacement rate.

4. One gas/oil compositional mass-transfer effect is oil swelling. If an oil field

contains a very under saturated oil, then oil swelling by contact with the

injected gas can be a very significant effect. However, if a reservoir has an

original gas cap, the oil swelling effect is minimal because the oil is already

fully saturated or nearly saturated with gas.

5. A few immiscible gas injection field projects have been undertaken that are

55

not vertical gas/oil gravity drainage projects but in which compositional

effects have led to project success.

6. Gas coning into producing wellbore perforated intervals occurs with thin oil

columns or as the gas/oil interface moves downward. Horizontal wells are a

method of further reducing the height of the remaining oil column by lowering

pressure drawdown and thus minimizing the effects of gas coning1.

7. Numerical reservoir simulators are the best tool to evaluate all the technical

aspects of an immiscible gas injection project, either historical performance

and/or projections of future performance. Simple mathematical techniques

have been developed to analyze some types of immiscible gas/oil

displacements. Reservoir simulation of gas injection processes can be

performed to address a wide variety of issues. In any simulation study a

systematic approach should be followed to acquire the appropriate field and

laboratory data. This is particularly important for gas injection processes

where the fluid and rock interactions can be complex. A fundamentally sound

understanding of the geology is also essential to identify impacts of

heterogeneity, lithology, and structure. Reservoir simulation models can then

be used to integrate all the rock, fluid, geologic, and production information.

Because of the breadth of issues and process mechanisms that may be

important when simulating gas injection, each case must be evaluated

individually to ensure models are fit-for-purpose. Cases covering immiscible

inert gas injection provide insight into how different approaches can be

applied to properly address a range of issues. Simulation models can be used to

optimize projects and avoid the expense of potentially costly project re-design2.

3.8 Immiscible Gas-flood Monitoring

In our case and usually the most obvious monitoring method is to track the GORs of

the production well as a function of time. The GOR will be approximately flat at the

oil’s solution GOR until there is gas breakthrough. Then the GOR will climb. The

timing of gas breakthrough and the rate of GOR climb will indicate how efficiently,

or in-efficiently, the gas/oil displacement is progressing. Field engineers should have

made preliminary calculations, possibly using a numerical reservoir simulator, so that

they have projections of what should be expected regarding gas breakthrough timing

56

and GOR increases at the individual well locations (and as a function of the volume of

gas injected at the individual injection wells).

3.9 Reservoir A-1 (Case Study)

Dry HC gas of sp. gravity 0.75 is set to inject at the constant rate of 12,500 MSCFD.

a) Oil Production rate is constant at 1875 STBD b) ―PROD‖ well minimum BHP is

set at 2000 psi with maximum oil production at 12,000 STB/D. Relative movement of

water, gas and oil in the reservoir is governed by saturation Table 3.1, 3.2 and 3.3

respectively, generated from Corey’s 2 phase and Stone’s 3 phase Model 2. Fig. 3.2

through 3.11 shows the behaviour of fluids flow in the reservoir during corresponding

time steps.

Graphical results will be presented in chapter 5.

From Report Generator Module following information was obtained after the 10 years

of injection.

Case (a)

Average Reservoir Pressure = 6324.46 PSIA

Oil Currently in Place = 130.57 MMSTB

Oil Recovered = 6.844 MMSTB

Ratio of oil displaced to OIIP = 4.981 %

Gas Dissolved Currently = 110.51 MMMSCF

Cumulative Gas Injected = 45.63 MMMSCF

Cumulative gas produced = 11.37 MMMSCF

Free Gas Present currently in place = 29.55 MMMSCF

Water in Place (immobile/connate water) = 34.25 MMSTB

Case (b)

Average Reservoir Pressure = 2875.40 PSIA

Oil Currently in Place = 120.53 MMSTB

Oil Recovered = 16.88 MMSTB

Ratio of oil displaced to OIIP = 12.282 %

Gas Dissolved Currently = 63.36 MMMSCF

Cumulative Gas Injected = 17.30 MMMSCF

57

Cumulative gas produced = 62.92 MMMSCF

Free Gas Present currently in place = 34.25 MMMSCF

Water in Place (immobile/connate water) = 34.25 MMSTB

Cumulative water produced = 17.48 STB

Table 3.1 Water saturation functions

Sw krw

0.15 0

0.2 6.25E-6

0.25 0.0001

0.3 0.00050625

0.35 0.0016

0.4 0.00390625

0.45 0.0081

0.5 0.01500625

0.55 0.0256

0.6 0.04100625

0.65 0.0625

0.7 0.09150625

0.75 0.1296

0.8 0.17850625

0.85 0.2401

0.9 0.31640625

0.95 0.4096

1 0.52200625

Table 3.2 Gas saturation functions

Sg krg

0 0

0.05 0.00039511

0.1 0.003065097

0.15 0.010021432

0.2 0.022988231

0.25 0.043402258

0.3 0.072412926

0.35 0.11088229

0.4 0.15938506

0.45 0.21820859

0.5 0.28735288

0.55 0.36653057

0.6 0.45516696

58

0.65 0.5524

0.7 0.65708026

0.75 0.76777098

0.8 0.88274805

0.85 1

Table 3.3 Oil saturation functions (3 phase)

So krow krowg = krog

0 4.65677E-63 1.13691E-66

0.05 1.1973E-5 1.1973E-5

0.1 0.000191569 0.000191569

0.15 0.000969816 0.000969816

0.2 0.003065097 0.003065097

0.25 0.007483148 0.007483148

0.3 0.015517056 0.015517056

0.35 0.028747261 0.028747261

0.4 0.049041558 0.049041558

0.45 0.078555094 0.078555094

0.5 0.11973037 0.11973037

0.55 0.17529723 0.17529723

0.6 0.24827289 0.24827289

0.65 0.3419619 0.3419619

0.7 0.45995618 0.45995618

0.75 0.60613498 0.60613498

0.8 0.78466494 0.78466494

0.85 1 1

Note the residual oil saturation in layer 2, 3, and 4. Lower production rate in case (b)

cause higher oil recovery in (b) than that of case (a).

59

Fig. 3.2 Fig. 3.3

Fig. 3.4 Fig. 3.5

Fig. 3.6 Fig. 3.7

Fig. 3.8 Fig. 3.9

Fig. 3.10 Fig. 3.11

60

References

1. Edward D. Holstein, ―Petroleum Engineering Handbook - Reservoir

Engineering and Petrophysics”, SPE (2006), Richardson TX.

2. J. J. Lawrence, SPE, G. F. Teletzke, SPE, J. M. Hutfilz, SPE /ExxonMobil

Upstream Research Company; ―Reservoir Simulation of Gas Injection

Processes”, SPE 81459 presented at SPE 13th Middle East Oil Show &

Conference, Bahrain 5-8 April 2003.

3. Lake, L.W.: ―Enhanced Oil Recovery”, first edition, Prentice-Hall Inc.,

Englewood Cliffs, NJ (1989).

4. Cotter, W.H.: ―Twenty-Three Years of Gas Injection into a Highly Under

saturated Crude Reservoir,‖ JPT (April 1962) 361.

5. Craft, B.C. and Hawkins, M.F.: Applied Petroleum Reservoir Engineering,

Prentice-Hall Inc., Englewood Cliffs, NJ (1959) 370.

6. Killough, J.E. and Foster, H.P. Jr.: ―Reservoir Simulation of the Empire Abo

Field: The Use of Pseudos in a Multilayered System,‖ SPEJ (October 1979)

279.

7. Dyes, A.G., Caudle, B.H., and Erickson, R.A.: ―Oil Production after

Breakthrough—As Influenced by Mobility Ratio,‖ Trans., AIME (1954) 201,

81.

8. Jessen, K., et al.: ―Fast, Approximate Solutions for 1D Multi-component Gas

Injection Problems,‖paper SPE 56608 presented at the SPE Annual Technical

Conference and Exhibition, Houston, 3–6 October, 1999.

61

Miscible Gas Injection in Oil Reservoirs

4.1 Introduction

The life of an oil reservoir goes through three distinct phases where various

techniques are employed to maintain crude oil production at maximum levels. These

include Primary, Secondary and Enhanced recovery techniques, of which secondary

techniques have been explained in detail in previous chapters. Techniques employed

at the third phase, commonly known as Enhanced Oil Recovery (EOR), can

substantially improve extraction efficiency1.

EOR processes involve the injection of a fluid or fluids into a reservoir that interact

with the reservoir rock/oil system resulting in conditions favorable for oil recovery.

These interactions might result in low interfacial tension, oil swelling, oil viscosity

reduction, wettability modification, or favorable phase behavior2.

Primary recovery typically recovers only a small fraction of a reservoir’s total oil,

except for the cases where there is strong water drive or large gas cap to maintain

reservoir pressure. Secondary recovery techniques can increase productivity to a third

or more. Depending upon the type of reservoir and EOR process applied, EOR can

recover up to over half of a reservoir’s original oil content1.

Carcoana3 gave a detailed classification of recovery processes which included many

techniques as thermal recovery, miscible recovery, polymer injection etc., but the one

discussed here is miscible recovery.

Miscible process is one in which ―displacing fluid is miscible with the displaced fluid

at the conditions existing at the displacing-fluid/displaced-fluid interface and

Interfacial tension IFT is eliminated”2. Miscible injection is a proven, economically

viable process that significantly increases oil recovery from many different types of

4

3

62

reservoirs. In miscible displacement relative permeabilities lose their significance

since there is no interface between the fluids4.

4.2 Types of Miscible processes

Miscibility is controlled by the four major factors; pressure, temperature, composition

of the oil, and composition of the displacing fluid5.

To understand the miscibility

process of complex hydrocarbon mixtures, pseudo ternary phase diagram is used often

as an aid. Two main types of miscible processes are explained below.

1. First Contact Miscibility(FCM) Process

In this process a slug of specified volume of a solvent (primary slug) that is directly

miscible with the crude oil is injected into oil reservoir2. Due to miscibility, a

transition-zone fluid is formed at the interface between primary slug and oil. This

fluid is miscible with slug solvent at the rear end of transition zone and with reservoir

oil at the front of this zone. Because primary slug is expensive, therefore a secondary

slug is injected for economic reasons and it is miscible with primary slug. Volume of

primary slug decreases with time due to mixing or dispersion-between primary slug,

reservoir oil, and secondary slug. Therefore volume of primary slug should be enough

so that miscibility rupture does not occur. Primary slug may be LPG or alcohol while

secondary slug may be lean gas or water6.

Fig 4.1 FCM displacement2

2. Multiple Contact Miscibility(MCM) Process

An MCM displacement process is one in which the condition of miscibility is

generated in the reservoir through in-situ composition changes resulting from multiple

contacts and mass transfer between reservoir oil and injected fluid. The MCM

processes are classified as2:

63

Vaporizing-gas (lean gas) displacements

Condensing and condensing/vaporizing-gas (enriched gas) displacements

CO2 displacements

Vaporizing-gas (lean gas) displacements

In the Vaporizing-gas process, the injected fluid is generally a lean gas containing

hydrocarbons or inert gases. The process is named so because injected dry gas is

enriched by vaporizing intermediate and heavy components from the oil. At the start

of injection, the displacement is immiscible and line CA (Fig 4.2) crosses the two-

phase region, because oil and gas are not in thermodynamic equilibrium. Phase

exchange takes place and as a result, intermediate and heavy components in oil are

vaporized into injected gas. This process continues until the tangent from oil C to the

dew point curve passes through modified gas composition. From this point miscibility

is achieved and phenomenon of miscible drive occurs.

Fig 4.2 Vaporizing Gas Displacement process2

The pressure of gas injection is typically 3000-4500 psi and this is why the process is

also called ―high pressure gas injection‖. The API of the oil is normally ≥ 35˚, which

shows oil is rich in intermediates7.

64

Condensing and condensing/vaporizing-gas (enriched gas) displacements:

In the condensing process, the injected fluid contains significant amounts of

intermediate components (C2 through C6). The process involves the condensation of

these components into the reservoir oil. The process can be represented on ternary

diagram; the fluid to be injected is represented by point A and reservoir oil by point C

(Fig 4.3). Initially there is no miscibility, but due to gradual exchange of components,

oil composition is modified to such a point at which it becomes miscible with the

injected gas.

It has been recognized that this process is often a combination of condensing and

vaporizing mechanisms8. The light intermediate components in the injected gas (C2

through C4) condense into the reservoir oil while middle intermediate components

(C4+) are vaporized from the oil into the gas phase. Gas injection pressure in this

process is normally 2000-3000 psi7. The alternative to increasing pressure is that the

injection gas composition can be enriched to achieve miscibility. At a fixed pressure,

the minimum enrichment at which the limiting tie-line passes through the injection

gas composition is called minimum miscibility enrichment (MME)2.

Fig 4.3 Condensing gas drive process2

CO2 miscible displacement

CO2 miscible displacement process is ideally same as high pressure vaporizing gas

process. Pseudo ternary diagram for CO2 is similar to that of CH4 gas but the two-

65

phase envelop for CO2 is much smaller. Thus miscibility can be generated at low

pressures for CO2 and reservoir oil.

Fig 4.4 A comparison of phase behaviour for CO2 and CH42

4.3 Forces Responsible for Oil Trapping

Several forces that influence microscopic displacement behaviour are discussed

below:

4.3.1 Capillary forces

Surface tension and IFT

Solid wettability

Capillary pressure

4.3.2 Viscous forces

4.3.1 Capillary forces

Surface tension and IFT

An interface is always present whenever immiscible phases are there in a porous

medium which influences saturations, distributions, and displacement of phases.

Water present in oil reservoir influences oil flow performance. Surface tension in a

liquid is the result of cohesive forces within the liquid molecules. The molecules near

the surface are pulled towards the bulk of liquid and liquid surface acts like a

66

stretched membrane. Surface tension, σ, is “the force acting in the plane of the surface

per unit length of the surface”2.

The term surface tension is used when surface is between a liquid and its vapour or

air. If surface is between two different liquids, or between a liquid and a solid, the

term ―interfacial tension‖ is used. Surface tension of water in contact with its vapour

at room temperature is about 73dynes/cm. IFT’s between water and pure

hydrocarbons are about 30 to 50 dynes/cm at room temperature.

IFT’s and surface tension are relatively strong functions of temperature. One way of

measuring surface tension is to use capillary tube. Other methods include ring

tensiometer, spinning-drop and pendant-drop methods.

Solid Wettability

Wettability is the tendency of one fluid to spread on or adhere to a solid surface in the

presence of a second fluid2. When two immiscible phases are placed in contact with a

solid surface, the phase that is attracted to the solid more strongly than the other is

called wetting phase.

Rock wettability affects the nature of fluid saturations and relative permeability

characteristics of a fluid/rock system. Also it affects the location of a phase within the

pore structure. If rock is oil-wet oil entrapment will be more and as a consequence

residual oil saturation will be more. Rocks also have intermediate or mixed

wettability, depending upon physical/chemical makeup of the rock and composition

of oil phase2. Intermediate wettability occurs when both fluid phases wet the solid

surface, but one phase is only slightly more attracted than the other. Mixed wettability

results from variation in chemical composition of exposed rock surfaces or cementing

materials in the pores. Due to this reason, the wettability condition varies from point

to point in which water wets part of the surface and oil wets the remaining part.

Contact angle θ is used as a measure of wettability. Solid is water-wet if θ<90˚ and

oil-wet if θ>90˚. A contact angle approaching 0˚ indicates strongly water-wet system

and an angle approaching 180˚ indicates strongly oil-wet rock. A contact angle of 90˚

indicates intermediate wettability. By convention contact angles are measured

through water phase9.

67

A prime effect of wettability is asymmetry of relative permeability curves. At a given

saturation of a fluid, the relative permeability to that fluid will be large if it is a non-

wetting rather wetting fluid because of location of wetting and non-wetting phases in

the pore structures. Non-wetting phase tends to be trapped as isolated drops held by

strong capillary pressures when it is displaced by a wetting phase. When a wetting

phase is trapped, it is held in small cracks and crevices interconnected by thin fluid

layers around the solid.

Capillary Pressure

Capillary pressure is related to fluid/fluid IFT, relative wettability of fluids and size of

capillary. Pc varies inversely as a function of capillary radius and increases as the

affinity of wetting phase for the rock surface increases2. Because interfaces are in

tension, a pressure difference exists across the interfaces, which is called capillary

pressure. Capillary pressure influences the initial distribution of fluids in a reservoir

and the residual saturations of water and hydrocarbons.

4.3.2 Viscous Forces

Viscous forces in a porous medium are reflected in the magnitude of the pressure drop

that occurs as a result of flow of a fluid through the medium. The oil trapping

mechanism depends on 1) Pore structure of the medium 2) Fluid/rock interactions

related to wettability 3) Fluid/fluid interactions reflected in IFT.

4.4 Factors Affecting Miscible Recovery

The two major factors that affect the performance of a miscible flood are oil-

displacement efficiency at the pore level and sweep efficiency on the field scale6.

4.4.1 Microscopic Displacement Efficiency

Several physical/chemical interactions occur between the displacing fluid and oil that

can lead to efficient microscopic displacement efficiency Ed (low Sor). These include

direct miscible displacement of oil by solvent along higher-permeability pore paths,

decreasing IFT2. Additionally, part of the oil initially bypassed (on the pore level) by

solvent can later be recovered through oil swelling that occurs as solvent dissolves in

the oil, or by extraction of oil into solvent. This swelling and extraction phenomenon

68

continues and is responsible for recovering as much as 20 to 30% of the total

incremental recovery. Oil-displacement efficiency is affected by solvent composition

and pressure6. The maintenance of favourable mobility ratio between displaced and

displacing fluid also contributes to better microscopic displacement efficiency.

4.4.2 Macroscopic Displacement Efficiency

Volumetric sweep is a macroscopic efficiency defined as the fraction of reservoir PV

invaded by the injected fluid2. The overall displacement efficiency in a process can be

viewed conceptually as a product of the volumetric sweep, Ev, and the microscopic

efficiency, Ed, as

Where E= overall hydrocarbon displacement efficiency, the volume of hydrocarbon

displaced divided by the volume of hydrocarbon in place at the start of the process

measured at the same conditions of temperature and pressure2.

Four factors control how much of a reservoir will be contacted by a displacement

process:

Fig 4.5: Factors affecting miscible recovery6

69

1. The properties of injected fluids

2. The properties of displaced fluids

3. The properties and geological characteristics of reservoir rock

4. The geometry of injection and production well pattern

Volumetric sweep efficiency can be considered as the product of areal and vertical

sweep efficiencies.

Where = Areal sweep efficiency, = Vertical sweep efficiency.

The right side of Fig.4.5 shows that, on a field scale, sweep efficiency is affected by

viscous fingering and solvent channeling through high-permeability streaks. Gravity

override can sometimes occur because solvent is usually less dense than the oil it is

displacing.

When vertical communication is high, solvent tends to gravity segregate to the top of

reservoir and sweep only the upper part of that zone. Sweep efficiency on the field

scale is usually the single most important factor affecting performance of a miscible

flood. Sweep efficiency can be increased to some extent by reducing well spacing,

increasing injection rate, re-configuring well patterns, increasing solvent-bank sizes,

and modifying the ratio of injected water to injected solvent (WAG ratio).

The miscible fluids generally have small viscosities and therefore fingering and poor

volumetric sweep result.

In a reservoir, lithology and petrophysical properties usually vary from one area to the

other, or the reservoirs frequently tend to be stratified. As the variation in the porosity

and permeability increase the sweep efficiency decreases. Scott and Read (1959)

found that miscible displacement sweep efficiency was related directly to pore

geometry, i.e., combined effects of tortuosity, pore shape, pore-size distribution and

width of inter-communicating channels5.

4.5 Designing a Miscible Flood

There are several steps involved in designing miscible flood:

70

4.5.1 Determining Miscibility

True miscible displacement implies that injected and displaced phases mix in all

proportions without forming interfaces or two phases and this can happen only when

gases are injected at or above MMP.

Minimum miscibility pressure is defined as “the minimum pressure at which the

injected solvent becomes miscible with reservoir oil after multiple contacts or the

minimum pressure at which the limiting tie line just passes through the reservoir oil

composition”2,7

.

Swelling and Slim-Tube tests are commonly conducted in addition to standard PVT

tests to determine conditions under which a candidate gas injected becomes miscible

with the oil. The tests are also used to determine phase volumes, densities, and

viscosities for solvent/crude oil mixtures as a function of pressure and solvent

content. The results of these tests are used to develop a set of equation of state (EOS)

parameters that characterize the solvent/crude system. The resulting EOS model is

then used to create phase behaviour and viscosity input for simulation. Correlations

(like Stalkup, Benham et al., Yelling and Metcalfe) are also available to find

miscibility pressure for a particular injected gas composition.

The Fig 4.7 shows the result of a laboratory slim tube experiment. Oil recovery

increases with pressure up to approximately 95 to 98% and then increases very little

thereafter. The pressure at which the break in the recovery curve occurs is said to be

the minimum miscibility pressure (MMP). If the displacements had been conducted at

Fig 4.6: Effect of pressure on phase behavior7

71

constant pressure and with increasing enrichment by components such as ethane,

propane, and butane, the break over would have been at the minimum miscibility

enrichment (MME). Above the MMP or MME, the displacement is said to be

―multiple-contact‖ or ―dynamically‖ miscible.

The increasing recovery with pressure or solvent enrichment results from in-situ mass

transfer of components between solvent and resident oil.

Fig 4.7: Effect of pressure and gas enrichment on oil recovery6

4.5.2 Choosing a Candidate Reservoir

A decision to implement a miscible flood in a particular field will usually consist of a

sequential approach. First is the screening stage. Data in the literature allow a

reasonable estimate of MMP or MME, Sorm (minimum residual oil saturation), amount

of solvent required and operating costs. This information is adequate to determine if a

reservoir is a candidate.

4.6 Economic Considerations for Implementing Miscible Gas

Injection Process

Several factors should be considered in assessing the economic viability of a miscible

project6:

72

What fluids are available for injection?

What is the MMP corresponding to fluid selected?

Whether or not MMP is less the formation fracture pressure.

Whether or not fluid enrichment option can be exercised. It depends on the

availability of enrichment fluid.

Do the incremental recoveries high enough to start the project? Numerical

simulation can provide help to evaluate the economics of a project. For most

projects, slug size can be refined further during the actual flood (usually

increased) when actual performance can be used to modify initial projections.

Will water- and solvent-injection rates change with time? Such decreases in

injectivity may significantly affect project economics.

Will separation of the solvent from produced fluids be necessary? Especially in

cases where CO2 or N2 is injected. After breakthrough separation is required to

remove contaminants before sale. The investment and operating cost of

separation facilities and compression for re-injecting the recovered miscible

materials should be included in the economic assessment of the project.

What is the amount of solvent to be purchased and what amount will be

recycled? Simulation can provide the rates of solvent after breakthrough to

answer this question.

Will injection be done by drilling new wells or by converting some producer/s to

injector/s?

4.7 Conclusion

Miscible injection has been applied successfully in many reservoirs6. The resulting

experience has made it possible to reliably predict the economic viability of new

projects in other reservoirs. This chapter contains some general guidelines that should

suffice in screening studies of the applicability of a miscible process to a given

reservoir or field. Finally, proper assessment of the application of a miscible project

should include the timing of capital outlays for project implementation, the timing of

solvent injection and production response, changes in injectivity, and the costs and

need to re-inject produced solvent.

73

4.8 Reservoir A-1 (Case Study)

In reservoir A-1, the miscible gas was set to inject at constant rate of 12,500 MSCFD.

Saturation tables, generated using Corey and Brooks’ correlation, are shown in Table

4.1 and 4.2.

Table 4.1 Gas saturation functions

Sg krg Pc (psia)

0 0 0

0.05 0.000420789 0.03

0.09 0.002397776 0.1

0.18 0.018163961 0.3

0.27 0.057839127 0.6

0.36 0.1288148 1

0.45 0.2352438 1.5

0.54 0.37791703 2.1

0.63 0.55407723 2.8

0.72 0.75708665 3.6

0.81 0.97554186 4.5

Table 4.2 Oil saturation functions

So kro

0.18 0

0.2 4.96E-7

0.3 0.000546192

0.4 0.005839558

0.45 0.013003455

0.5 0.025263631

0.55 0.044562626

0.6 0.073140296

0.65 0.11352989

0.7 0.16855465

0.75 0.24132488

0.8 0.33523529

0.85 0.4539626

Simulation was run with the above described strategy for miscible gas injection and

the results in the form of 3D are shown in Fig. 4.8 through 4.17. From Report

Generator Module following information was extracted after the 10 years of injection.

74

Fig 4.8 Fig 4.9

Fig 4.10 Fig 4.11

Fig 4.12 Fig 4.13

Fig 4.14 Fig 4.15

Fig 4.16 Fig 4.17

75

Average Reservoir Pressure = 2510.88 PSIA

Oil Currently in Place = 121.91 MMSTB

Oil Recovered = 15.49 MMSTB

Ratio of oil displaced to initial OIP = 11.28 %

Cumulative gas injected = 45.63 MMMSCF

Cumulative gas produced = 76.65 MMMSCF

Gas Dissolved Currently = 53.88 MMMSCF

Free Gas currently in place = 20.90 MMMSCF

References

1. Teledyne Isco, Inc., ―Enhanced Oil Recovery‖, Lincoln, Nebraska, USA,

November 27, 2007

2. Don W. Green, G. Paul Willhite, “Enhanced Oil Recovery” SPE, Richardson

TX, 1998.

3. Aurel Carcoana, ―Applied Enhanced Oil Recovery‖, Prentice-Hall, Inc.,

Englewood Cliffs, New Jersey, 1992.

4. H.C. ―Slip‖ Slider, ―Worldwide Practical Petroleum Reservoir Engineering

Methods‖, Penn Well Books, Tulsa, Oklahoma, 1983.

5. Erle C. Donaldson, ―Enhanced Oil Recovery, II- Processes and Operations‖,

Elsevier, Amsterdam, Netherlands, 1989.

6. Edward D. Holstein, “Reservoir engineering and petrophysics, Petroleum

Engineering Handbook Vol: 5” SPE series Richardson TX, 2007.

7. M. Latil, C. Bardon, J. Burger, P.Sourieau, ―Enhanced Oil Recovery‖,

Petroleum Institute of France, 1980.

8. Zick, A.A, ―A Combined Condensing/Vaporizing Mechanism in the

Displacement of Oil by Enriched Gases,‖ paper SPE 15493 presented at the

1986 SPE Annual Technical Conference and Exhibition, New Orleans.

9. G. Paul Willhite, ―Waterflooding, SPE Textbook Volume 3‖, SPE Richardson

TX, 1986.

76

Analysis and Screening

5.1 Individual Project Analysis

5.1.1 Waterflood Performance

Fig 5.1 Waterflood performance profile

Fig 5.1 shows the production history of reservoir A-1 under the influence of water

injection at a constant rate of 20,000 STB/D. Oil production rate initially set to 18,700

STB/D which starts decreasing smoothly after three months, due to the drop in

reservoir potential. Gas first started evolving at bottom hole of PROD, and this

transient of decreasing pressure moved away from the wellbore into the formation,

once critical gas saturation reached GOR increased rapidly and then its trend became

smooth due to pressure maintenance. Pressure behaviour is quite smooth as we have

5

77

seen in literature; the water injection cause reservoir pressure to be constant provided

the injection and production rate are optimized. It was good to see that there was no

breakthrough even after the 10 years of injection. If the breakthrough had occurred,

oil production would have started decreasing, but the system conditions are optimized

in such a way that an ideal trend is observed.

5.1.2 HC Gas (Immiscible) Flood Performance

Case (a): In this case oil production rate is set constant at 1,875 STB/D which keeps

GOR of field constant until the breakthrough occurs and the reservoir pressure starts

decreasing because the source of energy; gas, starts flowing out of the reservoir.

Fig 5.2 HC gas flood (a) performance profile

Case (b): Maximum oil rate is set at 12,000 STB/D and bottom hole pressure for

production well is limited to 2000 psi minimum, so that it can maintain the

production, but first, it is observed that oil production from 12,000 STB/D starts

decreasing after 50 days of production indicating the decreasing capacity of the

system to maintain this production rate. Secondly, gas break through takes place

earlier under the influence of voidage produced in the reservoir due to high

production rate.

78

Fig 5.3 HC gas flood (b) performance profile

Comparison of case (a) and case (b)

In case (b), by increasing the production rate approximately 6 times, reservoir

pressure decreases two times (see section 3.). Oil recovery increases by 2 times, the

cumulative gas injected decreased by 3 fold, and the GOR increased to 12,000

SCF/STB instead of 7,500 SCF/STB as in case (a). By observing both of these cases

we can say that case (b) is more economical and technically viable as compared to

case (a) because on the basis of delayed breakthrough and increased reservoir pressure

we can’t switch to increased gas requirement for injection and lower gas production

(for re-injection). This can lead to earlier demerits of case (a) as compared to case (b).

Note: Case (a) is slumped here and case (b) will be used for comparisons with other

techniques.

79

5.1.3 Miscible Gas Flood Performance

Fig 5.4 Miscible flood performance profile

Oil production rate initially set at 12,000 STB/D, is too high for the reservoir to

maintain, therefore it decreases rapidly along with GOR, then remains stable for

some time till and after breakthrough occurs and keeps on decreasing. But the

interesting thing to note is the reservoir pressure which decreases rapidly as compared

to HC gas and waterflood.

5.2 Comparative Project Analysis

5.2.1 Field Pressure

By observing the pressure behaviour as result of water and gas flooding, waterflood

appears to be the most suitable, as it maintains the reservoir pressure. On the other

hand pressure behaviour in case of HC and misc gas flooding decreases, and thus

gives less recovery. (Fig 5.5) shows pressure performance in blue line for waterflood,

red line for HC gas flood (b) and green line for miscible gas flood, same colour

convention will be used for proceeding comparisons.

80

Fig 5.5 Field Pressure Comparison

5.2.2 Oil Production Rate

Higher production rate means more recovery. Water injected at constant rate of

20,000 STB/D causes oil to produce at highest rates ranging from 18,700 STB/D to

11,800 STB/D. Observing other techniques; in HC gas flood oil is set to produce at

initial rate of 12,000 STB/D (previously discussed in Section 5.1.2) which along its

pressure trend indicates natural reservoir depletion, and miscible gas which is set to

produce maximum 12,000 STB/D of oil, rapidly declines to 6500 STB/D in early 200

days of project life and slowly declines to minimum rate of 1550 STB/D approx. in

remaining 3450 days. (Fig 5.6)

81

Fig 5.6 Oil production rates comparison

5.2.3 Gas-oil ratio

By observing gas-oil ratio trend of the three techniques, waterflooding proves to be

the most appropriate mechanism. Higher GOR’s in gas floods are due to the fact that

once gas breakthrough the well, GOR increases rapidly. Breakthrough could be

delayed if production rate is set at minimum and economically possible value. (Fig

5.7)

82

Fig 5.7 Gas-oil ratios comparison

5.2.4 Gas Production Rate

Our main concern is with the oil in developing production strategy for the reservoir

A-1. However gas produced can be used for many useful purposes but on the other

hand cost of gas handling facilities is also high and have certain environmental issues

associated. Fig 5.8 shows the gas production rate for the three techniques. Initial peak

in GPR for miscible flood is due to high initial oil production while at later stage GPR

starts decreasing till critical gas saturation reaches and it shoots-up. This behavior is

not so sharp in HC gas because of good pressure maintenance due to immiscibility.

However economic limit can be imposed on GOR but it causes lower oil production

too.

83

Fig 5.8 Gas production rates comparison

5.2.5 Oil recovered and the Recovery Factor

Comparing the amount of oil recovered and the recovery factors in Fig 5.9 , 5.10 and

5.11, waterflooding is found to be the appropriate most mechanism of the three under

study, for the subject reservoir A-1.

84

Fig 5.9 Field cumulative oil production comparison

Fig 5.10 Oil recovery factors comparison

35.92%

12.28% 11.28%

Ratio of Oil Displaced to OIP

Water Flood HC gas Flood (b) Misc Gas Flood

85

Fig 5.11 Cumulative oil recovered comparison

5.3 Extending simulation time to 30 years

Increasing the simulation time for the three cases following results are obtained for

field pressures, oil production rates, field water production rates and field cumulative

production. It is observed that oil production for waterflood get doubled for the next

20 years and there is negligible increase in recovery for gas floods. That’s why we

have kept our analysis for initial 10 years.

0

5

10

15

20

25

30

35

40

45

50

49.37

16.88 15.50

MM

STB

Oil Recovered

Water Flood HC Gas Flood (b) Misc Gas Flood

86

5.3.1 Field Pressures

Fig 5.12 Field Pressures comparison

5.3.2 Field oil production rate

Fig 5.13 Oil production rates comparison

87

5.3.3 Field Water Cut

Fig 5.14 Breakthrough time for waterflood

5.3.4 Field Oil Production Total

Fig 5.15 Cumulative oil recovered comparison

88

5.3.5 Recovery Factors

Fig 5.16 Recovery factors

5.3.6 Cumulative oil recovered

Fig 5.17 Cumulative oil recovered

35.92%

63.11%

12.28% 14.84%

11.28% 13.22%

Oil Recovery after 10 years Oil Recovery after 30 years

Ration of displaced oil to initial OIP

Water Flood HC gas Flood (b) Misc Gas Flood

49.37

86.73

16.88 20.39

15.50 18.17

Cummulative Oil Recovered (MMSTB)

Water Flood HC Gas Flood (b) Misc Gas Flood

After 10 years After 30 years

89

5.4 Conclusion

Pressure maintenance, constant gas-oil ratio, higher oil production rate, delayed

breakthrough and minimum gas rate make waterflood the most preferable technique

to be applied to the candidate reservoir A-1. However gas floods can be good if given

more time to extract the oil and develop reservoir pressure with lower production

rates and when fining upwards deposits or low permeability barriers are present.

If high permeability layer was not present at the top, and production rates were not too

high, breakthrough could have been delayed in case of gas floods. For example in HC

gas flood case (a): production rate was constant which resulted in delayed

breakthrough. It can be observed in waterflood that low permeability layers (B, C, and

D) are also swept due to favourable mobility ratio of water and give their part in

cumulative recovery and this phenomenon is in contrast with gas floods.

Extending the project life to 30 years reveals the benefits of waterflooding more

concretely. There is no appreciable increase in cumulative recovery in case of gas

floods beyond 10 years, however for waterflood case; there is a tremendous increase

in cumulative recovery. Thus we conclude from this study that water injection is the

best method for such reservoirs.

5.5 Recommendation

We have a volumetric and saturated reservoir constituting different permeability

layers with highest permeable layer at the top; and vertical permeability of all layers is

1/10th

the horizontal permeability. This study clearly demonstrates that gas injection

in this type of reservoirs (highest permeability in top layer and lowest in bottom one,

and also saturated conditions) doesn’t give satisfactory results due to gravity override.

However, waterflooding in such reservoirs sweeps bottom layers as well due to its

higher density thus causes higher recoveries. On the basis of results after 10 years of

flooding, upto three times higher recovery, excellent pressure maintenance and lower

gas-oil-ratio makes waterflooding to be the recommended recovery technique.