“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.