dynamic reservoir simulation of the alwyn field using eclipse

INSTITUTE OF PETROLEUM STUDIES

June 2015

Dynamic Reservoir

Simulation of the Alwyn

Field using ECLIPSE TM

NWOSU UGONNA DIXON IPS/MSC/PPD/2014/240

IJEH GIFT ISIJOKELU IPS/MSC/PPD/2014/235

NWOSU, DIXON 1 IJEH, ISIJOKELU

EXECUTIVE SUMMARY

This project proposes an optimized development plan for production of the Alwyn North reservoir

through the maximization of total oil production at minimum cost per barrel. A black oil model was

simulated using Eclipse for the determination of the field oil recovery, among other parameters such as

field oil production rate and field water cut, of four development scenarios: natural depletion, water

injection, gas injection and water-alternating-gas injection. Each development scenario was optimized for

number, location, completion and geometry of production and injection wells as applicable.

Natural depletion was simulated by depleting the reservoir to a bottom-hole pressure limit 0f 100 bars

using four already-drilled wells. The field oil recovery was 30 % and the duration of the production

plateau at 4200m3 was 6 years.

Water injection was simulated injecting water as a secondary recovery mechanism after depleting the

reservoir to a bottom-hole flowing pressure of around 260 bars. Two additional production wells and four

additional injection wells were drilled to give maximum results with this scheme. The oil recovery thus

increased from 30% to about 53% with the production plateau sustained for 3.9 years albeit at a higher

plateau rate of 7200m3

Gas injection was proposed to reduce the high water cut levels associated with water injection by

injecting gas into the reservoir using the same water injection wells. The field oil recovery reduced to

42%.

The Water-alternating gas scheme, using the same injectors and producers as in water injection, gave a

field oil recovery of about 555 with a production plateau sustained for 4.2 years.

Water Injection and Water-alternating Gas stood out clearly in terms of profitability, internal rate of return

and pay-back time. . Water Injection was the best performer with a pay-back time, internal rate of return

and profitability index of 1.2 years, 90% and 3.26. Recommendation on best production scheme was

proposed based on technical criteria, environmental consideration and comparison of economic

parameters.


ACKNOWLEDGEMENT

This project is dedicated to Mrs Elizabeth Nneka Nwosu who departed this earth

on 5th, June 2015. May her soul rest in perfect peace.

Mr Soma Sakthikhumar also deserves a worthy mention for being patient enough

to impart the desired knowledge to us.

Picarq Corporation, Total Nigeria and Institute of Petroleum Studies are also

appreciated for putting the necessary logistics, facilities and finance in place to

make this project a success.


Table of Contents

Executive Summary ...................................................................................................... ii

Acknowledgements iv

List of Tables vi

List of Figures ix

CHAPTER ONE ............................................................................................................... 9

INTRODUCTION ........................................................................................................... 11

1.1 Purpose of study ..................................................................................................... 11

1.3 Geological Description And Field Characteristics .............................................. 11

1.3.1 Location ............................................................................................................... 12

1.3.2 Field Characteristics Tectonics .......................................................................... 13

1.3.3 Geological Setting ............................................................................................... 13

1.3.4 Brent East Reservoir of Alwyn North Field ....................................................... 15

1.3.4.1 Geological Description ..................................................................................... 15

1.3.4.2 Tectonics .......................................................................................................... 16

1.3.4.3 Sedimentology ................................................................................................. 17

1.3.4.4 Log correlations ............................................................................................... 19

1.4 OBJECTIVES OF THE STUDY ............................................................................. 20

1.5 Reservoir Model And Characteristics ................................................................... 21

1.5.1 Rock Typing ........................................................................................................ 22

1.5.2 Reservoir Fluid Properties ................................................................................. 24

1.5.3 Fluids in Place .................................................................................................... 24

CHAPTER TWO ............................................................................................................ 26

FIELD DEVELOPMENT TECHNIQUES ...................................................................... 27

2.1 Constraints ............................................................................................................ 27


2.1.1 Drilling Constraints ........................................................................................... 27

2.1.2 Production Constraint ...................................................................................... 28

2.1.3 Water Injection Constraint ............................................................................... 28

2.1.4 Gas Injection Constraint ................................................................................... 29

2.2 Analytical Calculations ........................................................................................ 29

2.2.1 Case One: Natural Depletion ............................................................................ 30

2.2.1.1 Minimum number of wells .............................................................................. 31

2.2.1.2 Material Balance For Natural Depletion Alone ............................................ 32

a. Rock And Fluid Expansion .................................................................................... 32

i. Tarbert Region: ....................................................................................................... 33

ii. Ness Region: .......................................................................................................... 33

2.2.2 Case Two: Water Injection ............................................................................... 35

2.2.2.1 Material Balance ............................................................................................. 35

i. Tarbert Region: ....................................................................................................... 35

Evaluation of Ea ......................................................................................................... 35

Evaluation of Ed ........................................................................................................ 37

ii. Ness Region ........................................................................................................... 38

Evaluation of Ea ......................................................................................................... 38

2.2.2.2 Estimation of Oil Recovery Using Hand Calculation .................................. 40

Table 2.6: Oil Recovery from Natural Depletion and Water Injection ................... 41

2.2.2.3 Minimum number of wells: ............................................................................ 41

Implication: ................................................................................................................ 43

2.2.3 Case Three: Gas Injection ................................................................................. 44

2.2.3.1 Material Balance ............................................................................................. 44


i. Tarbert Region ........................................................................................................ 44

Evaluation of EA: ....................................................................................................... 44

Evaluation of ED: ....................................................................................................... 44

CHAPTER THREE ......................................................................................................... 49

DYNAMIC FIELD DEVELOPMENT STUDY USING ECLIPSE SOFTWARE ............. 49

3.1 Case One: Natural Depletion ............................................................................. 49

3.1.1 Natural Depletion with the Available Four Exploratory Wells ..................... 49

3.1.2 Effect of Critical Gas Saturation ....................................................................... 52

3.1.3 Natural Depletion with Increased Development Wells: ............................... 54

3.1.3.1 Natural Depletion with Five Producer Wells .............................................. 54

3.1.4 Inferences: Natural Depletion .......................................................................... 57

3.2: Case 2: Water Injection Preceded by Natural Depletion ................................ 58

3.3 Case 3: Gas Injection Preceded by Natural Depletion ....................................... 62

3.4 Case 4: Water- Alternating Gas Injection .......................................................... 63

CHAPTER FOUR ........................................................................................................... 68

ECONOMIC ANALYSIS ................................................................................................ 68

4.1 Economic Evaluation of Natural Depletion at Economic Limit ....................... 70

4.2 Economic Evaluation of Gas Injection Scheme at Economic Limit ................. 72

4.3 Economic Analysis of Water Injection Scenario ............................................... 76

4.4 Economic Analysis of the Water-Alternating-Gas Scheme .............................. 78

4.5 Investment Decision ............................................................................................ 81

4.5.1 Lowest Capital Investment ............................................................................... 82

4.5.2 Pay-back time ................................................................................................... 83


4.5.3 Profitability Index and Economic Life............................................................. 84

4.5.4 Gross Profit Margin per barrel ......................................................................... 85

4.5.5 Cumulative Net Present Value (CNPV): ......................................................... 86

4.5.6 Internal Rate of Return (IRR): ......................................................................... 86

CHAPTER FIVE ............................................................................................................. 88

CONCLUSION AND RECOMMENDATIONS ............................................................ 88

5.1 Conclusion ......................................................................................................... 88

5.2 Recommendations ............................................................................................ 89

REFERENCES ................................................................................................................. 90

APPENDICES .............................................................. Error! Bookmark not defined.

APPENDIX A ............................................................................................................. 92

A1 Natural Depletion: Evaluation Of Revenue, Opex, Cash Flow, Internal Rate

Of Return , Pay-Back Time And Npv Using 10% As The Discount Factor ............ 92

A2 Gas Injection: Evaluation Of Revenue, Opex, Cash Flow, Internal Rate Of

Return , Pay-Back Time And Npv Using 10% As The Discount Factor ................. 93

A3 Water Injection: Evaluation Of Revenue, Opex, Cash Flow, Internal Rate Of

Return , Pay-Back Time And Npv Using 10% As The Discount Factor ................. 94

A4 Natural Depletion: Evaluation Of Revenue, Opex, Cash Flow, Internal Rate

Of Return , Pay-Back Time And Npv Using 10% As The Discount Factor ............ 95

APPENDIX B .............................................................................................................. 96

Evaluation Of Npv For The Various Development Schemes Using The Calculated

Internal Rate Of Return ............................................................................................ 96

B1 Gas Injection: Evaluation Of Npv Using The Calculated Internal Rate Of

Return......................................................................................................................... 96


B2 Water Injection: Evaluation Of Npv Using The Calculated Internal Rate Of

Return......................................................................................................................... 97

B3 Wag Injection: Evaluation Of Npv Using The Calculated Internal Rate Of

Return......................................................................................................................... 98

APPENDIX C .............................................................................................................. 99

Full PVT Report ......................................................................................................... 99


LIST OF TABLES- Table 1.1: Rock Typing and Layers representing the Tarbert and Ness

22

Table 1.2: Initial Values of Fluid Properties ............................................................. 24

Table 1.3: Table Showing the Fluids in Place Volume ............................................. 25

Table 2.1: PVT File ..................................................................................................... 30

Table 2.2: Analytical solution for Recovery by Natural Depletion Drive............... 34

Table 2.3: Reciprocal Mobility Ratio computation for obtaining error. Ea ........... 37

Table 2.4: Relative Permeability (Imbibition) data table ....................................... 37

Table 2.5: Relative Permeability (Imbibition) data table ........................................ 39

Table 2.6: Oil Recovery from Natural Depletion and Water Injection ................... 41

Table 2.7: Gas-Oil Relative Permeability Data for Rock-Type 1 ............................. 45

Table 2.8: Recoveries from combined Natural Depletion and Gas Injection ........ 48

Table 3.1: Comparison of WI and WAG ................................................................... 67

Table 4.1 Revenues and Expenditures for Natural Depletion ............................... 70

Table 4.2 Economic Evaluation Indices for Natural Depletion ............................. 71

Table 4.3 Revenues and Expenditures for Gas Injection 73

Table 4.4 Economic Evaluation Indices for Gas Injection .................................... 74

Table 4.5 Revenues and Expenditures for Water Injection .................................... 76

Table 4.6 Summary of Economic Evaluation for Water Injection

77

Table 4.7 Revenues and Expenditures for WAG Injection ................................... 79

Table 4.8 Summary of Economic Evaluation Parameters for WAG Injection .... 80

Table 4.9: Economic Evaluation for the various development schemes

87


LIST OF FIGURES Figure1.1: Alwyn North Field Localization Map 7

Figure 1.2: Alwyn Area Location Map 8

Figure1.3: Stratigraphy of the Alwyn North Field 9

Figure 1.6: Cross Section Through Alywn Showing The Faults 11

Figure 1.7: Depositional Setting of the Brent Group

Figure 1.8: Showing Log Correlations 13

Figure 1.8: Reservoir Model Showing the Grids 17

Figure 1.9: Data File Initialized to Obtain Volumes In-Place 19

Fig2.1: Reciprocal Mobility Ratio Chart 29

Fig2.2: Fractional Flow curve for the Tarbert Region 31

Fig2.3: Fractional Flow curve for the Ness Region

32

Figure 2.4: Relative permeability versus gas saturation curves 39

Figure 2.5: Plot of Gas Fractional flow against saturation for Tarbert 40

Fig 3.1: Well Architecture: Natural Depletion 42

Fig 3.2: FOPR, FOPT and FOE for the 4-well Natural Depletion case 42

Fig 3.3: Oil Production Rate from Wells PA2, PA1, PN2 and PN1 44

Fig 3.4: Field Recovery Efficiency and Field Plateau Rate for both cases 46

Fig 3.6: Field Water Cut and Field Gas-Oil Ratio for both cases 47

Fig 3.7: Well Architecture: Natural Depletion with Wells 48

Fig 3.9: FPR, FOE, FWCT, FGOR as a function of time 49

Fig 3.10: Well by Well Analysis 50

Fig 3.11: Well Architecture: 7 producers and 5 injectors 52


Fig 3.12: Water Injection: FOPR, FOE and FOPT 53

Fig 3.13: Water Injection: FPR, FWCT and FWIR 54

Fig 3.14: Gas Injection: FOPR, FOE and FOPT 55

Fig 3.15: Water Injection: FPR, FWCT and FWIR 56

Fig 3.16: Sub-case 1: FOPT, FOE, FOPR, FWIR and FOPR 59

Fig 3.17: Sub case 2: FOPR, FOPT, FOE, FWIR and FPR 59



Fig4.1 Cash flow curve for Natural Depletion Scheme 67

Fig4.2 Cash flow for Gas Injection 69

Fig4.3 Cash flow for Water Injection 73

Fig 4.4: Cash flow for WAG Injection 75

Fig 4.5: Investment Costs for the various development schemes 76

Fig 4.6 : Pay-back time for the various development schemes 77

Fig 4.7: Economic Life and PI for the various development schemes 79

Fig 4.8 GPM per barrel for the various development schemes 80

Fig 4.9 NPV for the various development schemes 81

Fig 4.10 IRR for the various development schemes 82


CHAPTER ONE

INTRODUCTION

1.1 Purpose of study

To determine the optimum field development plan for the Alwyn North Field

(Brent East Reservoir) in terms of recovery and economics, using Eclipse reservoir

simulator.1.2 Scope of Study

This study was limited to the Brent East panel of the Alwyn North Field. The

reservoir model focused on the Ness 2 and Tarbert 1, 2 and 3 units because of the

small oil content in Ness 1.

Black Oil PVT representation was used in this study. The drive mechanisms were

determined using material balance. Annual production was set at 15% of ultimate

reserves.

The following cases were examined:

1. Natural depletion with Flowing well pressure limit of 100bars

2. Natural depletion up to a reservoir pressure 290bars then introduction of

Water injection as secondary recovery process

3. Natural depletion to a reservoir pressure 350bars then introduction of Gas

injection as secondary recovery process

4. Natural depletion to a reservoir pressure 350bars then introduction of

Water injection as secondary recovery process for 4years followed by an alternate

gas injection.

1.3 Geological Description And Field Characteristics

In a bid to explore the Alwyn North field a thorough geological description of the

field is necessary to ensure complete understanding of the geology of the area. The

geological settings, sedimentology and other related aspects of the field are

described in this section.


1.3.1 Location

The Alwyn North Field was discovered in 1974 in the South Eastern part of the East

Shetland Basin in the UK North sea, about 140 km East of the near most Shetland

Island and about 400 km North East of Aberdeen. The Alwyn field lies respectively

4 and 10 km south of Strathspey and Brent field, 7 km east of Ninian field, and 10

km north of Dunbar field (see field localisation map below). The water depth is

around 130 m. The field is in the UKCS Block 3/9 and extends northward into the

Block 3/4. The location map and 3D view of the area is shown in Fig. 1.1 and 1.2

respectively.

Figure1.1: Alwyn North Field Localization Map


Figure 1.2: Alwyn Area Location Map

1.3.2 Field Characteristics Tectonics

Tectonics played a significant role on the structure of ALWYN North field.

Tensional movements leading to the development of the Viking Graben from

the lower Permian times to Upper Jurassic generated a complex fault pattern.

Several seismic data acquisition programs were carried out: 2D seismic in 1974

and 1977, and 3D in 1980/81. Seismic data analysis indicates that the oil bearing

sands are controlled on one hand by normal sealing faults with a general North-

South direction, on the other hand by a major unconformity at the base of

Cretaceous. This unconformity is related to erosion of the Brent formation in the

eastern part of ALWYN North field.

In a bid to explore the Alwyn North field a thorough geological description of

the field is necessary to ensure complete understanding of the geology of the

area. The geological setting, sedimentology and other related aspects of the field

are described in this section.

1.3.3 Geological Setting

The Brent formation was deposited in a deltaic and shallow marine environment


during the Middle Jurassic period. The Statfjord formation was deposited in a

fluvial and shallow marine environment during the Lower Jurassic period. Each

panel has several pre-cretaceous tilted blocks (see Figure 1.3 below). The cap

rock is made of three on lapping shaly formations:

Heather formation: marine transgressive shales with thin limestone

stringers, which is deposited after the tectonic activity.

Kimmeridge clay thick in the West, thin in the East, which is the main

hydrocarbon source rock.

Thick cretaceous sequence.

Figure1.3: Stratigraphy of the Alwyn North Field

ALWYN North reservoirs were relatively unaffected by diagenesis due probably

to an early hydrocarbon impregnation.

RFT shows that each panel had its own pressure regime. Water-oil contacts were

identified at different depth. All the panels were independent from the other.


1.3.4 Brent East Reservoir of Alwyn North Field

This study was considering only the East Panel of the Alwyn North field.

1.3.4.1 Geological Description

The structure of Alwyn Brent East Block was generally an eroded monoclinal,

with Base Cretaceous Unconformity (BCU) setting east and south limit, Spinal

Fault setting west limit (separating Brent east from north and central west

blocks), and a fault with sometimes very small throw setting north limit. East

structure under BCU is quite complicated, and described under the generic term

of slumps (linked to gravitational collapse of head blocks during Cretaceous

erosion similar as ones encountered in Brent field).

In the Brent East panel, the oil zone is in a stratigraphic trap as shown below

created by the erosion unconformity to the east, by a northsouth fault to the

west (between A-1 and A-2 wells) and by a transverse fault to the north. The

Brent Geological Cross section is shown below.

Figure 1.4: Brent Geological Cross section

The Brent geological well section is shown in Fig. 1.5.


Fig: Brent Geological well Section

1.3.4.2 Tectonics

Several seismic data acquisition programs were carried out: 2D seismic in 1974

and 1977, and 3D in 1980/81. Seismic data analysis indicates that the oil bearing

sands are controlled on one hand by normal sealing faults with a general North-

South direction, on the other hand by a major unconformity at the base of

Cretaceous. This unconformity is related to erosion of the Brent formation in the

eastern part of ALWYN North field.

Following the seismic interpretation, ALWYN North field was divided into the

following panels:

Brent North.

Brent Northwest.

Brent Southwest.

Brent East.

Statfjord

Triassic .


The first four panels are oil bearing within the Brent. The Statfjord formation is

a condensate gas reservoir with the Brent completely eroded. The underlying

Triassic is gas bearing.

Figure 1.6: Cross Section Through Alywn Showing The Faults

1.3.4.3 Sedimentology

The Brent group is divided into three main units: the Lower Brent (Broom,

Rannoch and Etive formations), the Middle Brent (Ness formations), and the

Upper Brent (Tarbert formations). The last two are the only oil-bearing

formations in the Brent East panel.

The Lower Brent formation was deposited in a shoreface (Rannoch) to

coastal barrier (Etive) environment. The clastic reservoir is made of

transgressive sandstone (Broom) and prograding sandstones (Rannoch

and Etive). Thus, the petrophysical properties range from low to medium

permeability. This unit does not contain any oil in the Brent East reservoir.

The Middle Brent formation was deposited in a deltaic to alluvial plain

(Ness 1) and lagoon to lower delta plain (Ness 2) environment. Thus,

sandstones are inter bedded with clay and coal. In general, Ness 1 unit has


poorer petrophysical characteristics than Ness 2 unit and its oil-bearing

leg is much lower especially to the East of the reservoir.

The Upper Brent was deposited in a prograding lower shoreface

environment. Three different types of sandstone are identified. At the top

(Tarbert 3), are massive sands with very good reservoir characteristics.

This is the main oil bearing unit in the Brent East reservoir. Below

(Tarbert 2), there are mica-rich sandstone with lower permeability. These

mica-rich sandstones exhibit a high natural radioactivity. The base of the

Tarbert formation (Tarbert 1) is very similar to the top sandstone. Despite

its lower average permeability, Tarbert 2 unit is not considered as a

permeability barrier.

Figure 1.7: Depositional Setting of the Brent Group

To summarize, Tarbet can be described as massive shore face sands with

excellent petro-physical properties, well connected throughout the field and

may be even regionally, communicating partially with Upper Ness fluviatile

system which is isolated from Lower Ness.

Base Brent Etive and Rannoch are better quality reservoirs, but mainly water

bearing in Brent East Block.


Considering the small oil content in Ness 1, this unit is neglected in the reservoir

model. Thus, the reservoir model focuses on the Ness 2 and Tarbert 1, 2 and 3

units.

The Brent East reservoir of Alwyn North was characterized using data from two

of the original vertical appraisal wells (3/9A-2, 3/9A-4) and two new deviated

delineation wells (N1 and N3). N3 characterized the northern part of the field

where an important oil leg was confirmed mainly in the Tarbert units. N1

located to the West did not produce any oil and only encountered the aquifer,

which does seem to be active. The water salinity in the reservoir is about 17,000

ppm.

1.3.4.4 Log correlations

The last two appraisal wells, namely N1 and N3, were extensively cored.

Numerous core samples were analyzed through routine conventional core

analysis. Several permeability-porosity relationships were derived (see annex 2):

one for each of the reservoir units considered (Tarbert 3, Tarbert 1&2 and Ness 2).

Special core analyses were carried out on a few samples from each of the

reservoir units. Unsteady state measurements under reservoir conditions (fluids

and pore pressure) were conducted to obtain a set of relative permeability and

of capillary pressure curves.


Figure 1.8: Showing Log Correlations

1.4 OBJECTIVES OF THE STUDY

The goal of this study is to propose an initial development plan for the Brent

East reservoir, this plan should maximize the total hydrocarbon production and

minimize the development cost in $/bbl.

Several aspects were investigated:

a. Using available data, a reservoir performance analysis was performed to

identify the main reservoir driving force. Using material balance, the different

drive mechanisms were investigated in order to estimate the oil recovery.

Primary production as well as secondary production must be investigated

(material balance calculation above Psat). In order to calculate the Material

Balance, use average values of Swi and Sor.

b. Based on the results of the first step, different production schemes should

were defined: Natural depletion, water injection, gas injection. Each scenario

was reported in detail with all relevant information, assumptions and selected


options. The annual production plateau was estimated to be around 15% of

EUR. The production profiles were evaluated over 15 years.

c. 60% of EUR must be produced at plateau rate.

d. Each scenario was implemented in the numerical reservoir model. In natural

depletion, the model was run until 100 bar (BHP). Are the calculated

numbers of producers relevant? Investigate was done to give the best number

of wells. For secondary production: We optimize the injectors to meet the

target production. Attention was paid to the critical gas saturation (Sgc).

e. A proposed scenario was selected based on technical criteria and economic

parameters were compared.

f. Using the selected development scheme, the major uncertainties were

investigated to assess the impact of the model assumptions including for

instance:

permeability anisotropy: Ky = 10*Kx,

fault transmissibility: sealing / non sealing,

Tarbert 2 Tarbert 3 connection: transmissivity of layer 4,

aquifer strength: decrease of pore volume in the water zone (see the impact

on natural depletion scheme),

1.5 Reservoir Model And Characteristics

Based on the Brent East characteristics described previously, a reservoir

simulation model was designed to investigate the production capacity of this

reservoir. The reservoir model was built using the four appraisal wells: A2, A4,

N2 and N3. These wells can be abandoned according to the production scheme.

Due to a sketchy knowledge of the Brent East reservoir at the beginning of the

study, a Black Oil model was designed with rectangular cells with 36 cells along

the x-direction and 51 cells along the y-direction. The geometry definition is


given in a Petrel file: 'MODEL_PETREL.GRDECL'. The structural

framework used for the Corner Point Geometry is based on the Spinal Fault

Geometry and the North fault limit. Model size is geometrically 36x51x18 but is

in reality 36x51x17 (since the 1st layer representing all layers between the Base

Cretaceous Unconformity and Top Brent is killed by nil porosity), Fig. 1.8.

1.5.1 Rock Typing

The rock typing to represent the Tarbert and Ness formations as shown in Table

1-1. Tarbert can be described as massive shore-face sands with excellent

petrophysical properties, well connected throughout the field. Tarbert

communicates partially with the Upper Ness fluviatile system which is isolated

from Lower Ness.

Ness 1 and Ness 2 bear small oil content while lower Brent is mainly water and

are thereby neglected in the reservoir model. Thus, the reservoir model focuses

on Tarbert 1, 2 and 3.

Table 1.1: Rock Typing and Layers representing the Tarbert and Ness

Rock Type Formation Layer Tags

Rock Type Formation Layer Tags

Impermeable zone

1

Type 1

Tarbert 3

2,3,4

Tarbert 2

5,6

Tarbert 1

7,8,9

Type 2

Type 2

Ness 2

10,11,12,13,14

Ness 1

15,16

Lower Brent

17,18

This model will only include the oil bearing sands from the Tarbert (1, 2 &

3) and Ness (1 & 2) formations. Thus, in this study, the reservoir model has 17

layers:

3 in Tarbert 3

2 in Tarbert 2


3 in Tarbert 1

5 in Ness 2

4 in Ness 1

There are three equilibration regions defined in the EQUNUM keyword in the

Regions section. However, there is no evidence of compartmentalization, all the

regions have the same water-oil contact (WOC) and pressure regime.

Figure 1.8: Reservoir Model Showing the Grids

Initial pressure of the reservoir is 446 bar and saturation pressure is 258 bar. The

reservoir petrophysical properties (porosity, permeability) were also scaled up.

The property modeling was done as follows:

Tarbert and Ness shallow marine sheet flood sandstone: Determine

modelling with trend surface control maps

Ness: Object modelling floodplain & lagoonal back barrier lobes

Porosity: Depth and facies trends incorporated

Permeability: Calibrated with core and DST Data


The petrophysical properties (porosity, permeabilities and NTG) are included in

the grid in the include file: 'MODEL_PETREL_PETRO.GRDECL'. The original

oil in place (OOIP) estimation, according to the geological model, is about 35.68

MMsm3; this value is dependent on capillary pressure.

1.5.2 Reservoir Fluid Properties

Black Oil PVT representation was used in this study. The PVT data file PVT.INC

contains the relevant composite black oil PVT data which accounts for the field

separation conditions. Below is a table showing the initial PVT values of the

reservoir fluid.

Table 1.2: Initial Values of Fluid Properties

Properties Value

Initial Reservoir Pressure (Pi) 446 Bar

Temperature (T) 110 oC

Saturation Pressure (Psat) 258 Bar

GOR 206.8974 v/v

Formation factor, Bo@ Pi 1.6038

OOIIP 35.68MMm3

1.5.3 Fluids in Place

The original data file was initialized to obtain the fluid in place values shown

below. This was illustrated by adding the ECHO and FIPNUM keywords in the

dot DATA simulation.


Table 1.3: Table Showing the Fluids in Place Volume

Currently in place Tarbert Ness Entire Field

Oil (sm3) 31,104,045 4,577,946 35,681,991

Water (sm3) 125,222,389 188,540,747 313,763,137

Dissolved Gas

(sm3)

6,426,769,976 945,920,886 7,372,672,862

Figure 1.9: Data File Initialized to Obtain Volumes In-Place


As shown above, the Tarbert (Region 1) had Oil Originally in place as 31104045

Sm3, while Ness (region 2) had Oil Originally in place as 4577946 Sm3,with

Tarbert contributing 87% of the total oil in place in the entire field. The Ness

can be said to be non-prolific, since it is producing more water than oil. For this

reason, region 2 will not contribute per say to our proposed production, as such

drilling into it would lead to early breakthrough and a reduction in oil recovery.

Hence, our study was focused mainly on the Tarbert rock.


CHAPTER TWO

FIELD DEVELOPMENT TECHNIQUES

In this chapter we proposed an initial development plan for the Brent East

reservoir, this plan should maximize the total hydrocarbon production and

minimize the development cost in $/bbl. This is done in two parts, the analytical

calculation of the recovery from natural depletion, water injection and gas

injection and the other part, the simulation using ECLIPSE for each of the above

mentioned scenarios with the inclusion of water alternate gas injection. In the

excel calculation involving material balance and the different drive mechanisms

were used to estimate the oil recovery. The first case used to produce the oil in

place was natural depletion and also different cases of secondary production

were also investigated (material balance calculation above Psat).

The different secondary production schemes used were: Natural depletion, water

injection, gas injection as well as Simultaneous Water Gas Injection (WAG).

Each case is described in this chapter using both excel calculation and eclipse to

validate. The annual production plateau estimate is around 15% of EUR. The

production profiles were evaluated over a period of 15 years.

Each case was implemented in the numerical reservoir model. For primary

method, production was optimized by investigating the best number of wells.

For secondary method, production was optimized by investigating the best

number of producers and injectors to meet the target production.

2.1 Constraints

2.1.1 Drilling Constraints

To develop the Brent East reservoir, a 40-slot well platform will be used.

The maximum well deviation should not exceed 46 with respect to

vertical.

Production program should start at the beginning of 2012.


The maximum horizontal drain (x or y direction) of a well will be less than

1000 m.

The kick off point (start of deviation) is set at 2,000 m ground level. It is

also possible to drill vertical wells with subsea completion.

The average drilling completion time is about 2 months for vertical wells

and 2 months for the horizontal ones.

Wells may be t

Two drilling rigs are available.

The wells are drilled in 7".

2.1.2 Production Constraint

The minimum bottom hole flowing pressure (BHFP) is 260 bar.

The perforations of the wells are chosen to optimize recovery depending

on the well location.

Vertical well production test indicates a maximum fluid (oil + water) rate

of 1,800 Sm3/d.

Horizontal well could produce up to 2,400 Sm3/d of liquid. Only flowing

production is considered at this stage.

Drainage radius for vertical wells is about 400 m.

The averaged maintenance down time is 10 % for all the wells.

Due to surface facilities on platforms, the maximum allowable GOR is 1500

m3/m3 and the maximum allowable water cut is 90 %.

The minimum economical rate for the field is 1000 Sm3/d of oil.

To estimate the productivity index, we considered a skin of 5

The annual production plateau should be around 15% of EUR (~7200

Sm3/d)

The production plateau should be maintained for 60% of the total oil

production

The production profiles should be evaluated over 15 years

2.1.3 Water Injection Constraint

During secondary recovery, the following constraint will be considered for water

injection.


Seawater may be injected into the reservoir without any water

compatibility problem.

To estimate the water injectivity index, we considered a skin of -4 induced

by thermal fractures due to the low temperature of the sea water injected

in the formation (surface temperature of water: 8C).

The fracture pressure of the Brent reservoir is about 480 bars.

The maximum water injection rate is 3,000 Sm3/d. The maximum total

water injection available is 15,000 Sm3/d.

Control in voidage replacement

2.1.4 Gas Injection Constraint

If gas injection is considered during secondary recovery, the following constraint

will be considered:

Lean Statfjord gas may be injected.

This lean gas is assumed to have the same characteristics as the Brent dissolved

gas.

The maximum gas injection rate is 800,000 Sm3/d per well. The maximum total

gas injection available is 3,200,000 Sm3/d.

Control in voidage replacement.

2.2 Analytical Calculations

The main drive mechanism for production of the Alwyn North Brent East

reservoir is Expansion of original reservoir fluids (Oil) because the reservoir

initially is undersaturated and will be depleted above bubble point pressure with

a minimum drawdown of 20 bars. However, secondary and enhanced oil

recovery mechanisms will also be deployed to increase recovery via water and/or

gas injection. These scenarios will be investigated using MBE (Analytical or

Hand Calculations) vis--vis dynamic Numerical Simulation with Eclipse and

the results will be presented and discussed.

However, before proceeding we ran Eclipse in NOSIM mode to generate the

PRT file containing the STOIIP of Alwyns Tarbert and Ness formations. The

following screenshot captures this information and other important data.


The PVT file used for various calculations is shown below. The full PVT file used

for gas injection is shown in the appendix.

Table 2.1: PVT File

Assumptions

1. The Petro-physical and PVT Properties of both rock types are assumed to be

similar.

2. Vertical Sweep Efficiency, Ev is assumed to be 0.7 for all regions.

2.2.1 Case One: Natural Depletion

This refers to production of hydrocarbons from a reservoir without the use of

any process (such as fluid injection) to supplement the natural energy of the

reservoir. In the case of natural depletion, we used the material balance equation

(MBE) to calculate the production and ultimate oil recovery under a natural


depletion process. The reservoir was depleted from the initial pressure (Pinitial =

258bar) to a bottom hole pressure limit of 100 bar.

The data used for these calculations were obtained from the PVT report and the

INPUT data file. The Original Oil in Place for the two regions (Tarbert and Ness)

was obtained from an initialization run in ECLIPSE. The result is displayed in

Figure 1.9.

In this type of reservoir, the principal source of energy is a result of gas

liberation from the crude oil and the subsequent expansion of the solution gas

as the reservoir pressure is reduced.

Assumptions:

1. No Aquifer support or water influx into the reservoir

2. Recovery is by rock and liquid expansion

2.2.1.1 Minimum number of wells

The following equations were used to determine the minimum number of wells:

------------------------------2.1

To get the initial number of wells, we need:

--------------------------------------2.2

Considering that for the development field case we don't have any production

data, to estimate productivity index (average value between Pi and Pmin):

--------------------------------------------------2.3

Where,

= 0.0086.2 = 0.0536 ___metric units

= 0.0086.2 = 0.0536 ___metric units

At reservoir pressure, 446bars


At 280bars,

Well Potential =

----------------------------------------------2.4

Assuming EUR = 25%

Hence,

Minimum number of wells =

2.2.1.2 Material Balance For Natural Depletion Alone

a. Rock And Fluid Expansion

The equations were used for calculating material balance;

---------------------------------------------------------------2.5

Where,

Np = Cumulative Oil Produced

Boi = Initial Formation Volume Factor of Oil

Bo = Final Formation Volume Factor of Oil

N = Stock Tank Oil Initially in Place (STOIIP)

Ce = Equivalent Compressibility of Oil

P = Pressure Drop

But,

----------------------------------------------------2.6

Where,

Co = Compressibility of Oil

Cw = Compressibility of Water


So = Oil Saturation

Swc = Connate Water Saturation

Cf = Rock Compressibility

Also

-----------------------------------------------------------------------------2.7

i. Tarbert Region:

Boi = Bo @ 446 = 1.6038

Bo @ 280 = 1.6737

For water participating in expansion,

-----------------------------------------------------------------------2.8

ii. Ness Region:

Boi = Bo @ 446 = 1.6038

Bo @ 280 = 1.6737


For water participating in expansion,

Estimation of the above parameters and final EUR for NATURAL DEPLETION

case are presented below:

Table 2.2: Analytical solution for Recovery by Natural Depletion Drive


2.2.2 Case Two: Water Injection

The previous case assumed the reservoir produced only by natural depletion. In

practice, reservoirs are rarely allowed to deplete almost to their bubble point

pressures. Pressure maintenance schemes are implemented to sustain plateau

production usually with Water Injection Scheme (Note: Pressure maintenance

by Gas Injection is usually not feasible because of the enormous amounts of gas

that is required; gas Injection supports oil recovery mainly via dissolution and

miscibility phenomena).

Here, we will calculate the amount of additional oil that can be recovered by

water injection and also the number of wells that will effectively sweep oil in the

reservoir while maintaining the reservoir pressure above bubble point.

The total recovery during a water injection process can be given by;

----------------------------------------------------------------2.9

-------------------------------------------2.10

Where,

Ed = f(primary depletion, krw & kro, o & w)

Ea = f(mobility ratio, pattern, directional permeability, pressure

distribution, cumulative injection & operations)

Ev = f(rock property variation between different flow units,fluid density), Ev =

0.7(assumption)

2.2.2.1 Material Balance

i. Tarbert Region:

Evaluation of Ea

Ea can be gotten from the graph as shown below:


Fig2.1: Reciprocal Mobility Ratio Chart

The Mobility Ratio (MR) is first obtained using the relationship

---------------------------------------------------------2.11

Next, the Reciprocal Mobility Ratio (inverse of MR) is calculated and the areal

sweep efficiency (EA) corresponding to this value is read off the Reciprocal

Mobility Ratio Chart.


Table 2.3: Reciprocal Mobility Ratio computation for obtaining error. Ea

From the table and chart above, Ea = 0.98

Evaluation of Ed

Ed is calculated from a plot of fractional flow, fw versus water saturation, Sw.

This plot shows the fractional flow of water when injected into the reservoir to

displace oil. The plots are different for each rock type.

-------------------------------------------------------------2.12

Plot of fw vs Sw is generated using corresponding Relative Permeability

(Imbibition) data

Table 2.4: Relative Permeability (Imbibition) data table


Fig2.2: Fractional Flow curve for the Tarbert Region

As shown above,

Swc = 0.15, Swm = 0.71

Therefore, the drainage efficiency at Break-through (BT) is obtained from

equation 2.12;

Recovery =

= 0.6588 = 65%

Ed = 0.66, Ev = 0.7, Ea = 0.98

Therefore, R = 0.66*0.7*0.98 = 0.45

ii. Ness Region

Evaluation of Ea

EA is the same as obtained for Tarbert since both rock types contain the same

reservoir fluid.

Evaluation of Ed:

Plot of fw vs Sw is generated using corresponding Relative Permeability

(Imbibition) data

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

1.1

0 0.2 0.4 0.6 0.8 1 1.2

fw

Sw

Tarbert

Tarbert

Swm


Table 2.5: Relative Permeability (Imbibition) data table

Fig2.3 : Fractional Flow curve for the Ness Region

As shown above,

Swc = 0.30, Swm = 0.66

Therefore, the drainage efficiency at Break-through (BT) is obtained from

equation 2.12;

Recovery = (0.66-0.30)/(1-0.30) = 0.51 = 51%

Swm


Ed = 0.51, Ev = 0.7, Ea = 0.98,

R = 0.51*0.7*0.98 = 0.35

2.2.2.2 Estimation of Oil Recovery Using Hand Calculation

From equation 2.9,

Oil Recovery with water:

Total oil produced:

------------------------2.13

Therefore,

Table 2.6 shows a section of an MS Excel file that contains calculations for the

total oil that can be produced by water injection.


Table 2.6: Oil Recovery from Natural Depletion and Water Injection

From the table above, the total oil recovery from Tarbert and Ness by natural

depletion and water injection is 4.49E+06 Sm3 with a Global percent recovery of

51%.

Given that annual production plateau should be around 15% of Estimated

Ultimate Reserves (EUR), Average Oil Withdrawal per day calculated from Table

2.6 is 7478 Sm3/day.

2.2.2.3 Minimum number of wells:

Oil Flow rate, Qo, per well, is given by :

----------------------------------------------------------2.14

Where,

Kro = relative permeability of oil in the presence of water

Bo = oil formation volume factor

o = viscosity of oil


C =conversion factor

K = permeability

H = net pay thickness

P = pressure drawdown

Rd = reservoir drainage radius

Rw = well radius

S = skin

Assumptions for Calculation:

Wells drilled and completed in the TARBERT Region

Reservoir producing at Pseudo-steady state

Oil flowing at connate water saturation

Reservoir drainage radius equals 400m

Values of average permeability, K, Net-to-Gross ratio, NTG and average

thickness, DZ were obtained from the geological model using FLOVIZ with

Eclipse Simulator run on NOSIM mode. An examination of the 9 vertical

layers of the Tarbert region showed an erosion of the top layer. Hence, only 8

layers of reservoir sand thickness were used.

Qo @ 446bars

Bo = 1.6038

o = 0.3916

Kro = 0.8

Z = 8.0907 per layer* 8 layers *NTG = 64.7256 * 0.96883 = 62.7081m

Qo @ 280bars

Bo = 1.6737

o = 0.2829

Kro = 0.8


Z = 8.0907 per layer* 8 layers *NTG = 64.7256 * 0.96883 = 62.7081m

We have been informed of a possible production downtime of 10%. Hence, our

rate is subject to a WEFAC (Well Efficiency Factor) of 90%.

Therefore,

=

Implication:

We need to drill at least 5 producer wells for optimal reservoir exploitation by

Natural Depletion.

Secondary oil recovery by water injection is usually incorporated in the field life

of a reservoir. Hence, optimum number of wells for increased recovery by water

injection was also calculated. Because of thermal cracks induced by injecting

cold North Sea water into the hot reservoir, a skin of -4 is expected for a water

injection case.

The most efficient way to determine the amount of Water for injection is to

calculate the amount of water required to achieve zero-net-voidage by applying

the VOIDAGE REPLACEMENT PRINCIPLE.

Field oil production rate was previously determined as 7478 Sm3/day. We shall

find the equivalent reservoir oil volume. This volume is equal to reservoir water

volume for zero-net-voidage.

Subsequently, we determine the surface equivalent of this reservoir water which

is calculated as:


Implication:

We need to drill at least 4 injection wells for optimal reservoir exploitation by

voidage replacement.

2.2.3 Case Three: Gas Injection

We would calculate the amount of recovery that can be achieved by gas

injection while maintaining the reservoir pressure above bubble point. Because

the NESS region is predominantly water zone, there will be no need injecting gas

in this region. Hence, we focused on recoveries from the TARBERT region.

2.2.3.1 Material Balance

i. Tarbert Region

The total recovery possible during a gas injection process can be obtained from

equation 2.15

---------------------------------------------------------------2.15

Recall that Equation 2.10 for Recovery Factor with all parameters defined as

previously is:

Evaluation of EA:

The Mobility Ratio is first obtained, Reciprocal Mobility ratio estimated, and

traced up to the corresponding gas cut curve to read off EA =0.74 (See Table

2.8).

Evaluation of ED:

As with the water injection case, plot varies for the different rock types as

presented below. Because the reservoir is predominantly water-wet, Gas


Injection constitutes a Drainage Process. Hence, the Drainage Data for Tarbert

is made use of for computing fractional flow.

Table 2.7: Gas-Oil Relative Permeability Data for Rock-Type 1


Figure 2.4: Relative permeability versus gas saturation curves


Figure 2.5: Plot of Gas Fractional flow against saturation for Tarbert

From the graph, the Sgf and Sgm as shown on the chart are determined.

Sgm = 0.25 , Sgc 0.0

Therefore, the drainage efficiency at Break-through (BT) is obtained as follows;

EV = 0.7 (assumption)

Applying Equation 2.10,

Recovery of oil from gas injection is shown in the Table 2.8 below:


Table 2.7: Recoveries from combined Natural Depletion and Gas Injection

As shown in the table above, total oil produced from Tarbert due to gas injection

is 5,219,682.323 Sm3 with a per cent recovery of 14.49 %.

Total oil from Tarbert from both natural depletion and gas injection is therefore,

6,978,338.529 Sm3 with a per cent recovery of 19 %.


CHAPTER THREE

DYNAMIC FIELD DEVELOPMENT STUDY USING ECLIPSE

SOFTWARE

A field development study can be conveniently done using Eclipse as different

reservoir production cases can be simulated to determine the best strategy for

producing from the field.

Four cases will be considered:

Natural Depletion

Natural Depletion followed by Water Injection

Natural Depletion Followed by Gas Injection

Natural Depletion followed by Water Alternating Gas Injection (WAG)

3.1 Case One: Natural Depletion

Natural depletion, also known as primary production, describes a scenario

where the reservoir is produced via its natural energy. In natural depletion, the

energy required to drive the fluids from the reservoir to the wellbore and

consequently to the surface is the reservoirs energy. This energy might be due

to a solution gas drive, aquifer and rock expansion, gravity drainage or water

drive.

3.1.1 Natural Depletion with the Available Four Exploratory Wells

For this natural depletion case, the original four vertical wells in the model were

run to limit BHP of 100 bars atmospheric and the evolution of field pressures

and flow rates during the period were noted.


Fig 3.1: Well Architecture: Natural Depletion from Wells PA2, PN2, PA1 and

PN1

Fig 3.2: FOPR, FOPT and FOE as a function of time for th e 4-well Natural

Depletion case


The figure above indicates a maximum oil recovery of 22% for this natural

depletion case. Also, the plateau production period peaks for only five years and

then declines to zero in seven years. Hence, natural depletion can neither

sustain production for the 15 years proposed for the project nor can recoveries

are maximized.

Moreover, the principle of profitable business is directly challenged as oil

production revenue will be insufficient to offset the huge investments required

for a project of this magnitude.Thus, the need for secondary and tertiary

recovery schemes arises as the field cannot be produced with a primary recovery

technique alone.

Further, a disparity was observed between the calculated and simulated value of

the maximum recovery. The recovery from the analytical calculations was 6%

while the recovery from the numerical simulation was 22%. This suggests that

there is a nearby aquifer that provided pressure support to the reservoir

Fig 3.3: Oil Production Rate as a Function of Time from Wells PA2, PA1, PN2

and PN1

From an analysis of the figure above, it was observed that well PA2 contributed

poorly to the total field production. This could be due to any or a combination

of the following reasons:


Improper well placement,

Proximity to a fault,

High positive skin

Completing the well in a water zone.

Well PA2 can either be shut off or converted into an injection well since it is a

poor producer. The latter was deemed a better economic decision as it ensured

the continuous use of the well to add value to the field. Hence, subsequent

simulations for the natural depletion case were done with PA2 shut while new

wells were drilled and brought on stream.

3.1.2 Effect of Critical Gas Saturation

To study the effect of critical gas saturation on field productivity, the critical gas

saturation was increased from 0%, as was used in the previous cases, to 10%. The

implication of setting the critical gas saturation to 0% is that gas begins to

evolve from solution throughout the reservoir as soon as the reservoir pressure

depletes to a level that is below the bubble point pressure of the oil. This leads

to an increase in gas-oil ration and a subsequent decrease in oil productivity.

Fig 3.4: Comparing the Field Recovery Efficiency and Field Plateau

Production Rate for both cases


Higher recoveries and longer plateaus were recorded for the simulation case

with a critical gas saturation of 10%. There was an increase in total recovery from

22% to 26% and the time required for production to terminate increased by one

year.

Fig 3.5: Comparing the Field Pressure and Total Field Production Volume for

both cases

By increasing the critical gas saturation to 10%, the field total production

increased from 8MMm3 to 9MMm3 and an additional year was required for the

reservoir to deplete to the bottom hole flowing pressure limit of 100bars.

As with the previous graphs, the new case gave better results. In contrast with

the previous case, an extra year was required for the field water cut to attain its

maximum value and an additional 18 months was required for the field gas-oil

ratio to attain its peak. From the results above, it can be confidently inferred

that recovery is improved when dissolved gases stay longer in solution as gas

mobility is delayed to obtain better oil recoveries. Hence, subsequent simulation

cases will be done with the critical gas saturation set to 10%.


Fig 3.6: Comparing the Field Water Cut and Field Gas-Oil Ratio for both

cases

3.1.3 Natural Depletion with Increased Development Wells:

The need to drill added development wells arises as a result of the fact that the

three available wells are inadequate to optimally drain the field of its oil

resources. Economics plays a major role here as drilling of new wells represents a

major portion of capital expenditures. Thus, the number of new wells to be

drilled should be optimized to obtain maximal recovery from the field.

3.1.3.1 Natural Depletion with Five Producer Wells

The minimum number of production wells, as computed through the hand

calculations, was 5 wells. Well PA2 was shut in and two new wells, PB1 and PB2,

were drilled to increase recovery from the field. PB2 was drilled very close to the

shut-in PB1 and PB1 was drilled in an area with very high oil saturation.


Fig 3.7: Well Architecture: Natural Depletion with W ells PA1, PNI, PN2, PB2

and PA4

Fig 3.8: Natural Depletion with 5 Producers: FOE, FOPT and FOPR as a

function of time

For the 5-well case, FOPR peaked for 6 years in contrast with the 4-well case in

which FOPR peaked for only 5 years. Field Oil Recovery also increased from 26%

to 30%.


Fig 3.9: Natural Depletion with 5 Producers: FPR, FOE, F WCT, FGOR as a

function of time

Fig 3.10: Well by Well Analysis: Individual Oil Well Production Rate as a

function of time


3.1.4 Inferences: Natural Depletion

From the simulations and optimizations done thus, we came up with the

following inferences:

Ultimate Oil Recovery:

The oil recovery obtained from the different simulation runs is shown on

the bar chart displayed above. EUR from the natural depletion varied from 20%

to about 30%. The highest recovery (30%) was obtained by depleting the

reservoir naturally with 7 wells while shutting well A2. The low recovery from

this type of reservoirs suggests that large quantities of oil remain in the reservoir

and the reservoir pressure dropped very much for this low recovery. This

naturally depleted reservoir will be considered a good candidate for secondary

recovery applications such as water injection as well as gas.

Reservoir pressure:

The reservoir pressure declined rapidly and continuously. This reservoir

pressure behaviour is attributed to the fact that no extraneous fluids or gas caps

are available to provide a replacement of the gas and oil withdrawals. There is

no voidage replacement no sweep provision for the hydrocarbon.

Water production:

There was considerable water production with the oil during the entire

producing life of the reservoir. This is due to the presence of an active water

drive.

Gas-oil ratio:

This natural depletion is characterized by a rapidly increasing gas-oil ratio from

all the wells, regardless of their structural position. After the reservoir pressure

has been reduced below the bubble-point pressure, gas evolves from solution

throughout the reservoir. Once the gas saturation exceeds the critical gas

saturation, free gas begins to flow toward the wellbore and gas-oil ratio

increases.


3.2: Case 2: Water Injection Preceded by Natural Depletion

In many cases, water injection has traditionally used in the oil industry for

pressure maintenance. It is usually used to maintain pressure above the bubble

point pressure and in some cases, to pressurize the reservoir to the bubble point

pressure. By simulation for water injection, water is pumped or injected into the

reservoir to maintain pressure and expel oil in the pore spaces. This water

displaces this resident oil and pushes them towards the producing wells in that

manner so as to maintain pressure and achieve improved recovery.

In this water injection simulation case, the desire was to maintain the average

reservoir pressure at 290 bars. Hence, the field was naturally depleted from 490

bars to 290 bars and water injection was initiated at this instance. Well PA2, the

poor producer well, was converted to an injector well. Four additional wells were

then drilled to serve as injection wells.

Due to the fact that oil could be recovered as a result of the water injection

sweep, two extra producer wells were drilled. This gave a total of 7 producers

and five injector wells.


Fig 3.11: Well Architecture: 7 producers and 5 injectors. We ll PA2 is an

injection well


Fig 3.12: Water Injection: FOPR, FOE and FOPT as a function of time

As predicted, the recovery efficiency increased with the water injection scheme.

The recovery efficiency increased astronomically from 30%, as obtained with

natural depletion to 52%. The maximum oil production of 7200m3/day could be

sustained for four years and the production constraint of a keeping the plateau

for a 60% of the Estimated Ultimate Recovery could be met.

Also, the total oil production rose steadily and finally peaked at 18MMm3 in 14

years.


Fig 3.13: Water Injection: FPR, FWCT and FWIR as a function of time

Since the oil production was done at a pressure above oil bubble point pressure,

the FGOR remained constant at a value of 0.2m3/m3. Reservoir pressure dropped

steadily from initial reservoir pressure to 296 bars and started rising at the start

of water injection. Field pressure rose very slowly from 296 bars to a final value

of 312 bars in 14 years.

The water injection wells were opened in the 16th month after the start of oil

production. Water injection was done mostly in the Tarbert region. For this 7-

well case, the water injection rate increased rapidly at the time of injection in

order to compensate for voidage already created before injection. Injection rate

then dropped gradually as the plateau rate (oil production) dropped too. The

average reservoir pressure was maintained above 300 bars as it gently rose. The

water cut also increased as the plateau rate was dropping which indicated that

the injected water has broken through and then being produced.


3.3 Case 3: Gas Injection Preceded by Natural Depletion

This was simulated by re-defining the water injection wells as gas injection wells.

Gas was then injected into the reservoir when the reservoir pressure had

dropped to 290bars because the injected gas is most soluble in the oil at that

pressure.

Fig 3.14: Gas Injection: FOPR, FOE and FOPT as a function of time

The FOPR plateau at 7200m3 could only be sustained for 4 years and total oil

recovery was 15 million cubic metres of oil. FOE dropped to 42% as against 52%

that was obtained with water injection


Fig 3.15: Water Injection: FPR, FWCT and FWIR as a function of time

From the production profile of the four wells case, proposed pressure

maintenance at 340 bars wasnt as successful as desired. But however, the rate of

pressure decline around 340 bars reduced for a while, it then reduced gradually

from 340 bars at 300 days to 290 bars at 4 years where it was then maintained

continuously.

Since the field oil recovery dropped by using gas injection, there are still

bypassed oil that were not recovered. This makes only the gas injection not very

suitable on an absolute scale, hence the need for combination with water.

3.4 Case 4: Water- Alternating Gas Injection

In this secondary recovery scheme, the reservoir was allowed to deplete to a

predetermined pressure after which water and gas were alternately injected.

Water-alternating gas schemes have proven very effective for secondary recovery

as gas injection schemes result in viscous fingering and reduced sweep


efficiency. In WAG schemes, the injected water displaces the oil in the high

permeability layers while the gas displaces the oil in the low permeability zones.

Water is injected into the reservoir for a period of say two years with the same

conditions required for ordinary water injection. The water pumps are then shut

off and the gas compressors are started for injection of gas into the reservoir

through the same injection wells for a shorter duration. The duration of the

water and gas injections are continuously altered until favourable results are

obtained.

Four WAG cycles were considered:

Sub case 1: 2.5 years of water injection - 6 months of gas injection - 1.5

years of water injection - 6 months of gas injection-water injection.

Sub case 2: 32 months of water injection - 6 months of gas injection - 2

years of water injection - 6 months of gas injection - 18 months of water

injection-3 months of gas injection - 12 months of water injection - 3

months of gas injection - 12 months of water injection - 3 months of gas

injection - water injection

Sub case 3: 2.5 years of water injection - 6 months of gas injection - 2 years

of water injection - 6 months of gas injection - 2 years of water injection -

6 months of gas injection - 2 years of water injection - 6 months of gas

injection - 2 years of water injection - 6 months of gas injection -water

injection.

Sub case 4: 5 years of water injection-6 months of gas injection-2 years of

water injection-6 months of gas injection-2 years of gas injection-6 months

of gas injection-2 years of water injection-6 months of gas injection-water

injection.

The results are presented below:


Fig 3.16: Sub-case 1: FOPT, FOE, FOPR, FWIR and FOPR as a function of time

Fig 3.17: Sub case 2: FOPR, FOPT, FOE, FWIR and FPR as a function of time.


Fig 3.18: Sub case 3: FOPR, FOPT, FOE, FWIR and FPR as a function of time

Fig 3.19: Sub case 4: FOPR, FOPT, FOE, FWIR and FPR as a function of time


Sub-case 3 was the most effective as it had the highest field oil recovery of 55%.

Sub-cases 1, 2 and 4 had field oil recoveries of 54%, 54.5% and 52 % respectively.

The pressure maintenance was effective around 350 bars and the decline in

plateau rate was gradual over time. The field gas oil ration rose gently over the

production period while the water cut rose steeply during the plateau

production and then unnoticeable slowly during the decline period.

There was fluctuation in the producing gas-oil ratio during the life of the

reservoir due to the alternating injection of water and gas with FGOR highest

during years of gas injection.

In conclusion, compared to the water injection case, WAG showed an overall

increase in FOE, FOPR, reduction in FWCT and better pressure maintenance.

Table 3.1: Comparison of WI and WAG

CASE

FOE (%)

FOPT (MM

Sm3)

FWCT (%) PLATEAU

(Years)

FPR

(Bar)

WI 50 18.30 85 3.8 310

WAG 55 18.75 80 4.2 350

WAG has a higher total oil production with reduced water production and

better pressure maintenance than the water injection scheme. This is due to the

fact that injecting gas; reduces the viscosity of oil which improves the sweep,

reduces the amount of injected water/water cut. WI exhibited a longer plateau


CHAPTER FOUR

ECONOMIC ANALYSIS

The oil and gas business aims to maximize profitability of any prospect while

minimizing expenditures and associated uncertainties/risks, within a shorter

time frame. Hence, a key parameter for the justification of any petroleum

business is its economic viability.

The goal of this reservoir simulation project is to propose a development plan

for the Brent East reservoir that maximizes hydrocarbon production and

minimizes the development cost in $/bbl. In the previous chapter, the optimized

development cases for the different development scenarios were determined

after rigorous numerical simulations. This chapter will therefore, deal with the

economic evaluation of those optimal development options for the ALWYN

field.

The capital costs, operating costs, gross revenues, pay-back time and other

profitability indices will be determined for each of the development strategies

that were optimised in the previous chapter. The final project decision will then

be based on the economic evaluation results.

The following assumptions were made in the evaluation:

Oil price is pegged at $110/bbl.

OPEX is limited to the lifting, transportation and distribution costs only.

Other components of the operating expenditure that are based on

specific activities anticipated in the lifetime of the field were not

considered.

The already existing wells come at zero cost. They will be neglected in

the computation of the CAPEX

The cost of water and gas volumes used for the injection cases, as well as

their supportive surface handling equipment, was ignored.

Taxation costs is 40% of gross revenue

Maintenance costs, replacement costs, manpower costs,

decommissioning and well work over expenditures were not considered


On-stream time was 7884 hours per year

The economic analysis will be based on the field development capital

and operating costs that were given in the November 2011 edition of the

Journal of Petroleum Technology

CAPEX

Treatment and Production Facilities Platform 700MM$

Drilling and Accommodation Platform 250MM$

Secondary Platform 250MM$

Drilling Cost per well for deviated wells from a platform 12MM$

Gas compressors 44.2MM$

OPEX

Lifting, Production and Transportation costs 6.5$/bbl

The following computed parameters were used to evaluate the profitability of

the different scenarios:

Revenue = Selling Price of oil x Volume of Produced Oil

Total CAPEX = Cost of drilling and accommodation facilities + Cost of

Production facilities

Total OPEX= Lifting costs x Volume of Produced oil

Depreciation = CAPEX/ Project life

Taxable Income= Gross Revenue Depreciation - Operating Expenses

Project tax bill = Taxation Rate x Taxable Income

Cash Flow = Revenue Investment - OPEX- Tax bill Discounted Factor = (1 + i) n

Discounted Cash Flow = Discount Factor x Cash Flow

Net Present Value = Cumulative NPV each year.

Gross Profit Margin = Gross Revenue Total Investment Costs

GPM per barrel = GPM/ Total Production

Profitability Index = Final CNPV/Total Investment

Pay Back Period = Time at CNPV is 0


Internal Rate of Return, IRR = D.F at CNPV is 0

4.1 Economic Evaluation of Natural Depletion at Economic Limit

The natural depletion case represents the simplest and cheapest production

strategy. Production commences as soon as the production and treatment

facilities have been set up and no extra wells have to be drilled. Oil production

from the four available injection wells totalled 67.33 million barrels with a

recovery efficiency of 30%.

Table 4.1 Revenues and Expenditures for Natural Depletion

CAPITAL EXPENDITURE

Units/Cost

per barrel

Unit

Cost

in

MM$

Total Cost in

MM$

Treatment and Production

Facilities 1 700 700

Drilling and Accomm0dation

Platform with 40 Platform slots 1 250 250

Drilling Cost for Horizontal Wells 0 16 0

Drilling cost for Deviated/Vertical

Wells 2 12 24

Horizontal Subsea Well and Piping 0 40 0

Vertical Subsea well and Piping 0 36 0

Gas Injection Compressors 0 44.2 0

Total Capital Investment 974 974

OPERATING EXPENDITURE

Production and Transportation

Costs 67.33 6.5 437.6

TOTAL EXPENDITURE 1411.6 1411.6

Total Expenditure per barrel 20.96539433

PROFIT

Profit per barrel 89.03460567

Gross Profit Margin in MM$ 5994.7 5994.7


Table 4.2 Economic Evaluation Indices for Natural Depletion

NATURAL DEPLETION

Total Oil Production in MMbbls 67.33

Total Investment in MM$ 724

Gross Revenue in MM$ 7406.3

Gross Profit Margin in MM$ 5994.7

Gross Profit Margin per barrel in MM$ 92.75

Profitability Factor 1.975138122

Cummulative Net Present value in MM$ 1430

Internal rate of Return in % 40%

Pay back Period 2.8 years

Project's Economic Life 9 years

With a gross profit of $5.99 billion dollars, over a fifteen year period, from a total

expenditure of 974 million dollars, this seems to be a very sound investment

strategy. For every barrel of oil produced, a gross profit of $89 is to be made.

Investors should also drool at the fact that the initial capital investments would

be recovered after only 2.7 years. Cumulative Net Present value stands at a

staggering 1.43 billion dollars and the profitability factor is 1.97.

The financial soundness of this production strategy is also backed by other

profitability indices. The internal rate of return is 42% which is far greater than

the projects rate of return.


Fig4.1 Cash flow curve for Natural Depletion Scheme

However, the short economic life of the project might want to deter investors

from backing this option. The project is only economic for 9 years out of the 15

years that it is expected to run. The cash flow is fairly constant at 500 million

dollars for the first six years and peaks at 580 million dollars in the seventh year.

Economic decline sets in after the seventh year as cash flow is at the end of the

8th and 9th is 419 MM$ and 41 MM$ respectively. The project is no longer

economically viable after the 9th year.

At face value, this is profitable for any investor but the short economic life

represents a drawback.

Other development strategies will have to be evaluated to determine the most

profitable development option based on basic assumptions, available constraints

and data.

4.2 Economic Evaluation of Gas Injection Scheme at Economic Limit

The gas injection scheme consists of seven producers (four new wells) and five

injectors (four new wells) as well as the associated treatment and production

systems. A very expensive gas compressor is also installed on-site to facilitate the

injection of the gas at the required pressure. The gas injection strategy led to the

-1200

-1000

-800

-600

-400

-200

0

200

400

600

800

0 2 4 6 8 10

Cash flow in MM$

Time in years

Cash Flow for Natural Depletion

Cash Flow


production of 92.25 million barrels with a recover

dynamic reservoir simulation of the alwyn field using eclipse

Documents

field water

water injection wells

time water injection

injecting water

high water

field oil production

field oil recovery

production plateau