enhanced oil recovery for norne field

130 Pages·2012·7.02 MB·English

by  Kazeem Adetayo Awolola

ENHANCED OIL RECOVERY FOR NORNE
FIELD (STATOIL) C-SEGMENT USING
ALKALINE-SURFACTANT-POLYMER
FLOODING
Kazeem Adetayo Awolola
Petroleum Engineering
Submission date: July 2012
Supervisor: Jon Kleppe, IPT
Norwegian University of Science and Technology
Department of Petroleum Engineering and Applied Geophysics

ENHANCED OIL RECOVERY FOR NORNE FIELD (STATOIL) C-SEGMENT
USING ALKALINE-SURFACTANT-POLYMER FLOODING.

MASTER THESIS

BY

KAZEEM ADETAYO AWOLOLA

(JULY, 2012)

SUPERVISOR: PROFESSOR JON KLEPPE

DEPARTMENT OF PETROLEUM ENGINEERING AND APPLIED GEOPHYSICS

TRONDHEIM, NORWAY

1
DISCLAIMER
All ideas expressed in this thesis work are my opinions and do not necessarily reflect the
views of Statoil and the Norne field operating partners.

2
ABSTRACT
A great percentage of oil is observed to be left in the reservoir after the traditional primary
and secondary recovery methods. This oil is described as immobile oil. Alkaline-Surfactants
are chemicals used to reduce the interfacial tension between the involved fluids, while
polymer is used in making the immobile oil mobile.

Norne C-segment is in the decline stage and is facing considerable challenges regarding
volume of oil bye-passed due to water flooding. There is need for developing cost efficient
enhanced oil recovery (EOR) methods that would be suitable for Norne fluid and rock
properties and therefore improve sweep efficiency significantly. Based on literature and
screening criteria, alkaline-surfactant-polymer can be used as an enhancing agent to produce
extra oil and reduce water-cut significantly in the C-segment.

The objective of this work is to evaluate the possibilities of using alkaline, surfactant and/or
polymer to increase the oil recovery factor and prolong the production decline stage of Norne
field. An initial study was conducted using heterogeneous synthetic models (with Norne C-
segment fluids and rock properties) to assess the suitability of alkaline/surfactant/polymer
(ASP) flooding. All the chemical cases simulated gave substantial incremental oil production
and water-cut reduction.
However, history matched Norne C-segment reservoir model was used to simulate alkaline-
surfactant-polymer flooding using Eclipse 100. Appropriate chemical quantity for injection
was ascertained by simulating several cases with different concentration, injection length and
time of injection. Different sensitivity analyses were made and simulations revealed that the
most effective method was not the most profitable. Having established most profitable method
which was injecting ASP slug with a concentration of 7Kg/m3, 2Kg/m3 and 0.3Kg/m3 into
C-3H (injector) for 4-years in a cyclic manner, an incremental recovery factor of 2.61% was
recorded and Net Present Value (NPV) was calculated to be 1660 x103MNOK.

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ACKNOWLEDGEMENT
I hereby express my sincere appreciations to my supervisor, Professor Jon Kleppe and my co-
supervisor, Richard Rwenchugura, PhD (Integrated Operations Center) for their undiluted
advice and supports in writing this thesis. I also thank Mr. Jan Ivar Jensen for his numerous
helps on Eclipse simulator. Thanks to Dr. Nan Cheng (Statoil) for his technical advice
especially during my visit to Harstad. A big thank you to Professor Jan Age Stensen (SINTEF
Petroleum Research) for his unquantifiable helps and to Vegard Kjøsnes your contributions
and assistance on Eclipse simulator remain unforgettable.
I equally convey my profound gratitude to Statoil ASA and Center for Integrated Operations,
NTNU for making Norne field data available for study.

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NOMENCLATURE

Symbols

µ Viscosity
Bbl Barrel
B Oil formation volume factor
o
Cr Rock Compressibility
Dp Pressure Gradient
K Absolute Permeability
a
K Effective Permeability
eff
Kg Kilogram.
K Relative Permeability to Gas
rg
K Relative Permeability to Oil
ro
P Capillary Pressure
c
Q Volumetric Flow Rate
3
Sm Standard cubic meter
S Initial Oil Saturation
oi
S Residual Oil Saturation
or
S Irreducible Water Saturation
wi
T Temperature
USD United State Dollar
V Velocity
V Bulk Volume
b
V Pore Volume
p
ϴ Contact Angle
λ Mobility
ρ
Oil Density
o
σ Interfacial tension
Φ Porosity
Қ Permeability

Abbreviations

(1+r)t Discount Factor
2D Two-Dimensional
3D Three-Dimensional
AdC Polymer Adsorptive Capacity on the Rock
AIME American Institute of Mechanical Engineers
AS Alkaline Surfactant
ASP Alkaline Surfactant Polymer
BHP Bottom Hole Pressure
BSm3 Billion Standard Cubic-Meters
CA (C ) Adsorption Isotherm
surf
CAo Concentration of acid in Oil
CA Concentration of acid in Water
w
5
CDC Capillary Desaturation Curve
CMC Critical Micelar Concentration
CON Concentration
Cp Polymer Adsorbed
DX Grid thickness in x-direction
DY Grid thickness in y-direction
DZ Grid thickness in z-direction
E Areal Displacement Efficiency
A
E Displacement Efficiency
d
EIT Expert in Team
EOR Enhanced Oil Recovery
E Vertical Displacement Efficiency
V
F Permeability Reduction Factor
kr
Fo Fractional flow of Oil
FOE Field Oil Efficiency
FPSO Floating Production Storage and Offloading
FVF Formation Volume Factor
GOC Gas Oil Contact
GOE Group Oil Efficiency
GOR Gas Oil Ratio
GTADSUR Group Total Surfactant Adsorption
GTPTSUR Group Total Surfactant Production
GTPTSUR Group Total Surfactant Production
HEC Hydroxyl Ethyl Cellulose
HPAM
IFT Interfacial Tension
IOC Centre for Integrated Operations
IPT Institute of Petroleum Technology
K Partition Coefficient
n
K Rock Permeability when Aqueous Polymer Solution Flows
p
Kw Rock Permeability when Water Flows
LS Low Salinity
LSW Low Salinity Water
LSWF Low Salinity Water Flooding
M Mobility Ratio
MD Rock Mass Density
MEOR Microbial Enhanced Oil Recovery
MNOK Million Norwegian Kroner
MSm3 Million Standard Cubic-Meters
MultPV Multiply Pore Volume
Nc Capillary Number
NCF Net Cash Flow
NGL Natural Gas Liquid
NOK Norwegian Kroner
NPD Norwegian Petroleum Directorate
NPV Net Present Value
NTNU Norwegian University of Science and Technology
OGIP Original Gas in Place
6
OOIP Original Oil in Place
OWC Oil Water Contact
P V Pore Volume
or
PV Present Value
PVT Pressure Volume Temperature
ROS Remaining Oil Saturation
SAGD Steam Assisted Gravity Drainage
SCM Standard Cubic Metre
SP Surfactant Polymer
SPE Society of Petroleum Engineers
SUR Surfactant
V Pore Velocity
WAG Water Alternating Gas
σ
Interfacial tension between Oil and Substrate
os
σ
Interfacial Tension between Oil and Water
ow
σ
Interfacial Tension between Water and Substrate
WS

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Table of Contents
DISCLAIMER ........................................................................................................................... 2

ABSTRACT ............................................................................................................................... 3

ACKNOWLEDGEMENT ......................................................................................................... 4

NOMENCLATURE ................................................................................................................... 5

TABLE OF CONTENTS ........................................................................................................... 8

1.0 INTRODUCTION ............................................................................................................ 16

1.1 Background .................................................................................................................................. 16

1.2 Objective of Study ....................................................................................................................... 17

1.3 Methodology ................................................................................................................................ 17

2.0 LITERATURE REVIEW ................................................................................................ 19

2.1 Enhanced Oil Recovery Methods ................................................................................................ 19

2.2 Classification of Enhanced Oil Recovery Methods ..................................................................... 19

2.2.1
 Chemical
 Processes
 ............................................................................................................
 20

2.2.2
 Mobility-­‐Controlled
 Processes
 ...........................................................................................
 20

2.2.3
 Low-­‐Salinity
 Water
 Flooding
 ..............................................................................................
 20

2.2.4
 Micelar
 Flooding
 ................................................................................................................
 20

2.2.5
 Microbial
 (MEOR)
 ...............................................................................................................
 21

2.2.6
 Miscible
 Processes
 .............................................................................................................
 21

2.2.7
 Miscible
 Slug
 Process
 .........................................................................................................
 21

2.2.8
 Condensing
 Gas
 Drive
 ........................................................................................................
 21

2.2.9
 Vaporizing
 Gas
 Drive
 .........................................................................................................
 21

2.2.10
 Gas
 Injection
 ....................................................................................................................
 21

2.3 Previous Works on ASP Flooding ............................................................................................... 21

2.4 Principles of Improved Recovery ................................................................................................ 22

2.4.1
 Mobilization
 of
 Remaining
 Oil
 ............................................................................................
 22

2.4.2
 Reservoir
 Rhythmicity
 ........................................................................................................
 23

2.4.3
 Mobility
 Ratio
 .....................................................................................................................
 23

2.4.4
 Capillary
 Number
 ...............................................................................................................
 24

2.4.5
 Dispersion
 of
 Chemicals
 .....................................................................................................
 24

2.4.6
 Displacement
 Efficiency
 .....................................................................................................
 24

2.4.7
 Chemical
 Adsorption
 ..........................................................................................................
 24

2.4.8
 Areal
 Sweep
 Efficiency
 .......................................................................................................
 24

2.4.9
 Contact
 Factor
 ....................................................................................................................
 24

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