file - Center for Integrated Operations in the Petroleum

Evaluation of Polymer Flooding for
Enhanced Oil Recovery in the Norne Field
E-Segment
Pasha Huseynli
Petroleum Engineering
Submission date: June 2013
Supervisor:
Jon Kleppe, IPT
Norwegian University of Science and Technology
Department of Petroleum Engineering and Applied Geophysics
NORWEGIAN UNIVERSITY OF SCIENCE AND TECHNOLOGY
DEPARTMENT OF PETROLEUM ENGINEERING AND
APPLIED GEOPHYSICS
MASTER THESIS
Evaluation of Polymer Flooding for Enhanced Oil
Recovery in the Norne Field E-Segment
SUPERVISOR: PROFESSOR, JON KLEPPE
STUDENT: PASHA HUSEYNLI
JUNE, 2013
Acknowledgements
I would like to express my sincere gratitude to my supervisor, Professor Jon Kleppe, for support
and guidance he has provided during this work. I would also like to thank Mehran Namani (PhD
Scholar) and Jan Ivar Jensen (NTNU) for their technical assistance and recommendations.
I would also like to extend my appreciation to Statoil and SINTEF for providing me with Norne
field data and chemical properties, and advises through email.
My sincere appreciation is extended to all Professors and staff of IPT, SINTEF, NTNU, for their
immeasurable amount of help.
I am also thankful to my family for giving me the chance to follow my dreams and the love to
make them a reality.
Trondheim, June 2013
Pasha Huseynli
ii
Summary
Nowadays various recovery methods like water flooding; gas flooding and etc. are widely used
in petroleum industry in order to increase hydrocarbon production as much as possible. Despite
the fact water flooding is the main technology for maintaining reservoir pressure and enhancing
oil production rate, this technology allows us to recover up to 10-40% of original oil from the
fields. The rest amount of oil is divided into two categories: the remaining oil beyond water
flooding process and bypassed oil.
The purpose of this research is to examine efficiency of polymer flooding for improved oil
recovery for Norne field E-segment by doing the simulation study on the black oil reservoir
model.
Firstly, by using Schlumberger’s software Eclipse 100, history matching was performed on the
Norne Field E-segment. The history matching was done by adjusting base reservoir model
properties, changing the shape of relative permeability curve, skin factor and KH values of
production wells. The best possible history match was gained after applying all modifications
which are stated above.
Secondly, before doing field scale enhanced oil recovery research, polymer flooding was
simulated and analyzed on three dimensional synthetic model which was built based on rock and
fluid properties of Norne field E-Segment. By assuming the model is flat and homogenous the oil
recovery with almost 9% was achieved.
In case of the E-Segment the injector well F-3H was chose for EOR study due to high residual
oil saturation around the well compare to F-2H. Two sensitivity analysis: chemical solution
concentration effect and injection rate effect were performed to evaluate the efficiency of
polymer flooding in E-Segment.
Due to the fact that the concentration of polymer was high (0.6 kg/m3) and injection rate low
(1000-3000 Sm3/day), polymer flooding didn’t give high oil production as it was forecasted. It
can be explained as a late introduction of polymer flooding in E-Segment where the mobile oil
saturation is low and aquifer mainly affects production profile, and minor increase in oil
production can be the result of a small effect of polymer in a close area to production wells.
The oil recovery increased in the range of 0.5-1% and it allows us conclude that with the
reservoir model on which the study was done; polymer flooding is not favorable for Norne field
E-Segment as Enhanced Oil Recovery methods.
iii
Table of Contents
Acknowledgements ....................................................................................................................................... ii
Summary ...................................................................................................................................................... iii
List of Figures ............................................................................................................................................... v
List of Tables .............................................................................................................................................. vii
1 Introduction ................................................................................................................................................ 8
2 Literature Review..................................................................................................................................... 11
2.1 Polymer Flooding.............................................................................................................................. 11
2.1.1 Mechanics of Polymer Flooding ................................................................................................ 11
2.1.2 Behavior of Polymer Solutions .................................................................................................. 15
2.1.3 Type of Polymers ....................................................................................................................... 20
2.1.4 Criteria for Polymer Flooding .................................................................................................... 22
2.2 Norne Field ....................................................................................................................................... 25
2.2.1 General Information ................................................................................................................... 25
2.2.2 Geology ...................................................................................................................................... 29
2.2.3 Norne Field E-Segment.............................................................................................................. 30
2.2.4 The Eclipse model of E-Segment............................................................................................... 30
3 Simulation Results and Discussion .......................................................................................................... 32
3.1 History Matching .............................................................................................................................. 32
3.2 Synthetic Model Simulation.............................................................................................................. 43
3.4 Polymer Flooding in Norne E-Segment ............................................................................................ 46
3.4.1 Polymer Concentration Effect .................................................................................................... 47
3.4.2 Injection Rate Effect .................................................................................................................. 51
Conclusions ................................................................................................................................................. 53
Recommendation ........................................................................................................................................ 54
References ................................................................................................................................................... 55
Appendix ..................................................................................................................................................... 57
A.Polymer Introduction in Eclipse Simulator ......................................................................................... 57
B.Eclipse Data File for Norne Field E-Segment ..................................................................................... 58
C.Polymer Input File............................................................................................................................... 81
iv
List of Figures
Figure 1: Viscosity criteria for EOR processes. .............................................................................................. 9
Figure 2: Depth criteria for EOR methods..................................................................................................... 9
Figure 3: Permeability criteria for EOR methods. ....................................................................................... 10
Figure 4: Remaining oil saturation after water and polymer flooding [5]. ................................................. 11
Figure 5: The effect of fingering in water and polymer flooding [4]. ......................................................... 12
Figure 6: Influence of viscosity ratio on oil recovery according to TUNN [7]. ............................................ 13
Figure 7: Viscosity Behavior of 500 ppm Polyacrylamide solution [9]. ....................................................... 14
Figure 8: Viscosity Behavior of 500 ppm solution of Xanthomonas polysaccharide. ................................. 14
Figure 9: The relationship between viscosity and shear rate at fixed salinity [11]. ................................... 16
Figure 10: Injected pore volume vs. concentration at outlet [7]. ............................................................... 17
Figure 11: Permeability reduction for different polymer solutions [13]. ................................................... 18
Figure 12: The effect of salinity on permeability reduction [13]. ............................................................... 19
Figure 13: Cellulose microfibrils .................................................................................................................. 21
Figure 14: Polymer Flood Project Evaluation and Development Process [16]. .......................................... 23
Figure 15: Polymer flooding process [17]. .................................................................................................. 24
Figure 16: Location of Norne Field [18]. ..................................................................................................... 25
Figure 17: The segments and wells of Norne field [18]. ............................................................................. 26
Figure 18: The profile of North-South Structure [19]. ................................................................................ 27
Figure 19: Cross-section of fluids contacts [18]. ......................................................................................... 28
Figure 20: Drainage Strategy for the Norne Field from Pre-start to 2014 [18]. ......................................... 28
Figure 21: Stratigraphical sub-division of the Norne reservoir [23] ........................................................... 29
Figure 22: The eclipse model of E-Segment................................................................................................ 31
Figure 23: Field Oil Production Rate for the model and history. ................................................................ 32
Figure 24: Field Water Production Rate for the model and history. .......................................................... 33
Figure 25: Field Gas Production Rate for the model and history................................................................ 33
Figure 26: Relative permeability curve of base case. ................................................................................. 34
Figure 27: Relative permeability curve after adjustment. .......................................................................... 35
Figure 28: Field Oil Production Rate after adjustment relative permeability curve. .................................. 35
Figure 29: Field Water Production Rate after adjustment relative permeability curve. ............................ 36
Figure 30: Field Gas Production Rate after adjustment relative permeability curve. ................................ 36
Figure 31: Oil Production Rate for well E-2H. ............................................................................................. 37
Figure 32: Oil Production Rate for well E-3AH. ........................................................................................... 38
Figure 33: Water Production Rate for well E-2H. ....................................................................................... 38
Figure 34: Water Production Rate for well E-3AH. ..................................................................................... 39
Figure 35: Oil Production Rate for well E-2H after changing skin and KH values. ...................................... 40
Figure 36: Oil Production Rate for well E-3AH after changing skin and KH values. .................................... 40
Figure 37: Water Production Rate for well E-2H after changing skin and KH values. ................................ 41
Figure 38: Water Production Rate for well E-3AH after changing skin and KH values. .............................. 41
v
Figure 39: Field Oil Production Rate after all modifications. ...................................................................... 42
Figure 40: Field Water Production Rate after all modifications. ................................................................ 42
Figure 41: Synthetic model. ........................................................................................................................ 43
Figure 42: Field Oil Recovery. ..................................................................................................................... 44
Figure 43: Oil Production Rate. ................................................................................................................... 44
Figure 44: Water Production Rate. ............................................................................................................. 45
Figure 45: Norne E-Segment. ...................................................................................................................... 46
Figure 46: Oil production rate at different polymer concentrations. ......................................................... 47
Figure 47: Water production rate at different polymer concentrations. ................................................... 48
Figure 48: Reservoir pressure at different polymer concentrations. ......................................................... 49
Figure 49: Bottom-hole pressure of injection well at different polymer concentrations. ......................... 49
Figure 50: Total polymer production at different polymer concentrations. .............................................. 50
Figure 51: Total oil production at different polymer concentrations. ........................................................ 50
Figure 52: Total oil production at different injection rates. ....................................................................... 51
Figure 53: Reservoir pressure at different injection rates. ......................................................................... 52
Figure 54: Reservoir pressure at different injection rates. ......................................................................... 52
vi
List of Tables
Table 1: Reservoir criteria for the polymer flood project [15].................................................................... 22
Table 2: NPD's estimates of recoverable and remaining reserves as of 31.12.2011 [20] .......................... 27
Table 3: Wells Status in the Norne field E-Segment ................................................................................... 30
Table 4: Characteristic Fluid Parameter for Norne Field E-Segment [24]................................................... 31
Table 5: Completion data for wells E-2H and E-3AH................................................................................... 39
vii
1 Introduction
Oil and gas production life of hydrocarbon fields are divided in several phases. In the initial
stage, oil and gas production from the reservoir occurs due to natural mechanisms. In the next
stage when the reservoir pressure is not enough for supporting the production from the
formations, water is injected in order to uphold the hydrocarbon production. The water flooding
is main driving mechanism for maintaining reservoir pressure because of availability and low
cost of injection fluid. But oil recovery in this flooding process is not high enough due to
following reasons [1]:
•
•
•
reservoir heterogeneity
problems related to the well siting and spacing
unfavorable mobility ratio
In the tertiary recovery stage (EOR), it is possible to recovery almost 30-60% of the field’s OOIP
(original oil in place) which is high compare to primary and secondary recovery methods where
recovery factor is equal to 20-40% [2]. The main types of EOR are:
•
•
•
•
Thermal recovery
Gas flooding
Chemical flooding
MIOR or Microbial IOR
Thermal recovery is an enhanced oil recovery method where steam or air is injected to the heavy
oil reservoirs to decrease the viscosity of oil. During this process the mobility ratio decreases and
oil flows towards production wells. This EOR method is widely used in unconventional oil fields
of Venezuela and Canada.
Gas flooding has been broadly used in oil industry. In gas injection process the interfacial tension
between water and oil reduces that leads better displacement efficiency. Carbon dioxide is main
injection fluid for this method due to its low cost and because it decreases oil viscosity.
Chemical flooding consists of two processes: polymer flooding and surfactant-polymer flooding
[3]. To produce oil that trapped in reservoir surfactants are injected and then polymer to decrease
the mobility ratio of oil and water which gives favorable volumetric sweep efficiency.
Microbial injection is not usual EOR method nowadays because of its high cost.
8
From figure 1, 2 and 3 it is observable that depth, permeability and viscosity are the key factors
that need to be considered and evaluated before applying enhanced oil recovery methods for
specific oil fields [1].
Figure 1: Viscosity criteria for EOR processes.
Figure 2: Depth criteria for EOR methods.
9
Figure 3: Permeability criteria for EOR methods.
10
2 Literature Review
2.1 Polymer Flooding
Polymer flooding is one of the chemical enhanced oil recovery methods and has been introduced
in late 1960s. In this chemical EOR method polymer is added to injected water in order to
increase injected fluid viscosity and to improve oil displacement in the reservoirs.
According to reports, the first commercially success was gained in Daqing oil field of China
where oil recovery factor increased up to 20% after applying polymer flooding technique [4].
After some successful projects, currently it is believed that polymer flooding can be profitable
EOR technique.
2.1.1 Mechanics of Polymer Flooding
The purpose of polymer flooding is improving sweep efficiency and consequently enhanced oil
recovery which is gained due to the following processes:



Increase in viscosity of injected fluid
Decrease in water and oil mobility ratio
Decrease in a volume of capillary trapped oil
All these processes lead higher oil recovery than water flood case. Figure 4 illustrates the result
of laboratory where clearly can be seen that polymer flooding is more efficient than water
flooding.
Figure 4: Remaining oil saturation after water and polymer flooding [5].
11
The reservoir key parameters of field, specifically, mobility ratio, effective porosity, permeability,
mobile oil saturation, volumetric sweep and etc. should be discussed in detail before starting any
project [6].
Mobility Ratio. Based on the study of DYES, CAUDLE and ERICSON (1954), the mobility
ratio is defined as:
(1)
M - mobility ratio
- relative permeability to water
- relative permeability to oil
- water viscosity
- oil viscosity
According to the equation of mobility ratio, a good displacement happens when the ration is
equal to one or less than one. Therefore to get low M, chemicals are added to injected fluid in
order to increase water viscosity with aim of to lower mobility factor.
The volumetric sweep efficiency is not good throughout water flooding and the main problem is
this recovery method is a fingering effect as shown in figure 5. But during polymer flooding,
sweep efficiency increases due to decreasing the effect of fingering compare to water flooding.
Figure 5: The effect of fingering in water and polymer flooding [4].
.
12
Figure 6 demonstrates the effect of viscosity ratio on oil recovery. It is clear that by increasing
the viscosity of displaced fluid, the oil recovery can be increased.
Figure 6: Influence of viscosity ratio on oil recovery according to TUNN [7].
Permeability. Permeability is a key parameter for polymer flooding. According to studies,
polymer flooding can be applied to field where permeability value is in the range of 20-2300mD
[8].
Effective porosity. It describes pores that are connected with other pores in rock where flow
occurs. The effective porosity also defines the recoverable hydrocarbon of reservoir and the
amount of chemical that will be needed for the polymer flooding
Initial water saturation. According to some studies the reservoirs with high water saturation are
not acceptable candidates for polymer flooding.
Water salinity. The water salinity has a great effect on mobility, adsorption and permeability
reduction features of polymers. Adding salt to polymer solutions leads to the change in shape of
molecules where its shape transforms from inflated to spherical form. Figures 7 and 8 show the
steep decrease in solution viscosity when 3% NaCl is added to polyacrylamides while in case of
Xanthan polysaccharide, added salt does have a big effect.
13
Figure 7: Viscosity Behavior of 500 ppm Polyacrylamide solution [9].
Figure 8: Viscosity Behavior of 500 ppm solution of Xanthomonas polysaccharide.
14
2.1.2 Behavior of Polymer Solutions
Viscosity. A characteristic of fluids that shows their resistance to shear stress or tensile stress. It
is specified as the ratio of the shear stress to the shear rate [10]. The relationship between these
parameters is described as,
̇
(2)
̇ (3)
- shear stress
– viscosity
̇ - velocity gradient or the shear rate
The unit of viscosity is the poise and because one poise signifies a high viscosity; centipoise is
mainly used for field measurements. A liquid’s viscosity depends on the flow velocity, the size
and shape of fluid atoms and the interactions between those atoms.
There are two types of fluids: Newtonian and non-Newtonian. Fluids which have non –
changeable viscosity value at different shear rate or relationship between shear rate and shear
stress can be shown by equation 3 are termed Newtonian fluid; fluids which have non constant
viscosity value at different shear rate are called non-Newtonian fluid. The experiments show that
the viscosity of polymer solution does not remain constant at various shear rates and therefore
polymers are categorized as the non-Newtonian fluid.
Figure 9 illustrates the experimental results where relationship between the viscosity of polymer
solution and shear rate was investigated [11]. According to the laboratory study, polymer
solution behaves as Newtonian fluid at low rate of deformation while at higher shear rate acts as
non-Newtonian fluid. And based on this experimental study, correlation between the viscosity of
polymer solution and the rate of deformation was defined as,
̇
- power-law coefficient
- exponent
15
(4)
Figure 9: The relationship between viscosity and shear rate at fixed salinity [11].
Polymer adsorption and retention. Adsorption or retention of polymer has a big effect on
flooding process. Based on previous studies, polymer adsorption depends on water salinity; as
salinity of water increases, the polymer adsorption rate also increases. It is desired to achieve
sufficient quantity for adsorption [7].
Inaccessible pore volume. During the polymer flooding chemicals do not occupy all the
effective pore volumes. This volume that is not occupied by polymers is called inaccessible pore
volume or IPV. Inaccessible pore volume is occupied by water with no polymer that leads to
change in polymer concentration. This process was studied and reported by Dawson and Lantz in
1972.
IPV is key parameter that needs to be studied due to it’s a great effect on reservoir performance.
Because the less contact with the rock surface compare to total pore volume will cause decrease
in quantity of chemical adsorption which consequently affect the efficiency of polymer flooding.
In the experiments, Littman observed that the velocity of polymer-mixed water in reservoir was
higher than the velocity of a tracer where polymer was injected and which was resulted in earlier
breakthrough in polymer than tracer (Figure 10). And this fact also proves that some of pore
volume is inaccessible to the chemicals.
16
Figure 10: Injected pore volume vs. concentration at outlet [7].
Permeability reduction.
The polymer adsorption causes to the reduction of porous media ( ) or decrease in the volume
interacted pores which can lead to no flow [8]. The permeability reduction can be defined as the
ratio of water to polymer solution at same flowing condition:
(5)
- permeability reduction
- permeability of water
- permeability of polymer
17
The shear rate, the molecular weight of polymer solution, the polymer type and pore structure
can affect permeability reduction [12].
Figure 11 shows the result of experiment where the relationship between
and polymer
concentration was studied. Based on the graph, it was concluded that the permeability reduction
and concentration of associative polymer solution have nearly linear relationship. The
permeability reduction is also sensitive to salinity. The effect of salinity was investigated by
adding 2 wt% NaCl and 10 wt% NaCl to the polymer solution. It was founded that by increasing
the salinity of the conventional and associative polymer, the permeability reduction decreases
because of its lower viscosity [13].
Figure 11: Permeability reduction for different polymer solutions [13].
18
Figure 12: The effect of salinity on permeability reduction [13].
19
2.1.3 Type of Polymers
Polymers used in enhanced oil recovery methods are divided into two groups: synthetic polymers
and biopolymers.
Synthetic polymers.
This is a type of polymers that are produced synthetically and polyacrylamide - water soluble
polymers are the one of the widely used synthetic polymers for EOR. Polyacrylamides can be in
various forms: in liquid phase, gels, powder and so on.
Biopolymers.
Biopolymers are formed by living organisms. The molecular weight and structure of
biopolymers are smaller than synthetic polymers. Therefore it gives hardness that causes a good
viscosifying effect in salinity water and a bad viscosifying effect in fresh water [14].
In the late 80-ties, Statoil was involved in a large project with a biopolymer called Xanthan. It is
a polysaccharide secreted by the bacteria Xanthomonas campestris. It is an anionic polymer with
tolerance for salinity and fair tolerance for hardness ion temperature tolerance varies with waterphase components, but starts to degrade around 93 to121°C. It is susceptible to bacterial attack
and does not tolerate extreme pH20. Even though very promising, Xanthan was found not
profitable at that time. [15]
One of the possible new areas of application for debris from the paper and pulp industry can be
polymers. Three kinds of polymers are present in wood: cellulose, hemicelluloses and lignin.
Cellulose is the framework polymer, comprising 40-50% of wood; whereas hemicelluloses and
lignin are the matrix substances present between cellulose microfibrils.
Cellulose microfibrils constitute layers (lamellas) which form the cellulose fiber as can be seen
in Figure 13. The microfibrils consist of 20-100 cellulose chains organized more or less in
parallel. The degree of parallel orientation of the cellulose chains is termed crystal Unity. The
cellulose chains consist of 5-10 000 glucose monomer units which give the microfibrils a high
aspect ratio (length/diameter =L/D). The microfibrils are 1-50 nm thick and may have an aspect
ratio of more than 100.
20
Figure 13: Cellulose microfibrils
A: Wood structure, B: Microfibrils, C: Bundle of microfibrils, D: Single microfibril, E:
Crystallite cellulose, F: Crystallite cellulose cell, G: Repeating cellulose unit.
These types of polymers have many beneficial properties. They are generally strong, hydrophilic,
and insoluble in water, stable to chemicals, generally recognized as safe to living creates,
renewable, recyclable, and easily available.
21
2.1.4 Criteria for Polymer Flooding
In order to find appropriate reservoir candidate for polymer flooding several parameters have to
be evaluated. Table 1 demonstrates basic screening criteria for polymer flooding. One oil field
that matched to these criteria is Daqing field where the incremental oil recovery about 200
MMSTB was achieved due to polymer flooding [14].
Properties
Standard
Oil Viscosity
From 10 to 3000 cp
Temperature
up to 120°C
Permeability
10 md to 10 Darcy
Reservoirs
sandstone (preferred)
Oil gravity
>15° APl
Salinity
< 250,000 TDS
Oil saturation
>50%
Water injectvity
Good
Table 1: Reservoir criteria for the polymer flood project [15].
The oil field in which oil recovery is low and the water production is high, the commercial
performance of hydrocarbon production is not good.
22
In 2007 Kaminsky et al. proposed the schematic of processes for the appraisal and development
of polymer flood projects (Figure 14).
The first step is the screening of reservoir where reservoir geometry and fluid, rock features are
studied due to the passing criteria. If the properties of suggested reservoir are matched with the
screening criteria, further deep investigations like modeling, laboratory works, and reservoir
specification can be considered. Eventually these phases result in a technical-economical
evaluation.
The next phase is to determine targets and structure the pilot test. After successful study on pilot
test, the profitable scenario is developed and improved; this involves field scale modeling and an
operation strategy that examines realization, observation and operations.
Figure 14: Polymer Flood Project Evaluation and Development Process [16].
23
Based on the literature, there are two fundamental arguments for employing the selection rules
[8]:
• Find reservoirs with high mobility ratio and poor volumetric sweep efficiency
• Define if the properties of reservoir meet the screening criteria for polymer flooding.
Figure 15 shows the process of polymer flooding. The process starts with injecting low salinity
water, followed by the polymer injection at appropriate concentration. The last stage is injecting
the water in order to push the chemical into the reservoir.
Figure 15: Polymer flooding process [17].
24
2.2 Norne Field
2.2.1 General Information
The Norne oil field is found in Norwegian Sea, 200 km from the Norwegian shore and 85 km
from the nearby oil field - Heidrun. The field is located on the blocks 6608/10 and 6508/1 where
the water depth is almost 380 m. The figure 16 illustrates the location of the Norne field compare
to other fields of the Norwegian Sea.
Figure 16: Location of Norne Field [18].
25
There are two separate oil compartments in the Norne field:
•
•
The C, D and E segments – Norne Main Structure, discovered in 1991 and contain nearly
96% OIIP (oil in place)
Norne G-Segment (Figure 17)
Figure 17: The segments and wells of Norne field [18].
The Norne main structure is relatively flat contains 110 m oil thickness in the formations Tofte
and Ile, gas cap in the Garn formation above the Not formation shale and acts as a barrier. This
was proved by studies that there is no communication between formations across Not shale
formation (Figure 18).
26
Figure 18: The profile of North-South Structure [19].
The type of wells of Norne field is horizontal and the first well was drilled in 1996. The oil
production started in 1997 and water injection was only drive mechanism for maintaining the
reservoir pressure. Re-injecting produced gas was also used to maintain the pressure of
formations but as a result of later researches this process was ceased in 2005 because of no
communication between the Garn and Ile formations and injected to water zone in order to
prevent early gas breakthrough (Figure 19&20).
The table 2 shows the total hydrocarbon production, estimated recoverable and remaining
reserves to 31st of December 2011 (Norwegian share).
Table 2: NPD's estimates of recoverable and remaining reserves as of 31.12.2011 [20]
27
Figure 19: Cross-section of fluids contacts [18].
Figure 20: Drainage Strategy for the Norne Field from Pre-start to 2014 [18].
28
2.2.2 Geology
The reservoir rock of Norne field is categorized by sandstones that are located at a depth of
2500-2700 m and affected by diagenesis which causes the reduction in reservoir rock quality
because of mechanical compaction. The porosity of field is approximately 25-30% while the
permeability is 20-2500 mD [21].
The reservoir consists of two main groups the FANGST which consists of the Garn, Not and Ile
formations and the BÅT which includes the ROR, Tofte, Tilje and Åre formations and these
formations comprises sub formations (Figure 21) [22].
Figure 21: Stratigraphical sub-division of the Norne reservoir [23]
29
2.2.3 Norne Field E-Segment
The Norne E-Segment is also a part of Norne main structure; Tofte and Ile are main formations
of it because of nearly 80% of oil in the field contained in these formations. There is no
communication between E-Segment and the rest parts of field based on assumption of constant
flux boundary that means no quantity difference between the fluid inflow and outflow of
segment.
According to the eclipse model of field there are 5 wells in the Norne field E-Segments (Table
3).
Table 3: Wells Status in the Norne field E-Segment
2.2.4 The eclipse model of E-Segment
The Norne field E-Segment is was modeled with non-vertical faults in Eclipse 100. The model is
a fully implicit, three dimensional, three phase black oil. The reservoir model has 46 grids in the
X-direction, 112 in the Y-direction and 22 layers and each reservoir zone is signified by a layer,
for instance, the layers 5-11 embody the Ile and the layers 12-18 represent the Tofte. The
simulation starts from 1997 and the historical data are available until December 2004.
Table 4 gives some Norne field E-Segment’s fluid properties while Figure 22 shows the
coarsened simulation model of Norne Field E-segment.
30
Table 4: Characteristic Fluid Parameter for Norne Field E-Segment [24]
Figure 22: The eclipse model of E-Segment
31
3 Simulation Results and Discussion
3.1 History Matching
In order to simulate future reservoir performance, we need to have the history matched reservoir
simulation model. The procedure of adjusting the model input data until getting the minimum
difference between the performance of the model and the history of a reservoir is termed history
matching.
The process is a crucial study to verify the reservoir rock and fluids specification throughout
model building. There is usually the limited quantity of historical data presented to characterize a
hydrocarbon reservoir. Therefore we have to get a very accurate history matched model which
we can use in making predictions.
Few decades ago, we were used to create a single model, adjust it and perform single predictions
for numerous cases due to cost, computers, methods and time restrictions. But nowadays because
of developed technology it is possible to build, evaluate more models and use them for various
prediction scenarios.
The history matching can be done automatically but the many petroleum engineers prefer to do it
manually by reason of restrictions and cost of today’s existing automatic techniques. For this
study I have done traditional (manual) history matching.
Figure 23: Field Oil Production Rate for the model and history.
32
Figures 23, 24 and 25 show the difference between the reservoir simulation model and history
data.
Figure 24: Field Water Production Rate for the model and history.
Figure 25: Field Gas Production Rate for the model and history.
33
The figures above show that there is deference between actual field data and reservoir model
data, and in order to make accurate future EOR study we need to minimize the gap between real
and model data.
For the history matching procedure used key parameters are:





Relative Permeability Of Oil to Water
Transmissibility factor
Adding an Aquifer
Skin factor
KH values around the production wells
The original case of relative permeability is shown in figure 26. The possible best matching was
gained by modifying the shape of relative permeability curve which is shown in figure 27.
Figure 26: Relative permeability curve of base case.
34
Figure 27: Relative permeability curve after adjustment.
Figure 28: Field Oil Production Rate after adjustment relative permeability curve.
35
Figure 29: Field Water Production Rate after adjustment relative permeability curve.
Figure 30: Field Gas Production Rate after adjustment relative permeability curve.
36
As might be seen from the figures 28, 29 and 30 change in the shape of relative permeability
gives better match till 2000 but after that period the difference between base and historical cases
is still high.
The next key parameter of reservoir, transmissibility factor was modified, but change of
transmissibility factors around the wells did not conclude with estimated outcomes. Also the
results of history matching after adding aquifer were subjectively assessed as "unsatisfied."
Therefore the production wells were analyzed separately in order to get a better history match.
The graphs below show that there is gap between actual and model oil and water production data
of wells E-2H and E-3AH (Figures 31, 32, 33, 34).
Figure 31: Oil Production Rate for well E-2H.
37
Figure 32: Oil Production Rate for well E-3AH.
Figure 33: Water Production Rate for well E-2H.
38
Figure 34: Water Production Rate for well E-3AH.
In order to get history match for the WOPR, WWPR of wells E-2H and E-3AH, the KH value
and skin factors of the production wells were modified. In base case the skin factor of these wells
were set to zero however I adjust it to -3 and KH values was reproduced to 9 times assuming that
there are some natural stimulation nearby wells bore of wells E-2H and E-3AH.
Table 5: Completion data for wells E-2H and E-3AH.
39
Figure 35: Oil Production Rate for well E-2H after changing skin and KH values.
Figure 36: Oil Production Rate for well E-3AH after changing skin and KH values.
40
Figure 37: Water Production Rate for well E-2H after changing skin and KH values.
Figure 38: Water Production Rate for well E-3AH after changing skin and KH values.
41
The results for history matching after applying all modifications are given below:
Figure 39: Field Oil Production Rate after all modifications.
Figure 40: Field Water Production Rate after all modifications.
42
3.2 Synthetic Model Simulation
The polymer flooding process first was studied on the synthetic model which was built based on
fluid and rock properties of Norne field.
The synthetic model has two phases: oil and water. The model is homogeneous and consists of
11x11x3 grid block where the porosity value of system is equal to 0.28. There are two active
wells; one producer and one injector which are positioned in blocks 11,11,3 and 1,1,3
correspondingly (Figure 41). The simulation lasted 600 day where the water is injected for the
first six months then polymer injection at concentration of 0.5 kg/m3 starts lasting fourteen
months.
Figures 42, 43 and 44 represent the results of simulation, where blue line is water flooding (base
case) and red line is polymer flooding. Figure 42 demonstrates that by applying the polymer
flooding the oil recovery factor increased almost 9%, from 0.78 to 0.86.
Figure 41: Synthetic model.
43
Figure 42: Field Oil Recovery.
Figure 43: Oil Production Rate.
44
Figure 44: Water Production Rate.
It is readily observable that after 200 days there is low water production from day 200 to day 450
and then it increases to its highest rate which is 480 Sm3/day because water occupies the space
left by residual oil as they form a bank and move towards producing wells (Figure 44).
The EOR study on the synthetic model confirms the efficiency of polymer flooding and allows
us to do the same study for actual Norne E-segment model. However, it is probable not to gain
predictable results from the study on actual case because in the synthetic model, it is assumed
that the system is homogeneous and flat.
45
3.4 Polymer Flooding in Norne E-Segment
As it mentioned in previous chapter, there are 2 active injectors: F-1H and F-3H, 2 active
producers: E-2H and E-3AH in Norne E-Segment. In order to have effective EOR results, the
proper injector needs to be selected.
Due to the fact F-1H is placed in water region, while F-3H is located in the oil region, injector F3H was selected as a good option for polymer flooding study. Because in the case of F-1H,
polymer will spread out in water zone and lot of polymer will be needed for injection to increase
oil recover and it will be non-economical for EOR project.
The prediction was made from 2005 to 2017 where the injection of polymer starts from January
2006 and ends at January 2009. Then through the rest of simulation water was injected. For the
project two sensitivity analyses were studied:


Polymer concentration effect
Injection rate effect
Figure 45: Norne E-Segment.
46
3.4.1 Polymer Concentration Effect
The simulation has been run with three different concentration values to investigate polymer
concentration effect. The graphs below show the results of study with polymer concentration of
0.3, 0.6, 0.9 kg/m3. In this case water is injected for the first eight years from 1997 to 2005 then
polymer injection lasts from 2006 to 2009 and finally from 2009 to 2017 water is injected.
Total oil, water and polymer production, the production rate of oil and water, reservoir pressure
and bottom-hole pressure of injection well (F-3H) have been plotted for analysis.
Figure 46: Oil production rate at different polymer concentrations.
Figure 46 illustrates that polymer flooding causes higher oil recovery as compare to water
flooding where red line curve shows the result of polymer flooding at concentration of 0.3 kg/m3
green line curve injection at concentration of 0.6 kg/ m3 while blue one injection of chemical at
concentration of 0.9 kg/m3.
From the figure above it is obvious that after applying the polymer flooding in 2006, there was
considerable increase in oil production rate and the highest oil production for all injected
polymer concentrations is attained between 2007 and 2009, then hydrocarbon production rate
came down the base case. The reason is oil saturation; because of notable sweep performance,
47
oil production rate is higher in early stage and then after 2009 trend goes down by reason of low
oil saturation which left behind breakthrough front. But based on graph 29, polymer flooding at
different concentrations increased oil recovery in a small range of 0.5-1%.
From figure 47 it is clear that the polymer injection has a great effect on sweep efficiency;
polymer flooding at concentration of 0.9 kg/m3 causes enhanced sweep efficiency and less field
water production compare to base case. Despite the fact that the water production rate is lower at
early stage, it increases faster over other cases after 2012.
Figure 48 illustrates the reservoir pressure of all cases which is sustained over the bubble point
(251 bara) and less the maximum restriction (300 bara). According to simulation results, higher
polymer concentration follows with higher reservoir pressure. As a solution concentration
increases, injector pressure and the pressure around injector also increase (Figure 49). Polymer
flooding at concentration of 0.9 kg/m3 gives big increase in oil recovery compares to other cases
but at that concentration the bottom-hole pressure of injection well rises from 320 bara to 420
bara which makes this case inapplicable.
Figure 47: Water production rate at different polymer concentrations.
48
Figure 48: Reservoir pressure at different polymer concentrations.
Figure 49: Bottom-hole pressure of injection well at different polymer concentrations.
49
Figure 50: Total polymer production at different polymer concentrations.
Figure 51: Total oil production at different polymer concentrations.
50
3.4.2 Injection Rate Effect
Injection rate is another crucial parameter which needs to be studied in EOR projects. In this
chapter injection rate sensitivity analyses is performed with three different fluid injection rates:
1000 sm3/day, 4000 sm3/day and 7000 Sm3/day where 4000 sm3/day is initially given injection
rate for well F-3H and is used as a base case to compare with other cases. For all cases the
polymer flooding was applied at concentration of 0.6 kg/m3.
From figure 52, for the case where injection rate is higher than the base case total oil production
is lower which can be explained as a result of early water breakthrough and at injection rate of
1000 Sm3/day, the oil recovery is slightly higher than base case.
There is low pressure drop in reservoir at lower injection rate and vice versa. The pressure of
formation and the pressure of injector (Figure 53 and Figure 54) behaves similarly at injection
rate of 1000 Sm3/day and 4000Sm3/day which let us conclude that 1000 Sm3/day is most
favorable rate for polymer flooding process for Norne E-segment.
According to sensitivity analyses, the polymer flooding is an effective EOR technique compare
to water flooding due to slightly high oil recovery factor, low water production and better
mobility factor. Studies show that total oil production increases with injecting polymer at high
concentration because of improved mobility ratio and high injection rate causes reduction in oil
production due to early water breakthrough.
Figure 52: Total oil production at different injection rates.
51
Figure 53: Reservoir pressure at different injection rates.
Figure 54: Reservoir pressure at different injection rates.
52
Conclusions
History Matching:

Modifying the shape of relative permeability curve for Norne E-Segment helps to
minimize the difference between actual and reservoir model data.

The skin factor and KH values of wells have been adjusted in order to get low water and
high oil production into the wells.

A closer match was gained for Norne E-Segment by applying all parametric
modifications which are stated above.
Prediction:

A better result was achieved when EOR study was performed after 2006.

F-3H is best candidate as an injector for polymer flooding in Norne E-Segment.

Polymer flooding causes increase in oil recovery in range of 0.5-1%.

Production of oil is higher for higher polymer concentration.

Polymer flooding at concentration of 0.6 kg/m3 gave the same result of oil production but
with less polymer usage compared to 0.9 kg/m3.

Fluid injection rate at 1000 Sm3/day can be better case for polymer flooding due to its
high oil recovery and low injection pressure.
53
Recommendation
The type and chemical property of polymer that was used in this study may not be truthful.
Therefore the detailed laboratory works need to be done in order to use the right polymer which
will be appropriate for field rock and fluid characteristics.
The injection time is another crucial parameter which needs to be studied because polymer
flooding is more effective when reservoir oil saturation is high.
54
References
1. Lyons, William C and Plisga, Gary J. Standard Handbook of Petroleum and Natural Gas Engineering.
s.l. : Gulf Professional Publishing, 2011.
2. Enhanced Oil Recovery/CO2 Injection. United States Department of Energy. [Online] 2011.
www.energy.gov.
3. Sheng, James J. Modern Chemical Enhanced Oil Recovery ( Theory and Practice). USA : Elsevier Inc,
2011.
4. Wang, D, et al. The Influence of Visco-Elasticity on Micro Forces and Displacement Efficiency in pores,
Cores and in the Field. s.l. : SPE 127453.
5. Xia, H, et al. Effect of Elastic Behavior of HPAM Solutions on Displacement Efficiency Under Mixed
Wettability Conditions. s.l. : SPE 90234, 2004.
6. Medad, Tweyho. Polymer Flooding EOR. s.l. : Statoil ASA, 2006.
7. Littmann, J. Polymer Flooding: Developments in Petroleum Science vol 24. Amsterdam : Elsevier Inc,
1988.
8. Sorbie, K. Polymer Improved Oil Recovery. Blackie, Glasgow-London : s.n., 1991.
9. Polymer Flooding Technology –Yesterday, Today and Tomorrow . s.l. : SPE 94553, 1978.
10. Symon, Keith. Mechanics. Third ed. s.l. : Addison-Wesley, 1971.
11. Lake, L. Enhanced Oil Recovery. NJ : Prentical Hall, 1989.
12. Dawson, R. and Lantz, R. Inaccessible pore volume in polymer flooding. s.l. : SPEJ, 12:448- 452, 1972.
13. Monrawee, Pancharoen. PHYSICAL PROPERTIES OF ASSOCIATIVE POLYMER (Master Thesis). s.l. :
STANFORD UNIVERSITY, 2009.
14. Selle, Olav. An Experimental Study of Viscous Surfactant Flooding for Enhanced Oil Recovery .
Trondheim : NTNU, 2005.
15. [Online] http://en.wikipedia.org/.
16. Dong, H. Z., et al. Review of Practical Experience of Polymer Flooding at Daqing. s.l. : Paper SPE
114342, 2009.
17. Screening Criteria. SNF. [Online] [Cited: May 22, 2013.] http://www.snf-oil.com/.
55
18. Kaminsky, R. D., Wattenbarger, R. C. and Szafranski, R. Guidelines for Polymer Flooding Evaluation
and Development. s.l. : Paper IPTC 11200, 2007.
19. Lindley, J. Chemical Flooding (polymer). s.l. : http://www.netl.doe.gov, 2001.
20. Annual Reservoir Development Plan for Norne & URD Field. s.l. : Statoil, 2006.
21. Reservoir Management Plan Norne Field’ 01A05*183. s.l. : STATOIL PL 128 NORNE, 2001.
22. The NPD's fact. NPD. [Online] [Cited: June 20, 2013.]
http://www.npd.no/engelsk/cwi/pbl/en/field/all/43778.htm.
23. Welcome to IO Center-Norne Benchmark Case, Introduction to Norne Field. IO-Center. . [Online]
[Cited: Jun3 20, 2013.] http://www.ipt.ntnu.no/~norne/wiki/data/media/english/gfi/introduction-tothe-norne-field.pdf.
24. PDO-Reservoir Geology, Support Documentation. s.l. : Statoil, 1994.
25. Reservoir Management Plan Norne Field’ 01A05*183. s.l. : Statoil PL 128, 2001.
26. Plan for Development and Operation Support Document-Reservoir Engineering. s.l. : Statoil , 1994.
27. Oil Field Glossary. Schlumberger. [Online] 2013. [Cited: 05 19, 2013.]
http://www.glossary.oilfield.slb.com/.
56
Appendix
A.Polymer Introduction in Eclipse Simulator
Before presenting the results let us shortly discuss how polymer flooding might be presented in
Eclipse simulator. The option is activated by the keyword POLYMER in the RUNSPEC
section. The mixing parameter data is obligatory and should be defined using the keyword
TLMIXPAR. The maximum number of mixing parameter regions is set using the parameter
NTMISC in RUNSPEC keyword MISCIBLE. The maximum polymer and salt concentrations to
be used in calculating the effective fluid component viscosities are entered under the keyword
PLYMAX The polymer adsorption data should be entered using the keyword PLYADS in the
PROPS section. Other polymer-rock parameters such as the rock mass density used in the
adsorption calculation, the dead pore space, the residual resistance factor are input using the
keyword PLYROCK. The shear thinning model is activated if the PLYSHEAR keyword is
present in the PROPS section. The shear thinning data consists of tables of viscosity reduction
as a function of local velocity. The values of used to calculate the velocity can be printed out
using the mnemonic POLYMER (38th switch) in the RPTGRID keyword [10].
The definition of the polymer/salt well injection streams should be set using the keyword
WPOLYMER in the SCHEDULE section. Grid arrays reports can be produced for polymer
concentration, salt concentration, adsorbed polymer concentration and the permeability
reduction factor for the aqueous phase at each report time.
2 different tables of parameters were used in polymer flooding; one of them is standard
defaulted values from ECLIPSE TECHNICAL description, while second one was kindly
presented by SINTEF ASA. After comparison (in term of running) of this data were concluded
that data given by the company suits our simulation better compare to ECTD.
57
B.Eclipse Data File for Norne Field E-Segment
-- water injection rate of F-1, F-2, and F-3 by 50
----------------------------------------------------------------------------
-- Ny model July 2004 build by marsp/oddhu
-- New grid with sloping faults based on geomodel xxx
-------------------------------------
RUNSPEC
--LICENSES
--'NETWORKS' /
--/
DIMENS
46 112 22 /
--NOSIM
--- Allow for multregt, etc. Maximum number of regions 20.
-GRIDOPTS
'YES' 0 /
OIL
WATER
GAS
58
DISGAS
VAPOIL
METRIC
-- use either hysteresis or not hysteresis
--NOHYST
HYST
START
06 'NOV' 1997 /
EQLDIMS
5 100 20 /
EQLOPTS
'THPRES' / no fine equilibration if swatinit is being used
REGDIMS
-- ntfip nmfipr nrfreg ntfreg
22
4
1*
20 /
TRACERS
-- oil water gas env
1*
10 1* 1* /
WELLDIMS
--ML 40 36 15 15 /
130 36 15 84 /
--WSEGDIMS
-- 3 30 3 /
59
LGR
-- maxlgr maxcls mcoars mamalg mxlalg lstack interp
4 2000 693
1
4
20 'INTERP' /
TABDIMS
--ntsfun ntpvt nssfun nppvt ntfip nrpvt ntendp
110
2
33
60 16 60 /
-- WI_VFP_TABLES_080905.INC = 10-20
VFPIDIMS
30
20 20 /
-- Table no.
-- DevNew.VFP
-- E1h.VFP
=1
=2
-- AlmostVertNew.VFP = 3
-- GasProd.VFP
=4
-- NEW_D2_GAS_0.00003.VFP = 5
-- GAS_PD2.VFP = 6
-- pd2.VFP
= 8 (flowline south)
-- pe2.VFP
= 9 (flowline north)
-- PB1.PIPE.Ecl = 31
-- PB2.PIPE.Ecl = 32
-- PD1.PIPE.Ecl = 33
-- PD2.PIPE.Ecl = 34
-- PE1.PIPE.Ecl = 35
-- PE2.PIPE.Ecl = 36
-- B1BH.Ecl = 37
-- B2H.Ecl = 38
-- B3H.Ecl = 39
-- B4DH. Ecl= 40
-- D1CH.Ecl = 41
-- D2H.Ecl = 42
60
-- D3BH.Ecl = 43
-- E1H.Ecl = 45
-- E3CH.Ecl = 47
-- K3H.Ecl = 48
VFPPDIMS
19 10 10 10 0 50 /
FAULTDIM
10000 /
PIMTDIMS
1 51 /
NSTACK
30 /
UNIFIN
UNIFOUT
--RPTRUNSPEC
OPTIONS
77* 1 /
-----------------------------------------------------------
Input of grid geometry
---------------------------------------------------------GRID
61
NEWTRAN
GRIDFILE
2 /
-- optional for postprocessing of GRID
MAPAXES
0. 100. 0. 0. 100. 0. /
GRIDUNIT
METRES /
-- do not output GRID geometry file
--NOGGF
-- requests output of INIT file
INIT
MESSAGES
8*10000 20000 10000 1000 1* /
PINCH
0.001 GAP 1* TOPBOT TOP/
NOECHO
----------------------------------------------------------
Grid and faults
---------------------------------------------------------
--- Simulation grid, with slooping faults:
-62
-- file in UTM coordinate system, for importing to DecisionSpace
INCLUDE
'./INCLUDE/GRID/IRAP_1005.GRDECL' /
-- '/project/norne6/res/INCLUDE/GRID/IRAP_0704.GRDECL' /
-INCLUDE
'./INCLUDE/GRID/ACTNUM_0704.prop' /
--- Faults
--INCLUDE
'./INCLUDE/FAULT/FAULT_JUN_05.INC' /
-- Additional faults
--Nord for C-3 (forlengelse av C_10)
EQUALS
MULTY 0.01 6 6 22 22 1 22 /
/
-- B-3 water
EQUALS
'MULTX' 0.001 9 11 39 39 1 22 /
'MULTY' 0.001 9 11 39 39 1 22 /
'MULTX' 0.001 9 9 37 39 1 22 /
'MULTY' 0.001 9 9 37 39 1 22 /
/
-- C-1H
EQUALS
'MULTY' 0.001
26 29 39 39 1 22 /
/
63
----------------------------------------------------------
Input of grid parametres
---------------------------------------------------------
-INCLUDE
'./INCLUDE/PETRO/PORO_0704.prop' /
-INCLUDE
'./INCLUDE/PETRO/NTG_0704.prop' /
-INCLUDE
'./INCLUDE/PETRO/PERM_0704.prop' /
-- G segment north
EQUALS
PERMX 220 32 32 94 94 2 2 /
PERMX 220 33 33 95 99 2 2 /
PERMX 220 34 34 95 97 2 2 /
PERMX 220 35 35 95 98 2 2 /
PERMX 220 36 36 95 99 2 2 /
PERMX 220 37 37 95 99 2 2 /
PERMX 220 38 38 95 100 2 2 /
PERMX 220 39 39 95 102 2 2 /
PERMX 220 40 40 95 102 2 2 /
PERMX 220 41 41 95 102 2 2 /
/
-- C-1H
MULTIPLY
64
PERMX
4 21 29 39 49 16 18 /
PERMX 100 21 29 39 49 19 20 /
/
COPY
PERMX PERMY /
PERMX PERMZ /
/
-- Permz reduction is based on input from PSK
-- based on same kv/kh factor
-- ******************************************
-- CHECK! (esp. Ile & Tofte)
-- ******************************************
MULTIPLY
'PERMZ' 0.2 1 46 1 112 1 1 / Garn 3
'PERMZ' 0.04 1 46 1 112 2 2 / Garn 2
'PERMZ' 0.25 1 46 1 112 3 3 / Garn 1
'PERMZ' 0.0 1 46 1 112 4 4 / Not
(inactive anyway)
'PERMZ' 0.13 1 46 1 112 5 5 / Ile 2.2
'PERMZ' 0.13 1 46 1 112 6 6 / Ile 2.1.3
'PERMZ' 0.13 1 46 1 112 7 7 / Ile 2.1.2
'PERMZ' 0.13 1 46 1 112 8 8 / Ile 2.1.1
'PERMZ' 0.09 1 46 1 112 9 9 / Ile 1.3
'PERMZ' 0.07 1 46 1 112 10 10 /
Ile 1.2
'PERMZ' 0.19 1 46 1 112 11 11 /
Ile 1.1
'PERMZ' 0.13 1 46 1 112 12 12 /
Tofte 2.2
'PERMZ' 0.64 1 46 1 112 13 13 /
Tofte 2.1.3
'PERMZ' 0.64 1 46 1 112 14 14 /
Tofte 2.1.2
'PERMZ' 0.64 1 46 1 112 15 15 /
Tofte 2.1.1
'PERMZ' 0.64 1 46 1 112 16 16 /
Tofte 1.2.2
'PERMZ' 0.64 1 46 1 112 17 17 /
Tofte 1.2.1
'PERMZ' 0.016 1 46 1 112 18 18 /
Tofte 1.1
'PERMZ' 0.004 1 46 1 112 19 19 /
Tilje 4
65
'PERMZ' 0.004 1 46 1 112 20 20 /
Tilje 3
'PERMZ' 1.0 1 46 1 112 21 21 /
Tilje 2
'PERMZ' 1.0 1 46 1 112 22 22 /
Tilje 1
/
----------------------------------------------------------
Barriers
---------------------------------------------------------- 20 flux regions generated by the script Xfluxnum
-INCLUDE
'./INCLUDE/PETRO/FLUXNUM_0704.prop' /
-- modify transmissibilites between fluxnum using MULTREGT
-INCLUDE
'./INCLUDE/PETRO/MULTREGT_D_27.prop' /
NOECHO
MINPV
500 /
EQUALS
'MULTZ' 0.00125 26 29 30 37 10 10 / better WCT match for B-2H
'MULTZ' 0.015 19 29 11 30 8 8 / better WCT match for D-1CH
'MULTZ' 1
6 12 16 22 8 11 / for better WCT match for K-3H
'MULTZ' .1
6 12 16 22 15 15 / for better WCT match for K-3H
66
/
COARSEN
-- I1 I2 J1 J2 K1 K2 NX NY NZ
6 29 11 44 1 3 1 1 3/
6 29 11 44 5 22 1 1 18 /
16 19 45 67 1 3 1 1 3 /
16 19 45 67 5 22 1 1 18 /
20 25 45 67 1 3 1 1 3 /
20 25 45 67 5 22 1 1 18 /
26 29 45 67 1 3 1 1 3 /
26 29 45 67 5 22 1 1 18 /
30 41 63 75 1 3 1 1 1 /
30 41 63 75 5 20 1 1 16 /
30 41 63 75 22 22 1 1 1 /
30 41 76 93 1 3 1 1 1 /
30 41 76 93 5 9 1 1 5 /
30 41 76 93 12 20 1 1 9 /
30 41 76 93 22 22 1 1 1 /
30 37 58 62 1 3 1 1 1 /
30 37 58 62 5 22 1 1 18 /
30 34 54 57 1 3 1 1 1 /
30 34 54 57 5 18 1 1 14 /
30 34 54 57 20 22 1 1 3 /
30 32 51 53 1 3 1 1 1 /
30 32 51 53 5 22 1 1 18 /
30 30 48 48 1 3 1 1 1 /
30 30 50 50 1 3 1 1 1 /
30 30 48 48 5 22 1 1 18 /
30 30 50 50 5 22 1 1 18 /
33 33 52 53 1 3 1 1 1 /
33 33 52 53 5 22 1 1 18 /
35 36 57 57 1 3 1 1 1 /
35 36 57 57 5 22 1 1 18 /
67
38 38 59 60 1 3 1 1 1 /
38 38 59 60 5 22 1 1 18 /
38 39 61 62 1 3 1 1 1 /
38 39 61 62 5 22 1 1 18 /
17 19 68 85 1 3 1 1 1 /
17 19 68 85 5 22 1 1 18 /
17 19 86 89 1 3 1 1 1 /
17 19 86 89 5 22 1 1 18 /
22 25 68 70 1 3 1 1 1 /
26 29 68 70 1 3 1 1 1 /
20 21 68 70 5 22 1 1 18 /
20 21 68 69 1 3 1 1 1 /
22 25 68 69 5 22 1 1 18 /
26 29 68 69 5 22 1 1 18 /
10 15 45 51 1 3 1 1 3 /
10 15 45 51 5 22 1 1 18 /
13 15 52 57 1 3 1 1 3 /
13 15 52 57 5 22 1 1 18 /
11 12 52 54 1 3 1 1 3 /
11 12 52 54 5 22 1 1 18 /
12 12 55 56 1 3 1 1 3 /
12 12 55 56 5 22 1 1 18 /
10 10 52 53 1 3 1 1 3 /
10 10 52 53 5 22 1 1 18 /
13 15 58 59 1 3 1 1 3 /
13 15 58 59 5 22 1 1 18 /
14 15 60 61 1 3 1 1 3 /
14 15 60 61 5 22 1 1 18 /
15 15 62 64 1 3 1 1 3 /
15 15 62 64 5 22 1 1 18 /
16 16 68 69 1 3 1 1 3 /
16 16 68 69 5 22 1 1 18 /
8 9 45 46 1 3 1 1 3 /
8 9 45 46 5 22 1 1 18 /
68
9 9 47 48 1 3 1 1 3 /
9 9 47 48 5 22 1 1 18 /
31 41 94 95 1 3 1 1 1 /
31 41 94 95 5 22 1 1 18 /
34 41 96 97 1 3 1 1 1 /
34 41 96 97 5 22 1 1 18 /
36 41 98 99 1 3 1 1 1 /
36 41 98 99 5 22 1 1 18 /
39 41 100 102 1 3 1 1 1 /
39 41 100 102 5 22 1 1 18 /
/
--------------------------------------------------
PROPS
----------------------------------------------------------------------------------
Input of fluid properties and relative permeability
----------------------------------------------------------
NOECHO
-- Input of PVT data for the model
-- Total 2 PVT regions (region 1 C,D,E segment, region 2 Gsegment)
-INCLUDE
'./INCLUDE/PVT/PVT-WET-GAS.DATA' /
TRACER
'SEA' 'WAT' /
'HTO' 'WAT' /
'S36' 'WAT' /
69
'2FB' 'WAT' /
'4FB' 'WAT' /
'DFB' 'WAT' /
'TFB' 'WAT' /
/
------------------------------------------------------------ initialization and relperm curves: see report blabla
-----------------------------------------------------------
-- rel. perm and cap. pressure tables --
-INCLUDE
'./INCLUDE/RELPERM/HYST/swof_mod4Gseg_aug-2006.inc' /
--Sgc=10 0.000000or g-segment
-INCLUDE
'./INCLUDE/RELPERM/HYST/sgof_sgc10_mod4Gseg_aug-2006.inc' /
---INCLUDE
-- './INCLUDE/RELPERM/HYST/waghystr_mod4Gseg_aug-2006.inc' /
'./INCLUDE/RELPERM/HYST/waghystr.inc' /
--RPTPROPS
-- 1 1 1 5*0 0 /
-------------------------------------------------------------------------------70
REGIONS
-INCLUDE
'./INCLUDE/PETRO/FIPNUM_0704.prop' /
-INCLUDE
'./INCLUDE/PETRO/SATNUM_0704.prop' /
EQUALS
'SATNUM' 102 30 41 76 112 1 1 /
'SATNUM' 103 30 41 76 112 2 2 /
'SATNUM' 104 30 41 76 112 3 3 /
/
-INCLUDE
'./INCLUDE/PETRO/IMBNUM_0704.prop' /
EQUALS
'IMBNUM' 102 30 41 76 112 1 1 /
'IMBNUM' 103 30 41 76 112 2 2 /
'IMBNUM' 104 30 41 76 112 3 3 /
/
-INCLUDE
'./INCLUDE/PETRO/PVTNUM_0704.prop' /
EQUALS
'PVTNUM' 1 1 46 1 112 1 22 /
71
/
-INCLUDE
'./INCLUDE/PETRO/EQLNUM_0704.prop' /
-- extra regions for geological formations and numerical layers
INCLUDE
'./INCLUDE/PETRO/EXTRA_REG.inc' /
---------------------------------------------------------------------------------
SOLUTION
RPTRST
BASIC=2 /
RPTSOL
FIP=3 /
---------------------------------------------------------------------------------- equilibrium data: do not include this file in case of RESTART
--INCLUDE
'./INCLUDE/PETRO/E3.prop' /
-- restart date: only used in case of a RESTART, remember to use SKIPREST
--RESTART
-- 'BASE_30-NOV-2005' 360 / AT TIME
3282.0 DAYS ( 1-NOV-2006)
THPRES
1 2 0.588031 /
1 3 0.787619 /
1 4 7.00083 /
72
/
-- initialise injected tracers to zero
TVDPFSEA
1000 0.0
5000 0.0 /
TVDPFHTO
1000 0.0
5000 0.0 /
TVDPFS36
1000 0.0
5000 0.0 /
TVDPF2FB
1000 0.0
5000 0.0 /
TVDPF4FB
1000 0.0
5000 0.0 /
TVDPFDFB
1000 0.0
5000 0.0 /
TVDPFTFB
1000 0.0
5000 0.0 /
-------------------------------------------------------------------------------
SUMMARY
FOE
RUNSUM
SEPARATE
EXCEL
73
-INCLUDE
'./INCLUDE/SUMMARY/summary.data' /
--------------------------------------------------------------------------------
SCHEDULE
NOWARN
-- use SKIPREST in case of RESTART
--SKIPREST
-- No increase in the solution gas-oil ratio?!
DRSDT
0 /
-- Use of WRFT in order to report well perssure data after first
-- opening of the well. The wells are perforated in the entire reservoir
-- produce with a small rate and are squeesed after 1 day. This pressure
-- data can sen be copmared with the MDT pressure points collected in the
-- well.
NOECHO
---------------------------------------------=======Production Wells========---------------------------------------------
-INCLUDE
'./INCLUDE/VFP/DevNew.VFP' /
74
-INCLUDE
'./INCLUDE/VFP/E1h.VFP' /
-INCLUDE
'./INCLUDE/VFP/NEW_D2_GAS_0.00003.VFP' /
-INCLUDE
'./INCLUDE/VFP/GAS_PD2.VFP' /
-INCLUDE
'./INCLUDE/VFP/AlmostVertNew.VFP' /
-INCLUDE
'./INCLUDE/VFP/GasProd.VFP' /
-- 01.01.07 new VFP curves for producing wells, matched with the latest well tests in Prosper. lmarr
-INCLUDE
'./INCLUDE/VFP/B1BH.Ecl' /
-INCLUDE
'./INCLUDE/VFP/B2H.Ecl' /
-INCLUDE
'./INCLUDE/VFP/B3H.Ecl' /
-INCLUDE
'./INCLUDE/VFP/B4DH.Ecl' /
-INCLUDE
'./INCLUDE/VFP/D1CH.Ecl' /
75
-INCLUDE
'./INCLUDE/VFP/D2H.Ecl' /
-INCLUDE
'./INCLUDE/VFP/D3BH.Ecl' /
-INCLUDE
'./INCLUDE/VFP/E1H.Ecl' /
-INCLUDE
'./INCLUDE/VFP/E3CH.Ecl' /
-INCLUDE
'./INCLUDE/VFP/K3H.Ecl' /
---------------------------------------------=======Production Flowlines========----------------------------------------------- 16.5.02 new VFP curves for southgoing PD1,PD2,PB1,PB2 flowlines -> pd2.VFP
-INCLUDE
'./INCLUDE/VFP/pd2.VFP' /
--- 16.5.02 new VFP curves for northgoing PE1,PE2 flowlines -> pe2.VFP
-INCLUDE
'./INCLUDE/VFP/pe2.VFP' /
-- 24.11.06 new matched VLP curves for PB1 valid from 01.07.06
76
-INCLUDE
'./INCLUDE/VFP/PB1.PIPE.Ecl' /
--24.11.06 new matched VLP curves for PB2 valid from 01.07.06
-INCLUDE
'./INCLUDE/VFP/PB2.PIPE.Ecl' /
--24.11.06 new matched VLP curves for PD1 valid from 01.07.06
-INCLUDE
'./INCLUDE/VFP/PD1.PIPE.Ecl' /
--24.11.06 new matched VLP curves for PD2 valid from 01.07.06
-INCLUDE
'./INCLUDE/VFP/PD2.PIPE.Ecl' /
--24.11.06 new matched VLP curves for PE1 valid from 01.07.06
-INCLUDE
'./INCLUDE/VFP/PE1.PIPE.Ecl' /
--24.11.06 new matched VLP curves for PE2 valid from 01.07.06
-INCLUDE
'./INCLUDE/VFP/PE2.PIPE.Ecl' /
---------------------------------------------=======INJECTION FLOWLINES 08.09.2005
========--
-------------------------------------------77
-- VFPINJ nr. 10 Water injection flowline WIC
-INCLUDE
'./INCLUDE/VFP/WIC.PIPE.Ecl' /
-- VFPINJ nr. 11 Water injection flowline WIF
-INCLUDE
'./INCLUDE/VFP/WIF.PIPE.Ecl' /
---------------------------------------------======= INJECTION Wells 08.09.2005
========--
--------------------------------------------- VFPINJ nr. 12 Water injection wellbore Norne C-1H
-INCLUDE
'./INCLUDE/VFP/C1H.Ecl' /
-- VFPINJ nr. 13 Water injection wellbore Norne C-2H
-INCLUDE
'./INCLUDE/VFP/C2H.Ecl' /
-- VFPINJ nr. 14 Water injection wellbore Norne C-3H
-INCLUDE
'./INCLUDE/VFP/C3H.Ecl' /
-- VFPINJ nr. 15 Water injection wellbore Norne C-4H
-INCLUDE
'./INCLUDE/VFP/C4H.Ecl' /
-- VFPINJ nr. 16 Water injection wellbore Norne C-4AH
78
-INCLUDE
'./INCLUDE/VFP/C4AH.Ecl' /
-- VFPINJ nr. 17 Water injection wellbore Norne F-1H
-INCLUDE
'./INCLUDE/VFP/F1H.Ecl' /
-- VFPINJ nr. 18 Water injection wellbore Norne F-2H
-INCLUDE
'./INCLUDE/VFP/F2H.Ecl' /
-- VFPINJ nr. 19 Water injection wellbore Norne F-3 H
-INCLUDE
'./INCLUDE/VFP/F3H.Ecl' /
-- VFPINJ nr. 20 Water injection wellbore Norne F-4H
-INCLUDE
'./INCLUDE/VFP/F4H.Ecl' /
TUNING
1 10 0.1 0.15 3 0.3 0.3 1.20 /
5* 0.1 0.0001 0.02 0.02 /
--2* 40 1* 15 /
/
-- only possible for ECL 2006.2+ version
ZIPPY2
79
'SIM=4.2' 'MINSTEP=1E-6' /
/
--WSEGITER
--/
-- PI reduction in case of water cut
-INCLUDE
'./INCLUDE/PI/pimultab_low-high_aug-2006.inc' /
-- History and prediction --INCLUDE
'./INCLUDE/BC0407_2004.SCH' /
END
80
C.Polymer Input File
PLYSHEAR
--Polymer shear thinning data
-- Wat. Velocity Visc reduction
-- m/day
CP
0.0
1.0
2.0
1.0 /
PLYVISC
-- Polymer solution Viscosity Function
Wat. Visc.
-- Ply conc.
mult.
-- kg/m3
0.0
1.0
0.1
1.55
0.3
2.55
0.5
5.125
0.7
8.125
1.0
21.2 /
PLYADS
-- Polymer Adsorption Function
-- Ply conc.
Ply conc. Adsorbed
-- kg/m3
by rock, Kg/kg
0.0
0.0
0.5
0.0000017
1.0
0.0000017 /
TLMIXPAR
-- Todd-Long staff Mixing Parameters 1 1* /
PLYMAX
-- Polymer-Salt concentration for mixing maximum polymer and salt concentration
-- Ply conc.
Salt conc.
-- kg/m3
kg/m3
1.0
0.0 /
PLYROCK
--Polymer-Rock Properties
--dead pore
residual resistance
-- space
factor
0.16
1.0
mass
density
2650
Ads.
Index
1
81
max. Polymer
adsorption
0.000017 /