Improving oil recovery in fractured reservoirs

1. Kurdistan Regional Government
Presidency of Minister Council
Ministry of higher education
And scientific Research
KOYA University
Faculty of Engineering
Department of Petroleum Engineering
Improving Oil Recovery In
Fractured Reservoirs
A project submitted in partial Fulfilment of the
Requirement for the award of the degree of
B.Sc. Petroleum Engineering
2016-2017
Prepared by:
Muhammad Faisal Huner Mahdi Bakhtyar Abdulstar
Under the supervision of:
Ayyub Hekmati
Academic Year (2016-2017)

2. 2
Abstract:
Naturally fractured reservoirs (NFR) are huge contributors to the world’s oil
reserves. These oil reservoirs are found in the Middle East, North Africa,
North and South America, and the North Sea. Suitable methods have to be
employed to enhance the oil recovery from these reservoirs. The
production strategy is one of the most important factors for the oil recovery
of reservoirs and is a complex process due to the multiple alternatives that
can be implemented. The adequate choice of a production strategy
improves the performance of the reservoir along its productive life. The
production strategies are proposed considering definite objectives and
observing the operational, economic characteristics and restrictions and
the physical conformation of the porous medium. Moreover, a production
strategy depends mainly on the geologic characteristics of the reservoir and
the operational program that will be used in the strategy proposal.
(Aguilera, 1995)
After that the primary recovery has produced most of the reservoirs oil
typically water injection is used to improve oil recovery while gas injection
is used to maintain pressure or to promote oil gravity drainage. Immiscible
gas injection, including injection of CO2, has been considered but not
implemented on a large scale for economic reasons. Furthermore, interest
in using surfactants in large carbonate reservoirs has recently flourished.
And other EOR methods are being widely used for the past decades such as
polymer flooding water alternating gas, steam injection, nitrogen and
surfactant injection and many more techniques are being tested in order to
recover the remaining oil in the fractured as well as conventional
reservoirs.

3. 3
Table of contents:
Abstract:........................................................................................................................................... 2
Table of contents:............................................................................................................................. 3
List of figures:................................................................................................................................... 5
List of tables: .................................................................................................................................... 5
Acknowledgment: ............................................................................................................................ 6
Chapter one: .................................................................................................................................... 7
1.1 Aim: ....................................................................................................................................7
1.2 Introduction:.......................................................................................................................8
Chapter Two:.................................................................................................................................. 10
2.1 Fractures:..........................................................................................................................10
2.1.1 How naturally fractured reservoirs are formed: ......................................................10
2.1.2 Types: .....................................................................................................................11
2.1.3 Classification:..........................................................................................................11
2.2 Oil recovery:......................................................................................................................12
2.2.1 Recovery in fractured reservoir:..............................................................................15
2.3 Recovery Mechanisms in Fractured Reservoirs:................................................................15
2.3.1 Primary Recovery:...................................................................................................16
2.3.2 Secondary Recovery:...............................................................................................16
2.3.3 Tertiary Recovery:...................................................................................................17
2.4 Enhanced Oil Recovery (EOR):...........................................................................................18
2.5 EOR classification:.............................................................................................................19
2.5.1 Thermal recovery:...................................................................................................19
2.5.2 Steam Flooding: ......................................................................................................20
2.5.3 Cyclic Steam Stimulation:........................................................................................21
2.5.4 Steam stimulation:..................................................................................................22
2.5.4.1 EOR-Steam injection-criteria:............................................................................23
2.5.5 Steam drive:............................................................................................................24
2.5.5.1 Mechanisms of this process: .............................................................................24

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2.5.6 In situ combustion: .................................................................................................25
2.5.7 Natural Gas injection: .............................................................................................26
2.5.7.1 Gas injection-criteria:........................................................................................26
2.5.8 Nitrogen flooding:...................................................................................................27
2.5.9 CO2 injection: .........................................................................................................28
2.5.9.1 Gas injection advantageous: .............................................................................30
2.5.10 chemical flooding:.................................................................................................30
2.5.10.1 Chemical EOR in Large Fractured Carbonate Reservoirs:..................................31
2.5.10.2 Chemical flooding criteria:...............................................................................32
2.5.11 Polymer flooding:..................................................................................................32
2.5.11.1 Mechanisms That Improve Recovery Efficiency:..............................................33
2.5.11.2 Limitations:.....................................................................................................34
2.5.11.3 Polymer flooding criteria:................................................................................35
2.5.12 Microbial injection:...............................................................................................35
2.5.12.1 Advantages of MEOR:......................................................................................36
2.5.12.2 Disadvantages of MEOR: .................................................................................37
2.5.13 Other Upcoming Technologies: .............................................................................38
Chapter Three: ............................................................................................................................... 39
3.1 Case studies & results:......................................................................................................39
3.1.1 (Nano fluid in Egypt) ...............................................................................................39
3.1.2 (EOR in Iran):...........................................................................................................40
3.1.2.1 Results: .............................................................................................................41
3.1.2.1.1 Quick screening:..............................................................................................41
3.1.2.1.2 Simulation Study and Prediction:....................................................................43
Chapter Four: ................................................................................................................................. 46
4.1 CONCLUSION: ...................................................................................................................46
4.2 Recommendations:...........................................................................................................49
Chapter Five:.................................................................................................................................. 50
Bibliography............................................................................................................................50

5. 5
List of figures:
Figure 1: Production life cycle of oil (MAERSK OIL, 2014).............................................................9
Figure 2: Fracture types(ResearchGate.net, 2016) ....................................................................13
Figure 3: Oil recovery mechanisms (youngpetro.org, 2014).......................................................18
Figure 4: SAGD process (ikanmedia.tv, 2014).............................................................................20
Figure 5: Cyclic steam stimulation (independent.com, 2017).....................................................22
Figure 6: In situ combustion (pipingguide.net,2017)..................................................................25
Figure 7: Nitrogen injection (airproducts.com, 2012).................................................................27
Figure 8: CO2 injection (energy.gov, 2015) ................................................................................29
Figure 9: Polymer injection (studyblue.com, 2016)....................................................................34
Figure 10: Microbial injection (lizinan.wordpress.com, 2011)....................................................36
Figure 11: Nano fluid VS Water flood (researchgate.net, 2013).................................................39
Figure 12: Graphical results of screened EOR methods (researchgate.net, 2014)......................43
Figure 13: Simulation by using steam flooding method (researchgate.net, 2014)......................44
Figure 14: Injected steam to the reservoir (researchgate.net, 2014). ........................................44
Figure 15: Oil recovery factor by steam flooding method (researchgate.net, 2014). .................45
Figure 16: Breakthrough due to fractures (uis.no, 2013) ...........................................................47
Figure 17: Out of zone fracture (uis.no, 2013) ...........................................................................48
Figure 18: EOR worldwide (slideshare.net, 2013) ......................................................................48
List of tables:
Table 1: Classification of (NFR) (petrowiki.org, 2015).................................................................11
Table 2: Steam injection criteria (slideshare.net, 2015) .............................................................23
Table 3: Gas injection criteria (slideshare.net, 2015) .................................................................26
Table 4: Advantages of gas injection (slideshare.net, 2015).......................................................30
Table 5: Chemical flooding criteria (slideshare.net, 2015) .........................................................32
Table 6: Polymer flooding criteria (slideshare.net, 2015)...........................................................35
Table 7: Nano fluid against other EOR methods (slideshare.net, 2016) .....................................38
Table 8: Critical data for EOR screening (researchgate.net, 2014) .............................................41
Table 9: Results summary of EOR screening (researchgate.net, 2014).......................................42
Table 10: Production Processes & EOR in Middle East (searchanddiscovery.com, 2010)...........47

6. 6
Acknowledgment:
Although this project has been somehow difficult to manage and
needed a lot of hard work and effort and it has been much harder without
the help of a present supervising teacher but at last it is finished and we
want express our gratitude to some people who have been much kind to
guide us and have been a great help with their advises. Mr. Ayyub Hekmati
and Mr. Barham Sabir were very helpful by supporting us through the way
and providing us with some of the necessary elements of our project. That’s
why we want to thank them for their effort and their valuable time.

7. 7
Chapter one:
1.1 Aim:
The aim of this project is to investigate the oil production in fractured
reservoirs and to have an understanding of recovery mechanisms and all
the methods that lead to improvement of the production in fractured
reservoirs especially the EOR processes and to determine the advantages
and limitations of fractures during EOR process.

8. 8
1.2 Introduction:
For primary recovery (i.e., natural depletion of reservoir pressure), the
lifecycle is generally short and the recovery factor does not exceed 20% in
most cases. For secondary recovery, relying on either natural or artificial
water or gas injection, the incremental recovery ranges from 15 to 25%.
Globally, the overall recovery factors for combined primary and secondary
recovery range between 35 and 45%. Increasing the recovery factor of
maturing water flooding projects by 10 to 30% could contribute
significantly to the much-needed energy supply. To accomplish this,
operators and service companies need to find ways to maximize recovery
while minimizing operational costs and environmental imprint.
After conventional primary and secondary oil recovery, there is usually
a great amount of oil remaining in the reservoir. This unrecovered oil is a
target for enhanced oil recovery in order to meet the energy demand in the
future. The interest for enhanced oil recovery has increased due to
increasing oil prices, and because most of the easily recovered oil has been
or is being produced. Enhanced oil recovery techniques can be thermal
exposure, gas injection, WAG, polymers, surfactant and foam. (P.O. Roehl,
1985)
It is estimated that more than 60% of the world's oil reserves are held
in carbonate reservoirs, and a significant part of these reservoirs are
naturally fractured. The oil recovery from these fractured carbonate
reservoirs are typically low because approximately 80% are mixed-wet or
oil-wet, leading to an ineffective water injection. (HIRASAKI, 2004)

9. 9
That’s why it is impervious for engineers and oil companies to find
better solutions to recover more oil from fractured reservoirs using other
solutions like EOR which is widely used today, besides water flooding and
secondary recovery solutions. This paper talks about the recovery process
of the fractured reservoirs and the EOR techniques that improve the
recovery of petroleum.
Figure 1: Production life cycle of oil (MAERSK OIL, 2014)

10. 10
Chapter Two:
2.1 Fractures:
Fractures are the most abundant visible structural features in the Earth’s
upper crust. They are apparent at most rock ridges, and it is likely that most
reservoirs contain some natural fractures. Naturally fractured reservoirs
are elusive systems to characterize and difficult to engineer and predict. It
is important to establish some basic criteria for recognizing when fractures
are an important element in reservoir performance and to recognize the
nature and performance characteristics of a naturally fractured reservoir.
(Nelson, 2001)
2.1.1 How naturally fractured reservoirs are formed:
Natural fractures are caused by stress in the formation usually from
tectonic forces such as folds and faults. Natural fractures are more common
in carbonate rocks. Fractures occur in preferential directions, determined
by the direction of regional stress. This is usually parallel to the direction of
nearby faults or folds, but in the case of faults, they may be perpendicular
to the fault or there may be two orthogonal directions.
A fracture is often a high permeability path in a low permeability rock, or it
may be filled with a cementing material, such as calcite, leaving the fracture
with no permeability. It is important to distinguish between open and
healed fractures. The total volume of fractures is often small compared to
the total pore volume of the reservoir. (Nelson, 2001)

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2.1.2 Types:
Naturally fractured reservoirs can be open, permeable pathways, or they
can be permeability baffles resulting from the presences if secondary
mineralization or other fine-grained material filling the gaps. Most natural
fractures are more or less vertical. Horizontal fracture may exist for a short
distance, propped open by bridging of the irregular surfaces. Most
horizontal fractures, however, are sealed by overburden pressure. Both
horizontal and semi-vertical fractures can be detected by various logging
tools. (Saidi, 1987)
2.1.3 Classification:
Naturally fractured reservoirs have been classified according to the relative
contribution of the matrix and fractures to the total fluid production. The
following table is modified form.
Table 1: Classification of (NFR) (petrowiki.org, 2015)

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2.2 Oil recovery:
Naturally fractured carbonate reservoirs naturally fractured carbonate
reservoirs are geological formations characterized by a heterogeneous
porosity and permeability. A common scenario is low
distribution of
porosity and low permeability matrix blocks surrounded by a tortuous,
highly permeable fracture network. In this case, the overall fluid flow in the
e fracture network,
reservoir strongly depends on the flow properties of th
with the isolated matrix blocks acting as the hydrocarbon storage. Most
reservoir rocks are to some extent fractured, but the fractures have in many
cases in significant effect on fluid flow performance and may be ignored. In
fractured reservoirs, defined as reservoirs where the fractures
naturally
have a significant impact on performance and oil recovery, fracture
properties should be evaluated because they control the efficiency of oil
e failure induced by
production. Fractures are usually caused by brittl
geological features such as folding, faulting, weathering and release of
lithostatic (overburden) pressure. Fractured reservoirs may be divided into
categories characterized by the relationship between matrix and fracture
ch as permeability and porosity. Defined four categories of
properties su
fractured reservoirs based on the ratio between permeability and porosity
in their comprehensive study of fractured reservoirs in the US as follows.
(Ameen, 2003)
little to no porosity and permeability in the matrix. The
-
Type I
interconnected fracture network constitutes the hydrocarbon storage and
controls the fluid flow to producing well.

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low matrix porosity and permeability. Some of the hydrocarbons
-
Type II
are stored in matrix. Fractures control the fluid flow, and fracture
intensity and distribution dictates production.
high matrix porosity and low matrix permeability. Majority of the
-
Type III
capacity, the
hydrocarbons are stored in matrix. Matrix provides storage
fracture network transport hydrocarbons to producing wells.
high matrix porosity and permeability. The effects of the
-
Type IV
fracture network are less significant on fluid flow. In this type category
lity instead of dictating fluid flow.
reservoir fractures enhance permeabi
(Ameen, 2003)
(ResearchGate.net, 2016)
Figure: Fracture types
2
The four types of fractured reservoir defined above honors the geological
features related to hydrocarbon storage and the relationship between
permeability and porosity. Furthermore, the production characteristics of

14. 14
tional reservoirs in many
fractured reservoirs differ from conven
.
fundamental ways. Some of the most pronoun differences are listed below
1-Due to high transmissibility of fluids in the fracture network, the pressure
drop around a producing well is lower than in conventional reservoirs, and
pressure drop does not play as important role in production from fractured
reservoirs. Production is governed by the fracture/matrix interaction.
2-The GOR (gas-oil ratio) in fractured reservoirs generally remains lower
than conventional reservoirs, if the field is produced optimally. The high
permeability in the vertical fractures will lead the liberated gas towards the
top of the reservoir in contrast to towards producing well in conventional
reservoirs. This is to some degree sensitive to fracture spacing and
orientation and the position of producers. Liberated gas will form a
secondary gas gap at the top of reservoir or will expand the existing cap.
3-Fractured reservoirs generally lack transition zones. The oil-water and oil-
gas contacts are sharp contrasts prior to and during production. The high
fracture permeability allows the rapid re-equilibration of the fluid contacts.
(Ameen, 2003)

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2.2.1 Recovery in fractured reservoir:
Oil production from fractured oil reservoirs poses great challenges to the
oil industry, particularly because fractures may exhibit permeability’s that
are several orders of magnitude higher than the permeability of the rock
matrix. Low viscosity fluids used for enhanced oil recovery, such as gases or
supercritical fluids may channel into the high permeable fractures,
potentially leading to early breakthrough into the production well and low
sweep efficiency. Carbonate reservoirs usually exhibit low porosity and
may be extensively fractured. The oil-wet nature of the matrix reduces
capillary imbibition of water. Carbonate reservoirs contributes
substantially to US oil reserves, and the low primary recovery and the large
number of carbonate reservoirs in the US and around the world makes
them good targets for EOR efforts (Manrique, 2010)
2.3 Recovery Mechanisms in Fractured Reservoirs:
In fractured reservoirs there are four principal recovery processes, fluid
expansion, capillary imbibition, diffusion and gravity-controlled
displacement. We will describe each of these processes in turn. Initially the
reservoir is at high pressure with oil in both fracture and matrix. During
primary recovery, the pressure will drop. Since the fractures are well
connected, the pressure will drop rapidly in them, while the lower
permeability matrix will remain at high pressure. This leads to a pressure
difference between the matrix rock and the fractures: slowly there will be
flow of oil from matrix to fracture as the fluids expand. When we drop
below the bubble point, gas will evolve from solution and the expanding

16. 16
gas will lead to further recovery from the matrix. This process is effective,
but once the gas is connected in the system, principally only gas will be
produced, leaving significant quantities of oil. (Gong, 2017)
2.3.1 Primary Recovery:
The underground pressure in the oil reservoir is sufficient, then this
pressure will force the oil to the surface. Gaseous fuels, natural gas or water
are usually present, which also supply needed underground pressure.
Uses natural pressure of the reservoir to push crude oil to the surface
 Water Drive (70 to 80%)
•Solution gas drive (10 to 30%)
•Gas Cap Drive
•Gravity Drainage
•Fluid and Rock Expansion
Usually, about 20% of the oil in a reservoir can be extracted using primary
recovery methods. (hatiboglu, 2006)
2.3.2 Secondary Recovery:
Secondary oil recovery uses various techniques to aid in recovering oil from
depleted or low-pressure reservoirs. Sometimes pumps, such as beam
pumps and electrical submersible pumps (ESPs), are used to bring the oil
to the surface. Other secondary recovery techniques increase the

17. 17
reservoir's pressure by water injection, natural gas reinjection and gas lift,
which injects air, carbon dioxide or some other gas into the reservoir.
Together, primary and secondary recovery generally allow 25% to 35% of
the reservoir's oil to be recovered (hatiboglu, 2006)
2.3.3 Tertiary Recovery:
Tertiary Recovery, also known as Enhanced Oil Recovery (EOR), introduces
fluids that reduce viscosity and improve flow.Producing the oil that remain
in the part of the reservoir already swept by the displacing.
• increasing the displacement efficiency
(Part of the reservoir that was already swept in secondary recovery)
• Increasing the sweep efficiency
(Producing oil that remains in the part of the reservoir not swept by
displacing fluid)
• Increasing both displacement and sweep efficiencies
Allows additional 20% to 30% of the oil in the reservoir to be extracted
(hatiboglu, 2006)

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2.4 Enhanced Oil Recovery (EOR):
Enhanced oil recovery (abbreviated EOR) is the implementation of various
techniques for increasing the amount of crude oil that can be extracted
from an oil field. Enhanced oil recovery is also called improved oil recovery
or tertiary recovery, Enhanced oil recovery (EOR) methods can be divided
into thermal methods (e.g., steam methods) and non-thermal methods. No
thermal methods include in chemical methods (e.g., designer water,
polymer flooding, alkali/surfactant/polymer (ASP) flooding, surfactant
flooding) and nonchemical methods (e.g., miscible or immiscible gas
flooding). To place EOR methods in a proper physical context, recall that
hydrocarbons are trapped in the pores either by an unfavorable viscosity
ratio or by capillary forces acting on different scales. For instance, water
flooding or gas flooding (CO2, N2, etc.) with a high oil viscosity leads to an
unfavorable mobility ratio between displacing and displaced fluid. A large
fraction of the oil is not contacted by the injected fluid1 and the oil that is
contacted is poorly displaced. (Donaldson, 1989)
Figure 3: Oil recovery mechanisms (youngpetro.org, 2014)

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2.5 EOR classification:
•The processes in the EOR can be classified into 3 major categories. These
methods have their own and mainly related to the type of oil remaining to
be taken and reservoir characteristics (rock where the oil is)
•Chemical: 1) Surfactant flooding, 2) Micellar Polymer Flooding, 3) Polymer
Flooding 4) Alkaline or Caustic Flooding.
•Thermal: 1) Steam Flooding 2) Fire Flooding
•Miscible: 1) Carbon Dioxides Flooding, 2) Nitrogen and Flue Gas Flooding,
3) Enriched Hydrocarbon Gas Flooding (Donaldson, 1989)
2.5.1 Thermal recovery:
Thermal recovery methods are generally applicable to viscous, heavy oil
crudes, and involve the implementation of thermal energy or heat into the
reservoir to raise the temperature of the oil and reduce its viscosity.
Continues steam (or hot water) injection, cyclic steam stimulation (CSS), in-
situ combustion and steam assisted gravity drainage (SAGD) are the
popular thermal recovery methods. In the steam based methods, hot
steam is injected to the reservoir through injection wells and oil flow to the
surface through production wells. In-situ combustion involves the injection
of air, where the oil is ignited, generates heat internally and also produces
combustion gases, which enhance recovery. Totally, thermal recovery
methods have been applied in lower depth and API degree and higher oil
viscosity compared to the other methods. (Donaldson, 1989)

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2.5.2 Steam Flooding:
In a steam flood, sometimes known as a steam drive, some wells are used
as steam injection wells and other wells are used for oil production. Two
mechanisms are at work to improve the amount of oil recovered. The first
is to heat the oil to higher temperatures and to thereby decrease its
viscosity so that it more easily flows through the formation toward the
producing wells. A second mechanism is the physical displacement
employing in a manner similar to water flooding, in which oil is meant to be
pushed to the production wells. While more steam is needed for this
method than for the cyclic method, it is typically more effective at
recovering a larger portion of the oil. A form of steam flooding that has
become popular in the Alberta tar sands is steam assisted gravity drainage
(SAGD), in which two horizontal wells are drilled, one a few meters above
the other, and steam is injected into the upper one. The intent is to reduce
the viscosity of the bitumen to the point where gravity will pull it down into
the producing well. (Donaldson, 1989)
Figure 4: SAGD process (ikanmedia.tv, 2014)

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2.5.3 Cyclic Steam Stimulation:
This method, also known as the Huff and Puff method, consists of 3 stages:
• 1)injection
• 2)soaking
• 3) Production.
• Steam is first injected into a well for a certain amount of time to heat the
oil in the surrounding reservoir to a temperature at which it flows. After it
is decided enough steam has been injected, the steam is usually left to
"soak" for some time after (typically not more than a few days). Then oil is
produced out of the same well, at first by natural flow (since the steam
injection will have increased the reservoir pressure) and then by artificial
lift. Production will decrease as the oil cools down, and once production
reaches an economically determined level the steps are repeated again.
• The process can be quite effective, especially in the first few cycles.
However, it is typically only able to recover approximately 20% of the
Original Oil in Place (OOIP), compared to steam flooding which has been
reported to recover over 50% of OOIP. It is quite common for wells to be
produced in the cyclic steam manner for a few cycles before being put on a
steam flooding regime with other wells.
• The mechanism was accidentally discovered by Shell while it was doing a
steam flood in Venezuela and one of its steam injectors blew out and ended
up producing oil at much higher rates than a conventional production well
in a similar environment.

22. 22
Figure 5: Cyclic steam stimulation (independent.com, 2017)
2.5.4 Steam stimulation:
Steam Stimulation (steam huff and puff, steam soak, or cyclic steam
injection)
The process involves
–Injection of 5000–15,000 bbl. of high quality steam.
–Shutting-in the well (from 1-5 days) to allow the steam to soak the area
around the injection well
–Placing the injection well into production.
•The length of the production period is dictated by the oil production rate
the cycle is repeated as many times as is economically feasible.

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•Mechanisms of this process include1)
•Reduction of flow resistance by reducing crude oil viscosity.
• Enhancement of the solution gas drive mechanism by decreasing the gas
solubility in an oil as temperature increases.
•Recoveries of additional oil have ranged from 0.21 to 5.0 bbl. of oil per
barrel of steam injected. (Donaldson, 1989)
2.5.4.1 EOR-Steam injection-criteria:
Table 2: Steam injection criteria (slideshare.net, 2015)

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2.5.5 Steam drive:
•It is like a conventional water flood. Steam is injected into several injection
wells while the oil is produced from other wells. (Diff. from steam
stimulation)
•Some thermal energy is lost in heating the formation rock and water
•The steam moves through the reservoir and comes in contact with cold
oil, rock, and water.
•As the steam comes in contact with the cold environment, it condenses
and a hot water bank is formed. This hot water bank acts as a water flood
and pushes additional oil to the producing wells. (Donaldson, 1989)
2.5.5.1 Mechanisms of this process:
– include thermal expansion of the crude oil,
–viscosity reduction of the crude oil,
–changes in surface forces as the reservoir temperature increases,
–and steam distillation of the lighter portions of the crude oil.
•This application is limited due to loss of heat energy. In deep wells,
steam will be converted to liquid water
•Oil recoveries have ranged from 0.3 to 0.6 bbl. of oil per barrel of steam
injected.
•More expensive than steam stimulation (Donaldson, 1989)

25. 25
2.5.6 In situ combustion:
•Forward dry combustion process
–Ignition of crude oil down hole.
–Injection of steam of oxygen enriched air
–Propagation of flame front through the reservoir heating oil.
–Heat loss
•Wet combustion process
–-Beginning as a dry process
–Once flame front is established, the oxygen stream is replaced by water.
–Water meets hot zone left by combustion front,
–Turns into steam, and aids the displacement of oil.-
–Usage of otherwise wasted energy
•Not all crude oils are amenable to the combustion process.-Heavy
components must be enough in crude oil to serve as the fuel source for the
combustion, so low API gravity oil is required.
•As the heavy components in the oil are combusted, lighter components as
well as flue gases are formed. These gases are produced with the oil and
raise the effective API gravity of the produced oil. (Donaldson, 1989)
Figure 6: In situ combustion (pipingguide.net,2017)

26. 26
2.5.7 Natural Gas injection:
Sometimes known as cycling, gas injection can entail re-injection of
produced natural gas. As the pressure drops in a natural gas field, the
condensate separates from the dry gas in the reservoir. The condensate
liquids block the pores within the reservoir, making extraction practically
impossible.
•Cycling is used to prevent the condensate from separating from the
natural gas in the reservoir. In this process, the natural gas liquids
(condensate) are stripped from the gas on the surface after it has been
produced from the reservoir, and the dry gas is then re-injected into the
reservoir through injection wells. Again, this helps to maintain pressure in
the reservoir while also preventing the separation within the hydrocarbon.
•Additionally, gas injection can serve as an economical way to dispose of
uneconomical gas production on an oil reservoir.
•In the past, low levels of natural gas that were produced from oil fields
were flared or burned off.
•This practice is discouraged in some countries by environmental
regulations (S. Lee, 2013)
2.5.7.1 Gas injection-criteria:
Table 3: Gas injection criteria (airproducts.com, 2012)

27. 27
2.5.8 Nitrogen flooding:
The following conditions should be met for applying nitrogen flooding:
–The reservoir oil must be rich in ethane through hexane (C2-C6) or lighter
hydrocarbons. These crudes are characterized as "light oils" having an API
gravity higher than 35 degrees.
–The oil should have a high formation-volume factor – the capability of
absorbing added gas under reservoir conditions.
–The oil should be under-saturated or low in methane (C1).
–The reservoir should be at least 5,000 feet deep to withstand the high
injection pressure (in excess of 5,000 psi) necessary for the oil to attain
miscibility with nitrogen without fracturing the producing formation.
•Nitrogen can be separated from air by cryogenic methods. So there is
unlimited source for this gas.
Figure 7: Nitrogen injection (energy.gov, 2015)
•When nitrogen is injected into a reservoir, it forms a miscible front by
vaporizing some of the lighter components from the oil.

28. 28
•Natural gas enriched nitrogen front moves away from the injection wells,
contacting new oil and vaporizing more components, thereby enriching
itself still further.
•The leading edge of this gas front becomes so enriched that it goes into
solution, or becomes miscible, with the reservoir oil. At this time, the
interface between the oil and gas disappears, and the fluids blend as one.
•Continued injection of nitrogen pushes the miscible front through the
reservoir, moving a bank of displaced oil toward production wells.
•Water slugs are injected alternately with the nitrogen to increase the
sweep efficiency and oil recovery (Arthur J. Kidnay, 2011)
2.5.9 CO2 injection:
•When a reservoir’s pressure is depleted through primary and secondary
production, carbon dioxide flooding can be an ideal tertiary recovery
method
•It’s particularly effective in reservoirs deeper than 2,000ft., where CO2 will
be in a supercritical state
•On injecting CO2 into the reservoir, it dissolves in oil, the oil swells and the
viscosity of any hydrocarbon will be reduced and hence, it will be easier to
sweep to the production well
•If the well is suitable for CO2 flooding, then the pressure is restored by
water injection. Then CO2 is injected
•In these applications, between one-half and two-thirds of the injected
CO2 returns with the produced oil.

29. 29
•This is then usually re-injected into the reservoir to minimize operating
costs.
•Carbon dioxide as a solvent has the benefit of being more economical
than other similarly miscible fluids such as propane and butane.
•Unless natural CO2 exists in the near area, it’s generally difficult to
collect sufficient amounts of CO2 for industry use.
•Availability of CO2 from the flue gas of coal power plants makes CO2
injection method more economical (S. Lee, 2013)
Figure 8: CO2 injection (studyblue.com, 2016)

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2.5.9.1 Gas injection advantageous:
Table 4: Advantages of gas injection (slideshare.net, 2015)
2.5.10 chemical flooding:
•The injection of various chemicals, usually as dilute solutions, have been
used to aid mobility and the reduction in surface tension.
•Injection of alkaline or caustic solutions into reservoirs with oil that has
organic acids naturally occurring in the oil will result in the production of
soap that may lower the interfacial tension enough to increase production.
•Injection of a dilute solution of a water soluble polymer to increase the
viscosity of the injected water can increase the amount of oil recovered in
some formations.
•Dilute solutions of surfactants such as petroleum sulfonates or bio
surfactants may be injected to lower the interfacial tension or capillary
pressure that obstructs oil droplets from moving through a reservoir.
Special formulations of oil, water and surfactant, micro emulsions can be
particularly effective in this.

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2.5.10.1 Chemical EOR in Large Fractured Carbonate Reservoirs:
In the U.S, typically about a third of the original oil in place (OOIP) is
recovered by primary and secondary recovery processes, leaving two-thirds
of the oil behind as remaining oil. About 60% of world’s discovered oil
reserves are in carbonate reservoirs, and many of these reservoirs are
naturally fractured. According to a recent review of 100 fractured
reservoirs fractured carbonate reservoirs with high matrix porosity and low
matrix permeability could be good candidates for enhanced oil recovery
(EOR) processes. The oil recovery from these reservoirs is typically very low
because about 80% of fractured carbonate reservoirs are either oil-wet or
mixed-wet. Injected water will not penetrate easily into the oil-wet porous
matrix to displace oil (Sheng, 2010). Wettability of carbonate reservoirs
probably is the most important oil recovery controlling parameter. Typically
water injection is used to improve oil recovery, while gas injection is used
to maintain pressure or to promote oil gravity drainage as an IOR process.
If gas injection is miscible or near-miscible, oil recovery is enhanced
because a fraction of the conventional residual oil is mobilized by miscibility
or near-miscibility conditions. Water and gas injection have been used to
produce oil from the matrix in naturally fractured reservoirs (NFR) mainly
by gravity drainage. Viscous displacement in fracture-dominated NFR
generally plays a minor role except for chemical flooding, where surfactants
might enter the matrix from fractures with assistance from viscous
displacement to mobilize oil. Even this effect appears to be small because
of the lack of deep surfactant penetration.
In water-wet NFR, water imbibes strongly into the matrix and produces a
lot of oil. However, in oil-wet reservoirs, water-flooding is relatively
inefficient. This is characterized by the early water breakthrough and
rapidly increasing water-oil ratio. The reason is that, for an oil-wet

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reservoir, the injected water tends to travel only through the fractures and
not enter the pores of the rock matrix. The same processes take place
during primary production in a fractured reservoir with a strong aquifer.
(Schramm, 2000)
2.5.10.2 Chemical flooding criteria:
Table 5: Chemical flooding criteria (slideshare.net, 2015)
2.5.11 Polymer flooding:
•In polymer flooding, the polymers used reduces the "surface tension"
between the oil and the oil-containing rock within the oil reservoir,
"freeing" the trapped oil making it easier to flow to the production well(s).
•Polyacrylamide powder or "PAM" is a non-toxic powder that is having
long-chain molecule is used in polymer flooding
•PAM makes the water "gel" greatly improving the production of oil. The
water injected becomes more "viscous" or thick, much like a gel and is
particularly beneficial in heavy oil recovery

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•Benefits:
–Improved oil recovery
–Increased "sweep efficiency"
–Significantly less water required when compared with typical water-
flooding & steam injection
–Superior EOR technology with "heavy oil" formations/reservoirs with low
viscosity and where Steam Assisted Gravity Drainage (SAGD) is not suitable.
(polymerflooding.com, 2013)
2.5.11.1 Mechanisms That Improve Recovery Efficiency:
•The added PAM increases the viscosity of the water to that of a gel making
the oil and water greatly improving the efficiency of the water flood.
•Three potential ways for more efficient oil recovery
–1) through the effects of polymers on fractional flow,
– (2) By decreasing the water/oil mobility ratio,
– (3) By diverting injected water from zones that have been swept.
•Mobility Ratio

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To get a low mobility factor, the viscosity of water should be increased.
•In water injection the fingering effect reduce sweep efficiency. But in
polymer flooding this finger effect is not present. Fingering causes to flow
water along with oil through production line (polymerflooding.com, 2013)
Figure 9: Polymer injection (studyblue.com, 2016)
2.5.11.2 Limitations:
High oil viscosities require a higher polymer concentration. Results are
normally better if the polymer flood is started before the water-oil ratio
becomes excessively high. Clays increase polymer adsorption. Some
heterogeneity is acceptable, but avoid extensive fractures. If fractures are
present, the cross linked or gelled polymer techniques may be applicable.
(Zerkalov, 2015)

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2.5.11.3 Polymer flooding criteria:
2.5.12 Microbial injection:
Currently global energy production from fossil fuels is about 80-90% with
oil and gas representing about 60 %. During oil production, primary oil
recovery can account for between 30-40 % oil productions. While
additional 15-25% can be recovered by secondary methods such as water
injection leaving behind about 35-55 % of oil as residual oil in the reservoirs.
This residual oil is usually the target of many enhanced oil recovery
technologies and it amounts to about 2-4 trillion barrels. Microbial
Enhanced Oil Recovery (MEOR) is a technology using micro-organisms to
facilitate, increase or extend oil production from reservoir. (Biji Shibulal,
2014)
Table 6: Polymer flooding criteria (slideshare.net, 2015)

36. 36
2.5.12.1 Advantages of MEOR:
 Microbes do not consume large amounts of energy
 The injected bacteria and nutrient are inexpensive and easy to obtain
and handle in the Field
 Economically attractive for marginally producing oil fields; a suitable
alternative before
 According to a statistical evaluation (1995 in U.S.), 81% of all MEOR
projects the abandonment of marginal wells Demonstrated a positive
incremental increase in oil production and no decrease in oil production
as a result of MEOR processes. (Yen, 1989)
Figure 10: Microbial injection. (lizinan.wordpress.com, 2011)

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2.5.12.2 Disadvantages of MEOR:
The microbial enhanced oil recovery process may modify the
immediate reservoir environment by damaging the production hardware
or the formation itself. Certain sulfate reducers can produce hydrogen
sulfide, which can corrode pipeline and other components of the recovery
equipment.
· Safety, Health, and Environment (SHE)
· A better understanding of the mechanisms of MEOR
· The ability of bacteria to plug reservoirs
·Numerical simulations should be developed to guide the application
of MEOR in fields · (Yen, 1989)

38. 38
2.5.13 Other Upcoming Technologies:
Nano can be named one of the new science in oil industry. One of the major
characteristics of Nano-technology is the ability to combine it with other
methods of EOR. Generally it can be said Nano technology refers to the
ability to complete and fix the weakness of the old ways and discover the
new mechanisms for EOR to continue the way.
The table show that Nano technology is the best choose were the other
method can’t use or have not good oil recovery such as low permeability,
high salinity or hardness,
Table 7: Nano fluid against other EOR methods (slideshare.net, 2016)
Nano fluid can use to change properties of reservoir such as:
• Fluid-fluid properties: interfacial tension, viscosity
• fluid-rock properties: contact angle, relative permeability
• Thermal conductivity of injection fluid (Petroleum, 2017)

39. 39
Chapter Three:
3.1 Case studies & results:
3.1.1 (Nano fluid in Egypt)
El-Diasty and Salem, 2013 investigated using Nano silica particles on real
Egyptian formation to compare between using water flooding and Nano
fluid flooding as EOR methods. As shown in next slide, it is obvious that
using water flooding to displace the oil in place recovered 36% of IOIP at
the breakthrough point while the Nano fluid flooding recovered 67% of IOIP
at the breakthrough point. This is an evidence for the ability of the Nano
fluid to displace the oil better than the water. (Zhang, 2017)
Figure 11: Nano fluid VS Water flood (researchgate.net, 2013)

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3.1.2 (EOR in Iran):
To study EOR screening methods, a naturally fractured reservoir in south
western of Iran, whose properties are summarized in the table below, is
considered as a case study. Development of the field has not begun yet.
The field is like a symmetrical anticline, 90 km in length and 16 km width at
the surface. This involves 60 km length and 10 km width on the 1000 mss
depth of Jahrum and 60 km length and 9.8 km width on the 2000 mss depth
of the Sarvak formations. A large number of faults cut the axial plane of the
structure causing some strata displacements around the central and
plunging parts of the structure. The Sarvak formation with an average
thickness of 300 m is an important formation in the Ultra Heavy Oil projects.
This formation mostly consists of limestone with some interbedded shale
layers. By using the results gained from cores and surface studies, mud
losses data and the technique of the radius of curvature, it is concluded
that this field, especially the reservoirs (Jahrum and Sarvak), is highly
fractured in such a way that most of these fractures are vertical. The
average dips of the southwest and northeast flanks of the structure are 17°
and 15°, respectively. The oil reservoir is an oil-wet carbonate reservoir
located at a depth of 1450 ft. The reservoir, which belongs to a main Iranian
formation, has a total net pay thickness of 312 ft. Also, this reservoir has a
maximum gross thickness of 1100 ft. and contains 0.832×10^9 bbl. original
volume of oil in place. According to petro physical evaluation, the formation
limestone has the porosity in the range of 19-31% and water saturation
around 20%. The permeability, depth and API degree have been reported
50 md, 1450 ft. and 14, respectively. (Arash Kamar, 2014)

41. 41
3.1.2.1 Results:
3.1.2.1.1 Quick screening:
In this study, in order to select the most appropriate EOR method for
applying in our case study reservoir EORgui 1.0 software (EORgui 1.0
software, 2013) was used. Therefore, the values of most critical parameters
such as API degree, depth, oil viscosity and saturation, formation type,
reservoir thickness, composition, reservoir temperature and rock
permeability have been introduced to the software. The results show that
the most appropriate method for implementation in the reservoir is steam
flooding method, because this reservoir has high API degree, high viscosity,
heavy oil, low depth and, etc. As previously mentioned, thermal EOR
methods are applied in heavy and viscous oils. Therefore, steam flooding
method can be an optimal EOR method in order to enhancing oil recovery
in the under-survey reservoir. (Arash Kamar, 2014)
Table 8: Critical data for EOR screening (researchgate.net, 2014)

42. 42
Table 9: Results summary of EOR screening, (*Accuracy percent as well as priority class). (researchgate.net, 2014)
Table 9 summarized the results of the quick screening. This Table shows
that the in-situ combustion and immiscible methods are placed on the
second rank in terms of accuracy with 50%. The accuracy of CO2 miscible
flooding method is 44% and this method can be used in the reservoir after
steam, in-situ combustion and immiscible flooding methods according to
its screening criteria. Moreover, the accuracy of chemical-based
(micellar/polymer, ASP and alkaline) and polymer flooding are reported 36
and 30%, respectively. As previously mentioned, chemical flooding
methods are recommended for oils higher than 15 API degree and viscosity
in range of 15-35cp and greater depths. Also, the quick screening indicated
that the gas injection methods including nitrogen and hydrocarbon
flooding are not strongly recommended for applying in the reservoir due to
being contradictory of their criteria with the reservoir condition. Figure 12
represents obtained accuracy for the EOR methods graphically. (Arash
Kamar, 2014)

43. 43
3.1.2.1.2 Simulation Study and Prediction:
In this part of the study, the optimal EOR method (steam flooding) for the
under-survey reservoir was simulated in order to predict the oil rates. For
this reason, 2000 bbl. per day for steam injection rate, 1800 psi for injection
pressure, 0.9 for steam quality and 40 acre for pattern area are considered.
No heat loss is assumed as surface line heat loss method. Figure 13
indicates predicted semiannual oil production and cumulative oil rates per
40 acre pattern area. Original oil in place for 40 ac pattern area is
4651×10^3 bbl. and 3835.1×10^3 bbl. is reported for ultimate oil rates in
Jan-2031.
Figure 14 shows semiannual and cumulative steam injection rates per 40
acre pattern area for under-survey reservoir. By comparing the above
results, it can be concluded that the steam flooding method is a successful
approach for applying in the under-survey reservoir, because of its
excellent ultimate recovery factor (0.82.4%). Figure 15 represents obtained
Figure 12: Graphical results of screened EOR methods (researchgate.net, 2014)

44. 44
recovery factor values by using steam flooding method during 19 years
simulation. Finally, it should be noted that to achieve a successful EOR
project, economic policies and limitations must be considered in addition
to technical EOR screening. (Arash Kamar, 2014)
Figure 13: Simulated oil production by using steam flooding method during 19 years. (researchgate.net, 2014)
Figure 14: Injected steam to the reservoir during 19 years. (researchgate.net, 2014)

45. 45
Figure 15: Obtained oil recovery factor by using steam flooding method. (researchgate.net, 2014)

46. 46
Chapter Four:
4.1 CONCLUSION:
I) In this research, at first, different types of EOR methods were summarized
and then in the second case study a screening approach has been applied
for an Iranian heavy oil reservoir. This study confirms the important role of
screening approach to correct selection of an EOR method for a particular
reservoir. This clearly makes savings in time and cost, and reduces the risk.
Moreover, accurate recognize the criteria associated to any EOR methods
and rock and fluid properties can contribute to a useful and constructive
screening.
II) In addition to EOR other mechanisms have significant effects on
improving oil recovery such as production strategy, reservoir stimulation,
type of completion etc.
III) Besides the simulation process which can accurately decide the best
plan of recovery, other things must be considered such as economics and
environmental effects.
IV) Table 10 demonstrates the distribution of recovery mechanisms in
Middle East.

47. 47
V) Fractures have benefits and limitations during EOR process:
Risks:
1) Fractures may cause direct channeling between injection wells and
production wells (early breakthrough)
Table 10: Production Processes and EOR Evaluations in Middle East carbonate reservoirs (searchanddiscovery.com, 2010)
Figure 16: Breakthrough due to fractures (uis.no, 2013)

48. 48
2) Fractures may extend “out of zone”.
3) Most CO2 floods occur in 1-10 md carbonates, where many natural
fractures exist and cause breakthrough because (Permeability of a 1-mm-
wide fracture is over 8 million times greater than that for 10-md rock).
Benefits:
1) For water and surfactant imbibition processes, large fracture areas are
critical to making the process work.
2) With vertical wells, fractures or fracture-like features must be open
during polymer injection.
VI) The below figure shows the most used EOR methods worldwide.
Figure 17: Out of zone fracture (uis.no, 2013)
Figure 18: EOR worldwide (slideshare.net, 2013)

49. 49
4.2 Recommendations:
EOR has environmental effects that must be considered during screening
process for example EOR in fracture reservoir wells typically produces large
quantities of brine at the surface. The brine may contain toxic metals and
radioactive substances, as well as being very salty. This can be very
damaging to drinking water sources and the environment generally if not
properly controlled. But EOR has also good impacts for example Using
CO2 captured from power plants and industrial sources to enhance oil
production has the potential to help the U.S. reduce its emissions by
improving the CO2 intensity of the industrial and power generation sectors.
Over the life of a project, for every 2.5 barrels of oil produced, it is
estimated that EOR can safely prevent one metric ton of CO2 from entering
the atmosphere. (DOE/NETL, 2011)
Before applying an EOR technique or any other production plan simulations
must be run and models must be built to apply the most effective strategy.
That’s why simulations software play a major role in the process. Some of
the frequently used software are BOAST (used by the U.S department of
energy), MRST (MATLAB simulation toolbox), OPM, Schlumbergers
INTERSECT and ECLIPSE, CMG, Tempest MORE, ExcSim, Nexus, ResAssure,
tNavigator, FlowSim, ReservoirGrail, Merlin (used by Bureau of Ocean
Energy Management).

50. 50
Chapter Five:
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