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

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

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

4

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

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

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

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

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

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

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)

11

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)

12

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.

13

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

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)

15

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

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

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)

18

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)

19

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)

20

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)

21

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

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.

23

•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)

24

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

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

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

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

•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

•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)

30

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.

31

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

32

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

33

•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

34

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)

35

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

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)

37

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

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

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)

40

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

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

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

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

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

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

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

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

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

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

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