Tertiary Enhanced Oil Recovery

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RESERVOIR ENGINEERING

Enhanced (Tertiary) Oil Recovery EOR Essay

PRESENTATION OF THE DOCUMENT

Author

MOKDAD Belkhir
AKUANYIONWU Obinna
CORVATTA Luigi

Title

Enhanced (Tertiary) Oil Recovery EOR – An Overview.

Abstract

As all EOR processes are reservoir and reservoir – fluid specific, it is
necessary to identify the appropriate EOR Technology for use in a
reservoir, design the project to achieve the required economic
incremental recovery and manage the project to meet or exceed
expectation. Production from non – conventional oil sources generally
requires higher oil prices. Costs are higher because of the need for
injectants and for better surveillance, and required surface facilities.
Different aspects of the EOR are given in this report and the steps for EOR
Projects.

Keywords

EOR, Thermal recovery, steamflooding, Cyclic steam stimulation, in situ
combustion, Miscible recovery, Carbon dioxide flooding, Cyclic carbon
dioxide stimulation, Nitrogen flooding, Nitrogen - CO2 flooding, Chemical
recovery, Polymer flooding, Micellar-polymer flooding, Alkaline flooding,
EOR Cost, Mechanism

Contents

26
13
6
11

Pages
Figures
Tables
References

TABLES OF CONTENTS

Contents

Page No

I



Introduction................................................................................................................. 5

II



Definition of Tertiary EOR ............................................................................................... 5

III



EOR Project Planning – Process Selection .......................................................................... 6
III – 1 Data Collection ................................................................................................... 6
III – 2 Modelling ........................................................................................................... 7
III – 3 Economic Screening............................................................................................. 7

IV



The EOR techniques ...................................................................................................... 8
IV – 1 Thermal recovery (Fig. 8) ..................................................................................... 8
a) steamflooding. .................................................................................................. 9
b) Cyclic steam stimulation. .................................................................................... 9
c) In situ combustion. ............................................................................................ 9
IV – 2 Miscible recovery (Fig. 9) ...................................................................................... 9
a) Carbon dioxide flooding. ..................................................................................... 9
b) Cyclic carbon dioxide stimulation.......................................................................... 9
c) Nitrogen flooding ............................................................................................. 10
d) Nitrogen - CO2 flooding .................................................................................... 10
IV – 3 Chemical recovery (Fig. 10)................................................................................. 10
a) Polymer flooding ............................................................................................. 10
b) Micellar-polymer flooding.................................................................................. 10
c) Alkaline flooding .............................................................................................. 10
IV – 4 Other recoveries (Fig. 11 & 12) ............................................................................ 10

V



Targets for EOR .......................................................................................................... 11

VI



Actual and Projected Oil Recovery.................................................................................. 11

VII –

The Unfulfilled promise of Enhanced Oil Recovery ............................................................. 11
VII – 1 Steam Injection ............................................................................................... 12
VII – 2 Carbon Dioxide Flooding .................................................................................... 12
VII – 3 Miscible Flooding .............................................................................................. 12

VIII –

Conclusion................................................................................................................. 12

Figures

Reference

Figure

1

Oil Recovery Mechanism

(Ref. 1, 2)

Figure

2

EOR Activity and production response

(Ref. 5)

Figure

3

Effective EOR Project Management

(Ref. 8)

Figure

4

Cost Performance comparison of major EOR Method

(Ref. 3)

Figure

5

Effect of the EOR on the production

(Ref. 11)

Figure

6

Historical Growth of EOR in the United States and the World

(Ref. 7)

Figure

7

EOR in the United States by Major Processes

(Ref. 9)

Figure

8

Thermal recovery

(Ref. 11)

Figure

9

Miscible recovery

(Ref. 11)

Chemical recovery

(Ref. 11)

Figure 11

Microbial flooding recovery

(Ref. 11)

Figure 12

Cycling Microbial recovery

(Ref. 11)

Figure 13

Prevision of the percentage of EOR over the United States and the world

Figure 10

Tables
Table 1

Active US EOR Project

(Ref. 9)

Table 2

Questions for processes selection

(Ref. 8)

Table 3

EOR Cost Database

(Ref. 10)

Table 4

US EOR Production

(Ref. 9)

Table 5

Performance of the Basic EOR Processes

(Ref. 10)

Table 6

Actual and Projected oil recovery by processes for the US and the world

(Ref. 7)

I – Introduction
Nowadays, the increasing request of energy required to industry developments in one hand, and
the fall in reserve in the other hand, lead to find new sources of hydrocarbons or enhance
productivity of mature fields. Nevertheless, the recovery depends on the proper technologies,
economic viability and effective reservoir management strategies. The interest in Enhanced Oil
Recovery (EOR) and its application were fluctuating with oil price.
Interest of companies for enhanced recovery factor such as tertiary recovery, infills, horizontals,
and optimal placement of the new wells are the elements of reservoir development.
We will be concerned here mainly with the Enhanced (Tertiary) Oil Recovery.
An outline of the main aspects of the tertiary (EOR) is given in this report with an emphasis on
the review and critical analysis of tertiary recovery techniques including the theoretical, practical
and economical aspects.

II – Definition of Tertiary EOR
Figure 1 shows the different oil recovery mechanisms. We distinguish 02 main types; the first
one is the Conventional Oil Recovery (Primary and Secondary oil recovery), the second one is
the Tertiary Recovery. A brief definition should be given as a rough to understand the different
type of oil recovery mechanism:


Primary Recovery : Production depends on the natural energy of the
reservoir itself. The natural energy varies from pressure decline and the
accompanying evolution of dissolved gas, to the expansion of gas cap, or the
influx of water.



Secondary Recovery: When natural drive energy is depleted, energy must
be added to the reservoir to permit additional oil recovery. That additional
energy is usually in the form of injected water or gas. The process depends
mainly on physical displacement to recover additional oil. It can be said that it
mimics the natural process of water influx or gas expansion. The elements
forces are physical as opposed to thermal, chemical, solvent interfacial,
tension etc…

Until the early 1940s, economic dictated when a well was to be plugged and abandoned usually
after a recovery of 12 to 15% of original oil in place (OOIP) for primary recovery. Extensive
waterflooding which began in the 1940s, within a few decades became the established method
for secondary oil recovery, usually recovering about another 15 to 20% of OOIP.


Tertiary Recovery: In order to drain the oil not reachable (economically or
otherwise) by secondary means, tertiary processes may be considered, either
to mobilise oil through additional energy (thermal, etc) , by altering the
physical chemistry of the reservoir (surfactant, etc), or by some changes to
the relative mobilities (polymer, WAG, etc).

Wikipedia encyclopedia defines the EOR as follow:
“Enhanced Oil Recovery (EOR) is a technique for increasing the amount of oil that can be
extracted from an oil field. Using EOR, 30-60 %, or more, of the reservoir's original oil can be
extracted compared with 20-40 % using primary and secondary recovery.” (Ref. 4)

For the purpose of this paper, we will use the following definitions and Terminology used in the
SPE Literature:
“Enhanced Oil recovery (EOR) refers to reservoir processes that recover oil not
produced by secondary processes. Primary recovery uses the natural energy of the
reservoir to produce oil or gas. Secondary recovery use injectants to re-pressurize the
reservoir and to displace oil to producers. Enhanced Oil Recovery processes target
what’s left. They focus on the rock / oil / Injectant system and on the interplay and
viscous forces”
(Ref. 6)
The following chapters will introduce the main factors which induce to the process selection of
EOR. Every six month period for each year, the Oil and Gas Journal publish a survey article on
EOR activity. According to the figure 2 established by Oil and Gas Journal revue, the high oil
prices from 1980 to 1985 led to the larger number of EOR Projects, till the fall – off in the oil
prices which led to less number of EOR projects. The number of project in EOR is much related
to the oil prices. Table 1 confirms the behaviour of active US EOR Project with oil price. The year
2005 was the theatre of marked increase in oil price, which might explain the rise tendency with
9 more projects comparing with the previous year. The rise or decrease of EOR Projects is then
linked to the oil price. How then can we select the appropriate EOR in accordance with oil price,
and what are the main factors which may rise for the implementation of EOR?

III – EOR Project Planning – Process Selection
EOR Processes fall into two general categories:
Improving sweep efficiency:
Poor sweep efficiency results from either reservoir heterogeneities, or poor mobility ratio. The
use of methods that improve mobility ratio may also reduce the impact of reservoir
heterogeneity. Mobility ratio can be affected by decreasing the mobility of the injected fluid
(e.g., polymer flooding), or by increasing the mobility of the target hydrocarbons (e.g., thermal
methods).
Improving displacement efficiency:
Displacement efficiency is controlled by the capillary forces, which hold the oil in the reservoir
matrix. Methods that reduce the impact of these capillary forces include chemical (surfactant,
caustic, alkaline flooding) and miscible (hydrocarbon gas, carbon dioxide, nitrogen flooding).
Microbial processes rely on the use of in situ microbes to generate surfactants and polymers,
and so act to improve displacement efficiency.
Figure 3 illustrates roughly the interaction of economics, engineering planning and data
collection, and modelling for EOR process selection.
An outline of the step - process selection is given below in accordance with figure 3.

III – 1 Data Collection
Process selection can be summarized through three – step procedure. Thus, it is
necessary to:
- Determine the remaining hydrocarbon in place after conventional methods,
- Locate the resource,
- Understand why the oil was not recovered by primary and secondary recovery.

To be done, the characteristic of the reservoir and the fluid reservoir is required, ie core
analyses, fluid properties measurement, detailed production history and pressure
information have to be collected.
Once a target volume has been identified, and the relevant reservoir and fluid
information collected, screening of EOR processes for application takes place. The main
criteria for candidate processes is not wholly technical question, but mostly related to the
economic viability of the matching process.
Table 2 point up on the relevant questions for choice to the different processes. The
answers to these questions can not be done without being in combination with
geological, laboratory investigations, project economic analysis and project design. A
good understanding of the reservoir geology, especially its heterogeneity and pore scale
structures, is critical to the success of an EOR project.

III – 2 Modelling
The modelling of EOR projects is basically a five-step procedure:
- Select the appropriate reservoir simulator for conducting the project design
study,
- Collect valid input data,
- History match past production-pressure performance of the reservoir,
- predict future EOR project performance,
- determine the optimum EOR project design, by conducting sensitivity studies.
The modelling of EOR projects requires much more fluid and rock properties data than
waterflood secondary recovery project design studies, and the additional data required
depends upon the EOR process to be simulated.
Models for EOR are inherently different than those for conventional studies - by virtue of
the need to capture the fine scale structures and heterogeneity in a more representative
fashion will entrain a finer grid. Thus the end user need to think carefully of the gridding
strategy - it is not necessary to build a fine grid for the whole study (history matching
etc), but the ability to supplant finer scale refinements within areas of interest, or work
on extracted sectors and refine the grid properties is critical to the robustness of an EOR
study. Thus, gridding for a primary/secondary process should bear in mind the possible
desire to later screen for EOR.

III – 3 Economic Screening
For EOR Projects, the project profitability is the primary economic driver in most case.
The economics of an EOR Project are closely linked to the technical design of process.
Economic analysis should be carried out in tandem with the process screening and
process selection steps.
To date most fields wide EOR projects have been conducted onshore, since the facility
element (CAPEX) of any EOR project is high, and often difficult to justify late in an
offshore fields' life. These factors need to be borne in mind, but should not cloud the
engineers judgement in proposing the most successful reservoir processes to boost
recovery. Various tax breaks etc can be awarded to the operator to make the CAPEX side
more attractive.

The above section shows the importance of the EOR selection processes, and incrementing the
modeling through the geological, laboratory investigations with the project economic analysis
and project design. All the processes can not be done separately considering that each of them
interact consistently with the other.

Table 3 presents the worldwide cost database, which shows the average cost of the different
types of recovery processes; thermal, gas flooding, and chemical injection for projects that are
already carried out. For gas flooding (such as CO2 injection), the average total cost per barrel is
around US$ 12 – 20.
The following section gives the different type of EOR, which will be selected through the rigorous
process selection mentioned above.

IV – The EOR techniques
The three major EOR methods are thermal (application of heat), miscible (mixing of oil with a
solvent) and chemical (flooding with chemicals). Figure 4 shows roughly an overview of the Cost
Performance comparison of major EOR Method.
Figure 5 illustrates the effect of EOR on production.
Figure 6 show the historical growth of EOR in United States and the world. The United States are
considered as leader as regards in the EOR technology appliance. The percentage of total oil
produced for US production reach the crest in 2000 comparatively to the percentage of total oil
produced in the world seems to grow.
As the percentage of EOR in oil produced in US is significant rather in the world, we will focus on
the repartition of the different EOR production in US (Table 4 and figure 7). According to the Oil
& Gas Journal in his edition of April (figure 7), the tendency of the repartition of the different
EOR in EOR Production is changing. Indeed, during the last two decade, among the three major
EOR, thermal processes dominate, having the great certainty of success, and potential
application in about 70% of EOR Worldwide. Nowadays, the gas recovery is increasing by three
times than the gas recovery in 1986, while the thermal recovery is decreasing by 25%
comparing to the same recovery in 1986.
The term miscible means the mixing of two fluids – for instance oil and a solvent such as carbon
dioxide into a single phase fluid. It may also apply to a continuity between the oil and injected
gas. Use of miscible gasdrive has grown rapidly, and accounts for about 18% of EOR application
worldwide.
EOR Chemical processes have tantalized the industry with promises of significantly improved
recovery. As yet, cost and technical problem have precluded them from mainstream application.
IV – 1 Thermal recovery (Fig. 8)
This is accomplished either by hot fluid injection (Hot water or steam) or in situ
combustion (burning a part of the crude oil in place). Variations of these methods
improve production of crudes by heating them, thereby improving their mobility and ease
of recovery by fluid injection.
The following reservoir and crude oil characteristics apply for thermal recovery methods:
Steamflooding

In-Situ Combustion

Viscous oils

Moderate to viscous oil

Thick, shallow reservoirs

Some asphaltics for coke

High oil saturation

formation More than about 500 ft deep

High porosity

Permeability more than 100md

High permeability sands

a) steamflooding high-temperature steam is injected into a reservoir to heat the
oil. The oil expands, becomes less viscous and partially vaporizes, making it
easier to move to the production wells. Steamflooding is generally used in heavy
oil recovery to overcome the high viscosity that inhibits movement of the oil.
b) Cyclic steam stimulation, also known as the “huff-and-puff” method, is
sometimes applied to heavy-oil reservoirs to boost recovery during the primary
production phase. Steam is injected into the reservoir, then the well is shut in to
allow the steam to heat the producing formation around the well. After a sufficient
time, generally a week or two, the injection wells are placed back in production
until the heat is dissipated with the produced fluids. This cycle may be repeated
until the response becomes marginal because of declining natural reservoir
pressure and increased water production. At this stage a continuous steamflood is
usually initiated to continue the heating and thinning of the oil and to replace
declining reservoir pressure so that production may continue.
c) In situ combustion, or "Fireflooding," is commonly used to recover heavy oil
that is too viscous to be produced by conventional means. The fireflood is
generally maintained by igniting air to create a combustion zone that moves
through the formation toward production wells. The intense heat forms zones of
steam and vaporized oil that move in advance of the combustion zone toward
production wells, where the oil, water, and gases are brought to the surface and
separated.

IV – 2 Miscible recovery (Fig. 9)
Recovery methods in this category include both hydrocarbon and non – hydrocarbon
miscible flooding. These methods involve the injection of gases (carbon dioxide, nitrogen,
flue gases, etc.) that either are become miscible (mixable) with oil under reservoir
conditions. This reaction lowers the resistance of oil to flow through a reservoir, making
it more easily produced , either by water drive or injected gas pressure.
The following reservoir and crude oil characteristics apply for miscible recovery methods:

a) Carbon dioxide flooding is commonly used to recover oil from reservoirs in
which the initial pressure has been depleted through primary production and
possibly waterflooding. Water is injected into the reservoir until pressure is
restored to a desired level, then CO2 is introduced into the reservoir through
these same injection wells. As the CO2 is forced into the reservoir a zone of
miscible CO2 and light hydrocarbons forms a front that is soluble with the oil,
making it easier to move toward production wells. The initial CO2 slug is typically
followed by alternate water and CO2 injection - the water serving to improve
sweep efficiency and to minimize the amount of CO2 required for the flood.
Production is from an oil bank that forms ahead of the miscible front. As reservoir
fluids are produced through production wells, the CO2 reverts to a gaseous state
and provides a "gas lift" similar to that of original reservoir natural gas pressure.
b)Cyclic carbon dioxide stimulation, also known as the “huff-and-puff”
method, is a single-well operation, which is developing as a method of rapidly
producing oil. Similar to the cyclic steam process, CO2 is injected into an oil
reservoir, the well is shut in for a time, providing for a "soak period," then is
opened, allowing the oil and fluids to be produced. The dissolving of the CO2 in
the oil reduces the oil’s viscosity and causes it to swell, allowing the oil to flow
more easily toward the well. The process can also be used in heavy oil reservoirs

by high-pressure injection of CO2 to facilitate miscibility between the oil and CO2,
and in cases where thermal methods are not feasible.
c)Nitrogen flooding can be used to recover "light oils" that are capable of
absorbing added gas under reservoir conditions, are low in methane, and at least
5,000 feet deep to withstand the high injection pressure necessary for the oil to
mix with the nitrogen without fracturing the producing formation. When nitrogen
is injected into a reservoir, it forms a miscible front by vaporizing lighter oil
components. As the front moves away from the injection wells its leading edge
goes into solution, or becomes miscible, with the reservoir oil. Continued injection
moves the bank of displaced oil toward production wells. Water slugs are injected
alternately with the nitrogen to increase the sweep efficiency and oil recovery.
Nitrogen can be manufactured on site at relatively low cost by extraction from air
by cryogenic separation, and being totally inert it is noncorrosive.
d)Nitrogen - CO2 flooding, because of its lower cost, the nitrogen can be used
in a CO2 flood to displace the CO2 slug and its oil bank.

IV – 3 Chemical recovery (Fig. 10)
The chemical flooding methods are polymer flooding (including polymer gels), micellarpolymer flooding, and alkaline flooding.
Chemical recovery methods include polymer, micellar-polymer and alkaline flooding.
a)Polymer flooding is used under certain reservoir conditions that lower the
efficiency of a regular waterflood, such as fractures or high-permeability regions
that channel or redirect the flow of injected water, or heavy oil that is resistant to
flow. Adding a water-soluble polymer to the waterflood allows the water to move
through more of the reservoir rock, resulting in a larger percentage of oil
recovery. Polymer gel is also used to shut off high-permeability zones.
b)Micellar-polymer flooding uses the injection of a micellar slug containing a
mixture of a surfactant, co surfactant, alcohol, brine, and oil that moves through
the oil-bearing formation, releasing much of the oil trapped in the rock. This
method is one of the most efficient EOR methods, but is also one of the most
costly to implement.

c)Alkaline flooding requires the injection of alkaline chemicals (lye or caustic
solutions) into a reservoir that react with petroleum acids to form surfactants that
help release the oil from the rock by reducing interfacial tension, changing the
rock surface wettability, or spontaneous mulsification. The oil can then be more
easily moved through the reservoir to production wells.
A new modification to the process is the addition of surfactant and polymer to the
alkali, giving rise to an alkaline-surfactantpolymer (ASP) EOR method, essentially
a less costly form of micellar-polymer flooding.

IV – 4 Other recoveries (Fig. 11 & 12)
Only microbial EOR methods will be approached in this section at the expense of the
other, as electrical, chemical leaching and mechanical side.
Two methods of flooding are employed using microbial techniques to enhance oil
production, microbial flooding and cyclic microbial recovery.

a) Microbial flooding. Microbial flooding is performed by injecting a solution of
microorganisms and a nutrient such as industrial molasses down injection wells
drilled into an oil-bearing reservoir. As the microorganisms feed on the nutrient,
they metabolically produce products ranging from acids and surfactants to certain
gases such as hydrogen and carbon dioxide. These products act upon the oil in
place in a variety of ways, making it easier to move the oil through the reservoir
to production wells.
b) Cyclic microbial recovery. one of the newest EOR methods, requires the
injection of a solution of microorganisms and nutrients down a well into an oil
reservoir. This injection can usually be performed in a matter of hours, depending
on the depth and permeability of the oil-bearing formation. Once injection is
accomplished, the injection well is shut in for days to weeks. During this time,
known as an incubation or soak period, the microorganisms feed on the nutrients
provided and multiply in number. These microorganisms produce substances
metabolically that affect the oil in place in ways that facilitate its flow, making it
easier to produce. Depending on the microorganisms used, these products may be
acids, surfactants, and certain gases, most notably hydrogen and carbon dioxide.

V – Targets for EOR
A general Summary of recovery mechanisms, potential problems, conducted and typical
performance for the basic EOR methods is shown in Table 5. Typical recoveries (expressed as a
percent of original oil in place or OOIP) are highest for steamflooding and lowest for polymer
and alkaline flooding. Oil recoveries for the gas processes may be slightly lower than recovery
from a properly designed surfactant flood, but large amounts of chemicals are required to
achieve the incremental production, A primary reason for the high recovery efficiency of steam
flooding is that candidate reservoirs cannot be waterflooded effectively; thus, oil saturation at
the beginning of the process are unusually high compared to most other EOR methods, with any
displacement process, it is generally easier to recover oil that is continuous than to mobilize
discontinuous oil that has been trapped by water injection.

VI – Actual and Projected Oil Recovery
Table 6 shows the percentage of oil produced by primary, secondary recovery and enhanced oil
recovery, for the US and the world for the period of 1970 to 2050. The table shows that US
reached their peack in 1970, and began to decline. The world oil production will reach the peak
in 2037 and will begin to decline.

VII – The Unfulfilled promise of Enhanced Oil Recovery
After the 1973 oil Embargo, in the USA, $19 billion were allocated for “energy independence”
with emphasis on EOR. Today, the reality is different from the promise in the 70th. Figure 8
show that the rate is near by 660.000 Barrels/days instead of 2 or 3 millions Barrels/days.
The general lack
-

of success with EOR can be summarized:
Money could be made simply from tax incentives, even if the process failed,
Application of successful processes to wrong reservoir conditions,
Faith in unscaled laboratory results,
Inadequate attention to geology,
Bad numerical simulations,
Insufficient research before starting field,
Inappropriate definitions of “success” and “failure”,
Few reports on failures

Some incorrect applications are given below for the different processes to emphasis the point
above:
VII – 1 Steam Injection
Cyclic steaming has been very successful in high viscosity oil, thick, high permeability,
shallow sands, but many cyclic operations were done in thin sands, with complex
geology.
VII – 2 Carbon Dioxide Flooding
- The Carbon Dioxide Flooding were applied to deep, high temperature reservoirs, with
no chance of miscible displacement of oil.
- Application to heterogeneous, complex, and fractured formations.
- Trying to pressurize a depleted reservoir to be able to do a carbon dioxide flood.
- Application at the end of a waterflood – too much water to move, too much loss of
carbon dioxide to water.

VII – 3 Miscible Flooding
- Of more than 100 floods, only a dozen have been commercially successful; failures
because of lack of attention to gravity segregation, and frontal stability.
- Incompatible oil and drive fluid compositions in multi-contact miscibility.
- Wrong choice of the drive gas (nitrogen? inert gas?)
- Optimistic simulations (poor control of diffusivity); unscaled experiments.

VIII – Conclusion
The EOR techniques depend highly on the geological data used for the modelling, but also on
the economic environments. The oil price, which was fluctuating, has a real control on the
number of project launched each year.
The oil prices for 2005 and 2006 were exceptionally high, reaching the 60 $/bbl. This tendency
might help to increase the number of project in EOR, and also help small company or
independent to target the oil left by the big oil company. With an cost average of 20$/bbl for
EOR, the small company can still earn money with the oil left behind.
2006 / 2007 should be a promising year for increasing Research & Development for EOR, and
lead to raise the number of project for EOR.

Figures

Fig 1 – Oil Recovery Mechanism

Fig 2 – EOR Activity and production response.

Fig. 3 – Effective EOR Project Management

Fig 4 – Cost Performance comparison of major EOR Method

Fig. 5 – Effect of the EOR on the production

Fig. 6 – Historical Growth of EOR in the United States and the World

EOR Production (1,000 bbls / day)

800
700
600
500

Gas
Chemical

400
300

Thermal
200
100
0
1986

1988

1990

1992

1994

1996

1998

2000

Fig. 7 – EOR in the United States by Major Processes

Fig. 8 – Thermal recovery

2002

2004

2006

Fig. 9 – Miscible recovery

Fig. 10 – Chemical recovery

Fig. 11 – Microbial flooding recovery

Fig. 12 – Cyclic Microbial recovery

Primary

Secondary

Tertiary

120
100
80
60
40
20
0
Us

Us

Us

Us

Us

1970

2000

2020

2037

2050

Primary

Secondary

Tertiary

120
100
80
60
40
20
0
World

World

World

World

World

1970

2000

2020

2037

2050

Fig. 13 – Prevision of the percentage of EOR over the United States and the world

1986

1988

1990

1992

1994

1996

1998

2000

2002

2004

2006

Thermal
Steam
Combustion in situ
Hot water
Total thermal

181
17
3
201

133
9
10
152

137
8
9
154

119
8
6
133

109
5
2
116

105
8
2
115

92
7
1
100

86
5
1
92

55
6
4
65

46
7
3
56

40
12
3
55

Chemical
Mecellar - polymer
Polymer
Caustic/alkaline
Surfactant
Total chemical

20
178
8
8
206

9
111
4
4
124

5
42
2
2
50

3
44
2
2
49

2
27
1
1
30

11
1
1
12

10
1
1
11

10

4

4

0

10

4

4

0

Hydrocarbon
miscible/immiscible

26

22

23

25

15

14

11

6

7

8

13

CO2 miscible
CO2 immiscible
Nitrogen

38
28
9

49
8
9

52
4
9

52
2
7

54
1
8

60
1
9

66
10

63
1
4

66
1
4

70
1
4

80
2
3

3

2

3

2

104

90

91

1
89

1
79

84

87

74

78

83

97

Other
Microbial
Total other

1
1

0
0

0
0

2
2

1
1

1
1

1
1

0
0

0
0

0
0

0
0

Grand total

512

366

295

273

226

212

199

176

147

143

152

Gas

Flue gas (miscible and
immiscible)
Other
Total gas

Table 1: Active US EOR Project.

Processes

Questions

For miscible processes:

- What is the anticipated phase behavior between reservoir
fluid and injectant?
- What is the mobility of the anticipated phase(s)?
- Will the process be first contact miscible or developed
miscibility?

For immiscible gas injection processes:

- What is the remaining oil saturation after waterflooding?
- What is residual to immiscible gas?
- How will fault blocks or low permeability layers be drained?

For chemical processes:

- What is the design of the chemical slug to develop the ultralow interfacial tension necessary for a successful
displacement?
- To what extent will the chemical interact with the clays in
the reservoir rock through adsorption?
- What is the salinity of the reservoir water, and how will that
salinity impact the activity of the chemical slug and change
during the process?
- How will mobility control of the oil bank and chemical bank
be accomplished?

For polymer processes:

- What is the polymer concentration necessary to provide
mobility control?
- What portion of the polymer slug will be adsorbed on the
clays in the reservoir rock?

For thermal processes:

- What are the anticipated thermal losses in the wellbore, to
cap and base rock, to water in the formation?
- Can the thermal front be controlled in the reservoir?
- Can the reservoir pressure be controlled in the range
necessary for efficient heating of the reservoir fluid?

For microbial processes:

- Can microbes be identified that can be sustained in the
reservoir, utilize in-situ nutrients and/or oxidants, and
generate surfactants and polymers, which will accomplish
the goals of the project?
- How will the microbes and/or their products be stably
transported through the reservoir?

For any EOR process:

- Can the process selected be used in the selected reservoir,
given the reservoir rock and fluid environment in place?
- Can this process be implemented in such a way that it will
result in an economically attractive project?

Table 2: Questions for processes selection

Cost US $/bbl of incremental oil

Process

Injectant

1

only

Total Process

Thermal
Steam

3-5

5-7

Purchased fuel

4-6

7-10

Gas
CO2

5-10

12-20

Surfactant (Micellar)

10-20

20-30

Alkaline

~7

Surfactant / Alkaline / Polymer

2-7

Polymer

1-5

Chemical

Table 3: EOR Cost Database

1

Includes injectant, investment, capital costs, taxes and operating expense.

~19
10-17
~2-7

Thermal
Steam
Combustion in situ
Hot water
Total thermal
Chemical
Mecellar - polymer
Polymer
Caustic/alkaline
Surfactant
Total chemical

1986

1988

1990

1992

1994

1996

1998

2000

2002

2004

2006

468,692
10,272
705
479,669

455,484
6,525
2,896
464,905

444,137
6,090
3,985
454,212

454,009
4,702
1,980
460,691

415,801
2,520
250
418,571

419,349
4,485
250
424,084

439,010
4,760
2,200
445,970

417,675
2781
306
417,675

365,717
2,384
3,360
371,461

340,253
1,901
3,360
345,514

286,668
13,260
1,776
301,704

1,403
15,313
185

1,509
20,992

617
11,219

254
1,940

64
1,828

0
139

0
139

0
1,598

16,901

22,501

20
11,856

2,194

1,892

139

139

60
1,658

60
60

60
60

0

33,767

25,935

55,386

113,072

99,693

96,263

102,053

124,500

95,300

97,300

95,800

28,440
1,349
18,510

64,192
420
19,050

95,591
95
22,260

144,973
95
22,580

161,486

170,715

179,024

23,050

28,017

28,117

189,493
66
14,700

187,410
66
14,700

205,775
102
14,700

234,420
2,698
14,700

26,150

21,400

17,300

11,000









6,300

4,400

4,350

4,350

0

0

0

0

108,216

130,997

190,632

298,020

288,629

299,345

313,544

328,759

297,476

317,877

347,618

0
604786

0
618403

0
656700

2
2
760907

2
2
709094

0
0
723568

0
0
759653

0
0
748092

0
0
668997

0
0
663451

0
0
649322

Gas
Hydrocarbon
miscible/immiscible
CO2 miscible
CO2 immiscible
Nitrogen
Flue gas (miscible
and immiscible)
Other
Total gas
Other
Microbial
Total other
Grand total

Table 4: US EOR Production.

Process
Thermal
Processes

Gas Methods

Recovery
Mechanism
Reduce Oil
viscosity

Issue

Vaporization of
light ends

Override
Pollution

In – Situ
Combustion

Same as steam
plus cracking

Same as steam
plus control of
combustion

Immiscible

Reduces oil
Viscosity

Steam (Drive
and Stimulation)

Typical Agent
Utilisation
0.5 bbl oil
consumed per
bbl oil
produced

10 - 15

10 Mcf air per
bbl oil
produced

Stability
Override
Supply

5 - 15

10 Mcf solvent
per bbl oil
produced

5 - 20

Depth Heat
Losses

Oil Swelling
Solution gas

Chemical
Processes

Typical Recovery
(%OOIP)
50 - 65

Miscible

Same as
immiscible plus
development of
miscible
displacement

Same as
immiscible

Polymer

Improves
volumetric sweep
by mobility
reduction

Injectivity
Stability
High Salinity

5

Surfactant

Same as Polymer
plus reduces
capillary forces

Same as
polymer plus
chemical
availability,
retention

15

Alkaline

Same as
surfactant plus oil
solubilization and
wetability
alteration

Same as
surfactant plus
oil composition

0.3 – 0.5 lb
polymer per
bbl oil
produced
15 – 25 lb
surfactant per
bbl oil
produced

5

35 – 45 lb
chemical per
bbl oil
produced

Table 5: Performance of the Basic EOR Processes.

1970

2000

2020

2037

2050

Us

World

Us

World

Us

World

Us

World

Us

World

Primary

53

Na

37

56

32

48

27

43

20

35

Secondary

45

Na

51

40

54

44

57

47

62

51

Tertiary

<2

Na

12

<4

14

8

16

10

18

14

Table 6: Actual and Projected oil recovery by processes for the US and the world.

References

1

Venuto PB

1989

Tailoring
EOR
Processes
World Oil 209:
61 – 68

2

Donaldson EC,
Chilingarian GV, Yen TF

1989

Enhanced Oil Recovery II – Processes and Operations,
Developments in Petroleum Science. Amsterdam, The Netherlands:
Elsevier Science Publishers.

3

Simandoux P, Champlon D,
Velentin E

1990

Managing the cost of Enhanced Oil Recovery – Revue de
l’Institut Francais du Petrole 45, No 1; 131 – 139.

4

Wikipedia Encyclopedia

2006

Definition

5

Farouq Ali, S.M; Thomas, S. 1996

The promise and problems of recovery methods. The Journal of
Canadian Petroleum Technology V 35 N7 57 – 63

6

Stosur, George J.;
J. Roger Hite;
Norman F. Carnahan
Karl Miller

2003

The Alphabet Soup of IOR, EOR and AOR: Effective Communication
requires a definitions of terms – SPE 84908.

7

Stosur, J. George

2003

EOR: Past, Present and What the Next 25 years May Bring,
SPE 84864.

8

Roger Hite, J.;
Bondor, Paul L.

2004

Planning EOR Projects – SPE 92006.

9

Oil and Gas Journal

2006

10 Martin, F.D

1992

11 Website

2006

-

to

Geologic

Environments,

Enhanced Oil Recovery for Independent Producers SPE/DOE 24142
http://www.netl.doe.gov/technologies/oil-zgas/EP_Technologies/
ExplorationTechnologies /eordraw.html

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