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 Pages 13 Figures

6 Tables 11 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)

Figure 10 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

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), micellar-polymer 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

0

100

200

300

400

500

600

700

800

1986 1988 1990 1992 1994 1996 1998 2000 2002 2004 2006

EOR P

roduction (1,0

00 b

bls / d

ay)

Gas

Thermal

Chemical

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

Fig. 8 – Thermal recovery

Fig. 9 – Miscible recovery

Fig. 10 – Chemical recovery

Fig. 11 – Microbial flooding recovery

Fig. 12 – Cyclic Microbial recovery

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

0

20

40

60

80

100

120

Us Us Us Us Us

1970 2000 2020 2037 2050

Primary Secondary Tertiary

0

20

40

60

80

100

120

World World World World World

1970 2000 2020 2037 2050

Primary Secondary Tertiary

1986 1988 1990 1992 1994 1996 1998 2000 2002 2004 2006

Thermal

Steam 181 133 137 119 109 105 92 86 55 46 40

Combustion in situ 17 9 8 8 5 8 7 5 6 7 12

Hot water 3 10 9 6 2 2 1 1 4 3 3

Total thermal 201 152 154 133 116 115 100 92 65 56 55

Chemical

Mecellar - polymer 20 9 5 3 2

Polymer 178 111 42 44 27 11 10 10 4 4 0

Caustic/alkaline 8 4 2 2 1 1 1

Surfactant 8 4 2 2 1 1 1

Total chemical 206 124 50 49 30 12 11 10 4 4 0

Gas

Hydrocarbon miscible/immiscible

26 22 23 25 15 14 11 6 7 8 13

CO2 miscible 38 49 52 52 54 60 66 63 66 70 80

CO2 immiscible 28 8 4 2 1 1 1 1 1 2

Nitrogen 9 9 9 7 8 9 10 4 4 4 3

Flue gas (miscible and

immiscible) 3 2 3 2

Other 1 1

Total gas 104 90 91 89 79 84 87 74 78 83 97

Other

Microbial 1 0 0 2 1 1 1 0 0 0 0

Total other 1 0 0 2 1 1 1 0 0 0 0

Grand total 512 366 295 273 226 212 199 176 147 143 152

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 ultra-low 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

Chemical

Surfactant (Micellar) 10-20 20-30

Alkaline ~7 ~19

Surfactant / Alkaline / Polymer 2-7 10-17

Polymer 1-5 ~2-7

Table 3: EOR Cost Database

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

1986 1988 1990 1992 1994 1996 1998 2000 2002 2004 2006

Thermal

Steam 468,692 455,484 444,137 454,009 415,801 419,349 439,010 417,675 365,717 340,253 286,668

Combustion in situ 10,272 6,525 6,090 4,702 2,520 4,485 4,760 2781 2,384 1,901 13,260

Hot water 705 2,896 3,985 1,980 250 250 2,200 306 3,360 3,360 1,776

Total thermal 479,669 464,905 454,212 460,691 418,571 424,084 445,970 417,675 371,461 345,514 301,704

Chemical

Mecellar - polymer 1,403 1,509 617 254 64 0 0 0

Polymer 15,313 20,992 11,219 1,940 1,828 139 139 1,598

Caustic/alkaline 185

Surfactant 20 60 60 60

Total chemical 16,901 22,501 11,856 2,194 1,892 139 139 1,658 60 60 0

Gas

Hydrocarbon miscible/immiscible

33,767 25,935 55,386 113,072 99,693 96,263 102,053 124,500 95,300 97,300 95,800

CO2 miscible 28,440 64,192 95,591 144,973 161,486 170,715 179,024 189,493 187,410 205,775 234,420

CO2 immiscible 1,349 420 95 95 66 66 102 2,698

Nitrogen 18,510 19,050 22,260 22,580 23,050 28,017 28,117 14,700 14,700 14,700 14,700

Flue gas (miscible

and immiscible) 26,150 21,400 17,300 11,000 — — — —

Other 6,300 4,400 4,350 4,350 0 0 0 0

Total gas 108,216 130,997 190,632 298,020 288,629 299,345 313,544 328,759 297,476 317,877 347,618

Other

Microbial 2 2 0 0 0 0 0 0

Total other 0 0 0 2 2 0 0 0 0 0 0

Grand total 604786 618403 656700 760907 709094 723568 759653 748092 668997 663451 649322

Table 4: US EOR Production.

Process Recovery Mechanism

Issue Typical Recovery (%OOIP)

Typical Agent Utilisation

Reduce Oil viscosity

Depth Heat Losses

Steam (Drive and Stimulation)

Vaporization of

light ends

Override

Pollution

50 - 65 0.5 bbl oil consumed per

bbl oil produced

Thermal Processes

In – Situ Combustion

Same as steam plus cracking

Same as steam plus control of

combustion

10 - 15 10 Mcf air per bbl oil

produced

Reduces oil Viscosity

Immiscible

Oil Swelling

Solution gas

Stability Override

Supply

5 - 15 Gas Methods

Miscible Same as immiscible plus

development of

miscible

displacement

Same as immiscible

5 - 20

10 Mcf solvent per bbl oil

produced

Polymer Improves

volumetric sweep

by mobility reduction

Injectivity

Stability

High Salinity

5 0.3 – 0.5 lb

polymer per

bbl oil produced

Surfactant Same as Polymer

plus reduces

capillary forces

Same as

polymer plus

chemical availability,

retention

15 15 – 25 lb

surfactant per

bbl oil produced

Chemical

Processes

Alkaline Same as surfactant plus oil

solubilization and wetability

alteration

Same as surfactant plus

oil composition

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 to Geologic Environments,

World Oil 209: 61 – 68

2 Donaldson EC, 1989 Enhanced Oil Recovery II – Processes and Operations,

Chilingarian GV, Yen TF Developments in Petroleum Science. Amsterdam, The Netherlands:

Elsevier Science Publishers.

3 Simandoux P, Champlon D, 1990 Managing the cost of Enhanced Oil Recovery – Revue de

Velentin E 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.; 2003 The Alphabet Soup of IOR, EOR and AOR: Effective Communication

J. Roger Hite; requires a definitions of terms – SPE 84908. Norman F. Carnahan

Karl Miller

7 Stosur, J. George 2003 EOR: Past, Present and What the Next 25 years May Bring,

SPE 84864.

8 Roger Hite, J.; 2004 Planning EOR Projects – SPE 92006. Bondor, Paul L.

9 Oil and Gas Journal 2006

10 Martin, F.D 1992 Enhanced Oil Recovery for Independent Producers SPE/DOE 24142

11 Website 2006 http://www.netl.doe.gov/technologies/oil-zgas/EP_Technologies/

ExplorationTechnologies /eordraw.html

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