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Enhanced oil recovery using

natural gas in heavy oil fieldsTPG4140 Natural Gas Project

Ferron, Virginie

Losi, Claudia

Moreno Herrero, Jess

Pia Dreyer, Manuel

Terradillos, Alba

Trondheim, November 25th2010

Department of PetroleumEngineering and AppliedGeophysics

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Abstract

The following report presents an overview of the relationship between naturalgas as an enhanced oil recovery (EOR) element in the production of heavy oil. A

definition of what heavy oil is and where it is found is introduced; this in order to know

where both the producer and the market are located. Heavy oil constitutes itself a

representative percentage of the production of oil nowadays and it is going to have an

even bigger share in the future, as the non-conventional reserves make up for about 70%

of the total worlds oil in 2006 (Oilfield Review). Moreover, conventional oil reserves

are becoming scarce with time, hence the need of new and improved techniques to

produce the unconventional fields, such as heavy oil ones. A compendium of these

technologies are regarded in the report; giving special emphasis to those involving

natural gas. Among them, Gas lifting, Gas injection and Vapor Extraction Process

(VAPEX) are extended in terms of cases of study; where production data, process

details and recovery improvements are presented for different fields throughout the

world. Environmentally talking, the use of these techniques represent a path to reduce

the footprint that the fossil fuels industry leaves; this regarding a possible option to

handle contaminants such as carbon dioxide and hydrogen sulphide present in sour

natural gas or to prevent flaring scenarios. The current trend obliges the energy industry

to improve itself, being the heavy oil EOR techniques with natural gas an expression of

this forwarding behavior.

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List of contents

Abstract .......................................................................................................................................... i

List of contents .............................................................................................................................. ii

List of tables ................................................................................................................................. iii

List of figures ............................................................................................................................... iii

Introduction ................................................................................................................................... 1

1

HEAVY OIL ......................................................................................................................... 3

1.1

Definition...................................................................................................................... 3

1.2

API gravity parameter, oil classifications..................................................................... 3

1.3

Heavy oil in the world ................................................................................................... 4

2

ENHANCED OIL RECOVERY METHODS...................................................................... 5

2.1 Gas Injection and Gas Lift ............................................................................................ 5

2.2 Thermal methods........................................................................................................... 7

2.3

Chemical methods ......................................................................................................... 8

3 NATURAL GAS IN HEAVY OIL RECOVERY................................................................ 9

3.1 Sour gas injection .......................................................................................................... 9

3.2

Gas Lift........................................................................................................................ 12

3.3

Vapor extraction process ............................................................................................. 13

Discussion ................................................................................................................................... 15

Conclusions ................................................................................................................................. 17

References ................................................................................................................................... 18

Tables .......................................................................................................................................... 21

Figures......................................................................................................................................... 22

Appendices .................................................................................................................................. 28

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List of tables

Table 1: Classification of oil depending on API gravity.............................. ............................... 21

List of figures

Figure 1: World market energy use by fuel type, 1990-2035 (quadrillion Btu).......................... 22

Figure 2: Localization of Zama field within Alberta, Canada. .................................................... 22

Figure 3: Samples of heavy oil.................................................................................................... 23

Figure 4: Orinoco heavy oil belt in Venezuela............................................................................ 23

Figure 5: EOR methods now in current use ................................................................................ 24

Figure 6: Gas injection. ............................................................................................................... 24

Figure 7: Gas lift......................................................................................................................... 25

Figure 8: Steam injection ............................................................................................................ 25

Figure 9: In-situ combustion ....................................................................................................... 26

Figure 10: Polymer fluid method ................................................................................................ 26

Figure 11:

VAPEX Process Scheme ........................................................................................... 27

Figure 12: Contact Phase occurring during the VAPEX Process................................................ 27

Figure 13: Heavy oil fields in Oman ........................................................................................... 28

Figure 14: facilities of the sour-gas injection project for Harweel field ..................................... 29

Figure 15: Time evolution of cumulative (all operations) a) injection rate; and b) injected

volumes, at the acid-gas injection operations in western Canada, showing also the fraction of

injected H2S and CO2 .................................................................................................................. 30

Figure 16: Typical operating conditions for acid gas injection showing the compression and

dehydration cycle, transportation from the gas plant to the injection well, and injection, in

relation to the acid gas phase and hydrate forming conditions................................................... 30

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Introduction

The relationship between the development of our society and the growth of the

need of energy has always been almost symbiotic. Every empire, big civilization oreven the major events that occurred during the past time had a background in energy

matters. Nowadays, the trend is to reduce the consumption of energy as much as

possible; while trying to find resources that have leave less environmental footprints

than the ones related to fossil fuels. Nevertheless, the use of fossil fuels as the main

energy resource will still be the driving force in our development for, at least, the next

fifty years (U.S. Energy Information Administration, 2010).

If regarding the actual situation in matters of energy consumption (Figure 1), it

is clear that oil covers most of the demand in current time; while natural gas covers as a

less important but growing amount. Then, talking about the natural gas exploitation is a

must in matters of the energy sector.

The main producers of natural gas are located in the Caucasian Region, but there

are also heavy producers in other parts of the world (British Petroleum, 2010). One can

point out some names such as Russia, Azerbaijan, Middle East and Norway; for

example. This drives directly to the clients, being mainly the European Union and the

United States of America; where gas is used as heating, power generation,transportation and domestic uses (British Petroleum, 2010).

In most cases, natural gas comes as an associated product with oil, and then the

producer can decide whether to obtain both or just get the most valuable product from

the reservoir. This decision is related to market prices, environmental reasons or other

factors such as distribution issues or competitors inside the region. Within these

measurements, there are some less known actions such as the injection of natural gas as

a recovery technique.

First of all, gas and oil are pretty similar. They both are mainly composed of

hydrocarbons and usually, in reservoir, they are found as a single phase mixture that

will separate once at surface or in the reservoir after some production time. In some

cases, the production of associated gas is not seen as profitable: it could even be

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regarded as a problem. Flaring, re-injecting or other minor uses are, sometimes, the only

solution. Being oil the currently most valuable product, it is clear why the industry aims

onto a better recovery of the oil originally in place. This goal is reached through, as

said, injecting the gas, gas lifting, among others.

In the particular case of heavy oil, it is believed to be the main form of

petroleum in production in the next future. This is related to the depletion of the

conventional oil fields during the last years; leaving the industry mostly with this less

traditional kind of reservoirs. Natural gas also takes place as an enhancer in the

exploitation of these heavier oils. In countries such as Canada, Oman, Venezuela and

Brazil where there are heavy oil fields, companies are working upon the help of natural

gas to obtain more out of the well (Schlumberger, 2010).

The aim of the project is to show the existence of enhance oil recovery (EOR)techniques related to natural gas and heavy oil around the globe, while addressing

fundamental concepts such as what is heavy oil and what is EOR. Finally, a discussion

about the future and environmental impact of this industrial relationship is presented.

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1 HEAVY OIL

1.1

Definition

Heavy oil is one type of crude oil with high viscosity, meaning that it flows with

some difficulty (Figure 2). It is called "heavy" because it has heavier molecular

composition than light crude oiland, therefore, ahigher densityand specific gravity.

Heavy crude oil is defined as liquid petroleum with an API gravity lower than 20, and

a specific gravity greater than 0,933 (Dusseault, 2010).

The production, refining and transportation present different challenges in themoment of working with heavy oil. First of all, the viscosity has to be reduced somehow

to assure flow form start until the end of the processing. To achieve this and to increase

the amount of oil that can be produced from the reservoir several techniques can be

used; these being called enhanced oil recovery techniques for heavy oil production. Gas

lifting, Gas injection and High Temperature Steam Injection are just a glimpse of what

it is available when handling heavy oil (Dusseault, 2010).

1.2 API gravity parameter, oil classifications

To really cope with the definition of heavy oil there must be an extended

definition of what API gravity is and when can an oil sample be called heavy oil. API

gravity (API standing for American Petroleum Institute) is a parameter to measure the

relative heaviness of an oil compared to water. The breaking value is 10, meaning that if

the value is greater than 10, the oil with float on water and if it is smaller it will sink. It

is a dimensionless quantity but, traditionally, it has assigned a degree of API gravity

as unit (Crude Quality Inc., 2010).

Oil can be classified between light, medium, heavy or extra heavy depending of its API

gravity value (Table 1), whichvalue can be obtained either by direct measurement through

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a hydrometer instrument, or by relating the specific gravity of the fluid in question

through the following expression:

Inside heavy oil further classification can be made. Regarding the amount of

sulphur contained in the heavy oil it can be denominated as aromatic-asphaltic or

aromatic-naphthenic. When the sulphur content is higher than 1%, the case of aromatic-

asphaltic is present; if it is lower than that value the oil is called aromatic-naphthenic

(Mullins et al., 2007).

1.3 Heavy oil in the world

Heavy oil can be found almost anywhere throughout the world, but it has been

mostly found and produced in the Americas. The largest reserves of heavy oil in the

world are located in Venezuela, specifically north of the Orinoco River (Figure 3). This

deposit of oil itself represents 1,2 trillion barrels of oil, that to say the same amount as

the commercial oil reserves of Saudi Arabia. In this region, the oil being handled has a

viscosity over 10000 centipoises and 10 API gravity (Conoco Phillips).

Other places with heavy oil tradition are the Canadian Rockies provinces(Alberta and British Columbia), Western United States (Alaska, California and Utah)

and Ecuador (Eastern provinces located in the Amazon Region). All together, the

amount of heavy oil in the Americas represents 80% of the total heavy oil in the world

(Herron & King, 2004).

Nowadays, the proportion of heavy oil resources compared to the conventional

oil ones is increasing. By 2005, it was estimated that the proportion was around five

times heavy oil vs. conventional oil; hence presenting a panorama in which the need of

heavy oil exploitation will increase following the current and predicted energy demand

for the next years (Herron & King, 2004).

Currently, the exploitation of heavy oil has a very large potential demand

because the light crude is running out and other resources have to be found. This type of

oil has not been widely exploited previously as this process is very expensive and

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because it has many environmental problems. Thus, many researches are focusing on

extraction improvement in order to find an economical method and involve as little as

possible the environment.

2

ENHANCED OIL RECOVERY METHODS

The recovery techniques for heavy oil basically occur in three stages. At the first

stage oil is drained naturally into the wells, under the influence of pressure gradient

between the bottom of the wells within the reservoir. Then, when medium pressure is

inadequate or when significant amounts of other fluids (water and gas, for example) are

produced, starts the second phase, which involves injecting a fluid into the reservoir, to

maintain a pressure gradient (U.S Energy Information Administration).

After primary and secondary recoveries, an estimated 60-80% of original oil in

place (OOIP) remains trapped in the pores of the reservoir due to viscous and capillary

forces. Therefore, numerous enhanced oil recovery methods (EOR) have been studied to

produce this oil, essentially focusing on two things: reducing oil viscosity for easy flow,

or literally squeezing oil through the pores of the rock. The different tertiary recovery

methods for heavy oil are presented in Figure 4. In the following section of the project a

compendium of the main EOR methods have been selected, this regarding those that are

mostly related with the production of heavy oil.

2.1 Gas Injection and Gas Lift

These are the most typically used kind of methods in the oil industry and,

currently, they are being introduced in heavy oil exploitation more and more (Gmez

Cabrera, 2009). Although being highly effective in terms of recovery factors, this kind

of EOR are compromised by the need of a source of gas available for the injection; aswell as injection infrastructure.

Gas injection is the most popular EOR technique and involves carbon dioxide,

nitrogen, or natural gas being injected into a reservoir. The principle of this method is

shown in Figure 5 with CO2as the injected gas. Once injected, the gas will subsequently

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dissolve into the oil and both lower the viscosity of the oil and improve the oils flow

rate. In many applications of gas injection, up to two-thirds of the injected gas will

return with the oil that is produced; re-injecting the recycled gas to release additional oil

will then minimize the operating costs (Maya Energy, 2009).

This process involves both control and price restrictions, given that the operating

pressures and depths are rather elevated. The minimum pressure for miscible

displacement of oil with gas is approximately 3000 psi, thus the depth of the reservoir is

limited to a minimum of 5000 feet (Vargas, 2009).

The second alternative used in oil wells to lift fluids to the surface is gas lift, of

which a general scheme is presented in Figure 6. This system uses gas at a relatively

high pressure injected in the production tubing to lighten the fluid column and thus

allow the well flow to the surface. There are two types of gas lift: continuous tire pump

and intermittent pneumatic pump (Azcona, 2002).

As the basic rationale is to produce as much oil as possible with a smallest

amount of injected gas, what is sought is to compare the theoretical volume of gas

against the real, and understand the behavior of the well according to it

characteristics. The amount of gas to be injected to maximize oil production varies

based on well conditions and geometries and is generally determined by well tests,

where the rate of injection is varied and liquid production (oil and perhaps water) is

measured. Although the gas is recovered from the oil at a later separation stage, theprocess requires energy to drive a compressor in order to raise the pressure of the gas to

a level where it can be re-injected (Azcona, 2002).

As we talked about gas injection, also water injection has to be mentioned: the

process by which oil is displaced to production wells by the thrust of water. This

technique is not used in oil fields that have a natural water drive. The factors that are

favourable for high water injection recovery include: low viscosity oil, uniform

permeability and continuity of the reservoir (MK Tech Solutions).

Without forgetting that both gas injection and water injection used as a way of

pressure maintenance, being the oil too viscous, are of no use in heavy oil fields, we can

still compare the two techniques. To do that we have to take into account that water

floods leave more oil in the reservoir than gas floods; but the first one can recover oil

faster if the permeability of the reservoir is high. Usually, if the permeability of the

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reservoir is above 50 mD, a water flood will work well, whereas if the permeability is

below 25 mD, gas will recover oil faster than water because more gas can be injected

(MK Tech Solutions).

2.2

Thermal methods

Thermal methods provide some of the highest recovery factors, but they also

have the largest potential capital expenditure and operating costs. Nevertheless, they are

among the most commonly used methods in the heavy oil industry (Schlumberger).

Thermal methods typically involve the injection of steam or hot water into the

reservoir in order to decrease the oil viscosity. Therefore, they improve the mobility of

the heavy oil and provide a displacement mechanism. Another available technology is

commonly referred to as steam slugging and involves a mixture of carbon dioxide and

steam. This is shown in Figure 7 (Dolberry Oil & Gas Inc.).

The process of cyclic steam injection is sometimes called "huff and puff" or

"steam soak". This is a cyclical process in which the same well is used for injection and

production. The injection cycle followed by production will be repeated several times,

usually in each cycle will produce less oil than in the previous cycle. Some projects of

cyclic steam injection have been converted to continuous injection of steam after a fewcycles of injection. (Dolberry Oil & Gas Inc.)

In-situ combustion, on the contrary, is a way of letting the oil itself generates

energy to heat up the reservoir. There are two types of combustion processes in place:

combustion "forward" and burning "reverse. For the process "forward" the reservoir is

"burned" in one or more air injection wells and the combustion front propagates through

the reservoir to the nearest production well, as is shown in Figure 8.For the process

"reverse" the fire front moves from the production well to the air injection well

(Kristensen, 2008).

About the injection of hot fluids, we can say that, in general, the injected fluids

are heated on the surface. Those fluids vary from the more common water (liquid and

vapor) or air, to others, such as natural gas, carbon dioxide, exhaust fumes, and even

solvents and the choice is controlled by costs, expected effects on the response to oil

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production and the availability of fluids. The effective mobility ratio associated with the

injection of hot fluid is very unfavorable for the non-condensable gases, at least for the

injection of hot water, and less unfavorable (or favorable) for condensable gases and

water vapor (Prats, 1986). In the case of water injection, water is filtered, treated for

corrosion control, heated, and if necessary, treated to minimize swelling of clays in thereservoir. The main role of the hot water injection is to reduce the oil viscosity and,

therefore, improve the efficiency by getting more displacement than it can be achieved

with conventional water injection (Prats, 1986).

Vapex process (vapor extraction) consists in a pair of horizontal wells one above

the other and also displaced horizontally, using a light hydrocarbon solvent in the range

of propane and butane (or some combination of light hydrocarbons) injected into the

upper horizontal well. The solvent diffuses into the heavy oil and, ultimately, reducing

its viscosity to allow it to drain by gravity to the lower horizontal production well. The

operating conditions are controlled in order to maintain the solvent in the vapor phase:

pressure is very close to its vapor pressure to maximize the effects of dilution of the

solvent (Das, 1998).

2.3 Chemical methods

These are the less used techniques: fluid inclusion system and microbial

injection. They are currently under development and they propose newer ways to handle

with the recovery of the oil in place without compromising quality and environmental

matters (Dolberry Oil & Gas Inc.).

Starting with the fluid inclusion systems, three chemical flooding processes can

be applied as enhanced oil recovery techniques for heavy oil fields: polymer, surfactant

or alkaline flooding. It is also common to mix these methods, namely injection of alkali-

surfactant mixture (AS) or alkali-surfactant-polymer mixtures (ASP).

In the polymer flooding method, the water may become more viscous after the

addition of a water soluble polymer, which leads to an increase of the oil/water mobility

ratio. Therefore, the sweep efficiency is improved and a higher rate of recovery can be

obtained. At low salinities polymers have a higher mobility ratio by increasing the

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viscosity of water and decreased water permeability of the formation. The biopolymers

are less sensitive to the effects of salinity, but they are more expensive under the pre-

treatment processes that are required. This is shown in Figure 9 (Liquid Gold

International Corp.).

Concerning surfactant injection, this method aims to decrease the interfacial

tension between oil and water to move volumes of oil discontinuously trapped, usually

after the recovery process of water injection (Marquez, 2009). Alkaline injection on the

other hand involves the injection of caustic or alkaline solutions in the formation. These

chemicals react with the organic acids naturally present into the reservoir and thus

generate or activate natural surfactants. This situation results in direct improvements in

the mobility of oil through the reservoir and into producing wells (Marquez, 2009).

Microbial injection is a technology still under development. Laboratory tests

have shown that some microorganisms produce chemicals that can increase oil mobility

in the reservoir. These organisms may be displaced through the porous medium, and can

be adapted to live under a variety of environmental conditions (EuroAsia Industry).

Chemicals that may be produced by microorganisms include surfactants, acids, solvents

and carbon dioxide. Reservoirs with temperature below 160F, residual saturation

greater than 25-30% and permeability greater than 100 mD are considered as good

prospects for microbial injection (Giangiacomo & Mokhatab, 2006).

3 NATURAL GAS IN HEAVY OIL RECOVERY

In this section of the project, three natural gas enhanced oil recovery techniques

have been selected and displayed in terms of case scenarios around the globe where they

are being utilized.

3.1 Sour gas injection

First of all, the concept of sour gas injection is going to be introduced.This

technique belongs to the family of those called Miscible Gas Driven Techniques; which

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involve the putting in place a mixture or pure component stream that dissolves into the

oil and helps the production of it through a reduction of the viscosity of it.

Miscible Gas Driven Techniques are usually related to light oil reservoirs,

because it is easier to dissolve the streams into this kind of resource. Nevertheless, it is

being used in heavy oil reservoirs. With the right selection of components in the

injection stream, good results can be obtained in the reduction of viscosity ergo the

better production of the oil in place. The mixtures that are used are usually composed by

hydrocarbons or similar compounds that have affinity to the complex oil mixtures

(Green & Perry, 2007).

Gas injection, in general, involves a lot of substances that can be used apart from

hydrocarbons; the most commonly known case is that one related to CO2. But, when

using hydrocarbons such as those present in natural gas; the existence of other

components is a must, coming back to CO2, H2S, among others (Schlumberger, 2010).

In those places where heavy oil fields are closely located to natural gas ones the

possibility of using this gas in EOR is economically viable. But this is related to many

other factors, because one can say that exploiting both should be the best opportunity.

Extremely sour gas, lack of infrastructure or the absence of a market could be the

reasons why using the gas instead of producing it is preferred.

This is where sour gas comes into account. With this kind of gas, the injection

process is almost ready because there is no need to enrich it. Also, as it is more difficult

to treat, it is better to inject it in those cases where more money is going to be obtained

from the oil producing than from the gas producing.

Such panorama is presented in many locations. In countries with heavy oil

tradition, such as Canada, this kind of project is not rare and in western provinces, such

as Alberta and British Columbia, the production of heavy oil has been increased by the

injection of sour gas. This case is a little bit different, because the companies usually

treat the sour gas first and then they inject CO2and H2S whether as dry or wet streams.

According to Albertas local government, it has been injected an approximate

amount of 4.5 Million Tons of Sour Gas (until 2003) in almost 50 different locations

throughout the province (Bachu & Gunther, 2004). Nevertheless, it is still a small scale

project compared to the total amount of fields in the area. The composition of the gas

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being injected has been, in average, between 83% H2S and 14% CO2to 2% H2S and

95% CO2. The heaviest oil that has been subject of injection is around 16 API (Bachu

& Gunther, 2004).

To illustrate better the above situation a particular field, Zama, has been

selected. Located in the northwestern part of this Canadian province; it is a heavy oil

reservoir that has been operated by the Apache Canada Limited Company. In this field,

the operator has managed to increase around 180 000 and 276 000 barrels per year

compared to the normal production rate by the injection of an average of 81 ktons/year

CO2and 31 ktons/year H2S (Smith et al., 2008).

In the case of Canada, the injection of this gas components has not only been

related to profit issues; but also to environmental ones. With the injection of this toxic

and greenhouse gases, the reduction of the environmental trails left by the local oil/gas

companies has been reduced (Bachu & Gunther, 2004).

There are also some locations where heavy oil is not traditional in which sour

gas injection into heavy oil fields is being used. This is the situation happening in

Oman. This Middle East country has had a typical experience of producing light oil, but

the amount of this kind of oil fields is reducing every time; giving space to the heavier

oil ones. The properties of the heavy oil in place in this country are usually around the

20-22 API; but there are some fields with heavier oils with values down to 16 API.

In the region, it is believed that in a few decades almost half of the production of oil isgoing to be from heavy oil fields (Aalund, 2010).

This scenario drives the need of getting new techniques to develop such fields.

According to Petroleum Development Oman Company (PDO), one of the partially state

owned oil companies in the country, the use of sour gas injection is a fact in several

fields of the country. It is now a project that started in 2009 and it is believed to be

completed by the year 2012 (PDO, 2009).

The main reason to use this gas as part of sour gas injection is the high contentof acidic substances in the natural gas fields of the region. These values typically range

between the 3-4 % H2S and 10-15 % CO2 (PDO, 2009). In comparison to the before

mentioned Canadian case, in Oman the sour gas is being injected without previous

treatment, it means, the gas is taken directly from the reservoir of gas into the reservoir

of oil.

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One of the fields in question where the sour gas injection is taken place is the

Harweel field. In this particular place, the sour gas being injected has an average

composition of 4% of H2S and 15 % CO2 (Oil and Gas Journal, 2007). According to

Shell, one of the operating companies that it is developing the enhanced oil recovery in

this field, the aim is to increase the current 10 % recovery factor to approximately a 40%. One thing to point out of this project is the high pressures of gas injection, these

values being close to the 500 atm. (Penney, 2010).

3.2 Gas Lift

As previously stated, this technique is related to the immiscible gas techniques;

in which the injection to the well of a gas current is used to transport oil out of thereservoir in a two phase flow regime.

Gas lift can be found as an enhance oil recovery technique in many fields

throughout the world; especially in those where heavy oil is produced. The fact is that,

in many cases, the use of this technique is required not only to obtain more oil, but also

to assure flow from it (Schlumberger, 2010) by adding the gas directly into the

production pipe.

Such is the case found in the majority of the Venezuelan fields. This is a country

with a well-known heavy oil production history. In fact, Venezuela owns the worlds

biggest reserves of heavy oil (U.S. Energy Information Administration, 2010).

In the eastern part of the country there is the highest concentration of heavy oil

fields, especially north of the basin of the Orinoco River. In Monagas state in the San

Tom region there is a field called Morichal. With proved initial oil in place of 9945

Millions of Barrels with an API density around the 8 12 degrees, this field is consisted

of 306 wells that are or have been operating entirely with gas lifting systems. The

natural gas used for this activity is obtained from local fields in the state and it has beeninjected since 1958. In this particular case, the use of gas lifting has been essential to

assure oil flow (Mrquez, 2008).

Similar production scenarios are happening in other locations, inside Venezuela

(Intercampo field, Maracaibo Lake Oil Basin) or outside of it; such as Brazil (Jubarte

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field, Esprto Santo Offshore Basin), Canada (Alberta Province Fields), among others

(Schlumberger, 2010).

3.3 Vapor extraction process

The third and last technique described in this paper, the vapor extraction process

using an hydrocarbon mixture as a solvent (VAPEX), has been studied and developed

only recently, following the great improvements in horizontal drilling and Steam

Assisted Gravity Drainage process. This method consists in injecting steam into the

reservoir from a horizontal well, situated some meters above the production casing

(Figure 11), letting the viscosity of the heavy oil to be reduced thanks to the increased

temperature. Many problems are associated with the SAGD method, though. The mostimportant are the energy consumption and the need to treat the water before disposal,

once it reached the production well and starts being produced simultaneously with the

oil.

That is where and when the possibility of a vapor solvent injection has evolved.

The already mentioned huff and puff had been tried with hydrocarbon mixtures, and

the same had been done with vertical injection wells (Das & Butler, 1997), but the real

value and potential of this technique was acknowledged when the horizontal drilling

had been made possible and economically viable. The research process has given quite

promising results, even though a proper field implementation still has to be evaluated.

Vapex process works in a similar way to the steam assisted drainage. A mixture

of vapor hydrocarbons, which will be mainly pure propane or butane (Luo et al., 2007),

is injected through the upper well, creating a vapor chamber and a contact zone where

the dissolution of the solvent in the bitumen will take place. This is the first mechanism

that allows us to reduce the viscosity of the oil and gradually produce it as it moves

down to the second well (Figure 12). As long as the gas is below his saturation pressure

at reservoir temperature, the production rate will increase with increasing pressure, but

when we get close to this point another important process, which is the asphaltene

deposition, begins.

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De-asphalting, the second important step in reducing the heavy oil viscosity, as

the C50+ part of the oil separates and adheres to the rock, is frequently called in-situ

upgrading (Luo et al., 2007). A minimum concentration of solvent gas is also required

for this process to take place, in the case of propane injection this means that only with

a percentage in weight above 20-32% the asphaltene will separate and stick to the pores,upgrading the oil. The production rate mainly depends on the diffusion velocity of the

solvent in the heavy oil still, but a significant increase can be observed when de-

asphalting starts (Das & Butler, 1997).

It was thought that this precipitation would cause problems with the production,

reducing the porosity of the formation and creating an irreversible bond with the rock

material. That last conclusion is in fact true but, being the occupation of void space no

more than 20% even if all the asphaltene would separate (Das & Butler, 1997), this

allows yet the gas to flow through the pores and meet fresh bitumen, so that the

dissolution can continue and the asphaltene will simply be left behind in the zone where

no more oil could be recovered.

Many researches are being carried out on this type of process, expecting that, as

Das (1997) mentions, the applicability of the Vapex process may even surpass SAGD

in thin reservoirs, reservoirs underlain by aquifer, offshore operations.

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Discussion

As stated in previous sections, the relationship within natural gas and heavy oil

in terms of EOR is a fact. It is known that it helps in the production of these

unconventional reservoirs and that many companies are taking the option to do it.

Nevertheless, saying that it is positive or negative to the future of the industry is not as

easy as the fact.

First of all, the environmental issues take place into this discussion. In many

cases, companies or countries select the use of natural gas related techniques in order tostop and reduce the flaring of the gas associated to conventional oil fields. This natural

gas is then used to enhance the production of a neighbour heavy oil field instead of

being burned; contributing with the reduction of greenhouse gases generation. In many

countries, such as Nigeria, the introduction of natural gas injection was not an option

but part of the law (Climate Justice Programme, 2005). Even though, improving the

production of oil means improving the amount of less clean fossil fuels being used,

ergo increasing the pollution factor. Hence, the situation is not easy to handle. The

energy demand still depends on fossil fuels, so decreasing the flaring will at least helpto make cleaner the production stage.

Another issue that has to be pointed out is that one related to sour gas emissions.

When handling natural gas rich in acidic components the environmental alarm is also

set up. The use of sour natural gas in gas injection projects provides a useful path to

handle the contaminants. It is obvious that this situation is only presented where the

natural gas in place is considered rich in sour components.

A different approach that can be regarded is the economic one. There are

countries where natural gas resources are found but they currently cannot be produced

in an easy way; this regarding to the local market and competitors or the lack of

infrastructure and money to invest in them. Also, some of these nations have an oil

oriented industry, leaving no place to natural gas exploitation. Then, the use of natural

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gas a helper in the oil production is a more profitable option rather than building a new

industry for it.

In addition to the above said, the growing of the natural gas demand foreseen for

the next years has to be commented. It might seem contradictory that natural gas is not

being exploited for energy purposes when the market is demanding so. Although

building a local industry for exploiting natural gas looks expensive at first glance,

putting in place techniques such as the ones mentioned in previous sections of the text

also require representative investment. In the case of gas injection, compression and

injection wells have to be installed; these two representing a lot of capital expenditure.

Giving a fixed statement in response to this discussion is not possible; this linked

to the fact that every case is different. In each scenario several factors have to be

weighted to decide if more money is going to be saved or obtained by exploiting gas orproducing more oil.

As said before, the future in the energy sector is apparently heading to a cleaner

and more natural gas oriented industry. As seen in the Canadian case, the use of sour

gas components instead of the natural gasper seis an option where both the gas and oil

industry are being beneficiated as the same time than the environment is being so. The

techniques before discussed on natural gas EOR are only a fraction of the available

options. Also, new ones will be generated and then the use of both resources is going to

be optimized. To finish, the natural gas should not be only used as a helping hand to the

oil production but also as a parallel path to satisfy the current and future energy needs.

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Conclusions

Heavy oil production will have a major role in the oil industry of tomorrow.

It is possible to enhance the production of heavy oil through the use of natural

gas.

Natural gas has to be produced as an individual resource.

Enhanced Oil Recovery (EOR) of heavy oil is needed now and will be needed in

the future.

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References

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7. Crude Quality Inc. Website, www.crudequality.com, consulted on September 2010.

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11. Dolberry Oil & Gas Inc., www.dolberryoil.com, consulted on October 2010.12. DUSSEAULT M. B., Comparing Venezuelan and Canadian Heavy Oil and Tar

Sands, Canadian International Petroleum Conference June 12-14 2001, Calgary,

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13. EuroAsia Industry, www.euroasiaindustry.com, consulted on October 2010.

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14. GIANGIACOMO Leo A., MOKHATAB Saeid, Microbial enhanced oil recovery

techniques improve production, World Oil 2006, Volume 227, n10, pages 85-93,

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19. KRISTENSEN Morten Rode, In-situ combustion EOR, 2008.20. Liquid Gold International Corp., www.liquidgoldinternational.com, consulted on

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21. LUO Peng, YANG Chaodong, GU Yongan, Enhanced solvent dissolution into in-

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22. MRQUEZ Claudio, Distrito Venezolano de San Tom, PDVSA, Venezuela,

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23. Maya energy, 2009, www.cnmaya.com, consulted on October 2010.

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25. MOHAMED GAMMAL Moustafa, Subsidizing the oil reserves and increasing

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26. MULLINS O.C., SHEU E.Y, HAMMAMI A., MARSHALL A.G., Asphaltenes,

Heavy Oils and Petroleomics, Springer Editions, 2007.

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27. Oil and Gas IQ website, www.oilandgasiq.com, consulted on November 2010.

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JACKSON William, NIMCHUK Doug, LAVOIE Rob, Zama Acid Gas EOR, CO2

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Tables

Table 1: Classification of oil depending on API gravity

Source:

Crude Quality Inc. 2010

Type of Oil API gravity Viscosity

Light Crude > 31,1 < 100 cP

Medium Between 22,3 -31,1 ~100 cP

Heavy < 22,3 > 100 cP

Extra Heavy < 10 >> 100 cP

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Figures

Figure 1:World marketenergy use by fuel type, 1990-2035 (quadrillion Btu)

Source: U.S. Energy Information Administration, International Energy Outlook 2010, U.S.

Department of Energy Office of Integrated Analysis and Forecasting, U.S.A., 2010.

Figure 2: Localization of Zama field within Alberta, Canada.

Source: SMITH, S., SORENSEN, J., STEADMAN, E., HARJU, J., JACKSON, W.,

NIMCHUK, D., LAVOIE, R., Zama Acid Gas EOR, CO2 Sequestration and Monitoring

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Project, Energy and Environmental Research Centre-University of North Dakota, Apache

Canada, Ltd. CalPetra Research and Consulting, Canada, 2008.

Figure 3: Samples of heavy oil

Source: Conocco Phillips refinery, Alaska gas pipeline

Figure 4:Orinoco heavy oil belt in Venezuela

Source: DUSSEAULT M. B., Comparing Venezuelan and Canadian Heavy Oil and TarSands, 2001

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Figure 5: EORmethods now in current use

Source: Oil and Gas IQ, 2009

Figure 6:Gas injection.

Source:Rentex, 2009.

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Figure 9: In-situ combustion

Source:Schlumberger, Heavy oil info, 2010

Figure 10: Polymer fluid method

Source:Dar Energy Inc., 2009

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Figure 11:VAPEX Process Scheme

Source:Das & Butler, 1997

Figure 12:Contact Phase occurring during theVAPEX Process

Source:Das & Butler, 1997

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Appendices

Appendix A: Heavy oil fields and sour gas injection in Oman

Figure 13: Heavy oil fields in Oman

Source: Oil and Gas Journal, article Special report: PDO initiates various enhanced oilrecovery approaches, November 2007

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Figure 14: facilities of the sour-gas injection project for Harweel field

Source: Oil and Gas Journal, article Special report: PDO initiates various enhanced oilrecovery approaches, November 2007

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Appendix B: Sour gas injection in heavy oil fields in Canada

Figure 15: Time evolution of cumulative (all operations) a) injection rate; and b) injectedvolumes, at the acid-gas injection operations in western Canada, showing also the fraction of

injected H2S and CO2

Source: BACHU Stefan, GUNTER William D., Overview of Acid-Gas InjectionOperation in Western Canada, Alberta Energy and Utilities Board Alberta Research

Council, 2004

Figure 16: Typical operating conditions for acid gas injection showing the compression anddehydration cycle, transportation from the gas plant to the injection well, and injection, in

relation to the acid gas phase and hydrate forming conditions

Source: BACHU Stefan, GUNTER William D., Overview of Acid-Gas InjectionOperation in Western Canada, Alberta Energy and Utilities Board Alberta Research

Council, 2004

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