From the beginning of oil recovery, scientists have been puzzled by the huge amount of oil leftover following primary recovery. Naturally occurring drive mechanisms recover anything from 0% to 70% of the oil in place. In most cases, recovery declines rapidly as viscosity of oil increases. For instance, primary recovery is less than 5% when oil viscosity exceeds 100,000 cp. This is not to say that heavy oil recovery was the primary incentive for EOR, even though most EOR projects in the United States, Canada, and Venezuela involve heavy oil recovery. The primary incentive for EOR is the fact that a typical light oil reservoir would have more than 50% of the original oil in place leftover, while a small investment can recover over 70% of the oil in place. For heavy oil, the room for improvement is much higher. Even though theoretically there is much more recovery potential of heavier energy sources all the way up to biomass (Figure 4.6), the current recovery techniques are geared toward light oil. This figure shows that natural gas is the most efficient with the most environmental integrity. This argument has been sharpened in the previous chapter that breaks down natural gas further into various forms of unconventional reservoirs. Within petroleum itself, the “proven reserve” is miniscule compared to the overall potential, as depicted in Figure 4.7.

Of course, if one includes solar energy that would be the highest reserve possible. Because all energy source utilization techniques are equipped with processing light oil as a reference, the primary focus of EOR has been light oil. In early 2000, US tertiary recovery was estimated to be 12% (Figure 4.8). This number has held steady until the huge surge in unconventional recovery of oil and gas that increased the oil and gas production by 40% in 2013. It is difficult to characterize unconventional recovery under a known category of oil and gas production. In any event, the knowledge of EOR is invaluable for developing any form of petroleum production scheme.

One of the most important criteria for selection of an EOR scheme is the reserve/production ratio. This ratio is low for the United States. Consequently, the United States has been the leader in implementing EOR techniques. Of the total recoverable oil in the United States, 12% lends itself to EOR (Figure 4.8). Further clarification must be made about the term “recoverable” oil. Some of the OPEC countries calculate this number by multiplying total petroleum in place with the recovery factor, which has little scientific merit. Other countries, than OPEC, calculate initial oil in place by dividing “recoverable reserve” by the recovery factor, which is often low and without scientific justification. A recent survey shows little is known about how numbers such as “recovery factor,” “recoverable reserve,” etc., come to exist. However, it is commonly accepted that the “recoverable reserve” that is published worldwide and is used as the basis for determining OPEC quota for production is the most accurate starting point. This itself creates confusion in the scientific community that is vastly unfamiliar with how those “recoverable reserve” numbers are calculated. As for the pie chart in Figure 4.8, it concerns the contribution of various recovery techniques in the United States. It turns out that the recovery factor in the United States is much higher. For instance, many miscible floods as well as steamfloods have recovery factors in the vicinity of 85% and 70%, respectively. In order to avoid confusion as to what this pie chart should represent in countries that have yet to start an EOR scheme, it is best to determine primary recovery potential and expect 30% of that oil during EOR schemes for light oil reservoirs. For heavy oil reservoirs, this percentage of recovery is much higher, mainly because the primary oil recovery factor is very low. In addition, many heavy oil formations do not “see” primary recovery as is the case for most heavy oil reservoirs in the United States. Some Canadian heavy oil reservoirs do produce in primary mode but with an extremely low recovery factor (less than 10% of initial oil in place).

With regards to EOR technology development and implementation, the United States has been the world leader in implementing EOR. Figure 4.9 shows that the United States is ahead both in time of implementation and magnitude of EOR recovery in the world scale. This trend continues today despite the new found domestic resources in unconventional oil and gas and shale oil megaproject of Canada. Such leadership emerges from the US superiority in related areas of new drilling and well technologies, intelligent reservoir management and control, advanced reservoir monitoring techniques, and the application of different enhancements of primary and secondary recovery processes. However, the present paper presents a comprehensive review of EOR status and opportunities to increase oil recoveries and final recovery factors in reservoirs ranging from extra-heavy oil to gas condensate.

It is well known that EOR projects have been strongly influenced by economics and crude oil prices. The initiation of EOR projects depends on the preparedness and willingness of investors to manage EOR risk and economic exposure and the availability of more attractive investment options. For an economic scheme to be successful in the long term, the technology cannot be expensive beyond the rate of return. In addition, the incremental recovery has to be substantially more than recovery with status quo. In this regard, the recovery/reserve ratio is important and is the most important criterion for implementation of EOR. The following Table shows the ratio of reserve over production rate. When recovery potential is estimated, the actual recovery with EOR can be calculated. These numbers are listed in Table 4.2. It is to be noted that sustainable EOR is the most economic and environmentally appealing option. Unless such scheme is implemented, infill drilling is the most economic scheme. This is especially true for reservoirs with high reserve/production ratios.

It is difficult to comment on the validity of the “reserve” numbers. A recent survey shows that there is no standard for this reserve or the definition of “proven” reserve is so varied and subjective that there is a need for a comprehensive study of this subject. It seems clear that politics plays a significant role in claiming “proven reserve.” While the developing countries in general and OPEC countries in particular are cited for politicizing the reserve numbers, history tells us there is a systematic lack of transparency in both numbers and the process involved in determining these numbers. Resolution of this problem is beyond the scope of this document.

The need for EOR comes from the declining nature of worldwide reserve. Practically all countries have reached peak recovery rate as evidenced from Figure 4.10. This is the case despite the fact that new discoveries continue to grow. This is not to subscribe to the theory of peak oil because this graph does not consider increase in reserve due to the improvement of recovery technologies and the addition of unconventional oil and gas. This unconventional reserve is the principal reason that the United States has seen some 40% increase in domestic oil and gas recovery in the year 2013. Figure 4.11 shows how US reserve in oil and gas have progressively declined since 1970 only to pick up in 2011 onward.

There is a scientific group that believes that the above graph is misleading. As can be seen in Table 4.2, recovery alone cannot be an evidence of declining reserve because the recovery/reserve ratio varies largely among different countries. Figure 4.12 lends credibility to this statement.

Figure 4.12 also shows how countries with the exception of Venezuela have added no new reserve in the last decade. Despite this, there have been claims that major OPEC countries have inflated their reserves in order to gain more share in the competitive world market. This scenario is a pessimistic one because other countries do not actively look for or necessarily declare new reserves or reserves that have become “recoverable” because of technological improvements. The most remarkable case here is Saudi Arabia. World's 25% of recoverable reserve is in Saudi Arabia and until now the entire recovery process is through primary. Because the recovery/reserve ratio is still fairly high, EOR suitability of Saudi fields is a question mark. While it is considered as low risk to develop Saudi reservoirs for secondary recovery because of the low-cost of implementation of waterflood schemes, the benefit of implementing suitable EOR schemes directly after primary remain very high, at least in theory. Also, it is of importance to note that Saudi Arabia has significant amount of tar and other heavy oil deposits that are ignored in their reserve estimates. However, considering latest technological breakthroughs in tar sand and heavy oils, due to mega projects in Canada, Saudi Arabian heavy oil reserves, every well, can become very prominent in the world scale. Developments in the next most important case is that of Venezuela. Venezuela has the highest reserve/production ratio in the world. With EOR implementations, it has the capacity to double the daily output or total recoverable reserve.

In the United States, total oil reserve has been declining since 1970 only to peak up in 2011. Wet natural gas reserve, on the other hand has been declining since 1981 but started to increase shortly after 1999. Figure 4.11 shows the US reserve as a function of time. The decline in reserve was reversed shortly after the 2008 financial crisis. Such rise in reserve is attributed to horizontal drilling and hydraulic fracturing in shale and other “tight” (very low permeability) formations. Because the oil price increased sharply during that period, more drilling was performed. This added to the proven reserve of the United States. US proven reserves of natural gas began growing sharply in the mid-2000s as operators adopted expanded horizontal drilling programs and applied new hydraulic fracturing techniques in shale formations. Starting with 2009, similar horizontal drilling programs were applied in several of the nation's tight oil formations—reserves additions from tight oil plays have reversed the long-term trend of generally declining proved US oil and lease condensate reserves (Figure 4.11). Proven reserves of crude oil and lease condensate increased in each of the five largest crude oil and lease condensate areas (Texas, the Gulf of Mexico federal offshore, Alaska, California, and North Dakota) in 2011. Of these, Texas had the largest increase by a large margin, about 1.8 billion bbl (46% of the net increase), resulting mostly from ongoing development in the Permian and Western Gulf Basins in the western and south-central portions of the state. North Dakota reported the second largest increase, 771 million bbl (20% of the net increase), driven by development activity in the Williston Basin. Collectively, North Dakota and Texas accounted for two-thirds of the net increase in total US proven oil reserves in 2011.

Proven wet natural gas reserves increased in each of the five largest natural gas producing states (Texas, Wyoming, Louisiana, Oklahoma, and Pennsylvania) in 2011. Pennsylvania's proven natural gas reserves, which more than doubled in 2010, rose an additional 90% in 2011, contributing 41% of the overall US increase. Combined, Texas and Pennsylvania added 73% of the net increase in US proven wet natural gas reserves. Expanding shale gas developments in these and other areas, particularly the Pennsylvania and West Virginia portions of the Marcellus formation in the Appalachian Basin, drove overall increases.

In terms of technical recoverability, both oil and gas reserves changed over the last decade. Figure 4.13 shows how technical recoverability has changed for both oil and gas reserves in the United States. Even with reduced aggressive research, technological developments in various aspects of petroleum engineering made it possible to upgrade the reserve estimates (Figure 4.13). This decline has been accompanied with increasing sulfur content of US crude. Figure 4.14 shows general trends in sulfur content of crude oil in USA.

Figure 4.15 shows American Petroleum Institute (API) gravity decline in US crude oil. Together Figures 4.14 and 4.15 show that the overall quality of US crude oil is declining. Figure 4.16 shows both API gravity and sulfur content of crude oil from around the world. Light and sweet crude oil is the most desirable. However, any change of the quality of the crude implies both economic and technological drain on the crude oil. Light and sweet grades are desirable because they can be processed with far less sophisticated and energy-intensive processes/refineries. The figure shows selected crude types from around the world with their corresponding sulfur content and density characteristics. One particular advantage of certain EOR techniques is the in situ upgrading of in situ oil. While no data is available on the quality of oil recovered with EOR as compared to the same without EOR, it is reasonable to assume that in situ upgrading would improve the quality of produced oil.

The selected crude oils in the Figure 4.16 show the “sweetness” of various crude oils from around the world. These grades were selected for the recurrent and recently updated EIA report, “The Availability and Price of Petroleum and Petroleum Products Produced in Countries other than Iran.”

Figure 4.17 demonstrates the need for EOR. EOR involves making up for the loss of natural production cycle in order to meet the growing need of petroleum. However, for reservoirs with high reserve/production ratio, it is most cost-effective to infill drill. By carefully selecting infill drilling sites, the recovery factor can be increased even with primary production mode. For reservoirs that have seen significant rise in water cut during primary production, one should consider local improvement of mobility ratio by adding chemicals, such as polymer. However, increasing EOR performance with polymer is not recommended because polymer slugs do not travel in the reservoir beyond a few meters. The economics of EOR changes drastically if waste gas, produced gas or locally available gas, is used for EOR injection. Figure 4.18 presents a qualitative comparison among various modes of EOR. This figure that is modified from Zatzman and Islam (2007) shows how local fluid injection gives higher return in investment than conventional turn key projects, even though the return is lower at early stages of EOR. Using local fluid requires more investment in infrastructure than turn key projects but the investment pays off quickly and much higher return is posted at later stages. Local fluids may be produced hydrocarbon gas, locally available CO₂, or other gas/fluid available in and around the reservoir. Waste gas, on the other hand, shows higher return throughout the duration of the project. Waste gas may include produced hydrocarbon gas that is normally flared, flue gas, sour gas, or any others that are considered to be liability to the producer.

Figure 4.19 shows drilling activities in the United States over the last decade. This represents enhanced level of drilling throughout to match with the production boost during the same period. Note that the reserve/recovery ratio in the United States is quite low. Such intense drilling activities would represent far greater output in high ratio reservoirs. As stated earlier, infill drilling can increase both production rate and recoverable reserve for cases for which reserve/recovery ratio is low, as is in most OPEC countries.

Even though thermal recovery would include several methods in addition to steamflooding, steamflooding remains by far the most widely successful thermal EOR technique. Recently, it has been realized that mobility control can be realized by using surfactant with steam when steam/foam is generated. Ever since this realization, most emerging technologies in steamflooding involve some kind of surfactant application. EOR in light oil reservoirs have mainly focused on surfactant and/or polymer injection. Hundreds of patents have been issued on different forms of surfactant and polymer injection (in form of surfactant-water flood, micellar flood, surfactant/polymer enhanced waterflooding, etc.). Even though the chemical EOR has been recently marked as too expensive ever since the drop in oil prices in 1982, surfactants continue to play an important role in virtually all forms of successful EOR, be it in form of foam (mobility control in gas injection), steam/foam (mobility control in steamflooding), micellar, alkaline/polymer flooding or others.

Figure 4.20 shows the growth of different EOR schemes in last 40 years. This figure draws a particularly grim picture of the contribution of chemical flooding schemes. One must realize that Figures 4.20 and 4.21 do not consider the chemical applications in thermal and other EOR schemes and the scenario would be likely to change if they were considered.

Recent reports show that the contribution of EOR in total oil production has increased steadily throughout last two decades, despite fluctuating oil prices (Figure 4.20). Also, the number of EOR projects has steadily declined since the peak in 1986. This shows more efficiency of the EOR projects, indicating a trend that efficiency is the focus of the future EOR schemes. This trend is likely to continue even if the oil price continues to rise. Oil industries seem to be convinced that they can no longer afford to experiment with EOR schemes that do not show immediate improvement in oil production.

In using the United States as a reference, one must be cautious about the context in the United States. In United States, tax benefits for EOR projects were repealed in mid-1980s during Reagan era. This followed the sudden decline of the number of projects that were declared as “EOR.” In absence of tax breaks, there was no benefit of declaring a project as EOR. Of particular consequence was the “chemical/polymer” processes. There has been nil contribution of these techniques over the last two decades. With the exception of China, no other country developed any commercial EOR project using chemical methods. There have been several pilot tests involving chemical methods in the North Sea, but the results have been dismal. During the slump period, the production continued to rise, albeit with a small slope. The rise subsided after 2000. Note that this is the year oil price was unusually low. The original prediction was $200/bblin 2000. Instead, it was 10 times that number. In that decade, oil price was so low it was hard to justify investments in aggressive EOR techniques. The notion of sustainable EOR that gives one multiple dividend and is environmentally appealing was only a theoretical concept at that time. During that period recoveries with gas, thermal, and carbon dioxide schemes started to decline keeping pace with decreasing number of EOR projects. The number of thermal projects decreased because main fields in California began to reach maturity and the use of expensive mobility control agents with thermal EOR did not bear fruit. While this is theoretically demonstratable, the petroleum industry had to experiment with it before shutting down many thermal projects. For the same reason chemical EOR practically disappeared. By contrast, carbon dioxide projects continued to be in operation and after 2004, the number actually increased. Even though the number of projects with “other gases” was also increased, CO₂ projects showed marked increase in oil recovery. In fact, CO₂ projects continued to increase with the new incentive related to green house gas emission, as discussed in earlier sections. Since 2002, EOR gas injection projects outnumbered thermal projects for the first time in the last three decades. However, thermal projects have shown a slight increase since 2004 due to the increase of High pressure air injection (HPAI) projects in light oil reservoirs. This technique originally perfected with heavy oil and tar sand (through ISC projects) has the potential of increasing oil recovery from light oil reservoirs to a great extent. The technique is simple and cost-effective.

Chemical EOR methods that were highly successful in laboratory tests have failed miserably in field trials. Once again, this was theoretically expected but the industry could not anticipate in absence of scaled model studies or even scaling laws that capture chemical flooding effectively. Only two projects in chemical injection were reported in 2008. However, there are consorted efforts in the United States as well as the rest of the world to promote chemical flooding, particularly those involving mobility control agents. The focus now is not to create miscible fronts with micelle etc. Instead, new genre of chemical flooding schemes involve the introduction of new polymers and surface active agents. This reattachment to chemical flooding is reminiscent of 1970s and 1980s research in which hundreds of patents “proved” that chemical flooding would be effective in the field but not a single project became cost-effective or even technically successful, despite enjoying tax benefits in the United States for such projects. These techniques are not likely to produce positive results, as will be discussed in the case studies section.

The second most important considerations in CO₂ floods is the fact that it is considered to be inexpensive, at least in the United States (US$ 1–2/Mscf). In addition, the United States has existing network of pipelines that can be readily used for distribution of CO₂. There is one significant case study in Weyburn field of Canada, for which an entire pipeline was created in order to dispatch CO₂ from United States to Canada. This CO₂ was deemed most cost-effective than Canadian CO₂ that would have to be extracted from local coal-fired power plants. The project received US $1 billion in government grants and more in tax rebates and flagged as the most important CO₂ sequestration project of the time. This project was “profitable” only because of the government grant and some ten-fold increase in oil price. This will be discussed in later sections.

It is also important to note that the CO₂ pipeline system in the United States was built in a 30-year (1975–2005) time span when oil prices and tax incentives were sufficiently attractive to ensure security of supply as main drivers. These are viable only because of government interference in name of climate change, funding, and investment. Figure 4.23 shows evolution of CO₂ projects in the United States and average crude oil prices for the last 30 years. This figure is extracted from Alvarado and Manrique (2010). They used oil prices of the refiner average domestic crude oil acquisition cost reported by the Energy Information Administration (EIA). For reference purposes, crude oil price used in Figure 4.23 was arbitrarily selected for every month of June except for year 2010 (oil price as of March 2010). These CO₂ projects led to significant recovery (Figure 4.24).

Although it can be concluded that CO₂ EOR (“from natural sources”) is a proven technology with oil prices less than US $20/bbl, this EOR method represents a specific opportunity in the United States and not necessarily can be extrapolated to all producing basins in the world. This conclusion is based on the selection criteria listed in Table 4.3. This cannot be generalized to other countries, where different economic, environmental, and technical conditions prevail. From sustainability point of view, there must be questions that should be asked in proper sequence. For instance, if the technological feasibility question is asked before availability of the carbon dioxide, the answer would be irrelevant at best. Similarly, the presence of an existing infrastructure for both CO₂ purification and distribution can alter the decision tree. Finally, recent findings indicate that CO₂ is quite effective in recovering heavy oil. In fact, with the new incentive of CO₂ sequestration, heavy oil reservoirs offer the greatest potential for CO₂ injection.

Figure 4.25 shows the strategy developed by the government of Alberta. This program shows equal importance to conventional and heavy oil formations. Scaled model studies show that heavy oil recovery with CO₂ can lead to 70% of the oil in place. This is tremendous considering the fact that primary recovery of heavy oil is less than 5% and similar recovery factor with steamflooding would require significant cost increase while having bigger footprint on the environment.

Figure 4.26 shows the importance given to CO₂-EGR. The use of CO₂ injection in EOR is a mature well practice technology. Enhancing gas recovery through the injection of CO₂ however is yet to be tested in the field (Hussen et al., 2012). Numerous simulation studies ever since the early work of Islam and Chakma (1990) have appeared to support high recovery of gas and heavier components from a gas reservoir along with high capacity of CO₂ sequestration. Although there are some published simulation studies that have been carried out to comprehend by which process CO₂ sequestration in a depleted gas reservoir could lead to EGR, none of these studies have ever attempted to manifest the effect of mixing (CO₂–CH₄) on the recovery process prior to depleted reservoir. These studies were mainly aimed to reduce greenhouse gas emission in the atmosphere and sequestrating in a depleted gas reservoir or in an aquifer. In the year 2005, a project by Gas de France Production, The Netherlands was in progress to assess the feasibility of CO₂ injection prior to depletion of the gas reservoir (K12-B) for EGR and storage. However, since then no follow up results have been published on the final gain in reserve recovery (van der Meer, 2005).

Generally, high natural gas recovery factors along concerns with degrading of the natural gas resource through mixing of the natural gas and CO₂ have led to very little interest shown in CO₂-EGR (Clemens, 2002). In terms of sequestration, natural gas reservoirs can be a perfect place for carbon dioxide storage by direct carbon dioxide injection. This is because of the ability of such reservoirs to permeate gas during production and their proven integrity to seal the gas against future escape (Oldenburg et al., 2001).

However, displacement of natural gas by injection of CO₂ at supper critical state has not been studied extensively and not well understood (Mamora and Seo, 2002). Despite of the fact that CO₂ and natural gas are mixable, their physical properties such as viscosity, density, and solubility are potentially favorable for reservoir repressurization without extensive mixing. This phenomenon of gas–gas mixing can be controlled by controlling the operating parameters.

The injected CO₂ in geological formations undergo geochemical interactions, such as structural, stratigraphic and hydrodynamic trapping. The injected CO₂ is trapped either in the form of physical trapping as a separate phase or as a chemical trapping where it reacts with other minerals present in the geological formation (International Energy Agency, 2010). As time passes, CO₂ becomes immobilized in the geological formation as a function of given long time scales. This is known as geological sequestration. Oldenburg (2003) simulated CO₂ as a storage gas. The results suggested that CO₂ injection as a supercritical fluid allows more CO₂ storage as the pressure increases due to its high compressibility factor. Thus, an expansion of the compressed gas is expected due to changes in pressure and temperature. As a result, there will be a point when gas production no longer is economically feasible.

In terms of economics, not unsurprisingly, Gaspar et al. (2005) claimed the major obstacle for applying CO₂-EGR is the high costs involved in the process of CO₂ capture and storage. The experience from oil recovery schemes indicate that the economics look quite different when purity in injected CO₂ is not sought. It turns out that the purity does not need to be high, and naturally available CO₂ or even flue gas would accomplish the same outcome. It is in line with pressure maintenance schemes in oil reservoirs. This option that would make CO₂ injection appealing without tax incentive as claimed by IEA (2010).

Khan et al. (2012) conducted economic feasibility study of carbon dioxide into a natural gas reservoir and found the scheme economically attractive because of EGR. Figure 4.26 shows results of CO₂ injection at high and low injection rates. Natural gas production is the highest for CO₂ injection at high rate. It is because the mixing is the greatest under high injection rates. However, one should note that this study used a stable displacement front. This is a reasonable assumption because CO₂ is more viscous and denser than natural gas. Such results are not expected in oil reservoirs. In terms of overall gas injection for EGR, there are 50 projects in North America that employs sour gas injection for treatment of natural gas and produced CO₂ has been injected in Dutch sector of North Sea for years (K-12B gas reservoir).

Based on the CO₂ capture, utilization, and sequestration strategy, government of Alberta has drafted a comprehensive scheme as shown in Figure 4.27. “CO₂ Backbone” is a network or manifold of pipelines that can be used for transporting CO₂ from emission hubs as well as taking CO₂ to customer sites. The idea is to create an infrastructure based on the “CO₂ culture.” Because CO₂ is ultimately a valuable commodity, it is suggested that industrial complexes, including pharmaceutical industry, be developed along the backbone. This is a powerful template for developing a comprehensive carbon dioxide based EOR technique.

Figure 4.28 shows locations for various CO₂ sequestration projects around the world. These projects are in support of greenhouse gas mitigation.

Just as water is the best cleaner, thereby, making waterdrive the most common drive for oil production, steam injection is the most common technique for heavy oil reservoirs. Table 4.4 lists the contrasting features of water and oil. This list makes it clear why the use of water is the most effective technique for oil recovery.

Steam injection process involves conversion of scale-free water to high-quality steam of about 232 °C temperature and at a pressure higher than the corresponding saturation pressure. Generally, using direct fired heaters the water is converted to steam. Using insulated distribution lines, steam is transported to various injection wells. Steam injection can be done by two different methods: steam stimulation and steam displacement.

In the stimulation method a predetermined volume of steam is injection into well and the well is shut in to allow to stimulate the wellbore area. After a few days of shut in the well starts to production. If necessary the stimulation process repeat again. In the steam displacement process, continuous injection of steam, usually apply at lower rates. The steam is injected in place as to distance and direction form production wells. Steam injection is a highly sophisticated process and it requires extensive engineering and analytical inputs.

It is estimated that there are 85–110 billion bbl of heavy oil reserve in the United States. Since the 1960s, steam has become the predominant EOR method for these high-viscosity heavy oil reservoirs worldwide. However, factors such as steam channeling, gravity segregation, and reservoir heterogeneity often result in poor contact of the heavy oil formation by the injected steam, leading to low recoveries. One method of conformance control that has received considerable attention is the use of surfactant foams that reduce steam mobility. Numerous laboratory and technically successful field studies have been reported.

Figure 4.29 shows the production of Syncrude and bitumen in Alberta. Syncrude and bitumen represent the two extremes of the viscosity spectrum. Syncrude is synthesized from natural gas, whereas bitumen represents the heaviest (and most viscous) components of petroleum. Note that both products grew exponentially in the last few decades, ever since implementation in 1980s. While the economics of these products have been reported to be attractive, often the government contribution in building the infrastructure has been overlooked or not included in the analysis. Without significant government involvement, these projects would not be implemented, particularly during the time when oil price was in the range of US $10/bbl. With the increase in oil price, these schemes have become attractive and mega projects are being implemented in bitumen extraction and processing. The future of Syncrude has a somewhat conflicted scenarios. Gas price has increased making it more comparable with oil than previous years. In addition, Alberta has suffered from lack of enough natural gas to meet local needs. This is due to the fact that the population of the province has increased manifold in a country that has seen almost zero growth in population over the same period.

For a long time, steam has been used as the driving fluid in heavy oil reservoirs. The steam injection scheme has been very popular because of its simplicity. However, steam injection leads to an unfavorable mobility ratio in most applications. Besides, gravity lay over is a problem with most reservoirs with little or no dip. Injected steam, because of its low density, rises to the top of the reservoir and tends to form a channel beneath the cap rock to the production well. Early steam breakthrough can occur at producing wells owing to override, channeling, unfavorable, and viscous fingering mobility ratio, resulting in low oil recovery efficiency. Because of high steam mobility, there is little pressure differential between injector and producer once steam breakthrough occurs. The majority of subsequently injected steam follows this established path of least resistance and the process efficiency is impaired. Injecting surfactants to generate foam in situ can reduce steam mobility and improve the volumetric sweep efficiency in oil reservoirs. There have been many examples of increased oil production in Californian heavy oil reservoirs when steam r foam was used.

In the last three decades, there have been many attempts to improve steam injection efficiency by the use of additives. Among many additives tried, the aqueous surfactant solution appears to be the most promising one. The objective of such surfactant injection is either to increase the pressure gradient across the region of interest by generation of foam or to use the surface active properties of the surfactant to reduce the oil–water IFT and to alter the relative permeability curve. Following is a list of research areas in this topic:

(1) Surfactant Selection Criteria for Steamflooding. In selecting surfactants for application in thermal recovery, two criteria are set, namely, the resistance of surfactants to hydrolytic degradation and to thermal degradation. It is a common practice to study surfactants at elevated temperatures exterior to porous media. The foam tube test is the most commonly applied technique for determining foam stability exterior to porous media (DeVries, 1958). Some studies found foam stability outside of porous media to be an important indicator of potential mobility reduction within porous media (Doscher and Hammershaimb, 1981). In other studies, however, no such correlation was found (Dilgren et al., 1982). It is likely that the tube test represents foam behavior in very large pore throats and may not represent foam stability in a confined case as in a real porous medium. This observation has been further confirmed by Zhong et al. (1999).

Handy et al. (1982) indicated that thermal stability is a critical factor in the choice of a foaming agent for thermal EOR processes. It has been demonstrated through many studies that foam can be used for flow diversion in a steamflood process. Recently, Djabbarah et al. (1990) reported thermal stability of several surfactants. Despite many disjointed efforts, a comprehensive selection criterion applicable to steamflooding has not been developed yet (Zhong et al., 1999).

2. Microscopic Behavior of Surfactant Steamflooding. It is important to understand microscopic behavior of a system before a field application can be recommended. In steamflooding research, little effort has been spent in studying microscopic behavior and extending that observation to the scaled-up version. Several theories have been proposed to try to explain surface phenomena for a surfactant-steam system (Ransohoff and Radke, 1988; Falls et al., 1988, 1989; Hirasaki and Lawson, 1985). However, very little agreement among researchers exist and fundamental questions, such as the role of gas rate on apparent viscosity of foam, mechanism of bubble generation, effect of surfactant concentration, or the effect of temperature on foam flow cannot be answered without some degree of ambiguity.

3. Role of Residual Oil on Foam. This fundamental aspect of the steam/foam process has not been addressed properly. Most papers on the topic claim to offer different solutions. One possible way to address this process is to conduct research on the microphysical aspect of the process (Zhong and Islam, 1995).

When heat is combined with water, producing steam becomes an effective displacement tool for additional heavy oil recovery. The decrease in heavy oil viscosity being log with increase in temperature, any heating unlocks tremendous amount of oil from the porous medium. Figure 4.30 shows general trend in viscosity versus temperature. Note that the temperature scale is linear whereas the viscosity scale is logarithmic. It translates into a sharp decline in viscosity for moderate increase in temperature. Darcy's law being linear, such decrease in viscosity leads to immediate flow rate increase. In addition, the larger change in viscosity takes place in the lower temperature region and the sharpest decline in higher viscosity oils.

Also affected by temperature is the IFT. This alteration in interfacial difference comes from the fact that surface tensions of water and various petroleum fluids are affected differently, even though each of them varies linearly. Figure 4.31 shows how surface tension varies for various liquids.

Figure 4.32 provides a summary of the measured endpoint residual oil saturations to waterflood as a function of temperature for certain Canadian bitumen samples.

Figure 4.32 shows two different regimes exist as a function of temperature. At the lower temperature range (below 100 °C), there is a rapid decline in oil saturation. In the range of 120–200 °C, the decrease rate is subsided. However, at higher range of temperature (beyond 200 °C), the saturation declines rapidly once again.

It is well documented that residual oil saturation tends to reduce at constant temperature by steamflooding in comparison to conventional waterflooding at the same temperature condition. This is believed to be due to turbulence effects associated with the vaporization of pellicular films of water underlying trapped bitumen as well as possible changes in IFT and wettability during the steam displacement process. Also active is the steam distillation factor that can improve the efficiency of oil recovery with steamflooding. Overall, steamflooding represents optimum cleaning of oil.

Figure 4.33 illustrates the trend of pre- and post-steamflood residual oil saturation as a function of steamflood temperature. This figure demonstrates the superiority of steam over hot water injection at the same temperature.

Cyclic steam injection (Huff & Puff), steamflooding and Steam-Assisted Gravity Drainage (SAGD) have been the most widely used recovery methods of heavy and extra-heavy oil production in sandstone reservoirs during last decades. Thermal EOR projects have been concentrated mostly in Canada, former Soviet Union, the United States and Venezuela, and Brazil. Recently, China has made good progress in thermal EOR. Steam injection began approximately five decades ago. Mene Grande and Tia Juana field in Venezuela, and Yorba Linda and Kern River fields in California are good examples of steam injection projects over four decades. They are considered to be some of the most successful EOR projects of all time. The lessons learned have been immense. However, little of that knowledge has been transferred to conventional light oil recovery processes. There is a one-way disconnection between EOR in heavy oil and EOR in light oil. It is so because a great deal of the knowledge from light oil recovery has been transferred to recently developed heavy oil processes, such as steamfloods in the Crude E Field in Trinidad, Schoonebeek oil field in Netherlands and Alto do Rodrigues in Brazil. In addition, heavy oil recovery processes such as VAPEX has used light oil solvent flooding technologies, developed in the 1960s and 1970s. Ironically, “mistakes” of light oil recovery, particularly when it applies to much discredited chemical flooding, have filtered through heavy oil recovery schemes. If it was not for the subsidy of the government and the tax credits offered to stimulate heavy oil and tar sand recovery, these projects would not be viable.

Capitalizing on the success of steamfloods, numerous “improvements” have been suggested for steam-related recovery techniques. They include the use of solvents, gases, chemical additives, and foam in an attempt to control the mobility of the displacement front. Laboratory results shows great recovery potentials of these “novel” techniques. However, similar to chemical flood schemes, field experimentation with this mobility control chemicals have failed to produce satisfactory results. This failure is mainly due to the fact that (1) any use of solvent is deemed uneconomical, (2) it is impossible to control mobility with chemicals beyond a few feet from the wellbore, (3) original steam flood of cyclic steam injection produce significant amount of heavy oil, leaving behind little room for improvement. One example is the LASER (for Liquid Addition to Steam for Enhancing Recovery) process, which consists of the injection of C5+ liquids as a steam additive in cyclic steam injection processes. Although the LASER process was tested at pilot scale in Cold Lake, Canada, the process has not been expanded at a commercial scale. As stated in the previous paragraph, commercial viability of these projects is nil because of inherent issues.

Steam injection has also been tested in medium and light oil reservoirs being crude oil distillation and thermal expansion the main recovery mechanisms in these types of reservoirs. Because light oil reservoirs are often fractured that pose a scenario different from conventionally homogenous formations of heavy oil, considerations must be made in designing steamflood in light oil reservoirs. To be remembered also that light oil reservoirs are already hot and the temperature range from which the maximum decrease in viscosity occurs does not apply to light oil reservoirs. Any heat in the formation will expand the rock/fluid system in such a way that the displacement front is altered. Steam in light oil reservoirs will distillate the crude oil, creating in situ refining. The precipitation of heavier component and ensuing adsorption on the rock surface can change the rock wettability that may favor the oil production. Steam injection in light oil formations does hold promises but has rarely been investigated with rigor.

On the other extreme of the oil viscosity spectrum, SAGD has been employed in recovering tar sand in Canada. This process is particularly suitable for unconsolidated reservoirs with high vertical permeability and has become standard in many fields of Canada. Even though SAGD pilot tests have been reported in China, the United States, and Venezuela, commercial applications of this EOR process have been reported in Canada only and more specifically those implemented in McMurray Formation, Athabasca (e.g., Hanginstone, Foster Creek, Christina Lake, and Firebag, among others). These projects were all subsided by the government of Alberta that spent practically all extra revenues of additional income due to oil boom in the province on these and similar landmark projects. From technological perspective, these projects have been successful. However, their economics have been good only because of the new surge in oil prices. Some argue that they were attractive even when oil price was US$ 12/bbl. These calculations do not account for government subsidies and the tax breaks. A more realistic estimate is the oil price has to be at least US$ 20/bbl for these projects to be economically viable.

Figure 4.34 shows reservoir depths, average horizontal permeability and formation of several SAGD (pilot and large scale) projects, as documented in the literature. Among these projects, only those developed in McMurray Formation (blue bars of Figure 4.34) operate commercially. SAGD projects tested in Clearwater formation in Cold Lake, Canada (yellow bars of Figure 4.34) have proven to be uneconomic.

Commercial SAGD projects in McMurray formation validate the importance of the geology and reservoir characteristics for this EOR method, findings that have been reported by Rottenfusser and Ranger (2004), Putnam and Christensen (2004), and Jimenez (2008), among others. For any formation beyond 400-m depth, the nature of vertical permeability is such that the horizontal extent of the steamflood becomes more dominant leading to loss of steam in non-extractable zones. With such loss, economics of the system cannot be attractive. From technical perspective, there is a need to study the lateral extents of SAGD wells so that the fact that vertical permeability is lower than horizontal permeability can be used to the benefit of the project.

With the current level oil prices, it is anticipated that the SAGD processes will continue to expand, mainly in Athabasca's McMurray formation. More research and pilot projects should be done for implementation of SAGD to formations that are deeper than 400 m or have low vertical permeability.

Alternatives to SAGD have been proposed. As stated earlier, most alternatives involve “improvements” with chemicals that are meant to reduce mobility of the displacement phase and/or increase extraction of the oil through mixing with solvents (e.g. VAPEX, SW-SAGD, ES-SAGD). In addition, the well configuration or number of wells is also changed for some applications. As examples, one can cite X-SAGD, Fast SAGD, and single well SAGD or SW-SAGD. Well configuration should be designed based on individual formations and typically one should not adhere to a rigid set of well configurations. The use of chemicals, on the other hand, is unlikely to yield positive results because of inherent technical flaws. In addition, they are not sustainable from both economic and environmental aspects.

It is recognized that ISC is the second most important thermal recovery method. Even though, ISC has been applied in tar sand and extra-heavy oil formations, evidence has surfaced that tells us that it is most applicable to medium heavy or even light oil formations. This new evidence explains why most of the ISC pilot projects have yielded inconclusive or failed pilot results. It is increasingly being clear that heavy oil and tar sands are wrong candidates for ISC. In the last decade, ongoing ISC projects in heavy oil reservoirs such as Battrum Field in Canada, Suplacu de Barcu, Romania, Balol, Bechraji, Lanwa and Santhal in India, and Bellevue in the United States demonstrate that a much better candidate for ISC is medium heavy oil formation.

It is worth noting also that hot air injection is the first EOR scheme known to the modern petroleum industry. It is not well publicized because it was not implemented by design. The injection of air leads to ISC and every oil reservoir is a potential candidate of this application. It turns out that recently popularized HPAI is only an offshoot of the original hot air injection concept. The successful application of air injection projects in light oil reservoirs like West Hackberry in the United States demonstrate that this recovery process is a viable EOR strategy for high dipping angle reservoirs combined with double displacement strategies. Since 2000, the number of ISC projects has been steady with 10 projects in sandstone formations, whereas the number of HPAI projects in US light oil reservoirs has shown an important increase during the same period (Figure 4.35). These HPAI projects have been implemented in carbonate formations exclusively.

ISC in light oil reservoirs does not need to be at high pressure. In fact, simple air injection can lead to the onset of the ISC, making the drive turn into an effective recovery technique. There have been several reports on such applications, such as the one reported by Duiveman et al. (2005) and Hongmin et al. (2008) on air injection projects in Handil Field, Indonesia and Hu 12 Block, Zhong Yuan Field in China, respectively. Although Handil Field HPAI pilot (0.5–1 cp oil) reported injectivity problems due to lack of reservoir communication in the pilot area, the results were reported as encouraging. Injectivity problem in this field is most likely due to reasons other than oil viscosity. During injection of air, low temperature oxidation may occur leading to precipitation of plugging agents that would not generally occur under original field conditions. In addition, air injection that does not necessarily have a fire front at the leading edge can lead to intense viscous fingering making the process extremely inefficient. This may result in low recovery. However, such instability problem cannot be alleviated with the use of chemicals, mainly because chemicals do not travel beyond a few meters in the formation. In addition, use of chemicals is inherently uneconomic and can render the process environmentally unsustainable.

In an attempt to improve air injection, foam assisted water alternating air was used in a pilot project in China (Hongmin et al., 2008). This reservoir has an oil viscosity of 3.9 cp. The results were reported to be encouraging but it is difficult to determine how much of the result can be assigned to improvements with foam. It is likely that the presence of foam did not alter the mechanism of water injection alternated with air. An improvement is expected when one combines these two techniques. Other examples can be given from Rio Preto West onshore Brazil reported by Moritis (2008) and studies reported by Hughes and Sarma (2006), Sarma and Das (2009) and Teramoto et al. (2005), and Onishi et al. (2007) evaluating technical feasibilities and potential of HPAI in Australia and Japan, respectively. All these suggest both technical feasibility and future potential of HPAI in light oil formations.

Other alternatives to ISC has been proposed as well. One alternative involves “Toe-to-heel air injection” or “THAI”. It is an integrated reservoir–horizontal wells process, which uses air injection to propagate a combustion front from the toe-position to the heel of the horizontal producer. Figure 4.36 is a schematic representation of the basic features of the process. This process is meant to minimize gravity override.

The stability of the THAI process depends on two key factors: (1) a high temperature burning zone, which is more advanced in the top part of the oil layer, exhibiting controlled (stable) gas override behavior, and (2) deposition of coke, or heavy residue, inside the horizontal producer. The coke that is deposited inside the horizontal producer acts as a gas seal.

THAI is a new, more advanced variant of the conventional ISC process, which operates as a short distance, as opposed to long-distance displacement process. This is equivalent to SAGD version of steamflooding. Due to the well arrangement used in THAI, the mobilized oil ahead of the combustion front only travels a short distance (down) to the exposed section of the horizontal producer. Since THAI operates at much higher temperatures than SAGD, it can achieve significant in situ upgrading, and thereby maximize oil recovery. THAI is currently the subject of a pilot development at Christina Lake, Canada.

Controlled atmospheric pressure resin infusion (CAPRI) is the catalytic extension of the THAI process, incorporating an annular layer of catalyst, emplaced on the outside of the perforated horizontal producer well, along its whole length. The reaction conditions created ahead of the combustion front, prior to reactants passing down through the mobile oil zone to contact the catalyst, are established by the THAI process. Further upgrading of the produced oil is achieved by catalytic conversion, as the mobilized oil passes through the catalyst layer. This process is the first step toward downhole refining. While this system works well in laboratory, field application of refining technique is economically unattractive. This would not be the case if (1) expensive catalysts are replaced with natural, yet effective catalysts; (2) the produced fluid is considered to be upgraded, thereby being assigned a higher grade at the refinery; (3) custom-designed well placement for each application, depending on formation and fluid characteristics.

Figure 4.37 shows some of the test results using THAI and CAPRI. The test was combination of dry and wet THAI/CAPRI test, in which water was injected together with the injected air (CAPRI), as tracer during the second wet combustion period. A stable, high temperature combustion front (500–600 °C) was propagated along the horizontal producer, during the dry and wet combustion periods. The excellent sweep of the combustion front, in a “toe-to-heel” manner, achieved a high oil recovery, at 87% original oil in place (OOIP). The figure shows the variation of the API gravity and viscosity for samples of the produced oil collected during the experiment. Before the combustion front reached the catalyst layer, the degree of thermal upgrading of the produced oil was only about two API points. This is very low, compared to a normal THAI test on Wolf Lake heavy oil. This is because no clay was added into the sand pack for this particular trial. The effect of catalyst on the produced oil is clearly evident in Figure 4.37. The API gravity of the produced oil jumped from an API value of 14, up to 24, during the period of 240–400 min. As the combustion front approached the catalyst section along the horizontal producer, mobilized oil, already partially upgraded in the THAI process, underwent further catalytic conversion reactions. During the second wet combustion mode, with water injection, the upgrading trend was reduced slightly from 22 ^oAPI to 20 ^oAPI. The viscosity of the produced oil achieved by CAPRI was 10–40 mPas, down from the original 24,400 mPas for Wolf Lake crude oil.

In order to seek increased efficiency, other forms of thermal EOR have been proposed. For instance, downhole steam generation (Eson, 1982; Donaldson, 1997), electric heating (Sierra et al., 2001) or electromagnetic heating (Islam et al., 1991; Das, 2008), and microwave (Hascakir et al., 2008) technologies. Some of these technologies were touted decades ago in the form of electrical heating. Later on, great promises were made with electromagnetic heating. A company, called Electromagnetic Oil Recovery was formed in 1980s in Calgary. This company implemented a number of field applications of the electromagnetic heating technology. However, none produced satisfactory result and the company went bankrupt. This technique promised to eliminate one of the bigger technical problems with conventional steam injection in regions where permafrost exists. Several options have been tried for the use of electricity to heat oil reservoirs. These methods can be classified according to the mechanism of thermal dissipation that dominates the recovery process (Pizzaro and Trevisan, 1990). They range from dielectric heating with high frequency range to radio frequency in the microwave range. Wadadar and Islam (1994) had investigated the possibility of using electromagnetic heating with horizontal wells. Islam and Chilingar (1995) reported the results of a series of numerical simulation tests based on the method originally proposed by Islam and Chakma (1990). They showed that by coupling electromagnetic heating with other EOR schemes, one can increase the recovery of heavy oil or tar sand significantly. To date, however, not a single field project has been reported to be successful on the use of this technology.

Polymer flooding has been tried for a long time and is considered to be a mature technology and still the most important EOR chemical method in sandstone reservoirs based on the review of full-field case histories. Even though all forms of chemical methods have been practically abandoned in the United States, according to the EOR survey presented by Moritis in 2008, there are ongoing pilots or large-scale polymer floods in Argentina (El Tordillo Field), Canada (Pelican Lake), China with approximately 20 projects (e.g., Daqing, Gudao, Gudong, and Karamay fields, among others), and India (Jhalora Field). It is important to mention that a commercial polymer flood was developed in North Burbank during the 1980s, demonstrating that this EOR method may still have potential to increase oil recovery in mature basins (i.e. mature floods with movable and/or bypassed oil). North Burbank reinitiated polymer flooding on a 19-well pattern in December. Other reported polymer flooding projects include Brazilian Carmopolis, Buracica, and Canto do Amaro fields. India also reports a polymer flood in Sanand Field. Oman documented a polymer flood pilot developed in Marmul Field and almost 20 years later a large-scale application is under way (Moritis, 2008). Additionally, Argentina (El Tordillo Field), Brazil (Voador offshore Field), Canada (Horsefly Lake Field) and Germany (Bochstedt Field) announced plans to implement polymer flood projects.

Colloidal dispersion gels (CDGs) and BrightWater^® also represent novel polymer-based technologies that are currently under evaluation at field scale. These chemicals are meant for mobility control of a displacement drive. By injecting these mobility control agents, reservoir heterogeneities are homogenized, thereby avoiding channeling or fluid loss in unproductive areas. Documented CDGs projects include Daqing Field in China, El Tordillo and Loma Alta Sur fields in Argentina, and in multiple US oilfields. Regarding BrightWater^®, at the present time Milne Point in Alaska is the only field application discussed or documented in the public domain. While it is expected that the number of CDGs and BrightWater^® field applications will increase in the near future based on recent field and laboratory studies underway, none of them is expected to give positive results. If the oil price continues to be high, producers would be satisfied with the investment, irrespective of the actual benefit of the recovery scheme.

While polymer flooding has been the most applied EOR chemical method in sandstone reservoirs, the injection of alkali, surfactant, alkali-polymer (AP), surfactant-polymer (SP) and Alkaline Surfactant-Polymer (ASP) have been tested in a limited number of fields. In this application, alkali plays the role of a sacrificial agent. New genre of surfactants have been developed that reduce the dynamic IFT to a very low number (Islam and Farouq Ali, 1990; Taylor et al., 1990). These surfactants are highly unstable extremely toxic, and exuberantly costly.

As mentioned earlier, micellar polymer flooding had been the second most used EOR chemical method in light and medium crude oil reservoirs until the early 1990s. Although this recovery method was considered a promising EOR process since the 1970s, the high concentrations and cost of surfactants and co-surfactants, combined with the low oil prices during mid-1980s limited its use. The development of the ASP technology since mid-1980s and the development of the surfactant chemistry have brought up a renewed attention for chemical floods in recent years, especially to boost oil production in mature and waterflooded fields.

Several EOR chemical methods, other than polymer flood, have been extensively documented in the literature during the last two decades. However, at the present time Daqing Field represents one of the largest, if not the largest, ASP flood implemented as of today. ASP flooding has been studied and tested in Daqing for more than 15 years though several pilots of different scales. According to the EOR survey presented by Moritis in 2008, there are ongoing ASP pilots in Delaware Childers Field (Oklahoma) and planned ASP floods in Lawrence Field (Illinois) and Nowata Field (Oklahoma), and SP floods in Midland Farm Unit, Texas (Grayburg Carbonate Formation) and in Minas Field, Indonesia. The surging number of the chemical projects, however, does not tell the full story. There are many other unreported cases that are either in the plan or have been implemented but have not been reported because of lack of success. Fundamentally, ASP or any other chemical EOR technique is economically unattractive and environmentally disastrous. This can be changed only by resorting to other nonconventional sources of chemicals that are either naturally available in local areas or are liability of an operation site because it is a waste of by-product of other activities.

Numerous field reports in Canada (Shell and Husky Oil) show that horizontal wells can be used to successfully conduct stable miscible displacement of both light and heavy oil. The key to success in miscible or immiscible gas injection appears to be the accurate prediction of the frontal stability, which is very sensitive to reservoir heterogeneity.

Another method of reducing viscous fingering during gas injection is the use of foam. The foam increases the viscosity of the displacing gas phase to the extent that an otherwise unstable front (with gas only) can become stable. Also, foam has a homogenizing effect when the displacement front encounters a heterogeneous spot in the reservoir. Even though no study has been reported on the topic of frontal stability in a heterogeneous medium, foam is likely to eliminate some of the problem associated with frontal instability due to heterogeneity.

Launched in 2000, the Weyburn–Midale CO₂ Project in Saskatchewan, Canada, is the world's largest full-scale, in-field study of CO₂ injection and storage in depleted oil fields. When completed, the 11-year International Energy Agency project (funded in part by DOE) will permanently store 40 million metric tons of CO₂ while increasing oil production by 18,000 bbl/day.

Although nitrogen (N₂) injection has been proposed to increase oil recoveries under miscible conditions favoring the vaporization of light fractions of light oils and condensates, today few N₂ floods are ongoing in sandstone reservoirs. Immiscible N₂ floods are reported in Hawkins Field (Texas) and Elk Hills (California) based on the Moritis EOR survey in 2008. No new N₂ floods in sandstone reservoirs have been documented in the literature during the last few years. HPAI schemes and their success tell us that N₂ injection is not an effective option and certainly not economically and environmentally sustainable.

Hydrocarbon gas injection projects in onshore sandstone reservoirs have been employed for many decades. Initially, they were used as a means of pressure maintenance in order to arrest the pressure decline that occurs in any naturally depleting reservoir (Figure 4.38). These projects made a relatively marginal contribution in terms of total oil recovered in Canada and the United States other than on the North Slope of Alaska, where large natural gas resources are available for use that do not have a transportation system to markets. Conventionally, the term “EOR” gas methods include mainly hydrocarbon gases such as water alternating gas (WAG) injection schemes, enriched gases or solvents and its combinations. Even though pressure maintenance is not considered to be an EOR technique, the process remains the same and therefore one must investigate the possibility of additional oil and gas recovery with pressure maintenance. Most of immiscible and miscible EOR hydrocarbon gas floods in the United States are on the North Slope of Alaska while in Canada a miscible gas flood is reported in Brassey Field. The situation of hydrocarbon gas injection projects is different in offshore sandstone reservoirs. This aspect will be discussed in a later section. Conventionally, it is said that if there is no other way to monetize natural gas, then a more practical use of natural gas would be to use it in pressure maintenance projects or in WAG processes. However and if available, the substitution of hydrocarbon gases by nonhydrocarbon gases (N₂, CO₂, acid gas, air) oil recovery will make more natural gas available for domestic use or export while still maintaining reservoir pressure and increasing oil recoveries. This recommendation applies to both EOR and EGR.

On the other hand, CO₂ flooding has been the most widely used EOR recovery method for medium and light oil production in sandstone reservoirs during last decades, especially in the United States due to the availability of cheap and readily available CO₂ from natural sources. There has been an increasing trend in the number of CO₂ field projects in the United States during the last decade in both, sandstone and carbonate reservoirs.

The number of CO₂ floods is expected to continue to grow in the United States sandstone reservoirs. Some examples of planned CO₂-EOR projects in the United States include Cranfield Field, Heidelberg West (from anthropogenic sources) and Lazy Creek Field in Mississippi and Sussex Field in Wyoming. Number of CO₂ floods in Wyoming sandstone reservoirs are also expected to increase based in a recent evaluation presented by Wo et al. (2009). This particular project depends on the CO₂ availability. In all these projects, availability of CO₂ is considered as the determining factor of EOR application.

Additionally, Holtz (2008) reported an overview of sandstone gulf coast and Louisiana CO₂-EOR projects to estimate EOR reserve growth potential in the area including sandstone reservoirs in the Gulf of Mexico. Table 4.5 summarizes major features of certain CO₂-EOR projects. Moritis EOR survey (2008) reports up to nine active immiscible CO₂ floods operating since mid-1970s. The experience of various countries represent different lessons that can be learned. For instance, Midale project in Canada uses trucked CO₂ from another Canadian field, whereas Weyburn projects imports CO₂ that is specifically generated for this project and pipelined (over 200 km) from the United States. Yet, Weyburn is the only project worldwide that has the classification of being an EOR and sequestration project simultaneously. The experience of Trinidad is noteworthy. This project uses waste gas from a nearby Ammonia plant. As discussed earlier, waste gas from a chemical plant represents very high economic boon as well as environmental sustainability. Yet, this project is not considered to be a model for greenhouse gas sequestration. Canada's PTAC project represents the most comprehensive application of CO₂ projects. In terms of CO₂ EOR, Alberta projects 3.6 billion bbl additional oil recovery over the next two decades. At the same time, a significant amount of greenhouse gas would be sequestered. In addition, new industries that make use of CO₂ as a commodity would be developed.

Due to the lack of rigorous scientific investigation, the designs of EOR projects involving CO₂ or other greenhouse gases have been flawed from technical, environmental, and economical perspective. For instance, on the technical side, most flow rates selected, even with horizontal wells, are high enough to induce viscous fingering, with the only exception being the projects involving injection of gas from the top of an anticline or highly dipped formation. The problem is further accentuated for a heterogeneous formation or a formation previously flooded with water or with high water cut. Flow instability in these cases diminish or eliminate the possibility of maintaining a stable front. All laboratory experiments, however, are conducted under stable conditions, thereby, represent optimistic conditions that will not prevail in field. Any field or pilot design based on these experiments is likely to yield disappointing results (Islam et al., 2010, 2012).

Based on laboratory tests, it is often proposed that pure CO₂ be used for maintaining miscibility. Because of flawed definition of environmental integrity, it is suggested that the use of purified CO₂ and sequestration of it would be beneficial to the environment. A truly scientific criterion would indicate that processing CO₂ makes it lose its natural properties that make it a principal player of the photosynthesis process (Khan and Islam, 2007; Chhetri and Islam, 2008). As a consequence, “purified” CO₂ is toxic to the environment at the same time being costly. Ironically, the need for pure CO₂ arises from the premise that miscibility prevails in the reservoir—a premise that does not apply to most CO₂ applications. In presence of immiscible flow, there is no need for maintaining high concentration of CO₂ in the injected gas. Also, if miscibility is not achieved, there is little advantage to having pure CO₂, and even waste gas, produced gas, etc., would suffice. Pure CO₂ in high water cut zones would only result in a loss of valuable CO₂. On the other hand, the injection of greenhouse gas or produced gas would increase accessibility of the untapped oil.

The economics of any EOR project is unacceptable with expensive chemicals (e.g. pure CO₂, surfactant, polymer, alkali). While pure CO₂ is technically capable of recovering additional oil, it has been demonstrated through numerous field trials that conventional chemical floods do not yield acceptable results. This is because, these chemicals do not travel more than a few meters within the reservoir. This is the reason, chemical flooding has failed to recover any additional oil and the chemical techniques have been discontinued for several decades. Today, only China applies chemical flooding techniques and only a handful of operations have been tested in the North Sea. This is mainly because these operators produce their own chemicals.

In terms of emerging technologies, HPAI is the method with greatest potentials. This method combines the positive effects of CO₂ injection (through oxidation of in situ oil) as well as thermal methods. In case, CO₂ or other gases are not locally available, HPAI should be considered.

The following sequential screening is recommended.

For scaling an EOR process or to determine stability of the displacement front, the following steps are required:

Khan and Islam (2007) give full details of these steps, including the definition of the instability number, capillary number, mobility ratio, etc.

It is important to note that, for gas injection, the instability number continues to affect the recovery, meaning the higher the flow rate the less recovery there will be. This is because the pseudo-stable regime is never reached with gas. Gravity plays an important role during gas injection because the value of the gravity number can stabilize a process.

During miscible displacement, the displacement front develops a transition zone that can vary in length significantly. If the crude oil in question is not light, the transition zone can be much wider. The problem with a wide transition zone is that the miscibility can be lost altogether. The lack of miscibility or the extension of the transition under any displacement situation would translate into an inadequate sweep of the reservoir, resulting in low oil recovery. The effect of the transition zone length has not been studied in the past. Inherently related to this problem is the storage or mitigation aspect of CO₂ displacement. Unless efforts are made to define the miscible/immiscible system, the performance prediction is bound to be inaccurate. Also, it is important to predict the sustenance of a miscible front. The lack of miscibility may in turn lead to the onset of viscous fingering.

Typically, carbonate reservoirs show high recovery factors with primary and secondary modes. Similar to what happened with gas reservoirs, there are few incentives for applying EOR to carbonate reservoirs. Thermal recovery techniques are most applicable to heavy oil and tar sand reservoirs. Such reservoirs are exclusively sandstone or unconsolidated sand. The very few thermal projects applied in carbonate formations are not typical thermal operations nor are they with heavy oil. Nevertheless, thermal recovery projects are successful in carbonate reservoirs. The second most commonly used EOR technique for sandstone formations is the chemical technique. However, chemical floods are largely known as technical failures with nil incremental recovery reported after the tax incentive for EOR was removed in 1980s. Chemical floods do work in the laboratory trials but have yielded no tangible result in the field. This demonstrates the incompetence of experimental design of scaled models. There have been fewer applications of chemical techniques in carbonate formations. However, most of them are tagged as “successful.” This conclusion is based on misunderstanding the chemical process involved. Most “successful” recovery processes in chemical methods is the polymer flood technique. Polymer flood does improve oil production rates, but it is not because polymer flood contributes to the reservoir displacement process. It is mainly because polymer, while applying locally (not as drive process), reduces water cut drastically.

For sandstone reservoirs, gas injection is the least frequently used technique. However, incremental recovery is higher in gas injection than in chemical injection. Several decades were wasted in search of incremental recovery with chemical injection but with unfavorable results. In contrast, gas injection is the most commonly used in carbonate reservoirs. Among various gas injection techniques using natural gas, nitrogen and CO₂, CO₂ injection has been the most successful. In this chart pressure maintenance with gas is not included even though scientifically speaking they also constitute EOR.

Since waterflooding is the main offshore activity in Brazil, water management becomes an important issue. By 2002, 12 fields were under water injection, mainly for pressure maintenance, while for other seven, water injection plans were underway. From the 888,000 BWPD injected by 2005, and 330,000 BWPD produced, it was expected that roughly 3,145,000 BWPD will be injected by 2006. Several problems are associated with water injection. Lost of injectivity is an impairing problem because of the subsea wells completions that tend to dominate production schemes in the Brazilian offshore. Intervention for stimulation purposes in injection wells becomes rather expensive, requiring floating rigs. Several alternatives to alleviate water management problems have arisen. Open-hole completion in water injectors has been successful, but remedial activities for water diversion are then difficult. Raw water injection (or lower quality water) above the fracture threshold has been put forth as a serious option, and Petrobras PRAVAP program has dedicated efforts in this direction (PRAVAP is Petrobras corporative technology program that covers all aspects of the EOR activity, including monitoring programs such as time-lapse seismic). Another issue, now for producer wells, is inorganic salt deposition, mainly Barium and Strontium sulfates.

Offshore heavy oil reservoirs (API gravity lower than 19 and/or oil viscosity greater than 10 cp at reservoir conditions) are a challenge for operators in Brazil. The current proposed alternative would be cold production through high productivity wells (long-reach extended horizontal wells), plus associated water injection. Well-planned well architectures to delay/minimize water production and increase sweep efficiency are being proposed to make exploitation feasible. However, no more than 20% recovery factor is expected at present. Some of these projects are described below.

Albacora is one of the offshore giant fields, contains an estimated STOIIP (stock tank oil initially in place) of 4.4 billion bbl (by 1989, time of the development plan) at water depths ranging from 230 m up to 1900 m. The field was expected to develop in three phases for a peak production of 288,000 BOPD from 188 completed wells. The idea being to prepare exploitation phases for successively deeper water, as technology development and learning curves required progress. This is the tendency in offshore operations in the Campos Basin, because water depths grow substantially reaching ultradeep waters in some of the new discoveries.

Seven oil reservoirs were detected: Namorado (typical Cretaceous turbiditic sandstone in Campos Basin), and Eocene, Oligocene 1, Oligocene 2, Oligocene 3, Oligo-Miocene and Miocene, Tertiary. Namorado is a representative turbidite in the Brazilian offshore, like Brent for the North Sea, present in many of the Campos Basin reservoirs. At the time (1989), the field represented 10% of Brazilian STOOIP and 15% of Campos Basin STOOIP.

Phase I comprised the production of six exploratory wells, at water depths ranging from between 252 and 419 m. At the time, oil and gas production reached 33,000 BOPD and 430 m³/day, respectively. Phase II would add 95 wells, completed in Namorado, Eocene and Oligocene 1, 2, and 3 reservoirs, and a few in Miocene and Oligo-Miocene units, to gather information. Thirty nine injectors will be activated. This phase was divided in two steps. First, all possible alternatives and economical screening was used. The remaining cases were then optimized.

The challenge for developing offshore deep water oil fields led to a paradigm that differs from the 1970s and 1980s view, when closely spaced vertical wells was the way to go. This is something that characterizes most of the onshore developments and early cases in the offshore, such as Namorado Field, in relatively shallow waters. In the new scenario, with a need to reduce the number of wells, largely spaced or multilateral wells are required. Another important challenge was to describe some of the internal heterogeneities of turbiditic reservoirs. Although facies can be described from cores, scarce information is available for interwell areas. One feature of Campos Basin turbidities is the lack of outcrops that would facilitate the finding of analogues.

To illustrate the internal complexity of some offshore reservoirs that may have an impact on EOR activities, one can cite the example of the turbiditic reservoir Albacora, identified with the Namorado sandstone, a Cretaceous in age sediment. A relatively detailed stratigraphic description of Namorado sequences is reported. From the point of view of dynamics, calcite cementation (1–53 vol%) is the most important porosity and permeability control of the Namorado sandstone, which range 1.8% < f < 32% and 0.1 < K < 1624 mD.

At this time, more than 50% of the Brazilian oil production came from the offshore fields at water depths over 1000 m. By 2001, Marlim Field was producing 85,000 m³/day (535,000 BOPD), from 60 producers and 32 water injectors. This medium oil field presents excellent petrophysical properties and good vertical communication. The oil is sub-saturated, with viscosity values between 4 and 8 cp. This combination of properties makes water pressure maintenance an efficient process. However, paraffin deposition in flowlines represents a problem for Marlim Field. To sustain the roughly 540,000 BOPD, 640,000 BWPD were being injected. The recovery factor by 2001 reached 7.2%.

Pressure maintenance is carried out by injecting seawater in an alternate line drive pattern in the oil leg. Due to good reservoir properties and high vertical permeability, water injection tends to be stable, and hence efficient in the Marlim complex. Although water injection is the only EOR process used in the Marlim Complex, polymer injection and WAG have been studied alternatives, but not implemented.

Several EOR projects are underway in offshore North Sea. They will be discussed under field case studies. It is interesting to advance the idea that CO₂ flooding has been given serious consideration in offshore environments. An example of a detailed study is associated with the Forties Field. The field is located 170 km northeast of Aberdeen. Significant incremental could, in principle, be obtained in a process like this. Internal complexities of turbiditic reservoirs must be resolved in order to mitigate uncertainties in this depositional environments.

Figure 4.41 shows the statistics of oil recovery projects in the North Sea as well as EOR opportunities in offshore Malaysia. In this figure, SWAG stands for simultaneous water alternating gas injection whereas FAWAG stands for foam assisted-WAG.

The main task so far surrounds the placement of the injection well. Figure 4.42 shows one such configuration.

After placement, proper strategies involve selection of SWAG or WAG. From Figures 4.43a and 4.43b, it can be seen that case C had better performance in terms of residual oil recovery for both SWAG and WAG. The main difference in implementing the two techniques is related to the pressure profile of the reservoir. When SWAG injection is considered, the pressure profile for the case C lies between 250 and 290 bar, instead WAG injection pressure profile decrease rapidly with time, achieving the minimum pressure value of 220 bar approximately for case C and the minimum pressure values for cases different from case C are below 220 bar.

Figure 4.44 shows oil production in the U.S. Gulf of Mexico in shallow and deep waters since 1990 and the forecast until the year 2013. Gulf of Mexico oil production is mainly supported by water and/or gas injection.

Mexico is another example of offshore reservoir production supported by gas injection, bottom water drive, and/or water injection. Regarding gas injection, it is important to note that Cantarell/Akal represents the largest N₂ injection project in the world.

Similar to previous examples, most offshore environments are under continuous optimization strategies of gas and waterflooding to extend field production life and maximize oil recovery.

One specific aspect of MEOR appears to be unexplored—the possibility of using thermophilic bacteria along with hot water injection. Hot water alone can reduce oil viscosity significantly (Islam et al., 1992). If thermophilic bacteria are added, additional improvement can be caused due to decomposition of inorganic carbonates, evolution of viscosity-reducing gases, and IFT reduction with surface active bio-agents. Al-Maghrabi et al. (1999) have conducted some preliminary studies with this scheme. This study also opens up prospects of using bacteria in combination with other EOR techniques, such as surfactant-water flooding and others. In the combined process, it is important to ensure that the selected surfactant is compatible with the bacteria to be used (Sundaram et al., 1994). It is possible that the strain of bacteria will eventually use the surfactant as a nutrient that can add synergy to the system.

Even though it is commonly assumed that shale gas is also the source rock, there are numerous scenarios that have shale gas interbedded with sandstone or even limestone. Determining the origin of this gas is not a trivial task. The age of this gas can be determined by correlating gas properties with time. Arising from the premise that natural processing increases the quality of petroleum fluids, a scenario depicted in Figure 4.49 can be developed. The actual numbers in this figure will arise from database of the region. In absence of such data, geological age of the rock can be determined and gas property data be evaluated in order to assess the origin of the gas.

Because the processes involving the formation of unconventional gas are different, the quality at the beginning of the gas generation is different. Even if it is assumed that the original gas is biogenic for each of these cases, gas hydrate methane is the purest form of methane from the beginning. It is because the original gas is purified with water and only a pure form of methane gas can form hydrate structures. This process is diametrically opposite to the formation of diamond, albeit in a different time scale. This discussion of diamond formation is relevant for both explaining purity of gas hydrate methane as well as the formation of CBM.

Coal is considered to be the fossilized form of large volumes of biomass. One theory suggests that coal is formed in presence of water and with a low thermal gradient. Any gas that forms has the ability to escape or remain absorbed in the aqueous phase as well as adsorbed in the coal mass. Diamond, on the other hand, is formed when the cooling rate is much faster. Crystals are formed with a very high bonding energy without water molecules. As a result coal oxidizes at a relatively low temperature (similar to biomass oxidation temperature). On the other hand, diamond only oxidizes at a very high temperature, making it impractical to be an energy source for human consumption.

Volcanic rocks can be yet another form of unconventional oil/gas source. Vegetation entrained in ash flows may contain enough water to protect it from heat of emplacement. Subareal volcanism may create lakes and swamps with kerogen-rich sediments, and the volcanically warmed water in these basins can trigger nutrient growth, further enhancing the production of organic material. While there has been little consideration of exploring the potential of volcanic oil and gas reservoirs, it is well known that many conventional reservoirs have volcanic bedrocks that enhance oil and gas recovery from them. Once hydrocarbons are found in igneous reservoirs, assessing hydrocarbon volumes and productivity presents several challenges. Volcanic reservoirs are extremely hard. Seismic and logging fail to characterize these formations. The difficulty arises from the fact that volcanic rocks act as a shield for transmission of practically all signals that are used in logging. Log interpretation in igneous reservoirs often requires adapting techniques designed for other environments. For instance, resistivity logs that are based on conventional reservoirs will be less suitable for highly resistive matrix, low porosity, shale-free clean formations. Similar anomalies will occur with density log and neutron logs. Also, magnetic elements are more due to igneous origin. So nuclear magnetic resonance tool is ineffective in such formations. While sonic logs have better chance of being functional, volcanic rocks are so highly reflective, that they would not allow these signals to travel through.

Furthermore, because mineralogy varies greatly in these formations, methods that work in one volcanic province may fail in another. Usually, a combination of methods is required. In terms of porosity, direct measurement of volcanic rock porosity is most preferred.

The formation of volcanic rocks and entrapment of fluid within it can be explained by following the history of volcanic rocks. Figure 4.50 depicts formation of volcanic rocks and emplacement of igneous rocks. Plutonic rocks, formed by cooling of magma within the Earth, display well-developed crystals with little porosity. Plutons and laccoliths—bulging igneous injections into sedimentary layers—are examples of plutonic rock. Volcanic rocks, formed when magma extrudes onto the surface and cools rapidly, show very fine crystalline or even glassy textures. While during the cooling process, cooling of volcanic fluids either underground or at the surface, and agglomeration of fragments ejected during explosive eruptions will develop different tendency of fracturing. This explains why volcanic rocks do not show well-defined patterns in terms of fractures. The onset of fractures itself is distinctly different in volcanic rocks from others, such as sedimentary rocks. When magma contains large amounts of water and gases, buildup of excessive pressure will cause sudden eruption, leading to the development of fissures and eventual fractures. During cooling of volcanic rocks, tremendous restoring force is developed internally, because rock is a poor thermal conductor and there is differential stress that develops along the temperature variation line. This restoring force or stress depends on the nature of cooling. Nature and tendency of internal force guides tendency or direction of fracturing.

During the cooling process the neighboring rocks are also affected. Volcanic eruption near sedimentary basins will intrude into sediments extending over several kilometers and during cooling will create fractures and subsequently faults. This process essentially creates the basis for cyclic nature of fracture, fissures and faults. Figure 4.51 shows the cyclic nature of the process. In the subsurface, volcanic events trigger earth quakes that can create faults within consolidated rocks. Any fault is accompanied with fissures and cracks that eventually can grow into fractures. These fractures themselves make a rock system vulnerable to faults that lead the way to volcanic fluid invasion and earth quake.

This is in conformance with what has been known as burial-thermal diagenesis. The diagenetic evolution of the middle member of the Bakken Formation is depicted in conjunction with the reconstructed burial-thermal history of the unit in the deep part of the Williston Basin (Figure 4.52). The burial-thermal model takes into account differences in deposition and erosion, as well as variations in thermal regime during the basin's history. Thermal data constrain the maximum amount of erosion during the late Tertiary to about 500 m, which agrees closely with previously reported erosional estimates (Webster, 1984; Sweeney et al., 1992).

Figure 4.53 highlights the permeability-porosity characteristics of volcanic and conventional rocks. Volcanic rocks have much lower porosity of the matrix and the permeability of this rock is much higher than permeability encountered in conventional reservoirs. In contrast, other unconventional gas reservoirs, such as tight gas and shale will have higher porosity but lower permeability. Of course, this is due to the fact that shale and tighter formations have high surface area but little effective porosity. It is, therefore, difficult to penetrate shale gas and tight sand altogether and similarly it is difficult to penetrate the matrix of a volcanic reservoir. In terms of fluid production, shale gas or tight sand form a typical “permeability” as shown in Figure 4.53.

While Figure 4.54 highlights the difficulties associated with EGR, it also unlocks potential techniques that would work in such situations. It is known that fracturing as well as drilling horizontal wells recover significant amount of oil and gas from shale and tight sand. Both these processes increase gas saturation within fractures and the wellbore, thereby increasing the relative permeability to gas. The same effect can be invoked by using ISC (or equivalent to HPAI) or selected gas injection (e.g. with CO₂ or flue gas).

For very tight but fractured formations, the possibility of using cyclic thermal fluid injection should be considered. Because diffusive heat and mass transfer is the most prominent mechanism prevalent in these formations, hot gas and/or steam injection can be beneficial. Heat injection can also trigger thermal cracking.

Figure 4.54 also shows how injection of gas can move the actual placement of a reservoir toward the left side, rendering the gas phase mobile. The presence of fissures and fractures can facilitate this process, as gas injectivity is moderate under such conditions.

For CBM, the most effective recovery technique is production of water that contains almost the entire amount of methane in absorbed state. The possibility of EGR for CBM is not well explored. However, it is well known that the production can be greatly enhanced with multilaterals, which have been widely successful in recent years. It is also well known that the addition of heat can increase the sweep efficiency of water tremendously. Steam injection in such cases is not economically feasible. However, ISC holds great promises. Coal burning is slow and conforms to the slow mode of steam generation within the reservoir. Combustion of coal will lead to the formation of CO₂ that itself will enhance the displacement of gas as well as penetration of fractures. Figure 4.55 shows how such scheme would work.

Similar scheme is also applicable to oil-bearing volcanic reservoirs. However, for such reservoirs, the fuel is the hydrocarbon and not the matrix itself as is the case for CBM.

For gas hydrate formations, typically thermal, depressurization, and chemical stimulation have been considered for enhancing gas recovery. Among these, chemical stimulation is the least desirable. Chemical stimulations are economically impractical and the efficiency of the process is poor. Depressurization is effective if in situ pressure is high. Otherwise, depressurization does not yield reasonable gas production. Figure 4.56 shows various types of gas traps within a gas hydrate reservoir. Two of the three types of traps are structural whereas the third one is stratigraphic. In case, there is a gas trap, it becomes easier to initiate depressurization by putting the trap gas in production. This production destabilizes the hydrate zone and stream of gas is released making the process commercially viable. In case the volume of the trapped gas is not sufficient to create instability within the hydrate body, an innovative technique would be to initiate ISC by injecting air into the trap. This would trigger immediate instability due to sudden thermal change (Figure 4.57). This initial instability is followed by generation of CO₂ that acts as yet another stimulus for further hydrate instability (Figure 4.58). At this point, production of methane can be resumed because all three modes of hydrate dissociation have been activated. Even though, the use of geothermal energy has been discussed in the literature as a means of stimulating hydrate production, air injection to trigger in situ heat generation is the most effective technique.

At present, three ways of transport of gas from hydrates are known: (1) by conventional pipeline, (2) by converting the gas hydrates to liquid middle distillates via the newly improved Fischer-Tropsch process and loading it onto a conventional tanker or barge, or (3) by reconverting the gas into solid hydrate and shipping it ashore in a close-to-conventional ship or barge. The latter option was proposed in 1995 by a research team at the Norwegian Institute of Technology, which determined that the use of natural gas hydrate for the transportation and storage of natural gas was a serious alternative to gas liquefaction since the upfront capital costs are 25% lower. Yet another positive factor is that it is far safer to create, handle, transport, store, and regasify natural gas hydrate than liquefied natural gas.

Because natural gas hydrates are often found in shallow reservoirs, mining them is also an option. More importantly, natural gas hydrates offer the best candidates for downhole electricity generation. Efficiency of such process would be much higher than conventional electricity generation with gas turbines.