Egyptian fields have large potential for enhanced oil recovery technology

Fig. 1 shows the number of EOR projects as presented in the 2012 OGJ worldwide survey.³ It is clear from Fig. 1 that CO₂ miscible flooding, which is suitable for medium and light oil reservoirs, is the most widely used EOR process.

The number of CO₂ projects is expected to continue to grow due to the availability of cheap and readily available CO₂.⁴

Nitrogen EOR projects seem to be in decline. Nitrogen flooding has been an effective recovery process for deep, high-pressure, and light oil reservoirs. Generally for these types of reservoirs, nitrogen flooding can reach miscible conditions. However, immiscible nitrogen injection has also been used for pressure maintenance, cycling of condensate reservoirs, and as a drive gas for miscible slugs.⁵

Thermal methods, specifically steam injection, are often the best for recovering heavy oil. The world contains about 10 trillion bbl of heavy oil resources.⁶ However, Egypt has about 3 billion bbl of heavy oil in place with about 40% in the Eastern Desert, 3% in the Western Desert, 18% in Sinai, and 39% in the Gulf of Suez.^{1 7}

The thermal methods provide a driving force and heat for reducing oil viscosity and improving mobility. Cyclic steam stimulation is one of the most common thermal processes in use. It involves injecting steam and then producing oil for the same well. It is considered an economic oil recovery method that costs about $20/bbl of oil recovered. Oil recovery factors for cyclic steam in Cold Lake, Alta., are more than 25%, while in Venezuela recoveries as high as 40% have been noted.^{1 6}

Chemical EOR methods are mostly for low to medium viscosity oils. To date, chemical flooding has had limited application due to the high ongoing cost of associated chemicals, concerns about environmental impacts and the failure of selected laboratory successes to translate into significant production gains when applied to operating fields. Polymer flooding is considered a mature technology and still is the most important EOR chemical method based on the review of full-field case histories.⁴ Polymer flooding is the simplest technique to apply in the field and requires a relatively small capital investment. Injection of alkali, surfactant, alkali-polymer (AP), surfactant-polymer (SP), and alkali-surfactant-polymer (ASP) have been tested in a limited number of fields.

Reserves and EOR potential

World proved oil reserves in 2010 were sufficient to meet 46.2 years of global production, according to the 2011 BP statistical review of world energy.⁸

The 2010 figures are down slightly from the 2009 R/P ratio because of a large increase in world production. Global proved reserves rose slightly last year.

Global oil production increased in 2010 to reach record level of 82.1 million b/d but did not match the rapid growth in consumption. World oil consumption increased to reach record level of 87.4 million b/d.

Similarly, oil production in Egypt is less than demand. Egypt averaged 736,000 b/d in 2010, when the country's consumption averaged 757,000 b/d (Fig. 2).

Most of the world's oil is produced from mature fields. The rate of replacement of the produced reserves by new discoveries has been declining steadily in recent decades.

In addition, operators are focusing on redeveloping and improving oil recovery from existing oil reservoirs because of increased exploration costs for new oil fields and the limited opportunity for discovering major high-quality oil reserves. Therefore, the increase in recovery factors from mature fields by applying the EOR technologies will play a key role to meet the growing energy demand in coming years.

It is well known that EOR projects have been strongly influenced by economics and crude oil prices. Very strong consumption growth helped to push prices higher late in the year, with prices reaching a peak near $94/bbl for Brent at yearend. Other benchmark crudes registered similar increases. Therefore, EOR technologies are required as a key to sustain production plateau and fill demand.

EOR has potential to add significant reserves and add incremental oil recovery. The typical incremental recovery and agent utilization along with the estimated water usage for the enhanced oil recovery processes are presented in Table 1.^9-11 The volume of oil produced by EOR methods doubled from 1982 to 1990 (1.2 million b/d) and doubled again to 2.5 million b/d in 2006.^{12 13} In 2012, the volume of oil produced by EOR methods reached about 1.7 million b/d.³

Worldwide, a 1 percentage point increase in the global recovery factor represents 88 billion bbl of added conventional reserves, equivalent to the replacement of 3 years of global production at the current rate of 27 billion bbl/year. The estimated Capex required to develop these reserves is roughly $190 billion, corresponding to 80% of global E&P Capex outlays ($236 billion) in 2006.¹² The impact of EOR on future global oil supplies depends on the disposition to make significant long-term investments. The oil potential is there.

EOR screening approach

The general approach for discerning the EOR method suitable for a specific reservoir is a lengthy process and involves several phases and stages.

The current study will consider only the data management and preliminary screening stages.

In this study, an investigation on the applicability of using EOR methods in Egyptian oil fields is conducted. Table 2 presents a list of the reservoirs and fields under the current study. The rock and fluid properties data of these reservoirs were collected from a previous research.¹⁴

The screening criteria are useful for cursory examination of many candidate reservoirs before expensive reservoir descriptions and economic evaluations are performed. Therefore, a preliminary screening is initially carried out using specialized software (EOR Graphical User Interface—EORgui) to nominate and recommend the most suitable EOR technologies. Then, the results of the preliminary screening are analyzed based on the results of the successful EOR recovery projects worldwide coupled with the experimental results from previous and current research activities.

Through the use of EORgui software, the oil fields and reservoirs under the current study are screened and the potential of applying the EOR techniques are identified. Once all the necessary data for each reservoir (Table 2) are entered into the software, the relative criteria fit to the input data are calculated. The results for each run are shown in summary chart.

Fig. 3 presents a sample of EORgui results for one reservoir. The coloring scheme in Fig. 3 is based on the degree to which the criteria are met or not. A red cell signifies that the criterion is not met, light green that it is just met, and dark green that it is well met.

Table 2 indicates that the most appropriate EOR methods for the studied oil fields appear to be CO₂ injection, immiscible gas injection, ASP injection, combustion, or steam injection. Based on the history of successful EOR projects results, the CO₂ injection (miscible flooding) and micellar-polymer technology seem to be the most appropriate EOR methods.

Egypt has about 3 billion bbl of heavy oil in place. Issaran is one of the first heavy oil carbonate fields in which steam EOR has been successfully implemented.¹ However, the thermal enhanced oil recovery method is not seen to be applied in most of the reservoirs under the current study because of the reservoir depths and the oil viscosity, but there is a possibility of injecting steam in West Bakr field.

The depths of the reservoirs under the current study are relatively deep and the oil viscosity is relatively low. However, thermal EOR methods are usually suited for high-viscosity oils in shallow formations and require oil reservoirs of fairly high values of rock permeability.

The restriction of thermal processes to relatively deep reservoirs is because of potential heat losses through lengthy wellbores. The main technical challenges associated with steam technique are poor sweep efficiencies, loss of heat energy to unproductive zones underground, and poor injectivity of steam.

Poor sweep efficiencies are due to the density differences between the injected fluids and the reservoir crude oils. The lighter steam tends to rise to the top of the formation and bypass large portions of crude oil. Data have been reported from field projects in which coring operations have revealed significant differences in residual oil saturations in the top and bottom parts of the swept formation.¹⁵

Research is being conducted on methods of reducing the tendency for the injected fluids to override the reservoir oil. Techniques involving foams are being employed. The poor injectivity found in thermal processes is largely a result of the nature of the reservoir crudes. Many operators have applied fracture technology in connection with the injection of fluids in thermal processes. This has helped in many reservoirs.

Operational problems include the following: the formation of emulsions and the corrosion of injection and production tubing and facilities. When emulsions are formed with heavy crude oil, they are very difficult to break.

Table 2 indicates that CO₂ miscible gas injection methods may be applicable to some Egyptian oil reservoirs. For very light oils in deep formations, CO₂ and miscible displacement processes are the best to be applied. A low-viscosity and relatively high gravity oil will usually contain enough of the intermediate-range components for the multicontact miscible process to be established.

The most critical parameter with respect to miscible CO₂ flooding is minimum miscibility pressure (MMP). Preferably, the injection pressure at the start of a CO₂ flood should be at least 14 bar above MMP to achieve miscibility of CO₂ and reservoir oil. This means that the ratio between reservoir pressure and minimum miscible pressure (P/MMP) normally should be greater than 1, but CO₂ flood EOR is still possible for P/MMP greater than 0.9.¹⁶

Because of the uncertainties of both calculation of MMP and measured pressure data, reservoirs with P/MMP greater than 0.9 are regarded as suitable for CO₂ floods by this screening if the reservoir pressure is lower than the original reservoir pressure at the start of CO₂ injection.

The serious limitation to the use of CO₂ as an EOR method in Egypt is its availability and transportation. It should be highlighted that Egypt has several sources of CO₂ that need to be assessed in another study, for example:

• Gas processing plants such as Salam and Tarek in the Western Desert. These plants produce large quantities of CO₂ as a by-product of two-stage membrane systems.

• Power plants: Egypt has 32 power plants (15 thermal power stations, 15 gas turbine power stations, and 2 combined-cycle power stations) located in the Gulf of Suez, Western Desert, and Nile Delta.

• Refineries are at Suez, Alexandria, Cairo, and Assiut.

• Other industries: petrochemicals, cement, fertilizers, iron, and steel.

Because of differences in density and viscosity between the injected fluid and the reservoir fluid(s), the CO₂ miscible process often suffers from poor mobility. Viscous fingering and gravity override frequently occur. The simultaneous injection of a miscible agent and brine was suggested in order to take advantage of the high microscopic displacement efficiency of the miscible process and the high macroscopic displacement efficiency of a waterflood.

The improvement was not as good as hoped for since the miscible agent and brine tended to separate due to density differences, with the miscible agent flowing along the top of the porous medium and the brine along the bottom.

Several variations of the simultaneous injection scheme have been suggested and researched.¹⁵ They typically involve the injection of a miscible agent followed by brine or the alternating of miscible agent-brine injection. The latter variation has been named the water alternating gas (WAG) process and has become the most popular.

A balance between amounts of injected water and gas must be achieved. Too much gas will lead to viscous fingering and gravity override of the gas, whereas too much water could lead to the trapping of reservoir oil by the water. The addition of foam-generating substances to the brine phase has been suggested as a way to aid in reducing the mobility of the gas phase. Research is continuing in this area.

Operational problems involving miscible processes include transportation of the miscible flooding agent, corrosion of equipment and tubing, and separation and recycling of the miscible flooding agent.

Table 2 shows also that chemical EOR methods are applicable for some of the Egyptian oil fields such as Razak, El Morgan, Badri, and West Qarun fields, taking into consideration the salinity and temperature parameters.

The chemical EOR methods are suitable for low to medium viscosity oils. However, the high salinity of the Egyptian formations imposes a serious limitation on the use of micellar and polymer floods. High values of formation water salinity and temperature cause problems in degradation, difficulty of designing stable surfactant/polymer systems; and-or consumption of chemicals used in the process. The salinity should be less than 200,000 ppm and temperature should be less than 200° F.^{2 17}

In addition to the salinity and temperature, reservoir heterogeneity is another critical parameter. Most chemical EOR methods are applicable preferably to sandstone reservoirs and not for extensive fractures and or extreme reservoir heterogeneity. Therefore, application of the chemical methods to Egyptian oil fields should be carefully studied. The EOR techniques should be tailored to the specific reservoir.

Other technical challenges associated with chemical processes include (1) the screening chemicals to optimize the microscopic displacement efficiency, and (2) maintaining good mobility in order to lessen the effects of viscous fingering. The requirements for screening of chemicals vary with the type of process. Obviously, as the number of components increases, the more complicated the screening procedure becomes.

The chemicals must also be able to tolerate the reservoir environment. However, the main operational problems involve treating the water used to make up the chemical systems, mixing the chemicals to maintain proper chemical compositions, plugging the formation with particular chemicals such as polymers, dealing with the consumption of chemicals due to adsorption and mechanical shear and other processing steps, and creating emulsions in the production facilities.

Therefore, the available surface facilities should be taken into considerations as those have have a big impact on project Capex and Opex.

Table 2 illustrates also that some of the Egyptian oil reservoirs of this study are considered to be good candidates for applying hydrocarbon miscible flooding, immiscible displacement, and combustion methods.

It is worth mentioning that hydrocarbon miscible flooding is very costly and immiscible displacement is less effective than miscible flooding. Combustion requires more control, is suitable for heavy oil, and has limited successful field applications.

A main problem in combustion is the creation of adverse effects on the environment. In the high-temperature environments created in combustion projects and when water and stack gases mix in the production wells and facilities, corrosion becomes a serious problem. Special well liners are often required. Stack gases that form as crude is burned also pose environmental concerns in combustion applications.

Based on the screening analysis discussed in the study, it was found that CO₂ has the most potential for future miscible-flood projects. However, this potential depends heavily on the availability and cost of future CO₂ supplies.

Acknowledgments

Thanks to Prof. Helmy Sayyouh and Eng. Ahmed Shehata for their support during the preparation of this work. They provided the author with several valuable books and papers.

References

1. Abu El Ela, M., et al., "Thermal heavy-oil recovery projects succeeded in Egypt, Syria," OGJ, Dec. 22, 2008, p. 40.

2. Taber, J.J., et al., "EOR screening criteria revisited—Part 1: Introduction to screening criteria and enhanced recovery field projects," SPE 35385-PA, SPE Reservoir Engineering Journal, August 1997, Vol. 12, No. 3, p. 189.

3. Koottungal, L., "2012 Worldwide EOR Survey," OGJ, Apr. 2, 2012, p. 56.

4. Alvarado, V., and Manrique, E., "Enhanced oil recovery: An update review," Energies, Aug. 27, 2010, p. 1,529.

5. Manrique, E.J., et al., "EOR field experiences in carbonate reservoirs in the US," SPE 100063-PA, SPE Reservoir Evaluation & Engineering Journal, December 2007, Vol. 10, No. 6, p. 667.

6. Farouq Ali, S.A., et al., "Practical heavy oil recovery," draft volume, 1997.

7. Egyptian General Petroleum Corp., "Oil potential in Egypt: statistics & analysis," Sixth Technology Transfer Workshop, SPE Egypt Section, Cairo, May 2007.

8. BP Statistical Review of World Energy, June 2011.

9. Carcoana, Aurel, "Applied enhanced oil recovery," Prentice-Hall Inc., 1992.

10. Donaldson, E.C., et al., "Enhanced oil recovery: fundamentals and analysis," Elsevier Science Publishing Co. Inc., New York, 1985.

11. US Department of Energy, "DOE Updates enhanced recovery economics," OGJ, 1981, Vol. 79, Issue 28, p. 43.

12. Sandrea, I., and Sandrea, R., "Global oil reserves—1: Recovery factors leave vast target for EOR technologies," OGJ, Nov. 5 and 12, 2007.

13. Moritis, G., "2006 Worldwide EOR Survey," OGJ, Apr. 17, 2006, p. 46.

14. Shindy, A.M., "Development of an expert system for enhanced oil recovery method selection," MSc thesis, Cairo University, Department of Petroleum Engineering, 1996.

15. Terry, R.E., "Enhanced oil recovery," in Meyers, Robert A., ed., "Encyclopedia of Physical Science and Technology," 3rd Edition, Vol. 18, Academic Press, 2001, pp. 503-18.

16. Mathiassen, O.M., "CO₂ as injection gas for enhanced oil recovery and estimation of the potential on the Norwegian Continental Shelf," MSc thesis, Norwegian University of Science and Technology, Department of Petroleum Engineering and Applied Geophysics, 2003.

17. Sayyouh, M.H., and Al-Blehed, M., "Screening criteria for enhanced recovery of Saudi crude oils," Energy Sources, 1990, Vol. 12, Issue 1, p. 71.

The author

Mahmoud Abu El Ela ([email protected]) is an associate professor at the Petroleum Engineering Department, Cairo University, Egypt. He also works as a project manager at WorleyParsons Engineers Egypt Ltd. Previously, he was a lead process engineer at WorleyParsons, an assistant professor at the Petroleum Engineering Department at Cairo University, petroleum process consulting engineer for Khalda Petroleum Co., and a research engineer at Woodside Research Foundation at Curtin University of Technology in Australia. Since 1997, he has been a technical consultant in petroleum engineering for national and international companies. He has a BSc and MSc in petroleum engineering from Cairo University and a PhD from Curtin University of Technology.