PRODUCTION/RESERVOIR MANAGEMENT

Breaking a paradigm: Simultaneous gas cap and oil column production

Extensive reservoir modeling shows that this non-conventional production approach, with addition of water injection at the gas-oil contact, can increase oil and gas recoveries in certain types of reservoirs

Travis C. Billiter and Anil K. Dandona, Texaco Exploration and Production Technology Department, Houston

he conventional way to produce an oil reservoir that has a gas cap is to produce only from the oil column while keeping the gas cap in place so that it can expand to provide pressure support. Depending on geometry, reservoir dip angle and oil production rates, gas can either cone down to the oil producers or breakthrough as a front, leading to substantial increases in gas-oil ratios of the oil producers.

This article presents a unique production methodology of simultaneously producing the gas cap and oil column, while injecting water at the gas-oil contact to create a water barrier to separate cap and oil column.

This methodology has application in reservoirs with a low dip angle, relatively large gas cap, and a low residual gas saturation to water. It is demonstrated that the net present value of the project is improved if there is an immediate market for gas. The work also demonstrates that recovery from the cap is minimally affected by reservoir heterogeneities. This is illustrated by geostatistical reservoir models; and the effect of heterogeneities on oil recovery is also documented.

Concept Introduction

As noted above, the conventional way to produce an oil reservoir that has a gas cap is to produce the oil column while minimizing gas cap production. During oil column depletion, the cap will expand to provide pressure or energy support. After the oil column is depleted, 25 to 35 years into the life of the project, the cap is "blown down."

The authors had an opportunity to conceive of a development strategy for an oil reservoir with a large gas cap, low dip angle and large oil column. This reservoir is located in an area of the world where an immediate gas market exists. The new strategy was to produce this reservoir by injecting water at the gas-oil contact while simultaneously producing the gas cap and oil column.

The water is injected at the gas-oil contact at rates high enough to overcome gravity effects and, thus, the water displaces the gas up dip. In addition to providing pressure support, the created water wall separates cap and oil column regions. Since the development plan also calls for use of electrical submersible pumps (ESPs) in the producing wells, it is imperative to keep gas production volumes from these oil wells at low levels so the ESPs will operate smoothly. As such, it is critical to control downward gas cap migration. To maintain reservoir pressure, water is injected not only at the gas-oil contact, but also around the periphery of the oil column to support the oil withdrawal rates.

A simplistic representation of the simulated structure in Fig. 1 shows location of the gas-oil contact, along with the water injector at the gas-oil contact, and the gas cap producer. The reservoir considered in this study has a 2° dip angle; for purposes of illustration, the dip angle is exaggerated in Fig. 1. Horizontal distance between injector and producer is 12,155 ft; and structural elevation between these two wells is 425 ft. Taking into account the density difference between water and gas, the injected water must overcome a gravity component of 149 psi, in addition to energy required for the water to displace the gas. The possibility of injecting water at high enough rates to overcome both gravity and displacement components is shown here.

The main purpose of this article is to present the concept of simultaneously producing the gas cap and the oil column, while injecting water at the gas-oil contact. Application for a newly discovered, offshore oil field has been studied. In this study, most of the effort was dedicated to proving the concept, as opposed to optimizing number and placement of wells to increase oil/gas recovery. It is the authors’ vision that this production methodology can also be applied to other reservoirs with similar characteristics.

Partial Proof Of Concept

A literature survey indicated that simultaneous production of gas cap and oil column while injecting water at the gas-oil contact has never been documented. However, four case histories were found in which water was injected at the gas-oil contact for the sole purpose of preventing gas cap migration downstructure. By preventing this migration, increased oil recoveries were realized. In these four cases, the cap was not produced during oil column depletion.

One successful application of this production methodology was in Adena field in the Denver basin in 1965.¹ By injecting water at the gas-oil contact, the operator was able to keep producing GOR close to solution GOR for an extended time. Ultimate oil recovery was estimated to be 47% of original oil in place (OOIP).

Injecting water at the gas-oil contact was also applied in seven of the oil reservoirs of the Algyo field in Hungary.² These seven reservoirs are thin, oil-edge zones with large gas caps. The operators were able to increase oil recovery by more than 10% of OOIP.

In the Canadian oil field, Kaybob South, water injection at the gas-oil contact was studied by Deboni and Field.³ They used numerical simulation to determine that a waterflood can be successfully implemented adjacent to a gas cap if a proper water "fence" is established between cap and oil column. The authors concluded that an additional 10% OOIP can be recovered.

Ader et al.⁴ describe the case history for Badri field in the Gulf of Suez, offshore Egypt. The Kareem reservoir has a gas cap/oil column pore volume ratio of 1.09. During the first two years of production from the oil column, GOR increased to 10,000 scf/STB from 600 scf/STB. To improve oil recovery by preventing gas cap migration downstructure, water was injected at the gas-oil contact using four vertical wells, starting in May 1995. Although the field had been produced ten years before this water injection installation, it is estimated that an additional 9.4 million STB or 3.6% OOIP will be recovered.

From the above-mentioned studies, it is observed that this production methodology works best in reservoirs in which the gas cap does not overlie the entire oil column. In such reservoirs, surface area of the gas-oil contact is minimal, permitting water injection at high enough rates to separate cap and oil column. Conversely, this production methodology will not work in anticlinal structures in which the gas cap overlies the entire oil column. In such a structure, surface area of the gas-oil contact is large and gas cap isolation is difficult.

The literature review has thus provided partial proof of concept; at least four reservoirs around the world have been successfully produced by injecting water at the gas-oil contact while producing the oil column and containing the gas cap in place. In this presentation, the authors take the methodology one step farther.

Model Description

The concept of simultaneously producing the gas cap and oil column was tested using a three-phase, black-oil, finite-difference simulator. A uniform aerial grid of 40 by 40 was superimposed on the reservoir structure, which has a uniform thickness of 60 ft, and was divided into four, 15-ft layers. The model contains 6,400 cells (40×40×4); cell size is 1,100×1,400×15 ft. Using a large, coarse cell size provided the option of making a large number of simulation runs.

The grid imposed on the structure map is shown in Fig. 2. The gas cap is represented by the light blue region; the oil column by the red region. The reservoir is not supported by an aquifer; and gas cap dip is about 2°. Horizontal distance between the injector at the gas-oil contact and the gas cap producer is about 12,155 ft. Length and width of the oil column are about 4 and 6 mi, respectively.

Pore volumes and fluid volumes in place are reported in Table 1. Gas cap pore volume to oil pore volume ratio is 0.20. This reservoir contains 1,487 MMSTB oil and 519 Bscf gas cap gas. Pertinent reservoir properties are listed in Table 2. Average permeability is 2,500 md. A kV/k_H ratio (vertical/horizontal permeability) of 0.1 was used in the model to account for stratification. Corey-type correlations were utilized to generate the relative permeability curves.

When the simultaneous production concept was utilized, the reservoir was produced using four oil producers located in the center of the oil column (OPNSGC, OPEWT, OPNS, OPEWB), three water injectors located at the boundary of the field (WIEWB, WIEWT, WINS), one water injector at the gas-oil contact (WIGC), and one gas producer located in the gas cap (GP1), Fig. 2. All of these are horizontal wells, with laterals 4,400 to 6,000 ft in length. The oil producers are all completed in model layer 2, the gas producer in layer 1, and water injectors in layer 2.

The wellbore orientation is shown in Fig. 3. Water injectors are oriented to create a water ring around the oil column. The water injector at the gas-oil contact follows the gas-oil contact and is long enough (6,000 ft) to adequately separate gas and oil column with a water fence. Pressure sinks created by producing the gas cap well and the oil well that offsets the gas-oil contact (OPNSGC), will assist in creating a water wall between the gas and oil by drawing the water both ways.

To maintain full reservoir pressure, a reservoir barrel of water was injected for each reservoir barrel of fluid produced. The maximum withdrawal rate for three of the oil producers (OPEWB, OPEWT, OPNS) is 80,000 Rbpd/well. The maximum injection rate for three of the water injectors (WIEWB, WIEWT, WINS) offsetting these oil producers is also 80,000 Rbpd/well, as is maximum injection rate for water injector (WIGC) at the gas-oil contact. This well must inject enough water to support both the gas cap producer (GP1) and the oil producer nearest the gas-oil contact (OPNSGC). Thus, these two wells produce at the lower rates of 40,000 Rbpd/well. For the gas cap producer, the 40,000 Rbpd equates to about 60 MMscfd. The watercut limit for the gas cap producer is 20%, for the oil producers, 95%.

The above-mentioned rates are feasible, based on Texaco’s experience in developing Captain field in the North Sea. Captain, and the field under consideration for development, are both unconsolidated sands with similar productivity indices. When the concept of simultaneously producing the gas cap and oil column is applied to lower-productivity fields, a higher number of producers and injectors will be required.

Homogeneous Model, Results Comparison

The following production scenarios were simulated for 25 years using the homogeneous simulation model:

• Depletion: The oil column is produced through four oil producers and no water is injected. The gas cap is not produced, but expands to provide pressure support for the oil column.
• Conventional: The oil column is produced through four oil producers while water is injected in three peripheral water injectors (WIEWB, WIEWT, WINS), but not at the gas-oil contact. The cap expands to provide pressure support to the oil column.
• Gas cap containment: The oil column is produced through four oil producers while water is injected in all four injectors, including at the gas-oil contact. The gas cap is not produced, but is kept from expanding downward by a water wall created by injection at the gas-oil contact.
• Simultaneous production: The oil column is produced through the four oil producers while water is injected in all four water injectors, including at the gas-oil contact. The gas cap is produced through the cap producer (GP1) simultaneously, as the oil column is depleted. The water injector at the gas-oil contact (WIGC) provides pressure support for both cap and oil column.

The performance summary after 25 years of production for each of the simulated scenarios is reported in Table 3. Fig. 4 shows oil recovery vs. time for each homogeneous production scenario. Oil recovery for the depletion scenario after 25 years of production is 11.2% OOIP. This scenario was run to establish base oil recovery for comparison purposes. Oil recovery for the conventional scenario is 28.3%. This shows that injecting water everywhere except at the gas-oil contact dramatically increases oil recovery by providing needed pressure support.

Oil recovery for the gas cap containment scenario is 30.6%. Comparing recovery results for conventional and cap-containment scenarios shows that containing the cap through injecting water at the gas-oil contact, increases recovery by 2.3% of OOIP for the homogeneous system studied. This increase is somewhat smaller than the oil recovery increase reported in the literature (4–10%), perhaps because of the lack of heterogeneity.

Oil recovery for the simultaneous production scenario is 30.4%. This is not significantly different than the 30.6% computed for gas cap containment. Comparing oil recovery results for cap containment and simultaneous production scenarios indicates that simultaneous production of cap and oil column will not be detrimental to total oil recovery. Note from Fig. 4 that rate of oil recovery for these two scenarios is virtually identical, as indicated by the overlying curves. These results indicate that the economic viability of the simultaneous production scenario depends on the tradeoff between early gas sales and reduced gas recovery due to the trapping of gas in the reservoir by the advancing waterfront.

Also reported in Table 3 is gas recovery for each of the simulated scenarios. The gas recovery column includes both recovered solution gas and gas cap gas. Gas recovery varies, from 22.6% for cap containment to 66.6% for depletion. For depletion, reservoir abandonment is assumed to be at 1,000 psia. For simultaneous production, cap recovery is 54.7% of initial cap gas in place. Gas from the cap was produced in depletion and conventional production scenarios; however, no attempt was made to compute percentage of total gas production attributable to the gas cap gas.

Cumulative-water-produced results show that there is little variation between the amount of water produced among the cases in which water is injected. Also reported in Table 3 is cumulative water injected. For conventional and gas cap containment scenarios, the cap is not waterflooded and, thus, ratio of cumulative water injected to oil pore volume is tabulated. For simultaneous production, the cap is waterflooded and, thus, ratio of cumulative water injected to hydrocarbon (HC) pore volume is reported. In all scenarios in which water is injected, the amount of injected water exceeds one hydrocarbon pore volume.

A comparative analysis of these four scenarios indicates that simultaneous production is the most viable option because it enhances cashflow through early gas sales, if a ready gas market exists. Therefore, the rest of this paper focuses on results from simultaneous production.

Simultaneous Production Results

For the simultaneous production scenario, water injected at the gas-oil contact isolates the cap from the oil column, and moves as a vertical wall, up dip, providing a very efficient, piston-like gas displacement. This is intuitively what one would expect, since the water-to-gas viscosity ratio is 35.

Fig. 5 shows the vertical cross section of the area between cap producer and water injector at the gas-oil contact. In the figure, dark blue represents the highest possible water saturation; red represents highest possible gas saturation; and light green is highest possible oil saturation. The four components show progression of the gas-water interface at 1, 4, 9 and 12 years. Although a small tongue of water in lower layers precedes the front, the front for the most part is vertical. The residual gas saturation to water was assumed to be 24% in this simulation run. This trapped gas saturation is represented by blue blocks behind the gas-water interface.

For water injection to successfully separate cap and oil column, it should be injected at a velocity high enough to overcome the hydrostatic head gradient imposed by gravity and the displacement gradient. The average pressure gradient is a summation of the displacement pressure gradient and the hydrostatic head gradient. This gradient will change during waterflood life because the moving water front will cause the hydrostatic head gradient to increase. A simple mathematical explanation follows.

Fig. 1 is a simplistic representation of the simulated reservoir. Horizontal distance between cap producer and water injector at the gas-oil contact is 12,155 ft. Reservoir dip in the cap region is 2°; structural elevation distance between these two wells is 425 ft. At start of water injection, the water will have to overcome both a pressure gradient due to hydrostatic head of the gas, and a pressure gradient due to the water having to displace the gas.

The hydrostatic head gradient imposed by the gas gradient is 0.003 psi/ft (425 ft×0.08 ft /12,155 ft). The pressure gradient due to hydrostatic head will change as the flood advances up dip. When the front reaches the cap producer, it will have to overcome a hydrostatic pressure gradient of 0.015 psi/ft (425×0.43 psi/ft /12,155 ft), in addition to the pressure gradient required for the water to displace the gas; this latter factor should remain constant throughout front advancement.

Pressure gradients for the simultaneous production scenario run were analyzed. Average pressure gradient between cap producer (GP1) and water injector at the gas-oil contact (WIGC) is 0.021 psi/ft. This gradient is more than adequate for the water to both overcome gravity effects and displace the gas. For comparison, average pressure gradient between one peripheral water injector (WIEWB) and one central oil producer (OPEWB) is 0.142 psi/ft. The gradient required for water displacing oil is much higher than the gradient for water displacing gas.

On the oil side of the gas-oil contact, average pressure gradient between injector at the gas-oil contact (WIGC) and offsetting oil producer (OPNSGC) is 0.079 psi/ft. For the cap containment case, average pressure gradient between injector at the gas-oil contact and offsetting oil producer is 0.086 psi/ft. The minimal difference in this gradient between these two production scenarios indicates that cap production does not significantly disrupt oil displacement by water on the oil side of the gas-oil contact.

In the simultaneous production scenario, production from the cap producer is 60 MMscfd for the first 12 years of the project, Fig. 6. The gas production is water-free until the front reaches the well. In the model, the cap producer is set to shut off when watercut exceeds 20%. For the homogeneous model, watercut exceeds 20% in year 12. Because of the piston-like displacement, after-breakthrough gas production is negligible.

Since the oil-recovery-time curve is basically the same for both gap containment and simultaneous production scenarios, Fig. 4, economics of simultaneous production depend on the tradeoff between accelerated cashflow from early sales and reduced cashflow from lower gas recovery due to some gas being trapped by the advancing water. This immediate sale of gas can improve net present value of a project significantly. For the reservoir studied, the difference in net present value between simultaneous production and conventional scenarios, with the cap blown down after 25 years of oil production, is $100 million, a 25% increase.

The residual or trapped gas saturation to water is one of the main variables in determining economic feasibility of simultaneously producing cap and column. The ideal choice is to measure this parameter in the lab on a fresh core sample. However, for this study, a measured value was not available, so a range of values for residual gas saturation to water, Sgrw, was obtained from the literature. Chierici et al.⁵ measured Sgrw to be 18% to 26% for unconsolidated sands. For consolidated sands, Fishlock et al.⁶ measured 35% on a high permeability sample.

For this study, an Sgrw range of 20% to 32% was investigated. In the above-mentioned results, 24% was used. To determine cap-recovery sensitivity to the variable of trapped-gas saturation to water, a series of additional simultaneous production scenario runs were made using Sgrw values of 20, 27 and 32%. Cap recovery for each run is shown in Fig. 6, and varies from a high of 57% when Sgrw equals 20%, to a low of 42% when Sgrw equals 32%. Intuitively, this is what one would expect, i.e., when more gas is trapped in the reservoir, less is recovered. These results indicate that the spread in the cap-recovery numbers can be significant and, thus, Sgrw can greatly affect project economics.

Heterogeneity Effects

Effect of permeability variation on oil/gas recoveries using simultaneous production methodology was investigated. Homogeneous model simulation results conclusively proved that gas from the cap can be produced simultaneously without affecting oil recovery. Since all reservoirs are heterogeneous, the authors wanted to determine how permeability variation affected the process of simultaneously producing cap and oil column.

The probability density function of permeability used in this study is shown in Fig. 7. This distribution is log-normal and has a mean of 2,500 md, the same as the homogeneous case. The median is 1,651 md; the mode is 760 md; 90% of the values lie between 363 and 7,513 md, 98% between 194 and 14,076 md. Because the distribution is log-normal, a large percentage of the values are lower-permeability values, with 49% falling within the range of 194 to 1,651 md. In simulation runs, these lower-permeability cells will slow water flow and distort the waterflood front.

Effects of heterogeneity were studied using a reservoir description provided by two different geostatistical models: layered sand/shale and variable sand/shale. These models were constructed using the above-described probability density function of permeability. Relevant variogram information for each model is given in Table 4. Unconditional simulation was used to generate five equally-likely realizations (ELRs) for each model. Each realization was run to simulate simultaneous production. Identical input parameters and constraints were used in each run, the only difference being permeability variation.

The permeability distribution for one ELR for both layered and variable models is shown in Fig. 8. As indicated by the variogram information in Table 4 and 3-D illustrations in Fig. 8, these models are significantly different. The variogram of the layered model forces its permeability to be somewhat continuous in the aerial plane and vary significantly in the vertical. The variogram for the variable model forces its permeability to vary significantly in both aerial and vertical planes. It is interesting that the layered sand/shale model is much more continuous in the aerial plane than is the variable, while the variable is more continuous in the vertical plane.

Oil recoveries for the five ELRs of the layered model vary from 24.4% to 38.0%, with the average of the five ELR runs being 30.4%, Table 5 and Fig. 9. This happens to be the same as oil recovery for the homogeneous case, but this is just by chance. The wide range in oil recoveries for the five models indicates that heterogeneity can lead to very different water-oil displacement efficiencies, both favorable and unfavorable, as compared to the homogeneous run.

The distribution of ELR oil recoveries, both above and below recovery for the homogeneous case, is due to a layering effect. A higher oil recovery is obtained when permeability ordering is such that high-permeability layers are at the top of the structure, low-permeability layers at the bottom. For such a system, viscous forces counteract gravitational forces to increase displacement efficiencies. A lower oil recovery is obtained when the layering order is reversed, i.e., low-permeability layers are at the top. In this system, viscous and gravitational forces work together to decrease displacement efficiencies.

Gas cap recoveries for ELRs of the layered model vary within the narrow range of 51.6% to 55.0%, with an average of 53.1%, Table 5 and Fig. 9. These values are very close to the cap recovery value of 54.7% for the homogeneous case. These results indicate that heterogeneity does not significantly affect cap recovery when the methodology of simultaneously producing cap and oil column is utilized. This is intuitively expected since displacement in the gas cap is very piston-like due to the favorable water-to-gas viscosity ratio of 35. Overall, heterogeneity effects on gas recovery are minimized because the gas can outrun the advancing water front.

Oil recoveries for the five ELRs of the variable model vary from 22.2% to 34.9%, with an average of 26.8%, Table 5 and Fig. 10. Once again, the wide range in oil recoveries for the five ELR models indicates heterogeneity can lead to very different water-oil displacement efficiencies. The variable model has more permeability variation in the aerial direction, which causes lower recoveries, in general, than the layered sand/shale model.

Cap recoveries for the ELRs of the variable model vary within the narrow range of 53.5% to 58.7%, with an average 55.4%, Table 5 and Fig. 10. Once again, these values are very close to the cap recovery value of 54.7% for the homogeneous case. Thus, the same observations made for the layered model are applicable to the variable model.

Since cap recovery is relatively constant for both layered and variable models, revenue from the gas cap will constitute a higher percentage of project NPV, if heterogeneity is such that the oil recovery from a given reservoir is low. For such reservoirs, simultaneously producing gas cap and oil column is attractive. Conversely, when reservoir heterogeneity is such that the oil recovery from a given reservoir is high, this production methodology will still be attractive, because early gas production will increase NPV.

Conclusions

It has been shown that simultaneously producing gas cap and oil column improves NPV for the reservoir investigated. For similar reservoirs, for which variables such as dip angle, gas cap/oil column size ratio, and residual gas saturation to water are favorable, this production methodology can be economically viable if an attractive gas market exists and, thus, should be investigated. Results have shown that process economics depend on the tradeoff between early gas sales and trapped gas, since oil recovery is virtually the same, regardless of whether the cap is produced, as long as water is injected at the gas-oil contact. It is recognized that each reservoir and fluid system is unique.

Gas displacement by injecting water at the gas-oil contact is an efficient process. The water/gas viscosity ratio of 35 causes viscous forces to dominate gravitational forces, resulting in an efficient, piston-like displacement. In fact, the benefits of having a favorable viscosity ratio are so high that even introducing large permeability variations does not significantly affect cap recovery.

The future direction of this work will investigate effects of reservoir dip angle, gas cap production rates relative to water injection rates at the gas-oil contact, reservoir permeability and oil viscosity, to develop empirical equations for determining applicability of this production methodology. Another possible investigation will be the blowdown of the watered-out gas cap after oil column depletion, to further increase total gas cap recovery.

Acknowledgment

The authors express their sincere thanks to Texaco Inc. and management at Texaco EPTD for providing the time to pursue this effort. They especially thank Dr. Ed Hrkel of EPTD and Greg Himes of Texaco Exploration for their encouragement. And they express their gratitude to colleagues at EPTD who provided useful ideas during this project, and who took the time to edit the manuscript. This article was adapted from paper SPE 49083, "Breaking of a paradigm: The simultaneous production of the gascap and oil column," prepared for presentation at the 1998 SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, Sept. 27–30, 1998.

Literature Cited

¹ Bleakley, W. B., "A look at Adena today," Oil and Gas Journal, April 18, 1966, pp. 83–85.

² Werovsky, V., S. Tromboczky, S. Miklos and M. Kristof, "Case history of Algyo field, Hungary," paper SPE 20995, presented at SPE Europec 90, The Hague, Netherlands, Oct. 22–24, 1990.

³ Deboni, W., and M. B. Field, "Design of a waterflood adjacent to a gas-oil contact," paper SPE 5085, presented at the 1974 SPE Annual Meeting, Houston, Oct. 6–9, 1974.

⁴ Ader, J. C., B. J. Williams and H. H. Hanafy, "Gas cap water injection enhances waterflood process to improve oil recovery in Badri Kareem field," paper SPE 37756, presented at the 1997 SPE Middle East Oil Show, Bahrain, March 15–18, 1997.

⁵ Chierici, G. L., G. M. Ciucci and G. Long, "Experimental research on gas saturation behind the water front in gas reservoirs subjected to water drive," paper Section 17, PD 6, 1-14, prepared for the 6th World Petroleum Congress, Frankfurt, June 1963.

⁶ Fishlock, T. P., R. A. Smith, B. M. Soper and R. W. Wood, "Experimental studies on the waterflood residual gas saturation and its production by blowdown," paper 15455, presented at the 1986 SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, Oct. 5–8, 1986.

The authors

Travis C. Billiter, Texaco Exploration and Production Technology Department, Houston, received a BS degree in petroleum engineering from Marietta College in 1992 and a PhD in chemical engineering from Texas A&M University in 1996. While in school, he worked summers for major oil companies. Since joining Texaco E&P in 1996, he has had the opportunity to simulate significant gas-condensate and black-oil reservoirs. His technical interests are in reservoir simulation, phase behavior/thermodynamics and application of finite-difference simulators to pressure transient analysis.

Anil K. Dandona, Texaco Exploration and Production Technology Department, holds MS and PhD degrees in petroleum engineering from Texas A&M University. He has worked more than 25 years in the oil industry, with the last nine years in Houston at Texaco E&P as a reservoir engineer. In his industry experience, he has worked as a consultant for projects spanning the globe. His technical interests are in the areas of reservoir engineering, simulation, reservoir management and enhanced recovery.

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