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New Steamflooding Techniques Pay Off in Mukhaizna Field

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An operator has faced a number of challenges producing heavy oil (8000–20 000 cp) from the Khuff and Kahmah carbonate reservoirs at the Mukhaizna field since their discovery in 2010. The large, low-productivity reservoirs have few analogs in the world, so the operator established new approaches to bring these reserves to market. This paper covers the staged field-development methodology, including analysis and evaluation of various development concepts, that enabled the company to optimize both completion design and artificial-lift selection, reducing downtime and lowering operating costs by nearly 50%.

Introduction

The Mukhaizna field, located in the eastern part of central Oman, was discovered in 1975 by Petroleum Development of Oman. The Kahmah Group consists of shelf carbonate deposits of Cretaceous age, whereas the Khuff formation is of Permian age, with a major unconformity between the lower Kahmah and Khuff formations. The lower Kahmah units are believed to have been either eroded away or not deposited in this area. The Mukhaizna field is relatively close to the Huqf axis in southeastern Oman. The Kahmah and Khuff reservoirs are more representative of the interior of Oman than of either northern or southwestern Oman.

The field structure consists of two structural highs, the North structure and the South structure, separated by a saddle in the middle. The first well was drilled in the Khuff reservoir and proved its productivity. Because the shallower Kahmah B reservoir has even more stock-tank original oil in place, the operator decided to assess its productivity while delineating the reservoir by drilling four wells. These wells were drilled in the northern, middle, and southern areas of the North structure in northeast/southwest and east/west directions to acquire information about the fractures throughout the 20,000-acre field. A coring program was initiated at the same time. The results from the wells and cores helped form the Phase 1 field-development plan.

The two reservoirs have different geological properties. Khuff is highly fractured and has low matrix permeability, whereas Kahmah B is less fractured, has higher permeability, and has been dolomitized to varied levels across the field, which has had a significant effect on production performance.

Reservoir-Development Strategy

Steam-enhanced recovery of oil from heavy-oil reservoirs results from reduction in viscosity and residual oil saturation and from distillation. In fractured reservoirs, imbibition may play a significant role in improving recovery. If the crude has more resins and asphaltenes (i.e., more polar compounds), it tends to make the rock more oil-wet. Applying high-temperature steam can alter the wettability, making the rock more water-wet. This helps improve recovery because of imbibition. In addition to the complicated geology of Mukhaizna’s naturally fractured, vuggy, and dolomitized carbonate reservoirs, identifying the right steam-injection method and selecting the best artificial-lift system were critical to the success of the project.

Because of the heavy oil and high reservoir pressures, the wells were produced initially with cyclic steam stimulation (CSS) and lifted with progressive cavity pumps (PCPs) or all-metal PCPs (AMPCPs). The low matrix permeability (10–50 md) resulted in low steam slug volumes, and the wells cooled quickly when they were put on production. This CSS process required separate artificial-lift methods for the cold and hot portions of the production cycle, which was not economical.

The development strategy of the two reservoirs evolved as more performance data were collected from wells drilled in the field. The data included production rates, communication between wells, steam distribution across the horizontal section, artificial-lift failures, and pressure data. Recent improvements in completion design and artificial lift have reduced downtime significantly, thus increasing value from the field. The evolution of this strategy is a result of increased focus from both the subsurface experts in the office and the operations group in the field. The main development strategies for the different types of reservoirs include CSS, group CSS (GCSS), sequential steam injection (SSI), and pressure depletion followed by steam injection.

CSS. In CSS, steam is injected into the wellbore; then, after a few days of soaking, the well is produced. Because the initial cold production rates from most of the Mukhaizna wells were quite poor (5–20 B/D, depending on the reservoir quality), acid jobs were carried out to improve productivity from the wells. Also, initial steam-injection volumes were low because the reservoir pressure is quite similar to the steam-injection pressure. As the produced volumes increased with each cycle, steam-­injection rates improved, resulting in further improved oil rates.

GCSS. As more steam was injected in each CSS cycle, the wells started to show communication with adjacent wells and the injection well had to be shut in because the wellhead temperature and water cut in the adjacent producer increased drastically. To overcome this problem, the GCSS concept, in which wells that communicate with one another are injected with steam at the same time as a group, was developed. This resulted in the injection of a significant volume of steam in all the wells, but the reservoir filled up quickly as the wells communicated. ­Nevertheless, appreciable volumes of oil were recovered when the wells were put back on production.

SSI. Traditional steamflooding has not worked well in this context because of the presence of fractures and vugs in the reservoirs. This led to quick breakthrough of heat accompanied by increased wellhead temperatures and quick communication, which resulted in high water cuts. SSI is a hybrid steamflood and CSS process developed to overcome these problems. It allowed higher volumes of steam to be injected and enabled continuous production of oil from adjacent wells with more drawdown, which was not possible in the pure CSS configuration. In CSS, only approximately 5% of the oil was recovered, but SSI increased the recovery factor to approximately 15%. The process helps produce the oil between the wells, unlike CSS and GCSS, which help produce oil close to the wellbore.

Pressure Depletion Followed by Steam Injection. Some of the highly dolomitized areas (greater than 80% dolomite) in the central-southern part of the field exhibited high water cuts. This water was initially believed to be coming from the flanks through fractures. Drilling logs combined with simulation results showed that this water was from the reservoir itself and not from the flanks. Since then, electrical submersible pumps (ESPs) have been used in these wells to produce at high liquid rates, thereby reducing the pressure in these areas. The pressure was successfully reduced to approximately 700 psi from the initial 1,100 psi. This strategy decreased water cut and increased oil-production rates from the wells.

Artificial-Lift Techniques

Beam Pumps. Beam pumps can withstand high temperatures during production operations, but, as the fluid becomes cold and viscous, pumping the wells becomes difficult, resulting in rod failures because of floating.

AMPCPs. PCPs are best suited for cold, viscous oil, but they are unable to withstand temperatures greater than 175°F because of the rubber element in the stator. The temperature after CSS exceeds this limit. AMPCPs were designed to overcome these problems, but, after a couple of CSS cycles, the rod failures increased because of the increased torque exerted, possibly as a result of thermal expansion.

ESPs. ESPs can produce liquids at very high rates, but they are not suitable for lifting viscous fluids and they cost much more than the other lift methods, especially if the strategy is to use CSS. Each CSS cycle requires a minor modification to the artificial lift when switching from production to injection. Because a well can go through a large number of CSS cycles, the cost of failures and the cost of changing artificial lift each time can be uneconomical. For CSS, beam pumps are the least expensive overall and, thus, the preferred option.

Small Improvements Yield Big Results

A large number of small improvements over the last few years has rewarded the operator with excellent results in the Mukhaizna field; production has increased even without additional drilling (Fig. 1).

Fig. 1—Mukhaizna field producing intervals.

 

Using limited-entry perforations in the wells has led to better steam distribution. Raising beam-pump-installation depths from 90° in the horizontal wells to shallower depths at 70° has resulted in increased run life. Drilling slimmer holes has led to cost savings, and using flush tubing has enabled installation of bigger pumps in these slimmer wells. To reduce operating expenditures and downtime further, steam-bypass pump trials are being implemented. This would eliminate the need for a hoist, a rapid-service rig, or both to convert wells from injectors to producers and vice versa.

For a limited time, the complete paper SPE 190478 is free to SPE members.

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 190478, “Steamflooding Heavy Oil in a Naturally Fractured Carbonate Reservoir in Sultanate of Oman: A Case Study,” by Sanjeev Malik, SPE, Mohammed Al Balushi, SPE, Salim Al Salmi, Aamer Al Belushi, Faris Al Ismali, and Fahad Al Qassabi, Occidental Petroleum, prepared for the 2018 SPE EOR Conference at Oil and Gas West Asia, Muscat, Oman, 26–28 March. The paper has not been peer reviewed.

New Steamflooding Techniques Pay Off in Mukhaizna Field

01 April 2019

Volume: 71 | Issue: 4

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