600 West Java 500 Deep Alex
Mobile Bay Shearwater
400
Gulf of Thailand E. Cameron, Sable Egret, Heron
300
Asgard Brunei
Khuff
Thunder Horse Ursa
200
conventional treatment was estimated at 45 hours in contrast to 24 hours for the OneSTEP technique—a 21-hour savings. This time saving is a direct result of fewer fluid stages and faster flowback. Other benefits were also realized. Less equipment and chemical inventory equates to less deck space required, and fewer chemicals reduce the operational risks of chemical spills associated with handling and lifting.
New Fields—Severe Conditions
Great strides have been made in acidizing at high temperature in the past few years. Treatment with acid-oil emulsions and chelants allows operators to acidize formations at elevated temperatures with reduced corrosion rates and less risk of secondary damage. As promising as this picture seems for acidizing, more improve ments in treating agents and procedures will be required to meet difficult conditions in the future.27 Current world demand for energy is expected to grow—it is estimated that 40% more energy will be required in 2020 than in 2007.28
As the 100
> Acidizing deep, hot reservoirs. Acidizing with HCl and HF is typically effective at reservoir temperatures below 200°F, and use of chelants can extend this temperature range to about 400°F. Recent deepwater gas discoveries are good examples of hot reservoirs and can reach temperatures of 250 to 550°F [288°C]. Chelants could be considered for acidizing fields between Ursa at 250°F and Egret at 350°F, but to acidize fields above 400°F, such as West Java, Deep Alex and Mobile Bay, new technology will be required.
search for new reserves continues, exploration is turning to deeper reservoirs; operations in the USA illustrate this trend. In 2007, wells deeper than 15,000 ft [4,572 m] accounted for about 7% of domestic production; this is forecasted to grow to 12% in 2010. The deep gas resource being produced by this type of well is large and could be as high as 29% of production in the future. One defining characteristic of deeper basins is that they are hot. Deep gas wells in the Gulf of Mexico and Brazil have average bottomhole temperatures of 204°C [400°F], and even higher temperatures have been reported. To help opera - tors focus on the implications of drilling and operating deep, hot wells, several classi fication systems have been developed.29
Many of these
deep, hot wells will require matrix acidizing at some point in their life span, and current technology covers only part of the temperature range (above left). This trend toward increasingly higher temperatures will demand improvements in all aspects of acidizing, from corrosion rates to treatment-fluid stability.
27. DeBruijn G, Skeates C, Greenaway R, Harrison D, ParrisM, James S, Mueller F, Ray S, Riding M, Temple L and Wutherich K: “High-Pressure, High- Temperature Technologies,” Oilfield Review20, no. 3 (Autumn 2008): 46−60.
28. Aboud R, Smith K, Forero L and Kalfayan L: “Effective Matrix-Acidizing in High Temperature Environments,” paper SPE 109818, presented at the SPE Annual Technical Conference and Exhibition, Anaheim, California, November 11−14, 2007.
29. Payne ML, Pattillo PD, Miller RA and Johnston CK: “Advanced Technology Solutions for Next Generation HPHT Wells,” paper IPTC 11463, presented at the International Petroleum Technology Conference, Dubai, December 4−7, 2007.
DeBruijn et al, reference 27. 30. Aboud et al, reference 28.
31. Al-Otaibi MB, Al-Moajil AM and Nasr-El-Din HA: “In-Situ Acid System to Clean up Drill-In-Fluid Damage in High-Temperature Gas Wells,” paper SPE 103846, presented at the IADC/SPE Asia Pacific Drilling Technology Conference and Exhibition, Bangkok, Thailand, November 13−15, 2006.
In spite of the difficulty in acidizing at extreme conditions, some early successes have been reported. For example, a South American high-pressure, high-temperature sandstone well with significant damage was treated with a combination of acetic acid and HF, resulting in a doubling of oil production.30
Keys to success in
The treatment fluid in this system contains an acid precursor that delivers time- controlled release for long-interval wells. In the final analysis, successful acidizing of high-pressure, high-temperature wells will place greater demands on both treatment fluids and procedures. Fluids will be required that have controlled reaction rates, low corrosion and acceptable health, safety and environmental footprints—chelants are a good example of a step in this direction. In addition to the development of new fluids, treatments like the OneSTEP technique that emphasize simplicity and minimize operational time will be at a premium. Taken together, future developments in both treating fluids and procedures that employ them will ensure that matrix acidizing keeps pace with difficult conditions as new fields are developed.
—DA
this operation at high temperature included a mild acid—acetic—associated with HF, and inclusion of a phosphonic acid stabilizer to keep products in solution. Another example of innovative solutions to acidizing in high- temperature environments is the use of an in situ acid system.31
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Oilfield Review
HCl-HF
Chelants Static reservoir temperature, °F
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