Workover Review for Hot, High-Pressure Gas Wells
- S.A. Cassinis (Mobil Oil)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- August 1985
- Document Type
- Journal Paper
- 1,491 - 1,497
- 1985. Society of Petroleum Engineers
- 2.2.2 Perforating, 4.1.5 Processing Equipment, 1.8 Formation Damage, 1.6.9 Coring, Fishing, 4.1.2 Separation and Treating, 4.3.4 Scale, 4.6 Natural Gas, 5.4.2 Gas Injection Methods, 3 Production and Well Operations, 1.14 Casing and Cementing, 5.4.10 Microbial Methods, 4.2.3 Materials and Corrosion, 1.6 Drilling Operations, 4.1.9 Heavy Oil Upgrading, 1.10 Drilling Equipment
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Today's high operating costs demand a critical and thorough review of workover procedures and equipment. High-pressure gas leaks in both wellhead and tubing connections prompted an extensive workover program in the Arun field, North Sumatra. Mobil Oil Indonesia (MOI), contractor to Pertamina, Indonesia's national oil company, started operation of the Arun Pertamina, Indonesia's national oil company, started operation of the Arun field in 1977. Typical wells produce an average of 150 MMscf/D [4.25 X 10 6 std m3/d] through 7-in. [17.8-cm] tubing at wellhead pressures and temperatures of 3,500 psig [24.1 MPa] and 325F [163C], respectively. Following a series of in-depth technical reviews, including both design studies and laboratory evaluations, MOI was ready to undertake a well workover program on all production and gas injection wells. The plan was to upgrade the original completions as follows. 1. Install a metal-to-metal wellhead seal on the 9 5/8-in. [24.5-cm] casing. 2. Replace all 7-in. [17.8-cm] tubing connections with a premium thread, tested to withstand extreme temperature reversals. 3. If possible, run and cement a 5 1/2-in. [14.0-cm] liner in openhole completions. By early 1983, MOI had spent $80 million on 23 workovers. Application of the following workover review produced reliable conclusions and specific cost-effective recommendations.
Worldwide, workovers are required more often to service oil and gas wells producing from deep, hot, sour, high-pressure formations. With oil prices producing from deep, hot, sour, high-pressure formations. With oil prices dropping and operating costs rising, MOI found it necessary to review the performance of workover procedures and completion equipment used in the performance of workover procedures and completion equipment used in the Arun field. This review covered 18 workovers completed in 1982 and early 1983. To provide a detailed analysis, each review separated the workover operation into the following 10 distinct activities. 1. MIRU (Move-In, Rig-Up) -- time spent from rig release to spud on new location. 2. Rekill and condition mud -- time spent from spud to start of tubing cut and recovery operation. 3. Tubing cut and recovery -- cumulative time spent in fishing for tubing, production seals, and packers. 4. Cement/bridge plug -- cumulative time spent in setting plugs. 5. Metal-to-metal seal -- time spent machining and installing a metal-to-metal wellhead seal on the 9 5/8-in. [24.5-cm] casing. 6. Drilling/milling -- cumulative time spent in drilling and milling operations excluding time spent in kick-well-off operations and in sidetrack drilling. 7. Completion -- cumulative time spent in preparing and running the final completion equipment. 8. Kick well off -- time spent after completion to rig release. 9. Rig repair -- cumulative time spent on major rig repairs, normal maintenance not included. 10. Other -- cumulative time spent in miscellaneous jobs such as side-track drilling, fishing for tools, logging, and testing. Data then were gathered from each workover and collated into different tables and bar charts based on these 10 categories of activity. After careful evaluation, conclusions and recommendations were prepared.
In Spring 1980, a full review of the results of nearly 3 years' operation was carried out. The summary and conclusions of this review were as follows.
9 5/8-in. [24.5cm] Casing Metal-to-Metal Seal. The Arun producing conditions exceeded the ability of the then-available resilient sealing systems to provide a long-term effective seal between casing and wellhead. Several compositions of resilient material were used in the original wellheads (Fig. 1) provided by the manufacturers. Among them were fluoro-elastomer rated at 400F [204C] and a nitrile rubber rated at 300F [149C]. Although much work was done, the failure mechanism of the seal materials was not identified. The recommendation was made that a metal-to-metal seal must be established between the 9 5/8-in. [24.5-cm] casing and wellhead. The effectiveness of metal-to-metal seals was supported by the high degree of success with the metal-to-metal seals between the tubing hanger and the tubing heads. Fig. 2 shows the design of the metal-to-metal seal, which uses a hydraulically energized, mechanically locked stainless steel seal ring to effect a seal between the casing and the wellhead. The metal-to-metal seal assembly is a double-studded flange installed between the wellhead and tubing head. There were no changes in the existing wellhead. A minor change was made in the tubing head to allow installation of a casing hold-down ring.
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