Corrosion Monitoring and Inhibition in Khuff Gas Wells
- R.M. Stephens (Bahrain Natl. Oil Co.) | M.F. Mohamed (Bahrain Natl. Oil Co.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- October 1985
- Document Type
- Journal Paper
- 1,861 - 1,866
- 1985. Society of Petroleum Engineers
- 5.2 Reservoir Fluid Dynamics, 5.6.1 Open hole/cased hole log analysis, 3.3.1 Production Logging, 4.1.2 Separation and Treating, 3.1.6 Gas Lift, 5.6.5 Tracers, 4.2 Pipelines, Flowlines and Risers, 4.2.3 Materials and Corrosion, 4.3.4 Scale, 4.1.3 Dehydration
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Khuff reservoir gas has been produced in Bahrain for 13 years. Since 1970, the wells have been periodically batch-treated with corrosion inhibitor because the gas is potentially corrosive. Caliper surveys and iron counts potentially corrosive. Caliper surveys and iron counts have been the main techniques for monitoring corrosion rate. In general, corrosion rates were low; accelerated corrosion was detected in two wells for a short time, but subsequent monitoring failed to detect continued corrosion. An experiment with a gradiomanometer logging tool to track the inhibitor and tests for residual inhibitor in the produced fluids show that batch treating effectively contacts the tubing string to bottom and protects the tubing for approximately 6 months.
The Khuff reservoir in Bahrain produces gas for power generation throughout the island and for oil reservoir pressure maintenance and gas lift in the Bahrain field. pressure maintenance and gas lift in the Bahrain field. The gas contains 500 ppm H2S and 6.2% CO2, making it potentially corrosive. The gas composition is shown in Table 1. To date, no free water is being produced.
The top of the Khuff reservoir is found from 9,000 to 9,800 ft [2743 to 2987 m] and has 1,950 ft [594 m] of pay composed of four zones: KO, KI, KII, and KIII. pay composed of four zones: KO, KI, KII, and KIII. Completions have been made in both cased and open hole. In general, the older wells were completed with either 7-in. [17.8-cm] casing or a 5-in. [12.7-cm] liner set through the pay zones. In both cased- and open-hole completions, 5-in. [12.7-cm] production tubing was run. When the liner was run, the tubing was tied back from the liner. Wells recently have been completed with 7-in. [17.8-cm] casing set through Zone KII. Zone KIII, if completed, is open hole. The 5-in. [12.7-cm] production tubing is run with a permanent packer and a 20-ft [6. 1-m] seal assembly. Fig. 1 illustrates a typical completion.
Initial production in 1970 was from two wells. By 1982 there were 11 producing wells and 10 additional wells planned for completion by 1985. Average production in 1982 was 364 MMscf/D [10.3x10-6 std m3/d]. production in 1982 was 364 MMscf/D [10.3x10-6 std m3/d]. At peak demand in midsummer, the rate reached 435 MMscf/D [12.3 X 106 std m3/d]. individual well deliverability at 2,700 psig [18.7 MPa] flowing tubing pressure ranges from 50 to 94 MMscf/D [1.4 to pressure ranges from 50 to 94 MMscf/D [1.4 to 2.7 X 106 std m3/d]; dehydration facilities, however, restrict the wells to a maximum of 65 MMscf/D (1.8x 10-6 std m3/d). This paper reviews the downhole corrosion monitoring and inhibiting history of the wells.
Shortly after startup in 1970, severe erosion and corrosion of the surface flowlines were observed. The corrosion was found to be related to velocity, and the critical velocity, the point below which the corrosion could be controlled, was about 20 ft/sec [6. 1 m/s]. Although downhole velocities were well below this critical point, iron count monitoring was instituted and caliper surveys were run in the tubing strings. initial iron counts were high, but the calipers detected little corrosion. Significant corrosion pits were limited to one in each string at shallow depths. A program of batch inhibitor treating was initiated to protect the tubing strings. Corrosion appeared to be controlled until 1977, when accelerated corrosion was detected in two wells. The high corrosion rate continued until 1979, when scale deposition either halted corrosion or masked detection. None of the other wells were affected by either increased corrosion rates or scale deposition.
Tubing caliper surveys and iron counts were used to monitor corrosion. Corrosion coupons, corrosimeters, and hydrogen probes were installed in 1971, but no usable data were obtained. All these systems failed in a short time-because of erosion or mechanical failure.
Caliper Surveys. Mechanical caliper surveys first were run in Wells 254 and 255 after 7 months of production and have been repeated a number of times. Wells completed after 1970 have been surveyed shortly after initial production and at intervals thereafter. production and at intervals thereafter. Two types of caliper tools have been used. Until 1979, the tool used had 36 fingers, recorded only the greatest extension, and measured wall penetration to a minimum of 0.03 in. [0.08 cm]. From 1980 to 1982 a 15-finger tool that recorded all the fingers, measured wall penetration down to 0.01 in. [0.03 cm], and was capable of penetration down to 0.01 in. [0.03 cm], and was capable of giving a much more detailed "picture" of the tubing inside diameter (ID) was used. The greater spacing of the fingers, however, resulted in the tool missing small anomalies. Thus, many corrosion pits may not be detected, and repeated detection on subsequent surveys was rare. Fig. 2 shows the geometry of the 15-finger caliper and illustrates how corrosion pits can be missed or the pit depth misinterpreted.
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