Successful Inhibition of Deep, Hot, Sour-Gas Wells

Abstract

Summary The sour-gas wells in the Big Escambia Creek (BEC) field of South Alabamahave a production environment that consists of 280 degrees F, 21% H2S, 40% CO2, and up to 190,000 ppm chlorides in the produced water. The highly corrosiveconditions demand the ultimate in a corrosion mitigation program to producethese wells safely and economically. This paper describes the background, technical development, and results of the downhole and gathering-systemcorrosion inhibition and monitoring programs: continuous downhole inhibition bymeans of annular injection of a water-dispersible inhibitor in the mostaggressive wells; downhole batch treatments with nitrified tubing displacementsof an oil-soluble inhibitor in the remaining wells; continuous injection of awater-dispersible inhibitor in the gathering lines to augment the batchtreatments and in selected highly corrosive wells; monitoring of inhibitorresiduals and plotting of trends to ensure the effectiveness of downholetreatment and to injection rates; and flowline calipers and hydrotests tomonitor the gathering-line inhibition programs. The paper also de scribes thecomputerized approach used in designing, paper also de scribes the computerizedapproach used in designing, calculating, and updating both the continuousdownhole injection system and the nitrified batch treatments. The success ofthe inhibition and monitoring program is demonstrated by the tubing lifeachieved, field data on inhibitor residuals, and flowline and downholecalipers. The technical data presented will aid in the design andimplementation of successful inhibition programs for highly corrosiveproduction environments. Introduction and Background Field Location. The BEC field is located in Escambia County, AL, 40 milesnorth of Pensacola, FL, and covers about 5,000 acres northwest of the Florida/Alabama border (Fig. 1). The discovery well was the Mallard Exploration Intl. Paper Co. No. 2-1 in Dec. 1971. The production interval is from the Jurassic Upper Smackover at about 15,500-ft depth. Fig. 2 illustrates a typicalwellbore completion and geological strata. Production Parameters. The 26 active wells in BEC have an average Production Parameters. The 26 active wells in BEC have an average total field dailyproduction of 115 MMscf full well stream. This total is made up of 8,000 bbl ofcondensate, 3,000 bbl of water, and 900 tons of sulfur. Average productionconditions are 21 % H2S, 40% CO2, 23% CH4, and 15% other hydrocarbons, withbottomhole pressures (BHP's) of 3,500 psi at 280 degrees F. Water productionpressures (BHP's) of 3,500 psi at 280 degrees F. Water production rates varyfrom 2 to 350 B/D, with chloride levels ranging from 1,000 to 190,000 ppm. Downhole Batch Treatments Batch and Fall. The initial downhole inhibition treatments upon fieldstartup consisted of twice-monthly batch treatments with 55 gal (1 drum) of anoil-soluble/water-dispersible film-forming organic inhibitor mixed with 50 bblof condensate. The treatment was essentially bullheaded by pumping theinhibited mixture into the tubing. The 50+ bbl treatment displaced aboutone-half the average tubing volume. A 2-hour shut-in period followed thetreatment. The inhibitor was a type commonly used in batch treatment ofproduction wells and pipelines. The initial downhole inhibitor treatments wereessentially batch and fall, a technique used successfully in other productionareas. Downhole caliper surveys, however, indicated unacceptable high corrosionrates (50 to 80 mil/yr), particularly at the bottom of the tubing string. In1976, the inhibitor treatment volume was increased to 110 gal (2 drums) and theshut-in time increased to 4 hours. Despite these changes, tubing utilitycontinued to be about 4 years or less, particularly on high-water-productionwalls. Formation Squeeze. During the following 2 years, alternative inhibitors werelaboratory and field tested for both batch and squeeze applications. In 1979, Well Turner 6-1 was squeezed with a combination of scale and corrosioninhibitor. The resulting reduction in reservoir permeability precluded furtheruse of this treatment. Tubing Displacement. As a result of the unsuccessful squeeze-treatmentalternative and continued unacceptable rates of downhole corrosion, theinhibition treatments were changed to full tubing displacement with 110 gal ofinhibitor and a sufficient volume of condensate to displace the inhibitor slugto the perforations. Tubing calipers indicated that this method more successfulin mitigating bottomhole corrosion. This program was continued for about 2years until complications arose from difficulties in bringing the wells back onproduction after treatment. Nitrified Tubing Displacement. Original BHP's were 7,800 psi in 1974 butdeclined to 5,100 psi in 1981. To lighten the fluid column yet achieve a fulltubing displacement, a program of nitrifying the inhibited condensate wasinitiated. This nitrified treatment program was in effect until 1989 withoutmodification. Problems were encountered after treatment because the well waseither Problems were encountered after treatment because the well was eithertotally killed or required several days to return to normal production. BHP'ssteadily declined to 3,500 psi in 1989, to the point production. BHP's steadilydeclined to 3,500 psi in 1989, to the point where the nitrogen displacementcalculations had to be revised to reflect current bottomhole conditions. Calculations were made to determine tubing volumes, condensate volumes, andnitrogen requirements to ensure that the pressure exerted by the nitrifiedcolumn did not exceed the current BHP, with an average of 1,000-psi safetydifferential. This meant that nitrified condensate column pressures werereduced to within the required differential for well pressures were reduced towithin the required differential for well flowback while the inhibitedcondensate just filled the production tubing without being forced back into theformation. Inhibitor volumes were examined with respect to contactconcentration and coverage. The 110-gal inhibitor volume used previouslyprovided a contact concentration of about 50,000 ppm. previously provided acontact concentration of about 50,000 ppm. Laboratory inhibitor performancetests and current application guidelines indicated that 55 gal would provide anexcess of 25,000 ppm, which would be expected to provide adequate corrosionppm, which would be expected to provide adequate corrosion protection for thedownhole tubulars. According to the inhibitor protection for the downholetubulars. According to the inhibitor coverage guideline, 1 to 3 mils of neatinhibitor, or 20 to 30 mils of inhibited mixture, is the targeted treatmentrate. The change from 110 to 55 gal still approximated this somewhat arbitrarytreatment guideline. When downhole batch treatments are used, treatmentfrequency is an important parameter. The approach normally taken is to considerfield failure history and erosional velocity. Downhole failures at BEC werecontrolled with full tubing displacement or nitrified tubing displacement inlow-water-production wells. Failure history indicates that the currenttwice-monthly treatment frequency is required, given that it is operationallydifficult to meet the treatment target consistently. In addition, criticalerosion-velocity calculations support the rationale for twice-monthlytreatments because most wells are near or exceed calculated criticalerosional-velocity limits. P. 100