Gas-Lift Technology Applied to Dewatering of Coalbed Methane Wells in the Black Warrior Basin

Johnson, Kenneth J. (Otis Engineering Corp.) | Coats, Alan (Otis Engineering Corp.) | Marinello, Stephen A. (U. of Alabama)

OnePetro 

Summary

Coalbed methane (CBM) wells usually are dewatered with sucker rod orprogressive cavity pumps to reduce wellbore water levels, although not withoutproblems. This paper describes high-volume artificial-lift technology thatincorporates specifically designed gas-lift methods to dewater Black WarriorCBM wells. Gas lift provides improved well maintenance and productionoptimization by the use of conventional wireline service methods.

Introduction

Since 1971, CBM wells have been dewatered by conventional artificial lift.To date, Black Warrior basin wells typically have been produced by either rodor Moyno pumps, with few problems. Wells usually are drilled from 1,000 to2,500 ft deep, with some reaching 6,000 ft. Water has been produced inside 27/8-in. tubing, while methane gas has been produced up the annulus. Productionranges from 50 to 1,000 BWPD (averaging 300 to 350 BWPD). The wells generallyrequire 3 to 12 months to dewater.

The inherent requirement of a Black Warrior basin completion is that thebottomhole flowing pressure (BHFP) across the coal seams (desorption pressure)must be about 5 to 10 psi. The most effective installation meets this objectiveat an acceptable cost.

Many wells in the basin first arc brought on line by single-point injectionof air down the production string. This allows the well to be cleaned of anyremaining sand or coal fines and to reach a lower fluid production rate in lesstime. Upon reaching this rate, the well can be placed on pump lift.

A large number of wells are scheduled for completion over the next fewyears, many at greater depths than reached previously (3,500 to 4,500 ft).Artificial-lift technology commonly used in conventional wells now can beapplied to CBM wells to maximize efficiency and recovery while minimizingoverall costs.

Historical Experience

Over the past few years, gas lift has been introduced to CBM's in Alabama asan alternative method to dewater wells. Gas-lift technology first was used inthe Black Warrior basin in 1984.

A principal method of gas lift still in use is single-point injection (Fig.1). One of the first methods to unload oil and gas wells, this technique notonly assists in unloading the well but also can help remove fracture sand andcoal fines from the wellbore before completion.

Experience with conventional wells has shown that this procedure is quiteinefficient. procedure is quite inefficient. 1. The rig must be maintained atthe wellsite until the rods have been installed, while it might be betterutilized elsewhere if a more effective lifting system completed the well fromthe start. 2. The rig's air supply must be sufficient to turn the fluid aroundand bring the water back to surface. Such a compressor not only is costly butalso keeps the rig from its primary job. 3. Gas production and bottomholepressure (BHP) cannot be monitored effectively during production. 4. With airinjected down the tubing and air and water returning up the annulus, the casingand tubing are subject to significant, perhaps irreparable, corrosion damage ifair is injected for a prolonged period. The well cannot be watered downeffectively before being placed on a rod pump. 5. If the operator simply startsinjection at a higher point with a "macaroni"-type injection system andadds tubing as required to inject more deeply into the wellbore, a rig will berequired.

Conventional casing-flow gas-lift installations also have been tried withgas injected down the tubing through conventional gas-lift valves that arestrategically spaced in the string. Fluid and injected gas are produced up theprimary annular area, while coal-seam gas is produced up the secondary annulararea (Fig. 2). Although considerable fluid is produced, this installation hasseveral shortcomings.

1. Conventional gas-lift valves are a permanent part of the tubing string.As the well is unloaded, production first passes through the ported section ofthe unloading valves. Production fluid often contains coal fines that cut outthe stem and seat. As the well is unloaded to the next operating valve, amultipoint injection failure will occur because of damage to the uppervalve(s). This failure sharply curtails fluid lift efficiency and consumesexcessive quantities of lift gas. 2. Valves cannot be retrieved and repairedwithout the tubing being pulled and a completion workover performed. 3. Theinstallation would cost more than would a conventional rod or gas-liftinstallation. The secondary annulus requires 7-in. minimum casing ID, while theprimary casing string must be 51/2 in.

The installations discussed will produce large volumes of water, but neitheris a truly economical or effective gas-lift system. By comparison, asignificantly modified gas-lift completion was developed that allows theoperator to dewater a well efficiently. This installation (Fig. 3) yields thelifting efficiency and capacity of a standard gas-lift completion under theunique conditions of the Black Warrior basin. The completion requires onlystandard oilfield equipment: (1) a side-string side-pocket mandrel (Fig. 4),(2) wireline-retrievable gas-lift valves, (3) a reeled-tubing injection string,and (4) conventional wireline tools.

Black Warrior basin wells produce water up the tubing and methane up theannulus. Because of the low desorption pressures required and coal seam spacingvarying from 1 to 2,000 ft, a packer-type completion is out of the question.With a typical gas-lift completion, lift gas cannot be injected down theannulus into the tubing string and still attain the required BHFP. A new methodwas used to direct gas to the desired injection point while keeping the annulusopen for gas production.

Reeled tubing was used with side-pocket mandrels in a design that allowedlift gas to be injected selectively into the tubing string. The side-pocketmandrels have ]-in. pockets to accept wireline-retrievable gas-lift valves.These mandrels are designed to provide a full tubing ID. Valves may be servicedthroughout the life of the well without a well workover. These features allowthe operator luxuries not currently available.

1. BHP surveys are better without the concern for the accuracy of soundingdevices. 2. Problem valves can be identified and replaced as required. 3.Valves are not affected by downhole conditions inherently detrimental to pumpinstallations, reducing concerns with fracture sand, coal fines, and rod pumps.4. Fluid production may be altered by adjusting the injection-gas volume orpressure.

SPEPE

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