Scale Control Aids Gas Recovery

Abstract

Summary The East Hitchcock field has produced natural gas since 1958. Toward the end of the primary production phase, the wells watered out and formed excessive amounts of calcite scale. Acidizing was required frequently. In recent years, some of these wells were recompleted for coproduction. Because large volumes of brine are produced, scale control is necessary. Prets Unit No. 1 was successfully treated by an inhibitor squeeze, while Thompson Trustee Unit No. 1 was completed with two treat strings installed at calculated depths to administer scale inhibitor downhole. An inhibitor squeeze protects the formation and the perforations as well as the production tubing, surface equipment, and disposal system, Periodic interruption of production, however, is required to repeat the squeeze, and the concentration of inhibitor in the produced brine is controlled by the chemistry of the inhibitor salt. Installation of treat strings requires that the tubing be pulled and reinstalled with the treat strings clamped to the tubing OD. The concentration of inhibitor in the effluent brine is controlled by a surface injection pump connected at the top of the treat string. Introduction Gas reservoirs are generally considered "watered out" when they begin to produce a few hundred barrels of brine per day per well. At this point, the reservoir typically contains 40% or more of the original gas in place. Coproduction is the process of recovering a major fraction of the residual gas in place by simultaneously producing several thousand barrels of brine per day per well from several wells, thereby reducing the reservoir pressure and mobilizing additional gas. Over a period of about 18 months, the gas/brine ratio in the East Hitchcock field has steadily increased from 120 to 160 scf [3.44 to 4.58 std m3] of natural gas per barrel of produced brine. Progress has been made toward controlling scale formation from brines often associated with geopressured energy production, coproduction wells, and oil wells that produce large amounts of water. As brine flows out of the formation and up the well, the pressure drops, causing dissolved CO2) to go out of the solution and thus increasing the solution pH. The pH rise causes aqueous bicarbonate, HCO3, to be converted to carbonate, CO3, which tends to initiate precipitation of calcium carbonate, CaCO3, in the formation pore throats near the wellbore, on the production tubing walls, or in surface handling equipment. Scale-control options include (1) limiting production so that the pressure drop is not sufficient to induce precipitation, (2) injecting a trace concentration of inhibitors into the surface equipment, (3) injecting trace concentrations of inhibitors downhole through a small-diameter treat string, and (4) squeezing inhibitor into the formation in such a manner that the inhibitor will be slowly released when production begins. Option 1, reduced production. generally entails an unacceptable revenue loss. Option 2, injection of inhibitors into the surface equipment, does not protect the production tubing, and Option 3, installation of a downhole treat string, is often prohibitively expensive. Option 4, however, an inhibitor squeeze, can protect the near-wellbore formation. the production tubing, and the surface equipment. Successful inhibitor squeeze jobs were carried out on some coproduction wells in the Hitchcock field near Galveston, TX. Previous laboratory work led to the development of a method to predict when scale will begin to form and how much inhibitor will be needed to prevent scale. This paper first discusses the field applications and results of inhibitor squeezes to prevent formation of CaCO3 scale. This is followed by a description of laboratory experiments and theoretical considerations that led to the development of the inhibitor-squeeze techniques. The northeast Hitchcock Frio A sandstone, at a depth of 9,100 ft [2774 m], was conventionally produced as a waterdrive gas reservoir from 1958 through 1982. More than 80 Bcf [2265 × 10–6 m3] was produced from 12 wells. Peak gas production (20 to 25 MMcf/D [566 to 707 × 10–3 m3/d]) was between 1966 and 1969. By 1978, gas production had dropped to less than 1 MMcf/D [28.3 × 10–3 m3/d]. New wells placed on production in 1980 and 1982 added to the production from a well that had been on line since 1960, providing a production rate averaging about 2 MMcf/D [56.6 × 10–3 m3/d] before the onset of coproduction. Coproduction began in 1983, and some plugged and abandoned wells were reentered. Wells were plugged and abandoned when they were deemed uneconomical under the low, regulated gas prices in 1983. During the primary production, the dry gas/ brine contact rose from 9,106 to 9,060 ft [2776 to 2761 m] subsea because of the pressure decrease in the gas cap and the waterdrive. Gas-phase reservoir pressure declined from the original 5,750 psia [39.6 MPa] to a minimum of about 3,850 psia [26.5 MPa]. During the brine invasion, gas was trapped in about 30% of the PV in the invaded portion of the original gas cap. This trapped gas, plus remaining "attic" gas in the various fault blocks, are the targets for recovery by gas/brine coproduction. The coproduction process consists of completing wells to maximize production of fluids from the reservoir, thereby decreasing reservoir pressure to a level substantially below the minimum achieved during primary production. JPT P. 1080^