Small-Diameter Concentric Tubing Extends Economic Life of High Water/Sour Gas Edwards Producers
- Steve G. Weeks (Shell Oil Co.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- September 1982
- Document Type
- Journal Paper
- 1,947 - 1,950
- 1982. Society of Petroleum Engineers
- 5.1.1 Exploration, Development, Structural Geology, 3.2.4 Acidising, 2.4.3 Sand/Solids Control, 3 Production and Well Operations, 1.6 Drilling Operations, 4.1.2 Separation and Treating, 2.2.2 Perforating, 4.2.3 Materials and Corrosion
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The Edwards reef trend extends from the Buchel area in DeWitt County, TX, to the Mexican border. Tight, relatively thin sour gas objectives are underlain by water sources, which may be encountered unintentionally during hydraulic stimulation. Erratic, rapidly declining production with associated water, coupled with increased operating costs, resulted in decreasing financial returns. Subsequent installation of small-diameter concentric tubing has enabled continuous productivity as well as provided an inexpensive means of corrosion inhibition. This has extended economic productivity in two fields along the Edwards trend.
Development drilling of the Edwards limestone in the West Cooke and West Stuart City fields, LaSalle County, TX, was begun during 1976 (Fig. 1). Completions are at an average depth of 10,000 ft (3050 m). Porosities range up to 10%, although 5 to 6% or less is more common. Permeabilities may average about 0.1 md; however, they are more frequently less than 0.01 md, with rare streaks as high as 10 md. With such low-order permeability and porosity, stimulation for an extended distance from the wellbore is essential to establish any sustained productivity. For the most part, this has entailed hydraulic sand fracture treatments; although only acidizing, at pressures exceeding fracture gradients, has effected production in some cases. All fracture treatments were down 5 1/2-in. (14-cm) casing, with up to 400,000 gal (15 140 m3) water-base fluids. In anticipation of high flow rates, 2 7/8-in. (7-cm) production tubing then was installed. Postfracture monitor surveys indicated some vertical fracture extensions as much as 50 ft (15 m) beyond the perforated intervals for possible contact with adjacent water sources. Later, density-controlled well stimulation was effective in establishing economical gas flow without a significant initial increase in water production.1 Prefracture injection surveys might have resulted in more successful fracture treatments.2 Unfortunately, with pressure depletion, water recovery continued to increase to a point where sustained production could not be maintained for seven out of nine completions.
Produced gas contains about 6% CO2 and up to 2% H2S. In view of the potential pollution attributable to venting this gas, only minimum flow tests were conducted initially. Thus, only nominal amounts of load and treatment fluids were recovered before completion of the plant treating facilities and gathering system. Gas sales began during July 1977. However, with rapid accumulation of water in the wellbore, four out of nine wells ceased flow during the first 3 months of sales.
Liquid accumulation tends to occur whenever produced water does not flow out of the wellbore at the same velocity as the gas.3,4,5 Displacement of corrosion inhibitors with water may magnify this problem. Bottomhole pressure (BHP) surveys verified that a full column of water would exceed the reservoir pressure. Fortunately, permeability of the induced fractures has been sufficiently high for the water to be ultimately displaced back from the wellbore, under static conditions as gas rises in the tubing, as a result of density segregation. By this means, it was possible to maintain some production by stopcocking. That is, the wells were flowed until the accumulated fluid head plus line pressure equaled the reservoir pressure and the well ceased flowing. After the well was shut-in for a day or so, and after ultimate displacement of the accumulated water from the tubing by gas migration, the shut-in wellhead pressure in some cases increased to +2,000 psi (14 Mpa) to enable further flow. By such stopcocking, erratic production was maintained. For maximum productivity by this means, the wells required close surveillance. In addition, it became necessary to displace the corrosion inhibitor each month with nitrogen to minimize shut-in periods.
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