This is not another attempt to reinvent the wheel, but an example of combining established engineering methods, limited production performance data, and simulated perforating tests to help solve a practical problem. By obtaining a better picture of existing perforations, wellbore conditions can be appraised better, and a more effective stimulation program can be designed. Introduction Clear and effective communication between the wellbore and the reservoir is a minimum requirement for any successful completion. When objective intervals that are indicated to be productive by open-hole logs, flow tests, or core data fail to yield expected production rates, it is suspected that either the perforations are inadequate or the formation is damaged, or both. Test-well shooting under simulated well conditions can give a clue to the effectiveness of perforating techniques and can also help in planning nonroutine completions. This kind of testing indicated the nature of perforations made during initial completions of 20,000-ft objectives in the Mississippi Salt Basin. As a result of the tests additional perforating charges were developed and completion and stimulation were planned that effected production from wells that initially were nonproductive. The deeper Jurassic Age gas tests in the Mississippi Salt Basin (see Fig. 1) have been notorious for restricted flow performance. For example, in the southeastern part of the Basin, Well A, a Norphlet sandstone test below 18,000 ft, was perforated with 2-in. No-Plug jets with oil-base mud in the wellbore. After the mud was removed, the well tested less than 3.5 MMcf/D of gas, or about one-fourth the flow rate after subsequent stimulation. Well B, a Smackover limestone test at an offset location, failed to yield any flow after being perforated with 1 9/16-in. Hyper jets. This objective interval was perforated under what would be considered favorable conditions for a gas completion.1 Before perforating, the mud in the wellbore had been displaced with nitrogen and the well was shot with a pressure differential into the wellbore. After the well failed to flow, a 1.2-psi/ft fluid gradient was necessary to effect breakdown. After stimulation, the well had a stabilized flow rate of 11.2 MMcf/D of gas with 4,500 psi flowing tubing pressure. In the northwestern part of the Basin, Well C, a Smackover sandstone discovery at about 20,000 ft, flowed approximately 10 MMcf/D of gas, with 9,500 psi flowing tubing pressure during sustained open-hole testing. Later, during cased-hole completion operations, which included perforating with 2-in. No-Plug jets with inverted oil-base mud in the hole, less than half this rate of flow was established. Reperforating with more than 700 No-Plug jets (1 5/16 in.), with inhibited oil in the hole, resulted in only nominal improvement. There was no flow from Well D, an offet confirmation test, after perforating with 2-in. No-Plug jets or reperforating with 1 9/16-in. Hyper jets. Neither was flow established from Well E, at a nearby location, after perforating with 2-in. No-Plug jets and displacing the invert oil-base mud in the wellbore with nitrogen. This was especially startling, since 2 years earlier the offset location achieved considerable notoriety as a result of a blowout during drilling operations.
Introduction 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 Loading 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.
Potential hazards of wireline exposures to hostile CO2, and H2S environments often discourage running bottom hole pressure (BHP) surveys. While surface pressure build-ups may be utilized for dry-gas wells, detailed analyses may be of limited value where there is also liquid production. However, concurrent fluid level determinations can be used to enhance the value of surface build-ups. Other practical applications of fluid level practical applications of fluid level determinations include a means of monitoring liquid loading or depths of fluid displacement, such as encountered during some stimulation or corrosion inhibition treatments. Detailed testing, of a recently developed high-pressure acoustical well sounder, verifies that fluid levels can now be determined even under the most adverse well conditions. Introduction Acoustical well sounders (AWS) have been used routinely for many years, primarily as an aid in analyzing well performance of normal pressure oil producers. Subsequently, pressure oil producers. Subsequently, attention has also been toward applications pertaining to gas wells, including a very pertaining to gas wells, including a very comprehensive gas testing manual published by the Canadian Energy Resources Conservation Board. Uses of basic fluid level data, along with previous means of obtaining this information are discussed in detail in these publications. publications. Fluid levels may be determined by generating a pressure pulse at the surface - directed down the wellhead - and recording the echoes from collars and ultimately any liquid level existing in the wellbore. Firing a blank cartridge (22–45 caliber or 10 gauge) was the most frequent source of a sound wave or pulse until introduction of the Gas-Gun, and then implosion chambers for higher pressure testing. A microphone wellhead attachment converts the pulses, reflected by collars, liquid or other pulses, reflected by collars, liquid or other obstructions, into electrical signals which are amplified, filtered and recorded on a strip of paper. Until recently the most successful paper. Until recently the most successful results were obtained by "shooting" down the casing-tubing annulus in packerless completions (Figure 1). Unfortunately, reflections from internal tubing collars could not be defined, especially close-makeup or internal flush couplings. Continued search for gas reserves has resulted in development of deeper objectives, a large number of which have been tight geopressured reservoirs containing CO2 and/or H2S with bottom hole temperatures approaching 500F. Since most of the objectives have required high-volume waterfrac treatments, water may also be recovered for extended periods. All of these conditions contribute to a very corrosive environment. It is essential to know the pressure at the formation face to fully evaluate the performance of a gas well. Unfortunately, a performance of a gas well. Unfortunately, a hostile environment often discourages the running of wireline pressure recorders. However, accurate wellhead pressures plus known height of wellbore fluid columns and fluid densities, can provide a means of calculating downhole provide a means of calculating downhole pressures. In most of the deeper gas wells, the pressures. In most of the deeper gas wells, the casing-tubing annulus is isolated from the production string by a packer; and most of the production string by a packer; and most of the production tubulars have internal flush production tubulars have internal flush couplings. p. 185
Member SPE-AIME Abstract Excessive downhole temperatures, as well as some well bore restrictions, may limit the use of wireline bridge plugs. With careful planning, Shell Oil Company has successfully utilized sand-slurries for plugging back through tubing in deep, high-temperature, plugging back through tubing in deep, high-temperature, geopressured, gas tests—without limitations. This has included isolation of water producing zones as well as temporary exclusion of lower intervals that did not warrant additional stimulation expense. Introduction Primary objective formations in South Texas gas development activities has included the Vicksburg, Wilcox, and Edwards formations, ranging in depth from 10,000 to 20,000 feet (3,050 to 6,100 m). Several potential pay zones may be encountered in the same potential pay zones may be encountered in the same well bore. Geothermal gradients exceed 2F/100 feet (3.644 E+01 mK/m) and pressure gradients may exceed 0.95 psi/foot (2.149 E+01 kPa/m). Recovered gas has included up to 15 percent CO2 and 3 percent H2S. In some cases, dry gas production has been established even though apparent water saturations have exceeded 75 percent. Commercial production has also been obtained, after fracture treatment, from intervals that initially yielded insufficient gas to measure. Thus, log developments that would not be of interest, in some areas, have warranted cased-hole testing. This, in turn, has resulted in a number of subsequent zone abandonments, or an increase in plug back activity. In view of the geopressures and/or presence of sour gas, plus anticipated stimulation procedures requiring up to 15,000 psi (100 MPa) wellhead pressures, a permanent packer is normally installed. pressures, a permanent packer is normally installed. This may contribute to the increased cost of any subsequent plug back work for additional testing. For many of the questionable, low permeability zones, cost of removing downhole equipment would preclude testing. Furthermore, the use of control fluids, to enable removing production equipment prior to setting a cased-hole bridge plug to shut-off only a lower section of a perforated interval, can result in severe impairment to the remaining perforated section. Plugging back through tubing can result in appreciable savings over the cost of a workover rig to remove permanent downhole production equipment for installation of cased-hole bridge plugs. Prior to the 1960's, sand, gravel and even "brush-plugs" such as the tops of black-jack oaks, were utilized in shallower plug back activity. Subsequently, use of through-tubing bridge plugs has become the more frequently used means to permanently plug back in the casing without pulling the tubing - especially in the deeper, high pressure wells. However, available through-tubing bridge plugs are limited by excessive bottom hole temperature and some well bore restrictions. Our success ratio with available through-tubing plugs, above 300F (150C), has been less than 50 percent. Cementing through concentric tubing is one method of plugging off an extended interval below permanent production equipment. However, this method becomes production equipment. However, this method becomes increasingly hazardous at higher temperatures. Displacement of cement through the smaller tubing is restricted and there is a high risk of premature setting of the cement before retrieval of the concentric tubing. Through-tubing abandonment of cased-hole intervals can be accomplished, below permanent packers at a nominal cost, by displacing sand to bottom and then capping with cement, if warranted, for effective isolation of lower perforations. PRE-PLUG BACK CONSIDERATIONS FOR JOB PLANNING PRE-PLUG BACK CONSIDERATIONS FOR JOB PLANNING Depth and length of interval, plus location of any perforations, to be covered are primary considerations. Proximity of subsequent intervals to be tested, or stimulated, will determine the amount of fill to be attempted in one stage.
Establishing and maintaining acceptable flow rates from deep, low permeability, geopressured lower Wilcox gas objectives in S.W. Texas has long been a challenge. A number of such tests have yielded only minimum flow potentials or have later been abandoned due to damaging sand production and/or casing failure-due in part to excessive pressure drawdowns. Revised completion procedures have aided in initially establishing nominal flow rates. More recently, in the Rosita Field, Duval County, following an extensive core analysis and testing program, an initial daily open flow potential of program, an initial daily open flow potential of 1.7 MMCFG (48.1 × 10(-3) m) was increased to 80.0 MMCFG (2,265 × 10(-3) m) without any evidence of sand failure following ultimate stimulation and subsequent increased perforating density. Lack of sand production is attributed to minimum BHP drawdown during flow periods, as evidenced by a stabilized deliverability flow rate of 1.6 MMCFG/D (45.3 × 10(-3) m3/d) recorded with only a 10 psi (70 kPa) surface drawdown from a SITP of 8680 psi (59.8 MPa). This compares with an average of about 1000 psi (7 MPa) pressure drawdown per million for nine additional completions in the same field which were perforated for limited entry and initial ballout perforated for limited entry and initial ballout only. Introduction Major oil and gas reserves have been developed along the Eocene-Wilcox trend of the Texas Gulf Coast during the past several decades. However, for the most part, these reserves have been confined to hydropressured accumulations above 11,000 feet (3353 m). There has been only limited success with commercial exploitation of the deeper. Low-permeability, geopressured gas sands. These lower Wilcox objectives, herein referred to as the Deep Wilcox, have varied in depth from about 11,000 to 17,000 feet (3353 to 5182 m). Most of the completion intervals have had permeabilities between 0.1 and 3.0 md (0.1 and 3.0 × 10-3 um 2). Pressure gradients have ranged up to 0.93 psi/ft. (21. kpa/m). More than 400 Deep Wilcox tests have been drilled during the past 35 years. Frequent "gas kicks" and encouraging log developments have been encountered. Unfortunately, most of these tests have not resulted in economical completions. This has been attributed to very low permeability, formation fluid sensitivity, sand production and/or associated casing collapse. However, results from some of these completions have been sufficiently encouraging, or otherwise a contributing factor, to merit continued efforts to commercially exploit this important gas objective. Until recent activity in the Rosita Field, Duval County, the foremost Deep Wilcox producers of any consequence were at the northeastern end of the Wilcox trend in the North Milton Field, Harris County. This field has been a commercial success since initial development in 1963. While only minor stimulation has been necessary in North Milton, at other locations, stimulations, including fracture treatments, have failed to effect sustained productivity. With renewed interest, created productivity. With renewed interest, created by recent activity in Duval County, representative cores were obtained and a joint Shell and service company testing program undertaken. Concurrently, a comprehensive review of previous Deep Wilcox completions was made to further aid in evaluating more effective completion techniques. GEOLOGICAL SUMMARY AND CORE STUDY, AS RELATED TO STIMULATION AND PRODUCTION PARAMETERS The Wilcox Group consists of a variety of sand bodies interspersed in s hale. Typically, the sands are irregular with limited areal extent and thickness. The heterogeneous nature of these sands along the Texas Gulf Coast is well known. p. 41
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