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This paper was prepared for the Permian Basin Oil Recovery Conference of the Society of Petroleum Engineers of AIME, to be held in Midland, Tex., March 11–12, 1974. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Abstract Stimulation of the Lower Pennsylvanian (Atoka-Morrow) sands in Southeast New Mexico has presented a number of particularly difficult problems since the earliest treatments attempted. problems since the earliest treatments attempted. History of the area indicates that these sands are especially fluid sensitive and some damage most always occurs during drilling and completion operations. Treatments in the past very often reduced rather than improved flow characteristics, even those jobs involving very small breakdown volumes. Usually, production was never restored to the "natural" level. Recent advances in treating systems for these ultra-sensitive gas sands have made a significant contribution to the successful development of gas reserves in the area. Changes in the Morrow completion stimulation approach are discussed in this paper. In addition, a general description of job design is given along with a brief results cross-section. Introduction Over the past 12 to 15 years, the Morrow Sand has been the object of considerable industry interest and exploratory drilling has indicated an extensive area of potential production. This area encompasses most of Eddy and parts of Chaves and Lea Counties in Southeast New Mexico (Fig. 1). During this time, however, completion difficulties encountered in the Morrow have resulted in the abandonment of numerous promising prospects. Most of these were tested during drilling operations and yielded good shows of gas or gas-condensate. Once completion attempt was underway on those projects where tests seemed to warrant the risk, subsequent production rates were frequently never as good as were indicated from DST information. Completion - stimulation programs employed in the Morrow Sand for removal of skin damage and far reservoir improvement have for years provided inconsistent if not generally unsatisfactory results. A success ratio of 35 to 40 percent might even have been considered good but percent might even have been considered good but for those instances (at least 40 percent) where flow rate was reduced substantially as a result of treatment. This poor overall treatment response gave rise to the philosophy that the best way to complete from the Morrow was to avoid, where possible, treatment of any kind. Consequently, possible, treatment of any kind. Consequently, many completions were natural with the final flow rate being significantly less than the reservoir in an undamaged state was capable of delivering.
- North America > United States > Texas > Midland County > Midland (0.24)
- North America > United States > New Mexico > Lea County (0.24)
- Geology > Mineral > Silicate > Phyllosilicate (0.49)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.49)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (21 more...)
This paper was prepared for the Permian Basin Oil Recovery Conference of the Society of Petroleum Engineers of AIME, to be held in Midland, Tex., March 11–12, 1974. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication is the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF publication is the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Abstract Attempts to stimulate marginal gas producers in Sutton County, Texas, has provided an producers in Sutton County, Texas, has provided an opportunity to evaluate several types of stimulation fluids on a comparative basis. The fluids used here included water base, oil base, and acid base fluids. A thorough study of the production history of wells following treatment production history of wells following treatment demonstrates the effectiveness of the different fluids on a long term basis. Conclusions drawn from this study provide a guide to selection of fracture fluids for tight gas sands. Cost-performance factors are explored as they apply to stimulation of marginal gas production and further conclusions are drawn production and further conclusions are drawn concerning the importance of formation damage as a function of formation petrophysical properties. Examples are shown to indicate formation damage is a factor to consider in fracturing tight sands but performance compromises may be made in the choice of fluid to obtain maximum frac penetration. penetration Introduction Shortages of many chemicals used in well stimulation treatments has led to re-evaluation of many gas well treating techniques. Nowhere has this been more the case than in the Canyon play of Sutton County, Texas. A previous paper play of Sutton County, Texas. A previous paper (SPE 4678) describes the treating methods used in the initial development of the Sawyer Field. This study has been continued and cost effective fracturing has resulted. The results of the fracturing development may serve as a model for gas well stimulation in other areas with production from similar zones. production from similar zones. FORMATION The Canyon, a Pennsylvanian Age sand, is generally found at approximately 6500 feet and is produced to about 8200 feet. The zone is massive with many "ratty" sections. These sections are low in permeability (1 md) and porosity (8–12 per cent). When contacted by fresh water there is a noticeable clay migration. Acid response tests indicate migration damage accounts for about 35–40 per cent loss in permeability. Formation liquid saturation is low and any liquid entering the formation may cause further loss in relative permeability. Gas-oil ratios indicate an essentially dry gas formation.
- North America > United States > Texas > Sutton County (1.00)
- North America > United States > Texas > Midland County > Midland (0.24)
- Geology > Mineral > Silicate > Phyllosilicate (0.36)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.34)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.47)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (27 more...)
Abstract The purpose of this paper is to discuss the gas proration aspect of the over-all gas situation in Texas, both today and in the immediate future. There have been several recent changes in this area. The old proration problems have bee practically eliminated. The problem of nominating practically eliminated. The problem of nominating procedure is no longer a major problem, and the procedure is no longer a major problem, and the development of small tracts is properly controlled. Similarly, associated gas-well gas operations are relatively trouble free. Conversely, casinghead gas is becoming quite a problem. As soon as one plant eliminates flares, another develops similar problems. Thus both the Texas Railroad problems. Thus both the Texas Railroad Commission and the gas industry may be criticized since gas is being flared during a national fuel shortage. Communication is a major problem. The consuming public, the oil and gas industry, and the regulatory agency must work together in order to eliminate this problem. People must realize that natural gas is a bargain today and that a relatively large increase in the wellhead price should result in a very nominal increase price should result in a very nominal increase in the home energy bill. On the other hand, the Texas Railroad Commission is determined to eliminate the unnecessary wasting of gas while attempting to create the maximum incentives for oil and gas development and to communicate the dire need of accomplishing these goals to the consuming public. public. TEXT When Jack Paxton first talked to me about speaking before this group, I assumed that you were interested in the over-all gas situation from the Texas Railroad Commission standpoint. As usual, on Nov. 30, I was late getting in an outline to Jack, and at that time Jack told me he thought you would be particularly interested in the gas proration aspect, both now and in the immediate future. This is one of those cases when I think the good news should come first. Our proration problems have been practically eliminated. problems have been practically eliminated. That is, the old problems concerned with prorated fields. Apparently, most of the operators prorated fields. Apparently, most of the operators are operating at an optimum level and do not feel that their correlative rights are being adversely affected. Actually, most of our better gas fields appear to be operating at the approximate capacity of the handling facility. In the opposite case, I believe we have had an average of about two applications per formal conference to suspend the existing allocation formula in gas fields and allow all wells to operate at capacity during this past year. In the past, I think I have complained about the nominating procedure of many companies, but again, this problem has become moot. Three or four years ago, operators in the Permian Basin area were having pipeline problems Permian Basin area were having pipeline problems in such fields as Gomez and Coyanosa particularly. I do not recall a single incident in 1970 when a serious proration problem has occurred in either of these two fields or, for that matter, in any of the new, deep Ellenburger fields in this area. When I was out here the last time, the major gas discoveries for the state were coming from these deep fields. If we can include the Panhandle with the Permian Basin, I think the major Texas gas discoveries are still coming from deep reservoirs in West Texas. The new system of adopting temporary gas field rules and the compulsory pooling statute appears to have eliminated most of the old problems of small tract development. p. 105
- North America > United States > Texas > Cooke County (0.24)
- North America > Canada > Alberta > Woodlands County (0.24)
- Asia > Middle East > Israel > Mediterranean Sea (0.24)
Abstract Production cost control is a matter of growing concern to the industry. Even with much effort toward reduction, producing costs continue to rise. The reason for this lies in the fact that effective cost control is first an attitude and then an operational problem. People must feel that costs can be improved People must feel that costs can be improved before they will even try. A planned and properly presented-cost control program will properly presented-cost control program will create a positive atmosphere. It will open closed minds. It will answer the prime rebuttal of, "How do you know my costs are high?". Above all, it will dispel the universal excuse, "My costs are different". Such a program was initiated within Standard Oil Co. of Texas in early 1964. From the beginning it was realized that people, not procedures, reduce cost. However, procedures procedures, reduce cost. However, procedures and data properly prevented can influence the action of people. The system compares actual costs to forecast optimums to locate source and cause of high cost. The system embraces the philosophy that present expense does not always represent what is necessary; that experience does not dictate correctness. In brief, the past should not be the goal for the future. From results of this program, it is seen that tools to control cost are available. Tools alone., however, can build nothing. They must be used by people, in this case by line management. Introduction The cost-control procedures to be discussed were developed in the Western Division of Standard Oil Co. of Texas., a subsidiary of Standard Oil Co. of California. The Western Division operates approximately 2,500 wells located in the Permian Basin of West Texas and southeast New Mexico - Production ranges from 1,360 ft pumping to 16,000 ft flowing oil and gas. Operated oil and gas equivalent production was 120,000 BOPD in 1968 and will be production was 120,000 BOPD in 1968 and will be approximately 124,000 BOPD in 1969. In early 1961 the cost-control system now used in the Western Division of Sotex was visualized. It could not be implemented, however, because the records necessary for control were not available. In 1963 and 1964 this production cost-control system was developed and sold to operating people with the result that the steady 10 percent per year increase in field controllable costs was arrested. There has been no decrease in production as a result of the program. On the production as a result of the program. On the contrary, the Division's production has increased considerably each year without a corresponding increase in cost. With optimum producing expense as its eventual objective, producing expense as its eventual objective, the program's ultimate goal is maximum profits at all times. Success is attributable to direct and active support by division and district management. The system identifies areas of abnormal cost by comparing actual costs with forecast goals based on guiding standards. Comparison of actual costs vs guides identifies the particular fields in which costs are above the particular fields in which costs are above the forecast, tells why, and does so in time to allow corrective action. RESULTS For quite some time the Western Division's field controllable costs had increased 9 to 10 percent each year, or approximately $500,000 percent each year, or approximately $500,000 per year. There had been a corresponding per year. There had been a corresponding increase in production and, for this reason, the cost increase was not questioned.
- North America > United States > Texas > Permian Basin > Ward Estes Field > Pennsylvanian Formation (0.99)
- North America > Canada > Northwest Territories > Franklinian - Sverdrup Basin > Cisco Field (0.99)
- North America > United States > New Mexico > Permian Basin > Atoka Field > San Andreas Formation (0.98)
Sipes Jr., L. D., Member AIME Abstract In the past seven or eight years large gas fields have been discovered in the Delaware Basin of West Texas. The principal producing formation is the Ellenburger. Because marketing facilities have lagged development and relatively small volumes of gas have been produced from the reservoirs, decisions on produced from the reservoirs, decisions on large investments are being made on volumetric estimates of gas in place. How accurate are these estimates? A volumetric estimate of initial gas in place for the Ellenburger reservoir in the Coyanosa field has been made. Performance data are now available from which an initial gas in place can be determined. A comparison of the place can be determined. A comparison of the volumetric and performance derived values is illuminating and provides guidelines for determining volumetric gas in place in other Delaware Basin Ellenburger reservoirs. Introduction Large gas reserves have been discovered in the Delaware and Val Verde Basins of West Texas in the past few years. The principal accumulations have been in the Ellenburger formation of Ordivician age. Wells are deep and expensive, necessitating wide spacing to be economic. Tens of millions of dollars have been spent and are being spent to explore for and develop these deep reserves, often found below 20,000 feet. Figure 1 illustrates the location of the reservoirs which have been discovered in this trend. At the outset of the Deep Delaware Basin boom, the Permian Basin was not a major gas supply area. In 1960, only three interstate transmission lines were taking gas from the area. No large intrastate markets were supplied from the area. Much of produced gas was from oil wells. With the discovery of large gas reservoirs, several interstate and intrastate lines sought to purchase gas and justify the necessary facilities to transport the gas to ready markets. This process takes time, particularly when Federal Power Commission particularly when Federal Power Commission certification must be obtained. As a result, marketing lagged development rather badly at times. Takes from completed wells were low or non-existent although the purchasing companies were pushing for certification and construction of facilities. Many interstate purchasers eased their producers' burdens by making prepayments under take or pay contracts or by making production loans. production loans. Because takes were low, little reliable performance data were available from which performance data were available from which reserves could be determined during the first few years. Management decisions, consequently, had to be made on volumetric estimates of reserves. Data are now available on a limited number of reservoirs to permit definition of reserves by both the permit definition of reserves by both the volumetric and material balance techniques for comparison. A volumetric analysis of the Coyanosa Ellenburger reservoir has yielded an initial gas in place of 595 BCF. Material balance work defines the initial gas in place at 616 BCF estimate. The volumetric method is thus substantiated. Procedures and guidelines established should be useful in analyzing Delaware Basin Ellenburger reservoirs where material balance data are not yet reliable.
- North America > United States > Texas > Cooke County (0.41)
- North America > United States > Texas > Pecos County (0.34)
Good afternoon, gentlemen….. I am honored by your invitation to address this distinguished meeting, especially since it gives me an excuse to visit this great producing region once again. San Francisco and Los Angeles and Chicago and New York are wonderful cities and excellent places to conduct business. But to see the oil business in true perspective you have to return to the San Joaquin Valley or the Permian Basin, or one or the other places where the blood and bone or the industry is formed. Sometimes I think oil men are like the legendary Greek wrestler, Anteus. He was unbeatable as long as he stayed in contact with the earth—-in other words, as long as he kept his feet on the ground. It wasn't until he allowed himself to be lifted into the air that his opponent, Hercules, was able to do him in. In the same way, the oil fields—-where the real work or finding and producing oil is done—-are the industry's source or strength. Only by understanding what happens here can the oil business keep its feet on the ground, and be ready for all challenges.
- North America > United States > Texas (0.50)
- North America > United States > Illinois > Cook County > Chicago (0.24)
- North America > United States > California > San Francisco County > San Francisco (0.24)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (21 more...)
Publication Rights Reserved This paper is to be presented at the Conference on Production Research and Engineering, sponsored by the Mid-Continent Section, Society of Petroleum Engineers, in Tulsa, Oklahoma, May 3–4, 1965, and is considered the property of the Society of Petroleum Engineers, Permission to publish is hereby restricted to an abstract of not more than 300 words, with no illustrations, unless the paper is specifically released to the press by the Editor of the Journal of Petroleum Technology or the Executive Secretary, Such abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the Journal of Petroleum Technology or Society of Petroleum Engineers Journal is granted on request, providing proper credit is given that publication and the original presentation of the paper. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and considered for publication in one of the two SPE magazines with the paper. Abstract The relative commercial importance of the San Andres formation in the Permian Basin of West Texas is emphasized, and the general characteristics of the oil reservoirs are discussed. The rock properties and fluid distribution in a typical San Andres reservoir located on the North Basin Platform are investigated. In this reservoir, 80 per cent of the wells have been cored through at least part of the producing interval. The characteristics of the reservoir rock and the distribution of its contained fluids are determined with the assistance of special laboratory measurements. The vertical and areal definition of a 90-ft transition zone and "tilted" water table is determined and shown by production tests to be statistically reliable. The performance of a pilot water injection project in this reservoir is discussed. The injection rate and pressure response time are compared with values calculated from the reservoir rock and fluid properties. Introduction The San Andres formation of Permian age accounts for nearly 20 per cent of the current oil production from the Permian Basin of West Texas. In the older San Andres fields, relatively little quantitative data are available concerning the reservoir rock properties. However, in the Reeves (San Andres) field, 80 percent of the wells were cored in at least part of the producing interval; and these data, along with special laboratory measurements, permitted an unusually complete investigation of this typical San Andres reservoir. Laboratory measurements of rock and fluid properties were used to describe the reservoir, to define the fluid distribution, and to predict the performance of both well completions and water injection operations. The results of these calculations compared favorably with actual performance of both initial well completions and a pilot water injection project. In view of the importance of the San Andres as an oil producing formation, its huge secondary recovery potential and the limited data available in the older fields, this discussion of the Reeves field was prepared to further disseminate the available information. THE SAN ANDRES FORMATION The San Andres formation is an oil and gas-bearing member of the Guadalupe Series of Permian age. It occurs in the Permian Basin geologic province of West Texas and Southeast New Mexico, and it is by far the most important oil-producing formation in the Permian Basin. It has been estimated that the San Andres formation accounts for nearly 20 percent of the Basin's current oil-producing rate. What is of even greater significance is the estimate that approximately 20 billion bbl of oil will remain in these reservoirs after being exploited by both primary and conventional secondary recovery mechanisms. San Andres oil reservoirs in the West Texas Southeastern New Mexico area occur mostly on the periphery of the Midland Basin, and to a lesser degree, on the eastern side of the Delaware Basin, which are members of the greater Permian Basin. The general orientation of these reservoirs is presented on Fig. 1. The long axis of the basin with which they are associated. In most cases, the trap is formed by a combination of structure and lithology changes within a formation made up of massive limestone and dolomite with varying amounts of evaporite. The San Andres reservoirs range in depth from 1,500 to 6,000 ft, and the producing thickness ranges from 3 to 200 ft. The average porosity ranges from 7 to 16 percent, and the average permeability ranges from 1.0 to about 50 md, the typical reservoir occurring in the lower portion of the range. Fractures and tilted water-oil contacts are noted in some San Andres reservoirs, and extensive water-oil transition zones are common.
- North America > United States > New Mexico (1.00)
- North America > United States > Texas > Yoakum County (0.35)
- North America > United States > Oklahoma > Tulsa County > Tulsa (0.24)
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.54)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.79)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (26 more...)
Introduction Degasification of hydrogen sulfide from sour San Andres source water in West Texas has increased the availability of water for a flood project in Midland County. The plant is treating water for Mobil Oil Co.'s flood project in the Pennsylvanian beds of the Pegasus field. About three years ago, it became apparent that supplies of water to be used in secondary recovery in the Permian Basin would soon become critically short and that use of available sour waters would be necessary in many floods yet to be started. It became further apparent that this sour water would have to be treated for removal of hydrogen sulfide before it could be used economically. Several methods of stripping H2S from water which were considered of limited potential success included: aeration with forced draft aerators; stripping the H2S with engine exhaust in a packed column; and stripping the H2S with exhaust gas produced by a submerged burner in a packed column. Finally, after studying all available methods, the following method was decided upon: Stripping the H2S with exhaust gas generated in an external vessel under carefully controlled conditions to produce an oxygen-free gas, using a bubble cap column of sufficient height to remove hydrogen sulfide to an acceptable residual, arbitrarily chosen as 1.5 ppm. However, this method had several drawbacks:The method had not been tried, even on a pilot scale. No equipment had been designed for this purpose. Design efficiencies had not been established. Time did not permit pilot plant operation. The bubble cap column was chosen since it is less subject to fouling than a packed column and, if fouled, is more readily cleaned. Some data were established by the author in a similar column using natural gas to strip oxygen from water. That column has operated successfully for approximately six years under operating conditions which place extreme design restrictions on the column, with resulting low efficiencies. COLUMN DESIGN Design of the column is based on Henry's law, which states that "the solubility of a gas in a liquid is directly proportional to the partial pressure [in atmospheres] of that gas in the surrounding atmosphere at a given temperature." Thus, if the partial pressure of H2S in the atmosphere surrounding the water approaches zero and if, at the same time, the H2S is given sufficient opportunity to escape from the water, the dissolved H2S will also approach zero. It is obvious that countercurrent stripping is ideal for obtaining these conditions. Design of the column trays was made using published data and the following criteria:Capacity = 13,000 BWPD Riser velocity = 10 ft/sec Tower diameter = 4 ft 1D Weir length = 3 ft Weir height = 4 in. Available gas pressure = 5 psig Since no samples of water from supply wells were available for the design, the following assumptions were made:Minimum operating temperature, 68 F Operating pressure, Atmospheric H2S content of water, 170 ppm Tray efficiency, 7 per cent pH of water, 6.0 Sulfides which are H2S, 86 per cent Gas/water ratio, 66. 7 scf/bbl
- Phanerozoic > Paleozoic > Permian (0.53)
- Phanerozoic > Paleozoic > Carboniferous > Pennsylvanian (0.53)