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Kelm, C.H., Member SPE-AIME, Amoco Production Co. Production Co. Abstract This paper presents practical methods of recognizing and analyzing problem well symptoms. It also discusses the required data and its use, as well as presents a "well checklist" that assists the engineer in analyzing well performance. The objectives of well analysis are to maximize producing rates and recovery within allowable, economic and/or reservoir restraints. Based on experience gained from beam pumped oil wells in West Texas waterflood projects, well analysis as presented can be applied to oil wells produced by other means of lift and reservoir drive mechanisms. Introduction Maximizing pumping oil well rates and reserves within certain restraints have always been the objectives of the petroleum engineers. One of the obstacles that prevents achieving these objectives is problems that occur within the wells. These problems can be associated specifically with the reservoir, the wellbore and near wellbore area and mechanical aspects of the producing well. In this paper the primary concern is with the problems of the wellbore or near wellbore area and/or the mechanical condition of the well. Symptom recognition and definition of the cause of a problem can best be accomplished through regular collection and analysis of individual well production data. Although many times production data must be supplemented with other data to completely review performance. In shallow West Texas waterfloods, where beam units are the prevalent lift mechanism, it has been found that constant review of overall project and individual well performance by the production engineer results in wells being maintained in their optimum producing condition. These reviews are facilitated by the collection and proper display of at least monthly well test and fluid level data or pump off control device pump time on every producing oil well. pump time on every producing oil well. A "well checklist" as developed in this paper, helps the production engineer organize well performance and mechanical data necessary for well reviews. Once the data is organized, performance analysis becomes a matter of interpreting the data and comparing the well's performance or predicted performance to that of another. predicted performance to that of another.
American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc. This paper was prepared for the 49th Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in Houston, Texas, Oct. 6–9, 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 paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. 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 discussions may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Abstract A system is described for detecting and diagnosing problem gas lift wells based on well test data. Wells are screened so that only those with abnormal producing conditions are identified for further analysis. The analysis utilizes well tests and installation specifications to define troubles and predict efficient gas injection rates. This method circumvents the need for numerous flowing pressure and temperature traverses in pressure and temperature traverses in continuous flow gas lift facilities. Introduction Gas lift wells are subject to the following kinds of design and operating problems: Surface Excessive flowline restriction Tubing or casing choke plugging Undersized flowlines High separator pressure Undersized gas distribution systems Wet gas Subsurface Leaks in the flow string Improper flow valve operation Improper design of string Changing well conditions Excessive aeration Excessive slippage of fluid or fallback Foam conditions Low fluid heads or submergence heading or surging conditions Conventional methods to detect and diagnose inefficient gas lift wells can require many of the following: Well tests Casing-tubing pressure recordings Surface temperature recordings Pressure traverse surveys Temperature surveys Fluid levels determined by acoustic methods But in a large scale gas lift field, it is expensive and time consuming to get the necessary down-hole data.
American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc. This paper was prepared for the 49th Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in Houston, Texas, Oct. 6–9, 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 paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. 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 discussions may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Abstract The most profitable distribution of gas to wells in a continuous flow gas-lift system can be determined by an analytical procedure. The procedure utilizes well procedure. The procedure utilizes well test information and calculations of vertical two-phase flow behavior to predict individual well producing rate responses to changes in gas input rate. The optimum distribution of the available gas can be calculated based on each well's contribution to the profit for the system. A computer program was developed to perform the calculations for the procedure. This program has been used in a Venezuela field program has been used in a Venezuela field with 1500 gas-lift wells. A modified version of the program has been used in a Texas field containing 150 gas-lift wells. Introduction For the past several years Exxon Production Research Company (EPRCo) has Production Research Company (EPRCo) has assisted their affiliate in Venezuela, Creole Petroleum Corporation, in improving their gas-lift system efficiency. One of the results of this work has been the development of a calculation technique for determining the optimum distribution of gas to gas-lift wells. The determination of the optimum gas distribution has particular significance to Creole because of their need to use a large portion of the existing compressor facilities to inject produced gas in subsurface reservoirs. As the allocation of available gas for pressure maintenance projects increases, less gas is available projects increases, less gas is available for gas-lifting oil wells. To maintain oil production at desirable levels, Creole must make optimum use of available gas on those wells which will supply the most oil consistent with good reservoir engineering practices. Creole also has other incentives for determining the optimum gas distribution in a gas-lift system. First, there is a need to properly reallocate gas when a compressor station is down for regular maintenance or due to equipment failure. Second, bottlenecks in the gas-oil treating facilities may unnecessarily limit highly productive wells which require only small amounts of gas-lift gas. Therefore, Creole recognized they could improve their daily operations by minimizing the amount of gas required to maintain gas-lifted oil production.
This paper was prepared for the 48th Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in Las Vegas, Nev., Sept. 30-Oct. 3, 1973. 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 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 Increased depths of drilling operations has produced the need for pumping equipment that will perform reliably during long duration, extreme pressure stimulation treatments. Treating pressures above 15,000 psi and pumping of hot concentrated acids have rapidly pumping of hot concentrated acids have rapidly become more common practices in stimulation work. The first generation of high horsepower intensifier pumps was introduced for use on an experimental drilling project in late 1969. Later these units were placed in field service work for stimulation of wells that required high pressure fracturing and acidizing treatments. The units have proven to be capable and reliable in oil field service operations and have been a major factor in the satisfactory completion of many deep wells. Because of the excellent performance and acceptance of the first intensifier units, a new and much larger pump has been introduced. It is anticipated that the new unit will be capable of delivering over 4,000 hydraulic horsepower or approximately three times that of its predecessor. To date the intensifier pumps have met the challenge and demands of deep well stimulation; and with further innovations, should successfully meet future ultra-service requirements. Introduction During mid-1965, work was initiated to develop a high horsepower duplex intensifier pump that would be applicable for use on high pump that would be applicable for use on high pressure erosional drilling and stimulation pressure erosional drilling and stimulation of ultra-deep formations. Past experience had shown that the performance of this type of work with conventional pumping equipment was for all practical purposes economically prohibitive. It was theorized that a slow prohibitive. It was theorized that a slow speed-large displacement intensifier pump concept would yield a more reliable pump with extended expendable part life. Laboratory experience gained with a duplex unit proved the theory of improved life, but dictated the development of a triplex design to obtain the desired performance characteristics. The HT-1000 intensifier pump, shown in Figure 1, performed extremely well during laboratory testing that was performed concurrent with production of additional units. During the latter part of 1969, a complex of 10 prototype units was used in an experimental erosion drilling test, pumping abrasive laden mud at pressures of 10,000 to 15,000 psi.
- North America > United States > Texas (0.47)
- North America > United States > Nevada > Clark County > Las Vegas (0.24)
Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussions may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Abstract Amoco's position in West Texas is rather unique in that we have a high concentration of wells in a relatively small geographical area. This situation caused us to take a different approach to automation from any other in the producing industry that we know of today. Amoco's operations in West Texas include four Area offices and about 5,000 producing and water injection wells which are prime producing and water injection wells which are prime candidates for computerized automation. The basis for our approach to automation in West Texas was developed from information learned from a pilot project in the Smyer Field in Hockley County, Texas. This pilot project was designed to test all applications which reasonably offered an opportunity to reduce labor or accelerate production. As a result of this pilot, we decided that future Amoco operated automation projects in West Texas would be based around the following concepts:Pumpoff Control of Beam Pumped Wells Automatic Well Testing Data Gathering Alarm Monitoring These basic concepts permitted developing modular standard software applicable to all West Texas projects. projects. Once the basic concept for automation in West Texas was established, it was then necessary to develop an optimum computer system for this large number of wells. Economics and other advantages dictated that a Master-Mini, two level, hierarchical computer system would be best. The plan established for automation in West Texas included running multi-conductor cable to each producing well for pumpoff control and monitoring various statuses. It soon became evident that with conventional telemetry equipment available at that time, cabling costs would approach $1,100 to $1,200 per well and would be prohibitive. The obvious way to reduce cabling costs was to increase the number of RTU's which would in turn reduce cabling costs. We finally interested one telemetry vendor in designing and developing a small RTU referred to as a Mini RTU. We believe this was the first telemetry gear actually designed primarily to meet the requirements of oilfield automation.
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.55)
- North America > United States > Wyoming > Elk Basin > Elk Basin Field (0.99)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- (35 more...)
This paper was prepared for the 48th Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in Las Vegas, Nev., Sept. 30-Oct. 3, 1973. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgement of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF 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 This technique is based on a computerized mathematical model of a hydraulic pumping system. Mechanical equipment performance and capability of the well are evaluated jointly. The computer program is also used to evaluate changes that are needed to optimize production from a well. This method is implemented with a portable computer system and electronic data gathering equipment. Thus, results can be made available on the well site in a matter of minutes. Introduction Hydraulic pumping made its appearance as a method of oil well artificial lift in the early 1930's. Since that time this method has found wide acceptance, especially in deep, high volume pumping. Because the unit is located near the pumping. Because the unit is located near the bottom of the well, understanding the operation and condition of the downhole unit can often be a problem for the producer. This paper presents a well-site analytical method using pressure and production data to determine useful information about the overall condition of the hydraulic pumping system along with the well's potential. Thus, by thoroughly understanding equipment and well conditions, the producer is in a better position to reach his goal of producer is in a better position to reach his goal of maximizing profit. The hydraulic pumping system analyzed in this paper consists of a downhole hydraulic reciprocating engine directly connected to a reciprocating pump which functions as a unit. There are many configurations of downhole units available such as tandem engines with single pumps, tandem pumps with single engines, tandem pumps with tandem engines, and a large selection of power ratios. Also downhole tubular arrangements vary depending on application such as casing free, fixed casing, parallel and fixed insert. Since the operation is basically the same, the method discussed in this paper applies generally to all. Also of importance are the two types of power fluid arrangements, i.e. open and closed systems. The closed system keeps the power fluid separate from produced fluids as compared to the open system which produced fluids as compared to the open system which mixes produced fluid and power fluid as they are discharged from the unit. Most systems are of the open type because of simplicity of design and reduced equipment costs. This paper discusses the open type only but with minor modifications, the closed power fluid arrangement can be analyzed as well. DESCRIPTION OF EQUIPMENT AND IMPLEMENTATION OF TECHNIQUE Figure 1 is a schematic drawing of portable analytical equipment.
This paper was prepared for the 48th Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in Las Vegas, Nev., Sept. 30-Oct. 3, 1973. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgement of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF 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 Oil producing companies are continually seeking new ways to cut production costs through the production costs through the development of new ideas. This paper discusses a unique, economical hydraulic lift system installed by the Lafayette Division of Continental Oil Company. This system combines a new venturi, hydraulic bottom-hole pump and a compact, centrifugal power fluid cleaning system into a single installation. This jet eductor pump, or jet pump, is relatively unaffected by high gas-liquid ratio production or dirty power fluid and requires very little maintenance. The fluid cleaning system provides power fluid which meets the quality power fluid which meets the quality requirements of the jet pump for considerably less initial investment and lower operating costs than a conventional power fluid system. This combination is power fluid system. This combination is particularly adaptable to single well particularly adaptable to single well leases or fields. Currently, two of these compact systems are in operation producing sour crude from the deep Smackover formation in Mississippi. Excluding the problems corrected during an initial startup period, no system operating problems have been reported after a cumulative twenty-nine months of service. Introduction The Lafayette Division of Continental Oil Company has in operation two hydraulic lift installations which incorporate a new venturi hydraulic pump and a compact power fluid cleaning system, to be called "POCS" (power oil centrifugal separation) unit, into a unique system. To our knowledge, these were two of the first uses of this combination in the industry and the first installations designed specifically for use of a jet pump. The two single well systems were installed on wells in the deep Mississippi Smackover trend.
- North America > United States > Mississippi > Clarke County (0.47)
- North America > United States > Nevada > Clark County > Las Vegas (0.24)
- North America > United States > Mississippi > West Nancy Field (0.99)
- North America > United States > Mississippi > Nancy Field (0.99)
- North America > United States > Mississippi > Barber Creek Field (0.99)
- North America > United States > Louisiana > Mississippi Field (0.99)
This paper was prepared for the 48th Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in Las Vegas, Nev., Sept. 30-Oct. 3, 1973. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgement of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF 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 The problem of sucker rod failures has plagued the industry since the inception of plagued the industry since the inception of rod pumping. The seriousness of the problem has been aggravated by deeper pumping, high volume requirements imposed by secondary recovery projects, downhole friction in crooked directionally drilled holes, and corrosive well fluids. Technological advances have been seen through the years in improved gas lift valve design, improved electrical and mechanical dependability in submersible electric pumps, and increased capacity from subsurface hydraulic pumps, but until recently, little improvement had been made in the weak link of the rod pump system-the sucker rod. This paper relates Getty Oil Company's two years field experience with a new ultra-high strength sucker rod, the development of which has proved to be a major advance in sucker rod proved to be a major advance in sucker rod performance performance The high load capability of the new rod has allowed use of larger pumps in Getty Oil Company's Ventura Avenue Field C-Block Waterflood, extending the range of rod pump capacity from the prior limit of 500 B/D to a present limit of 1000 B/D. The new rods have been successfully field tested at loads of 47,317 PSI and are in service in 29 Getty Oil Company wells in the Ventura Avenue Field in California. Introduction After conducting a pilot waterflood for several years, Getty Oil Company began full scale expansion of it's Ventura Avenue Field C-Block Unit Waterflood in January, 1970. In December, 1971, after completion of the Main Injection Plant, the major portion of the C-Block Unit was being waterflooded. The project now includes 45 injection wells and project now includes 45 injection wells and 111 producing wells. Small rod pump units and hydraulic subsurface pumps were used to produce C-Block wells during primary recovery. Primary production equipment was too small to produce production equipment was too small to produce high rate waterflood response and is being replaced by high volume submersible electric pumps in wells which have 6-5/8" or larger pumps in wells which have 6-5/8" or larger casing. High volume rod pumps are used in wells with casing smaller than 6-5/8". Dependent on completion interval and location on the anticlinal structure, rod pump depths range from 5500' to 7500'. Crooked holes are common in the Ventura Avenue Field.
- North America > United States > California > Ventura County (0.86)
- North America > United States > Nevada > Clark County > Las Vegas (0.24)
This paper was prepared for the 48th Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in Las Vegas, Nev., Sept. 30-Oct. 3, 1973. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgement of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF 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 The well load monitor and related electronics are designed to monitor, analyze and control the operation of a beam pumping unit. The theory of operation, design and installation are presented. Computer-controlled and stand-alone local logic types are discussed. Case histories of field operation and results of operating fluid level control are included. One of the most significant results is that the operating fluid level can be effectively controlled to within approximately 100 ft of the pump intake. The potential of the well load monitor as a diagnostic tool for the detection of surface and subsurface operating problems is presented together with field-determined test results that demonstrate a more efficient and economical operation of beam-type pumping equipment. Introduction The well load monitor is the result of work undertaken in the Midland Div. of Mobil Oil Corp. on a system that would provide continuous information of the polish rod loading conditions for beam pumping units. The basic concept was that a continuous analog signal proportional to rod loading could be obtained. This load signal would then be examined and the conditions would be analyzed by a computer. The raw information obtained would be similar to that which is normally obtained from standard dynamometer cards. With the knowledge of the actual load conditions, the computer would take the required control action. The first transducer for the well load monitor system was installed on a well that is producing from the San Andres zone in the producing from the San Andres zone in the Pegasus field in the Permian Basin in West Pegasus field in the Permian Basin in West Texas. This first test and several later tests were very successful. The tests established that an analog signal representative of rod loading could be easily and accurately obtained. The next step in the development of the system dealt with analyzing the output and taking action. It was determined that, in order to accomplish this step, a system would be installed on a 44-well lease in the Slaughter field. Thus, a full-scale computer-controlled installation utilizing the WLM concept was undertaken. The techniques in telecomunications and computer control gained from the other projects that had previously been installed were projects that had previously been installed were modified to incorporate the new concepts of the use of the well load monitor. This completely new endeavor brought with it some completely new problems.
- North America > United States > Texas > Terry County (0.24)
- North America > United States > Texas > Hockley County (0.24)
- North America > United States > Texas > Cochran County (0.24)
- (2 more...)
- 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)
- (24 more...)
This paper was prepared for the 48th Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in Las Vegas, Nev., Sept. 30-Oct. 3, 1973. 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 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 A mathematical model of the reservoirs which are currently being waterflooded in the Middle Ground Shoal field of Alaska has been constructed and calibrated to match the six-year water production and pressure history in this field. The reservoir description and performance data are stored on magnetic tape and performance data are stored on magnetic tape and updated periodically. Thus the model represents a retrievable reservoir engineering tool for prediction of field performance under a variety prediction of field performance under a variety of short and long-term operating strategies. It has been recognized through application of this tool that acceleration of income and additional oil recovery will result from expansion of the current artificial lift capacity, control of produced water and additional drilling. produced water and additional drilling Introduction The evolution of solution techniques involved in reservoir performance predictions has prompted an accompanying change in the requirements for reservoir description. No longer are the assumptions of uniform rock properties and fluid saturations used in the properties and fluid saturations used in the classic Stiles and Dykstra-Parsons models sufficient for the calculation procedures. For the first time, geologists and engineers are being asked to quantify variables which have heretofore received only qualitative assessments. The degree of success which a simulation achieves in terms of meeting its specified objectives may directly reflect the amount of physical detail preserved in the mathematical physical detail preserved in the mathematical model. At the stage in the life of a reservoir when infill drilling or supplemental recovery projects are planned or in operation, simulation projects are planned or in operation, simulation to predict future performance requires a careful description of the variables which determine the magnitude and distribution of the displaceable oil and the capacity of the formation to transmit and store fluids. The accuracy necessary in the description process becomes exceedingly important when attempts are made to model heterogeneous, multilayer reservoirs. This paper presents the techniques which were used to describe the complex reservoirs of the Middle Ground Shoal field, which lies beneath the waters of the Cook Inlet approximately 60 miles southwest of Anchorage, Alaska. This field is one of five known petroleum accumulations in an area of the Cook petroleum accumulations in an area of the Cook Inlet commonly referred to as Oil Alley, and it ranks number three in terms of reserves and productive capacity (Figure 1). productive capacity (Figure 1).
- Geology > Structural Geology (0.93)
- Geology > Sedimentary Geology > Depositional Environment > Marine Environment > Shallow Water Marine Environment (0.45)
- Geology > Geological Subdiscipline > Geomechanics (0.34)
- North America > Canada > Alberta > Shoal Field > Agip Et Al Nipisi 14-24-82-7 Well (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Central Graben > Block 30/7a > J-Block Field (0.99)
- North America > United States > Alaska > Cook Inlet Basin > Middle Ground Shoal (0.98)