bluuebunny/crossref_metadata_2025_split huggingface dataset:
Some Economic Considerations of Underground Coal Gasification
Authors: Jennings J.W. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.
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 economics of the use of underground coal gasification to supply the fuel for a combined-cycle power generation plant are studied. Much of the data relative to the underground process was obtained from the experiment being process was obtained from the experiment being conducted by the Energy Research and Development Administration (E.R.D.A.) (previously the U.S. Bureau of Mines) at Hanna, Wyoming. The capital and annual operating monetary requirements are estimated for a 1000 MW, on site, combined-cycle power plant.
The sensitivity of the required selling price of the generated electricity to various price of the generated electricity to various operating parameters such as well spacing, coal seam thickness and depth, and producing rate are presented. The required capital for a 1000 MW plant producing from a 70 ft. thick seam of coal at a depth of 2000 ft. is estimated at $165 million. The annual operating cost of such a plant would be about $13 million and could profitably sell the generated power at 7.5 mils/ profitably sell the generated power at 7.5 mils/ KW-hour.

Introduction
Interest in underground coal gasification as a potential energy source in the nation has increased greatly over the last several years. The reasons for this renewed interest are many. The growing energy demand, the decrease in availability of more conventional energy sources and magnitude of the potential coal resource in this country are but a few of these reasons. It is apparent that underground coal gasification, if feasible, could be a process capable of producing vast quantities of clean fuel particularly suited for use in combined-cycle particularly suited for use in combined-cycle power generation. power generation. The use of combined-cycle power plants fueled by gas generated in surface coal gasification plants has been the topic of several papers in the recent past. Even more recently, several natural gas-fired, combined-cycle plants have been installed, typical of which is a 240 MW plant built for the Public Service Company of Oklahoma near Lawton, Oklahoma. These plants are particularly suited as low in capital cost, low polluting generating stations for supplying intermediate power loads. power loads.
Geological And Drilling Aspects Of Columbia's Mingo County Prospect
Authors: Gates Frank A. , Watson W.A. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.
Columbia Gas Transmission Corporation's Well 9674-T was located and drilled on the North Kermit Prospect on Mineral Tract No. 10, in Harvey District, Mingo County, West Virginia. (See Fig. 1).
The North Kermit Prospect is situated on the south flank of the Rome Trough in association with a major northeast-southwest trending down-to-the-north basement fault (see Fig. 2). It was anticipated that a southern platform, located south of the major fault would have been exposed to erosion during the formation of the trough resulting in deposition of clastic units adjacent to and north of the fault. These units would then have acted as reservoir beds. This supposition was based on seismic data, structure and stratigraphy observed along the northern hinge line.
Well 9674-T had as its primary objective the testing of the Rome and Basal Sand formations with a secondary objective of testing all units below the Tuscarora Sandstone.
Seismic data indicated structural closure of 600 feet against the fault on the basement surface. A closure of 200 feet was indicated near the top of the Rome.
The Rome was expected to contain massive marine sandstones with interbedded dark shales and some limestones. Both lenticular and blanket type sands were expected north of the fault, affording structural and stratigraphic possibilities, with maximum sand development along the fault scarp. The well was spudded on September 30, 1971, and was the first of several wells which have since been drilled to basement within the deeper portion of the Rome Trough.
The well was drilled by Loffland Brother's Rig 111 which is capable of drilling below 20,000 feet (see Fig. 3). Rig 111 was located near Laurel, Mississippi, and it required 14 days to move to the location.
Due to terrain, the well site was 140 × 200 feet, rather than the recommended 400 × 400 feet. The location was surrounded on three sides by a creek which could not be relocated.
Recent Oil and Gas Activities in Tennessee
Authors: Statler Anthony T. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Abstract
The 1969 discovery of Tennessee's first million-barrel field, Oneida West in Scott County, has resulted in a significant increase in the state's drilling activity and production in the last 5 years. This Mississippian carbonate play, centered in the Northern Cumberland play, centered in the Northern Cumberland plateau region, has resulted in several plateau region, has resulted in several good Ft. Payne limestone discoveries trending northeast through Scott and Morgan Counties. Several lesser finds have been made in the younger Monteagle and Bangor limestones. A number of scattered potential shallow gas wells have been drilled and shut-in, but little data is available on reserves. Marketed gas remains insignificant largely because of lack of pipeline facilities.
Mississippian pays are found depths of less than 2000 feet, and most fields appear to be stratigraphic traps with little or no relationship to structure. The better Ft. Payne fields are gas cap and gas-solution drive reservoirs with no producible water.
In 1974 crude oil production totaled a record 768,700 bbl, a sizeable increase from the previous year due largely to the Ft. Payne discovery at Indian Creek in late 1973. Field operators are initiating a repressuring program for this reservoir. Cumulative production from Indian Creek should reach a million bbl near the end of this year.
Several deep tests drilled in this part of the state have found porosity and gas shows in the Copper porosity and gas shows in the Copper Ridge section of the Knox Group. However, the premississippian horizons which may have potential in eastern Tennessee still remain largely untested.
Coiled Tubing Injection String for Geothermal Wells
Authors: Alescio Salvatore , Ricciardulli Roberto , Vallini Alessandro , Caponi Nicola 
Published: December 2007

Abstract
Geothermal wells are constantly producing extremely hightemperature steam and endogenous fluids containing corrosive substances.1 These corrosive substances are detrimental to completion, surface, and processingplant materials. In addition, geothermal wells contain high percentages of dangerous gasses, such as hydrogen sulfide (H2S), requiring operators to take special safety precautions. When coiled tubing (CT) injection strings are used to complete such wells, equipment and surfaceplant damage caused by corrosive geothermal fluids can be significantly reduced. Conventional methods require well cleanup operations at regular intervals, but CT provides a permanent installation that allows corrosioninhibiting fluids to be injected continually, thus neutralizing the chlorides produced from the steam. Consequently, operational costs are reduced, lost production time is avoided, and the need for workover interventions is decreased. In addition, because CT is continuous pipe without joints, it provides operators with a greater degree of safety when they work on wells under pressure.
This paper discusses the techniques, wellhead equipment, and bottomhole assembly (BHA) used to install CT injection strings in several geothermal wells in Italy. The technical aspects of some of the 15 wells already completed by this method are also discussed. In addition, ideas for improving future geothermal well completions are presented.
Dielectric Constant Logging, A Salinity Independent Estimation of Formation Water Volume
Authors: Meador Richard A. , Cox P.T. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.
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 knowledge of the dielectric constant of earth materials provides a potential method of directly measuring formation water saturation. Dielectric logging has been studied theoretically and experimentally in order to supply this valuable knowledge. Laboratory core measurements, theoretical borehole-system computer models, instrument design and a detailed field example are combined to illuminate the concepts and demonstrate the value of dielectric constant logging.

Introduction
An open hole logging method which directly distinguishes oil from water in formations having low or unknown water salinity has been needed for many years. A potential technique for solving this problem relies upon a determination of the dielectric constant of the formation. Dielectric constant is a basic electrical property of matter for which oil and water have distinctly different characteristics. It is measured in units of farads per meter.
It is well known that resistivity log interpretations are dependent upon a knowledge of formation water salinity. Unknown or variable salinity often leads to ambiguity in the log interpretation. Dielectric constant measurements can circumvent this problem because the formation dielectric constant is primarily determined by the water volume, not the water salinity. Large water volumes produce high dielectric constant values, and small volumes produce low dielectric values. produce low dielectric values. Efforts to build logging systems which measure formation dielectric constant have been underway. Russian scientists have been active in this field for several years and have published papers on the subject. published papers on the subject. The various aspects of dielectric logging have been discussed separately in these publications.
Production Management Of Reservoirs Through Log Evaluation
Authors: Smith R.L. , Patterson W.F. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.
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 paper describes a complete computer analysis technique which can be used to evaluate a reservoir periodically throughout its lifetime. The resulting periodically throughout its lifetime. The resulting presentation provides the production manager with presentation provides the production manager with heretofore unattainable data that can lead to more efficient reservoir exploitation and better planning of remedial workwover.
In the Gulf Coast it has provided quantitative depletion data. It can also detect many production problems, including: problems, including:*water encroachment and coning*bypassed production*vertical barriers*blocked perforations*premature water breakthrough
Comparison of Performance During Cycling and Blowdown with Various Prediction Methods-Washington Cockfield "D" Gas-Condensate Reservoir
Authors: Elkins L.F. , Brown R.C. , Skov A.M. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.
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
Performance of the Cockfield "D" sand gas condensate reservoir during cycling and subsequent blowdown is compared with calculations using the conventional layer model assumptions. Actual performance during cycling was better than that calculated using the Dykstra-Parsons and Stiles techniques of determining permeabilities for layers (adapted by analogy from their permeabilities for layers (adapted by analogy from their waterflood prediction methods) but not as favorable as that calculated by the Miller-Lents technique of determining such permeabilities from core data. Comparison of calculations with a similar layer model with actual performance indicates that permeability profile effects continue to be important in determining condensate content of gas produced during blowdown of the reservoir following cycling.

Introduction
The Cockfield "D" sand in the Washington Field, St. Landry Parish, Louisiana, was found to contain gas-condensate by the completion of the Thistlethwait Land and Cattle Co. No. 1 at a depth of 9313 feet in December 1951. Subsequently 18 producing wells and 6 dry holes have defined the extent and geologic characteristics of this reservoir. Limited volumes of gas were sold from November 1953 to May 1955 to determine performance characteristics of the reservoir. performance characteristics of the reservoir. The field was shut-in until unitization was achieved and facilities installed for gas injection. Cycling operations were started in October 1956. Gas injection was continued until October 1967; then gas was sold until April 1975 when the reservoir was shut-in for conversion to gas storage for a major gas-pipeline system.
The primary purpose of this paper is to compare the actual cycling performance of this reservoir with published prediction techniques. The concepts of flow in stratified reservoir rock systems during gas injection are also extended to the post cycling period - an area of technology just barely mentioned in petroleum literature. This is important in the economic decision of when to stop cycling and to start blowdown of a gas-condensate reservoir. Other aspects of reservoir performance discussed include an early long time injection-production interference test conducted to aid in selection of the tall pattern used for cycling, and a comparison of volumetric estimates of gas-in-place with actual production.
Reservoir Simulation Design of a Waterflood with Crestal Gas Injection - Caranda Field, Bolivia
Authors: Van Kirk Craig W. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.
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
Caranda is one of the largest and most complex oil fields in Bolivia. A recent reservoir-simulation study of the Taiguati "G" Este reservoir has resulted in the conclusion to initiate water injection at the oil-water contact to supplement the existing crestal gas injection program. This study also improved the understanding of the performance of other reservoirs in the field, representing a prime example of additional and unexpected benefits that frequently result from a detailed simulation study.

Introduction
This is a presentation of the results of a reservoir-simulation study of the Taiguati "G" Este reservoir in the Caranda field in Bolivia. The purpose of this study was to update a previous reservoir-simulation study conducted previous reservoir-simulation study conducted during 1972. The current study encompassed a description of the physical system, a match of the observed production history through June 1974, and predictions of the future performance of several different operating schemes.
The reservoir simulator used in this study is a three-dimensional, three-phase mathematical model that accounts for the effects of capillary pressure, relative permeability, gravity, and pressure, relative permeability, gravity, and variable reservoir dip. The reservoir fluids are described by pressure-volume-temperature relations. A large high-speed digital computer was used for performing the calculations in the model.
The Caranda field is in the major oil producing region of Bolivia, as shown in Fig. 1, and is located approximately 35 miles northwest of the city of Santa Cruz.
The field was discovered in 1960 with the major oil reservoir being the Permian Taiguati "G" Este at a depth of approximately 6,000 ft. Production began in early 1966, reaching a Production began in early 1966, reaching a maximum rate of 6,700 STBO/D during 1968, and has since steadily declined to the present rate of 1,800 STBO/D from 12 producing wells.
This update study has been based on a major geological reinterpretation done by Yacimientos Petroliferos Fiscales Bolivianos (Y.P.F.B.) Petroliferos Fiscales Bolivianos (Y.P.F.B.) since the last study in 1972. Also included in the update study are the production and pressure data gathered during the interim 2 years.
Past and Predicted Future Performance of Hassi Messaoud Field, Algeria Under Gas and Water Injection
Authors: Dorsey J.B. , Litherland J.G. , Saadi A. Ait , Boutalbi A. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.
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
Past and future predicted performance of Hassi Messaoud oil field is discussed. One of the larger fields in the world, Hassi Messaoud had 38 billion barrels of highly undersaturated oil originally in place. The field has been producing since 1957, and its performance is of particular interest because of the high-pressure, miscible, gas-injection program that has been in operation for the last 11 years. Field performance is described, and future operating plans for the field are discussed; these plans will include the drilling of 500 new wells, expansion of the gas-injection facilities, and initiation of large-scale water-injection operations. A technique used to predict future performance of the field under the proposed operating plan is also presented. presented

Introduction
The Hassi Messaoud field is located in the Sahara Desert of northeast Algeria approximately 350 miles southeast of Algiers (see Fig. 1). Hassi Messaoud is Algeria's largest oil field and ranks as one of the largest fields in the world with respect to in-place oil reserves. Discovered in 1956, it has a productive area of over 1,000 square miles and produces a current 580,000 B/D of oil from 300 wells.
The oil was highly undersaturated at original reservoir conditions, and laboratory work done in the early stages of development revealed it to be miscible with high-pressure gas injection. A pilot program using high-pressure gas injection was therefore initiated in 1964; the program has since proved successful and has been gradually expanded, and plans are now underway for further enlargement. Water injection and alternating gas- and water-injection pilots are also operating, and plans are being made for expansion of the plans are being made for expansion of the water-injection program. From numerous studies, a depletion plan for the field has been evolved which will employ both high-pressure gas and water injection; with the drilling of 500 additional wells over the next 10 years, the depletion plan will permit production from the field to be increased 50 percent over its current rate.
The purpose of this paper is to review field performance to the current time and to present plans performance to the current time and to present plans and study results for use in future exploitation of the field.

GEOLOGY and RESERVOIR ROCK PROPERTIES
The Hassi Messaoud reservoir is Cambro-Ordovician in age and is comprised of a highly siliceous, cemented quartzitic sandstone overlain by beds of shaly Triassic sandstone. Figure 2 is a type log through the producing section and shows the three sand members that comprise the reservoir.
Reservoir Engineering Design of a Tertiary Miscible Gas Drive Pilot Project
Authors: Faulkner Barry L. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.
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
Information relative to the design and implementation of a tertiary miscible gas drive pilot project, located in West Texas, is presented. This pilot was initiated to test the carbon dioxide multiple contact tertiary miscible displacement technique utilizing acid gas (71% CO2, 29% H2S) as the miscible fluid. Pilot sizing and evaluation approach, operating considerations, and data collection aspects are briefly discussed.
The primary scope of this presentation is the use of a streamline numerical miscible displacement program to match the classical secondary waterflood performance of this pilot and to predict and design the tertiary pilot and to predict and design the tertiary miscible gas phase as to slug size, gas water ratio, buffer slug size, and number and size of cycles.

Introduction
Improved recovery pilots are recognized as a vital step in the development of methods for recovering the vast amounts of oil remaining in reservoirs after secondary recovery. The use of carbon dioxide as a tertiary miscible solvent has the advantage of low fluid costs and therefore warrants particular attention. It has been established that carbon dioxide can provide miscible type displacement under appropriate conditions. While only limited laboratory information is available on the carbon dioxide multiple contact tertiary miscible displacement technique, laboratory tests have demonstrated that this improved recovery method is equally effective under secondary and tertiary modes. However, direct application of laboratory information to actual field endeavors has severe limitations, and only field testing in a total reservoir environment can demonstrate the operability and provide information on practical problems that must be solved before an economical tertiary recovery method is developed for an entire field. Therefore, a site for a pilot test of tertiary oil recovery by carbon dioxide flooding was selected in a carbonate reservoir in West Texas.
An available acid gas stream will actually be injected as the miscible fluid. Gas plant residue gas (predominantly methane) plant residue gas (predominantly methane) will be used as the chase fluid.