bluuebunny/crossref_metadata_2025_split huggingface dataset:
Performance of Seeligson Zone 20-B Enriched Gas-Drive Project
Authors: Baugh E.G. 
Published: December 2007

Abstract
An enriched gas-drive project was initiated in Zone 20-B, Seeligson field, Jim Wells and Kleberg counties, Tex., on March 19, 1957. To date nearly 2.5 billion cu ft of an enriched gas mixture composed of about 50 per cent methane and 50 per cent propane has been injected through two injection wells. There are 11 producing wells in this project. Cumulative production since injection began is approximately 750,000 bbl of stock-tank oil, and the current oil-producing rate for the reservoir is 1,000 bbl per calendar day.
Enriched gas in appreciable quantities has reached the first row of producing wells down-structure of the two injection wells. As predicted from laboratory work, displacement of reservoir oil by the enriched gas mixture has proved to be highly efficient. Project results to date are encouraging, and additional information should be gained from a conformance evaluation workover to be performed in the near future. The project is still at an early stage of operation because the enriched gas volume injected to date is only 16 per cent of the hydrocarbon pore volume.

Introduction
The enriched gas-drive process entails the injection of a gas which has been enriched through the addition of such intermediate hydrocarbon components as ethane and propane to the extent that it is completely soluble in the oil to be displaced. Enriching components in the gas are absorbed into the oil, forming a bank of swelled oil that is miscible with the oil ahead and the gas behind. There is no sharp interface between the displaced and displacing fluids; rather, there is a zone of short duration between the injected and resident fluids in which the fluid properties grade from those of the displaced to the displacing medium. Under these conditions, capillary and interfacial tension forces are not believed to be present. High recovery is made possible by removing or reducing the interfacial tension between the injected material and the reservoir oil to the extent that essentially no oil is left as residual droplets.
Miscible Slug Flooding - A Review
Authors: Craig F.F. , Owens W.W. 
Published: December 2007

Abstract
Over the past several years the petroleum industry has become increasingly interested in the possibilities of miscible slug flooding as a means of increasing the nation's recoverable reserves. Preliminary studies of this recovery method have demonstrated that substantially complete displacement of oil is obtained in those portions of the reservoir contacted by the miscible slug.
A large portion of the published research has been concerned with the volume of solvent slug required to maintain miscibility between the reservoir oil and the scavenging gas. In this paper laboratory results are reviewed with particular emphasis on the general conclusions of the studies as applied to field application of miscible flooding.
The factors affecting the portion of the reservoir swept by the miscible slug and reservoir conditions believed desirable for successful operation are discussed. Possible methods for improving the sweep efficiency are considered.

Introduction
During its growth, the petroleum production industry has continually sought improved methods for recovery of oil from underground reservoirs. Gas and water injection have been used to flush additional oil from formations and to restore and maintain reservoir pressure. However, even with these injection operations generally from one-third to one-half of the oil originally in place remains unrecovered at the time that further production becomes uneconomical. This lack of complete oil recovery is due to the inability to obtain both complete sweep of all oil-bearing portions of the reservoir (100 per cent volumetric sweep efficiency) and complete displacement of oil from the swept regions (100 per cent displacement efficiency).
The volumetric sweep efficiency during any injection operation depends uponthe nature and distribution of reservoir nonuniformities,well pattern effects, andgravity effects caused by the density difference between the oil and the injected fluid.
Five-Spot vs. Crestal Waterflood Patterns, Comparison of Results in Thin Reservoirs
Authors: Leissner E.L. 
Published: December 2007

Abstract
This paper presents a comparison of results for two different waterflood patterns which were utilized in separate reservoirs of the same producing horizon. The El Javali field is located in South Texas, about 30 miles north of Rio Grande City on the Jim Hogg County-Starr County boundary. The field is composed of two separate reservoirs separated by a shale-out. The production from the El Javali field is obtained from the O'Hern sand of Eocene age at approximately 2,300 ft. The field was discovered in Oct., 1951. Porosities are good, permeabilities are low, connate-water content in average and the sand thickness is thin. The oil gravity is 32°API and the viscosity is relatively low. Studies of secondary possibilities were initiated in early 1955 to conduct waterflood operations in the north reservoir. Water injection was commenced in this reservoir in May, 1956, by utilizing a crestal, or line, flood pattern in two injection wells and five producers. Primary recovery in this reservoir amounted to 297 bbl of oil/acre-ft. Secondary recovery, as of July, 1959, for the north reservoir was 102 bbl of oil/acre-ft. It is anticipated that the total secondary recovery from this reservoir will be about 157 bbl of oil/acre-ft. In Sept., 1957, water injection was begun in the south reservoir by injection into 10 injection wells forming three modified 20-acre five-spots. Primary production from this reservoir was 316 bbl of oil/acre-ft. Water flood recovery in the reservoir, as of July, 1959, was 81 bbl of oil/acre-ft; the ultimate secondary recovery is estimated to be at least 200 bbl/acre-ft. Secondary increases in production in the north reservoir were experienced in one well at a time. The secondary "kicks" in production for the south reservoir have been more or less simultaneous for all of the producers. From the data presented, it can be seen that the five-spot project will ultimately recover some 21 per cent more secondary oil per acre-foot than the crestal pattern flood.
A Pressure-History-Matching Method for Determination of Relative Permeabilities
Authors: Lai W. , Brandt H. 
Published: December 2007

Summary
A pressure-history-matching method for determining relative permeabilities was developed and verified in a one-dimensional (1D), analytical/experimental study. The matching method is based on a pressure history induced by injecting a gas (nitrogen in this study) into an incompressible-fluid-saturated porous medium.
The analytical model uses relative permeabilities expressed as two-parameter functions of saturation. A parametric study with a finite-difference implicit pressure, explicit saturation (IMPES) solution of the analytical model showed that the relative permeabilities can be determined by matching pressure histories in three steps: (1) match calculated pressure history with measured pressure history during the initial period of 1% of the total injection time, (2) match calculated pressure history with measured pressure history during the final period of 1 % of the total injection time, and (3) minimize differences between calculated and measured pressure histories at no fewer than three selected intermediate times. The parametric study also showed that determining relative permeabilities with this pressure-history-matching method requires a knowledge of porosity and specific permeability.
Experimental verification compared relative permeabilities of a core determined by the pressure-history-matching method with the relative permeabilities measured by the classic transient-displacement method. The comparison showed errors in the relative permeability of ±5% for water flow and +30% for gas flow.
The Rheological Properties of Cement Slurries: Effects of Vibration, Hydration Conditions, and Additives
Authors: Chow Thomas W. , Mcintire L. V. , Kunze Kenneth R. , Cooke Claude E. 
Published: December 2007

Summary
Dynamic material testing was used to study cement-slurry structure during early setting. The structure is very sensitive to shear strain and, to a lesser degree, to vibrational frequency. Both setting kinetics and cement structure can be affected by hydration conditions, including water content, temperature, and commonly used additives.
Performance of an Alternate Repressuring and Producing Project
Authors: Crosby George E. , Cochran Robert J. 
Published: December 2007

Introduction
A reservoir which is being subjected to an alternate repressuring and producing mechanism is the Rincon field Frio D–7 sand lens located 16 miles northeast of Rio Grande City, Starr County, Tex., along the Vicksburg flexure and the southwestern edge of the Rio Grande embayment. As in most Frio fields in this area, numerous sand lenses are encountered and, in this instance, throughout 12 distinct strata. The subject reservoir, the D–7, was the seventh reservoir to be outlined in the D stratum. The D–7 reservoir shown in Fig. 1 is a 38 acre-ft, sand lens located at a subsea depth of - 3,230 ft on the west side of the Rincon structure. Only two wells, T. B. Slick HB No. 90 and 91, were drilled into the sand lens, encountering 12 and 16 ft of sand, respectively. Although Well No. 91 was cored, no analysis was obtained; therefore, 23 per cent porosity and an irreducible water saturation of 24 per cent, the average figures in Frio D sands in this area, were used. A fluid analysis is not available from the D–7 reservoir. Therefore, an analysis from the D–5 reservoir (sand) in proximity to the subject reservoir was used to obtain the assumed formation volume factor of 1.172 at 1,523 psi and 155°F.

Primary Performance History
In June, 1941, the T. B. Slick HB No. 91, the only well that produced during primary operations, was completed in the D–7 reservoir and potentialed for 166 B/D, no water, flowing through a 1 1/64 in. choke with a GOR of 311 cu ft/bbl, and tubing pressure of 320 psi. Flow valves were installed in Aug., 1944; in Feb., 1946, the well was shut in due to low productivity. The flow valves were repaired in Dec., 1947, and the well was re-potentialed for 45 B/D. The well then produced until Feb. 21, 1950, at which time it was permanently shut in due to low productivity. The primary production history of the reservoir is illustrated in Fig. 2. Cumulative production at the end of the primary life was 80,820 bbl of oil, no water and 159,872 Mcf of gas. Bottom-hole pressures taken in 1948, 1950 and 1951 are thought to be in error and probably represent gas-lift system pressures caused by a leaking valve. The gas-oil ratio increased from 311 to 52,800 cu ft/bbl, but the accuracy of the erratic gas-oil ratio history after 1946 is questionable and can probably be contributed to the inherent industry-wide problem of measuring injection gas during intermittent gas-lift operations.
Feasibility of Underground Storage of Liquefied Methane
Authors: Flanagan D.A. , Crawford Paul B. 
Published: December 2007

Abstract
A study has been made of the feasibility of storing liquid methane at low pressures in underground caverns. Methane liquefies at - 258F at atmospheric pressure. It is shown that the methane evaporation rates will rapidly decrease and cool the surrounding rock so that at the end of one month they would be between 50 Mcf/hr for a cavern of 25-ft radius and 700 Mcf/hr for a cavern of 100-ft radius. At the end of 10 years, the evaporation rates would be 18 and 100 Mcf/hr, respectively, for caverns of the same radii. The evaporation rates may be reduced by a factor of 2 to 10 by the application of insulation.
The cost for mining the caverns is estimated to be $.75 to $1.25/Mcf of storage. This is substantially less than surface storage; it is believed to be safer and to result in lower maintenance, savings in space and savings in strategic materials.

Introduction
During the past few years, there has been an increasing interest in the economic feasibility of liquefying methane. Methane liquefaction is being considered for tanker transport; in addition, liquefaction is being reconsidered for shaving peak gas demands. Several articles have described natural gas liquefaction and the progress of the tanker in making trial runs from the United States to Great Britain to determine the feasibility of tanker transport.
At the present time, pipelines are not designed to supply peak gas loads during extremely cold periods such as are often encountered in the North and Northeast. Gas is being stored in underground reservoirs enroute to its destination, but in many instances satisfactory storage in porous reservoirs has not been practical, especially along the Eastern seaboard where few petroleum reservoirs have been found. In England and other foreign countries, it is unlikely that satisfactory porous structures could be found, and it may be desirable to mine or excavate the rock to obtain storage. By storing the methane near the consumption point, product availability can be increased during periods of need.
Overview of the Highlander Field Development
Authors: Smith G. D. , Batcheler G. H. 
Published: December 2007

Summary
This paper discusses the engineering, operational, and construction challenges encountered in the Highlander development and how the various elements of the Highlander production facilities were designed to provide economical solutions. Outlined descriptions of facilities are given to show the comprehensive nature of the project. The application of innovative designs, fast-track scheduling, tight budgetary controls, and stringent quality control are discussed.
A Subsea Completion System for Deep Water
Authors: Rigg A.M. , Childers T.W. , Corley C.B. 
Published: December 2007

Abstract
As the search for oil and gas reserves is extended to deeper water, conventional offshore exploitation methods become less attractive due to the high cost for fixed platforms. This has prompted consideration of subsea completion methods as an alternative development technique. Humble Oil and Refining Co. has conducted tests to develop technology and equipment needed for completion and production maintenance of satellite underwater wells in deep water. Results of this development program are presented.
Introduction
The development of offshore oil and gas fields has largely been conducted from permanent pile-supported platforms using directional drilling techniques. Wells are drilled through large diameter conductors and wellhead equipment is installed on the platform deck. Permanent-type platforms have been installed in water depths to 285 ft. As activity moves into deeper water, the investment required for fixed platforms increases rapidly. This has prompted consideration of alternate development techniques for deep water using floating drilling and subsea completion methods. Floating rigs have been widely used as a deep water exploratory tool and techniques and equipment are now in an advanced state of development. For example, Humble recently drilled an exploratory well from a floating vessel in 632 ft of water offshore California. Industry experience is rather limited, however, with the completion and production of underwater wells. Most have used adaptations of conventional land equipment and have been completed in water depths easily accessible to divers. The extension of offshore operations to the edges of the continental shelves, and even beyond, has accelerated interest in the use of subsea completion techniques. To provide the technology and equipment needed for the completion and production maintenance of satellite underwater wells in deep water, Humble has prompted development of
an underwater well completion system, an underwater Christmas tree system, and the tools and techniques required for performing well servicing and simple workover operations from a remote location.
All equipment has been designed for remote diverless installation and operation. As a part of this program, an off. shore underwater test well has been completed and production experience has been accumulated over an extended period.
Underwater Well Completion System
The well completion system for satellite underwater wells (Fig. 1) was designed so that routine production maintenance and simple workover operations could be performed from a remote location with access to the well tubing through the flowline.
JPT
P. 1049ˆ
An Analysis of Upstream Differencing
Authors: Sammon Peter H. 
Published: December 2007

Summary
A complete convergence analysis is carried out for upstream differencing as applied to one-dimensional (ID) tilted reservoirs experiencing gravity-segregation effects and possible countercurrent flows. It is shown that the standard upstream method converges to the correct physical solution of this problem, provided that an appropriate stability condition holds. Results from the theory of monotone-difference schemes are used. It is concluded that in addition to the practical advantages of the upstream formulation, there is also a strong theoretical justification for use of upstream techniques in multidimensional reservoir simulation.
Well-Test Analysis for Multiphase Flow
Authors: Raghavan Rajagopal 
Published: December 2007

Summary
This paper is a review of well-test analysis under multiphase-flow conditions. The contributions of Perrine and Martin are noted, and the consequences of using their results are documented. The advantages of incorporating the heterogeneous nature of the porous medium for solution-gas-drive systems with the pseudopressure function are discussed. Methods to predict well-inflow performance are discussed with regard to the works of Vogel and Fetkovich. The long-time-performance prediction of wells with decline curves that incorporate the heterogeneous nature of the porous medium is addressed. The final part of this paper considers pressure-falloff data. Theoretical developments are reviewed, and problems associated with the identification of fluid banks are listed.
Reservoir Performance Under Gas Injection, LL-453 Area, Bolivar Coastal Field, Venezuela
Authors: Stepanek D.L. 
Published: December 2007

Abstract
The Tia Juana conservation plant No. 2, which furnishes high pressure gas to pressure maintain four Eocene sandstone reservoirs of the prolific LL–453 area of the Bolivar Coastal field, was placed in operation during April, 1597. This is Creole Petroleum Corp.'s largest gas conservation plant to be constructed on Lake Maracaibo to date, and is capable of compressing 300 MMcf/D to 1,800 psig. The four reservoirs being pressure maintained extend over a surface area of 10,400 acres, with each having an average net oil-sand thickness of 114 ft. During the first 28 months of plant operation, an average total of 205 MMcf/D of gas was injected into the four reservoirs. This represents approximately 99 per cent replacement of hydrocarbon volume withdrawals. The total efficient producing rate of these reservoirs is 135,000 BOPD with a gas-oil ratio of 1,050 scf/bbl. The highly effective gravity segregation taking place throughout the reservoirs contributes quite heavily to the excellent reservoir performance experienced to date, under both natural depletion and pressure maintenance. Although gas injection has only been in operation for approximately 28 months, the beneficial effects are readily apparent from the production characteristics of up-dip wells. These wells have shown decreasing trends in gas-oil ratios accompanied by an increase in production rates. Furthermore, recent subsurface pressure surveys have indicated definite pressure increases in the up-dip portion as a result of the gas injection.

Reservoir Characteristics and Development History
The LL–453 area is located on Lake Maracaibo, approximately 11 miles southwest of the community of Tia Juana, Venezuela. The pressure maintenance area covers a surface area of 10,400 acres and consists of two B–6-X and two underlying B–7-X Eocene sandstone reservoirs, each of which has a net oil-sand thickness (when averaged together) of 114 ft. Structurally, the reservoirs are gently dipping monoclines bounded down-dip by essentially immobile water legs, up-dip by eroded or truncated zones resulting from the Major Miocene-Eocene Unconformity and laterally by major faulting. Shown in Fig. 1 is a structural map of the LL–453 pressure maintenance area. The total sand-section thickness of the B–6-X and B–7-X sands (when considered together) varies between 0 to 400 ft, depending on the structural position.
Slug-Catcher Design for Dynamic Slugging in an Offshore Production Facility
Authors: Miyoshi M. , Doty D. R. , Schmidt Z. 
Published: December 2007

SummaryA hydrodynamic model is developed for a typical offshore gathering system that consists of a pipeline, riser pipe, and slug-catching separator. The dynamic model is capable of determining the dynamic interaction between the slug-catching separator and the pipeline slug flow. In particular, a procedure is incorporated into the model for directly predicting the separator foam layer associated with the crude-oil stream. The model is capable of predicting all variables necessary for slug-catcher design.The influence of several variables—including the riser-pipe height, separator foam volume, and incoming slug size—on separator performance is examined. The analysis shows that each is critical to proper sizing of a slug-catching separator.
Pin-Point Sandfracturing - A Method of Simultaneous Injection into Selected Sands
Authors: Murphy W.B. , Juch A.H. 
Published: December 2007

Abstract
The conventional sandfracturing techniques first adopted by the Lagunillas Land Dist. of Cia. Shell de Venezuela in its Eocene wells, which had been perforated with four holes/ft over the full NOS interval, resulted in production increases which averaged some 700 per cent.
However, recent developments in completion technique not only have reduced completion costs, but also have resulted in a further appreciable increase in production. Production rates of the new completions over the first year after sand fracturing are some 60 to 90 per cent higher than those of the "conventional" completions.
It is believed that, by having a limited number of perforations and always providing an injection capacity which theoretically is greater than the total capacity of the perforations, there is a greater likelihood of fracturing all sands simultaneously.
It is estimated that the technique reduces completion costs by $3,700.

Introduction
Productive prospects have been known to exist in the Eocene formations on the eastern shore of Lake Maracaibo for some time, but it was not until the successful introduction of sandfracturing as a stimulation technique that these could be economically exploited. Cia. Shell de Venezuela's Eocene land activity has, in the main, been concentrated in the Lagunillas, Tia Juana and (to a lesser extent) Cabimas fields; (these three fields comprise the company's Lagunillas Land Dist. By Feb., 1959, a total of 155 Eocene wells had been completed as economic producers after receiving a sandfracturing stimulation treatment.
The productive shallow Eocene (B.1 sand), encountered between 1,000 and 3,000 ft, has gross intervals from 50 to 1,000 ft and is composed of interbedded shales and fine- to medium-grained consolidated sandstones. The sandstones make up, on the average, some 50 per cent of the section, but permeability (as shown by the Microlog) is restricted to some 60 per cent of the total sandstone development. The shallow Eocene is productive in the Lagunillas, Main Tia Juana and Cabimas fields.