bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Near-Term Supply and Demand Outlook for the Petroleum Industry
Authors: Winger John G. 
Published: December 2007

Abstract
This paper is in two parts. The first will deal with the current statistical position of the petroleum industry and the supply and demand outlook for the remainder of 1955 and the year 1956. Supporting the conclusions reached will be an explanation of forecasting techniques used.
The second portion is a discussion of several economic factors operating in the direction of chronic oversupply for the industry. Brought into focus is the impact of these elements on postwar developments and their probable effect in the near-term future.
The title of this paper announces that I am to discuss the near-term supply and demand outlook for petroleum. Near-term in this instance is intended to include the current year and 1956.With three-fourths of 1955 now history, we have a reasonably good idea what the final results will be - providing no abnormal factors suddenly enter the picture. But for 1956 it becomes necessary to bring into play various forecasting techniques.
While even the most carefully prepared forecast is admittedly subject to considerable error, it remains nevertheless a useful tool. For policy guidance a look-ahead is necessary. Actual conditions which subsequently deviate from the original estimate as a result of abnormal factors or faulty conclusions usually cast their shadows sufficiently early to permit timely adjustment in operating procedure.
Although specific volumes and rates of change will be discussed today, I shall consider the forecast successful if actual results in 1956 are within 2 percentage points of the predictions. Our primary objective is the direction in which the industry will move rather than the exact course.
Our forecasting is facilitated by the abundance of statistical data available. Consumption records from the past plus reliable figures for the number of petroleum consuming units expected to be in use permit satisfactory end-use studies. Barring some international incident, weather and general business conditions are the factors most likely to throw a forecast off.
Because oil heating represents such an important portion of petroleum demand, a change from normal winter weather conditions has a pronounced impact on consumption rates. With the last 8 winters averaging warmer than normal, there is the temptation to assume a continuation of that trend next year.
Improved Cementing of High Temperature Oil and Gas Wells Through Computer Applications
Authors: Crinkelmeyer Oliver 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
One of the primary problems in designing cement systems for deep, hot wells is the wide variation in performance of oil well Portland cements. Thickening times between Portland cements. Thickening times between similar API cements may vary by more than 100 per cent under severe well conditions. To help minimizes this problem, a special computer program was used to compare the working time of eleven oil well cements with their chemical analyses. This resulted in the isolation of the chemical factors which have the greatest effect on cement thickening time at a particular set of conditions. The equations developed provide the capability to predict cement working times under specified well conditions when a few chemical parameters of the cement are known.

Introduction
The trend toward deeper and hotter oil wells and the expanding search for geothermal energy has made it necessary to examine the performance of Portland Cement at higher performance of Portland Cement at higher temperatures and higher pressures. Under these conditions, slurry working times have not been as predictable as they are at lower temperatures and pressures.
Studies have been made which identify the compounds formed in set cement, and the physical and chemical conditions required to develop physical and chemical conditions required to develop stable compressive strengths at higher temperatures. However, very little has been done to define the parameters that determine the working time of retarded Portland Cement systems used in oil and gas wells. To help develop better high temperature retarders, and to explain fluctuations in existing data, the computer has been incorporated into high temperature cement testing. The results presented here show that not only can the computer be used to predict working times at various retarder concentrations, but it can also be used to define the parameters most important in determining the parameters most important in determining the working time of a particular cement system.
Simulation of Water- and Vapor-Dominated Hydrothermal Reservoirs
Authors: Mercer James W. , Faust Charles R. 
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 two-dimensional (areal), two-phase (steam-water) model for the numerical simulation of both water- and vapor-dominated hydrothermal reservoirs is presented. The model describes transport of heat and flow of compressed water, steam-water mixtures, and superheated steam in a porous medium. The continuity equations for porous medium. The continuity equations for steam and for water are combined and, assuming that capillary pressure is negligible and that conditions of local thermal equilibrium prevail, are reduced to two nonlinear partial differential equations in which the dependent variables are fluid pressure and enthalpy. The mass transfer (vaporization) terms are also eliminated when the continuity equations are combined.
The two partial differential equations are solved simultaneously using a Galerkin-finite element technique for the spatial terms and finite-difference techniques for the temporal terms. The model is applied to example problems consisting of a hypothetical hot-water reservoir and a hypothetical two-phase reservoir. Model calculations are compared with calculations from other numerical work involving a finite-element model that is restricted to the flow of compressed water, and a finite-difference model that is restricted to the vapor-pressure curve (that is, steam-water mixtures). Results indicate that this numerical model can be used to evaluate both types of reservoirs.

Introduction
Interest in new sources of energy has produced recent concern in the potential of produced recent concern in the potential of geothermal energy. Although evaluating this potential is important, even more important is potential is important, even more important is estimating the quantity of recoverable energy and the rate at which this energy may be recovered, for these values will ultimately aid in determining the economic feasibility of developing a geothermal reservoir. The recoverable energy in a geothermal reservoir may be estimated by using a mathematical model. In general, the model utilizes numerical techniques because of the complex nature of the equations and boundary conditions describing a geothermal or hydrothermal reservoir.
Hydrothermal reservoirs are classified according to the dominant fluid as either (1) a hot-water system or (2) a vapor-dominated system. Examples of hot-water reservoirs include the Wairakei, New Zealand, field and the Cerro Prieto, Mexico, field; vapor-dominated Prieto, Mexico, field; vapor-dominated reservoirs include the field at Larderello, Italy, and The Geysers, California.
Performance of the Hemlock Reservoir-McArthur River Field
Authors: Diver C.J. , Hart J.W. , Graham G.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
The pressure maintenance program by water injection in the Hemlock Reservoir of the McArthur River Field - Cook Inlet, Alaska - has been extremely successful. This is one of the largest offshore water injection projects in North America. Constant engineering study and surveillance coupled with an aggressive attitude on the part of the owners has resulted in a program which will maximize productivity and ultimate recovery from the reservoir.

Introduction
The McArthur River Field is located about 70 miles southwest of Anchorage, Alaska, in Cook Inlet (Fig. 1). The field was discovered in 1965 by the Union-Marathon Grayling Well No. 1-A. The field outline was subsequently delineated by ten additional exploratory wells drilled by four operators over a period of two years.
Current production is 104,000 BOPD from 49 wells which have been drilled from three platforms. Initial oil-in-place was in excess platforms. Initial oil-in-place was in excess of one billion barrels and cumulative production through June 1975 was about 250 production through June 1975 was about 250 million barrels.
The field was unitized as the Trading Bay Unit in August 1967 before development drilling operations had commenced. A unique feature of the Unit Agreement provided for equity redeterminations at specified intervals. This was a necessary and desirable vehicle to encourage unitization prior to development drilling and recognize subsequent data derived from development drilling. Union Oil Company of California is Unit Operator with Union, Marathon Oil Company and Atlantic Richfield Company as Suboperators for the three drilling and production platforms. The field has been effectively platforms. The field has been effectively engineered through the Unit Engineering and Planning Group which was formed in 1967 and has Planning Group which was formed in 1967 and has taken an active and continuing part in reservoir management throughout the life of the field. Engineering guidance led to the early installation of pressure maintenance facilities and to the installation and subsequent expansion of artificial lift on board the platforms. Engineering evaluation of the field-wide injection pressure maintenance project has been continuous pressure maintenance project has been continuous since its inception and engineering study led to the introduction in 1973 of an extremely successful infill drilling program which is still in progress.
Performance Matching for a North Sea Gas Field
Authors: Willcox P.J. , Riley H.G. 
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 offshore Leman Field is a complex, low permeability, highly faulted reservoir. Cluster development from platforms and uncertainties in the structural interpretation complicate matching of past performance with a simulation model. This paper sets out in detail the development of a history match proceeding by logical steps, each supported by independent evidence.

Introduction
The Leman Field is one of the world's largest offshore gas fields with nearly 14 TCF of gas originally in place. It was discovered in 1966, 30 miles offshore in the U.K. North Sea in 100 feet of water (Figure 1). Production commenced in 1969 and by Production commenced in 1969 and by mid-1975 the field had produced 1.5 TCF from 130 producing wells completed from ten platforms. Amoco (U.K.) Exploration Company is the operator for the East Leman Unit which comprises approximately the eastern half of the field (Figure 2).
Design and construction of a platform and the drilling of 12 to platform and the drilling of 12 to 16 wells there from requires two to three years. Compression facilities must also be ordered three years in advance to ensure timely delivery. These long lead times, combined with the ultra-expensive offshore operation in an hostile environment, require accurate long range predictions of reservoir performance.
The Rotliegendes Formation of Lower Permian age in the Leman Field is a highly faulted, low permeability, heterogenous sandstone, averaging 800 feet in gross pay thickness. The wide areal variation in rock characteristics and the cluster type development necessitated by offshore platform operations present a difficult problem in constructing a mathematical model that matches the observed pressure production performance. Wide vertical production performance. Wide vertical variations in porosity would normally require a three-dimensional model if a conventional permeability correlation were to be used. Synthesis of a two-dimensional model was made possible by use of the statistical parameter, coefficient of variation of porosity, parameter, coefficient of variation of porosity, correlated with the well test data.
Field Polymer Stability Studies
Authors: Bilhartz H.L. , Charlson G.S. 
Published: December 2007

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

Abstract
This paper presents the highlights of the results obtained from a field test designed to study shear degradation of polyacrylamide polymers. Recently, most major research polymers. Recently, most major research laboratories have been studying shear degradation in the laboratory; however, no extensive field testing has been reposed.
The field test consisted of injecting Pusher 700 into a well at four different rates Pusher 700 into a well at four different rates and back producing the polymer fluid. Laboratory measurements were made on location to determine polymer quality. These measurements were made in an oxygen-free environment in order to minimize chemical degradation of the polymer. Both surface and bottom hole sampling techniques were employed. Fluid samples were bottled under controlled conditions and brought back to our research laboratory for core flood experiments. Fluid entry profiling of the well was done before, during, and after polymer injection; and pressure transient tests were; conducted to pressure transient tests were; conducted to determine in situ polymer effectiveness. These tests indicated that the combined effect of shear degradation and calcium ion contamination due to anhydrite dissolution could reduce polymer effectiveness to an economically unattractive level.

Introduction
The influence of mechanical or shear degradation on the effectiveness of partially hydrolyzed polyacrylamides as mobility control agents has been receiving considerable attenbon. One of the earliest papers indicative of the importance of this involved the use of these polymers to control water production in oil polymers to control water production in oil wells. More recent studies have involved laboratory experiments designed to predict the degree of mobility control loss to be expected during the injection of polymers into a porous medium.
Coal Gas Resource and Production Potential of Subbituminous Coal in the Powder River Basin
Authors: Pratt Timothy J. , Mavor Matthew J. , DeBruyn Roland P. 
Published: December 2007

Abstract
This paper presents interim data for an ongoing project funded by the Gas Research Institute (GRI). The project objective is to obtain quantitative estimates of reservoir properties for a subbituminous Powder River Basin coal gas reservoir. The study is important since coal gas reservoir data are scarce in the Powder River Basin and for subbituminous coal in general.

Introduction
The subbituminous Powder River Basin (PRB) coal possesses characteristics that are dramatically different from the commercially developed areas in the San Juan, Warrior, and other basins. In particular, water content is very high, gas content is low, ash content is low, and absolute permeability is much greater, ranging from tens of millidarcies to more than a Darcy. Early in this decade, conventional wisdom concluded that large-scale commercial production of natural gas from Powder River coal seams was not possible. The coals were recognized as high permeability aquifers that could not be sufficiently “dewatered” to produce sorbed natural gas. Conventional wisdom was wrong, as has so often been the case when dealing with coal seams. Gas can be released from the coal matrix in commercial quantities even when gas content is low and permeability is high. This fact has been proven by numerous PRB operators over the past six years who have concentrated development along the basin's margins in thick coals typically 250 to 1,000 feet deep.
Redstone Resources, Inc. allowed GRI access to the Triton Federal #21C-2623 well located in Section 26, Township 52 North, Range 73 West, Campbell Co., WY. This well was cored and logged and is currently being tested. Redstone has also graciously allowed us to present data from the Twenty Mile #21C-3523 well located roughly 1 mile south of the Triton well in Section 21. Both wells are located on the eastern margin of the basin as illustrated in Figure 1, just west of large strip mines located near the outcrop. The specific coal target was the Canyon coal seam that belongs to the Tongue River Member (late Paleocene) of the Fort Union Formation. The depth of the Canyon coal seam is shallow in both these wells, 557 to 621 feet at the Triton location and 530 to 594 feet at the Twenty Mile location.
Selective Production of Horizontal Openhole Completions Using ECP and Sliding Sleeve Technology
Authors: Constantine Jesse J. 
Published: December 2007

Abstract
Openhole horizontal completions using external casing packers (ECPs) for zonal isolation are a growing trend in the oil industry. This style of completion is installed with slotted pipe or screen across production intervals that are isolated by ECPs. This method, integrated with standard liner hanger equipment set in one trip, allows for production at a lower completion cost, but it also minimizes the options for water shutoff or shutoff of a naturally depleting interval.
As companies continue to implement openhole horizontal completions, they look for alternatives that will provide precise zonal isolation while reducing installation time. This paper addresses an alternative isolation method wherein nonelastomeric sliding sleeves replace the slotted pipe between the ECPs. This method enables the operator to increase production while shutting off undesired intervals, thus fully optimizing the production program. With the use of coiled tubing and hydraulically actuated tools, sliding sleeve manipulation can be accomplished in long-reaching horizontal wellbores. The manipulation of these sleeves can increase production while shutting off undesired intervals.
These sliding sleeve isolation systems have been installed and successfully operated in numerous horizontal wellbores in the Rocky Mountain Region and worldwide. Sliding sleeve systems have been successfully manipulated using coiled tubing methods, even when placed at 90° angles, true horizontal. The capability of shifting sliding sleeves in the horizontal position by utilizing coiled tubing hydraulically actuated shifting tools will be demonstrated in the paper. This allows for the selective opening or closing of multiple sleeves in a single trip. Utilizing sliding sleeves to control well inflow can improve well economics by shutting off unwanted water or gas production.
Successful Completion Practices-An Experience Sharing Effort
Authors: Wang-Allen Yimei , Hill David G. , Fielding Robert Crane , Tesar Dennis 
Published: December 2007

Abstract
A study of Successful Completion Practices has been conducted in the J Sandstone of the Wattenberg Field of the Denver Julesberg (DJ) Basin. The data gathered from six operators suggests that reservoir quality plays an important role in well production performance. However, for the similar geologic, reservoir, and production conditions, the optimal fracture treatment design can result in significant addition in two-year recovery (TYR) and estimated ultimate reserve (EUR). Based on this study, the optimal treatment design parameters include an average proppant concentration of 3.25 ± 0.25 pounds per gallon (lb/gal) of proppant-laden fluid, pounds of proppant weight per foot of gross pay of 5460 ± 500 (lb/ft), and a pad fluid percentage of 20% ± 2%. Results also indicate that post fracturing performance of a well is more sensitive to the type of gel breakers utilized and post-frac shut in duration than to the type of gel used. By using "successful" instead of "average" completion practices, a 27% improvement in the average TYR benchmark and up to 70% improvement in cumulative cash flow can be achieved.
Mechanism for Gel Propagation Through Fractures
Authors: Seright R. S. 
Published: December 2007

Abstract
Many conformance control treatments rely on the ability of gels to extrude through fractures during the placement process. This paper describes an experimental investigation of the mechanism for propagation of a Cr(III)-acetate-HPAM gel through fractures. When large volumes of this gel were extruded through a fracture, progressive plugging (i.e., continuously increasing pressure gradients) was not observed. Effluent from the fracture had the same appearance and a similar composition as those for the injected gel, even though a concentrated, immobile gel formed in the fracture. The concentrated gel formed when water leaked off from the gel along the length of the fracture. The driving force for gel dehydration (and water leakoff) was the pressure difference between the fracture and the adjacent porous rock. During gel extrusion through a fracture of a given width, the pressure gradients along the fracture and the dehydration factors were the same for fractures in 650-md sandstone as in 50-md sandstone and 1.5-md limestone. A simple model was developed that accounted for many of the experimental results.
Production Well Water Shut Off Polymer Treatment in the Weber Sandstone – Ashley Valley Field, Uintah County, UT
Authors: Larson J. B. , Marchant B. P. , Cotton G. D. 
Published: December 2007

Abstract
The Ashley Valley field, located in the Uintah basin of northeastern Utah, produces oil from the Pennsylvanian Weber Sandstone in conjunction with a prolific natural water drive. Permeability heterogeneity is extreme. Matrix permeability in the reservoir rock ranges from 1 to 700 md. In addition, a substantial fracture network contributed to premature water breakthrough and the co-production of thousands of barrels of water per day from the underlying acquifer. This paper describes the application of a chromium (III) polyacrylamide gel system (MARCITSM) as a water shut off treatment in the Ashley Valley #2. In addition to conformance control from the reduction of excessive water production, the field exhibited potential for improved oil recovery from the polymer treatment.
A stratified reservoir model quantified a potential incremental target of 500,000 STB or 3.0% of original oil in place (OOIP) from uniform depletion of the lower permeability reservoir matrix by maximum pressure drawdown at the production wells. Production logging with a downhole video camera in the open hole completion interval confirmed that the highest permeability zones were not contributing any oil production.
Following placement of 2,200 barrels of the MARCIT SM polymer system in the Ashley Valley #2, oil production increased 6 BOPD (32%), water production decreased 2,950 BWPD (40%) and relative permeability to water decreased 70%.