bluuebunny/crossref_metadata_2025_split huggingface dataset:
Application of Pressure Transient Analysis in Steam Injection Wells
Authors: Messner Gregory L. , Williams Richard L. 
Published: December 2007

ABSTRACT
The determination of the swept volume in a steam displacement process provides an early means to evaluate the project's progress. By determining the volume occupied by steam, and knowing the cumulative volume of steam injected, the heat losses from the injection interval and the ensuing heat efficiencies can be estimated. These parameters dictate the performance efficiency of the displacement project.
Getty Oil Company has run pressure falloff tests in several steamflood projects located on the west side of the San Joaquin Valley. The first project tested had undergone nine months of continuous steam injection, with little apparent increase in oil production or wellhead temperatures in the displacement wells. The test data was analyzed using the theory presented in Eggenschwiler, et al.'s1 work and Walsh, et al.'s3 analytical procedure. The initial results are very encouraging and more-or-less consistent with the previous theoretical studies, implying that this type of testing can be a valuable tool for early evaluation of the viability of a steamflood project, with a minimal shut-in time and expense.
Several more falloff tests were run in displacement projects having more history, temperature observation wells, and better control of reservoir properties. These tests were run to verify the analysis procedure and determine steamflood characteristics in projects designated as commercial successes. A simple numerical study using a thermal model was also used to further analyze the principles of the underlying theory and demonstrate the applicability of this particular simulator to pressure transient problems. The results of the numerical study are included.
Reflection Seismology as an Exploration Tool for Fractured Zones in Gas-Bearing Shale — Cottageville, West Virginia: A Case Study
Authors: Ruotsala James E. , Williams Richard T. 
Published: December 2007

ABSTRACT
The Cottageville, West Virginia, gas field produces from the Lower Huron Member of the Ohio Shale formation of the Upper Devonian. The production results from increased permeability caused by anomalous fracturing of the shale. A normal basement fault, which lies below the fracture zone, may control fracturing in the shales.
Seismic reflection data obtained in the area in 1977 show the fault extending up into the Ordovician. These data are also analyzed for seismic velocity and attenuation anomalies associated with the gas-producing fracture zone. Gas production occurs in an area several miles long but only about one mile wide. Increased fracture intensity and presence of gas in the shale within this limited area serve to decrease the shear strength of the rock, decreasing the seismic velocity. Similarly, greater attenuation of the high-frequency components of the seismic wave can be expected. Examples from the Cottageville data showing basement structure and seismic velocity and attenuation anomalies associated with gas production are presented.
An exploration rationale for prospecting for eastern shale gas is developed. Although the total area covered by gas-bearing shales in the eastern United States is large, individual gas fields within this area are relatively small. Reflection seismology is used to target specific exploration wells after reconnaissance by other methods has been done.
Glacial Loading: A Cause of Natural Fracturing and a Control of the Present Stress State in Regions of High Devonian Shale Gas Production
Authors: Clark James A. 
Published: December 2007

ABSTRACT
It is likely that ice sheets contributed significantly to natural fracturing and hence gas production in low permeability Devonian shale. The large ice sheet of the last ice age caused considerable deflection of the lithosphere. Predicted horizontal tensional stresses south of the glacial limit resulting from this crustal flexing exceed the tensile strength of Devonian shale. Glacially induced fracturing is therefore expected in these regions which correspond with regions of historical gas production. The north-south variation in observed stress ratios is also explained by the glacial model. Lineaments and faults will perturb locally the glacially induced stresses and, when coupled with the glacial model, offer an exploration rationale.
Preliminary Resource Assessment of Coalbed Methane in the U.S.
Authors: Byrer Charles W. , Malone Rodney D. , Hunt Arlen E. 
Published: December 2007

ABSTRACT
Throughout the history of gas exploration and development in the U.S., potentially recoverable quantities of methane from unconventional sources such as coalbeds have been largely excluded from potential gas supply surveys. This is attributable to the lack of data about the resource, technology, and economics of its recovery. In order to provide answers, DOE initiated the Methane Recovery from Coalbeds Project (MRCP) to characterise the gas-in-place for various coalbeds and associated sediments.
Preliminary resuits of the DOE Methane Recovery from Coalbeds Project reveal that many of the coal regions in the United States have significant volumes of coalbed methane. Preliminary gas-in-place resource estimates were made based on the volume of coal-in-place and on direct methane-desorption data. It has been conservatively estimated that 14 percent of the 48 conterminous states are underlain by coal-bearing rocks(1). Over 50 wells have helped to update the estimates of methane in these various coal regions. The evaluation of 11 basins by the MRCP reveal that the total resource estimated in-place is between 57 and 285 Tcf· Those basins showing high potential include the Northern Appalachian, Arkorna, Piceance, Warrior, Illinois, and Greater Green River.
Methane Resources of the Unmineable Coal Seams in the Richmond Basin
Authors: Topuz Ertugrul , Wilkes Gerald P. , Karmis Michael , Lucas J. Richard , LeVan Donald 
Published: December 2007

ABSTRACT
The objective of this study was to evaluate the potential of the methane resource associated with the Richmond Coal Basin of Virginia. The study indicated that the basin may have a potential of 0.7 to 1.4 trillion cubic feet of methane resource that may be of considerable value to the Richmond area and the nation.
Tight Gas Research and Development: The Industry Perspective
Authors: Brashear J. P. , Elkins Lloyd E. , Haas Mark R. 
Published: December 2007

ABSTRACT
Low permeability gas reservoirs ("tight gas sands") are abundant in the U.S. Economic recovery of the gas in these formations requires reservoir stimulation, usually massive hydraulic fracturing. Significant investigations of tight gas sands by the National Petroleum Council (NPC)(1), Lewin and Associates(2), and the Gas Research Institute (GRI )(3) have agreed that, although some formations can be profitably produced with existing technology, improved reservoir diagnostic and stimulation techniques are required to realize the full potential of the resource.
Most major operators and well-service companies conduct research and development to improve tight gas technology. A survey of tight gas research managers in eight companies was conducted to determine their R&D priorities and the constraints under which they operate.
The responses of the R&D managers showed a high degree of consensus on tight gas R&D objectives, company priorities, decisionmaking criteria, current activities, and constraints. The representatives of six operating and two service companies stated that they prefer R&D that produces high "payoffs" in the near term, with low-to-medium risk of R&D failure. This characteristic leads industry to focus current R&D on measurement and prediction of fracture geometry (shape and orientation), particularly in the lower-risk blanket-type (as opposed to lens-type or lenticular) formations. Despite the presence of price incentives for production of tight gas and the potential of high return, the constraints on available personnel and funds for R&D limit industry's willingness to conduct the long-term, high-risk R&D needed to produce the lenticular resource. The industry R&D personnel interviewed were familiar with, and generally endorse, those long-range and high-risk objectives and priorities of the Federal tight gas research program that complement university and industry efforts.
GRI Program for Tight Gas Sands Research
Authors: O'Shea Patrick A. , Murphy William O. 
Published: December 2007

ABSTRACT
In mid-1981, the Gas Research Institute (GRI) drafted comprehensive programs for research directed toward increasing the national supply of natural gas from unconventional sources. Low-permeabi1ity (tight) gas sands are one of these sources. GRI's pre-draft planning for the tight gas sands program was for a duration of about one year and included workshops with advisors from the natural gas industry. The resulting program plan for tight gas sands research is oriented to industry participation and field testing. Research results are freely distributed to a wide variety of users.
The tight gas sands program is initiating in 1982; planning updates by GRI are on an annual cycle. GRI is proceeding with six projects for tight gas sands research, involving analyses for producing natural gas from tight blanket sands that are presently considered as non-commercial. The program plan is comprised of a sequence of projects relating to resource identification, formation evaluation, fluids and proppants investigations, fracture design, reservoir modeling, and staged field tests with technology transfer. Accelerated research work is scheduled for 1983, with emphasis on field evaluations beginning in 1984.
This paper describes the philosophy, objective, and content of the GRI program plan, which is currently scheduled through 1988. Accomplishment of the program is expected to provide for significant advances in tight gas sands research. GRI is a nonprofit scientific organization which contracts applicable research work to others for benefit to the natural gas industry and to natural gas consumers.
Methane Recovery From Deep Coalbeds in the Book Cliffs
Authors: Allred Larry D. , Coates Ralph L. 
Published: December 2007

ABSTRACT
A project jointly funded by Mountain Fuel Supply Company and the U.S. Department of Energy is being conducted to show the commercial potential of recovering methane gas from deep coal seams in the Book Cliffs coal field in Central Utah. Recovery technologies are being defined and economic analyses of methane recovery are being made. Three vertical wells have been drilled to depths ranging between 3,000 and 4,110 feet. Desorption measurements on core samples indicate gas contents up to 440 cu ft/ton. All three wells have been subjected to hydraulic stimulation treatments but with drastically different results. One well has demonstrated gas production of 20 to 30 mcfd from a 13-foot coalbed. A second well was extremely "tight" and very little production has been achieved to date. The third well has not been put on continuous production, but gas production rates of 120 mcfd averaged over a short testing period were measured.
Fracturing Using a Stabilized Foam Pad
Authors: Ainley Brian Roland , Charles J. Gary 
Published: December 2007

ABSTRACT
The development of stabilized foam has created the potential for a widely suitable fluid in water-sensitive and/or under-pressured reservoirs. Foams, to date, have proved to be effective fracturing fluids in shale, coal and tight sands, but proppant placement has been a problem. With the use of a stable foam pad, proppant can be transported with a crosslinked fluid at optimum concentrations for maximum fracture conductivity. The stable foam pad has excellent fluid-loss characteristics and will retain energy to flow back the gelled water stage. With the use of a stable foam pad and crosslinked proppant-carrying fluid, the advantages of both fluids can be utilized in creating a highly conductive fracture with minimal formation damage.
In coal seams where proppant may not be needed due to low closure stresses, stable foam alone can be an efficient fracturing fluid. With higher viscosities and better fluid-loss control properties than previous foams, a wider and longer fracture can be generated with similar volumes of fluid.
Recovery of Gas From Hydrate Deposits Using Conventional Technology
Authors: McGuire Patrick L. 
Published: December 2007

ABSTRACT
Methane hydrate gas could be a sizable energy resource if methods can be devised to produce this gas economically. This paper examines two methods of producing gas from hydrate deposits by the injection of hot water or steam, and also examines the feasibility of hydraulic fracturing and pressure reduction as a hydrate gas production technique. A hydraulic fracturing technique suitable for hydrate reservoirs is also described.
Unconventional Ideas About Unconventional Gas
Authors: Rose Walter , Pfannkuch Hans Olaf 
Published: December 2007

ABSTRACT
Vast quantities of natural gas exist as solid hydrates in the world's permafrost and deep sea environments. Russian experts estimate potential resources in excess of 107 TCF natural gas. Geophysical inference and direct sampling seem to substantiate the existence of hydrates where thermodynamic conditions are favorable. Their ubiquity provides an interesting link to another unconventional hypothesis of unconventional gas supply, namely the abiogenic origin of deep earth gas. A method to evaluate the abiogenic hypothesis is to compare the isotopic, trace element and compositional signature of hydrate samples from deep lake sediments in basins over crystalline basement rocks (Lake Superior) and over sedimentary rocks in connection with a producing, petroliferous province (Lake Michigan). Because of the complex relations between in situ dissociation and production of the free gas phase actual extraction methods will be technically complicated. A method to circulate warm surface water through a set of injection and withdrawal wells in deep sea hydrate deposits promises some advantages over conventional offshore drilling practices. Even if only a fraction of the claimed hydrate resources are accessible and producible the absolute amount is still very large compared to all other conventional and unconventional gas resources.
A Hydrodynamic Analogy of Production Decline for Devonian Shale Wells
Authors: Pullé Christopher V. 
Published: December 2007

ABSTRACT
Several studies on production decline curves have shown that an exponential or hyperbolic curve adequately fits production decline data for Devonian shale wells. Attempts to characterize the production decline based on open flows, rock pressures, and specific shale production mechanisms have also been made. This paper seeks to provide a genesis of the decline curves with the use of a simple hydrodynamic analogy. Some physical factors critical to well productivity are also examined.
Production Systems Analysis of Vertically Fractured Wells
Authors: Meng Hai-Zui , Proano Eduardo Antonio , Buhidma Ismail M. , Mach Joe M. 
Published: December 2007

ABSTRACT
A systematic approach is presented for generating transient inflow performance relationship curves for finite conductivity vertically fractured wells. A semi-analytical model was developed to simulate dimensionless wellbore pressure drop and dimensionless pressure loss through the fracture vs. dimensionless time at constant-rate of production for wells intercepted by a finite-conductivity vertical fracture. Flowing bottom hole pressure can be predicted at any time period using these dimensionless variables. System average pressure at any stage of production can be obtained through material balance calculations.
A straight line reference curve was observed at all times provided that the real gas pseudo-pressure function is used to plot m(pwf(t))/m(p¯R(t)) vs. qg(t)/qgmax (t). The advantage of normalizing the dimensionless variable in termas of pseudo-pressure function is that only one straight line relationship is obtained throughout the entire production life of the reservoir. This provides a more simple means for performance prediction purposes.
The major contribution of this paper is the provision of a valuable tocl to study the sensitivity of fracture design parameters on ultimate well performance. The economic benefits of this approach can be substantial.
Optimization of Hydraulic Fracturing Techniques for Eastern Devonian Shales
Authors: Swartz Greg 
Published: December 2007

ABSTRACT
A laboratory test program was performed to evaluate the physical characteristics of Devonian Shale reservoirs from six wells in the Appalachian Basin, four in Ohio and two in New York. As hydraulic fracturing is a mainstay for increasing well production, the interaction between fracturing fluids, the formation, and proppant in the induced fracture becomes of prime importance. In analyzing the physical characteristics of the core material, three types of tests were performed: physical properties, matrix permeability damage, and fracture conductivity damage.
Results of the physical properties testing indicate that the typical Devonian shale matrix was dense and of low porosity, averaging 2.75 gm/cc and 6 percent, respectively. In situ permeability values of the tested samples averaged 66 μd, with 9 of 13 samples below 10 μd. Fracturing fluid matrix damage tests were performed with three different fracturing fluids for comparison: a water-based gel (cellulose thickener), a nitrogen foamed liquid (75 percent quality), and a brine/CO2 mixture fracturing fluid. Recovery was based on the calculated ratio of final permeability to initial permeability. Results from these tests show better recoveries from those samples exposed to the nitrogen foam, up to 18 percent. Fracture conductivity damage tests were performed with the same fracturing fluids. Results of these tests give recovery values of 35 to 100 percent. Nitrogen foam gave better results. All testing of reservoir material, except some basic physical properties, was conducted at simulated in situ conditions.
Successful Deep Openhole Cement Plugs for the Anadarko Basin
Authors: Dees John M. , Spradlin William N. 
Published: December 2007

ABSTRACT
A cement plug is placed above a non-retrievable fish when a hole is to be sidetracked. The plug provides support and strength to commence deviation from the original hole. Setting a firm high strength cement plug in order to sidetrack is a difficult task. The volume of wellbore and displacement fluids are quite large compared to the volume of cement in the plug. This situation is compounded in a deep hole. Placement of the cement slurry without contamination from wellbore and displacement fluids becomes an exceedingly difficult task. Several cement plugs may be required before a successful plug is set.
The techniques described were developed for sidetracking purposes. However, they can be applied in setting other types of cement plugs.
Parameters involved in properly setting an open hole cement plug are defined in detail in this report. The primary objective of this work was to define techniques and materials necessary to optimize success with deep hole cement plugs. Important factors in successfully setting an open hole cement plug are hole condition, mud condition, cement composition, and placement technique. An example is included describing a successful technique used to set deep open hole cement plugs in the Anadarko Basin.
Fracture Width—Design vs. Measurement
Authors: Smith Michael B. , Rosenberg Randi J. , Bowen Jerry F. 
Published: December 2007

ABSTRACT
Current fracture designs are based on choosing fracture height and using a 2-D approximation to calculate fracture width. There are however, two approximations which can be used, leading to greatly different designs in terms of fluid volume, pad volume, etc. Given this discrepancy, accurate in-situ measurements of fracture width are needed to help define fracture geometry.
The purpose of this paper is to present measurements made with a downhole closed-circuit television camera during a fracture stimulation (without proppant) of an oil bearing sandstone formation in an effort to investigate the applicability of the two fracturing models. Data is presented showing fracture width as a function of height and pressure. The measured widths are briefly compared to different design theories.
Local Mesh Refinement for Finite Difference Methods
Authors: von Rosenberg Dale U. 
Published: December 2007

ABSTRACT
A method of local mesh refinement has been developed in which additional nodes are used only in regions where they are necessary. The extra mesh lines are not extended across the entire simulator as in the usual current practice. Refinement of a two-dimensional element, herein defined as the rectangle formed by mesh lines with nodes at the vertices, consists of bisecting it in each coordinate direction, thus dividing the original element into four smaller, but similar ones, and creating five nodes. The resulting smaller elements may themselves be refined by the same procedure. An element must be refined if two adjacent elements of the same size have been refined or if one smaller adjacent element has been refined. Three configurations of five nodes each which arise in current refinement methods also appear in the new procedure. In addition, a configuration of six nodes also occurs. Finite difference analogs for all configurations were developed.
An extensive study of local mesh refinement near a well was made for the repeated five spot in a homogeneous reservoir with unit mobility ratio. Results of the finite difference solutions were compared with the analytic solution. Generally, it was found there should be at least two consecutive increments of the same size between changes in increment size. When this practice is followed, a local minimum in truncation error occurs at each node where there is a change in increment size. The more accurate solution obtained in the vicinity of the well by use of smaller increments there results in a more accurate solution also in the coarser unrefined mesh. Some improvement elements with the well node as a vertex. An effective refinement was one using increments which were one half and one fourth the size of those in the coarser mesh. Four small increments were used nearest the well, and four was obtained by one refinement of the four mid-sized ones were used between these and the coarsest mesh. Results are presented to aid the reader in selecting the extent of refinement he desires.
An Improved Method for the Determination of Pseudo-Relative Permeability Data for Stratified Systems
Authors: Simon Andrew D. , Koederitz Leonard F. 
Published: December 2007

ABSTRACT
A procedure for modifying relative permeabilities for use in an areal model becomes necessitated in reservoir cases for which vertical equilibrium pseudo functions are not applicable and the displacement process is dominated by viscous horizontal flow. In practice, the areal model representation of stratified flow in such cases will lie between the extremes of the performance of a homogeneous layer of parallel-average permeability and the performance of a series of non-communicating layers. To date, the only analytical method specifically developed to approximate viscous flow in a stratified reservoir with an areal model is attributed to Hearn. This method employed the assumption of a unit mobility ratio displacement to generate pseudo relative permeability curves reflecting an instantaneous change from non-wetting phase to wetting phase production at each layer breakthrough. Due to this assumption, the history match procedure involved correcting for both the effects of crossflow and subordinate non-wetting phase production after breakthrough. A technique has been developed to account for the effects of subordinate phase production in a non-unit mobility ratio displacement occuring in noncomrnunieating layers. This adaptation is an improvement to the original method of Hearn, providing both a closer initial approximation to reservoir fluid flow in stratified systems, as well as affording a consistent basis for history matching through adjustments to relative permeability.