bluuebunny/crossref_metadata_2025_split huggingface dataset:
Slug Test Data Analysis in Reservoirs With Double Porosity Behavior
Authors: Mateen Khalid , Ramey H. J. 
Published: December 2007

ABSTRACT
Pressure analysis for a slug test which corresponds to the flow period of a Drill Stem test is extended to wells in reservoirs with double porosity behavior.
The modelling of fluid flow within the reservoir is achieved by considering reservoirs having homogeneously distributed regions of primary (matrix) and secondary (fissure) porosity. The matrix acts as a source and fissures connect with the well. The well conditions include wellbore storage and skin effect.
Solutions were obtained for either pseudostate, or transient interporosity flow. The distinctive features of both solutions are identified. Results presented are applicable to both naturally fractured and layered reservoirs as long as only the high permeability layer conducts to the wellbore.
An interpretation method based on type-curve matching is proposed. Type curves based on pseudosteady or transient interporosity flow are presented. These type curves are similar to existing single layer type curves with the addition of interporosity flow lines indicating double porosity behavior. Application of the type-curve matching technique can provide the interporosity flow parameter λ, the storativity ratio, ω, in addition to transmissivity kh/μ, and skin effect S.
Ramey et al. presented type curves for a single homogeneous layer which required empirical correlation in terms of CDe2s and tD/CD. A formal solution showing wellbore pressure as a function of CDe2s and tD/CD for a homogeneous reservoir is presented. This permits discussion of the approximation involved in Ramey et al. study.
Exploration/Production Studies of the Devonian Gas Shales
Authors: McBane R. A. , Thompson T. W. 
Published: December 2007

ABSTRACT
Producers currently develop Devonian shale gas fields by drilling wells which offset a high productivity well. Remote sensing as well as various geophysical and geochemical techniques are sometimes used to site wells. Yet, productivity of the development wells can be highly variable. In an attempt to improve the production potential of these wells, the Gas Research Institute has undertaken a research program aimed at developing a better understanding of the geological features which control production in the shale, and which a wellbore must intersect or communicate with in order to result in higher productivity. A better understanding of these geological production controls is necessary to develop an exploration or stimulation methodology which will enable the producer to better locate and stimulate wells, and thus improve overall productivity of the field.
Porosity and Permeability of Tight Sands
Authors: Randolph P. L. , Soeder D. J. , Chowdiah Prasan 
Published: December 2007

ABSTRACT
Detailed analyses of more than 50 core samples of western tight sands have resulted in several unanticipated observations that are set forth in this paper. Core analyses performed under stress representative of producing conditions provided data on porosity, pore volume compressibility, stress dependence of permeability to gas, and slope of the Klinkenberg plot (permeability at constant net stress vs· the inverse of pore pressure). Scanning electron microscope (SEM) and petrographic microscope analyses were performed on samples cut from the ends of core plugs tested. The microscopic studies were explicitly directed toward observing the &lt;0.1 micron flow path openings deduced from permeability data.
The Computer Operated Rock Analysis Laboratory (C.O.R.A.L.) used for these measurements has been previously described.(1) Permeabilities are measured with a maximum pressure drop of 20 psi, much less than the pore pressure of 100 to 1500 psia. At the one microdarcy level, the standard deviation of a sequence of permeability measurements under constant conditions is typically 2% of the measured value. Resolution is a few naaodarcies· The accuracy of porosity measurement is about ± 2% of the reported value, but the sensitivity to pore volume change due to an incremental step in confining pressure is better than 0·1% of the pore volume. Thus, pore volume compressibility is measured to an accuracy of a few percent for a 1000 psi step in confining pressure.
The selection of tight sandstone samples for analysis involved an intentional bias. Namely, all samples were from depths that were either known to be gas producers or judged likely to be producers on the basis of wireline log analysis.
Perforation Placement Optimization: A Modified Hydraulic Fracturing Technique
Authors: Ahmed Usman , Thompson T. W. , Kelkar S. M. , Veghte Richard , Hathaway Scott 
Published: December 2007

ABSTRACT
The success of a hydraulic fracture treatment is greatly enhanced by control of the created fracture geometry. This problem is most serious if the boundary lithologies are not highly stressed as compared to the pay zone and do not form an effective barrier to upward migration. Reservoirs with this nature are common in many areas, including the Douglas Creek Arch, Green River Basin, Uintah Basin, San Juan Basin, and Central Alberta.
The Perforation Placement Optimization technique involves the determination of perforation locations such that the hydraulic fracture contact area within the pay zone is optimized. Where the upper boundary lithologies are not highly stressed as compared to the pay zone, the fracture will migrate predominantly upward into weak boundary lithologies. Where weak boundaries exist, the extent of the exposed fracture area that can be contained within the pay zone is strongly dependent on the location of the perforations and the gross height of the pay formation. Initiating the fracture below the pay sand (should lithology at the site be amenable to locating the perforations below the sand) can lead to greater fracture contact area within the pay sand and thus increased production. The work presented in the paper includes laboratory simulations performed on one meter cubic blocks, fracture design efforts, field implementation and transient pressure testing. The results of the laboratory tests helped in developing a model for optimizing perforation placement. This has been used in conjunction with a pseudo three dimensional fracture geometry and a pseudo two dimensional fluid flow hydraulic fracture model to design a field hydraulic fracture treatment. The treatment has been implemented in a well in the Douglas Creek Arch area, Colorado.
In-situ stress measurements in the well and special core testing on retrieved core material were performed to evaluate this well and the reservoir properties. In-situ stress distribution indicated the absence of stress barriers as expected. Reservoir engineering studies indicated that a significant increase in post-stimulation production can be expected by the use of perforation placement optimized hydraulic fracture treatment. The well was stimulated through perforations placed fifty feet below the pay zone and the created fracture was allowed to migrate upward into the pay zone. Post-stimulation transient pressure testing, fracturing fluid clean-up, and gas flow data indicate that the technique has been successfully applied.
This paper discusses the development, application, and evaluation of the modified hydraulic fracturing technique. This particular technique has been developed as part of a research program sponsored by the Gas Research Institute of Chicago and conducted by Terra Tek, Inc. of Salt Lake City and Chandler and Associates of Denver.
A Case Study for Exploration and Development of the Trenton Reservoir in Northwest Ohio
Authors: Schrider L. A. , Caprarotta D. W. , Natoli M. A. , Sawyer W. K. 
Published: December 2007

ABSTRACT
Independent oil and gas companies such as Beiden and Blake continue to search for new sources of hydrocarbon reserves. In many instances this has resulted in a re-evaluation of reservoirs that were considered depleted or of higher risk. The Trenton Limestone reservoir, located in the northwestern part of Ohio, is a case study of such an occurrence.
Through an extensive three-year evaluation of this area, both geologically and from an active drilling program, it was found that the area still contains vast amounts of hydrocarbons located in various types of geologic traps. While large amounts of oil and gas exist in this reservoir, ultimate production is sensitive to well completion and production practices. More specifically in the case of natural gas, pressure transient tests were conducted to determine whether gas reserves were sufficient to consider pipeline construction. Results of the reservoir tests verified the Trenton formation to be of low permeability in the range of one millidarcy, and porosity between 2 and 4 percent. An economic evaluation was then performed to determine what reservoir flow capacities, well spacing and economic criteria were required for successful engineering and economic development.
Conclusions of the case study showed (1) the need for high grading the well site selection through geological interpretation in order to expand the "sweet spots," (2) a need for stimulation treatments designed to enhance production, (3) a marginal return on investment with current economics, and (4) that gas pipeline construction should be delayed until larger reserves are found or until a more favorable gas marketing climate develops.
Practical Aspects of Devonian Shale Exploration and Development in Western West Virginia: One Operator's Experience
Authors: Murray W. G. , Woodfork L. D. , Wolfe R. T. , Heck W. A. , Fairchild Mark 
Published: December 2007

ABSTRACT
The discovery of new oil production (with associated gas) from the Devonian shales in western West Virginia in 1979 led to a tremendous increase in Devonian shale exploration and development in that area. The records of the West Virginia Geological and Economic Survey indicate that over 40% of drilling permits issued in 1982 were for various zones in the Devonian shales. With the decline in the gas market, the number of Devonian shale gas wells has declined in 1983. Nevertheless, activity in Ritchie, Pleasants, and Wood counties has remained very high. That activity is a source of considerable practical information on Devonian shale exploration and development. In fact, that play has provided an active testing ground for a variety of theories and techniques. The information presented in this paper is derived largely from the experience of one operator, Rendova Oil Company of Midland, Texas. That organization has been active in West Virginia since 1980 and, through the end of 1983, has drilled over 40 Devonian shale wells. That effort has been a continuous learning process in all phases of exploration and development. This paper will attempt to share that experience by describing the methods and techniques that have been tried as well as Rendova's current practices. The discussion will include exploration rationale, drilling methods, and completion and production practices. In addition, we will discuss what we see as the major problems that remain in developing oil and gas reserves in the Devonian shales.
Devonian Shale Production Data Analysis
Authors: Koziar Gregory 
Published: December 2007

ABSTRACT
Analysis of Devonian shale production histories without careful data screening can easily mislead even the most exacting investigator. Trends established from cumulative production data may not accurately represent the true production pattern. The difference between a good well and a poorer producer may be the result of fracture depletion or the length of actual producing time (among other factors) rather than a change in reservoir quality. The use of matrix controlled production information, derived from decline curves, appears to resolve this problem.
Evaluation of Naturally Fractured Gas Shale Production Utilizing Multiwell Transient Tests: A Field Study
Authors: Chen Chih-Cheng , Alam Javaid , Vozniak J. P. , Blanton T. L. 
Published: December 2007

ABSTRACT
A series of multiple well transient tests1 were conducted in a Devonian shale gas field in Meigs County, Ohio. Production parameters were quantified and it was determined that the reservoir is highly anisotropic, which is a significant factor in calculating half-fracture length from pressure transient data. Three stimulation treatments, including conventional explosive shooting, nitrogen foam frac, and high energy gas frac (HEGF)2, were compared on the basis of overall effectiveness and performance. Based on the evaluation of results, the nitrogen foam frac provided the most improved productivity. The study provided new type curves and analytical solutions for the mathematical representation of naturally fractured reservoirs and confirmed that the shale reservoir in Meigs County can be modeled as a dual porosity system using pseudosteady-state gas transfer from the matrix to the fracture system.
Coal as a Conventional Source of Methane: A Review and Analysis of 50 Wells in Two Production Areas in the Black Warrior Basin of Alabama
Authors: Dunn B. W. 
Published: December 2007

ABSTRACT
This paper presents a review of the actual production, sales, and economic data from two production areas with 52 wells developed by a joint coal industry' gas industry effort owned equally by Jim Walter Resources, Inc. (JWR), a subsidiary of Jim Walter Corporation of Tampa, Florida and Enhanced Energy Resources, Inc. (EER), a subsidiary of Kaneb Services, Inc. of Houston, Texas. The unique reservoir characteristics of the coal environment are described in brief, a comparison of actual methane production from coal with computer model predictions is presented, and the capital and operating costs are discussed with specific emphasis on the economic results.
This information differs from similar previous work in that economic vitality is now apparent whereas previous inquiries were essentially restricted to the technical reservoir engineering characteristics and the physical capability of coal to desorb (produce) methane. There are a number of published papers on this important technical aspect several of which are references for this presentation.
Production Area I (31 well production area) has been generating an operating profit for the past 21 months. Profits have increased substantially in the past year as a result of the completion of an 8" transmission line and reduced operating costs. Initial production commenced in late 19/9. A five well pilot project was evaluated for approximately two years before commercial development commenced in late 1981. A total of 31 wells were drilled by mid-1982. First sales commenced in February of 1982. Production Area II drilling commenced in January of 1983 with initial sales in March of 1983.
The economic viability is demonstrated based on actual operating profits over the past twenty-one months and current experience with respect to improvements in operational techniques and costs. These data are applied to the computer forecasts of long term dellverabilities for projections of expected economic performance.
Methane Production Characteristics for a Deeply Buried Coalbed Reservoir in the San Juan Basin
Authors: Jones A. H. , Ahmed Usman , Bush D. D. , Holland M. T. , Kelkar S. M. , Rakop K. C. , Bowman K. C. , Bell G. J. 
Published: December 2007

ABSTRACT
In cooperation with Tiffany Gas Company, Terra Tek cored the Fruitland Formation coal, lying at approximately 3100 feet, in the Glover Well #1 drilled in the southeast quarter of Section 2, T32N, R6W, Archuleta County, Colorado, within the northern portion of the San Juan Basin. The coal was fully water saturated. Laboratory tests were performed on the recovered cores and reservoir engineering tests within the coal before and after underreaming. Production data indicates the need to treat the coal with a deeply penetrating fracture to achieve acceptable gas production. However, coal fines migration is a serious problem to maintaining high production.
A Lumped Numerical Model for the Design of Hydraulic Fractures
Authors: Keck R. G. , Cleary M. P. , Crockett Alan 
Published: December 2007

Abstract
This paper presents some derivations and results of lumped numerical models which describe the growth and final geometry of hydraulic fractures. Using generally averaged resevoir and fracture parameters the model employs simple numerical routines to solve coupled non-linear ordinary differential equations for the pressure and dimensions of the fracture. Results of more complex models are included as a data-base in the spatial lumping process; thus the models represent all the essential features of fully 3-D, physically realistic hydraulic fractures. The present model provides a consistent description of fracture growth and includes the effects of mechanisms such as fluid loss, backstress, heat transfer, proppant and variable fracture geometry. Results are presented for a variety of typical field applications and show the general usefulness of these models for fracture design and on-site interpretation of observed versus predicted downhole pressures.
Offshore Gulf of Mexico Drilling From a Floating Vessel
Authors: Rushing H.H. , Poimboeuf W.W. 
Published: December 2007

Abstract
Zapata Offshore Co.'s Nola No. 1 proved drilling from a floating vessel in the Gulf of Mexico is feasible and economical.
Fishing and completion operations below 10,000 ft presented no significant problems.
The Nola No. 1 and the drilling method used are described.
The advantages and disadvantages of this method of drilling are presented.
The success of the Nola No. 1 should extend drilling operations in the Gulf of Mexico to water depths in excess of 200 ft.

Introduction
This paper describes the Nola No. 1 and the method of drilling into the submerged lands of the Gulf of Mexico from a floating vessel. The results to date and the significance of floating vessel drilling also is included.
Due to the complex geology of piercement-type salt domes in the Gulf of Mexico, the use of a floating drilling vessel reduces the risk and cost involved in proving locations for expensive drilling platforms.
Increasing well costs and sharply declining allowables in Louisiana have affected profits from offshore oil drilling operations. In view of this situation, it is essential that operators find ways and means to decrease offshore drilling costs. Present indications are that drilling from floating drill barges ultimately will help accomplish this objective.

History
The initial drilling from floating drill barges occurred offshore California in 1953. Since that time several floating drill barges have been built and several hundred-thousand ft of hole drilled from floating drill barges. The majority of drilling from floating barges has occurred offshore California, and several holes have been drilled offshore Trinidad, but none have been able to complete above water until the advent of the Nola No. 1.
Several sulphur core holes were drilled offshore Texas with small floating drill barges. The Nola No. 1 drilled the first well in search of oil or gas from a floating drill vessel in the Gulf of Mexico on State Lease 2548, West Delta Block 51, No. 2.
A Review of the Northern North Sea's Beryl Field After Seven Years' Production
Authors: Steele L. E. , Adams G. E. 
Published: December 2007

ABSTRACT
The Beryl oil field is a United Kingdom North Sea giant. Ultimate recovery is estimated to be 800 million barrels of oil and 1.4 billion cubic feet of gas. The field was discovered in 1972 and first production from the Beryl A platform commenced in June 1976, only 44 months from discovery. This paper reviews the geology and performance of the Jurassic Upper Beryl Sandstone which is the principal reservoir in the field. Production from the Upper Beryl through March 1984 amounts to 179 million barrels. Ultimate recovery from this reservoir should be optimal because of gravity segregation and high pressure rich gas injection.
The Interpretation of Interference Tests in a Reservoir With Sealing and Partially Communicating Faults
Authors: Stewart G. , Gupta A. , Westaway P. 
Published: December 2007

ABSTRACT
The interference test has been extensively used in North Sea reservoirs to assess communication between wells and in this paper the effect of fault planes on interference test response is analysed. In the first part simple systems of intersecting and parallel sealing faults are analysed using the method of images. The matching of observed and model response to give the reservoir parameters kh/μ and ϕμct is best carried out using a method based on implicit function theory originally proposed by Cannon and Dogru. In the second part the effect of a partially sealing fault between the active well and the observation well is analysed using a two-dimensional single-phase numerical simulator. A set of log-log type curves giving pD as a function of td for various values of a fault transmissibility parameter is given.
The Use of Computerised Information Systems in Development and Production Operations: Part 1
Authors: Eckenhausen M. R. A. 
Published: December 2007

ABSTRACT
Timely and reliable information is essential for managing the oil and gas Exploration and Production business. Information on the status and progress of development and production operations is vital for many disciplines in the organisation.
Computer Applications for Operations (CAO) are computerised information systems which support the planning and management of oil and gas field development and operations. These systems enable close monitoring, timely control and realistic evaluation and planning of operations. They stimulate "managing during the event" instead of "thereafter".
Pre- and Post-Stimulation Pressure Test Analysis and Its Role in the Design and Evaluation of Hydraulic Fracture Treatments
Authors: Cuesta J. F. , Elphick J. J. 
Published: December 2007

ABSTRACT
Current technical literature contains a mass of theoretical writing in specialized areas of pressure transient analysis. This paper presents a review of analysis and design methodology specifically applicable to stimulation work. Firstly, it identifies all the flow regimes encountered in pre-stimulation tests and presents formulae necessary to calculate the reservoir parameters required for fracturing treatment design. Secondly, it develops a new methodology for fracturing treatment design and thirdly, the paper logically analyzes the flow regimes in poststimulation flow tests and reviews the formulae for calculating the parameters of the hydraulically created fractures. A field example explains the practical application of the method covered.
A Novel Class of Surfactants with Extreme Brine Resistance and its Potential Application in Enhanced Oil Recovery
Authors: Stournas S. 
Published: December 2007

ABSTRACT
Most of the surfactants that have been employed or proposed for enhanced recovery applications are of the anionic type. It has been discovered that another class of surfactants, which incorporate both an anionic and a cationic center in the same molecule, possess interesting and unusual properties. These surfactants display great chemical and thermal stability and are totally immune to precipitation in the presence of monovalent and/or divalent cations; in fact, many of them are freely soluble in saturated solutions of sodium, calcium, or magnesium chlorides. In several instances they are capable of lowering the oil-water interfacial tension down to the millidyne region even in the presence of over 200,000 ppm of total dissolved solids. What is even more noteworthy is that in many instances the solubility behavior of these surfactants is opposite to the one usually observed, in that they are more soluble in concentrated brines than in dilute ones; in other words they display increased solubility as the salt content of the water increases.