bluuebunny/crossref_metadata_2025_split huggingface dataset:
Power Averaging for Block Effective Permeability
Authors: Journel A. G. , Deutsch C. , Desbarats A. J. 
Published: December 2007

ABSTRACT
A binary type permeability distribution with spatial autocorrelation is introduced to model the transition between shales and sand in a reservoir. The contrast between the two modal permeability values can be made realistically high, and the autocorrelation ranges can be made realistically large and anisotropic. A steady state, single phase flow simulation is run over a network whose block grids are informed from the previous permeability distribution. The resulting network effective permeabilities are plotted vs. the shale proportion and show that a power averaging process would yield a good estimate much more accurate than either the arithmetic average (power 1) or geometric average (power 0) traditionally used. Connections with percolation theory results are indicated.
Numerical Simulation and Reservoir Characterization of Multiphase Fluid Flow in Naturally Fractured Formations
Authors: Nakornthap K. , Evans R. D. 
Published: December 2007

ABSTRACT
A numerical simulation model is developed for characterizing three dimensional multiphase fluid flow phenomena in naturally fractured reservoirs. This new model treats the reservoir as a double porosity medium consisting of heterogeneous, isotropic primary rock matrix, and an anisotropic, heterogeneous fracture system. The statistical distribution in space and orientation of the fracture system is manifest in terms of a fracture permeability tensor. Such an approach provides a model which permits flow through the rock matrix and the fractures to be described simultaneously. A fluid interaction term is utilized to couple the flow between the rock matrix and the fractures. Gravity effects, capillary forces, and the fluid velocity in the fractures are also taken into account in the simulator model.
A Tensor Model for Anisotropic and Heterogeneous Reservoirs with Variable Directional Permeabilities
Authors: Leung W. F. 
Published: December 2007

Abstract
Permeability tensor is used to model fluid flow in complex reservoirs with multiple zones of directional permeability. The orientation and magnitude of the principal permeabilities may, in general, vary between different zones in the reservoir. This type of reservoirs cannot be studied with conventional simulators, which assume that the orientation of the principal permeability axes are fixed in the reservoir; thus, the coordinate axes can be oriented in the same direction as these principal axes.
Cross permeability effect arises when the coordinate axes are offset at an angle to the principal permeability axes. The cross permeability effect has been analyzed with theory and with numerical simulations. The importance of this effect has been established. Consistent nine- and nineteen-point finite-difference schemes, applicable to two- and three-dimensional simulations, respectively, are derived for the tensor formulation. The numerical tensor model has been validated with analytical solution for two single-phase flow problems.
The tensor model is used to study the grid orientation effect for a pattern flood in an anisotropic reservoir. Minimum grid orientation effect is observed with the tensor simulation. Finally, the tensor model is used to analyze the complex flow behavior of a reservoir with multiple zones of directional permeabilities. It is demonstrated that the conventional simple anisotropy model, which does not account for the cross permeability effect, could lead to serious error in interpreting the well response.
Pump-In Test Correlation Predicts Proppant Placement
Authors: Shelley R. F. , McGowen J. M. 
Published: December 2007

ABSTRACT
An empirically derived correlation has been proposed to assist operators in optimizing proppant placement in formations where treating pressures are unpredictable. By observing the pressure decline after an injection test, the average fracturing treatment parameters can be obtained to aid in optimizing the treatment design. A correlation between the pump-in test, the average fracture treatment leakoff rate, and the average treatment pressure increase rate has been established. From these averages, the maximum recommended job size and the critical sand concentration are determined.
This technique has proven to be a valuable tool to pinpoint proppant placement difficulties and has assisted in realizing the most effective stimulation treatments.
Improvement of Primary Cementing Bonding, Powder River Basin, Wyoming
Authors: Reeves N. K. , Wickham J. F. 
Published: December 2007

ABSTRACT
Historically, the major cause of poor cement bonding in the Powder River Basin has been the high permeability and low pressure of some zones. Drastically reducing the fluid loss of the cement slurry gave little improvement in bonding and increasing fluid loss material levels led to undesirably long thickening times and poor strength development. Physical shrinkage of cement was still suspected even when thixotropic and conventional expanding cement slurries were used, since cement continued to lose fluid to the formation after it was in place. Other accepted practices for bonding improvement, such as mud conditioning, rotation of the pipe, centralization, preflushing, and pumping in turbulent flow were also used. Even with these techniques, logging showed that bonding was less than adequate.
These problems with cement bonding have led to the use of a new additive. With this new additive, we have seen improvement in the bonding of cement to the formation faces and to the pipe. This additive (1) can be dry-blended with cement, (2) its reactivity in cement slurries is controllable over a wide range of temperatures without the use of special additives, and (3) is also compatible with most retarders and fluid loss additives.
Treatment Optimization of Acid Fracturing in Carbonate Formations
Authors: Olsen T. N. , Karr G. K. 
Published: December 2007

ABSTRACT
The use of alternating stages of gelled water and acid to obtain deeply penetrating, highly conductive fractures is common practice in carbonate formations.5 By monitoring bottom-hole pressure during this type of treatment, and using a pseudo-threedimensional simulator, a history match of stimulation pressure response can be made to help quantify various effects of the treatment, and to proceed a step closer to optimization. This paper presents bottomhole pressure data from several wells during acid fracturing. The data include treatments with various acids and varying proportions of pad-to-acid. The results of the simulations indicate that once acid is introduced into a hydraulic fracture system, certain parameters (which are assumed constant during conventional fracturing) can vary greatly. Therefore, onsite interpretation of bottom-hole fracturing pressure becomes more difficult. The potential may also exist to apply this information to proppant fracturing of carbonate formations. Acid may be used to etch the fracture face to reduce fracture friction pressure, thus creating an artificial control upon fracture height growth.
A Comparison of Solvent/Acid Workovers in Embar Completions—Little Buffalo Basin Field
Authors: Douglass B. C. , King G. E. 
Published: December 2007

ABSTRACT
A comparison of acid/solvent workovers in 24 wells completed in the Embar Formation, Little Buffalo Basin Field, has shown an alcohol-aromatic solvent mixture to be superior to ethylene glycol monobutyl ether (EGMBE) for enhancing acid stimulation of oil-producing wells. The alcohol-aromatic solvent mixture assists acid stimulation by breaking emulsions, as well as dispersing asphaltenes and sludges. Data are presented on comparative job costs and pretreatment production versus performance three months after treatment.
Automated Core Measurement System for Enhanced Core Data at Overburden Conditions
Authors: Keelan D. K. 
Published: December 2007

ABSTRACT
A new automated, computer-directed, core measurement system furnishes porosity, air permeability, equivalent non-reactive liquid permeability (Klinkenberg), and Forcheimer (turbulence) factor at programmable, sequential overburden pressures from 500 to 10,000 psi. The system is accurate, precise, and flexible and furnishes enhanced routine core data. Capabilities and limitations of the system are discussed. Data are presented for selected rock types and a graphical technique is proposed to relate the system measured porosity and permeability values to uniaxial strain conditions.
Fracture Diagnostics in East Texas and Western Colorado Using the Hydraulic-Impedance Method
Authors: Holzhausen G. R. , Egan H. N. 
Published: December 2007

ABSTRACT
The growth of a hydraulic fracture changes the hydraulic impedance at the point where the fracture intersects the well. The components of impedance can be defined in terms of fracture dimensions using elasticity relationships for a suitable fracture model. When these components are derived from measurements of pressure oscillations, the dimensions of the fracture can be calculated. This method was applied during minifracture testing in a tight gas sand well in East Texas and a coal seam methane well in Colorado's Piceance Basin. In both tests we observed shifts in oscillation frequencies and decay rates consistent with theoretical predictions. We were able to closely duplicate measured oscillations at different stages of fracture development using numerical models. Calculated fracture dimensions are in the 70 – 120 ft range. The tests established that the impedance method can be used for fracture evaluation under both cased-hole and open-hole conditions.
Stratigraphy and Petroleum Production of Middle and Upper Devonian Shales, Northwestern West Virginia
Authors: Sweeney J. , Filer J. , Patchen D. , Hohn M. 
Published: December 2007

ABSTRACT
Middle and Upper Devonian subsurface rocks in six counties in northwestern West Virginia can be divided into formal units of organic-rich black shales overlain by inorganic gray and greenish-gray shales. The section thickens west-to-east from 2,000 to 4,000 feet, including some fine sandstones and siltstones in the upper part.
Drilling since 1980 has discovered several productive intervals in this thick sequence. Generally, younger siltstones and shales down to the Huron Shale produce oil and gas; below the Huron, gas dominates. In map view, three broad oil and gas plays can be related to facies changes and to the Burning Springs Anticline. West of this structure, both organic-rich and inorganic shales produce gas; on and immediately east of the anticline, transitional facies (including black and gray shales, and younger siltstones) produce oil and gas; and farther east, siltstone bundles produce gas and some oil. Thus, completion-zone thickness ranges between 30-2,000 feet, with varied completion techniques.
Under a current Gas Research Institute contract, we are seeking possible relations among stratigraphy, completion intervals and techniques, initial potential (IP), and production. Preliminary studies in three counties indicate that gas IPs are highest when three or more formations are completed using nitrogen-fracturing. In one first year production study, the average shale oil well east of the Burning Springs Anticline is short-lived, declining by 95% of IP after one year before leveling off. A similar first year production study for 3 adjacent counties indicated less rapid decline of oil wells located along the Burning Springs Anticline.
Interference Testing of a Coalbed Methane Reservoir
Authors: Koenig R. A. , Stubbs P. B. 
Published: December 2007

ABSTRACT
The Rock Creek Methane from Multiple Coal Seams Completion Project is a research and development effort to advance the technology for economical production of methane from coal seams. Interference testing of a coalbed methane reservoir in the Warrior Basin near Birmingham, Alabama, gives insight into the unique characteristics of coal seams which influence production techniques and strategies. Permeability anisotropy, scale-dependent permeability and a large porosity-compressibility product were observed, all of which have important implications for well field and stimulation design.
Risks and Rewards of Well Drilling in the Devonian Shale
Authors: Yost A. B. 
Published: December 2007

ABSTRACT
This paper addresses the risks and rewards associated with Devonian shale gas wells in West Virginia, Ohio, and Kentucky. In the development thereof, both geo-science and geostatistical studies were pursued. A geoscience approach was used to identify the plays or groups of counties in each of the three states having similar geology. Within these plays, data from existing wells were acquired to quantify reservoir parameters (pressure, depth, well spacing, and productive interval), Afterwards, a dual-porosity, single-phase simulator was used to forecast expected performance from stimulated wells. Using these curves, reserves were estimated for each play.
A geostatistical approach was used to rank and quantify the risk (probability of production) associated with drilling and producing Devonian shale wells in selected plays. The rewards associated with new well drilling ventures were addressed in the economic parameters of payout time and return on investment. This study should be of interest to Appalachian independents and businesses considering development of shale gas wells. It should reduce considerable uncertainty relative to areas worthy of drilling and, within them, options for stimulation.
An Integrated Reservoir Description Method for Naturally Fractured Reservoirs
Authors: Gatens J. M. , Olarewaju J. S. , Lee W. J. 
Published: December 2007

ABSTRACT
This paper presents a method to estimate reservoir properties and gas in place using both pressure transient test and production data from naturally-fractured reservoirs. The reservoir engineer needs to determine reservoir characteristics and gas in place to design and evaluate stimulation treatments and to predict performance. We attempted to estimate these properties for naturally-fractured reservoirs using only production data, and we have found that it is rarely possible to develop a unique reservoir description due to the insensitivity of most routine production data to the dual-porosity reservoir characteristics. If both long-term production and pressure transient test data are available, a better reservoir description is possible.
We present one theoretical and two field examples to illustrate application of the method The field examples are for Devonian Shale gas wells but the method is applicable to any naturally-fractured oil or gas reservoir.
Strategies for Adding Low-Cost Natural Gas Reserves
Authors: Kuuskraa V. A. , Wicks D. E. 
Published: December 2007

ABSTRACT
During this period of natural gas surplus and declining prices, gas production, transportation, and distribution companies need low-cost reserves to maintain market share and assure economic survival. This paper discusses the attractiveness of three new sources of natural gas -- tight formations, methane from coal seams, and Devonian shales -- as options for low-cost gas reserves. In particular, the paper examines the role of improved extraction technology for increasing the recovery efficiency for improving the economics of unconventional gas, and for making these new sources competitive with conventional supplies.
The paper addresses three key questions of concern to managers of gas supply: How does unconventional gas compare economically with conventional gas from the Lower-48 onshore and offshore?How do the various unconventional gas sources compete among themselves?How might one formulate a "least cost" investment and production strategy for future natural gas supplies?
A Multi-Phase, Multi-Dimensional, Variable Composition Simulation of Gas Production From a Conventional Gas Reservoir in Contact With Hydrates
Authors: Burshears M. , O'Brien T. J. , Malone R. D. 
Published: December 2007

ABSTRACT
A two-phase, three-dimensional numerical model was developed to simulate the dissociation and formation of hydrates (composed of water and any mixture of methane, ethane, or propane). This model was developed in order to address fundamental questions regarding the feasibility of production schemes for the utilization of this unconventional energy resource, gas hydrate, whenever a gas reservoir is in contact with a hydrate cap. These questions are also important in the design of conventional hydrocarbon resource production schemes from geologic zones in which hydrates are predicted to be thermodynamically stable. Results of the simulations indicate that massive hydrate can be dissociated without an external heat energy source, and that the water evolved from hydrate disassociation does not impose limits on the producibility of the reservoirs. Additionally, gas from hydrates was shown to contribute significantly to the produced gas stream. These results support the continued evaluation of gas hydrates as a potential resource, and indicate that conventional in situ recovery schemes may be effective in releasing gas from zones of hydrate stability.
The Characterization of High-Energy Chemical Sources for Fracturing Devonian Shale
Authors: Mniszewski K. R. , Westcott P. A. 
Published: December 2007

Abstract
To find more effective means to enhance permeability in Devonian shales and other unconventional, tight, or naturally fractured reservoirs, new stimulation methods are being pursued that have the ability to create multiple radial fractures. The desired result is to create several fractures of sufficient length that intersection with the natural fracture system is highly probable.
Methods were developed for experimentally testing high-energy materials through the use of pipe tests and a borehole simulator. The results of these tests have shown that central initiation of the charges provides the best control and most consistent performance. Simulation of water tamped charges showed that water could significantly reduce performance due to quenching of unburned propellant. Recommendations are presented for obtaining maximum use of the available energy, consistent combustion behavior, and packaging considerations.
Geology and Production Potential of the Devonian Rhinestreet Shale: A Case Study of Three Wells
Authors: Kirr J. N. , Eddy G. E. , Locke C. D. , Smith J. B. 
Published: December 2007

Abstract
The BDM Corporation, under contract to the Department of Energy/Morgantown Energy Technology Center, is collecting geologic and engineering data on Devonian shales from 10 sites in the Appalachian, Michigan and Illinois Basins. As part of that project, three wells were drilled into, collected up to 60 feet of oriented core, and tested the Devonian Rhinestreet Shale in the Appalachian Basin. Those wells were: L. B. Southwick #1, Crawford County, Pennsylvania; P. D. McCartney #1, Mahoning County, Ohio; and A. B. Wilson #19, Wirt County, West Virginia.
The target areas for drilling the wells was based on data from the past EGSP. Shale thickness, thermal maturity, organic content and stress distribution were factors considered in target selection. Data collected from the wells confirmed the presence of the required factors in the target areas. Petrophysical testing of samples collected from the core indicate the porosity and permeability for the shale is low. The maximum porosity found was 6.8 percent and maximum permeability (at reservoir pressure and for a non-fractured sample) was 7.24μd.
Production testing in the wells yielded mixed results. The L. B. Southwick #1 initially had a production of 3,000 cf/d, but eventually fell off to 800 cf/d. Core samples from the P. D. McCartney #1 had large volumes of gas initially desorbed, but the well yielded no production when tested one week after completion. The A. B. Wilson #1 was able to maintain a flow rate of 8 Mcf/d.
The L. B. Southwick has been stimulated using explosives. Preliminary indications are that it had minimal effect on production. Plans are in progress to foam fracture the P. D. McCartney.
The Rock Creek Methane From Multiple Coal Seams Completion Project
Authors: Boyer C. M. , Popvich G. S. , Schraufnagel R. A. 
Published: December 2007

ABSTRACT
The Rock Creek Methane From Multiple Coal Seams Completion Project is a multi-year joint venture between the Gas Research Institute and United States Steel Corporation. The project objective is to evaluate and recommend methods to profitably produce gas from shallow, multiple coal seams. Overall project plans and specific results in the areas of geology, reservoir characterization, drilling and completion, and economic analysis are presented.
Poroelastic Concepts Explain Some of the Hydraulic Fracturing Mechanisms
Authors: Detournay E. , McLennan J. D. , Roegiers J. -C. 
Published: December 2007

ABSTRACT
This paper reviews the role of coupled diffusion/deformation phenomena in the various facets associated with hydraulic fracturing: breakdown, propagation and closure, and the assessment of these effects by means of Biot's linear theory of poroelasticity.
The poroelastic concepts are first recalled and emphasis is placed on the fundamental parameters needed. The importance of the coupling terms in the elasticity and diffusion equations is also stressed. The general equations are then simplified for two particular applications: one-dimensional column and radial symmetry.
It is then shown that the reservoir history as well as the percolation occurring prior to hydraulic fracture initiation affects the breakdown pressure value. Poroelastic models also explain the decrease of propagation pressure with pore pressure, as has been often reported in the field. Finally, the fracture closure is considered and the coupling mechanisms clearly demonstrate the width decrease as well as the increase of shut-in pressure with time.
The Drilling Performance Curve: A Yardstick for Judging Drilling Performance
Authors: Brett J. F. , Millheim K. K. 
Published: December 2007

ABSTRACT
The Drilling Performance Curve (DPC) is a simple yet powerful tool to assess the drilling performance in any given area where a consecutive series of similar wells have been drilled. All the information that is needed to perform the analysis is the sequence numbers of the well and the time it takes to reach a given depth.
This paper presents some typical examples of DPC's covering a study of over 30 different areas (onshore and offshore) including over 2000 wells. From the data, a simple model for the overall drilling performance was derived.
Three constants C1, C2 and C3 are unique to the DPC. From the numerical value of the constants, the drilling performance can be derived. For example, the C1 constant indicates how well an operation is prepared to drill a given location and/or how difficult the area is to drill. The C2 constant directly reflects the rate of learning. The C3 constant indicates the level of technology and organization for drilling in a particular area. This paper will present cases from poor to excellent drilling with the associated coefficients.
It will be shown that the DPC can dictate the strategy for a drilling program and what the economics of drilling a sequence of wells should be in a given area. It is suggested that the DPC become the yardstick for evaluating drilling, much as the decline curve is for production.
A Simplified Model to Predict Heterogeneity Effects on WAG Flooding Performance
Authors: Genrich J. F. 
Published: December 2007

ABSTRACT
A steady-state, analytical model is presented to estimate ultimate recovery from water-miscible gas floods in heterogeneous reservoirs. The model is used to investigate miscible flooding performance as a function of well spacing, rock-fluid properties, and reservoir description.
Results show that layers or streaks of relatively high vertical permeability within an otherwise homogeneous formation cause little change in overall recovery. Flooding performance, however, is generally improved by low permeability heterogeneities, depending on their relative vertical position. Discontinuous shales near the bottom or the middle of the reservoir enhance vertical sweep efficiency, while such shales near the top have much less effect on oil recovery.