bluuebunny/crossref_metadata_2025_split huggingface dataset:
Formation Evaluation in the Devonian Shale
Authors: Campbell R. L. , Truman R. B. 
Published: December 2007

ABSTRACT
A Devonian shale – specific geophysical log interpretation model was developed to extract as much geological and reservoir data as possible from a suite of air- or gas-filled-hole logs. Development of the methodology and evaluation of the geological and reservoir properties was supplemented with core data, formation tests, mud logging data, temperature logs and borehole TV logs acquired in Devonian shale wells.
This new analysis technique improves the identification of hydrocarbon bearing intervals and the types of formations associated with production. As a result, the analysis when combined with other data, allows a more effective selection and treatment of the hydrocarbon productive intervals.
Examples are shown which compare the computed lithology and porosity with core measurements. The computed results are also compared to mud logs; noise logs; temperature logs; borehole television data; production logs; and production tests.
Geologic Parameters Controlling Natural Gas Production From a Single Deeply Buried Coal Reservoir in the Piceance Basin, Mesa County, Colorado
Authors: Decker A. D. , Seccombe J. C. 
Published: December 2007

ABSTRACT
Commercial exploitation of gas occluded in coal reservoirs has been hampered by appropriate exploration, drilling, completion and production methods. The Deep Coal Seam Project located at the Red Mountain Site, Mesa County, Colorado is a field laboratory experiment directed to develop, improve, evaluate and communicate the technology required to produce gas from a deeply buried coal reservoir.
Regional geologic studies have established the Red Mountain Site as representative of the majority of the coalbed methane resource within the Piceance Basin. The project is focused on the D coal seam, belonging to the Cameo Coal group of the Williams Fork Formation, Upper Cretaceous Mesaverde Group. Thickness of the D coal seam ranges from 16 to 20 feet (5 to 6.5 m) throughout the site with an average drilling depth of 5500 feet (1800 m). This coal seam is medium-volatile bituminous in rank with an average gas content of 250 scf/ton (8 scc/gm).
The geologic conditions responsible for gas productive coal reservoirs are not fully understood. Data suggests that changes in coal maturation with time and burial depth can create a wide diversity of coal reservoir conditions. Drilling, completion and production methods should be tailored to coal reservoir characteristics, and accurate prediction of coal reservoir conditions need to precede coalbed methane exploitation.
The amount of gas accumulated in a coal seam will be a function of gas generation during the maturation process. Recovery of the gas will be a function of water saturation, cleat permeability, gas desorption characteristics, reservoir pressure, and diffusion rates.
A New Algorithm for Automatic History Matching Production Data
Authors: Watson A. T. , Lee W. J. 
Published: December 2007

ABSTRACT
We present a new algorithm for automatically history matching production or well test data. The algorithm is designed to be robust and efficient for history matching problems which have moderate to small numbers of unknown parameters.
The algorithm is based on Marquardt's modification of the Gauss-Newton method for minimization of least-squares functions. The implementation of the algorithm differs significantly from that of Marquardt. The performance of the algorithm is evaluated by history matching actual production data using an analytical dual-porosity model. Its performance is compared to the Gauss-Newton and steepest descent algorithms. We have found that our algorithm is very effective for these problems, but that Gauss-Newton and steepest descent are not suitable.
The Use of Pseudotime: Wellbore Storage and the Middle Time Region
Authors: Spivey J. P. , Lee W. J. 
Published: December 2007

ABSTRACT
The gas flow equation is often linearized to allow liquid type curves to be used to analyze transient tests of gas wells. In the absence of wellbore storage, drawdown tests are best analyzed using the pseudopies-sure-time linearization. Buildup tests, however, require the pseudopres-sure-pseudotime linearization for best results. If wellbore storage is present, both time and pseudotime should be used in a combination analysis for drawdown.
An Approach for Determining the Drainage Boundary of the Gas Wells Producing From Low-Permeability Gas Reservoirs
Authors: Shariff A. J. 
Published: December 2007

ABSTRACTThe Pictured Cliffs Sandstone is a large, low permeability, gas producing reservoir. It is considered to belong to a class of reservoirs known as volumetric or bounded cylindrical reservoirs where the wells are surrounded by impermeable (or semi-permeable) boundaries.In the Pictured Cliffs reservoir, the advancement of the drainage radius is shown to reach its maximum limit at the end of the transient period of the pressure decline versus time curve.
The Development, Testing, and Application of a Comprehensive Coal Seam Degasification Model
Authors: Sung W. , Ertekin T. , Schwerer F. C. 
Published: December 2007

ABSTRACT
A series of mathematical and numerical models to simulate the simultaneous flow of methane and water in a coal seam are presented. Transportation of methane is described using multi-mechanistic flow concept whereas desorption of methane from coal grain surfaces is formulated by a quasi-steady state kinetic model.
The simulator employs a two-dimensional, rectangular coordinate, point-distributed grid system and has options to accommodate a number of hydraulically fractured or unstimulated wells. In order to describe the flow in hydraulic fractures, a secondary one-dimensional grid is superimposed over the primary grid system. Flow equations in the matrix and finiteconductivity fracture have been solved simultaneously. The coupling between fracture and matrix flow equations is established via a "fluid loss" term.
The model is also capable of handling a number of horizontal boreholes. Multiple boreholes can originate from the bottom of a common shaft or from different shafts and they are allowed to intersect each other. Furthermore, options exist to include a number of impermeable geological barriers within the system.
An assortment of boundary conditions can be imposed on the system at its external boundaries as well as at its internal boundaries. Along these lines a special algorithm is devised and implemented successfully in order to be able to specify methane drainage rate from a virgin coal seam which has macropores that are originally 100% saturated with formation water.
The simulator has been tested under stringent conditions and found to be stable. Finally, the validity of the developed model has been verified against some existing field data.
Production Characterization of Tight Lenticular Gas Sands in the Rulison Area of Western Colorado
Authors: Mercer J. C. , Frohne K.-H. 
Published: December 2007

ABSTRACT
The U.S. Department of Energy's (DOE) Morgantown Energy Technology Center has performed an extensive reservoir simulation study on gas production from tight gas sands in the Rulison Field area of the Piceance Basin in western Colorado. Production behavior was modeled for the low permeability gas sands of both the Wasatch Formation and the lenticular portion of the Mesaverde Group. The study forecasted total gas production for Township 6S, Range 94W for 25 years, based on current well spacing regulations (160 acres [6.5 x 105m2] for Wasatch wells, 320 acres [1.3 x 106m2] for Mesaverde wells). The study also predicted the effects on gas recovery of reducing the well spacing to 80 acres (3.2 x 105m2) and 160 acres (6.5 x 105m2) for the Wasatch and Mesaverde, respectively. The reservoir study utilized a dual porosity, single-phase gas simulator to characterize reservoir behavior by history matching actual production performance from 23 Wasatch and 12 Mesaverde wells in the Rulison Field.
The study followed two extensive DOE field testing programs, a multiwell experiment and a special Mesaverde test well drilled in Naval Oil Shale Reserve No. 3. These DOE field tests provided geologic information and values for reservoir parameters that control production from this unconventional gas resource. In addition to the results from the two field experiments, the study used a detailed geologic analysis to help characterize the producing formations.
Add Reserves in Existing Shallow Wells by Deepening With Slimhole Drilling Operations
Authors: Hoffman C. M. , Lawrence P. W. 
Published: December 2007

ABSTRACT
Since the mid nineteenth century, over 500,000 wells have been drilled in the Appalachian Basin. While many of these wells have been plugged and abandoned, approximately 185,000 wells are still active producers. A majority of these active wells were drilled during the last ten years at depths averaging approximately 3,200 ft [975.4 m]. The recent decrease in oil and gas prices has made it increasingly difficult for producers to Justify new shallow drilling programs. There are, however, deeper productive horizons in many existing wells that have remained untapped. A number of unique procedures have been developed which allows the deepening, economically, of existing wells through existing casing as small as 4-1/2 in [114 mm].
Hydraulic Fracture Stimulation and Openhole Testing of a Deeply Buried Coal Seam in the Piceance Basin, Colorado
Authors: Logan T. L. , Seccombe J. C. , Jones A. H. 
Published: December 2007

ABSTRACT
Deeply buried coal seams (greater than 3000 ft [914 m]) are difficult and sometimes hazardous to test and complete due to coal sloughing, formation pressure anomalies and coal fine generation. Data collected during testing and stimulating two deep coalbed methane wells located at the Gas Research Institute/Resource Enterprises, Inc. "Deep Coal Seam Project" test site in the Piceance Basin, Colorado, is presented in this paper. A single thick coal seam was completed openhole in each well: Core data, reservoir data, in-situ stress measurements, and pre-stimulation calibration test data were collected at the site to use in the design of the fracture stimulation treatments for both wells. A nitrogen foam fracture fluid treatment was selected for the first well and a linear gelled water for the second well. Treatment pressures were monitored with a downhole quartz pressure transducer. Atypically high treating pressures were observed possibly indicating coal fines plugging at the fracture tip or increase in fluid viscosity caused by interaction of the generated coal fines with the fracture fluid. In addition, a comprehensive fracture diagnostic effort was employed during the fracturing of the second well; namely, triaxial borehole seismic, seismic televiewer, hydraulic impedance monitoring, gamma ray log (in conjunction with radioactive additives in the sand), and temperature log. The results indicate a vertical fracture was created parallel to the face cleat as expected.
Tailored-Pulse Fracturing in Cased and Perforated Boreholes
Authors: Cuderman J. F. 
Published: December 2007

ABSTRACT
A propellant-based technology, High Energy Gas Fracturing (HEGF), has been applied to fracturing through perforations in cased boreholes. The use of propellants that deflagrate or burn, rather than high-order explosives that detonate, permits controlled buildup of pressure in the wellbore. The key to successful stimulation in cased and perforated wellbores is to control the pressure buildup of the combustion gases to maximize fracturing obtained, without destroying the casing. Eight experiments have been conducted in a tunnel complex at the Department of Energy's Nevada Test Site. This location provided a realistic in situ stress environment (7 MPa [1000 psi] overburden stress) and access for mineback to directly observe fracturing obtained. Primary variables in the experiments include propellant burn rate and amount of propellant used; presence or absence of liquid in the wellbore; in situ stress orientation; and perforation diameter, density, and phasing. Fracture surfaces propagate outward along lines of perforations, then gradually turn toward the hydraulicfracture direction. Fracture lengths of 3m (10 ft) or more are observed. It is shown that such fractures, with proper choice of propellant and perforation design, can be created with no attendant casing damage.
Measurement of Coalbed Properties for Hydraulic Fracture Design and Methane Production
Authors: Boyer C. M. , Stubbs P. B. , Schwerer F. C. 
Published: December 2007

Abstract
A single-zone coalbed methane well was installed in the Mary Lee Coal Group in the Warrior Basin, Alabama for research purposes. Laboratory and field tests were conducted to establish criteria for containment of an induced hydraulic fracture. Following production from the well, a wing of the induced fracture was mined-out and observed directly.
Coalbed Methane Geostatistical Analysis: A Method for Ranking Well Productivity
Authors: Pratt H. R. , Robey E. H. , Wojewodka R. A. , Mercer J. C. 
Published: December 2007

ABSTRACT
A study was conducted which demonstrated the use of geostatistical techniques for identifying correlations between geologic parameters and gas production for 38 coalbed methane wells completed in the Blue Creek coal seam of the Oak Grove (U.S. Steel) field in Alabama. Data used in the study consisted of production information for these wells along with geologic information for the area of interest. Results indicated that four geologic parameters showed statistical correlations with gas production: the well elevation (a proxy variable for permeabilty), the number of lineament intersections within 250 feet (76 meters), the thickness of the Blue Creek coal seam, and the length of the nearest lineament. The study suggested that the results obtained for wells in the primary degasi-fication grid could be extrapolated to wells in an adjacent area having lineament orientations similar to the primary grid. A method by which each well could be characterized based upon its production profile (i.e., production versus time relationships) rather than a simple one-number summary, such as 4-year cumulative production, was also identified.
Propagation of Hydraulically and Dynamically Induced Fractures in Naturally Fractured Reservoirs
Authors: Blanton T. L. 
Published: December 2007

ABSTRACT
The purpose of this project has been to provide a basis for selecting fracturing treatments that will cross and connect as much of the natural fracture system to the wellbore as possible. Interactions between induced and existing fractures have been examined in scaled laboratory experiments under different angles of approach and states of stress. For hydraulic fractures, when the angle of approach was 30 degrees, existing fractures tended to open, diverting fracturing fluid and preventing the induced fracture from crossing. At angles of approach of 60 and 90 degrees, hydraulic fractures tended to cross existing fractures when the differential stress was high enough. Dynamic fracturing tests were run for conditions where hydraulic fractures opened existing fractures to determine if more constructive crossing interaction could be obtained, but triaxial stresses tended to suppress cross-cutting dynamic fractures, and no crossing behavior was observed. An elastic solution for the stresses in the interaction zone has been used as a basis for a hydraulic/natural fracture interaction criterion. The criterion compares favorably with the experimental results. It has been used to delineate areas where crossing and opening interactions could be expected in Devonian shales of the Appalachian Basin by combining it with existing data on the state of stress and fracture patterns. Under preliminary assumptions, the criterion predicts opening of natural fractures in the central and western parts of the basin. In the northern and southern parts of the basin, there are zones where crossing interaction can be expected. Tectonic models were used to extrapolate fracture patterns from site-specific core data gathered from 33 EGSP wells. Fracture systems oriented for crossing appear to be associated with two tectonic features: a Precambrian failed rift system that has been reactivated periodically and deformation associated with the Appalachian orogeny.
The Influence of Crack Velocity During Brittle Fracture
Authors: Krugman D. G. 
Published: December 2007

SUMMARY
This paper investigates the effects of different commercially available processes for fracturing consolidated rock structures by applying the concept of Brittle Fracture. Brittle Fracture occurs when there is little or no plastic deformation of the material before the material fails.
The available commercial fracturing processes are grouped into three categories, namely (1) Hydraulic fracturing treatment using pump trucks and fluids, (2) High Energy Gas Fracturing (HEGF) treatment utilizing propellent mixtures deflagrated in situ to generate a fast pressure surge of gases and (3) Explosive-based treatment that makes rubble of the rock in the wellbore vicinity.
The fracturing processes vary in the duration of the energy-loading process and the maximum pressures achieved during the event (See Fig. 1 and Ref. 1). Figure 1 illustrates the order of magnitude of difference in time and pressures of the different fracturing processes.
The "Mechanism of Brittle Fracture of Rock" (Ref. 2) as developed by Dr. Z. T. Bieniawski and widely accepted in the mining industry as a basis for understanding rock failure, is applied to oilfield wellbore and reservoir conditions to evaluate the fracture geometries and penetrations of the different fracturing processes. The concept of Brittle Fracture also is applied to the mine-back and pressure-time records of open-hole and cased-hole tests of the fracturing processes conducted by Sandia National Laboratories at the Nevada Test Site (Ref. 3, 4 and 5).
The effect on wellbore and reservoir stimulation is investigated by applying Darcy's modified radial and linear flow equations (Ref. 6) to reservoir flow conditions. By applying the most applicable fracturing process for the wellbore and reservoir condition, one can maximize the evaluation and stimulation efforts of a well completion attempt.
Radial flow enhancement is best achieved by fast fracturing processes such as High Energy Gas Fracturing and explosive-based treatments, while linear flow enhancement is best achieved by hydraulic fracturing treatments. Radial flow enhancement treatments may stimulate reservoir productivity by 1 to 3 times, while linear flow enhancement treatments may stimulate reservoir production by 6 to 10 times.
Gravel Pack Repair with Wireline Devices
Authors: Carroll J. F. , Neal M. R. , Parker W. B. 
Published: December 2007

ABSTRACT
Gravel pack logs have been used previously to detect voids in gravel pack completions. These voids must be eliminated to achieve an optimum completion. Techniques using wireline repair devices are generally faster than conventional repair techniques, and formation damage resulting from fluid loss could therefore be reduced.
A study was made under laboratory conditions to develop wireline tools that could be used to eliminate these voids in order to save the rig time associated with conventional methods of repair. The tools, which were developed under laboratory conditions, were run in field completions. Field gravel pack logs have confirmed the success of wireline devices to repair gravel pack voids.
Replacement Costs of Domestic Oil and Gas Reserves
Authors: Kuuskraa V. A. , Godec M. L. , Morra F. 
Published: December 2007

ABSTRACT
The costs of adding new reserves of oil and gas have changed dramatically over the past several years. Changes in the costs of drilling, the prices for oil and gas, and the sources for new oil and gas supplies have combined to fundamentally alter the economics of replacing reserves. This paper provides a historical perspective on these changes, a review of the current situation, and a look into the future on this key area of concern to the petroleum industry.
Theoretical Study of Coning Toward Horizontal and Vertical Wells in Anisotropic Formations: Subcritical and Critical Rates
Authors: Chaperon I. 
Published: December 2007

ABSTRACT
Stable cones created by a horizontal well drilled with maximum clearance from the unwanted fluid are studied (Muskat9 type approach, using pertinent viscous flow potential), yielding practical values for the critical rate per unit length of a horizontal well, and for the critical cone elevation, depending on both vertical and horizontal permeabilities, oil thickness, both fluid gravities, and oil viscosity. Critical rate weakly decreases when vertical permeability decreases.
The same type of analysis is repeated for a vertical well completed over a very short interval (modelized as a point source) also with maximum clearance from the gas cap or water table, yielding values of critical rate and cone height for the vertical well. In this case the critical rate slightly increases when vertical permeability decreases.
The outcome of a comparison between both types of wells shows that a critical cone comes closer to the horizontal well than to the vertical well. Also horizontal wells generally allow higher critical rates than vertical wells, however this advantage lessens with increased anisotropy. Very simple formulas are provided to evaluate what gain in critical rate may be obtained from a horizontal well.
The Determination of Optimum Completion and Production Conditions for Sand-Free Oil Production
Authors: Peden J. M. , Yassin A. A. M. 
Published: December 2007

ABSTRACT
It is important for the selection of optimum completion conditions and the evaluation of optimum production conditions to understand the factors contributing to and controlling sand production. Many factors such as the geometry of the perforation, the inherent formation strength and the effective-stress distribution in the vicinity of the perforation tunnel during production must be considered to determine the maximum sand free rate possible from a given well.
A prediction model has been developed to predict sand stability in friable formations from stress analyses around a perforation tunnel. Failure or instability of the perforation tunnel was studied in terms of the conditions for failure initiation.
The application of the model allows evaluation of the optimum completion characteristics of shot density and pattern, tunnel length and diameter, and production conditions, to achieve a maximum sand free production rate. The concept of a ‘stability ratio’ is introduced to predict the degree of instability which can be anticipated under specific production conditions.
Application of Multilayer Testing and Analysis: A Field Case
Authors: Kuchuk F. J. , Shah P. C. , Ayestaran L. , Nicholson B. 
Published: December 2007

ABSTRACT
Recently developed well testing and analysis techniques for multilayered reservoirs to estimate individual-layer permeabilities, skin factors, and pressure are discussed with regard to their applications to a two-layered reservoir. The multilayer testing technique consists of a number of sequential flow tests with downhole flow rate and pressure measurements at the top of each layer using the production logging tool.
The analysis techniques are based on convolution and the use of nonlinear regression to fit the measured downhole flow rate or pressure data with a layered reservoir model.
This paper presents a field example that is used to estimate layer parameters. The results are compared to those from conventional analyses.