bluuebunny/crossref_metadata_2025_split huggingface dataset:
An Integrated Team Approach for Improving Company-Wide Stimulation Design and Quality Control
Authors: Nagel N. B. , Arnold W. T. , McCoy M. W. , Scott S. L. , Thrasher T. S. 
Published: December 2007

ABSTRACT
In 1987, Phillips Petroleum Company identified well stimulation as an area where costs were high and efficiency could be improved. Efforts to improve performance were addressed by creation of the Formation Completion Task Force. This task force has undertaken a variety of training and technology transfer tasks and, most importantly, has served as a vehicle for change. The inter-office teamwork fostered by the task force has allowed rapid implementation of new technologies throughout the company. Specific case histories are given which show the impact that these changes have had on improving well production as compared to previous stimulation efforts. The tangible results of these efforts have been an acceleration of production and an increase in reserves, which have been realized through a doubling of average sand concentrations pumped, company-wide implementation of the forced closure concept, and intense, on-site quality control of fracture treatments. Since 1989, the impact of these measures on world-wide operations is estimated to be well over 150 million dollars in accelerated cash flow and added reserves.
The Integrated Team Approach to the Optimization of a Mature Gas Field
Authors: Hooi H. R. , Goobie Lorraine , Cook Robert , Choi Joseph 
Published: December 2007

ABSTRACT
From 1988 to 1991 an integrated surface and subsurface simulator was designed and constructed to assist the petroleum engineer in the development and management of gas fields. The developed Gas Field Planning Tool, GFPT, allows the user to define the business environment strategies of a field since it has not been customized for any particular field.
This paper briefly describes the GFPT functionality and the application of the simulator in the study of several development scenarios for a maturing gas field in a multi-disciplinary team enviroment.
Determining Optimal Capacity and Recovery From Gas Reservoirs: Impact of Permeability Contrast, Tubing Size, and Compressor Horsepower
Authors: Dougherty E. L. , Chang Jincai 
Published: December 2007

ABSTRACT
This paper presents optimal solutions, obtained with commercially available software, that provide answers to a selected six important questions encountered by gas developers. The questions are concerned with optimizing; (1) development of a mix of reservoirs, (2) tubing size, (3) spare capacity, (4) intraformation gas migration, (5) dual completions and (6) division of production between compressor stations. The solutions show that economic benefit obtained from determining an optimal solution will usually far outweigh the cost of collecting data, validating a model and making computer runs.
Capillary Pressure Characteristics at Overburden Pressure Using the Centrifuge Method
Authors: Ajufo A. O. , Daneshjou D. H. , Warne J. D. 
Published: December 2007

ABSTRACT
This paper contrasts the results of centrifuge capillary pressure measurements determined at ambient and overburden pressures. The effects of centrifugal forces and overburden pressure on the integrity of well consolidated uniform rock samples are minimal. However, unconsolidated sands, poorly consolidated sandstones, and friable cores are susceptible to deformation and grain re-arrangement, while vuggy cores are susceptible to surface drainage. The severity of these occurrences, which depend on sample lithology and the magnitude of centrifugal forces, can be minimized or avoided by proper jacketing and application of overburden pressure.
Relative Permeability and Capillary Pressure Data From Non-Darcy Flow of Gas/Brine Systems in Laboratory Cores
Authors: Civan Faruk , Evans R. D. 
Published: December 2007

ABSTRACT
Most of the previously reported work for extracting relative permeability and capillary pressure data has been indirect and based on reservoir core history matching which requires iterative numerical solutions of inverse problems until a satisfactory match is obtained. The direct methods are based on integral formulations of the equations describing the fluid pressures and saturations for laboratory cores and they do not require numerical solution methods for differential equations involved in the indirect methods. Therefore, the numerical stability and accuracy and the history matching problems associated with the indirect methods are eliminated.
In the present study, a new direct method for determination of relative permeability and capillary pressure data from unsteady-state non-Darcy fluid displacement in laboratory cores is presented. The new method takes advantage of the internal fluid displacement data that can be obtained by noninvasive techniques in addition to the usual external fluid rate and pressure data. The mathematical interpretation method developed in this study enables the determination of relative permeability and capillary pressure simultaneously without the inherent limitations of the previous methods. It is also computationally more convenient, based on a semi-analytic solution of an algebraic formulation of the flow through porous media. Because it is an algebraic formulation it also provides a numerically more accurate interpretation of laboratory core data. The method is applied with typical gas/brine data to demonstrate its capability.
Identification and Comparison of True Net Fracturing Pressures Generated by Pumping Fluids with Different Rheology into the Same Formations
Authors: Wright T. B. , Aud W. W. , Cipolla C. , Meehan D. N. , Perry K. F. , Cleary M. P. 
Published: December 2007

ABSTRACT
Different hydraulic fracture simulators predict different levels of net pressure, especially with respect to changing/varying fluid viscosity. The level and distribution of net pressure in the fracture must be known to accurately calculate fracture width, which has major implications for the correct calculation of the other fracture dimensions and the location of the proppant. Fracture width also determines the amenability of the formation being fractured toward accepting higher proppant concentrations.
This paper presents various examples of measured data from fracture treatments pumped in a variety of reservoirs, using fluids with widely varying viscosities. The primary aspect of the dataanalysis technique is the evaluation of friction-pressure data obtained from strategically-timed shut-ins and flow-rate changes. Many of the examples are from research environments where more stringent data gathering techniques were used, as opposed to most commercial situations where such procedures are rarely allowed due to (often unjustified) fear of negative impact on treatment effectiveness.
Bottomhole pressure is sometimes seen to change significantly with changing theology. However, shut-ins done immediately after such pressure increases strongly indicate that these increases are due to changing frictional pressure in the perforation-adjacent, near-wellbore region (e.g., due to tortuosity) connecting the wellbore to the fully developed fracture. If this near-wellbore friction is subtracted from measured pressure, the data indicate relative insensitivity of net fracturing pressure to fluid rheology.
The primary implications of these observations are: that commonly-ascribed needs for high viscosity fluids are justified only when near-wellbore problems exist, and that viscosity cannot be used to control fracture geometry (versus proppant placement in the fracture).
Accelerated Fatigue Phenomena in High-Horsepower Turboexpander Wheels
Authors: Russell T. G. , Duncan Colin , Ershaghi Behrooz , Dyason G. J. , Agahi Reza 
Published: December 2007

ABSTRACT
Radial expansion turbines or "turboexpanders" are widely used in the gas industry in both process and power recovery applications. The increasing cost of plant inputs such as power and feedstocks, coupled with abrupt swings in plant throughput as a function of markets and pipeline system linepack, places a premium on tuxboexpander designs capable of operating efficiently and reliably over a broad range of operating conditions.
High horsepower turboexpander wheels which operate over a wide speed band are subject to fatigue failures if the wheel's operating frequency window is too narrow. The fatigue failure mechanism is accelerated by resonance. Appropriate wheel designs, which will deliver extended operating life, may require modified wheel hub profiles and the use of higher strength alloys. Strict control of forging and heat treatments must be maintained to ensure metallurgy of a uniform high quality.
This case study outlines the systematic methods adopted in identifying the cause of turboexpander wheel failures at the Karr Creek Gas Plant, and the engineering design revisions required to eliminate them.
Effect of Orifice Meter Orientation on Wet Gas Flow Measurement Accuracy
Authors: Ting V. C. 
Published: December 2007

SUMMARY
In many unprocessed natural gas measurement locations between wellheads and process plants, water and condensate are entrained with the gas flow. How measurement at these locations is used for reservoir management, monitoring, control, production allocation, and custody transfer. The accuracy of wet gas metering is of great importance, especially allocation and custody meters, because of the monetary value of the large volume of unprocessed natural gas being transferred daily.
This paper presents the effect of orifice meter orientation, installed in horizontal, upflow, and downflow positions, on the accuracy of flow measurement. Tests were conducted at the Chevron Petroleum Technology Company's Air How Facility in La Habra, California. Two-inch orifice meters with three different orifice/pipe diameter ratios (beta ratios) were selected for testing. Air and water were used as flowing fluid, and they were controlled and measured by sonic nozzles and turbine meter, respectively.
The effects of liquid entrainment on metering error are characterized at each operating position. The results of this study indicated liquid entrainment in orifice meters always contributes lower gas flow rate measurement, up to −2% at vertical upflow position. In order to minimize metering errors in wet gas flow measurement, an orifice meter should be installed in a horizontal position with a mid-range beta ratio.
Currently, there is no acceptable correlation to adjust low liquid entrainment in orifice metering flow. To maintain metering accuracy, the author recommends improving system design to avoid liquid entrainment in orifice meters. In addition, unaccountable liquid condensate accumulation in the meters is a potential loss of revenue.
Dynamic Gas Hydrate Formation and Properties of Diamondoids
Authors: Holder G. D. , Enick R. M. , Jones J. W. , Reiser J. A. , LeBlond C. R. 
Published: December 2007

ABSTRACT
Two solids which can form or deposit in gas transmission lines, gas hydrates and diamondoids, were investigated.
A high pressure apparatus has been designed which enables the rates of hydrate formation from ice to be determined under dynamic gas conditions. The rate of hydrate formation was found to increase with gas flow rate at gas temperatures slightly above the ice point, but this effect was diminished at lower temperatures.
Vapor pressure curves for two diamondoids, adamantane and diamantane, were determined between 25 C and 300 C. Solubilities of these diamondoids were also determined in various organic liquid solvents and dense CO2.
Analytical solutions to the rate of hydrate or diamondoid removal from pipelines containing significant hydrate or diamondoid deposits were also derived.
Improved Performance in Aquifer Gas Storage Fields Through Reservoir Management
Authors: Hower T. L. , Fugate M. W. , Owens R. W. 
Published: December 2007

Abstract
Active water influx into a gas reservoir reduces ultimate recovery from that which would be expected under volumetric conditions due to reduced sweep efficiency and residual gas which is trapped at high pressure. Previous investigations on Gulf Coast gas fields presented in the literature1,2 have demonstrated reservoir management techniques which can increase the expected ultimate recovery over 10% of the original gas in place. This paper presents new work in the form of a detailed case history which extends this emerging technology into aquifer gas storage reservoirs. By their nature, aquifer gas storage fields are water-drive reservoirs. Thus, prudent reservoir management is required to reduce the detrimental effects of trapped gas and poor volumetric sweep.
A detailed reservoir characterization and numerical simulation study are presented for a mid-continent aquifer gas storage field. It is demonstrated that rate optimization during both injection and withdrawal cycles can significantly improve the performance of the storage reservoir. Performance improvements are realized in the form of a larger working volume of gas, a reduced cushion volume of gas, and a decrease in field water production. This research has significant implications for the business facet of the natural gas industry. By utilizing these reservoir management techniques, gas storage operators will be able to minimize their base gas requirements, improve their economics, and determine whether the best use for a particular storage field is base loading or for meeting peak day requirements.
Prediction of Long-Term Deliverability in Tight Formations
Authors: Mattar Louis , Hawkes R. V. , Santo M. S. , Zaoral Karel 
Published: December 2007

Abstract
Those experienced in the natural gas industry know that tests conducted early in the life of a well, in a tight formation, tend to yield optimistic deliverability forecasts. It is not uncommon for producers to report to government agencies, or to purchasers, the results of such deliverability tests, and then to discover, after the well has been placed on production, that rates and pressures have declined continuously to as low as 10-20% of the initial test quantities.
By understanding what controls this transient flow behavior, sometimes called "flush" production, and by collecting appropriate pressure data during the deliverability tests, we can make use of pressure transient analysis to accurately predict the "stabilized" gas rates that the well will eventually achieve.
It is to the producers' advantage to make practical use of current deliverability testing regulations, and to apply the latest state of the art technology to Pressure Transient Analysis. From the pressure buildup data, and the informed use of ADVANCED well test analysis software, one can obtain completion and reservoir characteristics to accurately predict the well's longterm deliverability behavior.
Unlike conventional reservoirs, production from tight formations must be forecast utilizing the "transient flow" equations rather than the "stabilized flow" equations. It is no longer necessary, nor is it acceptable, to use simplistic reservoir models.
Realistic forecasts must take into account the reservoir characterization and model description derived from flow and buildup test analysis. The transient flow forecast in tight formations may control the economics of production, and must therefore be modelled rigorously
Equivalent Drawdown Time for Pressure Buildup Test Analysis for Hydraulically Fractured Wells
Authors: Liao Yizhu , Lee W. J. 
Published: December 2007

ABSTRACT
This paper presents an "equivalent drawdown time" for hydraulically fractured wells. This new equivalent time is derived from a general elliptical flow model. This new equivalent time is helpful in post-fracture pressure buildup test analysis for wells with finite-conductivity fractures including wellbore storage and fracture-face skin. Examples are provided.
Optimizing Matrix Acidizing for Near-Borehole Remediation Using the CIRF Reaction-Transport Simulator
Authors: Chen Yueting , Mu Jun , Chen Wei , Davis D. , Ortoleva P. 
Published: December 2007

Abstract
A new two-dimensional reaction-transport code CIRF (chemical interaction of rock and fluid) is used to design matrix acidizing fluids. Processes accounted for include aqueous phase, mineral and gel reactions, temperature and salinity-corrected activities, texture-dependent Darcy flow, thermal transport, dispersion, effective reacting surface, diffusion limited kinetics and nucleation. CIRF has built-in thermodynamic and kinetic databases, transport parameters, new adaptive gridding and mixed finite element-finite different schemes and user-friendly graphical I/O for complex lithologic geometries.
Examples are shown in which well designed fluids enhance permeability through matrix dissolution; permeability damage is shown to result from formation collapse induced by excessive dissolution or the formation of plugs through precipitation. Effects of injected fluid composition and velocity and initial formation state are illustrated in the case of a shaly sandstone. Flow self-focusing is shown through flow-reaction coupling via texture-dependent permeability to produce dissolution fingering and holes.
Extended Production Testing of the Bearberry Ultra-Sour Gas Resource
Authors: Chernik P. S. , Williams P. J. 
Published: December 2007

Abstract
The Bearberry ultra-sour resource is estimated to be 61-75 Bern (2-3 Tcf) of natural gas with an H2S content In excess of 90%. Hence Bearberry is a potential in place source of approximately 100 million tonnes of sulphur. In 1991/92 this source of sulphur was brought into production (two wells into a nearby processing plant) to assess the viability of long term production of this resource.
At reservoir conditions (37 Mpa, 118 C) the 90%+ H2S gas contains significant dissolved elemental sulphur which precipitates as liquid sulphur (analagous to retrograde condensation) in the formation and the wellbore during production. During the production test, approximately 6 tonnes/day of elemental sulphur were precipitated. Unique equipment and production techniques were required in order to produce the Bearberry gas stream. For example, continuous circulation of sulphur solvent was required to prevent plugging of tubing and flowlines.
From a reservoir engineering perspective, the concern was long term well productivity impairment due to precipitation of elemental liquid sulphur in the reservoir as the reservoir pressure declined. In order to quantify the productivity decline a one meter interval was completed in the 11-35 well. This technique enabled a region of low pressure to be created in the near wellbore area of the reservoir which simulated the long term performance of future commercial wells. Permanent gauges with continuous surface readout were used to measure downhole temperatures/pressures and track performance with time.
This paper describes how the reservoir data was evaluated and the basis for the conclusion that it is technically viable to produce the Bearberry resource.
Development Planning of the Coalbed Methane Gas: A Future Energy Prospect in Java, Indonesia
Authors: Nugroho Wisnu , Mucharam Leksono 
Published: December 2007

Abstract
During 1980-1990. the economic growth of South East Asia countries ranged between 5.5% to 7.9% per year. Along with this development, the energy would be an important element to maintain or increase this growth. In Indonesia, for instant, the growth of energy demand is estimated to be 6% during years of 2000 to 2010. For natural gas demand especially, Indonesia will consume about 1.1 Tcf/year. Java Island, in this case, would become the highest increase of energy demand, from 393 MMcf/D in 1989 to 1200 MMcf/D by 2010. By that time, the natural gas production from both non associated gas and associated gas reservoirs in the Northwest Java basin from where the large amount of gas is produced, is predicted to decline.
In order to overcome this problem, another prospective gas resources that could be exploited is coalbed methane. This kind of prospective gas resource has been found in large reserve in the of Northwest Java basin, epecially in Talang Akar formation, some of the coalbed methane layers found in Talang Akar posses overpressure condition. In this formation, it is found that the vitrine reflectance of coal, ranges from 0.5% to 1.9%. The gas resources from coalbed methane reservoir in Indonesia is estimated about 213 Tcf, and of 33.4 Tcf of this volume is found in Northwest Java basin area. Until this time, these coalbed methane deposit have not yet been developed or exploited commercially.
The economics and the technical aspects of the coalbed methane exploitation and its properties in Talang Akar formation are evaluated and discussed in this paper.
Restimulation Techniques To Improve Fracture Geometry and Overcome Damage
Authors: Schraufnagel R. A. , Spafford S. D. , Conway M. W. 
Published: December 2007

Abstract
This paper discusses remedial hydraulic stimulations used to increase production rates from two coalbed methane wells at GRI's Rock Creek project. The poorly performing stimulation was plugged with cement and the well restimulated using a non-damaging gel, nitrogen foam, and sand stimulation. These treatments suggest: 1) cement can be used to abandon undesirable hydraulic fractures prior to restimulation, 2) the use of an alternative gel polymer, identified by core testing for a specific coal sample, minimized permeability damage during stimulation, and 3) a special foam and sand stimulation created a more effective fracture than the original water and sand treatment in the same well.
Stimulation Technology in the Antrim Shale
Authors: Reeves S. R. , Cox D. O. , Smith M. B. , Schatz J. F. , Schatz John F. 
Published: December 2007

Abstract
The Antrim Shale of the Michigan Basin has been one of the most active natural gas plays in the U.S., with 1992 drilling exceeding 1200 wells. Gas production from the Antrim, reported to contain 76 Tcf (2.1 x 1012m3)of in-place resource, reached 74 Bcf (2.1 x 109m3) in 1992 with 2,600 wells producing at year end. Much of the 1992 drilling activity can be attributed to the expiration of the Section 29 tax credit which was applicable to the Antrim Shale.
The Gas Research Institute has targeted the Antrim Shale as a focus of stimulation research. Two field research projects addressing stimulation technology in the Antrim Shale were initiated during 1992 in cooperation with producing companies, one which is investigating methods to optimize hydraulic fracturing treatments and one which is investigating the potential application of alternative, low-cost stimulation methods.
The first project, being performed in cooperation with Ward Lake Energy, is studying whether single-stage fracture treatments (one treatment for two shale horizons) are more cost-effective than individual treatments for each zone. Four offset study wells were selected for the project; two open-hole completions to evaluate single-stage treatments and two cased-hole completions to evaluate multiple-stage treatments. Pre- and post-stimulation pressure transient testing, mini-fracs, bottomhole treating pressure data, and post-frac borehole camera surveys have been incorporated into the research program. Preliminary results indicate that single-stage fracture treatments do contact both shales, however the stimulation achieved in each zone has not been clearly defined yet.
The second project, being performed in cooperation with Terra Energy, is comparing the costs, stimulation effect and production performance of three offset wells stimulated by (a) an acid bailout treatment, (b) high-energy gas fracturing and (c) hydraulic fracturing. Post-stimulation pressure transient testing, production testing and stimulation diagnostics have been incorporated into the research program. Preliminary results indicate that hydraulic fracturing provides superior production results. The lower costs of the alternative treatments, however, may still make them attractive under certain reservoir conditions.