bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Outlook for Western Coal in the Competitive Marketplace
Authors: Pistole Harry 
Published: December 2007

Society of Petroleum Engineers 6200 North Central Expressway Dallas, Texas 75206
THIS PAPER IS SUBJECT TO CORRECTION
American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Abstract
To meet marginal energy requirements of the next 15 or 20 years, the US has only three viable alternatives . . . imported oil, nuclear energy, and coal. Imports are vulnerable to supply interruptions at the hands of foreign governments, and they present balance of payments problems. present balance of payments problems. Nuclear energy continues to face delays from financing, siting, and environmental problems. While increased coal usage also problems. While increased coal usage also faces specific problems, the US has about half the free world's reserves, and it is believed coal will increase its share of total US energy supply from 18% now to 25% in 1990, while oil and gas decline from 74% to 58%. To meet this demand, coal production must more than double by 1990, production must more than double by 1990, even with a three-fold increase in nuclear capacity. Much of the increased coal must come from the West because it is generally lower in sulfur content and less expensive to mine. In this 15-year time frame, western coal production is expected to increase almost six-fold.
Western coal faces all of the usual complexities of large-scale development in a frontier environment. . . limited infrastructure, severe sociological impacts, unfamiliar and uncertain marketing prospects. But in the West, all of the "usual" frontier uncertainties are surpassed by the uncertainties of government . . . legislation, regulation, and litigation. Eighty percent of western coal is directly affected by federal policy. Can leases be secured under federal leasing regulations? Can coal be mined under the various environmental laws? Can coal be used under the Clean Air Act? Can the consumer afford to buy the coal after it has traversed this expensive maze? These are but a few of the uncertainties facing the investor in western coal.
Higher energy prices have made coal more competitive among the viable alternatives for the marginal fuel market, and the economic foundation for significant growth in coal is being formed. Moreover, the added economic stimulus will promote new technology. It is our view that western coal is too important a national resource not to get on with its development during a period when our nation is experiencing a growing shortfall in meeting its energy needs. By the same token, now is not the time to legislate out of the business those investors whose skilled manpower, financial resources, and management capability are ideally suited to the development of coal for direct use as well as the technology for its conversion to synthetic fuels.
A Competitive Bidding Model That Uses Historical Data
Authors: Hartsock James H. 
Published: December 2007

Society of Petroleum Engineers 6200 North Central Expressway Dallas, Texas 75206
THIS PAPER IS SUBJECT TO CORRECTION
American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Abstract
A mathematical model has been derived and solved to compute the bidding strategy that maximizes the expected present worth in a competitive bidding environment. Basically, the model consists of three modules, each of which is processed sequentially. The first module performs a risk analysis on the geological performs a risk analysis on the geological estimate of the reserves under the lease and passes the expected reserves to the second passes the expected reserves to the second module that computes the expected present worth of these reserves. This value is then passed to the competitive bidding module that computes the bid that maximizes its expected present worth.
The competitive bidding model was developed to compute the probability of winning with a given bid. A Pearsonian analysis was performed on the published results of past lease sales to identify the functional forms of the probability density functions used i-n the model, and regression analyses of past lease sales provided estimates of the model's parameters. In addition, a data base management and maintenance system was coded to update the parameters of the model upon the completion of each lease sale.
The model has been tested in several recent federal lease sales and the results of the model compare favorably with the actual bidding outcomes.

Introduction
In order to achieve the objectives established by Project Independence, the Bureau of Land Management has accelerated the leasing of potential oil and gas acreage in the federal offshore areas. Since competitive bid leasing began 22 years ago, a total of approximately 18 million acres have been leased, 30 percent of which have been leased in the past 4 years. This increased activity has posed several interesting problems for management when developing a strategy for bidding. For example, is it more beneficial for a company to bid with a group, thereby spreading the risk by reducing the expected cost, or should a company bid alone and assume the full risk? With few exceptions, recent bidding results imply that corporations are unwilling to assume the full risk. Should a bidding combine spend their leasing budget by bidding very high on a few low-risk tracts, thus enhancing their chances of winning some tracts, or should they distribute the budget over more tracts by bidding less on each tract while reducing the chances of winning any single tract?
Morrow Stimulation in Southeast New Mexico
Authors: Simon David E. , Underwood Porter 
Published: December 2007

Abstract
The purpose of this paper is to reevaluate the stimulation procedures used in the Morrow Sand formation of Southeast New Mexico, and to improve these techniques based on current and new information.
This study considers the geological aspects of the Morrow Sand using the scanning electron microscope to investigate each Morrow rock type to determine rock properties and composition. The use of DST information is employed to establish pre-stimulation conditions involving transmissibility, BHP, damage ratio and productivity.
A study of fracturing fluids is presented investigating adsorption, clay presented investigating adsorption, clay swelling, compatibility and regained permeabilities with various Morrow rock permeabilities with various Morrow rock types. Fracturing techniques are evaluated using reservoir, DST, log, and fluid data to compare sand placement with thin and viscous fluids, sand concentrations, fracture length, fracture length and stabilized production increases. production increases. Conclusions based on previous work and this study indicate fracture stimulation with viscous gels improves Morrow Sand production.

Introduction
Prior to the late 1960's, the only morrow production in Southeast New Mexico was from wells having sufficient permeability to be completed naturally. permeability to be completed naturally. Stimulation attempts during this period utilized oil-base fluids or saturated brines with little or no increase in production. The first successful production. The first successful stimulation treatments consisted of aqueous potassium chloride solutions gelled with potassium chloride solutions gelled with guar, buffered for low pH, and incorporated a surfactant for low surface tension. The proppant used in these treatments was 20–40 mesh sand and 20–40 mesh glass beads.
In the early 1970's, use of a viscous crosslinked gel system and large sand concentrations proved successful for penetrating through wellbore damage. A typical treatment was 10,000 gallons of crosslinked guar carrying 18,000 pounds 20–40 mesh sand at 10 BPM. pounds 20–40 mesh sand at 10 BPM.
Successful Application of Foam Frac to Shallow Gas Sands
Authors: Ballard John L. 
Published: December 2007

Abstract
The purpose of this paper is not to review previous papers and reports on foam fracturing, but rather to relate and review the job procedures and results of foam fracturing treatments in low bottom hole pressure reservoirs in shallow gas sands. pressure reservoirs in shallow gas sands. This paper covers the mechanical hookup, computer programs relating to job design, sand concentrations obtainable, foaming agents and their concentrations, and a system of accurately monitoring foam quality down stream.
Conventional equipment can be used to provide up to 2 pounds sand per gallon of provide up to 2 pounds sand per gallon of foam, without viscosifying the water. Also, a differential density measuring system is available for monitoring foam quality as it enters the well.
The basic downhole problems solved by this technique are those of fluid retention and formation damage by water-base fluids in these water sensitive and low pressure formations.

Introduction
Foam fracturing has survived a slow beginning and, because of its present success, has become an established technique for stimulating production from gas wells.
The properties and rheology of foam have been discussed by many authors and will not be elaborated on any further.
This type treatment has shown to be more effective in gas wells than oil wells. This is largely due to the fact the liquid hydrocarbons have a tendency to break the foam prematurely, and high concentrations of prematurely, and high concentrations of foaming agents tend to cause emulsion problems. Therefore, the two problems cause a "stalemate." In some reservoirs one chemical can be found to foam effectively at low concentrations without causing emulsions, and in some reservoirs small amounts of a demulsifier can be combined with a nonionic foaming agent.
Many changes have been made in the treatment design in order to more accurately perform the treatment. perform the treatment.
Case History: A Pressure Core Hole
Authors: Bilhartz H.L. 
Published: December 2007

Abstract
A core hole was needed in the Willard Unit, Wasson Field, CO2 Pilot Test in order to evaluate the effectiveness of CO2 flooding. The coring program was designed to determine the residual oil saturation behind the CO2 front and the waterflood residual oil saturation in zones not yet affected by CO2. For the most definitive interpretation of the oil saturations found in the core, the presence of CO2 needed to be associated with the lowest oil saturations. Saturation measurements on conventional cores may result in incorrect values for one or both of two primary reasons:some hydrocarbon may be stripped from the coring by mud filtrate invasion,and additional fluids may be driven from the core by gas expansion as the pressure is reduced during surfacing.
If flushing by mud filtrate is controlled then valid fluid saturations can be obtained using a pressure retaining core barrel to prevent loss of fluids by gas expansion. Furthermore, if gas saturation and/or composition is desirable, then pressure coring is necessary and this was the situation at Willard. However, a major disadvantage to pressure coring is its high cost and a rather low 60% historical success ratio of getting core to surface under pressure.
This paper summarizes the work done with the pressure core barrels prior to spudding in order to increase our chances of getting core to surface under pressure. It also outlines the field procedures which were followed that resulted in obtaining 18 pressure cores out of 19 attempts. Also, discussed in this paper are the core analysis techniques which were used to determine oil, water, and gas saturations at reservoir conditions for full diameter cores.

Discussion
A pilot test of tertiary oil recovery by CO2/water miscible displacement was conducted in the Willard Unit, Wasson Field, Yoakum County, Texas. The Willard Unit pilot consisted of one injection well (32A), one logging observation well (32AO) located 100 feet to the north of the injector, and one fluid sampling and pressure monitoring well (32AS) 25 feet north of the logging well (refer to Figure 1). The test was designed to study unit displacement efficiency and in situ fluid movement and was not a producing pilot test.
The reservoir is a typical West Texas San Andres dolomite with a gross pay interval of 160 feet in the pilot area.
Waterflood Residual Oil Saturation - The Buffalo Field, Timor Sea
Authors: Behrenbruch Peter 
Published: December 2007

Abstract
A representative description of residual oil saturation is one of the fundamental requirements for studying the behaviour of a field under waterflooding.
Presented is a case history for describing waterflood residual oil saturation for the Buffalo field, offshore Australia. The aim is to give a practical framework for correlating laboratory results for residual oil saturation. The new methodology correlates residual oil saturation for a particular facies with initial oil saturation, permeability and when appropriate also wettability, and as a function of displacement velocity. As a non-conventional feature, the wettability parameter used is based on relative permeability endpoints.
It is demonstrated that correlation with permeability can follow both, a more conventional, positive relationship in case of a heterogeneous pore structure and a negative relationship in case of a more homogeneous formation. It is also shown how alteration in wettability, both in-situ due to drilling mud contamination and in the laboratory due to variation in ageing can impact the results.
The strength of the methodology is that it can be applied to very diverse situations and simple nomograms have been developed to better visualise the results. The methodology builds on the ideas of Land1 and can be universally applied using basic, readily available data. The method is also very suitable for comparative studies of different facies of the same field or in comparing different fields. Additional examples are cited from the Gulf of Mexico to demonstrate the applicability of the method.
20 Years of Laboratory Oil-Water Relative Permeability Data in the Malay Basin
Authors: Coyne Patrick L. , Omar Mohd. Ismail 
Published: December 2007

Abstract
The Malay Basin oil reservoirs are typically near shore marine sandstones, many of which are produced via natural water drive or water injection1-3. Esso Production Malaysia Inc. (EPMI) and PETRONAS Carigali Sdn Bhd (PCSB) currently operate 17 oil fields offshore peninsular Malaysia.
Beginning in 1975 and continuing to the present time, EPMI and PCSB have acquired more than 160 sets of laboratory oil-water imbibition relative permeability data to use in predicting field performance. These data were measured on cores cut with a variety of drilling muds, using extracted, restored state and preserved core samples. The relative permeability values were obtained from both centrifuge and waterflood experiments. Each oil-water relative permeability data set was analyzed and Corey equations were used to fit the oil and water relative permeability measurements.
After analyzing all the experimental results, a set of recommended oil-water imbibition relative permeability experiments was selected. Many of the samples were excluded due to the use of less desirable laboratory procedures or coring muds.
Additionally, recommended laboratory relative permeability curves were compared to values derived from simulation history matching. In general, oil relative permeabilities are similar. However, the laboratory curves predict higher water mobilities than the values derived from history matching. Finally, recommended procedures were developed for measuring oil-water imbibition relative permeabilities for future laboratory studies.
The work described in this paper provides a process for analyzing and assessing relative permeability data. The data itself can be used as analogues for similar sandstone reservoirs. In addition, the recommended laboratory procedures can be used to help design special core analysis programs.
Material Balance Study of Gas Reservoirs by Flowing Well Method: A Case Study of Bakhrabad Gas Field
Authors: Choudhury Z. , Gomes E. 
Published: December 2007

Abstract
Due to critical production-demand situation, proper pressure survey can not be conducted on a regular basis in the gas fields of Bangladesh. Shutting in the wells for pressure survey is also very expensive for the gas production companies. Flowing well method provides an opportunity for updating the reserves without interrupting the production. In recent years, pressures of different sands of Bakhrabad Gas Field have been declining sharply and it is believed that the field would be exhausted very shortly. Therefore, Bakhrabad Gas Field is a perfect candidate for applying this new method to estimate the gas reserve and verify it by the actual reservoir performance. Flowing well method of estimating the gas reserve is based on the assumptions that the wells have produced long enough to reach the pseudosteady state condition and the produced gas is relatively dry so that there is no liquid buildup in the well. In this study, actual flowing pressures of the four producing wells of the J Sand of Bakhrabad Gas Field have been analyzed in a similar fashion as the average reservoir pressure in a conventional material balance study. Both wellbore and wellhead flowing pressures have been used to find the reserve. Analytical justifications have been provided in support of this method. Limitations are also explained when applied to a particular gas reservoir. The flowing well method does not require shutting in the wells and conducting a pressure survey. The results of this study have been compared with those of conventional material balance and simulation studies. The results have also been compared with those of other studies previously conducted on Bakhrabad Gas Field. These comparisons show that the gas in place values obtained from flowing well method compare well with those of other studies.
Chemical Evolution of Formation Waters in the Palm Valley Gas Field, Northern Territory: Impact on Field Management
Authors: Andrew A. S. , Whitford D. J. , Berry M. D. , Giblin A. M. 
Published: December 2007

Abstract
The chemical composition and evolution of formation waters associated with gas production in the Palm Valley field, Northern Territory, has important implications for reservoir management, saline water disposal, and gas reserve calculations. Historically, the occurrence of saline formation water in gas fields has been the subject of considerable debate. At Palm Valley gas field there were no occurrences of mobile water early in the development of the field and, only after the gas production had reduced the reservoir pressure, was saline formation water produced. Initially this was in small quantities but has increased dramatically with time, particularly after the installation of compression in November 1996.
Produced waters from the field have been chemically and isotopically characterized in order to investigate the origin of the extreme salinity observed in some cases. The produced waters range from highly saline (TDS=&gt;300,000), with unusual enrichments in Ca, Ba and Sr, to very low salinity fluids that may represent condensate waters. The Sr isotopic compositions of the waters are also variable but do not correlate closely with major and trace element abundances.
The formation waters preserve chemical and isotopic heterogeneities and are thus not well mixed. The high salinity brines have Sr isotopic compositions and other geochemical characteristics more consistent with long term residence within the reservoir rocks than with present-day derivation from a more distal pool of brines associated with underlying evaporites. This conclusion is important in that the brines, if locally derived, may be less significant volumetrically than might be expected if there was present-day hydrological continuity between the brines and the evaporites.
Analysis on the Depletion and Recovery Behavior of a Geopressured/Geothermal Reservoir
Authors: Lee K. S. 
Published: December 2007

Abstract
Geopressured-geothermal reservoirs are presumed to contain a large resource of natural gas in solution with the native brine. The Gladys McCall geopressured-geothermal reservoir is one of such aquifer monitored and tested under U.S. Department of Energy geopressured-geothermal research program. Transient pressure analysis techniques were used to evaluate the performance of the reservoir. Analysis of transient pressure data furnished a specific reservoir description such as the formation parameters, pore volume and shape of the reservoir, and average reservoir pressure. Results of pressure tests suggest that the Gladys McCall reservoir probably has a long narrow shape with the well located significantly off-center. During both production and shut-in periods, pressure buildup tests provided some evidence of external pressure support. Aquifer recharging from a leaky boundary was believed to be the main source. An aquifer influx model was derived from a conceptual model of water leakage through a partially sealing fault into the reservoir under steady-state conditions. The model has been employed to match the production history of the test well. A match of the pressure history required that the conductivity of the fault be a function of the pressure difference between the supporting aquifer and the reservoir. Results of analyses provided a quantitative evaluation of the reservoir and a better understanding of the reservoir energy drive mechanism.
Plus Fraction Characterization and PVT Data Regression for Reservoir Fluids near Critical Conditions
Authors: Zuo Julian Y. , Zhang Dan 
Published: December 2007

Abstract
PVT information of reservoir fluids is of great importance to reservoir engineers. In order to describe phase behavior and PVT properties using equations of state (EOS), a characterization procedure is required for true boiling point (TBP) and plus fractions of reservoir fluids. Although reasonable prediction accuracy can be obtained, the EOS parameters need to be tuned to improve the agreement between the measured properties and the calculated results.
In this work, several characterization methods have briefly been reviewed and the results of two widely used characterization procedures have been compared with the experimental data. The characterization methods can be applied to both single and multiple sample systems. For single sample systems, either an exponential or a three-parameter gamma distribution function was used to split the plus fraction into subfractions. Then the TBP fractions and split subfractions were lumped into groups (pseudo-components) by means of molar averaging, mass averaging, Qauss-Laguerre quadrature or arbitrary selection. For multiple sample systems, a method has been developed to generate the same number of pseudo-components for each sample and the same physical properties of each pseudo-component while the mole fractions of pseudo-components reflect the overall distribution of C7+ mixtures.
In addition, a regression technique has been developed to fit the PVT data and phase behavior for single or multiple samples of reservoir fluids. A modified Levenberg-Marquardt nonlinear least-square algorithm has been utilized in this work. A sensitivity analysis is performed to determine which parameters are more sensitive. The more sensitive parameters are then chosen as adjustable parameters to fit the experimental PVT data. The lower and upper bounds can be set for each adjustable parameter. Finally, regressions are performed to match the measured saturation pressure, volumetric and viscosity data of reservoir fluids separately or simultaneously.
The developed characterization and regression techniques have been tested for oils and gas condensates near critical conditions and under ordinary conditions as well as for multiple samples that taken from a reservoir with a strongly compositional gradient. The results show that the implemented methods provide a reliable and efficient tool for representing PVT properties and phase behavior of reservoir fluids.