bluuebunny/crossref_metadata_2025_split huggingface dataset:
Assessment of the Subsurface Environmental Fate of Amines Used by the Gas Industry
Authors: Sorensen J. A. , Hawthorne S. B. , Gallagher J. R. , Thompson J. S. , Harju J. A. , Evans J. M. , Chollak D. 
Published: December 2007

Abstract
Atkanolamines are commonly used by the natural gas industry to remove acid gases from the natural gas stream. At gas processing plants that use alkanolamines for acid gas removal (AGR), spills and the on-site management of wastes containing alkanolamines and their associated sludges have commonly resulted in subsurface contamination that is presently the focus of some environmental concern. Research has been conducted by the Energy & Environmental Research Center that examines the subsurface transport and fate of the most commonly used alkanolamines, namely, monoethanolamine (MEA), di- iethanolamine (DEA), and methyldiethanolamine (MDEA), and process-derived sludge from AGR units that utilize each of those compounds. Experimental activities were conducted that can be grouped into three areas: 1) qualitative, semiquantitative, and quantitative characterization of alkanolamine-derived sludges; 2) investigations of the interactions of MEA, DEA, and MDEA with soils; and 3) activities investigating the biodegradability of MEA, DEA, MDEA, and associated sludges. Characterization of the sludges was performed using gas chromatography coupled with mass spectroscopy (GC-MS). In order to examine the potential effects of different soil types on subsurface transport and fate, investigations of interactions between alkanolamines and soil and of biodegradation of alkanolamines and process- derived sludges were performed using soils collected from Louisiana, New Mexico, and Alberta. These areas were selected to represent not only three unique soil types, but also to represent three regions of North America that produce an abundance of "sour" natural gas. The results of this research provide the natural gas industry with data and insights that will enable them to 1) significantly improve the assessment of subsurface alkanolamine-related contamination where it is known or suspected to occur and 2) make soundly based decisions concerning the remediation of that contamination.
Alternative Approaches for the Determination of Environmentally Acceptable Endpoints (EAEs) for Contaminants in Soil
Authors: Nakles D. V. , Roose T. R. , Hayes T. D. 
Published: December 2007

Abstract
The environmental closure of sites requires the establishment of contaminant concentrations that can be left in the soil and groundwater. It must be demonstrated that these concentrations, otherwise known as environmentally acceptable endpoints (EAEs), are protective of both human health and the environment. Due to the complexity associated with the soil-contaminant interactions, the release and movement of contaminants in the subsurface environment, and the different mechanisms of contaminant uptake by living organisms, no single approach for the establishment of EAEs has evolved. For example, to date, alternative measures of EAEs for contaminated sites have focused on several direct, and indirect, measurements of reduced contaminant availability: (1) the lack of availability of soil-bound contaminants to microorganisms, (2) the lack of toxicity of the soil-contaminant matrix to test organisms, and (3) the lack of mobility of soil-bound contaminants to the environment. Intrinsic processes of contaminant biodegradation and sorption in the subsurface environment have also been incorporated into these definition of EAEs. The Gas Research Institute (GRI), in conjunction with the Petroleum Environmental Research Forum (PERF), has compiled and summarized the results of the field applications of several of these approaches to hydrocarbon- impacted sites. This paper presents several case studies that demonstrate the use of the different measurements of reduced contaminant availability for the closure of sites contaminated with hydrocarbons.
Reserve Analysis and Economic Evaluation of Wasatch/Mesaverde Reservoirs, Greater Natural Buttes Producing Area, Southeastern Uinta Basin, Utah
Authors: MacMillan Logan 
Published: December 2007

Abstract
The Greater Natural Buttes (GNB) is located in the southeastern Uinta Basin of northeastern Utah. Cumulative production of the nonassociated gas of the producing area is 521 MMCF(1) and has been described as a continuous-type(2,3) or basin-centered gas accumulation. The GNB includes the Chapita Wells, Ouray, Natural Buttes, Island, and River Bend Federal Exploratory Units (Figure 1). The GNB field presently includes more than 880 producing wells, encompasses an area of 345,000 acres, producing from multiple fluvial sandstones in the Tertiary Wasatch and the Upper Cretaceous Mesaverde Formations. Since 1990, more than 350 additional wells have been drilled within GNB as infill development wells on an effective spacing of 80 acres, although the full development of the field area is not yet complete on this spacing pattern. There are three main operators in the field, with several additional operating companies around the perimeter of the field, as it is defined today.
The eastern limit of the Natural Buttes field has been defined generally by the economic limit of Wasatch and Mesaverde gas production. Data presented in the Utah Geological Association's 1992 Uinta Basin Guidebook show that the economic limit of Natural Buttes production(4) is related to the thermal maturity of that field's source rocks: the coal-rich beds in the basal Mesaverde Formation(5,2). Drilling activity in the GNB in 1991 and 1992 increased dramatically over the previous five years, due in part to tax incentives allowed for gas produced from formations designated as "Tight."
The Uinta basin contains some of the largest accumulations of oil and gas in any of the Western Interior basins, with production, indesending order, from the Tertiary Uinta Formation (gas), Green River Formation (oil and gas), Wasatch Formation (gas), and the Upper Cretaceous Mesaverde Group (gas). Figures 1 & 2 show diagrammatically the location of the significant gas producing fields: Natural Buttes and Island fields, as well as the other mlijor oil-producing fields in the Uinta and Piceance basins.
Economic Evaluation in the Courtroom: The Problem with Some Experts
Authors: Richard J. 
Published: December 2007

Abstract
This paper will examine the influence of some recent court decisions on the preparation and presentation of scientific and technical evaluation as part of expert witness and other testimony amid the mounting concern about "junk science" in the courtroom. The implications of the Daubert and Robinson decisions, will be discussed in terms of the geologic and engineering evaluation of oil and gas properties and projects which may be used for expert witness testimony or which have the potential to end up in civil or administrative litigation. The Daubert decision, in particular, has resulted in considerable review of the common practice of relying on methods deemed to be "generally accepted" and had required some, but not all, courts and other judicial bodies which are subject to court review, to adopt more restrictive standards. These new standards include demonstration of the sources of supporting and derivative information, determination of error rates for the analytical methods used, and demonstration of the acceptance of the evaluation methods used among knowledgeable persons in the field This paper will explore the application of these standards to examples of evaluation for geologic prospect development, in reservoir engineering analysis of EOR reserves, and in the development of economic parameters such as price/cost projections, comparable sales analysis, and discount rates for use in economic evaluations for tax or other purpose.
Acquiring Producing Properties Via Oil & Gas Auctions
Authors: Gibbs J. A. 
Published: December 2007

Abstract
Oil and gas auctions were relatively uncommon before 1987. Since then the auction market has grown at a rate of almost forty percent annually, and auctions have become a useful and accepted method of buying and selling producing interests. Thousands of properties, totaling almost $200 million, are anticipated to be committed to auctions in 1997.
Auctions provide advantages to both sellers and buyers. For sellers, they offer a quick and convenient means of "rationalizing" lower value, non-operated or geographically dispersed interests. For buyers, bids are transparent, against other willing bidders. Titles pass the day of the auction, eliminating the delays inherent in negotiated sales.
Disadvantages exist. Lack of time or data for sufficient due diligence increase the risks of mistakes. Nevertheless, for many buyers the opportunity to acquire good properties at reasonable costs outweigh concerns.
Determination of the Residual Oil Saturation in Two Aux Vases Sandstone Reservoirs
Authors: Sandiford B.B. , Eggebrecht N.M. 
Published: December 2007

Abstract
In order to determine the residual oil saturations in two sandstone reservoirs that were considered for tertiary oil recovery projects, test wells were drilled and the projects, test wells were drilled and the reservoirs were cored and logged. Both oil fields are located in South Central Illinois, and they had been under waterflood for about ten years. In one case the reservoir was cored by a special pressure core barrel that was developed by Esso Production Research laboratory; this same well was logged by an electric log and by a neutron decay time log. The oil saturations measured in the water swept areas of these two reservoirs ranged from 6% to 26% of the pore space.

Introduction
Material balance calculations show that many millions of barrels of potentially recoverable tertiary reserves are in Aux Vases sand reservoirs in the Illinois Basin. These reserve calculations are based on a residual Oil saturation equal to about 25 percent of the pore volume after waterflooding. Aux Vases sands are more uniform than most reservoir sands that we have studied, but interbedding of small gray shale laminations and variations in carbonate cementing material has caused heterogeneities. This heterogeneity and also the well locations affect the flow of fluids during primary and secondary recovery operations. It is possible that a large portion of the residual oil is retained in the periphery of these reservoirs and outside the well patterns; however, we are primarily interested in the residual oil that remains in areas between wells. We should be able to move this oil by miscible displacement, but we need to determine if this can be done economically, and the economics depends to a great extent on the oil saturation in the swept areas. In this paper we describe our methods for evaluating two Aux Vases sand reservoirs before selecting a test site for a tertiary recovery process. We were interested in finding a test process. We were interested in finding a test area in the Aux Vases reservoir that contained a typical residual oil saturation so that a tertiary recovery process could be applied to other similar areas. We used three common basic methods for determining oil saturations in the two areas.
An Optimization Model for Allocating Capital to Business Segments in an Integrated Oil Company
Authors: Burness G. C. , Fryer V. I. , Gupta R. K. , Novotnak J. F. 
Published: December 2007

Abstract
Capital investment strategies are being analyzed within an integrated oil company utilizing information from a mathematical model which determines optimal allocations of single and multi year capital outlays that will maximize the net worth of the company over a long term horizon. The optimal processes focus on an economic profit measure which is closely related to net present value or market value added when applied to any business segment or operating level within the company. It provides a more robust and comprehensive measure of value created for the shareholder than more traditional financial and accounting measurements such as net income, cash flow, earnings per share, or return on assets. The optimization model is described and the theoretical aspects and application of the economic profit measure are discussed.
The SPE/WPC Reserve Definitions: The Impact on Past and Future Reserve Evaluations
Authors: McMichael Claude 
Published: December 2007

Abstract
Petroleum reserves are one of the most fundamental elements in the international petroleum industry. To the producing company, reserves are the asset base from which future profits and investment capital will be derived. To the investor, they are a reflection of the financial strength of a company and an indication of future growth potential. For a government, they are a major source of energy and a key factor in the continued development the country’s economy. It is essential for future planning that both governments and industiy have a clear understanding of the quantities of oil and gas available for production, as well as, those quantities which are anticipated to become available through additional field development, technological advances, and exploration. To achieve such an assessment, the industry needs a simple and widely understood nomenclature for classifying the current and future quantities expected to be recovered from petroleum reservoirs based on the likelihood of their commercial recoverability.
Over the past sixty years, numerous technical organizations, regulatory bodies, and financial institutions have introduced nomenclatures for the classification of petroleum reserves. In 1987, the Society of Petroleum Engineers (SPE) and the World Petroleum Congress (WPC), working independently, developed sets of reserve definitions which were strikingly similar in most key aspects. Both gained wide acceptance and have become the preferred standards for reserves classification across much of the industiy. Soon after their introduction, it became apparent to both organizations that these two could be combined into a single set and that such a development would improve consistency in reserves evaluation and reporting across the industiy. Contacts between representatives of the two organizations started shortly after the publication of the initial sets of definitions and were increased in June 1994. A joint Task Force was established between the SPE, under the guidance of the Oil and Gas Reserves Committee, and the WPC with the assignment of drafting the joint definitions. This effort was completed in the July 1996 and the draft proposals distributed for industry review and comment in August 1996. The revised draft was submitted for consideration to the SPE and WPC Boards of Directors in February 1997.
This paper will review the efforts of the SPE/WPC Task Force and highlight the significant differences between past definitions and those now being proposed. It will, also, address the impact the changes will have on industry, discuss implications for existing reserve estimations and bookings, and highlight several outstanding reserve issues not addressed in the current proposal.
The Philosophy of Reserve Estimation
Authors: Ross J. G. 
Published: December 2007

Abstract
The recent publication for discussion of the SPE/WPC draft reserve definitions1 has highlighted the difficulty in attempting to relate deterministically-derived reserve estimates with those based on a probabilistic methodology. Although the debate over the benefits/disadvantages of the two estimation approaches will no doubt be rekindled, a more fundamental issue is that of the difference between an "incremental" (or risk) based philosophy to reserve estimation and a "Best Estimate" (or uncertainty) based one.
The current SPE definitions2 are based on an incremental philosophy where Proved reserves are "reasonably certain", Probable reserves are "less certain" than Proved reserves and the summation of Unproved (Probable and Possible) reserves with Proved reserves is precluded "because of different levels of uncertainty". The use of "uncertainty" in this context really reflects risk. This philosophy is perfectly acceptable and has been the fundamental basis of reserve estimation (especially in the USA) for many years; however, it is not directly comparable to the philosophy on which the probabilistic approach is based.
The Best Estimate philosophy reflects the hypothesis that the primary objectives of reserves estimation are (a) to make the best estimate possible as to what hydrocarbon volumes will actually be recovered up to field abandonment, and (b) to assess what is the uncertainty in that estimate. This philosophy is inherent in the probabilistic approach, but it is clear that the deterministic methodology can also be (and is) applied using this logic. If the Best Estimate philosophy is applied, deterministic and probabilistic reserve estimates may be comparable (in theory at least).
Comparison of Finite Volume Schemes for Reservoir Simulation on Unstructured Grids: Application to Productivity Index Calculations
Authors: Trujillo D. , Blanc G. , Estebenet T. , Quettier L. , Thomas J.-M. 
Published: December 2007

Comparison of Finite Volume Schemes for Reservoir Simulation on Unstructured Grids: Application to Productivity Index Calculations D. Trujillo, University of Pau, G. Blanc, SPE, IFP, T. Estebenet, IFP, L. Quettier, SPE, EAP, and J.-M. Thomas, University of Pau

Introduction
In reservoir simulations, it is difficult to choose among the great number of numerical methods adapted to solve diffusion equations in porous media. A solution may seem to satisfy reservoir simulation constraints while numerical dispersions or axis effects may discredit it completely. In the absence of general analytical results, numerical tests were could help the user choose a method for his specific application even though conclusions arising from these numerical tests rely greatly on the case treated. Nevertheless, it is very useful to consider some advantages and disadvantages of each numerical method, in order to be able to choose the best adapted one each particular application.

Finite element methods
There exists a great number of finite element methods. They are most often used to solve elliptic equations of the form - div(K P) = f or parabolic equations, for instance in the case of single phase flow. In fact, when it is possible to split the equations into a set of hyperbolic equations and a set of parabolic or elliptic equations associated with the pressure, a finite element method can be used to discretize the pressure equations. This approach is particularly suitable in the case of two phase incompressible flow.
Firstly, we obtain an approximation Ph for the pressure P, which uses piece-wise polynomial bases functions. From Ph we compute the velocity of filtration and then the saturation. A better approximation of the velocities can be obtained when considering them as unknowns in the pressure equations. This method is the so-called mixed finite element method.
Finite elements have been preferred to finite differences in recent years, because of their flexibility when dealing with irregularities in both geometry of domain and position of nodal points. Unfortunately, in the case where there is no possibility of splitting, the finite element schemes lead to numerical instabilities which necessitate the subsequent use other numerical schemes such as finite volume methods. Finite volume methods
There are two great classes of finite volume methods. The simplest one, in terms of programming, is the Control Volume Finite Difference (CVFD) method. However it cannot be applied on general domains.
The second class which is described here is the Control Volume Finite Element (CVEE) method, introduced to overcome the lapse of flexibility. Given a triangulation related to the pressure (with triangles or tetrahedrons), we build a control volume associated with the saturation around each vertex : for each triangle T of the triangulation, we consider an arbitrary point aT of T.
P. 291^
Representation of Gas-Condensate Wells in Numerical Reservoir Simulations
Authors: Panfilova I. , Panfilov M. 
Published: December 2007

Abstract
We have developed a new analytical method, allowing to relate wellbore and wellblock pressures, saturations and concentrations, in case of the multicomponent mixture flow with phase transitions. The saturation distribution near a well is shown to be governed by a fractional power-value logarithmic law. Moreover, the simple logarithmic approximation for pressure field may be invalid near the well. The relationships for integral parameters of a well, such as the productivity index and the transmissibility for each fluid phase and each chemical component, have been deduced. Non-trivial physical effects were shown. Certain instability caused by inversion of phase transitions could be observed, that result in oscillatory modes of well production.

Introduction
In reservoir simulation, the linear approximation for computed functions becomes non-valid near wells. The more complex approximations using the natural laws of the function distribution near the well have been proposed in case of one- and two-phase flows without phase transition. In case of compositional flow with phase transitions similar to gas-condensate mixture, the problem becomes more important, because the difference between wellbore and wellbloc saturations can be very large. The exhaustion of gas-condensate field may be divided on two time stages, where the process is described by different system of equations. The first stage corresponds to transient process of perturbation propagation from wells. Methods determining the wellbore saturation and concentrations for this time stage have been developed. In this paper, the same method is extended on the second stage, where the liquid flow takes almost steady-state behavior.
Optimization of Pipeline Network in Metropolitan Area, Korea, with Hybrid MCST-CD Networking Model
Authors: Sung W. , Lee J. , Huh D. , Kwon O. 
Published: December 2007

Abstract
This paper presents a hybrid network model(HY-PIPENET) implementing a minimum cost spanning tree(MCST) network algorithm to be able to determine optimum path and constrained derivative(CD) method to select optimum pipe diameter. The HY-PIPENET has been validated with the published data of 6-node/7-pipe networking system, and also this system has been optimized with MCST-CD method. As a result, it was found that the gas can be sufficiently supplied at the lower pressure with the smaller diameters of pipe compared to the original system in 6-node/7-pipe network. Hence, the construction cost was reduced about 40% in the optimized system. The hybrid networking model has been also applied to a complicated domestic gas pipeline network in metropolitan area, Korea. In this simulation, parametric study was performed to understand the role of each individual parameter such as source pressure, flow rate, and pipe diameter on the optimization of network. From the results of these simulations, we have proposed the optimized network as tree-type structure with optimum pipe diameter and source pressure in metropolitan area, Korea, however, this proposed system does not consider the environmental problems as well as safety concerns.