bluuebunny/crossref_metadata_2025_split huggingface dataset:
Adapting Probabilistic Methods To Conform to Regulatory Guidelines
Authors: Acuña Herman G. , Harrell D.R. 
Published: December 2007

Summary
Probabilistic methods have introduced inconsistent interpretations of how they should be applied while still complying with reserves certification guidelines. The objective of this paper is to present and discuss some pitfalls commonly encountered in the application of probabilistic methods to evaluate reserves. Several regulatory guidelines that should be followed during the generation of recoverable hydrocarbon distributions are discussed. An example also is given to understand the evolution of reserves categories as a function of probabilities.
Most of the conflicting reserves interpretations can be attributed to the constraints of regulatory bodies [e.g., the U.S. Securities and Exchange Commission (SEC)] and the current SPE/World Petroleum Congresses (WPC) reserves definitions in which reserves categories are expressed in terms of the probabilities of being achieved. For example, proved reserves are defined as those hydrocarbon volumes with at least a 90% probability of being equaled or exceeded (P90). Unfortunately, these definitions alone fall short as guidance on how to derive the distributions from which these percentiles will be calculated. This may lead to distributions that do not comply with the remaining guidelines. While a P90 can be calculated from a noncomplying distribution, proved reserves may not be assigned at this percentile level.
Electrical Resistivity of Geothermal Brines
Authors: Ucok Hikmet , Ershaghi Iraj , Olhoeft Gary R. 
Published: December 2007

Introduction
The electrical resistivity of dilute aqueous salt solutions has been studied for a number of years, but very few data exist on concentrations above 0.1 molar. Normal groundwaters commonly are near 0.1 molar, while most geothermal and oilfield fluids are at least several molar (Table 1). Thus, the interpretation of electrical measurements in geothermal areas at present is based mainly on extrapolation of lower temperature and lower concentration data. Such extrapolation may introduce serious errors into the interpretation of geothermal reservoir characteristics determined from electrical measurements. This paper presents new experimental data and an improved descriptive model of the electrical properties of brines as a function of temperature properties of brines as a function of temperature from 22 to 375 deg. C and concentration from roughly 3 to 26 wt% while under 31 MPa hydrostatic pressure. Data and models are given for brines composed of the chlorides of sodium, calcium, and potassium, and their mixtures. Comparison of the older log interpretation formulas to the new models illustrates an order of magnitude improvement in accuracy with an overall fit to within 2%.

Resistivity Dependence Upon Temperature
Some researchers have postulated that the electrical resistivity of fluid saturated rocks follows the temperature dependence of the saturating fluid in the absence of conducting minerals or significant surface conduction along altered pore walls. This assumption resulted from the success of a simple empirical formula relating the resistivity of a rock to the resistivity of the fluid filling the pores of the rock:
Pr=FPw,
where
Pr= resistivity of clay-free, nonshale material that is 100% saturated, Pw= resistivity of saturating solution, and F= formation resistivity factor.
A number of investigators have derived formulas that add the temperature of the saturating fluids. Experimental observations have shown that some rocks obey these formulas while others do not. 17–19 Part of the problem is the inadequate knowledge of Part of the problem is the inadequate knowledge of the resistivity dependence on temperature for the solution that fills the rock pores. We have found empirically that the best fit of the resistivity data to temperature is
pw=bo+b1T-1 +b2T+b3T2+b4T3,
where T is temperature and coefficients b are found empirically.
Chemical Treatments Associated With North Sea Projects
Authors: Mitchell R.W. , Grist D.M. , Boyle M.J. 
Published: December 2007

This paper discusses carbonate and sulfate formation in the Forties field and some of the laboratory inhibitor-selection techniques used to evaluate scale inhibitors for field use in the Forties injection and production systems. Two chemical treatments for stimulation injection wells also are described.

Introduction
Pressure maintenance in the Forties field began in Dec. 1976. Initial water sampling and core injectivity studies indicated that seawater would be a satisfactory injection fluid.Before commencing injection, the chemical treatment requirements for the seawater injection system were determined. The principal requirement at that time was for an effective microbiological treatment. This was discussed in detail in an earlier publication. Since that time the need has arisen for injection of suitable scale inhibitors into both the injection and production systems to prevent calcium carbonate and barium sulfate scale formation. This paper discusses scale formation in the Forties field and some of the scale-inhibitor selection techniques used. In particular, a novel test method is described that is used to monitor inhibition and flow pattern influence on formation scaling.The water quality aspects of North Sea injection water have been discussed in detail previously. In that study numerous core injectivity measurements were carried out, and the major core plugging mechanism was attributed to the organic portion of seawater. Although no similar plugging has been detected downhole, BP Research has developed a suitable well treatment product to remove organic debris. Some of the results of this study are discussed in relation to potential field application.

Field Scale Problems
Scale problems occurring in the Forties field can be attributed to two major factors:commingling of Forties formation and injection waters andprecipitation of calcium carbonate scale from formation water due to variations in pressure and temperature in production systems.
A partial chemical analysis of Forties formation water and North Sea injection water is given in Table 1. It will be seen that the commingling of formation water and seawater can precipitate both barium and strontium sulfates, which probably are the worst types of scale found in oilfield situations. The solubility of barium sulfate has been calculated as a function of temperature and mixing composition. The results are shown in Fig. 1 and are presented as a stability index, which is the logarithm of the ratio of actual barium sulfate present to the barium solubility under the specified conditions. For example, a stability index of +0.3 indicates the actual barium sulfate present exceeds the solubility limit by a factor of 2 (10 (0.3)).The worst condition exists for relatively large amounts of formation water and small amounts of injection water.
JPT
P. 904＾
A Set of Equations for Computing Equilibrium Ratios of a Crude Oil/Natural Gas System at Pressures Below 1,000 psia
Authors: Standing M.B. 
Published: December 2007

Use of equilibrium ratios (K values) to compute the quantity and composition of gas and liquid phases in equilibrium at given temperatures and pressures is documented extensively in the petroleum literature. While K values usually come from laboratory experiments, the values available to petroleum engineers are presented most often in the form of charts. The Gas Processors Suppliers Assn. (GPSA) charts of K data are well known in the industry.It long has been recognized that equilibrium ratios are system-compositional, temperature, and pressure dependent. Composition dependency usually is indicated by the apparent convergence pressure value (for example. 5,000 psia, 10,000 psia). However, at pressures below about 1,000 psia, the effect of the system composition is small and often may be neglected.A computer program package for evaluating GPSA ratios is available from the association. However, use of the GPSA programs requires a large computer. The equations presented here are simple enough to be handled by small programmable calculators, such as the HP-67, TI-52, and TI-59 machines. It is my opinion that K values developed from these equations are more appropriate than GPSA K values for calculating flash vaporizations at conditions usually found in oilfield gas/oil separation processes.The basic K data involved here are those developed by Katz and Hachmuth on recombined samples of gas and oil from the Wilcox sand of the Oklahoma City Field. Crude gravity was 38.4 deg. API. Based on the reported viscosity of the crude oil, 43.5 Saybolt Seconds Universal (SSU) at 100 deg. F, the Universal Oil Products Characterization Factor (UOP K) of this crude is judged to be about 12.2. While 22 sets of experimental data were determined at three temperatures (up to 3,422 psia), the K values used here were smoothed values read from 11- X 17 1/2-in. charts prepared by Katz and Hachmuth. The K values corresponded to pressures of 14,200, 400, 600, 800, and 1,000 psia, at temperatures of 400, 120 deg., and 200 deg. F.The basic equation used to correlate the Katz and Hachmuth data was that proposed by Hoffman et al.:
log Kp = f[b(1/TB- 1/T)).................(1)
where:
K= equilibrium ratio, y/x, of the compoundp= pressure. psia (MPa)T= temperature. deg. R (K)b= slope of the straight line connecting thecritical point and the atmospheric boilingpoint on a log vapor pressure vs 1/T plot
-log (pc /14.7)(l/TB - 1/Tc)
TB = boiling point of the compound at 14.7 psia, deg. R (K)TC = critical temperature of the compound, deg. RPc = critical pressure of the compound, psia(MPa)
The function inside brackets is the component characterization factor, designated by the symbol F.Several authors have shown that plots of log Kp vs F. at a given pressure. often form essentially straight lines. Also, the effect of increasing pressure has been shown to raise the position of the line on the plot and to yield a line of lesser slope.
P. 1193＾
Strategies for Reducing Oilfield Electric Power Costs in a Deregulated Market
Authors: Stiles Robert F. , Slezak M. Steven 
Published: December 2007

SummaryElectricity is one of the single largest costs associated with oil and gas production. This cost, however, tends to be overlooked relative to other production costs because of utilities regulation combined with its specialized and noncore technical requirements. In spite of this, several studies and strategies over the years have looked at ways of reducing this cost component with meaningful results. Many of these strategies consist of structuring loads and designing equipment to take advantage of the utilities’ regulated rate structure. As the electricity industry in the United States moves toward deregulation, these rate structures will no longer exist; in their place, contracts will be negotiated on a free-market basis between the user and supplier(s) of electricity.In the upcoming deregulated electricity market, three key strategies are available to effectively manage oilfield power costs.Real-time monitoring and control of the electrical load. In-field electricity generation. Negotiation of an integrated power-supply agreement. Because electricity is the ultimate just-in-time product, prices vary greatly depending upon when the power is consumed. The strategies listed previously allow users to proactively structure power-supply systems to address the fundamental volatility of the real price of electricity. The effect is to strip out the historic premium paid to the utility to handle the natural volatility of electricity prices by blending load shifting, internal generation, and market purchases.This paper examines different scenarios in which the previous strategies are proposed and makes estimates for potential savings. These solutions use existing technology applied to the changing market environment and, therefore, focus on economic justification as opposed to technology verification. In one such case, the pumping intervals for a collection of wells is adjusted with real-time power prices combined with remote operations. This reduces the total cost of electricity consumed per barrel of production while only marginally reducing the actual number of barrels produced.
Buildup Solution in a System With Multiple Wells Producing at Constant Wellbore Pressures
Authors: Camacho-V. Rodolfo , Galindo-N. Agustín , Prats Michael 
Published: December 2007

Summary
This paper presents a new analytical solution to obtain the shut-in wellbore pressure at a vertical well that had been producing at a constant wellbore hole pressure from a closed-boundary reservoir with multiple wells producing at constant, different wellbore pressures.
The analytical solution is a set of coupled simultaneous equations in the Laplace space (one for each well). These are obtained by using separation of variables, Green's functions, and the unit-step function with the methods of Rodriguez and Cinco-Ley1 and Camacho-V. et al.2 The equation for the shut-in well is nonlinear, preventing us from obtaining the formal solution of the set of equations either in real time or in Laplace space.
A number of approaches were used to make the solution tractable. These included expansion of Green's function for large times, a Taylor series expansion of the rates around the time of shut-in, and application of the concepts of Najurieta.3 None of the approaches gave satisfactory results.
Estimating Oil Reserves of Fields With Oil/Water Transition Zones
Authors: Fanchi J.R. , Christiansen R.L. , Heymans M.J. 
Published: December 2007

Summary
The amount of recoverable oil in an oil/water transition zone depends on the distribution of oil saturation as a function of depth and on the relationship between initial and final oil saturation in the transition zone (Soitz and Sortz), as well as the volumetric extent of the zone. Conventionally, it is assumed that Sortz is constant and equal to the residual oil saturation in the oil column (Sor) above the transition zone. However, limited data in the literature show that residual oil saturation depends on initial oil saturation as described by the trapped-oil relationship. Thus, Sortz should be a function of Soitz.
The purpose of this paper is to present recent experimental corroboration of the trapped-oil relationship and to demonstrate the impact of the trapped-oil relationship on reserves determination in oil/water transition zones. The effect of the trapped-oil relationship on reserves determination is shown in two ways: first, with an analytical model that shows the maximum possible incremental benefit of including the trapped-oil relationship; and second, with an extended black-oil simulation that incorporates the effects of relative permeabilities on reserves determination.
Seismic Determination of Saturation in Fractured Reservoirs
Authors: Brown R. L. , Wiggins M. L. , Gupta A. 
Published: December 2007

Summary
Detecting the saturation of a fractured reservoir using shear waves is possible when the fractures have a geometry that induces a component of movement perpendicular to the fractures. When such geometry is present, vertically traveling shear waves can be used to examine the saturation of the fractured reservoir. Tilted, corrugated, and saw-tooth fracture models are potential examples.
Effects of Price and Availability on the Future United States Energy Market
Authors: Eisemann Eugene F. 
Published: December 2007

Abstract
This paper is concerned with the competition between fuels for industrial use in the United States. Energy consumption in the U.S. is allocated between industrial and other uses. The industrial volume is divided into two classifications-where there is competition between fuels, andwhere there is no competition.
The pattern of fuel consumption by electric utilities is studied intensively because there is competition between fuels and because it is the fastest growing industrial market. The growth of each utility fuel in several geographic areas is investigated.
The analysis of these areas includes the study of the relationship between prices where fuels are in competition; i.e.,on the East Coast where price competition is between oil and coal, andin the South East states where the competition is between coal and gas.

Introduction
The purpose in developing this energy study was to examine the future demand for petroleum products in the total United States consumption of energy. To predict growth in liquid petroleum fuels, it is first necessary to analyze the competitive position of each fuel in each of the markets it serves. In this approach to the problem, total energy consumption has been segmented into several broad classifications-residential uses, transportation uses, industrial uses, etc.
A New Diagnostic Method for Prediction of Producibility and Reserves of Wells Producing From the Monterey Formation Using Well-Log Data
Authors: Wylie Ursula M. , Ershaghi Iraj , Christensen Karen 
Published: December 2007

Summary
Formation evaluation with well-log data is primarily a prediction tool for the purpose of identifying porous and permeable zones containing movable hydrocarbons. When the lithology is complex or the productivity is controlled by fracture density and the welllog data are limited in scope, underestimation of productive intervals can occur. This paper is a unique study on relating more than 28 years of actual production history to the initial well-log responses. This retrospective approach is the basis for presenting a diagnostic approach to predict producibility and reserves for other wells in the field under study or in other neighboring fields with similar geology.
The focus of the study is well-log responses in the Monterey formation, offshore California. The geology of this formation is regarded as a prime example of a heterogeneous matrix system and a lithology-dependent fracture network. The lithology of the Monterey formation is heavily influenced by the diagenetic stage of biogenic silica (comprising the bulk of the geologic column), the detrital content, and the calcareous component. The particular field selected represents the typical lithological and diagenetic stages observed in surrounding fields. As such, the proposed approach has merits for application to other fields. Geographically, the Monterey type sediments extend from Baja California all the way along the Pacific Rim to Japan.1 Extension of the lithological patterns observed and the productivity correlations in surrounding fields can lead to eventual development of a more general correlation for widespread exploratory or development wells in this type of formation.
Simulation of a Gas-Dominated, Two-Phase Geothermal Reservoir
Authors: Zyvoloski G. A. , O'Sullivan M. J. 
Published: December 2007

AbstractThe basic equations governing the behavior of a two-phase mixture of carbon dioxide (CO2) and water are discussed. A Newton-Raphson scheme, based on the alternating direction implicit (ADI) method for multidimensional problems, is used to solve the nonlinear finite difference approximation of the governing nonlinear system of partial differential equations. Sample calculations showing the behavior of hypothetical reservoirs with varying CO2 contents are presented.
Waterflood Performance Under Bottomwater Conditions: Experimental Approach
Authors: Shirif Ezeddin , ElKaddifi Khaled , Hromek Jonathan J. 
Published: December 2007

Summary
In many light or moderately viscous oil reservoirs in Saskatchewan and Alberta, Canada, a high water saturation zone of varying thickness and extent ("bottomwater zone") occurs in communication with the oil zone above. As a result, the primary production period is short, and water breakthrough occurs very early in the life of the reservoir. Later, during the secondary recovery stage, such a zone can have an adverse effect on the waterflood efficiency. This paper addresses the problem of waterflooding such reservoirs.
This study was directed toward reducing water mobility in the bottomwater zone for more efficient oil displacement. Polymer in various concentrations was used as a blocking agent in the bottomwater zone and as a mobility-control agent in the oil zone. Different strategies were investigated to reduce the water mobility in the bottomwater zone and improve the vertical sweep efficiency. The variables examined were relative water-to-oil layer thickness, oil viscosity, polymer concentration, injection rate and injection point, and the effect of vertical and horizontal injection and production well combinations.
The results showed that oil recovery could be increased by minimizing crossflow between layers by blocking the bottomwater zone. It also was found that for an unfavorable mobility ratio, as the injection rate increases, the ultimate oil recovery increases. The injection of a polymer solution had a favorable impact on waterflood performance. Moreover, the worse the conventional waterflood performance was, the more effective the polymer was as a mobility and blocking control agent. The use of horizontal wells showed slightly better oil recovery over vertical wells in a conventional waterflood of reservoirs under bottomwater conditions. In addition, certain well combinations (horizontal production and vertical injection) gave better oil recovery because of the increase in the swept area.
Field Operation of Drilling Marine Risers
Authors: Childers Mark A. , Martin E.B. 
Published: December 2007

Structural analysis techniques have been used since the 1950's to predict stresses in marine riser systems. However, little effort has been focused on the input design criteria, their interpretation, and field application. Taking into consideration the rig's characteristics, mooring capability, and riser system, this paper presents design and operating criteria for the engineer and rig personnel.

Introduction
Since the first marine riser (or mud riser) was run and operated in the late 1950's off the coast of California,1,2 the industry has analyzed and studied the structural aspects of drilling riser systems rigorously. Literally millions of dollars have been spent on computer programs and their refinement in an effort to analyze accurately the beam column structure as it is used on a floating drilling vessel.3–6 In search of field verification of developed analytical techniques, additional large sums of mopney have been spent for strain gauge and accelerometer measurements along with digital and analog recording systems.7 As of the mid-1970's, the industry generally had come to the conclusion that, from an analytical standpoint, the analysis techniques and conclusions were sound. This is apparent from the publication of API Bull. 2J8 as compiled by the Marine Riser Task Group, in which close agreement was obtained between nine different independent contributors.
The literature is full of presentations on riser structural analysis. However, no major piece of work has been presented on the methodology of taking the beam column computer output and implementing it on a daily basis in actual field operation. Because of this lack of attention, some interesting and varied results on how to design and operate a drilling riser in the field have taken place. It is our purpose (1) to show the tremendous divergence in approaches currently being used to determine a recommended tension and (2) to present a specific method for analysis that is based on operational considerations as well as riser structural stability.
We also will discuss field operations such as riser space-out, riser tensioner wire rope slip programs, and the inspection of marine riser joints and connectors.