bluuebunny/crossref_metadata_2025_split huggingface dataset:
Operating Experience With ESP's and Permanent Downhole Flowmeters in Wytch Farm Extended-Reach Wells
Authors: Brodie Alan , Allan Joe 
Published: December 2007

Summary
One-third of the recoverable reserves in British Petroleum CO.'s U.K. onshore oil field, Wytch Farm, lie in an offshore extension of the field. These reserves, which have been undeveloped until recently, are now being exploited with electric submersible pumps (ESP's) in extended-reach wells drilled from onshore wellsites. The relatively high productivities achieved as a result of successful horizontal completions have pushed ESP technology to the limits in terms of capacity and power requirements. This paper presents a case history of the unique set of problems encountered during and subsequent to startup of the ESP's in the first three wells. The problems, in particular pump-suction-blockage problems, were directly attributable to the position of the ESP's in the near-horizontal section (82 to 85°) of the wells.
The paper also describes the innovative permanent downhole flowmeter system incorporated in the completion. The system measures and logs flow-rate data, pump-suction and -discharge pressures, and temperature. Examples are presented that clearly demonstrate how these data have been invaluable in understanding the problems encountered in the initial extended-reach wells and the role the system has played in extending ESP run lives. Finally, completion-equipment modifications and operating-procedure changes, successfully introduced to resolve the problems encountered in the first two wells and to avoid them in subsequent wells, are described.

Introduction
Wytch Farm, on the southern coast of England ˜100 miles southwest of London (Fig. 1), is the largest onshore oil field in western Europe. The main reservoir lies under Poole Harbor and extends offshore under Poole Bay. Poole Harbor has been designated as an area of outstanding natural beauty, with sites of special scientific interest and special protection areas, and is noted for its landscape, ecology, and amenity value.
Relative Permeability Hysteresis: Laboratory Measurements and a Conceptual Model
Authors: Braun E. M. , Holland R. F. 
Published: December 2007

Summary
Relative permeability hysteresis has been measured for a water-wet outcrop rock sample and a mixed-wet reservoir core. For the oil phase, imbibition and drainage relative permeability curves differed significantly. The difference was much less pronounced for the water phase. Scanning curves, which characterize transitions between imbibition and drainage curves, were also measured. A notable characteristic of the oil relative permeability scanning curves is their reversibility; along most of the length of a scanning curve, oil relative permeability exhibits no hysteresis. A proposed mechanism for the reversible behavior is pinning of water/oil interfaces on surfaces of rock grains. Pinned interfaces remain anchored at fixed positions on grains despite changes in interface curvature and contact angle. In water-wet samples, pinning can occur as a result of contact-angle hysteresis. In mixed-wet rock, pinning can occur at the boundaries between water- and oil-wet grain surfaces. As long as interfaces remain pinned, pore-level fluid geometry is a function of saturation only and does not depend on the direction of saturation change.
Effect of Injectant Composition and Pressure on Displacement of Oil by Enriched Hydrocarbon Gases
Authors: Shyeh-Yung J. Jane , Stadler Maurice P. 
Published: December 2007

SummaryReservoir-condition phase-behavior and tertiary-gasflood studies have been conducted in the laboratory to investigate the effect of hydrocarbon-injectant composition and pressure on oil-displacement efficiency. Lower oil-recovery efficiencies and lower injectant mobilities have been observed at lower enrichment levels and/or at lower pressures. Coreflood oil recoveries, however, remained high for gas injectants that are below multiple-contact miscible (MCM) with the oil. These results suggest that near-miscible hydrocarbon-gas-injection processes show promise and that there may be a tradeoff between local oil-displacement efficiency and gas-sweep efficiency in near-miscible displacements in the field.
Evaluating Deepwater Development Concepts
Authors: Abbott P.A. , D'Souza R.B. , Solberg I.C. , Eriksen Knut 
Published: December 2007

Summary
This paper provides an overview of the current state of deepwater technology. It discusses the major factors that must be considered when evaluating potential deepwater development concepts, presents proven deepwater development concepts, and provides insight into the applicability of each. Two unproven "dry tree" concepts are presented to illustrate proposed new concepts. Approximate costs are included, leading up to general conclusions with respect to the evaluation process. The focus is primarily on the Gulf of Mexico.

The Deepwater Market
The incentives for developing deepwater fields are clear. World oil demand is expected to rise annually by an average of 890,000 B/D between 1993 and 1995. The U.S. has a serious balance of payments problem that is aggravated by the fact that it is importing more than half of its oil. The east and west coasts of the U.S., plus the section of the Gulf of Mexico east of Alabama, are restricted from drilling. Total deepwater discovered and potential reserves in the Gulf of Mexico are estimated to be 2 to 4 billion bbl and 10 to 12 billion bbl, respectively. More than 20 undeveloped discoveries exist in the Gulf of Mexico in water depths ranging from 2,400 to 7,520 ft.

Development Options and Critical Issues
Development Options. Deepwater fields can sometimes be developed with subsea tieback techniques without requiring a deepwater platform at the field itself. If a deepwater platform at the field is required, a wide choice of type exists. The list of proven and unproven (but highly developed) deepwater platform concepts includes (1) steel and concrete tension leg platforms (TLP's); (2) semi- and monohull, steel and concrete floating production systems (FPS's); (3) steel and concrete spars; (4) concrete deep draft floaters (DDF's); and (5) compliant towers (primarily steel).
Some critical issues to consider when selecting concepts to include in a detailed evaluation study will be presented before describing the various deepwater development concepts and discussing the pros and cons of each. The pros and cons of the use of DDF's will not be included because the 45-ft draft limitation along the U.S. gulf coast will probably prohibit their use unless and until suitable techniques for mating an integrated deck to an already-moored hull are developed.
Gas and Water Permeability Data for Some Common Oilwell Cements
Authors: Goode John M. 
Published: December 2007

Abstract
Permeabilities of cementing compositions have become of increasing interest during the last few years due to the growing use of underground reservoirs for gas storage. This paper presents data on water permeabilities and limited data on gas permeabilities for some of the more common oilwell cementing compositions. These data were obtained in the laboratory using both water and air permeameters with Hassler-sleeve specimen cells. The liquid permeameter was designed to operate at pressures up to 100 psi; the air permeameter was designed to operate at a maximum pressure of 3,000 psi. The study was made at the temperature range normally encountered in gas-storage reservoirs. Results obtained in this study indicate that, in obtaining permeability data on cements, liquid permeability tests should be run instead of gas. Also, permeability of any sort is probably not of significant importance when planning a cementing program of a low-temperature gas-storage reservoir since there is little to choose among cements as to permeability after seven days' curing time.

Introduction
Due to the growth in the number of underground gas-storage reservoirs in recent years, an increased interest in permeabilities of oilwell cementing compositions has been shown. When leakage of gas in storage wells is discussed, the question of permeability of cements always seems to arise. Therefore, the purpose of this study was to obtain these data. Some previous work has been done by Morgan and Dumbauld on water permeabilities of cements, but very little information could be found on gas permeabilities. This is particularly true for the wide range of cementing compositions available to the oil industry today. Questions have also arisen as to bonding of the cement to pipe and formation, and what practices should be observed in order to obtain a good bond for sealing wells in LPG-storage reservoirs. Bonding of cement to pipe has been discussed at length by Winn, Anderson and Carter in their paper. A survey of cementing practices among the companies utilizing underground storage for natural gas indicated that two types of reservoirs are being usedaquifers, or formations that originally contained water; andformations that originally contained oil and gas as well as water.
In multiple-zone storage some small leaks have occurred, but investigations indicate these are located between the mud cake-cement interface where poor bonding occurs and are not due to the permeability of the cement. Nevertheless, a comprehensive permeability study of a variety of cements has been made.

Experimental Determinations
The two instruments used in obtaining permeability data were an air permeameter (Fig. 1) and a liquid permeameter (Fig. 2).
JPT
P. 851^
Filtration From Mud During Drilling
Authors: Ferguson C.K. , Klotz J.A. 
Published: December 2007

Abstract
This paper describes experimental investigations conducted at the California Research Corporation's model oil well.
The first part describes filter loss from several drilling muds through bore hole walls during mud circulation and drill string rotation. The effect of mud properties and drill string rotation with mud circulation is described. Filtration from a bore hole full of drilling mud, not circulating, but under pressure for extended time periods, is also discussed.
The second part describes filter loss to permeable formations from beneath a drilling bit where filter cake has no opportunity to develop appreciable thickness. If potential flow theory is applied to predict filtrate invasion from this hole bottom, large invasions are calculated. But model well experimentation shows that filtrate invasion from the hole bottom is controlled by mud particles that penetrate the formation ahead of the bit. This experimentation provides data to estimate the effect of mud particle penetration on fluid loss to formation.
The third part presents an estimate of mud filtration during drilling of a well.

Introduction
As oil wells are drilled by the rotary method, drilling mud circulates up the annulus between drill pipe and well wall. Drillers adjust mud density so that the pressure at the bottom of the mud column is several hundred psi greater than the pressure of reservoir fluid. As a result of this pressure difference, the liquid part of the mud filters into the rock around the bore and mud solids deposit as a filter cake on the well wall. For many reasons the petroleum industry, within the past 20 years, has spent much money and energy to determine the volume of mud filtrate that enters rock around the well bore and dedicated much research effort to reduce this volume.
Among the reasons for attempts to determine the volume of mud filtrate and to reduce this volume are the following:If filtrate damages the permeability of oil sand, the resultant damage to oil well productivity will depend on the distance that the filtrate invades the oil sand; reduction of filtrate volume may, therefore, increase well productivity.Filtrate that penetrates shale sections may cause the shale to swell and to slough into the well bore. Uncontrolled sloughing may stick drill pipe. Reduction in filtrate volume may reduce drilling trouble.Electric log resistivity curves are changed by invasion of a mud filtrate; the change depends on the depth to which filtrate invades. Knowledge of this depth is necessary before resistivity logs can be interpreted accurately.
Parallel Reservoir Simulator Computations
Authors: Hemanth-Kumar Kesavalu , Young L. C. 
Published: December 2007

Summary
We describe the adaptation of a reservoir simulator for parallel computations. The simulator was originally designed for vector processors. It performs approximately 99% of its calculations in vector/ parallel mode, and, relative to scalar calculations, it achieves speedups of 65 and 81 for black oil and EOS simulations, respectively, on the CRAY C-90. This work also shows that it is easy to adapt a simulator designed for vector processing to parallel processing on shared memory parallel machines.
The Use of Wavelet Transforms in the Solution of Two-Phase Flow Problems
Authors: Moridis G. J. , Nikolaou M. , You Y. 
Published: December 2007

Abstract
In this paper we present the use of wavelets to solve the nonlinear Partial Differential Equation (PDE) of two-phase flow in one dimension. The wavelet transforms allow a drastically different approach in the discretization of space. In contrast to the traditional trigonometric basis functions, wavelets approximate a function not by cancellation but by placement of wavelets at appropriate locations. When an abrupt change, such as a shock wave or a spike, occurs in a function, only local coefficients in a wavelet approximation will be affected. The unique feature of wavelets is their Multi-Resolution Analysis (MRA) property, which allows seamless investigation at any spatial resolution. The use of wavelets is tested in the solution of the one-dimensional Buckley-Leverett problem against analytical solutions and solutions obtained from standard numerical models, Two classes of wavelet bases (Daubechies and Chui-Wang) and two methods (Galerkin and collocation) are investigated. We determine that the Chui-Wang wavelets and a collocation method provide the optimum wavelet solution for this type of problem. Increasing the resolution level improves the accuracy of the solution, but the order of the basis function seems to be less important. Our results indicate that wavelet transforms are an effective and accurate method which does not suffer from oscillations or numerical smearing in the presence of steep fronts.
A One-Dimensional Analytical Technique for Predicting Oil Recovery by Steamflooding
Authors: Shutler N.D. , Boberg T.C. 
Published: December 2007

Abstract
This paper describes a graphical method for calculating oil recovery by steamflooding that permits accurate prediction of fluid saturation permits accurate prediction of fluid saturation profiles and oil bank formation. profiles and oil bank formation. The oil displacement calculation is based on the Buckley-Leverett method for isothermal, two-phase flow in porous media. The fluid-flow theory is used with the Marx and Langenheim method to predict the size of a steam zone from energy balance and beat transfer considerations. The method is more complex than previous simplified methods, but permits band calculations of fluid saturation profiles and the delay of oil bank, arrival in producing wells for partially depleted oil reservoirs. These computations are in excellent agreement with those calculated numerically. Since uniform vertical displacement is assumed this method is suggested for use only for thin sands.

Introduction
The model for steamflooding described in this paper is based on the physical system illustrated paper is based on the physical system illustrated in Fig. 1. The reservoir is considered in vertical cross-section and is bounded above and below by impermeable strata. Heat losses to adjacent strata are accounted for by the method of Marx and Langenheim to describe the rate of steam front advance. This paper is concerned primarily with the prediction of linear fluid-flow behavior in the presence of temperature distributions that are time presence of temperature distributions that are time and distance dependent. The method may also be applied m hot waterflooding. In order to use the isothermal two-phase flow theory of Buckley and Leverett, the temperature distribution T(x, t) is represented by a series of n + 1 moving isothermal zones separated by discontinuities or "shocks" in temperature (Fig. 2a). The Marx-Langenheim method assumes only two isothermal zones (n = 1 in Fig. 2) -- one at injection temperature and the other at initial reservoir temperature - separated by a single shock. Since piston-like flow through the reservoir is assumed, the Marx-Langenheim method is not recommended for thick sands where gravity segregation would greatly reduce vertical sweep. A two-dimensional numerical method as described in Ref. 10 should be used in such a case.
SPEJ
P. 489
Accounting for Local Probabilities in Stochastic Modeling of Facies Data
Authors: Goovaerts Pierre , Journel Andre G. 
Published: December 2007

Abstract
This paper proposes an annealing-type algorithm for generating multiple realizations of facies distributions that: (i) honor the facies data at well locations, (ii) match global proportions of facies, (iii) reproduce spatial continuity and transition probabilities between facies, (iiii) account for prior information such as trend or gradient in facies proportions or the absence of a facies in any particular area. A case-study shows the realizations to reproduce important features of the reference categorical map. A waterflood simulation indicates that the algorithm allows a reduction of the space of uncertainty of flow response values.
A Battery-Operated, Electro-Mechanical Setting Tool for Use With Bridge Plugs and Similar Wellbore Tools
Authors: Gazda I. I. , Goiffon J. J. 
Published: December 2007

Summary
Traditionally, the method of choice for setting packers, bridge plugs, and similar wellbore tools has consisted of running an electrically activated explosive-charge setting tool to the required setting depth on electric line and activating the tool by an explosive charge. Although this method requires an electric line truck and an operator who is licensed to handle the explosives, it is more cost efficient and faster than other mechanical or hydraulic alternatives. Recently, however, new completion technologies with wellbore configurations in which the explosive-type setting method is not desirable have been introduced to the oilfield.
This paper will discuss the design and operational advantages of a new slickline service tool, the downhole power unit (DPU), which has the capability to set wellbore devices without the use of explosives, and thus can comply with the needs of the new completion technologies. Its gradual setting motion allows the slips and sealing elements of packer and bridge plugs to expand and conform uniformly against the tubing/casing wall, thus decreasing the chance of a misrun. The gradual setting motion also eliminates the high-impact stresses that are imposed upon downhole devices when using an explosive-charge setting tool.
The DPU uses an electric gear motor and linear drive mechanism to generate forces of up to 60,000 lbf, and the design is inherently safer than equipment requiring an explosive charge because the power to operate the tool is provided by standard alkaline batteries. Its specially developed circuitry also increases assurance that the tool will be activated at the proper depth.
The tool can be redressed quickly at the wellsite, and routine maintenance involves only lubrication and battery replacement. The combination of simple maintenance, safety-enhanced operation through the elimination of explosives, deployment with slick-line, and the capability to reduce high-impact stresses and misruns has provided the service industry with a cost-efficient, state-of-the-art setting tool that can be used in applications for which traditional methods have not been satisfactory.
Viscosity of Hydrocarbon Gases Under Pressure
Authors: Carr Norman L. , Kobayashi Riki , Burrows David B. 
Published: December 2007

Abstract
The viscosity of hydrocarbon mixtures, whether in the gas or liquid phase, is a function of pressure, temperature, and phase composition. This paper presents methods for the prediction of the viscosity of the gas or less dense fluid phase over the practical range of pressure, temperature, and phase compositions encountered in surface and subsurface petroleum production operations. The correlation necessary to predict the effect of pressure on viscosities is presented in Part I. Serious discrepancies in high pressure gas viscosity data in the literature are discussed.
The application of the correlation to predict absolute viscosities is discussed in Part II. Auxiliary correlations are presented to enable calculations of viscosities from a knowledge of the pressure, temperature, and gravity of the gas phase.

Introduction
A knowledge of the viscosity of hydrocarbon fluids is needed to study the dynamical or flow behavior of these mixtures through pipes, porous media, or more generally wherever transport of momentum occurs in fluid motion. Since flow is predominantly in the laminar region in petroleum reservoirs, the influence of fluid viscosity on this flow is especially important.
As early as 1894, Onnes and Onnes and de Haas noted that the viscosities of homologs under corresponding states could be correlated. The theorem of corresponding states has been further developed and applied to the viscosity of pure, nonpolar gases under pressure by Comings, Mayland, and Egly.
Serious discrepancies in the viscosity of pure hydrocarbon gases at high pressures have been called to our attention by Comings, Mayland, and Egly. They made a careful analysis of the following methods commonly used to measure gas viscosities:Oscillating disc viscometer.Rolling ball viscometer.Capillary tube viscometer