bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Mechanistic Model for Circulating Fluid Temperature
Authors: Hasan A. R. , Kabir C. S. , Ameen M. M. , Wang Xiaowei 
Published: December 2007

Abstract
An accurate fluid temperature profile in both tubing and annulus during circulation is desirable to allow computation of circulation rates. However, because the circulating fluid exchanges heat with the formation, fluid temperature changes both with time and depth. Consequently, the fluid's intrinsic properties of density and viscosity would change with an increase in circulation time, thereby influencing the optimal pumping rate.
Existing analytic methods for solving the heat transfer problem at hand generally assume a constant fluid inlet temperature plus a constant heat flux (or temperature) at the wellbore/ formation interface. These assumptions ignore the reality that the temperature of the circulating fluid entering the wellbore from the holding tank increases with time because of the heat carried by this fluid from the hot formation. Fluid circulation also causes a gradual decrease in heat flux between the wellbore and the formation. These assumptions inherent in the available methods may reduce their reliability in many situations.
In this work, we present a generalized analytical model for circulating fluid temperature in both conduits, for both forward and reverse circulation cases, as a function of circulation time and well depth. We use an energy balance for the fluid in the tank to express its temperature as a function of time. To account for the changing heat flux at the wellbore/formation interface, the principle of superposition in time is used. The heat flux schedule is represented by adding constant heat sources at successive times. This model is flexible to adapt any transient temperature distribution model, TD, and presupposes unsteady heat transport in the formation while steady heat flow occurs in the tubular.
Our results show that, under some circumstances, thud temperatures estimated using these approaches deviate significantly from that estimated without account for the varying nature of tank temperature or formation heat flux This difference is especially true when the temperature difference between the bottomhole and the wellhead is large. Thus, varying mud tank temperature and formation heat flux need to be accounted for when estimating flowing fluid or circulating mud temperature in the Arctic. However, when the bottomhole and wellhead temperature difference is small, the extra computation involved in this procedure is probably not worth the marginal gain in accuracy. Field examples illustrate the model's application.
On Estimating Recovery Efficiency in Depletion Drive and Water Drive Reservoirs
Authors: Sandrea Rafael 
Published: December 2007

Recently the API Subcommittee on Recovery Efficiency published a comprehensive statistical study of recovery processes, based on the actual performance of some 150 reservoirs located throughout the U. S., Canada and the Middle East.' Eighty of these reservoirs had only a depletion drive mechanism and the other 70 reservoirs had active water drives. Moreover, all of the water drive and 84 percent of the gas drive reservoirs were produced from sandstone formations, whereas 16 percent of the gas drive samples were produced from carbonate rocks. In the API study, which in effect is an extension of the well known investigations of Craze and Buckley and Guthrie and Greenberger regression equations were developed for each of the two mechanisms mentioned above, relating the recovery efficiency, RE, to several physical parameters that describe some of the oil and formation characteristics.
For Depletion Drive Reservoirs (sands, sandstones, and carbonate rocks):
................(1)
For Water Drive Reservoirs (sands and sandstones):
..............(2)
The standard errors of estimate of Eqs. 1 and 2 are 22.9 and 17.6 percent, respectively. To simplify the solution of these equations, the following nomographs were prepared. Note that recovery efficiency is expressed as a percent of the oil in place at the original pressure for the water drive reservoirs, and at the bubble-point pressure for the gas drive cases. Equivalent values for the recovery factor in barrels per acre-foot of net pay may be obtained by multiplying the values of recovery efficiency
by 71.58 times the oil-in-place term
(use Boh for depletion reservoirs and Boi for water drive reservoirs). For details on the valid range of values of the individual parameters that appear in Eqs. 1 and 2, the original study' should be consulted. However, the nomographic scales essentially represent the range of the data used in their correlation.

Nomenclature
B = oil formation volume factork = absolute permeability, darciesp = reservoir pressure RE = recovery efficiency, percent S = saturation, fractionu = viscosity, cp = porosity, fraction
P. 277
An Iterative Matrix Solution Method Suitable for Anisotropic Problems
Authors: Watts J.W. 
Published: December 2007

Abstract
Often, the most time-consuming step in solving partial differential equations in two space partial differential equations in two space dimensions is an iterative solution of the finite-difference equations. For the closed boundary case, this solution is difficult when the equations are anisotropic, as they are normally when mesh spacing is much longer in one direction than in the other. This paper presents a solution method for use in such problems. The method is shown to be very fast in an anisotropic problem, but not as fast as other available methods in an isotropic problem. the extension to three space dimensions is outlined.

Introduction
In the finite-difference solution of multidimensional parabolic or elliptic equations, a set of many linear parabolic or elliptic equations, a set of many linear simultaneous algebraic equations arises. The most time-consuming part of the solution is the solving of this set of equations, normally accomplished by using some iterative method. Often the finite-difference equations are anisotropic. By anisotropic it is meant that two of the of diagonal coefficients in each equation are much larger than the other off-diagonal coefficients. When this occurs, the solution becomes more difficult for the closed boundary case. Until recently it appeared that line successive overrelaxation was the best technique to use in such a situation. Now, a method developed by Stone appears best among those published. This paper describes an alternative method for use with anisotropic systems. The method can be considered to be a specialization of a more general technique discussed by De la Vallee Poussin. It consists of a correction applied at each mesh point in a line, coupled with line successive overrelaxation. The method is shown to be very fast in a two-dimensional anisotropic problem. The extension to three dimensions is outlined, but no calculations are presented for that case. A theoretical analysis of the new method will be the subject of a later paper. paper.

METHOD
Consider the physical system from which the finite-difference equations are derived, as shown in Fig. 1. The system is represented by a matrix of mesh points. The finite-difference equation at each mesh point takes the form
.........(1)
All coefficients with the exception of di, j, are nonnegative. If the problem is elliptic (steady-slate), bi, j is zero. This equation is more commonly written as follows.
.....(2)
where
This equation is written for each mesh point to create the set of simultaneous algebraic equations that must be solved. The matrix formed from the coefficients of these equations is often symmetric. The mesh points in Fig. 1 are arranged in a square pattern.
SPEJ
P. 47
Experimental Compaction and Evolution of Physical Properties of Clay-Sediments
Authors: Djéran-Maigre Irini , Grunberger Daniel , Rousset Gilles 
Published: December 2007

Summary
For a better understanding of sedimentary basin development, we studied the evolution of kaolinite with compaction. We made experimental compaction tests in a specially designed oedometric cell. We then characterized the obtained samples microscopically and macroscopically and made correlation between those parameters.
Paraffin Problems in Crude Oil Production And Transportation: A Review
Authors: Misra Sanjay , Baruah Simanta , Singh Kulwant 
Published: December 2007

Summary
Problems related to crystallization and deposition of paraffin waxes during production and transportation of crude oil cause losses of billions of dollars yearly to petroleum industry. The goal of this paper is to present the knowledge on such problems in a systematic and comprehensive form. The fundamental aspects of these problems are defined, and characterizatin of paraffins and their solubility tendencies have been discussed. It has been established conclusively that n -paraffins are predominantly responsible for this problem. Comprehensive discussion on the mechanism of crystallization of paraffins has been included. Compounds other than n-paraffins, especially asphaltenes and resins, have profound effects on solubility of n-paraffins. In evaluations of the wax potential of a crude, the climate of the area concerned should be considered. Under the most favorable conditions, n-paraffins form clearly defined orthorhombic crystals, but unfavorable conditions and the presence of impurities lead to hexagonal and/or amorphous crystallization. The gelation characteristics are also affected the same way. An attempt was made to classify the paraffin problems into those resulting from high pipeline pressure, high restarting pressure, and deposition on pipe surfaces. Fundamental aspects and mechanism of these dimensions are described. Wax deposition depends on flow rate, the temperature differential between crude and pipe surface, the cooling rate, and surface properties. Finally, methods available in the literature for predicting these problems and evaluating their mitigatory techniques are reviewed. The available methods present a very diversified picture; hence, using them to evaluate these problems becomes taxing. A top priority is standardizing these methods for the benefit of the industry.
A Software System for Oilfield Facility Investment Minimization
Authors: Ding Z. X. , Startzman R. A. 
Published: December 2007

Summary
Minimizing investment in oilfield development is an important subject that has attracted a considerable amount of industry attention. One method to reduce investment involves the optimal placement and selection of production facilities. Because of the large amount of capital used in this process, saving a small percent of the total investment may represent a large monetary value.
The literature reports algorithms using mathematical programming techniques that were designed to solve the proposed problem in a global optimal manner. Owing to the high-computational complexity and the lack of user-friendly interfaces for data entry and results display, mathematical programming techniques have not been given enough attention in practice. This paper describes an interactive, graphical software system that provides a global optimal solution to the problem of placement and selection of production facilities in oilfield development processes. This software system can be used as an investment minimization tool and a scenario-study simulator.
The developed software system consists of five basic modules: (1) an interactive data-input unit, (2) a cost function generator, (3) an optimization unit, (4) a graphic-output display, and (5) a sensitivity-analysis unit.
We used data from both onshore and offshore oil fields to test the performance of the developed system. We obtained significant reduction of computer run time and memory storage. Use of this system saved several million dollars in investments. These results show that the developed system can be applied where significant investments in offshore and/or onshore field developments are involved.
Modeling a Fractured Well in a Composite Reservoir
Authors: Chen Chih-Cheng , Raghavan Rajagopal 
Published: December 2007

Summary
We develop a new model for a fractured well producing a composite reservoir. In this model, the vertical fracture may transect the inner zone of the composite-reservoir system. Computational issues are addressed so that the development given here becomes a practical tool. We examine results pertaining to systems in which damage is deep to demonstrate the utility of the model.
Generalization of the API RP 14E Guideline for Erosive Services
Authors: Shirazi S.A. , McLaury B.S. , Shadley J.R. , Rybicki E.F. 
Published: December 2007

Abstract
The commonly used practice for controlling sand erosion in gas and oil producing wells is to limit production velocities following the API RP 14E. This guideline contains a procedure to calculate a threshold velocity, the flow velocity below which an allowable amount of erosion occurs. While providing advantages of computational ease, the approach has some disadvantages. One is that, while many factors influence the erosion rate, RP 14E includes only one factor, the density of the medium. Thus, factors such as flow geometry, type of metal, sand size, and Reynolds number are not accounted for. Another disadvantage is that the tolerable amount of erosion, in terms of loss of wall thickness, is not specified in RP 14E. A method is presented to overcome these disadvantages by (1) accounting for many of the physical variables in the flow and erosion processes and (2) including a way to predict the maximum penetration rate for sand erosion. The capabilities of the method are evaluated by comparing predicted penetration rates with experimental data found in the literature.
In this paper, the method is applied to calculate threshold velocities. The computational procedure allows an allowable amount of erosion to be specified in mils per year for elbows, tees and direct impingement geometries. Threshold flowstream velocities are calculated for carrier fluids of crude oil, water, and methane at elevated pressure. Resulting threshold velocities are presented for a range of sand sizes, pipe diameters, sand production rates, and methane pressures. Results show that threshold velocities for single phase gas flows are much lower than threshold velocities for single phase liquid flows.

Introduction
Sand erosion is a major problem in many production situations because small amounts of sand entrained in the produced fluid can result in significant erosion and erosion/corrosion damage. Even in "sand free" or clean service situations where sand production rate is as low as a few pounds per day, erosion damage could be very severe at high production velocities. Sand erosion can also cause localized erosion damage to protective corrosion scales on pipe walls and result in accelerated erosion/corrosion damage.
The objective of this work is to develop guidelines for predicting a threshold velocity and/or particle size below which only a small, allowable amount of erosion occurs. Threshold velocity guidelines help operators to estimate safe production velocities in erosive services, and serve as a tool to engineers for the cost effective design of piping systems, the selection of piping materials, and the selection of appropriate screen sizes for new wells.
The Use of Coiled Tubing During the Wytch Farm Extended Reach Drilling Project
Authors: Summers Tim , Larsen Henrik Aslak , Redway Mark , Hill Gardiner 
Published: December 2007

Abstract
The largest onshore oilfield in Western Europe is situated in an environmentally sensitive coastal area on the south coast of England. Initial development of the field in the late 1970's focused on accessing reserves underlying the onshore section of the reservoir. In 1989, various development options were screened to access the offshore section of the reservoir, containing some 80 million barrels of recoverable oil. In 1991, the decision was made to access these reserves through extended reach drilling (ERD) from an existing onshore well-site. This development is currently underway, with three out of a planned eleven wells already drilled and producing.
This paper will describe the application of Coiled Tubing in the logging and completion phases of the ERD wells drilled to date, including:-Operational details of Coiled Tubing deployed cement evaluation logging suites to a measured depth of 5,695m (18,685ft) at a horizontal departure of 4,950m (16,241ft), and a cased-hole vertical seismic profile to a measured depth of 4,391 m (14,330ft) at a horizontal departure of 3,800m (12,468ft).Operational details of Coiled Tubing use during the completion; setting/pulling plugs, shining sliding sleeves, sand/debris clean-outs, including novel tool and procedural developments.Results of predictive modelling to assess the point of helical lock-up, and comparisons of field data with these predictions.Details of operations involving the use of friction reduction chemicals to enhance Coiled Tubing penetration.The effects of ERD well tangent section angle on Coiled Tubing penetration.
Conclusions are made as to the value of Coiled Tubing in ERD wells to minimise rig time and the current limits of technology.

Introduction
Wytch Farm is the largest onshore oilfield in Western Europe, and is situated on the southern coast of England, approximately 100 miles south west of London. The main reservoir lies under Poole Harbour, extending offshore under Poole Bay (Figure 1), and is in an Area of Outstanding Natural Beauty with Sites of Special Scientific Interest and Special Protection Areas, noted for its landscape, ecology and amenity value.
The field was discovered in 1974, and the majority of production comes from two oil bearing sandstone formations.
Stability of Displacement Fronts in WAG Operations
Authors: Virnovsky George A. , Helset Hans Martin , Skjaeveland Svein M. 
Published: December 2007

Abstract
This paper presents an analytical and numerical study of the stability of gas-oil-water displacement fronts in two spatial dimensions. The flow equations are simplified by averaging in the dip-normal direction assuming vertical equilibrium to give analytical expressions for three-phase pseudo relative permeabilities and capillary pressures for a stratified reservoir.
A similarity transform results in a set of two coupled, ordinary differential equations and a simple technique is presented to identify the traveling-wave solution when certain conditions are met, and the shape of the front is calculated. The technique is based on an analysis of initial and boundary conditions and is verified by numerical simulation.
Dietz's classical stability theory for two-phase displacement fronts has recently been extended to layered reservoirs. To our knowledge, the present paper is the first to treat three-phase flow. It is shown that stable water-oil-gas fronts occur only for a limited number of the injection gas-water ratio, if at all.
An Inexpensive Mud for Deep Wells
Authors: Coffer Henry F. , Clark Roscoe C. 
Published: December 2007

Abstract
Development of a new mud designed to give the desirable drilling characteristics of the conventional lime mud but without its inherent limitations is discussed. The work includes both laboratory and field testing of the mud.
The mud has been used successfully in nine wells with considerable cost reduction. It is resistant to contaminants such as anhydrite, gyp, cement, and salt water and does not gel at high temperature. Field results have shown that the mud can compete economically with low- or high-pH caustic-quebracho muds with the added advantage that it yields better gauge holes and its filtrate is not as damaging to the pay formation.

Introduction
The use of conventional lime-base drilling muds has made possible the drilling of wells in areas where contamination from gyp, anhydrite, and salt water flows are encountered. Their desirable drilling characteristics and ease of maintenance have allowed the drilling of long sections of open hole and have often eliminated the necessity of a protective intermediate casing string. Conventional lime muds, however, suffer from several disadvantages which often make their usage impractical.
First, and of greatest importance in deeper holes, is the occurrence of high temperature gelation which prevents the successful application of various logging tools and perforating guns due to the solidification of the mud in the bottom of the hole. Further evidence of this gelation of conventional lime muds will be more apparent in the near future as workover jobs require washover operations in order to pull the packers set in lime mud.
Of almost equal importance is the high cost of the maintenance of a lime mud. This eliminates or sharply curbs its usage in areas where contamination from gyp, anhydrite, and salt is light enough that it can be successfully handled by use of low-pH or high-pH caustic-quebracho muds. Unfortunately, its elimination from a cost standpoint also limits the use of muds with filtrates containing calcium ion which is effective in reducing the swelling and sloughing of shales, thus yielding better gauge holes.
Active Damping of Torsional Drillstring Vibrations With a Hydraulic Top Drive
Authors: Jansen J. D. , van den Steen Leon , Zachariasen Erik 
Published: December 2007

SummaryThis paper describes the development and field testing of a new active-damping system to eliminate "stick/slip" torsional drillstring vibrations. The system controls the energy flow through a hydraulic top drive and makes the top drive react as a tuned vibration damper. The control algorithm, outlined in the paper, was implemented in software in the electronic control system for the pump unit of the top drive. Dedicated workshop testing allowed for a rapid installation at the rigsite. The system was field tested in a deep exploration well in the Barents Sea and contributed to excellent coring performance by eliminating torsional vibrations while coring hard limestone.
Produced-Water Reinjection and Fracturina in Prudhoe Bay
Authors: Martins J. P. , Murray L. R. , Clifford P. J. , McLelland W. G. , Hanna M. F. , Sharp J. W. 
Published: December 2007

SummaryThis paper presents an analysis of approximately 159 injectors from the Prudhoe Bay oil field that were subjected to periods of injection with seawater, produced water, and miscible injectant (MI) over a 10-year period. The long-term effects on injection performance of produced-water quality, fluid temperature, fracture growth, well trajectory, and other factors are quantified.