bluuebunny/crossref_metadata_2025_split huggingface dataset:
Steamflood Expansion Using Slim-Hole Injectors
Authors: Dennis E. L. , Johnson K. R. , Kirby R. H. 
Published: December 2007

Summary
This paper describes a successful steam-injection vertical expansion recently implemented in California's Midway Sunset field with slim-hole injection wells. Slim-hole injectors were chosen over conventional injectors to reduce capital investment. The savings allowed drilling of additional injection wells, which were used to optimize steam placement on the basis of reservoir architecture. Two vertical expansion designs were compared at a fixed cost with either conventional or slim-hole steam injectors. The conventional well design had 10 injection wells and three temperature-observation wells. The steamdrive targets were two steeply dipping turbidite depositional lobes containing multiple, vertically segregated sand bodies. Selection of conventional well locations was based on the upper primary reservoir compromising injection location in the lower secondary reservoir. The slim-hole plan, consisting of 38 injectors and 10 temperature-observation wells, was selected because of its advantages. The capital cost for the slim-hole wells was about the same as the conventional program. Approximately three slim-hole injectors could be drilled for the cost of one conventional injector. With additional wells, injector locations were optimized for both the upper primary and lower secondary reservoirs. These additional injection wells provided improved profile control and steamflood management of the individual sand bodies within each reservoir. As a result of the vertical expansion, incremental production has increased steadily since project startup.
Glenn Pool Surfactant-Flood Expansion Project: A Technical Summary
Authors: Bae J. H. 
Published: December 2007

Abstract
After a successful pilot test, a 92-acre surfactant-flood expansion project was conducted in the William Berryhill lease of the Glenn Pool field, Creek County, OK. The field had been waterflooded and had an average residual oil saturation (ROS) of 30% PV. At the end of Oct. 1992, ≈ 1.14 million bbl of incremental oil was produced, which accounted for about one-third of the residual oil. This is the largest amount of oil produced by a surfactant flood.
Scaling of Multiphase Flow in Simple Heterogeneous Porous Media
Authors: Zhou Dengen , Fayers F. J. , Orr F. M. 
Published: December 2007

AbstractThe nature of flow in porous media is determined by the interaction of the physical properties of the medium and fluids, and by the interplay of various forces involved in the displacement process. Identifying flow regions at a given reservoir operating condition is a key issue in forecasting reservoir performance and hence of optimizing operations. This work identifies dominant flow regions at various conditions. Three dimensionless groups, NgvM/(1 + M) (gravity/viscous ratio), NcvM/(1 + M) (capillary/viscous ratio) and Ri2 (shape factor), are defined and used to resolve flow regions. The analysis shows that the relative magnitudes of forces involved in the system combined with the reservoir properties determine the flow region and fluid distribution in the medium.By choosing appropriate ranges for the dimensionless numbers, recovery processes can be specified from the general theory, and the boundaries to flow regions confirmed by comparison with existing experimental and simulation results. Three commonly studied flow systems have been investigated, which are miscible displacements without dispersion (Ncv ≈ 0) in layered reservoirs, immiscible displacements (Ngv ≈ 0) in layered and homogeneous media, and flow in highly fractured reservoirs.
On the Subject of Abnormally Pressured Gas Reservoirs
Authors: Hurst William 
Published: December 2007

This is a discussion of SPE-2225-PA "Water Production from Abnormally Pressured Gas Reservoirs in South Louisiana", by W. E. Wallace, published in the Aug., 1969, issue of JPT.
In his paper on abnormally pressured gas reservoirs in South Louisiana, the main thesis as expressed by W. E. Wallace is that in high pressure gas fields much of the water produced with the gas results from the compaction of the shale from the weight of the overburden with the lowering of reservoir pressure to release water to be produced with the gas. This is his conclusion for several of the examples cited in his paper, and as he terms this, such is water produced from the shales and in-situ water resulting from the compressibility of the water within the reservoir.
If he wishes to approach it as such, I recognize that his thinking is that of the geologist whereas my interpretation is that of a reservoir engineer.
Mr. Wallace describes this water released as the compaction of the shale bodies, subject to the increasing weight of the overburden with the lowering in reservoir pressure. But I must ask, "To what extent does the weight of the overburden take effect?"
The Effect of Axial Tension on the Deflection of Centralized Casing
Authors: Sutko A.A. 
Published: December 2007

The midpoint deflection of centralized casing is often calculated using the equation for a uniformly loaded beam with two fixed ends:
..........(1)
where y M is the maximum deflection (excluding that of the centralizers themselves), w the weight per unit length of casing, L the distance between centralizers, E the modulus of elasticity, I the moment of inertia of the casing cross-section, and 0, the hole angle. The units are pounds, degrees and either feet or inches. At least two service companies use this equation in their literature. Although Eq. 1 takes into account the casing weight and strength, it does not consider the tension in the casing. This tension, which is due to the weight of the casing below, reduces the casing deflection just as the sag in a rope or cable is lessened if the rope or cable is more tightly stretched. The equation for the maximum deflection of cable loaded under its own weight, is
.............(2)
where y T is the maximum deflection and T is thew L tension. Substituting a power series for cosh and2 T simplifying leads, for our purposes, to the following form:
......(3)
Using Eqs. 1 and 3, it is possible to describe a method that includes the effect of both the strength properties and the tension in the calculation of the properties and the tension in the calculation of the maximum deflection of centralized casing. The method is as follows:1. Calculate the casing deflection using Eq. 1.2. Assume that this deflection exists in a cable and using Eq. 3, calculate the tension that would be present. present. 3. Add to this tension the actual tension, T A, in the casing (using either an estimated value or one calculated as outlined in Ref. 2).4. Calculate the actual casing deflection by using a form of Eq. 3.
......(4)
A quicker way to get an idea of be general effect of including tension can be obtained by combining Eqs. 1, 3, and 4:
............(5)
y r T L Fig. 1 is a plot of vs . For many oilfieldy M 48 EIy r applications is about 0.85 to 0.90 or higher.y M
P. 7
Methods for Numerical Simulation of Water and Gas Coning
Authors: MacDonald R.C. 
Published: December 2007

Abstract
This paper describes and evaluates three numerical methods for the simulation of well coning behavior. The first method employs the implicit pressure-explicit saturation (IMPES) analysis with pressure-explicit saturation (IMPES) analysis with the production terms treated implicitly. The second technique is similar to the first model except that the interblock transmissibilities are also treated implicitly in the saturation equation. The third model is fully implicitly with respect to all variables in a manner qualified in the introduction and utilizes simultaneous solution of the difference equations describing the multiphase flow. The use of implicit transmissibilities in the IMPES model results in a several-fold increase in the allowable time-increment size over that attainable with the implicit production IMPES scheme, while the computing time per step is increased by less than 10 percent. The fully implicit model accepts larger time-increment sizes than possible with the first two methods but requires 3.3 times the computing time per time step needed by the second model. The fully implicit model is substantially more efficient for problems involving high capillary forces (treated explicitly in the IMPES methods) and small computing grid blocks at the wellbore. In problems involving moderate capillary forces and larger grid spacings, the fully implicit method and the implicit transmissibility IMPES technique are comparable in computing efficiency. The results of three coning studies are presented: a water-oil problem, a three-phase coning presented: a water-oil problem, a three-phase coning example, and a comparison of simulation results with a laboratory coning experiment. Also presented is an analysis of truncation error and a comparison of computational work requirements.

Introduction
This study was performed to evaluate three finite-difference schemes for simulating well coning behavior. The basis for this evaluation was the IMPES (implicit pressure-explicit saturation) model with explicit transmissibilities and implicit production terms. This model is referred to hereafter production terms. This model is referred to hereafter as Model 1. The next model evaluated in this work is an IMPES model similar to Model 1, except that the saturation-dependent interblock transmissibilities are treated implicitly rather than explicitly in the saturation equation. The third model is fully implicitly with respect to all variables and terms transmissibilities, pressure, saturation an capillary pressure - and utilizes simultaneous solution of the difference equations describing the multiphase flow. These two models are referred to hereafter simply as Model 2 and Model 3. For the purpose of clarity all models are described in purpose of clarity all models are described in reference to the problem of incompressible, two-phase flow. The techniques are equally applicable, however, to compressible, three-phase flow models. The examples chosen for illustration employ both incompressible and compressible simulation models.
SPEJ
p. 425
A Formula for the Successful Management of Drilling Information
Authors: Magner M. J. , Booth J. E. , Williams J. W. 
Published: December 2007

Summary
Many drilling information systems have come and gone over the past decade. Some systems were very sophisticated because they used the latest technologies and human interfaces. Many factors about these systems and their implementation, however, proved to be weak points. In some cases, the system may have been too expensive to develop and/or maintain, too difficult to use, or simply did not meet the client's business need.
The Mobil Drilling Data Center (DDC) is a successful drilling information management system that has been in continuous operation for 13 years. This paper outlines key factors that have made the DDC one of the industry's most comprehensive and long-lived drilling information systems.
Design and Development of An Artificial Neural Network for Estimation of Formation Permeability
Authors: Mohaghegh Shahab , Arefi Reza , Bilgesu Ilkin , Ameri Samuel , Rose Deanna 
Published: December 2007

Summary
Permeability is one of the most important characteristics of hydrocarbon-bearing formations and one of the most important pieces of information in the design and management of enhanced recovery operations. With accurate knowledge of permeability, petroleum engineers can manage the production process of a field efficiently. Although formation permeability is often measured in the laboratory from cores or evaluated from well-test data, core analysis and well-test data are only available from a few wells in a field, while the majority of wells are logged.
In this study, we have designed an artificial neural network that can accurately predict the permeability of the formations by use of the data provided by geophysical well logs. Artificial neural network, a biologically inspired computing method which has an ability to learn, self-adjust, and be trained, provides a powerful tool in solving pattern recognition problems.
In the past, others have attempted to use well logs to predict permeability.1 The problems with previous approaches, however, were two-fold: the limited number of variables (only one variable— porosity) and the use of regression analysis as the main tool for correlations. The approach introduced in this paper attempts to overcome these shortcomings. We do this by first, using many variables from well logs that may provide information about the permeability, and second, recognizing the existence of possible patterns between these variables and formation permeability by use of artificial neural networks. Neural nets are analog, inherently parallel, distributive systems. These characteristics enable artificial neural networks to be successful in predicting the formation permeability in rocks from well-log data.
Adaptation of Reservoir Engineering Software to a DOS/Linux PC
Authors: Emanuel A. S. , Jones R. C. , McWilliams R. S. , Tsaio J. C. 
Published: December 2007

Summary
Recent publications have described the implementation of state-of-the-art reservoir engineering applications based on integrated networks of mainframe, workstation, and desktop computers. These facilities provide excellent resources for geologic and engineering applications, but at the cost of substantial investment in computer hardware, network installation, and systems staffing. This paper describes an adaptation of similar state-of-the-art applications to a desktop platform that minimizes the required hardware and system investment.
The platform is an Intel 486 or Pentium-based PC with two hard drives and 32 to 64 MB of memory. One disk is partitioned to a standard DOS/Windows environment. The other disk is partitioned to the Linux operating system. Linux is a freely available clone of Unix for the 80386/80486 CPU, which is supported by a worldwide volunteer effort. A machine of this type can be constructed from components for $4,000 to $8,000, depending on CPU and memory. A number of proprietary modeling codes have been ported over so that the PC can provide much of the capability of the network systems.
On the Linux disk, there are interactive graphics codes for log analysis, geostatistical reservoir characterization, mapping geologic data into reservoir models, streamtube modeling, and scale up of fine-grid models to coarse grid. On the DOS disk, there are the typical vender-supplied applications for pressure-transient analysis, production analysis, spreadsheet processing, and word processing. A proprietary, general-purpose 3D reservoir simulator is available under both DOS and Linux. The PC can be both networked on the DOS and Linux sides or run stand-alone. If networked, Linux can also provide an X-terminal facility to other Unix or Linux workstations. The PC is sufficiently fast to provide geostatistical processing for reservoirs of several hundred wells. With 64 MB of memory, finite-difference models of up to 20,000 gridblocks can be accommodated for a two-phase, black oil formulation. Using streamtube and hybrid simulation techniques, reservoir models incorporating 300 to 400 wells are practical. We have found the DOS/Linux PC to be useful in several niche situations: remote locations where there is no network, locations where there is insufficient capital budget for a workstation, and locations where network charges are insupportable or the workstations are overloaded.
A RAD Approach to Client/Server System Development
Authors: Brulé Mike , Fair Walt , Jiang Jun , Sanvido Ron 
Published: December 2007

Summary
The capability, richness, and leverage of inexpensive commercial operating systems, off-the-shelf applications, and powerful development tools have made building feature-rich client/server systems possible in rapid time and at low cost—ushering in a new level of systems integration not before possible. We achieve rapid application development (RAD) by using a flexible and extendible client/server integration framework. The framework provides the means to integrate in-house and third-party software applications with databases and expert-system knowledge bases and, where appropriate, provides communication links among the applications. We discuss the integration framework's capabilities, explain its underlying system architecture, and outline the methods and tools used to customize and integrate many diverse applications.
A 3D Analysis of a Bottomhole Assembly Under Large Deflection
Authors: Li Zifeng , Ma Xingrui , Huang Wenhu , Liu Xisheng 
Published: December 2007

Summary
A 3D static mathematical model of a bottomhole assembly (BHA) including steerable downhole motor assembly under large deflection has been established. The forces and deflections of the drillstring have been accurately computed by making use of the method of weighted residuals, the weighted objective function, and the method of optimization to calculate the tangency point and to reduce the effect of the indistinct tangency point conditions. The effects of the weight on bit, the borehole geometry, the geometry and tool face rotation of the BHA on the bit building, and right walking force have been studied separately. There is a significant difference between the bit forces of large deflection analysis and small deflection analysis.
Real-Time Job Monitoring and Performance Control of Primary Cementing Operations as a Way to Total Quality Management
Authors: Spoerker H. F. 
Published: December 2007

Summary
A high-accuracy wellsite mud-logging system was developed and implemented to compare standpipe pressures and annular flow rates during primary cementing operations with real-time predictions from a hydraulic simulation model. This paper investigates the development of possible cementing job execution problems, such as low (laminar) flow rates in the annulus at critical job stages, resulting in unsatisfactory mud displacement and ultimately inadequate zonal isolation. Ways to eliminate or at least control free-fall-induced problems through hydraulic simulation at the rigsite and comparison with real-time job parameters, such as pump rates, standpipe pressures, and annular return rates, are presented with detailed descriptions of tested flowmeter equipment and logging experience gained during field testing. Several case studies are presented that compare predictions from job simulation with recorded data (flow-in/-out and standpipe pressure) highlighting special trends, such as fracturing formations, caused by excessive equivalent circulating densities (ECD's) during free-fall conditions.
Optimum Position for Wells Producing at Constant Wellbore Pressure
Authors: Camacho-V Rodolfo , Rodríguez Fernando , Galindo-N Agustín , Prats Michael 
Published: December 2007

Abstract
This paper deals with the determination of the optimum position of several wells, producing at constant different wellbore pressures from a two-dimensional closed -boundary reservoirs, to maximize the cumulative production or the total flow rate. To achieve this objective we use an improved version of the analytical solution recently proposed by Rodriguez and Cinco-Ley1 and an optimization algorithm based on a quasi-Newton procedure with line search. At each iteration the algorithm approximates the negative of the objective function by a quadratic relation derived from a Taylor series.
The improvement of Rodríguez and Cinco's solution1 is attained in four ways. First, an approximation is obtained, which works better at earlier times (before the boundary dominated period starts) than the previous solution. Second, the infinite sums that are present in the solution are expressed in a condensed form, which is relevant for reducing the computer time when the optimization algorithm is used. Third, the solution is modified to take into account the possibility of having wells starting to produce at different times. This point allows us to deal with the problem of getting the optimum position for an infill drilling program. Last, the solution is extended to include the possibility of changing the value of wellbore pressure or being able to stimulate any of the wells at any time.
When the wells are producing at different wellbore pressures it is found that the optimum position is a function of time, otherwise the optimum position is fixed.
Further Advances in Coiled-Tubing Drilling
Authors: Eide Egil , Brinkhorst Jan , Volker Heinz , Burge Phil , Ewen R.L. 
Published: December 2007

Abstract
The use of coiled tubing (CT) to drill horizontal re-entry wells has received considerable interest in the industry over the last two years. The benefit of being able to drill at balance, safely and in a controlled manner, with nitrogen to reduce downhole pressure while drilling highly depleted reservoirs, provides an advantage over conventional techniques, particularly in reducing formation damage. This paper describes such a horizontal re-entry drilled in the shallow depleted waterflooded reservoir Barenburg in northern Germany. The scope of work for this project included (1) cutting windows through 6 5/8- and 9 5/8-in. casing, (2) drilling a 5 7/8-in.-medium-radius curve, (3) running a 5-in. liner and a 5½-in. parasitic string for nitrogen injection, (4) drilling a 4 3/8-in. horizontal with nitrogen to maintain a balanced condition, (5) running openhole logs, and (6) running 3½-in. slotted liner. The entire program was executed with no intervention from a conventional rig or workover hoist. A special structure to be positioned over the well to support the CT injector head and to provide a work platform had to be constructed for this type of operation. A dedicated mast for lifting pipe and downhole tools was placed on the substructure. The development of a surface-controlled orienting tool and an adjustable motor provided excellent directional capabilities on a 2 3/8-in. CT. This program represents a significant extension of the capabilities of drilling with CT.

Introduction
Over the last 2 years, a number of oil companies have gained experience with CT drilling that has been carried out mainly as re-entry operations. Encouraging results have been reported that generated the idea to develop this technology further as an integrated package capable of carrying out the entire operation without the intervention of a conventional rig or workover hoist. Because no service company on the market could provide the entire scope of work, BEB Erdgas & Erdol GmbH decided to cooperate with two companies on a partnership basis to develop required tools and equipment. A trust was formed between the two service companies for this project.