bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Method for Blowout-Rate Prediction for Sour-Gas Wells, Oldenburg Fields, Germany
Authors: Kikani Jitendra , Schwarz Heinrich , Graute Johannes 
Published: December 2007

Summary
In view of the toxicity of H2S, sour-gas production has to be carefully planned for safe operation. For the determination of safe evacuation distances in the unlikely event of an accident, well-blowout conditions had to be investigated. A methodology for predicting blowout rates from sour-gas wells in the south Oldenburg area in Germany is presented. Flow under sonic conditions, wellbore dynamics, reservoir capacities and their interdependencies control the fluid movement. Generally the blowout rates have been calculated by superimposing reservoir and tubing performance curves (based on steady-state correlations). This approach predicts lower short-term transient rates than actually occurs. A finite-element pipe-rupture model for ultrashort-term transient rate calculations is used. A coupling mechanism between these results and a reservoir simulator with a steady-state vertical-flow-performance correlation is then defined. A time-based switching criterion is determined iteratively for each situation when the flow goes subsonic, and traditional well outflow models can be used.
A Method for Improving Line Successive Overrelaxation in Anisotropic Problems-A Theoretical Analysis
Authors: Watts J.W. 
Published: December 2007

Abstract
A recent paper describes a method of improving the convergence rate of line successive overrelaxation (LSOR) in anisotropic problems. That paper presents computed results showing the method to cause dramatic improvements, but includes no theoretical analysis of the method.
This paper offers such an analysis, explaining mathematically how the method works and why it has the effect it does. In doing so, it clears up, at least partially, two important uncertainties left by the previous paper - when to use the method and how to arrive at an optimal extrapolation parameter.
Briefly, the analysis shows that the method removes the components of certain eigenvectors from the solution vector. As shown by the analysis, sometimes this removal causes a tremendous improvement in the rate of convergence and at other times it has no effect. This indicates, in most cases, whether or not to use the method.
Furthermore, the analysis shows that in certain simple problems the method is really a special case of LSOR. In these cases, the optimal extrapolation parameter can be calculated exactly. In other parameter can be calculated exactly. In other cases, it can be estimated using the same techniques as used with LSOR.

Introduction
One step in the calculations involved in reservoir simulation is the solution of a large set of simultaneous equations. Often this solution is the most time-consuming part of the simulation.
There are several methods used for solving these equations. One of the more common of these is line successive overrelaxation or LSOR. A recent paper describes a way to accelerate the convergence rate of LSOR. That paper shows the modified method, called LSORC, to be very good in an anisotropic case, but no better than LSOR in an isotropic case.
Briefly, LSORC consists of LSOR, with the lines oriented along columns, combined with a correction made by columns. This correction is made in such a manner that the sum of residuals in each column of mesh points is forced to zero.
In this paper we analyze LSORC as applied to a homogeneous but not necessarily isotropic Neumann problem. We show that the correction made using problem. We show that the correction made using LSORC removes the components of certain eigenvectors of the LSOR iteration matrix from the solution vector. Removing the components of these eigenvecton eliminates the effects of their associated eigenvalues on the rate of convergence. In isotropic cases these eigenvalues have little or no effect on the convergence rate, so no improvement is obtained. In anisotropic cases they determine the rate, and removing their effects causes large improvements in convergence rate.
This analysis clears up two points not covered in the original paper. First, it helps to determine when LSORC should and should not be used. Second, it shows that LSORC is really a special form of LSOR. Therefore, methods used to estimate an optimal extrapolation parameter for LSOR apply to LSORC as well.
Probabilistic Drilling-Cost Estimating
Authors: Kitchel B. G. , Moore S. O. , Banks W. H. , Borland B. M. 
Published: December 2007

Summary
Risk analysis has become an integral part of the decision-making process in the petroleum industry. Petroleum engineers, geoscientists, and project managers use risking tools to evaluate the economic viability of both exploration and development projects.
Conoco drilling engineers have combined a drilling-cost spreadsheet with a forecasting and risk-analysis program to predict the range of both cost and days necessary to drill a well. The model uses risk analysis and incorporates Monte Carlo simulation along with regional cost data to generate drilling cost and time requirements for a well. Using this model, the Conoco drilling engineers evaluate multiple drilling alternatives effectively. Subsequently, the drilling engineers' more informed risk-related recommendations aid management in the decisionmaking process of drilling a prospect or developing a project.
This paper describes the spreadsheet and the risk-analysis program used to generate the range of costs and days for a given well. In addition, the paper offers an example of the output data generated from the programs with an interpretation for a sample well.
Laboratory Studies of Fines Movement in Gravel Packs
Authors: Jennings A. R. 
Published: December 2007

SummaryMost high-permeability, high-deliverability, unconsolidated, and loosely consolidated sandstone formations require gravel packing as part of the completion procedure. The gravel packs are designed to allow the soft formations to produce sand-free at economical production rates. Techniques and procedures used for gravel-size selection are typically based on criteria that have been used by the industry for more than 20 years.Simple laboratory flow tests using clean gravel columns and fines from a variety of formations, however, indicate that existing gravelsize-selection guidelines are too conservative. Although the gravels selected are very efficient in preventing formation fines from entering the pack, the buildup of silt and fines at the gravel/formation interface can cause quick degradation of the effective permeability through the pack.Improvements in gravel-pack life can be obtained by using gravel with higher initial permeability, either by increasing the average size of the gravels used (i.e., larger sand grains) or through the use of more spherical particles (synthetic gravel). The laboratory tests reported in this paper suggest that both alternatives can be considered in gravel-pack operations. It is a further premise of this paper that sufficient improvements have been made in gravel-pack procedures in recent years to allow effective placement of the proposed higher-permeability gravels.
Compressibility Effects on Transient Gas Pipe Flow
Authors: Mouser Gerald F. , Govier J.P. 
Published: December 2007

Abstract
Methods of iterative solution for the partial-differential equations governing the transient flow of gases in pipelines are obtained by using the method of characteristics and linear finite-difference techniques. Solutions are developed for (1) a constant gas compressibility factor throughout transient conditions, and (2) a variable gas compressibility factor at constant temperature, dependent upon pressures encountered during transient flow. Theoretical studies are made to compare results using both approaches for pipelines operating at various constant flowing temperatures. Results show greater differences between the two methods at lower values of flowing temperature due to the more rapidly changing compressibility factor as a function of variable pressure.

Introduction
The partial-differential momentum and mass equations describing transient gas pipe flow have been solved by various numerical methods. Among the techniques frequently employed in recent studies are implicit finite-differences and the method of characteristics. While these studies have been concerned with the numerical techniques and stability criteria required in transient flow solutions, few investigations have examined the effect of a variable gas compressibility factor on transient behavior. The purpose of this study is to develop and apply the numerical equations of transient gas pipe flow based on (1) a constant gas compressibility factor evaluated at the average of inlet and outlet pressures at initial time, and (2) a gas compressibility factor completely dependent upon the gas pressures encountered in the pipeline during steady- and unsteady-state flow. For both approaches, digital computer solutions of the partial-differential equations describing gas pipe flow are made possible by application of the characteristics transformation and linear finite-difference approximations. The theoretical results, based on both constant and variable gas compressibility, are compared graphically for various transient flow conditions with particular emphasis placed upon temperature effects. Numerous limiting assumptions are required in the development of any steady- or unsteady-state flow equations. In this study, the following assumptions are made.
Incorporating Seismic Attribute Maps in 3D Reservoir Models
Authors: Behrens R. A. , MacLeod M. K. , Tran T. T. , Alimi A. O. 
Published: December 2007

Summary
We introduce a new geostatistical method to incorporate seismic attribute maps into a three-dimensional (3D) reservoir model. The method explicitly honors the difference in vertical resolution between seismic and well-log data. The method, called sequential Gaussian simulation with block Kriging (SGSBK), treats the seismic map as a soft estimate of the average reservoir property. With this method, the average of the cell values in any one vertical column of grid cells is constrained by the value of the seismic map over that column. The result is a model that contains vertical variability driven by well logs and the vertical-variogram model and spatial variability driven by the seismic map and the areal-variogram model.
A Single-Phase Wellbore-Flow Model for Horizontal, Vertical, and Slanted Wells
Authors: Ouyang Liang-Biao , Arbabi Sepehr , Aziz Khalid 
Published: December 2007

Summary
In this paper, a single-phase wellbore-flow model is presented that incorporates not only frictional, accelerational, and gravitational pressure drops, but also the pressure drop caused by inflow. The new model is readily applicable to different wellbore-perforation patterns and well completions, and can be easily incorporated into reservoir simulators or analytical, reservoir-inflow models.
It is found that the influence of either inflow or outflow depends on the flow regime present in the wellbore. For laminar wellbore flow, wall friction increases because of inflow but decreases because of outflow. For turbulent wellbore flow, inflow reduces the wall friction, whereas outflow increases the wall friction. New wall-friction-factor correlations for wellbore flows have been developed that can be applied to determine the wall-friction shear and the frictional pressure drop for either inflow (production well) or outflow (injection well) and for either laminar or turbulent flow regimes.
Calculation results show that the accelerational pressure drop may or may not be important compared with the frictional component, depending on the specific pipe geometry, fluid properties, and flow conditions. It is recommended that the new wellbore-flow model be included in wellbore/reservoir coupling models to achieve more accurate predictions of pressure drop and inflow distribution along the wellbore, as well as the well production or injection rates.
Simulation System Provides Unique Training Method for the Oilfield
Authors: Beck Kent , Schwendemann Ken 
Published: December 2007

Summary
Today's oilfield service environment has undergone significant change from that which existed 10 years ago. Integrated services and turnkey operations are becoming the norm for the industry, and oilfield service companies are finding themselves linked with operators and contractors in long-term service contracts that would never have been considered in the 1980's.
While these new alliances may prove to be the catalysts for energizing economic growth in the oilfield, they bring with them their own set of operational problems. For example, the integrated solutions approach requires that all parties have a thorough understanding of overall economic and operational project parameters as well as a defined area for which each must take responsibility. Therefore, to meet the demands of the integrated solutions concept, "the partners" must be able to assess all project needs properly so that the solution provided accomplishes the economic and operational goals for all involved. Each must have a detailed technical understanding of a wide variety of equipment, systems, and available resources. This is the area in which a major drawback to the integrated solutions concept often occurs—it has been difficult to provide a fast, efficient method to keep users abreast of the continuing enhancements to a technology that already appears to be state of the art! Additionally, development of unique systems often results from the combined efforts of integrated teams, and to ensure that the systems will provide the expected results, it is equally as important to be able to provide training for the personnel that are responsible for the day- to-day use and maintenance of the new systems.
In this paper, we will discuss a unique simulator that can resolve the training needs that have surfaced as a result of the rapidly changing operational concepts in the oilfield environment. We will present the concepts of the equipment simulator and capabilities of the global simulator methodology, and we will use an actual case history to describe in detail how the equipment simulator was used offshore on a recent well-test job in the Gulf Coast area to introduce a new well-test tool and to train a new design engineer.
With this information, we conclude that the use of the simulator will provide unparalleled training support for oilfield equipment and system applications and facilitate efficient development of integrated solutions for oilfield projects.
A Case History of the Postle Area-Computer Production Control and Reservoir Simulation
Authors: Irwin R.A. , Tucker C.W. , Schwartz H.E. 
Published: December 2007

The Postle Area Computer Control Operation (PACCO) handles 95 oil wells, 45 water injection wells, and 10 water supply wells about 300 miles from the control computer. After a year's operation, the system showed itself to be highly satisfactory and effective, and pleasing to everyone - whether in operations, engineering, accounting. or management.

Introduction
Oil reserves were discovered in 1958 in the Pennsylvanian Age sands in the Postle Area of Texas County, Okla., by Republic Natural Gas Co. Step-out wildcats and development drilling established additional production and by 1960 five separate fields were identified. Subsequent development has gradually coalesced these fields to form a major producing area called the Postle Area, located near the center of the Oklahoma Panhandle (Fig. 1). This area now includes 38,000 productive acres and produces approximately 27,000 bbl of oil per day and 35 MMcf of gas per day from 332 producing wells. Five pressure maintenance units are in operation and are currently injecting 70,000 BWPD. Two additional pressure maintenance units are being formed.
A computer production control and data acquisition system operates 95 oil wells, 45 water injection wells, 10 water supply wells, five central tank batteries, two production test satellites and four water injection stations in four of the five units. The control computer is located in Oklahoma City, approximately 300 airline miles southeast of the producing properties.
Reservoir simulator model studies were used to monitor project performance, design a pressure maintenance program, and change the operational guidelines for a second project. They are expected to result in a 15 percent increase in ultimate oil recovery. The use of computers, of the digital reservoir simulator model, and of the computer production control and data acquisition system has afforded optimum project management of reservoir performance and operations.
In 1962, when development was approximately 20 percent complete, Mobil Oil Corp. acquired the Republic Natural Gas Co.'s acreage, which is a significant portion of the oil-productive acreage in the Postle Area. The following is a discussion of the ensuing exploitation of the five major Pennsylvanian Age oil-bearing sands underlying the Postle Area and the computer production control and data acquisition system as it was applied in the Postle Area.

Geology
The Postle Area is located in the southern portion of the Hugoton Embayment of the Anadarko basin in Texas County, Okla. The Pennsylvanian Age sands in this area underlie a portion of the Permian Age Hugoton gas field.
Editor's note: This paper is a combined version of the original manuscripts of "A Review of Postle Area - Development, Unitization, Pressure Maintenance and Computer Applications," by R.A. Irwin, C.W. Tucker, and H.E. Schwartz, Jr.; and "Computer Production Control and Data Acquisition as Applied in Postle Area," by H.E. Schwartz, Jr.
Problems in Interpretation of Pressure Fall-Off Tests in Reservoirs With And Without Fluid Banks
Authors: Kazemi Hossein , Merrill L.S. , Jargon J.R. 
Published: December 2007

Secondary- and tertiary-recovery injection projects may cause fluid banks to form in the reservoir. Pressure fall-off testing is often used in hopes of determining the parameters for each side of the fronts that delineate such banks. A mathematical model was used to investigate the practicality of such an approach.

Introduction
Pressure fall-off testing consists of shutting in an injection well and measuring the surface pressure or preferably the bottom-hole pressure vs time. This test is the counterpart of a pressure buildup test in a production well. The analyses of the pressure-time data in both tests, therefore, are remarkably similar. Nonetheless, because of the,.jnjection mode of operation, pressure fall-off testing has some unique characteristics.
In secondary- and tertiary-recovery projects three major fall-off situations may arise: liquid injection, gas injection, and alternate gas and liquid injection. The first two cases can be subdivided as follows:
Liquid Injection Case
(1) Liquid injection before fillup,
(2) Gas injection in aquifers for storage,
Gas Injection Case
(1) Air injection as in in-situ combustion,
(2) Gas injection in aquifers for storage,
(3) Gas injection for pressure maintenance,
(4) Gas injection in miscible displacement,
(5) Gas injection in gas cycling.
From this classification we learn that the mathematics of pressure fall-off testing must account for multiphase flow in many complex situations. Fortunately, numerical methods and computers have made the task of simulating such situations fairly simple and economical. However, to interpret actual fall-off test data from the field is still very difficult. The main problem is the nonuniqueness of the situations that give rise to nearly identical pressure fall-off behavior. The analysis of pressure-time data from a pressure fall-off test yields information about the interwell transmissibilities, interwell average pressure, and skin factor. Fall-off testing has also been used to track the movement of the burning front in in-situ combustion, to locate the position of the outer radius of a water bank, and to help in calculating formation damage depth. In general, "front tracking," or locating discontinuities by pressure fall-off is very intricate and must be used with extreme caution. Often, the front or discontinuity cannot be detected, and what appears to be a front or a transmissibility change (damage or improved zone) on the fall-off curve is actually a reflection of some other phenomenon. Considerable care must also be taken in determining transmissibilities from the slopes of the straight-line segments. As we will show, there are several factors besides the transmissibility that can influence these slopes. Afterflow (wellbore storage) invariably occurs in fall-off testing and in many cases can cause misinterpretation of data. Recent advances in this area have laid the foundation for understanding such problems.
Electronically Enhanced Remote-Actuation Systems Improve Deepwater Completions and Capabilities
Authors: Hopmann Mark , Dodd P. L. 
Published: December 2007

Summary
With offshore rig demand at a premium and costs often exceeding U.S. $100,000/D, the economics of developing burgeoning deep-water arenas is closely tied to technologies that expedite production and reduce rig time. This paper describes a new, mud-pulse-frequency-based communication technique that actuates and manipulates downhole tools equipped with onboard electronics. The down-hole tools (which may include permanent or retrievable packers and sliding sleeves) are programmed at the surface to recognize one of 16 discrete actuation commands from a computer-controlled, portable terminal unit. Once in position, the tools are actuated upon receipt of a specific command sent from the portable terminal unit. As many as 16 devices can be actuated independently of one another in a single wellbore; and, because the system is independent of absolute pressure in the tubing, there is no need to install, for example, a tubing plug to set a packer.
By using packers equipped for electronically enhanced remote actuation, days of rig time can be saved by accelerating the completion cycle. Sliding sleeves equipped with the new technology can be remotely shifted without using coiled tubing or wireline. Electronically enhanced remote actuation allows for reduction, and in some cases total elimination, of common well-intervention operations associated with getting the initial completion in the ground. The resulting savings in operating expense and overall completion cost can be substantial, as has been proved in several recent deepwater applications.