bluuebunny/crossref_metadata_2025_split huggingface dataset:
SACROC Unit Operations
Authors: Allen H.H. , LaRue C.R. 
Published: December 2007

Abstract
A comprehensive and exhaustive study was made by engineering representatives of many owner companies and consultants between the discovery of the Kelly-Snyder field in Nov., 1948 and March 1, 1953, the effective date of SACROC Unit. Since that date the operating personnel have placed in operation a pressure maintenance program consisting of two component parts:water injection into wells located generally along the longitudinal axis of the field andless efficient edge wells shut-in with allowables transferred to more efficient wells in the center of the field.
The performance of the reservoir under pressure maintenance has been closely studied and analyzed. Practical evaluations have been made, and operations continued or modified as conditions required. Results have been most gratifying, and based upon that experience and performance, future operations and planning can be determined with a much greater degree of certainty than when the project started.
This paper will present the pertinent fact relating to pressure maintenance operation of the Kelly-Snyder field by SACROC Unit since the actual beginning of pressure maintenance in 1954 up to the present time.

Introduction
It is one thing to discover an oil reservoir of 2,800 million STB of oil but quite another thing to produce it. Thus, in the case of Kelly-Snyder field, Scurry County, Tex., early performance indicated a primary recovery of only 670 million bbl, and that 2,130 million bbl would not be recovered if primary methods only were used. Hence, the creation of SACROC Unit and the pressure maintenance program. Despite the fact that the organizational set-up of SACROC Unit is most complex and little understood, except by those involved with over-all operations, no time or space will be taken to discuss that subject because it is outlined in the SACROC Unit Agreement.

SACROC Pressure Maintenance Plan
Early in the life of Kelly-Snyder field, it was apparent that a solution gas drive was the only natural production mechanism because presence of water along the southeast flank of the field proved to be only a water drive of insufficient magnitude to be considered a recovery mechanism.
Directional Drilling - A Comparison of Measured and Predicted Changes in Hole Angle
Authors: Sutko Adolph A. , Myers George M. , Gaston Jonathan D. 
Published: December 2007

This paper compares measured hole angle changes and predicted angles between bit force and hole direction. The predictions were made using an analytical program that assumes the drillstring is a static beam with varying properties constrained by borehole geometry. Data were taken from a field study conducted in Dubai. Agreement was good for 8 of 12 cases and improved with use of an interpretive length.

Introduction
Directional drilling continues to play an important part in offshore field development. A more thorough and firmly based understanding of the factors affecting hole angle and direction are needed so that drilling can be done as economically as possible and so that overall drilling technology can advance at a uniform rate.Probably the most concentrated recent effort toward a logical and thorough understanding of the factors involved in directional drilling is that of Millheim. Among his works are a series of articles dealing with proper use of directional tools, bottomhole assembly (BHA) mechanics, and behavior of single- and multiple-stabilizer BHA's. In the first of these articles, he lists 46 references but states that there is still much to learn. Later in the series, he presents material derived from postanalysis of more than 70 wells in the U.S. and overseas, field tests, computer analyses, literature, and research.In other articles, Millheim et al. describe a finite-element method of analyzing BHA's and Millheim discusses hole curvature as it relates to hole trajectory. Among the conclusions reached are that reaction forces at the bit can be calculated, the dropping or building tendencies of various assemblies can be assessed, and hole curvature can play a significant role in deviation and deviation control. Walker and Friedman present a three-dimensional force and deflection analysis of a drillstring and state that the use of the model can improve the understanding of how various assemblies compare and can assist in determining the direction the bit will drill. Fischer describes an analysis of a drillstring in a curved borehole and concludes that valuable insight into the mechanical performance of drillstrings can be gained using such an analysis. In discussing the factors that affect the control of borehole angle in straight and directional wells, Bradley gives information relating to the location of drillstring tangency, drill collar stiffness and weight, placement of stabilizers, and downhole motor case flexibility. He emphasizes the need for additional research into the bit/rock interaction as it affects the deviation process.Analytical programs like those in Refs. 1 through 6 calculate the force acting at the bit. Although it generally is agreed that the bit tends to drill in the direction of this force, Millheim and Warren indicate that no method is available to predict rates of build, drop, or turn for a particular set of conditions.
JPT
P. 2090＾
Use of a Well Model To Determine Permeability Layering From Selective Well Tests
Authors: McGee Paul R. 
Published: December 2007

This paper describes the use of a numerical well model to determine permeability layering from selective drillstem and production tests for two wells in two Middle East reservoirs. Permeabilities of various geologic layers of a stratified reservoir may be determined by careful planning of selective drillstem tests coupled with a well model to interpret the pressure behavior of each test.

Introduction
The Middle East Reservoir A is a complex carbonate reservoir exhibiting considerable lateral and vertical lithological changes with consequent variation in reservoir characteristics. Based on three previous wells, six geologic units were identified, only five of which are considered productive. Drilling of Well 4 was planned to include drillstem tests of each of these five geologic units to determine their flow characteristics. After the well was completed, it was perforated and acidized and long-term production tests were performed. A numerical well model was developed for use in interpreting these tests by matching pressure buildup performance. This numerical model incorporated all the known geological zonation based on geologic analysis of the four wells drilled to that time. A three-dimensional well simulator was used in this modeling. However, it was used in a two-dimensional radial mode.Later this same technique was applied to an infill well in Middle East Reservoir B. This reservoir has been producing for several years. It is a carbonate reservoir and has considerable variation in lithological characteristics in both the lateral and vertical direction. Selective drillstem tests were conducted on Well 149 at the time it was drilled.

Well 4 Drillstem Tests
A schematic of the drillstem test procedure is shown in Fig. 1. After each geologic unit was drilled, a packer was set isolating that unit while a drillstem test was conducted. The well was produced for time periods ranging from 4.4 to 7 hours with two pressure recorders opposite the producing intervals. The well then was closed, and the buildup pressures were recorded.Reservoir A is highly undersaturated such that single-phase oil flow occurred at all times in all tests. While the reservoir has an aquifer, the well is located on the crest of the reservoir a considerable distance away from the water zone. Cores were obtained from all geologic units for Well 4.A radial well model was constructed to simulate the performance of this well. To have the first grid point as close to the wellbore as possible, it was selected 1 ft (0.30 m) from the wellbore. Six additional radial segments increase logarithmically in size to encompass a total drainage radius of 4,000 ft (1219.2 m). This radius is roughly comparable to the distance from the well to the leading edge of the oil/water contact. A constant-pressure outer boundary was assumed. However, for the short-term drillstem tests, it did not matter whether the outer boundary was sealed or at constant pressure due to the short duration of the tests.
JPT
P. 2023＾
Underbalanced Drilling Dynamics: Two-Phase Flow Modeling and Experiments
Authors: Lage Antonio C. V. M. , Fjelde Kjell K. , Time Rune W. 
Published: December 2007

Summary
A dynamic model based on the drift-flux formulation is presented for treating transient phenomena in underbalanced drilling (UBD) operations. A set of mechanistic steady-state procedures for dealing with the definition of flow patterns, pressure drops, gas volumetric fractions, and in-situ velocities completes the model. The iteration between those mechanistic laws and the conservation equations is discussed. The numerical solution uses a composite explicit scheme, which reduces false oscillations and numerical diffusion. In addition, details about the boundary treatment are also presented.
Model predictions are validated through comparison to fullscale experimental data in two distinct transient situations: first, a typical liquid unloading, and second, the injection of a high-velocity single pulse and a sequence of two pulses of a gas/liquid mixture. The comparisons address model limitations and improve the understanding of the physics involved.
Multilateral Pressure-Transient Response
Authors: Yildiz Turhan 
Published: December 2007

Summary
This study presents a 3D analytical model to analyze the transient flow into multilateral horizontal wells. The model considers arbitrary phasing angle, selective lateral completion, nonuniform formation damage around each lateral, and areal and vertical permeability anisotropy. Using the model, transient pressure, derivative, and rate distribution characteristics of multilateral horizontal wells are investigated. Flow regimes are examined. Asymptotic approximations for each flow regime and pseudoskin equation are provided.
A sensitivity study is carried out to identify the parameters controlling the transient pressure, derivative, and fractional rate responses. The sensitivity study includes the impact of lateral length, orientation, and number, formation anisotropy, and the degree of formation damage around the laterals. If all the laterals are put on production during the test, it is almost impossible to estimate principal permeabilities, their directions, and skin factors around each lateral by examining transient pressure and derivative responses only. When all the branches produce, the transient rate distribution is strongly controlled by the skin owing to formation damage. Therefore, if transient rate distribution data, as well as the pressure, is recorded during the test, nonuniqueness in the interpretation of test data may be minimized. Although it is more expensive and time-consuming, testing each lateral individually may provide more reliable estimates of formation properties and damage.
Theory of Multicomponent, Multiphase Displacement in Porous Media
Authors: Helfferich Friedrich G. 
Published: December 2007

Abstract
The basis of a general theory of multicomponent, multiphase displacement in porous media is presented. The theory is applicable to an arbitrary number of phases, an arbitrary number of components partitioning between the phases, and variable initial and injection conditions. Only the effects of propagation are considered; phase equilibria and dependence of fractional flows on phase compositions and saturations are required as input, but any type of equilibrium and flow behavior can be accommodated. The principal simplifying assumptions are the restriction to one dimension, local phase equilibria, volume additivity on partitioning, idealized fluid dynamic behavior, and absence of temperature and pressure effects. The theory is an extension of that of multicomponent chromatography and has taken from it the concept of "coherence" and, for practical application, the tools of composition routes and distance/time diagrams. The application of the theory to a surfactant flood is illustrated in a companion paper.1
Multiwell Variable-Rate Well Test Analysis
Authors: McEdwards Donald G. 
Published: December 2007

Abstract
A computer-based nonlinear least-squares method of pressure matching is presented. The program analyzes for transmissivity, T, storativity, S, and production well skin effect, Δps. It also detects the type (leaky or no-flow) and location (angle and distance) of any vertical hydrologic boundary that may be present. Pressure data affected by several production wells can be treated and, in addition, the variable production-rate history of each production well can be modeled as rigorously as the quality of the production data permit. The technique handles variable flow rates by a linear flow rate solution. Pressure data from several wells may be analyzed simultaneously for reservoir properties. The assumptions concerning the reservoir and well system are those of the conventional analysis methods that employ the line-source solution.
The computer program minimizes the statistic χ2, which is the average of the square of the normalized difference between the calculated pressure change and the observed pressure change:
The normalized pressure difference is used to give equal weight to all pressure responses, regardless of their magnitude. The average of the square of the normalized pressure differences is used so that results from several analyses that differ in their number of observed pressures can be compared.
In-Situ Combustion Model
Authors: Coats Keith H. 
Published: December 2007

AbstractThis paper describes a numerical model for simulating wet or dry, forward or reverse combustion in one, two, or three dimensions. The formulation is considerably more general than any reported to date. The model allows any number and identities of components. Any component may be distributed in any or all of the four phases (water, oil, gas, and solid or coke).The formulation allows any number of chemical reactions. Any reaction may have any number of reactants, products, and stoichiometry, identified through input data. The energy balance accounts for heat loss and conduction, conversion, and radiation within the reservoir.The model uses no assumptions regarding degree of oxygen consumption. The oxygen concentration is calculated throughout the reservoir in accordance with the calculated fluid flow pattern and reaction kinetics. The model, therefore, simulates the effects of oxygen bypassing caused by kinetic-limited combustion or conformance factors.We believe the implicit model formulation results in maximum efficiency (lowest computing cost), and required computing times are reported in the paper.The paper includes comparisons of model results with reported laboratory adiabatic-tube test results. In addition, the paper includes example field-scale cases, with a sensitivity study showing effects on oil recovery of uncertainties in rock/fluid properties.
Production Technology Experience in a Large Carbonate Waterflood, Denver Unit, Wasson San Andres Field
Authors: Ghauri W.K. 
Published: December 2007

Shell Oil Co. currently is operating a large waterflood project in the Permian San Andres dolomite reservoir in west Texas. The project comprises 900 producers and 360 injectors. In addition to major infill drilling programs, a substantial remedial and reconditioning program has been carried out. Highlights of production technology experience are presented.

Introduction
The Denver Unit waterflood project in the Wasson San Andres field in West Texas ranks among the largest supplemental recovery projects currently operating in the U.S. (Fig. 1). Shell Oil Co. is the operator and holds the major working interest. The paper has evolved through several phases of infill development drilling and flood pattern modifications that have been carried out in the course of conducting the waterflood project.
The paper is divided into two parts. The first deals with a brief history of the waterflood with the objective of providing the project setting for the production technology practices currently being followed. The emphasis is placed not on the statistical data per se but rather on the evolutionary process through which present procedures have been developed, as well as their interrelationship with the geologic, petrophysical, and reservoir aspect as as they pertain to the project. The second part describes the specific practices of well completion, well stimulation, injection profile control, artificial lift, flood surveillance, and related drilling, remedial, and reconditioning operations now being used and how they have contributed to the enhancement of ultimate recovery from the project.

Historical Background
The Wasson San Andres field was discovered in 1936. The bulk of primary development at 40-acre (162 000-m2) well spacing was completed by the early 1940's. Supplemental recovery operations were initiated with unitization and commencement of water injection in 1964 (Fig. 2).
The producing horizon is the Permian San Andres dolomite formation at an average depth of 5,200 ft (1585 m). Gross oil pay thickness varies between 200 and 500 ft (60 and 150 m). The structure is an anticline capped by dense dolomite and underlain by an essentially inactive aquifer. Solution-gas drive has been the primary producing mechanism. Table 1 shows a summary of basic project data. The oil reservoir has an original gas cap. Although some production has occurred from the gas cap, primarily before unitization, Shell's policy during waterflooding operations has been to leave the gas cap unexploited to conserve reservoir energy and prevent waste by the migration of oil into the gas cap.
When unitization was effected in 1964, the geologic concept of the reservoir was a simplistic one and was markedly different from the rather complex model that has evolved today. The original definition of the San Andres reservoir was based on gross geologic correlations of reservoir-quality rock and the assumption that this rock largely was interconnected over the entire extent of the unit.
Correlation of Gelation Times for Polymer Solutions Used as Sweep Improvement Agents
Authors: Terry Ronald E. , Huang Chyi-gang , Green Don W. , Michnick Michael J. , Willhite G. Paul 
Published: December 2007

Abstract
Gelled polymers are being used increasingly to redirect or modify reservoir fluid movement in the vicinity of injection or production wells for the purpose of improving water/oil ratios. To date, little has been reported about the chemistry of the in-situ gelling process that involves a multivalent metal ion, a reducing agent, and a polymer. This paper reports results of a study of the relationship between process parameters and gelation time, which is defined as the time required for the solution to reach a specified viscosity. The gelation time is determined by continuous monitoring of the viscosity following addition of the chemical reactants. The varied parameters in the investigation include polymer type and concentration, chromate concentration, and reducing-agent type and concentration. Five different polyacrylamide polymers were used including polyacrylamides that were hydrolyzed to different degrees, an anionic copolymer, and a cationic copolymer. Sodium bisulfite and thiourea were used as reducing agents. It was determined that for a given polymer-reducing agent system, the reciprocal of gelation time is a linear function of the reciprocal of the polymer concentration for a fixed metal ion concentration. The slope of the straight line is a function of the degree of polymer hydrolysis, the existence of the anion or cation functional groups, and type of reducing agent used.
Thermal Stability of Starch- and Carboxymethyl Cellulose-Based Polymers Used in Drilling Fluids
Authors: Thomas David C. 
Published: December 2007

Abstract
Starch- and cellulose-based polymers have been used to control water loss for many years. Thermal degradation of the polymers is the most important problem with their use. Representative starch and cellulose fluid loss reducers were tested for their thermal stability in mud systems. The thermal decomposition was found to be dependent on both exposure time and temperature. The rate of decomposition can be predicted using first-order reaction rate kinetics and the decomposition activation energy estimated for both polymer types. This technique allows the calculation of a polymer's usable lifetime at a given temperature. A table of half-lives (time for fluid loss to double) vs. exposure temperature is presented for both starch- and cellulose-based polymers. This paper discusses the results of the calculations and the method used to obtain the data. The method is generally applicable to any material used in drilling fluids that is subject to thermal degradation.
Adjustment of Differential Liberation Data to Separator Conditions
Authors: Al-Marhoun Muhammad A. 
Published: December 2007

Summary
Solution gas/oil ratio (GOR) and oil formation volume factor (FVF) are normally obtained from differential or flash liberation tests. However, neither the differential liberation process nor the flash liberation process can represent the fluid flow in petroleum reservoirs. Therefore, data obtained from any of the two test procedures must be adjusted to approximate the fluid behavior in the reservoir. At low pressures, the conventional method of adjustment yields negative values of solution GOR and values of oil FVF of less than 1. This, of course, is not physically correct.
This paper presents a new method for adjusting the differential liberation data to separator conditions. The new method overcomes the limitations of the conventional adjustment method and makes the low-pressure extension of the curves of solution GOR and oil FVF more accurate. The method is based on the fact that data obtained from both the differential and flash liberation tests should yield the same value of oil relative density at reservoir conditions. The new method is tested using 425 PVT files, yielding results that are consistent with the physical behavior of solution GOR and oil FVF.
Structure and Process Optimization for the Use of a Polymeric Relative-Permeability Modifier in Conformance Control
Authors: Eoff Larry , Dalrymple E. Dwyann , Reddy B. R. , Everett Don M. 
Published: December 2007

Summary
For many years, relative-permeability modifiers (RPMs) have received a great deal of attention from the oil- and gas-production industry. Because of the completion techniques used in many wells, it is not always practical or cost-effective to protect the hydrocarbon interval properly during a water-shutoff treatment. RPMs offer the option of bullheading a treatment without zonal isolation, which is designed to decrease water production with little or no decrease in oil or gas production.
This paper describes the laboratory development and optimization of a polymeric RPM. The resulting material can be best described as a brush polymer consisting of a polymeric backbone grafted with methoxypolyethylene glycol (MPEG). Various phases of the development will be discussed, such as the optimization of the molecular weight of the backbone polymer and the concentration of grafted MPEG. Details of laboratory evaluations will also be provided, including a discussion of the use of multipressure-tap flow cells for permeability-reduction tests, the effect of polymer concentration, and the effect of saturations. These test results show that the RPM polymer should be placed with a systematic approach consisting of proper preflushes and postflushes for optimum results.