bluuebunny/crossref_metadata_2025_split huggingface dataset:
Aspects of Multicomponent Resistivity Data and Macroscopic Resistivity Anisotropy
Authors: Schoen J. H. , Yu Liming , Georgi D. T. , Fanini O. 
Published: December 2007

Summary
New induction-logging hardware makes it possible to obtain both resistivity and resistivity-anisotropy data. Resistivity anisotropy, the ratio of vertical to horizontal resistivity, is the macroscopic effect of thinly layered formations in which logging tools have insufficient vertical resolution to properly resolve the individual beds, or laminae. Generally, there are two special types of layering.
Laminated shaly sands. The sediment consists of thin-bedded sand/shale sequences (anisotropy in these sands originates from the contrast of shale and sand resistivity). Finely layered anisotropic sands. The sand is composed of layers of different grain sizes/sorting (anisotropy in these sands originates from the resistivity contrast associated with the different water saturation).
The interpretation of conventional resistivity data is well understood. However, interpretation of vertical resistivity and resistivity anisotropy is not well understood and is often counterintuitive. We have used forward modeling to illustrate the effects of porosity variability in layered formations. For example, we have investigated the porosity-layering effect, which varies from an average porosity of 20 p.u. by +/− 5, 10, and 15 p.u. Three types of layering were considered: graded bedding and square- and sin2-porosity variation with depth. The modeling shows that sharp bed boundaries create the maximum resistivity anisotropy for any two component resistivity distributions.
The new induction-logging hardware comprises three mutually orthogonal, transmitter-receiver coil configurations that measure all data necessary to derive both resistivity and resistivity anisotropy of the formation in vertical, deviated, and horizontal wells. Simple models illustrate the physics, and the tools' capabilities are demonstrated with a synthetic example. Based on the petrophysical analysis of porosity contrast and layering type, a resistivity model is constructed, and the tool responses of this model are computed. With inversion techniques, both resistivity and resistivity anisotropy can be recovered.
Understanding Fracture Performance by Integrating Well Testing and Fracture Modeling
Authors: Cipolla C. L. , Mayerhofer M. J. 
Published: December 2007

Summary
This paper presents case histories and field data that detail the application of well test data to calibrate fracture models, understand fracture performance, and optimize treatment designs. The paper includes field results from gas reservoirs in the Rocky Mountains and west Texas. The case histories also illustrate the application of postfracture pressure-buildup data to identify reasons for fracture treatment problems and to confirm treatment success. The paper also includes a novel data set that illustrates fracture performance from a liquid CO2 stimulation (no sand, no water) in west Texas. The case histories illustrate the importance of integrating well test data with fracture treatment optimization, showing how this process can improve our ability to reliably make multimillion-dollar decisions concerning proppant selection and fracture treatment size.
Characterizing Curing Cement Slurries by Electrical Conductivity
Authors: Backe K. R. , Lile O. B. , Lyomov S. K. 
Published: December 2007

Summary
Electrical conductivity is a parameter that can be used to monitor the entire hardening process of oilwell cement slurries. The theoretical relationship among conductivity, porosity, cement chemistry, and ion content is discussed. The theory is confirmed by experiments; the decline in the slurry conductivity is primarily a function of porosity decrease and, thus, the degree of hydration. The applied results show that the electrical conductivity of curing slurries reflects strength development and that rapid hydration will reduce the risk of gas migration.
Uncertainty in Production Forecasts Based on Well Observations, Seismic Data, and Production History
Authors: Hegstad Bjørn Kåre , Omre Henning 
Published: December 2007

SummaryA stochastic model in a Bayesian setting, conditioned on well observations, seismic amplitude data and production history, is defined. Samples of reservoir characteristics and production forecasts from the posterior model are used to evaluate the impact of various observation types. Well observations are found to be important to production forecasts due to near-well conditioning, while seismic data impact facies geometries but not the production forecasts. Production history contributes significantly only if certain events, such as gas-breakthrough time, are observed in wells. A brute-force rejection sampling approach may work well if proper conditioning on well observations and seismic data is done.
Effect of Pressure Gradient and Initial Water Saturation on Water Injection in Water-Wet and Mixed-Wet Fractured Porous Media
Authors: Tang Guo-Qing , Firoozabadi Abbas 
Published: December 2007

Summary
A systematic study of the effect of wettability and initial water saturation on water injection and imbibition is made in Kansas outcrop chalk samples. (Kansas outcrop chalk is very similar to the rock matrix of the North Sea fractured chalk reservoirs.) Water-injection tests were conducted at different pressure gradients to simulate the effect of gravity (that is, negative Pc) on recovery. Based on a large number of carefully conducted tests, the following conclusions are drawn:
Initial water saturation has a pronounced effect on water injection in an intermediate-wet chalk. This effect is much less pronounced for a strongly water-wet chalk. The effects are also in opposite directions. Pressure gradients (which simulate the negative Pc effect) have a very strong effect on water-injection performance in an intermediate-wet chalk.
Our interpretation of these experiments leads to the conclusion that recovery from the chalk reservoirs may be nearly independent of wettability state. The results from the experiments also reveal that there is no relation between laboratory measurements of spontaneous imbibition and field performance of mixed-wet reservoirs, even when the wettability state is perfectly restored in the laboratory.
A True In-Situ Fracturing Experiment Final Results
Authors: Parrish R.L. , Stevens A.L. , Turner T.F. 
Published: December 2007

Summary
A true in-situ oil shale retort bed preparation experiment was performed by detonating an explosive slurry that had been displaced from well bores into preformed horizontal hydraulic fractures. The objective was to test this method for producing a distributed fracture network with sufficient void and permeability for retorting in a controlled manner. Numerous diagnostic and evaluation measurements were performed during the course of the experiment for initial site characterization, hydraulic fracture assessment, explosive displacement and detonation performance, and post detonation fracture and permeability assessment. Results show that fractures were induced; the fractures were found to be randomly distributed with no regions of extensive fracturing or shale dislocation. Enhancement of permeability was limited essentially to enlargement of the preformed hydraulic fracture horizons into which the explosive slurry was inserted and detonated. Successful retorting would be contingent on the ability to retort shale layers with random fractures but without significant permeability between the enlarged fractures.

Introduction
The potential advantages of true in-situ processing techniques, as compared with mining and surface retorting, for extracting hydrocarbons from oil shale have been recognized for many years. With such techniques, the only linkage between the underground shale bed and the surface is through a series of wells. Both the bed preparation and the retort processing phases are conducted from the surface through these wells. Resulting attractive features are that requirements for mining large quantities of raw shale and disposal of the spent shale are eliminated. Other environmental impacts, such as water requirements, may be reduced significantly.
In preparing an oil shale bed for in-situ processing, the naturally impermeable oil shale must be rubblized to introduce sufficient void and permeability. This permits process gases to flow from injection wells to the combustion front and permits product liquids and gases to flow from the pyrolysis zone to production wells during retorting. Past experiments1,2 have used variations of two basic methods (well bore springing and hydraulic/explosive fracturing) to fracture the shale bed and attempt to achieve the required void and permeability. The well bore springing method3 involves the detonation of explosive charges contained within the well, while the hydraulic/explosive fracturing method involves the detonation of slurry explosives that have been displaced from wells into preformed horizontal hydraulic fractures (hereafter called hydrofractures or simply cracks).
Gas Shutoff Evaluation and Implementation, North Slope, Alaska
Authors: Hupp D. , Frankenburg A. , Bartel P. , Roberts G. 
Published: December 2007

Summary
Oil production on Alaska's North Slope has been limited as a result of gas production and the ensuing gas handling-facility constraints. Diagnosis of gas production problems is complicated by the fact that many of the wells are high-angle or horizontal. This paper presents case studies in the diagnosis and treatment of excess gas production in three horizontal oil wells located on the North Slope of Alaska.
Candidate wells for gas shutoff (GSO) were identified based on gas flow rates and the gas/oil ratio (GOR). Wells that were not commercially producible were selected for evaluation as potential GSO wells. These wells were assessed with new-technology logging tools conveyed on coiled tubing or with a downhole tractor. The new production-logging technology provided direct gas and oil holdup measurements, allowing for interpretation of three-phase production in the horizontal well environments. The goal was to identify dry-gas production (i.e., gas production without associated oil production).
After dry-gas production was identified, GSO procedures were designed based on the location of the gas entry into the wellbore. Two of the case studies involved GSO from the toe of the horizontal section of the wells, which was accomplished by placing a cast-iron bridge plug on coiled tubing above the gas-producing perforations. The third case study identified dry-gas production from the top perforated interval. This GSO involved setting a plug below the gas-producing perforations and squeezing them off. The plug was then drilled out with coiled tubing and pushed to total depth (TD).
These techniques proved to be economical GSO solutions in difficult well environments, and each case resulted in significant reduction of free gas and increased oil production.
Design and Analysis of a Multiphase Turbine for Compact Gas-Liquid Separation
Authors: Rawlins C. H. , Ross G. D. 
Published: December 2007

Summary
The rotary separator turbine (RST) uses unique technology to provide compact separation of oil and gas while recovering energy wasted in conventional pressure-reduction operations. The technology has been used for industrial refrigeration and geothermal applications since the early 1980s and has recently finished a field evaluation and assessment on a deepwater, tension-leg platform (TLP) in the Gulf of Mexico. The focus of this paper is to cover the operating principles and mechanisms of multiphase turbine technology and the design parameters for installation as a separation or power-generation system in new developments or in debottlenecking applications. Operational experience pertaining to separation efficiency, mechanical reliability, and power output in a live-fluid environment are highlighted.
Porosity Prediction in Shallow vs. Deepwater Limestones
Authors: Scholle Peter A. 
Published: December 2007

Summary
Limestones can be divided arbitrarily into shallow- and deepwater types. Shallow-water limestones characteristically have complex depositional facies patterns and originally are composed primarily of unstable minerals (aragonite and high-Mg calcite), which make them highly susceptible to post-depositional alteration. Small differences in burial-uplift-water chemistry histories can produce radically different trends of porosity preservation, destruction, or creation as a consequence of the great susceptibility of unstable minerals to alteration by fresh (nonmarine) pore fluids. These factors make porosity prediction of shallow-water limestones very difficult. Only through careful and detailed mapping of both primary facies and mineralogical trends, coupled with equally painstaking determinations of diagenetic histories and patterns, can porosity predictions be made for shallow-water limestones.
Deepwater, pelagic limestones, on the other hand, commonly are composed of a much more stable primary mineral (low-Mg calcite) and have more uniform and predictable facies patterns. Studies performed on Mesozoic and Cenozoic chalks throughout the U.S. and Europe have shown that porosity is lost as a direct function of burial depth. The rates of porosity loss vary with the pore-water chemistry and, more importantly, as a function of pore-fluid pressure. If these factors are known with reasonable certainty, then reasonable predictions can be made of average subsurface porosity of deepwater limestones. Only where such limestones have never been buried deeply, where they have had an early input of oil, or where they have elevated pore-fluid pressure can high porosities and high petroleum-reservoir potential be expected.
Scanning electron microscopy (SEM), petrography, and isotopic analysis have proved useful techniques for deciphering the depositional and diagenetic histories of both shallow- and deepwater limestones.

Introduction
Prediction of porosity in carbonate rocks is at best a difficult undertaking. Most carbonate hydrocarbon reservoirs drilled to date have been in shallow-water limestones. In such rocks, depositional patterns are complex and variable and diagenetic alteration of original sediment textures and compositions may be extreme. Few, if any, general rules can be used to predict the porosity of such carbonate rocks in the absence of drilling data. Even where a significant number of wells have been drilled, useful porosity trends that enable accurate porosity prognostication over even relatively short distances may be difficult to discern.
Porosity prediction in deepwater limestones, on the other hand, generally is easier. Deepwater strata have more uniform depositional facies, more predictable primary chemical compositions, and simpler diagenetic alteration patterns than their shallow-water equivalents. Alteration of deepwater limestones is controlled mainly by their maximum burial depth. Average rates for such diagenetic porosity loss can be determined as a function of burial.
A Parallel Reservoir Simulator for Large-Scale Reservoir Simulation
Authors: Dogru A. H. , Sunaidi H. A. , Fung L. S. , Habiballah W. A. , Al-Zamel N. , Li K. G. 
Published: December 2007

SummaryA new parallel, black-oil-production reservoir simulator (Powers**) has been developed and fully integrated into the pre- and post-processing graphical environment. Its primary use is to simulate the giant oil and gas reservoirs of the Middle East using millions of cells. The new simulator has been created for parallelism and scalability, with the aim of making megacell simulation a day-to-day reservoir-management tool. Upon its completion, the parallel simulator was validated against published benchmark problems and other industrial simulators. Several giant oil-reservoir studies have been conducted with million-cell descriptions. This paper presents the model formulation, parallel linear solver, parallel locally refined grids, and parallel well management. The benefits of using megacell simulation models are illustrated by a real field example used to confirm bypassed oil zones and obtain a history match in a short time period. With the new technology, preprocessing, construction, running, and postprocessing of megacell models is finally practical. A typical history-match run for a field with 30 to 50 years of production takes only a few hours.
Improved Micellar/Polymer Flooding With High-pH Chemicals
Authors: Holm L.W. , Robertson Steven D. 
Published: December 2007

Summary
A study was made of various pre flush solutions for use in micellar/polymer flooding. The oil recovery in laboratory core floods was improved most by the use of high-pH silicate solution as a preflush and by adding chelating agents such as sodium NTA or sodium EDTA to the micellar slug.

Introduction.
One of the techniques which has great promise for recovering large quantities of residual, oil is micellar/polymer flooding.1–3 In this type of process, surfactants (micellar solutions) and polymers are used to recover oil left behind by waterflooding and other secondary recovery methods. Laboratory and field tests of micellar/polymer flooding processes have been conducted in the U.S., with a number of projects currently in progress.4 During this period, the reservoir' variables that affect the efficiency of the process have been more clearly identified and studied. The principal variables, which are also the most detrimental to the oil recovery efficiency of the processes, are (1) reservoir rock heterogeneity, (2) reservoir brine salinity, (3) clays arid other minerals present in the reservoir rock, and (4) multivalent cations present on the reservoir rock surfaces.
Further studies have continued on how these variables affect the processes and on techniques for modifying deleterious factors and improving process efficiency. A process which uses chemicals (surfact ants and polymers) which are not affected adversely by these variables may seem to be the ideal goal; however, recognition of all the complex variables involved in micellar processes and the costs of chemicals required for such a process leads to the conclusion that this goal may not be a practical one.
Since the early field tests of micellar flooding, changing and conditioning the reservoir environment has been a continuing goal. Pre flushing cores in the laboratory and the reservoir rock in field test areas with fluids that would replace or change the existing water or brine were used m many projects.5–7 Reducing flow in permeable channels, replacing high-salinity brines with fresher water, and injecting sacrificially absorbed agents ahead of the micellar fluids were the objectives of the injection of various preflush solutions. None of the attempts were completely satisfactory. At the same time, other research efforts8,9 were directed toward addition of chemicals to the micellar slug which would increase the tolerance of the surfactants to reservoir brine and/or multivalent cations and improve phase relationships of the micellar slug with the reservoir fluids.
Basic Fluid and Pressure Forces on Oilwell Tubulars
Authors: Hammerlindl D.J. 
Published: December 2007

The object of this paper is to clearly and simply define the basic fluid and pressure forces on oilwell tubulars with respect to stresses, buoyancy, neutral point, and the effective buckling force denoted as the "fictitious force." The paper is designed as a preface to Lubinski and Hammerlindl.

Introduction
Conventional thought seems to be that an understanding of the basic fluid and pressure forces in oilwell tubulars is the domain of experts only. The objective of this paper is to disprove this by presenting a simple explanation of these basic forces. presenting a simple explanation of these basic forces. Part of the misunderstanding results from the belief that the problem is complex and difficult, when actually only an elementary knowledge of pressure and stress is required. In purely mechanical pressure and stress is required. In purely mechanical systems (i.e., no fluid or pressure), most engineers readily can determine and understand the forces associated with Hooke's law and buckling. However, with the addition of fluids, the engineer may become confused as to (1) whether buoyancy is a concentrated or distributed force, (2) why the neutral point is not at the point of zero axial stress, and (3) point is not at the point of zero axial stress, and (3) the nature of the nebulous force denoted as the "fictitious force" by Lubinski and Blenkarn. All of the above can be understood easily by observing the distribution of the principal stresses. This paper interrelates these stresses with buoyancy, the neutral point, and the fictitious force. point, and the fictitious force. The objectives of this paper are to give the practicing engineer a working knowledge of basic practicing engineer a working knowledge of basic fluid and pressure effects on oilwell tubulars and to increase the industry's ability to understand and advance the existing literature.

Stress Distribution in the Absence of Fluid
Fig. 1a illustrates a freely suspended tube of constant inside and outside diameter. In the absence of fluid, the axial stress at any point is equal to the weight below that point divided by the cross-sectional area of the tube at that point. Thus, the axial stress at a point a distance x from the lower end may be point a distance x from the lower end may be determined from
(1)
Fig. 1b shows the axial stress distribution in the absence of fluid, over the entire length.Throughout this paper, compressive forces are considered to be positive and tensile forces are considered to be negative, accounting for the minus sign in Eq. 1 and the equations that follow. Also, all equations pertain to a system of constant units.The radial stress at any point is obtained from
(1)
where p and p are the internal and external pressures, respectively, at the point of interest. pressures, respectively, at the point of interest. JPT
P. 153
Application of Vector Processors To Solve Finite Difference Equations
Authors: Nolen James S. , Kuba D. W. , Kascic M. J. 
Published: December 2007

Abstract
As computer technology approaches limitations imposed by the speed of light, increased emphasis is placed on vector processors. These have the ability to increase greatly the speed of arithmetic even without improvements in such basic computer characteristics as memory cycle time. This paper deals with solving systems of finite difference equations on the STAR 100 and the CYBER 203, two Control Data Corp. computers with built-in vector processors.
Systems of three-dimensional finite difference equations having from 2,000 to 8,000 unknowns were solved by means of Gaussian elimination and line successive overrelaxation (LSOR). On these machines, the D4 Gaussian elimination technique reduced computer time by factors as large as 4.6 relative to standard Gaussian elimination. Vectorization of the D4 code on the STAR 100 reduced computer times relative to scalar results by factors as large as 26, despite nonoptimal coding.
LSOR was vectorized successfully with computer time reduction factors of 35 to 43 on the STAR 100. On the CYBER 203, run times were reduced by factors of 45 to 54, relative to the scalar performance of the STAR 100. On an 8,000-block problem, average processing speed for a complete LSOR solution was approximately 25 million floating operations per second (megaflops).