bluuebunny/crossref_metadata_2025_split huggingface dataset:
Logs From P and S Vertical Seismic Profiles
Authors: Omnes Gildas 
Published: December 2007

Vertical seismic profiles differ from ordinary well velocity surveys, or check shots, in two aspects: the records are longer and the depth intervals between measurements are much shorter. Accurate picking of first breaks makes the plotting of P and S velocity logs possible. From the velocity logs, a vs/vp log can be calculated.

Introduction
A vertical seismic profile (VSP) is the seismogram obtainable by lowering a multitrace seismic array in a well, activating a seismic source near or on the surface, and recording the seismic sensors during a time equal to at least twice the travel time between the surface and the deepest mirrors.Probes presently in use are not more than a few feet long, and the VSP seismogram is obtained by clamping the probe against the walls at regularly spaced depths and activating the seismic source for each position of the probe.Fig. 1 shows the three kinds of seismic signals detected at a geophone (receiver) R placed in a well when a source S located on the surface is activated:direct wave causing the first breaks,up-going reflections, anddown-going reflections resulting from the reflection of up-going waves by mirrors located above R.Fig. 2 shows how these events line up on a VSP seismogram.
The left-hand sketch shows ray paths corresponding to two locations of the probe R1 and R2, with R1 above R2. Down-going waves, first breaks, and down-going reflections reach R1 before R2. Their lineups have parallel slopes within a given velocity interval. Up-going reflections reach R2 before R1. The transit time is the same as in the case of down-going events, but the slope of the lineup on the seismogram has the opposite sign.Though field operations are basically the same, there are two main differences between VSP's and ordinary well velocity surveys, or check shots:the recording time is much longer in the case of VSP'S, andthe depth interval between successive locations of the probe is shorter in the case of VSP's 15 to 70 ft (5 to 20 m) vs.
165 to 650 ft (50 to 200 m), or even more in the case of ordinary check shots.VSP's generally are recorded in view of a study of the reflection phenomena at a given location. Good VSP's make possible the direct observation of attenuation, multiple reflections, correlation of P and S events, etc. Also, the short spacing between recording stations makes it possible to obtain transit time logs based on the accurate picking of first breaks. When both P and S events are recorded, elasticity moduli can be estimated, and a much more accurate knowledge of the lithology is made possible. It is the purpose of this paper to illustrate, through the study of an example, how interesting logs can be obtained from P and S VSP's recorded in the same well.

VSP Displays and Records
Figs. 3 and 4, respectively, correspond to P and S VSP's recorded in the same well. The stratigraphic series listed in Table 1, and indicated on the left side of each figure, is typical of the central part of the Paris basin in France. Depths indicated in Table 1 are exact depths in the considered well.
JPT
P. 1843＾
Gas- and Liquid-Phase Relative Permeabilities for Cold Production From Heavy-Oil Reservoirs
Authors: Tang Guo-Qing , Firoozabadi Abbas 
Published: December 2007

Summary
Solution-gas drive with two heavy oils, a mineral oil with a viscosity of some 32,000 cp (at 24°C), and a heavy crude with viscosities of 85,000 cp and 9,200 cp (at 24 and 35°C, respectively) is carefully studied. Both oils show recovery in excess of 10% at test termination; the recovery for the heavy crude exceeds 15%. Had we continued the test, the recovery could have been higher.
From the measured pressure and fluid-flow rates, gas and oil relative permeabilities are estimated by a simple mathematical expression. The results establish that high recoveries are mainly caused by the low gas relative permeability. The results on mineral oil and heavy crude also demonstrate that the widely held belief that efficient solution-gas drive in heavy crude is caused by the foamy nature cannot be justified. An increase in temperature would reduce the oil viscosity, which in turn increases the gas mobility, thereby reducing the efficiency of solution-gas drive for cold production.
Integrated Optimization on a Long Horizontal Well Length
Authors: Cho Hyun 
Published: December 2007

Summary
This paper presents a methodology developed to estimate the optimum horizontal well length based on total economics and on the productivity index (PI) change associated with frictional loss effects in the long section of the horizontal wellbore. An integrated approach is proposed for quantitative analysis of the parameters affecting productivity and economics to achieve the overall optimum performance of a horizontal well project. This study shows that production is no longer proportional to the horizontal well length after a critical point. The critical point is calculated as a function of the length of the horizontal production section, flow rate, drawdown pressure, and other parameters. A step-by-step calculation procedure with examples is described with sets of graphical charts developed for illustrating the relationships between the various parameters.
Laboratory-Instrumented Sucker-Rod Pump
Authors: Podio A. L. , Gomez Jaime , Mansure A. J. , Williams Benny , Mahoney Mark 
Published: December 2007

SummaryAlthough sucker-rod pumps are installed in nearly 90% of all oil wells and many gas wells (for liquid unloading) in the United States and have been widely used for decades, there are many issues regarding their hydraulic performance that are not well understood. This is caused by the difficulty of obtaining downhole pump-performance data. Many persistent problems in sucker-rod pumping, including partial pump fillage, gas interference, gas locking, fluid pound, sticking valves, rod downstroke compression loading, equipment failure, reduced production, etc., are difficult to diagnose from the surface. Currently, verification of sucker-rod pump problems can only be inferred by removing the pump at great expense. Thus, root-cause analysis depends on guesswork and component analysis. Knowledge of pump characteristics downhole would allow problems to be predicted rather than simply diagnosed after they have persisted long enough to result in failure.To develop a knowledge base on sucker-rod pumps, a two-fold approach is being pursued: instrumentation of a clear sucker-rod pump in the laboratory, followed by the development of an instrumented downhole pump. The laboratory pump allows the development of diagnostic techniques in which pump performance can be verified visually. The downhole pump will allow testing at field conditions.A key element to both the laboratory and downhole instrumented pumps is measuring the compression chamber pressure (pressure within the pump barrel). The instrumentation has been designed to collect high-speed (≥100 samples a second) data so that transient behavior (ball chatter, etc.) can be observed. Data is archived while the pump operates under various conditions, from full to pumped off.This paper presents results of tests with the laboratory pump that have resulted in new insights about pump friction and the techniques developed to measure dynamic and static pump friction. Analyses of the compression-chamber pressure are leading to a better understanding of what happens when both valves are closed and leading to the development of techniques to perform real-time diagnoses that determine fillage and gas locking. The laboratory data showed that compression-chamber data can be insightful in understanding pump conditions.
Numerical Modeling of Aquifer Disposal of CO2
Authors: Pruess Karsten , Xu Tianfu , Apps John , Garcia Julio 
Published: December 2007

SummaryDisposal of CO2 from stationary sources (fossil-fired power plants) into brackish (saline) aquifers has been suggested as a possible means of reducing emissions of greenhouse gases into the atmosphere. Injection of CO2 into such aquifers would be carried out at supercritical conditions and would give rise to the evolution of a two-phase fluid system, in which most of the injected CO2 will reside in a dense supercritical gas phase, while also dissolving partially into the aqueous phase and reacting with native minerals. This paper presents scoping studies of the amounts of CO2 that can be trapped into the various phases (gas, aqueous, and solid) for a range of conditions that may be encountered in typical disposal aquifers. Our analyses employ a realistic fluid property (PVT) description of brine/CO2 mixtures for supercritical conditions, which takes into account real gas density and viscosity effects for CO2, and includes pressure, temperature, and salinity dependence of CO2 dissolution into the aqueous phase. The fluid property description has been incorporated into a multipurpose reservoir simulator, and has been used to evaluate dynamic effects of CO2 injection into aquifers. A survey of minerals commonly encountered in crustal rocks was made to identify possibilities for chemical sequestration of CO2 through the formation of carbonates of low solubility. We also performed batch reaction modeling of the geochemical evolution of representative aquifer mineralogies. Results indicate that under favorable conditions the amount of CO2 that may be sequestered by precipitation of secondary carbonates is comparable to the amount of CO2 dissolved in pore waters. The accumulation of carbonates in the rock matrix and induced rock mineral alteration caused by the presence of dissolved CO2 lead to a considerable decrease in porosity.
Optimizing the Perforating Strategy in Well Completions To Maximize Productivity
Authors: Underdown D. R. , Jenkins W. H. , Pitts A. , Venkitaraman A. , Li H. 
Published: December 2007

Summary
The Britannia field is a gas-producing reservoir operated jointly by Chevron and Conoco. Before completion of the wells, the major concern was the optimum underbalance to obtain zero perforation skin during completion. Theoretical models were used to predict the optimum underbalance based on log-derived formation properties. With detailed log permeability data, numerous simulations were carried out to choose the gun, charges, shot density, and perforating strategy for optimum productivity. Different shot densities and charges were used in different sections of the formation based on simulation results, as opposed to choosing perforation parameters based on average well properties.
Experiments were conducted to confirm the theoretical underbalance predictions at high underbalance pressures. Reservoir and outcrop core samples were perforated at simulated downhole conditions in the laboratory at different underbalances based on values obtained from the model. Flow performance evaluation of the perforated reservoir core samples confirmed earlier conclusions on the sensitivity of the formation to aqueous wellbore fluids (brine). An underbalance value of 1,000 psi used in the outcrop sample tests indicated near-zero perforation skin. A perforation strategy for the North Sea field was chosen based on the results from this study. Well performance analyses of 12 of the wells completed indicate low to negative skins. The information is presented in this paper as a case of how to design a good perforating job and also to emphasize the need to study optimum underbalance for gas formations.
The Onset of Instability During Two-Phase Immiscible Displacement in Porous Media
Authors: Peters Ekwere J. , Flock Donald L. 
Published: December 2007

Abstract
This paper presents a dimensionless number and its critical value for predicting the onset of instability during immiscible displacement in porous media. The critical dimensionless number obtained from a stability theory for a cylindrical system successfully predicted the onset of instability in laboratory floods. Therefore, this number can be used to classify the stability of two-phase incompressible displacements in homogeneous porous media.
Successfully Managing Drilling-Fluid Losses in Multiple, Highly Depleted Sands
Authors: Jones J. F. , Taylor G. D. , Barree R. D. 
Published: December 2007

Summary
Successfully drilling through depleted sands to reach deeper targets often demands a delicate balancing act between maintaining mechanical stability in normal and overpressured shales and controlling fluid losses caused by hydraulic fracturing. A host of considerations go into the planning process, including whether further production from the depleted zones is planned.
Because of the prohibitive cost of a new North Sea well, a stability analysis was performed to determine the feasibility of sidetracking from an existing well and then directionally drilling through two highly depleted sand formations with a single hole section.
The case study presented compares the original mechanicalstability and hydraulic-fracturing estimates with the actual mud weights used to successfully complete this difficult drilling operation. Descriptions of hole instability and fluid losses are presented along with the drilling fluid parameters used to combat them. Methods used for estimating formation pore pressure, in-situ stresses, and formation rock properties are also described. In addition, possible explanations for the differences between the planned and actual stability estimates are explored, with future recommendations for similar operations.
Automated Reservoir Model Selection in Well-Test Interpretation
Authors: Güyagüler Baris , Horne Roland N. , Tauzin Eric 
Published: December 2007

Summary
Technological achievements in the area of well testing, such as permanent downhole gauges, demand automated techniques to cope with the large amounts of data acquired. In such an application, the need to interpret large quantities of data with little human intervention suggests the desirability of automated model recognition. Also, in some cases, the characteristic behavior of the pressure or its derivative curves for specific models may be hidden behind noise, or human bias may lead to the selection of an invalid or inappropriate model.
This paper demonstrates an approach based on a genetic algorithm (GA) that is able to select the most probable reservoir model from among a set of candidate models, consistent with a given set of pressure-transient data. The type of reservoir model to be used is defined as a variable and is estimated together with the other unknown model parameters (permeability, skin, etc.). Several reservoir models are used simultaneously in the regression process. GA populations consist of individuals that represent parameters for different models. As the GA iterates, individuals that belong to the most likely reservoir model dominate the population, while less likely models become extinct. Because different models may require different numbers of parameters, the solution vectors have varying lengths. The GA is able to cope with such solution vectors of differing size. Information exchange (GA crossover operator) is allowed only between parameters that are physically related.
Alternatively, we illustrate the use of the GA as a preprocessor for conventional gradient-based algorithms such as Levenberg-Marquardt.1 When combined with the GA, the dependency of such conventional algorithms on the initial guess is reduced, and the overall regression performance is improved. For automated interpretations in which the model is already known, this method allows us to eliminate the initial guess-determination step.
Tests on real and synthetic pressure-transient data indicated that the proposed method was able to select the correct reservoir model. The method revealed hidden implications of the pressure transient that may otherwise have been overlooked because of noise. As a preprocessor for more conventional nonlinear regression approaches, applying the GA to a number of noisy pressure-transient tests demonstrated that the method is robust and efficient.
Novel Thermal Process for Recovery of Extremely Shallow Heavy Oil
Authors: Osterloh W. Terry , Jones Jeff 
Published: December 2007

Summary
In this paper, we propose a new process for the recovery of heavy oil from sands at depths of 100 ft or less and report its feasibility as determined by reservoir simulation. The process, called blanket heating, recovers oil by the traditional mechanisms of viscosity reduction and gravity drainage; however, it avoids the problem of handling large volumes of injected fluids and reduces the risk of surface emissions that would occur with typical steam enhanced oil recovery (EOR) methods.
Simulation results indicate that excellent, thermally efficient oil recovery is possible. Process sensitivity to many critical parameters was determined.
Improved Drilling Performance With Enhanced Crossflow Rock Bits
Authors: Allen James H. , Baker William 
Published: December 2007

After review of the literature on drilling hydraulics and evaluation of two-nozzle drilling, specially designed two-nozzle enhanced crossflow rock bits were manufactured and tested. Performance analysis indicates a 12 to 16% increase in drilling rate over standard three-nozzle jet bits. Laboratory and preliminary field test results are presented.

Introduction
Many drilling people are not aware of the number of successful and unsuccessful field tests conducted in the last 15 years on special bits designed to improve bottomhole cleaning. Many of the successful test bits were not reported or offered for standard field usage because drilling cost reductions were negated by increased bit development and manufacturing costs. Today, drilling costs have risen to a level where a slight increase in drilling rate performance will result in sizable cost savings.One basic hydraulic improvement was made when jet nozzles were incorporated into bit design in the late 1940's. Surface equipment requirements changed, and a period of drilling hydraulics study commenced. Most drilling people are aware of several studies and articles published on the subjects of bottomhole cleaning, chip-removal forces, crossflow, extended-nozzle bits, and two-nozzle bits.

Review of the Literature
A basic relationship of nozzle flow and crossflow on an impingement plate was deduced by Poreh and Cermak. The resulting crossflow, Vc, was directly proportional to the square root of the product of flow volume through a nozzle and the nozzle velocity.McLean, in studies conducted in 1964 and 1965, concluded that maximizing crossflow should produce the maximum use of available bit hydraulic horsepower. These studies included laboratory tests which measured crossflow distribution resulting from jet impingement on an actual rock bit. McLean determined the relative crossflow velocity at various points on the hole bottom due to jet impingement. The velocity parallel to the hole bottom at various locations was
(1)
where
Vc = crossflow velocity, ft/s (m/s), k = geometric constant, Q = nozzle flowrate, gal/min (dm3/min), V = nozzle velocity, ft/s (m/s), and D = bit size, in. (cm).
For the normal range of flow rates used in rotary drilling, the maximum crossflow will occur at the maximum bit hydraulic horsepower condition.In 1971, Sutko and Myers concluded that hole cleaning and drilling rate should improve as the number of nozzles is decreased. Hole cleaning and drilling rate should improve as nozzle standoff decreases.
JPT
P. 1687＾
Increasing Injectivity of Shaly Sands With Chemicals
Authors: Chakravorty S.K. , Gateman J.C. , Bohor B.F. , Knutson C.F. 
Published: December 2007

Abstract
The Viking sandstone reservoir, Coleville-Smiley field, Saskatchewan, Canada, is very shaly and water sensitive. The proven sources of injection water in the area are relatively fresh and in laboratory tests quickly plug tile Viking cores. After screening a large number of chemicals in the laboratory, a two-stage treatment was developed that maximized water permeabilities in core plugs. The purpose of the treatment was to restrict or inhibit clay swelling, prevent bacterial growth and increase injectivity. No one chemical was found that could do all these jobs well, so a three-component system was used: potassium chloride, polyoxyethylene triethylenediamine and an imidazoline. The optimum laboratory technique was to use a spearhead containing a high concentration of the treating chemicals followed by continuous treatment of the injection water with these material.

Introduction
The Eureka Viking sand pool is located in Southeastern Saskatchewan, about 200 miles northwest of Regina, 50 miles east of the Alberta-Saskatchewan border, and 200 miles north of the International Boundary (Fig. 1). The pool is located on the western end of the Dodsland field and is approximately 15 miles east of the Smiley-Dewar Viking sand pool. These two pools are within the Coleville-Smiley field boundaries as defined by the Saskatchewan Dept. of Mineral Resources. The producing formation of these pools is the Viking sandstone found at a depth of approximately 2,300 ft. The discussion presented in this paper pertains only to the Viking formation. Production was first established from the Viking sandstone in this area in Sept., 1953, with the discovery of the Smiley-Dewar pool. Discovery of the Eureka pool followed in 1954 and production was established for the Dodsland field in 1958. These fields presently contain approximately 650 wells capable of production from the Viking sandstone. The Viking sand is continuous throughout this area and the oil is found in the lows or valleys of the structure. Gas caps are located between the Eureka and Smiley-Dewar pools and along the northern edge of the Dodsland field. The name and location of the well selected for the injectivity test is HB Coleville 4-26-31-23 (lsd 4-26-3 1-23 W3M) in the Eureka Viking sand pool (Fig. 2). Other pilot water injection wells are located in lsds 11-6-31-22 W3M, and 12-7-31-20 W3M in the Dodsland field, lsd 9-4-31-25 W3M, and a four-well five-spot pilot injection on section 17-31-25 W3M in the Smiley-Dewar pool.

Geology and Reservoir Characteristics
The Viking member of the Colorado formation is of lower Cretaceous age. It consists of gray, silty shale beds and thin beds of chert pebbles. The lower 30 ft of the Viking member, consisting of medium-grained shaly sand, is known as the Viking sandstone. Structurally, the Viking member reflects the Paleozoic erosional surface by its highs and lows.
JPT
P. 1107ˆ