bluuebunny/crossref_metadata_2025_split huggingface dataset:
New Results on Decline Curves Considering Non-Darcy Flow Effects
Authors: Camacho-V. R. G. , Vásquez-C. M. A. , Padilla-S. R. 
Published: December 2007

Summary
Most theoretical work on decline curves considering nonlaminar flow is related to dry gas systems. The purpose of this study is to analyze decline curves considering non-Darcy flow effects in the reservoir for both slightly compressible liquid flow and solution gas-drive systems, keeping the wellbore pressure constant.
The transient and boundary-dominated flow periods are examined by means of a finite difference black-oil reservoir simulator with a variable bubblepoint formulation. The consequences of this formulation under non-Darcy flow are also investigated.
The influence of the mechanical skin factor on the rate response is also documented. For the case of liquid flow, presented for the first time, it is an expression to evaluate the total skin factor, which is a function of the mechanical skin and skin caused by inertial forces. This expression is given in terms of physical properties of the system, and it is proportional to the square root of the pressure drop. It also equals the square root of the Reynolds number. This is one of the main findings of this work.
The possible presence of a semilogarithmic straight line of reciprocal rate for both liquid and solution gas-drive systems is investigated, and new insights are provided. In general, when inertial effects are important and the bottomhole wellbore pressure is kept constant, a true semilogarithmic straight line of the inverse of oil rate does not develop. This result is valid for both liquid and solution gas-drive systems, and it is an important difference in the case of liquid flow under a constant oil rate production, where a semilog straight line of the pressure drop is evident during the transient period considering a large drainage area.
For liquid flow, an apparent straight line may be fitted, and the ordinate to the origin is approximately equal to the value of total skin computed with the expression mentioned previously.
The presence of inertial effects distorts the shape of the laminar decline curves for both multiphase and slightly compressible liquid flow, causing type curve analysis to yield wrong estimates of the wellbore and reservoir parameters. Also, to perform a history match with data affected by non-Darcy flow by use of a conventional simulator that uses Darcy's law in its formulation, an alteration of the reservoir properties is necessary.
Field-Test Results of a Three-Phase Holdup Measurement in Horizontal Wells With a Pulsed-Neutron Source
Authors: Roscoe B. A. 
Published: December 2007

Summary
A new method of obtaining three-phase holdup (oil/water/gas) information in horizontal wells has been field tested. The method uses the data available from a pulsed-neutron tool. This measurement uses the inelastic near/far countrate ratio in addition to the near and far carbon/oxygen (C/O) ratios. The inelastic near/far countrate ratio response is dominated by gas in the borehole, whereas the near and far C/O ratios are used to separate the water and oil contributions of the borehole and formation. By using a linear programming approach, this information is combined to produce quantitative three-phase holdup answers. Calibration ofthe measurement is achieved by the combined use of laboratory measurements and Monte Carlo modeling predictions.
To obtain independent verification of the three-phase holdup answer, a local probe tool was run in combination with the pulsedneutron tool. The local probe tool is sensitive to two phases (water and hydrocarbon) and, hence, can be used for a partial verification of results. Field-test results show good agreement between the two independent measurements under various conditions of gas, oil, and water holdup in the horizontal borehole.
Athabasca Oil Sands
Authors: Bellows L.A. , Bohme V.E. 
Published: December 2007

Introduction
The Athabasca oil sands of the McMurray formation in northeastern Alberta cover an area of about 21,000 sq miles and contain the world's largest reserve of economically recoverable oil. Fort McMurray, a small town in the heart of the oil-sands area, is about 235 air miles northeast of Edmonton. A railway serves the town but no year-round roads connect with the rest of Alberta (Fig. 1).The McMurray formation is of early Cretaceous age, deposited unconformably on a limestone surface of Devonian age. The sediments appear to have originated from the Canadian Shield to the east and were deposited in bays and deltas of large fresh-water lakes. The lakes were later replaced by marine seas in which the overlying Clearwater shale was deposited (Fig. 2).The sand body rarely exceeds 200 ft in thickness and is made up of innumerable minor and major lenses of unconsolidated oil-bearing sand interspersed with clay and shale partings of variable thickness, carbonaceous and lignite beds, some rock and boulders. Overburden thins along a topographic trough which contains the Athabasca River and increases in thickness to about 2,000 ft along the southern and western limits of the oil impregnation. Oil sand is exposed on the banks of the Athabasca River and its tributaries.
The oil sand is primarily quartz with varying percentages of silt and clay. Maximum oil saturation is about 18 percent by weight in a clean sand but decreases with increasing silt and clay content. Sand with oil saturation in excess of about 10 per cent is classed as a "good" grade while sand containing less than about 5 per cent of oil is not considered to be economically recoverable by present mining and processing techniques.The oil found in the McMurray formation is heavy, viscous and sulfurous. Specific gravity is from 1.002 to 1.027; viscosity, 3,000 to 400,000 poise at 60F. The sulfur content is from 4 to 5 per cent, and the nitrogen content is about 0.4 per cent.
JPT
P. 479^
The Importance of Interfacial Tension on Fluid Distribution During Depressurization
Authors: Mackay E. J. , Henderson G. D. , Tehrani D. H. , Danesh A. 
Published: December 2007

Summary
Many North Sea reservoirs produce water at very high cuts under current waterflooding conditions. As oil production drops below economical limits, procedures for recovering residual and bypassed oil are being investigated. One technique identified as potentially suitable for at least ten candidate fields in the United Kingdom Continental Shelf (UKCS) is to depressurize these fields. During pressure depletion, improved hydrocarbon recovery has been shown to result from the release of solution gas and subsequent expansion of the freed gas. The precise nature of gas nucleation and its subsequent growth phenomena, however, have not been well understood. For example, there exists experimental evidence supporting two apparently conflicting models describing gas nucleation.
High pressure micromodel studies have shed light on the physical processes occurring at the pore scale during pressure depletion in waterflooded systems. Specifically, tests performed with fluids characterized by different gas/oil interfacial tensions (IFT's) have shown the important role gas/oil and gas/water IFT's play during bubble formation and growth in porous media. Analysis of visual information from water-wet micromodel tests have shown that the magnitude of the liquid-gas IFT is one of the factors that determines in which phase the bubbles nucleate, and how many bubbles form per unit volume of pore space. A low gas/oil IFT results in a relatively large number of bubbles forming in the oil phase only, with little or no supersaturation. Higher values of gas/oil IFT result in increasing levels of supersaturation with relatively fewer bubbles nucleating at cavity sites on the water-solid interface. Not only is the gas/oil IFT at the bubblepoint important in determining the nucleation loci and densities, but the increasing gas/oil IFT values with decreasing pressure also affect the distribution of the three phases during the process. Increasing gas/oil IFT's, combined with the effect of disjoining pressure in thin water films separating oil ganglia, result in delayed oil production and expulsion of water from the system below a certain threshold pressure. This suggests that there is an identifiable minimum pressure below which hydrocarbon production will not be viable.
Development and Application of the Multiwell Productivity Index (MPI)
Authors: Valkó P. P. , Doublet L. E. , Blasingame T. A. 
Published: December 2007

Summary
In this article we generalize the concept of the pseudosteady-state productivity index for the case of multiple wells producing from or injecting into a closed rectangular reservoir of constant thickness. The work complements the analytical study by Rodríguez and Cinco-Ley1 for systems produced at constant flowing pressures. Wells are represented by fully penetrating vertical line sources located arbitrarily in a homogeneous and isotropic reservoir. The multiwell productivity index (MPI) is a square matrix of dimension n, where n is the number of wells. The MPI provides a simple, reasonably accurate and fast analytical tool to evaluate well performance without dividing the cluster into single-well drainage areas. The MPI approach is used to obtain approximate analytical solutions for constant (but possibly different) wellbore flowing pressures, and to visualize the resulting pressure field. In addition, the skin factor trace technique is introduced as a tool to monitor a cluster of wells. The MPI technique is illustrated using a synthetic example taken from Ref. 2, as well as two field cases.
Extending Predictive Capabilities to Network Models
Authors: Øren P.-E. , Bakke Stig , Arntzen O. J. 
Published: December 2007

SummaryWe reconstruct three-dimensional (3D) sandstone models that give a realistic description of the complex pore space observed in actual sandstones. The reconstructed pore space is transformed into a pore network that is used as input to a two-phase network model. The model simulates primary drainage and water injection on the basis of a physical scenario for wettability changes at the pore level. We derive general relationships among pore structure, wettability, and capillary pressure for the different pore level displacement mechanisms that may occur in the network model.We present predicted transport properties for three different reconstructed sandstones of increasing complexity: Fontainebleau, a water-wet Bentheimer, and a mixed-wet reservoir rock. Predicted transport properties are in good agreement with available experimental data. For the reservoir rock, both the experiments and the simulated results show that continuous oil films allow low oil saturations to be reached during forced water injection. However, the oil relative permeability is very low.
High-Resolution Reservoir Models Integrating Multiple-Well Production Data
Authors: Wen Xian-Huan , Deutsch C. V. , Cullick A. S. 
Published: December 2007

SummaryThis paper presents a method to generate maps of high resolution permeability from multiple well single-phase flow rate and pressure data. The dynamic (i.e., temporal) production data contain important information about the interwell permeability distribution that should be integrated with static data, such as well and seismic data, to generate reservoir models to provide reliable input to reservoir simulation and reservoir management. A two-step procedure is proposed for such data integration: establish the spatial constraints on large-scale permeability trends caused by the production data by means of an inverse technique and construct the detailed geostatistical reservoir models subject to those spatial constraints by means of geostatistical techniques. The single-phase pressure and production data could be provided by permanent pressure gauges, simultaneous multiple well tests, or flow rates under primary depletion.Production data and reservoir petrophysical properties, specifically permeability, are nonlinearly related through flow equations. Establishing the spatial constraints on permeability resulting from production data calls for the solution of a difficult inverse problem. This paper adapts the sequential self-calibration (SSC) inverse technique to single-phase multiple-well transient pressure and production rate data. The SSC method is an iterative geostatistically based inverse method coupled with an optimization procedure that generates a series of coarse grid two-dimensional (2D) permeability realizations whose numerical flow simulations correctly reproduce the production data. Inverse results with two synthetic data sets show that this SSC implementation is flexible, computationally efficient, and robust.Fine-scale models generated by downscaling the SSC generated coarse-scale models (by simulated annealing) are shown to preserve the match to the production data at the coarse scale. Finally, reservoir performance prediction results show how the integration of production data can dramatically improve the accuracy of production forecasting with significantly less uncertainty.
An Investigation of Fluid Leakoff Phenomena by Use of a High-Pressure Simulator
Authors: Lord D. L. , Vinod P. S. , Shah S. N. , Bishop M. L. 
Published: December 2007

Summary
This paper describes the results of fluid-loss tests conducted with various hydraulic fracturing fluids through the use of a large-scale, high-temperature, high-pressure simulator (HPS) that has several unique capabilities. Among these capabilities is the ability to perform dynamic fluid-loss experiments over a large surface area under 1,000 psi differential pressure. Nearly all fluid-loss studies previously reported in the literature have described laboratory tests involving small-core plugs with a surface area of approximately 1.7 in.2. In contrast, the fluid-loss data collected in the HPS are over a significantly larger surface area, approximately 606 in.2.
Results from the HPS were compared to laboratory data, and significant differences in spurt-loss values were found. Surface texture was also found to be a significant factor in determining the extent of filter cake formation. The paper provides insight into the differences between fluid-loss control mechanisms displayed by linear polymer solutions and crosslinked gels. Experiments specifically designed to evaluate various hypotheses were performed to determine the significance of external filter cake on fluid-loss control of crosslinked fluids. Conventional fracturing fluids and additives were found to be inefficient in controlling fluid loss to natural fractures in a rock matrix.
Sizing Gelant Treatments in Hydraulically Fractured Production Wells
Authors: Seright R. S. , Liang J. , Seldal Mailin 
Published: December 2007

SummaryOften, when production wells are stimulated by hydraulic fracturing, the fracture unintentionally breaks into water zones causing substantially increased water production. To correct this problem, we developed an engineering basis for designing and sizing gelant treatments in hydraulically fractured production wells. In these treatments, gelant penetrates a short distance from the fracture face into the porous rock associated with both water and hydrocarbon zones. Success for a given treatment requires that the gel reduce permeability to water much more than that to hydrocarbon. We present a simple 11-step procedure for sizing these gelant treatments. This procedure was incorporated in user-friendly graphicaluser-interface software that can be downloaded from our web site at http://baervan.nmt.edu/ResSweepEffic/reservoir.htm.
Experimental Study of the Gelation Behavior of a Polyacrylamide/Aluminum Citrate Colloidal-Dispersion Gel System
Authors: Ranganathan Raja , Lewis Robert , McCool C. S. , Green D. W. , Willhite G. P. 
Published: December 2007

Summary
The gelation behavior of a polyacrylamide/aluminum citrate colloidal-dispersion gel (CDG) system was investigated in sandpacks at frontal advance rates of 2 ft/D. A gelatinous mass formed where the gelant encountered a change in flow medium. Permeabilities of homogeneous media were reduced only by factors that were similar to those obtained with a polymer displacement alone.
A laboratory investigation of a polyacrylamide/aluminum citrate CDG system was conducted to determine whether the system develops in-depth permeability modification in unconsolidated sandpacks. The study includes flow of the polymer and in-situ gelation behavior of the gelant in porous media and aggregate growth during the gelation reaction in beakers.
Flow experiments were conducted in long unconsolidated sandpacks in which the gel solution was mixed in-line before injection. Injection rates were designed to provide adequate residence time for the gel solution to develop in-situ flow resistance during displacements based on bulk gel characterization tests. Residual resistance factors were determined following a static rest period in which the sandpack was left saturated with the injected gel solution. For comparison, apparent viscosity and residual resistance factors were also determined for the polymer flowing through unconsolidated sandpacks. Membrane dialysis was used to study the aggregate size distribution of the gel system at selected times after mixing.
In-depth in-situ flow resistance did not develop when the gelling solution was injected into the sandpacks at frontal advance rates of 2 ft/D. Propagation through the sandpack was similar to a polymer solution. Flow resistance was characterized by the formation of a gelatinous filter cake, which formed when the injected solution encountered a change in flow medium, such as a screen placed at the ends to retain sand in place, the interface between the 50-mesh coarse sand layer at the inlet and the rest of the sandpack, and void spaces. Delaying injection by 2 hours after mixing in-line (to simulate field conditions) resulted in severe front-end stripping of gel aggregates. In all cases, residual resistance factors for the gel solution were similar to those obtained with a polymer displacement alone. Effluent fractions from gel solution displacements never developed a gel structure, and their viscosities were significantly lower than the injected solution. In the study of gel size distribution, aggregates were not detected at reaction times of 4 and 8 hours.
How Permeability Depends on Stress and Pore Pressure in Coalbeds: A New Model
Authors: Palmer Ian , Mansoori John 
Published: December 2007

Summary
In naturally fractured formations such as coal, permeability is sensitive to changes in stress or pore pressure (i.e., changes in effective stress). This paper presents a new theoretical model for calculating pore volume (PV) compressibility and permeability in coals as a function of effective stress and matrix shrinkage, by means of a single equation. The equation is appropriate for uniaxial strain conditions, as expected in a reservoir. The model predicts how permeability changes as pressure is decreased (i.e., drawdown). PV compressibility is derived in this theory from fundamental reservoir parameters. It is not constant, as often assumed. PV compressibility is high in coals because porosity is so small. A rebound in permeability can occur at lower drawdown pressures for the highest modulus and matrix shrinkage values. We have also history matched rates from a boomer well in the fairway of the San Juan basin by use of various stress-dependent permeability functions. The best fit stress/permeability function is then compared with the new theory.
Conditioning of Pacific Ocean Water for Waterflood Injection
Authors: Sudbury J.D. , Knutson C.F. , Felsenthal Martin , Lung J.D. 
Published: December 2007

Abstract
This paper has been written to summarize the laboratory and field studies leading to injection of Pacific Ocean water into the Third Grubb formation.
Laboratory tests for studying the permeabilities of cores to Pacific Ocean water are described. Results of these tests showed that the water could be successfully injected if it is chemically stable, sterile, and properly filtered. Clay swelling was shown to be a comparatively minor factor in permeability reduction.
Studies leading to development of an economical system for properly conditioning the ocean water are discussed. It was necessary to control pH, calcium carbonate deposition, bacterial growth, iron solubility, oxygen, and suspended solids. A relatively simple system combining the use of sulfur dioxide, a quaternary ammonium chloride, and filtration was shown to adequately control all these factors. This combination has not previously been used as a water treating technique.
Evaluation tests of the water conditioning system prior to injection are described, and results of such tests are presented. Control measures needed to insure a continuously adequate water treatment are reviewed.

Introduction
The utilization of sea water for waterflooding has only recently been attempted. Knowledge of treating requirements has been limited, and in most cases no water treating has been done.
Prior to the initiation of the Third Grubb zone pilot water flood at Ventura, Calif., extensive laboratory research was done in an effort to define the treatment necessary to provide a suitable injection fluid.
Close coordination and cooperation between field and research personnel were found to be the foremost requisites in developing the most economical and practical method for treating ocean water.

Laboratory Studies

Plugging Tendencies of Untreated Ocean Water
A program of laboratory studies was initiated for the purpose of evaluating whether ocean water could be injected into the formation for prolonged periods of time without causing plugging of the pore spaces of the formation. Because of the fairly low permeability of the formation (averaging about 40 md), it was realized from the outset that a water of exceptionally high quality was needed.
Addressing BHA Whirl: The Culprit in Mobile Bay
Authors: Mason J. S. , Sprawls B. M. 
Published: December 2007

Summary
Lateral bottomhole assembly (BHA) vibration, more particularly BHA whirl, is known to be an extremely destructive downhole phenomenon, the occurrence of which is thought to be one of the primary contributing factors to drillstring failure in Mobile Bay. Unfortunately, indications that BHA whirl is occurring while drilling are rarely evident from conventional surface measurements, especially in deeper sections of wells. Without knowledge of the existence of a problem, avoidance is almost impossible.
For the first time, the potential for the surface identification of BHA whirl is thought to be possible through the measurement of drillstring vibrations. We present data from a well in Mobile Bay where surface vibration measurement and monitoring was conducted while drilling the 12¼-in. hole section.
Axial and torsional data demonstrate characteristics thought to be indicative of BHA whirl, which is shown to be associated with accelerated drillstring fatigue, as demonstrated by BHA failures. Various approaches were taken to eliminate the whirl once the phenomenon was recognized, with ultimate success in that the incidence of BHA failure was reduced. Prewell planning and improved drilling practices resulted in the use of fewer bits and reduced drilling time over the same section on wells previously drilled in the area.