bluuebunny/crossref_metadata_2025_split huggingface dataset:
Determination of Active Constraints in a Network
Authors: Watts J.W.. W. , Fleming G.C.. C. , Lu Q.. 
Published: April 2012

Summary
There is increasing interest in modeling networks of wells, including subsurface components of complex wells and surface facilities. Such modeling requires setting constraints at various points in the network. Typical constraints are maximum phase flow rates and minimum flowing pressures. A major difficulty in network calculations is determining which of these constraints is active.
This paper presents a method that uses slack variables in determining active constraints. The linearized equations of interest generally come in pairs, with each pair consisting of a base equation and a constraint equation. The base equation is the equation that normally applies. The constraint equation replaces it if the constraint is active. Normally, only one of these two equations can be satisfied. The slack variable provides a way to ensure that both are satisfied, regardless of which is active. If the constraint is inactive, the slack variable is added to the constraint equation and accounts for the slack, which by definition is the amount by which the inactive equation is not satisfied. On the other hand, if the constraint is active, the slack variable is instead added to the base equation, and the constraint equation as originally written is satisfied. To obtain this behavior, we define a parameter w and add w times the slack variable to the base equation and (1 − w) times the slack variable to the constraint equation. Thus, if w = 1, the slack variable is added to the base equation, and the constraint is active. On the other hand, if w = 0, the slack variable is added to the constraint equation, and the base equation is active. The slack is always in the inactive equation. There is a w associated with each slack variable.
Determining the parameter w is an iterative process. The efficiency of the process is improved by manipulating the network matrix such that we can create a Schur complement that has the slack variables as its unknowns and contains the only references to the w's To determine the slack variables, we need only to work with this matrix, which typically is much smaller than the network matrix.
The resulting method is implemented within a general purpose reservoir simulator. Testing of the method in more than 700 cases has shown it to be much more robust than an earlier heuristic procedure.
Displacement Mechanism in Multi-Well Systems
Authors: Kern Loyd R. 
Published: April 2012

Abstract
A procedure for determining the behavior of a reservoir under a gas or water injection program was reported by Buckley and Leverett in 1942. This method, which allowed the calculation of the phase saturation distribution behind the front of a displacing fluid, has been extended to apply to a more general situation.
The reservoir may initially contain flowing quantities of the displacing fluid, or the fluid in the reservoir may be above saturation pressure so that solution effects are present. Production may occur behind the front as in the case of a well which is produced after breakthrough of the displacing fluid. The calculating procedure is simplified in that the graphical integration necessary to determine breakthrough saturation is eliminated by performing a direct integration and the graphical differentiation necessary to determine saturation distribution is eliminated by representing the displacing phase fraction of the flowing stream by an empirical equation. This representation results in simple expressions for the producing gas or water/oil ratio and cumulative production.

Introduction
A method for the calculation of the saturation distribution behind the front (interface between the displaced and displacing phases in a gas injection or water flooding operation) was reported by Buckley and Leverett in 1942. The method leads to a curve for the saturation distribution which is double-valued; consequently, part of the curve was interpreted to be physically meaningless. That part of the curve which has physical significance was determined by a graphical integration (material balance).
In this paper it is shown that the integration may be performed analytically with a resulting equation for the saturation of the displacing phase at the front. The case in which the displacing fluid is initially flowing and the case in which the reservoir is initially above the saturation pressure so that some injected gas goes into solution are included in the integration. The calculations are considerably simplified by representing the fraction of the flowing stream which is oil by an exponential function of saturation.
The method is extended to apply approximately to reservoirs in which wells located between the injection well and the front are produced. An illustrative example utilizing the methods presented is included.
A Method for Predicting the Tendency of Oil Field Waters to Deposit Calcium Sulfate
Authors: Stiff Henry A. , Davis Lawrence E. 
Published: April 2012

Abstract
A graphic method was developed which can be used to predict the tendency of oil field waters to precipitate calcium sulfate under a variety of conditions. Application of this method is made to the prediction of sulfate scale formation in heater treaters, boilers, oil wells, cooling systems and water injection wells.

Introduction
A solution may be said to be in equilibrium with respect to a given salt when the concentration of that salt is equal to its solubility. If for any reason the concentration of the salt is increased or its solubility decreased, the equilibrium is upset and precipitation of the salt takes place. Thus, if the concentration of a salt in a particular solution is known and its solubility can be calculated for a given set of conditions, the tendency of this salt to form a precipitate under these conditions can be predicted. Based on these principles a method has been developed for determining the tendency of oil field waters to form calcium sulfate precipitates under various conditions.

The Solubility Diagram
Calcium sulfate precipitation most frequently occurs when two waters are mixed; one containing calcium ions, and the other sulfate ions. As one of these waters is added to the other a point may be reached where the concentration of calcium sulfate is greater than its solubility, thus causing the formation of a precipitate. The solubility diagram is a graphic device for determining the location of such points, thereby making possible a prediction of the tendency of such a system to deposit sulfate scale. A similar diagram can be used to solve many other problems involving the precipitation of calcium sulfate.
Fig. 1 shows a solubility diagram representing the mixing of two waters. Water "A" contains a high concentration of sodium, magnesium, and sulfate ions together with a small amount of calcium. Water "B" contains a high concentration of calcium ions together with sodium, magnesium and a small amount of sulfate ions.
High-Resolution Reservoir Monitoring Using Crosswell Seismic
Authors: Nalonnil Ajay , Marion Bruce 
Published: April 2012

Summary
Crosswell seismic is an emerging technology that provides highly detailed images of the subsurface at the reservoir scale. The technology has the potential not only to delineate complex structures, but also to monitor the effectiveness of hydrocarbon-recovery and CO2-sequestration strategies. The technique employs tomographic surveying, whereby a transmitter and receiver are deployed in separate wells. With this setup, interwell velocity profiling and structure can be obtained from direct-wave and reflection processing, respectively.
With increased hydrocarbon recovery and CO2 sequestration becoming more prominent in the oil and gas industry, the ability to monitor the efficiency of these strategies is paramount. In this paper, two case studies of crosswell seismic surveying are discussed, with the focus on high-resolution imaging and monitoring during CO2 injection for improved oil recovery. A brief description of the measurement theory and its capabilities is provided, followed by a description of the processing workflow and, finally, a discussion of the acquired results.
The two cases discussed demonstrate that crosswell seismic was able to successfully monitor the injection through velocity profiling in time lapse and provide answers as to why and how the flow has occurred through interpretation of the crosswell reflection seismic section. The results clearly show that crosswell seismic could significantly reduce the uncertainty and risk associated with injection processes for improved recovery and can extend the technique to sequestration monitoring.
The Evolution of the Role of Openhole Packers in Advanced Horizontal Completions: From Novel Technology to a Critical Key to Success
Authors: Gavioli P.. , Vicario R.. 
Published: April 2012

Summary
Openhole packers have been shown to be very effective in many different applications, including curing losses, controlling high-permeability zones and fractures, improving equalization in passive- and active-inflow-control-device (ICD) completions, and, most importantly, controlling water and gas production. The use of these tools has increased exponentially in the last few years and will continue to grow. This paper summarizes the most important findings and lessons learned about the role of zonal isolation in advanced horizontal completions.
More than 12 years of experience using reservoir-optimized completions, including passive or active ICDs and openhole packers, in more than 1,000 wells and several tens of different fields around the world has led to the accumulation of best practices and rules of thumb. The approach for openhole packers has changed markedly with time, along with the industry learning about the importance of these tools in advanced horizontal completions.
Important considerations have been generated to design horizontal completions under different fluid properties, reservoir uncertainties, and optimum operational considerations allowing for equalization of flow along the entire length of the horizontal section. These best practices came from extensive run history and lessons learned, and it has been found that openhole packers often play the most critical role for a completion's success. The availability of a wide range of new zonal-isolation tools makes it easier for operators to obtain the best and most-cost-effective solution for each application.
Openhole packers for compartmentalization are key for success in many applications and offer benefits for inflow and annulus flow control. An extremely important consequence is the ability to control gas or water after breakthrough. This has been proved from analyzing a significant amount of production logs post-installation. Actual well-performance data and simulations will be shown to support the discussion and illustrate concepts and findings.
Observations From Profile Logs of Water Injection Wells
Authors: Kaveler H.H. , Hunter Z.Z. 
Published: April 2012

Abstract
Variation of the horizontal permeability (parallel to the bedding plane) in the vertical section of reservoir rocks has long been observed as a characteristic of a normally heterogeneous system which reservoir rock represent.
The use of a recently developed water injection profile device offered opportunity to measure with a high degree of reliability the rate of inflow of water into Burbank sandstone in wells previously cored. Water injection profiles were not correlative with core permeability profiles in such wells. Apparently the vertical permeability substantially influences the flow between strata in a formation in a manner as to void the usual conclusions that have been drawn from consideration of the horizontal permeability measurements alone. The results obtained in comparing water injection profiles with horizontal permeability profiles suggest that many of the usual production operations based upon "selective" behavior or treatment of rock exposed in well bores need to be re-valuated and re-examined.

Introduction
Petroleum reservoir rock are heterogeneous systems. Heterogeneity exists in respect to lithologic character insofar as such rock are composed of distinguishable solid phases. Heterogeneity also exists in respect to certain properties, such as porosity and permeability, that vary due to variation of the physical structure of the rock. Except in exceptional cases, both the horizontal permeability (measured parallel to the bedding planes) and the vertical permeability (measured perpendicularly to the bedding planes) exhibit significant variation in any common source of supply. The variation in horizontal permeability, as reflected by core analyses, has drawn the greatest attention of petroleum technologists probably out of the general notion that the mass movement of fluids in a reservoir is predominantly in the horizontal direction. Furthermore, in the usual case, the rock permeability measured in the horizontal direction is greater than that in the vertical.
Equation-of-State Modeling for Reservoir-Fluid Samples Contaminated by Oil-Based Drilling Mud Using Contaminated-Fluid Pressure/Volume/Temperature Data
Authors: Sah P.. , Gurdial G.. , Pedersen K.S.. S. , Izwan Deraman H.. , Ramli F.. 
Published: April 2012

Summary
Bottomhole samples collected in wellbore systems using oil-based muds (OBMs) are likely to be contaminated by medium-to-heavy hydrocarbon fractions present in the OBM. Pressure/volume/ temperature (PVT) data measured for a contaminated fluid will not be representative for the clean reservoir fluid, and such PVT data are hence often ignored by the operator, which means loss of a considerable investment. A proper estimate of the representative clean reservoir fluid is essential for reserves estimation and facilities design. Unfortunately, no experimental methods exist for such estimations. It would be valuable for the oil industry to have options for numerical cleaning of OBM-contaminated reservoir fluids and to be able to carry out equation-of-state (EOS) modeling and regression for a contaminated composition in a way that would allow PVT data for a contaminated fluid to be corrected to represent the uncontaminated fluid. This paper describes such a methodology, which is integrated with EOS modeling procedures for numerically cleaned reservoir-fluid compositions. Thanks to this method, PVT data for contaminated samples do not have to be ignored and oil and gas operators can justify investing in PVT analyses for contaminated-fluid samples.
This paper details the process through which the available data can be used. The composition of the reservoir fluid is estimated from the composition of the fluid with a certain content of OBM contaminate, and, contrary to other proposed methods for numerical cleaning, it takes into consideration that the aromaticity of the reservoir fluid may deviate substantially from that of the OBM contaminate. A regression procedure is applied afterward using the available PVT data in order to develop ultimately an EOS model for the clean reservoir fluid. Compositional data and PVT data are presented for a real reservoir fluid contaminated with OBM. Because data are also available for the clean reservoir fluid, it has been possible to verify the validity of the suggested procedure. The numerical cleaning procedure does not require any nonstandard laboratory data, and the given method also is not restricted to any particular brand of OBM or well type.
Visual Examinations of Fluid Behavior in Porous Media - Part I
Authors: Chatenever Alfred , Calhoun John C. 
Published: April 2012

Abstract
An exploratory study was made to examine the possibilities of a visual approach in investigations into microscopic mechanisms of fluid behavior in porous media. Appropriate apparatus and techniques were developed so that microscopic phenomena could he recorded on color movie film as well as be observed visually. The observation flow cells in which the fluid behavior studies were made were essentially single-layered matrices of spheres between plates, sometimes all-glass, sometimes all-Lucite and sometimes a combination of the two. The fluids were limited to water and a filtered crude oil.
Two flow regimes were observed during the flow of the immiscible liquids: channel flow and slug flow. In the former, transport was effected through stable networks of interconnecting channels; and in the latter, part of the movement took place in the form of slugs. Under certain conditions, flood-front patterns were found to be different depending upon which liquids were the displacing and displaced phases and not depending upon whether the matrix was water-wet glass or oil-wet Lucite. Residual formations of oil and water were observed and are described. Some of the ramifications and significance of the observed phenomena are discussed.

Introduction
In recent years considerations of microscopic mechanisms of fluid flow in porous media have taken on greater significance. Much needs to be learned before the fundamentals of petroleum technology are completely established. For example, many unanswered questions exist in connection with relative permeability, displacement phenomena, residual fluid formations, flow structure, etc.; and further analytical mathematical formulations are seriously indicated. It is hoped that systematic investigations into the microscopic mechanisms connected with the behavior of fluids in porous media will shed some light on some of the problems extant.
Until recently microscopic mechanisms have been considered almost exclusively as speculative hypotheses. Within the past few years, however, the problem has been submitted to a limited number of experimental investigations. Nuss and Whiting made some studies on the pore-space geometry of sandstones and limestones by impregnating cores with an inert plastic and leaching the solid matrices to leave behind plastic models of the pore spaces. Schaefer traced pore spaces microscopically through lengths of limestone cores by cutting away thin sections from the exposed faces normal to the line of view.
A Technical and Economic Study of Completion Techniques in Five Emerging US Gas Shales: A Woodford Shale Example
Authors: Agrawal A , Wei Y , Holditch S.A. A 
Published: April 2012

SummaryWith the increased demand for energy and the declining conventional hydrocarbons worldwide, energy companies are turning to unconventional resources such as shale gas. With more than 2,000 Tcf of gas in place indentified in just 5 shale gas plays in the United States, shale-gas formations are now the number one targets for exploration drilling. Furthermore, there are still many more major shale-gas plays and basins waiting to be explored, evaluated, and developed. Because of the extremely low permeability of most shale formations, it is essential to select the appropriate completion techniques for shale-gas reservoirs. There are very few papers in the petroleum literature that provide a logical method to select completion techniques for given shale-gas-reservoir conditions. There are papers discussing successful completion techniques that seem to work for a specific shale. We have used many of these SPE papers to help define "best practices" in completing shale-gas reservoirs. We then developed logic to determine the best practice in completing shale-gas reservoirs as a function of reservoir conditions. In this paper, we will specifically cover the logic we have developed for choosing completion techniques in shale-gas reservoirs.First, we performed a literature review on the five basins as well as on all shale-gas plays in the US to determine the best practices in shale-gas completion techniques in fluctuating price environments and identify key geologic parameters that affect overall well performance. From our literature review, we identified seven pertinent geologic parameters that influence shale-gas completion practices. Next, we identified different completion trends in the industry for different geologic settings. Subsequently, we generated an economic model and performed sensitivity analysis to determine optimal completions for each gas-shale basin. On the basis of these economic models, we developed decision flow charts to select completion techniques. Finally, we programmed the flow chart, and we call this program Shale Gas Advisor. This program can be used to determine optimum completion best practices not only for the five gas-shale basins discussed, but also for gas-shale plays that have similar geologic attributes. We validated the program with published case histories in the SPE literature.
Impacts of the Number of Perforation Clusters and Cluster Spacing on Production Performance of Horizontal Shale-Gas Wells
Authors: Cheng Y.. 
Published: April 2012

Summary
Multistage hydraulic fracturing has become the key technology to complete horizontal wells in shale-gas reservoirs. In each stage, multiple perforation clusters are used to create multiple transverse fractures. How these clusters are placed significantly affects both the short-term and long-term production performance of horizontal shale-gas wells. The author's previous work has demonstrated that when more than two fractures are created, mechanical interaction among fractures creates strong stress concentrations around the inner fractures. As a result, the fractures between two edge fractures (i.e., subcenter and center fractures) experience only limited dilation, and their widths are much smaller than the edge-fractures’ width.
In this paper, reservoir-simulation models were constructed by quantitatively incorporating the findings of the author's previous work to investigate the impacts of the number of perforation clusters and cluster spacing on production performance of horizontal shale-gas wells. The paper illustrates that with the same cluster spacing, the scenarios with more clusters have lower ultimate gas recovery because of the increased number of less-effective inner fractures. Given the same lateral length of a horizontal well, although reducing cluster spacing increases the total number of fractures, smaller cluster spacing does not necessarily improve well performance. Inadequate small cluster spacing can actually lead to a greater number of less-effective or ineffective fractures, and, therefore, lower gas rate and ultimate recovery.