bluuebunny/crossref_metadata_2025_split huggingface dataset:
Optimization of Waterflood Performance and CO2-flood Design Using a Modeling Approach, Mallet Unit, Slaughter Field
Authors: Kuo M. C. T. , Dulaney J. P. , Deer M. W. , Evans B. S. , Granquist M. R. 
Published: December 2007

ABSTRACT
The Mallet Unit, located in Cochran and Hockley Counties of west Texas, produces oil from the Permian San Andres dolomite as part of the larger Slaughter field. The Mallet Unit was evaluated for waterflood improvement and CO2 enhanced oil recovery. This paper discusses the modeling approach for optimizing the existing waterflood and designing a CO2-flood. Four components were found instrumental in achieving a reliable CO2-flood design. These four components are: (1) an Equation-of-State accurately matched with representative PVT data, (2) a reliable geological description validated by 23 years of waterflood history, (3) a compositional model which adequately describes the phase behavior and CO2 displacement mechanism, and (4) a valid scale-up technique for forecasting field-scale CO2-flood performance from pattern CO2-flood performance. With these four components, oil and CO2 production response forecasted from the compositional model and scale-up study were found to be in reasonable agreement with the field observation of a near by CO2-flood. This nearby CO2-flood has similar geology and fluids. Recommendations for waterflood improvement and CO2-flood design were made based on both black-oil and compositional simulation results.
Experimental Investigation of Drilled Cuttings Transport in Inclined Boreholes
Authors: Ford J. T. , Peden J. M. , Oyeneyin M. B. , Gao Erhu , Zarrough R. 
Published: December 2007

ABSTRACT
This paper describes an experimental investigation into drilled cuttings transport in inclined boreholes carried out in the Department of Petroleum Engineering at Heriot-Watt University.
The paper describes how a 21 ft. borehole simulator and peripheral equipment built within the department has been used to determine the effects of various drilling parameters on the circulation rate required to ensure that the drilled cuttings in a deviated borehole are efficiently transported to surface.
The procedures used to conduct the experiments are fully explained and experimental results and observations are discussed.
Two distinctly different cuttings transport mechanisms were identified. The first occurs where the cuttings are transported to surface by a rolling/sliding motion along the low-side wall of the annulus and the second is where the cuttings are transported in suspension in the circulating fluid. The latter mechanism requires a higher fluid velocity than the first. Although these two mechanisms produce the same effect (to clean the hole) their response to variations in the drilling parameters investigated was significantly different.
The main conclusions from the experiments carried out to date are that the annular fluid velocity required to initiate cuttings transport with either of the two different transport mechanisms is sensitive to variations in hole angle but that the relationship between the required fluid velocity and hole angle is different for each of these transport mechanisms. The effectiveness of a circulating fluid in removing drilled cuttings is not only dependant on the rheology of the fluid but also on whether the fluid is in laminar or turbulent flow. Water in turbulent flow, can be a very effective cuttings transport medium. Pipe rotation had little or no effect on the fluid velocity required to transport the cuttings when circulating water but significantly reduced the fluid velocity required to transport the cuttings when circulating medium or highly viscous fluids. It should be noted however that these experiments were conducted on a relatively small annulus. The fluid velocity required to transport the cuttings is a function of the size of the cuttings.
Investigation of Barite "Sag" in Weighted Drilling Fluids in Highly Deviated Wells
Authors: Hanson P. M. , Trigg T. K. , Rachal G. , Zamora M. 
Published: December 2007

ABSTRACT
Significant mud weight variations greater than 4 Ibm/gal have been measured in flowline returns when circulating bottoms up after trips. This phenomenon, called "sag", has preceded pack off, lost circulation, failure to get logging tools to bottom, stuck pipe, and other drilling problems on some directional wells.
Two key findings have emerged from an extensive project to investigate and minimize sag in highly deviated wells. First, the density variations are caused by the slumping of beds which form when weight material settles to the low side of the hole. Second, most of the bed formation occurs while the mud is circulating. Previous efforts to investigate sag have focused on static settling.
Case histories, results from laboratory flow-loop studies, and operational guidelines to minimize sag and its consequences are presented in this paper.
Specialized Shale Control Additives and Selective Drilling Fluid Design Prove Successful in Offshore Gumbo Environment
Authors: Bruton J. R. , Stamatakis E. , Pixley D. , Young D. B. 
Published: December 2007

ABSTRACT
Drilling highly reactive gumbo shale sediments offshore in the Gulf of Mexico has been and currently still is problematic, particularly when drilling deviated wellbores. Borehole instability can result from erosion and dispersion of formation clays. Bit balling may induce high torque and drag, swabbing, and stuck pipe. The multitude of drilling fluid systems that have been used vary greatly, from simple 2 or 3-component to very complex systems containing a wide range of shale-control additives with differing chemistries. It is not uncommon that a particular fluid performs well in one area or on one well, but is not successful on the next well or in a different area.
A water-base drilling fluid system has been developed containing proprietary shale control additives coupled with a fluid selectively formulated to drill reactive formations. The additives analyzed and subsequently field tested possess dual functionality in both controlling shale swelling and limiting the tendency for the gumbo to stick or "ball up" bottom hole assemblies. A unique feature of these additives is that they do not alter the rheological properties of the fluid.
The design and application of the fluid has been an evolutionary process. Systematic laboratory testing of shale samples from the area to be drilled were analyzed and fluid formulations tested for inhibitive qualities. Once a formulation was selected, the system was field tested and further refinements were made to adjust the system chemistry for optimum performance. Over 25 wells have been drilled with the fluid showing exemplary performance. Borehole stability has been achieved and bit balling has been minimized or eliminated. Refinements to the original shale control additives utilized have created "second generation" materials to meet environmental concerns and provide more flexibility, particularly if used in other mud systems.
This paper describes the shale control additives, the fluid systems they can be used in, performance testing, and field results from several wells.
Conversion of Mud to Cement
Authors: Wilson W. N. , Carpenter R. B. , Bradshaw R. D. 
Published: December 2007

ABSTRACT
A dependable method for converting drilling fluid into a cementitious slurry has been sought for many years. Recent advancements in copolymer technology have made it possible to introduce Portland cement directly into drilling fluid while maintaining control over the rheology of the resultant slurry. For purposes of brevity, converted drilling fluid as described herein will be referred to as mud-to-cement, or MTC.
Conversion of drilling mud into a cement slurry has several unique advantages. As examples, conversion of spent drilling mud reduces disposal costs. Secondly, the superior compatibility built into MTC significantly improves annular displacement efficiency by controlling the flocculation that normally results when drilling mud and cement contact. Thirdly, MTC makes the most benefit of manpower, equipment, time and materials by consolidating services at the rig site.
Consolidation of drilling mud and cementing technologies to cut costs while improving the quality of completions is the underlying topic of discourse in this paper. In addition to presentation of the slurry design process, laboratory data, mixing and handling concepts and case histories are discussed. Also, several important avenues of potential savings are suggested. Applications in a variety of locations using different types of completions have all been successful both operationally and from the standpoint of results.
Mathematical Modeling of Microbial Enhanced Oil Recovery
Authors: Islam M. R. 
Published: December 2007

ABSTRACT
Microbial enhanced oil recovery (MEOR) is receiving renewed interest worldwide. Microbial enhanced oil recovery involves the injection and transportation of microorganisms into the reservoir followed by nutrients which act as in situ growth products. These bacteria act as either a mobilizing agent of residual oil or a plugging agent for selective plugging of an undesired reservoir zone. Even though the concept of MEOR activities is rather straight forward, field tests have often been dismal. One of the reasons for such failure has been reported to be the inability to set up proper field strategy. In order to develop a proper strategy, a reservoir simulator capable of predicting bacterial movement and reactions in an oil reservoir. Such a simulator has been nonexistent to-date. This paper presents formulation and results of reservoir simulation using microbial EOR.
The formulation developed in this paper describes microbial transport in multidimensional porous medium. This description is completed with a kinetic model of bacterial growth which leads to either bacterial plugging and mobility control or alteration of oil properties (reduction of oil viscosity, interfacial tension (IFT), etc.). Reservoir simulation results are given for different types of bacteria used. A Canadian heavy oil reservoir was used as the prototype for all numerical simulation results.
A Dual Gas Tracer Technique for Determining Trapped Gas Saturation During Steady Foam Flow in Porous Media
Authors: Radke C. J. , Gillis J. V. 
Published: December 2007

ABSTRACTFoam is a possible mobility control agent for effective oil displacement from reservoirs. Thus, it is important to understand the mechanisms by which foam flows in porous media. Micromodel studies and prior gas-phase tracer experiments show that a significant fraction of the gas in a foam exists as trapped bubbles which, therefore, have a major impact on the flow resistance. Unfortunately, in the tracer experiments performed to date, partitioning of the tracer into the trapped gas has not been accounted for. Currently, only qualitative information is available on the actual amounts of trapped gas.To overcome these limitations and obtain quantitative measurements of trapped gas saturations, we have developed a unique experimental apparatus employing dual gas tracers. During steady foam flow in a porous medium, dilute sulfur hexafluoride (SF6) and methane (CH4) tracers in a nitrogen carrier are injected, and the effluent concentration is monitored by gas chromatography. The measured tracer histories are fit to a simple mass transfer model which describes any partitioning between the mobil and trapped foam phases. Tracer effluent concentrations predicted by the model are strongly influenced by the solubility of each tracer in the liquid phase. This behavior is observed in the experimental histories as well. Hence, multiple gas tracers provide a discriminating assessment of trapped gas saturation during foam flow through porous media.New trapped gas saturations are reported for an aqueous C14-16α-olefin sulfonate foamer solution and nitrogen flowing through a 2.3-μm2 fired Berea sandstone at 105 Pa (1 atm) back pressure and at room temperature. Total superficial velocities range from 0.4 to 4 m/day while inlet gas fractional flows are varied from 0.8 to 1.0. We find large fractions of trapped gas between 80 and almost 100% depending on the particular flow conditions. The importance of trapped gas to understanding foam-flow behavior is again confirmed.
An Artificial Neural Network Approach to Identify the Well Test Interpretation Model: Applications
Authors: Al-Kaabi A. U. , Lee W. J. 
Published: December 2007

Abstract
The objective of this paper is to present the application of a new approach to identify a preliminary well test interpretation model from derivative plot data. Our approach is based on artificial neural networks technology.
In this approach, a neural nets simulator which employs backpropagation as the learning algorithm is trained on representative examples of derivative plots for a wide range of well test interpretation models. The trained nets are then used to identify the well test interpretation model from new well tests.
In this paper we show that using artificial neural networks technology is a significant improvement over pattern recognition techniques currently used (e.g., syntactic pattern recognition) in well test interpretation. Artificial neural networks have the ability to generalize their understanding of the pattern recognition space they are taught to identify. This implies that they can identify patterns from incomplete and distorted data. This ability is very useful when dealing with well tests which often have incomplete and noisy data. Moreover, artificial neural networks eliminate the need for elaborate data preparation (e.g., smoothing, segmenting, and symbolic transformation) and they do not require writing complex rules to identify a pattern. Artificial neural networks eliminate the need for using rules by automatically building an internal understanding of the pattern recognition space in the form of weights that describe the strength of the connections between the net processing units.
The paper illustrates the application of this new approach with a field example. The mathematical derivation and implementation of this approach can be found in Ref. 1.
Transient Pressure Behavior and Formation Damage Evolution of Wells During Matrix-Acidizing Operations
Authors: Rodriguez F. , Sanchez-B. J. M. , Cinco-Ley H. 
Published: December 2007

ABSTRACT
The transient pressure response and the evolution of formation damage of a well during a matrix-acidizing operation, performed at constant injection rate, is studied in this paper. Solutions are derived from a novel fully-implicit numerical model which simulates the mechanics of a matrix-acidizing process along with the mechanics of compressible flow in a porous media. The dynamic changes of permeability and porosity due to dissolution of up to two mineral species are considered in the reservoir flow equation. A damaged zone with petrophysical properties and mineral content different from the rest of the reservoir is included; the injection of a batch of inert fluid prior to the acid is also accounted for.
It is found that the pressure behavior and the evolution of formation damage during acidization depend mainly on the acid capacity number, NAc, the Damköhler number, Npa, the initial formation damage, S0, and the radius of the damaged zone, rsD). Typically, the early time presure response of an acidized well might show a semilog straight line of slope 1.151, if NAC and NDa are small enough. As formation damage is being removed, there is a continuous decrease in the slope of the pwD vs tD curve which eventually takes on negative values. At later times, when formation damage is removed, all curves converge to the stimulation with no damage case and positive slope values are reassumed. Major benefits of acidization are found with large s0 and small rsD. Large Damköhler numbers seem to perform better al early st imulation times and worst afterwards, suggesting that variable injection rates could yield the best stimulation results. Acid capacity number was found to have a major effect over pwD and formation damage evolution.
An Application of Geostatistical Methods for Risk Analysis in Reservoir Management
Authors: Srivastava R. M. 
Published: December 2007

Abstract
A case study is presented of risk analysis for a reservoir in which gas injection is used to enhance oil recovery. Geostatistics is used to build a procedure for addressing the question of how much gas should be injected. Through the use of indicator simulation, this procedure incorporates not only the quantitative information available from well logs, but also the qualitative information available from a geologic model of the reservoir. The use of loss functions enables the decision-maker to incorporate the economic parameters that affect the enhanced oil recovery procedure.
Pressure Buildup Test Results From Horizontal Wells in the Pearsall Field of the Austin Chalk
Authors: Lichtenberger G. J. 
Published: December 2007

ABSTRACTThis paper presents the results and representative data sets of pressure transient tests on horizontal wells in the Pearsall Field of the Austin Chalk. The data trends indicated possible early time radial flow, largely obscured by wellbore storage, followed by a strongly developed linear flow period. On tests of adequate length this is followed by a multiple porosity transition and a return to linear flow. The data was interpreted in terms of a pseudosteady state dual porosity flow model for the Austin Chalk. The fracture system permeability was estimated to be in the range of 0.5 to 10 md, the dual porosity storativity ratio was found to be between 0.1 and 0.01, while the interporosity flow coefficient had values near IE-07. The net thickness drained by the wells was determined to be between 100 and 400 ft, depending on the well tested. The abnormally large observed wellbore storage coefficients correlate with well productivity and are considered to be indicators of the fracture intensity.
A New Approach to the Prediction of Slug Frequency
Authors: Hill T. J. , Wood D. G. 
Published: December 2007

ABSTRACT
The design of crude oil production systems involving the pipelining of unseparated reservoir fluids requires a detailed understanding of multiphase flow phenomena. Slug flow in particular may cause undesirable process upsets if the separation and processing facilities are not designed to handle the resultant gas and liquid flowrate variations.
Slug characteristics, primarily length, holdup and frequency, cannot be adequately predicted by existing empirical correlations. Mechanistic models are more satisfactory if the measured slug frequency is used as an input. However, existing methods for predicting slug frequencies are also unsatisfactory.
BP have collected a large database on slug flow characteristics in both low pressure test rigs and field production flowlines. From this database BP have developed an improved method for the prediction of slug frequency. This method correlates slug frequency against the two parameters which appear from test rig observations to be the most important in the initial formation of slugs from a stratified flow. These parameters are the liquid holdup in the stratified film at the start of the line, and the gas-liquid slip velocity. The results indicate a much improved comparison with the data. The phenomenological approach to the correlation development gives increased confidence of its applicability to conditions outside the range of data from which it was developed.
Use of Field Data in the Analysis of the Influence of Proppants on Apparent Fracturing Fluid Viscosity
Authors: Jennings A. R. 
Published: December 2007

ABSTRACT
Fracturing fluid viscosity has an important influence on the outcome of any hydraulic fracturing treatment. Much work has been done on the effect of sand or particle concentration on the viscosity of Newtonian fluids. Work concerning the effects of proppant concentration on the apparent viscosity of non-Newtonian fracturing fluids is now beginning to appear in the literature. Several correlations involving the effects of proppant or particle concentration in non-Newtonian fluids have been presented recently.1–5
This work presents an assessment of influence of proppant on fracturing fluid viscosity using the friction pressure properties of sand-laden non-Newtonian fracturing fluid compared to the friction pressure of the fluid without proppant. For this presentation, the premise is offered that viscosity effects due to the suspended particles in non-Newtonian fluids'should be correlatable when comparing fluid pressure behavior of these fluids in turbulent flow.
Correlations have been worked out to describe the effects of sand concentration on effective fluid viscosity. These results compare favorably to the results obtained by other investigators addressing the problem using different techniques.
Effects of Fracture Fluid Invasion on Cleanup Behavior and Pressure Buildup Analysis
Authors: Montgomery K. T. , Holditch S. A. , Berthelot J. M. 
Published: December 2007

Abstract
A hydraulic fracture treatment is the most common method used to stimulate the gas flow rate of a well completed in a low permeability gas reservoir. Hydraulic fracturing is accomplished by pumping a proppant laden fluid into the formation at high injection rates.' Once the minimum principle stress in the formation is overcome, a fracture is induced and begins to grow. The vertical fracture will continue to grow until pumping is stopped. After the fracture treatment, fracture fluid will leak off and imbibe into the formation around the fracture as the fracture closes. After the fracture has closed, the well will be placed on production in order to clean up the fracture fluid around the fracture and begin producing gas.
Prior to performing a hydraulic fracture treatment, a complete reservoir description should be developed by the engineer and geologist. The reservoir description should include properties such as formation permeability, porosity, net pay, reservoir pressure, skin factor, and other information needed to properly describe oil and gas flow from the reservoir.2,3
In addition, the mechanical properties of the formation layers above and below the productive zone should be evaluated. The mechanical properties are needed to compute the estimated shape and dimensions of the hydraulic fracture that will be created. After the reservoir description has been completed, the hydraulic fracture treatment can be designed and pumped. During the fracture treatment design, the engineer should optimize the fracture length and the fracture conductivity based upon the pre-fracture reservoir description. In order to improve the productivity of future wells, each existing well should be analyzed after the fracture treatment to determine how to improve the fracture treatment design.2,3