bluuebunny/crossref_metadata_2025_split huggingface dataset:
Sequence Stratigraphic Model and Geology/Reservoir "Flow Unit" Study Improve Profitability and Recover Additional Reserves at the Sharon Ridge Canyon Unit
Authors: Kane T. V. , Henderson R. P. 
Published: December 2007

Abstract
The creation of a sequence stratigraphic geologic model of the Sharon Ridge Canyon Unit (SRCU) has significantly improved reservoir description in this highly stratified carbonate reservoir. The enhanced vision of geologically continuous sequences is dramatically better than that provided by traditional 2-dimensional (2D) lithostratigraphic (log cross section) correlations. The much improved accuracy of predicting geologic continuity has enabled engineers and geologists to recommend effective programs to optimize current waterflood operations. The combined effect of developing a sequence stratigraphic model, identifying the reservoir "flow units" associated with continuous sequences of pay and optimizing the depletion of these "flow units" has improved field production rates and resulted in a reduction in operating expenses.
Multi Zone Completion Design Considerations
Authors: Aldridge Don 
Published: December 2007

Abstract
Very often, a wellbore penetrates numerous geologic zones of interest. An optimum completion design addresses a method of isolating these zones while protecting the reservoir for future exploitation. A common practice is to utilize two or more packers for efficient zonal isolation. When designing such a completion, a number of conditions and phenomena must be considered. These include, among others: thermal expansion; pressure changes; piston effects, and their resultant force and/or length changes. This paper outlines some of the factors that must be taken into consideration, then presents specific challenges and viable solutions for typical multitandem completion designs.
Wireless Telemetry for Transmitting Pressure and Temperature Data on a Drillstem Test
Authors: Holder Kent , Heine Dick , Copeland David 
Published: December 2007

Abstract
An openhole drillstem test (DST) simulates producing conditions to help operators determine if a formation may be commercially productive during the drilling phase of the well. A DST isolates a formation with packers, and a tester valve opens to expose the formation to lower hydrostatic, which causes the formation to produce. After a predetermined flow period, a downhole shut-in valve closes to start a buildup period. The sequence of flow and closed-in periods is repeated as required.
Testing can provide information such as effective perme-ability, skin damage, formation pressure, flow rate, fluid type, and radius of investigation. Effective permeability, skin damage, and formation pressure calculations are possible only if the buildup period is long enough to reach Horner data.1 The duration of close-in periods is generally based on rule of thumb, bubble-hose response, or field experience. Surveys of current DST reports indicate that 30% of formations tested were not shut in long enough for Horner data to be obtained. The best method to determine the length of flow and shut-in periods is to monitor the pressures real-time at the surface. Wireline surface readout is available but is costly and poses risks, since the wireline is in the well. This paper discusses the operation and application of a new wireless telemetry tool that transmits real-time pressure and temperature readings to surface on an openhole DST.
Process Changes Improve Fracture Treatment Designs in the Hugoton Gas Field
Authors: Hecker M. T. , Downie R. C. 
Published: December 2007

Abstract
Hydraulic fracturing has been used extensively for well stimulation in the Hugoton gas field since the 1960's. Through continuous improvement efforts, and a renewed importance placed on quality data collection, stimulation costs have been significantly reduced since 1991 by pumping smaller single stage fracture treatments without sacrificing gas production. Better control of fracture growth has lead to initial savings in capital investments as well as improving ultimate gas recovery.
Development of the Cleveland, Tight Gas Sand, in the Texas Panhandle
Authors: Lovett W. T. , Atkins R. J. 
Published: December 2007

Abstract
The Cleveland Formation exists across a large area of the Texas Panhandle. This is a tight gas sand with very low permeability.
The two major fields in the Cleveland Formation are the Bradford and Ellis Ranch. These fields were discovered in the late 1950's and developed on 640 acres per well originally. They were later downspaced to 320 acres and recently have been downspaced to 160 acres per well.
Work by a large independent producer in conjunction with the Gas Research Institute has resulted in more efficient and effective development of the Cleveland Formation. Field histories, regulatory difficulties, drilling cost reduction, fracture technology, and economics are discussed; along with case histories and comparison of techniques.
Increased reserves and profitability in the Cleveland Formation have been realized through this effort.
Prediction of Low-Frequency Offshore Structure Response to Irregular Waves Using Linear and High-Order Wave Theories
Authors: Ramos R. J. , Zhang J. 
Published: December 2007

Abstract
The predicted responses of an offshore structure when the wave kinematics are computed from different estimation methods can change significantly. The sometimes controversial results have recently motivated the development of a new methodology for random wave kinematics prediction known as Hybrid Wave Model (HWM). In this paper, the performance of the new methodology and other methods currently used for kinematics prediction was tested. The (surge) response of two offshore structures designed specially for deep-oil production was estimated using three methods (Hybrid Wave Model, Wheeler "Stretching" and Linear Extrapolation) and compared with the corresponding laboratory measurements. The wave forces were computed from the conventional Morison Equation evaluating the ambient wave kinematics from the wave elevation measurements and the response was computed using a numerical scheme based on a Finite Element time integration technique (Newmark-beta method).
The comparisons between measured and predicted responses using kinematics calculated from the Hybrid Wave Model showed excellent agreement, specially for the low frequency components, while those using methods based on linear modifications rendered poor underestimations. The low frequency (peak) responses of these deep-water offshore structures were found to be greatly dominated by very low frequency wave excitations, which are mainly due to the wave-wave interactions. This work will show the necessity of high-order methods to evaluate irregular wave kinematics and induced responses.
The Adon Road - An In-Depth Gel Case History
Authors: Smith J. E. , Mack J. C. , Nicol A. B. 
Published: December 2007

Abstract
The Adon Road Unit is a Minnelusa Reservoir located in the Powder River Basin of northeast Wyoming. Permeabilities in this unfractured Minnelusa sandstone range from 10 to 1200 md, with an average of 320 md. Oil viscosity at the bottom hole temperature of 175°F is about 5 cps. Polymer flooding was initiated at the beginning of the waterflood to correct the high perm variation and adverse mobility ratio. Because of the high permeability variation, in-depth colloidal dispersion gels (CDG's) gels were used to initially sweep and block the high permeability rock to subsequent water and polymer injection. CDG's consist of polymer with aluminum citrate crosslinker, injected as a homogeneous solution. A total of 564,948 barrels, or 8.03% PV, of CDG were injected at an average polymer concentration of 268 mg/L over 20 months. The CDG was followed by 556,800 barrels, or 7.91 % PV, of uncrosslinked polymer at an average concentration of 150 mg/L, injected over 17 months. Following the gel and polymer program, straight water was injected.
The polymer and gel program has resulted in more oil recovered with less water handled. Total recovery through January, 1995, was 45.2% STBOOIP after 32.3% PV total water injection, compared to 27% STBOOIP typical for straight Minnelusa waterfloods at the same cumulative water injection. Ultimate recovery has significantly exceeded the original model projections. The details of gel and polymer placement, field response and monitoring are reported. Original assumptions about the reservoir and chemical flood are explored to determine why actual performance exceeded projections.
A Systematic Laboratory Core and Fluid Analysis Program for the Design of a Cost Effective Treatment and Cleanup Guidelines for a Produced Water Disposal Scheme
Authors: Ohen Henry A. , Nnabuihe L. , Felber B.J. , Ososanwo Duni , Holmgren C.M. 
Published: December 2007

Abstract
A practical and systematic technique for the determination of cleanup guidelines based on laboratory rock and fluid studies is presented. This method was employed in the preliminary design of a water disposal scheme requiring a high rate (30,000 bpd per well) into a shallow aquifer system in the Niger Delta. A description of the laboratory tests employed in the evaluation of the potential and the degree of impairment from the different mechanisms is presented along with interpretations and scaling of laboratory data to field operating conditions. Injectivity impairment resulting from relative permeability effects due to increased oil saturation over time, emulsion block, particulate plugging from suspended solids and in-situ mobilization, and clay swelling were quantified by time dependent pseudo skin factors.
A composite time dependent pseudo skin was derived from the combination of the individual components obtained from specially designed laboratory analytical tests on representative core and fluid samples. The results were extrapolated to field conditions using standard scaling techniques and employed as a basis to determine water treatment requirement and periodic cleanup guidelines.
This approach enabled the conceptual design of a pilot water disposal scheme based solely on laboratory study of representative produced water, formation water and aquifer rock samples. Specification for water clarification, filtration, formation pre-treatment guidelines and cleanup schedule for the disposal well in the target aquifer system were made apriori to field implementation.

Introduction
The quality of the source water (produced or surface) is of prime concern in any water injection or disposal project. Clean water is particularly important in wells requiring sustained injection at high rates. Oil and suspended solids must be held to a concentration below maximum tolerable limits to maintain injectivity for an extended period of time. The objective of this water disposal study was to assess the feasibility of subsurface disposal of produced water from an inland dehydration station. The study was based on the current need to dispose of 175,000 bbl/d and the possible future need to dispose of up to 300,000 barrels per day of produced salt water by the year 2008.
The following four major tasks were pursued in the study;Identification of candidate aquifer system(s) for the disposal of the produced waterCharacterization of the aquifer system, compatibility studies, and development of injectivity criteria
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Evaluating Waterflood Potential in a Morrow Sandstone Reservoir
Authors: Mohan Hitesh , Burchardt Per , Willhite G. Paul , Reynolds Rodney R. , Jensen Mike 
Published: December 2007

Abstract
The Stewart Field project is a demonstration project being conducted in Kansas under the U.S. Department of Energy’s Class 1 Oil Program for fluvial dominated deltaic reservoirs. The objective of this project is to address waterflood problems in Morrow sandstone reservoirs in southwestern Kansas. The general topics addressed are 1) reservoir management and primary drive performance evaluation, and 2) the demonstration of a recovery process involving currently available technology which can be used to enhance waterflood recovery and increase reserves. The project is being conducted in a cooperative manner, involving University of Kansas scientists, engineers, and geologists and independent oil operators.
Project results to date are 1) the development of a comprehensive reservoir database using personal computers, 2) the completion of a simulation study to history match the primary production, 3) the simulation of waterflooding and polymer flooding, 4) an economic analysis to assist in identifying the most economical waterflood pattern, 5) completion of laboratory analysis conducted on reservoir rock, 6) unitization of the field so that a field-wide improved oil recovery process could be implemented, 7) design and construction of waterflood facilities and 8) initiation of the waterflood.
Current activities and future plans consist of the operation of a waterflood installation utilizing state-of-the-art technologies in an attempt to optimize secondary oil recovery. Production and reservoir data will be analyzed using reservoir characterization techniques and by updating the existing reservoir simulation. The analysis of results will be utilized to optimize the waterflood plan and flooding techniques to maximize the secondary oil recovery. This project was awarded the "Best Advanced Recovery Project in the Mid-Continent" for 1995 by Hart’s Oil and Gas World.
A Sinusoidal Pressure Response Method for Determining the Properties of a Porous Medium and Its In-Situ Fluid
Authors: Bennion D.W. , Goss M.J. 
Published: December 2007

Abstract
Solutions to the equations describing flow in porous media under sinusoidal pressure conditions are available in the pressure conditions are available in the literature. Very little use has been made of this theory and the experimental applications reported have dealt with gases and no flow through the media.
Frequency response data from sinusoidal pressure experiments using liquids can be pressure experiments using liquids can be used to characterize the porous media and fluid properties. The lack of this type of data is probably due to the difficulty of generating the sinusoidal disturbances having sufficient frequency range and amplitude.
Measurements were made using a synthetic oil in an unconsolidated medium. Equipment was designed to generate pressure sine wave whose upper frequency limit was in excess of 1,000 rad./sec. The core was equipped with high speed pressure transducers at various positions along the medium which measured the positions along the medium which measured the pressure response at a known flow rate. pressure response at a known flow rate. The experiments were designed to study the effect of pressure amplitude and frequency on the response of the system. Comparison of the theory and these experiments indicates that there are definite frequency limits which may be used if the equations are to adequately describe the data. As the frequency and or permeability increases, the inertial terms become important.
This study shows that practical use can be made of existing theory to increase our ability to describe the flow of fluids in porous media.

Introduction
The measurement of pressure transient responses is one of the few methods available for the reservoir to communicate its rock and fluid properties to an observer.
Frequency response methods have been used by several investigators to determine rock and fluid properties. Experimental studies have been reported which used sinusoidal pressure inputs in gas filled porous systems with storage pores. Other porous systems with storage pores. Other investigators have used pluse testing methods to determine reservoir properties.
Several methods have been proposed for describing the behavior of pressure transients in porous media.
Real-time Analysis of Dynamic Data Acquired During Gelant Placement for Water Control
Authors: Shah P. C. 
Published: December 2007

Abstract
A new technique is developed for real-time monitoring of the gelant placement through interpretation of the injection rate and pressure history in a high-permeability water producing layer of a petroleum reservoir. The method makes the same assumptions as those for Hall plot analysis of the longer-term polymer injection, i.e., steady-state, radial, two-fluid, Darcy flow in the treatment layer. A piston-like displacement of the reservoir fluid by the gelant is assumed.
The derivation of the mathematical model underlying the technique is presented that leads to introduction of a parameter group named Differential Impedance to Flow (DIF). DIF is defined as the difference of the two fluid relative impedances (viscosity divided by relative permeability of the fluid, reciprocal of the well-known relative fluid mobility) divided by the permeability-thickness of the treatment layer. It is robustly estimated in real time from the slope of the straight line fitted over a fixed-width time window containing the most recent data in a specialized plot This is the plot of the derivative of the classical Hall plot versus the log of injected fluid volume. The estimation of DIF in this manner requires remarkably little information about the treatment zone formation or the reservoir fluids. DIF monitoring may lead to real-time conclusions about changes in the rheology of the gelant, the onset of gelation, the effect on the reservoir permeability due to gel adsorption, or encounter with reservoir heterogeneities such as change in layer thickness or permeability with radial distance from the treatment well.
Illustrative examples with synthetic data from one and two-layer reservoir models are presented that show the evolution of real-time estimates of DIF as the injection of a low viscosity (3 cp) gelant proceeds. In both situations, the correct value of DIF is estimated within a fraction of an hour of the start of injection and the value remains essentially unchanged when the injection rate is halved.
An example with field data is also presented, in which a medium viscosity (100 cp) gelant was injected into a high-permeability gas-producing zone in a sandstone oil reservoir. It illustrates the variability of apparent DIF values and the difficulties that may be encountered in interpretation of real injection data.
Techniques for Multibranch Well Trajectory Design in the Context of a Three-Dimensional Reservoir Model
Authors: Ehlig-Economides C. A. , Mowat G. R. , Corbett C. 
Published: December 2007

Abstract
Mullibranch wells offer a means to contact more reservoir per wellhead or platform slot. Optimal well plans must begin with a concept of the trajectories of the lateral branches within the productive reservoir zones These can be vertical, inclined or horizontal, as can the main trunk of the well. This paper provides criteria for deciding the lateral branch trajectories depending on reservoir properties, rock stress regime and the geometries of the productive reservoir units. Because production from several lateral wells can be commingled in a common main trunk, this may permit more holes to be drilled in the reservoir than would have been feasible with conventional wells.
The reservoir model used for planning a multibranch well must capture the delineations of the hydrocarbon-bearing zones, the major axes of the stress regime and the first order controls on fluid flow in the reservoir. This paper illustrates the representation of the three-dimensional visualization of the main reservoir bodies showing the gas, oil and water zones along with the proposed well path. Finally, the reservoir model provides properties of the productive zones to be completed along the well trajectory enabling a forecast of the well productivity for economic analysis.
Once a set of well branches has been envisioned, the well plan proceeds from the reservoir to the surface. For a multibranch well, the main trunk should have a simple trajectory to ensure successful drilling and completion and to enable future access to the branches. From the main trunk the well plan projects an optimal path to the wellhead location. Alternatively, the well plan may accommodate a sidetrack trajectory to a planned branch from an existing well.
A Systems Approach to Production Management: Beryl Field Case Study
Authors: Arnondin M.C. , Jackson M.A. 
Published: December 2007

Abstract
When Beryl Field gas sales commenced in 1992, a production management system was implemented to ensure that gas sales targets were met without compromising oil production rates. This paper describes the operator's experience in establishing this system.
In the Beryl Field, systems analysis techniques are applied in both the data gathering and well modelling procedures. This approach has resulted in significant improvements in both the quality of field data and the accuracy of model predictions. The production system model is used for optimising lift gas allocation, production forecasting for normal and maintenance scenarios and workover planning.
The evolution of the production management system is described and its application to routine operations and special projects is illustrated by examples. The techniques described are general and can be applied to all production optimisation applications.

Introduction
Production optimisation is as much a culture as a technology. For any production optimisation initiative to succeed, the entire organisation must accept responsibility for data gathering and interpretation. This paper describes changes in the operating environment that catalysed the development of this system, along with the operators approach to data acquisition, the management of the collected and interpreted data, well model construction and maintenance practices, and the cultural elements which influenced the Beryl Field optimisation project. The resulting production management system has significantly increased production efficiencies and today, is a reliable component of the Beryl Field design, decision and implementation processes.

Background
The Beryl field, located in Block 9/13 of the UK sector of the North Sea, has produced approximately 650 MMSTB of oil and 700 Bcf of gas since production commenced in June 1976. The Beryl A Condeep structure, which contains the crude storage and loading facilities, has two separation trains each capable of handling 70 MSTB/D of oil, 60 MSTB/D of produced water and 300 MMscf/D of gas. The Beryl B platform, which began production in 1984, has a single separator train with a throughput capacity of 70 MSTB/D of oil, 60 MSTB/D of produced water and 200 MMscf/D of gas. On both platforms, gas compression capacity is the limiting production constraint.
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