bluuebunny/crossref_metadata_2025_split huggingface dataset:
Well Kill (Quenching) Study of Thermal Producers in the South Belridge Field, California
Authors: Fram J. W. 
Published: December 2007

Summary
This paper presents a field study confirming that damage occurs during kill (quenching) operations of thermal producers in the South Belridge field, Kern County, CA. Implementation of the recommendations from this study are expected to decrease damage that occurs during quenching by an average of 0.5 BOPD/kill. Results indicate that producers completed with openhole, gravel-packed, slotted liners in high-permeability sandstones can sustain substantial, irreversible damage when subjected to unfiltered produced-water kills. The damage results when previously produced sand and fines, which have settled in the flowline, are reinjected into the wellbore. Most of the damage is in the slots and gravel pack. Previous studies, field tests, and laboratory work quantifying the amount and site of the damage are detailed. Methods of determining water-quality specifications needed to minimize damage that occurs during well kills are outlined. The approach presented can be used to identify and quantify damage in any field where producers require kills before workover operations. The current recommended kill procedure is also included.
Acquisition Pitfalls: Operating Cost Forecasts
Authors: Doering M.A. 
Published: December 2007

Summary
Evaluations of potential oil and gas property acquisitions often prove to be substantially optimistic as a result of errors in operating-cost forecasts. This paper sets forth several potential pitfalls associated with forecasting operating costs that should be considered before an acquisition is consummated. Potential problems are identified and discussed from three general areas:seller-furnished information,field operations and government regulations, andforecasting methodologies.

Introduction
Acquisition of existing producing properties has become an important part of the growth strategies of many oil and gas companies. Many variables must be analyzed and projected to evaluate a potential acquisition, the most significant of which are production rates, product prices, and operating expenses. Each of these variables is critical to the determination of actual property value.
Extensive publications and training courses are available on production-rate projection, and numerous reservoir engineers and geologists specialize in the science of projecting production rates. Past performance history, which forms the basis of most production-rate forecasts, can be verified by checking public records or from copies of revenue checks obtained from the seller. Well tests also can be performed to verify the current producing characteristics of a well. Product-price forecasts also are given extensive attention by both engineers and financial marketing experts. Each company formulates its own product-price forecast (or range of forecasts) applicable during evaluation.
Even with the most accurate production-rate and product-price forecast, however, an oil and gas property acquisition can fail to generate projected profits as a result of errors in the operating-cost forecast. This area of evaluation often is given only cursory attention by the evaluation team and consists of merely mathematically averaging seller-furnished historical costs for the past 6 to 24 months. This analysis method can lead to significant mistakes in property evaluation. We determined several common pitfalls associated with operating-cost forecasts through review of data furnished by potential sellers of more than 800 property packages during the past 6 years and detailed analysis of actual post-acquisition performance of 18 selected purchases. Consideration of these pitfalls will help evaluators prepare more accurate forecasts and reduce the risks associated with this often-neglected area of evaluation.
Reduction of Gas and Water Permeabilities Using Gels
Authors: Seright R. S. 
Published: December 2007

SummaryWe investigated how different types of gels reduce permeability to water and gases in porous rock. Five types of gels were studied, including (1) a "weak" resorcinol-formaldehyde gel, (2) a "strong" resorcinol-formaldehyde gel, (3) a Cr(III)-xanthan gel, (4) a Cr(III)-acetate-HPAM gel, and (5) a colloidal-silica gel. For all gels, extensive coreflood experiments were performed to assess the permeability-reduction characteristics and the stability to repeated water-alternating-gas (WAG) cycles. Studies were performed at pressures up to 1,500 psi using either nitrogen or carbon dioxide as the compressed gas. We developed a coreflood apparatus with an inline high-pressure spectrophotometer that allowed tracer studies to be performed without depressurizing the core. We noted several analogies between the results reported here and those observed during a parallel study of the effects of gel on oil and water permeabilities.
Experimental Study of Nonlinear Effects in Hydraulic Fracture Propagation
Authors: de Pater C. J. , Weijers Leen , Savic Miloš , Wolf K. H. A. A. , van den Hoek P. J. , Barr D. T. 
Published: December 2007

Summary
We conducted fracture propagation experiments on blocks of cement paste, cement paste with sand, and a tight outcrop sandstone rock. A novel acoustic monitoring system was developed for measuring the fracture profile and radius during the tests.
Results of laboratory tests on cement agreed with numerical simulations based on elastic rock deformation and linear elastic fracture mechanics. Tests at confining stresses of 20 and 23 MPa gave higher pressures than predicted.
Dauphin Island Natural Gas Project
Authors: Layfield R.P. , Elser K.L. , Ostler R.H. 
Published: December 2007

Summary
Arco Oil and Gas Co. installed the Dauphin Island production facility in a fragile Alabama marine environment supporting important fisheries and tourist facilities. We used proactive communication with governmental agencies, area industry, and the public; innovative construction technologies; and unique platform design to minimize the environmental and aesthetic impacts and to develop an economically successful gas field. The innovative equipment used in the offshore pipeline installation is a model approach for solving certain turbidity problems. The project has received numerous environmental awards.

Introduction
The Mobile Bay area of Alabama is a popular recreational region, containing many sport and commercial fisheries. In 1969, the first oil and gas leases were acquired in Mobile Bay. Within 1 year, applications for the proposed drilling activities were submitted to the U.S. Army Corps of Engineers for approval. The first permit was approved 9 years later. The first well, drilled in 1978, led to the discovery of the Mary Ann field. Production of the deep, sour Norphlet gas was brought on line in 1988, 19 years after the original leases were purchased.
Also in 1988, Arco purchased its first leases in the Mississippi Sound just west of the Mary Ann field (see Fig. 1). That purchase was the beginning of the Dauphin Island Natural Gas Project. After successfully drilling three wells in 1990 and identifying the commercial potential, Arco wanted to secure prompt approval of its development plans. The project resulted in the development of shallow Miocene gas in two fields (North and Northwest Dauphin Island) located about 2,000 ft below the Mississippi Sound.

Concerns About the Development
The economic viability of the project hinged on obtaining timely permits to construct an offshore platform within sight of Dauphin Island and a 15-mile pipeline to transport the produced gas from the platform to its onshore sales point through a different pipe line corridor than used for previous Mobile Bay developments. Some regulatory representatives indicated that all offshore oil and gas developments in the area may be re quired to use an existing, single pipeline corridor several miles east of the development to minimize disruption to wetlands. Also, numerous regulatory and public concerns were stressed during other companies' construction activities that had heightened sensitivity to further developments. The greatest issues were the significant silt disturbances (potentially affecting oyster beds) and possible harm to onshore wetlands during pipe line construction. In addition, concern for area archaeological resources existed because of recent damage during similar types of pipeline construction by other companies. Finally, Alabama regulations required zero discharge in state waters during platform operations and all construction activities.
Modeling of Reservoir Compaction and Surface Subsidence at South Belridge
Authors: Hansen K. S. , Prats Michael , Chan C. K. 
Published: December 2007

Summary
Finite-element models of depletion-induced reservoir compaction and surface subsidence have been calibrated with observed subsidence, locations of surface fissures, and regions of subsurface casing damage at South Belridge and used predictively for the evaluation of alternative reservoir-development plans. Pressure maintenance through diatomite waterflooding appears to be a beneficial means of minimizing additional subsidence and Assuring as well as reducing axial-compressive-type casing damage.
Multidisciplinary Approach for Targeting New Wells
Authors: Shirzadi S.G. , Lawal A.S. 
Published: December 2007

Summary
Under currently known reservoir drive mechanisms, initial exploitation of a new field usually leads to drilling in several regions of the field for optimum production. As the field matures, it often is necessary to drill new wells to recover oil reserves trapped because of undetermined reservoir heterogeneity and not acknowledged during initial field development. Targeting new wells in a mature field is challenging because it calls for consensus among interdisciplinary groups (reservoir and production engineers, geoscientists, and drilling and facility engineers). The challenges usually involve estimating the cost and production of the new wells and finding convincing arguments that the existing wells will not drain the trapped reserves adequately. This paper provides a team approach to confront these challenges to target new wells in the mature Prudhoe Bay field. The field example shows that additional oil recovery was obtained with infill drilling.

Introduction
The large, unrecovered mobile oil resource base in the Prudhoe Bay field provides an immediate objective for additional recovery. A significant amount of oil was bypassed at the initial stage of field development because of a lack of knowledge of geologic information and reservoir heterogeneity (defined as the product of depositional and diagenetic processes and structural complexities). Therefore, as part of field depletion planning and to mitigate field decline, infill drilling of new wells often is proposed to increase recovery. In a large field, such as Prudhoe Bay, drilling new wells calls for interaction among professionals in several disciplines: reservoir, facility, environmental, production and drilling engineers, geoscientists, and petrophysicists. In addition, the field is divided into two operating areas. Therefore, cooperation with the partners also is required.
As in other infill-drilling projects, the development plan for drilling new wells in the Prudhoe Bay field was addressed with a multidisciplinary team approach. Also, as in other optimization strategies reported in the literature, the team approach focused on targeting new wells to optimize the depletion plan.
The Integrated Work Team Approach to Performing Reservoir Simulation Studies
Authors: Hazlett W. G. , Johnson R. S. , Sibley M. J. , Thompson J. C. , Bent J. V. , Hrkel E. J. , Bazzari J. A. 
Published: December 2007

Summary
Modern computer systems help the "integrated work team approach" to be applied effectively in major reservoir studies. Current computer hardware and software facilitate this approach and have allowed superior results to be obtained in a field study of a large Middle Eastern reservoir [3 billion bbl original oil in place (OOIP)]. This paper focuses on the use of computers in each stage of the study. The benefits of being able to update geophysical, geological, and reservoir models easily (as new knowledge is obtained) also is illustrated. For comparison, we present the old reservoir history match developed with a "linear approach" and without the use of current technology.
An Integrated Data Model for Reservoir Simulation
Authors: Aydelotte S. Robert 
Published: December 2007

Summary
This paper describes the capability of the Epicentre data model to manage reservoir-simulation information, including the spatial model used to describe the properties of the earth and the product-flow network model used to describe production performance. In addition to data values, the data model describes data creation and quality and provides a reliable means of understanding the source. To use the data model, reservoir-simulation applications need to be rewritten to conform to the data-model nomenclature and conventions. While this is a significant task, the benefit to reservoir-simulation practitioners and vendors includes integration of technical applications (such as mapping, well logging, and geophysical-interpretation systems), data portability (allowing Vendor A's simulator to use data prepared by Vendor B's preprocessor), and interoperability (such as using a third-party optimization package to conduct a series of simulations).
A Comparison of Probabilistic and Deterministic Reserve Estimates: A Case Study
Authors: Hefner J. M. , Thompson R. S. 
Published: December 2007

Summary
Twelve practicing petroleum engineers participated in a study comparing deterministic with probabilistic reserve estimates. Production data for five wells were provided sequentially in four phases covering the first 5 years of production history. A deterministic and probabilistic reserve estimate was made by each evaluator for each phase.
The deterministic reserve estimates were based on Securities & Exchange Commission (SEC) definitions. For the probabilistic reserve estimates, the evaluators were asked to supply three values: P90, P50, and P10. P90 is the value where there is a 90% probability that the actual reserves are greater than this value; P50 is the value where there is a 50% probability that the actual reserves are greater than this value; and P10 is the value where there is a 10% probability that the actual reserves are greater than this value. Most evaluators used their deterministic estimate as the basis for the probabilistic estimates. In these cases, subjective estimates were made rather than using a statistical approach.
The evaluators have more difficulty in estimating the P90 value when the decline exponent b is low. The evaluators have the same difficulty in estimating the P10 value when the decline exponent b is high. In comparing the individual evaluators, there is considerable variability in deterministic, P90, P50, and P10 values. The most variability is in the P10 values. Also, it was observed that over time, as more production history is recorded, P90 values do not approach truth from the low side.
A Rationale for Reservoir Management Economics
Authors: Hickman T.S. 
Published: December 2007

Summary
Significant economic benefits can be derived from the application of reservoir management. The key elements in economical reservoir management are the efficient use of available resources and optimization of reservoir exploitation through a multidisciplined approach. This paper describes various aspects of and approaches to reservoir management and provides case histories that support the findings.

Introduction
The genesis of this article was my participation in an SPE-sponsored reservoir management seminar in 1992. The invitation to speak on the economics of reservoir management arose from my experience in evaluating reservoir exploitation projects. However, after some reflection, I began to have doubts concerning what the economic considerations unique to reservoir management were. Reserve evaluations are not handled differently just because reservoir management is involved. Likewise, economic hurdle rates are unique to the particular company and have nothing to do with the study process. In a previous seminar, methods of financing projects were discussed. This was interesting but not normally the direct concern of those involved in reservoir management. What then are the unique economic aspects of reservoir management, if any? The answer seemed to lie within the reservoir management process itself.
What is reservoir management? Haven't reservoir engineers been doing this for years? Why all the hype about something that's not a new technology, not even a new concept? Most literature on reservoir management is centered around exploitation of large reservoirs in frontier areas of the world. Does reservoir management have a meaningful role in small reservoirs or mature producing basins? The leading advocates of reservoir management are usually experts in numeric simulation. Is reservoir modeling the essence of reservoir management? Only as these issues about the nature and use of reservoir management were examined did a rationale for the economic aspects develop.
What Is Reservoir Management?
Perhaps this question has been best answered in the negative. Reservoir management is neither a new technology nor the latest management consultant buzzword to justify corporate reorganization. While philosophical aspects to reservoir management exist, it is not an attempt to introduce Japanese management philosophy into petroleum engineering (e.g., total quality management).
Reservoir management has been described as (1) repackaging existing technology, (2) managing advanced technology, (3) long-range/strategic planning, (4) team approach to problem solving, and (5) common sense. All of these contain an element of truth.
Standoff and Caliper Measurements While Drilling Using a New Formation-Evaluation Tool With Three Ultrasonic Transducers
Authors: Moake G. L. , Birchak J. R. , Matthews R. G. , Schultz W. E. 
Published: December 2007

Abstract
A new formation-evaluation LWD tool that employs three ultrasonic transducers to determine tool standoff and borehole diameter is presented. The ultrasonic data are used to improve density and neutron-porosity measurements obtained from the same tool. The paper describes the ultrasonic transducer hardware and operating characteristics, as well as a unique technique for setting the ultrasonic threshold. Data processing procedures and caliper equations are also presented. Downhole phenomena that adversely affect the measurements are discussed, along with solutions used to handle them. Log examples illustrate the effectiveness of the ultrasonic measurements and include evidence of sticking, lateral bouncing, and whirling of the toolstring while drilling. Although monitoring of these undesirable bit motions is not currently available, future tools will be able to communicate this information to the surface to aid drillers.
Field Application of Hydraulic Impedance Testing for Fracture Measurement
Authors: Paige R. W. , Murray L. R. , Roberts J. D. M. 
Published: December 2007

Summary
Hydraulic impedance testing (HIT) is a technique for detecting and measuring formation fractures intersecting wellbores. A pressure pulse is introduced into a well, and the resulting pressure trace is interpreted to give fracture dimensions. The first part of this paper describes how HIT can be used to estimate fracture dimensions and presents some results from a laboratory experiment that show that dimensions can be measured accurately with HIT. The remainder of the paper describes field examples of the application of HIT. A demonstration of how HIT traces change as pressure is reduced, which provides a method for determining fracture closure pressure, is included.
Pressure Transient Analysis of Fracture Calibration Tests
Authors: Mayerhofer M.J. , Ehlig-Economides C.A. , Economides M.J. 
Published: December 2007

Summary
Fracture-calibration pressure decline has been used for determination of the leakoff coefficient, a bulk variable describing the process of fluid influx into the reservoir, normal to the created fracture face. In this work, the fluid loss is modeled in terms of the controlling mechanisms: flow through the filter cake, the invaded zone, and the reservoir. A rigorous model describes unsteady-state fluid flow from fractures of varying area into the formation, with the filter cake considered as a time- and rate-dependent skin effect. The injection history is superposed on the pressure decline. This work provides a straight-line technique for determination of reservoir permeability and fracture-face resistance. Log-log diagnostic plots provide the means to recognize visually whether the transient response is dominated by flow in the reservoir or at the fracture face. We found that the pressure transient very frequently is dominated by the flow in the reservoir rather than through the filter cake. The reservoir permeability (an essential value for fracture design that is usually not available) can be estimated, while the model captures all trends of the falloff-pressure variation.

Introduction
The fracture-calibration treatment, also called an injection test or "minifracture," frequently is conducted before the main stimulation treatment. For the injection test, the fracturing fluid intended for the main treatment is pumped at a constant rate of a sufficient magnitude to achieve fracturing pressure. After several minutes (usually 20 to 30) the pumps are shut off and the bottomhole pressure declines as the fracture closes.
During pumping, while the fracture volume grows, some of the fracturing fluid leaks off into the formation. After pumping ends, the fluid leakoff into the formation continues until the fracture is closed. Material balance, coupled with a model of propagation, permits estimation of the rate of fluid loss during pumping.
The behavior of the pressure decline after the end of pumping has been used to estimate the leakoff (fluid-loss) coefficient, with techniques pioneered by Nolte. Castillo, using Nolte's G-function for modeling the pressure-decline behavior, developed the straight-line plot of the G-function vs. pressure. The slope of this curve is used for the computation of the leakoff coefficient that is independent of pressure.