bluuebunny/crossref_metadata_2025_split huggingface dataset:
Mechanical Damage Caused by Perforations May Affect Fracture Breakdown
Authors: Halleck P. M. , Robins J. , Pekot L. , Schatz J. , Schatz John F. 
Published: December 2007

Abstract
We have performed perforation tests on three large rock specimens and mapped indentation hardness around the perforation. We find reduced hardness up to 1.5 inches from the center of the perforation. Maximum reductions as high as 75% occur near the wall of the perforation. In Berea Sandstone, there is a clear trend towards increasing damage near the entrance hole and reduced damage near the perforation tip. On the assumption that the indentation hardness represents more fundamental mechanical properties, a trial elastic model has been developed that illustrates the potential effect of the observed damage on stress distribution, and thus on fracture breakdown pressure. Based on the experimental results, this model predicts incipient fracture initiation at lower pressures, but also predicts high compressive stresses near the boundary of the damaged and undamaged material. This may be interpreted as representing a barrier to further crack extension, thus increasing the effective breakdown pressure. Preliminary, but more detailed computer calculations including wellbore and perforation flow suggest that the damage zone effect can be substantial in restricting ultimate breakdown. It is noted that the actual mechanical model should include brittle and plastic failure to more accurately predict breakdown behavior.
Desorption Enhancement in Fracture-Stimulated Coalbed Methane Wells
Authors: Lehman Lyle V. , Blauch Matthew E. , Robert Lavelle M. 
Published: December 2007

Abstract
The dewatering process, which stimulates gas desorption, is essential for gas production in coalbed methane (CBM) reservoirs. Many CBM wells require hydraulic fracturing to provide interconnectivity and hydraulic access to the cleat/matrix system. Without hydraulic communication and access to the hierar-chical flowpath, gas desorption is severely limited or nonexistent.
When economics allow operators to continue long-term gas production, the gas rate of most coalbed wells will eventually increase. Over time, gas desorbs from the coal macerals that form the cleat blocks. However, some coalbed fields experience premature or severe declines in production because of poor hydraulic-fracture conductivity. Particulates have been discovered as a primary cause of poor hydraulic-fracture conductivity. These particulates flow with produced water; they are then deposited within the proppant pack where they block pore throats and interfere with gas desorption.
A surface modification agent (SMA) that prevents or reduces hydraulic-fracture conductivity damage has been developed and successfully field-tested. This agent, which has strong adhesive properties, helps delay or prevent conductivity damage to the proppant bed. This paper discusses (1) the problems associated with poor hydraulic-fracture conductivity, (2) why it occurs in coalbed wells, and (3) how a new SMA can minimize the problem.
Field Applications of Advanced Stimulation Technologies in Deep and Hot Wells in Dagang Oilfield, China – Diagnostic Tests Made Fracturing Treatments Successful
Authors: Xiong Hongjie , Green Trent W. , Guo Xiuting , Wang Mary 
Published: December 2007

Abstract
Careful review of reservoir data, proppant data, fracture fluid data, and fracturing equipment resulted in the successful application of advanced stimulation technologies (AST)1 such as minifracs, step-down rate tests, and quality control measures in two deep [±3660m (±12,000 ft)] hot wells [150°C (±300°F)] in China. Neither well produced prior to stimulation. Using locally available fracturing equipment and Dagang Oil Co.'s sole fracture fluid system, we successfully designed and pumped two fracture treatments. One well is producing 40 m3/day (250 STB/D) oil and 12,036 m3/day (425 Mscf/D) after stimulation.
This paper describes the AST program implemented by Dagang and summarizes a general methodology for applying new technologies (AST) in new or frontier areas.
Virtual Magnetic Imaging Logs: Generation of Synthetic MRI Logs from Conventional Well Logs
Authors: Mohaghegh S. , Richardson M. , Ameri S. 
Published: December 2007

Abstract
MRI logs are well logs that use nuclear magnetic resonance to accurately measure free fluid, irreducible water (MBVI), and effective porosity (MPHI). Permeability is then calculated using a mathematical function that incorporates these measured properties. This paper describes the methodology developed to generate synthetic Magnetic Resonance Imaging logs using data obtained by conventional well logs such as SP, Gamma Ray, Caliper, and Resistivity. The synthetically generated logs are named Virtual Magnetic Imaging Logs or "VMRI" logs for short.
This methodology incorporates artificial neural networks as its main tool. Virtual MRI logs for irreducible water saturation (MBVI) and effective porosity (MPHI) as well as permeability (MPERM) were generated for four wells. These wells are located in East Texas, Gulf of Mexico, Utah, and New Mexico. The results are quite encouraging.
It is shown that MPHI, MBVI, and MPERM logs can be generated with a high degree of accuracy. For each case, 30% of the data were used to develop the neural model. The model was then tested on the remaining 70% of the data for verification. The models provide VMRI logs with approximately 80 to 97 percent accuracy using data not employed during model development.
This methodology does not supersede the need for performing MRI logging in a field. It is designed to supplement the process by reducing the cost of using MRI logging on an entire field. The natural application of this process is in fields that have conventional logs for all of the wells but MRI logs for only a few wells. To generate the Virtual MRI logs for every well in a field, data from wells that have both conventional and MRI logs are used in the model development and verification. The model is then applied to the other wells in the field to generate the virtual MRI logs for these wells.
Using this process, the operator can log a few strategically chosen wells using physical MRI tools and produce virtual MRI logs for the entire field. This will allow the development of an accurate representation of effective porosity, free fluid, irreducible water saturation, and permeability for the entire field.
Candidate Selection for Stimulation of Gas Storage Wells Using Available Data With Neural Networks and Genetic Algorithms
Authors: Mohaghegh S. , Platon V. , Ameri S. 
Published: December 2007

Abstract
The methodology developed in this study uses several artificial neural networks and genetic algorithm routines to help engineers select restimulation candidates based on available data. The neural networks provide realistic models of the hydraulic frac jobs and chemical treatments in this field. The genetic algorithms provide design optimization and economic analysis (capital investment allocation).
Historically wells in this storage field have been stimulated/restimulated by hydraulic fracturing or by being chemically treated using one, two or sometimes three different chemicals. Several neural network models were developed for different stimulation processes. The first series of genetic algorithm routines are used with each of the neural network models to provide optimum treatment design for each of the stimulation processes. A separate genetic algorithm uses several economic parameters and provides the engineer with an optimum stimulation combination of the candidate wells.
A software tool based on this methodology has been developed for a gas storage field in Ohio.
Upon the completion of the analysis, the software tool provides a list of the maximum number of candidate wells. This maximum number is based on the provided stimulation budget for a particular year. The list specifies the type of stimulation for each candidate well – whether it should be refraced or chemically stimulated – and recommends a list of possible parameters to be used during the implementation.
A Shock-Free Approach in Fractional Flow Theory
Authors: Malik Mohammad A. 
Published: December 2007

Abstract
The Buckley-Leverett solution to the one-dimensional, two-phase, incompressible, immiscible fluid displacement problem in permeable media forms the basis of fractional flow theory. In cases with S-shaped fractional flow curves, the problem of triple saturations is resolved by shock assumption. The Welge integration is then applied for recovery and frontal-advance calculations.
We present an alternative approach in fractional flow theory in which the two-phase displacement problem is analyzed without invoking the shock assumption. The shock-free approach eliminates the triple-saturation problem and identifies that saturation velocities are time dependent.
The shock-free solution is realistic and remarkably dynamic. It results in a simple procedure for recovery and frontal-advance calculations. It provides new insights into the fluid displacement problem by helping to better understand mechanisms that trigger fingering and cause dissipation.
Prediction of Contact Force for Drill Pipe/Coiled Tubing
Authors: Qiu Weiyong 
Published: December 2007

Abstract
This paper systematically presents an approach for predicting the contact force for drill pipe/coiled tubing in vertical, deviated, and curved wells corresponding to different pipe configurations, i.e., no-buckled, sinusoidal, and helical configurations. Utilizing the Lagrange multiplier method, the equilibrium equations are obtained for pipe in vertical, deviated, and curved wells. The Lagrange multiplier represents the unit lateral contact force between the pipe and the wellbore. Solving the equilibrium equations simultaneously, the contact forces corresponding to straight, sinusoidal, and helical configurations are derived for drill pipe/coiled tubing in vertical, deviated, and curved wells, respectively.
Environment and Coiled Tubing: Both Can Be Protected
Authors: Metcalf Arthur Steven 
Published: December 2007

Abstract
Acid stimulation using coiled tubing conveyance is becoming commonplace; however, protection of these coils from acid corrosion is challenging. Add to this the requirement for usage of materials less damaging to the environment, and the task approaches the impossible at high temperatures (&gt;250) and high acid strengths (&gt;20).
The common requirement of corrosion weight loss for jointed tubulars (N-80, J-55, L-80, CR-13, etc.) is &lt;0.05 pounds per square foot and &lt;0.02 to &lt;0.03 for coiled tubing. Increasing acid strength and/or temperature causes an increase in the corrosion inhibitor package cost by nearly 400% as the conveyance tubular changes from N-80 to coiled tubing.
Included in this paper is a comparison of corrosion data generated for hydrochloric acid systems from 20 to 28% on coiled tubing, N-80 and CR-13. The inhibitor evaluated is a blend of select solvents, activated ketone, a small quantity of acetylenics, surfactant and an amine. This material is given a Group "C" designation under the Revised Offshore Chemical Notification Scheme. A summary of the information used to define this inhibitor's Group "C" designation is presented.
An Unexpected Paraffin Dispersant
Authors: Voss M. S. , Cioletti K. R. , Deffeyes K. S. 
Published: December 2007

Abstract
A formulation originally developed for removing ink from printing presses turns out to be a suprisingly successful dispersant for paraffin and asphalt. The formulation is nontoxic and refineries are accepting crude oil produced during the treatment. Laboratory results suggest that the formulation is a freezing point depressant for paraffin not a kinetic inhibitor of paraffin crystallization.
Drilling And Production Techniques In Geothermal Reservoirs
Authors: Whiting Robert L. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.
Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Abstract
The general types of geothermal systems will be defined and the appropriate rock, fluid, pressure and temperature conditions characterizing each type of geothermal reservoir will be identified. These characteristics will be related to the drilling and production problems which are encountered and the present state of the art of pertaining to the solution of these problems.

Introduction
The population explosion coupled with man's accelerating desire for a higher standard of living has greatly increased his demand for energy in the past, and there is evidence to expect a similar—if nor greater— demand in the future. Quite obviously, natural forms of energy that are readily available at low development cost are those in greatest demand. One of the least expensive energy sources is natural geothermal steam. Although this form of energy has been recognized for centuries, it has been only during the past 20 years that serious efforts have been made to harness it. Natural geothermal steam is now being produced through wells to drive turbines and generate electricity. Identification of geopressured resources has stimulated multiple use development in producing electrical energy, desalinated water, minerals, dissolved gases, etc. The present energy crisis in the U.S. has further accelerated interest in this potential form of energy. Recent development of the Nation's geothermal resources has focused attention on reservoir evaluation and drilling and fluid production problems. It is the purpose of this paper to problems. It is the purpose of this paper to identify these problems and success in their solution, thus far.

RESERVOIR CHARACTERISTICS
Although geothermal reservoir geology has not been satisfactorily described, it is generally agreed that the geothermal fluid is contained in the porous and permeable matrix rock comprising a structural trap having an impervious cap. The geothermal fluid may exist in the reservoir in the vapor, vaporliquid, or liquid state depending upon the pressure, temperature and fluid composition. pressure, temperature and fluid composition. The matrix rock may be of either the isotropic (intergranular) or fracture type or a combination of the two types.
Technical and Operational Factors Crucial to Successfully Drilling Deep Exploratory Wells
Authors: Kandle Joseph R. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.
Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Abstract
This paper considers deep exploratory drilling from inception through casing design, programming, drilling operations, and programming, drilling operations, and evaluation In each area, the major technical and operational pitfalls that an operator can expect to encounter are discussed along with appropriate recommendations or considerations. Although there is a specific occasional reference to Great Basins - Tenneco 31X-10, Kern County, Calif. (T.D. 21,640 ft, California's deepest) and the basic experience is gleaned from California operations, the majority of recommendations and considerations offered would have application wherever a deep, exploratory well is proposed.

Introduction
Deep drilling operations below 15,000 ft continue to capture the majority of drilling publicity. This voluminous amount of 15,000+ publicity. This voluminous amount of 15,000+ literature deals, for the most part, with the general over-all success of a specific project. Rarely are the everyday field operational and specific technical pitfalls that an operator can encounter in venturing into a project ever delineated. It is the author's opinion that this broad-based successful trending literature has lauded many persons in the petroleum industry into believing that, since deep drilling has extended to the 31,441-ft depth, major technical and operational pitfalls to this depth have been solved; such is not the case, as those in both the design and direct 24-hour field management responsibility level can attest to. Daily, wells projected to 15,000 ft + continue to unsuccessfully reach their projected total depths and/or evaluate their "shows." It is the goal of this paper to delineate the everyday operational and technical pitfalls that an operator can encounter in deep drilling, regardless of their area of operation. By highlighting still existing technical and operational limitations, and suggesting certain operational and technical considerations, the expectation is that other operators will be able to minimize their problems, likewise their future expense, with the ultimate result being more wells to solve the problems associated with deep 15,000+ ft wells, and more reserves for an energy-short nation.

WELL PLANNING AND DESIGN

Information and Data Search
Successful deep exploratory drilling begins in the office of the drilling engineer months prior to spudding. prior to spudding.
Analysis of Drilling Strengths in Evaporite Rocks
Authors: Boone D.E. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.
This paper was prepared for the Deep Drilling and Production Symposium of the Society of Petroleum Engineers of AIME, to be held in Amarillo, Texas, Sept. 8–10, 1974. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made.
Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Abstract
The drilling strength of rock is a finite measurement of crushing resistence similar to compressive strength measured on laboratory specimens. This rock property dictates most of the drillers procedural decisions on a rig. Drilling strength determines which bit is used, the weight and rotary speed applied and mud properties.
A system has been developed that computes drilling strength automatically within seconds after each foot is drilled. A small computer is employed in the system with electronic sensors that determine depth, weight and revolutions on bit and time of drilling each foot. The computer calculates drilling strength then interprets it to provide a porosity and pore pressure provide a porosity and pore pressure log at bit depth.
Applications of the system, worldwide, have demonstrated a remarkable definition of porosity, permeability and pore pressure in permeability and pore pressure in evaporite rocks. Porosity is generally no more than two porosity percent varience with other porosity tools and pore pressure has an accuracy of + .2 ppg. Experience has shown pore pressure transition over several pressure transition over several hundred feet in massive carborates and significant pressure increase across a hard cap only ten feet thick. This has shown that evaporite rocks have pore pressure distribution detectable pore pressure distribution detectable in drilling response.

Introduction
The fear of a blowout and disaster has plagued the oil industry since Captain Lucas had the first one in 1901. Up to about 1965 a driller had the choice of drilling painfully slow with mud heavy enough to control any pressure or running light mud and gambling that abnormal pressure would not be encountered.
Production Case History, Jay Field, Florida
Authors: Maxson R.D. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.
Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussions may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Abstract
The Jay Field discovery in June of 1970 paved the way to extensive drilling and paved the way to extensive drilling and production facility activities in the Florida production facility activities in the Florida Panhandle and in south Alabama. Within 3 years, Panhandle and in south Alabama. Within 3 years, 94 wells had been drilled and 10 treating plants had been constructed. The Jay Field is approximately 8 miles long and about 4 miles wide. Recoverable reserves are estimated to be 337 million bbl of oil. This Smackover production contains about 9 mol percent of hydrogen production contains about 9 mol percent of hydrogen sulfide, which presented many technical challenges in view of safety and environmental considerations. The willingness of industry to commit to risk investments allowed a rapid production buildup to 84,000 B/D and the production buildup to 84,000 B/D and the initiation of a 200,000 B/D waterflood at the same time unitization was approved in March 1974.
The paper will highlight the field development history and will include basic reservoir description and drilling information. Emphasis will be placed on facility design and operating considerations for treating sour crude and gas, and sulfur recovery. A brief description of the field waterflood facilities and plans for gas processing will also be included. plans for gas processing will also be included

Introduction
Recent discoveries in the deep, sour Jurassic Trend in northwest Florida and south Alabama have paved the way to extensive drilling and production facility activities. These field development opportunities have presented many technical challenges in view of the safety and environmental considerations. The most significant discovery in this area is the Jay-Little Escambia Creek Field.
Fig. 1 is a map showing the major Jurassic Trend discoveries in the Jay area, which is some 60 miles east of Mobile, Ala., and 35 miles north of Pensacola, Fla. The first discovery of deeper production was the Flomaton Field, immediately production was the Flomaton Field, immediately north of the town of Flomaton, Ala. This field was discovered in 1968, and produces sour gas from the Norphlet sandstone. Exxon discovered the Jay Field in June 1970. The Blackjack Creek Field, southeast of Jay, was discovered by Exxon in Jan. 1972, and 15 wells have now been completed. Production facilities are scheduled for completion in October. The Big Escambia Creek Field, west of the Flomaton Field, was discovered by Mallard Exploration Co. early in 1972. Twenty wells have been completed and production facilities went on stream in July. production facilities went on stream in July.