bluuebunny/crossref_metadata_2025_split huggingface dataset:
Mathematical Modeling and Experimental Investigation of In Situ Oil Shale Retorting
Authors: Nuttall H.E. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Abstract
An experimental investigation of oil shale retorting is presented. The apparatus and operating conditions presented were designed specifically to simulate the in-situ vertical fractured bed retorting process. The dependent retorting variables (oil yield, retorting rate, and bed weight loss) were investigated in terms of six process variables (gas content). Multiple linear regression analysis was used to determine the significance and rank of each variable. In addition, extensive temperature profile measurements were recorded and are profile measurements were recorded and are presented from several of the more recent tests. presented from several of the more recent tests. Temperature profiles are illustrated graphically in two forms; as two-dimensional time/ temperature profiles and as three-dimensional thermo-response surfaces. A mathematical formulation of the experimental retort is presented and modeling results are discussed. presented and modeling results are discussed

Introduction
Retorting of oil shale has been investigated in this country since about 1920, a period of over 50 years. Similar testing and development has been undertaken in many countries around the world. As a result of a recent and renewed interest in energy recovery and resources, oil shale processing is again being intensively considered on a commercial basis. One of the most promising methods proposed for recovering oil from shale is the modified in-situ technique, which utilizes an underground vertical bed retort. This recovery concept is being investigated above ground by the Laramie Energy Research Center, and for the past several years, Occidental Oil Shale Corp. has undertaken an active field-testing program of this technique. In addition, nine petroleum firms have recently formed a consortium (WESCO) to explore this recovery method through a similar underground testing program. During the past 2 years, Mobil Research and Development Corp. has presented several papers describing related work and some modeling that they conducted in the late 1960's. Recently, Lawrence Livermore Laboratory has initiated research in this area.
In spite of the rather extensive activities in this field, no one has published detailed retorting data for this method nor presented a comprehensive analysis of the process variables. Since this processing approach seems to offer numerous advantages over more conventional mining and aboveground processing and because of the renewed interest in oil shale as an energy source, a fundamental understanding of this technique seems justified.
Combustion Front Propagation Through Fractured Oil Shale
Authors: Branch M.C. , Ness R. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Abstract
The recovery of oil from oil shale by in-situ combustion requires fracturing oil shale underground to establish permeability and passing air through the fractured shale to passing air through the fractured shale to support a combustion front. The heated products from the flame front contact the untreated shale where kerogen is decomposed and gas and liquid products are swept to a production well. products are swept to a production well. A major difficulty in this technique is characterization and control of the combustion front. An experimental study of flame front propagation through crushed oil shale in a laboratory reactor is presented. The oil shale is ignited at the top of a vertical 2-in.-ID insulated stainless-steel tube and the reaction maintained by air injection above the ignition plane. The structure of the reaction front and flame front propagation rates are studied as a function of propagation rates are studied as a function of oil-shale particle size and air delivery rates. Temperature profiles throughout the reaction front were measured continuously by coated thermocouple probes and oil yield determined for each run. Combustion front advance was found to reach steady state very rapidly and a linear relationship was found between steady flame front propagation rate and air flux and between particle size and flame propagation rate. The particle size and flame propagation rate. The reaction temperature is about 2100 deg. F and is slightly dependent on particle size and air flux. In contrast to sand-pack studies, the flame front was quite narrow without substantial preheating of downstream shale. preheating of downstream shale

Introduction
The recovery of oil from shale can be accomplished by surface retorting or in-situ combustion. Surface retorting consists of mining the oil shale, crushing, grading, and retorting aboveground. In continuous surface retorting processes such as the Bureau of Mines process, the crushed shale is placed in a retort process, the crushed shale is placed in a retort and falls successively through preheating, retorting, combustion, and cooling zones. Air is introduced above the cooling zone, burning the residual carbon off the shale, producing temperatures of 1600 to 1800 deg. F. This supplies heat for the recycling gases, which decompose the kerogen (800 to 900 deg.). Surface retorting efficiencies are 90 to 100 percent and the process has been demonstrated at a rate of 1,000 process has been demonstrated at a rate of 1,000 tons shale per day. The primary disadvantages of surface retorting are process-water pollution, spent-shale disposal, runoff-water pollution, and mining costs.
Fracturing Through Coiled Tubing - Recent Developments and Case Histories
Authors: Gavin W. G. 
Published: December 2007

Abstract
Fracturing through coiled tubing has progressed considerably since the first job done in 1993. In southeastern Alberta large numbers of wells are being selectively fractured through coiled tubing with mechanical isolation tools. Conventional fracturing techniques may result in small lenses that have the potential to contribute to production being either bypassed, or ineffectively treated. By utilizing coiled tubing and selective fracturing, all contributing zones can be fractured and the full potential of the well realized. Up to eight zones are being treated per well.
This paper will discuss work currently being undertaken with Carbon Dioxide and Nitrogen energized water based fracturing fluids. A summary of work done to date and case histories will be presented. Current and future developments in isolation tools and fracturing fluids will be discussed and the issues regarding geographical technology transfer examined.
The results of pumping fluids containing abrasive particulates at high pump rates through the coiled tubing are discussed with emphasis on abrasion of the pipe, fatigue and pressure limitations. Specific additional safety considerations are outlined and discussed.
Cable Internal, Coiled Tubing Deployed Submersible Pump Installation
Authors: Patterson J. C. , Wiess J. , Brookbank E. B. , Bebak K. T. 
Published: December 2007

Abstract
ARCO’s Kuparuk River Field on Alaska’s North Slope is a high cost operating environment. In the face of declining reservoir pressures, ARCO began using electric submersible pumps to augment production. Installing and pulling these units carries a very high cost due to the need to use large, arctic workover rigs designed for major well completion operations. Confronted by the need to lower intervention costs, ARCO began investigating alternate deployment methods for submersible pumps. Coiled tubing rigs were available and less costly, so the idea of installing a pump using only a CT rig was developed. Working with Centrilift’s cable and pump groups, a method of suspending power cable inside coiled tubing was developed1. This ElectroCoil™ would allow installation or pulling of a pump using only a CT rig and crane. With the cable inside the coiled tubing, no banding is required. The concept was further developed to include a Baker packer and dual flapper assembly downhole to assist in shutting off reservoir pressure mechanically instead of using formation damaging and expensive kill fluid. Note – the packer is required to segregate pump suction and discharge. The dual flappers allow the well to be pulled without continuously adding kill weight fluid. With dual flappers, we would kill to unsting and run under-balanced to pull and run. This paper details the procedures used to install this system and discusses additional issues that must be addressed to help ARCO continue to lower intervention costs.
Pumping with Coiled Tubing - A New Coiled Tubing Application
Authors: Leniek Humberto , Ayestaran Luis , Yang Y. S. 
Published: December 2007

Abstract
Coiled-Tubing (CT) continues to grow as an enabling technology that provides cost economy and time efficiency for the oil and gas industry. It has gained wider acceptance than ever due to efforts of the manufacturers, CT application engineers, and field operators. However, most CT applications (with the exception of velocity strings) are services to existing wells, with very few permanent production applications. A new CT application, using CT as a permanent production tubing string for artificial lift in shallow, low-production wells, has been developed. In this new application as described in this paper, CT is used to reciprocate a subsurface pump plunger. This CT pumping system is illustrated and engineering principles behind the system are presented. Engineering feasibility and reliability of the system, including fatigue problems, are investigated. Sensitivity of pump system fatigue to pump rate, CT and casing dimensions, CT material grade, pump length, vertical well depth, and fluid density is analyzed. Finally, a successful on-going field example is presented. More tests with the pump system are planned for deeper and higher production wells in the near future. It is believed that the new CT pumping system has the potential to significantly impact the economics of artificial lift systems, especially in shallow and low-production wells.
Anaconda: Joint Development Project Leads to Digitally Controlled Composite Coiled Tubing Drilling System
Authors: Marker Roy , Haukvik John , Terry James B. , Paulk Martin D. , Coats E. Alan , Wilson Tom , Estep Jim , Farabee Mark , Berning Scott A. , Song Haoshi 
Published: December 2007

Abstract
In 1997, Statoil and Halliburton Energy Services, Inc. began jointly evaluating technologies that could be used to develop a revolutionary coiled-tubing and well-intervention system. This system, which will be deployed initially in the Norwegian sector of the North Sea, sets a new standard for drilling with conventional drilling rigs or coiled-tubing drilling units. The advanced well-construction system consists of a digitally controlled and automated coiled-tubing drilling system that uses a new advanced composite coiled tubing (ACCT) with embedded wires and a tractor-driven bottomhole assembly (BHA). This system enables the geological steering of complex, extended-reach wellpaths that were not previously achievable.
This paper discusses a joint development project in which the operator and the service company worked together to design a fit-for-purpose system that met Norway’s stringent health, safety, and environment (HSE) requirements. The system’s three major subsystems are discussed: the digitally controlled and automated surface equipment, the 2 ⅞-in. ACCT with embedded wires, and the drilling and intervention BHA. Test results from qualification and pilot wells are also included.
Water Disposal System of the Shell Storage and Loading Spar
Authors: Kapteijn S.A.T. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Abstract
Many floating offshore storage systems are designed to operate on an oil/water displacement principle in which there is direct contact between the oil and the displacement water. One of these is the Shell Storage- and Loading Spar used in offshore oil field development. The high standards of purity of the displacement water required for environmental conservation makes the water disposal system a vital element in the design of the storage system.
The paper discusses the flow sheet and the important items such as low pressure drop hermetically closing check valves, pressure drop hermetically closing check valves, automatic measuring and alarm systems, and an oil-water separator developed specially for use on floating platforms.

Introduction
The spar is a floating platform with a reduced water plane area giving it an attractive motion characteristic when subjected to the environmental forces of wind and waves. She derives her name from her long and thin shape (Fig. 1), which floats upright in the water like a sparbuoy. This floating platform may be utilized for various purposes in an offshore oil field, e.g. to carry a production separator station, water- or gas injection modules, a storage- and tanker loading terminal or other facilities. The maximum water depth in which a Spar may be used is in principle unlimited, the minimum depth is limited to approximately 200 ft since in shallow water it becomes increasingly difficult to locate the main buoyancy deep and still maintain positive stability. The first application of the Spar is as a storage- and tanker loading terminal and this terminal is presently on location in the Brent oil field area in the northern North Sea 100 miles off the coast of the Shetland Islands in 460 feet of water. She is owned and being operated by Shell UK Exploration and Production Ltd., a joint venture of the Royal Dutch/Shell Group and Exxon. (Ref. 1).
To allow operations as a terminal in open sea this Spar is provided with living facilities for the operators, power generators, tanks, loading pumps, oil skimmers, utilities and a single point mooring turntable with loading gear.
Vacuum Deaeration - A New Unit Operation for Waterflood Treating Plants
Authors: Carlberg B.L. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Abstract
Conoco uses vacuum deaeration in treating seawater for injection in California and Dubai. With multistage towers, oxygen concentration in the effluent water is reduced to less than 0.05 mg/L, precluding need for corrosion inhibitor treatment. Improvements in the Dubai towers are noted, as are problems, such as foaming, which have been encountered. Data on throughput and oxygen concentrations are included.
Vacuum deaeration of water is a method known and used for many years. That use, however, has been limited by cost and available technology. Several writers ascribe a practical lower limit of 0.3 mg/L to 0.5 mg/L practical lower limit of 0.3 mg/L to 0.5 mg/L oxygen in the effluent water when using vacuum deaeration. Gas stripping and chemical scavenging have been considered more practical answers when truly low dissolved oxygen concentrations are required for waterflood operations. These methods have proven satisfactory in numerous applications proven satisfactory in numerous applications where availability of gas for stripping or the economics of chemical scavenging did not preclude their use. The limited solubility of preclude their use. The limited solubility of calcium sulfite has also interfered with sulfite ion scavengers in some systems.
In those systems which require deaeration, the need is based on those reactions involving oxygen; e.g., corrosion, oxidation of ferrous iron in solution, growth of aerobic bacteria, etc. Of these, corrosion control is probably the most important. Corrosion control by removal of dissolved oxygen is particularly important in waterflood operations. For large waterflood systems, the economics of a capital expense for vacuum deaeration are often more favorable than the continuing operating expense of chemical scavenging.
Recent cost estimates were $450,000 for a vacuum tower, vacuum pump, and booster pump to deaerate 100,000 b/d from 6.5 mg/L oxygen to less than 0.02 mg/L. Chemical scavenging with catalyzed sodium sulfite (32 cents/lb) would run $212,500 per year for chemicals alone.
Improvements in vacuum stripping technology have made this a practical and economically acceptable unit operation for use in waterflood treating systems.
The Application of Sensitivity Analysis to Reservoir Simulation
Authors: Bishop Kenneth A. , Brett Vernon S. , Green Don W. , McElhiney John E. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Abstract
The attainment of a pressure history match between field data and the response from a compute model has long been a tedious task. This task has generally been performed by trial and error. The procedure for history matching described in this paper is a semi-automatic technique based on certain useful concepts of sensitivity analysis from formal optimization theory.
The procedure is based on a determination of the sensitivity of an objective function to the value of reservoir parameters used in the simulator. Two objective functions were used: the square of the difference between the calculated and measured pressures, and the time integral of this function. The sensitivity determination employs a truncated Taylor's series expansion of the objective function about a point specified by the current estimate of the reservoir parameters. The partial derivative terms of parameters. The partial derivative terms of the expansion are calculated from the finite difference analog of the partial differential equation used in the simulator, differentiated with respect to the current estimate of the reservoir parameters.
Implementation of this method requires an initial running of the reservoir simulator, subsequent automatic modification of the permeability map through sensitivity analysis of the permeability map through sensitivity analysis of the objective function, with iteration until a predetermined error in pressure match results. predetermined error in pressure match results. The technique is currently implemented in a semi-automatic form for convenience in continued development. However, the technique is designed to be fully automatic.
The technique has been applied to the twenty-seven year history match of the Cotton Valley Gray Sand Reservoir. Pressure data on the seven wells in this field had originally been history matched using manual trial and error procedures. Data were limited in that only procedures. Data were limited in that only twenty-eight measured field pressures were available for matching purposes over the twenty-seven year history. This study produced a significant improvement in the history match. The magnitude of the objective function was reduced by a factor of approximately fifteen from that obtained in the original history match. The computational efficiency of the technique is good in that the sensitivity analysis software package required only 1.5 times as much execution time as the single-phase, gas-flow simulator.
On the Use of Accident Scenarios
Authors: Njaa Ove , Sandve Kjell 
Published: December 2007

Abstract
Accident scenarios are extensively used as premises for designing safety systems. Normally, the accident scenarios emerge systematically in the planning process by applying different risk analysis tools. However, describing accident scenarios is not straightforward, and neither is the interpretation and use of the accident descriptions.
This paper discusses important principles within description and use of accident scenarios. The base points for the discussion are experiences gained from the Norwegian petroleum industry. Many risk analysts and designers interpret the regulations in the sense that defined scenarios should be realistic, concrete and detailed. If by realistic we mean probable, this is self-contradictory since the occurrence of a detailed described scenario will be only one amongst an infinite number of other resembling scenarios. In using detailed accident scenarios the design of the safety measures could be "biased" towards less beneficial purposes (such as covering specific equipment only, limiting the knowledge base of the rescue team), and thus creating non cost efficient safety arrangements.
This paper presents an approach, which focuses on classes of situations of hazard and accident, where each class contains sufficient information to describe the variety of possible scenarios. Guidance is presented to ensure an effective link between the planning and operational phases of an offshore installation.
A Block Successive Over-Relaxation Method for Coupled Equations
Authors: Woo P.T. , Emanuel A.S. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Abstract
The simultaneous solution method in reservoir simulation gives rise to a system of coupled linear equations. This paper shows that the system can be efficiently solved by a block successive over-relaxation method even for large 3-D, 3-phase models. Examples are given which include a large 3-D problem and a radial coning problem. problem and a radial coning problem

Introduction
In reservoir simulation problems involving flow in the vertical direction, it is desirable to formulate a semiimplicit or fully implicit finite difference model and simultaneously solve for as many unknowns as practical. This approach yields a very stable solution, and is most useful when the reservoir is highly heterogeneous and when the throughput across the grid blocks is high. Simultaneous solution also allows a convenient implementation of strongly coupled production and reservoir flow terms, which further contribute to stability. However, for easy reservoir simulation problems, the implicit pressure explicit saturation method is often more economical.
The technique of solving for the unknowns simultaneously is known as the simultaneous solution method. There are, however, disadvantages in solving for several unknowns by this solution method. The number of linear equations to be solved is equal to the number of mesh points multiplied by the number of unknowns. For example, if a model has 1500 mesh points and 3 unknowns (oil pressure, points and 3 unknowns (oil pressure, gas saturation, and water saturation), there will be 4500 linear equations. A large system of this size precludes the use of direct methods because of excessive storage requirement, unless a special algorithm such as the storage management algorithm is available. For 3-D problems, direct methods also become rapidly uneconomical, as the number of mesh points increases. For example, the computational work for a cubic mesh with Nc3 mesh points is proportional to Nc6. Indeed, it is usually proportional to Nc6. Indeed, it is usually uneconomical to apply direct methods to simultaneous solution models, if the mesh exceeds a few hundred points.
Iterative methods require less storage than direct methods and also less computational work if they converge rapidly.