bluuebunny/crossref_metadata_2025 huggingface dataset:
Selection and Sensitivity Requirements for Blowout Control Detection Instruments
Authors: Dittmer Albert K. , Fisher F.J.
Published: December 2007

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

In blowout control and prevention planning, the prime detection instrument needs to planning, the prime detection instrument needs to be designated and its minimum sensitivity specified. Sensitivity requirements will depend on the drilling environment, i.e., casing depth, reservoir properties, mud underbalance possibilities, rig reaction time, circulating rate, etc. Through use of a computer program (KIKSIM) that quantifies the transient characteristics of hydrocarbon gas in the annulus of a drilling well, comparisons are made of detection instrument alternatives.

Introduction

In an earlier paper, the computer program KIKSIM was used to illustrate how program KIKSIM was used to illustrate how changes in mud circulation rate can aid in well control. The KIKSIM program which develops information concerning the transient characteristics of hydrocarbon gases in the annulus of a kicking well also has considerable value in planning. Among the planning decisions that can be improved with KIKSIM are selection and establishing specifications for mud flow sensors and pit level recorders. The concept of warning time is introduced and stressed.

This report deals with the detection of gas in the annulus in drilling ahead situations. It does not deal with detection of formation fluids during trips which is a distinctively different problem.

DETECTION STAGES

In drilling ahead situations formation gas in the borehole can be detected and measured at three stages, which we will refer to as the entry, mud transport and "expansion burst" stages.

Obviously it is to our advantage to try to detect gas as soon as possible, e.g., as it enters the borehole. Since we may at times be dealing with relatively small volumes at bottomhole conditions, this may not always be possible.

The second stage during which we may detect gas is during mud transport of the gas up the hole. As mud transports gas up the hole it slowly expands and this expansion can be used to detect gas. The mud transport stage is arbitrarily defined as that period during which the rate of gas ascent is largely (2/3) determined by the mud circulation rate.
An Acoustically Controlled Down-Hole Safety Valve (SCSSSV)
Authors: Pedigo John , Parker William H.
Published: December 2007

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

A surface-controlled subsurface safety valve (SCSSSV) system without external wires or hydraulic lines needed for the valve's operation is now available to the petroleum industry. Any of the current down-hole safety valves, such as Hydril, Otis, Camco or Baker, can be fitted to the valve operator. This is a totally fail-safe valve system, which can be overridden manually at the operator's choice to accomplish a number of different modes. The valve's operator is acoustically controlled by the operator's predetermined settings at the surface. The predetermined settings at the surface. The receiver, translator, and valve actuator are packaged and placed in a special mandrel that is packaged and placed in a special mandrel that is run as a part of the tubing string. The hydraulic valve operator is mounted on a length of production tubing between the mandrel and valve. The full-flow valve is at the bottom of the down-hole string. Any length of production tubing may be run below the valve. Hookwall hangers can be run in as may be needed.

The down-hole electronics is a module set in a side-pocket mandrel with wireline equipment. Setting depth can be below "paraffin" zones. The system does not reduce production flow and will permit other wireline operators to pass to other equipment below the setting depth.

REVIEW OF THE STATE OF THE ART

With the movement of the oil industry into the more or less hostile environment of offshore operations, it was apparent immediately to the oil operators that an automatic "fail-safe" valve was needed for the producing oil or gas "flow string".

A valve was produced that would respond to changes in flow rate either above or below levels preset into the valve. The first valve to be so adapted and so employed was the differential pressure, spring-loaded valve. Abnormal increases in the flow rate across the valve caused it to close. This valve was very simple in construction, could be set in the production string and removed by means of a production string and removed by means of a wireline. The differential pressure valve and its "sister" valve, the ambient pressure valve, which closed automatically if the rate of flow or resultant pressure across the valve dropped below a preset valve. These safety valves became known to the oil industry as "storm chokes", but actually the term "storm choke" is a registered patent term; therefore, such valves should only be referred to as down-hole production string safety valves. production string safety valves.
Continuing Education Programs Past, Present and Future
Authors: Chapman P.F.
Published: December 2007

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

Continuing Education for petroleum engineers and related professionals has increased significantly in scope and content during recent years. This activity is a response to the need for maintaining technical competence, and supplying new information, to practicing engineers during a period of rapid technological change. The Society of Petroleum Engineers established a standing committee in 1965 to develop programs for members of SPE. This program is discussed and current thinking about present and future programs explained. In addition, specialty programs presented by Universities, programs presented by Universities, consultants on a commercial basis, and by companies on an internal basis are reviewed.

Introduction

Continuing Education is a term that means different things to different people, and is described by many different terms. Continuing Education, Continuing Engineering Studies, Life-time Learning, Post-degree, Non-traditional, Adult Education Post-degree, Non-traditional, Adult Education and others are common terms, and used sometimes interchangeably. It is thought of commonly as any educational activity that occurs after formal full-time education ends.

In this paper, the term Continuing Education refers mostly to non-credit technical programs in the form of short courses and packaged programs for technical professionals in the oil and gas producing industry. And these professionals producing industry. And these professionals include the majority of the 23,000 members of the Society of Petroleum Engineers. These professionals have a variety of degrees, including non-engineering degrees, but in some cases can have extensive experience instead.

The scope of continuing education is large and growing. Because of diversity and a lack of structure, it is difficult to characterize, define, or describe. Continuing education is mobile.
An Iterative Solution for the Gas Pipeline Network Problem
Authors: Crafton James W. , Dyal Victor H.
Published: December 2007

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

To make steady-state gas pipeline network analysis a useful design and planning tool, it is essential that the planning tool, it is essential that the numerical solution procedure meet two important criteria:Assurance of rapid solution convergence, and uniqueness, thus economical solution costs andFlexibility in handling a wide variety of piping, loop, and compressor configurations encountered in gathering and transmission networks.

If these criteria are satisfied, a simulator useful for supply and demand optimization, allocation or proration evaluation and compressor optimization is achievable.

The steady-state methods presented in the existing literature fall in two classes, either direct-explicit replacement schemes or Newton-Raphson iterative methods. The scheme described in this paper is an iterative procedure which employs the connected nature of a network to achieve efficient computer storage and rapid solution for the pressures and volumes in the system. The pressures and volumes in the system. The method for solving complex looped pipe line systems and unconstrained or "loaded horsepower" compressors is developed. The results of this technique are exhibited by the solution of a sample gathering system, with interconnected loops containing large compressors.

Introduction

As the need for increasingly efficient utilization of natural gas occurs, tools capable of handling the resulting problems are needed. One important area problems are needed. One important area lies in the evaluation of system operations and design for a natural gas pipe line network. Regardless of the task, a rapidly convergent solution scheme for solving the systems of nonlinear equations describing the network is required. Two solution procedures appear to be in general use for the steady-state problem.
Natural Gas Production from Geothermal Geopressured Aquifers
Authors: Isokrari Ombo F.
Published: December 2007

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

The energy crisis has resulted in an increased interest in the use of alternative energy sources for electric power generation. Geothermal energy is commonly mentioned as a supplement to existing and projected major sources of fuel. A unique form of geothermal energy exists in geopressured aquifers underlying the United States Gulf Coast. Water from such geopressured aquifers often contains natural gas. This paper deals with the production of natural gas from such reservoirs. production of natural gas from such reservoirs. We have classified geothermal geopressured reservoirs into three types based upon the natural gas content. In Type 1, the reservoir water is undersaturated with natural gas. However, it could still contain more than 40 standard cubic feet of natural gas per reservoir barrel of water. In Type 2, the reservoir water is fully saturated with natural gas and the reservoir may contain a small gas cap. Type 3 is a geopressured gas reservoir. The water is nearly immobile in the reservoir but the adjacent and underlying shales contain water with gas in solution, that may move into the reservoir. Producers have been most interested in Type 3.

This paper presents computer studies of the production of multiphase fluids (natural gas, gas in solution and water) from geothermal geopressured reservoirs.

The two phase, two dimensional simulator was developed for simulating reservoir production behavior of both nonisothermal and production behavior of both nonisothermal and isothermal deformable reservoirs, and can be used for areal or cross-sectional studies.

Computer runs were made to generate a variety of data. For Type 1 and Type 2 reservoirs, reservoir pressure variations with natural gas and water production were generated. It was found that substantial amounts of natural gas can be produced over a long period of time. Where the water is hot enough the accompanying water may be used to generate electrical energy or for space heating or desalinated for agricultural purposes.

The model was used to make areal studies of a bounded hypothetical geopressured gas reservoir, with no shale water influx using different compaction coefficients. It was found that BHP/Z versus cumulative gas production curve changed significantly with production curve changed significantly with increase in compaction coefficients.

The model was also used to make cross-sectional studies to assess the effect of shale water influx from adjacent and underlying shales.

Finally the model was used for simulating the reported production history of Anderson 'L', a geopressured gas reservoir in south Texas. Good agreement was obtained between the observed BHP versus cumulative production as well as BHP/Z versus cumulative production.
Production Logging through the Annulus of Rod-Pumped Wells to Obtain Flow Profiles
Authors: Hammack Gregory W. , Myers Brent D. , Barcenas Gilberto H.
Published: December 2007

INTRODUCTION

Historically, downhole production surveys have been run through tubing, after pump and rods have been pulled and the well swabbed, or through the tubing-casing annulus after replacing existing tubing with a small diameter string. In both cases, normal well pumping conditions have been altered to the extent that many production surveys probably have not been representative. Running a production survey while a well is pumping under stabilized conditions allows observation of normal pumping fluid inflow performance. To this extent, a small diameter (7/8 in. oD) combination production logging tool is being used successfully to determine the following:Temperature ProfileInflow Velocity ProfileFluid Density

The configuration of the tool allows it to be used in small tubing-casing annulus sizes such as 5 1/2 in. OD casing and 2 7/8 in. EUE tubing. This paper discusses the tool's specifications and configuration, applications and results which are illustrated by field examples.

TOOL DESCRIPTION

The combination production logging tool has four basic modules that can be run in tandem: a) casing collar locator; b) radioactive tracer section; c) temperature probe; and d) fluid density section (see Figure 1).

The outside diameter of the tool is 7/8 in with a total length of approximately 20 feet. Construction is very clear with no protrusions in the tool case that will cause snagging or hanging up on tubing collars.
Application and Economics of Artificial Lift in the Judy Creek Field, Alberta
Authors: Steele Robert D.
Published: December 2007

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

Well productivities in the Judy Creek Field in Alberta, Canada range from very good (PI = 290 BPD/psi) to poor (PI less than 1). To obtain high lift efficiency, and low-cost well performance, Imperial Oil Ltd. used engineering and economics to select three artificial lift methods for Judy Creek. High capacity wells near the high pressure gas supply are on gas lift. High capacity pressure gas supply are on gas lift. High capacity wells in more isolated areas of the field have been equipped with submersible pumps. Lower productivity wells throughout the field are productivity wells throughout the field are equipped with sucker-rod pumps.

Well analysis is the important first step in the selection of a lift method. The analysis techniques used in Judy Creek are discussed and then applied to the design and evaluation of the three types of lift. Background to the economic comparison of gas lift to submersible pumps is included. pumps is included

Introduction

The Judy Creek reservoirs are located 130 miles northwest of Edmonton, Alberta, Canada (Fig. 1). The field was discovered in 1959. The two reservoirs, the larger "A" Pool and the "B" Pool, will be simply referenced as Judy Creek. Pool, will be simply referenced as Judy Creek. The reservoirs are a stratified limestone reef of the Upper Devonian age. The two pools have 629 MMSTB of recoverable oil.

Most of the discussion will concern two areas in the larger "A" Pool. The high productivity area (Fig. 2) is a high-porosity, fore-reef rubble. Wells typically have productivity indices (PIs) greater than 20 BPD/psi. The pattern waterflood area is a stratified lagoon with PIs normally an order of magnitude lower than the high-productivity area.

The field was drilled to a well spacing of 160 acres. Drilling in the early 1970s reduced the well spacing in the high-productivity area to 80 acres. At the end of 1975 the field had 30 submersible pumps, 25 gas lift wells, and 24 sucker rod pumps.

A peripheral, downdip waterflood was installed on the west side of both pools in 1963 and 1964. Beginning in 1969 productivity was supplemented, as market demand increased, by the installation of submersible pumps.

The pattern waterflood was installed in 1974 following extensive geological and reservoir work. Well productivity in the pattern waterflood area increased from 20,000 to 35,000 BOPD in less than one year.
Comprehensive Analysis Of Drillstem Test Data With The Aid Of Type Curves
Authors: Sinha B.K. , Sigmon J.E. , Montgomery J.M.
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 considered for publication in one of the two SPE magazines.

A substantial percentage of drillstem tests cannot be analyzed by conventional methods due to insufficient data. Numerous tests have been analyzed by several published type curves.

In this paper, many examples are included where the application of the appropriate type curve aided in providing correct analysis of data which providing correct analysis of data which otherwise may have been misinterpreted.

Introduction

The importance of the decision based upon drillstem test results regarding the-probability of commercial production from a well cannot be production from a well cannot be over-emphasized. This vital decision requires that available data be analyzed thoroughly to provide a high degree of confidence in the analysis. Due to various reasons, it is not often possible to assure availability of sufficient data to complete a conventional Horner analysis with confidence. Under these situations, the recent type curve matching techniques are being used for analyzing incomplete drillstem test data.

Since 1970 several type curves have been published for analyzing early time data from pressure transient tests. The majority of the literature on type curves application is oriented toward long duration tests (which are usually conducted later in the producing life of a well) and not toward drillstem tests.

There are several problems which are common to drillstem tests:occurence of critical flowpresence of superchargeusually short testing durationquestionable production datamechanical problemsdrastic variations in bottom-hole pressurespresence of more than one producing zonelack of reservoir and fluid properties data at the time of the test
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.

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.

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

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

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

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

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.

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.

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.

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

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.

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.
Prospects For U.S. Energy Self-Sufficiency
Authors: Nelson T.W.
Published: December 2007

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

The oil embargo and production cutbacks of 1973 and the ensuing OPEC price increases have brought into sharp focus the increasingly heavy reliance of the United States on foreign oil imports. This reliance, and the fact that it is increasing steadily, is unsound both for our economy and our national security.

Despite recent efforts to promote energy conservation and efficiency, demand for energy is expected to continue to rise with economic growth, the increase in population, and improvement in population, and improvement in environmental conditions and living standards. Therefore, to avoid even greater reliance on imports we must increase domestic energy production. Since U.S. oil and gas production will supply a smaller and smaller percentage of U.S. oil and overall energy demand, we must look to coal and nuclear energy, and later to solar and synthetic energy sources.

We must develop a sound national energy policy to eliminate waste in energy use policy to eliminate waste in energy use and to encourage greater exploration and production of gas and oil, the use of coal and nuclear energy, and the development of solar and synthetic energy. At the same time, to encourage exploration in the U.S. as well as a smooth flow of the imports that we need, national policy should foster a strong oil and gas industry, working free of the threat of discriminatory legislation, including divestiture legislation and price controls which create negative incentives.

Introduction

The United States is increasingly consuming more energy than is being produced from domestic resources. Current produced from domestic resources. Current patterns of production and consumption patterns of production and consumption can only widen this gap and pose increasing dangers to our nation's economy and security. Memories are short, and the public and many of their elected representatives seem to have forgotten the 1973 embargo, the long lines at service stations, the quadrupling of world oil prices and the resultant impact on our and the world's economy. Those events were a clear danger flag on the road we are following.

The reasons for the growing energy gap have been well documented.
Capital Resources For Energy
Authors: Krupp Herbert W.
Published: December 2007

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

Capital Shortage

You all remember the recession year of 1974. You remember the inflation that accompanied the recession and boosted your food bills in the supermarket and your expenses for the car and home more than it raised your salary. And you remember the sky-high interest rates that shook the utility industry, floored the housing industry and led to the cancellation and delay of many investment projects. And you remember reading about the hike in the nation's unemployment rate. Perhaps you yourself were unemployed; more likely you knew of friends and relatives in other industries who were laid off in the worst recession since the great depression of the 1930's. In short, you all remember 1974 as a year in which the economy did poorly and in which the standard of living for the average American slumped.

If you're able to visualize a string of years just like 1974, then you can imagine what a shortage of capital would do to this country. Not that the recession of 1974–1975 was primarily caused by a shortage of capital; it was primarily caused by a shortage of capital; it was not? But the economic symptoms of this last recession mimic those that would result from a capital shortage.

During a capital shortage not enough money is around to adequately finance industrial expansion. Interest rates skyrocket and necessary investment projects are cancelled or delayed. Industrial capacity consequently becomes inadequate, and this inadequacy leads to shortages and soaring prices. Unemployment rises, mainly because economic growth is too slow to completely absorb the entry of millions of new workers each year. Thus, a shortage of capital retards economic growth, raises inflation, boosts unemployment and in general lowers the standard of living.

Objective and Format

Some businessmen fear that this country will experience a capital shortage in the 1970'S and 1980's. They feel that the enormous and growing capital requirements of the oil and gas, coal and electric utility industries will make this outcome inevitable. Are their fears warranted?
Monitoring and Assessment of Produced Water Originating Contaminants in the Ekofisk Region of the North Sea
Authors: Durell G. , Neff J. , Melbye A. , Johnsen S. , Garpestad E. , Gruner H.
Published: December 2007

The North Sea Bioaccumulation Program was begun in 1995 to monitor and model the fate and effects of produced water discharges to the Norwegian sector of the North Sea. This program includes determining the levels and significance of key contaminants that may concentrate through the food web. In 1999 the potential impacts in the Ekofisk Region were investigated.

Sampling and chemical analysis techniques were selected to obtain optimum data for different interpretation objectives. The field methods included sampling (1) in situ, large volume waters, (2) semipermeable membrane devices, (3) caged mussels, and (4) plankton. Samples were collected near and distant to produced water discharges and state-of-the-art trace level analytical methods were applied to determine a suite of organic contaminants, including total hydrocarbons, and more than 60 parent and alkylated polycyclic aromatic hydrocarbons (PAH), phenols, decalins, and benzothiophenes. Toxic or produced water characteristic metals were also measured.

Most target analytes were detected at most stations, contrary to earlier studies that used more conventional and less sensitive and specific sampling and measurement techniques. The concentrations of produced water derived contaminants decreased rapidly with increased distance from the platforms, to near-background levels 5 km from the discharge. Produced water-specific contaminant composition was identified, and compositional changes were observed with distance and time from discharge. An ecological risk assessment was performed using multiple data assessment techniques, and consistently showed that the produced water poses a very low risk to the marine ecology.

This work shows the importance of customizing the sampling procedures for specific needs, carefully selecting source-and effects-specific analytes for measurement, and using matrix-specific ultra-sensitive analytical methods. Data generated in this manner can confidently be used for a variety of data analysis and interpretation purposes (e.g., contaminant transport and dissolution, contaminant bioaccumulation, environmental risk assessment, degradation and persistence of contaminants, source identification).