bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Development of Heavy Oil Fields in the United Kingdom Continental Shelf: Past, Present and Future
Authors: Jayasekera A. J. , Goodyear S. G. 
Published: December 2007

Abstract
Historically, most UKCS production has been of light oil, 30° API and above. However, since 1993, a number of heavy oil fields have been brought on production. This paper reviews the history of UKCS heavy oil, the challenges overcome to bring these fields to development, and the future outlook.
The occurrence and distribution of the UKCS heavy oil in place is discussed. A specific correlation to estimate reservoir viscosity from API gravity is presented. Productivity of heavy oil reservoirs is compared with light oil developments, different categories of heavy oil reservoirs are identified, and the use of horizontal or multilateral well technology to achieve acceptable production rates is discussed. The implication of well productivity testing (e.g. extended well testing) of appraisal wells is discussed.
The development challenges that have been overcome in current developments (Harding, Gryphon, Alba, Captain) are reviewed, in particular focusing on well productivity, pressure support, recovery efficiency (management of gas and water coning, areal sweep), and oil water separation. The paper will also review the cost and risk management strategies that need to be adopted to enable the economic exploitation of these heavy oil resources in a demanding environment such as the UKCS.
Finally, the potential for future heavy oil developments is discussed. The scope for IOR technology to increase reserves in heavy oil fields on production by waterflood, or to improve the economics of currently sub-economic fields, is reviewed, focusing on advanced well technology, downhole separation, thermal techniques and conformance control methods.
An Analytical Model for Light Oil Recovery by Steam Distillation
Authors: Mamora D. D. , Sutadiwiria G. 
Published: December 2007

Abstract
Distillation of oil at the steam-oil interface has long been recognized as an important mechanism for oil recovery during steam flooding, particularly in light-oil reservoirs. However, the heat and mass transfer mechanisms at the interface are not well understood.
This paper describes an experimental study conducted to shed more light on these mechanisms. The apparatus used consisted of a vertical sand pack containing a three-component liquid mixture, namely, cyclohexane, n-octane, and water. Cyclohexane has a boiling point lower than that of the steam introduced at the top of the sand pack, so that this hydrocarbon component will be predominantly distilled off. Data obtained included produced hydrocarbon and water volumes, sand-pack temperature profiles, and steam front velocity as measured with the aid of the CT scanner.
Analysis of the data indicates that, contrary to the usual assumption, steam distillation does not occur at equilibrium conditions. Moreover, oil recovery by steam distillation is largely dependent on the steam saturation point and injection rate. Based on these findings, an analytical steam displacement model has been developed. Temperature profile, steam front velocity, and hydrocarbon production based on the model agree satisfactorily with the experimental results.
Low Surface Tension Hydrochloric - Hydrofluoric Acid Mixtures in Low Porosity, Low Permeability Sandstones
Authors: Holcomb David L. 
Published: December 2007

Abstract
Hydrochloric - Hydrofluoric acid mixtures have long been topics of investigation with respect to the optimum requirements of concentrations necessary for effectiveness in the stimulation of low Porosity, low permeability sandstone reservoirs. Low permeability sandstone reservoirs. Low concentrations of hydrochloric and hydrofluoric acid in combination with one another (i.e., 3 per cent HCl - 0.6 per cent HF) provide a highly efficient system whereby less damaging reactions occur in the sandstone matrix or fracture system, thus reducing the damage caused by migrating and sloughing fines produced when conventional HCl-HF systems (i.e., produced when conventional HCl-HF systems (i.e., 12 per cent HCl - 3 per cent HF) are used. In addition, the ability of the low concentration HCl-HF system to overcome the capillary imbibition effects, which tend to reduce the efficiency of load fluid recovery following stimulation of a low porosity, low permeability sandstone reservoir, is permeability sandstone reservoir, is enhanced by using ultra low surface tension reduction via the application of a low adsorption, cationic, fluorocarbon surfactant. Coreflow studies illustrate the above nontioned principles.

Introduction
A significant mechanism for stimulation of low permeability, low porosity, well consolidated sandstone reservoirs is the efficiency and effectiveness of utilizing low concentrations of both HCl and HF acid coupled with fluorosurfactants which can be gel ed with low residue polymers for fracture - acidization with proppant incorporation.
Two-thirds of the world's oil is found in sandstone formations. Problems with regard to treatment technique and type range from saturation and clay swelling to regarding clay particle migration, fluid-formation compatibility, shale sloughing, and fluid recovery.
Reactions and reaction products have been extensively researched, and it is not within the scope of this paper to dwell upon or challenge them.
Perforating at Base of or Below Sand and Fracturing Improves Well Performance
Authors: Holm Anchor E. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.
This paper was prepared for the Oklahoma City SPE Regional Meeting, to be held in Oklahoma City, Okla., March 24–25, 1975. 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 presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. 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
During 1972, severe Dakota formation fracturing treatments were evaluated using temperature surveys, primarily. Created fractures were found to propagate upward into non-pay. Thus, below the pay perforations were attempted, and successful treatment the well resulted with better productivity A Workover had similar results.

Introduction
During 1972, El Paso Natural Gas Company completed eighteen gas drilled Dakota wells, running fracture evaluation logs. Five wells had perforations placed in the bottom or below the pay zones. This was done to evaluate the upward propagation of the induced fractures and improve the fracturing treatment.
The San Juan Basin (Fig. 1) is located in the northwest portion of New Mexico on the Eastern edge of the Colorado Plateau. Most production In the Basin has a Northwestern production In the Basin has a Northwestern trend. The Dakota formation is a tight (0.01 md) gas producing sand-shale sequence, deposited primarily as a moving shoreline trending primarily as a moving shoreline trending Northwest - Southeast with some deltaic deposition in local areas. Fig. 2 is a typical Gamma Ray/Induction Resistivity log of the Graneros - Dakota zone averaging about 250 ft. thick at a depth of 6000 to 8000 ft.
Drilled on a 320 acre spacing, each well had 4 1/2 in. casing set thru the Dakota formation in a 6 1/4 in. gas drilled hole or 7 7/8 in. mud drilled hole. Each pay zone was perforated with 16 to 20 shots per zone and the perforated with 16 to 20 shots per zone and the well hydraulically fractured with 40,000 to 90,000 lbs. of 20/40 sand at about 1 lb./gal. of fresh water treated with 3% calcium chloride and 2 lbs. of friction reducer per 1000 gal. Rubber covered nylon balls were dropped during the treatment in order to treat all zones.
All of the sixteen evaluated wells shown on Fig. 3 were gas drilled.
Effect of Temperature on Heavy Oil/Water Relative Permeabilities
Authors: Akin Serhat , Castanier Louis M. , Brigham William E. 
Published: December 2007

Abstract
In the first part of this study, the accuracy of the JBN technique for the determination of heavy oil/water relative permeabilities, and the effect of temperature on relative permeabilities is examined by giving numerical as well as experimental examples. Using the JBN technique leads to a false temperature dependence of relative permeability curves. In the second part, we present unsteady state relative permeability experiments with initial brine saturation at differing temperatures conducted using South Belridge sand and heavy oil. A new three step experimental technique and an analysis procedure were developed to test the effect of temperature on relative permeabilities. In this technique, an ambient temperature unsteady-state relative permeability run is conducted in the first stage, and following that the temperature is increased twice (i.e. 122°F and 150°F). Two phase saturation profiles along the sand pack are measured using a CT scanner. A commercial black oil simulator, coupled with a global optimization code is then used to estimate two phase relative permeabilities. Experimental saturation profiles, differential pressure and recovery data collected from both the ambient and higher temperature data are used in the numerical model. It has been observed that a single set of relative permeability curves can represent both the ambient and high temperature parts of the experiment. This suggests that relative permeability is not a function of temperature at least for the system tested.
Pipe and Supplies Shortages
Authors: Moore Wendell S. 
Published: December 2007

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

Introduction
The Arab embargo of oil shipments to the United States in 1973 as a result of the United States' support of Israel in the Arab-Israeli Yom Kippur war, and the subsequent formation of OPEC (Organization of Petroleum Exporting Countries), who instituted a worldwide increase in oil prices, triggered a reaction in the Unite States that is still far from settled.
The year 1974 was confusing at best—high interest rates, tight money supply, materials shortages and all-out production, rapidly accelerating inflation after price controls, and lifting of the oil embargo—all occurring more or less simultaneously. Then some cooling of economic growth became apparent; real GNP declined for four successive quarters.
Consumers, who lost buying power to inflated prices, decreased their purchases. Appliances, textiles, furniture, and housing construction moved into a deep recession. U.S. automotive production for the model year was off 30 percent, and sales curves show no real recovery yet in 1975 despite high-powered promotional campaigns. promotional campaigns. In the early months of 1974, the capital goods market seemed immune to growing recessionary signs. There existed a pent-up demand for increased plant capacity in many sectors after price controls expired. Environmental price controls expired. Environmental considerations had forced the shutdown of many facilities that could not operate profitably, and unprecedented activity began to increase electrical generating capacity and fossil fuels supply. Accelerating escalation rates and lengthening materials lead times continued into September.
Then signs of some decline in the rate of those increases began to appear. Nevertheless, in continuing short supply were: steel, forgings, castings, ferroalloys, pig iron, motors, coal, coke, bearings, fasteners, pipe, and pipe fittings. All of these items were needed for energy projects.

HISTORY
To counteract the implications of U.S. dependence on imported oil, The Federal Energy Administration in its "Project Independence Blueprint" started an all-out domestic energy search.
In the U.S., rising oil and gas prices touched off the biggest oilfield rush since the 1950's. It became apparent quickly that the industry was geared to drill more wells than there were pumps, piping, and associated equipment available to bring products to the surface.
Through-Tubing Inflatables: Isolation and Guidelines for Coiled-Tubing Applications
Authors: Mackenzie Gordon R. J. , Plante Mark E. 
Published: December 2007

Abstract
When planning a well intervention, there are many factors that need to be taken into consideration prior to the execution of the operation. The operator has many tasks to perform before the actual job and the last thing he or she wants to worry about is "Have I chosen the right isolation device and has this equipment been custom-fitted for my application?". Last, "does the performing service company have the ability to engineer the job correctly?" This paper will attempt to cover set up for thru-tubing inflatable devices run on coiled tubing.
This paper will examine guidelines with regards to the planning and execution of well interventions using thru-tubing inflatable devices such as bridge plugs (both permanent and temporary), packers, cement retainers and straddle systems. Discussion will involve the information required to be collated prior to equipment selection and job engineering and how said information relates to the equipment's performance and overall success or failure of the objectives of the intervention. Also discussed will be the most common failure methods of such devices and information with regards to preventative methods and practices to minimize such failures, taking into consideration information gathering, technological developments and correct tool usage. The paper will go on to highlight the impact of hydraulic considerations with regards to applied pressure differentials and drawdown or inflow testing, as it effects inflatable isolations, before, during and after the installation.
Scale Removal From the Recesses of Side-Pocket Mandrels
Authors: Tailby R. J. , Amor C. Ben , Mc Donough A. 
Published: December 2007

Abstract
Hard scales like barium and strontium sulfate have proven to be extremely difficult to remove from well completion by existing mechanical or chemical means.
A North Sea operator recently experienced scale deposits, which were identified to be barium sulfates, in the side-pocket mandrels of a gas-lift completion. Valves could not be retrieved and so a failure would have resulted in a workover. Solvent soaking together with agitation with a wireline brush, which had been successful in the accessible area of the TRSV, was ineffective in removing enough scale to allow kickover tools to function.
A new through tubing technique to selectively remove hard and inert scales has been in development for several years. The method is based on abrasive jetting technology using a new coiled tubing tool and consists of pumping specially manufactured particles through a rotating nozzle. These particles are softer than the tubular material yet hard enough to break the scale.
This paper describes the first use of the technology in the North Sea. Used in conjunction with coiled tubing, the technique was successful in removing enough of the scale for the kickover tool to engage, latch and pull the valve. Photos of the cleaned valve, post job Gamma Ray logs and solids analyses show clearly that the majority of the scale had been removed.
Development of Welding Procedure Specification for Girth Welds in Coiled Tubing
Authors: Luft H. B. 
Published: December 2007

Abstract
As oil and gas well servicing operations involve increasingly larger coiled tubing (CT) sizes, the ability for extending their useful or working life becomes of increasingly greater economic importance. Not only do larger tubing sizes exhibit inherently lower fatigue lives, but also their replacement cost is considerably greater. Efforts are underway elsewhere for developing CT repair strategies for recovering some of the CT fatigue life that has been reduced due to dents and other damage or degradation of the tubing. Such local repair methods, however, have both material and practical limitations. The capability to remove finite section(s) of tubing that has been damaged or expended a greater percentage of its working life, would be of significant benefit rather than force the retirement of the complete tubing string. Removing sections of excessive ovality and subsequent replacement with new sections without discarding the complete tubing or the ability to extend the CT string length, are further examples of the benefits of performing reliable on-site girth-welded connection(s) in coiled tubing.
This paper describes the weld procedure specification (WPS) under development at BJ Services. The procedure utilizes an orbital tungsten inert gas (TIG) welding process equipped with a full-function "Magnatech D-Head". The welding sequence consists of a fine stringer bead technique for maximum grain refinement and a strategic control of heat input, preheat and interpass temperature control. Mechanized systems for tubing ovality removal, reaming of internal ERW seam weld flash and girth-weld edge preparation, are utilized to their fullest extent to maximize repeatability of the weldment integrity and minimize reliance on welder skill and quality of workmanship. Preliminary test results obtained indicate that the low-cycle plastic fatigue life of these mechanized girth welds can be increased by at least 100% compared with what is generally attainable from manual TIG girth welds in coiled tubing.
Industry Guidelines for Underbalanced Coiled Tubing Drilling of Critical Sour Wells
Authors: Luft H. B. , Wilde G. 
Published: December 2007

Abstract
Oil and gas well drilling using coiled tubing (CT), in general, is continually increasing. Because a significant portion of this drilling activity could involve critical sour environments, the industry and regulatory bodies have recognized a lack of adequate guidelines for under-balanced drilling of wells containing hydrogen sulfide. Drilling using coiled tubing (DUCT) in critical sour wells is currently not permitted pending the development of such guidelines. A key element of safe and reliable drilling operations in sour wells, is the materials integrity of coiled tubing when subjected to a wet hydrogen sulfide environment.
Considerable laboratory testing and investigation of small-scale, standard NACE test specimens, has already been performed, primarily through a prior joint industry project6 (JIP). These tests did not show unequivocally that coiled tubing steels could be used in sour environments without protection by corrosion inhibitors. Considerably more laboratory testing is indicated. A combined industry effort is required that will compile all laboratory test results from which must evolve a meaningful and practical set of operational guidelines for use with actual full sized drill strings and associated equipment. This paper presents the background to these developments, a review of the materials problem, discusses results from new a new testing method and additional laboratory specimen testing that is required to address any deficiencies or lack in essential data.
Analogous to the development of CT fatigue life predictions, full-scale "corrosion fatigue" testing under representative loading and sour environments, is proposed. A methodology is required to integrate the materials response from these test results into the actual systems response of a CT drilling string operating in sour wells.
For readers unfamiliar with the technical issues of corrosion fatigue we included extensive appendices giving information related to CT chemistry, metallury and service conditions in sour environments.
A "New" Gas Supply - The Devonian Shales
Authors: Foster John M. 
Published: December 2007

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

Abstract
For the past 2-1/2 years, Columbia Gas System, through its Research Department and operating Companies, has conducted an exhaustive study of the Upper and Middle Devonian Shales in Columbia's operating territory in Appalachia. The various aspects of this study include gas reserves, depletion characteristics, method of containment, recovery technology and economics.
This study has indicated that the total natural gas reserves of the Appalachian Devonian Shales, in a five-state area of Columbia's principal operations, could be as great as principal operations, could be as great as 285 trillion cubic feet, although the magnitude of recoverable reserves depends on the stimulation technology available or developed and the allowable natural gas price level.
With this indication of large potential reserves, what is the "State of the Art" for the future development of Devonian Shale? In discussion of this potential, the following topics will be presented:Geological DescriptionPotential ReservesMethod of Containment and Depletion CharacteristicsRecovery Technology and Future Planning

Geological Description
The Upper and Middle Devonian Shales are very extensive formations of considerable thickness as shown in Figure 1. The Devonian Shales underlie approximately 100,000 square miles in Kentucky, Ohio, West Virginia, Pennsylvania, and New York. We estimate that Pennsylvania, and New York. We estimate that in this area there are approximately 460 trillion tons of Shale readily accessible to the drill, almost all of which is above 10,000 feet in depth. It should also be noted that the same formations underlie approximately 150,000 square miles in adjacent areas in Michigan, Indiana, Illinois, Tennessee, Mississippi, and Arkansas but will not be considered in this paper. paper.
A Special Application of NMR Logging to Detect Heavy Oil on North Slope Satellite Fields, Alaska
Authors: Campaign Wayne , Waters Doug 
Published: December 2007

Abstract
The occurrence and distribution of heavy oil on the North Slope of Alaska is poorly understood, however it may have economic implications, especially for small, newly discovered fields. Wells with a significant portion of heavy oil in the hydrocarbon column may impact the economic performance of the project.
Nuclear Magnetic Resonance (NMR) measurements provide an economic way of evaluating wells where heavy oil might be encountered. The alternative is expensive coring and testing programs. A simple technique utilizing the deficit in total porosity measured with a NMR tool compared to conventional Neutron/Density cross plot porosity may indicate the presence of heavy oil. The T2 distributions measured from the NMR tool show the point at which lighter oil starts to enter the hydrocarbon column.
The results of a case study from a well on the North Slope where NMR measurements identified a heavy oil zone and confirmed with core and RFT analysis will be presented.