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This paper was prepared for the SPE-European Spring Meeting 1974 of the Society of Petroleum Engineers of AIME, held in Amsterdam, the Netherlands, May 29–30, 1974. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Netherland Section of the Society of Petroleum Engineers, P. O. Box 228, The Hague, the Netherlands. 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 A new dehydration-desalting wash-tank design for treating large volumes of light crude oil is proposed. This wash tank has a perfect degassing system, a good coalescing area, and an ideal flow distribution. The effect of diurnal temperature changes is minimized and an undisturbed settling zone is assured. The design criteria of this new wash tank are explained. The various dehydration-desalting methods are reviewed and limitations discussed. Relatively light crude oil (above 30 degrees API) could be dehydrated with this new design wash tank to a sufficiently low final water content such that the desalting stage, using wash water, would not be required. This should result in considerable saving in capital investment, considerable saving in operating cost, and alleviation of problems in areas where the supply of wash water is scarce. Introduction With time, many oil fields will start producing formation water. The formation water can producing formation water. The formation water can be either fresh or salty. Salinities of 200 gm/liter NaCl are quite normal for many oil fields. The salt content of the crude oil depends on the salinity of the formation water and the amount of emulsified water. The generally accepted limit of salt in crudes shipped from the Middle East fields is 10 ptb (pounds per thousand barrels) at loading site. It should be mentioned that this crude, when received at European refineries, could have a salt content of up to 60 ptb due to contamination with sea water during transport (loading-on-top system, etc.). U.S. oil fields normally apply a limit to the water percentage, but not on the salt content. Any desalting is done at the refinery. If wet wells must remain on production, dehydration-desalting facilities have to be installed in the field. These facilities could be very costly. Dehydration (separation of formation water from the crude) and desalting (washing with relatively fresh water) can be done either chemically or electrically, depending on the quantity of the crudes the viscosity, the specific gravity, the temperature, the water content, and the cost of the demulsifier.

This paper was prepared for the 48th Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in Las Vegas, Nev., Sept. 30-Oct. 3, 1973. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Abstract An evaluation of stable water in oil emulsions (200 cp oil) at 180 degrees F as displacing agent is presented. The stability of emulsions as controlled by the pH of water. Displacement tests were carried out in consolidated Berea sandstone cores at a temperature of 180 degrees F. Secondary as well as tertiary recovery tests were conducted by injecting emulsion slugs followed by polymer solutions in order to control the mobility ratio. It was found that emulsions prepared with law pH water in a viscous oil were stable during the displacement process, and were able to recover up to 97 percent of the original oil at an approximate cost of 1 $ per barrel of extra oil with no need of a commercial emulsifier. Slugs of emulsion greater than 4 percent of the pore volume were able to maintain the displacement pore volume were able to maintain the displacement miscible during the whole process, recovering up to 7.5 barrels of extra oil per each barrel of oil in the emulsion when the mobility ratio was properly controlled. properly controlled Introduction Microemulsion flooding is a miscible oil recovery process which involves sequential injection of a process which involves sequential injection of a slug of microemulsion, a mobility buffer and water. The viscosity of the microemulsion and the buffer can be controlled in such a way that the mobility ratio is favorable during the displacement achieving high volumetric efficiency. The chemistry of microemulsions and their behavior in oil-water displacement tests are the most important aspects in the process. process. The use of microemulsions for secondary and tertiary recovery of oil have been presented in the literature. Laboratory as well as field tests have established their use as an important miscible method which is technically feasible. However the high cost of surfactant used in preparing microemulsions have limited its application in the field. Slug costs of 4 $/Bbl have been reported by Gogarty and Surkalo; they also indicated that in a large field test, the total cost of producing tertiary oil would be around 2.50 $/Bbl using micellar solutions. This work presents experimental tests showing that it is possible to prepare stable emulsions with some crude oils that can be used for secondary and tertiary recovery of oil without the requirement of commercial emulsifiers consequently reducing the cost of microemulsion slugs and thus improving the economics of the process. process.

This paper was prepared for the Improved Oil Recovery Symposium of the Society of Petroleum Engineers of AIME, to be held in Tulsa, Okla., April 22–24, 1974. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon requested 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 discussions may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Abstract Displacement of a 36 degrees API West Texas oil from watered-out cores with carbon dioxide was investigated at reservoir conditions of 90 degrees F and 1250 psig. Phase behavior of the CO2-West Texas oil system was also investigated. The objectives of the study were (1) to determine the oil recovery efficiency, and (2) to improve understanding of the oil recovery mechanisms, especially in relation to the phase behavior. The phase behavior studies indicate that CO2 efficiently swells the oil and forms two equilibrium liquid phases with the oil. Significant amounts of light and intermediate hydrocarbons are shown to be extracted into the CO2-rich liquid phase from the oil phase. The CO2 displacement studies conducted on watered-out cores indicate that a continuous CO2 drive can achieve a maximum recovery of 69 percent of residual oil from a 6-ft Berea core and 66 percent from a 20-ft sand-packed core. The minimum CO2 slug size required in a water-propelled CO2 drive for maximum recovery is 0.42 pore volume for the Berea core and 0.27 pore volume for the sandpacked core. In both cases, the required slug sizes are slightly greater than residual oil saturations. An analysis of the results of the phase behavior and displacement studies indicates that CO2 swelling and CO2 extraction of oil are among the dominant mechanisms responsible for recovering residual oil. Introduction As oil becomes more difficult to find and expensive to produce, more attention is being given to methods for recovery of the residual oil still present in reservoirs already waterflooded. Because of its availability and relatively low cost in some areas, carbon dioxide as a flooding medium is attracting renewed interest. A number of laboratory investigations on CO2 flooding processes for oil recovery have been reported in the literature. Several of these reports are primarily concerned with CO2 injection into high oil saturation cores. With regard to work on CO2 recovery of oil at conditions of high water saturation, it is only recently that two papers have been published. Shelton and Schneider reported results on first-contact and multiple-contact miscible displacement in secondary and tertiary recovery, and Kumar and Von Gonten presented data on oil recovery efficiency with CO2 injection into watered-out cores. It is known that when CO2 is mixed with a number of hydrocarbons, the phenomenon of liquid-liquid equilibrium is observed.

This paper was prepared for the SPE-European Spring Meeting 1974 of the Society of Petroleum Engineers of AIME, held in Amsterdam, the Netherlands, May 29–30, 1974. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Netherland Section of the Society of Petroleum Engineers, P. O. Box 228, The Hague, the Netherlands. 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 An analysis of the effectiveness of solutions of a series of seven polymers in the recovery of oil (220 cp) is presented. The rheologic properties of these polymer solutions in viscometers and their behavior in porous media are examined. Displacement tests were carried out in a quadrant of a five-spot model, with unconsolidated sand, using slugs of polymer solutions of varying viscosities. The viscosity gradients were the same for each polymer studied. There were definite increases in the oil recovery from these tests as compared to that obtained by employing water alone as displacing fluid. These increases ranged from 20% to 85% for the polymers with the lowest and the highest polymers with the lowest and the highest molecular weights respectively. Introduction Proper mobility control between the displacing and displaced phases in flow through porous media is important in the success of porous media is important in the success of secondary and tertiary recovery processes. Such control can be achieved in the waterflooding of oil reservoirs, by the use of slugs of polymer solutions, which act as mobility buffers between the water and oil phases. The types of polymers recommended for performing this function are the partially performing this function are the partially hydrolyzed polyacrylamides and the polysaccharides. In the design of a polymer flood, the selection of the concentrations of the appropriate polymer slug, necessitates an, understanding polymer slug, necessitates an, understanding of the particular rheologic behavior of the polymer solutions within the system (oil-water-rock) polymer solutions within the system (oil-water-rock) to be flooded. This paper presents experimental tests, to determine the effectiveness of solutions of several polymers in the secondary recovery of oil (220 cp), from a stratified reservoir. It outlines a simple procedure for determining the concentration of the polymer banks, and examines the rheologic properties of a series of polymers studied. EXPERIMENTAL PROCEDURE RHEOLOGY OF POLYMER SOLUTIONS A list of the polymers used in the experiments is presented in Table I.

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc. This paper was prepared for the Rocky Mountain Regional Meeting of the Society of Petroleum Engineers of AIME, to be held in Billings, Mont., May 15–16, 1974. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations mat not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. Discussion of this paper invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Abstract This paper presents the principles, philosophy, plausibility, practicality, promise, prospects, potential, possibilities, and problems practicality, promise, prospects, potential, possibilities, and problems of heavy oil recovery. Methods of heavy oil recovery are briefly examined, and field results are summarized. The criteria for applying such methods to specific reservoirs are outlined in the light of field test results. Finally, the heavy oil reservoirs in the Rocky Mountain region are briefly described, and possible recovery techniques are considered. Introduction The term "heavy oil" usually implies crude oil having an API gravity of 25 degrees, or less. Once in a while, semi-solid hydrocarbons (e.g. bitumen in tar sands, asphalt, etc.) are included in this category. However, in the following discussion we shall only consider those heavy oils which are mobile at reservoir conditions, as established by some primary production. At the other end of the scale, crude oils having viscosities in excess of 30–40 cp are frequently referred to as "heavy oils". Heavy crude oil has been recovered in the United States since the discovery of the Nacogdoches oilfield in Texas, in 1866. As of January 1, 1966, the heavy oil resources of the United States totaled 106.8 billion barrels, of which only 5.2 billion bbl were considered to be recoverable by conventional methods. It is estimated that of the remaining oil, some 45.9 billion bbl could be recovered by thermal methods, since this much oil occurs in reservoirs considered to be favorable for the application of such methods. The magnitude and the importance of this oil become readily evident if one considers the fact that the proved conventional oil reserves of the U.S. total only 36.3 billion barrels. In the past, recovery of heavy oils by rather exotic methods has been a marginal operation at best, since on one hand such recovery methods are expensive, and on the other, heavy oils sell for less than conventional oils. This has changed now, and with the increasing oil prices, recovery of heavy oils will become increasingly attractive from the commercial standpoint. This paper examines various aspects of heavy oil recovery, and briefly considers the heavy oil potential of the Rocky Mountain region. HEAVY OIL IN THE UNITED STATES Over 2000 heavy oil reservoirs, occurring in 1500 fields in 26 states have been catalogued.

This paper was prepared for the Society of Petroleum Engineers of AIME Symposium on Formation Damage Control, to be held in New Orleans, La., Feb. 7–8, 1974. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon requested 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 Development of techniques, materials and equipment for the elimination or improvement of some of the causes of formation damage has been an objective for several years. Interest has increased drastically recently because of an increased awareness of production loss due to these problems. Specialized equipment has been built and research is continuing on improved equipment. The use of special tankage and blenders, internal tank and blender coatings, surface and subsurface filters, down-hole tools (including surge tools and washing tools for perforation clean-out) down-stream (of pump) sand injectors for gravel packing and other special devices have proven to have helped in this objective. Large amounts of trash have actually been recovered from filters placed directly on top of squeeze tools used in plastic sand consolidation jobs. Also, large amounts of trash have been found in filters that were filtering supposedly clean fluid just prior to sand control and stimulation jobs. Trash has been removed several joints above surge tools just prior to performing sand control jobs. All of this has performing sand control jobs. All of this has caused a new awareness of this severe problem in sand control and stimulation work where clean fluids are a necessity for successful jobs. Research is continuing in the field of stimulation fluids to keep residue to a minimum after treatments. Additives for aqueous fluids may provide a non-swelling environment for clay-containing formations. Sequestering agents may be used to keep fines and precipitates released by acid solutions from restricting flow channels. Equipment and materials have been used in the Gulf Coast and other areas to help relieve formation damage during sand control and stimulation jobs. Continuing research and field application are directed toward alleviation of the problem. problem Introduction While the general public and government agencies have only recently become concerned with the potential dangers of pollution, the producing segment of the petroleum industry producing segment of the petroleum industry and the companies which provide service and materials for downhole treatment of wells have been acutely aware of cleanliness for some time.

ABSTRACT Procedures are developed for estimating geometry and load distribution in a chain connected from a floating object to a fixed anchor beneath the seabed. Previously published information on this subject has been restricted to a discussion of resistance of soil to movement of chain normal to the chain path. This paper expands the theory to include procedures for considering tangential resistance of soil to movement of the chain, the effective weight of chain in soil, and the general case of chain entering the s oil at an angle. The more rigorous treatment of chain behavior in s oil yields shriller Toads on anchor s. These smaller loads could result in savings on installation costs for anchors. A parameter study is included to snow the influence of several variables on chain loads at the anchor. INTRODUCTION Anchorage for a single-point mooring system, SPM, is provided by chains connected to conventional anchors or piling. For locations with weak soils, the connection to the anchor or piling should be at some distance beneath the seabed in order for the anchor to provide optimum resistance to the vertical and horizontal components of load from the chain. In this paper it is as sunned that the chain is connected to a pile, although the analytical treatment could apply to a conventional anchor that has been jetted or pulled to some distance below the seabed. Published information on loads from chain to anchor points beneath the seabed is restricted to a consideration of the component of soil resistance that is normal to the chain path. This results in the conservative assumption that chain tension is constant from the seabed to the point of connection to the pile. This cons erratum is believed unwarranted for connection points at considerable depths beneath the seabed. Analytical procedures presented in this paper are more complete in acknowledging the total resistance of soil to chain movement. For many installations, these more complete procedures will predict significantly lower loads at the pile. GEOMETRY AND EQUILIBRIUM OF CHAIN Korkut and Hebert1 have presented the basic derivations and equations for catenaries as they apply to marine anchorage problems. They discuss the effect of currents on catenaries and they include discussions of geometries of anchor chains related to the operations of running and dropping anchors. Collipp 2 has presented no dimensional parameters which define mooring line catenaries when the chain is anchored on the ocean floor. Stanton, Tidwell, and Lloyd3 have investigated effects of sloping sea floors on anchor line loads and chain geometry when the anchor is on the sea floor. Hsu and Blenkarn4 have developed procedures for calculating peak mooring forces of a vessel in a random or irregular sea. Reese5 has discussed the equilibrium of a chain in soil. Reese s discussion is restricted to chains which are tangent to the seabed and his equilibrium equations do not include effects of weight of chain in the soil or resistance of soil tangent to the chain path.

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Abstract Sand consolidation systems using resinous materials have been developed which require only water (brines) in the placement procedures The use of water treating fluids is solving several important problems in the field associated with current consolidation methods which use oil placement fluids. The brine treating fluids are easily handled and have presented no disposal problems, particularly on offshore locations. The desirable particularly on offshore locations. The desirable weighting and no fire hazard characteristics of brines have improved safety. These aqueous fluids can be used in gas and non-potable water (source or injection) wells where it is undesirable to use oils. Waters to prepare the brine treating solutions are readily available. Formation brine, fresh water, bay and sea waters have all been used. The ready availability of these fluids has resulted in reduced "storage tank" requirements on water job sites and have eliminated transport needs required in getting treating oils to offshore facilities. Considerable volume of oil is being saved on each application by using brines. The paper describes two separate consolidation procedures. One involves the consolidation procedures. One involves the consolidation of formation sands with neat resins using brine placement fluids and the second describes the placement fluids and the second describes the packing of formations with resin-coated sand packing of formations with resin-coated sand placed in a water carrier. With both systems placed in a water carrier. With both systems an aqueous hydrochloric acid solution is used to overflush catalyze the placed resin resulting in consolidation of the sands. Deemulsifier surfactants may be used in all treating solutions including the organic resin. The first technique, involving the placing of neat resin, has been successfully applied in a bull-head squeeze procedure requiring no or minimal rig facilities on location. Laboratory results and field development data on fourteen initial applications are presented. presented Introduction The petroleum industry's sand problems are both widespread geographically and persistent historically. Sand control has persistent historically. Sand control has consequently meant a succession of solutions.

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussions may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Abstract The Jay Field discovery in June of 1970 paved the way to extensive drilling and paved the way to extensive drilling and production facility activities in the Florida production facility activities in the Florida Panhandle and in south Alabama. Within 3 years, Panhandle and in south Alabama. Within 3 years, 94 wells had been drilled and 10 treating plants had been constructed. The Jay Field is approximately 8 miles long and about 4 miles wide. Recoverable reserves are estimated to be 337 million bbl of oil. This Smackover production contains about 9 mol percent of hydrogen production contains about 9 mol percent of hydrogen sulfide, which presented many technical challenges in view of safety and environmental considerations. The willingness of industry to commit to risk investments allowed a rapid production buildup to 84,000 B/D and the production buildup to 84,000 B/D and the initiation of a 200,000 B/D waterflood at the same time unitization was approved in March 1974. The paper will highlight the field development history and will include basic reservoir description and drilling information. Emphasis will be placed on facility design and operating considerations for treating sour crude and gas, and sulfur recovery. A brief description of the field waterflood facilities and plans for gas processing will also be included. plans for gas processing will also be included Introduction Recent discoveries in the deep, sour Jurassic Trend in northwest Florida and south Alabama have paved the way to extensive drilling and production facility activities. These field development opportunities have presented many technical challenges in view of the safety and environmental considerations. The most significant discovery in this area is the Jay-Little Escambia Creek Field. Fig. 1 is a map showing the major Jurassic Trend discoveries in the Jay area, which is some 60 miles east of Mobile, Ala., and 35 miles north of Pensacola, Fla. The first discovery of deeper production was the Flomaton Field, immediately production was the Flomaton Field, immediately north of the town of Flomaton, Ala. This field was discovered in 1968, and produces sour gas from the Norphlet sandstone. Exxon discovered the Jay Field in June 1970. The Blackjack Creek Field, southeast of Jay, was discovered by Exxon in Jan. 1972, and 15 wells have now been completed. Production facilities are scheduled for completion in October. The Big Escambia Creek Field, west of the Flomaton Field, was discovered by Mallard Exploration Co. early in 1972. Twenty wells have been completed and production facilities went on stream in July. production facilities went on stream in July.

This paper was prepared for the 44th Annual California Regional Meeting of the Society of Petroleum Engineers of AIME, to be held in San Francisco, Calif., April 4–5, 1974. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Abstract Landslides have damaged 65 oil wells on Getty Oil Company's leases in the Ventura Avenue Field. During a landslide, some wells may remain connected to the surface while other wells may be buried. Well damage ranges from slight bending to complete severing of all casing strings, and depth of damage varies from 15' to 120'. Two major problems have been encountered when problems have been encountered when repair work is planned for a landslide damaged well. The first problem is to locate the undamaged well casing below the landslide. The second problem is to recover the well and replace the damaged casing. Some methods used by Getty Oil Company to locate the undamaged portion of a well are conventional surveys, dip-needle surveys, magnetometer surveys, kinkmeter surveys, and test holes. In wells that remain connected to the surface following a landslide, an oriented kinkmeter survey may provide all of the information necessary for planning a well recovery program. For planning a well recovery program. For wells which are buried or have severed casing, conventional surveys, magnetic surveys, and test holes may provide enough information for planning recovery programs. Information on the movement, depth, and dimensions of a particular landslide may also be particular landslide may also be helpful or necessary. Three methods have been used to recover landslide damaged wells in the Ventura Avenue Field. The simplest method is an open excavation made with standard earthmoving equipment. This method is limited to shallow depths and locations where the landslide would not be reactivated. To reach greater depths, special methods such as hand-dug or machine-dug shafts must be used. All three methods have been used successfully by Getty Oil Company. Introduction Landslides have affected oil production in the Ventura Avenue Field since production in the Ventura Avenue Field since 1926. On Getty Oil Company's leases, 143 wells are located on the 11 landslides shown in Figure 1. These slides vary in size from 1.5 to 150 acres, and cover 43 percent of the productive surface area. productive surface area.

This paper was prepared for the 44th Annual California Regional Meeting of the Society of Petroleum Engineers of AIME, to be held in San Francisco, Calif., April 4–5, 1974. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Many people read the "Guidelines to Professional Employment of Engineers and Professional Employment of Engineers and Scientists" and ask "What harm could the 'Guidelines…' do?" After all, most of the Guidelines deal with the professional integrity of the company and the individual. Only a few speak of benefit plans, severance pay, and overtime. In plans, severance pay, and overtime. In my view the principle of placing a third party, be it a set of guidelines party, be it a set of guidelines endorsed by the Society of Petroleum Engineers, a professional union, or a well meaning individual, between the company and the engineer is out of tune with the spirit of the oil industry. It could have serious implications for the engineer, his company and society as a whole. The technological problems that confront the petroleum engineer are great. It is his responsibility, whether he is a manager, or in a staff advisory position, to create solutions to these problems in order to provide inexpensive, plentiful energy for the future. Innovations can and must be made both in the field of technology and management. The S.P.E. should be instrumental in informing all petroleum engineers of advancements made in both fields, rather than regulating either. I cannot speak for all engineers of my age group, or even all of the young engineers employed by Texaco. My background and situation have been different than most. I have been connected with the oil industry all my life. My father owned a drilling company in Bakersfield for fourteen years and is currently in the offshore workover business in the Gulf of Mexico. Luckily for me, he didn't believe in leaving his work at the office or in the field. It came home with him at night, and often the entire family spent vacations and weekends visiting drilling locations and equipment yards. My education at Stanford University was unique. My graduating class in Petroleum Engineering was 100% female. I was the only person to receive a B.S. from the department that year. Many of my classes were filled with graduate students, or were tutorial in nature. Because the professors in the department were very professors in the department were very active in industry, my education extended out of the textbook into the real world.

This paper was prepared for the SPE-European Spring Meeting 1974 of the Society of Petroleum Engineers of AIME, held in Amsterdam, the Netherlands, May 29–30, 1974. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Netherland Section of the Society of Petroleum Engineers, P. O. Box 228, The Hague, the Netherlands. 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 A subsea completed oil well lying offshore Congo was brought into production with the aid of a 48 m × 16 m barge carrying production, stimulation and wire line production, stimulation and wire line equipment. The success of the operation was mainly due to the use of a subsea lubricator and associated barge-mounted swell compensating device. The feasibility of bringing subsea completed wells into production working from a floating support was amply demonstrated by this successful operation. Introduction The great majority of wellheads in offshore fields either producing or under development are installed above the surface of the sea on fixed platforms. In water depths of 70/100 m (230/330 ft) and over, the installation of such platforms is difficult and very costly. For this reason, when possible, deviated wells are drilled so as to group together a large number of wells, up to 25 or 30, on one platform. This solution cannot always be adopted, however, as for example in the case of shallow pay zones, where deviated wells would not drain a sufficiently large area. It was obvious that alternative methods of developing such offshore fields would have to be sought using wellheads installed on the sea bed. In fact in very deep water this would appear to be the only practicable method of producing. Such subsea completions could use "wet" type wellheads either with or without temporary capsule or "dry" wellheads with permanent capsule. The system we present is for use on the "wet" type of wellhead.

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc. This paper was prepared for the 49th Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in Houston, Texas, Oct. 6–9, 1974. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL paper is presented. Publication elsewhere after publication in the JOURNAL OF 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 discussions may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Abstract The present supply of qualified personnel is inadequate to continue the industry's traditional practices at the present level of operation. Changes are taking place, and more are needed to ascertain that the industry maintains a minimally adequate operating force. Consultants are being employed to an increasing degree; turnkey operations are more common, as is increasing reliance on contract drilling supervisors for over-all supervision of drilling operations. Improved working conditions and remuneration are needed to attract and keep rig personnel and line supervision in the field. personnel and line supervision in the field. A complete revision of management philosophy of personnel utilization is mandatory. personnel utilization is mandatory. CAPABLE PERSONNEL NEEDED With the advent of the great energy shortage and the resultant 100-percent utilization of drilling rigs, the industry seems to be awakening to a problem that has been developing for quite some time. Most operating companies, large and small, new and old, are critically short of capable operating personnel. Drilling contractors have been telling us for years that they cannot keep experienced people to run their rigs efficiently. Technology has far outstripped performance at all levels of the industry. Most major operational problems encountered are predictable, and very few are the result of unpreventable mechanical failure. Necessary information from previously drilled wells and means of obtaining data from drilling wells are available to preclude most of the problems with which we are beset. Yet the industry continues doing a halfway job, poorly managing the supply of often unqualified people it does have. The situation starts with the drilling contractors' people. The industry has created conditions under which employment on drilling rigs is no longer desirable. It once was common practice to pick up help off the street, even to drag "winos" from under railroad trestles to man drilling and workover rigs. Some contractors still do, but even in this day of full rig utilization, such methods of recruitment are costly both to the contractor and well operator. The industry must make employment on rigs desirable. We can no longer hide behind our old complaint that the price of our product is too low. Most of us make a profit in spite of our management methods. We ask people to work under conditions and at a wage scale that is well below that for comparable skills, and then we ask them to drive up to 200 miles a day to and from work.

This paper was prepared for the Improved Oil Recovery Symposium of the Society of Petroleum Engineers of AIME, to be held in Tulsa, Okla., April 22–24, 1974. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon requested 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 discussions may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Introduction By mid-1972 Atlantic Richfield Co.'s leases in the Midway Sunset field, Kern County, Calif., were thought to be adequately developed. Most of the leases had begun to decline and some were approaching uneconomic status. In late 1972, an engineering effort was made to determine the feasibility of infill drilling that followed an earlier stake's survey. The effort involved a conceptual analysis of the parameters that influence steam-soak stimulation, which is widely used in the heavy, viscous oil production of the leases. The results obtained supported an experimental infill drilling program in selected leases, consisting of multiwell packages to test adequately the premise that packages to test adequately the premise that additional economic reserves could be found in some of these old, developed reservoirs. During the last two months of 1972 and the first half of 1973, Atlantic Richfield Co. drilled 23 new wells in three leases, which represented the 10 percent of all the wells drilled in the Midway Sunset field during that time. These wells were drilled using an optimized-package approach designed to reduce over-all costs per well and to obtain valid statistical data. The encouraging results obtained from the drilling program and the recent crude oil price increases program and the recent crude oil price increases have prompted additional drilling during the fourth quarter of 1973, when 12 more wells were drilled. Future plans for 1974 include an additional drilling program. The fact that, during 1972 and 1973, Midway Sunset field reached its peak of production and had the greatest number of wells drilled, may be an indication that other operators are reaching the same conclusions as those set forth here. Background Kuo et al. in 1970 published the results of a model of the steam-soak process based on the production performance of a reservoir in which gravity drainage was the dominant production mechanism. Their model assumed that the production mechanism. Their model assumed that the steam zone temperature was constant and that the heated area was gradually enlarged by conduction. Kuo's results were reported in comparison to earlier work done by Seba and Perry. These two papers, as well as earlier ones by Towson and papers, as well as earlier ones by Towson and Boberg and by Clossman, Ratliff and Truitt, were concerned with predicting oil production rates from stimulation with steam. Their work offers valuable insight into the steam-soak process, as does the work of other process, as does the work of other authors. The work of Kuo et al. sought to combine a temperature distribution with a model of the fluid flow, but excluded consideration of individual steam-soak cycles. The work of Clossman et al. predicted first-cycle performance of stratified reservoirs where performance of stratified reservoirs where crossflow from adjoining strata increased the flow of oil.

This paper was prepared for the 1974 Eastern Regional Meeting of the Society of Petroleum Engineers of AIME, to be held in Washington, D.C., Nov 14–15, 1974. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM ENGINEERS 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 the paper is invited. Three copies of the 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 on of the two SPE magazines. In a recent talk at the Louisville meeting on "Coal and the Environment," I suggested that the conversion of coal to liquids and to gases has been practiced in one form or another since the early days of this century. These early conversions resulted from construction of slot type coke ovens which produced by-product tar and gas. In 1913, Bergius carried out his original coal hydrogenation experiments and the original Fischer Tropsch work was carried out in the early 1920's. As the U.S. love affair with the automobile grew, the interest in producing motor fuel from coal tended to be up or down as a function of the then projected worldwide supplies of crude oil. During World War II, the Axis Powers used coal as a basic raw material to provide fuel for their military aircraft. In the closing days of World War II, our Congress provided for a synthetic fuel program in the United States and demonstration program in the United States and demonstration plants were constructed at Rifle, Colorado, and plants were constructed at Rifle, Colorado, and Louisiana, Missouri. In the early 1960's, work by the Office of Coal Research (OCR) tended to reinforce and augment efforts by the Bureau of Mines in the fields of coal liquefaction and gasification. More recently, the American Gas Association entered into an agreement with the Office of Coal Research to accelerate the development of processes for converting coal into pipeline quality gas. Subsequent to that, as an energy crisis tended to develop in the United States, both the Bureau's programs and the OCR programs were provided with programs and the OCR programs were provided with additional funds to accelerate development of coal-based processes. The net result of all of the above work has been to provide the United States with a sound technological base for converting coal to fuel gas, pipeline-quality gas, liquid boiler fuels, refined petroleum products, and various chemical products. The key to a successful synthetic fuel products. The key to a successful synthetic fuel industry, however, involves both process technology and the process economics. Generally, processes are available that produce clean liquid products from coal at a produce clean liquid products from coal at a price competitive with crude oil ranging from price competitive with crude oil ranging from $8-$10 per barrel. How, you may ask, can this be done? The conversion of coal can be undertaken in four basic ways:Coal carbonization, or pyrolysis, followed by hydrogenation and carbonization liquid. Gas is produced in both the hydrogenation and carbonization operations.

Slim-Hole Tubing Was One Key to the Successful Production of Natural Gas from a Production of Natural Gas from a Low-Permeability, Low-Porosity Reservoir This paper was prepared for the Rocky Mountain Regional Meeting of the Society of Petroleum Engineers of AIME, to be held in Billings, Mont., May 15–16, 1974. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Abstract The successful application of high-pressure hydraulic fracturing using glass beads as the proppant resulted in a commercial completion in proppant resulted in a commercial completion in the Hall sand of the Cotton Valley formation in the Lisbon Field, Caliborne Parish, La. The Burgess Simmons sand was also added as development drilling progressed across the structure. The initial production rates were relatively lo (500 to 600 Mcf/D) and it was found that the vertical gas velocity in 2-7/8-in. OD tubing was not sufficient to keep a well unloaded, resulting in a very rapid drop in production. The completion program was revised to use 2-7/8-in. OD tubing as a "frac" string and a 1-1/4-in. tubing was used as the completion string in both single and dual wells. This field would have been of questionable economic value if a successful revised completion had not been developed. The production history of the low PI wells indicated that fluid buildup was also occurring in some of the 1 1/4-in. tubing strings as the formation pressure dropped. The wells were produced with various reduced tubing pressures produced with various reduced tubing pressures in a test program, prepared to evaluate flow efficiencies, production declines, and to evaluate one proposed method of artificial lift. The data from this program was used to establish an economic basis by which several proposed methods of well unloading were proposed methods of well unloading were evaluated, and to project a production decline. These projected declines were used to establish a basis for the installation of a booster compressor. It is anticipated that some method of controlled well unloading will have to be used in some, if not all, of the wells in this field before it is economically depleted. The methods, or method, used will be determined after the stabilized rate of production decline has been established with the wells producing at lower tubing pressures through the booster compressor. From experience gained in this field, the use of 1-1/4-in. tubing in medium depth (8,000 to 10,000 ft) gas wells is recommended if they are low volume producers. Pressure drops at low rates of flow are not large and smaller casing strings can be used, reducing initial completion costs. The increased flow efficiencies developed in 1-1/4-in. tubing, and in some cases 1-in. tubing, provide an additional economic incentive to evaluate marginal sands that might otherwise be abandoned.

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc. This paper was prepared for the 49th Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in Houston, Texas, Oct. 6–9, 1974. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL paper is presented. Publication elsewhere after publication in the JOURNAL OF 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 discussions may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Abstract In order to realize reasonable profits from drilling and producing profits from drilling and producing the Wilcox Sands of Zapata County in Southwest Texas, special consideration was given to the operational problems encountered in this area. Modern technology with respect to drilling fluids, open hole evaluation, completion programs, cementing techniques and programs, cementing techniques and materials and stimulation procedures was brought to bear against the special geologic features of the Wilcox trend. The results of applied technology have resulted in efficient drilling and cementing operations. Some unsolved problems remain in formation evaluation problems remain in formation evaluation procedures, and stimulation efforts have procedures, and stimulation efforts have not been completely satisfactory. Technology and improved gas prices have created much interest in probing the Wilcox for new production and profitable development of the Zapata profitable development of the Zapata County reservoirs. Introduction Zapata County is located on the Mexico-U. S. border, east and southeast of the Texas city of Laredo. The area has a history of oil production that dates back to the twenties when shallow development created "Boom Towns" such as Mirando City. Petroleum operations caused many small cities to come to life but now there are many empty buildings standing as reminders of more prosperous times. For many years the Wilcox formation of Zapata County (found from 5,600' to more than 12,000') remained unexplored primarily because of the high cost of primarily because of the high cost of wildcatting below the Queen City formation (Queen City base is generally found near 5,000' - 6,000'). New gas prices have helped overcome this prices have helped overcome this barrier to Wilcox development. The Queen City formation will rarely support mud weights in excess of 10 ppg while the Wilcox requires 13.5 to 14.0 ppg fox initial penetration. Protection pipe is therefore required near the midpoint of a shale section that separates the Queen City Sands from the top of the Wilcox. The commercially attractive Wilcox of this trend includes sandstone with porosity ranging from 18 to 23% and porosity ranging from 18 to 23% and permeabilities from 5 to 35 millidarcies. permeabilities from 5 to 35 millidarcies.

This paper was prepared for the Permian Basin Oil Recovery Conference of the Society of Petroleum Engineers of AIME, to be held in Midland, Tex., March 11–12, 1974. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication is the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF publication is the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Abstract Attempts to stimulate marginal gas producers in Sutton County, Texas, has provided an producers in Sutton County, Texas, has provided an opportunity to evaluate several types of stimulation fluids on a comparative basis. The fluids used here included water base, oil base, and acid base fluids. A thorough study of the production history of wells following treatment production history of wells following treatment demonstrates the effectiveness of the different fluids on a long term basis. Conclusions drawn from this study provide a guide to selection of fracture fluids for tight gas sands. Cost-performance factors are explored as they apply to stimulation of marginal gas production and further conclusions are drawn production and further conclusions are drawn concerning the importance of formation damage as a function of formation petrophysical properties. Examples are shown to indicate formation damage is a factor to consider in fracturing tight sands but performance compromises may be made in the choice of fluid to obtain maximum frac penetration. penetration Introduction Shortages of many chemicals used in well stimulation treatments has led to re-evaluation of many gas well treating techniques. Nowhere has this been more the case than in the Canyon play of Sutton County, Texas. A previous paper play of Sutton County, Texas. A previous paper (SPE 4678) describes the treating methods used in the initial development of the Sawyer Field. This study has been continued and cost effective fracturing has resulted. The results of the fracturing development may serve as a model for gas well stimulation in other areas with production from similar zones. production from similar zones. FORMATION The Canyon, a Pennsylvanian Age sand, is generally found at approximately 6500 feet and is produced to about 8200 feet. The zone is massive with many "ratty" sections. These sections are low in permeability (1 md) and porosity (8–12 per cent). When contacted by fresh water there is a noticeable clay migration. Acid response tests indicate migration damage accounts for about 35–40 per cent loss in permeability. Formation liquid saturation is low and any liquid entering the formation may cause further loss in relative permeability. Gas-oil ratios indicate an essentially dry gas formation.

This paper was prepared for the SPE-European Spring Meeting 1974 of the Society of Petroleum Engineers of AIME, held in Amsterdam, the Netherlands, May 29–30, 1974. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Netherland Section of the Society of Petroleum Engineers, P. O. Box 228, The Hague, the Netherlands. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Abstract This study presents the results of a laboratory investigation of a suitable waterflood tracer for a limestone reservoir such as the Bulgurdag field. For this purpose, continuous and slug injection tests were performed in a crushed limestone pack by using potassium iodide, sodium chloride and potassium iodide, sodium chloride and sodium borate as tracers. Continuous injection tests were performed with various concentration or tracer added to the floodwater. The lengths of the mixing zone for each tracer were thereby obtained. To obtain adsorption losses during propagation, a number of slug injection tests were made in which slugs ranging from 100 to 25 to 10 and to 5 percent of the length of mixing zone percent of the length of mixing zone were injected and displaced by continuous injector of floodwater. On the basis of the laboratory results, it is concluded that because of its adsorption loss and the difficulty of the chemical analysis, sodium borate is not a suitable tracer. Potassium iodide is a suitable tracer when present even very small quantities, but its use is not considered economical due to its high price. The sodium chloride tracer, although the required amount is the largest, is the most economical tracer for use in the Bulgurdag field due to its low price. A design of a tracer flood for the Bulgurdag field is also proposed. The weight of the tracer chemical and the cost are calculated for various slug sizes. The time at which the tracer will first appear in the production well is predicted on the basis of a presumed reservoir geometry and presumed reservoir geometry and lithology. Introduction In the secondary recovery of petroleum by water flooding, an accurate petroleum by water flooding, an accurate evaluation of the subsurface pattern of flow of the injected water is necessary.

Abstract A new mathematical model has been developed which considers more of the variables encountered during fracture acidizing treatments than previous models. In particular the variables include, wellbore cooldown, temperature profile of fluid in the fracture, the fracture geometry created by both non-reactive and reactive fluids the spending of the leading edge of the acid, and the conductivity of the etched fracture faces. Productivity increases calculated by the new program correlate more closely with actual field results than those calculated by previous programs. This paper describes the previous programs. This paper describes the method of handling the variables in setting up the new model and presents the equations used to describe the reaction rate of the acid. Introduction Fracture acidizing has been used for stimulating wells for over 25 years. The techniques used have developed more as an art, than a science, often based on intangible ideas, rather than on predictable facts. Although a mathematical model has been available since the early 1960's, little correlation has been observed between predicted and field results. One reason for this undoubtedly was due to the use of the acid as both the hydraulic fracturing fluid and as the reactive fluid. Another was the inadequacy of the model to describe the rheological and physical properties of the fluids in the fracture. properties of the fluids in the fracture. Only when treating techniques changed, in which better results were obtained by creating the fracture with a non-reactive pad fluid ahead of the acid, was serious effort directed toward describing the conditions or properties of the fluids in the fracture. Equations were developed first to describe the cooldown of the wellbore area, as illustrated by Ramey's "Wellbore Heat Transmission" equations in the Appendix. Then, Whitsett and Dysart, and later Sinclair, proposed methods for describing the proposed methods for describing the temperature profile of fluids within a hydraulic fracture. Hall and Dollarhide provided basic equations for considering the fracture geometry created by more than one fluid within the fracture.

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc. This paper was prepared for the 49th Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in Houston, Texas, Oct. 6–9, 1974. Permission to copy is restricted to an abstract of not more than 300 words. illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL paper is presented. Publication elsewhere after publication in the JOURNAL OF 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 discussions may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Abstract A thermal simulation program and a theoretical analysis consider the effects of cold waterflooding a warm reservoir. For the conditions investigated, the injected water quickly cools the region surrounding the wellbore and accounts for the major part of the pressure drop across the system. Heating the injected water or fracturing the formation each decrease the pressure drop and can be used to avoid an pressure drop and can be used to avoid an uncontrolled fracture or the need for costly, highpressure surface injection equipment. The study showed that thermal effects can play a major role in the economics of waterflooding projects. Introduction Several authors have discussed pressure falloff testing in reservoirs that develop fluid banks during improved oil recovery projects. Falloff testing has been used to track the movement of the burning front during in-situ combustion and to locate the position of the outer radius of a water bank. Kazemi et al. used a radial reservoir simulator to assist in interpreting pressure falloff tests in systems having fluid banks. Fluid banks may arise due to the injection of a fluid having properties different from the reservoir fluids. This creates discontinuities between the region where the injected fluid predominates and the region(s) where the predominates and the region(s) where the reservoir fluids predominate. Examples of such systems are 1) reservoirs being waterflooded, 2) reservoirs undergoing in-situ combustion, and 3) reservoirs receiving gas injection. This paper considers thermal effects in banks that arise when flooding a reservoir with water having a temperature considerably below that of the reservoir. DISCUSSION AND RESULTS As part of a pressure-maintenance program in an extensive field, it has been proposed to inject 70 degrees F surface water at the rate of 300,000 BPD into the 285 degrees F formation. For the well patterns and spacing currently under consideration, the injection rate would be about 10,000 BPD/well. The steam-stimulation model described by Weinstein et al. was used to investigate 1) the extent to which the reservoir and surrounding strata would heat the injected water and 2) the dependence of the pressure drop across the system on injection rate, permeability-thickness product, injected water temperature, and the product, injected water temperature, and the presence of a vertical fracture. presence of a vertical fracture.

This paper was prepared for the SPE-European Spring Meeting 1974 of the Society of Petroleum Engineers of AIME, held in Amsterdam, the Netherlands, May 29–30, 1974. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Netherland Section of the Society of Petroleum Engineers, P. O. Box 228, The Hague, the Netherlands. 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 Results are given of a study in which the behaviour of semi-submersible platforms equipped with respectively 2, 3 and 5 floaters is compared under the action of waves, winds and currents. Required conditions were minimum effects of wind and currant action and most favourable amplitude levels for drilling operations. A three-legged platform turned out to be the best choice. Results of mathematical model studies were complemented and verified with the help of model basin tests. Additional model tests were performed in a wind tunnel to determine the optimum deck shape. Main features of the installation of drilling equipment on deck will be shown. Information is also given on the dynamic positioning system. Introduction The search for new subsea oil and gas fields under greater and greater water depths and the exploration of such fields has led to the replacement of jack-up platforms by floating supports such as drilling ships and semisubmersible platforms. In addition, consideration must also be given to the effect of extremely hostile environmental conditions (storms) on such structures. A platform must withstand such disturbances at one time or another during its effective life span, depending on the work schedule it must follow. At the same time, new sorts of dangers (icebergs) make it necessary to minimize installation time at a given site and to maintain the possibility of moving away in the midst of a possibility of moving away in the midst of a drilling operation. Under such conditions, dynamic positioning is of great interest because it guarantees positioning is of great interest because it guarantees quick installation on a drilling site and enables the position to be changed as fast as it becomes necessary as the result of marine elements (i.e. keeping headed into the wind of current if necessary).

This paper was prepared for the SPE-European Spring Meeting 1974 of the Society of Petroleum Engineers of AIME, held in Amsterdam, the Netherlands, May 29–30, 1974. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Netherland Section of the Society of Petroleum Engineers, P. O. Box 228, The Hague, the Netherlands. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Abstract The author deals with the data management aspects of incorporating uncertainty in reservoir engineering studies. A data base with supporting programmes which handles probabilistic estimates in a complex data probabilistic estimates in a complex data hierarchy, as used by NAM in The Netherlands, is described. Much attention has been paid to the systematic evaluation of the uncertainties associated with the basic data. Important factors in this respect are: The uncertainty associated with seismic information, determination of net reservoir rock and the areal influence of individual data points. This latter aspect is especially important when concluding initial studies with pertinent information from only a few control wells. Introduction The development of oil- and gas accumulations is always based on limited and uncertain data. Nevertheless decisions have to be made regardless of the uncertainties. This is well recognized as is shown by many publications. Such work treats uncertainty generally in a more theoretical manner. It also stresses the importance of an analysis of uncertainty, as a first requirement for further application of the decision theory. However, to date, decision theory has not generally been very successfully applied in Petroleum Engineering problems, except perhaps in some problem oriented cases. This perhaps in some problem oriented cases. This is surprising, since the Petroleum Industry is constantly faced with the evaluation of the consequences of these uncertainties and the application of the decision theory would seem to be beneficial. There are several reasons to explain why this is the case. DECISION THEORY IN PETROLEUM ENGINEERING As a result of the limitations of our thinking process, we have to work within the limits set by basic assumptions or working hypotheses. The problem is that we formulate or quantify uncertainties within the framework set by such concepts, but that it is nearly impossible to judge the uncertainty associated with a concept itself. This would require that we would be able to define (using the phraseology of the decision theory) all possible phraseology of the decision theory) all possible concepts, as a mutually exclusive and exhaustive list of all "states of the world"**. This is not possible except again perhaps in some isolated cases. The result is that our estimates are invariably of a conditional nature.

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Introduction The use of centrifugal force to separate fluids is a proved process that has been applied by many industries. The force is explained in college physics textbooks under uniform circular motion where Newton's laws of motion are discussed. A classic textbook example describes an object of known weight that is held in a circular path by a string of known length, and the weight is moving at a constant speed. The inward force that is developed is known as the centripetal force. The equal and opposite reaction that is in the outward direction is known as the centrifugal force. This is the force that we use to separate gas well fluids in a centrifugal-type separator. The flowing pressure at the wellhead furnishes the energy for the process. Upon expansion to a lower pressure at the wellhead choke, the natural gas, condensate, and water flow to the centrifugal separator for rotation and subsequent separation. The fluids tend to separate in layers of uniform density. Water collects on the internal surface of the separator, condensate flows on the water, and the gas flows in a circular pattern in the center of the vessel. FUNDAMENTALS The following formula for centripetal - force summarizes the process. 2WVFc = ———,gR where Fc = centripetal force, lbW = weight of the fluids, lbV = velocity, ft/secg = gravity constant, 32 ft/sec/secR = radius of the circle, ft The centripetal force, Fc, is that force in the inward direction, expressed in pounds, that is developed when the fluids are directed in a circular path in the separator. The centrifugal force is an equal and opposite reaction to the centripetal force; therefore, calculated values for Fc are vend for the centrifugal forces in the outward direction. The weight of the fluids can be calculated from the fixed dimensions of the internals of the vessel, the operating pressure, and temperature in the separator, and the gas-condensate ratio and gas-water ratio of the flowing stream.

This paper was prepared for the SPE-European Spring Meeting 1974 of the Society of Petroleum Engineers of AIME, held in Amsterdam, the Netherlands, May 29–30, 1974. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Netherland Section of the Society of Petroleum Engineers, P. O. Box 228, The Hague, the Netherlands. 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 Induction logging theory, including the skin and propagation effects has been previously presented in the literature. previously presented in the literature. This paper reviews the radial response of a typical modern deep-reading multi-coil sonde in both homogeneous and invaded formations. For the case of a homogeneous medium of 0.2 ohm.m half the measured signal is shown to be derived outside a diameter of 60". The standard geometrical factor (no skin effect) suggests that half the signal is derived from outside 130". The function of the skin-effect correction circuit is described. It provides accurate corrected resistivities provides accurate corrected resistivities for homogeneous formations. For invaded formations the pseudo-geometrical factor is shown to vary for all pseudo-geometrical factor is shown to vary for all values of Rxo and Rt. A set of pseudo-geometrical factor curves is presented. The use of these curves improves estimates of Rt when only an induction log is available. If the induction tool is used with salty muds in high porosity formations it is shown that Rt can be seriously underestimated if the classical Geometrical Factor is used and that it is possible to miss hydrocarbons if invasion is not shallow. This reinforces the usual recommendation that the induction log alone should not be relied upon in very salty muds. When both laterolog and induction logs are available use of a new series of charts for various Rxo will lead to improved estimates of Rt and di. Introduction The induction log is in common use in the oil industry as a means of measuring formation resistivity. The interpretation of resistivity logs is complicated by many factors, including invasion. Invasion profiles can only be evaluated if sufficient profiles can only be evaluated if sufficient different resistivity measurements are available and if the radial response of the tools is well defined. The radial response of the induction log was therefore investigated. This required the use of complex mathematics and a knowledge of the induction tool construction.

This paper was prepared for the Society of Petroleum Engineers of AIME Symposium on Formation Damage Control, to be held in New Orleans, La., Feb. 7–8, 1974. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon requested 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 A computer model was used to study the effects on well productivity of formation damage resulting from perforating and drilling or workover operations. The effects of perforation depth and shot density were compare perforation depth and shot density were compare for damaged and undamaged perforations. The results show that:To maximize well productivity perforations must penetrate productivity perforations must penetrate substantially beyond the zone of drilling damage,In a well with drilling damage, a few deep perforations are more effective than many perforations are more effective than many shallow ones, andPerforation quality is more important than either shot density or penetration. The effect of severe damage in penetration. The effect of severe damage in the perforations cannot be entirely overcome by increasing either shot density or depth of penetration, within the limits of present day penetration, within the limits of present day technology and economics. Introduction Gun perforation has been used for over 40 years for generating a flow channel between oil and gas reservoirs and the wellbore of injection or production wells. The first well reported to be gun perforated was a Union Oil Company of California well in the Montebello field, Los Angeles County, California in 1932. Since that time many types of special bullets and jets have been introduced to improve the perforating process, and we include both devices perforating process, and we include both devices in the term "gun perforating". Although gun perforating became widely accepted as a practical completion method, engineers long suspected that well productivities should be better than observed. productivities should be better than observed. Experimental and field studies, ranging over more than a 20-year period, exposed deficiencies in perforator design and perforating procedures perforator design and perforating procedures that accounted for the reduced productivities or injectivities and lead to improved field results. Laboratory observations on linear, perforated cores demonstrated that crushing and perforated cores demonstrated that crushing and compaction of rock during perforating resulted in substantial impairment of the flow capacity of the hole. Although this experimental work provided a better understanding of the physical effects of perforating into rock, our ability to estimate how much oil, gas or water should flow into a wellbore through perforations formed under downhole conditions has been limited by the simplifying assumptions required to handle this problem. We have been able to eliminate most of the simplifying assumptions used in the previous studies through use of a computerized finite element method that is described in a previous publications.

This paper was prepared for the SPE-European Spring Meeting 1974 of the Society of Petroleum Engineers of AIME, held in Amsterdam, the Netherlands, May 29–30, 1974. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Netherland Section of the Society of Petroleum Engineers, P. O. Box 228, The Hague, the Netherlands. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Abstract The cementation of zones with low fracture gradients, particularly in offshore operations, calls for a lightweight cement, to reduce the risk of formation fracturing. LIBIT-cement, a newly developed lightweight bitumen cement, combines, a low slurry gradient (565 psi/1000 ft) sufficient mechanical strength of the set cement. These properties render LIBIT cement eminently to the cementation of deep-water topholes. Introduction Primary cementation of weak zones with neat Primary cementation of weak zones with neat cement slurries often, leads to losses as a result of the formation break-down pressure being exceeded. In such cases a good cementation job i.e. complete fill of the annular space to the desired height, can be realized only by applying a multi-stage cementation process or by using a lightweight cement slurry. However, multi-stage cementation has the drawback that failures may be experienced with D.V. collars, while moreover the cementing time is almost doubled. Since failures and long cementing times are undesirable, especially in offshore operations, the use of lightweight cement slurries should be preferred. With commercial Pozmix cements, slurries with gradients of the order of 695 psi/1000 ft can be obtained. For operations at greater water depths it is necessary to go to lower densities, e. g. medium/deep sea operations call for slurry gradients of approx. 570 psi/1000 ft. Such low slurry gradients can be achieved by incorporating diatomaceous earth or bentonite in the cement formulation. Unfortunately, both filler cements have a very poor mechanical strength and definitely do not meet the 500 psi compressive strength level, which is generally accepted by the industry. This was the incentive for Koninklijke/Shell Exploratie en Produktie Laboratorium, Rijswijk (the Netherlands) to initiate development work on a lightweight cement capable of reaching a compressive strength of 500 psi in 24 hours at 110 degrees F/1600 psi (API curing schedule 2 S). This has resulted in the development of a lightweight cement slurry, so-called LIBIT cement, which is essentially a mixture of oilwell cement and a bitumen powder. The bituminous component of LIBIT cement has been pretreated in order to promote the compressive strength of the hardened promote the compressive strength of the hardened cement.

Campbell, John M., John M. Campbell and Co., and Patton, Charles C., Patton, Charles C., PetroTech Ltd., Members SPE-AIME PetroTech Ltd., Members SPE-AIME Copyright 1974, American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc. This paper was prepared for the SPE-European Spring Meeting 1974 of the Society of Petroleum Engineers of AIME, held in Amsterdam, the Netherlands, May 29–30, 1974. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Netherland Section of the Society of Petroleum Engineers, P. O. Box 228, The Hague, the Netherlands. 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 Once completed, an offshore production facility is composed primarily of equipment components that are reasonably standard for onshore operations. Many operators are thus tempted to utilize an onshore-type flow sheet with primary emphasis on selection of components to minimize size and weight requirements. There are some special considerations, however, that require additional careful thought. The primary purpose of this paper is to review some of these purpose of this paper is to review some of these considerations based upon our recent involvement in large offshore installations. Introduction Most of the producing experience to date has been onshore or in rather shallow offshore waters like those off the coast of Louisiana or in Lake Maracaibo. When planning and designing a production installation in an area like the northern sector of the North Sea (where deep water and bad weather abound), there are special decisions to be made. The very severity of the environment makes this fairly obvious. In reality, each offshore installation will be different to some degree and each requires a few special decisions regardless of location. We begin with this point because people are prone to use their past experience as a "hitching prone to use their past experience as a "hitching post" instead of a guidepost. Too often, those post" instead of a guidepost. Too often, those with experience tend to simply take a familiar onshore system and reproduce it offshore, with only the minimum modifications required by space and weight limitations. This is logical—to a point. The use of proven components and equipment makes sense, provided they are used imaginatively. The other boundary of our problem is dictated by the amount and location of current activity. A large amount of engineering work is being performed by people with little experience in the petroleum industry. It is not as easy as it appears to translate experience with power plants, chemical plants, and the like to plants, chemical plants, and the like to offshore production. A design may be good from a technological viewpoint and yet may be an operational nightmare. However, designs by inexperienced persons (petroleum production-wise) often contain imaginative features production-wise) often contain imaginative features with real merit. Likewise, some equipment suppliers with no traditional petroleum history have much to offer. Our problem is to blend experience with imagination in a very careful manner. This is no easy task and requires judgment based on both experience and an understanding of prevailing (and potentially new) technology.

ABSTRACT The existing stability criterion for semi submersible drilling platforms requires righting moment energy in excess of wind heel energy to allow for dynamic effects. Dynamic effects have been studied by testing a scale model of a semi submersible platform to evaluate the effect of wind velocity, center of gravity, air gap, and moorings ontendency to capsize in survival wave conditionsrelative motion between leeward deck edge and wave surface as a measure of down flooding tendency. FOREWORD At the occasion of the 1971 Offshore Technology Conference, the research panel on Offshore Mobile Platforms had its first meeting. Designated as Panel MS-3 of the Marine Systems committee, under the continuing research activities of the Society of Naval Architects and Marine Engineers, it has a se 1ect representation of drilling con tractors, oil companies, regulatory agencies and naval architects. Its purpose was set forth to identify and to promote research in such vital areas associated with mobile platforms towards more adequate design, construction and operation. By the following year, the panel had clearly identified the assessment of stability of mobile platforms as one of the most important and pressing problems, particularly in regard to the semi-submersible. The existing criteria, as promulgated by the u. S. Coast Guard and the American Bureau of Shipping (Reference I), were considered inadequate to properly assess the various dynamic influences on the platform and its inherent ability to resist them. A program of research was indicated. By OTC 1973, the program was on its way. Davidson Laboratory of Stevens Institute of Technology was selected to perform the initial research, and funds were being accumulated from solicitations through the industry, to where by mid-summer the first phase of experimental work was begun. This paper discusses the rationale leading to the panel IS conclusion that a research project of this type was both necessary and urgent, along with an outline of the full intended program. The gist of the paper, however, is the presentation of the experimental work done during the second half of last year, as a major part of this research, and which resulted in some valuable observations and a few surprises. EXAMINING THE PRESENT STABILITY CRITERIA Dissatisfaction with the present stability criteria as applied to semi-submersibles has existed since their adoption in the 1968 ABS rules. (It may be noted that many panel MS-3 members have also been serving on the ABS rules committee.) Based on a U. S. Coast Guard criterion for the stability of a surface ship in roll, somewhat empirically derived, it does not adequately account for the excitations nor responses of the semi-submersibleto the possible environment. Figure I shows the now familiar curves of requirement for stability; taken from the detail requirements as set forth in Reference I and as later amended in Reference 2. It shows an overturning moment curve, calculated for a steady wind speed, superimposed on the vessel IS righting moment curve of static stability, all in calm water.

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc. This paper was prepared for the 49th Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in Houston, Texas, Oct. 6–9, 1974. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL paper is presented. Publication elsewhere after publication in the JOURNAL OF 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 discussions may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. The energy crisis has caused hardships in every sector of American society. The American consumers have been asked to make sacrifices, and in most cases the response has been heartening. Individuals are lowering their thermostats, slowing down on highways, modifying travel plans, and paying more for heating oil and gasoline. As a result of the President's energy messages, Sun Oil Company undertook implementation on Energy Conservation programs to enable us to use the energy we have more effectively. Our Energy Conservation strategies involve three levels of attack: One is identifying energy consumption in converting fuel to energy in our operations. The second level involves documenting what has already been accomplished, thus providing methods for finding and stopping wasteful operations in existing facilities. The third level involves setting of Energy Conservation goals. The purpose of the Energy Conservation Program is to identify, develop, and Program is to identify, develop, and implement programs designed to conserve energy usage throughout Sun Oil Company and its subsidiaries. These programs are meant to aid in establishing an energy conservation ethic among our people to increase their awareness so they can effectively perform their responsibilities in a different environment. The Program will be conducted in harmony with performance of the Company's primary purpose of providing energy supply. primary purpose of providing energy supply. An Energy Conservation Program was organized to itensify, develop, and quicken the implementation of programs throughout Sun Oil Company and its Subsidiaries. The published objectives of our program are to: published objectives of our program are to:Optimize the use of energy consistent with sound operating practices.Function as a responsible citizen within society by insuring that energy conservation is a "way of life" throughout our operations.Effectively communicate our accomplishments to our people, customers, suppliers, and the general public.Actively perform as a leader on energy conservation in industry.

This paper was prepared for the SPE-European Spring Meeting 1974 of the Society of Petroleum Engineers of AIME, held in Amsterdam, the Netherlands, May 29–30, 1974. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Netherland Section of the Society of Petroleum Engineers, P. O. Box 228, The Hague, the Netherlands. 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 A study is made of hydraulic fracturing of formations containing natural flaws. The three factors of importance are shown to be the strength of the weakness plane, its orientation with respect to the least compressive principal stress and the difference between the principal stress magnitudes. Material flaws with dimensions that are small compared with the induced hydraulic fracture are shown to be unable to change the over-all orientation of the hydraulic fracture. The induced fracture can encircle such material defects and override their possible effect. Even if it does not, the influence of these flaws is local and insignificant on the results of the fracturing treatment. Large material flaws are shown unable to drastically change fracture orientation. The analytical results presented in the paper are based on the principle of least paper are based on the principle of least resistance. The study does not include severely fractured, highly permeable formations. Introduction Rocks, in their natural state, contain many flaws of various forms. On a small scale these include small cracks, crystal and grain boundaries, etc. On a larger scale, joints, beddings, and faults are examples of strength flaws. Most theoretical and experimental investigations on rocks are performed on relatively isotropic, homogeneous, and brittle-elastic rocks. The reason is either mathematics or ease of data analysis. This paper considers a small deviation from the above assumptions. It discusses hydraulic fracturing of an essentially isotropic, homogeneous, brittle-elastic material weakened by a planar flaw. CONCEPTS OF FRACTURE MECHANICS IN HYDRAULIC FRACTURING The analysis of the cause and process of crack propagation is extremely difficult and subject of many investigations. Irwin has observed that there are three basic modes of crack propagation: opening, sliding, and tearing (Fig. 1). In the opening mode (cleavage), the two faces of the crack tend to separate symmetrically with respect to the plane occupied by the crack before fracturing. plane occupied by the crack before fracturing. Hydraulic fractures usually fall in this category. In the sliding mode, the two faces of the crack slide over each other in opposite directions, but in the same plane. In the tearing mode, the material points that were originally in the same plane will twist and consequently occupy different planes.

This paper was prepared for the SPE-European Spring Meeting 1974 of the Society of Petroleum Engineers of AIME, held in Amsterdam, the Netherlands, May 29–30, 1974. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Netherland Section of the Society of Petroleum Engineers, P. O. Box 228, The Hague, the Netherlands. 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 From theoretical considerations if follows that the production improvement factor (PIF) for dry oil or gas production due to natural and/or hydraulically induced vertical fractures in bottom water reservoir showing water coning is identical with the PIF obtainable with the same fracture configuration in a reservoir without bottom water. This is generally derived for a single, symmetrical fracture of arbitrary shape. It has been found that the highest PIF is obtained for a fracture with a PIF is obtained for a fracture with a technically-optimised tapered cross section. Results of calculated examples are discussed. Introduction In oil reservoirs with bottom water the height of a steady-state water cone depends on the potential gradient of the fluid moving along the interface: the greater the gradient (production rate), the higher is the cone. A decrease of the potential gradient, and thus a suppression of the cone, can be achieved by means of a fracture that effectively reduces the resistance to flow. Alternatively, if the cone is allowed to reach the same height, a higher production rate would be achieved. Hydraulically-induced vertical fractures would thus permit higher critical rates (maximum water-free oil production-rates), and make it possible to reduce the number of wells to be drilled for a required off-take. The shape of vertical fractures can be better controlled nowadays. This prompted us to investigate the problem of steady-state fluid flow in the presence of vertical fractures in reservoirs with presence of vertical fractures in reservoirs with bottom water, in order to derive the production improvement factors (PIF) for fractures of various prescribed practicable shapes. The PIF is prescribed practicable shapes. The PIF is defined as the ratio between the critical production rates with and without a fracture. The following considerations are generally valid for the movement of a fluid in the presence of a second non-flowing fluid of different density. hence, the results are equally applicable to the case of oil production over bottom water, respectively from under a gas cap, as to the case of gas production over bottom water. production over bottom water.

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc. This paper was prepared for the Deep Drilling and Production Symposium of the Society of Petroleum Engineers of AIME, to be held in Amarillo, Texas, Sept. 8–10, 1974. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, my be considered for publication in one of the two SPE magazines. Abstract The development of drilling equipment with increasingly greater depth capability should take into account the maximum depths at which economic hydrocarbon accumulations will be found. The origin, accumulation and destruction of hydrocarbons is controlled primarily by temperature and time. Most hydrocarbons form at primarily by temperature and time. Most hydrocarbons form at subsurface temperatures ranging from 125 degrees F to 350 degrees F, equivalent to depths of 3,500 ft. to 20,000 ft. in a typical basin. High temperatures (greater than 350 degrees F), or long exposure to moderate temperatures will ultimately destroy oil yielding mainly graphite and methane. Eventually, even commercial accumulations of methane are absent. Each sedimentary basin has a characteristic hydrocarbon limit, beyond which drilling is futile. ECONOMICS OF DEEP DRILLING In 1973 there were 506 wells drilled deeper than 15,000 ft. at a cost of over half a billion dollars (Scott). The average deep well cost $1,107,000 compared with about $900,000 in 1972. Although deep drilling costs have increased rapidly in recent years, this has not always been so. From the early 1950's until about 1966 the average cost oscillated around $40 per foot, as shown in Figure 1. This was partly due to the remarkable improvements in drilling technology, particularly in the number of bits required for deep drilling. This decreased from a high of around 200 bits per well in the late 1940's to only 38 bits per well last year. Since 1966 improvements in drilling technology have not been sufficient to offset rising costs, and for the ultradeep wells below 20,000 ft., the cost rise has been particularly steep. Today six wells can be drilled to 15,000 ft. particularly steep. Today six wells can be drilled to 15,000 ft. for each well that is drilled to about 30,000 ft. as shown in Figure 2. There is no question that drilling in the 15,000 to 20,000 ft. range is justified. Last year 31% of the wildcats were successful, which is high by most standards. The real question is, how much deeper than 20,000 ft. can we drill profitably? From 1944 through 1958 the deepest production generally lagged behind the deepest well by about 3,000 ft. as shown in Figure 3. In 1959, this gap began to approach 5,000 ft. and this year it exceeded 8,000 ft.

This paper was prepared for the SPE-European Spring Meeting 1974 of the Society of Petroleum Engineers of AIME, held in Amsterdam, the Netherlands, May 29–30, 1974. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Netherland Section of the Society of Petroleum Engineers, P. O. Box 228, The Hague, the Netherlands. 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 Hydrocarbon-bearing formations in the Carpathian basin frequently experience a normal or hydrostatic fluid pressure. However, occasionally formations are encountered that are overpressured. Most reservoir rocks are situated between, or covered by, a tectonically relaxed overburden. The combination of either normal or overpressured reservoirs with a relaxed overburden causes a high potential hazard of lost circulation with subsequent blowout danger if the setting depth of the casing shoe is not properly determined. Formations crossed by an open-hole section should, under all circumstances, be prevented from being fractured by the pressure gradient in the borehole resulting from either the maximum backpressure produced during a killing operation or by the pressure inversion due to a shutdown following a kick. Graphical methods to determine the minimum setting depth of the protecting casing string which still offer a sufficient safety margin against calamities are described. Introduction The central part of the Carpathian basin in Hungary is composed of and filled up by, respectively, a series of sand, clay, and shale layers of Middle Pliocene and Lower Pliocene ages. The thickness of the Middle Pliocene formations varies from a few hundred meters to 2,500 m. In these tectonically relaxed formations, the pore pressure is, according to the experience gained with several thousands of exploratory and exploitation wells drilled up to now, always normal, i.e., hydrostatic. As demonstrated by cracks and craters formed at the surface as a result of a number of blowouts, for these relaxed, locally very thick sand-clay intervals of highly varying nature, the theory of Hubbert and Willis is basically valid. (1) Fractures induced by fluid pressure in holes drilled in these relaxed zones obtain, in general, a vertical direction. (2) The magnitude of the pressure that causes formation fracturing is, in general, smaller than the overburden pressure. (3) The value of the fracturing pressure gradient or its equivalent mud density is independent of depth. For these conditions, the setting depth of a protecting casing string in the Middle Pliocene formations should be determined very Pliocene formations should be determined very carefully.

This paper was prepared for the Second Midwest Oil and Gas Industry Symposium of the Society of Petroleum Engineers of AIME, to be held in Indianapolis, Ind., March 28–29, 1974. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Abstract Michigan's northern and newest oil play cuts across an area largely devoted to timber propagation and recreational activities. The wilderness and scenic attributes of the area are valuable assets for tourism and year-around recreation, the regions major industry. The freeway system has put the region within a few hours drive from the congested urban areas of southern Michigan, thus increasing the demands put upon public land usage. The development of oil and gas resources in northern Michigan, much of it on public lands highly valued for recreational activity, began at a time when environmental issues were coming to the fore. Concerns for the protection of the wild, or natural, conditions protection of the wild, or natural, conditions of this environmentally-sensitive region necessitated closer controls over well sites, access and product removal. Unfortunate oilfield mishaps further increased citizen and government concern. Zoning of certain areas against drilling is designed to protect waters, wildlife habitat and to preserve aesthetics. Michigan's basic law governing the development of oil and gas resources has been strengthened. Policies and concepts of public land use have been restated in terms of public land use have been restated in terms of best use and management of public lands. Added safeguards for environmental protection have not been detrimental to exploration and development of oil and gas resources in Michigan. Introduction Michigan's northern and newest oil- and gas exploration play cuts across an area largely devoted to timber propagation and recreational activities. The drilling activity extends in a band across the northern part of the Southern Peninsula where all the part of the Southern Peninsula where all the states oil and gas fields are located. This northern region has long been known for its scenic and recreational attributes, particularly the coastal parts of Lakes Huron and particularly the coastal parts of Lakes Huron and Michigan which at this time limit the east-west spread of oil exploration. In 1846 William Cullen Bryant, American poet and journalist wrote: "I spoke in one poet and journalist wrote: "I spoke in one of TV former letters of the manifest fate of mackinaw, which is to be a watering-place. I cannot see how it is to escape this destiny.

This paper was prepared for the SPE-European Spring Meeting 1974 of the Society of Petroleum Engineers of AIME, held in Amsterdam, the Netherlands, May 29–30, 1974. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Netherland Section of the Society of Petroleum Engineers, P. O. Box 228, The Hague, the Netherlands. 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 As an alternative concept to probabilistic approaches to problems of probabilistic approaches to problems of uncertainty the concept of credibility is described. This concept expresses uncertainty in degrees of belief or credibility a particular individual has in certain propositions. The rules for manipulation propositions. The rules for manipulation of credibilities are selective. Major emphasis in decision making is put on extreme outcomes of possible actions. The method is illustrated by reserve calculations, production forecasting and setting-up of cash-flows. Introduction The systematic and consistent treatment of decisions under uncertainty with help of probabilistic approaches became prominent in the early sixties. prominent in the early sixties. Especially the findings of Grayson and Kaufmann based upon more or less theoretical work can be considered the starting point of various investigations point of various investigations concerning the application of probabilities in the field of petroleum engineering Nevertheless the idea of using probabilities in this industry goes back probabilities in this industry goes back to the thirties and forties. Grayson drew attention towards drilling decision problems in which probabilities interpreted from a personalistic probabilities interpreted from a personalistic point of view can be applied. This view point of view can be applied. This view holds that probability measures the confidence a particular individual has in the truth of a particular proposition. Following this interpretation one can conclude that all probabilities are known to the person concerned. Holders of this view stress that it is the very nature of probability to deal with decisions under probability to deal with decisions under uncertainty. Probabilities which can be determined by measuring - the so-called objectivistic probabilities - are to be considered as knowledge, and decision problems in which these probabilities problems in which these probabilities can be applied are not decisions under uncertainty as long as repeatability is given. Personalistic probabilities are subjected to the concept of mathematical probability which is commonly ascribed probability which is commonly ascribed to Kolmogoroff.

Abstract For a number of years the oil and gas fields of West Texas have supplied Texas and the nation with large amounts of fossil fuel. In recent years the Texas Air Control Board has adopted regulations which directly affect the exploration, production, and processing of these energy sources. The purpose of this paper is to show how adopted air pollution control regulations affect the various pollution control regulations affect the various phases of development of these fuel sources phases of development of these fuel sources in this age where concern for both a clean environment and abundant energy supplies is paramount. paramount Introduction In 1967, the 60th Texas Legislature passed the Texas Clean Air Act. The stated purpose of the Act was to "…safeguard the air resources of the state from pollution by controlling or abating air pollution and, emissions of air contaminants, consistent with the protection of health, general welfare, and physical property of the people, including the esthetic enjoyment of the air resources by the people and the maintenance of adequate visibility." The Act establishes the Texas Air Control Board as the state air pollution control agency, and names the Board as the "principal authority in the state on matters relating to the quality of the air resources in the state and for setting standards, criteria, levels, and emission limits for air contaminants and pollution control." The Act also provides for an Executive Director to be administrator of air control activities for the Board. His responsibilities include any and all things necessary to achieve the purposes and objectives of the Act and to purposes and objectives of the Act and to provide general supervision over all personnel provide general supervision over all personnel employed by the Board. The Executive Director has established 12 Air Quality Control Regions in the state. Within each region the Executive Director has established a regional office at a convenient location. These regions and their corresponding regional offices are designated in Figure 1. The Regional Supervisor is responsible for the operations of the regional office as well as all air pollution control activities within his assigned region. In January 1972 a regional office of the Texas Air Control Board, Air Quality Control Region 6, was established in Odessa, Texas. From the time of establishment of the Odessa regional office it became apparent that the largest number of air pollution problems in the region were those directly related to the production and/or processing of oil and gas from the rich deposits in West Texas. This paper is concerned with the air pollution problems encountered by the oil and gas industry in West Texas, and how that industry might operate in compliance with the Regulations established by the Board.

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc. This paper was prepared for the 1974 Eastern Regional Meeting of the Society of Petroleum Engineers of AIME, to be held in Washington, D.C., Nov. 14–15, 1974. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the SPE magazines. Abstract The annual estimated curtailment of firm requirements for natural gas for 1974–1975 is 1.8 Tcf. Even if all pending LNG projects were approved today pending LNG projects were approved today they would bring in only 1.2 to 1.45 Tcf. The economic impact of new LNG imports are expected to be important as the exporting countries value their resources on its BTU content and will index natural gas to crude oil. A typical transmission company importing LNG may see its average selling price increase by a factor of 1.6 or more. Introduction Has the pendulum swung the other way? This may be the situation today in the LNG business; only two years ago at LNG 3, Washington, D.C., a euphoria prevailed about the bright future of LNG imports to the United States. Today, however, the U.S.A. is at the crossroads of whether or not large scale imports of LNG will materialize. Several major LNG contracts are in the process of being renegotiated. They are El Paso II, Easco, Panhandle Eastern Trunkline, Distrigas (Ben Franklin) and Pacific Lighting (Indonesia). These contracts were scheduled to deliver LNG as early as the spring of 1975. Background This paper will deal exclusively with the import of LNG to the United States from an overall point of view and will not examine in detail the effect of the numerous peakload shaving plants now existing or being constructed in the U.S.A. processing pipeline gas and storing LNG in one or more large scale storage tanks. In the opinion of the author, as long as pipeline gas will remain relatively inexpensive pipeline gas will remain relatively inexpensive in comparison to imported LNG, the public utilities as well as the transmission lines will continue to develop peakload shaving plant and storage facilities as a way of satisfying their winter load requirements. It is obvious that the effect of these facilities is to level the pipeline sendout between summer and winter time.

This paper was prepared for the Rocky Mountain Regional Meeting of the Society of Petroleum Engineers of AIME, to be held in Billings, Mont., May 15–16, 1974. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Abstract The Tiger Ridge and Bullhook Gas Units, located in north central Montana, have been on stream over one year producing natural gas from the Eagle Sandstone Formation at approximately 1300 feet. A review of both units' performance, including reservoir parameters, performance, including reservoir parameters, development programs, completion techniques, production history and problems, and economics, production history and problems, and economics, are explained within this paper. Explanations of the current state of reserve development and necessary future drilling programs are discussed. Introduction The Tricentrol United States, Inc. operated Tiger Ridge and Bullhook Gas Units are in Blaine and Hill Counties of north-central Montana. The area of interest lies south of Havre, Montana, and encompasses approximately 112,000 surface acres of unitized Eagle Sandstone formation in the two units as shown in Fig. 1. The Eagle gas sand is approximately 1300 feet deep and ranges in thickness from 5 feet to over 120 feet of net gas pay, with the average approximately 30 to 40 feet. The discovery well was the O'Neil 1–8 in the SE/NE of Section 1, T31N, R17E of Blaine County drilled during September, 1966. The well was drilled through the Eagle Sandstone at 1340 feet and found productive. This indicated the possibilities of commercial gas production in the area. production in the area. With the advent of a gas field, additional wildcat drilling began to prove the extent of the reservoir. By the spring of 1969, 75 wells were drilled testing the Eagle, both in the now existing unit boundaries and areas presently outside the boundaries. Negotiations presently outside the boundaries. Negotiations were under way to bring the gas to market with sales at a reasonable rate-of-take and a gas price to justify the large necessary price to justify the large necessary development program. The operator negotiated with one intrastate and two interstate markets and in May, 1969, a gas purchase contract was signed with Northern Natural Gas Company of Omaha. Nebraska. From May of 1969 to May of 1972, Tricentrol spent time preparing evidence, submitting testimony, and appearing at hearings with the Federal Power Commission in order that the gas could be sold to an interstate market.

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc. This paper was prepared for the 49th Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in Houston, Texas, Oct. 6–9, 1974. Permission to copy is restricted to an abstract of not more than 300 words. illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL paper is presented. Publication elsewhere after publication in the JOURNAL OF 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 discussions may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Abstract A study has been made of the flow behavior of fractured oil reservoirs produced by water displacement. A two-dimensional numerical model capable of simulating flow of water and oil in the matrix blocks as well as in the fractures has been developed. The validity of the model has been cheeked against data from a laboratory experiment involving a matrix-fracture system. Good agreement was observed between the laboratory and simulation results. By means of numerical simulation, the effects of production rate and fracture flow capacity on the production history and ultimate oil recovery of a fractured system have been evaluated. Results are presented for a single matrix-block system where the block is surrounded by horizontal and vertical fractures. Production rates ranging from 0.05 to 5 times Production rates ranging from 0.05 to 5 times the gravity reference rate of the matrix, and fracture flow capacities ranging from 0.1 to 10 times the flow capacity of the matrix are included in the investigation. At production rates much lower than the gravity reference rat the system behaves essentially as a nonfractured reservoir. It is also observed that for fracture flow capacities of the order of one-tenth of the matrix flow capacity, the effect of the fractures is negligible. At higher fracture flow capacities the water-oil ratio performance of the system becomes increasingly more sensitive to production rate. Water production starts much earlier with high fracture flow capacities and high production rates than it does from a nonfractured reservoir, and a large portion of the oil is produced at high water-oil portion of the oil is produced at high water-oil ratios. However, if the additional water can be handled economically, no oil is lost by high rate production. It is demonstrated that for a given fracture flow capacity, the producing water-oil ratio is a unique function of oil remaining in place and present producing rate. Thus, a reservoir can be produced at a high rate until the water-oil ratio becomes too high to handle. Then, reducing the rate causes the water-oil ratio to decrease to the value it would have had if all the oil had been produced at this lower rate. Introduction A significant number of petroleum reservoirs exist where discontinuities such as fractures or joints in the porous rock matrix are the main paths for transmitting fluids to the producing wells. In naturally fractured producing wells. In naturally fractured reservoirs, the matrix rock generally has a low permeability and one or more well-developed permeability and one or more well-developed fracture systems are present.

This paper was prepared for the SPE-European Spring Meeting 1974 of the Society of Petroleum Engineers of AIME, held in Amsterdam, the Netherlands, May 29–30, 1974. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Netherland Section of the Society of Petroleum Engineers, P. O. Box 228, The Hague, the Netherlands. 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. Only a few months ago our world felt the bite of an energy crisis, whose consequences we re still experiencing. However, the crisis did have the positive effect of encouraging reflection and activated many groups to speculation as to how man can solve the problems of the supply of energy on a long-term basis and economize with raw goods. In this chain of issues for study the distribution of oil and the short-term storage of petroleum products are vital links. The development in the petroleum industry everywhere in the world is towards an increased need for larger storage installations (distribution terminals and short-term storage facilities). Underground installations for liquid petroleum products have been in use in Sweden for more than 25 years and still function faultlessly. Today in Scandinavia there are more than 200 rock cavern installations for the storage of liquid petroleum products (light and heavy fuel oil for heating, engine fuel oil, gasoline, petrol and petroleum spirit, crude oil). In recent years storage facilities for fuel oil with capacities of up to 1 million m have been completed. For the principles of functioning of the underground storage cavern and historical aspects of the technical development you are referred to earlier papers (Morfeldt: Oslo, 1969, Pennsylvania and Stuttgart, 1972). Pennsylvania and Stuttgart, 1972). The move to supertankers and the increased construction of refineries in recent years have made large rock storage facilities for crude oil a current issue. In 1965 Shell decided to build its first underground facilities for the storage of crude oil on the Swedish west coast by the Koppartrans' refinery in Gothenburg. Here was built the world's largest underground crude oil stores of that time consisting of three rock-caverns with a total capacity of 180,000 m3. These facilities entered service in the beginning of 1967. Encouraged by this success Shell began in 1966 to build another underground storage facility for crude oil near Sola in Norway: two caverns with a capacity of 5 000 m3 each and two with 60,000 m3 capacity, 16 metres wide and 24 metres high. This installation was completed in September 1967.

This paper was prepared for the SPE-European Spring Meeting 1974 of the Society of Petroleum Engineers of AIME, held in Amsterdam, the Netherlands, May 29–30, 1974. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Netherland Section of the Society of Petroleum Engineers, P. O. Box 228, The Hague, the Netherlands. 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. Summary Deep drilling in Austria is restricted to the Vienna Basin where at present time depths of 6000 meters are attained. The gas pay zone slightly overpressured lies in the pay zone slightly overpressured lies in the Triassic "Hauptdolomit" at depths between 4800 - 6000 meters. After having drilled several deep wells we came to the conclusion that the following casing layout covers our demands: 18 5/8" - 100 m, 13 3/8" - 1350 m, 9 5/8" - 3600 m, 7" liner - 5600 m, 5" liner - 6000 m. H2S environment requires careful selection of the casing grades. High temperatures cause a considerable reduction of yield strength and excessive landing loads. The support of the cement sheath is neglected. Burst in casing design for intermediate casing strings is based on blowout conditions assuming that gas has displaced the drilling fluid in the lowest third section of the hole. To keep the casing load at the casing head within a reasonable range the first intermediate casing string is cemented to the surface and the cement top of the casing strings to follow should be at the depth of approximately 1200 meters. Close attention is given to the design of the cementing slurries and their proper displacement based on rheological calculations. Introduction Deep drilling in the Vienna Basin reaches depths of 6000 meters at present time. The first deep test has been drilled in 1966/1967 to a total depth of 6009 m and discovered a gas reservoir below 4800 m. For further gas exploration we complete as an average one deep well per year. Fig. 1 shows the geological situation of the Vienna Basin. The objective of our deep drilling is the Triassic "Hauptdolomit" within the Limestone Alps. From the surface to about 3000 m we drill through the Neogene, consisting of silty marly-clays, sands and sandstones. The remainder are conglomerates, breccias and organic limestones. The bottom of the Neogene basin - mainly Triassic dolomites - has a high relief of buried hills, formed by the downfaulted parts of the Alps. Further down there are parts of the Alps. Further down there are sections with varying thickness of Triassic Limestone and Upper Cretaceous formation, a mixture of sandstone conglomerate and shale. The slightly overpressured gas pay zone is tectonically trapped underneath the Cretaceous. After having drilled several deep wells we found by experience that the layout of casing strings showing in fig. 2 was near to the optimum.

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Abstract This paper explores several aspects of economic decision making in actual use by members of the petroleum industry, including cost of capital, measures of investment evaluation, required minimum rate of return, and risk-analysis methodology. Certain internal procedures utilized by the responding firms in procedures utilized by the responding firms in the application of the above mentioned measures are reported and compared. The contents of this paper have valid implications for a variety of audiences. This study illustrates how different petroleum executives are handling economic decision making and evaluates the state-of-the-art of the economic decision-making process in the petroleum industry. The results of this study petroleum industry. The results of this study can be used by firms to evaluate and possibly improve their own practices. This paper can make its greatest contribution to smaller firms in the industry who have not yet adequately developed their economic-analysis capabilities and, hence, are searching for procedures to improve their economic decision making. This paper is based on the responses to a four-page questionnaire that was mailed to the chief executive officers of 15 major companies in the petroleum industry; 12 companies responded. Introduction The opportunities for investment or capital outlays form the framework for a company's future development and are a major determinant of efficiency and competitive power. Consequently, a corporation's investment decisions have a profound effect upon its future earnings. profound effect upon its future earnings. Any business is continuously faced with the problem of making investment decisions. Even problem of making investment decisions. Even for the small business, the problem of reinvestment of earnings, expansion, or diversification is a continuing one. Investment opportunities usually are analyzed by various segments of the organization, but the final decision is the responsibility of top management. This situation points out the need for sound programs of evaluation. Management needs an objective means of measuring and comparing the economic worth of the individual investment proposals submitted by various divisions of the organization in order to have a realistic basis for choosing among them and selecting those that will make the greatest contribution to meeting corporate goals. In addition, using objective criteria and formal guidelines for processing of capital investment proposals allow some investment decisions to be proposals allow some investment decisions to be delegated to lower levels of management, economizing on top-management time.

This paper was prepared for the Rocky Mountain Regional Meeting of the Society of Petroleum Engineers of AIME, to be held in Billings, Montana, May 15–17, 1974. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Abstract Low fluid level wells constitute a large percentage of all the wells in the world. Stripper wells are more important today because of the higher price for their production. price for their production. Many types of production problems plague these wells. Because they take plague these wells. Because they take treating fluid on a vacuum resulting in short contact time or take excessive fluid, it is difficult to maintain production or to stimulate them. production or to stimulate them. A large number of chemicals have been developed to solve downhole problems but because of inadequate problems but because of inadequate placement techniques, have either been placement techniques, have either been relegated to failure or to a lesser degree of effectiveness than is expected. Placement problems have now been solved by a new retrievable fluid control valve which is more versatile than prior tools. This retrievable fluid control valve can permit the placement of chemicals down hole without pulling the tubing. the valve can be run and retrieved through the tubing on a wire line or dropped until it lands in the pump seat or a seating nipple placed in pump seat or a seating nipple placed in the tubing for that purpose. This tool can also be used with packers for multiple treatments, packers for multiple treatments, allowing the packers to be moved while the tubing is full of chemical. Accurate placement of a small volume of expensive placement of a small volume of expensive chemicals is possible because the unique design permits the valve to be wide open while pumping through it, however, the column of fluid will be supported when injection stops. A large number of field jobs with many different types of chemicals have proven its efficacy. proven its efficacy.

This paper was prepared for the Society of Petroleum Engineers of AIME Symposium on Formation Damage Control, to be held in New Orleans, La., Feb. 7–8, 1974. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon requested 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 Underbalanced perforating has been proposed as a method of improving perforating proposed as a method of improving perforating efficiency in gas wells. However, it has not proven to be an effective means of establishing unimpaired communication with geopressured Vicksburg gas reservoirs in South Texas. Lack of effective jet perforating guns in the small diameter sizes is the probable cause. Average skin factors and AP probable cause. Average skin factors and AP skins of 8.09 and 3352 psi respectively were determined on ten wells after perforating with an underbalance of 4700 psi. The results in South Texas emphasize the need for improved through-tubing perforating guns. Introduction Underbalanced perforating is the routine completion practice in geopressured gas reservoirs in South Texas. Within the last two years, ten wells have been drilled and completed in the Vicksburg formation at depths ranging from 11,200' to 12,700'. Reservoir pressures encountered in these completions varied from 9,570 psi to 11,390 psi with formation temperatures near 300 psi with formation temperatures near 300 degrees F. Bottom-hole pressure data and log analysis indicated very low permeability and porosity reservoirs. Permeability varied from porosity reservoirs. Permeability varied from 0.11 to 0.81 millidarcies with an average porosity of 16.1%. These wells were all porosity of 16.1%. These wells were all perforated in an underbalanced condition perforated in an underbalanced condition with the tree installed to reduce the potential hazardous conditions existing when potential hazardous conditions existing when perforating high-pressured gas wells with a perforating high-pressured gas wells with a large casing gun and no tubing in the well. During perforating an average underbalance of 4700 psi was obtained. Completion Technique Procedures and production equipment used in completing these geopressured wells were developed to aid in optimizing limited entry or modified limited entry stimulation treatments. Table 1 presents physical characteristics of the wells prior to perforating. It is noted that both oil base perforating. It is noted that both oil base and water base drilling muds were used in the drilling of these wells. Prior to perforating, either fresh water or calcium chloride water was circulated to the completion interval to provide a hydrostatic underbalance for perforating. Figure 1 presents a typical perforating. Figure 1 presents a typical log section and completion detail. Perforating was conducted with a selective fire, 1-9/16" carrier shaped charge perforating gun equipped with premium charges.

ABSTRACT A dynamic-positioning (DP) system can be designed to stabilize and damp the motions of a vessel when moored as well as unmoored. The vessel motion dynamic characteristics are generally significantly different when the vessel is moored as opposed to unmoored and may Vary over a wide range with changes in depth, scope, pretension, mooring pattern, and offset. In the paper, a design process is described whereby the DP controller parameters and their fictionalizations are derived for smooth stable response through the operating regime of the moored vessel. Field results from a North Sea operating drill ship are compared with predicted results, and the problems that were encountered are discussed. An augmentation scheme is presented by which the DP system will automatically back up and reinforce the holding capability of the mooring system under varying weather conditions and yet remain quiescent in calm weather. A mooring system may be deployed to extend the holding capability of a dynamically-positioned offshore drilling rig in shallow and intermediate water depths when heavy seas are predicted and vice versa. When the DP system is augmenting the mooring system, the DP system improves the damping of the moored ship in addition to increasing its holding capability, and minimizes the time required to deploy and adjust the anchor system by keeping station. For the worldwide operating offshore drilling or pipe laying rig, the combined DP and mooring systems offer unmatched flexibility and redundancy by extending the operating water depth of the rig yet providing low power requirements and operating costs in shallow water. INTRODUCTION Considerable discussion has been given to both mooring and dynamic positioning (DP) systems for offshore floating vessels.l, 2,3,4 However, generally speaking, in each case the discussions were limited to one system or the other at a time. This paper considers the combination of the two systems on one vessel and the manner in which the DP system can assist the mooring system. The paper begins with a brief review of the sizing and dynamic characteristics of a mooring system. This review establishes the range of mooring system parameters which must be accounted for in the design of the DP system for effective assistance to the mooring system. Then, a design process for the DP controller is given which allows the DP system to effectively augment the mooring system in a stable fashion in all operating regimes of the mooring system. Throughout these discussions, actual data recorded on the drill ship SAIPEM Due is used to amplify points of interest and connect theoretical with actual results. The data was collected off the coast of Italy in February 1973 and in the North Sea in Norwegian waters in May 1973. A description of the SAIPEM Due and its dynamic positioning and mooring system is given in Table I. Before reaching the final conclusions, the paper contains a section describing less obvious benefits in using the DP system with a mooring system.

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc. This paper was prepared for the 49th Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in Houston, Texas, Oct. 6–9, 1974. Permission to copy is restricted to an abstract of not more than 300 words. illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL paper is presented. Publication elsewhere after publication in the JOURNAL OF 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 discussions may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Abstract The paper discusses the various aspects of engineering economy studies, including the meaning and significance of the interest rate used for discounting and the purposes of and differences between studies at project level and corporate level. The most common indices for project evaluation, discounted cash flow rate of project evaluation, discounted cash flow rate of return (DCFRR), present worth (PW), and uniform annual cost (UAC), as well as several-dual investment methods, are examined conceptually (rather than mathematically) and in example. The conclusions drawn are (1) methods applicable to project optimization studies generally are not applicable to corporate optimization studies; (2) for studies at project level, DCFRR, PW, and UAC do as good a job as can be expected from any index; (3) various methods that explicitly consider reinvestment add nothing useful to project analysis and fail to consider certain factors essential in corporate optimization studies; and (4) the standard techniques, particularly DCFRR, have suffered from considerable unjust and incorrect criticism. Introduction An investment, to be justified, must generate sufficient revenue to cover expenses, taxes, recovery of capital, and a reasonable return It is the purpose of an economy study to estimate how well each proposal does this. An economy study of a prospect involves three phases of investigation.Initial screening: This is a determination of whether or not the venture meets minimum profit requirements. Those that fail to meet this requirement are rejected; those that meet or exceed it are examined further.Comparison: The purposes of this segment of the study are to (1) compare various proposals for doing the same job (mutually proposals for doing the same job (mutually exclusive alternatives) and select the most profitable, or least costly, and (2) compare profitable, or least costly, and (2) compare accepted projects and develop an initial order of desirability to establish the priority for funds (budget optimization).Placement: This phase considers projects in the light of their over-all impact projects in the light of their over-all impact on financial structure and their position with respect to corporate goals. The placement establishes the order of preference among acceptable investments. Screening and comparison concern themselves mainly with project optimization and are a design or department-level function.

Abstract This paper discusses the importance of obtaining a good cement job in well completions, and the three areas vital to obtaining this effective wellbore cement seal. These three areas are (1) formation cement interface (2) casing cement interface, and (3) the cement sheath itself. An operator is interested in getting best cement job possible for several reasons:shut off and/or protect fresh and salt-water zones,segregate producing zones,eliminate communication between gas-oil, oil-water, or gas-water contacts,stabilize the casing string, andseal well fluids in wellbore to prevent surface or subsurface pollution. prevent surface or subsurface pollution. The steps involved in obtaining a good wellbore seal are (1) good borehole conditions, (2) good wellbore cleanup prior to cementing, (3) removal of excess filter cake from permeable formations, (4) selection of correct cement composition for given well conditions, (5) proper centralization of the well casing, and proper centralization of the well casing, and (6) preparation of the external casing surface for maximum cement bonding. Several field case histories are presented to show the effectiveness of proper cementing practices, particularly the effectiveness of practices, particularly the effectiveness of resin-sand coating of the casing in producing an extremely strong bond between cement and casing. The application of the Cement Bond Log for evaluation of the final cement job is also presented. The paper concludes that potential presented. The paper concludes that potential problems of fluid leakage and their consequences problems of fluid leakage and their consequences can be minimized by the proper use of known technology. Introduction The cementing of oil, gas, gas storage, injection, and disposal wells throughout the industry has received a great amount of attention over the past 50 years in both research and field development areas. This attention and research is continuing. Probably no other aspect of the completion operation has been as widely studied and discussed. Yet, cementing problems continue. Partially, this is due to problems continue. Partially, this is due to the complexity of the problem, but unfortunately, it is also partly due to failure to properly apply known technology. The cementing operation is designed to (1) shut off and/or protect fresh and saltwater zones, (2) segregate producing zones, (3) eliminate communication between gas-oil, oil-water, or gas-water contacts, (4) stabilize the casing string, and (5) seal well fluids in the wellbore to prevent environmental contamination.

Discussion of this paper is invited. Three copied of any discussion should be sent to the Netherland Section of the Society of Petroleum Engineers, P.O. Box 228, The Hague, the Netherlands. Such discussion may be presented P.O. Box 228, The Hague, the Netherlands. 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 Laboratory investigation has been made of a novel approach designed to improve the displacement efficiency of a waterflood. This approach consists of injecting a slurry of finely divided solid particles in water, at a linear advance rates of 3 to 20 ft./day, into 4 to 6-darcy unconsolidated sandpacks saturated with oil and water. The solids used in the slurry preparation are oleophilic coke particles and hydrophilic fluorite particles, in concentrations ranging from particles, in concentrations ranging from 0.02 to 1.2 gm/liter. The sand used in the preparation of sandpacks is rendered either preparation of sandpacks is rendered either strongly oil-wet by prolonged contact with oil containing N-octylamine or strongly water-wet by prolonged contact with water containing a water-soluble surfactant, Orvus-K. The data presented in this paper show that the addition of coke particles to floodwater results in enhanced oil recovery which is associated with lowered water-oil ratio production in both the oil-wet and the water-wet sandpacks. The increment in oil recovery over the conventional waterflood, generally of the order of 2 to 107, P.V., is directly proportional to the P.V., is directly proportional to the initial oil saturation in the sandpack and to the slurry concentration up to a maximum concentration value. In comparison, the addition of fluorite particles to floodwater does not result in enhanced oil recovery from either the oil-wet or the water-wet sandpack. The enhancement may be explained by the principle of preferential wettability exchange - a principle used in the benefaction of a mineral from its associated waste matter in the froth flotation process of mineral dressing. It is shown that mechanical drag does not play any significant role toward the enhancement of oil recovery. Introduction Primary oil recovery from an oil field depends upon the type and magnitude of the expulsive forces, the permeability of the reservoir rock, the viscosity of the reservoir oil, and to some degree upon the field exploitation. These factors vary not only from field to field but may also vary within a field.

ABSTRACT The United states Coast Guard through the efforts of Lockheed Missiles & Space. ComplarJ1L Inc., Sunnyvale, California, has developed and tested a device for recovering spilled oil from the high seas. This paper discusses the qualification, testing of the Lockheed prototype High Seas Oil Recovery System. These tests were:an inland pool test using oila high seas test in an operational environment (Sea State 4)a high seas test in a survival environment (Sea State 6) The tests proved the system capable of being transported in an HC-130B Coast Guard aircraft, buoy tender and by truck over the road. The system (one unit) also proved to be capable of recovering oil up to the rate of 1000 gpm under certain conditions of current, oil thickness and viscosity. The system proved that it will be capable of surviving a severe sea state condition after certain minor redesign. INTRODUCTION The United States Coast Guard developed through the efforts of Lockheed Missals & Space Company, Inc., Sunnyvale, California, a prototype High Seas Oil Recovery System unit based on Lockheed-patented rotating disc-drum principle. The unit is capable of recovering up to 1000 gpm oil under certain conditions of thickness of oil, relative current and oil viscosity. A considerable amount of information has been presented on the Lockheed-developed High Seas Oil Recovery System. Much of the prototype design and actual structure of the system is well known within the industry through prior publications in scientific and trade journals. In 1972 and 1973, Coast Guard authors Commanders Lehr and Leigh, and Lockheed author Bruch, presented technical papers which amply described the disc-drum principle. However, a brief description of the rough water oil recovery machine is in order at this point. The 14,750-1b machine is 27-ft wide and 23-ft long. It is 8-ft high, draws 20-in water, and with the main deck safety rails, presents an excellent radar and visual target. The 4-ft digester disc-drum oil recovery device is 13-ft long. It is suspended between twin machinery hulls, port and starboard (PiS), that are connected by the rigid cross structure over the disc-drum. The diesel prime mover and starting air bottle are in the cross structure. The oil recovery rate is dependent upon the rotating discs which are preferentially wet by the oil which is then collected from the discs by wipers. Wipers direct the oil onto an axially aligned trough through which it flows into the PIS hull sumps. From the sumps the oil is pumped through 300-ft of la-in diameter, lightweight transfer hose to a manifold on the tender. It goes to available storage from the manifold. Alternately, the manifold can be attached to the unit and two 6-in hoses used to transfer the oil directly to available storage. The unit is designed for remote control through a 300-ft long umbilical that also serves as a refueling hose for the on-board diesel prime mover.