Large Amount Of Oil Research Articles

Principles of attaining ultra-low interfacial tension: The role of hydrophile—lipophile-balance of surfactant at oil/water interface

The interfacial tension between water and surfactant, phases becomes very small with increasing mutual solubility, and finally disappears below the lower critical temperature at which surfactant disperses as micelles; namely, the interfacial tension between water and micelle is zero. In a surfactant solution in which a large amount of oil is solubilized, the interfacial tension between the swollen micelle and water is also zero at the critical temperature. In such a solution the interfacial tension between excess oil and water with adsorbed surfactant at the interface is small, and descreases further when the conditions of the system allow for a larger solubilization or swelling of oil, i.e., when the hydrophile—lipophile property of a given surfactant just balances at a given oil—water interface. Similar phenomena as a function of salt or alcohol concentration, rather than of temperature, were observed in solutions of ionic surfactants. The influence of the hydrocarbon chain length of oils, the concentration of salts in water, the temperature, etc. in attaining a minimum interfacial tension for a given surfactant are understood as the effects of these factors on the HLB of the surfactant at the interface. Thus, the conditions to attain minimum interfacial tension at an oil—water interface are clarified logically. The selection of hydrophile—lipophile balanced surfactants for a given oil—water system and the use of longer hydrocarbon chain compounds among the balanced surfactants seem the most important factors in attaining very small interfacial tension.

Primary migration theory of petroleum and its application to petroleum exploration

Current concepts of oil and gas generation by thermal decomposition of kerogen are reviewed. Primary oil migration mechanisms requiring large quantities of water to serve as a carrier for the movement of oil from source rock to reservoir are discussed. Previous investigators regarded the expulsion of interlayer water from montmorillonite and montmorillonite-illite mixed-layer minerals by transformation during diagenesis as the most important source of the carrier water. The process of diagenesis is subdivided into three stages based on the results of experimental compaction studies on montmorillonite clay, on studies of the expulsion mechanism of interlayer and interstitial waters, and on the observed changes in pores and mineral grains in argillaceous sediments during these stages. As a result, we concluded that the migration of oil chiefly occurs during the late compaction stage when the sediment's porosity ranges from 30 to 10%. This conclusion implies that a large amount of oil can move during the period when the active generation of oil corresponds with the primary migration of carrier water. For instance, in the oil-bearing Miocene sediments of the Akita area of northern Japan, the oil generation temperature ranged from 100 to 150°C and the average migration depth was between 1300 and 2600 m. Therefore, the possibility of large oil pool formation will be high in the basin where the paleo-geothermal gradient is about 5.0°C/100 m. In fact, it is expected that the paleo-geothermal gradients in the vicinities of large oil fields will be very close to this value. Prediction of the type and amount of hydrocarbons in the exploration area will be possible by an examination of the paleo-geothermal gradient in the area and by a study of the relation between absolute porosity and burial depth of argillaceous rocks.

Analysis of Electrification Alternatives to Oil Fueled Low Pressure Boilers in the Commercial Sector

Large amounts of oil are consumed by low pressure utility boilers that supply steam for commercial space heat, hot water and air conditioning requirements. The historical advantages of this type of utility system includes moderate capital costs. significantly lower cost of the residual oil that can be burned in these facilities relative to lighter heating oils and capability to centralize utility operations. However, large changes in energy costs, fuel availabilities and overall energy policy objectives dictate a reevaluation of these systems relative to the alternatives. These alternatives include electric heat because of potential of substituting nuclear or coal for oil or else cogeneration because of the potential of rejecting less heat and thus saving oil by utilizing oil more efficiently. Each of these alternatives also has a range of equipment type and sizing options.

Solution behavior of aerosol ot/water/oil system

The phase diagrams of water-cyclohexane containing 5, 10, and 20 wt% sodium 1,2-bis(2-ethylhexyloxycarbonyl)-1-ethanesulfonate (Aerosol OT, AOT) as a function of temperature were studied. There is the water phase in which AOT is dissolved and a large amount of oil is solubilized at higher temperature, and the oil phase in which AOT is dissolved and a large amount of water is solubilized at lower temperature. It is evident from the phase behavior that the hydrophile-lipophile property of AOT is well balanced. Accordingly, the phase diagram and properties of AOT solution are affected rather sensitively by the addition of a small amount of hydrophilic or lipophilic additive or by temperature. Careful elimination of inorganic salts also influences markedly the solution properties of AOT. Thus, the addition or removal of known amounts of inorganic salts, such as Na 2SO 4 is also very important to control the solution properties related to practical applications. In this context phase diagrams of both carefully purified and commercial AOT with or without additives have been determined.

Microbial release of oil from soil columns

When large quantities of oil are spilled on land, the pollutant penetrates the underlying soil layers and eventually forms an oil lens on top of the ground-water table. Fluctuations of the ground-water table result in a smearing out of the oil over a large volume of subsurface soil. In contrast to the oil adsorbed in the A-horizons, the oil thus retained in the underlying horizons only degrades slowly and, furthermore, only partially. However, percolating rainwater and migrating groundwater gradually leach out in the oil components and their breakdown products. Since parts per million levels of oil products suffice to make water undrinkable, it is clear that a subsurface oil lens can pollute large volumes of ground water for years and even decades. The possibility of cleaning up subsurface soil horizons polluted with gas oil by activating microbial processes has been investigated. The results obtained from the laboratory studies indicate that by irrigating the soil with a nutrient solution containing ammonium nitrate and peptone, 10 to 20% of the oil adsorbed in the soil can be recovered in a period of 3 to 4 mo. The release process is biological. The recovered oil is not emulsified and can be recuperated asmore » a phase. 10 references.« less

Geology of Gu-Dao Oil Field and Adjacent Areas: ABSTRACT

Gu-Dao oil field is located geologically in the center of Zhan-Hua basin, Bohai Bay hydrocarbon-bearing province, and geographically in the coastal zone of the lower Yellow River valley. Zhan-Hua basin is a Cenozoic block-faulted basin, with an area of 2,100 sq km. The intensive subsidence of the faulted blocks was followed by deposition of thick Tertiary continental strata (the Eocene series itself is as thick as 4,500 m), at a sedimentation rate of 0.127 mm/year. The strong block faulting in the basin led to the formation of buried Paleozoic hills, which controlled many overlapping Tertiary structures. Almost 90 of the known oil reservoirs are in these structures. Gu-Dao oil field produces from one of the late Tertiary overlapping structures which is cut along the north and south side by two faults striking nearly east-west. These faults controlled the origin and the development of the comparatively intact structure. A long period of faulting caused vertical migration of large quantities of oil and gas, and the formation of a series of multiple pays. The hydrocarbons are distinctly zoned. That is, in the Paleozoic and lower Tertiary rocks, they are high-paraffin crude oil of high wax and low sulfur content. The upper Tertiary rocks contain highly viscous aromatic-cycle alkane crude oil of low wax, high sulfur content, and dry gas occurs in the upper part of the Neogene and Quaternary. The analysis of the data shows that hydrocarbons are derived from the same source rock--the lacustrine lower Tertiary Sha-He-Jie formation--distributed in the depression surrounding the Gu-Dao structure. A secondary reservoir was formed along the faults during the multiple tectonic movement during the late Tertiary, as a result of the upward migration of hydrocarbons from lower Tertiary rocks. Hence the Gu-Dao oil field is a combination of both primary and secondary reservoirs. The main oil-bearing formation in the Gu-Dao oil field, the upper Tertiary Guan-Tao formation, comprises a set of fluvial deposits, with channel sand bodies as the principal reservoirs. The reservoir extends along the long axis of the Gu-Dao structure, and constitutes the major producing area. The oil field was discovered in 1968 and full production was begun in 1971. The development policy of water flooding at an early stage, either internally, separately, or quantitatively, was adopted according to reservoir characteristics of high viscosity, sand-out, or differences in pays. A series of measures has been taken to control sand and to reduce viscosity. Although 7 years have elapsed since the beginning of production, present oil production per well is equivalent to that of the early stage, a rising trend in productivity is obvious, and good development effects are insured. End_of_Article - Last_Page 698------------

Hydrodynamic Problems in Oil-Spill Control And Removal

The theoretical performance of equipment for the control and removal of oil spills is considered. Mathematical models of oil-spill recovery devices are developed that may be used in evaluating equipment or in simulating the operation of an oil-spill response system. Introduction Oil spills involve a bewildering number of hydrodynamic problems. The oil-water system is so complex, particularly problems. The oil-water system is so complex, particularly when substantial wave motion is involved, that it has been difficult even to identify the essential problems in a useful way. This paper considers some fluid-mechanics problems that have, or might be expected to have, important effects on oil-spill control and removal. The purpose is to develop background information that will assist in the evaluation of oil-spill-control equipment needs, and that should be of value when planning an oil-spill response system. Mathematical models for oil volume collection rates in calm water of several types of skimmers are presented. "Calm" water refers to situations that have a frame of reference in which events are steady in time. Each class of skimmer is considered in a general way, and results are applicable (when suitably adapted) to individual designs in the class. Specifically treated are (1) weir skimmers, with and without pumps for maintaining an inflow water current, (2) rotating disk skimmers, and (3) endless oleophilic-belt skimmers. Attention is directed to the role of oil-layer instabilities as a cause of performance failure in some skimmers. Detailed theoretical performance curves may be calculated from the models presented (or from the more complete ones from which the present material is abstracted), but this is not the objective here. The intention throughout the paper is to educe effects and to seek parametric trends. Oil-spill removal and control in open water is seldom conducted in calm conditions, so the effects of waves and turbulence on the performance of oil-spill equipment must be faced. These effects are readily apparent but are difficult to model theoretically. In cases where performance trends strongly depend on a critical water performance trends strongly depend on a critical water velocity, such as entrainment failure in booms, calm-water results may be generalized to include wave orbital speeds. Such quasi-steady adaptations of calm-water results are potentially of realistic value only if the acceleration potentially of realistic value only if the acceleration effects associated with the waves are relatively unimportant. In addition to wave orbital speed and acceleration effects on skimming action, a number of other effects of waves and water turbulence play a role. Some of these effects are discussed in the second part of this paper. The specific questions dealt with follow.The combined action of wave breaking and turbulence can cause floating oil films to disintegrate and become mixed into the water column as droplets. The extent and importance of mixing depends on oil type and the vigor of turbulence and wave breaking. Once large amounts of oil are removed from the surface by natural means, containment and cleanup operations are pointless. This question was studied in Ref. 1 and is reviewed here.Reflections and focusing of short waves are striking occurrences in containment booms; these effects are analyzed in this paper. Enhanced turbulence in the containment region can occur due to wave breaking, which can lead to loss of oil into the water column. JPT P. 311

Petroleum Potential and Stratigraphy of Pedregosa Basin: Comparison with Permian and Orogrande Basins

On the basis of stratigraphic similarity to the Permian basin of western Texas and southeastern New Mexico, the Paleozoic rocks of the Pedregosa basin, southwestern New Mexico, southeastern Arizona, and northern Mexico could yield large quantities of oil and gas. In addition, significant quantities of oil and gas may be produced from the Mesozoic rocks of the Pedregosa area. Because of the potential, this area, as well as the Orogrande basin of south-central New Mexico, deserves continued exploration. In the Pedregosa basin, major reservoir objectives include the Ordovician El Paso (= Ellenburger) and Montoya carbonate rocks, Silurian Fusselman dolomites, Pennsylvanian to Permian shelf and reef carbonate rocks and basin-fill sandstones, and Lower Cretaceous shelf limestones and sandstones. Important source units of petroleum include the Devonian Percha (= Woodford) shales, Mississippian to Permian basin limestones and shales, Jurassic shales, and Lower Cretaceous limestones. In contrast to the Permian basin, the Pedregosa area lies within the structurally complex Basin and Range province and has been subjected to intense tectonism and igneous activity from Laramide time onward. Around the few plutonic intrusive masses the sedimentary section has been metamorphosed, but most zones of alteration extend less than a few feet around the hypabyssal intrusive masses (volcanic necks, dikes, and sills). In spite of the local igneous activity and tectonism, large quantities of petroleum, which probably were generated and collected prior to Laramide time, should be preserved in the Pedregosa basin.

Sino-Soviet Relations and the Politics of Oil

CHINA, WHICH WAS once dependent on Soviet oil supplies, is being transformed into a regional oil power in East Asia and it is becoming a successful rival of the Soviet Union in the game of Asian oil politics. Soviet economic warfare encouraged the Chinese drive toward oil self-sufficiency and China emerged as a crucial factor affecting Japanese and American negotiations with the Soviet Union on Siberian oil development. China has strategic objections to the construction of the Tiumen oil pipeline close to its own border and its increasing sales of oil to Japan have been aimed at deterring Tokyo's involvement in any Siberian oil investment deal. While China's oil exports to Japan and other Asian states are rising, the Soviet Union is confronted with a growing oil squeeze due to its huge oil export commitments to East European states. Oil sales to non-communist states even declined in 1974 and, during the next decade, the Soviet Union's ability to be a major competitive force in Asian oil markets will be seriously strained. An evaluation of the dynamics of East Asian oil politics hinges on the responses to several crucial questions. Why has Japan decided to buy large quantities of oil from China and only small amounts from the Soviet Union? To what extent will China be able to expand its oil export capability? What strategic role does oil play in the power adversary relationship between the Soviet Union and China? How do American policies toward the major East Asian states affect the course of Sino-Soviet oil politics? The answers to these questions are essential to an understanding of superpower oil relations in East Asia and could also provide some insight into the prospects for peace in the area. The Soviet Union supplied small quantities of oil products to China before the 1949 communist takeover but large-scale deliveries were initiated shortly thereafter. China soon became the largest recipient of Soviet crude oil and oil products. It bought mostly oil products, rather than crude, because of its limited refinery capacity. Soviet sales

In-Situ Acid Neutralization System Solves Facility Upset Problems

Introduction Much of the world's crude oil is produced as emulsions that must be treated (demulsified) to be marketed. Normally, these emulsions can be readily broken by the addition of small amounts of demulsification chemicals, retention time, and, if necessary, heat. However, the oil produced from wells after an acid stimulation can be extremely difficult to treat, even with heat and large additions of treating chemicals. Poor demulsification can result in curtailed production, wet oil at the sales point, and large amounts of oil in the effluent water.There appear to be three basic reasons why emulsions from acid returns are more difficult to treat than normal production.1. Crude oils often contain organic acids and bases. Neutralization of these acids and bases can result in surface-active compounds that will lower the oil/water interfacial tension. With a lower oil/ water interfacial tension, the stable size of the dispersed droplet in the emulsion is much finer at any fixed agitation and thus more difficult than normal to demulsify. Fig. 1 shows the lowering of the oil/ water interfacial tension for an East Bay, La., crude in both the acid and the base.2. Acid media tend to result in adsorbed organic films at the oil/water interface. These films (generally asphaltenes and resins) act as physical barriers to the coalescence of the dispersed droplets. The strength of the films is increased at lower pH's.3. Acid can alter the wettability of loosened formation fines so that the new oil-wetted solids stabilize the emulsion. Like film strength, the apparent oil wetting is increased at lower pH's.We have developed a method to avoid these emulsion upset problems by controlling the pH of the return fluids. Acid Spending System and Design A technique has been developed to neutralize acid in situ. The system, designed to avoid both pH extremes of the returning acid treatments, consists of adding the diamide urea and an amide, such as acetamide or dimethyl formamide, to the acid. JPT P. 1153

The Santa Barbara oil spill Part 1: Initial quantities and distribution of pollutant crude oil

The quantity of oil which came ashore during the early stages of the Santa Barbara oil spill has been estimated from intertidal oil samples and aeirial photographs. These methods indicate that 4500 metric tons of crude oil were deposited on nearly 90 km of coast by 8 February 1969, 11 days after the spill began. Dosages in the intertidal zone varied from 2·7 to 118·1 metric tons/km. These dosage estimates suggest that the flow rate at the well was around 5000 barrels (726 metric tons)/day during the early stages of the spill. A large quantity of oil was held for varying periods of time in the surface canopies of offshore kelp beds. The interaction of wind, wave action, tides, and substrate determined the pattern of oil distribution within the intertidal zone.

SEISMIC STRATIGRAPHIC EXPLORATION PART II

Past seismic stratigraphic exploration capabilities, which found large amounts of oil with crude tools from 1938 to 1962, are illustrated with three additional case histories covering a contribution to the discovery of the only super‐giant reef‐type oil field in the United States, the discovery of a thin sand pinchout reservoir along a strand line, and an exploration method for the delineation of a barrier reef complex and the overlying compaction fold complex. Present and future seismic stratigraphic exploration capabilities will be presented in Part III in the August, 1971 issue of Geophysics.

SEISMIC STRATIGRAPHIC EXPLORATION—PART I

The basic problem to be solved in stratigraphic exploration always has been the same—how to develop and use practical techniques which have the capability of finding large stratigraphic oil reserves at a profit. If the petroleum industry in the United States is going to discover in domestic areas the huge reserves which are obviously required for the future, seismic stratigraphic exploration will have to be accepted by the industry and play a major role in the discovery. Seismic stratigraphic exploration must, therefore, be described in such a way that management can visualize it as practical and potentially profitable with proven past accomplishments, with important new capability not yet in application, and with significant future potential. Past seismic stratigraphic exploration capabilities, which found large amounts of oil with crude tools from 1938 to 1962, are illustrated with three case histories covering the probable direct detection of a hydrocarbon‐saturated sand, the discovery of saturated lenticular sands over the area of a tilted out ancestral structure, and the delineation of a flank type stratigraphic trap. Three additional case histories will be presented in Part II in the next issue of Geophysics.

Caustic Slug Injection in the Singleton Field

The watered-out portion of this field in Nebraska appeared to be a good candidate for injection with NaOH. The results of the pilot program have been disappointing, however, probably because of poor sweep efficiency and because of deterioration of the caustic slug. Introduction Waterflooding is still the most widely used of all secondary oil recovery processes. Unfortunately, oil recovery by waterflooding is far from complete because of two inherent limitations: no matter how much water may be passed through a reservoir, some quantity of residual oil remains in the pores that have been swept by the injected water; and economic considerations require that waterflooding be terminated when the produced WOR exceeds some critical limit, even through portions of the reservoir may not yet have been swept. Mungan showed that, at breakthrough, oil recovery from oil-wet cores is always less than from water-wet cores and that, after breakthrough, large quantities of oil are produced, accompanied by a high WOR. Leach et al. and Mungan showed that in some cases the oil recovery can be made more efficient by changing the pH of the injected water. We shall discuss here a laboratory study of oil recovery efficiency in synthetic cores using Singleton crude and water of pH ranging from 3.5 to 12.5, and the field trial based on the laboratory findings. Laboratory Study Most of the displacement studies were performed in flow tubes packed with unconsolidated Ottawa sand. Each tube had a cylindrical section 2.062 in. ID and 30 in. long, and was made of monel metal. The inlet flange had a straight face, two entry ports, and the usual fluid distribution grooves. The outlet flange, however, was bored in the shape of a funnel, which was packed with silica flour consisting of a mixture of 325- and 400-mesh powder. This effectively eliminated capillary end effects. The tubes were packed with a sand having a broad particle-size distribution. Experience has shown that if the sand is well sorted in particle size, the resulting unconsolidated pack gives waterflood residual oil saturations that are unreasonably low, ranging from 10 to 15 percent pore volume (PV). A commercially available sand mixture, American Graded Sand Co. AGSCO No. 16 sand, was used to pack the tubes and gave waterflood residuals of about 30 percent PV. The particle-size distribution of this sand is given in Table 1. Much care was devoted to cleaning the sand, and a technique involving no vibration was developed to eliminate segregation of grains of different sizes during packing. Random cores from several packs indicated the porosity and permeability to be uniform. Displacement experiments permeability to be uniform. Displacement experiments were also performed in two 10-ft-long, 4-in.-diameter Berea cores. Formation sensitivity studies were made with small cores from the Singleton field. These cores had been handled and stored in a conventional manner, with no precautions taken to keep them fresh or in their native equilibrium state. The refined oil used - Klearol* - was purified using procedures described elsewhere. JPT P. 1569

Aspects of Deep Drilling in The Carpathian Basin

Presented here are some experiences regarding oilwell drilling activity in Presented here are some experiences regarding oilwell drilling activity in Hungary, with reference to improved jet-bit drilling techniques, jet-bit design, drilling hydraulics, drilling control and blowout preventer systems for very high-temperature, high-pressure formations. Introduction In Hungary an especially large program of oilwell drilling has been realized in the past 10 years. As a result of certain geological and geothermal conditions prevailing in the Carpathian Basin, valuable prevailing in the Carpathian Basin, valuable experience has been gained in the field of drilling technology. Those conditions arethe occurrence of strata composed of unconsolidated young Upper Pliocene sand and plastic clay that locally are over 2,000 m thick, andanomalous formation pressure and formation temperature values that have been recorded below 2,000 m. Some of the more important achievements in the field of rotary drilling in Hungary over the past 30 years have involved increasing the speed of drilling and preventing blowouts. Drilling rates have been increased in much the same way throughout the world; i.e., drilling hydraulics have been developed, at first unsystematically, then on a carefully planned basis, until an optimum value is reached; simultaneously more weight has been p I laced on the bit and the rotary speed has been raised to reach a level of "power drilling". Increasing the average hole depth, as well as drilling deeper and deeper holes, raised problems of drilling safely and rapidly through high-pressure formations as well as of preventing blowouts. In the course of solving these, the possibility arose of performing underbalanced drilling, which could enable the drilling of very deep holes faster and at lower cost than ever before. Some factors leading to the need for blowout preventers are that thick and unconsolidated strata under preventers are that thick and unconsolidated strata under tensile stress tend to fracture vertically, and that at depths of about 2,000 m they are exposed locally to overburden pressures on the order of 50 to 60 percent of normal formation pressures; in addition, they percent of normal formation pressures; in addition, they exhibit relatively extreme temperature values. These factors demand a state of balance, at medium depth, between formation pressure and circulating-mud pressure. This could be achieved only with the help of pressure. This could be achieved only with the help of controlling devices, and steps have been taken to re-establish the state of balance that was lost. Oil and Gas Well Drilling Activities in Hungary Compared with its areal extent, which is less than 100,000 sq km, a relatively large amount of oil- and gas-well drilling now is taking place in Hungary (Fig. 1). The resulting hole network, expressed in m/sq km, is equally remarkable. This has been achieved through the use of the jet bit (introduced in 1951 and steadily improved since then), which has been effective even for increasingly deeper holes. The footage drilled for oil and gas wells (Fig. 1) has exceeded 350,000 m/year (1.15 million ft/year) for nearly a decade, and in fact in 1962 it approached half a million meters (1.64 million ft). 21 This has led to a drilling density exceeding 4 m/sq km for the past decade. (Drilling density for the U. S. is reported past decade. (Drilling density for the U. S. is reported to be about 7 m/sq km, and as much as 8.25 m/sq km for the past 10 to 12 years; for Trinidad, it is about 8 m/sq km; while in Rumania it is on the same level as in Hungary.) P. 125

Effect of diluents on the melt viscosity of branched polybutadienes

AbstractThe enchanced low‐shear melt viscosity of branched polybutadienes is shown to be sensitive to dilution with low molecular compounds. The viscosity of branched polymers falls more rapidly with dilution than that of linear polymers, i.e., branched polymers show increased response to plasticization. At least one instance is demonstrated in which the viscosity ratio ηbr/ηlin reverses from a value greater than unity to less than one in passing from dry polymer to rubber extended with relatively large quantities of oil.

An Investigation of the Recovery of the Bradford Crude by Steam Injection

Laboratory tests indicate that steam injected at relatively low pressures is effective in recovering oil from previously waterflooded porous media. They also indicate that the relative effect of an increase in temperature on oil recovery is much more pronounced at higher than at lower temperatures. Introduction In spite of the recently growing interest in continuous steam injection as an oil recovery technique, very few laboratory investigations of steam drive or steamflooding have been reported. The pioneering work of Willman et al. provided much useful information on the mechanism of a steamflood. More recently, Baker 2 has described results of similar studies conducted in a laminar flow model. While actual field tests will decide the effectiveness of a steamflood in a given area, laboratory studies, nevertheless, provide information that can be used to calculate the maximum oil recovery obtainable under a given set of conditions. The present investigation was designed basically to obtain information on the response of a fight crude oil (Bradford crude, 450 API gravity) to a steamflood in a previously waterflooded reservoir. (Many reservoirs in the Appalachian area are in this category, and could possibly give a third yield of oil by a steamflood.) Moreover, an attempt was made to ascertain the role of heat losses in laboratory studies of steam injection. Few previously published works have considered this effect. Steamflooding has been tested in the Appalachian oil fields. In spite of the several early failures, attributed to poor engineering and a lack of basic information on the crude oils involved, steamflooding has been successful in recovering large quantities of oil, as evidenced by steamfloods currently in progress. The results of the present investigation support this view. Experimental Apparatus A schematic diagram of the experimental apparatus used in this study - for the case of the consolidated core, Core No. 1 (see Table 1 ) -is shown in Fig. 1. The core was mounted in a Viton rubber sleeve, the ends of which were clamped to steel end plates provided with suitable connections and O-ring seals. The whole assembly was placed within a high- pressure casing, containing a nonvolatile oil. It was possible to heat the oil - and hence the core assembly - to any desired temperature by means of thermostatically controlled circular heater segments mounted on the outside of the casing. The oil within the casing could be kept at a constant pressure, regardless of the temperature, by means of a pressure regulator pressurized by a hydraulic accumulator and a pressure switch. If the casing pressure should increase above the preset pressure, the regulator could allow some of the oil to leak out of the casing. On the other hand, if the casing pressure should decrease below the set point, the pressure switch could turn on a pump, which would pump oil into the casing until the desired pressure was attained. Simpler experimental set-ups were employed for Cores 2 and 3. JPT P. 692ˆ

Near-shore marine and continental sediments of the Sirte basin, Libya

At the end of the Cretaceous period the Sirte basin developed in North Africa between the Tethyan foredeep and the Sahara Shield. In-filling of the basin throughout the Tertiary era resulted in the deposition of a thick sequence of clastic rocks and carbonates with minor evaporites. The Sirte basin contains large quantities of oil and gas. This paper describes mixed carbonate and clastic Miocene shoreline deposits of a type which prevailed during much of the history of the Sirte basin. These rocks have been studied in the field using sedimentological logging techniques. Forty-seven detailed sections have been recorded totalling some 3000 m of sediment over an area of about 1500 sq km. Some 26000 field observations have been made. These have been used to interpret the depositional environments of these rocks by comparison with studies of recent sediments. Five major facies have been recognized; each has been given a type section and is defined by five parameters, viz: geometry, lithology, sedimentary structures, palaeontology and palaeocurrent pattern. Four of these facies trend parallel to the shore of the Sirte basin. They are locally cross-cut by the fifth. In the north bioclastic limestones were deposited by the shoreward migration of offshore bars and barrier beaches. These interfinger southwards with laminated lagoonal shales with oyster banks. The shales in turn pass shorewards into interlaminated fine sands, silts and shales with abundant bioturbation and micro-cross-lamination. These beds are cut by channels of inclined laminated sand and shale. This third facies is interpreted as inter-tidal, the channels originating as creeks which drained the mud flats. The most southerly (landward) of these four facies consists of crossbedded sands and shales, lignites, rootlet beds, with a spectacular fauna of continental vertebrates. These beds are thought to be the deposits of a fluviatile coastal plain. The four facies belts just described are replaced at two places by n–s trending calcareous sandstone shoe-string complexes interpreted as estuarine channels. Palaeocurrent analysis shows that carbonate sediment, generated in the offshore zone, was transported up-slope towards the land, while clastic sediment was carried seawards from the Sahara Shield. Bipolar palaeocurrents in the calcareous sandstone channels indicate mixing of these two sediment types within the estuarine environment. This Miocene shoreline was similar to the present-day coast of south west Texas, though in this analogue the barriers are made of non-carbonate sediment. The Miocene limestones are broadly comparable to the present-day barrier carbonates of the Trucial coast and have certain points of similarity with recent carbonate sands of the Bahamas.

Steam-Drive Project in the Schoonebeek Field, The Netherlands

Abstract In Sept., 1960, a steam-drive project was started in the solution-gas drive area of the Schoonebeek field. A pattern of three five-spots and one four-spot was selected covering an area of 65 acres. The pay in the project area has good lateral continuity and dips slightly to the northeast; it is about 80 it thick and permeability increases from 1,000 md at the bottom to approximately 10,000 md at the top. The oil originally in place was 12.6 X 10 bbl. The oil has an in situ viscosity of about 180 cp. At the start of the steam drive the cumulative primary production due to solution-gas drive amounted to 4 percent of the oil originally in place. Reservoir pressure had dropped to about 120 psi and no significant primary reserves remained. Some 113 million bbl of steam (all steam quantities are expressed in barrels of water vaporized) have been injected, resulting in production of an additional 4.1 X 10 bbl of oil, or 33 percent of the oil originally in place. This corresponds to a cumulative oil-steam ratio of 0.37 bbl/bbl. It appears that the steam preferentially moves updip while liquids are produced mainly from downdip wells. Observations indicate that the steam flows through only the upper part of the formation. The lateral steam distribution in the pattern is unsatisfactory since several production wells hardly reacted and, hence, contributed little lo the oil production. Production performance and results from material balance calculations agree satisfactorily with the results of large-scale laboratory experiments. On the basis of these experimental results the steam drive, together with a cold water follow-up, is expected to bring ultimate recovery to a value of at least 50 percent of the oil originally in place. No serious production problems have been encountered. However, due to mechanical failure, two old production wells and one injection well had to be replaced. An extension of the steam drive in this area is, under construction. Introduction The Schoonebeek oil field, discovered in 1943 and developed after World War II, is situated in the eastern part of the Netherlands. The main oil reservoir in this field is the Valanginian sand. A completely sealing fault divides this reservoir into two areas (Fig. 1): the southwestern part of the sand body where primary production is obtained by means of a solution-gas drive, and the remainder where edge-water drive is the production mechanism. In the greater part of the field the reservoir consists of a single, unconsolidated sand body. The net thickness ranges from 30 to 100 ft and the top is between 2,400 and 2,800 ft below sea level. Formation permeability varies from approximately 10,000 md at the top to values of the order of 1,000 md at the bottom, and porosity is about 30 percent. The reservoir contains a paraffinic oil of 25 deg. API gravity with an in situ viscosity of 160 to 180 cp. Initial oil saturation was high (85 to 90 percent). The relatively large quantity of oil in place (more than 10' bbl), and the low ultimate primary recoveries expected from this field -approximately 15 percent stock-tank oil initially in place (STOIIP) for the water-drive area and 5 percent STOIIP for the solution-gas drive area - clearly indicate ample scope for secondary recovery. Because reservoir and crude characteristics made this field suitable for thermal secondary recovery, a hot-water drive project was started in the water-drive area about 10 years ago. A few years later a steam drive and an in situ combustion project were started in the solution-gas drive area. This paper deals with the performance of the steam-drive project, which was started in Sept., 1960, and which is still in operation.

Results From a Thermal Recovery Test in a Watered-Out Reservoir

ABSTRACT Residual oil in watered-out reservoirs is a tremendous reserve which has been unrecoverable by established production methods. A study of the new recovery methods indicated that the forward combustion process might recover oil from such reservoirs; however, no thermal recovery operating experience in a watered-out system was available. The Delaware-Childers pilot thermal test was undertaken to test the feasibility of thermal recovery in this watered-out reservoir. The pilot test consisted of a 2.22-acre, inverted five-spot in the 600-ft deep Bartlesville sand. The reservoir in the pilot area had a porosity of 20.6 per cent, a permeability of 118 md and an average sand thickness of 45 ft. The reservoir contains a 33° API, 6-cp oil. Combustion was started Nov. 22, 1960. The initial air injection capacity was 750 Mscf/D, but it was eventually increased to 2,000 Mscf/D. The test was surrounded by an active water flood; therefore, water production was initially high, but decreased as the heat wave moved toward the producing wells. Oil-bank arrival at an individual well was indicated by a drop in GOR and WOR, and an increase in oil production. Combustion-front arrival was evident at three of the pilot producers, and they were plugged. Cumulative oil production from pilot area wells was over 12,000 bbl. Operational difficulties were negligible and only conventional equipment was necessary. The combustion efficiency of this test averaged over 80 per cent. Results from coring showed that the leading edge of the combustion front tended to be wedge-shaped but a nearly complete sweep of the reservoir was eventually obtained. An isopach map based on evidence from 10 core holes and the existing wells showed that 126 acre-ft had been swept by the heat wave. Using this swept volume, an air requirement of 15.7 MMscf/acre-ft was calculated. It was calculated that 275 STB/acre-ft was consumed by the heat wave. INTRODUCTION There is a large amount of oil remaining in reservoirs that have been water flooded. A study of ways to recover this oil showed that the forward combustion process might be applicable. Results from a number of forward combustion tests have been reported in the literature, but none of these tests were conducted in a watered-out system. The Delaware-Childers pilot thermal test was initiated in 1960 to define the operating characteristics of underground combustion in this watered-out Bartlesville sand reservoir. The purpose of this paper is to present the pilot test results in detail. FORWARD COMBUSTION PROCESS The forward combustion process consists of initiating combustion in the formation surrounding an injection well and driving this heat wave through the formation toward offset producing wells. As the combustion front progresses through the reservoir, oil and formation water are vaporized, driven forward in the gaseous phase, and recondensed in the cooler part of the formation. These distilled liquids, water of combustion and gaseous combustion products, form a bank of three-phase region ahead of the burning front. This bank pushes mobile reservoir fluids toward the production wells. The rate of movement of the combustion front is controlled by the rate at which the nondistillable residue which serves as process fuel can be completely burned off the sand. The production performance from a heat wave conducted in a watered-out oil reservoir will differ from one conducted in a dissolved gas-depleted reservoir because of the difference in fluid saturations. The primary depleted reservoir contains connate water saturation, relatively high oil saturation and some gas saturation. The watered-out reservoir contains a highly mobile water saturation, residual oil saturation and little gas saturation.