Oil-bearing Rocks Research Articles

Petrographic Characteristics of Oil-Bearing Rocks in Alamein Oil Field; Significance in Source-Reservoir Relations in Northern Western Desert, Egypt

In petroleum potential the northern part of the Western Desert of Egypt has become one of the most promising localities of Egypt since the discovery of the Alamein oil field by the Western Desert Operating Petroleum Company (WEPCO). The oil production from the Alamein field comes from Aptian rocks. The Aptian series can be subdivided into two lithostratigraphic units. The lower unit is essentially clastic, whereas the upper one is mainly carbonate rock and commonly is known as the Alamein Dolomite. A petrographic study of the oil-bearing carbonate rocks of the Aptian series in Alamein oil field, the overlying sealing rocks, and the underlying carbonate beds and sandstones of Middle Jurassic age indicated that the dolomites of the Alamein are of syngenetic origin and were subjected to a diagenetic dedolomitization process by volume replacement rather than by molecular replacement. This study revealed that the petrographic characteristics of the Alamein Dolomite are important in the migration and accumulation of petroleum, as well as the source-reservoir relation in the Western Desert of Egypt petroleum province.

Supplemental Recovery Development of The Intisar "A" and "D" Reef Fields, Libyan Arab Republic

Large-scale pressure maintenance programs were begun very early in the producing life of these giant fields to maximize oil recovery and conserve producing life of these giant fields to maximize oil recovery and conserve associated gas. It is estimated that a continuation of these programs will effect a combined recovery of more than 60 percent of the oil originally in place and will conserve nearly 2 trillion cubic feet of natural gas for future use. Introduction Supplemental recovery operations were begun early in the Intisar "A" and "D" Reef reservoirs to maximize ultimate oil recovery, maintain flowing production. and conserve natural gas and gas liquids. production. and conserve natural gas and gas liquids. These giant fields originally contained approximately 4 billion bbl of stock-tank oil. Because the oil in both reservoirs was highly undersaturated, primary recovery efficiency was indicated to be relatively low, necessitating the installation of large water- and gas-injection pressure maintenance programs very early in their productive lives. This paper reviews the reservoir engineering planning and development work that led to the planning and development work that led to the installation of a 500,000 B/D bottom-water injection program in the Intisar "A" field and a combination program in the Intisar "A" field and a combination miscible gas-water displacement program in the Intisar "D" field. The projected peak injection rates in the latter were 700,000 Mcf of gas per day and 400,000 BWPD. A large gas liquids extraction plant, completed early in 1972, also was constructed as an integral part of this gas reinjection project. Water injection was begun in the Intisar "A" field less than 6 months after the held was placed on production. In the Intisar "D" reservoir, water production. In the Intisar "D" reservoir, water injection was started almost coincidentally with production, and crestal gas injection operations were production, and crestal gas injection operations were begun less than 15 months later. These pressure maintenance programs were completely implemented in July, 1971 when the last of three huge gas compressors was commissioned. Thus, the primary and supplemental development of these two fields was completed barely 4 years after the discovery of the first reservoir in April, 1967. This supplemental development was accomplished quickly in order to optimize ultimate oil recovery. It is estimated that these timely pressure maintenance programs will ultimately result in the recovery of approximately three times as much oil from the two fields as would have been realized by primary means alone. In addition, almost 2 Tcf of associated natural gas will be conserved for future use. Discovery and Development The Intisar "A", "C", and "D" field complex is located in the cast-central part of the Libyan Arab Republic's petroleum-rich Sirte Basin. The Intisar "A" and "D" fields are only 15 miles apart and lie within Occidental of Libya's 465,000-acre Concession 103, located about 220 miles due south of Benghazi and 525 miles cast-southeast of Tripoli (see Fig. 1). This concession was awarded in March, 1966, and seismic operations were begun there early in 1967. In April, 1967, the first well drilled on the concession, A1-103, discovered a major oil accumulation when it penetrated oil-bearing Paleocene carbonate rock at a well depth of 9,417 ft. JPT P. 785

Asphaltic Substances in Southeastern Turkey

The writers report the results of geologic field work, drilling, chemical and petrographic examinations, and other tests on the deposits of substances in southeastern Turkey. The veinlike features attain lengths up to 3,500 m and, locally, widths up to 80 m. Their formation is attributed to tectonic events, such as upthrusts and overthrusts, which caused the opening of generally irregular systems of deep, broad, gaping fissures. In particular, tilt of strata below the overthrusts was observed, whereas diagonal fissures are a very striking feature of the hanging walls of the thrust zones. Soft masses of asphalt originated from a former oil-bearing zone and became intricately mixed with the simultaneously deposited mineral substance. These masses were squeezed int the fissures up to the surface as a result of pressure of the overlying rock masses. An asphaltic pyrobituminous shale zone in the so-called Cudi Group, a limestone-dolomite sequence of Middle Triassic to middle or Late Cretaceous age, was recognized in the field, and by comparison of the infrared spectrograms of crude oil and CS2 extracts of the materials, as the original oil-bearing rock and source of the veinlike deposits.

Matrix Acidization with Highly Reactive Acids

Abstract A mathematical model representing the changes in pore structure attending the invasion of a porous material by a reactive fluid tending to dissolve the solid bas previously been tested and found to be valid. This mathematical model is solved by a simulation procedure using Monte Carlo techniques. The results so obtained are indicative of the acidization of sandstone using a last-reacting acid (diffusion limited). A correlation relating the permeability improvement to the change in porosity is presented and found to be applicable to a wide class of initial pore-size distributions. This means that the designer need not have explicit knowledge of the initial pore structure to utilize the correlation. The generality of the correlation stems from the fact that after exposure to fast-acting acids (diffusion-controlled reactions) wormholing tends to occur in all porous matrices, and the acid allows preferentially through these channels. Thus, the process is independent of the fine pore structure since the fine pores receive no acid Wormholing has been observed in almost all experimental studies of acidization, thus further confirming the validity of the model. Introduction Matrix acidization as practiced in the petroleum industry is a simple operation. Acids treated so as to prevent their corrosive attack on metal parts contacted are pumped down the wellbore and forced into the pore spaces of an oil-bearing rock. The rate of penetration is normally maintained small enough to prevent fracturing of the reservoir The aim of matrix acidization is to enhance the permeability of the region around the wellbore by permeability of the region around the wellbore by dissolving either a portion of the rock or of the foreign impurities that may have been introduced during the drilling operations. The success of this technique of oilwell stimulation is attested to by the fact that a significant fraction of the acids used for stimulation are injected at matrix rates. There were, moreover, in excess of 87 million gal of hydrochloric acid used last year in carbonate formations with many other special purpose acids such as acetic and formic having also been used for stimulation purposes. Despite the fact that acids have long been routinely used as a means of stimulating oil wells to greater production, there is, as yet, no reliable design procedure incorporating all of the essential features into a prediction of the new production that will result from a given acid treatment of a particular well. This lack of a design procedure particular well. This lack of a design procedure has been responsible for the rather minimal efforts expended in obtaining meaningful reaction rate data, for there is very little enthusiasm for obtaining data which cannot be put to practical application. This paper is an extension of some recently reported work on predicting the permeability change resulting from acid treatment of an oil-bearing rock. It has been proposed that the changes in the microstructure owing to acidization in a porous rock can be simulated by considering the effect of acidization of a collection of small, randomly distributed capillaries that are interconnected to the extent that a fluid will be conducted from point to point under the influence of an external pressure gradient. This model, the capillaric model, has been used with varying success in understanding the behavior of porous media. The use of the capillaric model in determining only the results of the evolution of a pore-size distribution, rather than as a vehicle for predicting a number of mare or less independent phenomena, such as capillary pressure curves and dispersion, is, as has been pressure curves and dispersion, is, as has been noted by Schechter and Gidley, a more limited and perhaps attainable goal. Taking the capillaric model to be correct, Guin et al. have shown that an equation relating the porosity change and the permeability change caused by an ideally retarded permeability change caused by an ideally retarded acid can be derived without any assumptions.

A Simplified Model of Conduction Heating in Systems of Limited Permeability

Abstract A simplified mathematical model of underground conduction beating in a system of limited permeability is presented. The model applies to underground retorting of oil shale, or to reservoirs containing extremely heavy oils. We assume that heat is introduced at a constant rate into a horizontal fracture which communicates between wells. The radial temperature distribution along the fractured surface is approximated by a step-function. Heat transfer away from the fracture is assumed to be by vertical conduction, and all convection effects are neglected. The model also takes into account the possible temperature dependence of thermal conductivity. A general expression for calculating the growth of the step-function temperature distribution with time is derived. The use of this expression and solutions to the one-dimensional beat equation make it possible to construct isotherms. Expressions for calculating oil recovery, well spacing and heat efficiency are also given. An example calculation is presented for the conduct ion heating process in oil shale. Finally, the effect of the heat transfer coefficient between the gas and the fracture boundaries is investigated Introduction Thermal recovery processes of oil recovery fall into the four general areas of hot fluid injection, forward combustion, reverse combustion and conduction heating. The first three of these processes have been rather extensively studied in the past decade from both the experimental and theoretical points of view. As a result, it is possible to make reasonable engineering predictions and analyses of these processes. Little attention has been devoted, however, to the conduction heating process other than to note its possible utility. To a certain extent, conduction heating cannot be divorced from the other regimes cited above, insofar as these provide the source of heat energy. In the conduction heating process, heat is introduced (either by combustion in the forward or reverse mode or by hot fluid injection) into a small fraction of the total reservoir thickness. This fraction may be either a streak of high permeability or an interwell fracture. Heat penetrates by conduction into the adjacent, less permeable regions of the oil-bearing rock, where the direction of conduction is essentially perpendicular to the streak or fracture. The heated product then drains by gravity or is gas driven to production wells. Conduction heating is probably most applicable to systems containing immobile bitumens such as tar sands and oil shale deposits and perhaps to low-permeability reservoirs containing highly viscous crudes. The mechanism also acts in combination with other thermal processes where fingering or overriding of a bed occurs. It seems probable that in at least one field test, conduction heating of this type was very influential. In this presentation we give a first approximation to some of the quantitative aspects of conduction heating. Marx and Langenheim treated a similar problem where they focused attention upon the injection interval, which spanned the total reservoir thickness. In their model, conduction heat losses to the bounding media imposed a practical limit on the calculated heated area. In the present study, however, we shall confine the injection interval to a small fraction of the reservoir thickness and assume it has no heat capacity. We therefore direct our attention to regions outside the injection interval into which the conduction of heat is beneficial. In particular, we will endeavor to locate specific isotherms in the media bounding the injection interval. Furthermore, we will construct our model to allow the thermal conductivity to vary arbitrarily with temperature. Thus the model will be applicable to underground retorting of shale where variations in thermal conductivity may be important. SPEJ P. 335ˆ

On the theory of hot-water drives

In this paper we are going to investigate a hot water drive in an oil-bearing rock formation. The hot-water drive is one of several thermal recovery methods EI~, [21, [81 a) used by the petroleum industry to produce the residual oil in a reservoir. (The essential phenomenon all such methods are based on is that by heating the reservoir the viscosity of the oil is lowered and may be more easily produced.) A disadvantage of this process is that initially cold oil must be displaced, unless of course there is ample stratification or pore-space in the formation for the hot water to flow through. There have been a number of theoretical hot-water drive studies made previous to this one. Most assume a piston like displacement by the encroaching water; however, they differ on the modes of heat transfer. SCI~UMANN [31, KLINKENBERG [41, and WALTER [51 have studied a model in which the heat is transfered by (1) convection of hot liquids, and (Model A) (2) heat exchange between the solid matrix and liquids which are at different temperatures.

SOME PLANT MIGROFOSSILS IMPORTANT TO PRE-CARBONIFEROUS STRATIGRAPHY AND CONTRIBUTING TO OUR KNOWLEDGE OF THE EARLY FLORAS

Fifty-six recently discovered spores and sporelike microfossils from Canadian non-coaly deposits of Middle and Upper Devonian age are described and classified. Their manner of occurrence suggests their probable usefulness in the establishment of biostratigraphic entities, and their applicability to the stratigraphic study of oil-bearing rocks. Relative to the history of plants, the microfossils convey evidence of a. more complex and more highly evolved Devonian flora than has been apparent from the macrofossil record. In addition, preliminary examination has disclosed spores of comparable abundance and of only slightly less complexity in rocks of Lower Devonian and Silurian age.

Wasatch Plateau Review, Central Utah: ABSTRACT

The Wasatch Plateau is an elevated tract in central Utah, having a north-south length of 60 miles and a width of 20 miles. It is not a separate or unique geologic feature, but rather a segment of the long transition belt between the Great Basin and the Colorado Plateau. Rocks capping the plateau are Tertiary Eocene and uppermost Cretaceous in age. The Mesozoic section is about 12,000 feet thick, thickening and becoming more clastic toward the west. The Paleozoic rock thickness is probably comparable with that of the Mesozoic. The Ferron and Dakota sands of Cretaceous age are gas-productive on the plateau. The Wasatch monocline constitutes a very distinctive topographic and structural boundary between the plateau and Sanpete Valley on the west. Except for normal fault-block tilting and/or slumping, the plateau top is almost flat. Little, if any, actual bending of the strata is evident except on the monocline. A north-south fault system of Tertiary age is predominant throughout the plateau. Although there is probably a deep-seated fault beneath the Wasatch monocline, many of the smaller faults on the Wasatch Plateau and in Sanpete Valley may be due to movement and solution of salt-bearing beds in the underlying Jurassic rocks. Structural and stratigraphic evidence tends to shift the Great Basin-Colorado Plateau boundary westward from previously assigned positions. This would increase the area of potential oil-bearing post-Paleozoic rocks considerably. It is suggested that the Paunsaugunt and Wasatch plateaus were parts of the same province through Wasatch time, and that the Paunsaugunt, 100 miles south, offers the same excellent Cretaceous oil and gas possibilities as those offered by the Wasatch Plateau. End_of_Article - Last_Page 953------------

Developments in Eastern Interior Basin, 1939 and First Quarter of 1940

Although Mississippian rocks continue to contribute the major part of the oil produced in this region, the outstanding new feature is the discovery and development of Devonian limestone wells in five pools, Sandoval, Salem, Bartelso, Centralia, and Tonti (in order of discovery). The saturated zone in the Devonian consists of dolomitic limestone with solution cavities, and probably fissures and joints. In the pools listed the top of Devonian limestone lies from 1,100 to 1,400 feet below the McClosky oolitic limestone (the lowest large producing zone in the Mississippian), and this interval probably increases to more than 2,000 feet in the deepest part of the basin. Initial productions of the new Devonian wells are exceptionally high for the area, some exceeding 10,000 barr ls per day, thus indicating a high degree of permeability of the oil-bearing rock. Thus far all the new areas of Devonian production are on structural closures indicated in Mississippian or Pennsylvanian key beds (or both) and furthermore are in areas of previous production from shallower strata. Whether or not there are structures affecting Devonian but not younger strata and of sufficient size to cause oil accumulation is not yet known.

Reopening Limestone Oil Wells with Acid

THE natural flow of an oil well may recede either from the exhaustion of the oil supply or as the result of a stoppage of the pores of the oil-bearing rock cutting off the free supply of oil. In the past, some what drastic methods have been tried to overcome this drawback, but they are difficult to carry out, especially at a depth which may be half a mile below the surface. When the well is in a limestone forma tion, it has now been discovered that it is possible to open it up again by treatment with successive quantities of 10 or 15 per cent hydrochloric acid, which dissolve new channels in the calcareous rock and permit of a new flow of oil. The use of hydro chloric acid is only made possible by the addition to it of 1–5 per cent of an arsenic compound, which inhibits the action of the acid on the metallic casing and pump tubes of the well. Other inhibitors,including certain organic nitrogen bases, have been discovered but the arsenic compounds are the most convenient to apply in practice. The discovery has been made by the Dow Chemical Co. in partnership with the Pure Oil Co., and patented as the Dowell process: it is described in greater detail in the News Edition of Industrial and Engineering Chemistry for February 20. The use of acid made inactive towards metal surfaces is a novel and important one: it may be a revolutionary factor in oil production. Further, it is likely to be beneficial in natural gas production and in other directions. It is certainly an achieve ment to be able to control the action of a strong acid as a boring agent half a mile below the surface.

Generation of Oil in Rocks by Shearing Pressures: II. Effect of Shearing Pressures on Oil Shales and Oil-Bearing Rocks

This paper, the second of a series on the generation of oil in rocks by shearing pressures, gives details regarding experiments performed with oil shales from Colorado, Australia, Kentucky, and Cleveland, Ohio. The shales were subjected to high shearing pressures of varying intensity and under different conditions, so that they yielded by either fracture or flow. Nearly all the tests were conducted at room temperature. In no case was any oil generated, and the shearing appears to have had little effect on the solubility of the organic matter. One effect noticed is the occurrence of more volatile matter in extracts from sheared shales than in extracts from shales not sheared. This, however, is explained by oxidation and is not applied to natural occurrences. Other experiments include the shearing of Colorado oil shale with various catalysts present and of a California shale containing oil. By the latter it is demonstrated that high shearing pressures will squeeze out practically no oil from a highly saturated shale. A general conclusion, based on the experiments, is that high shearing pressures on oil shales at low temperatures and throughout relatively short periods of time are quantitatively not important in the generation of oil from such rocks. It is also pointed out that where the deformation of oil shales occurs even partly by fracture and under considerable containing pressures, an increase in volume is brought about which will cause a reduction of fluid pressures. Should pressure be proved to influence the change of organic matter in oil shales towards oil, this reduction of fluid pressures may be important in explaining any actual changes brought about in nature.

Were Diatoms the Chief Source of California Oil?

California has occupied a peculiar position among the petroliferous provinces of the United States in having formations associated with the oil-bearing rocks which, from the content of microscopic organisms, obviously might have been the source of the oil. This has led to the general acceptance of the theory that of these organisms, the diatoms, which occur in greatest abundance, provided the greater part of the organic material which was altered to form the petroleum of the major oil fields of the state. Recent work has shown that the organic shales in other petroliferous provinces do not necessarily contain recognizable fossil remains, and that organic material carried into the basins of deposition by rivers and precipitated by saline waters, is an adequate source for the petroleum of our oil fields. Decay-resistent vestiges of plant and possibly animal remains may have contributed to the supply. The shales within the oil zones of the fields of southern California have many characteristics which suggest that they may have been the source of the oil now contained in the sandy beds with which they are interbedded. The present position of the oil in the Pliocene section and the distribution of the oil in the anticlinal structures in the Los Angeles basin point to the Pliocene sediments, which are relatively free from diatoms, as the source rocks. This hypothesis seems to fit the observed conditions in southern California fields better than the diatom theory.

Seasonal Rhythm in the Tertiary Sediments of Burma.

At the Bournemouth meeting of the British Association in 1919, Dr. J. W. Evans, in his characteristically stimulating address to Section C, pleaded for the closer examination of sediments by geologists in the field. He instanced especially the presence of rhythmic banding on a small scale in sediments of widely varying ages as a phenomenon badly in need of further study. Engaged in field work on the oil-bearing Tertiary rocks of Burma, the writer has been struck by the repeated occurrence of rhythmic banding in those beds. The present note embodies the firstfruits of the detailed examination of the banding.

On the Occurrence of Brown Cannel Coal (“Kerosene Shale”) with Reinschia australis in the Falkland Islands

AMONGST an interesting exchange series of fossils sent to. the National Museum, Melbourne, by the honorary curator of the Falkland Islands Museum, there is a specimen of “kerosene shale,” which, on account of its deep brown colour, resinous lustre, and eminent conchoidal fracture, at once reminded me of the oil-bearing rock of Hartley, New South Wales. Upon slicing this specimen and comparing the structure with a slide of the Hartley rock in our museum cabinet it was evident that they were practically identical. The Falkland Islands specimen is formed, like that of the New South Wales rock, almost entirely of the small (?) thallophyte described by MM. Renault and Bertrand under the name of Reinschia australis, and believed, by them to be nearly related to the Hydrodictyace or Volvocine. The deep yellow coloured sacs I are of the same dimensions in both examples. The specific I gravities of the Falkland Islands and the New South Wales rocks were found to be approximately equal, being in both cases slightly more than 1. Prof. Liversidge gives that of the Hartley, New South Wales, specimen as 1.052. As Liversidge points out, this rock is scarcely a shale, since the shaly structure in hand-specimens is absent, but would be more aptly termed a “Cannel coal,” or, as suggested by the Rev. W. B. Clarke,“brown cannel.”