Showing papers on "Petroleum reservoir published in 1978"

Enhanced recoveries of petroleum and hydrogen from underground reservoirs

Abstract: Hydrogen and other gases that are miscible in petroleum are injected into an underground reservoir to the extent that the volume of hydrogen exceeds the absorption capacity of the petroleum, thereby forming a gas cap composed substantially of hydrogen. Petroleum is withdrawn from the reservoir in part under the influence of gases absorbed into the petroleum and in part under the influence of increased reservoir pressure created by an artificial gas cap. Reservoir temperature is increased by establishing a combustion zone within the underground petroleum reservoir. Hydrogen is withdrawn from the artificial gas cap and is reinjected into the petroleum adjacent to the combustion zone with the resultant hydrogenation of the petroleum.

Oil and gas data from Paleozoic rocks in the Appalachian Basin; maps for assessing hydrocarbon potential and thermal maturity (conodont color alteration isograds and overburden isopachs)

Abstract: Maps are presented which show indices of organic diagenesis, and form part of a data base which includes previously published stratigraphic and structural data for assessing hydrocarbon potential in the Appalachian and structural data for assessing hydrocarbon potential in the Appalachian basin (de Witt, 1975; de Witt and others, 1975; Harris, 1975; Miller, 1975). The potential for oil and gas production in any basin depends on the presence of source beds, favorable hydrocarbon channelways, and structural and stratigraphic traps. Crucial to these factors is the level of organic diagenesis or thermal maturity within the basin. Numererous studies have shown that depth and duration of burial and geothermal gradient (time and temperature) are the chief elements producing organic diagenesis.

Reservoir and source-bed history of Great Valley, California

Abstract: The application of geochemical concepts and relations of reservoir porosity-permeability-depth helps focus exploratory efforts on the favorable parts of geologic trends in partially explored basins. Porosity data from 165 producing reservoirs ranging in age from Late Cretaceous to Pleistocene show that the "best reservoirs" lose porosity at a rate of approximately 1.52% per 1,000 ft (0.46% per 100 m) of burial. Reservoirs on the large-amplitude folds on the west side of the San Joaquin Valley have a more rapid porosity loss with depth. A crossplot of porosity-permeability indicates a "best reservoir" relation of a tenfold decrease in permeability for each decrease of seven porosity units. Within the Great Valley, four major depocenters are definable by use of isopach data. Each has had a different source-bed history. Continental margin sedimentary rocks of Late Cretaceous age contain organic material that generally is structured and is believed to be the source of gas in the Sacramento Valley. Although a Tertiary depocenter exists in the Delta area, subsidence has failed to place Paleocene and Eocene source beds into the thermal zone thought to be required for oil and gas generation. Gas trapped in Paleocene and Eocene reservoirs, therefore, must have migrated from more deeply buried Cretaceous source beds. Tertiary beds in the Buttonwillow and Tejon depocenters in the southern San Joaquin Valley contain large amounts of sapropelic organic material which is believed to be the source of the oil and gas found there. Source beds in the Buttonwillow depocenter have been in the thermal zone for generation for only about 5 m.y. In marked contrast, source beds in the Tejon depocenter started subsiding into the thermal zone more than 15 m.y. ago. Explorationists who recognize the "best reservoirs" and relate them to source, migration, and trap parameters in undrilled areas will be successful in finding future reserves of oil and gas and may avoid some unprofitable "geologic successes" that are economic failures.

The Optimization Of Well Spacing And Fracture Length In Low Permeability Gas Reservoirs

Abstract: This study describes a process for optimizing well spacing and fracture length in a low permeability gas reservoir. Three examples are discussed which represent a high permeability, a low permeability, and a medium permeability gas reservoir. The results from these investigations suggest that the solution is not always intuitively obvious. The complex interaction of the variables involved in each problem almost necessitates the use of a computer model to optimize the exploitation of a tight gas reservoir. Numerous computer runs have been made to illustrate the economic optimum fracture lengths for a variety of reservoir cases.

Beaver River Middle Devonian Carbonate: Performance Review of a High-Relief, Fractured Gas Reservoir With Water Influx

Abstract: The Beaver River field, located in the fold belt of NE. British Columbia and the S. Yukon Territory, produces from a massive, extensively fractured carbonate reservoir. Development in this frontier location was supported by reserve estimates in excess of 1 tcf and high well deliverabilities. After going on stream in 1971, a severe decrease in recoverable reserves and deliverability resulted from water influx. This history portrays the need to examine the potential for influx in view of both the properties of the reservoir rock and the nature of the aquifer.

Chemical and Physical Constraints on Petroleum Migration with Emphasis on Hydrocarbon Solubilities in Water

Abstract: Various suggested primary and secondary petroleum migration mechanisms are reviewed, with emphasis on hydrocarbon solubilities in water. Primary migration of crude oil in aqueous solution is shown to be not possible because of (1) the very low solubilities of high-molecular-weight hydrocarbons, compared with low-molecular-weight hydrocarbons; and (2) the markedly higher solubilities (185 to 650 times) of aromatic hydrocarbons with up to 20 carbon atoms in the molecule, compared with the corresponding carbon number alkanes. Thus, hydrocarbons in water solution in equilibrium with crude oils consist typically of more than 60% benzene plus toluene in the C6+ fraction. However, the concentrations of benzene and toluene in crude oils are typically 1% or less. The low-molecular-weight alkanes (C1-C5) have high solubilities in water, and natural gas may migrate dissolved in water. Migration of oil solubilized in surfactant micelles is not feasible, because a large amount of surfactant would be required to attain a critical micelle concentration (CMC). The size of micelles, if formed, would be too large to pass the small pore throat constrictions in source rocks. Migration by oil droplet expulsion also is not feasible, because of the difficulty of overcoming the high interfacial forces of small drops in small pores. Even if interfacial tensions between oil and water could be lowered sufficiently for oil flow, the source rock would be required to convert at least 7.5% organic matter by volume in order to attain 30% oil saturation required for separate phase flow. Attaining higher oil saturations required for "squeezing" oil from pores would require even higher organic matter concentrations. If oil expulsion did occur, the residual oil saturation would be at least 20% in all source rocks after oil migration. Such concentrations have not been universally observed. All processes whereby generated petroleum enters into or moves with water do not seem possible, because of chemical and physical constraints. Petroleum, in all likelihood, is generated in and flows from source rock in a three-dimensional organic matter (kerogen) network. Scanning electron micrographs clearly show a three-dimensional kerogen network after minerals have been removed by acid treatments. Petroleum flowing End_Page 1-------------------------- in this hydrophobic network is not subject to interfacial forces until bubbles of gas or droplets of oil enter the much larger water-filled pores in the reservoir rock. Oil will flow under the same forces of compaction or pressure developed by gas formation, or by volume expansion associated with petroleum generation. Oil and water flow are independent processes; that is, water flow is not required for primary or secondary petroleum migration. The oil saturation in the kerogen for oil flow to occur is indicated to be from 2 to 10%, based upon hydrocarbon analysis for organic matter in a large number of suspected source rocks. The lower limit of 0.5 to 1% organic matter content for potential source rocks may be due, not to lack of generation potential, but to lack of a three-dimensional kerogen network in rocks containing less organic matter. Secondary migration of separate-phase oil and gas should occur by buoyancy, when their saturations attain 20 to 30% along the upper or lower surface of the reservoir rock. Petroleum entering at the lower surface would cross the rock when the buoyancy head became sufficient for separate-phase flow. This cross-formational flow would occur at occasional intervals. Migration would occur along the upper few centimeters in the reservoir rock from source to trap, thereby providing an efficient migration mechanism. The volume of reservoir rock that attains oil or gas saturation during secondary migration should be small. Water flow is not required. In contrast, secondary migration of hydrocarbons in solution (gas, oil, and micelles) would be very inefficient and require large volumes of water. Secondary migration by solution would require all pores in a reservoir rock to attain 20 to 30% gas or oil saturation before separate-phase flow could occur. Smaller pores may attain higher gas or oil saturations. If separate-phase flow were not attained, petroleum would be locked in the pores and would not be available to form gas or oil reservoirs in trap positions. At 4572 m (15,000 ft) and a temperature of 160°C, a flow of about 90 pore volumes (PV) of gas-saturated water would be required to attain 30% gas saturation. At 1524 m (5000 ft) and 60°C, 200 PV flow would be required. Moving oil in solution would require much more water: 15,000 PV at 4572 m, and 200,000 PV at 1524 m. Limited solubility data suggest that even at 7929 m (26,000 ft) and 270°C, about 4500 PV of hydrocarbon-saturated water would be required to attain an oil saturation of 30%. Cores taken from any portion of the reservoir rock along the secondary migration pathway should show this residual gas or oil saturation. Recovered water should always contain the equilibrium concentrations of each individual hydrocarbon based upon its pure solubility in water and its mol fraction concentration in the separate gas or oil phase present in the rock pores. This has not been generally observed. End_Page 2-------------------------- In actuality, water flow probably disperses water-soluble constituents instead of concentrating them in reservoir traps.

Tensleep Reservoir, Oregon Basin Field, Wyoming

Abstract: The Oregon Basin field in northwestern Wyoming is about 9 mi (14.5 km) long and is composed of a north dome and south dome. Since its discovery in 1927, over 122 million bbl of oil have been produced from the Pennsylvanian Tensleep Sandstone at Oregon Basin. Geologists and engineers worked together to describe the reservoir and accumulate data that would aid in determining best methods for recovering oil from this 50-year-old reservoir. Major reservoir variations are caused by erosion and the presence of nonreservoir dolomite. Layers of nonreservoir material separate the Tensleep into zones that perform as discrete reservoirs. In parts of the field, some of these zones have been completely eroded by post-Tensleep streams. Local anomalies and low-magnitude variations are caused by sedimentary structures, small-scale forms of cement, solution vugs, fracturing, and faulting. On the basis of thicker, persistent, nonreservoir dolomite and dolomite- and anhydrite-cemented sandstone zones that can be located on the logs, the Tensleep reservoir was subdivided into zones. Maps of these individual zones reveal a complex reservoir distribution which was caused by original deposition characteristics, erosion, and cementation. The Tensleep, which has an overall thickness of up to almost 200 ft (60 m), has had tens of feet eroded on the north dome by a southeast-flowing stream. On the south dome, erosion by a northeast-southwest-trending stream has been even more extreme, reducing gross thickness to less than 40 ft (12 m). In that area, the combination of erosion, dolomitization, and cementation by anhydrite has reduced reservoir-sandstone thickness to less than 10 ft (3 m). Such reservoir variation was not recognized previously. The Tensleep generally had been considered as a thick, relatively uniform reservoir. However, maps of individual zones show that injection wells located on the edge of the field did not benefit all zones. Recognition of reservoir zonation and distribution has led to modification of existing water-injection programs, and has provided the basis for planning further development. Incorporation into the overall reservoir management program of the concepts developed has resulted in a significant increase in oil production rates and will result in increased oil recovery from the Tensleep reservoir.

Factors affecting water blocking and gas flow from hydraulically fractured gas wells

Abstract: This study presents results which were generated and analyzed over a 2-yr period. Several hundred computer runs were made during this project and an extensive amount of rock property data was reviewed to insure that these data were representative of tight gas reservoirs. The following conclusions reflect the combined information which was generated during the study. The reservoir properties, such as capillary pressure, change of capillary pressure in damaged zones, and relative permeability (in low permeability gas reservoirs) are primary factors in determining the behavior of a fractured well during cleanup. If the reservoir rock permeability is not damaged by frac fluid invasion, no serious water blockage to gas flow will occur when (1) the pressure drawdown is much greater than the capillary pressure in the formation, or (2) the capillary pressure and water mobility are large enough to rapidly imbibe the frac water into the formation. If the reservoir rock permeability is not damaged by frac fluid invasion, a complete water block to gas flow cannot occur; however, gas production can be severely curtailed if the pressure drawdown does not exceed the formation capillary pressure and the water mobility is so low that the frac water remains immobile nextmore » to the fracture face.« less

Process for locating residual or dormant hydrocarbons in petroleum reservoirs

Abstract: A subsurface earth formation or petroleum reservoir, either previously or presently producing petroleum hydrocarbons, such as oil and natural gas, is analyzed. From production data, the actual fluid flux of the hydrocarbons to each well penetrating the formation is obtained. By analyzing the actual fluid flux in the formation, areas in the formation where little if any hydrocarbon flow occurred are located. The areas so located are likely to contain dormant oil, which may be produced by new wells.

Role of geomicrobiology in enhanced recovery of oil: status quo

Abstract: The forthcoming decrease in availability of known, presently economical deposits of crude oil in the foreseeable future, makes it imperative that the search for new oil deposits be intensified and the present methods of oil recovery be improved or new ones introduced. From the work reported in the literature it is obvious that microbiology may play a significant role in both cases. Among many parameters influencing oil recovery, viscosity of the oil and the surface tension between the rock, oil and water are of great importance. Microorganisms growing in the reservoir produce gases and surfactants, which may, to some extent, regenerate the endogenous energy of the reservoir and facilitate movement of the crude oil to the well. The composition of the crude oil may become altered by biodegradation of asphaltic, napthenic and/or paraffinic components of the oil. The fraction being biodegraded varies according to the microbiological population present. In general terms mixed populations are more effective in biodegradative processes and production of surfactants. A combination of sewage microorganisms and reservoir microorganisms adapted to 95°C and high pressure, was found satisfactory. Molasses is a suitable supplementary substrate for the growth of such a mixed population. A decrease of viscosity of oil, resulting from biological degradation, may be a composite effect of degradation of highly polymerised hydrocarbons, precipitation of asphaltenes and solution of biologically produced gases in the oil. Such biogenic gases dissolved in the reservoir water may, in combination with biologically produced acids, contribute to the slow solution of the sedimentary rock, thus increasing the rock's permeability and facilitating migration of the oil through the reservoir. The biological activity in the reservoir is influenced by a number of parameters (pH, Eh, temperature, pressure, oil-water dispersion, mineralisation). The permeability of the reservoir rock is of primary importance. Rocks of permeability less than 150 md are not suitable for biologically enhanced recovery. Field tests indicate that biological activity in a reservoir may result in a drop of 50 per cent in the oil viscosity, a three-fold increase of oil production over several months, increase in water acidity and additional production of gas with a recorded pressure increase from 2 atm to 27 atm. The area affected by the biological activity depends on the mineralogy and permeability of the reservoir rock, sandstone and limestone of permeability higher than 600 md being most suitable. Further properly controlled and documented laboratory and field experiments are urgently required before the feasibility of microbiologically enhanced oil recovery can be firmly established.

Tertiary oil recovery processes

Abstract: A tertiary oil recovery (TOR) process must satisfy several requirements, such as overcoming capillary forces, and contacting as much of the reservoir as possible. Guidelines for selection of TOR candidate methods are listed, using screening parameters to screen their suitability. The parameters are oil viscosity, oil gravity, depth, net zone thickness, temperature, average permeability, salinity of formation brine, oil saturation, oil content, and rock type (sandstone/carbonate). Candidate methods for TOR including surfactant flooding, miscible carbon dioxide, and thermal (steam drive and in situ combustion) are rated in accordance with the screening parameters.

Borehole gravity survey in the Dry Piney oil and gas field, Big Piney-La Barge area, Sublette County, Wyoming

Abstract: This study presents formation density and porosity profiles calculated from a borehole gravity survey made by the U.S. Geological Survey in the Dry Piney oil and gas field in W. Wyoming. Borehole gravity measurements were used in the Dry Piney unit primarily to determine the in situ density of large volumes of rock that extend tens to hundreds of feet outward from the drill hole. Remote sensing of geologic structure was not an objective of the Dry Piney survey. Proven and potential applications of borehole gravity surveys include detection of irregularly distributed porosity, detection of gas and oil zones behind casing, evaluation and recalibration of conventional types of well logs, vertical density profiling for gravity map interpretation and for seismic modeling and analysis, remote detection of geologic structures such as salt domes and ore bodies, large-volume determination of reservoir porosity for reserve estimates, monitoring of reservoir fluid conditions for production evaluation, and porosity evaluation of unconsolidated materials for ground-water and engneering studies. 16 references.

The Discovery and Development of Minas Field

Abstract: The Minas field is located 35 km north of Pekanbaru, the capital of Riau province, Sumatra, Indonesia. The field was discovered in late 1944, and its discovery was a result of subsurface mapping prepared from data obtained by auger and counterflush drilling, and reflection seismic. The field is a broad low-amplitude anticline, with a productive area of 57,100 acres and 425 ft of oil column. The structure is extensively faulted, and some faults are effective barriers to fluid movement. The main oil reservoirs are in the Sihapas Croup of Miocene age, and are grouped into 5 major sand units. The sands are fairly massive, fine to coarse grained, poorly sorted, with carbonaceous stringers. Individual sands vary widely in thickness across the structure. Locally, the sands tend to coalesce toward the flank of the structure and in other places they are effectively separated by shale lenses. Sand porosities are rather uniform, averaging about 28%. Analyses of core data, however, suggest some permeability variation, vertically and areally. The horizontal and vertical permeabilities appear to be approximately the same, with an arithmetic average of about 1500 md. The production mechanism is a strong water drive and the producing history has been characterized by increasing water cuts, requiring frequent workovers to exclude water production. A shop-made cup packer assembly is being used successfully to isolate the sand intervals as they water out. Presently, Minas is producing 350,000 BOPD from 254 wells using submersible pumps with capacities ranging from 300 to 20,000 BFPD. To arrest excessive pressure decline, peripheral water injection was initiated in late 1969 in the south west portion of the field. The average injection rate is 300,000 BWPD. With cumulative oil production of over 2 billion barrels, Minas is the largest known oil field in SE Asia and its discovery was an event of major significance in the petroleum industry.

Reservoir Rocks and Traps, the Sites of Oil and Gas Pools

Abstract: Petroleum is ultimately collected through secondary migration in permeable, porous reservoir rocks in the position of a trap. Any permeable and porous rock may act as a reservoir for oil and gas. They may be detrital or clastic rocks, generally of siliceous material, or chemically or biochemically precipitated rocks, usually carbonates. It is not uncommon that petroleum is found in fractured shales. Occasionally, igneous and metamorphic rocks are hosts for commercial quantities of petroleum, when favorably located in proximity to petroleum-bearing sedimentary sequences. The fundamental characteristic of a trap is its upward convex shape of a porous reservoir rock in combination with a more dense and relatively impermeable sealing cap rock above. The ultimate shape of the convexity may be angular, curved, or a combination of both. The only important geometric parameter is that it must be closed in vertical and horizontal planes without significant leaks to form an inverted container. The strike contours of this inverted container on a structural map must encircle closed areas comprising what is termed closure area or closure of a trap. A rare exception to this rule is true hydrodynamic trapping.

Trap Spring Oil Field, Nye County, Nevada: ABSTRACT

Abstract: Trap Spring oil field, located on the west side of Railroad Valley, Nevada, is a combination structural and stratigraphic trap in the Tertiary Pritchard's Station ignimbrite. The reservoir is mainly in fractures caused by End_Page 701------------------------------ the cooling of the ignimbrite and local faulting. Structure is related to the valley bounding fault. Numerous unconformities and ignimbrite flows date the structural movement. Exact source of the oil is unknown, however both Tertiary-Cretaceous Sheep Pass Formation and Mississippian Chainman Shale are possible sources. Oil has been generated in commercial quantities in Nevada. Unconventional traps, reservoirs, and source rocks should be regarded as normal. Exploration for conventional traps and accumulations of hydrocarbons in Nevada may be part of the reason for past failures. End_of_Article - Last_Page 702------------

Hydrcarbons accumulations in the "d" sand adams and arapahoe counties, colorado

Abstract: The Lower Cretaceous “0” sand in western Adams and Arapahoe Counties, Colorado, contains significant hydrocarbon reserves in stratigraphically trapped reservoirs. ReSeNOirS are developed in marine bar-type sandstones and in deltaic distributary channel sandstones. Trapping conditions include classical stratigraphic traps consisting of up-dip pinchout of sandstone, and more complex traps such as interchannel point bar porosity permeability pinchout traps. Recognition of the environment of-deposition of individual sand bodies combined with a practical mapping technique utilizing log shapelstructure maps should lead to more discoveries in this area.

Experimental Study Of Formation Behavior In Underground Storage

Abstract: As gas is injected into or withdrawn from a reservoir in the aquifer, changes in pressure or in head occur in the water beneath and around the gas storage bubbles These changes cause flow that is partly controlled by the permeability of the reservoir rock and the compressibility of the water-saturated reservoir rock, and partly by gravitational effects From this flow, formation behavior can be predicted during the injection and withdrawal season

Petroleum Source-Bed Evaluation of Jurassic Twin Creek Limestone, Idaho-Wyoming Thrust Belt: GEOLOGIC NOTES

Abstract: Twelve samples of Jurassic Twin Creek Limestone from seven localities in the Idaho-Wyoming thrust belt region were found to be extremely low in organic matter content, even though the darkest colored and least weathered samples were selected for analysis. We believe that very little organic matter was deposited and preserved in the Twin Creek Limestone in this region. Moreover, rocks of pre-Cretaceous age were subjected to high temperatures unfavorable for preservation of liquid hydrocarbons in localized areas, especially near the point where the borders of Utah, Idaho, and Wyoming join. These interpretations suggest that oil produced from the Twin Creek Limestone and underlying Nugget Sandstone in this region was generated in source rocks of Cretaceous age buried beneath thrust sheets. This oil would have been emplaced in structural traps also associated with thrust movement, after rocks of Jurassic and Triassic age were uplifted, and at temperatures more favorable for the presence of liquid hydrocarbons.

Reservoir engineering aspects of fluid recharge and heat transfer in geothermal reservoirs

Abstract: Natural recharge of fluid filled geothermal reservoirs is shown to be important in the development of these reservoirs and in increasing geothermal energy reserves. Research contributions on methods for calculating water influx and heat transfer in petroleum reservoirs are discussed. The need to forecast the performance of geothermal fluid reservoirs subject to water influx is emphasized. (14 refs.)

Reserach on the physical properties of geothermal reservoir rock. Quarterly report. [From Columbia Plateau volcanic basin]

Abstract: Laboratory measurements of thermal conductivity and capillary pressure have been undertaken for samples of Cenozoic Volcanic rocks collected from the Columbia Plateau Volcanic basin. These measurements were performed at atmospheric pressure and room temperature. Various methods of measuring thermal conductivity were investigated and finally a flash method was chosen. The equipment was constructed and tested. The results were favorable. Numerous capillary pressure curves were obtained by use of the mercury injection technique. These curves indicate pore structure: pore size, pore distribution, pore volume, and pore geometry. Measurements of this type help to explain variations in rock properties such as seismic velocities and resistivities.

Exploration for Sandstone Stratigraphic Traps

Abstract: Effectiveness of trap facies can be calculated if the rock and fluid properties are known or can be estimated for reservoir conditions. This publication, written as an accompaniment for an AAPG Short Course, covers this through explanations and illustrations of transportation and deposition; classification of depositional environments; fluvial texture and composition; deltaic environments; coastal environments; neritic environments; batyl-abyssal environments; and fluid pressures.

Physicochemical Aspects of Primary Migration

Abstract: Most petroleum and gas accumulations are found between the surface and to a depth of about 6000 to 7000 m The physical and chemical conditions that prevail in source and reservoir rocks change with depth of burial Most pronounced is the increase of temperature and pressure

Seismic model study of Patrick Draw field, Wyoming: a stratigraphic trap in the Upper Cretaceous Almond Formation

Abstract: The Patrick Draw field, located on the eastern flank of the Rock Springs uplift in the Washakie basin of southwestern Wyoming, was discovered in 1959 without the use of geophysical methods. The field is a classic example of a stratigraphic trap, where Upper Cretaceous porous sandstone units pinch out on a structural nose. Two-dimensional seismic modeling was used to construct the seismic waveform expressions of the Patrick Draw field, and to better understand how to explore for other "Patrick Draw" fields. Interpretation of the model shows that the detection of the reservoir sand is very difficult, owing to a combination of acoustic contrasts and bed thickness. Because the model included other major stratigraphic units in the subsurface, several stratigraphic traps are suggested as potential exploration targets. Introducion The use of seismic modeling techniques to better identify seismic waveform expressions of subsurface geology has become an important tool in petroleum exploration. The current literature is full of important examples and applications of seismic modeling, which show that modeling has become a common and useful interpretation method to match changing seismic waveform shapes to corresponding changes in stratigraphic facies. The methods of modeling has evolved from the one-dimensional synthetic seismogram using just velocity information and primaries only, to twoand three-dimensional models, which predict the seismic responses of the subsurface. This report is the first of a two-part investigation whose major objective is to determine whether or not the Patrick Draw oil field a classic stratigragraphic trap in the Rocky Mountain area can be detected with modern reflection seismic techniques. The first phase of the investigation is to generate and interpret a two-dimensional seismic model of the oil field. The second part ties the model into an adjacent Vibroseis common-depth-point (CDP) seismic line. Results of the modeling phase are treated in this report. In addition to the Patrick Draw field, numerous lenticular sandstone units in the adjacent Lewis Shale and Fox Hills Sandstone, some of which produce oil and gas, were also highlighted in the model study. General Procedures for Stratigraphic Trap Modeling Two-dimensional seismic modeling is an outgrowth of the techniques of one-dimensional modeling, in which the acoustic parameters from well logs (i.e., the velocity and density data) are converted into synthetic seismic responses using the reflectivity equation. The reflectivity function is then filtered with a seismic wavelet to study the resultant seismic expression that might be found on real field data. It is the reflectivity function and not that wavelet that contains information about geology, such as the composition of rock layers, bed thickness, fluid content, and spatial relationships of the rock unit to other layers in the sequence. Unfortunately, the modern seismic method does not present the interpreter with a pure reflectivity function. In the simplest case, the reflectivity series is filtered by the natural filtering effect of the earth, and the result is a seismic expression created by the complex averaging of reflection spikes by the earth's filter. This complex averaging operator is commonly referred to as a wavelet, and its effect can be studied through modeling (Sengbush, Lawrence, and McDonal, 1961) by performing a convolution of a wavelet with the reflectivity series. Usually, since the real wavelet is never known precisely, simplified wavelets are commonly used, such as the impulse response of a bandpass filter. A two-dimensional seismic model requires that a geologic cross section be constructed from available well-log information, including the interpreter's idea of geologic style for the area. Data from out of the plane of the cross section can also be projected into the model, if care is taken to avoid contaminating the model with erroneous values. The geologic cross section provides the depth and horizontal coordinates to describe the approximate geometrical configuration of the sedimentary layers. Usually, stratigraphic modeling deals primarily with gently dipping beds, and so the problem of describing curvature of folded beds, as in structural modeling, is reduced. Care does have to be taken in describing the lateral and vertical velocity and density variations of the subsurface, since these parameters play a major role in defining the resultant seismic expression of a rock unit. The seismic expression, sometimes referred to as the signature or reflection character, is the shape or pattern of a reflection in terms of several attributes. Common attributes of a waveform include amplitude distribution, polarity, and frequency characteristics. The key to producing reasonably accurate models in areas of rapid and complex stratigraphic variations is to simplify the geology from the well logs just enough so that it is economically possible to run the model on a computer, yet without sacrificing the important details of the geology that are being studied. While modeling cannot reproduce every detail of the subsurface, the resulting modeled seismic cross section can often be compared favorably to high-quality field seismic data.

Appendix VI Fracturing of Reservoir Rocks

Abstract: Publisher Summary Hydraulic fracturing is the process of creating an artificial fracture or fracture system in a subsurface formation by injecting a fluid, that is, the frac-fluid, under pressure into the rock. Depending on the prevailing in situ stress environment, either horizontal or vertical fractures can be created. Such hydraulic fracturing is accomplished because of overcoming the native, natural state of stresses, by exceeding the failure limit of the rock. To fracture a reservoir rock, such as tar sand, the pressure must be applied by injecting a fluid down a wellbore and into the formation. A specific pressure is required to initiate fracturing of the reservoir rock. This pressure is called “the breakdown pressure of a formation” or referred to as “fracture initiation pressure.” A slightly lower pressure will be necessary to continue fluid injection and propagation of the created fracture; this is called the “injection pressure or fracture propagation pressure.” These pressures are related to formation pore pressure, lithology of the reservoir rock, age and depth of the formation, and the in situ rock stress environments. The mechanics of fracture initiation and extension and the resulting fracture geometry are related to the stress condition around the borehole, the properties of the rock, the characteristics of the frac-fluid, and the manner in which the frac-fluid is injected.