Shale Breaks Research Articles

Assessment of the pyrolysis, combustion and fractal dimension of fragmented oil shale particles

The main objective of this study is to examine the effects of temperature and residence time on oil shale size fragments in terms of the fractal dimension. A series of tests consisting of the pyrolysis and combustion of oil shale particles followed by mechanical impact shattering was carried out to evaluate the fractal dimension of the fragmented particle distribution. The effects of oil shale parent size fragmentation after aging at different oxidation times on the fractal dimension and fragments size distribution were investigated quantitatively. A mass based fragmentation approach rather than a number fraction method was used. Any set of n fragments obtained during oil shale break has its own fractal dimension. A decrease of fractal dimension in the range of 20%–30% was observed after shale particle gasification. The results show that increases of the oxidation time and temperature of the pretreatment increase the number of fragments for a fixed impacting energy. Dimensions of 2.7–2.9 were related to a lower temperature pretreatment and reduced oxidation times, while dimensions of 2.2–2.4 were attributed to a high temperature pretreatment and longer oxidation times.The fractal dimension nature was conserved despite the fact that different values were obtained for different retorting/combustion conditions. It was found that multi-fractal dimensions of fragmented oil shale particles retorted at fixed temperature with corresponding mass extent can be fitted with functions that characterised mass and size of particle progeny.The fractal dimensions and energy density for fracturing demonstrate a good linear relationship showing that the energy of fragmentation is affected by the scale effect.

Sequence Stratigraphic Analysis from Well Logs of an X-Field, Niger Delta, Nigeria

The sequence stratigraphic analysis of the area was studied using well log information in order to determine the lithostratigraphy, chronostratigraphy, possible reservoir sands, age and depositional environment of the study area for opportunities that will support exploration program. The depositional environment penetrated by the wells interpreted from log signatures gave three major facies association. The blocky and coarsening upward (funnel shape), the blocky and fining upward (bell shape) and the erratic (serrated or spiky) facies representing distributary mouth bar, distributary channel and marine mud facies respectively. The sediment deposition of the coastal deltaic and shallow marine delineated for the wells were inferred from the study. Lowstand Systems Tract (LST), Transgressive Systems Tract (TST) and Highstand Systems Tract are the depositional sequences observed. The Maximum Flooding surfaces observed from the stratigraphy analysis indicate major shale break (high shale content). The study area is dominated by altenation of sand and mudstone lithologies, which occurs in approximate ratio of 60:40. The stratigraphic column of the wells was subdivided into sequence boundary, system tracts and sedimentary cycles based on the integration of the various dataset. Some of the sequences have potential of a source rock and seals. The system tracts have the characteristics of good seal and traps. The Maximum Flooding Surfaces and sequence boundaries observed in the wells are four and five respectively. The depths at which the Maximum Flooding Surface occur are 1300, 9300, 9750 and 7050 ft while the sequence boundaries occurred at the depths of 12150, 10850, 8550, 7425 and 6875 ft respectively.

Exploration Implications of the Geometry and Orientation of Paralic and Shelf Sands, Wilcox Group (Paleogene), South Texas

ABSTRACT The geometry and orientation of sixteen stacked sands in a 300-350 ft-thick interval (100 m) in the Wilcox Group in the subsurface beneath La Salle and McMullen counties in South Texas is remarkably consistent. Two recurring sand-body geometries are present: broad, sheetlike, shoreline-attached sands with length-width ratios near one; and narrow, elongate, shoreline-detached sands with length-width ratios greater than two. The shoreline-attached sands pass landward into a continuous section without shale breaks and thin basinward before pinching out into shales on the shelf. The shoreline-detached sands pinch out into shales on both their landward and basinward margins. Because the regional dip is at right angles to depositional strike, the updip and landward limits of the shoreline-detached sands coincide to form attractive stratigraphic targets. Depositional strike averages N42°E for the seven shoreline-attached sands and N39°E for the nine shoreline-detached sands. The zone of maximum thickness of each of the shoreline-detached sands is parallel to the orientation of the sand-body on paleoslope. The zones of maximum thickness of the shoreline-attached sands in most cases are nearly perpendicular to the zero edge of the sand-body. The geometry and orientation of the shoreline-attached Wales sand at the base of the interval and the shoreline-detached Gasper sand near the top extend another 30-50 miles (50-75 km) along depositional strike to the northeast beyond La Salle and McMullen counties. The pattern of deposition in the middle part of the Wilcox Group persists over distances of at least 60-125 miles (100-200 km) along depositional strike in this area.

Production characteristics of sheet and channelized turbidite reservoirs, Garden Banks 191, Gulf of Mexico

ABSTRACT Garden Banks 191 is about 150 miles from Lafayette, Louisiana in 700 feet of water. Block 191 has produced over 210 BCF dry gas from Pleistocene reservoirs since 1993. This paper will address the production characteristics of turbidite sheet (4500' Sand) and channel (8500' Sand) sand reservoirs. Understanding the distribution of shale breaks within both reservoir types is critical because the shales compartmentalize gas production and control water encroachment through the reservoirs. The 4500' Sand reservoir is about 1000 ft. thick and is composed of interbedded sands and shales typical of amalgamated and layered sheet sands. The sand is subdivided into four production members (designated 1-4) by shale breaks that extend across the reservoir interval. The reservoir has exhibited a good water drive. Water encroachment occurs individually within each member. The 8500' Sand is approximately 900 ft. thick fining-upward channel succession that was deposited in a slope mini-basin formed by salt withdrawal. Shale breaks in this stacked channel succession do not extend across the reservoir, but they do control water encroachment in individual wells. The sand is informally divided into five members based on shale breaks and perched water contacts. Members 3, 4 and 5 are connected, based on RFT pressures. The 8500' Sand has produced from a combination pressure depletion/limited water dive mechanism resulting in excellent recoveries.

Alternative Stimulation Fluids and Their Impact on Carbonate Acidizing

Abstract Acidizing treatments are commonly used to remove near-wellbore damage and create artificial flow channels in carbonate formations. Matrix acidizing treatments are most useful when fracture acidizing is undesirable, such as when a shale break or other natural boundary must be maintained to prevent water or gas production1 or where fracture acidizing is ineffective, such as in soft chalk formations.2 Unfortunately, matrix treatments often require low injection rates to prevent fracturing the formation rock. These treatments may also be required in heterogeneous formations with zones of low conductivity (which need stimulation the most) that accept acid at low rates. It is at these low injection rates that the problem of rapid acid spending severely limits the acid penetration distance. The injection of hydrochloric acid (HCl) into carbonate formations at low rates results in face dissolution, or complete dissolution of the carbonate matrix near the wellbore. This face dissolution consumes large volumes of acid and provides negligible increases in the conductivity of the formation. Various acid systems have been used to reduce the limitations of rapid acid spending at low injection rates. A few of the acids include: weak acids, such as acetic and formic acid, which have relatively low H+ concentrations and therefore react with carbonates at a slower rate than HCl3,4; chemically retarded acids, such as oil external microemulsion systems containing HCl, that retard acid diffusion to the carbonate surface and thus allow deeper penetration of live acid2; and foamed acids (nitrogen gas and aqueous HCl) that prevent acid from spending outside the primary dissolution channel, thereby promoting the growth of wormholes.5 Although retarded and foamed acid systems can stimulate carbonate formations at lower injection rates, strong acids such as HCl induce the precipitation of asphaltic sludge from crude oil. This sludge can plug the formation and restrict production after an acidizing treatment. When ferric ions are present, this problem is even more severe.6 Thus, adequate corrosion protection becomes more essential. Acetic acid (HAc), an iron chelating agent, does not reduce sludging tendencies in the presence of ferric and ferrous iron.6 A variety of acid additives (antisludging agents, corrosion inhibitors, and iron-reducing agents) have been used to prevent the sludging problem. However, their effectiveness is limited by the need to obtain a compatible combination of additives and a lack of understanding of the complex chemistries involved in the precipitation reactions. These limitations demonstrate the need for an alternative stimulation fluid that combines the ability to stimulate at low injection rates with fluid properties that are not conducive to asphaltic sludge precipitation or corrosion problems.

Oil Recovery From Bottomwater Reservoirs

Introduction Billions of barrels of oil remain unrecovered in "bottomwater" reservoirs with a highwater-saturation zone in communication with the oil zone. Typically, the water cut in such reservoirs increases rapidly during primary production, leading to low primary oil recovery. If a water zone were not present, many of these reservoirs would be good candidates for waterflooding. Instead, the performance is poor under conventional waterflood and worse if the oil is highly viscous. Several techniques and production strategies have been proposed recently to improve waterflood performance of such reservoirs. These are the subject of this paper. Problems In Producing Bottomwater Reservoirs Water coning is the most common problem in producing oil from a bottomwater reservoir. Once the water reaches the perforations, it is produced in preference to the more viscous oil, and the producing WOR becomes prohibitively high. In heavy-oil formations, a high water cut often causes excessive sand deposits in the wellbore. A specific minimum oil flow rate is required to mobilize sand in most heavy-oil reservoirs. In most cases, with an increase in the water cut, the sand-carrying capacity of the produced fluids drops considerably and the wellbore sands up. The detrimental effect of the bottomwater zone sometimes is alleviated by shale breaks, which reduce vertical permeability. A number of heavy-oil reservoirs with water legs have not been affected significantly by an underlying high-saturation water zone because of the presence of frequent horizontal shale breaks. Similar horizontal shale breaks probably will increase productivity in light-oil reservoirs with bottomwater as well. Field Experience The Bonnie Glenn field of Alberta is a light-oil bottomwater reservoir that has produced successfully under primary production. This light-oil (35 to 40 deg API) reservoir has a water zone, yet the oil production rate has been steady with little water influx from the bottomwater zone. One interesting feature of this reservoir is the presence of a gas cap. Also, the reservoir has a very high vertical permeability, resulting in an efficient gas cap drive with maximum pressure gradient from the top of the reservoir. As a result, oil can be produced with relatively small drawdown and minimum influx from the bottomwater zone. However, the reservoir is maturing after producing (with gas reinjection) some 80% of the original oil in place (OOIP). Currently reported WOR values are high.

Effect of Temperature on Heavy-Oil/Water Relative Permeabilities in Horizontally and Vertically Drilled Core Plugs

Effect of Temperature on Heavy-Oil/Water Relative Permeabilities in Horizontally Permeabilities in Horizontally and Vertically Drilled Core Plugs Summary Oil/water displacement tests were conducted in preserved core material at reservoir pressure and at various temperatures ranging from room temperature to 522F [272C] to evaluate the effect of temperature on relative permeabilities. Both horizontally and vertically drilled permeabilities. Both horizontally and vertically drilled plugs were tested to determine the influence of flow plugs were tested to determine the influence of flow direction on relative permeabilities and on their temperature dependence. Results show that temperature influences both the endpoint saturations and the endpoint effective permeabilities. Irreducible water saturation increased with increasing temperature, whereas the dependence of residual oil saturation on temperature was less clear-cut. The residual oil saturation appeared to decrease up to an optimum temperature, beyond which the trend reversed. The endpoint effective permeability to oil decreased with increasing temperature, while the endpoint effective permeability to water appeared to be independent of permeability to water appeared to be independent of temperature. The endpoint effective permeability to oil was found to be from one to two orders of magnitude lower in vertically drilled plugs compared with horizontally drilled plugs. On the other hand, endpoint water permeability appeared to be similar in both directions. Introduction Numerical simulation of thermal recovery processes requires data on relative permeability and its dependence on temperature and flow direction. Reliable data of this nature have not been commonly available because of the experimental difficulties involved in measuring relative permeabilities at high temperatures. Often, relative permeabilities at high temperatures. Often, relative permeabilities routinely measured at room temperature permeabilities routinely measured at room temperature are used to predict performance at higher temperatures. In history-matching past reservoir performance, treating relative permeability as an adjustable parameter often becomes necessary. As shown by Dietrich, relative permeabilities measured in unconsolidated sands differ permeabilities measured in unconsolidated sands differ from those required to history-match cyclic steam stimulation results by more than an order of magnitude. Many heavy-oil fields contain discontinuous shale breaks and thin, tight zones that lead to significant differences between vertical and horizontal permeabilities. Since override in the steam injection process can be affected strongly by such barriers, it is desirable to know whether relative permeability curves also show anisotropic behavior and, if so, how this behavior is also affected by temperature. Many investigators have studied the effect of temperature on relative permeability. Edmondson found that residual oil saturation (Sor) decreased with temperature and that changes in water/oil permeability ratio were different with different oils. Poston et al. investigated the influence of temperature on oil/water displacements in unconsolidated sands and concluded that irreducible water saturation increased and Sor decreased with increasing temperature. They also found that relative permeabilities to both oil and water generally increased with increasing temperature. Weinbrandt et al. found that, in Boise sandstone cores, an increase in temperature from room temperature to 175F [79C] resulted in increased irreducible water saturations, decreased Sor, increased endpoint water permeabilities, and increased oil permeabilities. They suggested that thermally induced mechanical stresses may be responsible for some of the observed changes in absolute and relative permeabilities. Lo and Mungan measured water/oil relative permeabilities in Berea sandstone and porous Teflon cores using the steady-state technique at porous Teflon cores using the steady-state technique at temperatures up to about 302F [150C]. They found that the effect of temperature on relative permeabilities was similar in the oil-wet and water-wet systems. They also found that increases in temperature caused decreases in Sor and increases in irreducible water saturation, and suggested that a temperature-induced change in the viscosity ratio may be responsible for the observed changes in relative permeability. In a more recent investigation, Sufi et al. permeability. In a more recent investigation, Sufi et al. found that relative permeabilities determined with clean oil and water in clean Ottawa sand were independent of temperature between 70 and 186F [21 and 86C]. Most of the reported studies on temperature dependence of relative permeabilities have been conducted with clean or extracted core materials and refined oils. JPT P. 1500

Oil and Water Production in a Reservoir With Significant Capillary Transition Zone

Summary Analytical and numerical methods are used to investigate the mechanism of water production in a high-permeability sandstone reservoir that has a capillary transition zone height comparable to formation thickness. Production rates are well above those for transition-zone water production alone. Consequently all wells are affected production alone. Consequently all wells are affected by coning shortly after the start of production. It is found that water cut is largely insensitive to total fluid production rate for the same recovery. The depth of well penetration and the effect of radial capillary pressure gradients are shown to be of secondary importance pressure gradients are shown to be of secondary importance in these circumstances. The predictions are confirmed by the results of a long-term pilot production test. Introduction This paper considers the mechanism of water production in a highly permeable sandstone reservoir with a 22API [0.9-g/cm3] under saturated oil and a strong edge aquifer drive. The findings are drawn from a study recently performed on the M-1 Sand reservoir of the Fanny field, performed on the M-1 Sand reservoir of the Fanny field, which is located on the eastern flank of the Oriente basin in Ecuador. M-1 Sand belongs to the Napo formation of the Cretaceous Age and consists of moderately to poorly cemented quartzose sands of high permeability. Reservoir depth is approximately 7,700 ft [2347 m]. A characteristic feature of the reservoir is the wells' predisposition to develop substantial water cuts after predisposition to develop substantial water cuts after short periods of production. Attempts have been made in the past to reduce water production by squeeze cement jobs and recompletions. However, these operations have not been effective but for the very short term and consequently the study has concentrated on attempting to define the nature of fluid movement within the drainage area of the wells. Reservoir Description M-1 Sand shows lithological features characteristic of a fluvial channel depositional environment. These features are exemplified by the Induction Electrical Survey of Well 18-B-2 (Fig. 1), which shows a basal unit 45 to 55 ft [14 to 17 m] thick, overlain by a variable number of smaller units that are separated by shale breaks and tight streaks. These upper units are of poor quality and limited lateral continuity. In contrast the basal unit contains no correlatable shale breaks although thin shales were encountered in some wells and early completion practices attempted unsuccessfully to make use of them. Because of this early experience and the absence of correlation it has been concluded that such shale breaks are of limited lateral extent and do not contribute materially to the prevention of water-cone development. prevention of water-cone development. The basal unit contains more than 90% of the original oil in place, estimated at 48 × 10(6) STB [7.6 × 10(6) stocktank m3]. Currently all wells are completed in this unit, which has provided all production to date. The upper units have been neglected for the purposes of this paper. The structural configuration of the reservoir is a faulted asymmetrical anticline of low structural amplitude. Fig. 2 represents the structure on top of the basal sand unit and shows the intersection of the oil/water contact (OWC) with this surface, giving rise to a maximum oil column of 65 to 70 ft [20 to 21 m]. A comparison of sand thickness with oil column height indicates that the base of the sand is everywhere close to the OWC and that all wells have high basal water saturations. Pressure support is by edge aquifer influx, but with strong underrunning giving behavior characteristic of a bottom aquifer. Reservoir and Fluid Properties The basal unit is variable in quality but characterized by high porosity and permeability averaging 20 to 25% and 2 to 3 darcies, respectively. Figs. 3 and 4 are capillary-pressure and relative-permeability curves representative of the basal unit. These curves are typical of a sandstone that contains large, well-interconnected pores. Sands of this unit are generally poorly cemented and friable. No fractures are evident from either cores or logs. There is no evidence of any fracture-induced effects on pressure buildup data, which correspond to a single permeability intergranular system. Average oil and water fluid properties are presented in Table 1. The oil and water viscosities at reservoir conditions are 12 and 0.35 cp [12 and 0.35 mPas] respectively, which give a very unfavorable endpoint mobility ratio. The displacement of oil by the encroaching aquifer is thus an unstable displacement and the strong underrunning of water quickly results in high producing water cuts in the wells. JPT P. 1559

Implementation of a Gravity-Stable Miscible CO2 Flood in the 8000 Foot Sand, Bay St. Elaine Field

Summary This paper reviews implementation of a gravity-stable, miscible CO2 solvent flood in a reservoir located in the coastal marshes of south Louisiana. Key reservoir properties are presented, and field tests to determine residual oil saturation and to define reservoir limits and continuity are described. Unique equipment used to transport and inject the CO2 solvent is discussed along with the special instrumentation used for quality control. Also itemized are the regulatory agencies contacted and the permits acquired before the project could be implemented. Introduction Texaco U.S.A. initiated a gravity-stable, miscible CO2 solvent flood on Jan. 20, 1981, in the Bay St. Elaine field, Terrebonne Parish, LA (Fig. 1). The flood in the 8000 Foot Reservoir E Sand Unit (RESU) is being conducted to prove the effectiveness of gravity-stable, miscible CO2 solvent flooding in a steeply dipping, depleted sand. The results of this project will help to determine whether fieldwide CO2 flooding will be economical in similar south Louisiana reservoirs. The project consists of three wells-one injector and two producers. A structure map of the 8000 Foot RESU is shown in Fig. 2. Approximately 84.4 Mg/D [84.4 metric tons/d] CO2 solvent, consisting of CO2, methane, and normal butane, was injected into updip Well 22–26 over a 9-month period. The CO2 solvent slug occupied one-third of the reservoir PV. The CO2 solvent slug size and composition was designed by Texaco's Bellaire (TX) Research Laboratories. Nitrogen, used as a drive gas, is being injected into Well 22–26 to displace the CO2 solvent slug downdip in the reservoir. The CO2 solvent, as it moves downdip, will become miscible with the in-place residual oil. Production of tertiary oil will be from downdip Wells 22–5 and 22–31. An estimated 11 924.0 stock-tank m3 [75,000 STB] tertiary oil is expected to be produced from this depleted water-drive reservoir. The CO2 and n-butane were trucked in liquid states and off-loaded into storage tanks at Cocodrie, LA. These fluids were later transferred to similar storage tanks mounted on barges. The barges then were transported 11.3 km [7 miles] to the injection facility in the Bay St. Elaine field. The methane was obtained from the gas-lift system already in the field. The three components were mixed and injected into Well 22–26. Reservoir Description. The Bay St. Elaine field overlies a salt dome. The recoverable oil is found in numerous sands separated by shale layers. Fig. 3 is a typical electric log of the 8000 Foot Sand from Well 22–5. These sands dip steeply as a result of the upward movement of the salt dome. The 8000 Foot Sand is separated into segments by faults radiating from the salt dome. The 8000 Foot RESU varies in net sand thickness from about 9.1 m [30 ft] near the updip unconformity to about 30.5 m [100 ft] in the downdip portion of the project area. This Miocene sand exhibits high permeability and porosity. The reservoir oil has an 840-kg/m3 [36API] gravity and was produced at a normal GOR. The reservoir has a strong edgewater drive. Key reservoir parameters are presented in Table 1. The 8000 Foot RESU was determined a suitable candidate for a gravity-stable, miscible CO2 solvent flood for the following reasons. Well-Defined Reservoir. Reservoir E and Segment 790 are isolated from the rest of the 8000 Foot Sand by well-established faults. Well Availability. All wells in the two segments except Well 22–3 are completed in the 800 Foot Sand with no remaining primary or secondary potential. Well-Delineated Sand. The 12.7-cm [5-in.] log of Well 22–5 (Fig. 3) indicates significant shale breaks between the sands. The 8000 Foot RESU is not in communication with any other sand within the project area. Fairly Homogeneous Sand. The few shale streaks within the 8000 Foot Sand are not continuous, and the sand is uniform. Expansion Potential. Large reservoirs with millions of barrels of residual oil are adjacent to Segment 790 in both the 8000 Foot Sand and the 8050 Foot Sand (directly beneath the 8000 Foot Sand). The reservoir characteristics are quite similar and the same CO2 solvent flooding process can be used in these reservoirs. JPT P. 101^

Berea Sandstone Reservoirs in Ashland and Medina Counties, Ohio: ABSTRACT

The Berea Sandstone is one of the better known rock formations in Ohio. It occurs at shallow depths throughout a broad belt in central Ohio and crops out to the north and west of these counties. Stratigraphically, the Berea Sandstone is part of the Waverly Group and is underlain by the red and gray Bedford Shale and overlain by the black Sunbury Shale, all of which are of Early Mississippian age. In Ashland and Medina Counties, the Berea may be divided into two separately identifiable units. The upper unit, called the blanket Berea in outcrop, is approximately equivalent to the cap Berea in the subsurface. The second unit, which lies below the cap Berea varies considerably in its thickness. The thickness of the Berea Sandstone (excluding the cap) ranges from zero to over 125 ft (38 m) in the study area. The thickness changes occur within very short distances (i.e., 100-200 ft or 30-60 m) owing to the original depositional conditions responsible for the formation of the sand body. The traditional, long-standing, and generally accepted view is that the Berea Sandstone was deposited in Ashland and Medina Counties in southward-flowing river channels. More recent drilling in these counties has demonstrated that these sand channels are not continuous, but are isolated sandstone bodies in which petroleum has accumulated. The reservoir capacity of the Berea is between 8 and 22% with an average porosity of 15%. The sandstone consists of loosely cemented, medium to fine-grained quartz with only rare shale breaks below the cap Berea. In Ashland and Medina Counties, Berea wells generally produce oil. Initial production in this area ranges between 1 or 2 bbl and to 40 BOPD after treatment. Reservoirs in the Berea Sandstone generally are productive where the sandstones are thick. They are also productive where the sandstone is thinner, but high on structure. Although a high structural position is preferred, the critical consideration is the thickness of the sandstone body and the reservoir geometry. End_of_Article - Last_Page 1920------------

Significance of Limestone-Shale, Rock-Stratigraphic Contacts--The Connecting Links Between Areas of Contemporaneous Carbonate and Terrigenous Detritus Sedimentation: ABSTRACT

In undisturbed depositional sequences one rarely, if ever, observes lateral change directly from mud-supported carbonate Synthetic seismograms after normal moveout correction for a hypothetical 20-m (66 ft) high impedance sand reservoir in shale. Ratio of compressional velocity to shear velocity in this model is 1.8 for shale, 1.57 for brine sand, and 1.5 for gas sand. Variation in reflectivity with offset in this model is a first order effect over normal recording range. End_Page 417------------------------------ into grain-supported siltstones, sandstones, or conglomerates. Shale or claystone always intervene. Such bounding and internal contacts are the most conspicuous and most informative--yet most neglected--aspects of the limestone-shale record. Significant progress in understanding carbonate to terrigenous detritus facies changes can come from closer attention to these contacts. A majority of Mid-Continent Pennsylvanian limestone-shale contacts are of regional extent and commonly are represented by upward gradations from shale to limestone. Shale units in carbonate sections commonly range from fractions of inches to tens of feet in thickness. Genesis of thin (2 ft ot .6 m or less) shale breaks and argillaceous partings has been neglected. This is a serious oversight since such breaks are the connecting links between contemporaneous-land- and shallow-inland-sea-derived sediment. The following conclusions result from the study of numerous limestone-shale contacts in outcrops and conventional cores in the period 1957 to 1981. (1) The history of Mid-Continent Pennsylvanian sedimentation, including river mouth shifts and numerous floods, is recorded in limestone-shale contacts. (2) The day-to-day regime was one of minor terrigenous sediment bypassing laterally adjacent embayments in which carbonate sediment accumulated. (3) Day-to-day deltaic progradation was minor with carbonate sedimentation curtailed only along the narrow junction between deltas and adjacent embayments. (4) During and immediately after floods, major deltaic progradation spread relatively thin and widespread deltaic packages which stifled carbonate sedimentation over several hundred square-mi e (minimum) adjacent areas. (5) Thin shale or claystone breaks to featheredge argillaceous partings in limestone record flood-deposited prodeltaic increments. (6) Shale or claystone interbeds (more than 2 ft or .6 m thick) in limestone as well as shale- or claystone-sandstone units tens to a few hundreds of feet thick and laterally equivalent to largely limestone are predominantly the composite record of many floods and many times of small-scale mass movements. (7) Within the thicker terrigenous detritus units, individual flood or individual mass movement record is extremely difficult to define. (8) The lateral movement of life assemblages was slower than the influx of terrigenous clay in flood-generated plumes and organic communities were buried before they could vacate the area. (9) Te rigenous detritus sedimentation rates exceeded carbonate sedimentation rates. (10) The writer is unaware of a convincing modern analog supportive of all aspects of these conclusions. Possibly, the problem is that day-to-day tides reach most present-day shorelines whereas that may not have been so in the Paleozoic epieric sea setting. End_of_Article - Last_Page 418------------

Sedimentology of Westwater Canyon Member, Morrison Formation, Southern San Juan Basin: ABSTRACT

Outcrop measurements taken from trough cross-beds throughout the Westwater Canyon Member indicate that two separate fluvial complexes, each with its own distinct current direction, compose the member along the southern San Juan Basin. Lower Westwater streams flowed east-northeast at all points between Gallup and Laguna, whereas upper Westwater streams flowed consistently southeast over the same area. Measurements in the overlying Poison Canyon sandstone (of economic usage) suggest a return to northeast-flowing streams. Mine maps from the Ambrosia Lake area confirm these current directions in the subsurface. These data preclude the existence of a single fan emanating from the southwest, as proposed by previous workers. The upper Westwater had a source to the northwest which not only changes the overall picture of Westwater deposition but also raises significant questions about uranium mineralization and basin geometry during Morrison time. In many surface sections the lower and upper Westwater sandstones merge as a result of scouring by upper Westwater streams. In the subsurface these areas might appear as sand thicks on an isopach map. Elsewhere on the surface, the Westwater contains numerous breaks. Regardless of the number of shale breaks or total sandstone thickness, the type of deposition (braided) and the current directions (northeast-lower, southeast-upper) remain the same. This suggests that use of isopachs in the subsurface to determine stream type and current direction is invalid. Areas of greatest sandstone thickness in the mineral belt most likely reflect thickening End_Page 795------------------------------ in synclines that were actively growing during deposition. End_of_Article - Last_Page 796------------

Applied Exploration Geology and Uranium Resources of Great Divide Basin, Wyoming: ABSTRACT

End_Page 822------------------------------The Great Divide basin of central Wyoming has been the focus of intense uranium exploration for a decade. Over 10 million lb (4.5 million kg) of uranium oxide has been produced since 1957 from the Crooks Gap mining district in the northern part of the basin. This geologic province is estimated to contain at least 270 million lb (122 million kg) of uranium resources and is the least exploited of Wyoming basins known to contain significant deposits of uranium. The Great Divide basin has the most complex structural, stratigraphic, and sedimentologic history of any Wyoming uranium-producing basin. These complexities have exerted significant controls on the ore-forming processes which have resulted in many variations in the characteristics of alteration features and the geometry of the uranium deposits. The massive thickness of the Eocene Battle Springs Formation provides a host unit of up to 4,000 ft (1,200 m) at a maximum in the northern part of the basin and generally does not contain continuous shale breaks to allow for stratigraphic correlations or for the primary focusing of the ore-forming fluids. The result is a massive roll-front system which may be several thousand feet (1,000+ m) in vertical extent, a few miles wide, and tens of miles long exhibiting extreme irregularities caused by variations in both vertical and horizontal porosity and permeability as well as the structural complexities of the basin itself. Farther west and southwest, where the Battle Springs Formation intertongues with the Wasatch and Green River Formations, continuous shale beds are common, allowing fo easier stratigraphic correlations, good focusing of the ore-forming fluids, and the development of roll-front features similar to those in other Wyoming basins. Gross roll-front features indicate pervasive alteration through most of the basin leaving scattered areas of reduced ground as islands. The roll-front trends which outline these reduced islands display a significant influence by faulting and folding in the basins and contain deposits of uranium of variable tenor scattered along the trends at various lateral and vertical positions. The gross outlines of the redox interfaces outlining the reduced islands are very complex in detail and may represent multiple individual roll fronts, each of which must be mapped separately to insure a complete understanding of the frontal development and to result in the discovery of the greatest amount of uranium possible. End_of_Article - Last_Page 823------------

Facies Distribution of Hosston Sand, Central Texas--Implications to Low-Temperature Geothermal Waters: ABSTRACT

Electric-log patterns indicate that the Hosston Formation of central Texas consists of four principal facies: (A) massive sandstones greater than 80 ft (24 m) thick, (B) distinct sandstones 10 to 80 ft (3 to 24 m) thick interbedded with sharply defined shale breaks, (C) sandstones less than 10 ft (3 m) thick intercalated with shale and siltstone beds, and (D) thin calcareous (dolomitic?) beds with interbedded shale and siltstone. Facies A shows characteristics of fluvial sands, B of either deltaic or strand associations, C of interdistributary and overbank mud and silt deposits, and D of shallow intertidal to supratidal low-energy environments. Cross sections show facies A and B to be concentrated on and north of the San Marcos platform, whereas facies D is present farther downdip. Distinctive sequences of facies B with superposed facies D occur between these two belts. Facies C is somewhat erratic in its distribution. Warm waters are currently being produced from the A and B facies. The nature and distribution of the C and D facies probably preclude their use as a geothermal resource. End_of_Article - Last_Page 1607------------

Steam Drive as a Supplemental Recovery Process In an Intermediate-Viscosity Reservoir, Mount Poso Field, California

This paper describes field pilots and laboratory model studies used to design a full-scale, steam-drive project in the Mount Posofield, California. Actual field results are compared with model predictions. Performance indicates that the field will equal model-prediction recovery Performance indicates that the field will equal model-prediction recovery efficiency, but at a reduced oil-steam ratio. Introduction The Mount Poso field is located in the San Joaquin Valley approximately 14 miles north of Bakersfield, Calif. (Fig. 1). The productive area of the field constitutes some 2, 100 acres, with Shell Oil Co. owning approximately 97 percent of the total acreage, The field was discovered in percent of the total acreage, The field was discovered in 1926 and was developed in three major stages with 104 wells drilled from 1926 to 1930, 115 wells from 1934 to 1936, and 72 wells from 1941 to 1943. Only scattered infill drilling has occurred since 1943. A maximum production rate of 19,700 BOPD with 82-percent water cut production rate of 19,700 BOPD with 82-percent water cut was reached in 1943. The structure in the main area of the Mount Poso field is an easterly rising homocline with a dip of approximately 6 deg. (Fig. 2). Closure to the east and north is provided by the Mount Poso fault, a normal fault with provided by the Mount Poso fault, a normal fault with displacement of approximately 400 ft along the east and 200 ft along the north. Production is obtained from four separate horizons of Lower Miocene age. The Upper Vedder is the shallowest of the four zones and the largest in terms of productive area and volume. The top of the Upper Vedder sand ranges from 1,600 A deep updip to 2,000 ft deep at the oil-water contact. Cumulative oil production through 1970 from the Upper Vedder zone in the main area of Mount Poso is estimated at 90 a million bbl, or approximately 35 percent of the original stock-tank oil in place. This relatively low recovery efficiency under strong water-drive conditions provided a significant target for a supplemental recovery provided a significant target for a supplemental recovery process. process. Geologic and Reservoir Properties The Upper Vedder is a lower coarse to medium-grained, well-sorted, subrounded, unconsolidated sand with an average gross thickness of 75 ft throughout the main area of the field. The sand is of excellent reservoir quality and has good lateral continuity with no major shale breaks. Interbedded, thin, fine-grained silt stringers are present in the Upper Vedder and show a reduction in reservoir quality and higher water saturation. These stringers are not continuous throughout the field but are correlatable only in small areas. The poorer quality of these units could inhibit vertical fluid flow in the Upper Vedder. A typical electric log of the Vedder sands is shown in Fig. 3. Some minor faulting occurs downdip in the central portion of the Upper Vedder reservoir. Sand-to-sand portion of the Upper Vedder reservoir. Sand-to-sand contact is present across these faults because displacement is only 10 to 40 ft. Data from pressure measurements indicate a pressure discontinuity exists across these faults; however, this does not present a barrier to fluid movement. Migration of radioactive tracer material across the downdip fault in Section 9 was observed during tests conducted in 1972, and more importantly, oil production response has been observed updip across this fault resulting from steam injection on the downdip side. The Upper Vedder reservoir has an average porosity of 33 percent and an absolute permeability of 20 darcies. Gross thickness of the Upper Vedder averages 75 ft with 55 ft of net pay. JPT P. 125

Designing a Steamflood Pilot in the Thick Monarch Sand of the Midway-Sunset Field

This paper describes the design and development of a steamflood pilot consisting of six inverted five-spot patterns in Section 26C of the Midway-Sunsetfield. Steam injection will be in the 330-ft Monarch sand. A steamflood simulation study indicated a potential of 60- to 70-percent oil recovery and defined the relative importance of various steamflood parameters. Introduction The reservoir characteristics and production history of Section 26C of Midway-Sunset field make it a favorable candidate for thermal recovery. Current well productivity under cyclic steaming is only about 0.05 BOPD/ft. The estimated ultimate recovery by this method is only 15 percent because of its continuously decreasing percent because of its continuously decreasing effectiveness. Underground combustion is thought to be undesirable for this section because of the reservoir's large thickness and low dip. Based on its predicted and actual performance in other heavy oil reservoirs, performance in other heavy oil reservoirs, steamflooding is the most promising thermal recovery technique for this property. The high capital and operating costs of steamflooding made a pilot desirable to evaluate the process in this field. Other reasons were uncertainties about the geological structure, sand continuity, and the role of gravity override in steamflooding a very thick reservoir. This paper describes the reservoir and its geology, the production history under cyclic steaming, pilot project production history under cyclic steaming, pilot project details, and the results of a simulation study to optimize steam injection and predict performance. Reservoir Characteristics Geology The structural feature associated with the various productive zones in Section 26C of Midway-Sunset field is a productive zones in Section 26C of Midway-Sunset field is a large southeasterly plunging nose. The main productive sands lie on the southwest flank and plunge, where the dip is about 10 deg. . Little production comes from the northeast flank, where the dip is up to 50 deg. . The two areas are separated by a thrust fault that offsets the oil-water contact. A northeasterly trending sand channel in the northern half of the section is developed and productive mainly over the northwest quarter. No production comes from the southwest comer of the section because of sand truncation. The Monarch sand, considered the main productive zone, is of Miocene age and is at an average depth of 1,300 ft. Its thickness varies from 0 to 600 ft and averages 350 ft in the main productive area. Well logs show that the sand is vertically continuous, without any significant shale breaks. A typical induction-electric log is shown in Fig. 1. However, recent cores contain a number of diatomite beds from 0.25 to 6 in. thick. Their areal extent and ability to restrict vertical fluid movement are not known. Rock and Fluid Properties The reservoir rock is an unconsolidated, poorly sorted sand with very fine to very coarse grains. The productive interval consists of turbidite beds generally 2 to 5 ft thick that exhibit normal upward fining of grain size, and that usually are separated by thin, low-permeability diatomite beds. Average porosity is 27 percent and air permeability is 520 md under reservoir conditions. The over-all net-to-gross ratio for the zone is 0.74. The rock is saturated with a 14 deg. API oil whose viscosity is a strong function of temperature (Fig. 2). Current oil saturation in the main part of the reservoir is 59 percent but only 36 percent in the depleted portions near the top. JPT P. 1559

The Role of Geology in Reservoir Simulation Studies

Reservoir simulation models are becoming increasingly sophisticated, resulting in part from the development of both geological and engineering reservoir-description methods. The geologist's research usually follows a four-step procedure that is applicable to most exploration and production operations. production operations. Introduction This paper describes the geological activities required for constructing realistic mathematical reservoir models. The methods used by a geologist are pointed out and the typical data provided by these methods are presented. Also, the geological controls on reservoir properties and the significance of these controls in reservoir performance are summarized. The information presented should be helpful to both the engineer and the geologist involved with reserves estimation and performance prediction. Reservoir simulation models are used increasingly to evaluate both new and mature fields, and to determine the most efficient management scheme. Part of the information contained in the model is provided by the geologist, based on his studies of the physical framework of the reservoir. To be useful, such studies must develop quantitative data. The geologist must also understand the type of engineering data needed and how the engineer can aid the quantification of the framework data. In the following discussion, reservoir simulation models are described briefly. This provides a base for discussion of the geologist's activities in simulation work and the assistance that he requires from the engineer. This discussion is restricted to the reservoir-description phase of simulation studies. The main topic is demonstration of the geological activities used in a study of a pilot-test site. The illustrations indicate the information that is often required for simulation modeling and demonstrate how geologic data can be synthesized to provide quantified information. The general application of the methodology is also described. The technology required for future studies is discussed. Reservoir Simulation Models Over the past few years, improved technology has made it possible to develop detailed and complex computer programs for simulating fluid flow in new and in programs for simulating fluid flow in new and in developed reservoirs. These dynamic models are based on the Darcy equation for fluid flow and on material-balance calculations. The simulation may be in one, two, or three dimensions and may involve one, two, or three fluid phases. Engineering literature contains further phases. Engineering literature contains further information on the variety and historical development of simulation models. A common simulation model is the two-dimensional, multicell cross-section shown in Fig. 1. Such a model is capable of handling vertical variations in porosity, permeability, and capillary properties for a limited (or permeability, and capillary properties for a limited (or typical) area. The variation is represented by assigning values to the essential parameters (Table 1) characterizing each cell or element. These and other data are entered into a computer program, and changes in fluid volumes, fluid state, etc., are calculated for each cell on a predetermined production (or injection) schedule. production (or injection) schedule.The distributions of the reservoir- and nonreservoir-rock types and of the reservoir fluids determine the geometry of the model and influence the type of model to be used. For example, the number and scale of the shale (or dense carbonate) breaks in the physical framework determine the continuity of the physical framework determine the continuity of the reservoir facies and influence the vertical and horizontal dimensions of each cell. Real variations in reservoir parameters may require several cross-sections or a parameters may require several cross-sections or a three-dimensional model. P. 625

History of the Rio Bravo Field

History and reservoir performance of the Rio Bravo field, Kern County, Calif., are summarized. The Rio Bravo and Vedder zones have produced more than 100 million bbl of oil since 1937 with 125 wells completed in these zones. Efforts made to solve some rather unusual operating problems and to promote recovery are described. promote recovery are described. Introduction The Rio Bravo field is located about 15 miles north-west of Bakersfield, Kern County, Calif. (See Fig. 1.) The zones of principal importance are the Rio Bravo and the Vedder; and, although a deeper Helbling and a shallower sequence of Pliocene gas sands are of economic importance, this report is limited to the Rio Bravo-Vedder reservoirs. These other zones, as well as field stratigraphy, have been discussed in previously published papers. The Rio Bravo field is classed as published papers. The Rio Bravo field is classed as a major oil field, having producing 108 million bbl of oil. As of Aug. 1, 1974, total gas sales have amounted to 56.8 Bcf. Discovery was based on reflection seismograph surveys. The discovery well was Union Oil Co. Kernco 1-34 (now Rio Bravo Unit Kernco 85-34), completed Nov. 4, 1937, at a total depth of 11,302 ft in the Rio Bravo sand. Initial production was 2,400 B/D of oil; 39.6 deg. API; 0.7 percent of water; and 1,260 Mcf/D of gas from 11,220 to 11,302 ft. After 30 days, production was 2,588 B/D of oil and 4,306 Mcf/D of gas. This was the first commercial producer in California below 11,000 ft, and for a short period it was the deepest producing well in the world. Although the first few wells were limited to the Rio Bravo sand, the underlying Vedder sand was opened to production in April 1938 in The Superior Oil Co. Wagner 2 well. Development ensued rapidly with the use of large steam-powered rigs, and by the end of 1941, when the U.S. entered World War 11, 97 wells had been completed, Also by that time, except for some edge-well drilling (mainly in 1954, 1955, and 1956), development was substantially complete. Structure and Geology Structurally, the Rio Bravo-Vedder pool consists of an elongated, asymmetrical dome with axis trending in a generally northwest-southeast direction. The accumulation of hydrocarbons, as in the somewhat similar Greeley field adjacent to the southeast, is controlled by anticlinal folding that occurs along the same directional trend. A major fault, also trending in a northwest-southeast direction, bounds a portion of the easterly limits of production in both fields. The Rio Bravo and Vedder are of Miocene age, the former overlying the latter, and separated by a thin, apparently competent, shale break. The Rio Bravo is a blanket sand covering the entire area of the field, which is about 2,300 acres, while the area of the Vedder is somewhat less. As seen from Fig. 2, which shows contours on top of the Rio Bravo, closure in this sand is about 400 ft. The 11,200-ft contour was the approximate average depth of the original water-oil contact. The two north-south normal faults through the easterly limits of Section 28 have not had a major effect on production. Reservoir Rock and Fluid Characteristics The Rio Bravo sand varies between 40 and 70 ft in thickness, and, in general, 75 percent or more of the zone is productive. P. 145

Crude-Oil-Water Emulsions to Improve Fluid Flow in an Oil Reservoir

A field test was conducted to see if oil-in-water emulsions, prepared from petroleum crude oils, would reduce water channeling from injection to producing wells. In a two-year period after emulsion treatment of three water-injection wells, fluid production from offset wells showed increased oil recovery and lower water-oil ratios. Sweep efficiency was also improved. Introduction Channeling of injected water through high-permeability zones in heterogeneous reservoir sands results in low sweep efficiency in the displacement of crude oil. In efforts to improve the distribution of water injected into wells in waterfloods, wellbores have been treated with such solids as cement, ground limestone, and ground leather. However, even if such shallow-penetration methods do effect a better distribution of water into the formation at the wellbore, they are not likely to result in better sweep efficiency unless the higher-permeability zones are separated by shale breaks of very much lower permeability. Even shale breaks with low permeabilities may allow appreciable crossflow because the cross-formation surface areas are large compared with the formation areas at the flood fronts. A deep-penetration method should be more effective. Techniques for obtaining deeper-penetration plugging agents have been reported. These include the use of silica gel, rubber latex, and asphalt. In recent laboratory studies it was shown that oil-in-water emulsions possessed properties that suggested greater oil recovery. Injection of emulsion into sandstone cores improved sweep efficiency by improving the fluid flow heterogeneity of the sandstone cores. Field Investigation, Midway-Sunset Field, Section 5K This paper presents results obtained by injecting surface-prepared oil-in-water emulsion into water injection wells of a waterflood in progress at Section 5K of the Midway-Sunset oil field near Taft, Calif. the forming sections present briefly the geology, the waterflood results, and the results obtained by injecting 33,000 bbl of emulsified crude oil. Geological Information Fig. 1 is a structural map of the Section 5K area, contoured on top of the second finger, Top Oil sand. The structural nose dips to the southeast. A fault is shown as a heavy dashed line running just east of Wells 36, 109, and 126. Fig. 1 also shows an electric log, indicating the thicknesses and depth relationships of the producing intervals. The sands under flood are the first and second fingers of the Top Oil sands, and the Kinsey sand. Well-location hexagons indicate the wells and sands involved in the emulsion-treated and waterflooded areas. The legend gives the key to the hexagons. Note that in many wells not all sands are open. The average permeability of the first and second finger Top Oil sands and the Kinsey sand is 450 md. The sand thicknesses in both the waterflooded and the emulsion-treated areas arefirst finger, Top Oil, 10 to 20 ft;second finger, Top Oil, 10 to 11 ft; andKinsey, 6 to 12 ft. The oil gravities are about 20 degrees API for the first and second finger Top Oil sands, and the Kinsey oil gravity is 25 degrees API. JPT P. 721

Production Logging as Used To Solve Water Injection Problems in the Huntington Beach Offshore Field

In pressure transient testing, interzonal flow or the presence of just one unplugged sand tends to dominate the transient behavior and can easily mask damage in other sands. In those injectors where misleading data are suspected, combining pressure tests with spinner surveys and radioactive- tracer surveys can provide a sound basis for formulating remedial measures. Introduction The Huntington Beach oil field is approximately 41 miles southeast of Los Angeles on a high point along the Newport-Inglewood Fault trend in Orange County, Calif. (Fig. 1). The offshore portion lies in a westerly plunging anticline on the west side of the field. The heavily faulted offshore structure contains a number of thin, minor reservoirs, and three extremely thick, major reservoirs (400 to 800 ft in gross thickness). The thicker reservoirs, composed of continuous, Upper Miocene, unconsolidated sands and interbedded shales, are known as the Jones, the Upper Main and the Lower Main. Waterflooding is currently in progress in the Jones and the Lower Main. The Jones reservoir is divided vertically into two sections (each about 350 ft thick) by a 60-ft continuous shale bed located near the midpoint of the reservoir. This shale break allows independent flooding operations to be conducted in both the upper and lower zones. The Lower Main reservoir has no significant shale beds and the total interval (500 to 650 ft thick) is being flooded in a single, full-zone operation. Extremely high development costs and the low economic return generated from each barrel of secondary oil were the main reasons for developing the floods on a multiple-sand basis. The gravel-flow-packed, slotted-liner completion has been a key factor leading to the success of waterflooding in these thick, unconsolidated, multiple-sand reservoirs. The gravel flow pack provides the sand control needed to economically handle the high-rate, high-cut production arising from the unfavorable mobility ratios typical of California waterflood projects. All injection and response wells drilled projects. All injection and response wells drilled after mid-1966 in the offshore field have the gravel-flow-pack completion. The gravel-flow-packed injector wells have excellent injectivity characteristics, and generally have good injection profiles. However, they have one disadvantage in that many of the normal method such as the selective shut-off, used to control the distribution of injection water in other types of completions, cannot be easily applied to the flow pack. Some of the earlier gun-perforated injectors pack. Some of the earlier gun-perforated injectors completed before mid-1966 are still active in the Lower Jones flood. Others have been replaced with the more effective gravel-flow-packed, slotted-liner completion. Routine down-hole surveying of injector wells to check for profile changes with time has been the principal mechanism for monitoring flood principal mechanism for monitoring flood performance. The continuous spinner survey, the performance. The continuous spinner survey, the radioactive-tracer survey, and the continuous temperature survey are combined to generate this vital information. Maintaining desirable profiles is essential if multi-layered waterflooding is to be successful. Pressure fall-off testing and variable-rate testing in water injection wells are additional methods of monitoring flood performance and appraising wellbore damage. performance and appraising wellbore damage. JPT P. 1083