Shale Markers Research Articles

The Use of Gamma Ray Log Data to Compute and Study the Deposition of Shale Volume of Mishrif Formation in Middle and Southern Parts of Iraq

The shale volume is one of the most important properties that can be computed depending on gamma ray log. The shale volume of Mishrif Formation (carbonate formation from middle Cenomanian- early Turonian) was studied for the regional area of the middle and southern parts of Iraq. The gamma ray log data from seventeen wells ( Kf-3,Kf-4, Ad-1,Ad -2,Dh-1, Bu-47, Ns-2, Ns-4, Am-1,Am-2,Hf-2,Hf-115,Mj-3,Mj-15, Su-7,Wq-15 and Lu-7) distributed in the study area were used to compute the shale volume of Mishrif Formation. From the available data of the considered wells, a regional isopach map of Mishrif Formation was obtained. The isopach map indicates that the maximum thickness of Mishrif Formation is located at the eastern part of the study area. The results of the CPI and the shale volume map, which were computed using the Techlog and surfer software, show that the maximum value of shale volume is located at the southern part of the study area (Su-7 well), while the minimum value is at the eastern part (Hf-2well). According to the classification of Kamel and Mabrouk (2003), Mishrif Formation seems to be a Shaly Formation in the study area, except Halfaya oil field at the eastern part of the study area, which seems as a Clear Formation. The top map of the shale marker bed, which appears in most studied wells, shows a regional trend of the formation toward the northeast. According to the variation of the thickness of the shale marker bed, the study area is divided into four zones.

Learning characteristic natural gamma shale marker signatures in iron ore deposits

Uncertainty in the location of stratigraphic boundaries in stratiform deposits has a direct impact on the uncertainty of resource estimates. The interpretation of stratigraphic boundaries in banded iron formation (BIF)-hosted deposits in the Hamersley province of Western Australia is made by recognizing shale markers which have characteristic signatures from natural gamma wireline logs. This paper presents a novel application of a probabilistic sequential model, named a continuous profile model, which is capable of jointly modelling the uncertainty in the amplitude and alignment of characteristic signatures. We demonstrate the accuracy of this approach by comparing three models that incorporate varying intensities of distortion and alignment in their ability to correctly identify a shale band of the West Angelas member of the Wittenoom Formation which overlies the Marra Mamba Iron Formation in the Hamersley Basin. Our experiments show that the proposed approach recovers 98.72% of interpreted shale band intervals and importantly quantifies the uncertainty in scale and alignment that contribute to probabilistic interpretations of stratigraphic boundaries.

Identify re-development concepts to enhance Abu Roash “C” oil reservoir productivity Sitra Area, Abu Gharadig Basin, Western Desert, Egypt

This study includes a new understanding of the depositional model of Abu Roash “C” Member deposited in Sitra Field in Abu Gharadig Basin during Turonian time, and illustrates the major affecting factors that control the behavior of this reservoir and consequently offer a great opportunity for Sitra field’s future development activities through a new methodology to maximize the field’s ultimate recovery.The Sitra development lease is located in north Western Desert and occupies the central western part of Abu Gharadig Basin and covers the southern extension of Badr El-din Petroleum Company (BAPETCO) leases with an area of 322.4km2. Sitra Area is divided into several structural closures; the main producing one is the Sitra 8 block in which 39 wells were drilled since 1993. Various data from these wells were evaluated to construct the depositional facies models for the Abu Roash “C” reservoir. The log analyses have been integrated with the core descriptions, and ditch cutting data to interpret the depositional facies model that controlled the reservoir characteristics.In Sitra Area the Abu Roash “C” Member exhibits all of the characteristics of the Shallow Marine-Tidal dominated estuaries which are linked to the south with a fluvio-marine environment, the tide-dominated estuaries are represented in tidal channels and tidal flat facies, march deposits, and distributary mouth bars. The best reservoir rock in the Abu Roash “C” Member was deposited as distributary channel fill/Mouth bars that cut through the underlying strata.Two major parasequences were identified, the first lower one was developed during a shallowing upward sequence represented by shale/sand intercalations into which the main Abu Roash “C” reservoir sand bodies are included, and reached its end by the appearance of a laterally extended coal marker nearly one meter thick. This parasequence was deposited subsequently to a falling sea level phase which occurred after the deposition of Abu Roash “D” limestone. The succeeding parasequence (deepening upward) reached its maximum flooding surface (MFS) by the deposition of the widely extensive shale marker being rich in pelagic Pelecypod shells.The resultant stratigraphic units consist of: genetically related depositional cycles (3 cycles) and their components of facies sequences (5 facies types), each cycle has its own distribution, facies classification and reservoir characteristics.

The correlation and sequence architecture of the Ormskirk Sandstone Formation in the Triassic Sherwood Sandstone Group of the East Irish Sea Basin, NW England

AbstractThe existing stratigraphic nomenclature applied to the Early and Middle Triassic Sherwood Sandstone Group in NW England has resulted from more than 150 years of geological investigation, but is characterized by a lithostratigraphic system that is insufficiently flexible to allow for variations in lithology and sedimentary facies within a continental depositional system. A revised well correlation based on the detrital mineralogical and chemical composition of the Ormskirk Sandstone Formation in four offshore wells, that is then extended to provide near‐basin‐wide well correlations using a regional shale marker, confirms previously suggested but unproven diachroneity at the top of the Sherwood Sandstone Group. It also reveals the presence of incised valleys filled by stacked amalgamated fluvial channel sandstones and cut into previously deposited aeolian and sandflat sequences as well as older fluvial channel sandstones. The combination of well correlations indicates that the valleys were incised by a fluvial system flowing NW from the Cheshire Basin into the East Irish Sea Basin and then west towards the Peel and Kish Bank basins. The stratal geometry of the upper part of the Sherwood Sandstone Group is suggested to conform to models of climatically mediated alternations of fluvial degradation and aggradation in response to changes in the relationship between sediment flux and stream discharge. This model is supported in the Sherwood Sandstone Group by climatically driven variations in the non‐channelized facies which record upward wetting and drying cycles that can be locally tied to fluvial incision surfaces, and suggest a hierarchy of at least three levels of climatic cyclicity recorded within the sedimentary succession. Copyright © 2006 John Wiley & Sons, Ltd.

Detection of guided waves between gas wells for reservoir characterization

Guided seismic waves can be used to predict continuity and discontinuity of reservoir structures between wells, with the low‐velocity beds acting as waveguides. We relate guided‐wave signatures to waveguide targets using experimental data acquired at the Stratton gas field in southeast Texas. The observed seismic data indicate the presence of trapped energy in low velocity shale markers between wells 145 and 151. Guided waves in the form of leaky modes are excited, transmitted, and detected in the low‐velocity shale markers at a well separation of 1730 ft (527 m). Dispersion analysis, modeling, frequency–amplitude depth curves, well logs, and lithological information all support the results. Specifically, the characterization of two low‐velocity shale markers, V2 and V5, demonstrates that V2 is more heterogeneous than V5 between the source well 151 and detector well 145. Finally, images of synthetic and real data show the potential applications of the guided‐wave technology as a tool for reservoir characterization.

Reactivation of mature oil fields through advanced reservoir characterization: A case history of the Budare field, Venezuela

Budare field has produced 95 million bbl of oil since discovery in 1954, but a sustained 6 yr decline during the early 1990s reduced daily production to 3000 bbl of oil. Reactivation of the field as a result of this reservoir characterization study increased production by 13,000-16,000 BOPD, a rate that has been maintained in the 4 yr since the study was completed, resulting in an incremental recovery of more than 24 million bbl of oil. This increase in production was achieved through integrated reservoir characterization that identified the depositional heterogeneities and structural complexities responsible for intrareservoir entrapment of the bypassed oil in the field. The main producing zones are the Tertiary-age Merecure and Oficina reservoirs that are interpreted as the deposits of large-scale bed-load and mixed-load fluvial and wave-dominated deltaic depositional systems. The geologic analysis indicates that the large-scale systems are divided internally, or vertically stratified, by thin but widespread shale markers resulting from flooding episodes and that facies variability introduces lateral discontinuities. Syn- and postdepositional faulting further disrupts reservoir continuity. Trends in fluid flow established from engineering analysis of initial fluid levels, response to recompletion workovers, and pressure depletion data demonstrated that these geologic heterogeneities (flooding shale markers, lateral facies pinch-out, and faults) are effective barriers to lateral and vertical fluid flow. Considerable potential for sustained production exists at Budare field because the reservoir units are highly compartmentalized. Identification and targeting of the poorly drained and uncontacted compartments at Budare facilitated the development of a production optimization portfolio that encompassed four principal advanced-recovery opportunities: field extension or step-out; attic areas of the reservoir that are structurally higher than existing production and, hence, poorly drained; stratigraphically and structurally defined compartments that have not been tapped; and compartments that are poorly drained. Successful geologically targeted infill wells and strategic recompletions in these bypassed compartments achieved a sustained fivefold increase in daily production in the mature Budare field.

Seismic sedimentology and regional depositional systems in Mioceno Norte, Lake Maracaibo, Venezuela

Seismic sedimentology is the use of seismic data to study sedimentary rocks and the processes by which they form. It differs from classic seismic stratigraphy in that it uses mainly the horizontal, instead of the vertical, character of seismic data to provide high-resolution images of seismic attribute patterns that can be related to geomorphology and depositional models. A display of seismic attributes on geologic time surfaces is the basic tool of seismic sedimentology. However, there are strict limitations and conditions under which reservoir geometries can be optimally delineated on time and/or horizon slices. Specifically, the slice must be picked at or parallel to a geologic time-equivalent seismic event. This condition is seldom satisfied in practice because of structural dipping and lateral thickness variations of depositional sequences. Stratal slicing of 3-D seismic data overcomes some shortcomings of time slicing and horizon slicing by proportionally slicing between geologic time-equivalent seismic reference events. This facilitates the seismic mapping of sedimentary features on depositional surfaces. Miocene deposits in Mioceno Norte, Lake Maracaibo, Venezuela, provide an excellent example of this seismic sedimentological approach. A high-resolution stratigraphic framework, based on wireline logs, defines approximately 30 genetic stratigraphic units (GSU) separated by marine flooding surfaces, lacustrine flooding surfaces, paleosols, and floodplain shales (Figure 1). These GSUs, each 50–150 ft thick, were correlated by tracing low-resistivity shale markers on logs. The origin, scale, and hierarchy of GSUs in Mioceno Norte are similar to those of depositional episodes and genetic depositional sequences defined by Galloway (1989). A GSU, typically bounded by flooding surfaces or paleosols, represents a cycle of coastal progradation commonly capped by transgressive facies and a condensed section. Detailed isopach and facies mapping based on conventional core and SP/GR log-facies patterns showed that the GSU origins are shoreface, deltaic, and fluvial, respectively. Figure 1. Stratigraphic framework in Mioceno Norte …

Application of Nonmarine Genetic Sequence Stratigraphic Concepts to Reservoir Characterization in the Fluvial-Lacustrine Westbourne Formation, Eromanga Basin, Australia: ABSTRACT

A high-resolution sequence stratigraphic analysis of the Westbourne Formation identified five chronostratigraphic genetic units each separated by thin, but laterally extensive, shale markers interpreted as maximum lacustrine flooding surfaces. The flooding surfaces were primarily identified by their lateral persistence and high gamma-ray log response, but marked changes in bedding architecture across these surfaces also facilitated their identification. The changes in bedding architecture reflect reorganization of the depositional systems from one depositional episode to the next. The Westbourne Formation is interpreted as a series of fluvially-dominated lacustrine delta sequences. Although the genetic units generally display lobate to digitate sand body geometries, sediment transport directions between successive units is highly variable. The complex morphology of the distributary network and accompanying high degree of facies variability indicates shallow lacustrine sedimentation similar to that in the modern inland Niger River delta which provides a modern analog. Westbourne fluid flow trends were established by mapping water encroachment during field development, observing differential depletion in repeat formation test data, and monitoring production response to water shut-off workovers. The fluid flow trends emphasized the highly layered character of the Westbourne reservoirs and integrating these trends with the geologic architecture defined stratigraphic controls on Westbourne flow units. Themore » stratigraphic framework proved essential for unraveling sediment transport patterns and thus, predicting reservoir sandstone distribution. The stratigraphic framework also provided the key to understanding water encroachment and pressure a depletion which, when combined with predicted sandstone geometries, identified several step-out drilling and recompletion opportunities.« less

Strontium Isotopic Composition of Mid-Cretaceous Seawater

The (87)Sr/(86)Sr ratio in fish teeth separated from mid-Cretaceous marl and black shale from the northeastern Apennines and Venetian Alps (Italy) define three periods of low (87)Sr/(86)Sr ratio at 121 to 124 million years ago (Ma), 110 to 115 Ma, and 89 to 91 Ma. The (87)Sr/(86)Sr excursions correspond to oceanic anoxic events represented by the Livello Selli, Livello 113, Livello Urbino, and Livello Bonarelli black shale marker beds and probably reflect an increase in the low-(87)Sr/(86)Sr hydrothermal strontium flux associated with the emplacement of the Ontong-Java and Kerguelen plateaus (120 to 110 Ma) and the Caribbean Plateau (89 to 91 Ma). The modeled flux is consistent with the volumes and eruption rates of the oceanic plateaus but is far smaller than expected from the proposed Cretaceous crustal production rates of 50 to 100 percent greater than modern.

Genetic Stratigraphy of the Williams Fork Formation, Sand Wash Basin, Colorado and Wyoming

The Williams Fork Formation forms the upper part of the Upper Cretaceous Mesaverde Group, Sand Wash basin. The formation can be divided into four genetic depositional sequences each bounded by regionally extensive, low-resistivity shale markers. The markers are continuous across the basin, extending from the southeastern margin to the southern Flank of the Rock Springs uplift. Recognizing these bounding surfaces was relatively straightforward in the eastern half of the basin, where they are interpreted to be maximum marine-flooding surfaces. Recognizing them in the continental facies to the northwest, however, was more difficult, but still achievable with detailed well-log correlation. Presence of the markers to the northwest indicates that either the marine flooding extended farther west than is generally recognized, or that the controls on the flooding (such as shutting off sediment supply) leave a record in the non-marine environment as surfaces of sediment starvation or non-deposition. The four genetic depositional sequences represent progradational clastic wedges of variable areal extend that were deposited during discrete episodes of basin filling. Geometry of the framework sandstones and log-facies character of each of the genetic units indicate a similar depositional style for genetic units 1-3. These units are characterized by upward-coarsening, sandstone-rich linear shorelinemore » systems in the southeast that are bounded updip by aggradational coals and interbedded mudrocks of the coastal plain that, in turn, pass landward into aggradational log motifs of thick, stacked sandstone units and interbedded mudstones on the alluvial plain. Unit 4 is characterized throughout by mudstone-rich coal-bearing facies interpreted as alluvial-plain deposits with lacustrine influence.« less

Control of Depositional Environments, Eustasy, and Gravity and Salt Tectonics on Sandstone Distribution in an Unstable Shelf-Edge Delta, Eocene Yegua Formation, Texas and Louisiana

ABSTRACT Predicting the locations and geometry of downdip sandstone reservoirs in the Yegua trend of Texas and Louisiana is a key challenge to explorationists. In order to formulate and test and stratigraphic models for this purpose, well log, seismic and biostratigraphic data were integrated over a distance of about 350 miles along strike. The resulting correlation framework, based on almost 4,500 well logs, extends from updip on the stable shelf to the downdip limit of well control on the slope. Well logs provide the highest stratigraphic resolution in this data set. On the stable shelf, the entire Yegua-Cook Mountain sand-bearing interval is about 1,000-1,500 ft. thick. Shale markers which show tens to hundreds of miles of continuity along strike bracket progradational cycles 100-300 ft. thick. These log-defined cycles comprise the basic mapping units used in this study. Seismic reflectors in this zone are essentially parallel. Downdip of the shelf, complications were introduced by growth faulting, erosion due to slope failure, mass wasting of sediments overlying failure-induced erosion surfaces, and complex patterns of basin fill seaward of the shelf margin. This complex zone thickens basinward to several thousand feet. All of these zones were further complicated by contemporaneous and post-depositional salt movement in the Houston Salt Diapir Province. Biostratigraphic data were used to determine general ages for downdip section, to indicate prominent discontinuities, and to show environmental trends. Large-scale slope failures occurred several times during Yegua deposition, resulting in regional erosional unconformities. It is not known if their origin is related to eustacy. Slope deposits that onlap extensive erosional surfaces are also well represented, but their precise age relationship to updip systems is unclear. Paleoenvironments were interpreted from maps of log-derived interval isopach, net sand, percent sand, blocky sand and log facies. Each mapping unit is bounded by regionally correlatable shale zones interpreted to have formed during high stands. Strata bounded by the markers represent systems tracts comprising upper delta plain, lower delta plain, mouth bar, distal mouth bar, and shelf. Inferred local shelf bypassing, and channel incision and basinward shifts in facies suggest small but significant falls in sea level during deposition. Each of these cycles resemble depositional sequences but in terms of their duration they are described as high frequency fourth order events. Small-scale stratigraphic complexity within the mapped units suggests frequent autocyclic shifts of depocenters. Effective sand prediction downdip to the shelf edge and upper slope is accomplished using transgressive shale (condensed section or flooding surface) markers as a stratigraphic framework, while recognizing the significant effects of eustatic sea-level changes. Although widespread erosional unconformities, possibly equivalent to sequence boundaries, could be mapped on the slope, neither unconformities nor correlative conformities could be identified sufficiently on the shelf to enable their detailed and regional mapping.

Downdip Sandstone Prediction; Yegua Trend of Texas and Louisiana

Well log, seismic, and biostratigraphic data were integrated for 350 mi along strike to formulate and test depositional and stratigraphic models for predicting downdip sandstones in the Yegua trend. The correlation framework of almost 4,500 logs extends from the stable shelf downdip to the limit of well control of the slope. On the shelf, the Yegua sand-bearing interval is 1,000-1,500 ft thick. Shale markers formed during highstands are continuous for tens to hundreds of miles along strike and bracket progradational cycles 100-300 ft thick. Paleoenvironments were interpreted primarily from maps of log-derived interval isopach, net, percent and blocky sand, and log facies. Systems tracts range through delta plain, mouth bar, shelf, and upper slope. Downdip, complications were introduced by growth faulting, erosion due to slope failure, and complex patterns of basin fill. This zone thickens basinward to several thousand feet. Local shelf bypassing, channel incision, and basinward shifts in facies suggest small but significant eustatic falls. Each of the cycles resembles depositional sequences but in terms of their duration they are described as high frequency fourth-order events. Small-scale stratigraphic complexity within the mapped units suggests frequent autocyclic shift of depocenters. Effective sand prediction downdip to the shelf edge and uppermore » slope is accomplished using transgressive shale markers as a stratigraphic framework, while recognizing the significant effects of eustatic sea-level changes. Although widespread erosional unconformities could be mapped on the slope, neither unconformities nor correlative conformities could be identified sufficiently to enable detailed and regional mapping on the shelf.« less

Sequence Stratigraphy and Tectonic Influences on a Fluvial-Deltaic Lacustrine System: Fort Union Formation, Wind River Basin, Wyoming

The nonmarine Fort Union Formation in the Wind River basin of Wyoming is divided into a fluvial lower part and a lacustrine upper part. The separation between these intervals is a tectonically enhanced sequence boundary recording increased and pronounced subsidence in the Fort Union Depocenter owing to Laramide thrusting. This sequence boundary appears to be recorded in a thin but widespread shale rather than the base of the lacustrine Waltman Shale Member. A sand between the shale marker and the base of the Waltman Shale likely represents a maximum flooding surface. The upper part of the Fort Union is composed of the lacustrine Waltman Shale that is encroached by two coeval but distinct deltaic systems. The persistent progradation of these deltas suggests that the volume of sediment supplied was relatively constant. The similarity in relative rates of progradation and aggradation in the deltaic sequences suggests possible eustatic control. Dominant sigmoidal offlap indicates a gradual decrease in accommodation space with time. Well logs through this interval record an overall regressive unit (a progradational parasequence set) that can be subdivided into a series of progradation parasequences. The upper Fort Union is characterized by repetitive transgressive and highstand systems tracts, with some lowstandmore » wedges present. Individual transgressive-regressive cycles are numerous in the upper Fort Union.« less

Shale-Filled Channel System in Wilcox Group (Paleocene-Eocene), North-Central South Louisiana: ABSTRACT

ABSTRACT Anomalously thick shale intervals of limited extent within normally sandy facies of the Wilcox are evident on published regional electric-log structure sections through south Louisiana. These were investigated with a series of subregional stratigraphic electric-log sections and by mapping. The stratigraphic sections show that in places the shale cuts out nearly 1000 feet (300 meters) of adjacent interstratified sandstone-and-shale section and has lenticular, channellike cross-sectional geometry. The sections also indicate that the uppermost parts of the thick shale intervals are stratigraphically equivalent to, or at least contiguous with, a persistent subregional shale marker bed known informally as the Big Shale, but are distinguishable from it in places by more uniform log character. A map of the anomalously thick and uniform shale indicates a south-trending, relatively straight channel with a single bifurcation in southern Avoyelles Parish. The branches probably continue downdip although they cannot be traced with confidence south of central St. Landry Parish because of the overall shalier Wilcox section and scarcity of adequately deep control wells. The channel shale is analogous to other early Cenozoic subsurface truncational shale masses that have been mostly interpreted as submarine canyon-channel fills. Stratigraphic trapping possibilities are evident from the truncation of bounding permeable units, but the possible continuation of the branches downdip suggests the potential for deep sandy equivalents and deep gas.

Facies Analysis and Correlation in Lisburne Development Area, Prudhoe Bay, Alaska: ABSTRACT

The Lisburne is a widespread group of predominantly shallow marine carbonate rocks, largely Mississippian and Pennsylvanian in age, underlying much of Alaska's North Slope. Near Prudhoe Bay, it is divided into two formations, with the Wahoo overlying the Alapah. Oil was discovered in the Lisburne with the drilling of the Prudhoe Bay State 1 well in 1968. An active delineation program during 1983-84 and detailed geological/geophysical studies have demonstrated the viability of the Lisburne reservoir. Log interpretation for lithology is difficult in the Lisburne, and good core control is essential. A computerized data base has been established containing foot-by-foot descriptions for more than 5,000 ft of core. We have developed a lithofacies classification based on sediment texture, grain size and type, and dolomite content. The upper portion of the Wahoo has received the most attention and is best understood at this time. The most distinctive features of logs in the Lisburne interval are the so-called shale marker beds. These are readily correlatable across the reservoir area and have been used as time lines to divide the Wahoo into a set of detailed subzones. The major marker beds represent distinct breaks in sedimentation. Between these breaks, lithology varies both laterally and vertically. Detailed subzones have allowed us to map individual slices of the reservoir and to have confidence in overall reservoir continuity. Whereas matrix porosity appears to contain most of the hydrocarbons, fracture porosity is important for the interconnection of porous intervals and for productivity of the reservoir. /P> End_of_Article - Last_Page 674------------

Use of Seislog for Basin Evaluation and Field Development: ABSTRACT

Generation of synthetic sonic logs (Seislogs) from seismic data can provide lithologic, porosity, and fluid-content identifications in a variety of End_Page 290------------------------------ geologic settings. Case studies illustrate the type of information that can be extracted from seismic data on carbonate rocks, including North Sea chalk, fractured limestones in Venezuela, and porosity development in regional limestones of western Canada. In the North Sea, 2 adjacent structures that appear similar on conventional seismic sections display porosity development and fluid content changes within the chalk reservoir on the Seislog section. In a South American example, the Seislog display demonstrates the ability of seismic data to locate vertical fracture zones. In western Canada, secondary porosity development within Devonian carbonates was identified on Seislog displays, which led to the extension of a gas field. Examples from southeast Asia display a variety of depositio al environments in Miocene sediments. Shallow-marine and shoreline sands can be identified in a Malaysian example. An example from the Natuna Sea displays a lower delta-plain setting, with regional shale markers and thick clastic packages. An upper delta-plain example (Gulf of Thailand) displays more faulting, expansion of clastic packages, and discontinuous channel sands. End_of_Article - Last_Page 291------------

Middle Member of Minnelusa Formation (Middle and Upper Pennsylvanian)--Implications for Stratigraphic-Trap Oil Accumulations in Powder River Basin, Wyoming: ABSTRACT

The middle member of the Minnelusa Formation (Middle to Upper Pennsylvanian) thins northward across the Powder River basin from about 150 m thick in the Hartville uplift to less than 50 m near the Wyoming-Montana border. Much of the thinning occurs beneath a regional, pre-Permian unconformity, which is identified in the south half of the basin by a mudstone commonly identified as the red shale marker. Cyclically arranged units up to 10 m thick, composed in ascending order of black organic-rich shale, mud-supported dolomite, anhydrite, and quartzose sandstone, characterize most of the middle Minnelusa. The majority of the sandstone units (informally designated in the subsurface as the Leo sandstones) are less than 3 m thick, tabular shaped, and commonly cemented with anhydrite and dolomite. Locally, however, the sandstones, particularly in the first Leo interval, are lenticular and linear, very porous, and attain thicknesses of more than 15 m. Several of these 10 to 15-m thick, linear first Leo sandstone bodies trend northwest across the southern Powder River basin. They probably represent wadi-type channels that have cut across sabkha and associated peritidal deposits during low st nds of sea level. The source of the Leo sandstones is presently uncertain, but at least the lowermost ones appear to be distal equivalents of the Tensleep Sandstone (Desmoinesian) to the northwest. Where the thicker sandstone units of the first Leo cross anticlinal noses such as at Red Bird, Pine Lodge, and Little Buck Creek, they commonly contain stratigraphically trapped oil. The oil in these fields was probably locally derived from the thin (0.5 to 2 m), widespread, black organic-rich shale units in the middle member. The lenticularity, proposed northwest trend, thickness, porosity, and associated probable source rocks make these sandstone units prime targets for oil and gas exploration in the sparsely tested, deep, southern Powder River basin. End_of_Article - Last_Page 778------------

A New Fracturing Technique for Dean Sand

An innovation in fracturing the Dean sand of the Spraberry trend of West Texas is presented. The development of the new technique is described from the ideal suggestions and engineering aspects through the practical application. Results are reviewed and practical observations are correlated with theory. Introduction The Dean sand in the Midland Basin was stimulated by fracturing, using the same design parameters applied to members of the Spraberry-Dean sandstone lithology. The main considerations for a successful treatment were extended flush production and cost reduction. A new technique was applied to the Dean sand that was superior in both categories. This new method pumped alternate volumes of viscous sand-laden and thin spacer fluids to create a fracture system that was propped by "pillars" of sand, creating void channels through which oil was produced. produced. Geology and Reservoir Review The Dean sand is a Permian-Wolfcamp deposition. It is separated from the Wolfcamp by an identifiable shale marker. The separation from the Lower Spraberry is streaked with limestone and brown calcareous shale. The sand is generally medium to fine grained, has a gray-white to brown color, and contains some acid-soluble material and streaks of shale. The clays generally do not swell in fresh water. However, migration of released fines must be considered. Vertical fractures exist in all productive sections. A typical mineralogical analysis, as productive sections. A typical mineralogical analysis, as indicated by X-ray diffraction, is given in Table 1. The Spraberry and Dean sandstones (Fig. 1) are considered to be a lithological unit, rather than a time unit. Based on treating and production data, the Wolfcamp siltstone may be considered part of this unit. Spraberry-Dean sandstone underlies most of the Midland Basin. The westward anticline of the Spraberry trend forms one of the world's largest areal producing units. From the top of the Upper Spraberry to the bottom of the Dean it is 1,200 to 2,000 ft. Depositions of less than 1,200 ft have been unproductive generally. Production has been from sand stringers containing vertical fractures that are separated by shaly gray to brown limestone and streaks of brown calcareous shale. Upper Spraberry and Lower Spraberry usually are identified. Other identifications also have been made. Spraberry sandstones are of Permian-Leonard origin. According to Elkins, porosities average about 8 percent, although up to 13 porosities average about 8 percent, although up to 13 percent has been found. Sand permeability ranges from percent has been found. Sand permeability ranges from 0.001 to 1 md. All productive zones contain vertical fractures of varying width, with an average of 0.0002 in., and are spaced from a few inches to several feet. The production through these fractures has been a definite production through these fractures has been a definite feature of the Spraberry-Dean. Elkins also states that while production has been through these fractures, the fractures contain only a little of the oil in place. Although the adjoining shales also are fractured, little of the producible oil is contained in the fractured shale. producible oil is contained in the fractured shale. Production from Permian sandstones in the Spraberry trend usually followed a definite pattern. The separate zones were commingled and natural production was not tested. Even drillstem testing was rare because of inconclusive results. After stimulation, a high flush-production rate normally was observed. Early reports indicated rates of 1,000 BOPD. JPT p. 167

A Numerical Simulation of Kaybob South Gas Cycling Projects

In this study of the relative performance of downdip, line-drive, and crestal injection schemes, a three-dimensional, three-phase model was used to predict project performance and two-dimensional areal and cross-sectional models were used for supplementary calculations. The results of the study made it clear that a different scheme would have to be used with each of the two units in question. Introduction The Kaybob South field is located approximately 160 miles northwest of Edmonton, Alta., Canada. The Beaverhill Lake A pool was discovered in 1961, and subsequent development resulted in the formation of three Unit areas (Fig. 1). In the first of these Units (Unit 1), a gas cycling scheme was started in 1968. This was necessary because the reservoir fluid exhibits retrograde condensation and is extremely rich in condensate and sulfur. (The simulation of a gas cycling project for Unit 1 has already been discussed in a paper that presents a concise description of the development history, geology, data preparation and predicted performance of the area.) predicted performance of the area.) Two subsequent Units (Nos. 2 and 3) were formed to the south of Unit I as a result of additional drilling. Governmental authorities approved cycling schemes with throughputs of 170 MMcf/D and 445 MMcf/D for Units 2 and 3, respectively, with an initial voidage replacement of about 52 percent of withdrawals. To predict better the performance of these two Units predict better the performance of these two Units under a broader range of cycling pattern alternatives, more sophisticated mathematical models were required than those used for Unit 1. The inclusion of gravity override effects in this new work caused a greater areal dispersal of the injected dry gas fronts. To ensure that the results of this study were true to reality, a group of associated studies was performed before the proposed cycling alternatives were investigated. The results of these auxiliary studies provided:interference and water influx information,pressure drawdown restrictions due to water coning,pseudo relative permeability relationships,reasonably sized grid spacings, anddata on vertical communication and gravity effects. These results were incorported into the main study of cycling pattern alternatives. We shall describe here the work performed and present the results obtained. Reservoir Description Following the formation of Unit 1, additional drilling defined the eastern and southern limits of the reservoir. The Beaverhill Lake gas pool extends approximately 32 miles and currently contains 57 gas wells in the area defined as Units 2 and 3. In this area the reservoir can be geologically divided into two stages of reef growth. The two stages have distinctive lithologies and are separated by a correlatable green shale marker that averages about 5 ft in thickness and is referred to as the "B" shale marker (Fig. 2). The porous layer beneath this shale consists of a medium to coarsely crystalline dolomite. The upper porous unit is distinguished by a fine to medium porous unit is distinguished by a fine to medium crystalline matrix. Initial formation pressure data indicate that a gradient exists from north to south across the pool. This pressure gradient, along with a depressed gas-water contact in most of the Unit 3 area, led to the postulation of interreef interference. There appears to be communication with the Pine Creek and the Pine Northwest fields, as illustrated in Fig. 2. JPT P. 1253

Revised Stratigraphic Nomenclature of Pennsylvanian System, Paradox Basin

Pennsylvanian rocks of the Paradox basin provide an excellent example of rock-stratigraphic units occurring in a clear-cut relation with time-stratigraphic units. These rocks have had many names applied to them; some are confusing and contradictory. A system of simple, formal rock-stratigraphic and time-stratigraphic terms is proposed that is usable even in difficult transition areas where evaporite facies grade into shelf carbonate and terrigenous clastic rocks. The Hermosa Group includes rocks that overlie the Molas Formation of Late Mississippian and Early Pennsylvanian age and underlie the Permian Cutler Group, except in the northwestern part of the basin where the Elephant Canyon Formation of Early Permian age disconformably overlies lithologically similar Pennsylvanian rocks. The Hermosa Group consists of three distinctive formations. The oldest is the Pinkerton Trail Formation consisting mainly of marine carbonate rocks and shale. The overlying unit is the Paradox Formation, a sequence of evaporites, carbonate rocks of restricted marine origin, and dark-colored shale. The Paradox Formation is restricted to strata containing evaporites; time-equivalent rocks containing no evaporites are excluded from the formation. Outside the area of ev porite deposition, the Hermosa Group is called the Hermosa Formation undifferentiated because the individual units become indistinguishable. The youngest formation of the group is the Honaker Trail Formation consisting of carbonate, shale, and sandstone. The Honaker Trail Formation disconformably underlies the Permian rocks in the greater part of the Paradox basin. The group contains rocks of Morrowan(?), Atokan, Desmoinesian, Missourian, and Virgilian Series, identified for the most part by abundant fusulinids. A formal time-stratigraphic nomenclature is proposed for further subdivision of the Paradox and Honaker Trail Formations. This system uses the pay zones of the petroleum geologists. These units are bounded at top and base by dark-colored shales of regional distribution which are approximate time-marker beds according to fusulinid determinations. These time-stratigraphic shale units can be traced through many thousands of square miles, even from the evaporites into non-evaporitic facies of the Paradox basin. The shale markers are 10-25 feet thick in most of the basin, but are thicker toward the east. A formal time-stratigraphic unit named the Four Corners Stage is proposed as a subdivision of the Desmoinesian Series. The Ismay, Desert Creek, Akah, and Barker Creek Substages are included in the new stage. It is suggested that these units (formerly the pay zones) be called substages when used as time-stratigraphic units in the Paradox basin. Alternate type sections are proposed for some Pennsylvanian formations: (1) an alternate (subsurface) type section for the Pinkerton Trail Formation, (2) a subsurface type section for the Paradox Formation, and (3) an alternate type section for the Honaker Trail Formation.