Areal Continuity Research Articles

Stepping Stone Wetlands, Last Sanctuaries for European Mudminnow: How Can the Human Impact, Climate Change, and Non-Native Species Drive a Fish to the Edge of Extinction?

Throughout their history humans “tamed” not only the Danube River basin land, but also the river and its associated wetlands, drastically influencing their characteristic habitats, associations, communities, and species. One of these flagship endemic fish species in this respect is the European mudminnow (Umbra krameri Walbaum, 1792), influenced by Danube Basin geography, history, politics, and ecology. A study about this European community concern species in the context of long term human impact on its specific habitats, with potential synergic negative effects of climate change, was treated as highly needed, in an international researchers group initiative to support the efforts to provide hope for preserving this fish species and its ecosystems, and brought it back from the brink of extinction. All the characteristic inventoried wetlands which were or some of them still are natural, semi-natural, or accidental anthropogenic habitats, reveal an accentuated diminishing trend of this species areal continuity; fragmentation being the force which skewed it drastically untill now, and inducing diminishing the specific habitats quantitative and qualitative characteristics in the Danube Basin where these fish fight for survival. The main categories of human activities which impacted the climate changes in the context of this species’ habitats are: water regulation, pollution, dredging, draining, and introduction of non-native species. Overall, the diverse human impact in a climate changes in the context of this species’ habitats, Umbra krameri wetlands, creates serious perspectives on negatively influencing this at a very high scale and level. All the inventoried wetlands where Umbra krameri still survive can be considered an ecologically managed as a refuge and stepping stone wetlands, especially in the increasing climate change trend situation. Supplementary inventory studies in the field should be done for the identification of some may be unknown Umbra krameri habitats and populations.

Provenance of sandstones in the Hastings Block, southern New England Orogen: implications for tectonic setting

The Devonian–Carboniferous sandstones in the Hastings Block, southern New England Orogen have a predominantly arc-like provenance based on ternary QFL or QmFLt ternary diagrams and have a lower quartz content than Permian sandstones. Stratigraphically correlated formations show similar QFL components but not the same patterns of sandstone compositional variability for formations that outcrop over a wide area such as the Mingaletta and Pappinbarra formations. It is possible to correlate most of the petrological intervals in the Tamworth Belt with the Hastings Block. The trend of petrofacies from Devonian to Permian for the southern Tamworth Belt, Tamworth Belt overall and Hastings Block, is towards sandstone with more monocrystalline quartz and less feldspar and lithics. The areal pattern of sandstone compositions within individual formations shows similarities in the percentage of quartz, feldspar or lithics. This suggests areal continuity of sandstone compositions within a formation during deposition and that the faulting did not substantially change the formations continuity at the time of deposition. The arc-like provenance of Devonian to Permian sandstones within the Hastings Block indicates that the block was likely an along-strike continuation of the Tamworth Belt. KEY POINTS The Devonian–Carboniferous sandstones have predominantly arc-like provenance on QFL or QmFLt ternary plots with a higher quartz content in younger formations. The Hastings Block and Tamworth Belt sandstones of comparable age are similar but not the same on ternary QFL and QmFLt plots. The areal pattern of the composition of sandstones within formations suggests that faulting was not active during deposition.

The Potential of China's Lacustrine Shale Gas Resources

China is rapidly advancing both theoretical research and practical exploration of her shale gas deposits. Shale gas deposits in China span the gamut of the basic geological features e.g.: marine facies, marine-continental transitional facies, continental facies, and many strata covering the Palaeozoic, Mesozoic, and Cenozoic. Lacustrine shale contained abundant organic matter is mainly developed in the Mesozoic-Cenozoic and is distributed across the North of China, with local occurrences in southern regions. The deposits are characterised by thin monolayer thickness, many inter-beds, large total thickness, rapid lateral variation, varied organic matter types, and a low degree of thermal evolution. The favourable conditions for forming the shale gas enrichment of China's lacustrine organic rich shale mainly include: abundant reservoir porosity, varied organic matter types, large total thickness, good preservation conditions, resource abundance, and favourable surface conditions; the unfavourable conditions mainly include: poor areal continuity, sudden changes in cross-section, and relatively low maturity. At present, continental shale gas exploration of Triassic deposits in the Ordos basin and Jurassic deposits in the Sichuan basin have made significant breakthroughs. Based on the present state of China's shale gas exploration and development, combined with investigation and evaluation, the work demands favourable zone optimisation for China's shale gas resource potential to be best exploited. Shale gas enrichment is considered, not only through determination of the resource's physical boundary with many types and complex geological conditions pertaining to shale gas in China, but in combination with the paucity of shale gas exploration-related geological data and paucity of geological knowledge: the relevant computation parameters are difficult to ascertain accurately, thus the probability volume method is used to evaluate potential continental shale gas strata, including Triassic, Jurassic, Cretaceous and Palaeogene deposits in northern, and north-eastern China, Triassic, Jurassic, Cretaceous, and Palaeogene deposits in northwest regions, some Permian deposits, Jurassic deposits from the upper Yangtze and Dian Qian-Gui(Yunnan-Guizhou-Guangxi) regions, and Jurassic and Palaeogene deposits from the middle-lower Yangtze and southeast region. Estimated continental shale gas resources recoverable in China are 7.92×1012 m3, which accounts for 31.59% of her total shale gas recoverable resources. Among them, continental exploitable resource potential is greatest in northern, and northeast regions of China ( c. 3×1012 m3, some 37.75% of the total shale gas resource recoverable), followed by the northwest region, the upper Yangtze and Dian-Qian-Gui regions, the middle-lower Yangtze, and the southeast region. Geological resources, and recoverable resources, of Jurassic continental shale gas are the largest ( c. 3.77×1012 m3, some 47.6% of the total continental shale gas resource recoverable), followed by Cretaceous, Palaeogene, Triassic, and Permian deposits.

Characterizing CO2 storage reservoirs and shallow overburden for above‐zone monitoring in Texas Gulf Coast EOR fields

AbstractEnhanced oil recovery (EOR) through carbon dioxide (CO2) injection provides an excellent opportunity for commercial sequestration of anthropogenic CO2. A fluvio‐deltaic, deep‐seated salt dome and a strand‐plain, roll‐over anticline from the Gulf Coast region are currently under investigation for the design and implementation of monitoring, verification, and accounting (MVA) plans, in coordination with the commercial surveillance of independent, large‐volume (>1 million ton/year) CO2‐EOR operations. Characterization with wireline logs demonstrates the vertical extent and areal continuity of reservoir sands and geometries of faults that offset the reservoir. To develop the monitoring plan, we focused on several elements: (i) characterization of the zones above the confining unit for above‐zone pressure monitoring, (ii) collection and development of input data for ‘quick‐look’ dynamic modeling of CO2 plume extent and pressure elevation, and (iii) identifying intersections of faults with wellbores in intervals above the regional confining unit for thermal monitoring. Other uncertainties addressed during characterization are the upper extent of faults and the juxtaposition of layers to assess the potential for cross‐fault fluid migration. Successful use of such techniques for MVA, based on uniting elements of existing regulatory monitoring expectations, would lead to the establishment of commercial best practices for effective and rapid characterization of EOR sites in the Gulf Coast region. © 2012 Society of Chemical Industry and John Wiley & Sons, Ltd

Deep-Conformance Control Improves Sweep Efficiency in Mature Waterfloods of the San Jorge Basin

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 129732, ’Deep-Conformance Control by a Novel Thermally Activated Particle System To Improve Sweep Efficiency in Mature Waterfloods of the San Jorge Basin,’ by J.L. Mustoni, SPE, Pan-American Energy; C.A. Norman, SPE, Tiorco; and P. Denyer, BP plc, prepared for the 2010 SPE Improved Oil Recovery Symposium, Tulsa, 24-28 April. The paper has not been peer reviewed. Six pilot applications of a thermally-activated-particle (TAP) system were applied in mature waterfloods in the San Jorge basin (SJB), Argentina. Injected water preferentially flows along the center of the channel, which becomes a “thief zone,” and breaks through to the producers prematurely, leaving much of the oil unswept. Particle technology has blocked thief zones deep in the reservoir. This blocking creates a new pressure gradient in the reservoir that promotes diversion of injected water toward zones with higher oil saturation. Introduction SJB waterfloods are characterized by low recovery efficiency because of an adverse mobility ratio and the reservoir-rock spatial anisotropy. This heterogeneity is typical of fluvial systems with high contrasts of rock properties inside the same channel body. A permeability contrast of 5:1 between the center and the edge of the channel is typical. The three operating contracts are in southern Argentina and cover approximately 3500 km2 and include 3,800 active oil and gas wells producing from an average depth of 2200 m. As of June 2009, production totaled 17 800 m3/d of oil and almost 9×106 m3/d of gas. Approximately one-half of the oil production is attributable to a massive secondary-recovery (waterflooding) operation that injects 27 000 m3/d of water through 620 water-injection wells. Reservoir heterogeneities and the adverse mobility ratio typically increase the water/oil ratio (WOR) to greater than 10 within a few years of startup. Substantial oil is bypassed by injection water and is the target for a new technology to improve sweep efficiency. Complexity of SJB Reservoirs Sand bodies are separate hydraulic units with distinct reservoir pressures and fluid and rock properties. Depending on well location, the total column thickness varies from 400 to 3500 m and can include up to 30 separate reservoirs that are segregated vertically by water-saturated sandstone layers or impermeable shales. Each hydrocarbon trap is relatively small volumetrically, and most channels are 200 to 700 m wide and 3 to 10 m thick. Because areal continuity is limited, adjacent wells are likely to contact different reservoirs or the same reservoir with different petrophysical characteristics. Therefore, pattern configuration is irregular in an attempt to follow the geometry of the productive reservoirs. The injector/producer flow model is unique for each pattern, depending on reservoir heterogeneities, rock/fluid properties, location of the wellbore within the contacted reservoirs, and the number of productive reservoirs present in the injector and associated producers.

Depositional Regimes and Areal Continuity of Sedimentation in a Montane Lake Basin, British Columbia, Canada

Spatially variable sedimentation patterns are described for a small montane lake in southwestern British Columbia through the analysis of contemporary (20th century) varve sequences recovered from a high-density sediment coring program. Average, moderate, extreme, and localized depositional regimes, resolved at decadal to intra-annual scales, are differentiated for the Green Lake system from the stratigraphic record based on the volume and areal extent of the associated deposits. Average-regime sedimentation is mediated by the reliable annual freshet for the catchment. Moderate-regime events of the contemporary period (1930–2000) include periods of rapid glacial recession, extreme late-summer and autumn rainstorm-generated floods, and unusual snowmelt conditions. Only exceptional rainstorm events have led to extreme-regime sedimentation in the lake basin. Spatial sedimentation patterns are quantified by empirically derived surface models. Systematic differences are observed between both moderate and extreme sediment delivery events and the defined average-regime model. Substantial differences are observed between average and extreme regimes because of associated changes in sediment bypassing effects, intermediate sub-basin trapping, and sediment focusing mechanisms. Localized deposits coincide with isolated winter rainstorms in the region and anthropogenic disturbances along lake shorelines. Results indicate that the assumption of areal continuity in lacustrine sedimentation is not always appropriate for making comparisons between the identified depositional regimes. Sediment sampling programs that do not capture these spatially fluctuating sedimentation patterns may lead to biased accumulation chronologies and erroneous paleoenvironmental assessments of important hydroclimatic events.

Leaky Valves in Littoral Sediment Budgets: Loss of Nearshore Sand to Deep Offshore Zones via Chutes in Barrier Reef Systems, Southeast Coast of Florida, USA

The decrease in longshore sediment volumes from north to south, calculated for littoral cells between inlets, indicates significant loss from the littoral drift system along the Florida east coast or localized deposition. The decrease in littoral drift volume from about 490,000 m3 of sediment over a distance of about 550 km (average diminution rate of about 890 m3 km−1) was traditionally accounted for in terms of alongshore deposition and some unknown degree of speculated offshore transport. With the application of laser airborne depth sounding (LADS) technology to bathymetric survey in southeast Florida (2001–2003), recognition of detailed bottom topography became possible for the first time. Significant in this regard was the bathymetric display of macro- and mesoscale morphological features that showed areal continuity of sandy bottoms and the prominent but disjunctive occurrence of relict barrier coral reef tracts that line the shelf edge. Identification of gaps in the line of barrier reefs showed pathways of cross-shore sediment transport from the inner shelf to offshore beyond the shelf edge. Diabathic sediment transport through these reef gaps robs the littoral sediment package by allowing the chuting of sediments during high energy events or when the backreef flats over fill with sand. The reef gaps are thus leaky valves where littoral sediments are periodically chuted offshore and lost from the littoral drift system.

Formation Damage Control: Selecting Optimum Salinity in a Waterflooding Pilot

Abstract Waterflooding in viscous oilfields poses several problems to both the reservoir engineer and the production engineer. Despite unfavourable mobility ratios, it has been noted that injection performance often exceeds theoretically expected values. In the particular case of the waterflooding pilot project across the Cerro Fortunoso field (Malargue, Argentina), the occurrence of several water supplies of widely varying salinity coupled with the usual problems. This paper describes a pilot study designed to determine the optimal salinity of water to be injected, in order to avoid formation damage resulting from clay deflocculation through what is known in the literature as saline shock. As is clearly shown by the results of the study, abrupt changes in the salinity of injected water result in significant decreases in permeability. According to the study, the problem is minimized over certain ranges. Introduction The Cerro Fortunoso field is located in southern Mendoza, Argentina, in an environmental reservation area known as La Payunia, 135 km away from the capital city of Malargue Department (Figure 1). The field is characterized by its complex structure, which consists of a NNE-SSW striking narrow, elongated, and faulted anticline. Four major east dipping, NNE striking thrust faults are predominant. The oil bearing region belongs to the Neuquen Group, and develops along the anticline flanks. A gas cap, consisting mainly of CO2 (85 to 95% molar content), occurs in the upper part of the structure. Geologically, the field involves fluvial deposits exhibiting considerably marked tectonics with high dips (40 ° to 70 °) and intense NE-SW faulting, giving rise to compartmentalized lenticular reservoirs of poor areal continuity. These lenses are sand/shale intercalations with an average porosity in the order of 18% and mean permeability in the 50 mD range. Background There was concern about the feasibility of a secondary recovery project in the Cerro Fortunoso field, which contains a predominantly asphaltene-based, very viscous heavy oil (14 ° API). Complete information regarding the field's main features and its fluids can be found elsewhere(1). Numerical simulation of the reservoir characterization study performed in Canada with Teknica Overseas Ltd. made comple completion of the project feasible(2). The study warned about the potential negative effects of fresh water injection, due to the occurrence of smectite, illite and kaolinite. At an early stage, the most suitable area for implementation of a pilot project was studied and steps were taken to identify for potential water sources. Thus, we faced one of the main difficulties to overcome. As was described above, the field is located in an extremely desertlike environmental protection area where the nearest river (Rio Grande) is 70 km away. No lacustrine deposits or natural springs occur in the area. Water Sources The use of battery-gathered production water was initially ruled out due to low production rates, high emulsion content, and the significant treatment cost that it would require. The use of two additional water sources was also discussed, i.e., production water separated in the Los Cavaos field and production water from a nearby field which is operated by third parties.

Bullwinkle: A unique 3-D experiment

In the spring of 1988, Shell Offshore Inc. acquired two orthogonal three‐dimensional (3-D) surveys at Prospect Bullwinkle, located in the Green Canyon area of the Gulf of Mexico, to aid the development program which began later that year. Two surveys were acquired because of the complexity of the salt structures in the vicinity of the prospect. The independent acquisition and processing of two surveys shot perpendicular to each other provided a unique data set for checking the quality and accuracy of standard 3-D techniques. The high development cost of this deep water (410 m) turbidite field supported the acquisition of two 3-D data sets to provide a valuable redundancy for stratigraphic interpretation. This large scale 3-D experiment has been analyzed in terms of interpretive impact. Detailed comparisons of the seismic images away from the salt complex show good agreement between the two surveys and verify the relative accuracy and repeatability of the acquisition, processing, and interpretation techniques. Structural comparisons between the surveys show that acquisition oriented in a strike direction to the primary salt face yields a superior sediment image, particularly near overhung salt. An examination of the effects of shooting direction on small scale stratigraphic resolution illustrates the importance of fine sampling in the dip direction to the features of interest. Amplitude maps extracted for the main bright spot level show differences in areal continuity that are large enough to affect the geologic model of the prospect.

Brent Field 3D Reservoir Simulation

Summary The Brent field consists of two separate reservoirs and multiple pressurezones with variable PVT fluid properties and condensate-rich gas caps. Thereservoirs are being developed simultaneously with common facilities, presenting many reservoir engineering challenges that cannot be met withclassic tools alone. Reservoir simulation has been an integral and essentialpart of reservoir studies and depletion planning. Increasingly sophisticatedmodels were developed as the tools became available and the reservoirdescription matured. This paper describes the third-generation, 3D model, characterized by detailed geologic description, extensive use of pseudos toreflect reservoir complexity, pseudos to reflect reservoir complexity, and anintricate well-management/ platform-processing program. The platform-processingprogram. The studies performed with this model confirmed the viability of thebase development plan while also quantifying the benefits of alternativedevelopment schemes. Introduction The Brent field, jointly owned by Esso E and P U.K. Ltd. and Shell U.K. Band P Ltd. and operated by Shell, was the first structure in the North Sea Viking graben to be proved oil-bearing and productive. The field, discovered in1971, is about 100 miles northeast of the Shetland Islands (Fig. 1), where theaverage water depth is around 460 ft. Delineation wells proved a productivearea about 11 miles long north/south and 3 miles wide east/west. The fieldcontains two separate reservoirs of Middle and Lower Jurassic Age, called the Brent and Statfjord reservoirs, respectively. The two reservoirs are separated by the Dunlin shale (about 800 ft thick)and overlain by the Upper Jurassic Heather shale and Kimmeridge clay. The fieldis delimited to the north and south by major east/west faults, to the east byan erosional surface and slump faulting, and to the west by the oil/ watercontacts (OWC's). Both reservoirs, overpressured by about 2,000 psia, contain ahigh-shrinkage oil column with depth-dependent oil properties and acondensate-rich gas cap. Total in-place volumes of liquids and gas areestimated at 3.4 billion bbl and 7.0 Tscf, respectively. Commercial production started in 1976 from the Brent Bravo platform. Subsequently, three more platforms were installed, and production rates of morethan 450,000 B/D production rates of more than 450,000 B/D have beenachieved. Brent reservoir development has preceded that of the Statfjord, as indicatedby the January 1, 1988, recoveries for the two reservoirs of 37 and 28%original oil in place (OOIP), respectively. Since 1980, 3D numerical simulationstudies have become a useful aid to evaluate the effect of gas sales rates onreservoir performance, to optimize the remaining well locations and redrills, and to investigate future depletion strategies for the two reservoirs. Reservoir Description Structure. The Brent and Statfjord reservoirs are contained in a westerlydipping (about 7 degrees), monoclinal structure. Fig. 2 is a simplified contourmap of the top of the Brent reservoir. The structure of the Statfjord reservoiris similar to that of the Brent but located deeper and farther east. Fig. 3 isan east/west schematic cross section of Brent field. The original OWC's were at 9,040 and 9,690 ft subsea (ss), while theoriginal gas/oil contacts (GOC's) were interpreted to be at 8,560 and 9,100 ft55 in the Brent and Statfjord reservoirs, respectively. The original GOC's weredifficult to determine from well-log interpretation because the physicalproperties of the reservoir fluids at physical properties of the reservoirfluids at the contacts are very similar, especially for the Statfjordreservoir. Stratigraphy. The Middle Jurassic Brent reservoir (average thickness 750 ft)is stratigraphically divided into four major units, called cycles, on the basis of rock type, depositional environment, shale continuity, andpermeability/porosity variation. Reservoir performance during the later years of production revealed more extensive shale continuity within the upper cyclesthan previously thought. Currently, 12 pressure previously thought. Currently,12 pressure zones (subcycles) have been identified in this reservoir. Thedeepest stratigraphic unit, Cycle 4, is composed of a shaly, finegrained sandwith permeability increasing upward as the sand becomes a coarse-grained, barrier-beach sequence. Cycles 2 and 3, although separated by a fieldwidedelta-top, lagoonal shale (the Mid-Reservoir shale), were deposited basicallyin a similar lagoonal/delta-plain environment. The sands are primarily pointbars, channel deposits, and stream-mouth bars with minor beach deposits. Shaleand coal interbeds have considerable areal continuity. Cycle 1 consists of a lower shaly, lagoon-al/ delta-plain interval somewhatsimilar to Cycle 2 and an upper marine-beach sand with excellent reservoirqualities. JPT P. 589

Basement Influence on the Structural Geology of Southern Oklahoma Inferred from Residual Aeromagnetic Maps

This poster display illustrates magnetic basement control on the structural pattern of southern Oklahoma with a few examples of its influence on petroleum accumulation, including potential fracture reservoirs (i.e., Arbuckle, Viola-Bigfork, Woodford-Arkansas novaculite formations etc.). Exploration for fractured petroleum reservoirs requires knowledge of structural dynamics, structural mechanics, and present state of stress as well as paleostress. High-resolution residual aeromagnetic mapping provides a particularly useful display of areal continuity of basement block pattern that, when considered in context of tectonic plate movements, allows predictions of specific fault reactivation, timing, and sense of displacement. Study of aeromagnetics often provides better understanding, downward and lateral projection of known faults, support for suspected faults, and inference of previously unrecognized faults.

Sedimentology of the Early Devonian Walhalla Group at Walhalla, Victoria

The Early Devonian Walhalla Group is a turbidite sequence deposited on the eastern margin of the Melbourne Trough. Five lithofacies were identified: (1) massive sandstones; (2) turbidites with a basal Ta division; (3) turbidites with a basal laminated division (Tb or Td); (4) fine grained, rippled sandstones interbedded with shales; and (5) shales and siltstones. Episodic reworking by water currents has produced reworking features such as wave‐current and unidirectional current ripples, sharp topped turbidites and interrupted Bouma sequences. The reworking was attributed to storm currents indicating that the sequence was deposited above storm‐weather wave‐base. Palaeobathymetric calculations, based on wave ripple geometry, are consistent with geological observations, and suggest that deposition took place in 65–90 m of water. The relatively shallow water depths implied, combined with the general areal continuity of lithofacies, suggested that the turbidites are sheet‐like deposits originating from a distr...

Monitoring and Mathematical Modeling of Contaminated Ground‐Water Plumes in Fluvial Environments

ABSTRACTGround‐water monitoring to delineate a contaminant plume in fluvial hydrostratigraphic units often is uncertain. Fluvial deposits consist typically of interbedded layers of sands, silts and clays, with buried stream channel deposits of sands or gravels. The channel deposits are often interpreted erroneously to be discontinuous between test holes and in cross section due to their sinuosity. Erroneous conclusions pertaining to the areal continuity of these geometrically complex deposits are inevitable unless the investigator thoroughly understands the depositional environment(s).The hydraulic conductivity of buried stream channel deposits may be several orders of magnitude higher than the matrix materials in which they are enclosed. The higher hydraulic conductivity of buried stream channel deposits has potentially significant ramifications with respect to ground‐water monitoring to delineate the geometry of a contaminant plume migrating through these deposits.Ground‐water monitoring at uranium mill waste disposal sites located in fluvial environments began on a significant scale in about 1977. A uranium mill tailing disposal site located in such an environment in central Wyoming is among the first sites monitored. Thirty‐seven monitor wells were constructed at the site to delineate a seepage plume originating from one of the tailing ponds. This case history illustrates the need for a detailed under—standing of the hydrostratigraphy at a waste disposal site in order to interpret the meaning of ground‐water quality data effectively. Water quality data from monitor wells located on a hit or miss basis often are misleading. The hydrostratigraphic horizon from which a water quality sample is collected must be well defined before the sample analyses can be interpreted quantitatively.

Hydrocarbon Accumulations in Turbidite and Contourite Sands of Upper Cretaceous Forbes Formation, Bounde Creek Gas Field, California: ABSTRACT

Upper Cretaceous marine strata of the Forbes Formation in the northern Sacramento Valley are composed of terrigenous clastic detritus deposited in westward-prograding shelf to basinal sedimentary environments that existed in a south-trending fore-arc basin. Subsurface stratigraphic investigations in the Bounde Creek gas field indicate that upper, middle, and lower informal divisions of the Forbes Formation are composed of submarine fan and slope sediments deposited in the northern extension of the fore-arc basin. The upper Forbes contains deposits of inner slope sub-association. Predominantly very fine to fine-grained contourite and feeder channel sands are present within this upper section. These inner slope deposits are underlain by, and are interpreted to pass westwardly into, outer slope and inner fan deposits that comprise the middle part of the Forbes. Sands within this middle part are generally coarser (very fine to coarse-grained), thicker bedded, and have greater stratigraphic irregularity than vertically adjacent deposits within the formation. The lower Forbes consists of middle and outer submarine fan deposits. Sand bodies in this interval were deposited in channels and as suprafan lobes. Ongoing analysis indicates that channel configurations were, in some places, influenced by synd positional faulting that created steep channel margins and abrupt route alterations and/or abandonments. Sand lobe deposits exhibit areal continuity and lateral lithologic gradations. In the Bounde Creek gas field, distinct hydrocarbon accumulations occur in sand packages that are interpreted to represent: (1) feeder channels and contourites of slope associations; (2) channel lag or mouth bars of middle to inner fan sub-associations; and (3) suprafan lobes of middle to outer submarine fan sub-associations. Paleogeographic reconstructions of depositional horizons within the Forbes reveal a scenario of development and progradation of these inner slope to outer fan associations, and allow geometric projections of hydrocarbon-bearing sand bodies within the system. End_of_Article - Last_Page 468------------

High-Resolution Reflection Seismics at Potential In-Situ Coal Gasification Test Site: ABSTRACT

Figure Sandia National Laboratories is the technical manager for a Department of Energy project directed toward selection and characterization of a potential in-situ coal gasification site in the State of Washington. Prior geophysical investigations at this site in the Centralia-Chehalis coal district included in-line and broadside refraction surveys, VLF and Turam electromagnetic surveys, in-seam seismic wave propagation, and geophysical logging of exploratory boreholes. The results of these surveys, presented at last year's SEG meeting, indicated several anomalous features which we interpreted as faulting. Detailed description of the existing structure, however, could not be determined from the earlier surveys. A high-resolution, seismic reflection survey, reported here, was later conducted to detail the site geologic structure and, thereby, determine areal continuity of objective coal seams. Approximately 12,000 ft (3,658 m) of survey line was obtained over this 62-acre (25 ha.) site, seeking to define the first 1,000 ft (305 m) of the subsurface. A 30-ft (9 m) receiver interval was employed; a portable shotgun source supplied seismic energy yielding a net stack of 1,200% at 15 ft (4.6 m) CDP spacing. Analysis of the resulting reflection data verifies the existence of faulting across the site as interpreted from earlier geophysical and borehole data. However, the geologic structure is found to be more complex than indicated by the earlier data above. A sample reflection record section is given in the figure. Here, faulting of the Big Dirty seam (approximately 170 msec) is evident as are offsets in both deeper and shallower seam. Correlation of prior data and those most recent lead to total site characterization. End_of_Article - Last_Page 896------------

Eigenvector analysis as an aid to airmass recognition

At each of the eighteen Australian Radiosonde stations with a sufficient length of record, the standard upper air variables are converted to potential temperatures, mixing ratio, and equivalent potential temperature for individual soundings. Only data for the winter month of July and data from the atmosphere below 800 mbs is considered. A Principal Component or Eigenvector Analysis reduces these variables into coefficients or weightings on the significant eigenvectors of the data set. It is shown that the weightings on the first eigenvector are representative of the airmass present at the time of the sounding. A partial collective analysis assesses the degree to which the weightings group together, i.e. have similar characteristics in the vertical. Finally the areal continuity of the airmasses, so defined, is discussed.

Hammer Seismic Timing as a Tool for Artificial Recharge Site Selection

AbstractHand‐carried hammer impact seismic timing equipment utilizes the physics of seismic wave refraction to explore stratigraphic changes deeper then those found on soils maps. In alluvial areas, artificial recharge and liquid waste disposal sites are selected from sandy, single‐grained soil series noted for their high water‐transmitting properties through the surface 2 m. The surface horizon seismic velocity exhibited by these soils in the San Joaquin Valley has a very narrow range (V1 = 315–440 m/sec) which gives good definition to the refraction off the second horizon (V2 = 610–2,100 m/sec). Accurate information on depth and horizontal continuity of this second horizon can be obtained in areal surveys. A third horizon may often be described, but its areal continuity is usually masked by intermediate discontinuous layers above it of equal or lesser refractivity. All these horizons are of hydraulic significance for ground‐water recharge by water spreading.

Lower Huronian Sandstones; Correlation Problems and Uranium; Morin Township Area, Ontario

Huronian feldspathic sandstones 30 km north of Thessalon (the Morin Township area) rest noncomformably upon Archean rocks and are overlain by the Huronian Gowganda Formation. They contain uraniferous pyritic quartz-pebble orthoconglomerate, similar to the uraniferous conglomerate ore of the Elliot Lake – Blind River area. The sandstones also contain paraconglomerate units at several stratigraphic levels which are lithologically similar to the Ramsay Lake and Bruce Formations.Trends in Huronian stratigraphy on the North Shore of Lake Huron suggest that in the Morin Township area the Quirke Lake Group is absent and the McKim and Pecors Formations, which contain much argillite, are likely to be very thin or absent. Thus the feldspathic sandstones of the Morin Township area are assigned to the Matinenda and the Mississagi Formations. The most continuous paraconglomerate unit might be correlated with the Ramsay Lake Formation.Huronian feldspathic sandstones lying nonconformably upon Archean rocks 16 km northeast of Sault Ste Marie (the 'Soo Series') and 50 km north of Sudbury, have many features in common with the sequence of the Morin Township area. Stratigraphic subdivision of these two sequences and finer delimitation of potential uraniferous units may be aided by using paraconglomerates such as the Ramsay Lake Formation as marker units. Such subdivision however will be uncertain until the number, exact stratigraphic position and the areal continuity of these paraconglomerates can be assessed better.

Hydrodynamics of Geopressure in the Northern Gulf of Mexico Basin

The behavior of water in geopressured systems of the northern Gulf of Mexico basin is non-Newtonian; hydrodynamic forces are gravity related, but the dominating forces such as osmosis, diagenesis, and terrestrial heat flow are molecular. Introduction The term "geopressure" was first used by Charles Stewart of the Shell Oil Co. to describe abnormally high subsurface fluid pressure, defined by Dickinson as "any pressure which exceeds the hydrostatic pressure of a column of water [extending from the stratum pressure of a column of water [extending from the stratum tapped by the well to the land surface] containing 80,000 mg/1 total solids." A pressure of approximately 0.465 psi is exerted by each foot of such a water column. Geopressure may be expressed in terms of the geostatic ratio, which is the ratio of the observed fluid pressure in an aquifer to the pressure due to the weight pressure in an aquifer to the pressure due to the weight of overlying deposits, computed for the depth at which the aquifer occurs. The geostatic load at any given depth, based upon observed bulk densities of sediments, is generally very close to the following ratio: load (lb/sq in.) depth (ft) equals 1.0, to depths of more than 20,000 ft. This is because the average density of all rocks in the stratigraphic column changes but slowly with depth. Any observed subsurface fluid pressure for which the geostatic ratio is between 0.465 and 1.0 psi i, by this definition, a geopressure. Geologic Occurrence The structural and stratigraphic environments of geopressure in the northern Gulf basin are well known. Three types of reservoir seals necessary to preserve geopressure are illustrated by Dickinson, and described as "small reservoir sealed by pinchout,large reservoir sealed updip by faulting down against thick shale series, and sealed downdip by regional facies change, andrelative position of fault seals in upthrown and downthrown blocks." The depth distribution, range of observed pressures, and hydrodynamic features of geopressured reservoirs then known in the Gulf Coast are reviewed in detail; and the belt they underlie, "35 to 75 miles wide along the coast from the Rio Grande in the southwest to the Mississippi Delta in the east, a distance of approximately 800 miles", is said to coincide approximately with the area of Pleistocene and Holocene formations. As of 1968 it was known that this belt extends far out beneath the Gulf Continental Shelf, and that geopressure occurs at some depth beneath the main del talc sand series in Miocene and Pliocene (Neogen) sediments everywhere Gulfward from the innermost zone of growth faults. (See Table 1.) The role of growth faults in the structural deformation of geopressured sediments is defined by Ocamb and Thorsen. Shelton explains growth faults as "contemporaneous faults" that occurred when "salt and some thick shale units [had] been deformed by uniform flow which, in turn, apparently caused failure by faulting in the overlying paralic sediments." Dickey et al. suggest that the areal continuity and depth of occurrence of geopressure are due to reversal of dip and landward thickening of stratigraphic units associated with growth faults. JPT P. 803

Stratigraphy and Depositional History of the Gaptank Formation (Pennsylvanian), West Texas

The base of the Gaptank Formation is redefined as the base of the conglomerate member, and the underlying Chaetetes -bearing limestone member is transferred to the Haymond Formation. This change gives the Gaptank Formation a more distinctive lithologic base having greater areal continuity. The Gaptank Formation is subdivided into a conglomerate member (bottom) and a limestone member (top) that intertongue, in part, with a sandstone and shale member (middle). Gaptank strata display cyclical repetition and illustrate differences in deposition arising from differences in subaqueous topography. Three submarine land forms persisted as distinctive depositional sites: a shallow shelf (undaform), a sloping surface (clinoform), and a basin (fondoform). Progressive basinward extension of the shallow-shelf areas resulted in more widespread shallow-water environments during deposition of the Gaptank Formation. In outcrop, many individual Gaptank limestone beds can be traced laterally from a shallow-shelf facies into a shelf-edge facies, then into an upper-slope facies. Other modifications in the sedimentary pattern resulted from gentle warping in different areas and at different times during deposition. Comparison of lithologic and depositional features in the Gaptank Formation with those of the late Pennsylvanian strata along the eastern shelf of the Midland basin in central and north-central Texas shows striking similarities.