Sand Lenses Research Articles

Influence of Geologic Discontinuities on Hydraulic Fracture Propagation (includes associated papers 17011 and 17074 )

Summary. Geologic discontinuities, such as joints, faults, and beddingplanes, can significantly affect the overall geometry of hydraulic planes, can significantly affect the overall geometry of hydraulic fractures. This can occur by arresting the growth of the fracture, increasing fluid leakoff, hindering proppant transport, and enhancingthe creation of multiple fractures. Results from mineback experimentsand laboratory tests and analyses of these data are integrated todescribe this complex fracture behavior. Introduction Hydraulic fracturing has become a valuable technique forthe stimulation of oil, gas, and geothermal reservoirs ina variety of reservoir rocks. In many applications, onlyshort fractures are required for economic production, andfor these, the constant-height, ideal-fracture models ofPerkins and Kern, Geertsma and de Klerk, and Nordgren Perkins and Kern, Geertsma and de Klerk, and Nordgren may quite adequately represent the fracturing process. In low-permeability gas reservoirs, however, long, penetrating fractures are generally needed; in penetrating fractures are generally needed; in this case, many assumptions about the fracturing processneed to be re-examined. In particular, the widely heldassumption that the hydraulic fracture is an ideal, planarfeature (usually of constant height) is probably untenablein many reservoirs because of geologic discontinuities. Geologic discontinuities such as joints, faults, beddingplanes, and stress contrasts are ubiquitous features whose planes, and stress contrasts are ubiquitous features whose effect on the hydraulic fracture depends on ancillarytreatment and such reservoir parameters as, the treatingpressure, in-situ stresses, orientations of the discontinuities, pressure, in-situ stresses, orientations of the discontinuities, and permeability. Previous analyses and laboratory andfield data have shown the effects of some of thesefeatures but only hinted at others. The effects of stresses, material properties, andunbonded bedding planes on fracture height are welldocumented and will not be discussed in detail in thispaper. Clearly, the in-situ stress distribution is the paper. Clearly, the in-situ stress distribution is the primary factor controlling containment, but when the stress primary factor controlling containment, but when the stress contrasts are small, material property variations may havesome effect. In addition, plasticity of the shale layersmay restrict fracture height. Cohesionless interfaces canprovide an excellent containment feature, but this is provide an excellent containment feature, but this is probably applicable mostly at shallow depths where the probably applicable mostly at shallow depths where the normal stress (in this case, the overburden) acting on theplane is small. plane is small. In a more general context, geologic discontinuities willinfluence the overall geometry and effectiveness of thehydraulic fracture byarresting vertical propagationas described above;arresting lateral propagation asat a fault or sand lens boundary where stresses mayincrease;reducing total length by fluid leakoff;reducing total length by facilitating the formation ofmultiple parallel-fracture systems;hindering proppanttransport and placement because of the nonplanarity ofthe fracture or fracture system; andinducing additionalfracture height growth from higher treating pressuresbecause of many of the above features (e.g., Items 2, 4, and 5). The result may range from negligible tocatastrophic, depending on the values of the ancillaryparameters. parameters. We show examples of several of these features that wereobserved in mineback experiments at the U.S. DOE NevadaTest Site. In addition, we present laboratory data andanalyses that give some guidelines as to when thesefeatures become important. Examples From Mineback Experiments The effects of many geologic discontinuities have beenobserved in mineback experiments conducted at DOE's Nevada Test Site. These facilities are ideal forhydraulic fracturing experiments because they provide anin-situ medium with the appropriate boundary conditions(in-situ stresses and no free surfaces) yet still allowfor detailed examination of the created fractures andgeological features through mineback (physical excavationof the rock to observe the fracture directly). A detailedphysical description can be obtained through photography physical description can be obtained through photography and mapping, and this can be correlated with measuredmaterial properties, in-situ stress distributions, geologicdiscontinuities, fluid behavior, and the operationalparameters of the test. parameters of the test. At tunnel level, there is approximately 1,400 ft [425 m]of overburden that provides a realistic in-situ stressdistribution. The experiments were conducted mainly inash-fall tuffs, which are soft, low-modulus, high-porosity, low-permeability tuffs that allow for easy excavation witha continuous-mining machine. Overlying the ash-fall tuffis an ash-flow tuff, which is much denser and has a highermodulus and lower porosity than the ash-fall tuff. Theash-flow tuff grades upward from an unwelded basal ash-flowtuff into a densely welded ash-flow tuff. Although thevarious volcanic tuffs in which these fractures are propagatedare not the sandstones and shales usually encountered ingas reservoirs, proper application of rock mechanicsprinciples allows the extrapolation of these results to principles allows the extrapolation of these results to gas well conditions. JPT P. 209

North Sabine Lake Field: Complex Deposition and Reservoir Morphology of Lower Hackberry (Oligocene), Southwest Louisiana

Gas and condensate production at the North Sabine Lake field is from sands of the Hackberry wedge of the Oligocene Frio Formation. These lower Hackberry sands were deposited in a preexisting submarine canyon. Multiple sand bodies are present, and five patterns of sand deposition are recognized from SP logs: (1) incised channel fill, (2) braided fan channel, (3) intermediate suprafan, (4) proximal suprafan, and (5) overbank. Although three faults surround the field, the primary trapping mechanism is stratigraphic. The development and production history of the field indicate that many small sand lenses have coalesced to form a single large reservoir; however, differences in permeability have caused variations in water influx and in the levels of gas-water contacts. Sand lenses that are not connected to the larger reservoir are of limited size and have produced small amounts of hydrocarbon. Development of the field has been complicated by casing damage probably caused by reservoir compaction.

Carbonate Platform Accretion by Cementation of Ribbons of Dune Ridge Sediments, Yucatan, Mexico: ABSTRACT

The north coast of the Yucatan Peninsula, Mexico, consists of an almost continuous dune ridge backed by a swamp/estuary system. Conditions peculiar to a platform of almost pure carbonate rock result in delivery to the dune ridge of large quantities of fresh to brackish ground water saturated with respect to calcium carbonate. This ground water, which passes beneath the swamp/estuary system, arrives at the dune ridge charged with CO/sub 2/ and with a head higher than mean sea level. The result, over practically the entire north coast of the peninsula, is that CO/sub 2/ is released from ground water as it arrives at the dune ridge. Concomitantly, CaCO/sub 3/ becomes supersaturated and precipitates in pore spaces in the beach sand to produce a 300-km ribbon of impermeable rock between layers of unconsolidated carbonate sand of unstable mineralogy. This rock layer separates a surface lens of salt water about 3 m thick from the deeper lens of fresh water. Regional conditions require that, deeper still, lies a classic salt water intrusion. They submit that the system they report here may be a common, hitherto unrecognized feature important in the stabilization of large carbonate platforms. One interesting characteristic of this system ismore » that it should result in protected lenses of carbonate sand of unstable mineralogy, which can become lithified at a later time and in a different chemical and physical environment. They welcome suggestions of possible analogs in the geologic record.« less

Distribution of Petroleum Reservoirs Relative to Allocycles and Autocycles, Upper Portion of the Cherokee Group (Middle Pennsylvanian, Desmoinesian), Mid-Continent Region, U.S.A.: ABSTRACT

Sequences of mud rocks, lenticular sandstones, coals, and thin carbonates form autocycles and allocycles in the upper portion of the Cherokee Group. Autocycles delineated in eastern Kansas and northern Oklahoma are relatively local in extent, while allocycles are traceable over the entire region. All autocycles delineated in this study are embedded within the regressive portions of allocycles. Petroleum-bearing sandstones consist of shoestring-shaped and thin sheetlike units in thicker sedimentary lobes. These lobes were deposited as deltaic complexes, which included fluvial and distributary channel sands, interdistributary muds, crevasse splay sands and muds, flood-basin muds, delta-front sands, and predeltaic muds. Delta lobes prograded across the margins of the Middle Pennsylvanian epeiric sea during times of eustatic stillstand or regression. When lobes were abandoned, waves and currents winnowed their upper portions, leaving thin sheetlike lenses of sand. These reworked sands along with marine muds above regressive deltaic sequences form the transgressive parts of autocyclothems. The transgressive parts of allocyclothems, generally consisting of marine shale, resulted from sea level rises that rapidly shifted shorelines far northeastward, moving siliciclastic sources away from the study area. The positions of reservoir-containing deltaic complexes were determined by strandline positions at various sea levels. Extent of eustatic sea levelmore » changes appears to have been the major mechanism that controlled the distribution of petroleum reservoir and source units. In addition, sea level changes probably were a significant factor in the nature of diagenetic alterations that affected reservoir properties.« less

Sand dune stabilization in Central Somalia

As part of a reforestation project in refugee impacted areas of Somalia, a sand dune stabilization pilot project was started in June, 1983, in the Hiiraan region of central Somalia. Thirty ha of the 5.6 km 2 of broken sands have been crosshatched with Commiphora (sp.) cuttings and then planted with trees. The Commiphora cuttings were obtained from nearby areas of natural vegetation. The 1.5 m long cuttings were then planted in dry sand in rows at 10 m intervals, closing to 5 m at the crest of the dune. The live micro-windbreaks formed reduced wind velocity and blowing sand. Perhaps more importantly, they excluded livestock, mainly goats and sheep, from the stabilized area. Eighteen tree/shrub species, grown in plastic pots in a small nursery, were planted between the micro-windbreaks at a 5 m × 4 m spacing. The seedlings were outplanted during the rainy season without supplementary watering. After planting, ground cover increased from 5% to 26% in 18 months. The new vegetation is more dense at the base of the dune, becoming sparser on the steep slopes and crest. These grasses and forbs were started from seed blown in by the wind and caught by the live fencing. They became established and grew because livestock have been excluded from the area. Prosopis juliflora out-performed all other tree species. The largest trees have branches 3 m long after 15 months with extensive root systems. Survival of the seedlings is high and can be attributed to a lens of water approximately 1 m below the surface of the dune (deeper at the crest). Seedling roots, initiated during the rainy season, when the entire soil profile is wet, were able to reach this lens of moist sand.

The flood plain deposits of the Lower Thames

Summary The flood plain of the tidal Thames is underlain with soft clays, peats, silts and sands which in turn rest on gravel. These deposits vary in thickness from a few to tens of metres. As with all soft deposits considerable care is required in order to obtain good quality samples for geotechnical testing. The wide range of soils which often occur down single soil profiles and from location to location can make it very difficult to assign soil parameters for design purposes and careful categorization is required. The presence of varying percentages of organic matter as well as silt and sand lenses in the clays can lead to difficulties in the interpretation of in situ tests such as the field vane. While the foundations for large structures are taken down to the underlying gravel and chalk, problems arise from services and smaller foundations. Stability problems arise during the design and construction of road and flood embankments. Since the gravel aquifer is exposed in the river channel along much of the length, pore water pressures transmitted through gravel during high tides can affect the stability of flood banks. High pore water pressures in the gravel can also lead to instability of excavations unless the pressures are relieved by groundwater lowering. When it is necessary to lower the water pressures for construction purposes consideration needs to be given to the additional settlement of adjacent ground and small structures founded on the alluvium. The paper looks at the distribution of the various soil types, gives typical geotechnical properties and discusses some engineering implications.

Analysis of factors influencing excess heads in shales during burial

Excess fluid pressure in compacting shales is analysed with the help of an approximate solution of the fluid flow equation. Excess head depends on hydraulic diffusivity, thickness of the shale, bulk rock density, and rate of sedimentation. Both storage coefficient and hydraulic conductivity of shales decrease with compaction. Hydraulic diffusivity of shales increases up to a maximum and then decreases with decreasing porosity. In case the rate of permeability decline with compaction is high, then significant excess heads may develop in shales during burial. Shales which include sand lenses acquire higher excess fluid pressures than pure shales because the storage coefficient of sands decreases at a far lower rate than that of shales during burial.

Cenozoic Shallow Marine Sands of North Carolina and South Carolina Sandhills Area: ABSTRACT

Skolithos burrows occur in post-Cretaceous sands of the Sandhills region of the upper coastal plain of North Carolina and South Carolina. The burrows, about 15 cm tall and 1.5-2 cm in diameter, are the only fossils found in this tide-dominated, shallow marine deposit. The sediments are moderately sorted, medium quartz sands; most samples contain less than 10% silt and clay. The major sedimentary structures are horizontal and cross-bedded alternating layers (1-2 cm thick) of clean and more clayey sand. Crossbedded sets are 2-3 m thick and probably represent large sand waves. Some burrows are in the horizontally bedded layers, which also have wavy bedding. This unit is transgressive-regressive. The lowermost sands are very clean, cross-bedded eolian sands. Overlying these are shallow marine sands (alternating clean and clayey layers), which grade upward into a massive sand layer with 20-25% silt and clay. Above the sharp truncation of the massive sand are layers of alternating clean and clayey sand. Interfingering with these sands near the top of the unit at one location, a lens of dark sand contains abundant wood fragments. Burrows also occur in a thin layer that dips gently away from this lens.

Stratton Field, Texas Gulf Coast: A Successful Cased-Hole Re-Evaluation of an Old Field to Determine Remaining Reserves and to Increase Production Level

Summary Recompletion decisions at Stratton field historically have been complicated by the presence of many thin sand lenses of widely varying pay quality. The advent of a cased-hole formation evaluation tool-the dual detector pulsed neutron log (DDPN)-has simplified matters greatly by revealing current, detailed information about reservoir rock properties and fluid saturations. By using 4 years of recompletion data, DDPN log characteristics and log derived parameters have been identified and used successfully to distinguish between gas-, oil-, and water-bearing zones, to predict when fracture stimulations will be required to produce at commercial gas rates, to tify depleted gas zones, and to rank potential recompletion zones according to their respective absolute open-flow potentials (OFP's). potentials (OFP's). Introduction Stratton-Agua Dulce field, discovered in the late 1930's, is a gulf coast field located about 45 miles [72 km] west of Corpus Christi, TX (see Fig. 1). Production is from the Frio and upper Vicksburg formations (Oligocene shaley sands), with the typical wellbore penetrating more than 25 reservoirs scattered throughout a 3,000-ft [914-m] interval (see Fig. 2 for a type log). The reservoirs are relatively thin sand lenses, ranging from 5 to 20 ft [1.5 to 6.1 m] gross interval. The areal extent of these resvoirs is limited by both the many down-to-the-coast faults in the area and reservoir pinchouts attributed to sand depositional environments. Thus recompletion attempts have been complicated not only by the sheer number of reservoirs, but by the complex geology of the area. It is quite common that recompletion attempts reveal a sand that is wet, depleted, or tight but productive in an ediate offset well. Likewise, sands known to be wet or depleted in some wells often are found to be commercial in offset recompletion attempts. With the increase in hydrocarbon value since 1978, recompletion econonmics have improved vastly and created a need for a tool to help identify the best possible zone remaining in the wellbore. The original suite of openhole logs (for all the older wells this consisted of simply an electric log) was not found to be useful since production from a given reservoir in offset wells could raise a water table into the prospective zone or pressure deplete it. Migration of gas between zones behind pipe also has been found to occur. The tool with the highest degree of success in recompletion attempts is the DDPN. Specifically designed to be run in a cased hole, it consists of a high-energy neutron source and two detectors in a logging sonde. The DDPN had been accepted in areas of the Texas gulf coast with highly saline water before 1978; however, the lower Stratton water salinities (15,000 ppm total Cl ) had delayed use of the log in Stratton. After some experimentation it was determined that indeed the DDPN could be used in Stratton since, although not fully understood, the DDPN routinely recorded capture cross-section values (E) in the range of 24 to 30 c.u. for Stratton's wet, shaly Frio sandstones. Equivalent to a much larger indicated water salinity (50, OW to 80, OW ppm total Cl ), this allowed the required resolution to discriminate between hydrocarbonand water-bearing sands. Additionally, the newer generation of DDPN equipment offered both porosity indicators and gas detection. The DDPN, therefore, was selected for cased-hole recompletion analysis and subsequently assisted in both selection of recompletion zones and updating the condition of producing reservoirs. Theoretical calculations based on DDPN tool responses are used to calculate rock porosities and fluid saturations of behind-pipe zones. Schlumberger's experiences with recompletion results since 1978 have determined certain log characteristics and log-derived parameters useful as guidelines to predict the parameters useful as guidelines to predict the commercial potential of a candidate recompletion zone in Stratton field. They used a (effective porosity times water saturation) product of 10% or less as indicative of a commercial hydrocarbon zone. This paper refines the service company pay cutoff by establishing correlations between actual recompletion attempt results at Stratton and the corresponding DDPN curve readings. Over the last 4 years, we ran 27 DDPN logs in Stratton field (see Fig. 3) and attempted a total of 76 recompletions across the logged intervals. JPT p. 105

Hydrogeologic Characteristics of Shallow Glacial Drift Aquifers in Dissected Till Plains (North‐Central Missouri)

ABSTRACTThe dissected till plains physiographic province contains extensive areas of pre‐Illinoian drift in Kansas, Nebraska, Iowa, and Missouri. The drift is typically a clay‐rich, oxidized, and highly weathered till. In many areas of Missouri, this shallow drift represents the only readily available aquifer suitable for domestic and small agricultural users. There are, however, only few published data on the region's hydrogeology. Water budget analyses indicate that approximately 30% of mean annual rainfall is discharged by stream flow and 70% by evapotranspiration. The shallow drift flow systems are best considered unconfined, steady‐state systems. Each watershed corresponds roughly to a local ground‐water system. There is, typically, little hydraulic connection between the shallow drift systems and underlying strata. The drift hydraulic conductivity varies from approximately 1011 m/sec (laboratory tests) to 10−6 to 10−7 m/sec (field tests) when permeable sand lenses or joints are intersected. Ground‐water discharge is concentrated in the immediate vicinity of stream channels, and recharge is concentrated on nearly horizontal hillslope summits. The ground water is generally potable (averaging 455 mg/1 total dissolved solids), but may be high in iron or polluted locally by organic wastes.

Stability of Steel Oil Storage Tanks

Oil storage tanks built on weak and compressible foundations have suffered catastrophic failures due to foundation instability. These experiences are reviewed and used to establish simple procedures for evaluating factors of safety against base shear failure and edge shear failure. Methods for averaging foundation shear strength values for these two modes of failure are described, which make it possible to apply simple bearing capacity formulas to conditions where the shear strength of the foundation varies with depth, and where the foundation contains or is overlain by layers of sand or gravel. Recommendations concerning minimum values of factor of safety against undrained foundation failure are provided. In cases where the first loading of the foundation is very slow, or where drainage is accelerated by sand drains, wick drains, or natural sand lenses, appreciable drainage and strength gain occurs during water load tests. Methods of rehabilitating tanks after failure of the foundation are reviewed.

A New Approach To Fracturing The Milk River Formation In Southeastern Alberta

Abstract The shallow Milk River gas sands of southeastern Alberta contain significant gas reserves. Recent improvements in production logging techniques and greater reservoir and completion knowledge of the Milk River zone indicated that current fracturing techniques were less than adequate to develop the potential of this zone. A series of wells were completed using conventional Milk River fracture treatments and then logged to determine the effectiveness of the fracture treatment on the Milk River zone. The results indicated that only one or two sets of perforations were being stimulated. On the basis of the above information, a stage fracturing technique was designe1t in which the Milk River zone would be fractured in two separate treatments. The fracture treatments were also redesigned to complement the new fracturing technique. Two separate Medicine Hat/Milk River shallow gas projects were chosen to evaluate the effectiveness of the stage fracturing concept and the redesigned fracture treatments. The initial after fracture results indicated a 91% and 130% improvement in productivity from the Milk River zone, for the respective projects. The results obtained to date validate the concept of stage fracturing the Milk River zone. The initial average increased gas production from the Milk River zone of 6 100 m3/d (STD) and its related $20 000 cost has a payout period of approximately 43 days per well. Long term production tests are being undertaken to determine if there is a sustained level of increased production between the wells recently completed and wells previously completed using the old fracturing techniques. Introduction Throughout the past ten years there has been considerable ctivity in the southeastern portion of Alberta, one of the main zones of interest being the gas bearing Milk River formation. Figure I indicates the location of the Milk River formation in Alberta. The Milk River formation is found at relatively shallow depths and hence is often referred to as shallow gas. The Milk River formation has a gross thickness of approximately 110m. The formation is an extremely heterogeneous mixture of coarse grained siltstone varying to fine sandstone irregularly distributed through a dark to medium, grey, soft, silty shale. The siltstones have a high clay content, the predominant constituents being the Kaolinite and Illite clays. The clays often account for as much as 10% of the bulk volume. The average permeability values of the Milk River formation are less than 0.1 md. Hydraulic fracturing is required to increase productivity due to the low permeability thickness of the reservoir and the low reservoir pressure. Identification of potential zones on logs has been hampered by the fact that connate water in the Milk River is fresh and prevents the differentiation of gas from water using a standard resistivity log. The producible sand lenses in this reservoir have been difficult to detect using conventional log analysis due to the shaliness of the reservoir. In the last ten years, better logging tools such as the Dual Spacing Thermal Neutron Decay Time Log and the Neutron Lifetime Log, both previously Described(l) (2), have been developed to better define potential zones.

Use of Microresistivity From the Dipmeter To Improve Formation Evaluation in Thin Sands, Northeast Kalimantan, Indonesia

Summary Estimation of reserves in lenticular reservoirs consisting of many thin-bedded sand/shale sequences is complicated by an overly pessimistic evaluation of sand count and hydrocarbon in place when conventional log interpretation techniques are used. It is probable that thin clean sand lenses have connected permeability. Their contribution to production should be considered in the estimation of reserves. An approach has been devised to improve the evaluation of thin clean sands by introducing accurate bed boundaries between sand and shale laminae as identified clearly on the dipmeter microresistivity curve processing presentation (GEODIP). Dipmeter data are integrated presentation (GEODIP). Dipmeter data are integrated into conventional computer log analyses to yield more realistic estimates of porosity and hydrocarbon saturation throughout the reservoir. The method and the results attained to date are described. Introduction The subject of this paper is a producing field in the Tarakan basin of northeast Kalimantan, Indonesia. It was discovered in late 1975 and has produced since 1977. Reservoirs are upper-middle Miocene sandstones that were deposited in a lower delta plain to front tidaldominated environment. The thin (less than 5 ft [1.5 m]) and interbedded nature of the oil reservoirs throughout this field has led to inaccurate oil in place (OIP) estimates on the basis of conventional log analyses. This paper demonstrates (1) how the thin sands were overlooked in the calculation of reserves in the initial log analysis, (2) the means by which the correct interpretation of this reservoir has been accomplished on 12 producing wells in this field, and (3) how the newly producing wells in this field, and (3) how the newly developed quantitative method of evaluating these thin reservoirs has been accomplished. The inaccuracy of conventional log analysis and its effect on reserve calculations did not appear significant until a later date when cumulative production data were interpreted. These production data, in conjunction with drillstem tests (DST's), which have produced oil from thin sands, have now been evaluated with respect to the log and core data previously gathered. The standard suite of logs was run on each well in this field. However, not until recently did we develop a technique to adapt accurately the log interpretation to evaluate the thin-bedded nature of these reservoirs. This adaptation uses logs and extends normal interpretation with the aid of recently developed computer programs. The interpretation of the reservoir geology has become the most important aspect of the evaluation and analysis of reserves in this producing field. Initial Log Analysis The early logging program included the induction electic log (IES), sonic, formation density log/compensated neutron log (FDC/CNL), MLL/Microlog, and dipmeter (HDT). In later wells, the (induction spherical focused) ISF/sonic replaced the IES and the dual laterolog (DLL) was added also. The oil producing interval is within a gross sand/shale sequence 1,000 to 1,400 ft [305 to 427 m] thick. Initial log analyses indicated relatively clean sands ranging from 5 to 20 ft [1.5 to 6 m] thick. The logs showed the hydrocarbon-bearing sands to have resistivities of more than 10 and commonly to 30 0 in the thicker sands (Fig. 1). Porosities range from 18.5 to 27.7% across the field in the well-developed thicker sands. These sands have produced individually more than 2,000 B/D [318 m 3 /d] on a DST. These clean sands commonly add up to more than 100 ft [30.5 m] of net estimated oil pay in the structurally high wells. (See Fig. 9 for original net pay calculation.) Conventional cores taken over a portion of the reservoir section showed that in addition to major sand bodies there also were sequences that consisted of thinly interbedded clean sand and shale. Early log analyses of these thinly interbedded sequences indicated that throughout the producing section, in addition to the clean sands, there are many other sand intervals that range in their log response from shaly to very shaly. These sands usually exhibit resistivities from 4 to 10 (Fig. 1). Use of standard V-clay (clay volume) corrections of Coriband generally yields average porosities in the range of 5 to 12% in these sands. porosities in the range of 5 to 12% in these sands. JPT p. 1535

Interdune areas of the back-island dune field, North Padre Island, Texas

The small, young (about 100 yrs) back-island dune field on north Padre Island, south Texas, consists of fairly persistant oblique dunes (up to 6 m high) with well-developed interdune areas that grade northwestward to small, ephemeral transverse and barchan dunes with interconnected “interdune” areas, thence sheet sand areas. The subhumid climate is marked by rain associated with frontal systems and tropical storms. Winds are seasonally bimodal—prevailing southeasterly are punctuated by northerly and northwesterly winds with the passage of frontal systems in winter. The entire dune field and individual oblique dunes show a net migration of about 15 m yr −1 to the northwest. The dunes however are on a seasonally reversing track, changing their slipface direction and migration direction with frontal systems. One year of monitoring shows sand transport in the dune-interdune system to be complex and cyclic. During the wind reversals of winter, dunes are very ineffecfive sand traps owing to loss of flow separation, and much sand is lost to the interdune areas. Interdune areas store sand during these wet winter months as a result of the wind reversals and higher moisture content. During the summer, the interdune areas deflate and the dunes build in size. The overall dune field deposit appears to consist of three laterally contiguous zones from southeast to northwest: (1) continuous, climbing oblique dune and interdune deposits; (2) discontinuous lenses of dune sand in overall “interdune layers”; and (3) a chaotic mixture of dune and horizontal deposits of the sheet sand areas. One year's mapping and trenching documents that interdune sedimentary structures are extremely variable laterally and vertically reflecting specific microenvironments within the interdune flat. Wet-surface features consist of current and wave ripples, channel fill, miniature deltas, wrinkle marks, mini-ripples, rills, algae and sand volcanoes. Abundant adhesion structures, rain-impacted ripples, brecciated surfaces and microtopography reflect damp-surface deposits. Dry-surface features are predominately wind ripples; others include small isolated barchan and shadow dunes, organic debris lag surfaces, deflation scours, beetle bioturbation, plant-root structures associated with shadow-dunes, and grainfall from the adjacent dunes. Interdune deposits account for about 40% of the total dune field deposits, which seems reasonable compared to some ancient examples. By virtue of occupying a relative “basin”, interdune deposits are selectively preserved compared to dune deposits. In general, interdune sedimentation is enhanced by non-eolian depositional mechanisms, a high water table, early evaporatic cements, and a variable wind regime. The actual thicknesses of individual dune and interdune deposits are less on Padre than ancient examples, reflecting the relative scale of the bedforms. In many respects, sequences of sedimentary structure in Padre Island interdune deposits are typical of ancient, coastal interdune strata, but some marked departures occur. Adhesion structures, relatively rare in some ancient examples but abundant within Padre interdune deposits, seem favored by the small size of dune and interdune area, the climate and a variable wind regime. Penecontemporaneous deformation, absent in Padre interdune deposits but pronounced in some ancient examples, probably reflects dune size and the nature of the deposits. Wavy laminae in ancient interdune deposits probably result from many causes, but seem best represented by modern examples of evaporitic algal/bacterial-formed structures.

Tectonic Significance of Currant Creek Formation, North-Central Utah: ABSTRACT

The Currant Creek Formation is composed of conglomerate, sandstone, and fine-grained clastic rocks that crop out along the northwestern margin of the Uinta basin in north-central Utah. Lateral gradations in grain size define proximal, medial, and distal parts of coalescing alluvial-fan deposits that prograded eastward from the active Sevier-Laramide orogenic belt during Maestrichtian through Paleocene(?) time. Paleocurrent directions indicate a dominant southerly transport direction and a minor easterly component. Strong east and southeasterly directions, measured in imbricated clasts and in sand lenses in conglomerate, indicate multiple source areas for the detritus. Source of the coarse-grained detritus in the Currant Creek Formation was the Charleston thrust sheet. Conglomeratic clasts are composed of Precambrian and Cambrian quartzite, chert derived from Cambrian and Mississippian carbonate beds, and Pennsylvanian sandstone. These rocks are exposed in the upper plate of the Charleston thrust near Deer Creek Reservoir, Mount Timpanogos, and Strawberry Reservoir. At Big and Little Canyons, the same rocks are exposed in the lower plate. A large basement-cored east-verging anticline that is refolded around the Uinta Mountain structure is present in the region. By the time of its final emplacement, the Cottonwood fold likely formed a small mountain range. Erosional dissection was well under way and Carboniferous, Cambrian, and Precambrian beds were exposed. The Charleston-Absaroka thrust rises in the stratigraphic section farther east, displacing Mesozoic rocks. Reworking of Cretaceous sandstone and shale flanking the newly uplifted western end of the Uinta arch also contributed sediment to southward-flowing streams. End_of_Article - Last_Page 939------------

Fan-Deltaic and Marine Siliclastic Facies of Laborcita Formation, Northern Sacramento Mountains, New Mexico: ABSTRACT

Fan-deltaic sequences in the Laborcita Formation, northern Sacramento Mountains, New Mexico, form a clastic wedge that prograded north and west. These Penn-Permian (Virgilian-Wolfcampian) deposits represent a facies tract of proximal to distal alluvial fan and fan-deltaic facies. Associated nearshore and shelf siliclastics are also developed. Red bed conglomerates interpreted as braided and ephemeral fluvial channel fills are the most proximal deposits. These limestone cobble conglomerates crop out near the Fresnal Canyon fault and are syntectonic deposits. Northern quartzite cobble conglomerates are less proximal and form more continuous sheet-like units. These thick (10 m, 33 ft) and laterally extensive (6 km, 4 mi) conglomerates that contain trough cross-bedded coarse sand lenses associated with intrachannel bars are interpreted as midfan deposits. Shales and thin (20-40 cm, 8-16 in.) progradational distal sands under conglomerates are highly variable in total thickness (20-60 m, 65-200 ft). The thin sandstones show evidence of marine processes and are interpreted as fan-deltaic foreset deposits. Gray limestone and chert conglomerates deposited directly on limestones are thin (0.5-2 m, 1.5-6.5 ft), deposited subaqueously, and exhibit reworking by marine processes. Northern sands are disassociated with conglomerates. These green arkosic sands are relatively thick (3 m, 10 ft) and contain landward (east) accreting tangential foresets. Geometry, stratigraphic position, and minor upward coarsening indicate shelf-bar deposition. Fan-delta source areas shifting during Laborcita deposition. Initial deposits were from the southeast and characterized by limestone/chert conglomerates. Later quartzite/rhyolite porphyry cobble conglomerates prograded from the east and northeast. Ultimately, alluvial fan red beds of the Abo Formation prograded over Laborcita fan-delta and shelf-bar deposits. End_of_Article - Last_Page 512------------

Toward a comprehensive upper quaternary tephra and ignimbrite stratigraphy in New Zealand using electron microprobe analysis of glass shards

New Zealand Quaternary marine and terrestrial sequences contain numerous tephras, or volcanic-ash horizons, that are the distal correlatives of voluminous welded ignimbrite sheets, erupted from central North Island. Electron microprobe analyses of glass shards from the distal tephras demonstrate their homogeneity and are shown to identify each tephra examined. By matching tephras from stratigraphically controlled sequences, the first comprehensive tephra stratigraphy spanning from 50,000 to 700,000 yr ago and covering the New Zealand region is advanced. Analyses on glass shards from the unwelded base of ignimbrite sheets are comparable to the distal tephra analyses and allow correlation between ignimbrites and to the distal tephras. The better exposed tephra record constrains the number of separate eruptive events and the stratigraphy of the ignimbrites, both of which were previously confused by lack of outcrop. Samples from pumiceous marine sediments were found to contain two or more chemically distinct populations of glass. The pumice is in cross-bedded sands or sand lenses within conglomerate, attesting to a shallow high-energy environment where reworking could occur. However, each glass population could be matched to older, known tephras.

Drilling and Sampling Frozen Fine-Grained Soils

Abstract A frozen, moderately plastic clay with a few lenses of shell fragments and sand was successfully sampled using a Denison sampler with a plastic liner. Chilled diesel fuel was used as the drilling fluid. Improvements to this approach are suggested.

Depositional Sequences in Pensacola Clay of Southwest Alabama and Their Significance in Petroleum Exploration: ABSTRACT

ABSTRACT In southwest Alabama, the subsurface Pensacola Clay of Miocene age overlies Tampa Stage sediments of early Miocene age and is overlain by Miocene coarse clastics. The Pensacola Clay consists of greenish-gray to light-olive-gray, slightly calcareous, glauconitic, micaceous, fossiliferous, silty to sandy clay containing beds and lenses of sand, some of which produce gas. Thickness of the Pensacola Clay increases southwestward. The Miocene coarse clastics are micaceous, locally carbonaceous and fossiliferous, and contain numerous beds of small mollusk shells. Within the Pensacola Clay and the overlying Miocene coarse clastics three separate progradational marine sequences may be recognized. Generally, sediments within each sequences coarsen upward. The lowermost sequence, the Amos depositional sequence, contains the gas-productive Amos sand. The middle sequence, the Escambia depositional sequence, has the Escambia Sand at its top. The uppermost sequence includes the upper member of the Pensacola Clay, which contains the gas-producing Meyer sand, and the interfingering Miocene coarse clastics. Foraminifera found in the Pensacola Clay are indicative of outer to inner neritic environments. Foraminiferal species number and diversity, as well as number of planktonic species, generally decrease upward within each depositional sequence indicating an increasingly restrictive marine environment and shallowing of the seas. The presence of Globorotalia fohsi fohsi, G. fohsi robusta, G. fohsi lobata and G. praemenardii in the Amos depositional sequence indicates a middle Miocene age for the sequence. A late Miocene age is indicated for the Miocene coarse clastics by Rangia (Miorangia) microjohnsoni. The three depositional sequences appear to correlate with the TM 2.2, TM 2.3, and TM 3.1 third-order cycles of sea-level change as proposed by Vail et al. in 1977. Isopach and net sand maps of the different depositional sequences are useful for petroleum exploration. Comparison of such maps for the Amos depositional sequence indicates that in Baldwin County Amos sands (the most productive of the Miocene sands) occur where the depositional sequence is locally thinker, probably as a result of postdepositional compaction of clays surrounding sand bodies. Sands found at the top of the Amos depositional sequence are often productive because these sands have been transgressively reworked and are overlain by marine source beds.

Neogene Fore-Arc Basin Development in Northern California: Eel River Basin: ABSTRACT

Strata representing the youngest phase of fore-arc basin development in northern California are exposed in an unusual cross-sectional view across the basin axis. The exposure of a large part of the stratigraphic section of the Neogene Eel River (Humboldt) basin can be attributed to uplift along the northern edge of the Mendocino triple junction. The fore-arc deposits overlie the Mesozoic and Cenozoic accretionary prism and slope deposits of the Franciscan Complex. Outcrop geology of the uplifted southern flank of the basin indicates that the facies and sediment distribution patterns agree with paleobathymetric studies; a complete deep to shallow marine transition is recorded in the basin sediments. Facies studies demonstrate the time-transgressive nature of the sedimentary environments. Proximal facies are landward (east) of coeval deeper water deposits exposed along the coast. The basal contact is clearly depositional on this southern flank of the basin. Sandstones and pebbly conglomerates cut into coastal belt Franciscan accretionary prism sediments inland. A previously undescribed debris flow is conformable on similar Franciscan sediments along the coast. This debris flow is faulted against overlying faulted and fractured basin plain siltstones and fine sandstones (Miocene-Pliocene) which contain thin lenses of shell debris, pebbles, and glauconitic sand. A monotonous accumulation of organic-rich diatomaceous mudstones is capped by amalgamated channels continuing sequences of thin glauconitic sands with locally derived siltstone rip-ups, siltstone, and hemipelagic mudstones. The overlying sediments consist of fine-grained turbidites, thick bioturbated siltstones and fine sandstones, and coarser turbidites. A continental shelf sequence concludes this phase of Eel River basin development. To the south of the main basin outcrop, progressive uplift and faulting related to the migration of the triple junction have left erosional remnants of sediments coeval with Eel River basin rocks. These rocks are found up to 50 km (31 mi) south of the upturned basin edge, suggesting that the basin was at one time more extensive to the south. Shallower depositional environments in some of these basin remnants may indicate the proximity of the original southern edge of the basin. Structural complexities to the south include strike-slip faulting and possible upper Miocene and younger trusting of Franciscan melange over Neogene marine sediments. End_Page 512------------------------------ Shallow gas fields have been developed in the basin; ongoing exploration for deeper oil and gas is not yet definitive. Potentially good source rocks in the deeper parts of the basin, underlying organic-rich Franciscan sediments, and the abundance of potential reservoir rocks higher in the section make this structurally complex onshore/offshore basin an attractive exploration target. End_of_Article - Last_Page 513------------