Downdip Flow Research Articles

Steady-State Flow Through a Subsurface Reservoir with a Displaced Fault and its Poro-elastic Effects on Fault Stresses

We consider steady-state single-phase confined flow through a subsurface porous layer containing a displaced, fully conductive fault causing a sudden jump in the flow path, and we employ (semi-)analytical techniques to compute the corresponding pressures and fault stresses. In particular, we obtain a new solution for the pressure field with the aid of conformal mapping and a Schwarz–Christoffel transformation. Moreover, we use an existing technique to compute the poro-elastic stress field with the aid of inclusion theory. The additional resistance to fluid flow provided by a displaced fault, relative to the resistance in a layer without a fault, is a function of dip angle, fault throw divided by reservoir height, and reservoir width divided by reservoir height. Fluid flow has a larger effect on fault stresses in case of injection than in case of depletion, where injection with up-dip flow results in increased zones of fault slip near the bottom of the reservoir. Opposedly, injection with down-dip flow results in increased slip near the top of the reservoir. An order-of-magnitude estimate of the effect of steady-state flow across displaced faults in the Groningen natural gas reservoir shows that the effect on fault stresses is probably negligible. A similar estimate of the effect in low-enthalpy geothermal doublets indicates that steady-state flow may possibly play a small role, in particular close to the injector, but site-specific assessments will be necessary to quantify the effect.

3D geometry of a shale-cored anticline in the western South Caspian Basin (offshore Azerbaijan)

The internal structure of one of the common fold structures in the western margin of the South Caspian Basin (SCB) has been characterized in 3D using a depth-migrated seismic cube in offshore Azerbaijan. The fold corresponds to a NNW-SSE anticline with a basinward vergence; i.e., eastwards, because in this direction of the margin the SCB is floored by a probable oceanic crust. The anticline has two culminations cut by mud-diapirs and is bounded by two parallel rim synclines with contrasting sedimentary thickness. This anticline deforms congruently the thick Productive Series (PS; Messinian to Late Pliocene), whereas the most recent sequences (<3.1 Ma; e.g., Akchagyl and Apsheron units) onlap or thin towards the fold crest.We reconstruct the existence of two episodes of folding. During deposition of the uppermost PS sequences (ca. 3.5–3.4 to 3.1 Ma), fold uplift initiated with a significantly lower rate than sedimentation. During this epoch, folding was accompanied by basin tilting and by faulting in a basinward normal fault with a limited right lateral, strike-slip component. Motion along this fault zone promoted the downdip flow of a weak layer formed by fluid- and mud-rich sediments (Maykop Formation), which also migrated along strike to build-up the growing anticline. Henceforth, fold growth accelerated and sedimentary units like the Akchagyl (3.1–1.7 Ma) were deposited preferentially in the subsiding flanks. Seafloor upwarping due to folding conditioned the sediment transport, and large deltas adapted their prograding pattern to the growing anticline crest.This structure resembles a detachment fold with a leading, East-vergent forelimb. Nevertheless, the occurrence of progressive tilting accompanying sedimentation and folding, or the mud inflation of the fold core by deep flow parallel to the anticline axis, make this example in the SCB a special example of this fold type.

Depositional features of co-genetic turbidite–debrite beds and possible mechanisms for their formation in distal lobated bodies beyond the base-of-slope, Ulleung Basin, East Sea (Japan Sea)

Abstract A detailed analysis of the MR1 (11–12 kHz) sonar images, chirp (2–7 kHz) profiles, core sediments and 14 C ages from the latest Quaternary lobated bodies (LB) on the deep (> 2100 m water depth) basin plain of the western Ulleung Basin reveals depositional features and context of co-genetic turbidite–debrite beds in the LB on the distal setting and a plausible mechanism for generating these beds. Eight LB are present in the basin plain, ca. 30–60 km beyond the base-of-slope, and were generally deposited retrogressively. Older and more distal LB 1–4 have large dimensions (> 27 km long, 15–25 km wide). In contrast, younger and less distal LB 5–8 are small (8.8–31.5 km long, 1.2–12 km). The muddier, larger LB 1 and 2 were most likely originated from the relatively large-scale sediment failures on the muddy upper slopes (> 350–400 m water depth) between 18.5 and 20.0 cal. ka B.P. On other hand, the sandier, smaller LB 6 and 7 were deposited between 17.0 and 17.5 cal. ka B.P., probably by the relatively small-scale sediment failures on the sandy uppermost slope, shallower than 350–400 m water depth. In LB 1, a lower sandy-mud turbidite is transitional upward into an upper mud-matrix debrite having small, rounded mud clasts. In contrast, LB 6 exhibits a gradual upward change from a lower clay-poor, sandy turbidite to an upper clay-rich, sand-matrix debrite with large, interlocking mud clasts. Each mixed bed in LB 1 and 6 can represent a co-genetic (or linked) turbidite–debrite bed formed by the down-dip flow transformation from turbidity current to debris flow at a point during the same event. The abundant large-scale (up to 20–25 m deep, 3–5 km long) erosions of fine-grained substrates near the base-of-slope area suggest that the down-dip transformation was driven by incorporation of mud via erosional bulking by turbidity currents reaching the base-of-slope area. The different clay/sand content and size/shape of mud clasts in the co-genetic turbidite–debrite beds between LB 1 and 6 imply that the composition (sandy or muddy) and dimension of initial turbidity current approaching the base-of-slope, the volume of eroded masses from the fine-grained substrates, and the transport distance of sediment gravity flows from the erosional areas of muddy substrates can be all important factors controlling the depositional styles of co-genetic turbidite–debrite beds.

Strontium isotopic signatures of oil-field waters: Applications for reservoir characterization

The 87Sr/86Sr compositions of formation waters that were collected from 71 wells producing from a Pennsylvanian carbonate reservoir in New Mexico display a well-defined distribution, with radiogenic waters (up to 0.710129) at the updip western part of the reservoir, grading downdip to less radiogenic waters (as low as 0.708903) to the east. Salinity (2800–50,000 mg/L) displays a parallel trend; saline waters to the west pass downdip to brackish waters. Elemental and isotopic data indicate that the waters originated as meteoric precipitation and acquired their salinity and radiogenic 87Sr through dissolution of Upper Permian evaporites. These meteoric-derived waters descended, perhaps along deeply penetrating faults, driven by gravity and density, to depths of more than 7000 ft (2100 m). The 87Sr/86Sr and salinity trends record influx of these waters along the western field margin and downdip flow across the field, consistent with the strong water drive, potentiometric gradient, and tilted gas-oil-water contacts. The formation water 87Sr/86Sr composition can be useful to evaluate subsurface flow and reservoir behavior, especially in immature fields with scarce pressure and production data. In mature reservoirs, Sr isotopes can be used to differentiate original formation water from injected water for waterflood surveillance. Strontium isotopes thus provide a valuable tool for both static and dynamic reservoir characterization in conjunction with conventional studies using seismic, log, core, engineering, and production data. Roger Barnaby has conducted stratigraphic studies of carbonates and siliciclastics in outcrop and subsurface for 15 years. He holds a Ph.D. from Virginia Polytechnic Institute and a B.S. degree from East Carolina University. Barnaby has worked on sedimentary successions of the Gulf Coast, Permian basin, Alaska North Slope, Middle East, and Caspian region. He maintains interests in carbonate diagenesis and geochemistry.Gregg Oetting received an M.A. degree in geology in 1995 from the University of Texas at Austin. He is the author of six publications concerning geochemical and strontium isotopic variations in Edwards aquifer groundwaters. For the past seven years, Oetting has traded energy futures for leading merchant energy concerns. He works for an independent consulting business in Houston, Texas. Guoqiu Gao received his B.S and M.S. degrees in geology from Central-South University, Hunan, China, and his Ph.D. in geology from the University of Texas at Austin. He works for a major oil company in Houston, Texas. His current interests lie in the field of geoscience computing.

Quantitative measures of textural anisotropy resulting from magmatic compaction illustrated by a sample from the Palisades sill, New Jersey

Early in the crystallization of many tholeiitic basaltic magmas, plagioclase crystals cluster together into a 3-D cellular network, which forms a passive marker capable of recording the deformation that accompanies compaction of crystal mush. Although irregular in detail, the overall network is initially isotropic and only becomes anisotropic as a result of compaction. We have developed four independent methods to quantify the 3-D textural anisotropy of a basalt sample using at least three non-parallel thin sections. Three of the methods are based on the geometrical properties of digitized maps of the feldspar chain networks. One approach focuses on the angular variation of the mean intercept along parallel traverses through the network, another examines the orientation and size distribution of individual links, and the third considers the average shape of interstitial regions outlined by the plagioclase network. The fourth technique approximates the textural anisotropy by the variogram anisotropy of a scanned thin section image. We illustrate the methods using five oriented non-parallel thin sections from a sample of diabase 146 m above the base of the 300-m-thick Palisades sill of New Jersey. Compaction of crystal mush in this sill has previously been postulated on the basis of chemical evidence. The 3-D feldspar network anisotropy based on the first three approaches suggests nearly uniaxial compaction on the order of 8.6% in a direction within 3° of the intersection of the columnar joints at the sample site. A rigorous statistical test based on the statistics of elliptically contoured non-normal multivariate distributions documents that the link-vector distribution in vertical sections are statistically anisotropic at a 95% confidence level and that the overall compaction is 7.9±2.6%. The orientation and magnitude of the 3-D textural anisotropy determined by the image variogram of the non-opaque minerals is almost identical to the mean feldspar network anisotropy; 8.5% compaction in a direction 10° from the columnar joint intersections. The major silicate textural and feldspar network anisotropy axes both plunge almost directly down dip of the sill. On the other hand, the major axis of the variogram anisotropy of the opaque minerals is approximately parallel to the strike of the sill and to the major axis of the anisotropic magnetic susceptibility. The anisotropy of the silicate mineral fabric may reflect down-dip flow of a deformable melt-rich crystal mush, whereas the AMS and opaque textural anisotropy reflects the influence of gravitational stresses during the growth of magnetite in the final stages of melt crystallization. Evidently the Palisades sill was not originally horizontal but was intruded in an orientation close to its present attitude.

ABSTRACT: Effect of Hydrodynamics on Seals in Stratigraphic or Unconformity Type Traps: Case Histories - Updip vs Downdip Flow

ABSTRACT: Effect of Hydrodynamics on Seals in Stratigraphic or Unconformity Type Traps: Case Histories - Updip vs Downdip Flow

Abstract: Spatial Variations in Formation Water Salinities, South Pelto and South Timbalier Areas, Eastern Louisiana Continental Shelf&amp;nbsp;

ABSTRACT Spatial variations in pore fluid pressure, temperature, and salinity were determined from borehole logs along a 100-km long north-south transect from the Louisiana coastline to the shelf edge in the South Pelto and South Timbalier outer continental shelf areas to help identify driving forces and pathways of regional fluid flow and solute transport, information potentially useful also in identifying pathways of hydrocarbon migration. The Pleistocene to Upper Miocene sediments were deposited in fluvial, deltaic, and open marine environments and hence contained waters of fresh to brackish to normal marine salinities, <1 to 35 g/L, at the time of their deposition. Most of these sediments, however, now contain hypersaline fluids having salinities of up to 140 to 170 g/L. Exceptions are shallow Upper Pleistocene fluvial and deltaic sediments that contain fluids less saline than sea water, even though this section is now overlain by seawater. These shallow brackish fluids probably represent the remnant of a regional freshwater lens formed during the last low-stand of sealevel. A regional plume of water having salinities in excess of 140 g/L dips gulfward to the shelf edge at depths of 3 to 5 km below the seafloor. The locus of this plume is within the sandier Pliocene section. Potential sources of dissolved salt within this plume include updip shallow salt structures and the underlying remnants of an allochthonous salt sheet at depths of approximately 6 km. Regional faults in the area may have acted as vertical conduits for upward transport of brines. Down-dip fluid flow was presumably in part gravity-driven. The distal end of this regional salinity plume near the shelf edge is now highly overpressured, and fluid flow should be in the opposite direction, i.e., updip. Hence, this part of the regional salinity structure was probably established prior to over pressuring. The results of this study establish the dynamic nature of formation water flow which has occurred in the outer continental shelf. Further work is now needed to quantify the magnitude of the driving forces and rates of these processes.

Geothermal Regime and Thermal History of the Llanos Basin, Colombia

The Llanos basin is a siliciclastic foreland sub-Andean sedimentary basin located in Colombia between the Cordillera Oriental and the Guyana Precambrian shield. Data on bottom-hole temperature, lithology, porosity, and vitrinite reflectance from all 318 wells drilled in the central and southern parts of the basin were used to analyze its geothermal regime and thermal history. Average geothermal gradients in the Llanos basin decrease generally with depth and westward toward the fold and thrust belt. The geothermal regime is controlled by a moderate, generally westward-decreasing basement heat flow, by depositional and compaction factors, and, in places, by advection by formation waters. Compaction leads to increased thermal conductivity with depth, whereas westward downdip flow in deep sandstone formations may exert a cooling effect in the central-western part of the basin. Vitrinite reflectance variation with depth shows a major discontinuity at the pre-Cretaceous unconformity. Areally, vitrinite reflectance increases southwestward in Paleozoic strata and northwestward in post-Paleozoic strata. These patterns indicate that the thermal history of the basin robably includes three thermal events that led to peaks in oil generation: a Paleozoic event in the southwest, a failed Cretaceous rifting event in the west, and an early Tertiary back-arc event in the west. Rapid cooling since the last thermal event is possibly caused by subhorizontal subduction of cold oceanic lithospheric plate.

Flow of Formation Waters in the Cretaceous--Miocene Succession of the Llanos Basin, Colombia

This study presents the hydrogeological characteristics and flow of formation waters in the post-Paleozoic succession of the Llanos basin, a mainly siliciclastic foreland sub-Andean sedimentary basin located in Colombia between the Cordillera Oriental and the Guyana Precambrian shield. The porosity of the sandy formations is generally high, in the range of 16-20% on average, with a trend of de-creasing values with depth. Permeabilities are also relatively high, in the 102 and 103 md range. The salinity (total dissolved solids) of formation waters is generally low, in the 10,000-20,000 mg/L range, suggesting that at least some strata in the basin have been flushed by meteoric water. The shaly units in the sedimentary succession are weak aquitards in t e eastern and southern parts of the basin, but are strong in the central-western part. The pressure in the basin is close to or slightly subhydrostatic. The underpressuring increases with depth, particularly in the central-western area. The flow of formation waters in the upper units is driven mainly by topography from highs in the southwest to lows in the northeast. Local systems from the foothills and from local topographic highs in the east feed into this flow system. The flow of formation waters in the lower units is driven by topography only in the southern, eastern, and northern parts of the basin. In the central-western part, the flow is downdip toward the thrust-fold belt, driven probably by pore-space rebound induced by erosional unloading, which also is the cause of underpressu ing. Hydrocarbons generated in the Cretaceous organic-rich, shaly Gacheta Formation probably have migrated updip and to the north-northeast, driven by buoyancy and entrained by the topography-driven flow of formation waters; however, the downdip flow of formation waters in CretaceousOligocene strata in the central-western part of the basin could have created conditions for hydrodynamic entrapment of hydrocarbons.

Hydrodynamic Trapping in Mission Canyon Formation (Mississippian) Reservoirs: Elkhorn Ranch Field, North Dakota

Hydrocarbons in Mission Canyon dolomite reservoirs in the Elkhorn Ranch field are trapped by downdip flow of formation water to the northeast. Elkhorn Ranch field is located on a north-plunging anticline with only 10 ft (3 m) of crestal closure. The Mission Canyon is a regressive, shallowing upward sequence of subtidal dolomitized mudstones and wackestones grading upward into sebkha-salina evaporites. Mission Canyon oil production is localized on the north and northeast side of the structure. Maps of porosity pinch-outs and permeability barriers defined from core data, superimposed upon the Mission Canyon structure, show that most of the oil cannot be trapped by stratigraphic facies change. Southwest-trending, updip porosity pinch-outs cross the north-plunging structural axis at an angle so low that hydrocarbons would leak out to the southwest under hydrostatic conditions. Downdip hydrodynamic flow to the northeast provides the critical trapping component. Regional maps of apparent formation water resistivity and water salinity show a region of fresher water south and southwest of the field. A regional potentiometric map constructed using Horner-plot extrapolated shut-in pressure data indicates a head gradient of about 20 ft/mi (4 m/km) to the northeast at Elkhorn Ranch field. This gradient corresponds to a calculated water-oil tilt ofmore » about 50 ft/mi (20 m/km). Observed tilt of the oil accumulation is actually about 25 ft/mi (5 m/km) to the northeast. This discrepancy might be the result of the field having not yet reached equilibrium with the invading water.« less

FLUID HISTORY ANALYSIS — A PROSPECT EVALUATION

Fluid history analysis investigates oil migration and basin hydrology which are important factors affecting hydrocarbon charge to reservoirs. A combination of direct observation and measurement at the mineralogical scale and numerical simulations is used.Fluid inclusions in diagenetic minerals are used to make direct observations about the timing of oil migration and to measure palaeotemperatures. Isotopic compositions of diagenetic minerals are measured for age determination and to identify the sources of ancient pore waters in order to interpret basin hydrology.Integrated interpretation of time specific and time dependent thermal indicators provides a detailed thermal history of the rocks as input to numerical simulations of oil generation. Hydrocarbon fluid inclusions provide an observational check on the theoretical predictions.In the Eromanga Basin in south-west Queensland two areas with different oil migration history are identified. On the Jackson-Challum trend there was a pulse of oil migration synchronous with quartz cementation in late Cretaceous time. On the Tintaburra-Bodalla South trend oil migration followed quartz cementation from the mid Cretaceous to the present day. Jackson oil migrated while the isotopic composition of pore water became increasingly oxygen-18 enriched indicating diagenetic modification during slow flow of groundwater. Tintaburra oil migration occurred during the present regime of downdip flow of relatively oxygen-18 depleted groundwater characteristic of a meteoric origin.

Abnormal Pressures and Their Relation to Oil and Gas Migration and Accumulation: ABSTRACT

Subsurface water exists in a dynamic state, and the condition of hydrodynamic flow, or potential for flow, is indicated by abnormal fluid pressures. Excess pressures indicate updip flow of water and transfer of hydrocarbons from source rock to reservoir in stratigraphic or structural traps. Deficient pressures most commonly indicate downdip flow, reinforcement of capillary-pressure barriers, and enhanced oil columns in stratigraphic traps. The principles of hydrodynamic flow can be applied in either case for prediction of sites for petroleum accumulation; furthermore, a quantitative estimate can often be made of the amount of oil or gas trapped. Excess pressures in the Gulf Coast Tertiary section are generated by several mechanisms: (1) nonequilibrium compaction, (2) clay transformation, (3) aquathermal pressuring, and (4) hydrocarbon End_Page 422------------------------------ generation. These mechanisms operate at different depths and temperatures, but may, in some cases, operate together to produce hydrodynamic flow. The result of flow is development of secondary porosity by dissolution of grains or cement and by hydrocarbon migration. Oil and gas accumulate in local, low-potential volumes of reservoir rock in which the pressures can be either slightly or greatly in excess of normal hydrostatic pressures. Deficient pressures in Rocky Mountain basins are caused by uplift, exposure, and recharge of aquifer systems by meteoric waters. Downdip hydrodynamic flow results in oil columns of unusual height in which the oil trapped by flow greatly exceeds that which can be trapped by capillary-pressure barriers alone. These basins may have locally excess pressures due to clay transformation, or hydrocarbon generation, or locally deficient pressures due to gas blockage in fine-grained rocks. The principles of flow are well established but not widely applied, and there is a need for better documentation of causes for abnormal pressures and the effects of flow. Knowledge of fluid-pressure regime can often be determined from relatively few points of subsurface control for a better understanding of fluid-migration history. Such knowledge is essential to oil and gas exploration in both poorly tested and mature basins. End_of_Article - Last_Page 423------------

The grabens of Canyonlands National Park, Utah: Geometry, mechanics, and kinematics

The grabens of the Needles District, Canyonlands National Park, Utah occur in a 460 m‐thick plate of unfolded, brittle rocks overlying ductile evaporites. These rocks dip gently northwest towards Cataract Canyon of the Colorado River. The river has eroded entirely through the brittle plate, thus permitting downdip flow in the evaporites with consequent extension and faulting within the brittle plate producing systematically spaced grabens which in plan are curved, concave in the direction of dip. Stresses in the brittle plate are similar to those in the brittle surface ice of a valley glacier in extending flow, and stress analyses of crevasse geometry are applicable to the Canyonlands grabens; graben curvature is due to shear stresses acting on vertical planes parallel to the lateral boundaries of the zone of evaporite flow. Flow in the evaporites relaxes basal shear stress on the brittle plate, hence the spacing of grabens is a function only of the thickness of the brittle plate and the strength of the contained rocks. Because both are essentially uniform throughout the area, the grabens tend to be uniformly spaced. Evidence from the field and from experiments suggests that the graben faults initiated at or close to the contact between brittle and ductile rocks and propagated both upward and laterally within the brittle plate. At the surface, the resulting incipient grabens thus had initial widths that were functions only of thickness of the brittle plate and dips of the faults. Because plate thickness and mechanical properties of the rocks parallel to bedding do not vary significantly within the area, these initial widths were similar for all major grabens formed. Grabens terminate in ramps which retain this initial width. An equation based on this model of graben geometry and kinematics relates thickness of faulted plate to graben parameters measurable on photographs. Near the surface, graben geometry and trend indicate a compromise between a curved intermediate principal stress trajectory and two sets of pre‐existing, nearly rectilinear, vertical joints, resulting in grabens characterized by en‐echelon offsets and saw‐toothed walls and which have bounding faults that are vertical near the surface but dip inward at depth.

Mannville (Lower Cretaceous) Basin Of Southwestern Saskatchewan: ABSTRACT

The Mannville Group is represented by the Success (new name), Cantuar, and Pense Formations. The Success Formation, Neocomian in age and lying on a low relief unconformity across the Swift Current region, is dominated by sandstones of quartz and kaolinite with accessory chert and spherosiderite. A bipartite lacustrine to fluviatile succession, the Success Formation is correlated with the upper Morrison and the Lakota sandstone of central Montana. Its provenance is deduced to have been the Precambrian shield. The tripartite Cantuar Formation lies on a high-relief unconformity that dissects the Success and all Jurassic strata in the area. At the base of the pre-Cantuar relief is the McCloud Member (new name). It is composed largely of autochthonous sandstones overlain by an estuarine to marine shale that reaches southward from east-central Alberta to the international border in Saskatchewan as ria-like fingers of the marine Ellerslie Formation. The member is Aptian in age, is correlated with the Third Cat Creek and Cut Bank sandstones of the Kootenai of Montana, and with the Success Formation, is correlated with the lower Mannville of Alberta. The Albian Dimmock Creek and Atlas Members (new name), by virtue of their chlorite and biotite content, constitute the green feldspathic facies of the Mannville and Kootenai that are distributed across southern Saskatchewan from the Rocky Mountains of southwestern Alberta. Fluviatile to deltaic-marine, these deposits were laid down on sedimentation surfaces that progressively encroached upon and largely buried the pre Mannville topography. The Pense Formation is entirely marine and is composed of four units represented in general by (1) basal black shales, (2) dark gray and black bioturbated sandy mudstones, and (3) well-sorted, bedded and crossbedded, fine to medium calcareous sandstones. The last are thought to have formed under wave conditions as a culmination of sediment buildup on the crown of the submerged Swift Current platform prior to renewed foundering of the platform. The Pense sandstones grade into the silts and black shales at the base of the Colorado Group in central Montana. Locally, sedimentation was controlled by episodic uplift of the Swift Current platform from the Middle Jurassic Shaunavon basin. This uplift began during the Late Jurassic and reached a climax (500-700 ft) during the earliest Cantuar, but continued into post-Cantuar-pre-Pense times. Now, the platform forms the broad structural keel of southern Saskatchewan, having down-tilted about 1,600 ft from its early Cantuar elevations. Its mass is furrowed by valley sinks and punctuated with knobs created by the episodic dissolution of salt from the Middle Devonian Prairie Evaporite. The oil reservoirs occupy the northwestern updip edge of the Roseray and Success Formations and lie in mesas enveloped by Cantuar argillaceous valley fill. The oil reservoirs are also under the influence of a massive high-pressure potentiometric cell and its subsidiaries on the west, that are pressurized by the upwelling of waters from the Paleozoic limestones through a regional linear zone of structural weakness. The easterly to southeasterly downdip flow through the Cantuar semi-permeable barriers acts to enlarge the trapping capacity of the reservoirs. Oil prospects lie in unlocated Roseray and Success mesas, and structural highs in general. Other prospects are associated with permeable sandstones of the upper Mannville beds, as well as channel sandstones of the McCloud Member. Gas prospects in addition are found in the updip edge of the Pense Formation. End_of_Article - Last_Page 912------------

Deformational Structures Near Cincinnati, Ohio

Research Article| May 01, 1966 Deformational Structures Near Cincinnati, Ohio H. J HOFMANN H. J HOFMANN Dept. Geology, University of Cincinnati, Cincinnati, Ohio1 1 Present address: Dept. Geology, McMaster University, Hamilton, Ontario, Canada Search for other works by this author on: GSW Google Scholar Author and Article Information H. J HOFMANN 1 Present address: Dept. Geology, McMaster University, Hamilton, Ontario, Canada Dept. Geology, University of Cincinnati, Cincinnati, Ohio1 Publisher: Geological Society of America Received: 28 Dec 1964 First Online: 02 Mar 2017 Online ISSN: 1943-2674 Print ISSN: 0016-7606 Copyright © 1966, The Geological Society of America, Inc. Copyright is not claimed on any material prepared by U.S. government employees within the scope of their employment. GSA Bulletin (1966) 77 (5): 533–548. https://doi.org/10.1130/0016-7606(1966)77[533:DSNCO]2.0.CO;2 Article history Received: 28 Dec 1964 First Online: 02 Mar 2017 Cite View This Citation Add to Citation Manager Share Icon Share Facebook Twitter LinkedIn MailTo Tools Icon Tools Get Permissions Search Site Citation H. J HOFMANN; Deformational Structures Near Cincinnati, Ohio. GSA Bulletin 1966;; 77 (5): 533–548. doi: https://doi.org/10.1130/0016-7606(1966)77[533:DSNCO]2.0.CO;2 Download citation file: Ris (Zotero) Refmanager EasyBib Bookends Mendeley Papers EndNote RefWorks BibTex toolbar search Search Dropdown Menu toolbar search search input Search input auto suggest filter your search All ContentBy SocietyGSA Bulletin Search Advanced Search Abstract The maturely dissected area immediately west of Cincinnati, Ohio, is underlain by rhythmically interbedded Upper Ordovician mud-stones and calcarenites that dip less than one-half degree to the northwest. Structure contours drawn on the lower and upper contacts of the Fairview Formation (lower Maysville) show very low and broad, northwest-plunging ridges and troughs that roughly coincide with present topographic highs and lows; these ridges and troughs may also reflect original sea-floor irregularities. Especially interesting are deformational structures visible in outcrops, i.e., small folds, thrust faults, and joints.Typical structures are small asymmetric anticlinal folds, 1–3 feet high and 10 feet across, which are cut by one or more low-angle thrusts. The thrusts have dislocations up to 1 or 2 feet and terminate in bedding planes. These structures are observed almost exclusively in stream cuts, situated topographically below 700 feet elevation, stratigraphically in the Kope Formation and lower part of the Fairview Formation, and lithologically in thick mudstone beds separated by thin limestone layers. When the structures of the entire area are considered, a compilation of their strike directions produces a slight maximum to the north-northwest. Locally, they are generally transverse to the creek in which they occur although some types are parallel to it.In decreasing abundance, systematic vertical joints have formed along four main directions–northwest, north-northeast, east-northeast, and north-northwest. The strongest trend follows the direction of a parallel drainage, as well as the ridges and troughs shown in the structure contours of the Fairview contacts, and the northwest prong of the Cincinnati Arch.The deformational structures, which are of complex origins, have been formed by gentle postdepositional draping of the beds over the regional Arch; unloading by erosion and intrastratal down-dip flow of mudstone by gravitational squeezing; expansion; and sliding and slumping. Broad irregularities of the depositional surfaces, the contrasting physical properties of the lithologies, the arrangement of the lithologies with increasing amounts of mudstone toward the bottom, and the mature topography are responsible for locally controlling the direction and magnitude of the deformational stresses and, hence, the location, attitude, size, and shape of these folds, faults, and joints. This content is PDF only. Please click on the PDF icon to access. First Page Preview Close Modal You do not have access to this content, please speak to your institutional administrator if you feel you should have access.

Big Geology for Big Needs

If we are to continue the current rates of petroleum demand and production, it will be necessary to obtain more petroleum during the next 37 years, or by 2000 A.D., than during the past 100 years. And if discovery of new deposits is to continue as the most important source of petroleum, then the question becomes: Is there oil of that magnitude yet to be discovered within the United States? This is a geological question. Two approaches to the problem are considered. Both are based on the fact that as so often in the past, one or more of the chief ingredients for discovery may lie staring us in the face for years before being put into the discovery recipe. The first may be thought of as a way of thinking. The petroleum industry has gradually developed a great many fine geological administrators who deal in reports from highly trained specialists--but these administrators move farther and farther away from the rocks, and the specialists become more specialized and more microscopic in their outlook. Needed are more experienced geologists, in between, who are still with the rocks and able to integrate the various specialized elements of structure, stratigraphy, and fluids into a recipe for discovery. One integrated-type prospect consists of an arched, updip wedge of a potential reservoir rock, coupled with a downdip flow of the reservoir water. The flanks of every fold, large and small, from the surface to the basement, and in every sedimentary area, both productive and non-productive, offer innumerable opportunities for such petroleum discovery. The second approach lies in the simple fact that many oil fields and oil provinces--including some of the largest--occur in close association with truncated reservoir rocks. Large volumes of potential reservoir rocks, with many unconformities, well known and staring us in the face, but as yet unexplored, are cited as potentially productive on a large scale. The answer from this Peek at the Deep seems to be, There is enough potential favorable geology to supply a normal expected demand, large though it may be. The big question that remains is Will there be sufficient incentive to do the exploring? And this is in the realm of economics and politics.

Post-Depositional History of Tensleep Sandstone (Pennsylvanian), Big Horn Basin, Wyoming

The clean, orthoquartzitic, Pennsylvanian Tensleep Sandstone of the Big Horn basin, Wyoming, contains three prominent mineral cements: quartz, dolomite, and anhydrite. Present areal and stratigraphic distribution of these cements is the product of two major factors: environment control at the time of original precipitation, and subsequent redistribution by a hydrodynamic system that was created during the Laramide orogeny. Quartz cement shows a marked increase toward a northern and northeastern land source. Massive silica cementation of tightly folded, crest-faulted anticlines, however, is the result of solution and reprecipitation during cross-formational artesian flow. Original accumulation of microcrystalline carbonate mud matrix was strongly affected by the winnowin ability of currents moving over a shallow-water platform in north-central Wyoming. Some recrystallization and replacement of microcrystalline carbonate by coarser dolomite occurs throughout the Tensleep as a consequence of downdip flow of ground water. Secondary dolomite cementation is especially prominent below oil-water contacts in Big Horn basin fields where reprecipitation was not inhibited by petroleum. Anhydrite is present in various basin areas where circulation over the former cratonic shelf was restricted. Subsequent anhydrite replacement by dolomite in some of these areas may be related to oxidation-reduction reactions with petroleum. Characteristic differences between Tensleep and Mesozoic oils in the basin are believed to have been caused by degradation of mature Tensleep petroleum as a result of contact with artesian ground water. Degradation probably occurred through oxidation of petroleum by gases and mineral salts dissolved in the downdip flowing ground water, by bacterial activity, by solution of petroleum in the water, or by a combination of these actions. Oxidation-reduction reactions between artesian water and petroleum can also explain the fact that API gravity, per cent light gasoline fraction, and sulphur content of Tensleep oil display regional variation patterns which closely conform to the potentiometric surface in the Big Horn basin. Oxidation could have taken place during migration of petroleum to structural traps created by the Laramide orogeny. Substantial oxidation also occurred as a result of post-accumulation contact with artesian ground water in the oil-water transition zones of oil fields, and throughout faulted traps during cross-formational migration of water. Big Horn basin fields may be divided into three classes on the basis of prevalence and location of faulting, potentiometric position, and API gravity of produced oil. The classes are: (1) relatively unfaulted, normal or main trend fields displaying inclined oil-water contacts and having no active water drive; (2) fields which possess higher than average API gravity oil for their potentiometric position, display flat oil-water contacts with active edge-water drive, and which are associated with updip ramp faults; (3) highly faulted fields with lower than average API gravity oil for their potentiometric position, and multiple oil-water contacts, either horizontal or tilted. Solid hydrocarbon developed on detrital grain surfaces appears to be the product of in situ oxidation of petroleum by artesian water and anhydrite cement. The observed hydrodynamically tilted oil-water contact in some Big Horn basin fields is actually a fossil or paleohydrodynamic tilt maintained by secondary dolomite and solid hydrocarbon cementation that prevents or strongly inhibits an edge-water drive. Where solid hydrocarbon is found coating grains in producing fields, the reservoir rock behaves as if partially oil-wet. Unrecognized oil-wet reservoirs can lead to incorrect reserve estimates, and possibly to completion of wells in water-producing zones.

Big Geology for Big Needs: ABSTRACT

If we are to continue the current rates of petroleum demand and production, it will be necessary to obtain more petroleum during the next 37 years, or by 2000 A.D., than during the past 100 years. And, if discovery of new deposits is to continue as the most important source of petroleum, then the question becomes: Is there that much oil yet to be discovered within the United States? This is a geological question. As has happened so often the past, one or more of the chief ingredients for a discovery may lie staring us the face, sometimes for years, before being put into the discovery recipe. The petroleum industry has gradually developed a great many fine geological administrators who deal with reports from highly trained specialists--but the administrators move farther and farther away from the rocks and the specialists become more and more specialized and more microscopic their outlook. Needed are more experienced geologists between, who are still with the rocks and able to integrate the various specialized elements of structure, stratigraphy, and fluids into a discovery picture. Two situations typical of the in between problems, with their import to discovery. 1. One is the arched, updip, wedge-out of a potential reservoir rock coupled with a downdip flow of the water. The flanks of every fold, large or small, from the surface to the basement and every sedimentary area, both productive and non-productive, offer innumerable opportunities for petroleum discovery. 2. The second is the simple fact that many oil fields and oil provinces--including some of the largest--occur close association with truncated reservoir rocks. Large volumes of potential reservoir rocks, with many unconformities, well known and staring us the face, but as yet unexplored, are potentially productive on a large scale. The answer from this Peek at the Deep seems to be, There is enough potential, favorable geology to supply a normal expected demand. The big question that remains is Will there be sufficient incentive to do the exploring? And this is the realm of economics and politics. End_of_Article - Last_Page 362------------

Corpus Christi Structural Basin Postulated from Salinity Data

Water wells completed in the Lissie and Beaumont show that artesian conditions exist in spite of supposed lenticularity. Analyses of 1,400 water samples yield a salinity map based on regional, smoothed-out lines of equal chlorine concentration (isosalinity lines) ranging from 500 to 4,000 parts per million. Inability to correlate individual sands requires that the Lissie-Beaumont be treated as a single water sand. Sands, the water of which was sampled, lie beneath a shallow zone of highly saline ground water which is replaced under sandy soil by fresh water of surface origin. The strongest Lissie-Beaumont water analyzed had 9,578 parts, and immediately beneath the Lissie is water with more than 22,000 parts of chlorine. After analogy with the Woodbine artesian sand of the East Texas basin, where isosalinity lines and structural contours are parallel, a wide swing of the lines around the head of Nueces-Corpus Christi Bay is considered to establish a Corpus Christi structural basin, provided the hypothesis of the down-dip flow of surface waters mixing with the original brines may be accepted as the explanation of the observed distribution of salinity in both regions. This hypothesis is favored. Adjustment of the ancient, high-level delta of Nueces River of the Pleistocene to the postulated structural basin, and entrenchment in it of the present Nueces River with its drowned-valley bays, support the structural interpretation of the salinity map. Outside the basin the lines are parallel with the gulf shore line. The Beaumont outcrop in Nueces and San Patricio counties is the area covered by the survey. Barton's top-of-salt contours for salt domes suggest that the other bays of Texas may lie in structural basins. Theoretical stages in the evolution of mixed waters of coastal-plain aquifers (reservoir beds) are developed, several being found which could produce the observed salinity gradients of Corpus Christi and East Texas. Opposing interpretations are briefly discussed. The probably varied nature of the connate waters of the Pleistocene may require a combination of methods to explain the observed salinity gradients with the numerous local chlorine highs. One of the highs covers a producing gas field. Other highs are believed to be associated with diastrophic structure. Some are probably due to lenses of impervious sediments obstructing down-dip flow in the water sands. Their pattern does not seem to be that of End_Page 317------------------------------ shore-line features, such as lagoon and bay basins. The structural interpretation of the local chlorine highs is not studied in detail.

The Corpus Christi Structural Basin as Mapped by Salinity Data: ABSTRACT

Water wells completed in the Lissie and Beaumont show artesian conditions to exist in spite of supposed lenticularity. Analyses of 1,400 water sands yield a salinity map based on regional, smoothed-out lines of equal chlorine concentration (iso-salinity lines) ranging up to 4,000 parts per million. Inability to correlate individual sands requires that the Lissie-Beaumont be treated as a single water sand. Sands sampled lie beneath a shallow zone of highly saline ground-water which is invaded under sandy soil by fresh water. The strongest Lissie-Beaumont water analyzed has 6,200 parts and immediately beneath the Lissie is water with more than 22,000 parts of chlorine. After analogy with the Woodbine artesian sand of the East Texas basin, where iso-salinity lines and structural contours are parallel, a wide swing of the lines around the head of Nueces-Corpus Christi Bay is taken to establish a Corpus Christi structural basin, provided the hypothesis of the down-dip flow of surface waters mixing with original oceanic brine is accepted as the explanation of the observed distribution of salinity in both regions. Adjustment of the ancient, high-level delta of the Atascosa-Nueces rivers of the Pleistocene to the postulated structural basin, and entrenchment in it of the present Nueces River with its drowned-valley bays, support the structural interpretation of the salinity map. Outside the basin the lines are parallel with the gulf shore line. Barton's top-of-salt contours for salt domes indicate the other bays of Texas to be probably in structural basins. Opposing interpretations are briefly discussed. The probably varied nature of the connate waters of the Pleistocene may require a combination of methods to explain the observed salinity gradients with their numerous local chlorine highs. Two of the highs cover producing oil and gas fields. Others are believed to do so. Some are probably due to lenses of impervious sediments obstructing down-dip flow in the water sands. Their pattern does not seem to be that of shore-line features such as lagoon and bay basins, but superposition of many water sands which probably have varying salinities may have influenced the result. The structural interpretation of the local highs is not studied in detail. End_of_Article - Last_Page 139------------