Jurassic Smackover Formation Research Articles

Controls on lithium content of oilfield waters in Texas and neighboring states (USA)

The amount of lithium (Li) required to support the energy transition underscores the need to develop Li sources beyond the traditional hard-rock mining and surface continental brines. The objective of this study was to explore the potential for Li production from oilfield waters in the U.S. Gulf Coast region. Data on Li concentrations were obtained from ~2450 formation water samples taken in states along the greater Gulf Coast (NM, TX, OK, LA, AR, and MS). The dataset contains geochemical analyses that spans >70 years, including the USGS database (v2.3), compilation of recent data previously published by the authors, analyses from recently collected samples and from archived samples, and data from U.S. Bureau of Mines reports.Aqueous Li distribution is lognormal, typical of trace elements, with background levels in the 0–20 mg/L range. High concentrations (≥80 mg/L) are restricted to some intervals at certain locations: Jurassic Smackover Formation, a well-known brine deposit in Arkansas (300+ mg/L Li), but also along the Gulf Coast in Texas, Louisiana, and Mississippi (several samples ≥100 mg/L Li); Permian and Pennsylvanian Granite Wash in the Anadarko Basin of Texas (several samples >100 mg/L Li) (not confirmed); and Cretaceous Edwards Formation of South Texas (several samples ≥100 mg/L Li). Genetic models for Li enrichment are lacking, but high Li seems to be related to the noted fact that Li concentrations increase with depth and with total dissolved solids. Other common characteristics of high-Li brines in the Gulf Coast are high K, Ca, and B, which reflect water-rock interactions, presence of major faults, and association with higher permeability intervals that can spread Li-bearing fluids. Host rocks for high-dissolved Li brines commonly are carbonates, possibly because of their limited sorption opportunities. Close connection to an igneous basement or to a depositional environment that supported accumulation of surface continental brines does not seem to be required.

Investigating the controls on architecture and facies distribution of a carbonate ramp to shelf system: Insights from stratigraphic forward modeling of the Jurassic Smackover Formation, Gulf of Mexico

To develop a better understanding of the controls on the stratigraphic architecture of carbonate systems, it is necessary to quantify the impact of the physical and chemical variables responsible. The growth, distribution, and nature of carbonate factories are dependent on various space and time-dependent variables, such as paleotopography, accommodation, sediment supply, energy and slope of the system, and water chemistry.The Upper Jurassic Smackover Formation is a heterogeneous hydrocarbon source rock and reservoir in the semi-restricted Conecuh Embayment of southwestern Alabama. It consists of a lower transgressive unit composed of microbialite and mudstone/wackestone, and an upper regressive mixed carbonate-siliciclastic unit composed of oolitic packstone-grainstone, microbialite, bioturbated to laminated carbonate mudstone, and shale. The physiographic setting of the Conecuh Embayment, along with the variability in the carbonate factory types, eustatic sea level fluctuations, and sea-water circulation presents an exceptional site for evaluating the controls on carbonate platform/shelf margin to slope architecture.Stratigraphic forward modeling using DionisosFlow, calibrated with a geologic cross-section built from well log and core data, was carried out to test the impact of antecedent topography, accommodation, and carbonate factory type on the facies distribution and architecture of the carbonate shelf. Results of our study indicate that geometries in the transgressive Smackover shelf are controlled by accommodation and rate of carbonate production, while limited accommodation controlled the stratigraphic architecture of the regressive system.

Controls on large-scale architecture and facies distribution of an oolitic-microbial carbonate shelf margin, Nanpanjiang Basin, south China

Carbonate factory types and facies architecture of carbonate depositional systems result from complex interactions among several space- and time-dependent variables, including paleobathymetry, tectonic setting, water chemistry and oceanographic setting, clastic sediment influx, and accommodation. Whereas tropical factories that dominate modern settings have been documented and modelled extensively, microbial-oolitic systems, which are very common throughout the Paleozoic and Mesozoic, have received less attention.Continuous exposures along a platform-to-basin transect of an Early Triassic (Induan) microbial-oolitic carbonate ramp to shelf system in the Nanpanjiang Basin, South China, serves as a viable analogue to similar systems, including the Jurassic Smackover Formation of the Gulf of Mexico, and provide a natural laboratory to test these variables. Carbonate deposition following end-Permian regional drowning and retreat of the Yangtze Platform resulted in low-angle margin-slope systems during the Early Triassic. Lower Triassic carbonate systems display shifts in carbonate factory types, including skeletal, microbial, and abiotic factories, and lateral and vertical architectural variability.We applied stratigraphic forward modelling using DIONISOSFLOW, calibrated with detailed stratigraphic sections and facies mapping, to assess the impact of carbonate factory type, antecedent topography, and variations in accommodation on facies distribution and large-scale geometries of the carbonate shelf margin. Results from model simulations suggest that in the absence of skeletal carbonates in the Lower Triassic, the architecture of the carbonate margin is mainly controlled by rate of microbial growth along the slope.

Chemostratigraphy of the Upper Jurassic (Oxfordian) Smackover Formation for Little Cedar Creek and Brooklyn Fields, Alabama

The Upper Jurassic (Oxfordian Age) Smackover Formation is a significant source for hydrocarbon production in southwest Alabama. Brooklyn Field is in southeast Conecuh County, Alabama, and has been a major producer of oil and natural gas for the state. The Smackover is a carbonate formation that has been divided into seven distinct lithofacies in the Brooklyn and Little Cedar Creek fields. In southwest Alabama, the facies distribution in the Smackover Formation was influenced by paleotopography of the underlying Paleozoic rocks of the Appalachian system. The goal of this study is to determine elemental ratios in rock core within the Smackover Formation using an X-ray fluorescence (XRF) handheld scanner and to correlate these elemental characteristics to the lithofacies of the Smackover Formation in the Brooklyn and Little Cedar Creek fields. Eight wells were used for the study within Brooklyn Field and Little Cedar Creek fields. Cores from the eight wells were scanned at six-inch intervals. Chemical logs were produced to show elemental weights in relation to depth and lithofacies. The chemical signatures within producing zones were correlated to reservoir lithofacies and porosity. Aluminum, silicon, calcium, titanium, and iron were the most significant (>95% confidence level) predictors of porosity and may be related to the depositional environment and subsequent diageneses of the producing facies. The XRF data suggests relative enrichments in iron, titanium, and potassium. These elements may be related to deposition in relatively restricted marine waters.

Origin and distribution of hydrogen sulfide in the Yuanba gas field, Sichuan Basin, Southwest China

The Yuanba gas field in the Permian Changxing Formation (P2c), which exhibits wide variations in its hydrogen sulfide (H2S) concentration (1.20–12.16%), is a typical sour gas field in the northern Sichuan Basin. The sulfur-rich reservoir's solid bitumen (atomic S/C ratios are 0.032–0.142), and late calcite cement δ13C values, which are smaller than the δ13C values of the host dolostone, indicate that the H2S originated from thermal sulfate reduction (TSR) and oil was involved in TSR. The gas souring index (GSI) of P2c's gases is generally lower than 0.1. The ethane δ13C values increase as the GSI increases, although no obvious increase was observed in the methane δ13C values. The calcite cements' δ13C values (−15.36 to +4.56‰) in dolostone are heavier than the typical reported values, which implies that only limited heavy hydrocarbon gases were involved in TSR. No anhydrites developed in P2c's reservoirs, and dissolved sulfate anions (SO42−) were mainly enriched during dolomitization. Insufficient dissolved SO42− most likely caused the lower H2S concentrations in the Permian to Triassic reservoirs in the northeastern Sichuan Basin compared to the Permian Khuff Formation in Saudi Arabia and the Jurassic Smackover Formation in Mississippi. Except for the SO42− in residual water in paleo-oil zones, SO42− from bottom water may also be involved in TSR; therefore, oil reservoirs with bottom water have more SO42− and can produce more H2S than pure oil reservoirs. This phenomenon may be the main cause of the great difference in the H2S concentrations between reservoirs, while gravitational differentiation during late uplift most likely creates differences in H2S concentrations in a single reservoir. Carbon dioxide (CO2), which has a relatively heavy δ13C value (−3.9 to −0.3‰), may be the combined result of TSR, the balance between CO2 and inorganic fluid systems, and carbonate decomposition.

Geologic assessment of undiscovered oil and gas resources in Aptian carbonates, onshore northern Gulf of Mexico Basin, United States

Carbonate lithofacies of the Lower Cretaceous Sligo Formation and James Limestone were regionally evaluated using established U.S. Geological Survey (USGS) assessment methodology for undiscovered conventional hydrocarbon resources. The assessed area is within the Upper Jurassic–Cretaceous–Tertiary Composite total petroleum system, which was defined for the assessment. Hydrocarbons reservoired in carbonate platform Sligo-James oil and gas accumulations are interpreted to originate primarily from the Jurassic Smackover Formation. Emplacement of hydrocarbons occurred via vertical migration along fault systems; long-range lateral migration also may have occurred in some locations. Primary reservoir facies include porous patch reefs developed over paleostructural salt highs, carbonate shoals, and stacked linear reefs at the carbonate shelf margin. Hydrocarbon traps dominantly are combination structural-stratigraphic. Sealing lithologies include micrite, calcareous shale, and argillaceous lime mudstone. A geologic model, supported by discovery history analysis of petroleum geology data, was used to define a single regional assessment unit (AU) for conventional reservoirs in carbonate facies of the Sligo Formation and James Limestone. The AU is formally entitled Sligo-James Carbonate Platform Oil and Gas (50490121). A fully risked mean undiscovered technically recoverable resource in the AU of 50 million barrels of oil (MMBO), 791 billion cubic feet of natural gas (BCFG), and 26 million barrels of natural gas liquids was estimated. Substantial new development through horizontal drilling has occurred since the time of this assessment (2010), resulting in cumulative production of >200 BCFG and >1 MMBO.

Three-dimensional pore connectivity evaluation in a Holocene and Jurassic microbialite buildup

Microbial carbonates have complex pore networks formed by their biological growth framework, which later may be modified by diagenetic alteration. A proper evaluation of the porous media characteristics and their evolution is essential to better characterize microbial carbonate reservoirs. However, conventional methods of fundamental rock characteristic description are insufficient to elucidate the heterogeneity of pore networks and textural shifts. X-ray computed tomography allows a better evaluation of these fundamental characteristics, which, when integrated with stratigraphic analysis, enhances the understanding of the volume and connectivity of pore networks in different microbial textures. A three-dimensional evaluation of a Holocene microbialite from Brazil provides insights about how the primary pore network is related to the textural changes in microbialite successions, which, in ancient deposits, may be reduced or enhanced by diagenesis. Conventional methods such as petrography, carbon and oxygen stable isotope analysis, and laboratory measurements for porosity and permeability were integrated with computed tomography images and three-dimensional rendering to provide a high-resolution history of the evolution of porosity and permeability within this microbialite. The pore network differences are related to microbial textural evolution driven by environmental changes. The depositional textures control petrophysical properties based on fundamental rock characteristics such as structure size, structure packing, and framework fabric. Those fundamental characteristics influence the pore volume and number of pore throats. Large structures, open packing, and chaotic framework fabric result in a better connected pore network, whereas small structures, tight packing, and organized fabric result in less connected pore networks. Comparative pore geometry analysis of the Upper Jurassic Smackover Formation thrombolites shows that their depositional textures also had high primary porosity values. If the microbial textures and petrophysical properties are environmentally controlled, their prediction in the subsurface is made possible by refined depositional models.

Assessment of undiscovered conventional oil and gas resources, onshore Claiborne Group, United States part of the northern Gulf of Mexico Basin

The middle Eocene Claiborne Group was assessed for undiscovered conventional hydrocarbon resources using established U.S. Geological Survey assessment methodology. This work was conducted as part of a 2007 assessment of Paleogene–Neogene strata of the northern Gulf of Mexico Basin, including the United States onshore and state waters (Dubiel et al., 2007). The assessed area is within the Upper Jurassic–Cretaceous–Tertiary composite total petroleum system, which was defined for the assessment. Source rocks for Claiborne oil accumulations are interpreted to be organic-rich, downdip, shaley facies of the Wilcox Group and the Sparta Sand of the Claiborne Group; gas accumulations may have originated from multiple sources, including the Jurassic Smackover Formation and the Haynesville and Bossier shales, the Cretaceous Eagle Ford and Pearsall (?) formations, and the Paleogene Wilcox Group and Sparta Sand. Hydrocarbon generation in the basin started prior to deposition of Claiborne sediments and is currently ongoing. Primary reservoir sandstones in the Claiborne Group include, from oldest to youngest, the Queen City Sand, Cook Mountain Formation, Sparta Sand, Yegua Formation, and the laterally equivalent Cockfield Formation. A geologic model, supported by spatial analysis of petroleum geology data, including discovered reservoir depths, thicknesses, temperatures, porosities, permeabilities, and pressures, was used to divide the Claiborne Group into seven assessment units (AUs) with three distinctive structural and depositional settings. The three structural and depositional settings are (1) stable shelf, (2) expanded fault zone, and (3) slope and basin floor; the seven AUs are (1) lower Claiborne stable-shelf gas and oil, (2) lower Claiborne expanded fault-zone gas, (3) lower Claiborne slope and basin-floor gas, (4) lower Claiborne Cane River, (5) upper Claiborne stable-shelf gas and oil, (6) upper Claiborne expanded fault-zone gas, and (7) upper Claiborne slope and basin-floor gas. Based on Monte Carlo simulation of justified input parameters, the total estimated mean undiscovered conventional hydrocarbon resources in the seven AUs combined are 52 million bbl of oil, 19.145 tcf of natural gas, and 1.205 billion bbl of natural gas liquids. This article describes the conceptual geologic model used to define the seven Claiborne AUs, the characteristics of each AU, and the justification behind the input parameters used to estimate undiscovered resources for each AU. The great bulk of undiscovered hydrocarbon resources are predicted to be nonassociated gas and natural gas liquids contained in deep (mostly 12,000-ft [3658 m], present-day drilling depths), overpressured, structurally complex outer shelf or slope and basin-floor Claiborne reservoirs. The continuing development of these downdip objectives is expected to be the primary focus of exploration activity for the onshore middle Eocene Gulf Coast in the coming decades.

Upper Jurassic updip stratigraphic trap and associated Smackover microbial and nearshore carbonate facies, eastern Gulf coastal plain

The development of Little Cedar Creek field in the eastern Gulf coastal plain of the United States has shown that the current exploration strategy used to find hydrocarbon-productive microbial and high-energy, nearshore carbonate facies in the Upper Jurassic Smackover Formation requires refinement to increase the probability of identifying and delineating these potential reservoir facies. In this field, the petroleum trap is a stratigraphic trap characterized by microbial boundstone and packstone and nearshore grainstone and packstone reservoirs that are underlain and overlain by lime mudstone and dolomudstone to wackestone and that grade into lime mudstone and dolomudstone near the depositional updip limit of the Smackover Formation. Reservoir rocks trend from southwest to northeast in the field area. The grainstone and packstone reservoir is thickest in the central part of the field. The boundstone reservoir is thickest in local buildups that are composed of thrombolites in the southern part of the field and is absent along the northern margin. These reservoir facies are interpreted to have accumulated in water depths of approximately 3 m (10 ft) and in 5 km (3 mi) of the paleoshoreline. In contrast to most other thrombolites identified in the Gulf coastal plain, these buildups did not grow directly on paleohighs associated with Paleozoic crystalline rocks. The characterization and modeling of the petroleum trap and reservoirs at Little Cedar Creek field provide new information for use in the formulation of strategies for exploration of other Upper Jurassic hydrocarbon productive microbial and related facies associated with stratigraphic traps in the Gulf coastal plain.

Enrichment of diamondoids and 13C in condensate from Hudson Canyon, US Atlantic

Gas condensate migrated vertically to Upper Jurassic and Lower Cretaceous reservoir rocks in the Hudson Canyon (HC) area of the Baltimore Canyon Trough, US Atlantic. Condensate samples are enriched in diamondoids (4742–4774 ppm) and 13C ( δ 13C = −23.7‰ to −24.6‰ PDB). Several lines of evidence suggest that the main source rock is within the Middle to Lower Jurassic section of Hudson Canyon. Condensates from Hudson Canyon are similar to condensates generated by the Upper Jurassic Smackover Formation of the US Gulf Coast, a laminated lime mudstone with shale facies. The petrologic fabric of the lime mudstone favors early generation of diamondoids. Hydrogen rich kerogen and clay catalysts are concentrated within thin laminations of depositional origin separated by thicker barren carbonate layers.

Geometry and seismic geomorphology of carbonate shoreface clinoforms, Jurassic Smackover Formation, north Louisiana

Abstract Across much of the Gulf Coast basin of the USA, the Smackover Formation consists of a nearly 100m-thick shoaling upward cycle capped by oolitic/oncolitic packstones and grain-stones. It has long been interpreted as a homoclinal ramp succession, which was analogous to the modern example in the southeastern Arabian Gulf. In a three-dimensional seismic survey in north Louisiana, the shoaling-upward cycle is imaged as basin ward progradational clinoforms (4–7° inclination) with well-defined toplap and downlap surfaces. In map view, amplitude slices show that the clinoform bodies are strike-oriented and continuous. The inclination and width of the clinoform bodies indicate that water depths of up to 90 m were present within 1 km of the shoreline. Such characteristics indicate that the Smackover Formation cannot be classified as a homoclinal ramp in north Louisiana and that the Arabian Gulf is not analogous to the Smackover.

Use of Volume-Based 3-D Seismic Attribute Analysis to Characterize Physical-Property Distribution: A Case Study to Delineate Sedimentologic Heterogeneity at the Appleton Field, Southwestern Alabama, U.S.A.

Abstract In this paper we illustrate the use of 3-D seismic attribute studies for predicting the distribution of physical properties in the subsurface. Using a data set consisting primarily of digital logs and seismic data, we show how correlations can be made between seismic attributes and physical properties (porosity), and how those relationships can be exploited to predict the distribution of the property of interest in three dimensions. The results of these studies: (1) provide quantitative, site-specific 3-D models of physical properties that are of more use for applied studies than qualitative 2-D models commonly derived from facies modeling or sequence stratigraphic analysis, (2) are generally more geologically reasonable than studies based on geostatistics alone, (3) can provide sedimentary geologists with fundamental insights into depositional and/or diagenetic controls on the distribution of properties of interest, (4) need to be rigorously evaluated by integrating other types of data and analyses, and (5) are best thought of as supplementing, rather than replacing, conventional geologic analyses. The concepts and methods we illustrate may have application in various branches of sedimentary geology. Our study area is Appleton Field in southern Alabama. At this location we predict the 3-D distribution of porosity in carbonates of the Upper Jurassic Smackover Formation using a probabilistic neural network and a combination of four attributes. Our results suggest that porosity was best developed, and preserved, in thrombolite facies of the reef front.

Improving recovery from mature oil fields producing from carbonate reservoirs: Upper Jurassic Smackover Formation, Womack Hill field (eastern Gulf Coast, U.S.A.)

Reservoir characterization, modeling, and simulation were undertaken to improve production from Womack Hill field (eastern Gulf Coast, United States). This field produces oil from Upper Jurassic Smackover carbonate shoal reservoirs. These reservoirs occur in vertically stacked, heterogeneous depositional and porosity cycles. The cycles consist of lime mudstone and wackestone at the base and ooid grainstone at the top. Porosity has been enhanced through dissolution and dolomitization. Porosity is chiefly interparticle, solution-enlarged interparticle, grain moldic, intercrystalline dolomite, and vuggy pores. Dolostone pore systems and flow units have the highest reservoir potential. Petroleum-trapping mechanisms include a fault trap (footwall uplift with closure to the south against a major west-southeast–trending normal fault) in the western area, a footwall uplift trap associated with a possible southwest-northeast–trending normal fault in the south-central area, and a salt-cored anticline with four-way dip closure in the eastern area. Potential barriers to flow are present as a result of petrophysical differences among and within the cycles, as well as the presence of normal faulting. Reservoir performance analysis and simulation indicate that the unitized western area has less than 1 MMSTB of oil remaining to be recovered, and that the eastern area has 2–3 MMSTB of oil to be recovered. A field-scale reservoir management strategy that includes the drilling of infill wells in the eastern area of the field and perforating existing wells in stratigraphically higher porosity zones in the unitized western area is recommended for sustaining production from the Womack Hill field.

Interpretation of charging phenomena based on reservoir fluid (PVT) data

Abstract Molar concentration profiles of reservoir fluids reveal accumulation history and alteration. Slope Factors (SF) define rates of exponential decrease in concentration of light n -alkanes (C 3 - n C 5 ) and liquid pseudo-components (P 10+ ) with increasing carbon number. Most petroleum fluids are substantially characterized by SF(C 3 - n C 5 ) and SF(P 10+ ), the former invariably being the greater. Specific paired values of SF(C 3 - n C 5 ) and SF(P 10+ ) are process-diagnostic. In oils, maturation, gas injection, evaporative fractionation and migration depletion involving loss of gas, are recognizable. SF data are interpreted in the light of PVT analyses representing oils (principally from western Canada) and gas-condensates (from numerous basins), also asphaltene pyrolysis experiments and equation of state calculations. Covariant increase of SF(C 3 - n C 5 ) and SF(P 10+ ) during maturation is demonstrated, but correlation is frequently destroyed by modification of the light ends by the admixture of allochthonous gas, increasing only SF(C 3 - n C 5 ). Secondary gas-enrichment is a requisite process for the generation of gas-condensates by evaporative fractionation. Compositional criteria for the recognition of enrichment are provided for the first time, particularly attainment of a value of SF(C 3 - n C 5 ) exceeding 1.69 (a tentative limit). Available data indicate that the process has occurred in a large proportion of oil accumulations, ranging from 23% of 30 reservoirs in the Jurassic Smackover Formation in Alabama, to 78% of 36 in the northern North Sea.

Upper Jurassic (Oxfordian) Smackover carbonate petroleum system characterization and modeling, Mississippi Interior Salt Basin area, northeastern Gulf of Mexico, USA

The Upper Jurassic (Oxfordian) Smackover Formation is a prolific oil and gas reservoir in the northern Gulf of Mexico, including the Mississippi Interior Salt Basin area. The Smackover petroleum system is categorized as a giant petroleum system and ranks fourth among recognized Upper Jurassic petroleum systems. In the Mississippi Interior Salt Basin area, the components of the Smackover petroleum system include pre rift, syn rift and post rift siliciclastic, evaporite, and carbonate underburden and overburden rocks, Smackover subtidal lime mudstone source rocks, uppermost Smackover anhydrite and Buckner Anhydrite Member subaqueous saltern and sabkha seal rocks, and upper Smackover shoal complex and tidal flat complex packstone, grainstone, boundstone and dolostone reservoir rocks. The critical events include the initiation of the generation of crude oil, the commencement of hydrocarbon expulsion, the initiation of hydrocarbon migration, and the entrapment of hydrocarbons during the Early to Late Cretaceous. The critical moment for the Smackover petroleum system is the time of peak hydrocarbon expulsion in the mid to late Early Cretaceous in basin center areas and mid to latest late Cretaceous in areas along the northern basin margin. *** DIRECT SUPPORT *** A00QA034 00003

Sequence stratigraphic controls on the development of microbial fabrics and growth forms-implications for reservoir quality distribution in the Upper Jurassic (Oxfordian) Smackover Formation, eastern Gulf Coast, USA

This paper presents a model that integrates sequence stratigraphic concepts with a fabric and growth form classification of Smackover microbial buildups to aid in understanding the distribution of reservoir quality in the updip basement ridge play of southwest Alabama. Microbial growth forms and fabrics, early diagenetic processes, and resulting reservoir quality are all ultimately controlled by the rate of relative sealevel change, position of sea level with respect to exposed Paleozoic basement, and position in an inner ramp setting. The microbial classification divides fabrics and growth forms into five “types,” which developed in response to changes in water energy, sedimentation rate, and substrate. Layered thrombolite with characteristic mm/cm-scale crypts characterize Type I buildups. Reticulate and “chaotic” thrombolite comprise Type II buildups. In the updip basement ridge play, the Smackover sea did not flood the Paleozoic basement until deposition of the sediments associated with the late transgressive systems tract. Layered and reticulate thrombolite buildups (Types I and II) grew directly on Paleozoic basement and formed in reponse to late transgressive systems tract catch-up conditions when sedimentation rates were low and water energies were moderate to high. Both Type I and II buildups occur on low and high relief basement structures. Type III buildups are characterized by dendroidal thrombolites. On low relief basement structures, dendroidal thrombolite buildups (Type III) typically overlie Type I and II buildups. Type III buildups are absent on high relief structures. Dendritic thrombolites grew in early highstand systems tract keep-up conditions when sedimentation rates were slightly elevated and water energy low. These conditions occurred on the tops of low-relief basement structures associated with early highstand systems tract deposition. Type IV microbialite are composed of isolated stromatolitic crusts that acted as binders to Type V oncoidal packstone/grainstones that grew on soft to firm substrates in high-energy conditions. Abundant in the late highstand systems tract deposits, Type IV (isolated crusts) and V (oncoid) microbialite are found in upper Smackover shoal, lagoon, and tidal flat facies. Classification of microbial types is significant to hydrocarbon exploration and production in southwest Alabama. Types I, II, and III buildups are the best fabrics for productive reservoirs. Of these, Type III buildups are the highest quality reservoir rocks. Dolomitized reticulate and dendritic fabrics result in well-connected intercrystalline and vuggy porosity. Type IV and V microbialite are poor reservoir rocks because Type IV forms are often isolated, and the moldic porosity associated with Type V oncoids are typically not well connected.

An eolian facies within the Upper Jurassic Smackover Formation, Tchula Lake field, Mississippi

The Late Jurassic upper Smackover Formation in Mississippi is primarily composed of an overall regressive sequence of marine carbonate ramp deposits. In central Mississippi, however, carbonate deposition was interrupted by a large influx of siliciclastic sediment. Tchula Lake field is unique not only because it produces gas and condensate from dolomitic quartz sandstone deposited in a mixed siliciclastic-carbonate environment but also because it produces from what we interpret to be an eolian dune sand facies. Throughout the Gulf Coast Basin no previous literature has cited an eolian facies within the Smackover Formation. Several characteristics of the producing zone sandstones have led to interpretations of this unit as an eolian coastal dune facies deposited on and around a Jurassic paleohigh. Facies and paleoenvironmental interpretations are based on compositions and textures described in cores and thin sections. The eolian facies consists of fine-grained, dolomitic quartz sandstone with a mean porosity of 10-20% and permeability of 0-800 md. The sand grains are rounded to subrounded and well sorted. The sandstone exhibits a sequence of upward-steepening planar laminations capped at the top by a set of small-scale wedge planar cross-laminations. The sharply defined, parallel lamina are less than 5 mm thick and are commonly inversely graded and contain probable vadose meniscus carbonate cements. This facies is interpreted to have been deposited in a backshore coastal dune environment. The unit is characterized by low-angle (<20 degrees dip) climbing translatent strata commonly produced by the migration of wind ripples along a dune. No fossils or trace fossils are found within this facies. Eolian-deposited sandstone is a potential reservoir rock along the updip limit of the Smackover Formation in west-central Mississippi. Other paleohighs along the Jurassic shoreline may have undergone similar eolian deposition during a regional sea level fall. Eolian-deposited sandstones on these paleohighs should have (Begin page 486) similar reservoir properties as the sandstone at Tchula Lake field. The updip Smackover Formation in west-central Mississippi is an underexplored horizon, and eolian-deposited reservoirs have strong potential as a new exploration target. The sea level fluctuation event associated with deposition at Tchula Lake field also has implications for exploration in Upper Jurassic sedimentary rocks across the entire United States Gulf Coast Basin and prompts a reevaluation of these reservoirs.

ABSTRACT: Determining Reservoir Quality by Combined Stratigraphic, Petrographic and Petrophysical Methods As Part of Optimized Recovery Programs: Womack Hill Smackover Field, Clarke and Choctaw Counties, Alabama

Objective of the Study The objective of this study is to describe depositional and diagenetic characteristics of the Oxfordian (Jurassic) Smackover Formation in the Womack Hill field, Alabama, as part of an integrated reservoir description program. In order to understand the distribution of reservoir units, this study utilized an integrated array of data from core lithological descriptions, borehole logs, core reports, thin section petrography, porosity and permeability measurements on core plugs, and mercury injection capillary pressure (MICP) measurements. These data made it possible to establish reliable measures of reservoir quality by comparing pore geometry with pore type; then determining which pore types correspond with highest porosity-permeability paired values. Pore aperture (throat) median sizes measured by mercury capillary pressures were tested for correspondence with porosity, pore type, permeability, and saturation in order to establish quality rankings for the reservoir units.

ABSTRACT: Massive, High Temperature Recrystallization of Low-Mg Calcite in Hydrocarbon Source Rocks, Upper Jurassic Smackover Formation, Mississippi

ABSTRACT: Massive, High Temperature Recrystallization of Low-Mg Calcite in Hydrocarbon Source Rocks, Upper Jurassic Smackover Formation, Mississippi

Porosity loss, fluid flow, and mass transfer in limestone reservoirs: Application to the Upper Jurassic Smackover Formation, Mississippi (Discussion &amp;amp; Reply)

Heydari (2000) presents a series of calculations and interpretations based on 24 modal analyses covering a limestone interval 36 m (117 ft) thick. This is an impressive application of quantitative petrography to determine the detailed mechanisms of carbonate diagenesis. Although I reviewed this article in manuscript, I did not have the opportunity to comment on the use of a model for convective circulation of formation water, which was added after my review was completed and which now stands as the main conclusion arrived at by this study. This discussion contends that (1) the convective circulation model used to explain apparent differences in material loss and gain between different parts of the reservoir is implausible and unnecessary; (2) the calculations of porosity loss by compaction and cementation are unnecessarily inexact; and (3) the main significance of this very interesting study is entirely different from what is stated in the article. The convective circulation model is implausible because to operate it requires unrealistically high permeability throughout the grainstone layer. This can be illustrated by considering an example calculated by Bjorlykke et al. (1988, p. 348) for a bed …