Tuscaloosa Sandstone Research Articles

Predicting the CO2 Footprint in Saline Aquifers: A Numerical-analytical Hybrid Model

In this study, we present a hybrid framework in which we combine pore-scale lattice Boltzmann (LB) simulations with a macroscopic analytical model for predicting CO2 plume migration and its residual trapping in saline aquifers. These integrated methods combine the flexibility of a pore-scale simulation method, allowing for implementing the micro-scale properties such as wettability, with the efficiency of an analytical method, for a quick estimation of the CO2 plume extension and its residual trapping during the injection and post-injection stages. The LB model is adopted to perform two-phase flow simulations of CO2/brine in the microstructure of a rock sample of Tuscaloosa sandstone taken from the Cranfield site in Mississippi. Employing the pore-scale LB simulations, we estimate pore-scale properties such as connate brine saturation, CO2 residual saturation, and CO2 end-point relative permeability. Subsequently, these parameters have been used in the analytical model for predicting the macro-scale behavior of CO2 plume during the injection and post-injection periods. To gain a better insight into the effect of wettability on the footprint of CO2 plume and its residual trapping, we run pore-sale simulations in different samples under various wetting conditions and calculate the pore-scale properties as a function of wettability. Thus, incorporating the pore-scale simulation results into the analytical model helps us evaluate the effect of pore-scale properties such as wettability on storage efficiency. We believe that this approach provides an appropriate tool for the estimation of storage efficiency in CO2 sequestration projects.

Application of arbitrary polynomial chaos (aPC) expansion for global sensitivity analysis of mineral dissolution and precipitation modeling under geologic carbon storage conditions

Numerical modeling of geochemistry associated with geologic CO2 storage involves many conceptual and quantitative uncertainties. In this study, a time efficient arbitrary polynomial chaos (aPC) expansion approach was proposed to do global sensitivity analysis of mineral dissolution and precipitation modeling in geologic carbon storage scenarios. To demonstrate the workflow of the aPC approach, a numerical model to predict permeability evolution of a Lower Tuscaloosa sandstone core exposed to CO2 saturated brine was used. The modeled sandstone core permeability by the aPC approach was 2095.5 mD ± 504.5 mD after 180 days of CO2 exposure. The measured permeability of the core after 180 days of CO2 exposure was 1925.0 mD, which was within the uncertainty range. Keq (SiO2 (am)) was the most important modeling parameter that influenced permeability results, implying that SiO2 (am) is a key mineral that governs permeability evolution of sandstone in geologic carbon storage scenarios. The aPC approach can reduce 99% of simulation time needed to do global sensitivity analysis of a complicated geochemical model, compared with traditional Monte Carlo approach.

CO2-brine relative permeability and capillary pressure of Tuscaloosa sandstone: Effect of anisotropy

Relative permeability and capillary pressure are known as essential properties that have substantial impacts on the accuracy of reservoir simulations. The effect of small-scale heterogeneity and lamination in the rock structure is often ignored during the measurement of capillary pressure and relative permeability curves in core samples. This study highlights the remarkable impact of anisotropy on the multiphase flow properties of stratified formations. A series of steady-state CO2-brine drainage and imbibition tests are conducted at reservoir conditions in horizontal and vertical core samples of the Tuscaloosa sandstone from the Cranfield CO2 injection site in Mississippi. The relative permeability curves represent an anisotropic behavior influenced by the heterogeneous and laminated structure of realistic rock samples. The CO2 saturation profiles during drainage and imbibition cycles indicate that the phase distribution in the pore space is controlled by core-scale heterogeneity in the porosity distribution among the laminations that causes capillary pressure inhomogeneity. Using the saturation profile during the imbibition cycle, the trapping characteristic of the horizontal and vertical rock samples are compared and we found that the capillary trapping is less likely in the vertical direction. Furthermore, the centrifuge-measured capillary pressure demonstrates distinctive characteristics for horizontal and vertical core samples. Since the flooding experiments are performed under capillary controlled flow, the capillary pressure contrast in the laminated structure of the rock strongly affects the relative permeability. The presented results can potentially improve the accuracy of the large-scale simulations for the CO2 post-injection period, in which the vertical displacement has an important role in the plume migration.

Pore-scale characteristics of multiphase flow in heterogeneous porous media using the lattice Boltzmann method

This study provides a pore-scale investigation of two-phase flow dynamics during primary drainage in a realistic heterogeneous rock sample. Using the lattice Boltzmann (LB) method, a series of three-dimensional (3D) immiscible displacement simulations are conducted and three typical flow patterns are identified and mapped on the capillary number (Ca)-viscosity ratio(M) phase diagram. We then investigate the effect of the viscosity ratio and capillary number on fluid saturation patterns and displacement stability in Tuscaloosa sandstone, which is taken from the Cranfield site. The dependence of the evolution of saturation, location of the displacement front, 3D displacement patterns and length of the center of mass of the invading fluid on the viscosity ratio and capillary number have been delineated. To gain a quantitative insight into the characteristics of the invasion morphology in 3D porous media, the fractal dimension Df of the non-wetting phase displacement patterns during drainage has been computed for various viscosity ratios and capillary numbers. The logarithmic dependence of Df on invading phase saturation appears to be the same for various capillary numbers and viscosity ratios and follows a universal relation.

Pore–scale analysis of supercritical CO2–brine immiscible displacement under fractional–wettability conditions

The objective of this study was to investigate the effect of wettability heterogeneity on pore–scale characteristics of Supercritical (sc) CO2 displacement dynamics and its capillary trapping mechanism during a scCO2–brine drainage and imbibition cycle. A multiphase lattice Boltzmann (LB) model was employed to simulate scCO2–brine flow in rock samples of Tuscaloosa sandstone taken from the Cranfield CO2 injection site. Using a spectral method, we adopted various wettability fields to generate rock samples containing distributed CO2–wet regions. To gain a better insight into the effect of fractional wettability on scCO2 displacement patterns during drainage, we quantified the evolution of scCO2 interface with brine and rock surface for samples with various wettability heterogeneities. In addition, the effect of heterogeneous wettability on the drainage relative permeability and capillary pressure curves has been investigated in this study. According to our results, heterogeneous distribution of CO2–wet regions in the rock leads to more dispersed fluid distribution and, hence, more tortuous flow paths, resulting in higher interfacial area between fluid phases and rock surface at any given scCO2 saturation. Furthermore, the spatial distribution of wettability controls the scCO2 entrapment pattern and spatial distribution of residual scCO2 clusters during brine flooding. In fractional–wet samples, residence of scCO2 phase in CO2–wet regions creates more trapped scCO2 clusters, suppressing the connectivity of the CO2 phase, thus enhancing more residual trapping. Our results imply that the total number of scCO2 clusters and, as a result, their residual trapping, increases as the fraction of CO2–wet regions becomes larger, leading to a larger surface area of scCO2 with brine and rock surface, potentially, facilitating the likelihood of long-term dissolution and mineral trapping.

Laboratory Study of Ultrasonic Velocity Variations During CO2 Flooding in Tuscaloosa Sandstone

SummarySurface seismic technology offers a promising technique for monitoring carbon dioxide (CO2) flood fronts during the enhanced-oil-recovery (EOR) process. Changes in the seismic signature have been observed with CO2 flooding, but its quantification with respect to subsurface saturation is still in its infancy. This study is focused on quantifying variation in the seismic parameters (velocity and impedance) as a function of subsurface fluid type and saturation.We present results of a laboratory study in which velocity and density were monitored as the pore fluids (formation brine and oil, and CO2) were replaced sequentially. All the experiments were performed at in-situ pressure conditions on core plugs (Tuscaloosa Sandstone) recovered from a well in a field currently undergoing CO2 flooding. These plugs are characterized as fluvial (quartz ≈87%, clay ≈10%) and distributary channels (quartz ≈75%, clay ≈17%).When dry samples were flooded with brine, a decrease in compressional-wave (P-wave) velocity (≈2%) was observed until 95% saturation of brine was achieved. For the remaining 5% of saturation, the velocity increased by 7 to 12.5%. After attaining 100% brine saturation, oil was pumped to displace the brine until irreducible water saturation was achieved. A linear drop of 3 to 4% in velocity to oil saturation was observed during this step. Thereafter, liquid CO2 was injected to displace the oil/brine system and a drop of 5 to 10% in P-wave velocity was observed. Biot-Gassmann modeling shows good agreement with experimental results for the gas/brine and oil/brine systems, but not for liquid-CO2 flooding.An empirical relationship was derived from the experimental results, and was applied to sonic logs and used for sensitivity analysis of 4D-seismic data. Post-flooded sonic data were compared to a theoretical sonic curve estimated from an empirical and ‘patchy’ model. Also, a significant increase in seismic amplitude difference was observed when CO2 saturation was greater than 50%.

The Northern Gulf of Mexico During OAE2 and the Relationship Between Water Depth and Black Shale Development

AbstractDespite their name, Oceanic Anoxic Events (OAEs) are not periods of uniform anoxia and black shale deposition in ancient oceans. Shelf environments account for the majority of productivity and organic carbon burial in the modern ocean, and this was likely true in the Cretaceous as well. However, it is unlikely that the mechanisms for such an increase were uniform across all shelf environments. Some, like the northwest margin of Africa, were characterized by strong upwelling, but what might drive enhanced productivity on shelves not geographically suited for upwelling? To address this, we use micropaleontology, carbon isotopes, and sedimentology to present the first record of Oceanic Anoxic Event 2 (OAE2) from the northern Gulf of Mexico shelf. Here OAE2 occurred during the deposition of the well‐oxygenated, inner neritic/lower estuarine Lower Tuscaloosa Sandstone. The overlying organic‐rich oxygen‐poor Marine Tuscaloosa Shale is entirely Turonian in age. We trace organic matter enrichment from the Spinks Core into the deepwater Gulf of Mexico, where wireline log calculations and public geochemical data indicate organic enrichment and anoxia throughout the Cenomanian‐Turonian boundary interval. Redox change and organic matter preservation across the Gulf of Mexico shelf were driven by sea level rise prior to the early Turonian highstand, which caused the advection of nutrient‐rich, oxygen‐poor waters onto the shelf. This results in organic matter mass accumulation rates 1–2 orders of magnitude lower than upwelling sites like the NW African margin, but it likely occurred over a much larger geographic area, suggesting that sea level rise was an important component of the overall increase in carbon burial during OAE2.

Permeability and Mineral Composition Evolution of Primary Seal and Reservoir Rocks in Geologic Carbon Storage Conditions

It has been reported that deep saline aquifers represent the largest geologic CO2 storage resource. To better predict containment effectiveness and long-term reservoir behavior of these formations, it is important to understand the potential geochemically induced changes to the porosity and permeability of both the primary sealing formation and CO2 storage formation rocks. To investigate these potential changes, an experimental study to probe the geochemical interactions of CO2/brine/rock system under geologic CO2 storage conditions was conducted in a static reaction system. Marine shale (primary sealing formation) and Lower Tuscaloosa sandstone (CO2 storage formation) core samples taken from the Plant Daniel CO2 storage test site (Jackson County, Mississippi) were exposed to CO2-saturated brine in a batch reactor at relevant geologic storage conditions (85°C and 23.8 MPa CO2 pressure) for 6 months. X-ray diffraction, scanning electron microscopy, computed tomography, and brine chemistry analyses were performed before and after the exposure. Permeability measurements from the marine shale and sandstone core samples before and after CO2/brine exposure indicated a significant effective permeability change. Sealing marine shale permeability increased following exposure while the permeability of the sandstone from the storage formation was observed to decrease. Analysis results of the primary sealing formation sample (marine shale) at the Plant Daniel CO2 storage test site have not been reported before. The permeability decrease of the Lower Tuscaloosa sandstone sample reported in this study verifies the results reported in a previous study. These results have implications for the integrity of the primary seal in a CO2 storage setting.

Numerical investigation of Lower Tuscaloosa Sandstone and Selma Chalk caprock under geological CO2 sequestration conditions: mineral precipitation and permeability evolution

AbstractA numerical model was developed using CrunchFlow to simulate reactive transport and porosity and permeability changes of sandstone and carbonate rock samples taken from the Lower Tuscaloosa Formation and the Selma Chalk Formation, Jackson County, MS, USA. The model predicted a permeability decrease from 2190 mD to 2038 mD for the Lower Tuscaloosa Sandstone sample in a static batch reactor after 180 days of exposure to CO2‐saturated brine, which is consistent with measured permeability results. The model predicted a negligible permeability change from 2.00 mD to 2.08 mD for the Selma Chalk carbonate sample after 180 days of exposure to CO2‐saturated brine. Based on model prediction, key mineral dissolution and precipitation reactions in the Lower Tuscaloosa Sandstone sample include dissolution of quartz, chlorite, and feldspar, as well as precipitation of amorphous silica and kaolinite. For the Selma Chalk carbonate sample, key predicted reactions include dissolution of calcite, quartz and chlorite, and precipitation of kaolinite and amorphous silica. Initial porosity, initial feldspar content and the exponent n value (related to pore structure and tortuosity) used in permeability calculations were three important factors affecting permeability evolution of sandstone samples under CO2 sequestration conditions. The small permeability change predicted for both the Lower Tuscaloosa Sandstone and the Selma Chalk caprock after exposure to CO2‐saturated brine suggests that poro‐permeability changes during CO2 injection into the Lower Tuscaloosa Formation are not likely to significantly affect reservoir and seal quality. © 2017 Society of Chemical Industry and John Wiley & Sons, Ltd.

CO2/brine/rock interactions in Lower Tuscaloosa formation

AbstractSaline aquifers are the largest potential continental geologic CO2 sequestration resource. Understanding of potential geochemically induced changes to the porosity and permeability of host CO2 storage and sealing formation rock will improve our ability to predict CO2 plume dynamics, storage capacity, and long‐term reservoir behavior. Experiments exploring geochemical interactions of CO2/brine/rock on saline formations under CO2 sequestration conditions were conducted in a static system. Chemical interactions in core samples from the Lower Tuscaloosa formation from Jackson County, Mississippi, with exposure to CO2‐saturated brine under sequestration conditions were studied through six months of batch exposure. The experimental conditions to which the core samples of Lower Tuscaloosa sandstone and Selma chalk were exposed to a temperature of 85°C, CO2 pressure of 23.8 MPa (3500 psig), while immersed in a model brine representative of Tuscaloosa Basin. Computed tomography (CT), X‐Ray diffraction (XRD), Scanning Electron Microscopy (SEM), brine chemistry, and petrography analyses were performed before and after the exposure. Permeability measurements from the sandstone core sample before and after exposure showed a permeability reduction. No significant change of the permeability measurements was noticed for the core sample obtained from Selma chalk after it was exposed to CO2/brine for six months. These results have implications for performance of the storage interval, and the integrity of the seal in a CO2 storage setting. © 2016 Society of Chemical Industry and John Wiley & Sons, Ltd

Comparison of relative permeability–saturation–capillary pressure models for simulation of reservoir CO2 injection

Constitutive relations between relative permeability (kr), fluid saturation (S), and capillary pressure (Pc) determine to a large extent the distribution of brine and supercritical CO2 (scCO2) during subsurface injection operations. Published numerical multiphase simulations for brine–scCO2 systems so far have primarily used four kr−S−Pc models. For the S−Pc relations, either the Brooks–Corey (BC) or Van Genuchten (VG) equations are used. The kr−S relations are based on Mualem, Burdine, or Corey equations without the consideration of experimental data. Recently, two additional models have been proposed where the kr−S relations are obtained by fitting to experimental data using either an endpoint power law or a modified Corey approach. The six models were tested using data from four well-characterized sandstones (Berea, Paaratte, Tuscaloosa, Mt. Simon) for two radial injection test cases. The results show a large variation in plume extent and saturation distribution for each of the sandstones, depending on the used model. The VG–Mualem model predicts plumes that are considerably larger than for the other models due to the overestimation of the gas relative permeability. The predicted plume sizes are the smallest for the VG–Corey model due to the underestimation of the aqueous phase relative permeability. Of the four models that do not use fits to experimental relative permeability data, the hybrid model with Mualem aqueous phase and Corey gas phase relative permeabilities provide the best fits to the experimental data and produce results close to the model with fits to the capillary pressure and relative permeability data. The model with the endpoint power law resulted in very low, uniform gas saturations outside the dry-out zone for the Tuscaloosa sandstone, as the result of a rapidly declining aqueous phase relative permeability. This observed behavior illustrates the need to obtain reliable relative permeability relations for a potential reservoir, beyond permeability and porosity data.

Geochemical impact of oxygen on siliciclastic carbon storage reservoirs

In planning for large-scale CO2 capture procedures, there exists an economic incentive to leave minor gas components in the captured CO2 stream for geological storage, because doing so would reduce the cost of the capture process. However, co-injection of reactive impurities (such as O2, CO, H2, NOx, and SOx) may have detrimental effects on well injectivity, wellbore integrity, seal performance, and gas–brine–rock interactions. In this study we investigated, using a series of autoclave experiments, the potential impact of O2 as an impurity on geochemical reactions. Three sandstones were tested: Miocene sandstone (Texas offshore, USA), lower Tuscaloosa sandstone (Cranfield field, Mississippi, USA) and Cardium sandstone (Pembina field, Alberta, Canada). Samples were subjected to reaction with 1.88M NaCl solution and CO2, with and without the addition of a small volume of O2 in order to determine the geochemical effects of O2. A total of ten reaction experiments were conducted at 200bar and 70°C or 100°C. Overall, for rock samples lacking reducing minerals, co-injection of a small volume of O2 with supercritical CO2 showed only a limited geochemical impact compared to the reactions with pure CO2. The presence of O2 did not accelerate the dissolution of carbonate and feldspar minerals, nor did it alter the reaction pathways. However, the small amount of pyrite (≈0.7%) contained in the Cardium sandstone had an important impact. As it was oxidized, the solution pH was further lowered because the Cardium sandstone contains little pH-buffering carbonate and feldspar minerals. Consequently, dissolution of carbonates and feldspars was enhanced by the more-acidic solution. Aqueous ferrous iron was largely converted to iron oxyhydroxides and precipitated on mineral surfaces. The minor cations that showed the largest increases in aqueous concentration (such as Mn, Sr, and Ba) were mostly mobilized from carbonates and were not significantly enhanced by O2 for the low-pyrite sandstones. Releases of trace metals, with the exception of Zn and Pb, were not enhanced by the presence of O2. In fact, concentrations of As, V, Mo, and other oxyanions were lower in the reactions involving O2 than in the pure CO2 reactions, because these metals sorb on the newly precipitated iron oxyhydroxides.

Geochemical Impact of Oxygen Impurity on Siliciclastic and Carbonate Reservoir Rocks for Carbon Storage

Abstract Geochemical effects of gas impurities in the CO2 stream are not fully investigated. Co-injection of reactive impurities (such as O2, CO, H2, NOx, and SOx) may cause detrimental effects on storage reservoirs and seals. In this study, a series of autoclave experiments are conducted to investigate the potential impacts of O2 as an impurity on selected siliciclastic and carbonate reservoir rocks. Eight reaction experiments on three sandstones have been conducted at 200 bar and 70 °C and100 °C: Miocene sandstone (Texas offshore, U.S.A.), lower Tuscaloosa sandstone (Cranfield field, Mississippi, U.S.A.) and Cardium sandstone (Pembina field, Alberta, Canada). Six experiments have been conducted on two carbonate rocks so far (Redwater Leduc limestone, Canada; Cisco limestone, SACROC Unit, Texas, USA). The study shows that rocks lacking reducing minerals show limited geochemical changes with co-injection of a small volume of O2 in supercritical CO2. The presence of O2 does not accelerate the dissolution of carbonate and feldspar minerals, nor does it lead to new reactions. However, the addition of oxygen causes pronounced geochemical impacts when a small amount of the reducing mineral-pyrite is present in rock. As pyrite is oxidized, H+ ions are produced, resulting in pH reduction that increases dissolution of carbonate minerals. When there is a lack of pH buffering carbonate minerals, the effect of further pH drop is manifest as feldspar dissolution accelerates. Aqueous ferrous iron derived from pyrite oxidation is largely converted to iron oxyhydroxides which precipitate on mineral surfaces. The results suggest that addition of small volume fractions of O2 is unlikely to result in significant effects on carbonate rocks. Dissolution of calcite and/or dolomite is the dominant reactions to take place when CO2 is added.

Time-lapse pre-stack seismic inversion with thin bed resolution for CO2 sequestration from Cranfield, Mississippi

Time-lapse surface seismic surveys have been used for CO2 sequestration monitoring at Cranfield, Mississippi. The 3D time-lapse seismic data were recorded both before (2007) and after (2010) CO2 injection. The injection interval is the lower Tuscaloosa sandstone formation, which appears as a thin layer and displays weak signature due to CO2 injection in the post-stack seismic amplitudes. Previous studies have reported inversion of time-lapse acoustic impedances for CO2 plume mapping. However, the acoustic impedances lack elastic information, which are more sensitive to the fluid variation. To address this, we applied a basis pursuit pre-stack inversion on time-lapse Amplitude Versus Angle (AVA) datasets to obtain elastic properties (Vp, Vs, density and Vp−Vs ratio). The inverted elastic properties show improved resolution and provide reasonable fits to the well-log data. The temporal changes of inverted elastic properties provide a basis for mapping the CO2 plume after three years’ injection, demonstrating their effectiveness for a CO2 sequestration study.

Sensitivity analysis of Tuscaloosa sandstones to CO2 saturation, Cranfield field, Cranfield, MS

The study of the seismic response of reservoirs containing injected CO2 is important because it will improve monitoring and characterization of sites used for CO2 utilization and storage. We investigated the sensitivity of the seismic properties to CO2 saturation of the Cranfield injection site using rock physics modeling, fluid substitution, amplitude variation with angle (AVA), and statistical classification. Rock physics models quantitatively linked the elastic properties to variations of CO2 saturation, lithology, and cement content. We modeled velocity and density logs with different fluid compositions. With seismic properties from to these different fluid compositions, we computed (1) AVA responses through Monte Carlo simulations and (2) probability density functions for statistical classification. Rock physics modeling indicated that the upper reservoir is a cemented sandstone and the lower portion a poorly to well sorted mixed lithology sandstone. Consequently, AVA illustrated that the stiff reservoir masked the seismic response due to fluid changes. Statistical classification differentiated between CO2 and brine, with the ratio of compressional to shear wave velocity (Vp/Vs) used as a discerning parameter. Accordingly, these seismic-based tools, applied to relatively high-resolution data, showed the sensitivity of the elastic properties of the Cranfield reservoir to modeled changes of CO2 saturation.

Time-lapse surface seismic inversion with thin bed resolution for monitoring CO2 sequestration: A case study from Cranfield, Mississippi

The feasibility of carbon dioxide sequestration research at Cranfield, Mississippi is studied by injecting millions tonnes of CO2 into the lower Tuscaloosa sandstone Formation over a two year period. Time-lapse surface seismic surveys were recorded at pre-(2007) and post-(2010) injection stages to monitor the subsurface fluid plume. The injection interval, appearing as a thin layer in the well-log data, shows very weak signature of CO2 injection in the time-lapse seismic amplitude data. In order to improve the capability of tracking CO2 plume movement using seismic data, we have applied a basis pursuit inversion (BPI) method to the post-stack seismic datasets. This method of inversion incorporates a priori information as a wedge dictionary and employs a L1-norm optimization for obtaining solutions with improved resolution. The inverted time-lapse acoustic impedances show a strongly decreasing trend mostly at the top of the injection interval, which is in agreement with well-log measurements for CO2 saturation. Improved resolution time-lapse impedance mapping therefore is an effective tool for imaging the displacement of the CO2 plume.

Taenidium and Associated Ichnofossils in Fluvial Deposits, Cretaceous Tuscaloosa Formation, Eastern Alabama, Southeastern U.S.A

Exposures of the Tuscaloosa Formation in eastern Alabama (U.S.A.) provided an opportunity to examine ichnofossils and ichnofabrics within Cretaceous fluvial facies. Floodplain mudstones are completely bioturbated and dominated by backfilled burrows most allied with Taenidium serpentinum. These burrows likely reflect the work of insects or oligochaetes that occupied soft, moist proximal floodplain substrates. Although the affinities and ethology of the tracemakers and the precise environmental conditions that prevailed during burrowing cannot be confidently inferred, Tnenidium‐dominated ichnofabrics of the mudstones can be assigned to the Scoyenia ichnofacies in the narrower sense of several recent authors (e.g., Buatois and Mángano, 1985). Ichnofossils are rare to absent in Tuscaloosa sandstones. The tops of some thin crevasse‐splay sands within mudstone‐dominated intervals were intensely disrupted by Taenidium producers. Large, vertically extensive, chambered(?) burrow systems, presumably dug by some unknown vertebrate organisms, locally were excavated in abandoned channel sands. In situ ichnofossils apparently are absent altogether in conglomeratic fades. However, intraformational conglomerates in channel‐fill sequences locally are composed almost entirely of Taenidium backfill segments that survived erosion from semi‐consolidated floodplain muds and subsequent fluvial transport and, thus, represent a form of concentration‐type ichnofossil‐lagerstätte.

Gas and Condensate Composition in the Deep Tuscaloosa Trend, Southern Louisiana--Influence of Oil and Wet Gas Cracking: ABSTRACT

Natural gas and condensate samples from 34 wells in six fields producing from deep Tuscaloosa sandstones show regular changes in chemical and isotopic composition with increasing depth of burial. A gas-condensate system at 5.2 km (17,000 ft) changes to dry gas at 6.1 km (20,500 ft). Carbon isotopic compositions of ethane and propane become heavier ({delta} {sup 13}C{sub 2} increases from -31 to -23 permil); ({delta}{sup 13}C{sub 3} increases from -29 to -21 permil), while methane becomes lighter ({delta}{sup 13}C{sub 1} decreases from -38 to -42 permil). Depletion of condensate liquids relative to gas over this same depth interval (condensate/gas ratios decrease from 120 to 1 bbl/mmcf) is accompanied by systematic molecular and isotopic changes in the residual liquids. Higher molecular-weight (>C{sub 20}) hydrocarbons are progressively depleted, and isoprenoids are lost relative to adjacent normal alkanes. The liquids shift to heavier {delta}{sup 13}C values (from -27 to -23 permil). These changes are believed to be caused by thermal cracking and progressive conversion of oil and wet gas hydrocarbons to dry gas in Tuscaloosa reservoirs at temperatures of 165 to 195{degrees}C.

Carbonate-Cemented Zones in the Lower Tuscaloosa Formation (Upper Cretaceous), Southwestern Mississippi

ABSTRACT Zones of preferential ankerite cementation are common within non-marine and marine Lower Tuscaloosa sandstone reservoirs of southwestern Mississippi. These carbonate-cemented zones occur as nodules (average radius 6 cm), streaks (average thickness 1 cm), and patches which reduce and often completely impede porosity. Petrographic comparison of sandstone compositions and textures inside and outside the cemented zones revealed that the precipitation of the ankerite was a late-diagenetic event. With the exception of carbonate cement infilling porosity, the overall mineralogy and textural relationships both inside and outside of the carbonate-cemented zones are alike. Stable carbon and oxygen isotope analyses of whole-rock samples also indicate that the cemented zones are products of late diagenesis. Light 18O values of -9 to -12 indicate that the carbonates were precipitated after considerable burial. Negative 13C values of -11 to -14 indicate that carbonate precipitation was from pore waters enriched in 12C because of thermal decomposition of interbedded organic-rich zones.

Sandstone Diagenesis above and below a Pressure Seal--Tuscaloosa Trend, Louisiana

Significant diagenetic differences are observed in the Lower Tuscaloosa sandstone sampled above and below a pressure seal. Additionally, textural evidence suggests that the high porosity (> 20%) in some of the sandstones is secondary. Samples are classified into two groups: normal' (< 12%) and high porosity (12-24%). The normal' porosity sandstones, situated predominantly above the seal, are cemented by either quartz or calcite. At some grain-quartz overgrowth contacts, dissolution of overgrowths and portions of grains is concurrent with precipitation of calcite; some calcite is partially replaced by saddle dolomite. Pore-lining chlorite is present but rare in the normal' porosity sandstones. The high porosity sandstones, situated predominantly below the seal, retain remnants of quartz and carbonate cements; virtually all pores are lined with chlorite. High porosity is attributed primarily to dissolution of carbonate cement. Evidence for previously existing carbonate cement includes: remnant cement, rhomb-shaped porosity, and partially dissolved quartz grains whose surfaces are similar to grain surfaces of the calcite-cemented sandstones. The characteristic robust pore-lining chlorite growth is attributed to accelerated dissolution of volcanic rock fragments with the increase in porosity and permeability after carbonate dissolution. The authors suggest that the pressure seal plays two roles in creating and preserving high more » porosity: (1) the seal impedes fluid flow between two zones of different fluid chemistry and therefore different paragenesis in rocks of essentially the same age and depositional environment, and (2) the seal creates a compartment in which fluid pressures support the rock, inhibiting further compaction after the dissolution of the cement. « less