Norphlet Formation Research Articles

The value of integrated core–CT–BHI data in characterizing aeolian dune geometries and effects of cross-cutting deformation bands: implications for permeability architecture

Abstract Three-dimensional circumferential CT-scans have transformed how core is described and calibrated with borehole image (BHI) datasets to refine reservoir rock typing and facies description. This paper focuses on the value of circumferential CT-scans in the assessment of plug and bed-scale heterogeneities. It shows how careful re-orientation and calibration with borehole images can help unravel sandbody geometries and orientation, and the potential effects of cross-cutting deformation bands on permeability architecture and sweep efficiency. This is demonstrated using aeolian-dominated core examples, supported with circumferential CT-scans, minipermeability data, conventional logs and BHI data, taken from the Jurassic Norphlet Formation from producing fields in the Gulf of Mexico. The formation overlies Early Jurassic Louann Salt, and syn-depositional halokinesis significantly influenced depositional accommodation space, facies distribution, and preservation potential. Furthermore, deposition during active salt tectonics has resulted in complex deformation band networks within these clean sandstones. CT-scan density contrasts highlight stratification types and deformation bands not always visible on slabbed core. Furthermore, BHI re-orientated CT-scans provide high-resolution dip/azimuth data and aid aeolian bedset bounding surface definition, which is important for determining dune geometry and stacking patterns. Hence, an integrated approach using core, circumferential CT-scan and calibrated BHI has been essential for deciphering the complexity of these deposits.

Three‐dimensional bounding surface architecture and lateral facies heterogeneity of a wet aeolian system: Entrada Sandstone, Utah

ABSTRACTAeolian deposits form noteworthy reservoirs (for example, Norphlet Formation and Rotliegend Group) in hydrocarbon extraction and carbon capture and storage contexts, but stratigraphic architecture imparts significant heterogeneity. Bounding surfaces result from autogenic and allogenic controls and can represent important changes in dune‐field dynamics. To further evaluate the impacts of facies heterogeneity and flow‐inhibiting bounding surfaces on reservoir performance and reconstruct ancient erg evolution, the stratigraphic architecture of aeolian systems must continue to be studied at multiple scales. This study pairs traditional methods (for example, measured stratigraphic sections) with advanced technologies (for example, drone‐derived outcrop models) to precisely resolve the metre to kilometre‐scale three‐dimensional stratigraphic architecture of wet aeolian Middle Jurassic Entrada Sandstone outcrops located at Rone Bailey Mesa near Moab, Utah, USA. Five facies are identified, primarily based on sedimentary fabrics, and are grouped into three associations named dune, sabkha and sand sheet. Statistical analyses of gamma‐ray spectrometer and automated mineralogy data indicate a distinct mineralogical difference between dune (quartz‐rich) and sabkha (more feldspathic) packages, suggesting that gamma‐ray logs may be used to better predict facies distribution in the subsurface. Seven modelled super bounding surfaces are planar to undulatory, with no perceived spatial trends. Five modelled interdune migration surfaces are undulatory but exhibit an average 0.09° angle of climb roughly parallel to the palaeocurrent direction. Two modelled superposition surfaces are linear to sinuous in plan‐view. Laterally discontinuous sabkha packages observed are interpreted to be remnants of closed, damp, interdune flats located between ca 8.5 to 17.0 m tall, sinuous, transverse bedforms or patches of such bedforms. Based on stratigraphic architecture interpretations, the Entrada Sandstone preserves signals of allogenic forcing and localized autogenic bedform cannibalization of the substrate. The findings of this study, some of which are not commonly recognized in wet aeolian facies models, enhance the understanding of erg evolution and can parameterize static models of aeolian reservoirs.

Age and provenance of the Middle Jurassic Norphlet Formation of south Texas: stratigraphic relationship to the Louann Salt and regional significance

The age and provenance of the Norphlet Formation in south Texas and its stratigraphic relationship to the Louann Salt are documented for the first time using new detrital zircon U–Pb geochronological data. Nine samples from the Hockley salt diapir and four deep wells (three in south Texas, one offshore México) yielded 1001 zircon ages and eight age populations; the most important of these are Neoproterozoic (900–541 Ma), Cambrian–Middle Mississippian, and arc-related Middle to Late Mississippian–Permian–Triassic and Triassic–Jurassic, the latter two representing the first evidence of Nazas and Guerrero arc extrusive volcanism reaching south Texas. Statistical analyses of these data and published zircon ages support the interpretation that these age populations reflect the dominance of peri-Gondwanan sources, especially the Yucatán/Maya Block and Coahuila terrane, although Laurentian sources probably contribute to specific populations. The maximum depositional age of upper Norphlet Formation sandstones is 165.5 ± 1.5 Ma (Callovian). These upper sandstones are separated from lower Norphlet sandstones by an unconformity spanning 1.5–5 myr; the lower sandstones are interbedded with halite of the Louann Salt, and may be as old as Bathonian. These new data may be of regional significance when applied to future models of the Jurassic evolution of the Gulf of Mexico. Supplementary material : The detrital zircon dataset for this study, DZmix and DZmds model parameters, DZmix statistics and references for figures are available at https://doi.org/10.6084/m9.figshare.c.6002060

Dynamic Simulation in Deep Water Enhances Operations From Design to Production

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 30838, “Shell Appomattox Model-Based Operations From Design to Production: A Game Changer in Gulf of Mexico Deepwater Operation,” by Robert Tulalian, Shell, and Evan Keever and Ankur Rastogi, Kongsberg, prepared for the 2020 Offshore Technology Conference, originally scheduled to be held in Houston, 4–7 May. The paper has not been peer reviewed. Copyright 2020 Offshore Technology Conference. Reproduced by permission. The complete paper discusses how large operations such as Appomattox in the Gulf of Mexico’s deepwater Norphlet formation can use an integrated dynamic simulation-based solution throughout the project life cycle to aid in design verification, operator training, startup support, and real-time surveillance. The authors write that their recommendations and findings can be applied to similar project implementation efforts elsewhere in the industry. Introduction The Appomattox development spans Mississippi Canyon Blocks 348, 391, 392, and 393. Peak production rates are estimated to be approximately 175,000 BOE/D, with water injection planned for the future to support reservoir pressures. Appomattox includes a combined cycle steam system, using process waste heat to generate steam. This steam can be used to drive a generator, providing extra power for the facility. The Appomattox facility can be seen in Fig. 1. A multipurpose dynamic simulator (MPDS) was developed to address the inherent complexities of the Appomattox system, providing a high-fidelity integrated model that simulates both top-sides and subsea process conditions. This model was integrated with the Appomattox control system and deployed in a setup to mimic the offshore control room, creating a realistic training environment for operators. The MPDS was completed over 1 year before first oil, providing ample time for operator training and other use cases such as distributed-control-system (DCS) checkout and engineering studies. Because of the success of the MPDS, the operator applied the existing Appomattox model to the operation phase through the creation of a real-time surveillance system (RTS). Connecting the process model to the facility’s historian by open-platform communications (OPC) enables the RTS to serve as a virtual copy of the live facility, mimicking process conditions in real time. This enables the RTS to serve as a platform for useful surveillance applications such as virtual flow metering, blockage detection, and equipment-performance monitoring. Process Model Development Once the decision to build an MPDS was made, the project team determined which systems would be included in the scope of the model as well as what data would be used for input and validation. Because the MPDS would be used for both engineering and operations use, most systems were included in the scope and modeled at high fidelity to maximize potential benefits.

Palaeogeographical reconstruction and provenance of Oxfordian aeolian sandstone reservoirs in Mexico offshore areas: comparison to the Norphlet aeolian system of the northern Gulf of Mexico

Abstract Palaeogeographical reconstruction of the Oxfordian-age (Jurassic) depositional systems in the southern Gulf of Mexico is supported by detailed sedimentological analyses, detrital zircon geothermochronology and plate tectonic restorations. This integrated approach departs from prior local studies by placing the Bacab Sandstone, a major reservoir in offshore Mexico, in a larger basin- to regional-scale context. Sedimentary characteristics derived from detailed core description show how remarkably similar the Bacab Sandstone is to coeval sandstones of the Norphlet Formation of the northern Gulf of Mexico. A comparison of lithofacies associations suggests similar depositional processes and palaeoclimate regimes, with aeolian dunes forming near base level with adequate wind, sediment supply and arid climatic conditions promoting development of dunes and adjacent sabhkas. Construction of prominent ergs (aeolian sand seas) with lateral transitions to updip fluvial–wadi systems is envisioned in Mexico, comparable to the Norphlet of the northern Gulf of Mexico. Reservoir quality over the southern Mexican offshore area is variable, as numerous well penetrations over several decades have demonstrated. However, in the core area of the Ek-Balam Field, the best reservoirs have surprisingly good porosity and permeability for their age (Jurassic) and present-day depth of burial (>4000 m). However, published information is not definitive on the factors mitigating subsurface reservoir quality destruction. It is possible that similar processes preserving or enhancing porosity under deep burial conditions for the Norphlet are likely to have operated in the Ek and Balam well locations. Available petrographical data on framework grains are similar for Oxfordian sandstones in both the northern and southern Gulf of Mexico. Detrital zircon U–Pb geochronology, however, indicates that different source terranes supplied clastics to the Oxfordian Bacab and Norphlet sandstones. Detrital zircon geothermochronology age spectra indicate that the Mayan (Yucatán) Block was the primary terrane for the Bacab Sandstone. This is separate and distinct from Norphlet source areas that vary from Appalachian (Laurentian) to Pan-African (Gondwanan and peri-Gondwanan) terranes. While it possible that the Bacab and Norphlet sandstones were continuous and connected across the Yucatán margin that lies between the two areas, detrital zircon provenance results do not show any indication of common source terranes. Dimensional considerations, such as the contrasting ratios of Bacab and Norphlet source areas to their respective documented areas of deposition, also support the notion of separated aeolian palaeoenvironments.

Relative reactivity of saturated hydrocarbons during thermochemical sulfate reduction

Tazhong and four other well-known TSR-altered petroleum reservoirs from around the world were analyzed for their molecular and carbon isotopic compositions of saturated hydrocarbons, thiaadamantanes concentrations or H2S contents to determine the relative stability of saturated hydrocarbons during thermochemical sulfate reduction (TSR). We find that TSR does not preferentially deplete tricyclic terpanes and 17α, 21β hopanes with the “exposed” tertiary carbon atoms compared to 18α (H)-22, 29, 30-trisnorhopane (Ts) and C29Ts that have no tertiary carbon atoms, as proposed by Xia and Gong [35]. However, pristane (Pr) and phytane (Ph) seem to have been preferentially oxidized over normal C17 and C18 alkanes, respectively, resulting in decreasing Pr/nC17 and Ph/nC18 ratios with increasing extent of TSR for the Tazhong and Nisku oils and condensates. iC4 appears to be preferentially depleted relative to nC4 during early TSR stage. At later TSR stage both nC3 and nC4 are oxidized more readily than iC4 in the Mobile Bay Norphlet Formation condensates. Thus, we tentatively propose that relative oxidization order during TSR may start with long chain iso-alkanes followed by n-alkanes, then cycloalkanes, C2-C4 alkanes and finally methane; however, it seems that oxidization of these compounds overlaps significantly.

Late Mesozoic gravity sliding and Oxfordian hydrocarbon reservoir potential of the northern Yucatan margin

Abstract The stratigraphy and structural evolution of the western Florida margin is much better understood than its northern Yucatan conjugate because previous hydrocarbon exploration has been more extensive on the Florida margin. In the deep-water northeastern GOM, the post-salt section records late Jurassic-Cretaceous gravity sliding of rafted blocks along a basinward-dipping layer of Callovian salt. This study uses approximately 31,000 line-km of 2D seismic data to describe a coeval area of widespread, gravity sliding along the less-studied, northern Yucatan margin. We define three structural domains based on their distinctive salt structures and associated deformation: 1) a region in the northeastern study area consists of relatively undeformed, late Jurassic-Cretaceous section underlain by 0–300 m-thick salt; 2) areas in the central and southwestern study area contain late Mesozoic gravity slides defined by 300–600 m-thick salt rollers and normal faults rooted onto a 1–4° basinward-dipping salt detachment; and 3) the distal margin of the western and central study area exhibits large salt diapirs up to 6 km tall that deform Quaternary stratigraphic units. In the central Yucatan study area containing late Mesozoic gravity slides, a stratigraphic unit equivalent to the productive Oxfordian Norphlet sandstone of the deep-water northeastern GOM is identified based on its similar seismic character. Reconstructing the extent of this Norphlet-equivalent unit along the Yucatan margin to its location during Oxfordian deposition places it adjacent to an extensive area of Norphlet sandstone mapped in the deep-water northeastern GOM by previous authors. Our reconstruction suggests a 48,000 km2 fairway of potential aeolian, late Jurassic reservoirs on the Yucatan and Campeche margins that includes productive reservoirs in the southeastern Bay of Campeche, which previous authors correlated with the Norphlet Formation.

E&P Notes (March 2018)

E&P Notes (March 2018)

Sediment source regions and paleotransport of the Upper Jurassic Norphlet Formation, eastern Gulf of Mexico

The Upper Jurassic Norphlet Formation is an eolian sandstone and important hydrocarbon reservoir that overlies the Louann Salt in the Gulf of Mexico (GOM). Because the sand was concentrated into dunes formed by Late Jurassic winds, determining the source areas and paleotransport direction of the sand can improve predictions of the distribution of the dune facies around the GOM. Paleo–wind-blown sediment transport into the proto-GOM was controlled by wind direction and magnitude and the extant topography of the basin and adjacent uplands. Analysis of the Norphlet Formation in the eastern GOM shows that wadis and alluvial fans controlled by the location of highs were the primary route for introducing sediment of varied provenance into the eolian erg. Eolian transport directions interpreted from dip-log analyses are south directed in southern Alabama and west to northwest directed in western Florida. Interpretations of regional, two-dimensional, prestack-depth-migrated seismic data show that erosional incision of the Middle Ground arch occurred prior to and during the time of Norphlet deposition; this as well as preexisting lows in the basement topography may have facilitated basinward sand transport of sediment that fed the Norphlet Formation erg preserved in the deep-water subsurface eastern GOM.

Jurassic raft tectonics in the northeastern Gulf of Mexico

The northeastern Gulf of Mexico is dominated by the 900–1800-m Florida Escarpment, which forms the bathymetric expression of the Cretaceous carbonate shelf edge. Outboard of the escarpment lies a region of salt-detached raft blocks, which are closely analogous to type examples in the Kwanza Basin, Angola, in terms of structural style, scale, and amount of extension. We undertook the first detailed structural interpretation of an emerging petroleum exploration province. The rafts detached and translated basinward by gravity gliding on the autochthonous Louann salt in the late Jurassic to early Cretaceous. The Upper Jurassic source rock (lime mudstones) of the Smackover Formation and eolian sandstone reservoir intervals of the Norphlet Formation are structurally segmented and entirely contained within the raft blocks. The rafts are separated by salt ridges and/or extensional fault gaps containing expanded uppermost Jurassic and lower Cretaceous strata of the Cotton Valley Group. The main episode of rafting occurred after deposition of the Smackover and Haynesville Formations and broke the Jurassic carbonate platform into raft blocks 2–40 km in length, which were then translated 25–40 km basinward from their original position. Map-view restoration of the raft blocks suggested a minimum extension of 100%, with basinward transport directions indicating a radial divergence of rafts. In the north of the study area, the transport direction was westerly, whereas in the south, translation was southerly. This pattern, which mimics the Florida Escarpment, suggested that the morphology of the Jurassic slope controlled the style of gravitational tectonics and the location of subsequent Cretaceous carbonate buildups. As with other linked systems on mobile substrates, the observed extension and translation must be balanced by downdip contraction. In the case of the northeastern Gulf of Mexico, the contraction is largely cryptic, being accommodated by salt evacuation, compression of salt walls/stocks, and possibly open-toed canopy advance.

Sand on salt: Controls on dune subsidence and determining salt substrate thickness

Lenticular sand bodies in the Upper Jurassic Norphlet Sandstone in the northeastern Gulf of Mexico basin have been interpreted as preserved large linear dunes that subsided into the underlying Louann Salt layer. Due to imaging difficulties, the thickness of the underlying salt is largely unknown. We performed physical experiments and created a mathematical model to understand dune and salt deformation and to determine the controls on the final preserved dune topography. Nonuniform dune geometry results in unequal loading by sand that drives locally varying subsidence into the salt substrate, resulting in varying degrees of dune flattening and dune relief. Our results indicate that initial salt thickness relative to dune size governs the initial rate of subsidence, thus affecting the final dune topography. However, interdune spacing and dune geometry are also important because they set the pressure gradient and determine the maximum possible subsidence. We conclude that preserved dunes with high relief indicate areas of relatively thin salt thickness and/or close dune spacing, and that dunes with low relief indicate areas of relatively thick salt thickness and/or wide dune spacing. For the case of the Norphlet Formation, dune spacing and salt thickness likely played the major roles in controlling dune subsidence.

Prediction of deep reservoir quality using early diagenetic process models in the Jurassic Norphlet Formation, Gulf of Mexico

We have developed process-based models for early grain coats and their impact on deep reservoir quality in the Jurassic eolian Norphlet Formation, Alabama, with implications for exploration and development in other conventional and tight-gas continental reservoirs. The Norphlet, a major gas reservoir to depths of 21,800 ft (6645 m) and temperatures of 419F (215C), displays contrasting intervals of high and low reservoir quality within compositionally similar cross-bedded eolian sands. Study results show that grain coats formed soon after deposition are responsible for differences in deep Norphlet porosity of up to 20% and permeability up to 200 md. Three types of grain coats were identified in Norphlet dune sands, each formed in a different part of a shallow groundwater system, and each with distinctive impact on deep reservoir quality. Diagenetic chlorite coats, formed where dunes subsided into shallow hypersaline groundwater, preserve good deep porosity (to 20%) and permeability (to 200 md). Continuous tangential illitic coats, formed in the vadose zone of stabilized dunes exposed to periodic fresh-water influx, preserve good deep porosity (to 15%) associated with poor permeability (1 md) due to linked formation of later high-temperature diagenetic illite. Discontinuous grain coats, formed in active dunes where grains were abraded by eolian transport, are associated at depth with tight zones of pervasive quartz cement, low porosity (8%), and low permeability (1 md). These concepts plus data from 60 wells were used to derive bay-wide predictive tight and porous-zone isopachs that can be used for well placement, geologic models, and field development.

Gas geochemistry of the Mobile Bay Jurassic Norphlet Formation: Thermal controls and implications for reservoir connectivity

The Mobile Bay gas field is located offshore Alabama in the northern Gulf of Mexico. Production is from eolian dunes of the Jurassic Norphlet sandstone at depths exceeding 6100 m (20,000 ft) and temperatures greater than 200C. Reservoir connectivity and compositional variation, including the distribution of nonhydrocarbon gases (H2S and CO2), are critical factors in production strategy. To evaluate the controls on compositional variation and connectivity, detailed molecular and isotopic analyses were conducted for 29 wells. Analysis of volatiles in fluid inclusions suggests that the field was originally filled with oil that subsequently cracked to gas. In addition to the thermal destruction (cracking) of oil, the process of thermochemical sulfate reduction (TSR) continues to destroy the remaining hydrocarbons through oxidation of gas and reduction of sulfate to form H2S and CO2. The variable extent of the TSR process at Mobile Bay results in a wide range of hydrocarbon and H2S compositions. Condensates are almost exclusively composed of diamondoids whose composition appears controlled by H2S concentrations. In contrast to hydrocarbon and H2S contents, CO2 concentrations are relatively constant throughout the field. Carbon isotopic ratios for CO2 correlate positively with those for wet-gas hydrocarbons but are heavier than expected for CO2 originating from hydrocarbon oxidation via TSR. The narrow range of CO2 contents and heavy isotope ratios suggests that CO2 is regulated by water-rock equilibration and carbonate precipitation. The destruction of the hydrocarbon gas and mineralization of the carbon dioxide product create a volume reduction and an associated drop in reservoir pressure. This process creates several internal sinks (or exits) that may control the spill direction for gas in the field.

High temperature quartz cementation and the timing of hydrocarbon accumulation in the Jurassic Norphlet sandstone, offshore Gulf of Mexico, USA

Abstract Jurassic Norphlet Formation sandstone reservoirs in Mobile Bay (offshore Alabama, USA) produce gas from great depths (>6.4 km) and elevated temperatures (>200 °C). Quartz cement is concentrated at the top of these aeolian reservoirs forming a low porosity ‘tight-zone’ of widely variable thickness (3–58 m) above a more porous reservoir section. The extent of the tight-zone is independent of depositional facies and its thickness strongly influences well performance. Intergranular porosity in the Norphlet has been preserved by inhibition of quartz cementation due to the occurrence of robust grain-coating chlorite. Quantitative petrographic data reveal that chlorite grain-coat coverage is less in the tight-zone sands (mean = 92%) than in the reservoir sands (mean = 99%). Burial history and quartz precipitation kinetics modelling indicate that this seemingly minor difference in the completeness of grain coatings is sufficient to produce the observed differences in cementation and porosity. Quartz cementation to form the tight-zone took place under conditions of deep burial and high temperature. It followed in time the onset of pressure solution, emplacement of liquid hydrocarbons, and the precipitation of a solid hydrocarbon film (pyrobitumen) on the walls of the intergranular pores. Fluid inclusion microthermometry data indicate that volumetrically significant quartz cement precipitated at temperatures of 150 °C or greater from highly saline aqueous fluids. Hydrocarbon-bearing inclusions are notably absent in quartz cement of the tight-zone, implying that the pore fluids were predominantly brine during precipitation. Oil and gas associated with pyrobitumen evidently escaped from Norphlet traps prior to tight-zone cementation. Gas presently found in Norphlet reservoirs of Mobile Bay represents a relatively recent accumulation and is not the product of in situ thermal cracking of oil.

Sequence Stratigraphy of the Smackover Formation in Northern Louisiana

Electric logs, conventional cores, 2D and 3D seismic reflection data reveal three sequences in the Smackover Formation in northern Louisiana and adjacent areas. In ascending order these are the Smackover “C”, “B”, and “A” sequences. Characteristics of these sequences were controlled by relative sea-level change, climate, and the nature of the carbonate factory—namely the rate of inorganic carbonate production. The lowstand systems tract (LST) portion of the “C” sequence has not been recognized, but it could possibly be the Norphlet Formation. The Smackover portion of the “C” sequence was initiated by a rapid sea-level rise resulting in a very sharp lithologic contact between the Norphlet and Smackover formations. The “C” sequence lacks a distinct transgressive systems tract (TST) component, and consists primarily of beach-tobasin prograding highstand systems tract (HST) deposition on a ramp. The “C” sequence deposition was terminated by a type-1 sequence boundary characterized by caliche and silcrete. A shelf morphology with a distinct shelf margin had developed by the end of the “C” sequence upon which the “B” sequence was deposited. The “B” sequence consists of a LST that is composed of basinal terrigenous sediment gravity flow deposits. A rapid sea-level rise flooded the shelf area, but again no clear TST deposition occurred. The “B” sequence is composed primarily of HST shoal complexes that prograded over the shelf. A type-1 sequence boundary ended “B” sequence deposition. The “A” sequence consists of an LST that is also composed of basinal terrigenous sediment gravity flow deposits in the basin. The “A” sequence consists of progradational shoals formed slightly basinward of the “B” sequence shelf margin. The “A” sequence sedimentation was terminated by a type-1 or type-2 sequence boundary. The Buckner Formation is not time-equivalent to any of Smackover sequences. It is a younger unit and was deposited in a broad restricted lagoon during a sea-level rise after the Smackover deposition had ended. GULF COAST ASSOCIATION OF GEOLOGICAL SOCIETIES TRANSACTIONS VOLUME LI, 2001 108

The Petrophysical Characteristics of Jurassic Reservoirs of the Coastal Mississippi Counties and Adjacent State Waters

The purpose of this study is the determination of petrophysical characteristics observable for Jurassic reservoirs in the study area; these characteristics are important for hydrocarbon production from those reservoirs. The study area consists of the three Mississippi coastal counties, Hancock, Harrison, and Jackson, and Mississippi's state waters offshore. The section of importance to this study is the Upper Jurassic, which is made up of, from oldest to youngest, the Norphlet Formation, Smackover Formation, Haynesville Formation (including a Frisco City-equivalent granite wash and the Buckner Anhydrite), and Cotton Valley Group. Within the study area only one Upper Jurassic gas field has been discovered. The Catahoula Creek field is located onshore in Hancock County in the western portion of the study area and is productive of gas from Cotton Valley sands below 19,000 ft. Well log and core data from dry exploratory holes in the study area were used to supplement the limited reservoir data at Catahoula Creek. Nine wildcat wells have penetrated the Jurassic in the study area, so the Jurassic wildcat drilling density is approximately one wildcat well per 290 mi2. Because of this lack of data in the study area, published information on the following Upper Jurassic fields in southwestern Alabama, both onshore and offshore, is included: Chunchula field (Smackover), Hatter's Pond field (Smackover), Hatter's Pond field (Norphlet), and Lower Mobile Bay Mary Ann field (Norphlet). Structurally, the three coastal counties and offshore state waters of Mississippi occupy the southern flank of the Wiggins Arch, an area of positive Paleozoic basement features, and the related Hancock Ridge. The Jurassic strati graphic section in the study area consists of more than 5,000 ft of clastics, evaporites, and carbonates at depths below 17,000 ft to 24,000 ft.

Depositional and Diagenetic History and Petroleum Geology of the Jurassic Norphlet Formation of the Alabama Coastal Waters Area and Adjacent Federal Waters Area

The discovery of deep (20,000 ft) gas reservoirs in eolian sandstone of the Upper Jurassic Norphlet Formation in Mobile Bay and offshore Alabama in the late 1970s represents one of the most significant hydrocarbon discoveries in the nation during the past several decades. Estimated original proved gas from Norphlet reservoirs in the Alabama coastal waters and adjacent federal waters is 7.462 trillion ft3 (Tcf) (75% recovery factor). Fifteen fields have been established in the offshore Alabama area. Norphlet sediment was deposited in an arid environment in alluvial fans, alluvial plains, and wadis in updip areas. In downdip areas, the Norphlet was deposited in a broad desert plain, with erg development in some areas. Marine transgression, near the end of Norphlet deposition, resulted in reworking of the upper part of the Norphlet Formation. Norphlet reservoir sandstone is arkose and subarkose, consisting of a simple assemblage of three minerals, quartz, albite, and K-feldspar. The present framework grain assemblage of the Norphlet is dominantly diagenetic, owing to albitization and dissolution of feldspar. Despite the simple framework composition, the diagenetic character of the Norphlet is complex. Important authigenic minerals include carbon ate phases (calcite, dolomite, Fe-dolomite, and breunnerite), feldspar (albite and K-feldspar), evaporite minerals (anhydrite and halite), clay minerals (illite and chlorite), quartz, and pyrobitumen. The abundance and distribution of these miner als varies significantly between onshore and offshore regions of Norphlet production. The lack of sufficient internal sources of components for authigenic minerals, combined with unusual chemical compositions of chlorite (Mg-rich), breunnerite, and some minor authigenic minerals, suggests that Louann-derived fluids influenced Norphlet diagenesis. In offshore Alabama reservoirs, porosity is dominantly modified primary poros ity. Preservation of porosity in deep Norphlet reservoirs is due to a combination of factors, including a lack of sources of cement components and lack of pervasive early cement, so that fluid-flow pathways remained open during burial. Below the dominantly quartz-cemented tight zone near the top of the Norphlet, pyrobitumen is a major contributor to reduction in reservoir quality in offshore Alabama. The highest reservoir quality occurs in those wells where the present gas water contact is below the paleohydrocarbon water contact. This zone of highest reservoir quality is between the lowermost occurrence of pyrobitumen and the present gas water contact.

Abstract:Norphlet Geology and 3-D Geophysics of Fairway Field Mobile Bay, Alabama

Abstract The exploration and exploitation of the area south of Dauphin Island, Alabama, has been based primarily on the geophysical evaluation of a high quality 3-D seismic survey shot by an industry consortium in 1986 to image the eolian Norphlet Formation at depths between 21,000 ft and 22,000 ft. An analog bay cable was used to acquire data over 49 state and federal offshore blocks in a 250 sq mile area at the mouth of Mobile Bay. The 3-D imaging of the lenticular Norphlet dune trends in this area is significantly better than with 2-D data. The 3-D data have led to a much better regional understanding of the Norphlet and consequently a much-improved interpretation of the Shell-BP Amoco Fairway Field. The Norphlet isopach has been mapped with confidence in areas where the sandstone lenses are thick, and has revealed a series of northwest-southeast-trending linear dune forms across the survey area. Post-3-D exploration and development has targeted these thick, paleogeomorphic features where they have been enhanced by subjacent salt structure. Reservoir decline had averaged about 9% per year starting from a maximum production rate of about 200 MMCFG per day in the fall of 1992. Recently, the volumetric decline has become more exponential at about 12%, and some of the wells have begun to demonstrate production characteristics that may be associated with internal dune heterogeneity and water coning. The ultimate recoverability for Fairway Field is projected to be about 65 percent of the approximately 800 BCFG in place with low abandonment pressures due to the high mechanical strength of the dune reservoir matrix. End_of_Record - Last_Page 64--------

Authigenic Muscovite and Stylolitization Timing, Jurassic Norphlet Formation, Offshore Alabama : ABSTRACT

Authigenic Muscovite and Stylolitization Timing, Jurassic Norphlet Formation, Offshore Alabama : ABSTRACT

Petroleum System Evolution in the Conecuh Embayment, Southwest Alabama, U.S. Gulf Coast: ABSTRACT

ABSTRACT Analyses of hydrocarbon maturation trends in Smackover reservoirs of southwest Alabama indicate that crude oils in updip reservoirs of the Conecuh Embayment are anomalously mature for their present temperature-depth regimes. It is inferred that these mature oils equilibrated to depth-temperature conditions in deeper reservoirs downdip, and subsequently re-migrated to their present positions. Burial history reconstructions, regional structure, and reservoir distributions support a model in which these mature oils leaked from the Jay-Flomaton-Big Escambia Creek field complex during Tertiary time, migrated through the Norphlet Formation, and accumulated in updip Smackover and Haynesville traps associated with basement knobs. Geochemical evidence suggests that hydrocarbon leakage from the Jay-Flomaton-Big Escambia Creek complex may have been triggered by an influx of very mature gas-condensates with high non-hydrocarbon gas contents from failed reservoirs still farther downdip. This scenario has potential implications for 1) predicting potential migration pathways and preferred areas of crude oil accumulation in the updip portion of the Conecuh Embayment, and 2) re-interpreting organic-inorganic burial diagenetic reactions in Norphlet Formation reservoirs of offshore Mobile Bay. End_of_Record - Last_Page 484-------