Ernest A. Mancini

Geochemical Relationships of Petroleum in Mesozoic Reservoirs to Carbonate Source Rocks of Jurassic Smackover Formation, Southwestern Alabama

Algal carbonate mudstones of the Jurassic Smackover Formation are the main source rocks for oil and condensate in Mesozoic reservoir rocks in southwestern Alabama. This interpretation is based on geochemical analyses of oils, condensates, and organic matter in selected samples of shale (Norphlet Formation, Haynesville Formation, Trinity Group, Tuscaloosa Group) and carbonate (Smackover Formation) rocks. Potential and probable oil source rocks are present in the Tuscaloosa Group and Smackover Formation, respectively. Extractable organic matter from Smackover carbonates has molecular and isotopic similarities to Jurassic oil. Although the Jurassic oils and condensates in southwestern Alabama have genetic similarities, they show significant compositional variations due to differences in thermal maturity and organic facies/lithofacies. Organic facies reflect different depositional conditions for source rocks in the various basins. The Mississippi Interior Salt basin was characterized by more continuous marine to hypersaline conditions, whereas the Manila and Conecuh embayments periodically had lower salinity and greater input of clastic debris and terrestrial organic matter. Petroleum and organic matter in Jurassic rocks of southwestern Alabama show a range of thermal transformations. The gas content of hydrocarbons in reservoirs increases with increasing depth and temperature. In some reservoirs where the temperature is above 266°F (130°C), gas-condensate is enriched in isotopically heavy sulfur, apparently derived from thermochemical reduction of Jurassic evaporite sulfate. This process also results in increased H2S and CO2 in the gas, and depletion of saturated hydrocarbons in the condensate liquids. Thermochemical sulfate reduction probably depends on the mineralogic composition of the reservoir rock as well as temperature, because some deep (18,000 ft or 5.5 km) and hot (320°F or 160°C) Smackover and Norphlet reservoirs contain low-sulfur petroleum.

Norphlet Formation (Upper Jurassic) of Southwestern and Offshore Alabama: Environments of Deposition and Petroleum Geology

Upper Jurassic Norphlet sediments in southwestern and offshore Alabama accumulated under arid climatic conditions. The Appalachian Mountains of the eastern United States extended into southwestern Alabama to provide a barrier for air and water circulation during the deposition of the Norphlet Formation. These mountains produced topographic conditions that contributed to the arid climate, and they affected sedimentation. Norphlet paleogeography in southwestern Alabama was dominated by a broad desert plain, rimmed to the north and east by the Appalachians and to the south by a developing shallow sea. The desert plain extended westward into eastern and central Mississippi. Norphlet sedimentation initiated as a result of basin subsidence accompanied by erosion of the southern Appalachians. Norphlet conglomerates were deposited in coalescing alluvial fans in proximity to an Appalachian source. The conglomeratic sandstones grade downdip into red beds that accumulated in distal portions of alluvial fan and wadi systems. Quartz-rich sandstones were deposited as dune and interdune sediments on a broad desert plain. The principal source of the sand was updip alluvial fan and plain and wadi deposits. Wadi and playa lake sediments also accumulated in the interdune areas. A marine transgression was initiated during the late phase of deposition of the Norphlet Formation, resulting in the reworking of previously deposited Norphlet sediments. Norphlet hydrocarbon potential in southwestern and offshore Alabama is excellent; six oil and gas fields already have been established. Petroleum traps discovered to date are primarily structural traps involving salt anticlines, faulted salt anticlines, and extensional fault traps associated with salt movement. Reservoir rocks consist primarily of quartz-rich sandstones that are eolian, wadi, and marine in origin. Porosity is principally secondary (dissolution) with some intergranular porosity. Smackover algal carbonate mudstones were probably the source for the Norphlet hydrocarbons. Jurassic oil generation and migration probably were initiated in the Early Cretaceous.

Upper Jurassic thrombolite reservoir play, northeastern Gulf of Mexico

In the northeastern Gulf of Mexico, Upper Jurassic Smackover inner ramp, shallow-water thrombolite buildups developed on paleotopographic features in the eastern part of the Mississippi Interior Salt basin and in the Manila and Conecuh subbasins. These thrombolites attained a thickness of 58 m (190 ft) and were present in an area of as much as 6.2 km2 (2.4 mi2). Although these buildups have been exploration targets for some 30 yr, new field discoveries continue to be made in this region. Thrombolites were best developed on a hard substrate during a rise in sea level under initial zero to low background sedimentation rates in low-energy and eurytopic paleoenvironments. Extensive microbial growth occurred in response to available accommodation space. The demise of the thrombolites corresponded to changes in the paleoenvironmental conditions associated with an overall regression of the sea. The keys to drilling successful wildcat wells in the thrombolite reservoir play are to (1) use three-dimensional seismic reflection technology to find paleohighs and to determine whether potential thrombolite reservoir facies occur on the crest and/or flanks of these features and are above the oil-water contact; (2) use the characteristics of thrombolite bioherms and reefs as observed in outcrop to develop a three-dimensional geologic model to reconstruct the growth of thrombolite buildups on paleohighs for improved targeting of the preferred dendroidal and chaotic thrombolite reservoir facies; and (3) use the evaporative pumping mechanism instead of the seepage reflux or mixing zone models as a means for assessing potential dolomitization of the thrombolite boundstone.

Sequence-stratigraphic analysis of Jurassic and Cretaceous strata and petroleum exploration in the central and eastern Gulf coastal plain, United States

The formulation of an integrated sequence-stratigraphic and biostratigraphic framework is fundamental in the design of an effective strategy for petroleum exploration in a sedimentary basin. For the interior salt basins of the Gulf coastal plain of the United States that are filled primarily with Mesozoic postrift nonmarine to marine siliciclastic and carbonate deposits, a sequence-stratigraphic approach using transgressive-regressive (T-R) sequences and integrated with biostratigraphic information has utility as a method for establishing such a framework. The sequence stratigraphy established for Upper Jurassic and Cretaceous strata is used to categorize petroleum reservoirs in the central and eastern Gulf coastal plain. Transgressive aggrading eolian, fluvial, and coastal sandstone facies of the T-R sequences include highly productive hydrocarbon reservoirs in the eastern Gulf coastal plain. Productive reservoirs in the central and eastern Gulf coastal plain include regressive infilling fluvial to nearshore marine sandstone facies, and nearshore marine, shelf, ramp, and reef carbonate facies. Transgressive backstepping nearshore marine facies include highly productive reservoirs in the central Gulf coastal plain. These transgressive and regressive facies are recognized by their wireline log patterns and seismic reflection configurations. Knowledge of the diagnostic wireline log signatures and seismic reflection characteristics assists in the detection of exploration targets.

Regional Jurassic geologic framework of Alabama coastal waters area and adjacent Federal waters area

Abstract To date, numerous Jurassic hydrocarbon fields and pools have been discovered in the Cotton Valley Group, Haynesville Formation, Smackover Formation and Norphlet Formation in the tri-state area of Mississippi, Alabama and Florida, and in Alabama State coastal waters and adjacent Federal waters area. Petroleum traps are basement highs, salt anticlines, faulted salt anticlines and extensional faults associated with salt movement. Reservoirs include continental and marine sandstones, limestones and dolostones. Hydrocarbon types are oil, condensate and natural gas. The onshore stratigraphic and structural information can be used to establish a regional geologic framework for the Jurassic for the State coastal waters and adjacent Federal waters areas. Evaluation of the geologic information along with the hydrocarbon data from the tri-state area indicates that at least three Jurassic hydrocarbon trends (oil, oil and gas condensate, and deep natural gas) can be identified onshore. These onshore hydrocarbon trends can be projected into the Mobile area in the Central Gulf of Mexico and into the Pensacola, Destin Dome and Apalachicola areas in the Eastern Gulf of Mexico. Substantial reserves of natural gas are expected to be present in Alabama State waters and the northern portion of the Mobile area. Significant accumulations of oil and gas condensate may be encountered in the Pensacola, Destin Dome, and Apalachicola areas.

Mesozoic (Upper Jurassic–Lower Cretaceous) deep gas reservoir play, central and eastern Gulf coastal plain

The Mesozoic (Upper Jurassic–Lower Cretaceous) deeply buried gas reservoir play in the central and eastern Gulf coastal plain of the United States has high potential for significant gas resources. Sequence-stratigraphic study, petroleum system analysis, and resource assessment were used to characterize this developing play and to identify areas in the North Louisiana and Mississippi Interior salt basins with potential for deeply buried gas reservoirs. These reservoir facies accumulated in Upper Jurassic to Lower Cretaceous Norphlet, Haynesville, Cotton Valley, and Hosston continental, coastal, and marine siliciclastic environments and Smackover and Sligo nearshore marine shelf, ramp, and reef carbonate environments. These Mesozoic strata are associated with transgressive and regressive systems tracts. In the North Louisiana salt basin, the estimate of secondary, nonassociated thermogenic gas generated from thermal cracking of oil to gas in the Upper Jurassic Smackover source rocks from depths below 3658 m (12,000 ft) is 4800 tcf of gas as determined using software applications. Assuming a gas expulsion, migration, and trapping efficiency of 2–3%, 96–144 tcf of gas is potentially available in this basin. With some 29 tcf of gas being produced from the North Louisiana salt basin, 67–115 tcf of in-place gas remains. Assuming a gas recovery factor of 65%, 44–75 tcf of gas is potentially recoverable. The expelled thermogenic gas migrated laterally and vertically from the southern part of this basin to the updip northern part into shallower reservoirs to depths of up to 610 m (2000 ft).

Recognition of maximum flooding events in mixed siliciclastic-carbonate systems: Key to global chronostratigraphic correlation

The maximum flooding event within a depositional sequence is an important datum for correlation because it represents a virtually synchronous horizon. This event is typically recognized by a distinctive physical surface and/or a significant change in microfossil assemblages (relative fossil abundance peaks) in siliciclastic deposits from shoreline to continental slope environments in a passive margin setting. Recognition of maximum flooding events in mixed siliciclastic-carbonate sediments is more complicated because the entire section usually represents deposition in continental shelf environments with varying rates of biologic and carbonate productivity versus siliciclastic influx. Hence, this event cannot be consistently identified simply by relative fossil abundance peaks. Factors such as siliciclastic input, carbonate productivity, sediment accumulation rates, and paleoenvironmental conditions dramatically affect the relative abundances of microfossils. Failure to recognize these complications can lead to a sequence stratigraphic interpretation that substantially overestimates the number of depositional sequences of 1 to 10 m.y. duration.

Environments of Deposition and Petroleum Geology of Tuscaloosa Group (Upper Cretaceous), South Carlton and Pollard Fields, Southwestern Alabama

In southwestern Alabama, the lower Tuscaloosa Group (Upper Cretaceous) consists of two informally defined units, the Massive and Pilot sand intervals. The Massive sand interval accumulated principally as sands in a wave-dominated, high-destructive delta system. These sandstones are structureless, well sorted, micaceous, locally fossiliferous, calcareous, glauconitic, fine grained, and quartz rich, containing angular to subangular quartz grains. The Massive sand interval unconformably overlies fluvial-deltaic sediments of Lower Cretaceous strata. The Pilot sand interval, which overlies the Massive sand interval, accumulated as shelf sands and clays during a marine transgression. The sandstones are well sorted, micaceous, fossiliferous, calcareous, glauconitic, very fine to fine grained, and quartz rich, containing sub-angular to subrounded quartz grains. The sandstones appear massive but may be structureless as a result of extensive bioturbation. Marine bivalves, such as inoceramids, are present in the sandstones and claystones. The Pilot sand interval is overlain by a marine claystone (Marine shale) containing a diverse faunal assemblage of macroinvertebrates, including ammonites, inoceramids and other bivalves, and a rich microfossil assemblage of planktonic foraminifera and calcareous nannofossils. The Marine shale accumulated in an open-marine shelf environment. Petroleum traps in the Tuscaloosa are structural traps involving salt anticlines (South Carlton field) and extensional fault traps associated with salt movement (Pollard field). Reservoir-grade porosity occurs in the Massive and Pilot sandstone units as primary intergranular porosity. Although Tuscaloosa marine claystones contain significant amounts of organic carbon, these rocks are thermally too immature to be the petroleum source rocks for the Tuscaloosa crude oils in South Carlton and Pollard fields.

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.

Appleton field case study (eastern Gulf coastal plain): Field development model for Upper Jurassic microbial reef reservoirs associated with paleotopographic basement structures

Appleton oil field, located in Escambia County, Alabama, was discovered in 1983 through the use of two-dimensional seismic reflection data. The field structure is a northwest-southeast–trending paleotopographic ridge comprised of local paleohighs. The field produces from microbial reef boundstones and shoal grainstones and packstones of the Upper Jurassic Smackover Formation. Because Appleton field is approaching abandonment, owing to reduced profitability, an integrated geoscientific study of the field structure and reservoir was undertaken to determine whether drilling additional wells in the field would extend the productive life of the reservoir. The conclusion from the integrated study, which included advanced carbonate reservoir characterization, three-dimensional geologic visualization modeling, seismic forward modeling, porosity distribution analysis, and field production analysis, was that a sidetrack well drilled on the western paleohigh should result in improved oil recovery from the field. The sidetrack well was drilled and penetrated porous Smackover reservoir near the crest of the western paleohigh. The well tested 136 bbl oil/day. (Begin page 1700)