David C. Kopaska-Merkel

Petrofacies Analysis of Carbonate Rocks: Example From Lower Paleozoic Hunton Group of Oklahoma and Texas

A petrophysical classification of Hunton Group dolomitized carbonates (lower Paleozoic) in the Anadarko basin of Oklahoma and Texas is based on porosity, mercury-recovery efficiency, median pore-throat size, normalized pore-throat size, the shapes of capillary-pressure curves, and lithology. Five petrophysical facies (petrofacies) include (I) porous and permeable dolostones, (II) skeletal grainstones and packstones, (III) low-porosity, low-permeability dolomitized oomoldic ooid grainstones, (IV) cemented ooid grainstones, cherts, and cherty carbonates, and (V) lime mudstones and tight fine-grained dolostones. Petrofacies I (porous dolostone) is the most variable. This variability reflects the inherent variability of dolostones, and the probability that dolomitization of t e Hunton Group occurred in more than one episode. Four subpetrofacies include (IA) crystalline and sucrosic dolostones, (IB) vuggy dolostones, (IVA) cemented ooid grainstones, and (IVB) cherts and cherty mudstones and wackestones. The petrofacies form mappable subsurface units that can be used to predict the distribution of petroleum reservoirs (e.g., petrofacies I and II) and of potential sealing units (petrofacies III, IV, and V), and to identify potential stratigraphic traps. Petrofacies and depositional lithofacies are discordant, indicating that diagenetic processes did not respect lithofacies boundaries. The best reservoir rocks (sucrosic fossiliferous dolostones of subpetrofacies IA and crinoidal grainstones of petrofacies II) have both high porosities (mean = 5.2-6.9%) and high mercury-recovery efficiencies (mean = 30.7-36.1%). These rocks are characterized by moderately sized throats (median = 2.6-8.8 µm), mesokurtic to platykurtic pore-throat-size distributions, and intermediate or gently sloping cumulative mercury-intrusion capillary-pressure curves. Higher porosity rocks with low mercury-recovery efficiencies (mean porosity = 11.8%; RE <= 25%; for example, vuggy and moldic dolostones of subpetrofacies IB) would not perform well during primary oil recovery, but would be good candidates for enhanced oil recovery. For reservoir rocks that are oil wet, capillary-pressure dat must be interpreted differently than is done in this paper. Most petrofacies can be distinguished by the shapes of capillary-pressure curves alone. However, bivariate plots of petrophysical parameters also allow discrimination between petrofacies. The negative log of median pore-throat size plotted vs. either porosity or mercury-recovery efficiency provides the most readily interpretable graphic method of assigning samples to petrofacies. Such plots are particularly useful in highlighting samples that are lithologically similar to but petrophysically different from samples typical of a particular petrofacies.

A lone biodetrital mound in the Chesterian (Carboniferous) of Alabama

Abstract A carbonate mound in the Chesterian Bangor Limestone of Lawrence County, Alabama, consists chiefly of packstone and grainstone dominated by echinoderm ossicles and fragments of fenestrate bryozoans. In-situ colonies of the rugose coral Caninia flaccida comprise about 8% of the mound by volume. The exposed portion of the mound is approximately 25 m wide, 1.6 m thick at the thickest point and roughly circular in plan. The mound developed on top of a shallow ooid shoal that had been cemented and stabilised during an earlier episode of sub-aerial exposure. Subsequent flooding of the exposed shoal surface permitted establishment of the mound biota. Lateral and vertical facies relationships suggest that the mound possessed about 45 cm of synoptic relief when fully developed. Rugose corals, fenestrate and ramose bryozoans, stalked echinoderms, and sessile soft-bodied organisms encrusted by foraminifera colonised the shoal, forming a mound. Baffling resulted in deposition of mixed-fossil packstone containing locally derived debris and coated grains from the surrounding sea floor. Strong currents within the mound are indicated by preferred orientation of corals and by coarse, commonly cross-stratified grainstone in channels between neighboring coral colonies. Corals are most abundant on the windward side of the mound, where they account for about 13% of the mound compared to 6–10% in the central part of the mound, and 2–4% on the leeward flank. Biodetrital mounds such as the one described here are uncommon in upper Paleozoic strata and previously unknown in the Bangor Limestone. Of 10 carbonate buildups we examined in the Bangor in Alabama and Tennessee, only one is a biodetrital mound. Two are rugose coral–microbial reefs, one is a coral biostrome, and six are dominated by microbialite. The Bangor shelf, previously interpreted as sedimentologically simple, appears to contain many small mounds of quite varied characteristics. Also, the discovery of a biodetrital mound in the Chesterian of Alabama suggests that there may be more kinds of upper Paleozoic mounds than commonly acknowledged.

Controls on Reservoir Development in a Shelf Carbonate: Upper Jurassic Smackover Formation of Alabama

Hydrocarbon reservoirs of the Upper Jurassic Smackover Formation in Alabama are predominately oolitic and pelletal dolostone. Pore systems are dominated by moldic and secondary intraparticle pores, intercrystalline pores, or mixtures of these pore types. All Smackover reservoirs in Alabama have been strongly affected by early cementation, dissolution of calcium-carbonate allochems, and dolomitization. Marine-phreatic cement occluded primary interparticle porosity in much of the Smackover reservoirs in Alabama. Dolomitization of the Smackover in Alabama included penecontemporaneous, early burial, and late (deep) burial episodes. Early burial dolomite predominates. Fabric-selective dolomitization yielded reservoirs strongly influenced by both depositional fabric and diagene is. Nonselective dolomitization yielded reservoirs with intercrystalline pore systems shaped primarily by diagenesis. Porosity evolution was controlled regionally by level of thermal exposure, mode of dolomitization, and proximity to the Wiggins arch. Thermal exposure is inversely related to porosity, but the relationship is weak (r2 < 0.5). Fabric-selective dolostone is slightly more porous than nonselective dolostone when averaged over the entire study area (averages of 18.1% and 15.1%, respectively; p = 0.0001), but nonselective dolostone is more porous at a given level of equivalent vitrinite reflectance. Smackover fields on the north flank of the Wiggins arch are unusually porous given their level of thermal maturity, and are unusual in other ways as well. Local porosity variation was controlled by depositional fabric, early cementation, dissolution, and burial compaction and cemen ation. Regional permeability variation cannot be explained using existing data. Permeability is locally controlled by pore-throat size, the effects of dolomite crystal-size distribution, early cementation, fracturing, and burial compaction and cementation. Pore-throat size exhibits the strongest overall correlation with permeability (r2 = 0.54). Permeability and porosity are strongly correlated locally, but the regional correlation is weak.

Microporosity and production potential in ooids: Mesozoic and paleozoic of Texas

Micritized ooids consisting of euhedral calcite rhombs 1 to 5 microns across are described from ooid grainstones and packstones of Ordovician to Jurassic age from 4 outcrops, 3 cores, and 7 suites of well cuttings in Texas. Microporosity within the micritized ooids may be greater than 15 percent, with permeabilities up to about 1 millidarcy. Micritization of the ooids described here was not caused by leaching, but may have occurred during mineralogical stabilization from aragonite to calcite.

Classification of Lithified Carbonates Using Ternary Plots of Pore Facies: Examples from the Jurassic Smackover Formation

Ternary diagrams whose apexes are carbonate pore types (ternary pore plots) are used to summarize quantitative data derived from point counting of thin sections, using a modification of the genetic carbonate-rock porosity classification of Choquette and Pray (1970). Ternary pore plots provide information on the shapes and origins of pore-system elements. Hence, ternary pore plots complement engineering data, which give information on the sizes of pore-system elements. Thin-section point-count data are inexpensive and easy to collect, and can be used to guide more expensive engineering analyses.

Fabric and composition of dolostones and dedolomites from near karapinar (Adana, Southern Turkey)

Dolostone and dedolomite textures in Mesozoic and upper Paleozoic carbonates of southern Turkey exhibit the following fabrics: xenotopic equigranular, hypidiotopic inequigranular, idiotopic equigranular, hypidiotopic inequigranular-porphyrotopic, and poikilotopic. The paragenetic sequence is as follows: 1) deposition and shallow-burial diagnesis, 2) growth of coarsely-crystalline, euhedral, zoned dolomite, 3) pervasive dolomitization, 4) dedolomitization, 5) fracturing, 6) dolomite cementation in fractures, 7) stylolitization. Bulk compositional analyses of 50 samples suggest the following observations: 1) most samples are either nearly pure calcite, or nearly pure dolomite, 2) the youngest rocks (Upper Cretaceous Akdaĝ Formation), and most of the Lower to Middle Cretaceous black “dolosparite” of the Belemedik-Köserelik Formation are primarily calcium carbonate, whereas most of the true dolostones are Carboniferous black biosparites of the Belemedik-Köserelik Formation are primarily calcium carbonate, whereas most of the true dolostones are Carboniferous black biosparites of the Belemedik-Köserelik Formation. Some Carboniferous black “dolobiosparites” are actually nearly pure calcium carbonate, 3) samples from the southern part of the study area are nearly all dolostones, whereas those from the east are limestones (or dedolomites). This suggests either a southern or southwestern source for the magnesium-rich fluids which dolomitized these rocks, or a northern or northeastern source for the dedolomitizing fluids.

Depositional History of the Smackover-Buckner Transition, Eastern Mississippi Interior Salt Basin

ABSTRACT Shoaling upward cycles of the upper part of the Smackover Formation are locally capped by thin sabkha deposits adjacent to and on the crests of paleotopographic highs in the eastern Mississippi interior salt basin (MISB). These sabkhas are overlain by peritidal carbonates of the uppermost Smackover. Relative sea level fell during late-Smackover progradation and sabkha deposition, then rose again to deposit peritidal carbonates. A sharp contact typically separates these peritidal carbonate deposits and the overlying massive Buckner Anhydrite in the MISB. Evidence for a significant sea-level change at the Smackover-Buckner Boundary is lacking. Smackover sabkha deposits in the MISB consist of intercalated matrix-dominated nodular anhydrite and anhydritic dolostone in which the proportion of anhydrite commonly increases upward. They are overlain by micritic, pelletal, or oolitic peritidal dolostone. Smackover sabkhas formed on local paleotopographic highs concentrated along a north-south trending ridge produced by movement of the Louann Salt. Because salt movement was variable in timing and intensity causing Smackover sabkhas to be discontinuous and probably not everywhere the same age. The carbonates that overlie the Smackover sabkhas resemble typical Smackover carbonates and include reservoir strata. Massive Buckner Anhydrite strata are predominantly subaqueous saltern deposits, though peritidal evaporite deposits occur on the margins of the MISB. Saltern deposits formed in a gypsum-precipitating lagoon in the eastern MISB. This region was a silled basin, sheltered from less saline water in the main part of the MISB by a salt-cored anticline capped by carbonate grainstone shoals in eastern Mississippi. Saltern deposits are dominated by selenite and gypsarenite. Saltern deposits are locally interbedded with subtidal hypersaline to normal-marine carbonate deposits which may record sea-level fluctuations or changes in water circulation. A saltern, or evaporite lagoon, formed in the eastern MISB at the beginning of Buckner time as a result of restriction of water influx into the eastern MISB and resultant rapid increase in salinity to gypsum saturation. The salinity increase was a chemical event; hence the base of the massive anhydrite is a time plane, and its extent approximates that of the Buckner evaporite lagoon. Subaqueous evaporites of the basal Buckner occupy a smaller area than do peritidal carbonates of the uppermost Smackover, suggesting that evaporative drawdown was a contributing factor in the deposition of the massive anhydrite. Smackover sabkhas are not physically connected to the subaqueous evaporite deposits of the Buckner nor did they form in the same way. Saltern deposits thicken away from paleotopographic highs and have a blocky density-log pattern. Smackover sabkhas typically have spiky density-log patterns and thin away from paleotopographic highs.

Regional Variation in Microscopic and Megascopic Reservoir Heterogeneity in the Smackover Formation, Southwest Alabama

ABSTRACT Quantitative (rank) measures of microscopic and megascopic reservoir heterogeneity are used to characterize the distribution of reservoir heterogeneity in Smackover hydrocarbon fields and wildcat wells in southwest Alabama. Microscopic reservoir heterogeneity (µH) is {[(0.25) + (meanlnK) + (1.5lnK)]/3}. Megascopic Heterogeneity (MH) is [(# of reservoir intervals) + (# of high-K reservoir intervals) + ( of # of reservoir intervals)] where reservoir rock is defined as exhibiting permeability values >= 0.1 md and high-permeability reservoir rock exhibits permeability values >= 1.0 md. Both MH and µH are determined from core data. The Dykstra-Parsons coefficient (DP) is a measure of microscopic heterogeneity that is partially independent of µH(r2 = 0.428). All three of these parameters are primarily measures of vertical heterogeneity, although averaging of wells within a field incorporates lateral heterogeneity in µH and DP. µH and MH are distributed in contrasting but related patterns. µH generally decreases from northwest to southeast, with the highest values found in the vicinity of the Choctaw Ridge complex north of the Mississippi Interior Salt Basin (MISB). Moderately high values typify the Manila Embayment and the Conecuh Ridge complex to the south, whereas lower values are found in the MISB, on the north flank of the Wiggins Arch, and in the Conecuh Embayment. µH values are high in the Moldic Pore Facies and low in the Intercrystalline Pore Facies. The distribution of MH is roughly opposite to that of µH. MH values are high on the north flank of the Wiggins Arch, on the Conecuh Ridge complex and in the Conecuh Embayment: MH values are low near the Choctaw Ridge complex. The Conecuh Ridge is unique because it is characterized by high values of both µH and MH. Also, the low-relief north-south trending salt-cored anticline in western Washington County is characterized by relatively high values of MH. Reservoirs belonging to the Moldic Pore Facies tend to be homogeneous with respect to MH, whereas reservoirs assigned to the Intercrystalline Pore Facies are characterized by relatively high values of MH. MH and µH vary congruently with pore-system characteristics (controlled by depositional patterns, dissolution, and dolomitization) and regional structural and paleogeographic trends. This suggests that reservoir heterogeneity characteristics are controlled by structural and paleogeographic setting, by depositional fabric, and by diagenesis. However, because contours of µH and MH are approximately normal to structure contours but parallel to Smackover thickness contours, it appears that depositional setting (or paleogeography) influenced reservoir heterogeneity more than did structural evolution. The distribution of DP values is not related to pore-facies distribution. Thus we conclude that DP is less useful for regional heterogeneity studies than is MH or µH.

Upper Jurassic Smackover Oil Plays in Alabama, Mississippi and the Florida Panhandle

ABSTRACT Five Smackover (Upper Jurassic, Oxfordian) oil plays can be delineated in the eastern Gulf Coastal Plain. These include the basement ridge play, the regional peripheral fault trend play, the Mississippi Interior Salt basin play, the Mobile graben fault system play, and the Wiggins arch complex play. Plays are recognized by basinal position, relationships to regional structural features, and characteristic petroleum traps. Within two plays, subplays can be distinguished based on oil gravities and reservoir characteristics. Reservoirs are distinguished primarily by depositional setting and diagenetic overprint. The basement ridge play is updip of the regional peripheral fault trend where the Jurassic Louann Salt is thin or absent; structures in this trend formed on pre-Jurassic basement rocks. The basement ridge play is characterized by structural and combination traps. Reservoirs in the Choctaw ridge complex subplay are peritidal, partially to completely dolomitized, oolitic, peloidal, and oncoidal grainstone. Reservoirs of the Conecuh and Pensacola-Decatur ridge complexes subplay are subtidal to supratidal oolitic, oncoidal, intraclastic, and peloidal dolograinstone and dolopackstone, fenestral dolostone, quartz sandstone, and algal doloboundstone. The regional peripheral fault trend play is basinward of the updip limit of the Louann Salt and is typified by salt related structural features. These structural features occur in association with the Pickens, Gilbertown, West Bend, Pollard, and Foshee fault systems and are generally parallel to the basin margin. The regional peripheral fault trend play is exemplified by salt-related structural and combination traps. Reservoirs of the Pickens, Gilbertown, and West Bend fault systems subplay are peritidal, nondolomitic to completely dolomitized, oolitic, oncoidal, and peloidal grainstone. Reservoirs of the Pollard and Foshee fault systems subplay are subtidal to supratidal, partially to completely dolomitized, peloidal grainstone to wackestone, and dolomitized algal boundstone. The Mississippi interior salt basin play is downdip from the Pickens and Gilbertown fault systems and is characterized by structural and combination traps associated with salt tectonism in this basin. Reservoirs are peritidal, nondolomitic to completely dolomitized, oolitic and peloidal grainstone and packstone. The Mobile graben fault system play is located along the eastern limit of the Mississippi interior salt basin and is typified by salt-induced structural and combination traps and Smackover peritidal peloidal and oolitic dolograinstone to dolowackestone and dolostone reservoirs. The Wiggins arch complex play is in a downdip basinal position and is characterized by structural and combination-petroleum traps associated with stratigraphic thinning and salt flow. The traps occur along the flanks of pre-Mesozoic paleohighs associated with this complex. Reservoirs are subtidal to supratidal peloidal, oolitic and oncoidal dolograinstone and dolopackstone, thrombolitic dolostone, and crystalline dolostone.

Sponge-microbial mound facies in Mississippian Tuscumbia Limestone, Walker County, Alabama

A new core from the Black Warrior Basin of Alabama contains a newly discovered mound lithofacies in the Tuscumbia Limestone (Meramecian). The Schlumberger-Alabama Power 1 Plant Gorgas well contains 37.2 m (122 ft) of carbonate rock assigned to the Tuscumbia. This formation overlies the Fort Payne Chert (Osagean), which was penetrated but not cored in this well. The Tuscumbia underlies calcareous shale and limestone of the Chesterian Pride Mountain Formation. Three lithologic units have been defined in the cored part of the Tuscumbia. The basal 2.8 m (9.25 ft) of the core consists of sponge-microbial boundstone (unit 1). This is overlain by 20.6 m (67.6 ft) of mixed carbonate strata dominated by mixed-particle grainstone, which increases in abundance upward (unit 2). Some of the grainstone is brecciated, suggesting exposure and paleokarst development following mound formation. Grainstone is interbedded with thin units of argillaceous cherty peloidal carbonate, sponge-microbial boundstone, and mixed-particle rudstone. Glauconite is common in the basal part of unit 2. Unit 2 is abruptly overlain by 13.8 m (45.2 ft) of bryozoan crinoid grainstone (unit 3) containing breccia beds, low-angle cross-strata, and immature carbonate paleosols. This unit is sharply overlain by the Lewis limestone of the Pride Mountain Formation, which here consists of 0.5 m (1.7 ft) of interbedded fossiliferous shale and mixed-particle packstone. The Lewis limestone is overlain disconformably by fenestrate-bryozoan-rich shale. The basal part of the core records growth of a sponge-microbial mound in relatively shallow water below normal wave base. The mound is not Waulsortian: stromatactis is absent, and matrix material is grainy. The upper contact is sharp, and borings are locally abundant. Abundant authigenic glauconite indicates reducing pore waters. The mound was buried by foreshoal grainstone, much of which is brecciated. Upper Tuscumbia bryozoan-crinoid grainstone formed in a mobile shoal that quickly aggraded to sea level. Although the upper Tuscumbia here is typical of the formation, the shoal buried a mound facies not previously reported from the Tuscumbia. Early diagenesis was dominated by marine cementation, syndepositional alteration, and fracturing. Burial diagenesis was dominated by calcite cementation, dissolution of siliceous spicules, stylolitization, chert formation, and later, emplacement of hydrocarbons and their subsequent transformation to pyrobitumen. Today, original interparticle voids are filled with a mixture of calcite cement, replacive chert, and solid hydrocarbons. Irregular nodules of chert replaced parts of the mound and the overlying heterogeneous unit. Dolomite partially replaced heterolithic strata of unit 2. Patches of once porous rock in units 1 and 2 contain abundant solid hydrocarbons, but porosity (0.7%–5.6%) and permeability (1–78 d) are low. In-place heating led to gas generation and to concomitant in-place solidification of liquid hydrocarbons.