Jurassic Smackover Formation Research Articles

Approaches to defining reservoir physical properties from 3-D seismic attributes with limited well control: An example from the Jurassic Smackover Formation, Alabama

Much industry interest is centered on how to integrate well data and attributes derived from 3-D seismic data sets in the hope of defining reservoir properties in interwell areas. Unfortunately, the statistical underpinnings of the methods become less robust in areas where only a few wells are available, as might be the case in a new or small field. Especially in areas of limited well availability, we suggest that the physical basis of the attributes selected during the correlation procedure be validated by generating synthetic seismic sections from geologic models, then deriving attributes from the sections. We demonstrate this approach with a case study from Appleton field of southwestern Alabama. In this small field, dolomites of the Jurassic Smackover Formation produce from an anticlinal feature about 3800 m deep. We used available geologic information to generate synthetic seismic sections that showed the expected seismic response of the target formation; then we picked the relevant horizons in a 3-D seismic data volume that spanned the study area. Using multiple regression, we derived an empirical relationship between three seismic attributes of this 3-D volume and a log‐derived porosity indicator. Our choice of attributes was validated by deriving complex trace attributes from our seismic modeling results and confirming that the relationships between well properties and real‐data attributes were physically valid. Additionally, the porosity distribution predicted by the 3-D seismic data was reasonable within the context of the depositional model used for the area. Results from a new well drilled after our study validated our porosity prediction, although our structural prediction for the top of the porosity zone was erroneous. These results remind us that seismic interpretations should be viewed as works in progress which need to be updated when new data become available.

Porosity Loss, Fluid Flow, and Mass Transfer in Limestone Reservoirs: Application to the Upper Jurassic Smackover Formation, Mississippi1

Ooid grainstones of the Upper Jurassic Smack over Formation are buried to a depth of over 6 km and exposed to temperatures in excess of 200°C at Black Creek field, Mississippi. Combined effects of mechanical compaction, intergranular pressure solution, and cementation have reduced intergranular porosity of these ooid grainstones to 0%, indicating that porosity reduction has gone to completion. Modal analysis of 24 samples lacking preburial cements indicates that from the original 40% porosity, 13 porosity units (range: 4 to 21) were lost by mechanical compaction, 15 porosity units (range: 8 to 23) were reduced by intergranular pressure solution, and 12 porosity units (range: <1 to 26) were destroyed by cementation. Intergranular pressure solution caused an average of 28% (range: 15 to 51%) vertical shortening in Smackover ooid grainstones. Under ideal conditions, the 28% vertical shortening will generate enough calcium carbonate to precipitate 10% calcite cement. This is close to the measured volume of cements in Smackover grainstones (12%), suggesting that intergranular pressure solution provided most of the calcite cement present. No external sources of calcium carbonate are required. Fine-grained samples that experienced high degrees of intergranular pressure solution and contain only small amounts of cement occur at the top of the reservoir, whereas coarse-grained samples with abundant cement and low degrees of pressure solution occur in the middle and basal parts of the reservoir, suggesting that the fine-grained intervals acted as sources and the coarse-grained intervals as sinks for calcium carbonate. Mass transfer of pressure solution-generated calcium carbonate from the top of the unit to precipitation sites in the middle and basal parts of the reservoir could have occurred by a non-Rayleigh-type convection cell. Due to calcite's reverse solubility with respect to temperature, the cooling, upward-moving limb of the convection cell would become progressively more undersaturated, and hence able to transport more dissolved calcium carbonate released by intergranular pressure solution in the upper portion of the reservoir. Pore fluids descending in the downward-moving limb of the cell would become progressively more supersaturated, and calcium carbonate would tend to precipitate as cement in the middle and basal parts of the reservoir as fluids become progressively hotter.

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

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)

Abstract: New (?) Bioherm-Building Tubular Organism in Jurassic Smackover Formation, Alabama&nbsp;

Abstract: New (?) Bioherm-Building Tubular Organism in Jurassic Smackover Formation, Alabama&nbsp;

Abstract: Structure and Evolution of North Choctaw Ridge Field, Alabama, a SaltRelated Footwall Uplift Along the Peripheral Fault System, Gulf Coast Basin

ABSTRACT North Choctaw Ridge (NCR) Field is in a structural trap that produces from the Jurassic Smackover Formation in the Gilbertown graben system, near the updip limit of the Louann Salt. The field is in a footwall uplift below the southernmost of the three faults that form the northern boundary of the graben system. The top seal is anhydrite in the overlying Buckner Member of the Haynesville Formation, and the boundary fault provides a lateral seal. The geometry and evolution of the structure has been determined from a three-dimensional interpretation of the graben system and from a balanced and sequentially restorable cross section. The cross section is both area and length balanced with a lower detachment in the Louann Salt. Significant structural growth began in Early Cretaceous time when three major south-dipping, down-to-the-Gulf faults formed, creating an imbricate system of half grabens (the Melvin fault system). Regional subsidence in the hangingwall of the Melvin fault system indicates contemporaneous salt deflation, with the NCR Field subsiding the least. The north-dipping boundary fault of the Gilbertown graben system (East Gilbertown fault) developed in the Late Cretaceous. Late Cretaceous and Tertiary extension produced a full graben between the East Gilbertown and Melvin C faults.

Abstract: Geologic and Computer Modeling of Upper Jurassic Smackover Reef and Carbonate Shoal Lithofacies, Eastern Gulf Coastal Plain

ABSTRACT Reefs and carbonate shoals have long been known from the Upper Jurassic Smackover Formation in the Gulf Coastal Plain; however, these carbonate lithofacies have unique acoustic properties that make them difficult to define using 3-D seismic reflection technology. In the eastern Gulf Coastal Plain, microbial reef and shoal buildups occur on pre-Jurassic paleotopographic basement features on a carbonate ramp margin. Development of these buildups is a result of the interplay among paleotopography, sea-level changes, and carbonate productivity. Geological and computer modeling indicates that Smackover reef and shoal development is restricted to the flanks of high (emergent) relief structures, while reef and shoal development occurred on the crest and flanks of low-relief structures (submergent). For these submergent features, modeling indicates that carbonate productivity during reef growth was significantly greater than during shoal development. In addition to the initial paleorelief, the rate of sea-level rise, the level of carbonate productivity, and duration of reef growth appear to be critical factors in determining thickness and distribution of the reef lithofacies. Subsidence and compaction are minor factors. Shoal development is greatly influenced by reef distribution, sea-level changes, level of carbonate productivity, and duration of shoal deposition. Subsidence, compaction and sediment redistribution are also factors. Modeling of parameters affecting reef and shoal development associated with pre-Jurassic paleohighs in combination with 3-D seismic reflection studies increases the chances of drilling a successful exploration well.

Abstract: Diagenesis of Passive Margin Reservoirs - Upper Jurassic Smackover Formation of the Eastern Gulf Coastal Plain, USA

Abstract: Diagenesis of Passive Margin Reservoirs - Upper Jurassic Smackover Formation of the Eastern Gulf Coastal Plain, USA

The Role of Burial Diagenesis in Hydrocarbon Destruction and H2S Accumulation, Upper Jurassic Smackover Formation, Black Creek Field, Mississippi

Organic-inorganic interactions during burial of the Smackover Formation at Black Creek Field, Mississippi, have resulted in nearly complete destruction of hydrocarbons. The formation has been buried to a depth of 6 km, has experienced temperatures of over 200 degrees C, and presently contains 78% H 2 S, 20% CO 2 , and 2% CH 4 . Three distinct stages of burial diagenesis correspond to three phases of organic matter maturation. Pre-oil window diagenesis was dominated by precipitation of prebitumen calcite cement. Diagenesis in the oil window was characterized by precipitation of saddle dolomite and anhydrite in water-filled layers and by formation of solid bitumen in the oil column. Diagenesis in the gas window was dominated by thermochemical sulfate reduction (TSR) resulting in hydrocarbon destruction, anhydrite dissolution, large amounts of H 2 S, CO 2 , and S generation, and postbitumen calcite cementation. During TSR, anhydrite reacted with H 2 S to produce S , which in turn reacted with CH 4 to generate more H 2 S in a self-reinforcing cycle. The lack of metal cations to stabilize H 2 S as metal sulfides, availability of sufficient sulfate to generate H 2 S, and a closed system to prevent H 2 S from escaping resulted in the continuation of the TSR cycle until nearly all hydrocarbons were consumed. In Mississippi, concentration of H 2 S is nearly zero in Smackover hydrocarbon reservoirs that have experienced temperatures of 120 degrees C for more than 50 m.y., suggesting that TSR is not a kinetic (time-dependent) process. High H 2 S concentrations initiate at temperatures above 140 degrees C and increase with temperature, indicating that TSR is a thermodynamic phenomenon. Reported high H 2 S concentrations at low temperatures (80-120 degrees C) from other locations may be explained by the following processes; (1) migration of H 2 S into these reservoirs, (2) high geothermal gradients or local thermal perturbations in the past, (3) a biochemical origin for the H 2 S, or (4) exposure of these reservoirs to temperatures greater than 150 degrees C and a rapid uplift. In Black Creek Field, burial cementation and pressure solution resulted in total destruction of porosity and permeability in limestone reservoirs, but not in dolomite reservoirs, which still possess up to 20% porosity and 100 md permeability. Secondary porosity was not created as a result of hydrocarbon migration. Abundant CO 2 derived during hydrocarbon destruction resulted in calcite cementation rather than carbonate dissolution. Late, secondary porosity development in carbonates may be related to acids generated by metal sulfide precipitation.

Pore Geometry: Control on Reservoir Properties, Walker Creek Field, Columbia and Lafayette Counties, Arkansas

Walker Creek field in southern Arkansas produces hydrocarbons from oolitic packstones and grainstones of the Jurassic Smackover Formation. The relationships between pore geometry and reservoir quality in these rocks were evaluated using petrographic methods and mercury injection capillary pressure analyses. Results indicate that reservoir quality is controlled by pore geometry, which, in turn, is determined by depositional and diagenetic processes. Reservoir rocks at Walker Creek were deposited as prograding grainstone shoals in a shallow-water, high-energy environment. Diagenetic processes, including early marine cementation, compaction, and deeper burial pressure solution and calcite cementation, modified the original pore system. Primary interparticle porosity is the dominant effective pore type and is most important in terms of reservoir performance. Secondary microporosity is also abundant, comprising a significant percentage of total porosity (locally up to 100%), but is generally ineffective. The rocks were subdivided into lithofacies based on their depositional and diagenetic origin. Within each lithofacies, reservoir, marginal reservoir, and nonreservoir rock types are identified based on their pore geometry and characteristic capillary pressure curve. The reservoir rock types are less cemented oolitic and oolitic-skeletal grainstones with steeply sloping capillary pressure curves and flat plateaus indicating relatively homogeneous pore sizes that are well interconnected by large pore throats. The marginal to nonreservoir rock types include mudstones, wackestones, muddy packstones, and cemented grainstones with generally small interparticle and moldic pores. Gently sloping capillary pressure curves with poorly defined or no plateaus indicate variable pore and pore-throat sizes. A close correlation is found among parts of the capillary pressure curve shape, such as slopes, plateaus, and displacement pressure, and aspects of pore geometry such as pore-throat size, pore-throat size distribution, and pore interconnectivity. In addition, capillary pressure analyses provide guidance in evaluating overall reservoir quality by rock type, as well as answer specific questions regarding net pay criteria as a function of height above free-water level.

Salt-Induced Subsidence: Accommodation of Stacking Patterns and Implications for Reservoir Development in Oolitic Ramp Depositional Sequences: Jurassic Smackover Formation, State Line Graben, Louisiana and Arkansas: ABSTRACT

Salt-Induced Subsidence: Accommodation of Stacking Patterns and Implications for Reservoir Development in Oolitic Ramp Depositional Sequences: Jurassic Smackover Formation, State Line Graben, Louisiana and Arkansas: ABSTRACT

Distribution of Illite and Mixed-Layered Illite in the Smackover Formation of the Manila Embayment of Southwest Alabama (Wilcox, Clarke and Monroe Counties): ABSTRACT

ABSTRACT The Jurassic Smackover Formation within the Manila Embayment of southwest Alabama was deposited on a carbonate ramp modified by paleotopographic highs. The Smackover Formation consists of limestone, dolostone and silici-clastic units. Although low energy lithofacies were dominant within the embayment, moderate to high energy lithofacies are associated with shallow water across paleotopographic highs. These formed locally permeable lithofacies which became sites of preferential dolomitization. Also, during burial diagenesis, authigenic clays formed from ions within pore fluids of the rock. Authigenic clays in large quantities may have had an effect on the formation of dolomite within the embayment. Authigenic clay occurrence within the Smackover Formation of the Manila Embayment has largely been ignored in the past. Scanning electron imagery (SEI) and energy dispersive spectral (EDS) analytical techniques identified small quantities of illite and/or mixed-layered illite clay within the carbonates and clastic units of the Smackover Formation. The mixed-layered illite may be illite-smectite, -vermiculite, or -mica. The clays form pore-lining and filling morphologies with crenulated platy habits and occasional fibrous or ribbon-like projections which sometimes coalesce to form plates. X-ray diffractometry (XRD) could not be used for identification because of small quantities of clay minerals present. The clays seem to have an irregular distribution throughout the embayment, although they were found to be most common within the dolostone lithologies, probably due to these rocks high porosities. However, authigenic clay occurrence was found to be sparse and their growth was a late, deep burial diagenetic event, occurring after dolomitization and therefore having no effect on the formation of dolomite.

Regional porosity evolution in the Smackover Formation of Alabama

The Upper Jurassic (Oxfordian) Smackover Formation is the most prolific oil producer in Alabama. Smackover strata in Alabama were deposited on carbonate ramps under conditions of stable relative sea level. Reservoir rocks consist primarily of nonskeletal (primarily oolitic and pelletal) dolograinstone, with lesser amounts of nonskeletal dolopackstone, microbial doloboundstone, and nondolomitized nonskeletal grainstone and packstone. Porous and permeable strata are classified on the basis of the relative proportions of genetic pore types as belonging to one of three pore facies: moklic, intercrystalline, and intermediate (mixtures of moklic and intercystalline pores at various scales). Equivalent vitrinite reflectance (Ro) data, commercial core-plug porosity data, conventional core description, and point counting of petrographic thin sections were used to evaluate the relationships among thermal exposure, pore types, and porosity evolution in Smackover reservoirs in Alabama. Porosity and thermal exposure are inversely related in Smackover reservoirs of Alabama, as they are in most sedimentary rocks. However, the overall correlation between porosity and Ro is not strong, indicating that other factors significantly affected porosity evolution. Factors of rock type (limestone vs. dolomite), depositional environment, and depositional fabric did not strongly influence regional porosity evolution. By contrast, mode of dolomitization as expressed by pore-facies classification had a direct effect on regional porosity evolution. This results from regional geographic trends in mode of dolomitization. Subdivision of the data set by pore facies increases correlation coefficients of porosity-Ro as a function of geographic variation in pore-facies assignment. Intermediate pore systems are more porous than moldic pore systems at a given value of Ro. Reservoirs with intercrystalline pore systems were too few to analyze quantitatively, but these reservoirs plot approximately within the field defined by intermediate reservoirs on a porosity-Ro plot, and resemble intermediate reservoirs petrophysically. Smackover reservoir rocks on the north flank of the eastern (Alabama) end of the Wiggins arch, a major paleohigh that was partially exposed throughout deposition of the Smackover, are unusually porous for the Smackover of Alabama. Smackover reservoirs in this area are unique in other ways as well: they are more completely dolomitized, contain more hydrocarbons than would a similar number of Smackover fields elsewhere in Alabama, are dominated by intercrystalline pore systems (uncommon elsewhere in the Alabama Smackover), and exhibit values of mean porosity, mean permeability, standard deviation of permeability, Dykstra-Parsons coefficient, and microscopic reservoir heterogeneity (variable defined by Kopaska-Merkel and Mann, 1992) that deviate from regional trends.

The Tallahala Creek Complex, Smith County, Mississippi: The Crest Is Not Always the Best: ABSTRACT

ABSTRACT The Tallahala Creek complex, comprising both Tallahala Creek and East Tallahala Creek fields, is a salt-induced anticline transected by two down-to-the-north fault systems. Since 1967, upper portion of Jurassic Smackover Formation has yielded almost 15 million bbl of oil and 20 billion ft3 of gas, or 75 percent and 64 percent of total oil and gas, respectively, produced from fields. Contemporaneous sediment accumulation and structural growth have created various lithofacies in upper Smackover, thereby significantly affecting reservoir heterogeneity. These lithofacies can be delineated by their structural position on anticline. On most downdip and downthrown portions of structure, upper Smackover consists of a series of gray, fine- to medium-grained sandstones separated by limestones. These sandstones generally exhibit both high porosity and permeability and have thus contributed more than 95 percent of total Smackover production. Updip upper Smackover becomes increasingly calcareous, finally grading into a sandy, in some places dolomitic, limestone on crest and southern upthrown flank of anticline. This limestone lithofacies has been noncommercial as a reservoir rock, as evidenced by less than 7,000 bbl of oil cumulatively produced from Smackover in two of structurally highest wells, Shell 2 E. M. Lane and Shell 1 F. James. Structural and stratigraphic relationships discovered through field development of Tallahala Creek complex have significantly altered conventional idea that the crest is always best. End_of_Record - Last_Page 772-------

Pore-throat Morphology in the Upper Jurassic Smackover Formation of Alabama

ABSTRACT A new parameter called is calculated from capillary-pressure data. = (m - 1)/2, where m is the slope of a line segment on a log-log plot of the difference between maximum cumulative intrusion volume and cumulative intrusion volume versus capillary pressure. has been previously interpreted as a measure of pore-throat shape: has the value I for sheetlike pore throats, 2 for cylindrical pore throats, and 3 for equant pore throats. An alternative, and more likely, interpretation is that measures pore-throat surface roughness. This inference is based on the observations that (1) is calculated by a method analogous to that of fractal dimension, and fractal dimension is commonly interpreted as a roughness measure, (2) most values in Smackover reservo r rocks from Alabama are low (

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.

Paleoceanographic and Paleoclimatic Controls on Ooid Mineralogy of the Smackover Formation, Mississippi Salt Basin: Implications for Late Jurassic Seawater Composition

ABSTRACT The Late Jurassic Smackover Formation in the Mississippi salt basin consists of two 150 m thick shoaling-upward cycles, each capped by ooid grainstones. During deposition of the lower cycle, originally calcite ooids (preserved radial fabric, 18O = -3.8 PDB, 13C = 4.5 PDB, Sr2+ = 315 ppm) formed on the seaward side of the basin and former aragonite ooids (calcitized textures, 18O = -3.0 PDB, 13C = 5.5 PDB, Sr2+ = 1790 ppm) were precipitated on the landward side. In the upper cycle, originally calcite ooids (preserved radial fabric) were precipitated on both the seaward (18O = -2.5 PDB, 13C = 4.2 PDB, Sr2+ = 300 ppm) and the landward (18O = -2.5 PDB, 13C = 3.2 PDB, Sr2+ = 250 ppm) sides of the basin. Because kinetic variables (Mg2+/Ca2+, rate of CO32- supply, PO43-, SO42-) are incapable of totally preventing aragonite formation, we suggest that Smackover calcite ooids were precipitated from seawater with low carbonate saturation state (possibly undersaturated relative to aragonite). The shift from seaward calcite to landward aragonite ooids in the lower cycle was controlled by a shoreward increase in seawater salinity. The net effect of the salinity gradient was a landward increase in the carbonate saturation state in response to decreasing dissolved CO2 and increasing CO32-, Ca2+, and temperature. In seawater supersaturated with respect to both arago ite and calcite, kinetic variables favored dominance of aragonite over calcite. The landward increase in seawater salinity reflects extensive evaporation in an arid climate, resulting in antiestuarine circulation. The monomineralogic (calcite) nature of ooids of the upper cycle suggests that the salinity gradient across the basin was not sufficient to alter the seawater saturation state. This is attributed to a less arid climate and/or a less restricted circulation.

Characterization and Geologic Framework of the Jurassic (Oxfordian) Smackover Formation in the Alabama State Coastal Waters Area

Characterization and Geologic Framework of the Jurassic (Oxfordian) Smackover Formation in the Alabama State Coastal Waters Area

Macroscopic Reservoir Heterogeneity in Upper Jurassic Smackover Formation Oil Plays, Southwest Alabama

Macroscopic Reservoir Heterogeneity in Upper Jurassic Smackover Formation Oil Plays, Southwest Alabama

Sequence Stratigraphy of Carbonate-Ramp Sediments of the Upper Jurassic Smackover Formation, USA Gulf Coast Region

Sequence Stratigraphy of Carbonate-Ramp Sediments of the Upper Jurassic Smackover Formation, USA Gulf Coast Region

New constraints on carbonate diagenesis from integrated Sr and S isotopic and rare earth element data, Jurassic Smackover Formation, U.S. Gulf Coast: a reply

Isotopic (Sr, S, O, C) and trace element, including rare earth element (REE), compositions of calcite cements, metal sulfides and sulfate minerals from oolitic carbonate grainstones of the Smackover Formation (Jurassic, southwest Arkansas shelf) constrain the mechanism of sulfate reduction and establish temporal relations between sulfur and carbonate diagenesis. Strontium isotopic values of calcite cements range from near Jurassic-age sea water values (0.7068) up to values of 0.7096. This evidence, coupled with variation in O and C isotopic compositions and in cement zoning under cathodoluminescence, suggests that calcite cement precipitated over the course of burial diagenesis. Strontium isotopic compositions of pyrite, marcasite and native S range up to maximum values observed for calcite cements, but galena and sphalerite are less radiogenic. The Sr contents of sulfides and native S are <30ppm, but the Rb content is sufficiently low that in-situ growth of87Sr would not dramatically alter the initial Sr isotope ratio. Diagenetic sulfate minerals also exhibit a range of Sr isotopic compositions: anhydrites range from 0.7071 to 0.7081, while celestites are more radiogenic (0.7096). The REE patterns of early and late calcite cements and framework grains differ. Using Sm/Yb ratios as an indicator of heavy vs light REE enrichment, early calcites have Sm/Yb ratios <1 whereas late calcite cements have ratios of 1.8–3.2. Importantly, both cement signatures differ from framework grain ratios (1.3–1.7) indicating lack of rock-buffering in fluids from which the cements precipitated. Furthermore, the sympathetic increase in Sm/Yb and Sr isotopic ratios from early to late calcites is consistent with input of light REE from siliciclastic sources. Sulfur isotopic compositions of metal sulfide minerals range from −32 to +8% CDT. Native S and anhydrite values (+18%) are near Jurassic-age sulfate values while celestites are heavier (+28%). Although thermochemical sulfate reduction has been proposed to explain H2S in deeply buried carbonate units associated with evaporite S, lack of S isotopic homogenization between sulfate and sulfide minerals, lack of S isotopic equilibration of oil with reservoir SO4, and the limited distribution of H2S-rich brines in southwest Arkansas demand a more complex origin.