Stephen C. Ruppel

Spectrum of pore types and networks in mudrocks and a descriptive classification for matrix-related mudrock pores

Matrix-related pore networks in mudrocks are composed of nanometer- to micrometer-size pores. In shale-gas systems, these pores, along with natural fractures, form the flow-path (permeability) network that allows flow of gas from the mudrock to induced fractures during production. A pore classification consisting of three major matrix-related pore types is presented that can be used to quantify matrix-related pores and relate them to pore networks. Two pore types are associated with the mineral matrix; the third pore type is associated with organic matter (OM). Fracture pores are not controlled by individual matrix particles and are not part of this classification. Pores associated with mineral particles can be subdivided into interparticle (interP) pores that are found between particles and crystals and intraparticle (intraP) pores that are located within particles. Organic-matter pores are intraP pores located within OM. Interparticle mineral pores have a higher probability of being part of an effective pore network than intraP mineral pores because they are more likely to be interconnected. Although they are intraP, OM pores are also likely to be part of an interconnected network because of the interconnectivity of OM particles. In unlithifed near-surface muds, pores consist of interP and intraP pores, and as the muds are buried, they compact and lithify. During the compaction process, a large number of interP and intraP pores are destroyed, especially in ductile grain-rich muds. Compaction can decrease the pore volume up to 88% by several kilometers of burial. At the onset of hydrocarbon thermal maturation, OM pores are created in kerogen. At depth, dissolution of chemically unstable particles can create additional moldic intraP pores.

Mississippian Barnett Shale: Lithofacies and depositional setting of a deep-water shale-gas succession in the Fort Worth Basin, Texas

The Mississippian Barnett Formation of the Fort Worth Basin is a classic shale-gas system in which the rock is the source, reservoir, and seal. Barnett strata were deposited in a deeper water foreland basin that had poor circulation with the open ocean. For most of the basins history, bottom waters were euxinic, preserving organic matter and, thus, creating a rich source rock, along with abundant framboidal pyrite. The Barnett interval comprises a variety of facies but is dominated by fine-grained (clay- to silt-size) particles. Three general lithofacies are recognized on the basis of mineralogy, fabric, biota, and texture: (1) laminated siliceous mudstone; (2) laminated argillaceous lime mudstone (marl); and (3) skeletal, argillaceous lime packstone. Each facies contains abundant pyrite and phosphate (apatite), which are especially common at hardgrounds. Carbonate concretions, a product of early diagenesis, are also common. The entire Barnett biota is composed of debris transported to the basin from the shelf or upper oxygenated slope by hemipelagic mud plumes, dilute turbidites, and debris flows. Biogenic sediment was also sourced from the shallower, better oxygenated water column. Barnett deposition is estimated to have occurred over a 25-m.y. period, and despite the variations in sublithofacies, sedimentation style remained remarkably similar throughout this span of time.

A model for carbonate to terrigenous clastic sequences

The development of carbonate sequences that grade toward a source region into terrigenous clastic sediment is poorly understood. In both carbonate and terrigenous clastic regimes, environments of rapid sedimentation have comparable rates of deposition (102 to 102.5 cm/1,000 yr); slowest continuous rates are also comparable (100.5 to 101 cm/1,000 yr). Because of the inhibiting effect of terrigenous deposition on carbonate (skeletal) production, the slowest rates in a transect tend to occur where mixed lithologies are deposited—midway between coarse clastic and pure carbonate sediments. This leads to a bimodal distribution of rapid depositional rates and invariably to the development of a basin in the intervening area. To develop a model, we combine concepts of depositional rate with knowledge of the Middle Ordovician carbonate to terrigenous clastic sequence of the southern Appalachians. Deposition began on a shallow-water ramp sloping gently eastward, but everywhere within the photic zone. An episode of tectonic subsidence differentiated this ramp into a shallow shelf on the northwest and a deep, starved basin on the southeast, separated by a linear shelf margin with organic build-ups. Subsequent development of the sequence consisted of the filling of the deep basin (first with pelagites, then with turbidites), during which the carbonate shelf was isolated from terrigenous deposition. Once the basin filled, terrigenous deposition began to affect the shelf. Inhibition of carbonate deposition near the shelf edge led to formation of successively smaller basins within the old shelf area. After the initial pulse of tectonic subsidence, deposition of the sequence can be explained by sediment-loading subsidence. Thus, the Ordovician sequence, coupled with the concept of bimodal distribution of sedimentation rates in carbonate to terrigenous clastic facies patterns, allows development of a model for basins adjacent to active tectonic lands. Five model stages are derived by application of calculated deposition rates and sediment loading along a transect away from the terrigenous source. These stages are (1) an initial carbonate ramp stage; followed by (2) a carbonate shelf-starved deep-basin stage; (3) a carbonate shelf-turbidite basin-terrigenous shelf stage; (4) a carbonate shelf-narrowed and shallowed basin-broad terrigenous shelf stage; and finally (5) a stage in which the initial basin is filled, a subsequent starved basin forms on the old carbonate shelf, and a new carbonate shelf margin forms a few to tens of kilometres farther from the terrigenous source. The model should be useful in predicting depositional facies in analogous basins.

High-resolution 87Sr/86Sr chemostratigraphy of the Silurian: Implications for event correlation and strontium flux

Analyses of 87Sr/86Sr in Silurian conodonts recovered from localities in North America and Europe representing 13 of the 14 defined Silurian conodont zones provide a high-resolution record of seawater chemistry for the Silurian Period. These data, which are characterized by little or no scatter, depict several high-frequency cycles superimposed on a gradual longer term rise in 87Sr/86Sr for the Silurian. High-frequency cycles have a duration of about one conodont zone, and many correlate with sequence boundaries recognized around the world. These data provide a much higher resolution image of secular changes in 87Sr/86Sr during the Silurian and may require a rethinking of models of strontium isotope flux in marine basins.

Pore and pore network evolution of Upper Cretaceous Boquillas (Eagle Ford–equivalent) mudrocks: Results from gold tube pyrolysis experiments

Low-maturity Boquillas Formation (Eagle Ford Formation–equivalent) organic-lean calcareous mudrock samples collected from outcrop were heated in gold tubes under confining pressure to investigate the evolution of organic matter (OM) pores and mineral pores. The majority of OM in the Boquillas samples was migrated petroleum (bitumen) based on evidence from geochemical analyses, solvent extraction, and scanning electron microscopy (SEM) petrography. The SEM images showed several diagenetic events—including framboidal pyrite precipitation and euhedral calcite, quartz, kaolinite, and chlorite cementation—that were all interpreted to have occurred prior to petroleum expulsion and pore-scale to bed-scale petroleum (bitumen) migration. Two major pore types were present prior to heating: primary mineral pores and modified mineral pores with migrated relic OM. From heating experiments, pores were found to be associated with stages of OM maturation. During the bitumen generation stage, modified mineral pores were dominant, and primary interparticle and intraparticle pores were present. During the oil generation stage, modified mineral pores with isopachous OM rim were observed to be the most abundant pore type. During the gas generation stage, both modified mineral pores and nanometer-sized spongy OM pores were predominant. We interpreted the occurrence of modified mineral pores to be the result of (1) oil and gas filled or partially filled voids that developed during petroleum migration and water expulsion; (2) voids after removing of oil, gas, and water during sample preparation; and (3) trapping of water molecules. The formation of these nanopores was interpreted to be related to gas generation and structural rearrangement of OM.

Controls on Reservoir Development in Devonian Chert: Permian Basin, Texas

Chert reservoirs of the Lower Devonian Thirty-one Formation contain a significant portion of the hydrocarbon resource in the Permian basin. More than 700 million bbl of oil have been produced from these rocks, and an equivalent amount of mobile oil remains. Effective exploitation of this sizable remaining resource, however, demands a comprehensive appreciation of the complex factors that have contributed to reservoir development. Analysis of Thirtyone Formation chert deposits in Three Bar field and elsewhere in the Permian basin indicates that reservoirs display substantial heterogeneity resulting from depositional, diagenetic, and structural processes. Large-scale reservoir geometries and finer scale, intra-reservoir heterogeneity are primarily attributable to original depositional processes. These cherts, which were deposited by relatively deep-water sediment gravity processes along a north-trending depocenter, exhibit relatively continuous stratal geometries in northern, more proximal parts of the depocenter and more discontinuous geometries in the center of the depocenter. Despite facies variations, porosity development in these cherts is principally a result of variations in rates and products of early si ica diagenesis. Because this diagenesis was in part a function of depositional facies architecture, porosity development follows original depositional patterns. In reservoirs such as Three Bar field, where the Thirtyone Formation has been unroofed by Pennsylvanian deformation, meteoric diagenesis has created additional heterogeneity by causing dissolution of chert and carbonate, especially in areas of higher density fracturing and faulting and along truncated reservoir margins. Structural deformation also has exerted direct controls on heterogeneity that are particularly noteworthy in reservoirs under waterflood. High-density fracture zones create preferred flow paths that result in nonuniform sweep through the reservoir. Faulting locally creates compartments by offsetting reservoir flow units. Three Bar field exhibits many of the major styles of heterogeneity that contribute to inefficient recovery in the Thirtyone Formation. As such, the processes and models defined here improve understanding of the causes of heterogeneity in all Thirtyone chert reservoirs in the Permian basin and aid recovery of the sizable hydrocarbon resource remaining in these rocks.

Origin and characterization of Eagle Ford pore networks in the south Texas Upper Cretaceous shelf

ABSTRACT Recent studies have shown that the loss of primary pores and the development of secondary pores in mudrocks are primarily controlled by burial diagenesis of the mineral matrix and thermal maturation of organic matter (OM). However, the lack of quantitative data on nanometer- to micrometer-scale rock properties has limited the ability to define and predict petrophysical properties and fluid flow in these fine-grained rocks. To upscale these rock properties, quantitative data are needed at multiple scales. Representative Eagle Ford Group samples were collected from continuous cores taken from two adjacent oil-producing wells in Karnes County, Texas, to investigate small-scale variations in mineralogy, diagenesis, and pore type. Point-count and pore-tracing methods were used to systematically quantify pore types and determine the size and shape of the identified pores. The two cores from the Eagle Ford are dominated by modified mineral pores, although secondary OM pores in migrated petroleum (bitumen) are also important. The mineral-pore network includes (1) primary mineral pores originally saturated with formation water and (2) modified mineral pores containing migrated petroleum (bitumen and/or residual oil). The OM-pore network includes (1) primary OM pores and (2) secondary OM pores including relatively large, less abundant OM bubble pores and relatively small, more abundant OM spongy pores. The abundance of OM spongy pores correlates positively with total-organic-carbon (TOC) content, and that of mineral pores weakly correlates with the volume of quartz plus feldspar. Studied samples have similar thermal maturities, although samples from one deeper core are slightly more mature than the other. Except for thermal maturation, the strong, micrometer-scale heterogeneity of rock components and properties (texture, fabric, mineralogy, and TOC) impacts the abundance, distribution, and type of pores. This micrometer-scale heterogeneity in porosity and pore networks would, in turn, significantly impact matrix permeability.

High-resolution stratigraphy and facies architecture of the Upper Cretaceous (Cenomanian–Turonian) Eagle Ford Group, Central Texas

Rock-based studies of the Eagle Ford Group of Central Texas demonstrate that mudrock deposition is more complicated than previously supposed. X-ray diffraction, x-ray fluorescence, total organic carbon (TOC), and log data collected from eight cores and two outcrops demonstrate that bottom-current reworking and planktonic productivity are primary depositional controls, acting independently from eustatic forcing. Central Texas Eagle Ford facies include (1) massive argillaceous mudrock, (2) massive foraminiferal calcareous mudrock, (3) laminated calcareous foraminiferal lime mudstone, (4) laminated foraminiferal wackestone, (5) cross-laminated foraminiferal packstone–grainstone, (6) massive bentonitic claystone, and (7) nodular foraminiferal packstone–grainstone. High degrees of lateral facies variability, characterized by pinching and swelling of units, lateral facies changes, truncations, and locally restricted units, are observed even at small lateral scales (50 ft [15 m]). At 10 mi (16 km) and greater lateral spacings, core and geochemical data significantly underestimate intraformational facies variability. Approximately 73% of units can be successfully correlated across a distance of 500 ft (152 m), 35% are traceable across 1 mi (1.6 km), and only 16% of beds are correlative across 10 mi (16 km). Geochemical proxies (enrichment in molybdenum and other trace elements) indicate that maximum anoxia occurred within the Bouldin Member despite being composed of the most calcareous and high-energy facies. Comparison of total gamma ray (GR) logs to computed GR logs is requisite, because GR alone may provide misleading determination of facies, TOC content, depositional environment, and sequence stratigraphic implications.

Play Analysis and Digital Portfolio of Major Oil Reservoirs in the Permian Basin: Application and Transfer of Advanced Geological and Engineering Technologies for Incremental Production Opportunities

The Permian Basin of west Texas and southeast New Mexico has produced >30 Bbbl (4.77 x 10{sup 9} m{sup 3}) of oil through 2000, most of it from 1,339 reservoirs having individual cumulative production >1 MMbbl (1.59 x 10{sup 5} m{sup 3}). These significant-sized reservoirs are the focus of this report. Thirty-two Permian Basin oil plays were defined, and each of the 1,339 significant-sized reservoirs was assigned to a play. The reservoirs were mapped and compiled in a Geographic Information System (GIS) by play. Associated reservoir information within linked data tables includes Railroad Commission of Texas reservoir number and district (Texas only), official field and reservoir name, year reservoir was discovered, depth to top of the reservoir, production in 2000, and cumulative production through 2000. Some tables also list subplays. Play boundaries were drawn for each play; the boundaries include areas where fields in that play occur but are 1 MMbbl (1.59 x 10{sup 5} m{sup 3}) was 301.4 MMbbl (4.79 x 10{sup 7} m{sup 3}) in 2000. Cumulative Permian Basin production through 2000 from these significant-sized reservoirs was 28.9 Bbbl (4.59 x 10{sup 9} m{sup 3}). The top four plays in cumulative production are the Northwest Shelf San Andres Platform Carbonate play (3.97 Bbbl [6.31 x 10{sup 8} m{sup 3}]), the Leonard Restricted Platform Carbonate play (3.30 Bbbl 5.25 x 10{sup 8} m{sup 3}), the Pennsylvanian and Lower Permian Horseshoe Atoll Carbonate play (2.70 Bbbl [4.29 x 10{sup 8} m{sup 3}]), and the San Andres Platform Carbonate play (2.15 Bbbl [3.42 x 10{sup 8} m{sup 3}]).

Petrology and depositional history of a Middle Ordovician carbonate platform: Chickamauga Group, northeastern Tennessee

The Middle Ordovician of northeastern Tennessee comprises two stratigraphically and paleoenvironmentally discrete sedimentary packages. In the northwest, the Chickamauga Group, which can be further subdivided into nine formations, is primarily composed of shallow-water carbonate-platform deposits formed during the transgression of the early Middle Ordovician sea. Water depths normally were no greater than about 50 m, usually less. Greatest depths were probably present in the southeastern parts of the platform, where deeper-water (below wave base) reef complexes developed. Farther southeast, partially equivalent Middle Ordovician deposits, comprising at least five distinct formations, exhibit considerably more lithologic and paleoenvironmental diversity. These deposits include a relatively thin basal sequence of shallow-marine carbonates overlain by deep-water, hemipelagic carbonates and turbiditic shales and siltstones. Maximum depths of water in this region were on the order of 700 m. The earliest recognizable stage in the history of this paleoenvironmentally complex sequence is associated with the development of a shallow-water carbonate platform in the southeastern-most part of the area (Whiterockian time). Subsequent rapid downwarping in this area resulted in the drowning of the platform and the formation of a starved, deep-water, foreland basin in which hemipelagic carbonates and related slope deposits began to accumulate. The final phase of tectonic movement in the area was associated with the nearly isochronous flooding of exposed Lower Ordovician sediments (Knox Group) to the northwest. This event, which marked the beginning of deposition of the Chickamauga Group, was associated with the first introduction of eastwardly derived turbidites into the basin. Continued infilling of the basin was initially coupled with a gradual deepening trend on the carbonate platform to the northwest. Eventually, the basin was filled to the point at which terrigenous material began to be effectively transported across the basin and onto the platform. Associated with this terrigenous influx, an initial deepening, related to a reduction in carbonate production, was followed by gradual shallowing on the platform. Continued terrigenous input and shallowing ultimately resulted in the development of terrigenous-carbonate tidal flats throughout the area. The Tennessee Middle Ordovician contains a sequence of depositional facies that detail the developmental history of a foreland basin in an active margin setting. Recognition of similar sequences elsewhere may be used to infer analogous depositional settings and tectonic styles.