ALBERT

Description: We study the effects of planform dome shape on fault patterns developing with and without concurrent regional extension oriented oblique to the long axis of the dome. The motivation was the need to understand fault and fracture patterns in two adjacent mature hydrocarbon fields in the Middle East: one, an elliptical dome, and one, an irregularly shaped dome. The largest faults have throws of approximately 30 m (~98 ft), which is close to the resolution limit of older two-dimensional seismic reflection data. The known fault trends are not parallel to the highest transmissivity direction but could form compartment boundaries. Fault and fracture patterns developed over the modeled domes provide insight into the populations of faults and fractures that are likely to exist in the reservoirs but have been undetected because they are at or below the resolution limit of reflection seismic data. Major domal structural elements, crestal fault systems, end splay systems, and radial faults are observed in modeled domes rising both with and without concurrent regional extension. Experimental results indicate that fault and fracture patterns are influenced by the effects of dome shape, regional extension, and relative timing of uplift with respect to regional extension. The expression of particular sets of faults and fractures associated with concurrent doming and regional extension depends on the interaction among regional extension, outer arc extension over the dome, and tangential extension around the dome margins. Our results also indicate that the two adjacent natural domes possibly experienced different kinematic histories from those previously interpreted.

Description: Predicting the presence and connectivity of reservoir-quality facies in otherwise mud-prone fluvial overbank successions is important because such sand bodies can potentially provide connectivity between larger neighboring sand bodies. This article addresses minor channelized fluvial elements (crevasse-splay and distributary channels) and attempts to predict the connectivity between such sand bodies in two interseam packages of the Upper Permian Rangal Coal Measures of northeastern Australia. Channel-body percent as measured in well logs was 2% in the upper (Aries-Castor) interseam and 17% in the lower (Castor-Pollux) interseam. Well spacing were too great to allow accurate correlation of channel bodies. The Ob River, Siberia, was used as a modern analog to supply planform geometric measurements of splay and distributary channels so that stochastic modeling of channel bodies was possible. The resulting models demonstrated that (1) channel-body connectivity is more uniform between minor distributary channels than between crevasse-splay channels; (2) relatively good connectivity is seen in proximal positions in splays but decreases distally from the source as channel elements diverge; and (3) connectivity tends to be greater down the axis of splays, with more isolated channel bodies occurring at the margins.

Description: Multiple techniques are available to construct three-dimensional reservoir models. This study uses comparative analysis to test the impact of applying four commonly used stochastic modeling techniques to capture geologic heterogeneity and fluid-flow behavior in fluvial-dominated deltaic reservoirs of complex facies architecture: (1) sequential indicator simulation; (2) object-based modeling; (3) multiple-point statistics (MPS); and (4) spectral component geologic modeling. A reference for comparison is provided by a high-resolution model of an outcrop analog that captures facies architecture at the scale of parasequences, delta lobes, and facies-association belts. A sparse, pseudosubsurface data set extracted from the reference model is used to condition models constructed using each stochastic reservoir modeling technique. Models constructed using all four algorithms fail to match the facies-association proportions of the reference model because they are conditioned to well data that sample a small, unrepresentative volume of the reservoir. Simulated sweep efficiency is determined by the degree to which the modeling algorithms reproduce two aspects of facies architecture that control sand-body connectivity: (1) the abundance, continuity, and orientation of channelized fluvial sand bodies; and (2) the lateral continuity of barriers to vertical flow associated with flooding surfaces. The MPS algorithm performs best in this regard. However, the static and dynamic performance of the models (as measured against facies-association proportions, facies architecture, and recovery factor of the reference model) is more dependent on the quality and quantity of conditioning data and on the interpreted geologic scenario(s) implicit in the models than on the choice of modeling technique.

Description: Outcrops of the middle Eagle Ford Formation in south-central Texas reveal well-developed joint networks in subhorizontal competent carbonate (chalk) beds and less well developed networks in interlayered incompetent calcareous mudrock beds. Northeast-striking bed-perpendicular joints in competent beds have the longest trace lengths and are abutted by northwest-striking joints. All observed joints terminate vertically in incompetent beds. Normal faults are common but less abundant than joints; dominantly dip north, northwest, or southeast; and are abutted by the joint sets and, thus, predated jointing. The faults cut multiple competent and incompetent beds, providing vertical connectivity across mechanical layering. Products of hybrid and shear failure, the dip of these faults is steep through competent beds and moderate through incompetent beds, resulting in refracted fault profiles with dilation and calcite precipitation along steep segments. Fluid inclusions in fault zone calcite commonly contain liquid hydrocarbons. Rare two-phase fluid inclusions homogenized between about (1) 40 and 58°C, and (2) 90 and 100°C, suggesting trapping of aqueous fluids at elevated temperatures and depths on the order of 2 km (6562 ft). Fluid inclusion and stable isotope geochemistry analyses suggest that faults transmitted externally derived fluids. These faults likely formed at depths equivalent to portions of the present-day oil and gas production from the Eagle Ford play in south Texas. Faults connect across layering and provide pathways for vertical fluid movement within the Eagle Ford Formation, in contrast to vertically restricted joints that produce bed-parallel fracture permeability. These observations elucidate natural fractures and induced hydraulic fracturing within the Eagle Ford Formation.

Description: Production from self-sourced reservoirs relies on natural and induced fracturing for permeability and conductance of hydrocarbons to the producing wellbores, thus natural or induced fracturing is often a key to success in unconventional reservoir plays. On the other hand, fractures may compromise seals and large or well-connected fractures or faults may cause undesirable complications for unconventional reservoirs. Natural and induced fractures are influenced by (1) mechanical stratigraphy, (2) pre-existing natural deformation such as faults, fractures, and folds, and (3) in situ stress conditions, both natural and as modified by stimulation and pressure depletion. This special issue of the AAPG Bulletin elucidates some of these structural geologic and geomechanical controls. Understanding the occurrence and controls on natural and induced faulting and fracturing in self-sourced reservoirs is a key component for developing effective approaches for exploiting self-sourced reservoirs.

Description: The First Eocene reservoir at the Wafra Field produces heavy oil from very porous dolomites at depths of $$\sim 1000\hbox{ \hspace{0.17em} }\hbox{ \hspace{0.17em} }\hbox{ to }\hbox{ \hspace{0.17em} }\hbox{ \hspace{0.17em} }1300\hbox{ \hspace{0.17em} }\hbox{ \hspace{0.17em} }\mathrm{ft}$$ (300 to 400 m) in the Paleocene–Eocene Umm Er Radhuma Formation. Porosity is commonly 30–50%, permeability is commonly 100–2000 md, and those reservoir characteristics were determined largely by diagenesis. Early diagenesis is dominated by dolomitization, dissolution associated with dolomitization, and precipitation of sulfates. Petrographic and stable isotopic characteristics support dolomitization and sulfate precipitation in evaporated (refluxing) seawater during shallow burial. The highest permeabilities occur in subtidal facies. Low-permeability tidal-flat facies stratify the reservoir. Heavy oil preferentially filled high-permeability dolomites; whereas, low-permeability tidal-flat facies are commonly filled with water because their pore throats are too small to allow migration of viscous oil into the rock. This reservoir’s very high porosity is probably related to its shallow burial and early oil emplacement. Late-stage diagenesis is dominated by bacterial sulfate reduction (BSR) that caused dissolution of sulfate nodules, calcite cementation, sulfur precipitation, and oil biodegradation. The BSR is indicated by very low $${\updelta }^{13}\mathrm{C}$$ compositions of calcite cements ( $$-17.1$$ to $$-34.9$$ , Peedee Belemnite standard), which require an organic carbon source; probably oil. The oxygen isotopic compositions of the calcites support precipitation from formation waters similar to those in the reservoir now. The BSR probably started during initial oil emplacement and continues to the present. The BSR was heterogeneous resulting in produced oils with gravities of 14–21° API. Even heavier oils are present that could not flow during primary production. Primary production was likely greatest in areas and intervals with lighter, less viscous oil.

Description: This study examines the geochemical record of diagenesis in the Middle Permian Yates shelf, exposed in Slaughter Canyon, New Mexico. This diagenetic history significantly modified lithologies, depositional fabrics, and pore systems. Early diagenesis was dominated during sea level highstands by marine cementation and reflux dolomitization, and during sea level lowstands by meteoric cementation and stabilization—the focus of this study. This early diagenesis variably overprinted primary marine isotopic signatures, potentially leading to erroneous chemostratigraphic correlations or paleoclimate reconstructions. Four correlative sections through one m-scale cycle were analyzed for their $${{\updelta }}^{13}\mathrm{C}$$ and $${{\updelta }}^{18}\mathrm{O}$$ values. They show significant (2–4) $${{\updelta }}^{13}\mathrm{C}$$ and $${{\updelta }}^{18}\mathrm{O}$$ variability in coeval, texturally well-preserved calcites. The $${{\updelta }}^{13}\mathrm{C}$$ and $${{\updelta }}^{18}\mathrm{O}$$ values of marine cements, brachiopods, bulk carbonate, micritic matrix, and the first generation of meteoric spar (from high to low values) delineate an "inverted J curve," indicating the variable alteration of components by diagenetic fluids. Numerical models indicate that the observed stable isotope trend is most consistent with diagenetic alteration in a partially closed system by meteoric fluids mixed with a progressively diminishing contribution of recycled marine waters. In the Yates shelf, marine cements provide a more robust primary isotopic record than micritic matrix; however, neither preserves primary seawater isotopic values. Furthermore, common criteria used to diagenetically screen samples proved inadequate (e.g., textural preservation, staining, luminescence, depletion near sequence boundaries). Instead, diagenetic resetting is resolved by analyzing multiple, closely spaced, independently correlated sections, and by delineating trends between primary and later diagenetic components in populations of isotopic data.

Description: Reservoir management studies of California’s Kern River field rely on a full-field 155-million cell three-dimensional (3D) earth model. This full-field model provides input for reserves estimation as well as the identification, targeting, and ranking of remaining opportunities. The earth model is regarded as "fit for purpose" in that characteristics of the model are aligned with specific needs for reservoir management. Normalized resistivity logs from more than 12,000 wells are used to establish lithology and reservoir architecture. Temperature, steam, gas, and oil saturation logs from over 650 boreholes provide regular periodic surveillance for identifying changes in fluids and temperature. Changes in fluid contacts and saturations are integrated with reservoir architecture three times each year. These model updates are important to the development teams for staying current on changes in their project area. The integration of these data provides the basis for linked reserves and resource estimation and the identification and development of remaining opportunities. Kern River reserves and resources are estimated from the model for over 130 internal reporting entities. For asset reservoir management purposes, reserves are updated for over 160,000 entities (based on patterns, zones, and reserves) across the 12-sq-mi (31-sq-km) field. The updated reserves supply input to reserves distribution maps and spreadsheets used for evaluating workover and new development opportunities. Some of these opportunities represent heat mining of untapped hot oil zones whereas other opportunities are cold and require the introduction of steam to mobilize the oil. Using multiple reservoir property characteristics as filter criteria for identifying remaining opportunities is an important tool used at Kern River. Reservoir volumes containing hot moveable oil below steam zones in non-producing areas can be quickly and efficiently identified and prioritized with this method. This has helped lead to the success of our current field-wide horizontal infill drilling program that identifies geobodies based on these filtering criteria.

Description: Weakly confined channel systems are common in low-relief minibasins on continental margins and are important hydrocarbon reservoirs. They are characterized by channels that diverge in the proximal part of the basin and converge because of topographic confinement in the distal part of the basin. The Morillo 1 member, in the Ainsa Basin, Spain, is an excellent outcrop analog of a weakly confined submarine channel system. Data from the Morillo 1 member are used to quantitatively document how reservoir characteristics vary laterally and longitudinally in weakly confined submarine channel reservoirs. The key axis-to-margin patterns are the proportions of channel elements, channel complexes, channel-complex sets, reservoir facies, and net sand content; static connectivity decreases laterally from the axis to the margins of the system. The key longitudinal patterns in the updip area are channel elements that have levees, are spatially dispersive, and have a radially divergent map pattern. In the downdip area, channel elements are spatially focused and have uniform orientations, and the proportion of channel elements does not change along the longitudinal profile. However, the size of channel elements, percentage of reservoir facies, and connectivity of channel elements are higher in the downdip area. Patterns identified herein are significant because they cannot be resolved using subsurface or sea-floor data. Results of this study can therefore be used to reduce uncertainty in the interpretation of subsurface data, provide input to constrain rule-based forward stratigraphic models, and provide input to constrain reservoir models.

Description: 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 μd) are low. In-place heating led to gas generation and to concomitant in-place solidification of liquid hydrocarbons.