ALBERT

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: Tidal heterolithic sandstones are commonly characterized by millimeter- to centimeter-scale intercalations of mudstone and sandstone. Consequently, their effective flow properties are poorly predicted by (1) data that do not sample a representative volume or (2) models that fail to capture the complex three-dimensional architecture of sandstone and mudstone layers. We present a modeling approach in which surfaces are used to represent all geologic heterogeneities that control the spatial distribution of reservoir rock properties (surface-based modeling). The workflow uses template surfaces to represent heterogeneities classified by geometry instead of length scale. The topology of the template surfaces is described mathematically by a small number of geometric input parameters, and models are constructed stochastically. The methodology has been applied to generate generic, three-dimensional minimodels (9 m 3 [~318 ft 3 ] volume) of cross-bedded heterolithic sandstones representing trough and tabular cross bedding with differing proportions of sandstone and mudstone, using conditioning data from two outcrop analogs from a tide-dominated deltaic deposit. The minimodels capture the cross-stratified architectures observed in outcrop and are suitable for flow simulation, allowing computation of effective permeability values for use in larger-scale models. We show that mudstone drapes in cross-bedded heterolithic sandstones significantly reduce effective permeability and also impart permeability anisotropy in the horizontal as well as vertical flow directions. The workflow can be used with subsurface data, supplemented by outcrop analog observations, to generate effective permeability values to be derived for use in larger-scale reservoir models. The methodology could be applied to the characterization and modeling of heterogeneities in other types of sandstone reservoirs.

Description: Tidal heterolithic sandstone reservoirs are heterogeneous at the submeter scale because of the ubiquitous presence of intercalated sandstone and mudstone laminae. Core-plug permeability measurements fail to sample a representative volume of this heterogeneity. Here, we investigate the impact of mudstone drape distribution on the effective permeability of heterolithic, cross-bedded tidal sandstones using three-dimensional, surface-based "minimodels" that capture the geometry of cross beds at an appropriate scale. The impact of seven geometric parameters has been determined: (1) mudstone fraction, (2) sandstone laminae thickness, (3) mudstone drape continuity, (4) toeset dip, (5) climb angle of foreset–toeset surfaces, (6) proportion of foresets to toesets, and (7) trough or tabular geometry of the cross beds. We begin by identifying a representative elementary volume of 1 m 3 (~35 ft 3 ), confirming that the model volume of 9 m 3 (~318 ft 3 ) yields representative permeability values. Effective permeability decreases as the mudstone fraction increases, and it is highly anisotropic: vertical permeability falls to approximately 0.5% of the sandstone permeability at a mudstone fraction of 25%, whereas the horizontal permeability falls to approximately 5% and approximately 50% of the sandstone value in the dip (across mudstone drapes) and strike (parallel to mudstone drapes) directions, respectively. Considerable spread exists around these values, because each parameter investigated can significantly impact effective permeability, with the impact depending upon the flow direction and mudstone fraction. The results yield improved estimates of effective permeability in heterolithic, cross-bedded sandstones, which can be used to populate reservoir-scale model grid blocks using estimates of mudstone fraction and geometrical parameters obtained from core and outcrop-analog data.

Description: The Vaca Muerta–Quintuco system (uppermost lower Tithonian–lower Valanginian) is a thick shallowing-upward sedimentary cycle consisting of dark bituminous shales, marlstones, limestones, and sandstones, cropping out in the Neuquén Basin, west–central Argentina. This paper analyzes three outcrop sections in Chos Malal area, northem Neuquén province. Detailed facies analysis allows us to differentiate six facies associations, representing basinal to proximal outer ramp facies of a homoclinal carbonate ramp system (Vaca Muerta Formation) and basinal to shoreface facies of a mixed carbonate–siliciclastic shelf system (Quintuco Formation), prograding westward from the eastern margin of the basin. Two sequence hierarchies were recognized: 5 composite depositional sequences (third order) and 15 high-frequency sequences (fourth order). Fluctuations in organic matter content within the Vaca Muerta Formation suggest a relationship with depositional sequences, finding the highest values associated with transgressive systems tract, whereas the transition to the Quintuco Formation shows a strong decrease in total organic carbon. The x-ray diffraction studies show an increase of clay minerals and quartz in the transgressive systems tract of the Vaca Muerta Formation and an increase in the content of calcite in highstand systems tracts. This pattern is reversed in the Quintuco Formation. Our sequence stratigraphic approach contributes to the understanding of the relationship between organic matter, clay minerals, facies, stacking pattern, and relative sea level changes in this exceptional shale oil and shale gas unconventional reservoir. This study may be helpful for a better postulate of petrophysical and geomechanical models for unconventional exploration.

Description: To date, most condensates and gases found in the Hammerfest Basin exist in distal, central basin settings, in traps with tight cap rocks of class 1 traps, whereas low-gas–oil-ratio (GOR) oils occur systematically in proximal basin settings, where cap rocks of class 3 traps prevail. Multiple fill-spill events resulted in the redistribution of oils toward structurally higher basin margins. In a systematic evaluation of light hydrocarbon parameters from condensates and oils, it was found that oils in general exhibit more traceable alteration effects than do condensates. Whereas 75% of condensate and 13.3% of oil samples are fractionated, 6.25% and 10%, respectively, show signs of biodegradation. Long-distance migration is indicated for 12.5% of condensate and 50% of oil samples. In addition, clear evidence is shown for the mixing of recently migrated high-GOR petroleum phases with older, low-GOR paleo oils. In general, variation in source-specific parameters is surprisingly less pronounced. Decreasing thermal maturity of entrapped petroleum from the eastern part of the Tromsø Basin toward the Måsøy-Nysleppen Fault Complex is observed, whereas high maturities are shown for the Nordkapp Basin and the Finnmark Platform in the eastern part of the study area. Low-to-medium maturities are recorded for oils from the basin margins of the Hammerfest Basin. Alterations in the composition of the petroleums by physiochemical processes and distribution patterns of the petroleums are closely associated with uplift and erosion.

Description: Water salinity in the San Joaquin Valley is a function of depth, location, and stratigraphy. This paper presents a reconnaissance study of water salinity within Kern County, California, using chemical analyses from oil field produced water and water wells as well as geophysical logs. Log analysis indicates that the base of underground sources of drinking water (USDWs) (〈10,000 mg/L) slopes from northwest to southeast. Lab analyses show that USDWs extend to depths as great as 1900 m (6233.5 ft) southeast of Bakersfield. This area receives the greatest amount of fresh water recharge from streams flowing westward from the Sierras. The marine Olcese Sand is more saline than the overlying and underlying aquifers and separates the aquifers into an upper and lower USDW. Log analysis also indicates a zone of higher salinity separating zones of lower salinity in this area. Salinities in the west are higher, and depths to base USDW are variable. Although waters in many sands in the western valley are more saline than 3000 ppm total dissolved solids (TDS), numerous wells contain waters between 3000 and 10,000 ppm at depths of less than 600 m (1968.5 ft), particularly in the nonmarine Tulare Formation. At North Belridge field, a salinity reversal is apparent below 2100 m (6890 ft). Waters above this depth are approximately 40,000 mg/L TDS, whereas water salinities below 2200 m (7218 ft) range from 10,000 to 32,000 mg/L. Extremely high salinities are found in several wells less than 30 m (98 ft) deep, primarily in the northwestern area. These may be perched aquifers or lie adjacent to unmapped agricultural drainage sumps and do not reflect salinities in the regional aquifer.

Description: This study evaluates the proportion, length, and effective properties of thin (0.003–0.7 m [0.01–2.3 ft]) shale beds and drapes in tidally influenced channels within a compound valley fill with a focus on estimating geologically based effective rock properties. The Cretaceous Ferron Sandstone is an outcrop analog for fluvial–tidal systems with primary reservoirs being deposited as tidally influenced valley filling point bars. The study outcrops expose three valley systems in Neilson Wash of Utah. Light detection and ranging–derived digital outcrop models have been used to characterize shale length, width, thickness, and frequency of each valley fill succession. Long, uncommon, and anisotropic shales in valley 1 (V1) were deposited in a braided setting with little tidal influence. In contrast, shales in valley 2 (V2) were abundant, short, common, and equidimensional, suggesting deposition by more tidally influenced meandering rivers. Short, frequent, and equidimensional shales in valley 3 (V3) were deposited in single-thread meandering rivers with less tidal influence. A sandstone–shale model was used to estimate the effects of shales on vertical to horizontal permeability ratio ( \[{k}_{v}/{k}_{h} \] ). The unique character of each depositional unit was reflected in resultant \[{k}_{v}/{k}_{h} \] distributions. The valley fill deposits, V1, V2, and V3, had average \[{k}_{v}/{k}_{h} \] ratios of 0.11, 0.09, and 0.17, respectively. More tidally influenced reservoirs such as the studied V2 had short but frequent shales, which resulted in low \[{k}_{v}/{k}_{h} \] estimates. Estimates of \[{k}_{v}/{k}_{h} \] for valleys that predominantly contained fluvial point bar deposits with lesser tidal influence (V1 and V3) were higher. The results of this study highlight the link between shale heterogeneity, reservoir architecture, and inferred flow parameters.

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.