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4th Edition: Stratigraphic Traps of the Middle East Call for Posters
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Prolific hydrocarbon discoveries in the subsalt, commonly known as the “presalt,” section of Brazil and the conjugate African margin have created a business imperative to predict reservoir quality in lacustrine carbonates. Geothermal convection is a style of groundwater flow known to occur in rift settings, which is capable of diagenetic modification of reservoir quality. We simulated variable density groundwater flow coupled with chemical reactions to evaluate the potential for diagenesis driven by convection in subsalt carbonates.
Rates of calcite diagenesis are critically controlled by temperature gradient and fluid flux following the principles of retrograde solubility. Simulations predict that convection could operate in rift carbonates prior to salt deposition, but with rates of dissolution in the reservoir interval only on the order of 0.01 vol. %/m.y., which is too low to significantly modify reservoir quality. The exception is around permeable fault zones and/or unconformities where flow is focused and dissolution rates are amplified to 1 to 10 vol. %/m.y. and could locally modify reservoir quality. After salt deposition, simulations also predict convection with a critical function for salt rugosity. The greatest potential for dissolution at rates of 0.1 to 1 vol. %/m.y. occurs where salt welds, overlying permeable carbonates thin to 500 m (1640 ft) or less. With tens of million years residence times feasible, convection under these conditions could locally result in reservoir sweet spots with porosity modification of 1% to 10% and potentially an order of magnitude or more in reservoir permeability. Integrating quantitative model–derived predictive diagenetic concepts with traditional subsurface data sets refines exploration to production scale risking of carbonate reservoir presence and quality.
The Heidrun field, located on the Halten Terrace of the mid-Norwegian continental shelf, was one of the first giant oil fields found in the Norwegian Sea. Traditional reservoir intervals in the Heidrun field lie within the Jurassic synrift sequence. Most Norwegian continental shelf fields have been producing from these Jurassic reservoirs for the past 30 yr. Production has since declined in these mature fields, but recently, exploration for new reservoirs has resurged in this region. The Jurassic rifted fault blocks form a narrow continental shelf in Norway, thereby greatly reducing the areal extent for exploration and development within existing fields. As the rift axis is approached farther offshore, these Jurassic reservoirs become very deep, too risky to drill, and uneconomical. This risk has prompted exploration in more recent years of the shallower Cretaceous, postrift stratigraphic succession. Cretaceous turbidites have been found in the Norwegian and North Seas, and the discovery of the Agat field in the Norwegian North Sea confirms the existence of a working petroleum system capable of charging Cretaceous reservoirs. These Cretaceous reservoirs were deposited as slope- and basin-floor fans within a series of underfilled rifted deeps along the Norwegian continental shelf and are thought to be sourced from the localized erosion of Jurassic rifted highs. We use three-dimensional seismic and well data to document the geomorphology of a deep-water, Lower Cretaceous wedge (Cromer Knoll Group) within the hanging wall of a rift-related half graben formed on the Halten Terrace offshore mid-Norway. Seismic attribute extractions taken within this Lower Cretaceous wedge reveal the presence of several lobate to elongated bodies that seem to cascade over fault-bounded terraces associated with rifted structures. These high-amplitude, elongated bodies are interpreted as deep-water sedimentary conduits that are time equivalent to the Cretaceous basin-floor fans in more distal parts of the basin to the west. These half-graben fills have the potential to contain high-quality Cretaceous sandstones that might represent a potential new reservoir interval within the Heidrun field.
New dimensions: Geoscientists study how 3-D views of Eagle Ford outcrops are a great tool.
We describe the structure, microstructure, and petrophysical properties of fault rocks from two normal fault zones formed in low-porosity turbiditic arkosic sandstones, in deep diagenesis conditions similar to those of deeply buried reservoirs. These fault rocks are characterized by a foliated fabric and quartz-calcite sealed veins, which formation resulted from the combination of the (1) pressure solution of quartz, (2) intense fracturing sealed by quartz and calcite cements, and (3) neoformation of synkinematic white micas derived from the alteration of feldspars and chlorite. Fluid inclusion microthermometry in quartz and calcite cements demonstrates fault activity at temperatures of 195C to 268C. Permeability measurements on plugs oriented parallel with the principal axes of the finite strain ellipsoid show that the Y axis (parallel with the foliation and veins) is the direction of highest permeability in the foliated sandstone (10–2 md for Y against 10–3 md for X, Z, and the protolith, measured at a confining pressure of 20 bars). Microstructural observations document the localization of the preferential fluid path between the phyllosilicate particles forming the foliation. Hence, the direction of highest permeability in these fault rocks would be parallel with the fault and subhorizontal, that is, perpendicular to the slickenlines representing the local slip direction on the fault surface. We suggest that a similar relationship between kinematic markers and fault rock permeability anisotropy may be found in other fault zone types (reverse or strike-slip) affecting feldspar-rich lithologies in deep diagenesis conditions.
The McMurray Formation of northern Alberta in Canada contains multiscale complex geologic features that were partially formed in a fluvial-estuarine depositional environment. The inclined heterolithic strata deposited as part of fluvial point bars contain continuous centimeter-scale features that are important for flow characterization of steam-assisted gravity drainage processes. These channels are common, extensive, and imbricated over many square kilometers. Modeling the detailed facies in such depositional systems requires a methodology that reflects heterogeneity over many scales. This article presents an object-based facies modeling technique that (1) reproduces the geometry of multiscale geologic architectural elements seen in the McMurray Formation outcrops and (2) provides a grid-free framework that models these geologic objects without relating them to a grid system. The grid-free object-based modeling can be applied to any depositional environment and allows for the complete preservation of architectural information for consistent application to any gridding scheme, local grid refinements, downscaling, upscaling, drape surface, locally variable azimuths, property trend modeling, and flexible model interaction and manipulation. Features millimeters thick or kilometers in extent are represented very efficiently in the same model.
Understanding the distribution and geometry of reservoir geobodies is crucial for net-to-gross estimates and to model subsurface flow. This article focuses on the process of dolomitization and resulting geometry of diagenetic geobodies in an outcrop of Jurassic host rocks from northern Oman. Field and petrographic data show that a first phase of stratabound dolomite is crosscut by a second phase of fault-related dolomite. The stratabound dolomite geobodies are laterally continuous for at least several hundreds of meters (1000 ft) and probably regionally and are one-half meter (1.6 ft) thick. Based on petrography and geochemistry, a process of seepage reflux of mesosaline or hypersaline fluids during the early stages of burial diagenesis is proposed for the formation of the stratabound dolomite. In contrast, the fault-related dolomite geobodies are trending along a fault that can be followed for at least 100 m (328 ft) and vary in width from a few tens of centimeters to as much as 10 m (1–33 ft). Petrography, geochemistry, and high homogenization temperature of fluid inclusions all point to the formation of the dolomite along a normal fault under deep burial conditions during the Middle to Late Cretaceous. The high 87Sr/86Sr ratio in the dolomite and the high salinity measured in fluid inclusions indicate that the dolomitizing fluids are deep basinal brines that interacted with crystalline basement. The dolomitization styles have an impact on the dimension, texture, and geochemistry of the different dolomite geobodies, and a modified classification scheme (compared to the one from Jung and Aigner, 2012) is proposed to incorporate diagenetic geobodies in future reservoir modeling.
West Edmond field, located in central Oklahoma, is one of the largest oil accumulations in the Silurian–Devonian Hunton Group in this part of the Anadarko Basin. Production from all stratigraphic units in the field exceeds 170 million barrels of oil (MMBO) and 400 billion cubic feet of gas (BCFG), of which approximately 60 MMBO and 100 BCFG have been produced from the Hunton Group. Oil and gas are stratigraphically trapped to the east against the Nemaha uplift, to the north by a regional wedge-out of Hunton strata, and by intraformational diagenetic traps. Hunton Group reservoirs are the Bois d'Arc and Frisco Limestones, with lesser production from the Chimneyhill subgroup, Haragan Shale, and Henryhouse Formation.
Hunton Group cores from three wells that were examined petrographically indicate that complex diagenetic relations influence permeability and reservoir quality. Greatest porosity and permeability are associated with secondary dissolution in packstones and grainstones, forming hydrocarbon reservoirs. The overlying Devonian–Mississippian Woodford Shale is the major petroleum source rock for the Hunton Group in the field, based on one-dimensional and four-dimensional petroleum system models that were calibrated to well temperature and Woodford Shale vitrinite reflectance data. The source rock is marginally mature to mature for oil generation in the area of the West Edmond field, and migration of Woodford oil and gas from deeper parts of the basin also contributed to hydrocarbon accumulation.
A new hierarchical architectural classification for clastic marginal-marine depositional systems is presented and illustrated with examples. In ancient rocks, the architectural scheme effectively integrates the scales of sedimentology (core, outcrop) and sequence stratigraphy (wireline-log correlation, reflection seismic). The classification also applies to modern sediments, which allows for direct comparison of architectural units between modern and ancient settings. In marginal-marine systems, the parasequence typically defines reservoir flow units. This classification addresses subparasequence scales of stratigraphy that commonly control fluid flow in these reservoirs. The scheme consists of seven types of architectural units that are placed on five architectural hierarchy levels: hierarchy level I: element (E) and element set (ES); hierarchy level II: element complex (EC) and element complex set (ECS); hierarchy level III: element complex assemblage (ECA); hierarchy level IV: element complex assemblage set (ECAS); and hierarchy level V: transgressive-regressive sequence (T-R sequence). Architectural units in levels I to III are further classified relative to dominant depositional processes (wave, tide, and fluvial) acting at the time of deposition. All architectural units are three-dimensional and can also be expressed in terms of plan-view and cross-sectional geometries. Architectural units can be linked using tree data structures by a set of familial relationships (parent-child, siblings, and cousins), which provides a novel mechanism for managing uncertainty in marginal-marine systems. Using a hierarchical scheme permits classification of different data types at the most appropriate architectural scale. The use of the classification is illustrated in ancient settings by an outcrop and subsurface example from the Campanian Bearpaw–Horseshoe Canyon Formations transition, Alberta, Canada, and in modern settings, by the Mitchell River Delta, northern Australia. The case studies illustrate how the new classification can be used across both modern and ancient systems, in complicated, mixed-process depositional environments.
The Upper Jurassic Arab Formation in the Arabian Peninsula, the most prolific oil-bearing interval of the world, is a succession of interbedded thick carbonates and evaporites that are defined stratigraphically upsection as the Arab-D, Arab-C, Arab-B, and Arab-A. The Arab-D reservoir is the main reservoir in Khurais field, one of the largest onshore oil fields of the Kingdom of Saudi Arabia.
In Khurais field, the Arab-D reservoir is composed of the overlying evaporitic Arab-D Member of the Arab Formation and the underlying upper part of the Jubaila Formation. It contains 11 lithofacies, listed from deepest to shallowest: (1) hardground-capped skeletal wackestone and lime mudstone; (2) intraclast floatstone and rudstone; (3) pelletal wackestone and packstone; (4) stromatoporoid wackestone, packstone, and floatstone; (5) Cladocoropsis wackestone, packstone, and floatstone; (6) Clypeina and Thaumatoporella wackestone and packstone; (7) peloidal packstone and grainstone; (8) ooid grainstone; (9) crypt-microbial laminites; (10) evaporites; and (11) stratigraphically reoccurring dolomite.
The Arab-D reservoir lithofacies succession represents shallowing-upward deposition, which, from deepest to shallowest, reflects the following depositional environments: offshore submarine turbidity fans (lithofacies 1 and 2); lower shoreface settings (lithofacies 3); stromatoporoid reef (lithofacies 4); lagoon (lithofacies 5 and 6); shallow subtidal settings (lithofacies 7 and 8); peritidal settings (lithofacies 9); and sabkhas and salinas (lithofacies 10). The depositional succession of the reservoir represents a prograding, shallow-marine, reef-rimmed carbonate shelf that was subjected to common storm abrasion, which triggered turbidites.
Isolated carbonate buildups (ICBs) are commonly attractive exploration targets. However, identifying ICBs based only on seismic data can be difficult for a variety of reasons. These include poor-quality two-dimensional data and a basic similarity between ICBs and other features such as volcanoes, erosional remnants, and tilted fault blocks. To address these difficulties and develop reliable methods to identify ICBs, 234 seismic images were analyzed. The images included proven ICBs and other features, such as folds, volcanoes, and basement highs, which may appear similar to ICBs when imaged in seismic data. From this analysis, 18 identification criteria were derived to distinguish ICBs from non-ICB features. These criteria can be grouped into four categories: regional constraints, analysis of basic seismic geometries, analysis of geophysical details, and finer-scale seismic geometries. Systematically assessing the criteria is useful because it requires critical evaluation of the evidence present in the available data, working from the large-scale regional geology to the fine details of seismic response. It is also useful to summarize the criteria as a numerical score to facilitate comparison between different examples and different classes of ICBs and non-ICBs. Our analysis of scores of different classes of features suggests that the criteria do have some discriminatory power, but significant challenges remain.
Join us for the 4th Edition of: "Stratigraphic Traps of the Middle East" workshop.
The workshop will be hosted by AAPG in Al Khobar, Saudi Arabia 4-6 March 2024.
As oil and gas exploration and production occur in deeper basins and more complex geologic settings, accurate characterization and modeling of reservoirs to improve estimated ultimate recovery (EUR) prediction, optimize well placement and maximize recovery become paramount. Existing technologies for reservoir characterization and modeling have proven inadequate for delivering detailed 3D predictions of reservoir architecture, connectivity and rock quality at scales that impact subsurface flow patterns and reservoir performance. Because of the gap between the geophysical and geologic data available (seismic, well logs, cores) and the data needed to model rock heterogeneities at the reservoir scale, constraints from external analog systems are needed. Existing stratigraphic concepts and deposition models are mostly empirical and seldom provide quantitative constraints on fine-scale reservoir heterogeneity. Current reservoir modeling tools are challenged to accurately replicate complex, nonstationary, rock heterogeneity patterns that control connectivity, such as shale layers that serve as flow baffles and barriers.
Request a visit from Tao Sun!
The carbonate sequences that were deposited in the now exhumed Tethyan Ocean influence many aspects of our lives today, either by supplying the energy that warms our homes and the fuel that powers our cars or providing the stunning landscapes for both winter and summer vacations. They also represent some of the most intensely studied rock formations in the world and have provided geoscientists with a fascinating insight into the turbulent nature of 250 Million years of Earth’s history.
By combining studies from the full range of geoscience disciplines this presentation will trace the development of these carbonate sequences from their initial formation on the margins of large ancient continental masses to their present day locations in and around the Greater Mediterranean and Near East region.
The first order control on growth patterns and carbonate platform development by the regional plate-tectonic setting, underlying basin architecture and fluctuations in sea level will be illustrated. The organisms that contribute to sequence development will be revealed to be treasure troves of forensic information. Finally, these rock sequences will be shown to contain all the ingredients necessary to form and retain hydrocarbons and the manner in which major post-depositional tectonic events led to the formation of some of the largest hydrocarbon accumulations in the world will be demonstrated.
Request a visit from Keith Gerdes!
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