Yassin, Mohamed A. (Geosciences Department, CPG, KFUPM, Dhahran Saudi Arabia) | Abdullatif, Osman M. (Geosciences Department, CPG, KFUPM, Dhahran Saudi Arabia) | Makkawi, Mohammad H. (Geosciences Department, CPG, KFUPM, Dhahran Saudi Arabia) | Yousif, Ibrahim M. (Geosciences Department, CPG, KFUPM, Dhahran Saudi Arabia) | Osman, Mutasim S. (Geosciences Department, CPG, KFUPM, Dhahran Saudi Arabia)
Well exposed Jurassic outcrops belt in central Saudi Arabia provides good outcrop analogs which can be utilized to capture the high resolution facies types and architecture that might help to fill the inter-wells gap in the subsurface. This study is focused on the characterization and modeling the facies types, body geometries deposited in geomorphic elements of carbonate ramp system and the distribution of the reservoir properties on it. Three-dimensional models for the different facies-body geometries were conducted to provide accurate stochastic representation. This study was conducted at a selected Jurassic outcrop reservoir analog that exposed around Riyadh area. The Mesozoic carbonate strata of central Saudi Arabia are interpreted to have been deposited in ramp systems and exposed in hundreds of kilometers in the strike and dip direction of palaeoshoreline. The study integrates detailed sedimentological and stratigraphic analysis from outcrop strata to capture facies-body geometries and their petrophysical properties on the ramp system. Nine lithofacies were interpreted from the stratigraphic sections. Spatially, the porosity and permeability show different ranges of heterogeneity from micro to meso and macro scales. Laterally, the reservoir properties show steady variations in contrast with the abrupt change vertically. This variation seems to be related to the sedimentary structure, grain size, and degree of cementation. Different pore types were recognized in the studied intervals, which include fracture, intraparticle, moldic and intercrystalline porosities. Several 3D facies models were constructed using sedimentological and stratigraphic data that collected from the field. These models express the complex and heterogeneous relationship between facies-body geometries in the outcrop precisely. Integration of these data to subsurface equivalent reservoirs will provide qualitative and quantitative information useful for understanding and predicting reservoir quality and architecture in carbonate ramps.
Salahuddin, Andi A. B. (Abu Dhabi National Oil Company, Onshore) | Khan, Karem A. (Abu Dhabi National Oil Company, Onshore) | Al Ali, Reem H. M. (Abu Dhabi National Oil Company, Onshore) | Al Hammadi, Khaled E. (Abu Dhabi National Oil Company, Onshore)
This paper described the novel approach for stochastically modeling complex carbonate reservoir lithofacies and properties distribution within a High Resolution Sequence Stratigraphy (HRSS) framework. The carbonate lithofacies discussed in this paper contains heterogeneous pore types and properties. The reservoir displays an extensive range of geologic and petrophysical properties that make the efficient recovery of hydrocarbons is a challenging task. Hence one of the key steps in improving the recovery factor is by defining the three dimensional variability patterns in the reservoir in the form of fine geocellular static model. The key static geological elements that must be well defined are HRSS framework, lithofacies architecture, and field wide rock properties.
Subsurface analysis was done by examining 600 feet core footage from more than 15 wells, conventional logs from more than 50 wells, and more than 350 thin sections. The reservoir section averages 35 feet that can be subdivided into 6 high-frequency sequences. The reservoir consists of lagoonal packstone-rudstone, grain rich ooid-peloid shoal, and rudstone-boundstone mid-ramp. The shoal deposits exhibit the best permeability and oil saturation and it consists of discontinuous lithofacies body that depicts locally excellent porosity and permeability characteristics.
Lithofacies geometry and properties studies must form a fundamental basis for characterizing and modeling HRSS framework and lithofacies architecture variability through the reservoir. Combined with wireline-log data, they provide a basis for defining both reservoir framework and rock attribute distributions.
Complex lithofacies geometries and transitions, both vertically and laterally between the mound and discontinuous grain-rich ooid-peloid shoal lithofacies together with the continuous and sequential lagoonal and mid-ramp lithofacies does not allow to simulate these sorts of lithofacies assemblage using single lithofacies model algorithm. Hence a new holistic approach was implemented. A combination of Object Based (OB) algorithm and Truncated Gaussian Simulation (TGS) algorithm was employed to handle the complex lithofacies transition. This enables generating multiple realistic field wide lithofacies distribution and relationship which aligns with data trend, subsurface analog in the nearby fields, as well as that is from the outcrop exposure. The established lithofacies distribution within HRSS framework was then used to constrain field-wide properties and diagenetic trend and distribution in the reservoir.
This new holistic approach has recently been successfully implemented in the studied field. The resulted geostatistical model was able to explain pressure depletion and production rate as shown in historical production data of the field. The resulting dynamic model will hence provide reliable production forecast and reservoirs development plan which will eventually allow accomplishing the mandate recovery target.
Chen, Rongtao (Tianjin Branch, CNOOC Ltd.) | Su, Yanchun (Tianjin Branch, CNOOC Ltd.) | niu, Chengmin (Tianjin Branch, CNOOC Ltd.) | Wang, Qingbin (Tianjin Branch, CNOOC Ltd.) | Shi, Xinlei (Tianjin Branch, CNOOC Ltd.) | Zhang, Jianmin (Tianjin Branch, CNOOC Ltd.) | Wang, Feilong (Tianjin Branch, CNOOC Ltd.) | Qin, Runsen (Tianjin Branch, CNOOC Ltd.)
Through the comprehensive analysis of the data related to cores, logging and seismic, the author holded that there were two kinds of sedimentary systems in the study area, which were braided river deposits and meandering river deposits. According to the sequence stratigraphy method of fluvial facies proposed by Catuneanu et al, we established sequence stratigraphic framework in the Guantao formation of south gentle slope belt, Huanghekou Sag. It was divided into 2 third-order sequences, named as SQGU and SQGL, each of the third-order sequences contains a high accommodation systems tract (HAST) and a low accommodation systems tract (LAST). On this basis, the author summarized the sedimentary sequence evolution characteristics in the Guantao formation of south gentle slope belt, Huanghekou Sag. In the period of LAST in the SQGL, there were mainly composed of braided river facies in the study area, main developed multistage compound sand body. In the period of HAST in the SQGL, there were mainly composed of meandering river facies in the study area, main developed isolated point bar sand body and a high proportion of flood plain mud. The evolution characteristic of the SQGU was similar to the SQGL. Because of the accommodation space of the SQGU was at a high level, the grain size of sandstone and the percentage of sandstone are smaller than SQGL.
It is generally accepted that it was mainly composed of braided river facies in Guantao formation of Huanghekou Sag, difficult to form oil and gas reservoir due to lack of mudstone cap rock. The exploration of Guantao formation has not attracted enough attention. Through this analysis, the author thinked that two sets of meandering river deposition can provide partial sealing and created conditions for oil-gas accumulation in the Guantao formation of south gentle slope belt, Huanghekou Sag. Under the guidance of this research, we have obtaineda certain oil and gas discovery in the study area.
Magnetic Susceptibility (MS) is an indicator of the concentration of magnetic particles in rocks. In pre-Quaternary sediments the magnetic susceptibility is often sourced in either Fe-rich clays (chlorites etc), or Fe-oxides (magnetite or hematite), and often shows a dilution-relationship with calcite which has a small negative MS. Mudrocks lend themselves readily to MS analyses, since MS often responds to the gross lithological variations, with a superimposed provenance or sometimes diagenetic signature.
Two applications for magnetic susceptibility in shale resource plays will be considered in this paper: a) stratigraphic correlation and b) paleoflow determination. The first is carried out using data acquired from either small samples, measured in the laboratory, or by direct analysis of cores using a hand held MS meter. Paleoflow determinations utilise directional variation in magnetic susceptibility (Anisotropy of Magnetic Susceptibility- AMS) to make an interpretation of grain orientation. Re-orientation of the core is required to convert the preferred grain orientation into geographic coordinates.
Direct measurement of core using a handheld magnetic susceptibility meter enables large, high resolution (5-10 cm spacing) datasets to be gathered rapidly. Typically, these data show marked cyclicity, which in a Miocene carbonate sequence from Mallorca will be shown to be controlled by sea level fluctuations. Furthermore, because high resolution measurements are available, parasequences can be imaged in the magnetic susceptibility data. Changes in the symmetry of the transgressive - regressive portions of parasequences allow variations in "stacking patterns" to be compiled, thereby providing input into sequence stratigraphic interpretations. This aspect will be demonstrated using core analysis from a US shale play.
AMS measurements provide a rapid and precise determination of the three-dimensional orientation of grains in samples. When dealing with a shale play, any such grain-orientation data are difficult to determine using visual analyses. The AMS expresses the bedding-foliation, and the lineation (i.e. paleoflow direction) within the bedding plane. Hence, it can be used to infer structural information, as well as with-bedding preferred grain-orientation information. Here, we will show initial results from a European shale play that suggests AMS has the potential to be a powerful tool in paleoflow and sediment fabric analysis of mudrocks.
McMechan, G.A. (University of Texas at Dallas) | Garrison, J.R. (University of Texas at Dallas) | Ferguson, J.F. (University of Texas at Dallas) | Sharp, J.M. (University of Texas at Austin) | Hesse, M. (University of Texas at Austin)
We acquired high resolution geophysical data including ground-penetrating radar (GPR), electrical resistivity (ER), electromagnetic (EM), and seismic reflection and refraction data to create 3-D sedimentological/stratgraphic models to define hydrological models. The geophysical data are calibrated by vibracoring to provide samples for analysis of grain size, porosity, permeability, and electrical properties.
Glenton, P.N. (Esso Australia Pty Ltd) | Sutton, J.T. (Esso Australia Pty Ltd) | McPherson, J.G. (ExxonMobil Exploration Co.) | Fittall, M.E. (Esso Australia Pty Ltd) | Moore, M.A. (Esso Australia Pty Ltd) | Heavysege, R.G. (ExxonMobil Exploration and Production Malaysia, Inc.) | Box, D. (ExxonMobil Upstream Research Co.)
The Scarborough gas field was discovered by Scarborough-1 in 1979 in the Carnarvon Basin on the Australian North West Shelf. The field is 285 km offshore in water depths of 900 to 1000 m, and contains about 16 Tcf OGIP of very dry gas within a large, very low-relief faulted anticline covering about 800 sq. km. It has been appraised by four additional wells and a 3D seismic survey, and is being evaluated for development.
The Scarborough reservoir consists of Early Cretaceous deepwater turbidite sands deposited in a basin-floor fan setting. These sands were sourced from the expansive, northward-prograding Barrow Group fluvio-deltaic system located some 50 km to the south of Scarborough. The reservoir interval is a three-tiered fan sequence with variable sand content and quality: a high-quality, high net-to-gross Lower Fan unit which contains the majority of the gas-in-place, overlain by lower net-to-gross and lower quality Middle and Upper fans. The dominant reservoir lithofacies are quartzose medium- and fine-grained sandstones which are largely unlithified and uncemented, with average porosities of greater than 30% and permeabilities of 100's to 1000's of millidarcies. The background lithofacies are mudstones and siltstones which straddle the silt-mud boundary.
Static geological models and dynamic flow simulation models have been used to integrate seismic and well data, petrophysical analysis, and sedimentologic and stratigraphic interpretation. Outcrop analogues for deepwater basin-floor fan systems include the extensive, well-exposed and well-studied Permian Ecca Formation of the southern Karoo Basin, South Africa, the Carboniferous Ross Formation of western Ireland, and the Eocene Ainsa Formation of northern Spain. These outcrop analogues suggest that siltstone facies are bottom-loaded within genetically related depositional packages.
Reservoir models were used to investigate the effects of stratigraphic organisation and lithofacies distribution on reservoir performance predictions. By reference to outcrop analogues, an hierarchical approach was developed to systematically distribute depositional facies and lithofacies within the models. This permitted investigation of the effect of stratigraphic features of different scales on predicted production rates, reservoir performance and individual well performance.
Three hierarchical levels of facies models were incorporated into the stratigraphic zones. Two levels define deterministic and stochastic depositional facies geometries, and the third and finest level is lithofacies, or reservoir rock type. Seismic data were used to map large-scale depositional facies elements, and lithofacies were interpreted from well logs calibrated to conventional cores.
The use of lithofacies distributed within depositional facies provides flexibility in the modelling workflow, provides the template for distribution of the rock properties of porosity, horizontal and vertical permeability, and water saturation, and allows systematic investigation of the effect of siltstone baffles on predicted flow streams, particularly on the timing of water arrival.
Sutton, J. T. (Esso Australia Pty Ltd) | Glenton, P. N. (Esso Australia Pty Ltd) | Fittall, M. E. (Esso Australia Pty Ltd) | Moore, M. A. (Esso Australia Pty Ltd) | Box, D. (ExxonMobil Upstream Research Company)
The offshore Scarborough gas field in Western Australian's Carnarvon Basin was discovered in 1979 by the Scarborough-1 well. The field contains about 16 trillion cubic feet original gas-in-place (OGIP) of dry gas. It has been appraised by an additional four wells and the 2004-vintage HEX03A 3D seismic survey. Concepts are currently being evaluated for the field's development.
The field is contained within a large, 800 square-kilometre, very low-relief faulted anticline. The reservoir interval comprises deep water deposits, is divided into a high-quality, high net-to-gross Lower Fan, overlain by lower net-to-gross Middle Fan and Upper Fan. The field is expected to have strong flank and bottom-water drives. The development concepts being considered have minimal tolerance for water production; as such water production is expected to be managed via well shut-ins. Given the low relief of the structure, a significant factor in characterising reservoir performance will be the effect of stratigraphic baffles at various scales, on water movement. Static reservoir models for the Scarborough field were built to incorporate deepwater stratigraphic concepts derived from a plethora of basin-floor fan subsurface and outcrop analogues. These concepts have been applied with systematic distribution of depositional facies, including siltstone baffles bottom-loaded at multiple hierarchical levels.
Dynamic simulation models were built to investigate the sensitivity of sweep efficiency, timing of water arrival and ultimate recovery on a number of key static model parameters. The parameters that were evaluated included: 1) the effect of reduced stratigraphic organisation; 2) the partial removal of baffles at varying stratigraphic levels; 3) the lateral extent and continuity of baffles; and 4) the vertical permeability of siltstones.
The success of the study was facilitated through the effective workings of an integrated, multidisciplinary team of geoscientists and engineers, who maintained frequent communication and feedback through the modeling process.
The Urengoi field (Novo-Urengoiskiy license area - NU LA) is used in this article as an example to review available knowledge on the Achimov deposits based on seismic, geological and field development data, as well as reservoir-scale geological simulation. A comprehensive approach is required for detailed characterization of the deposit structure to enable forecast of best prospects and differentiated treatment of individual areas of the field as development efforts are planned for the future.
Three geological bodies were distinguished at the Urengoi field (NU LA) in the Achimov formation each having its own turbidite fans simulated in the 3D reservoir model.
Details of the reservoir internal structure, identification and localization of facial phases is of interest from the point of view of locating new exploration and development wells, planning additional research activities, identifying patterns and number of producing wells, selecting optimal development techniques and deciding upon the time schedule for the field development.
The article is based on the example of the geology structure studies of the field at its initial stage of development (greenfield) and its reservoir scale geological 3D simulation. The LA is situated 15 km away from the city of Novy Urengoi. The field is located in the eastern part of the West-Siberian basin. The Achimov deposits attributed to the Cretaceous period (the Neocomian) are considered a most promising interval in the territory.
Tight Gas Reservoirs (TGR) is attracting the attention of Oil & Gas industry from all quarters. Optimum exploitation depends upon the petrophysical evaluation and geological understanding. An insight into geological complexities of TGR is imperative to have a better evaluation of such reservoirs. This study details the tight gas sands (TGS) only as most of the TGR activities around the world are focused mainly on the clastics. It aims at explaining the different geological events that give rise to the tightness in the sandstone reservoirs and also presents a methodology to properly evaluate the geological complexities introduced. The TGS carry the imprint of both the primary depositional factors and secondary post-depositional ones. Grain size, sorting and distribution of detrital clay within a sequence stratigraphic framework govern the reservoir properties as depositional factors. Diagenesis is the key factor to control the tightness of the reservoirs after the deposition depending upon the compaction and cementation. Fractures are the post-depositional factors; the tectonic fractures along with the drilling induced ones provide an understanding of the stress regime and a clue towards planning the stimulation program. Conventional and sidewall cores with conventional open hole logs provide a larger understanding in terms of depositional environment and lithology variations. Detailed petrography with the help of XRD and SEM aids to understand the cementation pattern. Elemental capture spectroscopy and Spectral gamma logging can help correlating the cementation/ clay distribution within wells. Borehole images are quite helpful in capturing the textural variations which govern the differential diagenesis and also the drilling and natural fractures orientation and their association with rock facies. The study attempts to establish the need of proper geological evaluation which provides the building blocks for
petrophysical and reservoir engineering evaluation to optimize the exploitation strategy.
Deltaic successions are an important habitat for some of the major world's fossil fuel reserves (i.e. oil, gas and coal). An outcrop analogue study of the excellently exposed Permian siliciclastic Kookfontein deltaic sequence will therefore improve prediction of sandbody geometries and complex internal heterogeneities of subsurface examples.
Preliminary findings from field outcrop log data show the nature of complexity that could be encountered in a deltaic system that fills a basin. The complexity of the Kookfontein deltaic system is reflected in the succession of sedimentary structures (i.e. cross laminations, ripple laminations, Hummocky, massive and homogenous slump layers and horizontal laminations) both in time and space in a more or less an unpredictable manner.
In order to establish a 3D model of the rock record that includes stratigraphic elements and boundaries of all scales, we propose an approach that combines outcrop log, gamma ray log and photo-panel analysis. This approach will allow critical examination of the lateral and vertical variations of facies and their properties regarding fluid flow i.e. geometry and internal heterogeneity. The photo-panel analysis allows 3D high-resolution interpretations of the lithological boundaries both laterally and vertically which cannot be obtained from seismic resolution.
Based on the nature and complexity of the facies association, this study will propose a standard facies model for the deltaic sequence that will test the applicability of Walter's law of facies associations in facies analysis. A 3D reservoir-scale model will then be constructed based on the 3D geological model. The emphasis here will be to depict possible errors that could arise if all the stratigraphic elements and their boundaries (both on small and large scales) are not fully incorporated into reservoir scale modelling.
Kookfontein deltaic sequence, Facies analysis, Photo-panel analysis, Reservoir-scale geological model, 3D Reservoir model.