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Valhalla Field, discovered in 1979 and located in northwest Alberta, produces from the Upper Cretaceous Doe Creek Member of the Kaskapau Formation. Original reserves in place are 44 x 106m3 of oil, of which 10.3 x 106m3 of oil (82% of recoverable reserves) have been produced (ERCB, 2008). This study evaluates the depositional and diagenetic controls on reservoir quality within the Doe Creek at Valhalla Field in order to identify reservoir-prone facies and predict their distribution in wells lacking core. Analysis of core and well log data indicates that intervals of highest reservoir quality are preferentially associated with thin (meter-scale) sandstone bodies deposited in proximal lower and upper shoreface environments. Based upon the relationships of facies to deep resistivity, mud content as gamma-ray derived shale volume, and density-neutron porosity separation within cemented zones, a well log transform was created that successfully predicts the distribution of reservoir-prone facies and calcite cement.
The Doe Creek Member of the Late Cretaceous (Cenomanian) Kaskapau Formation is located in northwestern Alberta. Valhalla Field was discovered in 1979 and is the major producer of hydrocarbons from the Doe Creek Member. This study assesses the spatial and temporal distribution of reservoir facies by evaluating the sequence stratigraphic controls on reservoir quality and continuity across Valhalla Field. A total of ten retrogradationally-stacked parasequences and/or associated bedsets occur within the Doe Creek Member, of which, four include reservoir quality sandstone (I-1, I-Sand, I+1 and I+2). For these sandstones, maps are provided that depict the spatial distribution of reservoir facies, average effective porosity, gross pore volume and fraction of calcite cement. Comparison of these maps with fieldwide trends of total fluid and cumulative oil production suggest a strong correlation, and validate the utility of the sequence-keyed stratigraphic framework presented in this study as a guide for enhanced oil recovery.
The purpose of this study was to describe depositional and diagenetic characteristics of the (Jurassic) Smackover formation and subsequently identify and rank the quality of flow units within Grayson field, Columbia County, Arkansas. The field has production from the Smackover, a reservoir which consists mainly of highly altered peloidal grainstones. This was a four part study including a lithological analysis of ten cores, a petrographical study of 97 thin sections, a petrophysical study of reservoir properties from core analyses and borehole logs, and predictive mapping of quality ranked flow units across the field. Examination of the cores and thin sections revealed H1[subscript]a as the main pore type in Grayson field, which was a hybrid of both depositional and diagenetic processes with dominantly interparticle pores. The lowest ranked reservoir quality corresponded to intraparticle and intercrystalline pore types, which occurred mainly in the wackestone/mudstone and packstone/wackestone facies. The highest ranked reservoir quality corresponded to the H1[subscript]a pore type which occurred mainly in the grainestone/packstone facies 1 and 2. The reservoir quality maps identified the spatial distribution of the facies within the field, which could be used to locate zones for possible in-fill drilling. These results should aid in the economical development of Grayson field and other similar fields.
Diagenesis research is the foundation of hydrocarbon reservoir characterization and exploration. Reactive transport modeling (RTM) is an emerging approach for diagenesis research, with unique capability of quantification and forward modeling of the coupled thermo-hydro-chemical processes of diagenesis. Using TOUGHREACT simulator, this thesis investigates the two most important fluid-rock interactions in carbonate rocks, i.e., dolomitization and karstification, based on generic model analyses and a case study in the Ordos Basin, China. In particular, this study attempts to quantitatively characterize the diagenetic processes and to reconstruct the diagenesis-porosity evolution of carbonate reservoirs. Some controversies in carbonate diagenesis research, which cannot be well explained by classical geological methods, have also been discussed. The results are helpful to better understand the spatial-temporal distribution and co-evolution of diagenesis-mineral-porosity during the complicated diagenetic processes with their potential controlling factors, and to reduce the uncertainty of reservoir quality prediction.
The Upper Devonian-Lower Mississippian Bakken Formation in the Williston Basin is an important source rock for oil production in North America. The Bakken Formation is comprised of three units: Upper and Lower Bakken black shales and Middle Bakken Member. Upper and Lower Bakken shales are high quality source rocks which source reservoirs in the Middle Bakken, Upper Three Forks and lower Lodgepole Formations. The Middle Bakken Member, consisting of predominantly gray, silty and sandy dolostone, is under investigation in this study. The goals of this study are to determine the regional distribution of lithofacies and depositional environments of the Middle Bakken Member and explain diagenetic sequence and reservoir quality parameters in the Williston Basin. The reservoir quality of the Middle Bakken Member is mainly influenced by mineralogical composition and cementation resulting in low porosity and permeability and linked to lithofacies distribution in the basin. Dolomitization is pervasive throughout the unit, and also occurs as dolomite cement. Moreover, cementation occurred including quartz overgrowths, K-felspar, clay cement and pyrite as both cement and nodules. Not only dolomitization but also pyrite cementation plays an important role in reducing pore space in the reservoir. The pore types that were identified are intergranular, intragranular, fracture and moldic pores. Secondary intragranular porosity generally resulted from dissolution of biogenic fragments and dissolution of other unstable minerals including feldspar and dolomite. In this study, five lithofacies and one sandy interval within lithofacies C were described throughout the North Dakota portion of the Williston basin. The sandy interval in Lithofacies C was interpreted as bars or channel fills, which differentiates this study from previous studies in terms of core description. N-S, W-E, NE-SW, NW-SE oriented cross-sections drawn via cores suggest that the lithofacies of the Middle Bakken Member pinch out towards the edges. However, the anticlines in the basin affect their thickness distributions. Sandy interval in Lithofacies C reaches its thickest succession in the center of the basin. Lithofacies C and D consist of up to 80% of dolomite although the other lithofacies consist of relatively lower dolomite (up to 65%). While well logs indicate 4-8% of porosity, point-counting results show up to 5% of porosity. The sequence of diagenetic events in the North Dakota portion of the Williston Basin is from youngest to oldest: micritization, mechanical and chemical compaction, calcite cementation, dolomitization, pyrite cementation, microcrystalline quartz cementation, syntaxial calcite overgrowth, quartz overgrowth, K-Feldspar overgrowth, dolomite dissolution, feldspar dissolution, dedolomitization, fracturing, anhydrite cementation and hydrocarbon migration.
In the Permian Basin, strata of Leonardian age typically consist of interbedded carbonates and siliciclastics interpreted to be turbidite deposits. Happy Spraberry Field produces from a 100-foot thick carbonate section in the Lower Clear Fork Formation (Lower Leonardian) on the Eastern Shelf of the Midland Basin. Reservoir facies include oolitic- to-skeletal grainstones and packstones, rudstones and in situ Tubiphytes bindstones. Depositional environments vary from open marine reefs to shallow marine oolitic shoal mounds. Best reservoir rocks are found in the oolitic-skeletal packstones. Diagenesis occurred in several phases and includes (1) micritization, (2) stabilization of skeletal fragments, (3) recrystallization of lime mud, (4) intense and selective dissolution, (5) precipitation of four different stages of calcite cement, (6) mechanical compaction, (7) late formation of anhydrite and (8) saddle dolomite and (9) replacement by chalcedony. Oomoldic porosity is the dominant pore type in oolitic grainstones and packstones. Incomplete dissolution of some ooids left ring-shaped structures that indicate ooids were originally bi-mineralic. Bacterial sulfate reduction is suggested by the presence of (1) dissolved anhydrite, (2) saddle dolomite, (3) late-stage coarse-calcite cement and (4) small clusters of pyrite. Diagenetic overprinting on depositional porosity is clearly evident in all reservoir facies and is especially important in the less-cemented parts of the oolitic grainstones where partially-dissolved ooids were subjected to mechanical compaction resulting in "eggshell" remnants. Pore filling by late anhydrite is most extensive in zones where dissolution and compaction were intense. Finally, a porosity-permeability model was constructed to present variations in oolitic packstone- rudstone-bindstone reservoir rocks. The poroperm model could not be applied to oolitic grainstone intervals because no consistent trends in the spatial distribution of porosity and permeability were identified. Routine core analysis did not produce any reliable value of water saturation (S[subscript]w). An attempt to take advantage of wireline log data indicates that the saturation exponent (n) may be variable in this reservoir.
Understanding chalk depositional and diagenetic processes, and how they relate to porosity formation and pore evolution provide a foundation for more accurately predicting the occurrence and distribution of hydrocarbon source and reservoir rocks within the Niobrara.