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Abstract Rock fabric and physical properties are known indicator of the fracturing potential of unconventional reservoirs under hydraulic fracturing stimulation. However, very limited study is documented on reservoir cut offs to find fracturing potential. Therfore, systematic workflow adopted to estimate reservoir properties and their relationship with brittleness index. For this purpose, the One-Dimensional Mechanical Earth Model (MEM) and multi-mineral petrophysical models is developed to estimate reservoir properties based on laboratory experiments and well logs. Rock brittleness (BI_T) is estimated using petrophysical properties and elastic properties. The reservoir cut offs determined to classify reservoir into brittle and ductile zones. The correlations indicated that higher concentration of minerals quartz and siderite, and young's modulus (YM_Cali) enhance brittle nature of rock, while higher concentration of organic richness (TOC), porosity (φT), clay contents, and Poisson's ratio enhance ductile nature of rock. The gamma ray log indicated a decreasing trend with an increase in brittleness index. However, there is no significant relationship observed between BI_T, pore pressure and strength/failure parameters except few zones, where BI_T decrease with an increase in pore pressure that is attributed to higher clay minerals in such zones. There is significant decrease in BI_T observed with an increase in fracturing pressure. It implies that brittle rock requires less fracturing pressure to induce hydraulic fractures or open natural fractures. Both shale formations had an organic richness of 3% to 5%, total porosity, φT, of 5% to 20%, and a BI_T of 0.15 to 0.7. It is observed that calibrated values lied between static and dynamic geomechanical properties, which is considered actual reservoir properties. The stress regime is strike slip due to higher magnitude of maximum horizontal stress (σH). Furthermore, the several correlations could be used to classify reservoir into brittle and ductile zones, which would enable the better selection of intervals for fracturing. The model indicated that the Roseneath shale was potentially better than the Murteree shale for stimulation purposes because of its high BI_T, and favourable stress concentration, which is attributed to its high content of quartz and siderite, and relatively less organic matter. However, generally, both shale formations fall in the region of "less brittle". It is recommended that reservoir properties could be computed from top to bottom of interval by integrating core and well logs data due to good agreement between core and well logs which could be used to assess fracturing potential of reservoir. The reservoir cut offs can be used as a proxy to find fracturing potential in unconvemntional reservoirs.
- Oceania > Australia > South Australia (1.00)
- North America > United States > Texas > Panola County (0.28)
- Phanerozoic > Mesozoic (0.67)
- Phanerozoic > Paleozoic > Permian (0.67)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Oceania Government > Australia Government (0.46)
- Oceania > Australia > South Australia > Warburton Basin (0.99)
- Oceania > Australia > South Australia > Great Artesian Basin (0.99)
- Oceania > Australia > South Australia > Eromanga Basin (0.99)
- (62 more...)
Reservoir Characterisation and Evaluation of Micaceous sandstone of Geleki Field, Upper Assam, India - An Integrated Study
Kumar, Pardeep (Oil & Natural Gas Corp. Ltd.) | Sharma, S.C. (Oil & Natural Gas Corp. Ltd.) | Roy, U.S. (Oil & Natural Gas Corp. Ltd.) | Sud, V.K. (Oil & Natural Gas Corp. Ltd.)
Abstract Tipam sandstone, the main hydrocarbon-producing reservoir of Geleki Field located in Upper Assam, India, is of highly complex nature containing good amount of mica (Muscovite) in addition to quartz, feldspar and montmorillonite as inferred from sedimentological studies. Mica complicates log analysis as most lithology indicators reflect it as high-density shale, resulting in pessimistic reservoir evaluation. Mica is often misinterpreted as shale by common clay indicators used in conventional deterministic interpretation models based upon Density-Neutron-GR logs. However, mica should be considered as structural part of the rock not affecting porosity and permeability. Surface of mica is altered by diagenesis and acquires surface conductance leading to reduced resistivity of the formation even at constant porosity. Therefore, if mica is not included in lithological model the evaluation can be misleading. Further, high computed shale volume will make good reservoirs either appear worthless or with reduced potential. In the present paper, the influence of mica on various log responses has been analysed, based upon which a highly micaceous sandstone facie has been identified in the upper portion of the reservoir. However, presence of mica and feldspar in moderate proportions is inferred throughout the formation. Multi-mineral interpretation model based upon statistical inverse modeling technique has been successfully used for realistic evaluation of reservoir parameters leading to identification of new hydrocarbon bearing layers. Oil production from a well tested on the basis of the present integrated study has confirmed the efficacy of the suggested model. Extension of the model to other similar reservoirs can lead to better reservoir characterization and delineation of by-passed hydrocarbons.
- Geology > Mineral > Silicate > Phyllosilicate (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.96)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.68)
Abstract Assam-Arakan basin having an area of approximately 100,000 sq km. is one of the main, proven and highly prospective petroleum province in the north eastern part of India. Upper Assam valley contains 7000 m of sediments under its alluvial cover. On the southern edge of platform, lies the mobile belt of Assam geosyncline with very thick sediments of the same age as in the shelf region. Over pressure horizons in northeast India occur mostly in the geosynclinal region in the western Tripura, Cachar as well as in schuppen belt and adjoining Arunachal Pradesh areas, mostly in the younger Tertiaries of Miocene-Pliocene age. In the Tripura area, abnormal high pressures to super high pressure horizons occur in Middle to Lower Bhubans of Surma group in almost all the structurs so far drilled. Deeper prospects are yet to be probed especially Barails which may have oil too, in case the popular belief of pressure regression brought out froni the PIVT studies, comes true. The studies, duly corroborated by weilsite evidences and seismics-VSP/PIVT for pressure prediction, have been quite successful for the pore pressure evaluation in this region. In the Schuppen belt (north-eastern part of Arunachal Pradesh) commercial production of oil is obtained from over pressure horizons of Mio-Pliocene age. Seismic and sonic log data, duly corroborated by the well site evidences, indicates very high pore pressure gradient up to 0.95 psi per ft in this area. Pressure reversal has also been observed in some of the structures isn the Tipams which may help in developing better porosities and likely to have good amount of exploitable reserves. High abnormal to super pressures are observed from Middle-Lower Bhubans, practically in all the structures of the Cachar area with pressure gradient reaching to almost geostatic or even exceeding. Compaction disequilibrium, aided partly by clay diagenesis has been responsible for generation of over pressures in Tripura area. However, in Cachar itnitial over pressuring took place due to compaction disequilibrium, subsequent major tectonic activity and uplifting of structures further intensified formation pressures. In the Schuppen belt of Assam and Arunachal Pradesh compaction disequilibrium as well as the tectonics has been responsible for generation of over pressures. The decreasing pore pressure gradients below the over pressures zones of Miocene-Pliocene age, as evidenced by the pressures regression plots of seismic/VSP and interpreted PIVT data, should encourage exploration for deeper prospect especially in the structures in Tripura and Cachar adjoining Bangladesh where oil is reported in some of the fields. P. 653
- Phanerozoic > Cenozoic > Neogene > Pliocene (0.65)
- Phanerozoic > Cenozoic > Neogene > Miocene (0.55)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Geological Subdiscipline > Geochemistry (0.93)
- Geology > Structural Geology > Tectonics > Compressional Tectonics > Fold and Thrust Belt (0.68)
- Geology > Mineral > Silicate > Phyllosilicate (0.48)
- Asia > India > Tripura > Assam-Arakan Basin (0.99)
- Asia > India > Assam > Upper Assam Basin > Digboi Field > Nahor Oil Sand (0.99)
- Asia > India > Assam > Upper Assam Basin > Digboi Field > Digboi Oil Sand Group (0.99)
- (4 more...)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
SUMMARY TxF two Tertiary petroliferous regions dealt with in this paper lie between the pre-Tertiary rocks of the Eastern Himalaya to the north, and those of the Shan Plateau of Burma to the east. They are now separated by the mountain ranges of the Arakan Yoma and Chin and Naga Hills, and this separation has probably been more or less effective from early Eocene time. In the Burnish Tertiary basin the key to the Tertiary succession is found in the great monocline of the "Western Outcrops" where the complete sequence is exposed on the eastern flank of the pre-Tertiary metamorphic rocks of the Arakan Yoma. Here a thick series of shales and sandstones with thin numnnilitic limestones of Eocene age is overlain by the Pegu Series (Oligocene and Miocene) of alternate argillaceous and arenaceous stages. The Irrawaddy Series of coarse arenaceous rocks of continental facies rests unconformably on Pegu, or Eocene, beds. Marine fossils are abundant in Upper Eocene and Pegu rocks and have enabled the formations of the Western Outcrops to be identified in the central oilfields and elsewhere. A widespread unconformity occurs in the middle of the Pegu Series. The marine sediments when traced northwards gradually assume a continental facies and cease to be petroliferous. The bulk of the petroliferous strata was deposited under shallow marine conditions which persisted, in the central part of the basin,. from Middle Eocene to Middle Miocene times. A striking feature of the geological structure of the ChindwinIrrawaddy Valley is the long synclinal trough which separates the western monocline from a broad series of folds to the east. The main oilfields of Burma are on the first anticlines which rise to the east of this syncline, and on its western margin are numerous oil-shows in the Western Outcrops. Oil seepages are rare to the east of the folds forming the eastern boundary of the main syncline; test wells on structures which do not rise directly from this syncline have found little or no oil. It is concluded that most of the oil in the main fields of Burma originated in the marine sediments of the median syncline, which probably marks the site of an extensive depression in the general area of deposition. The Tertiary deposits of Assam-Arakan, including part of eastern Bengal, comprise a great thickness of sandstones, conglomerates, sandy shales and shales. An important feature of the structure is the Haflong-Disang fault. North of this fault the lowest Tertiaries are Middle Eocene foraminiferal limestones developed along the south-east margin of the Shillong Plateau and Mikir Hills. South of the fault the thick Disang Shales occur: these may be of Cretaceous age in their lower part. The overlying Barail Series is mainly arenaceous but develops a more argillaceôus facies, with thick
- Phanerozoic > Cenozoic > Paleogene > Eocene > Lutetian (0.88)
- Phanerozoic > Cenozoic > Paleogene > Eocene > Bartonian (0.75)
- Geology > Structural Geology > Tectonics > Compressional Tectonics > Fold and Thrust Belt (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.87)
- Asia > Myanmar > Pyay Embayment > Central Lowland Province > Padaukpin Field (0.99)
- Asia > Myanmar > Mandalay Region > Palanyon Field (0.99)
- Asia > Myanmar > Magway Region > Myanmar Central Basin > Salin Basin > Yethaya Field (0.99)
- (13 more...)
Abstract According to EIA (Kuuskraa et al., 2013) and PDVSA Exploration (Molina et al., 2014), the Maracaibo Basin in Western Venezuela has two stratigraphic units of Late Cretaceous age which are considered as important unconventional shale plays in Latin America: La Luna Formation and La Grita Member of Capacho Formation. Venezuela is ranked in 7 place in shale oil resources, with an estimate above 13,000 MM barrels, and ranked in 13 place in shale gas resources, with an estimate above 201 TCF. In order to evaluate the mentioned shale plays, a methodology was developed through the integration of petrophysical, geochemical and geomechanical analysis. The complete evaluation methodology has 4 phases: 1) petrophysical evaluation, that includes multimineral evaluation, porosity estimation and calibration with mineralogical analysis; 2) TOC content evaluation, that includes TOC content estimation, using 3 methods: density logs (Schmoker, 1979), gamma ray logs (Schmoker, 1981), sonic and resistivity logs (Passey et al., 1990), and porosity associated with organic matter; 3) geomechanical evaluation, that includes rock mechanical properties estimation, state of stress determination and brittleness index estimation, using 3 methods: mineral content (Jarvie et al., 2007), elastic properties (Rickman et al., 2008) and a modified method of Grieser-Bray (2007), calibrated with geomechanical field test (XLOT, microfracs and minifracs); and 4) determination of most prospective intervals for completion. La Luna Formation and La Grita Member of Capacho Formation are mainly composed by carbonatic rocks, with high content of calcite (above 75%) and low content of clay minerals. In both units, the estimation of TOC content varies from 0.50 to 9%. Mechanical properties show moderate values of Poisson's ratio (0.20 to 0.32), high values of Young's modulus (0.80 to 9.60 10 psi) and UCS (6.20 to 31.00 10 psi). In the Cretaceous sequence, the state of stress changes according to geographic location in the basin, from normal in northwest region and central lake region, to transcurrent and reverse in southeast region. The brittleness index estimated for different methods varies from 0.54 to 0.85, which indicate that both units may be classify as brittle. The integration of geomechanical and petrophysical analysis allowed identifying prospective intervals in both units, with thickness between 20 to 100 ft. Therefore, the study indicates that both units show very good conditions for horizontal drilling and hydraulic fracturing. Moreover, the comparison of various estimation methods of TOC content and brittleness index allowed to observe the uncertainty presented by these parameters in analysis of shale plays.
- South America > Venezuela > Zulia > Maracaibo (0.63)
- South America > Venezuela > Zulian Region > Lake Maracaibo (0.62)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.94)
- (2 more...)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.54)
- South America > Venezuela > Zulia > Maracaibo Basin > Mara Field (0.99)
- South America > Venezuela > Zulia > Maracaibo Basin > Ayacucho Blocks > Boscan Field > Rob-l Formation (0.99)
- South America > Venezuela > Zulia > Maracaibo Basin > Ayacucho Blocks > Boscan Field > Misoa Formation (0.99)
- (29 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale oil (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)