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This paper describes a well-based analysis program, written in the C programming language, called " Quantitative Petrophysical and Seismic Evaluation Technique" (QPSET). The program is designed to accomplish the evaluation of reservoir parameters in shaly-sand sedimentary sections in marginal hydrocarbon zones. The program flow is designed to complete an analysis in a single pass and uses two modified approaches for the evaluation of water saturation and acoustic impedance. Output values are stored in ASCII format and are therefore available for plotting in any graphic software package. Either the user selects the precise analysis algorithms employed, or they may be restricted by the data available. This paper reports results obtained using the program on data from seven wells located in the northern portion of the Gulf of Suez Rift Basin, spanning the Lower Middle Miocene Rudeis sedimentary section. (Rudeis thickness ranges from 500 ft. to 5000 ft. within the basin.) The program has successfully characterized the essential features of the Rudeis and permits some speculation as to the depositional environment for the sediments and the tectonic setting of the basin at the present day. In this latter regard, it is stressed that other information is required before adequate interpretations can be established.
- Africa > Middle East > Egypt > Gulf of Suez > Southern Gulf of Suez (0.40)
- Africa > Middle East > Egypt > Eastern Desert > Southern Province (0.40)
- Personal (1.00)
- Overview > Innovation (1.00)
- Research Report > Experimental Study (0.67)
- Phanerozoic > Cenozoic > Neogene > Miocene (0.54)
- Phanerozoic > Mesozoic (0.45)
- Geology > Structural Geology > Tectonics (1.00)
- Geology > Sedimentary Geology > Depositional Environment (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (1.00)
- (5 more...)
- Geophysics > Seismic Surveying > Seismic Processing (1.00)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Seismic Modeling > Velocity Modeling (0.67)
- South America > Colombia > N Formation (0.99)
- South America > Argentina > Salta > Noroeste Basin > Agua Blanca Field (0.99)
- North America > United States > Wyoming > Wind River Basin (0.99)
- (11 more...)
- Information Technology > Software (1.00)
- Information Technology > Modeling & Simulation (1.00)
- Information Technology > Data Science (1.00)
- (2 more...)
Abstract Significant amounts of gas accumulations exist in unconventional gas plays. Current understanding held that in unconventional shale plays, natural gas was stored as "free" gas in pore spaces and as an "adsorbed" phase on clay minerals and surface of organic pores material. The adsorption of methane has been confirmed in lab experiments in high-pressured gas chambers. Our lab experiments indicated that hexane vapor could be adsorbed onto organic-rich shale core samples through capillary condensation and the signal could be detected by Nuclear Magnetic Resonance (NMR) instruments. This study further examines the capillary condensation of hexane vapor into clay minerals and the NMR response. Smectite samples from the Clay Minerals Society were used in the experiments. Two types of capillary condensation experiments were conducted: one with water vapor and the other with hexane vapor, both at room conditions. Weight gains indicated that some of the vapor condensed in the loose powder of smectite clay. NMR experiments were performed on vapor-saturated samples using a Maran 2 MHz spectrometer with an inter-echo time of 300 ฮผsec. The T2 distributions of the water-vapor and hexane vapor-saturated smectite clay were both unimodal. The water vapor-saturated sample showed a T2 at 0.5 ms, while the hexane vapor-saturated sample showed a T2 between 1 and 6 ms. This was likely due to the fact that the smectite crystallites have a small charge that has a more pronounced effect on polarized molecules such as water, than on non-polarized molecules such as hexane.
Bi-Center Drill Bits and MWD/LWD Tools in a Horizontal Application Prove Effective in Reducing Well Costs and Increasing Liner-Size Capability Rick Parrish,*,** Chevron Niugini Pty. Ltd., and Coy Fielder* and Rod Ishmael,* Diamond Products Intl. Inc. Abstract A horizontal drilling program at the Kutubu Project in Papua New Guinea (PNG) called for the use of bi-center drill bit technology to be applied with MWD/LWD tools in a drill-in fluid system. This was the first time that bi-center polycrystalline-diamond-compact (PDC) bits were utilized in a horizontal drilling application. Bit performance while drilling with MWD/LWD tools was enhanced through the use of a sized-salt biopolymer drill-in fluid system. The fluid system was being enlisted for the first time in PNG. The tool combination was able to drill a larger 9 1/8-in. hole out of the 9 5/8-in.-OD casing, as opposed to the 8 1/2-in. holes in four previous horizontal wells (includes one sidetrack) drilled with conventional PDC bits. The larger hole drilled by the 8 3/8-by-9 1/8-in. bi-center bits allowed a 7-in. production liner to be run, instead of the 5 1/2-in. liners run in the previous horizontal wells. The larger liner permits installation of larger production tubing required to selectively produce the desired 8,000-bopd flowrate, as well as a packer/sliding-sleeve completion system. In addition to the benefit of multizone-completion ability and increased flowrate capability, drilling time in the horizontal section was reduced by 13 days using the bi-center-bit/MWD-LWD combination. This reduction in drilling time alone amounted to more than a $ 1.56 million savings to the operator. Bi-center drill bit applications can now yield predictable results in demanding directional environments. The ability to log-while-steering in a horizontal lateral while providing an enlarged hole diameter, without need for additional trips in and out of the hole, results in an extremely cost-effective drilling system. Project background Oil was discovered at the Kutubu Project in 1986 by the Iagifu 2X exploratory well in a remote location in PNG's Southern Highlands Province about 300 mi northwest of Port Moresby, Fig. 1. The petroleum development license (PDL) was approved in December 1990 and first commercial production began in June 1992. Average Kutubu production for 1996 was 107,000 bopd. Before the PDL could be approved, extensive appraisal drilling was required. Including sidetracks, some 31 delineation wells were drilled in the Iagifu/Hedinia and Agogo fields to determine the extent of the Kutubu oil reserves. A large number of appraisal wells were needed due to the significant structural complexity in each well. Massive karsted limestone beds also covered the surface of much of the license area that made acquisition of useful seismic data virtually impossible. Current Kutubu original oil-in-place (OOIP) estimates are slated at about 515 MMSTB based on information from appraisal and development drilling. This is a combined estimate for seven distinct reservoir blocks in two fields. About 80% of the total OOIP, or 420 MMSTB, is from the Toro formation and about 73% is contained in one fault block, the Main Block Toro in the Iagifu/Hedinia field. P. 551^
- Oceania > Papua New Guinea > Southern Highlands (1.00)
- Oceania > Papua New Guinea > Central Province > National Capital District > Port Moresby (0.25)
- Oceania > Papua New Guinea > Southern Highlands > Papuan Basin > PL 2 > Agogo Field (0.99)
- Oceania > Papua New Guinea > Southern Highlands > Papuan Basin > PDL 2 > Agogo Field (0.99)
Fluid Characterization and Volumetric Assessment in the MontneyโฆOne Tricky Fluid System
White, Aaron J. (Pipestone Energy Corp.) | Feick, Wesley (McDaniel & Associates) | Prefontaine, Nina (McDaniel & Associates) | Thomas, F. Brent (Resopstrategies) | Marin, Juan (Resopstrategies) | Ponto, Jared (Pipestone Energy Corp.) | Apil, Ronnel (Stratum Reservoir) | Clarkson, Carter (Stratum Reservoir)
Abstract Fluid characterization and correct volumetric assessment can be very difficult to quantify in saturated fluid systems. Commonly, during initial fluid sampling, the flowing sand face pressure condition is less than saturation pressure, leading to multiphase flow. In this common unconventional production situation, appropriate in-situ fluid characterization is critical for valid resource assessment. Simplified protocols have been developed for saturated fluid characterization and a continuous volumetric assessment approach is developed across variable fluid phases. A broad range of Montney fluid systems, defined by valid Pressure-Volume-Temperature (PVT) characterization, are described relative to field production results and commonly available routine fluid sample diagnostics. In order to accurately describe in-situ fluid character three recombination paths are followed after field sampling of separator liquids and gases at multiple drawdowns. The three paths are: increasing pressure to force single-phase behavior with subsequent equilibration at reservoir pressure; incremental addition of separator gas to separator liquid while maintaining reservoir pressure; equilibration at reservoir pressure at the lowest sampling gas-oil ratio (GOR). The application of a fluid characterization method utilizing the concept of a pseudo formation volume factor for gas system hydrocarbon in-place assessment is described. Continuous volumetric assessment across variable phases is established with a simple predictive link to the formation volume factor and the pseudo formation volume factor concept with the normalized molecular weight of the pressured lower phase separator liquid C4+. Linking valid PVT laboratory protocols with observed producing fluid components is critical for accurate fluid characterization and volumetric assessment. In complex fluid systems consisting of both coexisting gas and oil systems, oil in-place estimates can fluctuate +/-50% based upon the relative allocation of phase, demonstrating the importance of appropriate characterization and resource assessment in the monetization of assets. Volatile fluid systems, that is, saturated or near saturated reservoirs, can produce fluid samples that exhibit complex recombined fluid character. Field and lab workflows for sampling and characterization materially impact the assessment of hydrocarbon in-place. This paper provides a simple accurate approach to characterize volatile fluid systems to ultimately drive field development decisions. The team who produced this paper were comprised of laboratory, production testing, field sampling, exploration/development and reserves/asset evaluation individuals.
- North America > Canada > Alberta (0.47)
- North America > Canada > British Columbia (0.47)
- North America > Canada > Saskatchewan > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > Canada > Northwest Territories > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > Canada > Manitoba > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- (2 more...)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid management & disposal (1.00)
- Reservoir Description and Dynamics > Reserves Evaluation > Estimates of resource in place (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- (2 more...)
Abstract The Nahorkatiya oilfield had an initial stock tank oil in place of about 200 MMm and has been on production since 1953. The field is a structural-stratigraphic trap formed by block faulting resulting in a number of individual reservoir blocks of various sizes. The reservoir crude is saturated and combination drive with varying degree of aquifer support has been the primary drive mechanism. Pressure maintenance by gas and water injection and limited water/polymer flooding have been in operation in the major blocks. Overall field recovery is 31%, although in a few blocks recovery as high as 46% has been achieved through secondary recovery measures. This paper presents the reservoir management strategies undertaken at various stages of development to optimize production profiles and ultimate recovery. P. 569
- Asia > India > Assam (1.00)
- North America > United States > Texas > Coleman County (0.24)
- Geology > Geological Subdiscipline (0.66)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.32)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying (0.68)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.35)
- North America > United States > Texas > Fort Worth Basin > Overall Field (0.99)
- Asia > India > Assam > Upper Assam Basin > Nahorkatiya Field (0.99)