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The reservoir evaluations NITEC has performed vary in size, complexity, and reservoir type reflecting the variations found in petroleum reservoirs worldwide. Our projects have included volatile oil, medium & heavy oils, gas-condensate, gas, and gas storage fields found in clastic and carbonate lithologies with varying degrees of faulting and fracture complexity. Due to the complexity of many of our projects, we have found that the available technologies or processes are often inadequate to resolve various reservoir issues. Hence, NITEC has developed appropriate technologies and software to address these problems. Typical projects include:
- Unconventional oil reservoir: A long horizontal
well in the Bakken formation with a multistage hydraulic fracture
completion and two years of performance was history matched and
performance predictions made. Microseismic data was collected during
the fracs and used to develop multiple induced fracture
characterizations. NITEC’s MatchingPro technology was used to
investigate up to 25 uncertain reservoir and hydraulic fracture
parameters. MatchingPro allowed multiple acceptable history match
solutions to be created. These history matched models were used to
investigate the impact on future performance of the different
history match solutions.
- Tight gas reservoir: NITEC simulated the
performance of a long horizontal well in the Williams Fork portion
of the Mesa Verde interval. The well was hydraulically fractured in
multiple stages and microseismic data was collected. The geologic
characterization of the thick, highly lenticular section was
simulated at the geocellular scale rather than conducting upscaling.
The hydraulic fracture characterization and the compressibility of
the fractures were key to history matching the well performance and
to its projected EUR.
- Fracture characterization: A highly fractured and faulted reservoir in Mexico with an active aquifer was successfully characterized with NITEC's in-house technology. Reservoir simulation resulted in identification of highly productive zones which were confirmed by drilling.
- Gas storage: A unique helium gas storage project in the U.S. required an improved reservoir characterization in order to history match 78 years of production/injection performance. Future production plans were optimized to achieve a U.S. Congress mandated depletion policy.
- Thermal recovery: A verification of process was carried out for a thermal recovery process - insitu upgrading of hydrocarbons. Thermal simulation correctly correlated with laboratory results and a U.S. field evaluation considered Huff-n-Puff and continuous injection.
- Compositional simulation: This light-oil field in Venezuela with a thin oil rim and overlying gas condensate zone was characterized and simulated. Understanding reservoir performance required identification and characterization of asphaltene deposition in the oil rim and detailed simulation of over 100 wells with multiple production strings. Simulation predictions provided new completion alternatives and workovers to improve future oil recovery.
- CO2 Injection: An integrated reservoir study was carried out on a near depleted oil field in Wyoming discovered in 1916 with over 700 completions. The simulation model history match indicated substantial remaining oil in place. Extended black-oil simulation of CO2 WAG and continuous CO2 injection processes indicated significant tertiary oil recovery potential. Full-field development is in the planning stages.
- Fracture characterization: Limited performance and wellbore data in a recent oil discovery in India suggested the existence of a natural fracture system. Seismic, wellbore, and performance data, along with NITEC’s unified capillary pressure technology were used to confirm and describe the vertical and areal fracture distribution. Field development is being planned accordingly.
- Secondary or tertiary recovery: A prolific oil field in Wyoming with significant primary and secondary recovery was evaluated for bypassed secondary and tertiary oil potential. The natural fractures in the formation and the historical water injection resulted in little additional secondary oil recovery potential. Accordingly, the remaining oil in place was found to be insufficient to warrant an economically viable CO2 injection program. Other tertiary recovery processes are under consideration.
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