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ABSTRACT Nonmiscible fluid displacement without salt exchange takes place when oil-base mud (OBM) invades connate water-saturated rocks. This is a favorable condition for the estimation of dynamic petrophysical properties, including saturation-dependent capillary pressure. We developed and successfully tested a new method to estimate porosity, fluid saturation, permeability, capillary pressure, and relative permeability of water-bearing sands invaded with OBM from multiple borehole geophysical measurements. The estimation method simulates the process of mud-filtrate invasion to calculate the corresponding radial distribution of water saturation. Porosity, permeability, capillary pressure, and relative permeability are iteratively adjusted in the simulation of invasion until density, photoelectric factor, neutron porosity, and apparent resistivity logs are accurately reproduced with numerical simulations that honor the postinvasion radial distribution of water saturation. Examples of application include oil- and gas-bearing reservoirs that exhibit a complete capillary fluid transition between water at the bottom and hydrocarbon at irreducible water saturation at the top. We show that the estimated dynamic petrophysical properties in the water-bearing portion of the reservoir are in agreement with vertical variations of water saturation above the free water-hydrocarbon contact, thereby validating our estimation method. Additionally, it is shown that the radial distribution of water saturation inferred from apparent resistivity and nuclear logs can be used for fluid-substitution analysis of acoustic compressional and shear logs.
- Europe (1.00)
- North America > United States > Texas (0.93)
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.69)
- Geology > Mineral > Silicate (0.68)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.33)
- Europe > United Kingdom > North Sea > North Sea > Northern North Sea > South Viking Graben > Block 16/28 > Andrew Field (0.99)
- Europe > United Kingdom > North Sea > North Sea > Northern North Sea > South Viking Graben > Block 16/27a > Andrew Field (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Northern North Sea > South Viking Graben > Block 16/28 > Andrew Field (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Northern North Sea > South Viking Graben > Block 16/27a > Andrew Field (0.99)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
Petrophysical Properties of Unconventional Low-Mobility Reservoirs (Shale Gas and Heavy Oil) by Using Newly Developed Adaptive Testing Approach
Hadibeik, Hamid (The University of Texas at Austin) | Chen, Dingding (Halliburton Energy Services) | Proett, Mark (Halliburton Energy Services) | Eyuboglu, Sami (Halliburton Energy Services) | Torres-Verdín, Carlos (The University of Texas at Austin)
Abstract Pressure testing in very low-mobility reservoirs is challenging with conventional formation-testing methods. The primary difficulty is the over-extended build-up times required to overcome wellbore and formation storage effects. Possible wellbore overbalance or supercharge are additional complicating factors in determining reservoir pressure. This paper addresses the above technical complications and estimates petrophysical properties of low-mobility formations using a newly developed adaptive-testing approach. The adaptive-testing approach employs an automated pulse-testing method for very low-mobility reservoirs and uses short drawdowns and injections followed by short pressure stabilization periods. Measured pressure transients are used in an optimized feedback loop to automatically adjust subsequent drawdown and injection pulses to reach a stabilized pressure as quickly as possible. The automated pulse data is used to determine supercharge effects, formation pressure, and mobility via analytical models by analyzing the entire pressure sequence. A genetic algorithm estimates additional reservoir parameters, such as porosity and viscosity, and confirms results obtained with analytical models (reservoir pressure and permeability). The modeled formation pressure exhibits less than 1% difference with respect to true formation pressure, while the accuracy of other parameters depends on the number of unknown properties. As a quicker method to estimate reservoir properties, a direct neural-network regression of pulse-testing data was also investigated. Synthetic reservoir models for low-mobility formations (M < 1 μD/cp), which included the dynamics of water- and oil- based mud-filtrate invasion that produce wellbore supercharging were developed. These reservoir models simulated the pulse-testing methods, including an automated feedback-optimization algorithm that reduces the testing times in a wide range of downhole conditions. The reservoir models included both simulations of underbalanced and overbalanced drilling conditions and enabled the development of new field-testing strategies based on a priori reservoir knowledge. The synthetic modeling demonstrates the viability of the new pulse-testing method and confirms that difficult properties, such as supercharging, can be estimated more accurately when coupled with the new inversion techniques.
Improved Estimation Of Pore Connectivity And Permeability In Deepwater Carbonates With The Construction Of Multi-Layer Static And Dynamic Petrophysical Models
Diniz-Ferreira, Elton Luiz (Schlumberger) | Torres-Verdín, Carlos (PETROBRAS – Petróleo Brasileiro S.A. and The University of Texas at Austin)
Due to sea-level variations, cycles of sedimentation can often be recognized from well logs. It is possible to differentiate rock types based on such geological cyclicity; for petrophysical purposes we will refer to those rock types as fluid flow units. In the presence of thin layers, flow units can only be detected with core data. The cause of sea-level variation in this field is not well understood and remains a subject of study by geologists. Wells were drilled with both oil-base mud (OBM) and water-base mud (WBM). The oil bearing-zone of wells drilled with WBM gave rise to a conspicuous invasion profile on resistivity logs. It is possible to simulate this invasion profile in different layers and estimate their permeability. Conversely, wells drilled with OBM did not show a conclusive invasion profile in the oilbearing zone because of the lack of electrical resistivity contrast between oil and mud filtrate. Due to the complexity of the pore space and the spatial heterogeneity of the reservoir under consideration, conventional well-log evaluation seldom reproduces petrophysical properties consistent with core data. It is necessary to construct multi-layer petrophysical models based on geological information to improve the interpretation. A model that combined well logs and geological properties was key to select bed boundaries and to construct an earth model. The latter model was used to perform static and dynamic simulations - matching simulated resistivity, nuclear, and NMR logs with field measurements. Petrophysical properties estimated with those simulations were in agreement with core laboratory measurements. Interpretation was performed in the oil-bearing zone of three wells: two of them-Wells Η and Γ – were drilled with OBM, the remaining well-Well Χ – drilled with WBM (Table 1). It is not possible to perform a correlation between the evaluated wells using well-logs.
- South America (0.93)
- North America > United States > Texas (0.29)