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ABSTRACT: Nuclear magnetic resonance (NMR) is widely used to assess petrophysical and fluid properties of porous rocks. In the case of fluid typing, two-dimensional (2D) NMR interpretation techniques have advantages over conventional one-dimensional (1D) interpretation as they provide additional discriminatory information about saturating fluids. However, often there is ambiguity as to whether fluids appraised with NMR measurements are mobile or residual. In some instances, high vertical heterogeneity of rock properties (e.g. across thinlybedded formations) can make it difficult to separate NMR fluid signatures from those due to pore-size distributions and fluids. There are also cases where conventional fluid identification methods based on resistivity and nuclear logs indicate dominant presence of water while NMR measurements indicate presence of water, hydrocarbon, and mud filtrate. Depending on drilling mud being used, and the radial extent of mud-filtrate invasion, the NMR response of virgin reservoir fluids can be masked by that of mud filtrate. In order to separate those effects, it is important to reconcile NMR measurements with electrical and nuclear logs for improved assessment of porosity and mobile hydrocarbon saturation. We quantify the exact radial zone of response of NMR measurements and corresponding fluid saturations with studies of mud-filtrate invasion that honor resistivity and nuclear logs. Examples of application examine field data acquired in thinly-bedded gas formations of the Wamsutter basin invaded with water-base mud, wherein residual hydrocarbon saturation is relatively high. Additionally, fluid identification and partial porosity calculations obtained from a T1-T2 map indicate that NMR measurements originate from a radial annulus approximately 5 inches into the formation where the pore space is predominantly saturated with water but in which gas saturation is still higher than residual saturation. It was also found that the uncertainty of total NMR porosity could be as high as 3 pu because of noise and thin-bed effects.
- Geology > Rock Type > Sedimentary Rock (0.94)
- Geology > Geological Subdiscipline (0.88)
- North America > United States > Wyoming > Sand Wash Basin (0.99)
- North America > United States > Wyoming > Greater Green River Basin > Wamsutter Basin > Wamsutter Field (0.99)
- North America > United States > Wyoming > Greater Green River Basin > Almond Formation (0.99)
- (2 more...)
Formation-Tester Pulse Testing in Tight Formations (Shales and Heavy Oil): Where Wellbore Storage Effects Favor the Determination of Reservoir Pressure
Hadibeik, Hamid (The University of Texas at Austin) | Proett, Mark (Halliburton Energy Services) | Chen, Dingding (Halliburton Energy Services) | Eyuboglu, Sami (Halliburton Energy Services) | Torres-Verdín, Carlos (The University of Texas at Austin) | Pour, Rooholah A. (The University of Texas at Austin)
Abstract Tight formation testing when mobilities are lower than 0.01 mD/cP poses significant challenges because the conventional pressure transient buildup testing becomes impractical as a result of the large buildup stabilization time. This paper introduces a new automated pulse test method for testing in tight formations that significantly reduces testing time and makes the determination of formation pressure and permeability possible. A pulse test is defined as a drawdown followed by an injection test, and the source is shut in to record the pressure transient. Based on pressure data during the shut-in period, the next drawdown or injection test is designed, such that the flow rate is a fraction of the initial pulse rate, followed by another shut-in test. This procedure continues until the difference in pressure at the beginning and at the end of the shut-in period is reduced to within a specified limit of pressure change; then, an extended transient is recorded to a stabilized shut-in pressure. The overall advantage is to reduce the pressure stabilization time by implementing an adaptive pressure feedback loop in the system. The method can be applied to a straddle packer test using conventional drillstem testing tools or formation testers, using either straddle packers or probes. The effects of wellbore storage and fluid compressibility are found to reduce the pressure drop and positive pressure pulse in the drawdown and injection tests, respectively; they also affect the decay rate to the asymptote of the shut-in pressure response. Consequently, the combined pulse test method with the pressure feedback system and wellbore storage effect reduces the reservoir pressure testing time in tight formations. The automated pulse-test method has been successfully validated with consideration of the effects of wellbore storage and overbalance pressure in tight gas and heavy oil formations. In addition, the effects of invasion with water- and oil-based mud filtrate were considered in the modeling. The method uses successive pressure feedbacks and automated pulses to yield a pressure to within 0.5% range of the initial reservoir pressure while decreasing the wait time by a factor of 10 for a packer type formation tester. To account for various tool options and storage effects, the packer-type, oval probe, and standard probe-type formation testers have been simulated in various tight formation conditions. The method enables a rapid appraisal of pressure measurements in comparison to conventional testing. Simulations also indicate that the analytical spherical model can be used to analyze a pulse test, even when encountering multi-phase compositional fluid effects.
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.72)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.41)
- North America > United States > Wyoming > DJ (Denver-Julesburg) Basin > Niobrara Formation (0.99)
- North America > United States > Nebraska > DJ (Denver-Julesburg) Basin > Niobrara Formation (0.99)
- North America > United States > Kansas > DJ (Denver-Julesburg) Basin > Niobrara Formation (0.99)
- North America > United States > Colorado > DJ (Denver-Julesburg) Basin > Niobrara Formation (0.99)