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Results
Abstract Petrophysical interpretation of well logs acquired in organic shales and carbonates is challenging because of the presence of thin beds and spatially complex lithology; conventional interpretation techniques often fail in such cases. Recently introduced methods for thin-bed interpretation enable corrections for shoulder-bed effects on well logs but remain sensitive to incorrectly picked bed boundaries. We introduce a new inversion-based method to detect bed boundaries and to estimate petrophysical and compositional properties of multi-layer formations from conventional well logs in the presence of thin beds, complex lithology/fluids, and kerogen. Bed boundaries and bed properties are updated in two serial inversion loops. Numerical simulation of well logs within both inversion loops explicitly takes into account differences in the volume of investigation of all well logs involved in the estimation, thereby enabling corrections for shoulder-bed effects. The successful application of the new interpretation method is documented with synthetic cases and field data acquired in thinly bedded carbonates and in the Haynesville shale-gas formation. Estimates of petrophysical/compositional properties obtained with the new interpretation method are compared to those obtained with (a) nonlinear inversion of well logs with inaccurate bed boundaries, (b) depth-by-depth inversion of well logs, and (c) core/X-Ray Diffraction (XRD) measurements. Results indicate that the new method improves the estimation of porosity of thin beds by more than 200% in the carbonate field example and by more than 40% in the shale-gas example, compared to depth-by-depth interpretation results obtained with commercial software. This improvement in the assessment of petrophysical/compositional properties reduces uncertainty in hydrocarbon reserves and aids in the selection of hydraulic fracture locations in organic shale.
- North America > United States > Texas > Haynesville Shale Formation (0.99)
- North America > United States > Louisiana > Haynesville Shale Formation (0.99)
- North America > United States > Louisiana > Haynesville Formation (0.99)
- (2 more...)
Abstract Rock typing in carbonate reservoirs is challenging due to high spatial heterogeneity and complex pore structure. In extreme cases, conventional rock typing methods such as Leverett's J-function, Winland's R35, and flow zone indicator are inadequate to capture the heterogeneity and complexity of carbonate petrofacies. Furthermore, these methods are based on core measurements, hence are not applicable to uncored reservoir zones. This paper introduces a new method for petrophysical rock classification in carbonate reservoirs that honors multiple well logs and emphasizes the signature of mud-filtrate invasion. The method classifies rocks based on both static and dynamic petrophysical properties. An inversion-based algorithm is implemented to simultaneously estimate mineralogy, porosity, and water saturation from well logs. We numerically simulate the process of mud-filtrate invasion in each rock type and quantify the corresponding effects on nuclear and resistivity measurements to derive invasion-induced well-log attributes, which are subsequently integrated into the rock classification. Under favorable conditions, the interpretation method advanced in this paper can distinguish bimodal from uni-modal behavior in saturation-dependent capillary pressure otherwise only possible with special core analysis. We successfully apply the new method to a mixed clastic-carbonate sequence in the Hugoton gas field, Kansas. Rock types derived with the new method are in good agreement with lithofacies described from core samples. The distribution of permeability and saturation estimated from well-log-derived rock types agrees with routine core measurements, with the corresponding uncertainty significantly reduced when compared to results obtained with conventional porosity-permeability correlations.
- North America > United States > Texas (1.00)
- North America > United States > Kansas > Finney County (0.49)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (1.00)
- North America > United States > California > Sacramento Basin > 2 Formation (0.99)
- North America > United States > Kansas > Panoma Field (0.94)
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...)