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Collaborating Authors
Results
Fluid Substitution Analysis to Correct Borehole Geophysical Measurements Acquired in Gas-Bearing Formations Invaded by Oil-Base Mud
Xu, Chicheng (The University of Texas at Austin) | Torres-Verdín, Carlos (The University of Texas at Austin) | Ma, Jun (The University of Texas at Austin) | Li, Wei (China University of Petroleum)
Summary Borehole geophysical measurements acquired in gas-bearing formations can be significantly influenced by oil-base mud (OBM) invasion. Fluid substitution of density and sonic logs in OBM-invaded gas-bearing formations is necessary but difficult because resistivity logs cannot differentiate the saturations of OBM filtrate and gas. Numerical simulations indicate that invasion of OBM filtrate into gas-bearing formations is typically shallower than 30 cm and exhibits a sharp saturation front. The radial invasion profile is largely controlled by the rock’s petrophysical properties under relatively stable drilling conditions. On the other hand, density and neutron logs are mainly sensitive to invasion shallower than 18 cm while slowness/velocity processed from sonic waveforms is only affected by invasion deeper than 18 cm. Therefore, accurate fluid substitution in OBM invaded gas-bearing formations requires pre-assessment of the radial invasion profile which is governed by pore geometry, i.e., petrophysical rock type. We introduce a new method to address this technical challenge by integrating fast numerical simulation of well logs under mud-filtrate invasion and well-log based petrophysical rock classification. A field example from Trinidad onshore deltaic gas reservoirs is used to validate the proposed method.
- Asia (0.47)
- Europe > Norway > Norwegian Sea (0.45)
- North America > United States (0.32)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (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)
Enhanced Dispersion Analysis of Borehole Array Sonic Measurements With Amplitude and Phase Estimation Method
Li, Wei (China University of Petroleum-Beijing) | Guo, Rui (China University of Petroleum-Beijing) | Tao, Guo (China University of Petroleum-Beijing) | Wang, Hua (China University of Petroleum-Beijing) | Torres-Verdín, Carlos (The University of Texas at Austin) | Ma, Jun (The University of Texas at Austin) | Xu, Chicheng (The University of Texas at Austin)
Summary We introduce a new non-parametric matched-filterbank spectral estimator, referred as Amplitude and Phase Estimation (APES), to perform dispersion analysis of borehole array sonic measurements. This method extracts the dispersion characteristics of all wave modes by applying an APES filter to array sonic spectral data and converting the estimated wavenumber to slowness. The implemented adaptive filter in APES ensures that the output signal be sufficiently close to a sinusoid with a designated wavenumber in space domain, which constrains the interference from other wavenumber components and suppresses the noise gain. Consequently, the resolution and signal-noise-ratio of dispersion analysis is significantly enhanced. Dispersion fitness functions processed with APES indicate clearer and narrower ridges with minimum presence of alias. At each frequency, dispersions of all modes can be identified without knowledge a priori of the exact number of modes. More importantly, the new method is not computationally intensive compared to existing dispersion analysis methods. Processing examples with synthetic and field data are presented and compared with the weighted spectral semblance (WSS) method to demonstrate the applicability and advantages of this method.
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)