Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
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)
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)
ABSTRACT Calculation of mineral and fluid volumetric concentrations from well logs is one of the most important outcomes of formation evaluation. Conventional estimation methods assume linear or quasi-linear relationships between volumetric concentrations of solid/fluid constituents and well logs. Experience shows, however, that the relationship between neutron porosity logs and mineral concentrations is generally nonlinear. More importantly, linear estimation methods do not explicitly account for shoulder-bed and/or invasion effects on well logs, nor do they account for differences in the volume of investigation of the measurements involved in the estimation. The latter deficiencies of linear estimation methods can cause appreciable errors in the calculation of porosity and hydrocarbon pore volume. We investigated three nonlinear inversion methods for assessment of volumetric concentrations of mineral and fluid constituents of rocks from multiple well logs. All three of these methods accounted for the general nonlinear relationship between well logs, mineral concentrations, and fluid saturations. The first method accounted for the combined effects of invasion and shoulder beds on well logs. The second method also accounted for shoulder-bed effects but was intended for cases where mud-filtrate invasion is negligible or radially deep. Finally, the third method was designed specifically for analysis of thick beds where mud-filtrate invasion is either negligible or radially deep. Numerical synthetic examples of application indicated that nonlinear inversion of multiple well logs is a reliable method to quantify complex mineral and fluid compositions in the presence of thin beds and invasion. Comparison of results against those obtained with conventional multimineral estimation methods confirmed the advantage of nonlinear inversion of multiple well logs in quantifying thinly bedded invaded formations with variable and complex lithology, such as those often encountered in carbonate formations.
- Geology > Mineral (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.32)