Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
Torres-Verdín, Carlos
ABSTRACT Unlike the common situation for which vertical wells penetrate horizontal layers, the trajectory of high-angle wells is usually not aligned with the principal axes of elastic rock properties. Borehole sonic measurements acquired in high-angle wells in general do not exhibit axial symmetry in the vicinity of bed boundaries and thin layers, and sonic waveforms remain strongly affected by the corresponding contrast in elastic properties across bed boundaries. The latter conditions often demand sophisticated and time-consuming numerical modeling to reliably interpret borehole sonic measurements into rock elastic properties. The problem is circumvented by implementing the eikonal equation based on the fast marching method to (1) calculate first-arrival times of borehole acoustic waveforms and (2) trace raypaths between sonic transmitters and receivers in high-angle wells. Furthermore, first-arrival times of P and S waves are calculated at different azimuthal receivers included in wireline borehole sonic instruments and are verified against waveforms obtained via 3D finite-difference time-domain simulations. Calculations of traveltimes, wavefronts, and raypaths for challenging synthetic examples with effects due to formation anisotropy and different inclination angles indicate a transition from a head wave to a boundary-induced refracted wave as the borehole sonic instrument moves across bed boundaries. Apparent slownesses obtained from first-arrival times at receivers can be faster or slower than the actual slownesses of rock formations surrounding the borehole, depending on formation dip, azimuth, anisotropy, and bed boundaries. Differences in apparent acoustic slownesses measured by adjacent azimuthal receivers reflect the behavior of wave propagation within the borehole and across bed boundaries and can be used to estimate bed-boundary orientation and anisotropy. The high-frequency approximation of traveltimes obtained with the eikonal equation saves more than 99% of calculation time with acceptable numerical errors, with respect to rigorous time-domain numerical simulation of the wave equation, and is therefore amenable to inversion-based measurement interpretation. Apparent slownesses extracted from acoustic arrival times suggest a potential method for estimating formation elastic properties and inferring boundary geometries.
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Seismic Processing (0.93)
- Well Drilling > Well Planning > Trajectory design (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
ABSTRACT Conventional borehole acoustic measurements deliver P and S wave slowness logs that inherently average in-situ rock properties along the receiver array of the acoustic instrument. These acquisition and processing conditions often limit the accuracy and resolution of the estimated rock elastic properties across heterolithic sedimentary sequences. We introduce an inversion-based interpretation method for borehole acoustic measurements that improves their vertical resolution by complementing them with ultrasonic borehole images. Results consist of high-resolution, layer-by-layer P and S wave slownesses. The combination of borehole acoustic measurements with borehole ultrasonic images enhances the definition of small rock features such as thin beds or vugs. We verify the new inversion-based interpretation method with synthetic borehole measurements and field acoustic logs acquired across sandstone-shale laminated formations and spatially heterogeneous carbonates. High-resolution layer-by-layer compressional and shear slownesses obtained with the new inversion method give rise to wider variations of calculated elastic properties than with standard acoustic logs for improved petrophysical and geomechanical evaluation. It is also found that implementing a common set of layers for the estimation of layer-by-layer rock elastic properties mitigates biases due to discrepancies in the intrinsic resolution of the various input measurements.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.69)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.49)
- Geophysics > Seismic Surveying > Seismic Processing (1.00)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Borehole Seismic Surveying (0.90)
- Geophysics > Seismic Surveying > Seismic Modeling > Velocity Modeling (0.67)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- (2 more...)
Assessment of Depth of Mud-Filtrate Invasion and Water Saturation Using Formation-Tester Measurements: Application to Deeply Invaded Tight-Gas Sandstones
Bennis, Mohamed (The University of Texas at Austin) | Mohamed, Tarek S. (The University of Texas at Austin) | Torres-Verdín, Carlos (The University of Texas at Austin) | Merletti, German (bp) | Gelvez, Camilo (bp)
Abstract Formation pressure/fluid measurements are impacted by mud-filtrate invasion, which may require long fluid pumpout durations to acquire hydrocarbon samples with minimal mud-filtrate contamination. However, unlike other well-logging instruments, formation testers do not have a fixed depth of investigation that limits their ability to pump out mud filtrate until acquiring original formation fluids (i.e., sensing the uninvaded zone). We use an in-house petrophysical and fluid-flow simulator to perform numerical simulations of mud-filtrate invasion, well logs, and formation-tester measurements to estimate the radial distance of invasion and the corresponding radial profile of water saturation. Numerical simulations are initialized with the construction of a multilayer petrophysical model. Initial guesses of volumetric concentration of shale, porosity, water saturation, irreducible water saturation, and residual hydrocarbon saturation are obtained from conventional petrophysical interpretation. Fluid-flow-dependent petrophysical properties (permeability, capillary pressure, and relative permeability), mud properties, rock mineral composition, and in-situ fluid properties are obtained from laboratory measurements. The process of mud-filtrate invasion and the corresponding resistivity and nuclear logs are numerically simulated to iteratively match the available well logs and estimate layer-by-layer formation water saturation. Next, using our multiphase formation testing simulator, we numerically simulate actual fluid sampling operations performed with a dual-packer formation tester. Finally, we estimate irreducible water saturation by minimizing the difference between the hydrocarbon breakthrough time numerically simulated and measured with formation-tester measurements. The examined sandstone reservoir is characterized by low porosity (up to 0.14), low-to-medium permeability (up to 40 md), and high residual gas saturation (between 0.4 and 0.5). The deep mud-filtrate invasion resulted from extended overbalanced exposure to high-salinity water-based mud (17 days of invasion and 1,800 psi overbalance pressure) coupled with the low mud-filtrate storage capacity of tight sandstones. Therefore, the uninvaded formation is located far beyond the depth of investigation of resistivity tools, whereby deep-sensing resistivities are lower than those of uninvaded formation resistivity. Through the numerical simulation of mud-filtrate invasion, well logs, and formation-tester measurements, we estimated radial and vertical distributions of water saturation around the borehole. Likewise, we quantified the hydrocarbon breakthrough time, which matched field measurements of 6.5 hours. The estimated radius of invasion was approximately 2.5 m, while the difference between estimated water saturation in the uninvaded zone and water saturation estimated from the deep-sensing resistivity log was approximately 0.13, therefore improving the estimation of the original gas in place.
- South America (0.93)
- Europe > Norway (0.66)
- North America > United States > Texas > Travis County > Austin (0.30)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Mineral (1.00)
- North America > United States > Wyoming > Powder River Basin (0.99)
- North America > United States > Montana > Powder River Basin (0.99)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Formation test analysis (e.g., wireline, LWD) (1.00)
ABSTRACT Petrophysical interpretation of logging-while-drilling (LWD) borehole measurements in the presence of electrical anisotropy, mud-filtrate invasion, noise, and well deviation effects remains a challenge in formation evaluation. In high-angle and horizontal (HAHZ) wells penetrating electrically anisotropic sandstones, phase and attenuation apparent resistivity logs often exhibit values larger than resistivity parallel to bedding planes. Consequently, traditional interpretation methods often fail to accurately estimate hydrocarbon saturation when using only the long-spacing phase apparent resistivity log (P40H) in petrophysical calculations. We implement two approaches (analytical and Bayesian) to estimate horizontal and vertical resistivities from apparent resistivity measurements. The first analytical approach is based on the numerical simulation of LWD resistivity measurements using synthetic models under various conditions of electrical anisotropy and well inclination to derive analytical models. The relative error of analytical approximations is less than 6%. In the presence of measurement noise and shoulder-bed effects, we implement a Bayesian method for well-log inversion and uncertainty quantification. The relative error of Bayesian inversion is less than 2%. Estimates of horizontal and vertical resistivities then can be used for petrophysical analysis. A challenging set of synthetic and field examples of HAHZ wells penetrating electrically anisotropic formations is selected for examination and verification of the new methods. For radial lengths of invasion less than 20 cm (8 in), sensitivity analysis indicates that the effects of conductive mud-filtrate invasion on long-spacing resistivity logs are negligible. The long-spacing phase (P40H) and attenuation (A40H) apparent resistivities are used to estimate horizontal and vertical resistivities. In the field examples under study, electrical anisotropy is caused by intercalated laminations of coarse- and fine-grained sandstones; the volumetric concentration of shale is negligible. Considering that Archie’s parameters are direction dependent, sensitivity analysis indicates that the effective value of the saturation exponent parallel to bedding planes is less sensitive to the volumetric concentration of fine-grained sandstone layers compared with the saturation exponent perpendicular to bedding planes. Thus, water saturation of grain-laminated sandstones in HAHZ wells can be estimated using horizontal resistivity with Archie’s parameters that are consistent with petrophysical interpretations performed in vertical wells. Estimates of water saturation in the field examples using horizontal resistivity agree with saturation-height models. Compared with conventional interpretation methods that use P40H as the formation resistivity, the new approach improved the estimation of hydrocarbon saturation by 10%.
- Asia (0.67)
- North America > United States > Texas (0.46)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Geological Subdiscipline (1.00)
- South America > Colombia > T Formation (0.99)
- Asia > India > Maharashtra > Arabian Sea > Bombay Offshore Basin > Mumbai High Field > L-V Formation (0.99)
- Asia > India > Maharashtra > Arabian Sea > Bombay Offshore Basin > Mumbai High Field > L-IV Formation (0.99)
- (3 more...)
In-Reservoir Mixing Dynamics Over Geologic Time of Separate Gas and Oil Charges in Well-Connected Reservoirs
Mohamed, Tarek S. (University of Texas at Austin) | Kristensen, Morten (SLB) | Pan, Shu (SLB) | Wang, Kang (SLB) | Betancourt, Soraya S. (SLB) | Torres-Verdín, Carlos (University of Texas at Austin) | Mullins, Oliver C. (SLB)
Abstract Many reservoirs experience separate gas and oil charges that can lead to a variety of different outcomes of fluid type and distribution. There has been fundamental uncertainty even as to which charge fluid can arrive first, let alone what fluid dynamic processes can result over geologic time. For high-pressure basins such as the Gulf of Mexico, this mixture can lead to increased solution gas, large GOR gradients and sometimes cause formation of viscous oil and tar at the oil-water contact, impacting aquifer support. In some reservoirs, the present-day outcome of oil and gas mixing over geologic time is clearly established by detailed chemical evaluation of reservoir fluids from many reservoir locations. Our objective is to understand the dynamics of the gas and oil mixing processes. Chemical measurements show that the extent of mixing includes thermodynamic equilibration in young reservoirs by 1) FHZ equation of state (EoS) asphaltene gradients and cubic EoS modeling of solution gas for reservoir fluids, 2) analysis of liquid-phase geochemical biomarkers, and 3) methane carbon isotope analysis. Specifically, in the common charge of primary biogenic gas and oil into reservoirs, methane isotope analysis is unequivocal. We employ reservoir simulation of a point gas charge into oil with various geometries and charge rates to establish parametric conditions which lead to excellent mixing vs those conditions that lead to large, disequilibrium gradients. The roles of compositional diffusion vs. momentum diffusion induced by forced convection are explored both in simulation and overall fluid mechanics analysis, which helps both to validate the results and extend the range of applicable parameters. Modeling results and simple fluid mechanics estimates also establish that there is no possibility that these reservoirs could have a gas charge followed by an oil charge; in the selected reservoirs, oil must have arrived first, followed by a biogenic gas charge. Seismic images of gas chimneys offer guidance regarding how the latter process can take place. Second, modeling results clearly establish a surprisingly wide range of charge conditions that can lead to excellent mixing and equilibration even for a point gas charge. Modeling results also show that for a very fast charge, results are consistent with those expected for CO2 injection and sequestration. The evaluation of geodynamic processes of separate biogenic gas and oil charges into reservoirs has rarely been accomplished. Even the result that biogenic gas charge must occur after oil charge challenges widely-held conventional thinking. In addition, the rapid and thorough mixing (less than 2 million years) of gas and oil charges is unexpected yet readily reproduced by reservoir simulation. The ability to connect CO2 sequestration to a wide range of reservoir studies is a novel way to constrain CCS modeling.
- Europe (1.00)
- North America > United States > Texas (0.28)
- Asia > Middle East > Qatar (0.28)
- Asia > Middle East > UAE > Abu Dhabi Emirate > Abu Dhabi (0.19)
- Geology > Rock Type > Sedimentary Rock (0.97)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.90)
- Geology > Geological Subdiscipline > Geochemistry (0.88)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Chalk Formation (0.99)
- Asia > Middle East > Turkey > Selmo Field (0.99)
- Asia > Middle East > Qatar > Arabian Gulf > Rub' al Khali Basin > Al Shaheen Field > Shuaiba Formation (0.99)
- (10 more...)
Abstract Data quality of well logs and laboratory measurements is crucial for accurate petrophysical interpretations in formations with complex solid compositions, thin beds, and adverse geometrical conditions . In this paper, we introduce a new method to calibrate and verify the reliability of core data and well logs acquired in spatially complex rocks. The method is based on the numerical simulation of well logs to reproduce the effects of borehole environmental conditions and instrument physics on the measurements. Additionally, high-resolution (HR) core data combined with rock typing and multiwell measurement analysis techniques enable the construction of multilayer formation models. We document the successful application of the new core-well-log calibration method to two wells penetrating a clastic formation in the North Sea. While the numerically simulated well logs match the available borehole measurements in the first well, large measurement discrepancies were observed in the second well. Normalization of nuclear logs in the second well based on core data and numerically simulated well logs improved the assessment of bulk density and neutron porosity by 5% and 20%, respectively, while unnormalized nuclear logs overestimated formation porosity. Multiwell comparisons of well logs also confirmed that measurement accuracy was compromised. The problem with data quality was attributed to a probable inadequate tool calibration, although the log header did not indicate any notable issues. Additionally, numerical simulations of nuclear magnetic resonance (NMR) porosity logs indicated a prominent depth mismatch among well logs. The numerical simulation of well logs based on HR core data enables the detection of inconsistent, noisy, and inaccurate measurements, including cases of abnormal borehole environmental corrections causing biases in petrophysical interpretations.
- North America > United States > Texas (1.00)
- Europe (1.00)
- Geology > Mineral (1.00)
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.91)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Deep Basin > Cardium Formation (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Thompson Field (0.89)
- North America > United States > Texas > Fort Worth Basin > Katz Field (0.89)
- Information Technology > Mathematics of Computing (1.00)
- Information Technology > Data Science > Data Quality (1.00)
Abstract Borehole measurements, such as electrical resistivity, neutron porosity, or nuclear magnetic resonance, are critical for the in-situ petrophysical assessment of subsurface rocks. However, the interpretation of borehole measurements is often subject to uncertainty arising from their sensitivity to the interplay between mud filtrate, connate fluids, and the rock’s pore structure. This uncertainty remains present even in homogeneous geological formations. Mudcake deposition on the borehole wall causes additional complexity, impacting both well construction and formation evaluation. It is, therefore, essential to account for the latter effects and perform appropriate corrections when interpreting borehole measurements. Recently, new experimental procedures were introduced to quantitatively describe the process of mud invasion under realistic rock and fluid conditions, focusing on gas-bearing rocks and without considering how original saturating fluids affected the process of invasion. Both mud-filtrate invasion and filter-cake deposition must be understood and incorporated into numerical and analytical models to reliably interpret borehole measurements and maximize value. This objective can only be fulfilled via experiments. We use X-ray microfocus radiography to examine in real time the processes of mud-filtrate invasion and internal and external mudcake deposition in thin rectangular rock samples. The high-resolution experimental procedure (10 to 30 μm) mimics the borehole and near-wellbore regions and facilitates the time-lapse visualization of in-situ fluid-transport processes in spatially complex rocks. Water- and oil-based muds were injected into rock samples initially saturated with a range of different connate fluids, including viscous liquids, while being continuously scanned with X-rays. Because the injected drilling muds were the same across all experiments, the observed discrepancies between experiments originate from differences in rock properties, heterogeneity and anisotropy, or initial fluid saturation conditions. Experimental results emphasize the effect of rock heterogeneity and initial connate fluid on the spatial distribution of fluids and mudcake formation ensuing from mud-filtrate invasion. Mud-filtrate invasion rates and final average mudcake thicknesses were similar across all cases for a given drilling mud, suggesting that mudcake properties, as opposed to rock properties, were the controlling factors. By contrast, the spatial distribution of fluids in each rock sample varied significantly between cases, highlighting the impact of rock heterogeneity/anisotropy on the process of invasion. Laboratory experiments also emphasize the impact of viscous and/or capillary forces on mud-filtrate flow behavior. The experimental method is efficient and reliable, allowing for a better understanding of the uncertainty of the effects of mud-filtrate invasion on borehole geophysical measurements acquired while or after drilling.
- Personal > Honors (1.00)
- Research Report > New Finding (0.67)
- Research Report > Experimental Study (0.67)
- Geology > Mineral (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.32)
- Well Drilling > Formation Damage (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
Abstract Accurate reservoir characterization is vital for effective decisions made throughout the life cycle of an oilfield reservoir, including management and development. Of all the components of reservoir description, hydraulic connectivity carries the highest amount of uncertainty, where inaccurate connectivity evaluation often results in production underperformance. Shortcomings are faced when applying conventional approaches of connectivity assessment. Seismic surveys are not always sufficient to evaluate lateral connectivity as detected faults can be transmissive or partially transmissive, while some faults are below the detection limits of seismic amplitude measurements. Vertical connectivity represents another uncertainty, where pressure measurements and well logs are often either unable to detect the baffles along oil columns or cannot assess whether detected baffles are relevant seals or flow diverters. Although conventional downhole fluid analysis (DFA) workflows have proven effective in delineating reservoir connectivity, enough DFA data are not always available, and with added complexity, uncertainties arise. Additionally, while equilibrated asphaltene gradients, measured through DFA probes, imply connectivity, ongoing reservoir fluid geodynamics (RFG) processes, such as current hydrocarbon charging, can preclude equilibration in a connected reservoir. Thus, a comprehensive assessment approach, that utilizes all available data streams, is needed to overcome the significant spatial complexity associated with moderately and heavily faulted reservoirs. In this paper, we employed our recently introduced interpretation workflow to evaluate the connectivity of a heavily faulted reservoir in the deepwater Gulf of Mexico. The field was divided into five investigation areas penetrated by 12 wells. Areal downhole fluid analysis (ADFA) was applied to assess local connectivity leading to reservoir-scale connectivity. Through integrating fluid/dynamic and rock/static data, each data type provided insights that were pieced together to enhance consistency and reduce uncertainty. Analyzed data included pressure-volume-temperature (PVT) reports, pressure surveys, well logs, and geochemistry. The study resulted in a verifiable connectivity description where faults, previously regarded as sealing, were classified into sealing or partially transmissive faults; unresolved faults were detected. Fault-block migration was detected, and fault throw was estimated; asphaltenes behavior was used to deduce original field structures prior to faulting. We also examined RFG processes to investigate oil biodegradation, where an asphaltene clustering trend was observed, causing high oil viscosities toward the bottom of one sandstone. A correlation was then derived and successfully implemented to estimate oil viscosity.
- Geology > Structural Geology > Fault (1.00)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.35)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Seismic Processing (0.34)
- North America > United States > Wyoming > Powder River Basin (0.99)
- North America > United States > Montana > Powder River Basin (0.99)
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Green Canyon > Block 826 > Mad Dog Field (0.99)
- (2 more...)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- (5 more...)
ABSTRACT Multimineral analysis is widely used to calculate in situ porosity, fluid saturation, and mineralogy of rocks penetrated by a well. It delivers weight/volumetric concentrations of rock solid/fluid constituents by combining multiple borehole geophysical measurements and often is referred to as petrophysical joint inversion. Recently, a probabilistic method was developed for improved petrophysical estimation of rock constituents and their uncertainty from well logs. This method mitigates borehole and instrument-related environmental effects present in the measurements and efficiently propagates the uncertainty from measurement noise and rock-physics models (RPMs) to compositional/petrophysical estimations. The probabilistic estimation method is extended to the challenging conditions of multiple neighboring wells penetrating similar rock formations where borehole/drilling environmental conditions, borehole instruments, and measurement noise may vary from well to well. A calibration step is performed in a few key wells with core data and/or advanced borehole measurements; it enables the same RPMs and prior models to be implemented in nearby wells but with limited measurements. In addition, a precomputed surrogate model constructed with radial basis function interpolation is implemented for accurate and efficient nuclear-property calculations. The multiwell interpretation method is verified using synthetic and field examples of organic-rich shale formations. Results find that the probabilistic method (1) improves rock petrophysical/compositional estimations by mitigating borehole environmental effects and incorporating a priori knowledge, (2) yields regionally consistent compositions among wells, and (3) quantifies the uncertainty of the estimations. As a result, the probabilistic approach is especially suitable for assessing petrophysical/compositional properties in multiwell settings with complex rock constituents and/or limited borehole measurements.
- Research Report > Experimental Study (0.50)
- Research Report > New Finding (0.34)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline (1.00)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Seismic Modeling > Velocity Modeling (0.46)
- South America > Argentina > Patagonia > Neuquén > Neuquen Basin > Vaca Muerta Shale Formation (0.99)
- North America > United States > Texas > Permian Basin > Val Verde Basin > Upper Wolfcamp Formation (0.99)
- North America > United States > Texas > Permian Basin > Delaware Basin > Wolfcamp Formation (0.99)
- (9 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale oil (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- (4 more...)
Adaptive OCCAM’s inversion for the interpretation of borehole ultra-deep azimuthal resistivity measurements
Saputra, Wardana (The University of Texas at Austin) | Hou, Junsheng (The University of Texas at Austin) | Torres-Verdín, Carlos (The University of Texas at Austin) | Davydycheva, Sofia (3D EM Modeling & Inversion JIP) | Druskin, Vladimir (3D EM Modeling & Inversion JIP)
Ultra-deep azimuthal resistivity (UDAR) logging technology has been around for the last two decades. However, the real-time inversion of deep-sensing borehole electromagnetic measurements is still an outstanding challenge to yield a reliable image of subsurface electrical resistivity. In this study, we develop a new procedure for adaptive 1D inversion of UDAR measurements that quantifies the uncertainty of results and implements various measures of data misfit to trigger local higher-dimensional inversions. We construct an augmented linear system for fast and stable OCCAM’s inversion that accounts for data and model weight matrices, as well as priors for adaptive inversion. We further verify the successful application of this adaptive inversion method on three resistivity models inspired by actual reservoir structures explored with commercial UDAR tool configurations.
- Geophysics > Electromagnetic Surveying (1.00)
- Geophysics > Borehole Geophysics (1.00)