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Collaborating Authors
The University of Texas at Austin
PREDICTING MISSING SONIC LOGS WITH SEISMIC CONSTRAINT
Pham, Nam (The University of Texas at Austin) | Fu, Lei (Aramco Americas) | Li, Weichang (Aramco Americas)
Compressional and shear sonic transit-time logs (DTC and DTS, respectively) provide important petrophysical and geomechanical information for subsurface characterization. However, they are often not acquired in all wells because of cost limitations or borehole problems. We propose a method to estimate DTC and DTS simultaneously, from other commonly acquired well logs like gamma-ray, density, and neutron porosity. Our method consists of two consecutive models to predict the sonic logs and predict the seismic traces at well locations. The model predicting the seismic traces adds a spatial constraint to the model predicting sonic logs. Our method also quantifies uncertainties of the prediction, which come from uncertainties of neural network parameters and input data. We train the network on four wells from the Poseidon dataset located on the Australian shelf, in the Browse basin. We test the network on other two wells from Browse basin. The test results show better predictions of sonic logs when we add the seismic constraint.
- North America > United States (0.93)
- Oceania > Australia > Western Australia > North West Shelf (0.54)
- Oceania > Australia > Western Australia > Timor Sea (0.44)
- Geology > Geological Subdiscipline > Geomechanics (0.68)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.46)
- Geophysics > Seismic Surveying > Seismic Processing (1.00)
- Geophysics > Borehole Geophysics (1.00)
- Oceania > Australia > Western Australia > Western Australia > Timor Sea > Browse Basin (0.99)
- Oceania > Australia > Western Australia > North West Shelf > Timor Sea > Browse Basin (0.99)
- 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)
- Data Science & Engineering Analytics > Information Management and Systems > Neural networks (1.00)
Experimental Investigation of Two-Phase Flow Properties of Heterogeneous Rocks Based on X-Ray Microfocus Radiography
Aรฉrens, P. (The University of Texas at Austin (currently with Halliburton)) | Espinoza, D. N. (The University of Texas at Austin) | Torres-Verdรญn, C. (The University of Texas at Austin (Corresponding author))
Summary An uncommon facet of formation evaluation is the assessment of flow-related in-situ properties of rocks. Most of the models used to describe two-phase flow properties of porous rocks assume homogeneous and/or isotropic media, which is hardly the case with actual reservoir rocks, regardless of scale; carbonates and grain-laminated sandstones are but two common examples of this situation. The degree of spatial complexity of rocks and its effect on the mobility of hydrocarbons are of paramount importance for the description of multiphase fluid flow in most contemporary reservoirs. There is thus a need for experimental and numerical methods that integrate all salient details about fluid-fluid and rock-fluid interactions. Such hybrid, laboratory-simulation projects are necessary to develop realistic models of fractional flow in complex rocks, i.e., saturation-dependent capillary pressure and relative permeability. Furthermore, these two crucial properties are usually measured independently. Capillary pressure is typically assessed using static measurements and unrealistic pressure conditions, whereas relative permeability is evaluated dynamically. Consequently, the disparity between the nature of the two experimental procedures often results in a potentially significant loss of information. We document a new high-resolution visualization technique that provides experimental insight to quantify fluid saturation patterns in heterogeneous rocks which allow for the simultaneous and dynamic evaluation of two-phase flow properties. The experimental apparatus consists of an X-ray microfocus scanner and an automated syringe pump. Rather than using traditional cylindrical cores, thin rectangular rock samples are examined, their thickness being one order of magnitude smaller than the remaining two dimensions. During the experiment, the core is scanned quasicontinuously while the fluids are being injected, allowing for time-lapse visualization of the flood front. Numerical simulations are then conducted to match the experimental data and quantify effective saturation-dependent relative permeability and capillary pressure. The experimental results indicate that flow patterns and in-situ saturations are highly dependent on the nature of the heterogeneity and bedding-plane orientation during both imbibition and drainage cycles. In homogeneous rocks, fluid displacement approaches piston-like behavior. The assessment of capillary pressure and relative permeability is performed by examining the time-lapse water saturation profiles resulting from fluid displacement. In spatially complex rocks, high-resolution time-lapse images reveal preferential flow paths along high-permeability sections and a lowered sweep efficiency. Our experimental procedure emphasizes that capillary pressure and transmissibility differences play an important role in fluid-saturation distribution and sweep efficiency at late times. The method is fast and reliable to assess mixing laws for fluid-transport properties of rocks in spatially complex formations.
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.47)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.39)
Deep learning with soft attention mechanism for small-scale ground roll attenuation
Yang, Liuqing (China University of Petroleum (Beijing), China University of Petroleum (Beijing)) | Fomel, Sergey (The University of Texas at Austin) | Wang, Shoudong (China University of Petroleum (Beijing), China University of Petroleum (Beijing)) | Chen, Xiaohong (China University of Petroleum (Beijing), China University of Petroleum (Beijing)) | Chen, Yangkang (The University of Texas at Austin)
ABSTRACT Ground roll is a type of coherent noise with low frequency, low velocity, and high amplitude, which masks useful signals and decreases the quality of subsequent seismic data processing. It is a challenge for traditional signal processing methods to separate useful signals effectively when the ground roll and useful reflected signals overlap seriously in the low-frequency band. We develop a supervised-learning-based framework with soft attention residual learning mechanisms for suppressing the ground roll noise. To reduce the cost of manual labeling, the 2D patching technique is used to segment large-scale seismic data into a large number of small-scale patches for training. Our network includes a multibranch attention block that uses multiple branches with different kernel sizes to extract waveform features at different scales from input noisy patches. Then, we use the soft attention mechanism to select and fuse the feature maps of different branches. Our network can achieve encouraging ground roll attenuation performance by using a small number of training samples, which is demonstrated by synthetic and field data examples. Compared with one traditional method and two advanced deep-learning frameworks, our network has better abilities in preserving low-frequency useful signals and removing ground roll.
- Asia > China (0.68)
- North America > United States > Texas (0.28)
Streaming seismic attributes
Geng, Zhicheng (The University of Texas at Austin) | Fomel, Sergey (The University of Texas at Austin) | Liu, Yang (Jilin University) | Wang, Qinghan (Jilin University) | Zheng, Zhisheng (Jilin University) | Chen, Yangkang (The University of Texas at Austin)
ABSTRACT Local seismic attributes play an important role in seismic processing and interpretation. However, the iterative regularized inversion required by the calculation of local seismic attributes makes it prohibitively expensive for real-time processing tasks. In this paper, we present an efficient method for estimating local seismic attributes, such as local frequency and local spectrum, using streaming computation. In our approach, the local attributes can be computed by updating the previously calculated attribute value using one new data point at a time, making it unnecessary to conduct the iterative inversion and thus significantly speeding up the computation for online usage. We apply our method to synthetic and field data to demonstrate its efficiency and effectiveness in accurately characterizing nonstationary seismic signals.
- Geophysics > Seismic Surveying > Seismic Processing (1.00)
- Geophysics > Seismic Surveying > Seismic Interpretation (1.00)
Axial resolution enhancement of borehole acoustic measurements via inversion-based interpretation supported with ultrasonic data
Liu, Jingxuan (The University of Texas at Austin) | Eghbali, Ali (The University of Texas at Austin) | Torres-Verdรญn, Carlos (The University of Texas at Austin)
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...)
A New Adaptive Implicit Method for Multicomponent Surfactant-Polymer Flooding Reservoir Simulation
Batista Fernandes, Bruno Ramon (The University of Texas at Austin (Corresponding author)) | Sepehrnoori, Kamy (The University of Texas at Austin) | Marcondes, Francisco (Federal University of Cearรก) | Delshad, Mojdeh (The University of Texas at Austin)
Summary In the oil industry, chemicals can improve oil production by mobilizing trapped and bypassed oil. Such processes are known as chemical-enhanced oil recovery (CEOR). Surfactants and polymers are important chemicals used in CEOR with different mechanisms to improve oil recoveries, such as reduction in residual saturation, oil solubilization, and mobility control. However, both surfactant and polymer may increase the cost of oil production, making optimizing these processes essential. Reservoir simulators are tools commonly used when performing such field optimization. The simulation of surfactant flooding processes has been historically performed with the implicit pressure explicit composition (IMPEC) approach. The injection of surfactants requires modeling the brine/oil/microemulsion phase behavior along with other processes, such as capillary desaturation and retention. The microemulsion phase behavior and the complex relative permeability behavior can lead to convergence issues when using fully implicit (FI) schemes. Only recently, the FI approach has been efficiently applied to simulate this process using new modeling. The adaptive implicit method (AIM) can combine the benefits of the FI and IMPEC approaches by dynamically selecting the implicitness level of gridblocks in the domain. This work presents a new AIM in conjunction with recently developed models to mitigate discontinuities in the microemulsion relative permeabilities and phase behavior. The approach presented here considers the stability analysis method as a switching criterion between IMPEC and FI. To the best of our knowledge, the approach presented here is the first AIM to consider the brine/oil/microemulsion three-phase flow in its conception. The new approach uses the finite volume method in conjunction with Cartesian grids as spatial discretization and is applied here for field-scale problems. The new approach is tested for polymer flooding and surfactant-polymer (SP) flooding for problems with several active cells ranging from about a hundred thousand to almost a million. The AIM approach was compared with the FI and IMPEC approaches and displayed little variation in the computational performance despite changes in the timestep size. The AIM also obtained the fastest performance for all cases, especially for SP flooding cases. Furthermore, the results here suggest that the gap in performance between the AIM and FI seems to increase as the number of gridblocks increases.
- North America > United States > Texas (1.00)
- Asia (0.93)
- Overview (0.54)
- Research Report > New Finding (0.46)
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-Verdรญn, 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)
The Application of a New Variable Pressure Decline-Curve Analysis Technique to Unconventional Reservoirs in Argentina
Maraggi, Leopoldo M. Ruiz (The University of Texas at Austin) | Tuero, Fernando (VYP Consulting Services) | Walsh, Mark P. (The University of Texas at Austin) | Lake, Larry W. (The University of Texas at Austin)
Abstract Traditional rate-transient analysis (RTA) is used to match the past and forecast the future production history of unconventional wells. This approach has several drawbacks: (a) the analysis of a single well is time-consuming, (b) it uses two approximate transformations: rate normalization and material balance time, and (c) the interpretation is subjective. Recently, we have developed a new variable pressure decline-curve analysis (DCA) method. This new approach delivers fast and accurate history matches and forecasts, removing the need for subjective interpretation and avoiding potential errors caused by rate normalization and material balance time transformations. The goal of this paper is to apply of this new variable pressure DCA method to unconventional reservoirs in Argentina. The new variable pressure DCA technique performs sequential optimizations. In each iteration, the algorithm sequentially estimates: (1) the reservoir model parameters, (2) the pressure change, and (3) the initial reservoir pressure. The outputs of the method are the following: (a) the model's parameters, (b) the production history-match, and (c) estimates of the bottomhole flowing pressure (BHP) and initial reservoir pressure. In addition, the technique allows the user to select any decline-curve model, numerical, analytical, or empirical model. We illustrate the application of the technique for a tight-oil and a shale gas well using three different models: the constant-pressure solution of the diffusivity equation, the logistic growth model, and the Arps hyperbolic relation. The analysis of production from unconventional wells shows that the new technique provides excellent production history-matches using different reservoir models. We show that the estimated BHP using our technique is in good agreement with the calculated BHP for the wells under study. Furthermore, the technique is computationally fast; it only requires around 20 seconds to analyze and history-match the production of a well. For the tight-oil well, we perform a hindcast analysis using only the flowback data to match the model parameters which were then used to forecast the production history with excellent agreement. The method provides the possibility to history-match and estimate the future behavior of wells under different choke management scenarios. This work illustrates the application of a recently developed variable pressure DCA technique that efficiently performs automated production history-matches and forecasts of unconventional reservoirs. The technique provides improved estimates of the BHP and initial reservoir pressures. It can be used with any decline model. In addition, the method is computationally inexpensive and does not require the use of diagnostic plots and the interpretation of a practitioner. The major contributions of the present method are its flexibility to incorporate any decline-curve model and its speed to analyze and history-match the production of unconventional wells. Finally, we developed a web-based application to provide readers with a hands-on experience of this new technique.
- North America > United States > Texas (1.00)
- South America > Argentina (0.70)
- North America > Canada (0.69)
Stratal Surfaces Honoring Seismic Structures and Interpreted Geologic Time Surfaces
Wang, Fu (University of Science and Technology of China, Tongji University) | Wu, Xinming (University of Science and Technology of China) | Zeng, Hongliu (The University of Texas at Austin) | Janson, Xavier (The University of Texas at Austin) | Kerans, Charles (The University of Texas at Austin)
Seismic horizons play a significant role in reservoir model construction and sedimentary facies interpretation, providing crucial low-frequency constraints for seismic inversion. In basin and regional interpretations, the assumption that seismic reflections represent a stratigraphic surface with constant geologic time is significant for guiding seismic interpretation. This assumption may fail when applied to local reservoir scales due to common geologic time transgressions of a particular event in regular wavelet frequency. There will be inconsistencies between seismic events and stratigraphic surfaces. To address this issue and obtain relatively accurate stratal interpretations, we develop a hybrid horizon extraction method honoring both seismic structures and time-stratigraphic frameworks, in which seismic reflection structures provide local details and interpreted geologic time surfaces offer critical constraints. First, we develop concepts and a workflow using a realistic outcrop model. We propose a new geology-guided structure tensor by fitting a gradient vector of seismic images and geologic time surfaces. We also consider existing geologic conditions, such as unconformities, and fuse them into our method to calculate accurate slopes and generate reliable relative geologic time (RGT) images at a fine scale, followed by making slices. Further, we extend the proposed method to 3D seismic data volumes. Our experiments, conducted using simulated and field data, show the superiority and accuracy of our hybrid method compared with the slope-based and stratal slicing methods. These results highlight the potential for applying the proposed method to fine-scale subsurface modeling.
- North America > United States > Texas (1.00)
- Asia (0.67)
- Geophysics > Seismic Surveying > Seismic Processing (1.00)
- Geophysics > Seismic Surveying > Seismic Interpretation (1.00)
- Geophysics > Seismic Surveying > Seismic Modeling > Velocity Modeling (0.34)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (23 more...)
Numerical simulation and interpretation of sonic arrival times in high-angle wells using the eikonal equation
Liu, Jingxuan (The University of Texas at Austin) | Torres-Verdn, Carlos (The University of Texas at Austin)
Borehole sonic measurements acquired in high-angle wells in general do not exhibit axial symmetry in the vicinity of bed boundaries and thin layers, while 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. We circumvent this problem by implementing the eikonal equation based on the fast-marching method to (a) calculate first-arrival times of borehole acoustic waveforms, and (b) trace ray paths between sonic transmitters and receivers in high-angle wells. Furthermore, first-arrival times of compressional and shear waves are calculated at different azimuthal receivers included in wireline borehole sonic instruments and are verified against waveforms obtained via three-dimensional (3D) finite-difference time-domain simulations (3D-FDTD). Calculations of travel times, wavefronts, and ray paths for challenging synthetic examples with effects due to formation anisotropy and different inclination angles show 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 travel times 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
- North America > United States (0.46)
- Europe (0.28)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Seismic Processing (0.92)