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ABSTRACT Surface wave exploration technology has been extensively used in the inspection of construction engineering quality and shallow surface surveys. To enhance the efficiency of surface wave exploration field acquisition and achieve high-precision and high-density surface wave profile imaging, a wireless distributed seismic surface wave signal acquisition system has been developed based on the principles of active source transient surface wave signal acquisition and dispersion curve calculation methods. For the purpose of achieving rapid multiple coverage signal acquisition and enhancing fieldwork efficiency, a method for rapidly configuring common-midpoint signal couples (CMCs) for multiple coverage common-shot signal acquisition has been devised, and a high-precision visualization method for dispersion curve calculation based on the CMC array has been formulated. When compared with the multichannel analysis of the surface wave method under identical conditions, the CMC array can effectively enhance surface wave dispersion curve survey station density and lateral resolution, thereby enabling high-density analysis of surface wave profile imaging. Through model analysis and field examples related to construction quality detection, including foundation compactness and earth and rock mixture compactness, it has been demonstrated that this method offers significant advantages in terms of high accuracy, high density, and a wide application range. These advantages greatly enhance the efficiency of surface wave exploration and the accuracy of profile imaging for the construction of engineering projects.
ABSTRACT Gassmann’s equations have been known for several decades and are widely used in geophysics. These equations are treated as exact if all the assumptions used in their derivation are fulfilled. However, a recent theoretical study claimed that Gassmann’s equations contain an error. Shortly after that, a 3D numerical calculation was performed on a simple pore geometry that verifies the validity of Gassmann’s equations. This pore geometry was simpler than those in real rocks but arbitrary. Furthermore, the pore geometry that was used did not contain any special features (among all possible geometries) that were tailored to make it consistent with Gassmann’s equations. In other recent studies, I also performed numerical calculations on several other more complex pore geometries that supported the validity of Gassmann’s equations. To further support the validity of these equations, I provide here one more convergence study using a more realistic geometry of the pore space. Given that there are several studies that rederive Gassmann’s equations using different methods and numerical studies that verify them for different pore geometries, it can be concluded that Gassmann’s equations can be used in geophysics without concern if their assumptions are fulfilled. MATLAB routines to reproduce the presented results are provided.
- North America > United States > Massachusetts (0.29)
- Europe (0.29)
ABSTRACT The well-known “Biot-Gassmann” equation for the fluid dependence of incompressibility of a porous rock is in error. However, a recent numerical calculation on a simple rock model verifies that equation. The calculation appears to be correct but constitutes a special case not representative of real rock. Physical experimentation on actual rocks is required to verify the corrected theory.
ABSTRACT Gassmann’s equations have been known for several decades and are widely used in geophysics. These equations are treated as exact if all the assumptions used in their derivation are fulfilled. However, a recent theoretical study claimed that Gassmann’s equations contain an error. Shortly after that, a 3D numerical calculation was performed on a simple pore geometry that verifies the validity of Gassmann’s equations. This pore geometry was simpler than those in real rocks but arbitrary. Furthermore, the pore geometry that was used did not contain any special features (among all possible geometries) that were tailored to make it consistent with Gassmann’s equations. In other recent studies, I also performed numerical calculations on several other more complex pore geometries that supported the validity of Gassmann’s equations. To further support the validity of these equations, I provide here one more convergence study using a more realistic geometry of the pore space. Given that there are several studies that rederive Gassmann’s equations using different methods and numerical studies that verify them for different pore geometries, it can be concluded that Gassmann’s equations can be used in geophysics without concern if their assumptions are fulfilled. MATLAB routines to reproduce the presented results are provided.
- North America > United States > Massachusetts (0.29)
- Europe (0.29)
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)
Seismic 3D full-horizon tracking based on a knowledge graph to represent the stratigraphic sequence relationship
He, Xin (University of Electronic Science and Technology of China (UESTC)) | Zhou, Cheng (University of Electronic Science and Technology of China (UESTC)) | Zhang, Yusheng (PetroChina Southwest Oil and Gas Field Company) | Qian, Feng (University of Electronic Science and Technology of China (UESTC)) | Hu, Guangmin (University of Electronic Science and Technology of China (UESTC)) | Li, Yalin (BGP Inc. China National Petroleum Corporation)
ABSTRACT Seismic 3D full-horizon tracking is a fundamental and crucial step in sequence analysis and reservoir modeling. Existing automatic full-horizon tracking approaches lack effective methods for representing the stratigraphic sequence relationships in seismic data. However, the inability to represent the stratigraphic sequence relationships fully and accurately makes it challenging to address discontinuous areas affected by faults and unconformities. To address this issue, we develop a knowledge graph representing the stratigraphic sequence relationship, which enables the simultaneous extraction of all horizon surfaces once the stratigraphic distribution of the seismic data is obtained. This method first generates horizon patches and calculates the fault attributes, followed by the construction of an initial knowledge graph that characterizes the overall distribution of horizon patches and faults. The initial knowledge graph comprises nodes and edges. The nodes represent horizon patches, and their attributes cover the geographical location information of the patches and faults. Simultaneously, the edges represent the relationship between the horizon patches, including the stratigraphic sequence relationship, and their attributes illustrate the potential for connecting these patches. Furthermore, we introduce a multilayer knowledge graph based on the point-set topology to fuse the nodes. This allows for the continuous merging of the horizon patches to obtain horizon surfaces across discontinuities with the constraints of fault attributes and stratigraphic sequence relationships in 3D space. Synthetic and field examples demonstrate that our approach can effectively represent stratigraphic sequence relationships and accurately track horizons located in discontinuous areas with faults and unconformities.
- Geophysics > Seismic Surveying > Seismic Interpretation (1.00)
- Geophysics > Seismic Surveying > Seismic Processing (0.68)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Geologic modeling (1.00)
- Data Science & Engineering Analytics > Information Management and Systems > Artificial intelligence (1.00)
Parsimonious Refraction Interferometry (PRI) is a useful technique for generating dense virtual traveltimes when the seismic survey is performed with sparse acquisition geometry. However, PRI has limitations in accurately calculating the traveltimes of direct and diving waves, leading to inaccurate velocity structures when applying the first-arrival traveltime tomography (FATT). To address this issue, we propose an improved approach using a deep learning (DL) network called U-Net. We first examine the feasibility of the proposed algorithm analytically through the traveltime interpretation of a simple model. Then, the U-Net model is trained on various datasets to learn the relationship between PRI results and actual traveltimes. Subsequently, the trained network corrects the traveltime errors of the PRI results. As a result, we can obtain accurate first-arrival traveltimes using only two shot gathers without additional information such as infilled shots. The proposed technique enables virtual traveltime corrections, allowing for improved FATT results, even in cases where dense shots are difficult to deploy. Numerical results demonstrate that the proposed method can achieve comparable accuracy to picked traveltime data, indicating its high effectiveness in increasing the resolution of FATT results. The proposed approach maximizes the cost-saving benefits of PRI and can be advantageous in obtaining high-resolution FATT results when dense shot geometry is unavailable.#xD;
- Geophysics > Seismic Surveying > Seismic Processing (1.00)
- Geophysics > Seismic Surveying > Seismic Modeling > Velocity Modeling (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Data Science & Engineering Analytics > Information Management and Systems > Neural networks (1.00)
- Data Science & Engineering Analytics > Information Management and Systems > Artificial intelligence (1.00)
Abstract This paper documents the results of diagnostic tests in a well that was equipped with measuring devices for analyzing pressure and acoustic behavior during multistage fracturing treatments. This well was also surveyed by an ultrasonic device for measuring the entry hole sizes of treated and untreated perforations. Well and treatment design parameters selected for scrutiny included cluster perforation density and the circumferential phase angle of entry holes with respect to elevation. Perforation erosional analysis was performed on each frac stage of the diagnostic wells by comparing perforation sizes of treated perforations with intentionally untreated perforations to estimate the eroded area for each perforation, then applying a two-component erosion model to allocate proppant among all the clusters for that frac stage. The allocated proppant was then used to compute treatment uniformity and compared with allocation and uniformity values determined by the DAS provider. This unique dataset was used to perform five categories of analyses: pipe/casing friction pressure, step down testing, perforation entry hole erosion, treating pressure, and inter-cluster proppant allocation and uniformity. Determination of perforation entry-hole erosion parameters are shown to have diagnostic value in assessing treatment confinement and identifying deviations from standard erosion theory. The impact of variable and uncertain initial (untreated) entry hole sizes is shown to adversely impact the accuracy of both DAS and erosion-based proppant allocation routines. Evidence is provided quantifying the negative effect of proppant separating from the fluid stream due to inertia on the accuracy of treatment distribution provided by DAS interpretation.
_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 216673, “CO2 Injectivity Test Proves the Concept of CCUS Field Development,” by Yermek Kaipov, SPE, and Bertrand Theuveny, SLB, and Ajay Maurya, Saudi Aramco, et al. The paper has not been peer reviewed. _ The complete paper presents a unique case study on injectivity tests done in Saudi Arabia to prove the concept of carbon capture, use, and storage (CCUS) capability. It describes the design of surface and downhole testing systems, lessons learned, and recommendations. The injectivity tests were effective in identifying and confirming the best reservoir for CO2 injection and defining the best completion strategy. Creating injection conditions close to CCUS is vital, especially in heterogeneous carbonate reservoirs where the petrophysical correlations for the reservoir model require calibration with dynamic data. Introduction The energy company has conducted an extensive evaluation campaign by drilling appraisal wells through multizone saline aquifer reservoirs on different sites close to potential sources of CO2 at the surface. The evaluation program included coring, openhole logging, formation testing for stress-test and water sampling, and injectivity testing in the cased hole. Apart from reservoir characterization, different completion strategies were evaluated by performing injectivity tests in both vertical and horizontal wells. The lower completion was represented by perforated casing and an open hole. Injectivity Testing Injection tests are a commonly used method in waterflood projects to evaluate the injectivity capacity of the well and reservoir. The test involves an injection period with one or more injection rates, followed by a falloff period (Fig. 1). During the injection period, the liquid is injected at a stable rate to reduce the risk of near-wellbore formation damage caused by fluid incompatibility or exceeding the fracture gradient and inducing formation fracturing. The bottomhole-pressure data acquired during the test is analyzed using the pressure transient analysis method to estimate the permeability thickness, skin factor, and lateral heterogeneities. Additionally, the injection logging profile can be conducted along the sandface to assess completion efficiency and formation heterogeneity. By interpreting the results of the injection test, engineers can optimize the injection rate and improve the performance of the well and reservoir, ultimately leading to more-efficient oil recovery. Injectivity Test: Case Study The injectivity tests were conducted on virgin reservoirs using vertical appraisal wells that were sidetracked horizontally into the reservoirs with the greatest potential for storage. The reservoirs’ depths varied from 4,000 to 8,000 ft, with a normal gradient of reservoir pressure and temperature. The injectivity test design used reservoir properties estimated from the openhole evaluation, such as porosity, permeability, reservoir pressure, temperature, reservoir fluid sample, and fracture gradient. These data were used to set injectivity-test objectives, calculate expected well parameters, select equipment, and plan operations. The primary goal of the tests was to assess reservoir injectivity by injecting water, nitrogen, and CO2 to prove the concept for a CO2-injection project. While water and nitrogen injections are well-known in the industry, the CO2 injectivity test was new and required more attention during the design phase to evaluate all possible risks.
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Asia Government > Middle East Government > Saudi Arabia Government (0.55)
A dynamic Velocity Prediction Program (VPP) integrated in a Computational Fluid Dynamics (CFD) code is described. Aerodynamic forces are obtained either through empirical coefficients or interpolated from aerodynamics matrices. These aerodynamic forces are then input to the hydrodynamics CFD solver, which solves both the flow and the motions of the boat, resulting in a closely coupled VPP. For a given True Wind Angle and True Wind Speed a sail power parameter is optimised to obtain the best possible boat speed within heel angle constraints. This approach allows naval architects to swiftly and precisely compare several yacht designs in real sailing configurations using only a few CFD computations. Several advanced features recently added to this program are covered in this paper including convergence criteria, automatic grid refinement, foil fluid-structure interaction, multiple aerodynamics models and rudder control. Results obtained from our CFD VPP on a 40-feet fast-cruising yacht demonstrates promising agreement with other existing VPP polars, affirming the accuracy and reliability of our approach. The CFD VPP presented was also successfully applied to an IMOCA, a 60-feet racing yacht.
- Europe (0.68)
- North America > United States (0.28)