Enhancing Seismic Feature Quality with Transformer-Based Models for Mud Weight Prediction

Seismic formation pressure logs are derived from seismic data in this study. The main objective is to delineate the distribution of overpressured zones in the subsurface, and seismic data from Offshore Louisiana are used to illustrate the proposed approach. The seismic data processing consists of velocity modeling, wavelet processing, and seismic inversion. From the acoustic impedances produced by seismic inversion, seismic velocity and density "logs" are derived at every CDP location using a relationship between sonic velocities and acoustic impedances (AI). Seismic formation pressure logs are computed against depth, making use of the above seismic velocity and density logs. Formation pressure logs are calculated assuming that compressional velocity, mean density, and depth are proportional to formation pressure. These logs are constrained at every depth point by estimated matrix and fluid compressional velocities (Vmax and Vmin). Vmax and Vmin are derived using porosity and sonic well log information. Results include profiles of seismic velocity logs, seismic density logs, and seismic formation pressure logs for two intersecting seismic lines from Offshore Louisiana. One well is used to constrain the data processing. The seismic formation pressure sections delineate a large region of overpressured shales in the subsurface. INTRODUCTION An important parameter in hydrocarbon exploration and exploitation is formation (or pore) pressure. In particular, detection of abnormally high formation pressures, or "overpressured" zones, can provide valuable information for exploration and exploitation purposes. High formation pressures are common in the Gulf of Mexico. Overpressured sediments are generally caused by a sequence of events wherein water becomes. trapped by faults or nonpermeable barriers in sediments at depth where, otherwise, the water would have been forced out by normal increasing overburden pressure (Bilgeri and Ademeno, 982). Abnormal fluid pressure is also caused by release of water into the pore system during clay diagenesis (smectiteillite transformation), and other mechanisms as listed in Bruce, 1984. High formation pressures cause major changes in subsurface rock parameters. In overpressured shales (Which contain pressured water), seismic velocity is lower, density is lower, and porosity is higher than if the pressured water had been able to escape (Bilgeri and Ademeno, 1982). Detection of overpressured sediments can also contribute to the overall analysis of hydrocarbon potential of a basin. Abnormal pressures exert partial control on the type and quantity of hydrocarbons accumulated because pressure potential determines the direction of fluid flow, and overpressuring partly controls the geometry of growth faults and related folds in basins where shale structures are the dominant type formed (Bruce, 1984). In the area of hydrocarbon exploitation, knowledge of formation pressure distribution can aid in conducting safe and efficient drilling operations. In this study, several recent advances in velocity modeling, seismic wavelet deconvolution, and inversion are incorporated to more accurately derive velocity and density "logs" from seismic data in both time and depth domains. (In his paper, seismically derived "logs" refers to a derived section where each output trace, or "log", has been generated from one CDP in the original seismic section).

High Resolution, Simultaneous VSP and Land Seismic Acquisition

<p>In 2016, approximately 850 km of high-resolution multichannel seismic reflection data of the BALTEC survey have been acquired offshore Poland within the transition zone between the East European Craton and the Paleozoic Platform. Data processing, focused on removal of multiples, strongly overprinting geological information at shallower intervals, included SRME, TAU-P domain deconvolution, high resolution parabolic Radon demultiple and SWDM (Shallow Water De-Multiple). Entire dataset was Kirchhoff pre-stack time migrated. Additionally, legacy shallow high-resolution multichannel seismic reflection data acquired in this zone in 1997 was also used. All this data provided new information on various aspects of the Phanerozoic evolution of this area, including Late Cretaceous to Cenozoic tectonics and sedimentation. This phase of geological evolution could be until now hardly resolved by analysis of industry seismic data as, due to limited shallow seismic imaging and very strong overprint of multiples, essentially no information could have been retrieved from this data for first 200-300 m. Western part of the BALTEC dataset is located above the offshore segment of the Mid-Polish Swell (MPS) – large anticlinorium formed due to inversion of the axial part of the Polish Basin. BALTEC seismic data proved that Late Cretaceous inversion of the Koszalin – Chojnice fault zone located along the NE border of the MPS was thick-skinned in nature and was associated with substantial syn-inversion sedimentation. Subtle thickness variations and progressive unconformities imaged by BALTEC seismic data within the Upper Cretaceous succession in vicinity of the Kamień-Adler and the Trzebiatów fault zones located within the MPS documented complex interplay of Late Cretaceous basin inversion, erosion and re-deposition. Precambrian basement of the Eastern, cratonic part of the study area is overlain by Cambro-Silurian sedimentary cover. It is dissected by a system of steep, mostly reverse faults rooted in most cases in the deep basement. This fault system has been regarded so far as having been formed mostly in Paleozoic times, due to the Caledonian orogeny. As a consequence, Upper Cretaceous succession, locally present in this area, has been vaguely defined as a post-tectonic cover, locally onlapping uplifted Paleozoic blocks. New seismic data, because of its reliable imaging of the shallowest substratum, confirmed that at least some of these deeply-rooted faults were active as a reverse faults in latest Cretaceous – earliest Paleogene. Consequently, it can be unequivocally proved that large offshore blocks of Silurian and older rocks presently located directly beneath the Cenozoic veneer must have been at least partly covered by the Upper Cretaceous succession; then, they were uplifted during the widespread inversion that affected most of Europe. Ensuing regional erosion might have at least partly provided sediments that formed Upper Cretaceous progradational wedges recently imaged within the onshore Baltic Basin by high-end PolandSPAN regional seismic data. New seismic data imaged also Paleogene and younger post-inversion cover. All these results prove that Late Cretaceous tectonics substantially affected large areas located much farther towards the East than previously assumed.</p><p>This study was funded by the Polish National Science Centre (NCN) grant no UMO-2017/27/B/ST10/02316.</p>

Improvement of the seismic reservoir characterisation is performed by introducing an uncertainty connected to parameters in the rock physics model. Traditionally the Ensemble Kalman filter (EnKF) method has been used to estimate permeability and porosity.<br><br>In this paper we show that when seismic difference data are available also the lithology can be estimated, which is coupled to the effective bulk modulus via the rock physics model. Incorporation of inverted seismic difference data in the EnKF introduces a large amount of data in the assimilation step. Thus, to improve the results a methodology based on a combination of a global and a local analysis scheme is proposed. The global and the local analysis are used to assimilate respectively the production data and the inverted seismic difference data, where the local scheme assume that only seismic data within a certain distance from a state variable will impact the analysis in this state variable. The technique is applied to synthetic 2D and 3D reservoir models, where effects of using local versus global analysis schemes on different inverted seismic difference data, such as acoustic impedance and Poisson's ratio, are investigated. Other evaluated factors are the effects of using an incorrect seismic data error model in the analysis schemes.

Thin (<20 m), sand injectites, too small to resolve in conventional seismic reflection data, can constitute a large part of the net-to-gross volume and affect fluid flow in the reservoir. However, they may also cause challenges for well placement and reservoir development because they are too small to be reliably imaged in seismic reflection data. It is therefore important to better understand how small-scale injectites influence seismic images, and how they may be recognized and characterized above reservoirs. The Grane Field (North Sea) hosts numerous small-scale sand injectites above the main reservoir unit, challengin well placement, volume estimates and seismic interpretation. Here, we investigate how such small-scale sand injectites influence seismic images and may be characterized by (1) using well, 3D seismic and outcrop data to investigate geometries of small-scale sand injectites (0–15 m thick), (2) performing seismic convolution modelling to investigate how these would be imaged in seismic data, and (3) comparing these synthetic seismic images with actual 3D seismic data from the well-investigated Grane Field. Our results show that despite injectites being below seismic resolution, small-scale sand injectites can be detected in seismic data. They are more likely to be detected if they have high thickness (>5 m), steep dip (>30°), and when densely spaced. Furthermore, as the fraction of sand injectites increases the top reservoir amplitude will decrease. Moreover, comparison of the synthetic seismic images with real seismic data from the Grane Field indicates that the low-amplitude anomalies and irregularities observed above the reservoir may be a result of the overlying sand injectites. Additionally, the comparison strongly suggests that the Grane Field hosts sand injectites that are thicker and located further away from the top reservoir than is indicated by well observations. These results may be used to improve well planning and develop reservoirs with overlying sand injectites. Supplementary material: A PDF file containing all the seismic modelling results allowing the reader to flip back and forth between the models is available at https://www.doi.org/10.6084/m9.figshare.14333102 and well logs from well 25/11-18T2 are available at https://factpages.npd.no/pbl/wellbore_documents/2358_25_1_18_COMPLETION_REPORT_AND_LOG.pdf

Summary EnCana Corporation's Christina Lake Thermal Pilot Project located 170 km south of Fort McMurray, Alberta, Canada, uses steam-assisted gravity drainage (SAGD) technology to recover bitumen from the Lower Cretaceous McMurray formation. This paper presents an analysis of time-lapse and crosswell seismic data, as part of an overall study integrating different disciplines and technologies, to understand the effects of geology on SAGD-process performance in the pilot area. A 3D baseline survey was conducted at the start of the pilot in 2001, and two follow up surveys were conducted in 2004 and 2005. In addition, six crosswell seismic profiles were acquired by placing both sources and receivers in the vertical wellbores. The goal of the seismic surveys was to better understand steam-chamber growth and reservoir architecture by detecting lithology changes, including the occurrence and distribution of mudstone stringers. Data from the surveys, especially from the crosswell profiles, indicated significant reservoir heterogeneity, and helped to characterize reservoir architecture in the pilot area more accurately. Analysis of seismic data (both 4D and crosswell) showed steam-chamber growth and oil recovery to be influenced strongly by reservoir geology. Steam-chamber growth is especially affected by the presence of low-permeability facies in the vicinity of the SAGD well pairs. Our analysis indicates that these reservoir heterogeneities have contributed to the creation of areas within the reservoir that have been unaffected by steaming operations to date. These findings are in agreement with flow-simulation results and collectively contribute significantly to the planning of future developments.

Innovative seismic forward modeling is used to illustrate the sensitivity within seismic data, and its application in the interpretation of onlap and pinch-out of terminating deep-water sandstones, two critical components in deep-water exploration and production. Sandstone quality, net-to-gross estimates, volume calculations, vertical connectivity, and stratigraphic trapping are all dependent on the sandstone extent and their seismic characteristics in these settings. However, seismic resolution is commonly insufficient to resolve the critical reservoir parameters. Seismic modeling of termination styles based on integrated outcrop and subsurface properties allows for depth- and resolution-focused predictive models to be built for improved subsurface analysis. This technique is currently underused as a method to better understand the sensitivity of seismic data to the target lithologies and their geometries. The Grès d'Annot Formation is a well-studied sand-prone deep-water system of Paleogene age, deposited in a bathymetrically complex setting. Six end-member termination styles are discussed, including three sand-prone styles—simple onlap (O s), draping onlap (O d), and bed thickening (O t)—and three heterolithic styles—advancing pinch-out (P a), convergent pinch-out (P c), and convergent thickening and pinch-out (P ct). Local thickening close to the system margins is common in both sand-prone and heterolithic terminating strata and plays an important function in the appropriate distribution of sandstone. The outcrops are interpreted as potential (process) analogs for the complex sandstone distribution and termination patterns observed in plays like the Paleogene of the Gulf of Mexico and the Jurassic of the northern North Sea.

Seismic data is a critical source for examining and understanding subsurface structures. It is used in various fields such as oil exploration, geological research, mining, underground infrastructure planning, environmental monitoring, and conservation. The analysis and interpretation of these data are often complex and time-consuming. Deep learning, on the other hand, is recognized for its ability to identify complex patterns in large datasets. Deep learning models can be used to address challenges such as understanding complexity, noise reduction, and feature extraction in seismic data. The role of deep learning methods in seismic data analysis is increasingly significant because these techniques offer the potential to obtain more accurate results and discover new opportunities in seismic interpretation. This contributes to making the seismic interpretation process more efficient and enhancing the understanding of subsurface structures. This study focuses on interpreting seismic data using deep learning methods and examines how deep learning models can be utilized in seismic interpretation. The results of the study demonstrate that deep learning models can effectively address complexity in seismic data and perform automatic feature extraction. These findings highlight the potential of deep learning methods in the field of seismic interpretation and shed light on future research directions.

The collection of a range of different seismic data types has greatly improved our understanding of the crustal architecture of Australia's Archaean Yilgarn Craton over the last few years. These seismic data include broadband seismic studies, seismic receiver functions, wide-angle recordings and mine-scale to deep seismic reflection transects. Each data set provides information on the three-dimensional (3D) tectonic model of the Yilgarn Craton from the craton scale through to the mine scale. This paper demonstrates that the integration and rationalisation of these different seismic data sets into a multi-scale 3D geological/seismic model, that can be visualised at once in a single software package, and incorporating all available data sets, significantly enhances this understanding. This enhanced understanding occurred because the integrated 3D model allowed easy and accurate comparison of one result against another, and facilitated the integrated questioning and interrogation across scales and seismic method. As a result, there are feedback questions regarding understanding of the individual seismic data sets themselves, as well as the Yilgarn Craton as a whole. The methodology used, including all the data sets in the model range, had to allow for the wide range of data sets, frequencies and seismic modes. At the craton scale, P-wave, S-wave and surface wave variations constrained the 3D lithospheric velocity model, revealing noticeable large-scale velocity variations within and across the craton. An interesting feature of the data, easily identified in 3D, is the presence of a fast S-wave velocity anomaly (> 4.8 km s − 1 ) within the upper mantle. This velocity anomaly dips east and has a series of step-down offsets that coincide approximately with province and terrane boundaries of the Yilgarn Craton. One-dimensional receiver function profiles show variations in their crustal velocity across the craton. These crustal velocity variations are consistent with the larger-scale geological subdivision of the craton, and provide characteristic profiles for provinces and terranes. The receiver function results and the deep seismic reflection data both agree on the depth to the Moho, and both indicate an increase in Moho depth to the east. The 2D seismic refraction results in the south-west of the craton provide crustal thickness information, an indication of middle and lower crustal compositions, and information regarding the broad-scale architectural framework. At the province- and terrane-scale, the deep seismic reflection data and the mine-scale seismic data provide geometric constraints on crustal architecture, in particular the orientation of the region's fault systems as well as variations in the thickness of the granite–greenstone succession. Integration of the results from wide-angle seismic refraction data coincident with the deep seismic reflection data provided additional constraints on likely upper crustal lithologies. The integrated 3D seismic model implies the dominant geodynamic process involved the development of an orogenic belt that developed with a series of contractional (folding and thrusting) events, separated by equally important extensional events. The seismic reflection data in particular suggests that extensional movement on many shear zones was more common than previously thought. The seismic reflection data suggest that the dominant mineral systems involved deeply sourced fluid flowing up crustal-penetrating shear zones. These deeply sourced fluids were further focussed into sites located above fault-breached domal regions in the upper crust.

Seismic data offer valuable spatial information that contributes to the development strategy, such as drilling decisions and well planning. Inverting 3D seismic reflectivity data to impedance unlocks the potential of using seismic data to estimate the lateral variability and to predict reservoir geomechanical behaviour. The geomechanical model contributes for the evaluation of wellbore stability, frackability and drilling direction. The objective of this work is to illustrate the use of seismic derived models for reservoir and geomechanical properties, such as total porosity, total organic carbon (TOC) and rock rigidity. These properties are instrumental to characterize tight reservoirs and useful tools for defining a horizontal well trajectory.The study area has an exploration potential of unconventional reservoirs, targeting tight carbonates from Upper Jurassic. To date, only one well has been drilled in the area of the interest and high quality 3D seismic data is available. The process consists of conducting seismic inversion, using the well and the 3D PSTM seismic data, and resulting in the generation of 3D subsurface impedance model. The well-log relationships between impedance and reservoir quality (effective porosity, source richness) and completion quality (brittleness) were determined and showed high correlation. Hence, 3D rock quality and geomechanical volumes were derived to characterize the behaviour of the reservoir target.Seismic derived properties models yield a better description of the reservoir heterogeneity than using seismic reflectivity data only. The horizontal well trajectory was planned taking into account the observed and significant lateral variability revealed by the 3D models estimated based on seismic inverted data.The results obtained using this methodology demonstrate the importance of integrating geophysical characterisation as a relevant supporting factor in the drilling decision making process. In particular, it validates the use of seismic derived reservoir and completion quality models as an additional tool in the definition of a horizontal well trajectory in a tight/unconventional deep gas target.

Accurate subsurface modeling and characterization require the prediction of facies and rock properties within the reservoir model. This is commonly achieved by inverting geophysical data, such as seismic reflection data, using a two-step approach either in the discrete or the continuous domain. We have adopted an iterative simultaneous method, namely, stochastic perturbation optimization, to invert seismic reflection data jointly for facies and rock properties. Facies first are simulated according to a Markov chain model, and then rock properties are generated with stochastic sequential simulation and cosimulation conditioned to each facies. Elastic and seismic data are computed by applying a rock-physics model to the realizations of petrophysical properties and a seismic convolutional model. The similarity between observed and synthetic seismic data is used to update the solution by perturbing facies and rock properties until convergence. Coupling the discrete and continuous domains ensures a consistent perturbation of the reservoir models throughout the iterations. We have evaluated the method in a 1D synthetic example for the estimation of facies and porosity from zero-offset seismic data assuming a linear rock-physics model to demonstrate the validity of the method. Then, we apply the method to a real 3D data set from the North Sea for the joint estimation of facies and petrophysical properties from prestack seismic data. The results show spatially consistent rock and fluid inverted models in which the predicted facies reproduce the vertical ordering as observed in the well data.

On the Pacific margin off central Costa Rica, an anomalous lens-shaped zone is located between the overriding plate and the subducting oceanic lithosphere approximately 25 km landward of the deformation front. This feature was previously recognized in reflection seismic data when it was termed 'megalens'. Its origin and seismic velocity structure, however, could not unambiguously be derived from earlier studies. Therefore during RV SONNE cruise SO163, seismic wide-angle data were acquired in 2002 using closely spaced ocean bottom hydrophones and seismometers along two parallel strike and two parallel dip lines above the 'megalens', intersecting on the middle slope. The P-wave velocities and structure of the subducting oceanic Cocos Plate and overriding Caribbean Plate were determined by modelling the wide-angle seismic data in combination with the analysis of coincident reflection seismic data and the use of synthetic seismograms. The margin wedge is defined by high seismic velocities (4.3-6.1 km s(-1)) identified within a wedge-shaped body covered by a slope sediment drape. It is divided into two layers with different velocity gradients. The lower margin wedge is clearly constrained by decreasing velocities trenchward and terminates beneath the middle slope at the location of the 'megalens'. Seismic velocities of the 'megalens' are lower (3.8-4.3 km s(-1)) relative to the margin wedge. We propose that the 'megalens' represents hybrid material composed of subducted sediment and eroded fragments from the base of the upper plate. Upward-migrating overpressured fluids weaken the base of the margin wedge through hydrofracturing, thus causing material transfer from the upper plate to the lower plate. Results from amplitude modelling support that the 'megalens' observed off central Costa Rica is bound by a low-velocity zone documenting fluid drainage from the plate boundary to the upper plate.

Seismic data and core from the shallow cartographic Pilzno P-7 borehole were used to construct a new model of the Carpathian orogenic front between Tarnów and Pilzno, in the Pogórska Wola area (southern Poland). The most external, frontal thrust of the orogenic wedge (the Jaśniny structure) was identified as a syn-depositional fault-propagation fold detached above the Upper Badenian evaporites. Its formation was controlled by the presence of mechanically weak foredeep evaporites and by the morphology of the sub-Miocene Meso-Paleozoic foreland plate (Jaśniny and Pogórska Wola palaeovalleys). The frontal zone of the Carpathian orogenic wedge (the Skole thrust sheet and the deformed foredeep deposits of the Zgłobice thrust sheet) is characterized by significant backthrusting of the foredeep succession towards the south, and by the presence of a triangle zone, with strongly deformed Upper Badenian evaporites of the Wieliczka Formation in its core. The triangle zone was formed during the latest thrusting movements of the Carpathians. An indication of the existence of the triangle zone in the vicinity of Dębica has also been provided by reinterpretation of the archive regional geological cross-section. The youngest foredeep deposits, brought to the surface above the backthrust, have been dated as Sarmatian (NN7 nannoplankton zone), which indicates that the latest thrust movements within the frontal Carpathian orogenic in the vicinity of Tarnów–Dębica took place approx. 11–10 million years ago. Thermochronological studies (AFT and AHe) indicated that the foredeep succession drilled by the Pilzno P-7 borehole has not been buried deeper than 1.5–2 km, which is compatible with reconstruction based on the seismic data.

We present an integrated study of fracture detection by analyzing the seismic anisotropy in the 3D P-wave seismic data from Caidamu Basin in Northwest China. The study area lies on a big anticline which runs from southeast to northwest with the area around 400 km2, and each flank of the anticline develops a reverse fault. The target layer is a fractured gas reservoir at a depth of around 3 km just under the anticline. We first study the fracture characteristics from outcrop analogues, core samples and well logs. We then analyze the coherence and curvature attributes from post-stack seismic data, and azimuthal variation of amplitude and traveltime from pre-stack seismic data. After a careful and integrated analysis, we find that fractures are widespread and regularly distributed in the middle of study area along the anticline strike, and form good pathways and store space for fluid. The final results estimated using azimuthal analysis of pre-stack seismic amplitude data are consistent with results of core and log analysis at the well locations, which extended our knowledge of the fracture distribution in the reservoir.

Seismic wave attenuation has strong, negative effect on the seismic data resolution. The high influence of this phenomenon was observed during realization of seismic survey Duza Wolka 3D (Geofizyka Krakow S.A. 2010a). The resolution of recorded seismic data was very low due to high attenuation caused by the Lower Triassic Buntsandstein sandstones. In consequence, interpretation of the thin-layered Zechstein formation is ambiguous. The aim of this paper is to present the multi-stage algorithm for the purpose of minimizing the attenuation effect, hence increasing the resolution of the seismic data. In order to achieve this, the inverse Q filtering process was used. The Q factor (quality factor) was estimated from the vertical seismic profiling data (Geofizyka Krakow S.A. 2010c). To verify the effectiveness of inverse Q filtering, seismic modelling was performed. Results received from seismic modelling gave basis for application the inverse Q filtering on real data. For this operation the seismic time profile inline 112 was chosen from the seismic data set Duza Wolka 3D. Application of inverse Q filtering significantly increased the seismic resolution, which enabled the interpretation of the Zechstein formation with more accuracy.