Seal Analysis Research Articles

Frictional strength of siliciclastic sediment mixtures in fault stability assessment

Frictional strength of fault zones is a key parameter for evaluation of fault stability and reactivation. We measure friction using the direct shear test (DST) for (i) sand-clay mixes mimicking fault gouges, and (ii) strength of fault zone interfaces. The sand-clay mixing ratio is linked to the established Shale Gouge Ratio (SGR) used in fault seal analysis, suggesting an approach for linking the measured frictional properties to the established subsurface fault characterization methods and risk assessment. We use powdered caprock material from the Draupne Formation mixed with sand to prepare the fault gouge and discuss application of results for fault zones on the Horda Platform, Norwegian North Sea.Shearing of fault gouge show a systematic decrease in residual friction coefficient with increasing clay content from 0.6 (φ = 31°) in pure sand (SGR 0%) to 0.4 (φ = 22°) for clay rich mixtures (SGR 100%). Interface testing mimicking fault gouge on sand surface is less systematic and shows residual friction coefficients ranging from 0.53 to 0.6 (φ = 28–31°) for SGR 0–50%. Detailed interpretation of the shear testing results shows changes in drainage properties, volumetric changes during shearing and shear responses to normal stresses indicating threshold values for sand versus clay dominated material behaviour. However, the results are non-conclusive on the question if a linear variation of friction with clay content or a threshold between sand dominated versus clay dominated friction provides the best approach for linking friction to fault clay content.

Implication of fault seal analysis method to evaluate the sealing conditions of major fault planes at Barapukuria basin, North-West Bangladesh

The Barapukuria coal basin stands as Bangladesh’s sole active underground coal mining site. The geological setting of this basin is marked by two major faults, the Eastern Boundary Fault and FB fault encircling the basin perimeter, alongside several smaller faults and those induced by underground longwall mining activities. A major concerning issue of this mine is the water inrush into the mine area from the extensive groundwater aquifer, Upper DupiTila (UDT). Using the Fault Seal Analysis technique employed by (Yielding et al. in Am Assoc Pet Geol Bull 81:897–917, 1997) algorithm, this analysis attempts to identify susceptible areas and potential unsealed faults that could provide the risk of water invasion into the mine area. Evaluation of Fault Seal Analysis reveals varying Shale Gauge Ratio (SGR) values: 0.08 and 0.13 for the major Eastern Boundary Fault, 0.05 for the second largest FB fault, 0.35 and 0.53 for FB-1, and 5.65, 1.69, and 1.22 for the smaller faults BGP-N-F11, BGP-N-F2, and F-24, respectively. According to SGR values, the Eastern Boundary Fault and the FB fault plane are anticipated to be unsealed and dip westward at an angle of 75°-80°, rendering them vulnerable to water inflow through the fault planes. The analysis also suggests that the Lower DupiTila (LDT) aquiclude which can impede the groundwater flow from the UDT aquifer into the mine area, is very thin or absent in the northern region of the basin making this region highly susceptible to water inundation.

Evaluating CO 2 retention risk of geological sequestration sites: physical, time-scale, and site style considerations

With some exceptions, such as fluid phase, pressure evolution, and reservoir geometry, evaluation of CO 2 retention for geological sequestration sites primarily involves well-established seal and trap concepts and methods developed by the petroleum industry. Inputs to a CO 2 retention evaluation (e.g. bed seal capacity analysis) include CO 2 phase, CO 2 and brine density, reservoir pressure and temperature, rock properties, and stress state. The inputs are used to perform capillary and mechanical seal analyses similar to the petroleum industry, but unlike hydrocarbons, CO 2 retention also occurs within the reservoir pore volume by capillary and solubility trapping, adding additional requirement for analyses using reservoir engineering concepts and methodology. Reservoir geometry types for CO 2 storage include conventional traps (depleted hydrocarbon fields, brine-filled traps) and brine-filled reservoirs that lack a conventional trap geometry (e.g. a monocline). Each geometry style and project phase (injection, near-term post-injection, long-term static) requires different retention considerations, for example the CO 2 plume extent and height. Based on a retention evaluation, retention risk and uncertainty may be articulated using a qualitative risk matrix that facilitates early screening, identification of data needs, possible mitigating strategies, and comparisons across a portfolio of potential sites. Thematic collection: This article is part of the Geoscience workflows for CO 2 storage collection available at: https://www.lyellcollection.org/topic/collections/geoscience-workflows-for-CO2-storage

Mechanical, Rheological, and Heat Seal Properties of 1‐Octene Grafted Low Density Polyethylene Films

AbstractHeat seal and mechanical properties of 1‐octene grafted low density polyethylene films containing various concentrations of Dicumyl peroxide as the initiator and 1‐octene grafting agent is investigated through using experimental measurements. The results of differential scanning calorimeter (DSC) measurements revealed that the melting temperature shifts to higher values and the peak of the DSC curve becomes wider with the increase of 1‐octene concentrations. Thermogravimetric analysis (TGA) revealed a higher thermal stability up to 20 °C for 1‐octene grafted PE compared with neat LDPE alloy. The results of stress–strain measurements revealed that the 1‐octene grafted PE alloys has higher tensile strength in comparison with neat PE alloy and samples containing only DCP initiator. The results of heat seal analysis indicated that both DCP initiator and 1‐octene tended to offer a moderate increase peel strength of PE alloy. DMTA measurements for various grafted PE alloys show a higher damping factor in comparison with neat LDPE alloy. Rheological measurements indicated a higher storage modulus up to 25% and higher complex viscosity for grafted PE samples containing 1‐octene comonomer.

Shale Gouge Ratio (SGR) 3D Model for Quantitative Characterization of Fault Seal Analysis

Shale Gouge Ratio (SGR) 3D Model for Quantitative Characterization of Fault Seal Analysis

Assessing the impact of hydrodynamics on capillary seal capacity: application of the Manzocchi & Childs model in trap analysis workflows

The evaluation of seal in conventional stratigraphic and structural traps requires the characterization of the capillary top seal to assess the capacity to hold a hydrocarbon column. Typically, this seal analysis addresses the static seal and does not consider the role that hydrodynamics (the flow of water into or out of the reservoir) may play in influencing the seal capacity. Although possessing extremely low permeability, shale seals are not perfect seals and water can seep through them under an imposed hydraulic gradient. Likewise, water can move vertically through trapped hydrocarbon columns even though relative permeabilities are very low. The impact of this flow on the capillary seal capacity can, in theory, be quite profound and should be considered in seal analysis workflows. This paper revisits the Manzocchi & Childs model for hydrodynamic effects on capillary seals and employs it directly in real-world trap analysis. The implementation of this model is described, and a workflow developed to incorporate the impact of hydrodynamics into column height prediction. The technique is applied to several known over-pressured fields from the Norwegian continental shelf to evaluate its applicability. Preliminary results from Monte Carlo modelling are promising and with some agreement between the observed column heights and the predicted hydrodynamic seal-controlled columns, dependant on the parameterization used. Further testing is ongoing, but the methodology should be considered in exploration prospect evaluation. The impact of hydrodynamics on seal capacities should not be discounted. Thematic collection: This article is part of the Fault and top seals 2022 collection available at: https://www.lyellcollection.org/topic/collections/fault-and-top-seals-2022

A multi-disciplinary approach for trap identification in the Southern Meleiha Area, North Western Desert, Egypt: integrating seismic, well log, and fault seal analysis

The southern Meleiha concession, situated within the development encouragement areas of the Agiba Petroleum Company between Matrouh Basin and Shushan basin, spans approximately 700 km2. This study examined late Cretaceous strata to improve trap identification in the Bahariya, Alamein Dolomite, and Alam El Bueib Members. This required a thorough study of 33 seismic lines and five well log records. Our investigations revealed the presence of hydrocarbons in the deep, mid, and shallow target zones, underscoring the significant potential of the Khatatba-Ras Qattara and Bahariya layers. The net pay thicknesses observed ranged from 12 to 43 feet, while effective porosity values fluctuated between 10 and 18%. Water saturation varied from 10 to 98%, while hydrocarbon saturation varied from 48 to 90%. Seismic interpretation revealed abundant normal faults in the study area, and our maps showed structural closures, including three-way and four-way dip closures, influenced by these faults. The shallowness of the Bahariya layer, coupled with Shally Sand facies intercalations in the upper target, makes it particularly susceptible to fault leakage, necessitating careful consideration when selecting drilling locations. Notably, the western half of our investigation area exhibited more Alam El Bueib Member net pay zones compared to the eastern and south-eastern regions. The geological structure of the deep-target Khatatba-Ras Qattara is of particular interest, revealing a total of 37 potential leads across all levels. These leads encompass destinations like Bahariya, Alam El-Bueib, and Khatatba formations, some of which may have dual targets, while others may focus on a single objective.

Fault seal analysis for VS area, block 16 -1/15, Cuu Long Basin, Viet Nam

Fault-bound traps represent an important class of hydrocarbon-bearing structure. Whether a fault can seal hydrocarbons on a geological timescale may be controlled by one or more of three conditions: (1) sealing due to lithological juxtaposition, where reservoir rock is juxtaposed against sealing rock across the fault; (2) sealing by the fault damage zone, which forms a barrier composed of low-permeability clay within the fault zone and (3) the tectonic activity of the fault, as during faulting, hydrocarbon accumulations can be destroyed and leakage along the fault zone. This research employs an indirect method to establish a correlation between pressure and the sealing properties on fault surfaces, such as the SGR (Shale Gouge Ratio), across various formations under the same geological conditions from all fields within the region and around the world. This aids in assessing the sealing potential of the faults. Evaluate the fault seal capacity according to 3D model for the structures in Oligocene D, Oligocene C and Lower Miocene sediments to serve the assessment hydrocarbon potential in VS area and reduce the risk for further exploration - appraisal work in block 16-1/15, Cuu Long basin. Geology, seismic and petrophysical data were used to construct 3D structural frameworks, lithology model and Vclay model. Parameters such as fault throw, Vshale, lithology, bed thickness, burial depth history, fluid density and pressures, ect. are incorporated into fault seal analysis and also estimate the maximum hydrocarbon column height can be held by each fault in study area, therefore helping to assess the hydrocarbon potential in undrilled structures in VS area.

Field, Western Desert, Egypt

This study aims to overcome the unexpected hydrocarbon non-potentiality detected in the upper Alam El-Bueib (I to IIIE) and justify the hydrocarbon accumulation within Alam El-Bueib (IIIG) at the Emry oil field, also, it is important to highlight the importance of fault seal analysis and the impact of Matruh canyon as a seal. Seismic interpretation and 3D structural framework are carried out using the fault-seal analysis technique for fault no.1 (F1). To assess the fault zone's capacity to be defined as either seal or leakage. Litho-facies juxtaposition diagram (Allan diagram) and Shale Gouge Ratio (SGR) were generated. It is concluded that the possible reason for the dry reservoir of the upper part of Alam El Bueib (Alam El Bueib I to IIIE) due to the leakage of the fault (F1). On the other hand, the seal mechanism for Alam El Bueib IIIG is mainly related to increasing the thickness of the Matruh shale and Matruh Canyon act as a seal rock. SGR for Alam El Bueib IIIG is around 80%, which confirms the presence of the shale in Matruh Canyon is the reason for accumulating the hydrocarbon at Alam El Bueib IIIG.

Carbon capture and storage – a safe and reliable monitoring and verification plan developed using oil and gas industry core skill sets

Carbon capture and storage (CCS) is a necessary technology essential for meeting global emissions targets and limiting the impact of climate change – all identified pathways to global net-zero 2050 emissions targets require significant scale-up and deployment of CCS. The Moomba CCS project is an example of the type of projects that will reduce emissions and enable decarbonisation technology such as Direct Air Capture (DAC). The first phase of the project will utilise depleted hydrocarbon fields in the Cooper Basin, South Australia, to safely capture and permanently store 1.7 Mtpa CO2 that is currently vented. This paper will highlight the oil and gas industry’s unique skill sets that make it ideally placed to measure, monitor and verify the permanent storage of CO2 in geological formations. A monitoring and verification plan (M&V plan) has been developed based on SEO and ISO standards that encompasses four key elements: injection telemetry, reservoir surveillance, well integrity and environmental assurance. The plan was developed using a methodical approach to identify key risks, evaluate consequences, take preventative actions and put mitigating controls in place. Core oil and gas industry skill sets were utilised for the evaluation such as geomechanical and geochemical analysis, seal analysis, fault interpretation and reservoir modelling of CO2 migration. A program of surveillance activities will be undertaken to monitor and verify CO2 containment within the storage complex on an ongoing basis for the life of the project, and the M&V plan sets out a response plan and actions that will be taken in the case of deviation from expected performance.

Integration of charging time, migration pathways and sealing analysis to understand hydrocarbon accumulation in complex fault blocks, the Pinghu Slope Belt of the Xihu Depression, East China Sea Basin

A large number of oil and gas fields have been successfully discovered in complex fault blocks worldwide. However, the role played by the fault-rock seal in the hanging wall traps is not fully understood due to the paucity of datasets. The trap examples of the Pinghu Slope Belt are used to analyze the migration and accumulation of hydrocarbons in the complex fault blocks, as well as the fault-sealing mechanism of the hanging wall traps. The burial history in typical wells, combined with the homogenization temperature of fluid inclusions, is used to determine the hydrocarbon charging time. Based on detailed 3D seismic interpretation, the paleo-structural features at critical moments and their control on hydrocarbon migration were discussed. Hydrocarbon accumulation characteristics were illustrated based on triangle juxtaposition diagrams. The result shows that there are two hydrocarbon charging episodes in the study area, respectively, 10.6–8.1 Ma and 2.8 Ma-present, with the latter being predominant. This phenomenon that the homogenization temperatures of inclusions are generally higher than the measured formation temperatures at the same depth is attributed to late fluid accumulation and not reaching thermal equilibrium with the reservoir fluids. The analysis of hydrocarbon generation history, trap fixation history and fluid inclusions indicate that the critical moment of the generation-migration-accumulation of most hydrocarbons ranges from 2.8 Ma to the present. Due to the difficulty in effectively recognizing the reflector (the top of the Santan Fm) and the nearly horizontal sediments above T20, the reflector T20 (5 Ma) near the top of the Santan Fm was chosen as an approximate proxy for this critical time (2.8 Ma). The paleo-structures of the Pinghu Slope Belt at 5 Ma are a gentle southeast-dipping slope. Based on the numerical simulation of three different fault scenarios (no faults, closed faults and open faults), wells A-H are located on the preferential migration pathways. Fault seal analysis shows that multiple juxtaposition types on the fault surface and moderate-potential to effective SGR values at the sandstone reservoirs in the middle and lower Pinghu Formation. Lateral and vertical reservoir compartmentalizations are presented in clean sand-sand juxtapositions with low-potential sealing (SGR<20%) in well A. The SGR-buoyancy pressure relationship from hanging wall traps and the global calibration plots from footwall traps have a consistent trend. The fault sealing mechanism of hanging wall traps is similar to that of the footwall traps. Therefore， those global calibration plots can be simultaneously applied to the fault seal evaluation of both hanging wall traps and footwall traps.

A new vision for hydrocarbon trapping of Alam El-Bueib Formation in Aman oil field using Fault seal analysis technique, northern Western Desert, Egypt.

A new vision for hydrocarbon trapping of Alam El-Bueib Formation in Aman oil field using Fault seal analysis technique, northern Western Desert, Egypt.

Numerical modelling of braided ceramic fiber seals by using element differential method

• A multi-physical coupled model is proposed for the braided ceramic fiber seals. • The coupled fields contain the process of heat conduction, seepage and deformation. • Element differential method (EDM) is used to solve the multi-physical problems. • The material-dependent parameters in model are obtained by an inverse procedure. • Compared to FEM, EDM is more easy and efficient dealing with the coupled model. A new kind of dynamic seal with braided ceramic fibers has been designed to seal the movable panels in the scramjet engines, which are used for the propulsion of hypersonic vehicle. The braided ceramic fiber structure can provide buffer forces when the seals are subjected to the external dynamical preloads. However, it also makes the seals difficult to analyze. Up to now, the analysis of the seals still uses 1D models so that one cannot implement the coupled analysis of seals and their surrounding structures and flows. In this paper, a novel 2D and 3D mechanics-thermal-seepage coupled model is proposed to describe these seals, which provides a possibility for the aforementioned coupled analysis. Meanwhile, a strong-form numerical method, element differential method (EDM) is employed to discretize the governing equations of the coupled model due to its efficiency and robustness. Three examples are given. The first one is to invert the material-dependent parameters of three kinds of seal strips from the experimental data by Levenberg-Marquardt (LM) algorithm. Other two implement the analyses of 3D square and circular cross-section seals, respectively, which verify that EDM is more efficient than FEM in seal analysis when using the same mesh sizes.

Assessment of Fault Sealing in the Gabo Field, Niger Delta, Nigeria

This research assesses the sealing of the fault bounded stratigraphy of the Gabo Field, Niger Delta, Nigeria. Materials used comprises of 3D seismic volume in seg-y, ditch cuttings and well logs. The methods applied are standard fault plane evaluation techniques and they include seismic interpretation, well correlation, XRD analysis, and application of the Yielding et al., (1997) shale gouge ratio (SGR) algorithm for fault seal analysis. The tectonic framework was interpreted in terms of deformational, depositional and post-depositional structures. The order of magnitude of stress is SHmax &gt; σv &gt; Shmin. The juxtaposed strata relationships were analyzed by taking cross sections A-A1 and B-B1 and this showed the structural framework across the field. Cross section A-A1 showed that the depositional and post depositional structures are pinchouts (channel abandonment or switching) and shale smears respectively. The cross section B-B1, showed that the deformational structures are faults F1 and F2 – recognized as closely spaced normal faults and F3 is a syn-depoitional growth fault. The well correlation showed the vertical stratigraphy of the wells are comprised of cyclic succession of sands and shales and the shale thickness increased in intermediate sections. The X-ray diffraction (XRD) analysis of the shales showed that the predominant minerals are kaolinite, rutile, gypsum, albite, microcline and quartz. The rock property analysis showed that the net to gross ranges from 26.28 – 82.0% with an average of 73.7%. The volume of shale ranges from 18 – 73.72% with an average of 63.59%. The bulk density of the shales ranges from 2.379 – 2.692g/cc with an average of 2.46g/cc. The total porosity ranges from 0.159 – 0.317 with an average of 0.167 in the shales and 0.272 in the sand. The effective porosity range from 3.58 – 22.71 with an average of 6.028 in the shale and 20.13 in the reservoir. The drawdown mobility and temperature range is 2.2 – 4124.4mD/cP and 63.3 – 80.1oF respectively, while the average is 569mD/cP and 70.63oF respectively. The estimated pore pressure ranges from 0.4213 – 0.4762psi/ft with an average of 0.47psi/ft in the shales and 0.428 psi/ft in the sand. The fault seal analysis showed that the shale gouge ratio range from 0.2 – 0.7 and the stratigraphic juxtapositions are predominantly sand to sand, sand to shale and shale to shale. The results of this research reduces the fault seal uncertainty in the planning of oilfield development projects and enhanced pressure support for the recovery of bypassed hydrocarbons, most especially in compartmentalized reservoirs. In addition, the results of this research can be applied to similar deltaic successions around the world.

Faultxcel: an excel worksheet for fault seal analysis in clastic sequences

Faultxcel: an excel worksheet for fault seal analysis in clastic sequences

Fault Rock Property Prediction on Jurassic Clastics of the Barents Sea, Norway

Summary We analyzed the fault rocks of a compartmentalized field in the Barents Sea, in an area with several tectonic elements, which formed at different tectonic events. Standard fault seal analysis (FSA) was conducted to predict the shale content of the fault rock (shale gouge ratio, SGR). A static cellular model based on well data, seismic data, and geological concepts served as input. The fault rock calibration workflow required various data acquired by different methods. We analyzed the Middle Triassic to Upper Jurassic clastic deposits to reconstruct the tectonic history. Apatite fission track (AFT) and (U-Th)/He thermochronology were used to determine the maximum burial depths and exhumation history. The results of high-resolution shale ductility analysis, a compaction trend study, kinematic analysis, and structural modeling (section balancing) served as additional input constraints for fault rock calibration. The interpretation of the results helped to reconstruct the following tectonic evolution. The orthogonal faults developed shortly after deposition, during Late Triassic to Early Jurassic times at relatively shallow depth, below 1000 m. Ongoing subsidence created accommodation space for Upper Jurassic to Cenozoic deposits with a maximum burial depth of 2000 m for the Middle Jurassic rocks. Exhumation of the area started around 10 Ma and continued through to Quaternary times. The predicted across-fault-flow values for fault rock permeability show a wide range when using poorly constrained input for fault rock calibration: 9.9E−15 to 9.9E−13 m² for SGR values around 0.08 at reservoir/reservoir juxtaposition. Fault rock calibration using elaborated results reduced the uncertainty of fault rock permeability estimates, and ultimately, for transmissibility multipliers (TMs). The reason for the sensitivity of the fault rock calibration is a combination of following factors: highly permeable reservoir sandstone, shallow depth of initial faulting, maximum burial depth and low shale content at the upper, main reservoir level. The study shows that an accurate reconstruction of the geohistory provides essential parameters for fault rock calibration and fault rock permeability prediction. The range of values can widely scatter if boundary conditions are not acknowledged. Well-constrained fault rock calibration reduces the uncertainty on possible flow scenarios, increases the reliability on production forecasts and helps determine the most efficient drainage strategy.

Reducing uncertainty with fault seal analysis: A case study of Jherruck Block, LowerIndus Basin, Pakistan

Faults can be either conduits or baffles for hydrocarbon flow. Assessing the sealing potential of faults plays a vital role in reducing the risks associated with hydrocarbon exploration. The study area is located in Jherruck Block, Lower Indus Basin, Pakistan. Several intervals within the Lower Goru Formation in Lower Indus Basin are proven hydrocarbon reservoirs. The main aim of the study is to predict the cause of failure of 3 wells (Jherruck B-1, Jamali-1, and Jamali Deep-1), and to propose a new well location based on juxtaposition analysis and shale gouge ratio (SGR). The Upper Sands (sandstone) of the Lower Goru Formation (A-Sand, B-Sand, C-Sand, and D-Sand) have reservoir potential in the region including the Jherruck Block. These reservoir sands have been interpreted in seismic sections to generate time and depth surface maps. Using depth surface maps, Allan diagrams have been constructed for juxtaposition and shale gouge ratio analysis. The integration between juxtaposition and shale gouge ratio analysis suggested that the main reason for the failure of these wells was sandstone to sandstone juxtapositions leading to updip hydrocarbon leakage to the adjacent fault block. In addition to this, the shale gouge ratio indicated low shale gouge distribution in the fault zones. Allan diagram and shale gouge ratio analyses helped us to propose a new well location further northwest of Jherruck B-1 well where sands are juxtaposed against impermeable shale lithology of the Goru Formation and SGR ratio is above 80%.

Reducing uncertainty with fault seal analysis: A case study of Jherruck Block, LowerIndus Basin, Pakistan

Faults can be either conduits or baffles for hydrocarbon flow. Assessing the sealing potential of faults plays a vital role in reducing the risks associated with hydrocarbon exploration. The study area is located in Jherruck Block, Lower Indus Basin, Pakistan. Several intervals within the Lower Goru Formation in Lower Indus Basin are proven hydrocarbon reservoirs. The main aim of the study is to predict the cause of failure of 3 wells (Jherruck B-1, Jamali-1, and Jamali Deep-1), and to propose a new well location based on juxtaposition analysis and shale gouge ratio (SGR). The Upper Sands (sandstone) of the Lower Goru Formation (A-Sand, B-Sand, C-Sand, and D-Sand) have reservoir potential in the region including the Jherruck Block. These reservoir sands have been interpreted in seismic sections to generate time and depth surface maps. Using depth surface maps, Allan diagrams have been constructed for juxtaposition and shale gouge ratio analysis. The integration between juxtaposition and shale gouge ratio analysis suggested that the main reason for the failure of these wells was sandstone to sandstone juxtapositions leading to updip hydrocarbon leakage to the adjacent fault block. In addition to this, the shale gouge ratio indicated low shale gouge distribution in the fault zones. Allan diagram and shale gouge ratio analyses helped us to propose a new well location further northwest of Jherruck B-1 well where sands are juxtaposed against impermeable shale lithology of the Goru Formation and SGR ratio is above 80%.

Impacts of seismic resolution on fault interpretation: Insights from seismic modelling

Seismic mapping of subsurface faults is hampered by factors such as seismic resolution, velocity control for depth conversion and human bias. Here, we explore the challenges and pitfalls related to interpreting normal faults by comparing objective and subjective uncertainties. A panel of 20 interpreters, with different geoscientific backgrounds, interpreted faults in modern conventional (dominant frequency 40 Hz) and high-resolution P-Cable (dominant frequency 150 Hz) 3D seismic data from the Hoop area, SW Barents Sea. The interpretations created by the test-panel were sorted into 10 scenarios characterized by different fault geometries. These scenarios were explored with 2(3)D point-spread function based convolution seismic modelling to investigate the potential of seismic data to image detailed fault architectures. The results reveal that: (1) Statistical analysis shows considerable variations between manually picked faults. (2) Identifying the location of fault tips is challenging and smaller antithetic faults are rarely recognizable. (3) Uncertainties arise from masking of closely spaced fault segments even where displacement values are large, showing distorted reflection signatures of apparent extensional fault tip monoclines. The distortion is larger for conventional versus high-resolution data. (4) In the conventional and high-resolution seismic data the vertical resolution of closely spaced reflections and small offset faults is 20 m and 5 m, respectively. (5) The utilisation of high-resolution seismic data, combined with seismic modelling, add confidence to interpretation of conventional seismic data in the same area. We conclude that subsurface fault mapping with seismic data requires insight in objective uncertainties associated with the data. Automatic machine-learning fault interpretation is void of subjective bias but still hampered by objective limitations. Further, a risking workflow requires acknowledgement of uncertainties that are transferred to seismic based fault analysis techniques such as juxtaposition analysis, quantitative fault seal analysis, and fault stability analysis.

Fault interpretation uncertainties using seismic data, and the effects on fault seal analysis: a case study from the Horda Platform, with implications for CO&amp;lt;sub&amp;gt;2&amp;lt;/sub&amp;gt; storage

Abstract. Significant uncertainties occur through varying methodologies when interpreting faults using seismic data. These uncertainties are carried through to the interpretation of how faults may act as baffles or barriers, or increase fluid flow. How fault segments are picked when interpreting structures, i.e. which seismic line orientation, bin spacing and line spacing are specified, as well as what surface generation algorithm is used, will dictate how rugose the surface is and hence will impact any further interpretation such as fault seal or fault growth models. We can observe that an optimum spacing for fault interpretation for this case study is set at approximately 100 m, both for accuracy of analysis but also for considering time invested. It appears that any additional detail through interpretation with a line spacing of ≤ 50 m adds complexity associated with sensitivities by the individual interpreter. Further, the locations of all seismic-scale fault segmentation identified on throw–distance plots using the finest line spacing are also observed when 100 m line spacing is used. Hence, interpreting at a finer scale may not necessarily improve the subsurface model and any related analysis but in fact lead to the production of very rough surfaces, which impacts any further fault analysis. Interpreting on spacing greater than 100 m often leads to overly smoothed fault surfaces that miss details that could be crucial, both for fault seal as well as for fault growth models. Uncertainty in seismic interpretation methodology will follow through to fault seal analysis, specifically for analysis of whether in situ stresses combined with increased pressure through CO2 injection will act to reactivate the faults, leading to up-fault fluid flow. We have shown that changing picking strategies alter the interpreted stability of the fault, where picking with an increased line spacing has shown to increase the overall fault stability. Picking strategy has shown to have a minor, although potentially crucial, impact on the predicted shale gouge ratio.