Md Nazmul Haque Mondol

• Ahmed, Nisar; Weibull, Wiktor Waldemar; Mondol, Md Nazmul Haque; Luo, Xiaodong & Mardan, Amir (2026). Seismic Pre-stack Inversion Using Iterative, Nonlinear Quasi-Second-Order Optimization Techniques. Mathematical Geosciences. ISSN 1874-8961. doi: 10.1007/s11004-026-10279-9. Fulltekst i vitenarkiv Vis sammendrag

  Seismic inversion contributes significantly to the estimation of subsurface properties based on seismic reflection data, serving as an essential step in reservoir modeling. Unlike conventional post-stack acoustic impedance inversion, this study presents a model-based nonlinear pre-stack inversion approach to estimate acoustic impedance, shear impedance, and density models, which are crucial for mapping subsurface lithofluid properties. The inversion algorithm comprises a convolutional model using a linearized amplitude versus offset approximation, the sum of squares of data misfit between theoretical model predictions and actual observations, and a Hessian-free conjugate gradient method and a nonlinear limited-memory quasi-Newton algorithm, which approximates second-order Hessian behavior, are employed to iteratively minimize the data misfit by fitting trial models to observed data. As the key novelty of this work, analytical adjoint-state gradients for acoustic (P-wave) and shear (S-wave) impedances are explicitly derived, which can eliminate the computational burden of finite-difference gradient approximations typically used in seismic inversion, while significantly improving the efficiency and scalability of large-scale seismic inversions. Meanwhile, Tikhonov and total variation regularization constraints are also applied to generate smooth estimated models for the ill-conditioned inverse problem. The proposed inversion technique is evaluated using a synthetic example based on one-dimensional well logs, a two-dimensional Marmousi model, and Troll field data from the Norwegian North Sea. Our investigations indicate that the estimated impedances and density models are accurate and stable, and the method provides good convergence to an optimal solution to the nonlinear inverse problem. A comparison of the sensitivity of the inversion results to the initial models is performed using Monte Carlo simulation and continuous ranked probability scores.

• Bohloli, Bahman; Bjørnarå, Tore Ingvald & Mondol, Md Nazmul Haque (2025). Geologic/Natural hydrogen potential in Norway. doi: 10.3997/2214-4609.202521157. Fulltekst i vitenarkiv
• Rahman, Md Jamilur; Huff, Owen Rohwer; Ahmadigoltapeh, Sajjad; Faleide, Jan Inge; Fawad, Manzar & Mondol, Nazmul Haque (2025). A Simple Method for Estimating Shale Brittleness From Seismic Data: An Example From Offshore Norway. Geophysical Prospecting. ISSN 0016-8025. 73(7). doi: 10.1111/1365-2478.70076. Fulltekst i vitenarkiv Vis sammendrag

  The brittleness of a caprock layer is an important property to measure, as it influences sealing integrity for subsurface fluid injection projects. However, brittleness is a complex function of various factors, such as mineral composition, diagenesis and effective stress, and consequently can vary spatially. Because well log‐based methods for brittleness estimation are often spatially limited, we develop a simple workflow to estimate the brittleness of a shale formation directly from seismic data. The shale in question is the Draupne Formation of the Upper Jurassic age, which acts as a primary seal of Viking Group sandstones in the Horda Platform area of the northern North Sea for hydrocarbon extraction (e.g., the Troll field) and geological CO 2 storage (e.g., Smeaheia). First, well log data from 26 wells in the Horda Platform area is aggregated, focusing on the compressional sonic, bulk density and resistivity values of the Draupne Formation. This data are used to establish a linear model relating the acoustic impedance and elastic properties‐estimated brittleness index (BI) of the Draupne Formation; these two quantities display a correlation of 0.86. By combining this acoustic impedance information with a wavelet extracted from field seismic data and using average acoustic properties for the relatively homogeneous underlying sandstone reservoir, synthetic seismograms corresponding to different BI values of the Draupne Formation are generated. The amplitudes extracted from the synthetic seismograms are then used to establish a quadratic model relating seismic amplitudes at the base Draupne reflection with the BI. Applying this quadratic model on a 2D seismic line from the Stord Basin (south of the Horda Platform) results in BI values that are close to elastic‐properties‐based values at wells which intersect the seismic line and an expected trend of increasing brittleness with respect to depth. This integrated method can be used as part of a workflow to characterize top seal effectiveness, which may be useful in fluid storage prospect evaluation.

• Falcon-Suarez, I.H.; Mangriotis, M.-D.; Papageorgiou, Georgios & Mondol, Nazmul Haque (2024). Impact of Fluid Distribution and Petrophysics on Geophysical Signatures of CO<inf>2</inf> Storage Sandstone Reservoirs. Journal of Geophysical Research (JGR): Solid Earth. ISSN 2169-9313. 129(5). doi: 10.1029/2024JB029027. Fulltekst i vitenarkiv Vis sammendrag

  Carbon Capture and Storage (CCS) is a key element to achieving net-zero energy challenge timely. CCS operations require the integration of geophysical data, such as seismic and electromagnetic surveys, numerical reservoir models and fluid flow simulations. However, the 10–100s m resolution of seismic imaging methods complicates the mapping of smaller scale rock heterogeneities, while borehole measurements commonly show large fluctuations at sub-cm scales. In this study, we combine laboratory data, well-logging, rock physics theories and a proof-of-concept time-lapse seismic modeling to assess the effect of pore-scale fluid distribution and petrophysical heterogeneities on the expected performance of whole-reservoir CCS operations in deep saline aquifers, by analogy to the Aurora CCS site, North Sea. We monitored the elastic and electrical properties of three sandstone samples with slightly different physical and petrographic properties during carbon dioxide (CO2) flow-through tests under equivalent in situ effective pressure. We inferred the CO2-induced damage in the rocks from the variations of their hydromechanical properties. We found that the clay fraction, CO2-clay chemical interactions, and porosity were the main factors affecting both the CO2 distribution in the samples and the hydromechanical response. We used seismic modeling of well-log data and the laboratory results to estimate the reservoir-scale time-lapse seismic response to CO2 injection and to assess the effect of the rock heterogeneities in our interpretation. The results show that disregarding the effect of rock heterogeneities on the CO2-brine fluids distribution can lead to significant misinterpretations of seismic monitoring surveys during CCS operations in terms of both CO2 quantification and distribution.

• Rahman, Md Jamilur; Fawad, Manzar & Mondol, Nazmul Haque (2024). Integrated containment risks assessment for subsurface CO<inf>2</inf> storage: Overburden analysis and top seal integrity study, offshore Norway. International Journal of Coal Geology. ISSN 0166-5162. 282. doi: 10.1016/j.coal.2023.104440. Fulltekst i vitenarkiv Vis sammendrag

  This study summarizes the OASIS (Overburden Analysis and Seal Integrity Study for CO2 Sequestration in the North Sea) project that focuses on assessing the containment risks associated with the geological carbon sequestration (CCS) of the Northern Lights project. CCS is viewed as one of the most effective solutions for reducing carbon emissions, as it captures carbon dioxide from point sources and permanently stores it in suitable geological formations. However, injecting CO2 into the subsurface may have mechanical consequences, including fault reactivation, top seal fracturing, surface heave, etc. This study proposes an interdisciplinary workflow to characterize the caprock, faults, and overburden associated with CCS projects in the Horda Platform area, to improve injection-induced containment risk assessment. Our findings show that the proposed workflows and tools effectively characterize stress-related mechanical hazards. However, due to the complex nature of rocks, it is challenging to evaluate the top seal integrity using a single method. Therefore, the proposed interdisciplinary approach is more effective for any fluid injection site's characterization, given the complex nature of the subsurface and its behavior under injection-induced stress changes. This research paper adds knowledge about the top seal integrity assessment and the reliability of injected CO2, making CCS projects more reliable and safer. Although this study focuses on the northern North Sea, the proposed methods are equally applicable globally to characterize subsurface CO2 storage sites. Apart from CCS projects, these research results can benefit other subsurface injection projects, such as water injection for reservoir management, wastewater injection for disposal, hydrogen storage, and hydraulic fracturing for unconventional hydrocarbon resources.

• Rahman, Md Jamilur; Fawad, Manzar & Mondol, Nazmul Haque (2024). Potential secondary seals within overburden: Observation from the CO<inf>2</inf> storage sites Aurora and Smeaheia, northern North Sea. International Journal of Greenhouse Gas Control. ISSN 1750-5836. 133. doi: 10.1016/j.ijggc.2024.104101. Fulltekst i vitenarkiv Vis sammendrag

  This study evaluates potential secondary seals within the overburden in two CO2 storage sites, Aurora and Smeaheia within the Horda Platform area, of the northern North Sea. Secondary sealing intervals provide for safe and reliable CO2 storage as they prevent injected fluids from migrating into the atmosphere in the case of primary seal failure. This study analyzes the possible fate of the CO2 plume in the case of primary seal failure for the Aurora and Smeaheia CO2 storage sites by evaluating the secondary caprock and sealing potential of polygonal fault systems within the overburden intervals using structural reliability methods. Our findings suggest that a ductile secondary caprock is present in the overburden intervals of the storage sites, which could act as a secondary seal in the case of primary seal failure. The trapped hydrocarbon leaked from the Troll field within this ductile unit indicating a good secondary sealing potential. The study also reveals the presence of polygonal fault systems in the entire study area, but their frequency and orientation vary between layers. However, polygonal fault systems are not structurally stable, posing a risk of fault-parallel flow within the overburden interval. Nonetheless, the ductile clay-rich secondary caprock provides a seal for the polygonal fault systems within the interval. Due to either erosion or non-deposition, the ductile rock interval is not present in the east of the study area. As such, the critical risk for the Alpha structure in the Smeaheia injection site is the Vette fault and the efficiency of the primary Draupne caprock. Moreover, the crucial factor in the western Aurora site is the connectivity between the depleted Troll reservoirs and the CO2-injected pressurized reservoirs underneath. Based on our qualitative assessment, it is concluded that the overburden interval in the Horda Platform has adequate secondary sealing potential to hold and accumulate CO2 in the case of primary seal failure. Still, further numerical simulations are recommended to quantify our findings for both the Aurora and Smeaheia sites.

• Grande, Lars; Skurtveit, Elin; Choi, Jung Chan; Mondol, Md Nazmul Haque & Thompson, N. (2024). Consolidation Behaviors of Clays, Mudstones and Shales -CO2 Storage Sites in Horda Platform, Offshore Norway, 58th U.S. Rock Mechanics/Geomechanics Symposium. American Rock Mechanics Association (ARMA). ISSN 9780979497599. doi: 10.56952/ARMA-2024-0457. Fulltekst i vitenarkiv
• Rahman, Md Jamilur; Lebedev, Maxim & Mondol, Nazmul Haque (2024). Nanoscale mechanical properties of organic-rich Draupne caprock shale using nano-indentation method, offshore Norway. International Journal of Greenhouse Gas Control. ISSN 1750-5836. 132. doi: 10.1016/j.ijggc.2024.104073. Fulltekst i vitenarkiv Vis sammendrag

  Mechanical properties of cap and overburden rocks are crucial for field-scale geomechanical modeling and simulation of subsurface CO2 storage and hydrocarbon production. However, obtaining these properties can be challenging due to the lack of core extraction during drilling. The nano-indentation technique offers a solution to this problem by allowing the estimation of mechanical properties using small samples such as cuttings. This study evaluated 12 organic-rich shale samples from the North Sea to measure nanoscale mechanical properties. Half of these samples were cuttings, allowing for a sensitivity analysis between core and cuttings samples. A comparative analysis of the nanoscale and triaxial lab tests has been conducted. It is found that the mineralogical composition significantly affected the mechanical properties, with a strong negative correlation observed between Young's modulus and brittle mineral assemblages. The sensitivity analysis demonstrated that properties estimated from cuttings were reliable, like those obtained from core samples. This study suggests that the nano-indentation technique is a practical and reliable method that can add significant values and reduce uncertainty in field-scale geomechanical simulation.

• Sharifi, Javad; Moghaddas, Naser Hafezi; Saberi, Mohammad Reza & Mondol, Nazmul Haque (2023). A novel approach for fracture porosity estimation of carbonate reservoirs. Geophysical Prospecting. ISSN 0016-8025. 71(4), s. 664–681. doi: 10.1111/1365-2478.13321. Fulltekst i vitenarkiv
• Khoirrashif, Khoirrashif; Rahman, Md Jamilur & Mondol, Nazmul Haque (2022). Characterization of Utsira Formation around the Sleipner CO2 storage site, central North Sea. Society of Exploration Geophysicists. Expanded Abstracts with Biographies. ISSN 1052-3812. s. 552–556. doi: 10.1190/image2022-3750949.1. Fulltekst i vitenarkiv
• Khoirrashif, Khoirrashif; Rahman, Md Jamilur; Bohloli, Bahman; Torabi, Anita & Mondol, Md Nazmul Haque (2022). Machine learning application for compressional wave velocity log prediction in Sleipner CO2 storage, offshore Norway. 83rd EAGE Annual Conference & Exhibition. EarthDoc. doi: 10.3997/2214-4609.202210408. Fulltekst i vitenarkiv
• Rahman, Md Jamilur; Fawad, Manzar & Mondol, Nazmul Haque (2022). Influence of Rock Properties on Structural Failure Probability—Caprock Shale Examples from the Horda Platform, Offshore Norway. Energies. 15(24). doi: 10.3390/en15249598. Fulltekst i vitenarkiv Vis sammendrag

  In any geological subsurface fluid injection, a viable top seal is required to contain the vertical movement of the injected fluid plume. However, seal integrity assessment is challenging because of the uncertainties possessed by various parameters. A probabilistic solution might be more appropriate when significant uncertainties are present. In this study, we evaluate Drake shale caprock structural reliability using a stochastic method. Drake shale is the primary top seal in the Aurora CO2 storage site, located in the Horda Platform area in the northern North Sea. Based on the lithological variations, Drake caprock shale is divided into two parts designated by upper and lower units. Six model scenarios from the upper and lower Drake units have been tested. The probabilistic structural failures of varying model scenarios are estimated using the First-Order Reliability Method (FORM). Drake Formation shale shows a considerably low probability of failure (~0) with a high reliability index in the initial stress-state condition and after-injection scenarios. Moreover, the parameter sensitivity study indicates that horizontal stress and cohesion are the most influential input parameters during reliability estimation. Comparative analysis between the caprock properties and failure probability reveals that rock strength properties such as cohesion and friction angle strongly dictate the probability of failure estimation. Moreover, comparing two caprock shale formations indicates that the structural failure values are not correlatable; hence, a formation-specific failure assessment is recommended.

• Sharifi, Javad; Nooraiepour, Mohammad; Mohammadkazem, Amiri & Mondol, Nazmul Haque (2022). Developing a relationship between static Young’s modulus and seismic parameters. Journal of Petroleum Exploration and Production Technology. ISSN 2190-0558. 13, s. 203–218. doi: 10.1007/s13202-022-01546-6. Fulltekst i vitenarkiv Vis sammendrag

  Mechanical properties of petroleum reservoirs can be determined via static techniques based on laboratory triaxial tests under reservoir conditions. Dynamic approaches represent an alternative in cases where such static laboratory data are unavailable. Dynamic elastic properties are calculated using ultrasonic wave measurements in the laboratory or in situ well logging. Different relationships have been proposed to estimate static properties from dynamic ones based on the available data from a particular reservoir. However, these relationships are often reservoir-specific, making them inadequate for general seismic inversion purposes. This research proposes a method for developing relationships between seismic parameters and static Young’s modulus in carbonate reservoirs by integrating ultrasonic measurements, well logging data, and rock mechanic tests. A multistage triaxial test simulating the reservoir conditions was used to fully control the stress and strain during the geomechanical experiments. Static Young’s modulus was cross-correlated with a broad spectrum of seismic parameters that can be extracted from seismic inversion (e.g., acoustic impedance, shear impedance, Lambda–rho, and mu–rho). Separate analytic relationships were proposed to convert dynamic Young’s modulus and seismic parameters into static Young’s modulus. Analysis of variance was used to evaluate the results and study the applicability and reliability of the obtained relationships. Furthermore, the reliability of the obtained relationships was successfully confirmed by well logging data and blind well analysis. The proposed methodology can be used to predict rock behavior for geomechanical and structural modeling.

• Grande, Lars; Mondol, Md Nazmul Haque; Skurtveit, Elin & Thompson, Nicholas (2022). Stress Estimation from Clay Content and Mineralogy-Eos Well in the Aurora CO2 Storage Site, Offshore Norway. 16th Greenhouse Gas Control Technologies Conference 2022 (GHGT-16). doi: 10.2139/ssrn.4286343. Fulltekst i vitenarkiv Vis sammendrag

  Determination of in-situ stress is vital for many engineering applications, including Carbon Capture and Storage (CCS). A reliable estimation of minimum horizontal stress (σh) in a top seal is crucial for quantifying risk related to safe CO2 injection/storage. In this study, an alternative method is used to estimate the ratio between effective horizontal stress to vertical stress (K0, which directly relates to σh) from clay volume as indicated by gamma ray and spectra gamma ray logs. The method is based on correlations from laboratory uniaxial strain tests on natural and synthetic mixtures of clay with known mineralogy. The alternative method is predicting stress from volume clay (Vcl method) assuming uniaxial strain conditions; in addition, corrections accounting for smectite-rich high plasticity clays and uplift have been introduced. The method has been demonstrated for 5 wells and one geotechnical well in Aurora, Smeaheia, and Troll East, in the Horda Platform area. It is found that the sonic log method and the Vcl method are comparable within the Dunlin Group. For organic-rich shales like the Draupne Formation, the Thorium values from the spectral gamma log should be used for Vcl rather than the regular total gamma log. When other mineralogy data are present, this can be used for more precise quantification of Vcl and smectite and better estimation of K0. The Vcl method is a good alternative when sonic logs are unavailable to fill in the gaps in between field stress data, to understand the local lithological impact on stress, and reduce uncertainty. After correcting for uplift and high smectite content, the Vcl method were found to reproduce high K0 values as indicated from field stress tests in shallower units (Nordland, Hordaland, Shetland). For deeper main sealing units Draupne and Drake, the diagenetic impact may resulted in low K0 values although extensivly uplifted. The method presented improves quantification and reduces the uncertainty of σh which is one key input in all integrity evaluations

• Johnson, James Ronald; Kobchenko, Maya; Johnson, Andrew Charles; Mondol, Nazmul Haque & Renard, Francois (2022). Experimental modelling of primary migration in a layered, brittle analogue system. Tectonophysics. ISSN 0040-1951. 840. doi: 10.1016/j.tecto.2022.229575. Fulltekst i vitenarkiv Vis sammendrag

  A 2D Hele-Shaw cell was built to study microfracture nucleation, growth, and network formation during internal fluid production. Fluid is slowly produced into a low permeability solid, which leads to a local fluid pressure increase that controls the nucleation of microfractures that grow and then connect to create flow pathways. This process occurs during the primary migration of hydrocarbons in source rocks, which is the main topic of our study. It may also occur in other geological systems, such as the expulsion of water during dehydration of clay-rich sediments in sedimentary basins or serpentinite rocks in subduction zones and the transport of magmatic melts. Our system consists of a transparent, brittle gelatin material mixed with yeast and sugar. The consumption of sugar by yeast leads to CO2 formation, resulting in microfracture nucleation and growth. We varied three parameters, (1) anisotropy (i.e., number of layers), (2) lateral sealing, and (3) rate of fluid production. We tracked fluid movement through the opening and closing of microfractures within the system. Microfracture nucleation density is similar in a layered system to previous studies (0.45 microfracture per cm2). However, we observed that lateral confinement (0.31 microfracture per cm2) and rate of expulsion (0.99 microfracture per cm2) affect nucleation density and the geometrical characteristics of the microfracture network. The size, extent, and geometry of the microfracture network are dependent on all three parameters investigated, where lateral confinement and a higher rate of expulsion result in greater microfracture network connectivity. Layers control the angle of intersection between microfractures. Furthermore, layering and sealing have an impact on fracture topology. Results also show that the microfracture pattern significantly influences the fluid expulsion rate. Our results have direct applications to understanding how fluid migration occurs in low-permeability rocks through the development of a connected microfracture network produced by internal fluid generation.

• Rahman, Md Jamilur; Fawad, Manzar; Jahren, Jens & Mondol, Nazmul Haque (2022). Influence of Depositional and Diagenetic Processes on Caprock Properties of CO2 Storage Sites in the Northern North Sea, Offshore Norway. Geosciences. 12(5). doi: 10.3390/geosciences12050181. Fulltekst i vitenarkiv Vis sammendrag

  Characterization of caprock shale is critical in CO2 storage site evaluation because the caprock shale acts as a barrier for the injected buoyant CO2 plume. The properties of shales are complex and influenced by various processes; hence, it is challenging to evaluate the caprock quality. An integrated approach is therefore necessary for assessing seal integrity. In this study, we investigated the caprock properties of the Lower Jurassic Drake Formation shales from the proposed CO2 storage site Aurora (the Longship/Northern Lights CCS project), located in the Horda Platform area, offshore Norway. Wireline logs from 50 exploration wells, various 2D seismic lines, and two 3D seismic cubes were used to investigate the variations of the caprock properties. The Drake Formation was subdivided into upper and lower Drake units based on the lithological variations observed. Exhumation and thermal gradient influencing the caprock properties were also analyzed. Moreover, rock physics diagnostics were carried out, and caprock property maps were generated using the average log values to characterize the Drake Formation shales. In addiiton, pre-stack seismic-inverted properties and post-stack seismic attributes were assessed and compared to the wireline log-based analysis. The sediment source controlled at 61° N significantly influenced the depositional environment of the studied area, which later influenced the diagenetic processes and had various caprock properties. The upper and lower Drake units represent similar geomechanical properties in the Aurora area, irrespective of significant lithological variations. The Drake Formation caprock shale near the injection site shows less-ductile to less-brittle brittleness values. Based on the caprock thickness and shaliness in the Aurora injection site, Drake Formation shale might act as an effective top seal. However, the effect of injection-induced pressure changes on caprock integrity needs to be evaluated.

• Fawad, Manzar & Mondol, Nazmul Haque (2022). Monitoring geological storage of CO2 using a new rock physics model. Scientific Reports. 12. doi: 10.1038/s41598-021-04400-7. Fulltekst i vitenarkiv Vis sammendrag

  Abstract To mitigate the global warming crisis, one of the effective ways is to capture CO 2 at an emitting source and inject it underground in saline aquifers, depleted oil and gas reservoirs, or in coal beds. This process is known as carbon capture and storage (CCS). With CCS, CO 2 is considered a waste product that has to be disposed of properly, like sewage and other pollutants. While and after CO 2 injection, monitoring of the CO 2 storage site is necessary to observe CO 2 plume movement and detect potential leakage. For CO 2 monitoring, various physical property changes are employed to delineate the plume area and migration pathways with their pros and cons. We introduce a new rock physics model to facilitate the time-lapse estimation of CO 2 saturation and possible pressure changes within a CO 2 storage reservoir based on physical properties obtained from the prestack seismic inversion. We demonstrate that the CO 2 plume delineation, saturation, and pressure changes estimations are possible using a combination of Acoustic Impedance (AI) and P- to S-wave velocity ratio (Vp/Vs) inverted from time-lapse or four-dimensional (4D) seismic. We assumed a scenario over a period of 40 years comprising an initial 25 year injection period. Our results show that monitoring the CO 2 plume in terms of extent and saturation can be carried out using our rock physics-derived method. The suggested method, without going into the elastic moduli level, handles the elastic property cubes, which are commonly obtained from the prestack seismic inversion. Pressure changes quantification is also possible within un-cemented sands; however, the stress/cementation coefficient in our proposed model needs further study to relate that with effective stress in various types of sandstones. The three-dimensional (3D) seismic usually covers the area from the reservoir's base to the surface making it possible to detect the CO 2 plume's lateral and vertical migration. However, the comparatively low resolution of seismic, the inversion uncertainties, lateral mineral, and shale property variations are some limitations, which warrant consideration. This method can also be applied for the exploration and monitoring of hydrocarbon production.

• Johnson, James Ronald; Hansen, Jørgen André; Rahman, Md Jamilur; Renard, Francois & Mondol, Nazmul Haque (2022). Mapping the maturity of organic-rich shale with combined geochemical and geophysical data, Draupne Formation, Norwegian Continental Shelf. Marine and Petroleum Geology. ISSN 0264-8172. 138. doi: 10.1016/j.marpetgeo.2022.105525. Fulltekst i vitenarkiv Vis sammendrag

  The evaluation of the interplay between kerogen maturation and total organic carbon (TOC) content within an organic-rich shale is critical to characterizing source rock shale's elastic behavior. We analysed a comprehensive database of twenty-nine well logs, two 3D seismic surveys, and geochemical data of eighteen wells within the Draupne Formation in the Norwegian North Sea. The Upper Jurassic (Kimmeridgian) Draupne Formation Shale is found throughout the Norwegian Continental Shelf and is the primary source, carrier, and seal rock in several oil and gas fields. The dataset explores a broad range of depths (2–5 km), total organic contents (0–20 wt%), and various maturation states ranging from immature to overmature. We study the relationship between rock brittleness and organic content as shale matures. We use calculated values of Young's modulus and Poisson's ratio. Academic and industry-standard cutoffs are applied to both the TOC content and maturation level. We introduce here the Organic Maturation Product (OMP) rock physics template, which incorporates a relationship between organic content and any subsequent maturation. The degree of brittleness or ductility is impacted directly by the kerogen maturation process, with lower TOC content having a dampening effect on the transition towards increasing brittleness. This template allows one to classify rock maturation in nine categories, from low to high maturation, and link these categories to rock geomechanical properties. Seismic inversion of the 3D surveys and mapping utilizing the OMP classification reveal how large-scale depositional environment and subsequent diagenetic events influence both placement and quality of source rock broadly within the basin context of the North Sea.

• Rahman, Md Jamilur; Johnson, James Ronald; Fawad, Manzar & Mondol, Nazmul Haque (2022). Characterization of Upper Jurassic Organic-Rich Caprock Shales in the Norwegian Continental Shelf. Geosciences. 12(11). doi: 10.3390/geosciences12110407. Fulltekst i vitenarkiv Vis sammendrag

  Characterizing the top seal integrity of organic-rich caprock shale is critical in hydrocarbon exploration and fluid storage sites assessment because the caprock acts as a barrier to the low-density upward migrating fluids. This study investigated the geomechanical properties of the Upper Jurassic caprock shales of various basins from the Norwegian Continental Shelf. Usually, paleo-deposition and diagenesis vary from basin to basin, which influences the geomechanical properties of caprock shale; hence, the seal integrity. Fourteen (14) wells from four (4) different basins within the Norwegian Continental Shelf were analyzed to evaluate the effects of various processes acting on caprock properties. Comparative mineralogy-based caprock properties were also investigated. We include a thorough review of the distribution of organic and inorganic components utilizing SEM and 3D microtomography as they relate to the development and propagation of microfractures. Five (5) wells from three (3) basins contain measured shear sonic logs. These wells were used for petrophysics and rock physics analysis. Three elastic properties-based brittleness indices were estimated and compared. The percentage of different mineral fractions of the studied wells varied significantly between the studied basins, which is also reflected in the mineralogical brittleness indices evaluation. Irrespective of the studied basins, relative changes in caprock properties between wells have been observed. The Young’s Modulus–Poisson’s ratio-based empirical equation underestimated the brittleness indices compared with mineralogy- and acoustic properties-based brittleness estimation. A better match has been observed between the mineralogy- and acoustic properties-based brittleness indices. However, as both methods have limitations, an integrated approach is recommended to evaluate the brittleness indices. Brittleness indices are a qualitative assessment of the top seal; hence, further investigation is required to quantify sealing integrity.

• Rahman, Md Jamilur; Fawad, Manzar; Choi, Jung Chan & Mondol, Nazmul Haque (2022). Effect of overburden spatial variability on field-scale geomechanical modeling of potential CO2 storage site Smeaheia, offshore Norway. Journal of Natural Gas Science and Engineering. ISSN 1875-5100. 99. doi: 10.1016/j.jngse.2022.104453. Fulltekst i vitenarkiv Vis sammendrag

  Although geological CO2 sequestration is an essential solution for reducing anthropogenic carbon dioxide from the atmosphere, the method needs critical evaluation of injection-induced mechanical risks for safe and reliable CO2 storage. 3D field-scale geomechanical modeling is a preeminent solution for assessing mechanical risks of subsurface geological CO2 storage. However, data scarcity of seals and overburden rocks might limit building the 3D field-scale geomechanical model. This study focuses on seismic data-derived 3D field-scale geomechanical modeling of potential CO2 storage site Smeaheia, offshore Norway. The geomechanical properties inverted from seismic data are resampled in the 3D grid to consider spatial variabilities of seal and overburden rock properties. This method allows us to investigate the effect of overburden rock spatial variability imposed in seismic data on the 3D geomechanical model of Smeaheia. The model was built in Petrel-2019, while the one-way geomechanical simulation is iterated using the finite element method. Simplified constant overburden property models are also constructed to analyze the sensitivity of the overburden rock properties. The results reveal that the seismic data-driven spatially distributed overburden properties model workflow used in this study is a convenient and robust solution for 3D field-scale geomechanical modeling. The maximum vertical estimation of rock deformation is doubled in the simplified (isotropic) overburden rock property model compared to the new spatially variable (anisotropic) overburden rock property model. The Mohr-Coulomb failure envelope reveals that the new modeling approach is less prone to failure than the simplified (isotropic) model, which might influence the project decision. Moreover, our study demonstrates the importance of considering the spatial variability of overburden rock properties in building the 3D field-scale geomechanical model.

• Bohloli, Bahman; Berndt, Christian; Bjørnarå, Tore Ingvald; Bouquet, Sarah; Dujardin, Jean-Remi & Eiken, Ola [Vis alle 21 forfattere av denne artikkelen] (2022). Monitoring CO2 storage sites onshore and offshore using InSAR data and strain sensing fiber optics cables. SSRN Electronic Journal. Fulltekst i vitenarkiv
• Rahman, Md Jamilur; Fawad, Manzar; Jahren, Jens & Mondol, Nazmul Haque (2022). Top seal assessment of Drake Formation shales for CO<inf>2</inf> storage in the Horda Platform area, offshore Norway. International Journal of Greenhouse Gas Control. ISSN 1750-5836. 119. doi: 10.1016/j.ijggc.2022.103700. Fulltekst i vitenarkiv Vis sammendrag

  Evaluating top seal integrity is crucial for successful subsurface CO2 storage. Caprock shale geomechanical properties are complex and influenced by various parameters and processes. It is challenging to understand the role of various factors affecting the geomechanical properties; therefore, an integrated approach is required to evaluate top seal shales. In this study, we investigated the caprock properties of the Early Jurassic shaly Drake Formation overlying the reservoir sandstones of Early Jurassic Cook and Johansen formations. The study area is the potential CO2 storage site Aurora (the Longship CCS project), located in the Horda Platform area, offshore Norway. Based on lithological variations, the Drake Formation is subdivided into upper and lower Drake units. Variations of the geomechanical properties are investigated using wireline logs from 50 exploration wells, two 3D seismic cubes, and several 2D seismic lines. Elastic property-based brittleness indices of the Drake Formation caprock shales are evaluated to identify possible top seal quality. Moreover, seismic attributes and gas leakage scenarios are investigated qualitatively to assess the possibility of injected CO2 escaping from the reservoir. Low brittleness indices value of the Drake Formation shale near the Aurora injection site indicated that the seal rock might diffuse the injection-related stress change and act as an effective top seal. Based on the integrated qualitative assessment, it is likely that the Drake caprock shale will be acted as an effective top seal in and around the Aurora storage site. However, due to the complex nature of caprock shales, we recommend field-scale numerical simulation to evaluate the injection-induced stress-strain effect.

• Pratikna, Khoirrashif; Rahman, Md Jamilur & Mondol, Md Nazmul Haque (2022). Porosity log prediction of the Utsira Formation in Sleipner CO2 storage site by implementing machine learning techniques. SSRN Electronic Journal. Fulltekst i vitenarkiv
• Rahman, Md Jamilur; Fawad, Manzar & Mondol, Nazmul Haque (2022). 3D Field-Scale Geomechanical Modeling of Potential CO<inf>2</inf> Storage Site Smeaheia, Offshore Norway. Energies. 15(4). doi: 10.3390/en15041407. Fulltekst i vitenarkiv Vis sammendrag

  Injection-induced rock mechanical failure risks are critical in CO2 sequestration, and thus there is a need to evaluate these occurrences to ensure safe and reliable subsurface storage. A stress–strain-based numerical simulation can reveal the potential mechanical risks of any CO2 sites. This study investigated the hydromechanical effect on geomechanical failure due to injection-induced stress and pore pressure changes in the prospective CO2 storage site Smeaheia, offshore Norway. An inverted-seismic-property-driven 3D field-scale geomechanical model was carried out in the Smeaheia area to evaluate the rock failure and deformation risks in various pressure-build-up scenarios. A one-way coupling between the before- and after-injection pressure scenarios of nine different models has been iterated using the finite element method. The effect of the sensitivity of total pore volume and pore compressibility on rock mechanical deformation is also evaluated. Although various models illustrated comparative variability on failure potential, no model predicted caprock failure or fracture based on the Mohr–Coulomb failure envelope. Moreover, the lateral mechanical failure variation among different locations indicated the possibility to identify a safer injection point with less chances of leakage. In addition, the pore volume and pore compressibility significantly influence the mechanical behavior of the reservoir and caprock rocks. Although this analysis could predict better injection locations based on geomechanical behavior, a fluid simulation model needs to be simulated for assessing lateral and vertical plume migration before making an injection decision.

• Johnson, James Ronald; Kobchenko, Maya; Mondol, Nazmul Haque & Renard, Francois (2022). Multiscale synchrotron microtomography imaging of kerogen lenses in organic-rich shales from the Norwegian Continental Shelf. International Journal of Coal Geology. ISSN 0166-5162. 253. doi: 10.1016/j.coal.2022.103954. Fulltekst i vitenarkiv Vis sammendrag

  Kerogen lens shape and size distribution control how organic-rich shales may behave as either source or seal rocks. Prior to thermal conversion, kerogen is a brittle, load-bearing constituent of the shale matrix. During thermal maturation, kerogen lenses become more ductile, and hydrocarbon expulsion may lead to the creation of microfractures, a process controlled not only by temperature and pressure but also by the size and shape of kerogen lenses and their total content in the rock. Here, we use high-resolution multiscale synchrotron microtomography imaging of centimeter-scale shale rock samples collected in two boreholes at different depths in the North Sea and the Barents Sea, respectively. From these three-dimensional microtomography data, we quantify the various shapes of kerogen lenses and discuss how each step of a kerogen lens's life-cycle (i.e. original biological structure, deposition, degradation, and diagenesis) impacted its shape before catagenesis. We quantify the relationship between kerogen volume and the number of kerogen lenses in a given rock volume. The relationship between total organic carbon (TOC) content and the average kerogen lens volume is also measured. For a given rock volume, results show that organic content increases with the number of kerogen lenses up to a point (~8–12 wt% TOC) above which TOC continues to increase, but the number of kerogen lenses decreases. These results combined with kerogen lens orientation may control microfracturing during kerogen maturation.

• Park, Joonsang; Griffiths, Luke; Dautriat, Jérémie; Grande, Lars; Rodriguez, Ismael Vera & Iranpour, Kamran [Vis alle 16 forfattere av denne artikkelen] (2022). Induced-seismicity geomechanics for controlled CO<inf>2</inf> storage in the North Sea (IGCCS). International Journal of Greenhouse Gas Control. ISSN 1750-5836. 115. doi: 10.1016/j.ijggc.2022.103614. Fulltekst i vitenarkiv Vis sammendrag

  The aim of the current study, IGCCS (2017–2020), is to evaluate the feasibility of micro-seismic (MS) monitoring of CO2 injection into representative storage candidates in the North Sea, based on broad and quantitative characterization of relevant subsurface behavior with respect to geology, geomechanics and seismicity. For this purpose, we first group potential CO2 storage sites in the North Sea into three different depths. Then, advanced triaxial rock mechanical tests are performed together with acoustic emission (AE) acquisition under representative loading for CO2 storage sites in the North Sea and for formations of each depth group, covering shale, mudstone and sandstone cores. Our work focuses particularly on quantifying the effects of injected fluid type and temperature on mechanical behavior and associated MS response of subsurface sediments. The experiment results show that each depth group may behave differently in responses to CO2 injection. Particularly, the occurrence of detectable MS events is expected to increase with depth, as the combined effects of rock stiffness and temperature contrast between the host rock and injected CO2 are increasing. In addition, lithology plays an important role in terms of the MS response, i.e. high AE event rate is observed in sandstones, while aseismicity in shale and mudstone. The test results are then scaled up and applied to advanced coupled flow-geomechanics simulations and a synthetic field-scale MS data study to understand micro-seismicity at fracture, reservoir and regional scales. The numerical simulation of scCO2 injection scenario shows quite different stress-strain changes compared to brine injection, resulting mainly from the thermally-induced behavior. Furthermore, the numerical simulation study via so-called Cohesion Zone Modeling (CZM) approach shows strong potential to improve our understanding of the multiphase-flow-driven fracture propagation. Our synthetic MS data study, focused on slow-earthquake scenario, also suggests that sensors with high sensitivity at low frequency might be necessary for better signal detection and characterization during CO2 injection. This manuscript covers the main findings and insights obtained during the whole study of IGCCS, and refers to relevant publications for more details.

• Ahmadigoltapeh, Sajjad; Rahman, Md Jamilur; Mondol, Nazmul Haque & Hellevang, Helge (2022). Artificial Neural Network-Based Caprock Structural Reliability Analysis for CO2 Injection Site—An Example from Northern North Sea. Energies. 15(9). doi: 10.3390/en15093365. Fulltekst i vitenarkiv Vis sammendrag

  In CO2 sequestration projects, assessing caprock structural stability is crucial to assure the success and reliability of the CO2 injection. However, since caprock experimental data are sparse, we applied a Monte Carlo (MC) algorithm to generate stochastic data from the given mean and standard deviation values. The generated data sets were introduced to a neural network (NN), including four hidden layers for classification purposes. The model was then used to evaluate organic-rich Draupne caprock shale failure in the Alpha structure, northern North Sea. The train and test were carried out with 75% and 25% of the input data, respectively. Following that, validation is accomplished with unseen data, yielding promising classification scores. The results show that introducing larger input data sizes to the established NN provides better convergence conditions and higher classification scores. Although the NN can predicts the failure states with a classification score of 97%, the structural reliability was significantly low compare to the failure results estimated using other method. Moreover, this indicated that during evaluating the field-scale caprock failure, more experimental data is needed for a reliable result. However, this study depicts the advantage of machine learning algorithms in geological CO2 storage projects compared with similar finite elements methods in the aspect of short fitting time, high accuracy, and flexibility in processing different input data sizes with different scales.

• Aker, Eyvind; Kjønsberg, Heidi; Fawad, Manzar & Mondol, Nazmul Haque (2021). Estimation of Thickness and Layering of Johansen and Cook Sandstones at the Potential Co2 Storage Site Aurora. I Røkke, Nils Anders & Knuutila, Hanna K (Red.), TCCS–11. CO2 Capture, Transport and Storage. Trondheim 22nd–23rd June 2021. Short Papers from the 11th International Trondheim CCS Conference. SINTEF akademisk forlag. ISSN 9788253617145. s. 19–26. Fulltekst i vitenarkiv Vis sammendrag

  We have estimated the reservoir sand thickness and internal layering in the Aurora area, a planned geological CO2 storage site in the northern North Sea. The results are obtained by stochastic Markov chain Monte Carlo (MCMC) simulations on probabilistic lithology and fluid distributions in the subsurface. The probabilistic distributions are obtained by inverting the seismic data in a Bayesian framework. The inversion is using angle-dependent pre-stack seismic data and the linearized seismic forward model of Aki and Richards to estimate the posterior probabilities of lithology and fluid classes (facies) in the subsurface. The facies are defined from well log data by identifying depth intervals with distinct elastic responses to seismic waves. The inversion methodology and the MCMC simulations are developed and implemented by the Norwegian Computing Center. The planned CO2 storage reservoir comprises the Johansen and Cook sandstones belonging to the Early Jurassic Dunlin Group. The injection site (well 31/5-7) is located south and west of the Troll field in the northern North Sea and is currently being developed by Equinor in partnership with Total and Shell as part of the Northern Light project. The seismic inversion is mapping structural details like faults and internal layering of the sandstones, and the MCMC simulations estimate the probability of sand thickness and expected layering. Results show that the Johansen Formation sandstone has a tendency of layering towards the west and largest thickness to the east in the inversion area. The sandstone in the Cook Formation is generally thinner, and probability maps indicate that it pinches out to the east. Cumulative thickness distributions provide low (P90), median (P50), and high (P10) thickness maps of both Johansen and Cook Formation sandstones. The presented methodology defines a functional workflow for quantifying the thickness uncertainty and possibly internal layering of the reservoir sands. Such results may provide important input for future field development strategies and CO2 migration predictions.

• Rahman, Md Jamilur; Choi, Jung Chan; Fawad, Manzar & Mondol, Nazmul Haque (2021). Probabilistic Analysis of Draupne Shale Caprock Reliability of the Alpha Prospect - A Potential Co2 Storage Site in the Smeaheia Area, Northern North Sea. I Røkke, Nils Anders & Knuutila, Hanna K (Red.), TCCS–11. CO2 Capture, Transport and Storage. Trondheim 22nd–23rd June 2021. Short Papers from the 11th International Trondheim CCS Conference. SINTEF akademisk forlag. ISSN 9788253617145. s. 127–134. Fulltekst i vitenarkiv Vis sammendrag

  CO2 injection into a saline aquifer requires a viable caprock to arrest the vertical movement of the CO2 plume. Quantitative assessment of caprock integrity is often challenging because of uncertainties involved in the model input parameters. In this study, Draupne Formation's reliability as caprock is evaluated before CO2 injection by introducing a stochastic approach. We estimated both deterministic factors of safety and probabilistic failure values of different scenarios, and the results are compared. The probabilistic failure values are calculated using the First Order Reliability Method (FORM). Draupne formation shows a considerably low probability of failure with a high-reliability index in the initial stress condition. The sensitivity study reveals that the pore pressure and horizontal stress are the most crucial parameters and contribute two-thirds to failure probability. When the change of effective horizontal stresses in the reservoir is assumed considering the pore pressure change in the Troll field, this study shows that the field production may decrease the probability of shear failure. Moreover, the study indicates that the suggested probabilistic approach is critical in the presence of various uncertainties. However, the assumptions used in this study, especially the change in effective horizontal stresses within the reservoir, can be affected by other factors (e.g., stiffness contrast between reservoir and surroundings, geometrical effects, stress paths, etc.) and should be investigated further.

• Soto, Juan I.; Hudec, Michael R.; Mondol, Nazmul Haque & Heidari, Mahdi (2021). Shale transformations and physical properties—Implications for seismic expression of mobile shales. Earth-Science Reviews. ISSN 0012-8252. 220. doi: 10.1016/j.earscirev.2021.103746. Fulltekst i vitenarkiv
• Fawad, Manzar & Mondol, Nazmul Haque (2021). Monitoring geological storage of CO2: a new approach. Scientific Reports. 11(1). doi: 10.1038/s41598-021-85346-8. Fulltekst i vitenarkiv Vis sammendrag

  Abstract Geological CO 2 storage can be employed to reduce greenhouse gas emissions to the atmosphere. Depleted oil and gas reservoirs, deep saline aquifers, and coal beds are considered to be viable subsurface CO 2 storage options. Remote monitoring is essential for observing CO 2 plume migration and potential leak detection during and after injection. Leak detection is probably the main risk, though overall monitoring for the plume boundaries and verification of stored volumes are also necessary. There are many effective remote CO 2 monitoring techniques with various benefits and limitations. We suggest a new approach using a combination of repeated seismic and electromagnetic surveys to delineate CO 2 plume and estimate the gas saturation in a saline reservoir during the lifetime of a storage site. This study deals with the CO 2 plume delineation and saturation estimation using a combination of seismic and electromagnetic or controlled-source electromagnetic (EM/CSEM) synthetic data. We assumed two scenarios over a period of 40 years; Case 1 was modeled assuming both seismic and EM repeated surveys were acquired, whereas, in Case 2, repeated EM surveys were taken with only before injection (baseline) 3D seismic data available. Our results show that monitoring the CO 2 plume in terms of extent and saturation is possible both by (i) using a repeated seismic and electromagnetic, and (ii) using a baseline seismic in combination with repeated electromagnetic data. Due to the nature of the seismic and EM techniques, spatial coverage from the reservoir's base to the surface makes it possible to detect the CO 2 plume’s lateral and vertical migration. However, the CSEM low resolution and depth uncertainties are some limitations that need consideration. These results also have implications for monitoring oil production—especially with water flooding, hydrocarbon exploration, and freshwater aquifer identification.

• Rahman, MD Jamilur; Choi, Jung Chan; Fawad, Manzar & Mondol, Nazmul Haque (2021). Probabilistic analysis of Vette fault stability in potential CO2 storage site Smeaheia, offshore Norway. International Journal of Greenhouse Gas Control. ISSN 1750-5836. 108. doi: 10.1016/j.ijggc.2021.103315. Fulltekst i vitenarkiv Vis sammendrag

  Reliable assessment of fault stability is key for safe CO2 storage in a saline aquifer in fault-bounded structures. The Alpha structure located in the Vette fault's footwall in the Smeaheia area, offshore Norway, is one of the potential CO2 storage sites with a fault-bounded three-way closure. Assessing fault stability in the Smeaheia area is challenging because of the uncertainties associated with the subsurface fault properties (i.e., fault rock lithologies, strength and geometry of faults, etc.). Besides, CO2 injection-related pore pressure changes is another critical factor for mechanical deformation and potential failure. We employed a stochastic analytical approach to assess the probability of Vette fault failure using the Monte Carlo Simulation (MCS) and First Order Reliability Method (FORM). The possible fault smear scenarios of the Vette fault zone are evaluated by interpreting the seismic section and the detailed geological understanding. Each scenario's likelihood and the corresponding probability of failure are then integrated stochastically using an event tree method. Overall, Vette fault's system reliability shows a good to average performance range, which has a system probability of failure between 10−3 to 10-4. This finding suggests that the Vette fault will likely act as a potential barrier during CO2 injection into the Alpha structure. Moreover, the sensitivity study reveals that the stresses (both horizontal and vertical) and fault rock strength (i.e., cohesion and friction angle) are the most crucial parameters to characterize uncertainty reduction.

• Fawad, Manzar; Rahman, MD Jamilur & Mondol, Nazmul Haque (2021). Seismic-derived geomechanical properties of potential CO2 storage reservoir and cap rock in Smeaheia area, northern North Sea. The Leading Edge. ISSN 1070-485X. 40(4), s. 254–260. doi: 10.1190/tle40040254.1. Fulltekst i vitenarkiv
• Sharifi, Javad; Nooraiepour, Mohammad & Mondol, Md Nazmul Haque (2021). Application of the Analysis of Variance for Converting Dynamic to Static Young’s Modulus. I SPE, , (Red.), SPE Europec featured at 82nd EAGE conference and exhibition, October 18-21, 2021, Amsterdam, The Netherlands. Society of Petroleum Engineers. ISSN 9781613997918. doi: 10.3997/2214-4609.202012000. Fulltekst i vitenarkiv Vis sammendrag

  A statistical methodology was presented for interpreting dynamic-to-static relationships. Respecting the importance of the Young’s modulus in seismic geomechanics, as case study was performed on the dynamic-to-static Young’s modulus conversion. To this end, six core samples from the studied oilfield were selected and in-situ stress curves were obtained. Next, in order to obtain static properties of the selected rocks, rock mechanics test were carried out under reservoir condition. In the same way, dynamic test was further performed using ultrasonic in the laboratory. Once finished with obtaining the static and dynamics values, simple linear regression and forward and backward stepwise multiple linear regressions were developed. Then empirical equations were developed for obtaining static Young’s modulus based on dynamic Young’s modulus, density, and porosity. Next, the developed formulations were interpreted by the analysis of variance (ANOVA). The results showed that, due to the small sample size, the regression analysis alone could not provide significant relationships, highlighting the important roles of other statistical methods (e.g., F-test and t-test) in the reliability evaluation of the relationships. The findings of the present article provide a methodology for obtaining regression-based relationships for seismic geomechanics and reservoir modelling applications, especially where limited core samples are available.

• Fawad, Manzar; Rahman, MD Jamilur & Mondol, Nazmul Haque (2021). Seismic reservoir characterization of potential CO2 storage reservoir sandstones in Smeaheia area, Northern North Sea. Journal of Petroleum Science and Engineering. ISSN 0920-4105. 205. doi: 10.1016/j.petrol.2021.108812. Fulltekst i vitenarkiv Vis sammendrag

  Evaluating any subsurface CO2 storage site comprises the reservoir, seal, and overburden investigation to mitigate injection and storage-related complications. The Upper-Middle Jurassic Sognefjord, Fensfjord, and Krossfjord formation sandstones are potential CO2 storage reservoirs at the Smeaheia area, northern North Sea. The Smeaheia area is located east of the Troll oil and gas field. The Upper Jurassic organic-rich Heather and Draupne Formation shales are the main seals for the sandstone reservoirs. In this study, we carried out a prestack seismic inversion to obtain elastic property cubes of acoustic impedance (AI), velocity ratio (Vp/Vs), and bulk density (RhoB). From these elastic cubes, we obtained the reservoir properties such as porosity (Phi), shaliness (Vsh), and permeability (k) of Sognefjord, Fensfjord, and Krossfjord formations. We introduced two new equations to extract the shale volume and porosity cubes from the inverted elastic cubes in the present study. These equations are nonlinear based on the AI versus Vp/Vs rock physics template. Both equations are correlated first with the well log data and then applied on the elastic property cubes (AI versus Vp/Vs) to obtain the Vsh and Phi property cubes. An additional porosity cube (PhiD) was generated from the inverted RhoB for comparison. Finally, using an empirical equation, permeability was extracted from the porosity cube. The reservoir properties we derived from 3D seismic, in addition to the well log, revealed the vertical and lateral variations of porosity, shaliness, and permeability in the Smeaheia area. We used these reservoir properties to infer the depositional environment and the viability of reservoirs for CO2 storage. The depositional environments identified were shoreface and deltaic from the extracted sand-body geometries. We found the Sognefjord Formation possessing the best reservoir properties, followed by the Fensfjord Formation as the secondary storage potential. In contrast, the Krossfjord Formation owed the lowest reservoir quality in the Smeaheia area.

• Rahman, MD Jamilur; Fawad, Manzar & Mondol, Nazmul Haque (2020). Organic-rich shale caprock properties of potential CO2 storage sites in the northern North Sea, offshore Norway. Marine and Petroleum Geology. ISSN 0264-8172. 122. doi: 10.1016/j.marpetgeo.2020.104665. Fulltekst i vitenarkiv Vis sammendrag

  Assessment of the geomechanical properties of organic-rich shale caprocks is critical for a successful CO2 storage into a saline aquifer. In this study, we investigated the geochemical properties of the organic-rich shale caprocks of the Draupne and Heather formations, overlying the potential sandstone reservoirs of Sognefjord, Fensfjord, and Krossfjord formations in the northern North Sea, offshore Norway. The caprock’s depositional variations within the sub-basins are established by analyzing the gamma-ray shape and stacking patterns. The effect due to differences in depositional environments, on the caprock compaction behavior is investigated by integrating petrographical analysis of core and cutting samples from 3 wells and by rock physical analysis of wireline log data from 27 exploration wells. Three rock physics templates are used where the wireline log data are interpreted using the published background trends. The effect of kerogen type, maturation level, and deposition environment on caprock properties within the study area are also evaluated. Moreover, the caprock property, such as brittleness, is estimated by using four mineralogy and elastic property-based, empirical relations, which is a quantitative measure of caprock property with respect to changes in stress-state. Finally, the seismic inversion method is assessed for the possibility of extracting caprock properties from surface seismic data. Regardless of compaction processes, the results indicate that the Heather Formation is mechanically stronger than the Draupne Formation. However, both formations appear to be ductile in nature. The depositional environments control the mineralogical composition and fabric of the Draupne and Heather formations, which influence the caprock properties significantly. Results also show that the effect of TOC on caprock properties is insignificant in the study area. The brittleness of the organic-rich shale caprocks in the study area follows a different trend compared to the published trends. We also observed an excellent correlation between the log-derived elastic properties and geomechanical parameters. Still, it is difficult to assess the caprock elastic properties from seismic due to the overlap of data clusters. The evaluation of caprock geomechanical behaviors is challenging as these properties are site-specific and also influenced by other factors such as exhumation, in-situ stress conditions, the existence of natural fractures, and their orientations.

• Ogebule, Oluwakemi Yetunde; Jahren, Jens & Mondol, Nazmul Haque (2020). Compaction, rock physics and rock properties of sandstones of the Stø Formation: Case study of five wells from the south-western Barents Sea, Norway. Marine and Petroleum Geology. ISSN 0264-8172. 119. doi: 10.1016/j.marpetgeo.2020.104448. Fulltekst i vitenarkiv Vis sammendrag

  Five wells containing Lower-Middle Jurassic sandstones of Stø Formation from the Hammerfest Basin (7120/9–1, 7121/7–1), the Ringvassøy-Loppa Fault Complex (7119/12–1, 7119/12–4) and the Troms-Finnmark Fault Complex (7019/1-1) in the Barents Sea area are considered in this study. The Stø Formation sandstones contain dominantly very fine-to medium-grained quartz arenites with occasional coarse-grained sandstone layers. Feldspathic and quartz wackes are also present. The effect of compaction and exhumation on reservoir properties (porosity and permeability) and seismic property (P-wave velocity) of these sandstones have been investigated. Source of quartz cement has also been investigated. Forty polished thin sections embedded in blue epoxy were studied using optical microscopy, scanning electron microscopy and cathodoluminiscence. Bulk mineralogy was also analysed using X-ray diffraction. The studied sandstones have experienced Cenozoic exhumation ranging between 820 and 1050 m. P-wave velocity is higher; porosities and permeabilities are lower in the western wells (7019/1-1, 7119/12–1 and 7119/12–4) compared to the eastern wells (7120/9–1 and 7121/7–1). Rock physics models and diagnostics show that the western wells are diagenetically more mature, stiffer, more compacted and more cemented than the eastern wells. These trends are attributed largely to difference in burial history from the east to the west and less to textural variations. Quartz cement is the most important authigenic mineral in these sandstones. Quartz cement in the western well (7119/12–1) is predominantly derived from clay-induced dissolution at macrostylolites whereas the eastern wells (7120/9–1 and 7121/7–1) are mostly sourced from clay-induced dissolution at grain contacts or microstylolites. While cementational porosity loss dominates in the western wells, compactional porosity loss dominates in the eastern wells. Compaction can reduce porosities down to 26% and this might be the reason for better porosity preservation and reservoir quality in the eastern wells than in the western wells.

• Hansen, Jørgen André; Mondol, Nazmul Haque; Jahren, Jens & Tsikalas, Filippos (2020). Reservoir assessment of Middle Jurassic sandstone-dominated formations in the Egersund Basin and Ling Depression, eastern Central North Sea. Marine and Petroleum Geology. ISSN 0264-8172. 111, s. 529–543. doi: 10.1016/j.marpetgeo.2019.08.044. Fulltekst i vitenarkiv Vis sammendrag

  Reservoir quality assessment was conducted from petrophysical analysis and rock physics diagnostics on 15 wells penetrating Middle Jurassic sandstone reservoir formations in different regions of the eastern Central North Sea. Seismic interpretation on available 3D and 2D seismic reflection data was utilized to map thickness variations and to draw broad correlations to structural features such as salt structures and faults. In the central Egersund Basin, the Sandnes Formation shows good reservoir properties (gross thickness = 107–147 m, N/G = 33–53%) while the Bryne Formation exhibits poorer reservoir quality (N/G < 20%). Both formations display variable reservoir properties and thicknesses on the northern flank of the Egersund Basin and in the Ling Depression (Sandnes Formation: gross thickness 16–26 m, N/G = 11–81%; Bryne Formation: 30–221 m, N/G = 25–70%). The time-equivalent Hugin and Sleipner formations are more locally developed in the southwest part of Ling Depression, and display good-to-excellent and intermediate reservoir quality, respectively. Furthermore, we use the outcomes of the conducted analyses to correlate observations to further exploration on various reservoir target formations and on seismic prediction of reservoir properties. Thus, the risk on reservoir presence and efficiency for the chased targets is considerably reduced. The main remaining risks within the study area are related to source rocks, their maturity, expulsion and migration of hydrocarbon, and the timing of trap formation.

• Lehocki, Ivan; Avseth, Per Åge & Mondol, Nazmul Haque (2020). Seismic methods for fluid discrimination in areas with complex geologic history - A case example from the Barents Sea. Interpretation. ISSN 2324-8858. 8(1), s. SA35–SA47. doi: 10.1190/INT-2019-0057.1. Fulltekst i vitenarkiv Vis sammendrag

  We develop a new scheme for calculation of density ratio, an attribute that can be directly linked to hydrocarbon saturation, and apply it to seismic AVO data from the Hoop area in the Barents Sea. The approach is based on the inversion of Zoeppritz’s equation for PP-wave. Furthermore, by utilizing interval velocities, we quantify uplift magnitude for a given interval beneath BCU horizon in the Hoop area. Depending on the temperature gradient, the maximum burial depth can be estimated, a crucial factor affecting the elastic properties of the rocks. Coupling uplift map with temperature history for key stratigraphic units from basin modeling enables us to extend training data away from well control. By doing so, we have created nonstationary amplitude variation with offset (AVO) probability density functions (PDFs) for calibration and classification of seismic attributes in the test area. This decreases the likelihood of misclassification of pore fluid type as opposed to the case where the training data are created based only on sparse well log data. We test and compare the methods on the Barents Sea seismic dataset, and the results are validated at four well locations. Finally, maps of fluid distribution obtained from stochastic rock physics modeling honoring burial history are compared against the density ratio map. Four maps reveal the same anomalous zones, the major difference being the detection of the down-flank presence of oil associated with some of the predicted gas anomalies in the prospect area, in the case of density ratio map. Possible gas caps are detected/predicted only for certain temperature constraints during the AVO classifications, and are most obvious in the density ratio map.

• Hansen, Jørgen André; Mondol, Nazmul Haque; Tsikalas, Filippos & Faleide, Jan Inge (2020). Caprock characterization of Upper Jurassic organic-rich shales using acoustic properties, Norwegian Continental Shelf. Marine and Petroleum Geology. ISSN 0264-8172. 121. doi: 10.1016/j.marpetgeo.2020.104603. Fulltekst i vitenarkiv Vis sammendrag

  Our analysis of a comprehensive well log database and complementary mineralogical and geochemical information indicates that the risk for Upper Jurassic shales on the Norwegian Continental Shelf (NCS) to permit severe leakage of hydrocarbons from the reservoir is generally low, even in the case of substantial uplift. The content of brittle minerals, organic content, and compaction are dominant factors that explain the observed discrepancies in acoustic properties of organic-rich caprock shales. In particular, variations in silt-clay content in clay-dominated shales are found to primarily influence sonic velocity and to correlate closely with gamma-ray where the uranium contribution is limited (“grey shales”). Changes in organic content exhibit a stronger density-component and are seen to counteract or mask the compaction effect on velocity and density in Kimmeridgian black shales. The Hekkingen, Draupne and Tau formations are distinctly different from the underlying grey shale formations in acoustic properties, despite that the latter group also contains significant amounts of organic matter. Based on the low permeability and high capillary sealing capacity of clay-dominated shales, we conclude that even for a silty seal, migration through the caprock matrix is highly unlikely. Furthermore, tectonic fracturing is an ineffective leakage mechanism when the seal is poorly consolidated/cemented prior to uplift. Brittleness, related to both mineralogical composition and consolidation, is consequently a crucial parameter for predicting seal integrity in exhumed basins. Our rock physics framework and interpretations relate this rather qualitative parameter to acoustic properties, and thus, to seismic data.

• Chauve, Thomas; Scholtes, Luc; Donzé, Frédéric-Victor; Mondol, Nazmul Haque & Renard, Francois (2020). Layering in shales controls microfracturing at the onset of primary migration in source rocks. Journal of Geophysical Research (JGR): Solid Earth. ISSN 2169-9313. 125(5). doi: 10.1029/2020JB019444. Fulltekst i vitenarkiv Vis sammendrag

  The process of primary migration, which controls the transfer of hydrocarbons from source to reservoir rocks, necessitates the existence of fluid pathways in low permeability sedimentary formations. Primary migration starts with the maturation of organic matter that produces fluids which increase the effective stress locally. The interactions between local fluid production, microfracturing, stress conditions, and transport remain difficult to apprehend in shale source rocks. Here, we analyze these interactions using a coupled hydro‐mechanical numerical model based on the discrete element method. The model is used to simulate the effects of fluid production emanating from kerogen patches contained within a shale rock alternating kerogen‐poor and kerogen‐rich layers. We identify two microfracturing mechanisms that control fluid migration: i) propagation of hydraulically driven fractures induced by kerogen maturation in kerogen‐rich layers, and ii) compression induced fracturing in kerogen‐poor layers caused by fluid overpressurization of the surrounding kerogen‐rich layers. The relative importance of these two mechanisms is discussed considering different elastic properties contrasts between the shale layers, as well as various stress conditions encountered in sedimentary basins, from normal to reverse faulting regimes. The layering in shales causes local stress redistribution that controls the prevalence of each mechanism over the other and the onset of microfracturing during kerogen maturation. Results are applied to the Draupne formation, a major source rock in the Norwegian continental shelf in the North Sea.

• Fawad, Manzar; Hansen, Jørgen André & Mondol, Nazmul Haque (2020). Seismic-fluid detection-a review. Earth-Science Reviews. ISSN 0012-8252. 210. doi: 10.1016/j.earscirev.2020.103347. Fulltekst i vitenarkiv Vis sammendrag

  Since the advent of seismic imaging techniques, the dream of geophysicists has been to identify the fluid effect and be able to accurately map hydrocarbon from the brine within a target reservoir. The usage of bright spots (strong reflection amplitudes) as an indicator of hydrocarbon was the earliest recognition of the direct role played by the pore fluids in seismic signatures. Further development of new techniques had a strong correlation with the increase in computing power and advances in seismic acquisition and processing techniques. In this review, we touch upon the relevant theory developed more than 100 years ago, and then review the methods developed over five decades leading to the quantitative interpretation of seismic data for fluid detection. We also carried out a case study to compare selected fluid identification methods applied to a complex reservoir within an oil and gas field in the Barents Sea. The impedance-based methods “CPEI-Curved Pseudo-elastic Impedance” and “LMR-Lambda-Mu-Rho” inversion provided better results compared to other techniques, highlighting the critical influence anomalous lithologies have on such screening attributes.

• Grande, Lars; Griffiths, Luke; Park, Joonsang; Choi, Jung Chan; Bjørnarå, Tore Ingvald & Sauvin, Guillaume [Vis alle 7 forfattere av denne artikkelen] (2020). Acoustic Emission Testing of Shales for Evaluation of Microseismic Monitoring of North Sea CO2 Storage Sites, 82nd EAGE Conference & Exhibition. I NN, NN (Red.), Proceedings 82nd EAGE Conference and Exhibition 2020. European Association of Geoscientists and Engineers (EAGE). ISSN 9781713813620. s. 1977–1981. doi: 10.3997/2214-4609.202011984. Fulltekst i vitenarkiv
• Narongsirikul, Sirikarn; Mondol, Nazmul Haque & Jahren, Jens (2019). Effects of stress reduction on geomechanical and acoustic relationship of overconsolidated sands. Geophysical Prospecting. ISSN 0016-8025. doi: 10.1111/1365-2478.12902. Fulltekst i vitenarkiv Vis sammendrag

  Relationship between different geomechanical and acoustic properties measured from seven laboratory tested unconsolidated natural sands with different mineralogical compositions and textures were presented. The samples were compacted in the uniaxial strain configuration from 0.5 up to 30 MPa effective stress. Each sand sample was subjected to three loading – unloading cycles to study the influence of stress reduction. Geomechanical, elastic, and acoustic parameters are different between normal compaction and overconsolidation (unloaded and reloaded). Stress path (K0) data differs between normal consolidated and overconsolidated sediments. The K0 value of approximately 0.5 is founded for most of the normal consolidated sands, but varies during unloading depending on mineral compositions and textural differences. The K0 and Overconsolidation Ratio (OCR) relation can be further simplified and can be influenced by the material compositions. K0 can be used to estimate horizontal stress for drilling applications. The relationship between acoustic velocity and geomechanical is also found to be different between loading and unloading conditions. The static moduli of the overconsolidated sands are much higher than normal consolidated sands as the deformation is small (small strain). The correlation between dynamic and static elastic moduli is stronger for an overconsolidation stage than for a normal consolidation stage. The results of this study can contribute to geomechanical and acoustic dataset which can be applied for many seismic‐geomechanics applications in shallow sands where mechanical compaction is the dominant mechanism.

• Narongsirikul, Sirikarn; Mondol, Nazmul Haque & Jahren, Jens (2019). Acoustic and petrophysical properties of mechanically compacted overconsolidated sands: Part 2 – Rock physics modelling and applications. Geophysical Prospecting. ISSN 0016-8025. 67(1), s. 114–127. doi: 10.1111/1365-2478.12692. Fulltekst i vitenarkiv Vis sammendrag

  Part one of this paper reported results from experimental compaction measurements of unconsolidated natural sand samples with different mineralogical compositions and textures. The experimental setup was designed with several cycles of stress loading and unloading applied to the samples. The setup was aimed to simulate a stress condition where sediments underwent episodes of compaction, uplift and erosion. P‐ and S‐wave velocities and corresponding petrophysical (porosity and density) properties were reported. In this second part of the paper, rock physics modelling utilising existing rock physics models to evaluate the model validity for measured data from part one were presented. The results show that a friable sand model which was established for normally compacted sediments is also capable of describing overconsolidated sediments. The velocity‐porosity data plotted along the friable sand lines not only describe sorting deterioration, as has been traditionally explained by other studies, but also variations in preconsolidation stress or degree of stress release. The deviation of the overconsolidated sands away from the normal compaction trend on the VP/VS ‐ AI space shows that various stress paths can be predicted on this domain when utilising rock physics templates (RPTs). Fluid saturation sensitivity is found to be lower in overconsolidated sands compared to normally consolidated sands. The sensitivity decreases with increasing preconsolidation stress. This means detectability for 4D fluid saturation changes can be affected if sediments were pre‐stressd and unloaded. Well log data from the Barents Sea show similar patterns to the experimental sand data. The findings allow the development of better rock physics diagnostics of unloaded sediments, and the understanding of expected 4D seismic response during time‐lapse seismic monitoring of uplifted basins. The studied outcomes also reveal an insight into the friable sand model that its diagnostic value is not only for describing sorting microtextures, but also preconsolidation stress history. The outcome extends the model application for preconsolidation stress estimation, for any unconsolidated sands experiencing similar unloading stress conditions to this study.

• Mondol, Nazmul Haque (2019). Geomechanical and Seismic Behaviors of Draupne Shale: A Case Study from the Central North Sea, 81st EAGE Conference and Exhibition 2019. European Association of Geoscientists and Engineers (EAGE). ISSN 9781510892811. doi: 10.3997/2214-4609.201901599. Fulltekst i vitenarkiv Vis sammendrag

  Organic-rich shales exhibit a variation in shear strength and anisotropic behavior of seismic wave propagation when the direction of the plane of weakness is varied with respect to the direction of the principal stresses. This study investigats geomechanical and seismic behaviors of a Draupne shale core retrieved from an exploration well from the Central North Sea, offshore Norway. CIU- Isotropically Consolidated Undrained-tests were performed on three core plugs that drilled parallel (0 degree), inclined (45 degree) and perpendicular (90 degree) to the layerings/beddings. The index test results indicate very low permeability of the shale with small pore throats ensuring a high capillary sealing for the intact part, whereas the observed shear fracture is more uncertain with respect to sealing capacity. Anisotropy has been demonstrated to have a marked influence on the strength properties (e.g. shear strength, Young's Modulus, Poisson's Ratio) of the Draupne shale. The minimum shear strength is measured for 45 degree core plug whereas the plug drilled parallel (0 degree) to the layering exhibits the highest shear strength. Post-test sample observation confirms that the strength anisotropy is related to failure with respect to the layerings/beddings.

• Fawad, Manzar & Mondol, Nazmul Haque (2019). Comparison of Sealing Properties of Amundsen and Drake Formations for Potential CO2 Storage in North Sea, 81st EAGE Conference and Exhibition 2019. European Association of Geoscientists and Engineers (EAGE). ISSN 9781510892811. doi: 10.3997/2214-4609.201900793. Fulltekst i vitenarkiv Vis sammendrag

  Seal evaluation for CO2 storage is different from that of a hydrocarbon trap since the oil or gas accumulation itself validates the cap-rock integrity. However, in case of subsurface CO2 storage a careful investigation is required to avoid any risk of potential seal failure. The Johansen Formation of Early Jurassic age in and around the Troll field is a potential CO2 storage reservoir in the northern North Sea. It is enveloped by Amundsen mudstone, whereas in the southeast where the Amundsen cap pinches out, the Drake mudstone Formation directly overlies the Johansen Formation. We evaluated wireline log data from 24 exploration wells using petrophysical analysis and rock physics diagnostics to obtain present day depth, thickness, temperature, volume of clay, physical and elastic properties to evaluate the seal integrity of the Amundsen and Drake Formations. The sealing properties of both the formations were found to be within acceptable range, with minor presence of brittle zones at deeper levels within the Drake Formation containing low volume of shale. These findings will help understanding the seal integrity of Amundsen and Drake Formations as cap-rocks above the Johansen Sandstone being a potential CO2 storage reservoir.

• Hansen, Jørgen André; Mondol, Nazmul Haque & Fawad, Manzar (2019). Organic content and maturation effects on elastic properties of source rock shales in the Central North Sea. Interpretation. ISSN 2324-8858. 7(2), s. T477–T497. doi: 10.1190/int-2018-0105.1. Fulltekst i vitenarkiv Vis sammendrag

  We investigate the effects of organic content and maturation on the elastic properties of source rock shales, mainly through integration of a well log database from the Central North Sea and associated geochemical data. Our aim is to improve the understanding of how seismic properties change in source rock shales due to geological variations and how these might manifest on seismic data in deeper, undrilled parts of basins in the area. The Tau and Draupne Formations (Kimmeridge Shale equivalents) in immature to early mature stages exhibit variation mainly related to compaction and TOC content. We assess the link between depth, acoustic impedance (AI) and TOC in this setting, and express it as an empirical relation for TOC prediction. Additionally, where shear wave information is available, we combine two seismic properties and infer rock physics trends for semi-quantitative prediction of TOC from Vp/Vs and AI. Furthermore, data from one reference well penetrating mature source rock in the southern Viking Graben indicates that a notable hydrocarbon-effect can be observed as an addition to the inherently low kerogen-related velocity and density. Published Kimmeridge Shale ultrasonic measurements from 3.85 to 4.02 km depth closely coincide with well log measurements in the mature shale, indicating that upscaled log data is reasonably capturing variations in the actual rock properties. AVO inversion attributes should in theory be interpreted successively in terms of compaction, TOC, and maturation with associated generation of hydrocarbons. Our compaction-consistent decomposition of these effects can be of aid in such interpretations.

• Nooraiepour, Mohammad; Mondol, Nazmul Haque & Hellevang, Helge (2019). Permeability and physical properties of semi-compacted fine-grained sediments – A laboratory study to constrain mudstone compaction trends. Marine and Petroleum Geology. ISSN 0264-8172. 102, s. 590–603. doi: 10.1016/j.marpetgeo.2019.01.019. Fulltekst i vitenarkiv Vis sammendrag

  Permeability and physical properties of fine-grained clastic sediments show a wide range of variations. Despite rather intensive research, the impact of grain size distribution and mineralogical composition of individual rock constituents is not thoroughly investigated. We performed mechanical compaction of brine-statured reconstituted borehole cuttings and synthetic quartz-clay mixtures to study the evolution of properties in fine-grained clastic sediments during burial. The primary objective was to examine whether the hydraulic and physical properties of fine-grained sediments could be described and constrained by binary quartz-clay mixtures. The synthetic binary mixtures were prepared by mixing quartz with non-swelling (kaolinite) and strongly-swelling (smectite) clays, which can represent the endmember properties within the clay minerals. In addition to vertical permeability, physical and seismic properties, stress-dependence of permeability, and two-phase relative permeability of brine-oil system were investigated. Experimental results show that grain size distribution and mineralogical composition control the vertical permeability. A well-constrained porosity-permeability bound is defined, where the compaction trends of pure quartz and quartz-smectite 15:85 (wt %) mixtures describe the maximum and minimum boundaries, respectively. The quartz-clay mixtures, however, fail to provide bounds to constrain the broad range of variations in physical and seismic properties of reconstituted aggregates, and consequently natural mudstones. It is crucial to incorporate microstructure into the permeability prediction models because the experiments indicated that the microscale characteristics control the macroscale fluid flow properties.

• Narongsirikul, Sirikarn; Mondol, Nazmul Haque & Jahren, Jens (2019). Acoustic and petrophysical properties of mechanically compacted overconsolidated sands: part 1 – experimental results. Geophysical Prospecting. ISSN 0016-8025. 67(4), s. 804–824. doi: 10.1111/1365-2478.12744. Fulltekst i vitenarkiv Vis sammendrag

  This paper part one is set out to lay primary observations of experimental compaction measurements to form the basis for rock physics modelling in paper part two. P‐ and S‐wave velocities and corresponding petrophysical (porosity and density) properties of seven unconsolidated natural sands with different mineralogical compositions and textures are reported. The samples were compacted in a uniaxial strain configuration from 0.5 up to 30 MPa effective stresses. Each sand sample was subjected to three loading cycles to study the influence of stress reduction on acoustic velocities and rock physical properties with the key focus on simulating a complex burial history with periods of uplift. Results show significant differences in rock physical properties between normal compaction and overconsolidation (unloaded and reloaded). The differences observed for total porosity, density, and P‐ and S‐wave velocities are attributed to irrecoverable permanent deformation. Microtextural differences affect petrophysical, acoustic, elastic and mechanical properties, mostly during normal consolidation but are less significant during unloading and reloading. Different pre‐consolidation stress magnitudes, stress conditions (isotropic or uniaxial) and mineral compositions do not significantly affect the change in porosity and velocities during unloading as a similar steep velocity–porosity gradient is observed. The magnitude of change in the total porosity is low compared to the associated change in P‐ and S‐wave velocities during stress release. This can be explained by the different sensitivity of the porosity and acoustic properties (velocities) to the change in stress. Stress reduction during unloading yields maximum changes in the total porosity, P‐ and S‐wave velocities of 5%, 25%, and 50%, respectively. These proportions constitute the basis for the following empirical (approximation) correlations: Δϕ ∼ ±5 ΔVP and ΔVP ∼ ±2ΔVS. The patterns observed in the experiments are similar to well log data from the Barents Sea. Applications to rock physics modelling and reservoir monitoring are reported in a companion paper.

• Johnson, James Ronald; Hansen, Jørgen André; Renard, Francois & Mondol, Nazmul Haque (2019). Modeling maturation, elastic, and geomechanical properties of the Draupne Formation, Offshore Norway. SEG technical program expanded abstracts. s. 3245–3249. doi: 10.1190/segam2019-3215340.1. Fulltekst i vitenarkiv Vis sammendrag

  Understanding shale’s geomechanical and elastic properties is critical to success in conventional and unconventional plays. This understanding provides a framework for the safe extraction of hydrocarbons as well as a guide to mapping favorable source locations. The Upper Jurassic Draupne shale in the North Sea is a world class organicrich source rock, a commendable seal for both hydrocarbon and possibly CO2, and potentially a future reservoir. As such, the Draupne Formation is an ideal candidate to study the modeling of maturation as they relate to both elastic and geomechanical properties.

• Moghadam, Javad Naseryan; Nooraiepour, Mohammad; Hellevang, Helge; Mondol, Nazmul Haque & Aagaard, Per (2019). Relative permeability and residual gaseous CO2 saturation in the Jurassic Brentskardhaugen Bed sandstones, Wilhelmøya Subgroup, western central Spitsbergen, Svalbard. Norwegian Journal of Geology. ISSN 2387-5844. 99(2). doi: 10.17850/njg005. Fulltekst i vitenarkiv Vis sammendrag

  This study investigates fluid-flow properties of the low-permeability Brentskardhaugen Bed (Knorringfjellet Formation), Wilhelmøya Subgroup, western central Spitsbergen, Svalbard. To evaluate the two-phase relative permeability of the water-CO2 system, we performed unsteady state core-flooding experiments using deionised water and gaseous CO2. The absolute permeability and residual fluid saturations were also studied. Moreover, a core plug of the Berea sandstone was tested as a reference sample. The core-flooding experiments recorded microDarcy permeability values (0.022–0.039 mD) for various differential pressures (4 to 12 MPa). The poor grain sorting and the abundance of cement were the main factors controlling the low matrix permeabilities. Closure of sub-micron fractures was the likely reason for reduced permeability with increasing effective stresses. The experimental measurements showed that CO2 fractional flow reached unity at relatively low CO2 saturation (approximately 0.35–0.45). The irreducible water saturation and trapped CO2 saturation were 56% and 23%, respectively. The corresponding endpoint CO2 and water relative permeability were 0.18 and 0.47, respectively. The results, therefore, demonstrate low endpoint CO2 saturation and low relative permeability, in addition to high CO2 fractional flow at high water saturation. The trapped CO2 saturation was relatively high, which suggests a high CO2 immobilisation capability of the Wilhelmøya Subgroup sandstones. Moreover, a lower relative permeability was observed for gaseous CO2 compared to published results for supercritical CO2. In addition, the examined core sample showed a higher trapped CO2 saturation and higher endpoint CO2 relative permeability compared with the porous and permeable Berea sandstone.

• Fawad, Manzar; Mondol, MD Nazmul Haque; Baig, Irfan & Jahren, Jens (2019). Diagenetic related flat spots within the paleogene sotbakken group in the vicinity of the senja ridge, barents sea. Petroleum Geoscience. ISSN 1354-0793. 26(3), s. 373–385. doi: 10.1144/petgeo2018-122. Fulltekst i vitenarkiv Vis sammendrag

  Rock physics analyses of data from a wildcat well 7117/9-1 drilled in the Senja Ridge area, located in the Norwegian Barents Sea, reveal changes in stiffness within the fine-grained Paleogene Sotbakken Group sediments, caused by the transformation of opal-A to opal-CT, and opal-CT to quartz. These changes manifest as flat spots on 2D seismic profiles. These flat spots were mistaken as hydrocarbon–water contacts, which led to the drilling of well 7117/9-1. Rock physics analyses on this well combined with a second well (7117/9-2) drilled further NW and updip on the Senja Ridge indicate overpressure within the opal-CT-rich zones overlying the opal-CT to quartz transformation zones in the two wells. The absence of opal-A–opal-CT and opal-CT–quartz flat spots on seismic in the second well is attributed to differences in the temperature and timing of uplift. Amplitude v. angle (AVA) modelling indicates both the opal-A–opal-CT and opal-CT–quartz interface points plot on the wet trend, whereas modelled gas–brine, oil–brine and gas–oil contacts fall within quadrant-I. These findings will be useful in understanding the nature of compaction of biogenic silica-rich sediments where flat spots could be misinterpreted as hydrocarbon-related contacts in oil and gas exploration.

• Griffiths, Luke; Dautriat, Jérémie; Rodriguez, Ismael Vera; Iranpour, Kamran; Sauvin, Guillaume & Park, Joonsang [Vis alle 13 forfattere av denne artikkelen] (2019). Inferring microseismic source mechanisms and in situ stresses during triaxial deformation of a North-Sea-analogue sandstone. Advances in Geosciences. ISSN 1680-7340. 49, s. 85–93. doi: 10.5194/adgeo-49-85-2019. Fulltekst i vitenarkiv Vis sammendrag

  Monitoring microseismic activity provides a window through which to observe reservoir deformation during hydrocarbon and geothermal energy production, or CO2 injection and storage. Specifically, microseismic monitoring may help constrain geomechanical models through an improved understanding of the location and geometry of faults, and the stress conditions local to them. Such techniques can be assessed in the laboratory, where fault geometries and stress conditions are well constrained. We carried out a triaxial test on a sample of Red Wildmoor sandstone, an analogue to a weak North Sea reservoir sandstone. The sample was coupled with an array of piezo-transducers, to measure ultrasonic wave velocities and monitor acoustic emissions (AE) – sample-scale microseismic activity associated with micro-cracking. We calculated the rate of AE, localised the AE events, and inferred their moment tensor from P-wave first motion polarities and amplitudes. We applied a biaxial decomposition to the resulting moment tensors of the high signal-to-noise ratio events, to provide nodal planes, slip vectors, and displacement vectors for each event. These attributes were then used to infer local stress directions and their relative magnitudes. Both the AE fracture mechanisms and the inferred stress conditions correspond to the sample-scale fracturing and applied stresses. This workflow, which considers fracture models relevant to the subsurface, can be applied to large-scale geoengineering applications to obtain fracture mechanisms and in-situ stresses from recorded microseismic data.

• Smith, Halvard; Bohloli, Bahman; Skurtveit, Elin & Mondol, Nazmul Haque (2019). Engineering Parameters of Draupne Shale - Fracture Characterization and Integration with Mechanical Data, 6th EAGE Shale Workshop 2019, Bordequx, France 28 April - 1 May 2019. European Association of Geoscientists and Engineers (EAGE). ISSN 9781510886667. doi: 10.3997/2214-4609.201900277. Fulltekst i vitenarkiv Vis sammendrag

  Fracture characteristics are important as they provide information about the mechanical integrity of its host rock. This study addresses the properties of fractured surfaces of Upper Jurassic organic-rich Shale (Draupne Formation) cored from an exploration well (16/8-3 S) in the Central North Sea. The characterization consists of two steps: i) petrographic studies of the fractured material at micro- and macroscale compared with the mechanical data, and ii) mapping of surfaces with photogrammetric method before and after the samples were sheared in a direct shear test (DST) to determine frictional properties. The preliminary results reveal complex structures, with the natural fractures appearing more diverse than the artificially reactivated surfaces produced from the direct shear test, which may affirm the importance of factors as e.g. temperature, displacement, slip rate and number of reactivations. Moreover, these small-scale fracture planes seem to link up with adjacent fractures to accumulate displacement over a wider area. Little attention has been paid to the details of fractures in shale, despite their importance in the energy industry. Therefore, objective of this study is to provide detailed descriptions of fracture surfaces in shale and the consequences this might induce

• Hansen, Jørgen André; Johnson, James Ronald & Mondol, Nazmul Haque (2019). Cap Rock Evaluation of Central North Sea Shales, Through Log-Derived Poisson's Ratio and Young's Modulus, 6th EAGE Shale Workshop 2019, Bordequx, France 28 April - 1 May 2019. European Association of Geoscientists and Engineers (EAGE). ISSN 9781510886667. doi: 10.3997/2214-4609.201900269. Fulltekst i vitenarkiv Vis sammendrag

  We present an evaluation of shale dominated cap rocks relevant for Middle Jurassic sandstone reservoirs in the Central North Sea, based on well log data from the Norwegian Continental Shelf. Previously established indicators for brittleness and seal quality, E (Young's modulus) and ν (Poisson's ratio), are utilized in the analysis. Similar ductile to fairly ductile behaviour is found in different formations for five analysed wells, of which two are oil discoveries, one contains only oil shows, and two are dry. Cap rocks in the discovery wells are comparatively most brittle, compared to a published E–ν template. Uplift of ~500 m in one of the discovery wells is not found to have compromised the sealing capability. We also investigate how organic content influence an organic-rich shale interval in terms of cap rock properties by using kerogen substitution and comparing to the other more organic-lean shales, which does not support a direct correlation between TOC and ductility. Finally, we consider how observed properties of different shales relate to different mineralogical composition.

• Baig, Irfan; Faleide, Jan Inge; Mondol, Nazmul Haque & Jahren, Jens (2019). Burial and exhumation history controls on shale compaction and thermal maturity along the Norwegian North Sea basin margin areas. Marine and Petroleum Geology. ISSN 0264-8172. 104, s. 61–85. doi: 10.1016/j.marpetgeo.2019.03.010. Fulltekst i vitenarkiv Vis sammendrag

  The North Sea area has been subjected to significant erosion and subsequent deposition of sediments in the basin margin and deeper basin areas, respectively, during the late Neogene. A large amount of Cretaceous-early Quaternary sediments have been removed below the angular unconformity along the west and southwest coast of Norway and deposited in the huge North Sea Fan at the mouth of the Norwegian Channel. At the same time, a considerable thickness of early Quaternary-Paleocene sediments was also eroded towards the east in the central North Sea and subsequently deposited in the deeper basin areas to the west. This study seeks to estimate exhumation from compaction and thermal maturity based techniques by using sonic velocities of shales/carbonates and vitrinite reflectance data in a large number of boreholes in the central, eastern and northern North Sea. The results indicate no or minor exhumation in the Central Graben and flanking high areas, whereas more than ∼1 km sediments are eroded in the basin margin areas towards the Norwegian coast. More than ∼500 m sediments are eroded in the Egersund Basin and Stord Basin areas. A similarity of exhumation estimates from the Early Cretaceous-Early Miocene shales and Late Cretaceous-Early Paleocene carbonates indicates maximum burial sometime after the Early Miocene in most of the central and northern North Sea areas. However, the maximum burial throughout the North Sea Basin may be diachronous. Seismostratigraphic analysis indicates maximum burial sometime during the Oligocene in the Sorgenfrei-Tornquist Zone area in the eastern North Sea. Maximum burial in the Norwegian-Danish Basin varies from Miocene-Pliocene in eastern parts to early Pleistocene in western parts, whereas sediments are currently at their maximum burial in the Central Graben and southern Viking Graben areas. Restoration of surface elevations to their original position before the onset of erosion indicated large subaerially exposed areas in the Norwegian-Danish Basin and along the southwest coast of Norway. This is also supported by predominantly coastal and/or deltaic environments in the Norwegian-Danish Basin area during the late Neogene. These subaerially exposed areas may be linked to the regional tilting and erosion of the basin margin areas to the east and progressive basinward migration of deposition centres to the west since the Oligocene. The exhumation had significant effects on the petroleum system in the basin margin areas by cooling down the source rock. However, the deeper burial of sediments may also have changed the rheological properties of sediments from more ductile to brittle due to compaction and diagenetic processes which makes them more failure prone during exhumation leading to hydrocarbon leakage or seal failure in case of CO2 injection.

Se alle arbeider i NVA

• Grande, Lars; Forsberg, Carl Fredrik; Mondol, Md Nazmul Haque; Skurtveit, Elin; Singh, Rao Martand & Amiri, Seyed Ali Ghoreishian [Vis alle 10 forfattere av denne artikkelen] (2023). Impact of sediment composition, glacial loading and uplift on ground stresses in the Horda-Platform area. Fulltekst i vitenarkiv
• Roberts, Dan; Phillips, Dan; Grande, Lars; Forsberg, Carl Fredrik; Mondol, Md Nazmul Haque & Choi, Jung Chan [Vis alle 8 forfattere av denne artikkelen] (2023). Accounting for Stress History and Lithology in Geomechanical Models: Implications for Subsurface CO2 Storage Integrity on the Horda Platform. Fulltekst i vitenarkiv
• Bohloli, Bahman & Mondol, Md Nazmul Haque (2022). Assessing integrity of CO2 storage sites based on ground deformation. Fulltekst i vitenarkiv
• Rahman, Md Jamilur; Fawad, Manzar & Mondol, Nazmul Haque (2022). Potential Effect of Biot’S Coefficient on Rock Failure in CO2 Storage Site Smeaheia, Northern North Sea. Fulltekst i vitenarkiv
• Rahman, Md Jamilur; Fawad, Manzar & Mondol, Nazmul Haque (2022). Lateral distribution of the upper Amundsen shale in potential Co2 storage site Aurora, northern North Sea. Fulltekst i vitenarkiv
• Dombrovski, Elisaveta; Mondol, Nazmul Haque; Bohloli, Bahman; Gaina, Carmen & Torabi, Anita (2021). Monitoring ground surface and seafloor deformation caused by subsurface fluid injection. Fulltekst i vitenarkiv
• Fawad, Manzar; Rahman, MD Jamilur & Mondol, Nazmul Haque (2021). Overburden Analysis and Seal Integrity Study for CO2 Sequestration in the North Sea (OASIS). SSRN Electronic Journal. doi: 10.2139/ssrn.3813310. Fulltekst i vitenarkiv
• Rahman, MD Jamilur; Fawad, Manzar & Mondol, Nazmul Haque (2021). Caprock characterization of Longship CCS project. Abstracts and Proceedings of the Geological Society of Norway. Fulltekst i vitenarkiv
• Rahman, Md Jamilur; Lebedev, Maxim & Mondol, Nazmul Haque (2021). Nanoscale mechanical properties of organic-rich Draupne shale caprock, offshore Norway. SEG technical program expanded abstracts. s. 1726–1730. doi: 10.1190/segam2021-3581994.1. Fulltekst i vitenarkiv
• Bohloli, Bahman; Park, Joonsang; Bjørnarå, Tore Ingvald; Sparrevik, Per; Frauenfelder, Regula & Vöge, Malte [Vis alle 10 forfattere av denne artikkelen] (2021). Monitoring ground surface and seafloor deformation caused by subsurface fluid injection. Fulltekst i vitenarkiv
• Johnson, James Ronald; Kobchenko, Maya; Mondol, Nazmul Haque & Renard, François (2021). Multiscale synchrotron X-ray microtomography imaging of organic material in shales in the context of primary migration. Fulltekst i vitenarkiv
• Kobchenko, Maya; Pluymakers, Anne Marie Henriette; Benoit, Cordonnier; Mondol, Nazmul Haque & Renard, François (2021). Time-lapse synchrotron X-ray imaging of deformation modes in organic-rich Green River Shale heated under confinement. Fulltekst i vitenarkiv
• Dombrovski, Elisaveta; Mondol, Nazmul Haque; Bohloli, Bahman & Torabi, Anita (2021). Applying machine learning on InSAR data for carbon sequestration site monitoring. Fulltekst i vitenarkiv
• Fawad, Manzar; Rahman, MD Jamilur & Mondol, Nazmul Haque (2021). Comparison of pore pressure estimation from P- and S- wave velocities. Fulltekst i vitenarkiv
• Olsen, Håkon Berggren & Mondol, Nazmul Haque (2021). Reservoir characterization of Utsira High, central North Sea. Fulltekst i vitenarkiv
• Kizatbay, Alseit; Rahman, MD Jamilur & Mondol, Nazmul Haque (2021). Reservoir characterization of Jurassic sandstones in the SW Barents Sea. Fulltekst i vitenarkiv
• Rahman, MD Jamilur; Fawad, Manzar & Mondol, Nazmul Haque (2021). Reservoir fluid effect on caprock properties in the Horda Platform area, northern North Sea. SSRN Electronic Journal. doi: 10.2139/ssrn.3812432. Fulltekst i vitenarkiv
• Shahid, Ali Asghar; Rahman, MD Jamilur & Mondol, Nazmul Haque (2021). Characterization of HTHP reservoir in the northern North Sea, offshore Norway. Fulltekst i vitenarkiv
• Bohloli, Bahman; Bateson, Luke; Berndt, Christian; Bjørnarå, Tore Ingvald; Eiken, Ola & Estublier, Audrey [Vis alle 23 forfattere av denne artikkelen] (2021). Assuring Integrity of CO2 Storage Sites Through Ground Surface Monitoring (SENSE). SSRN Electronic Journal. doi: 10.2139/ssrn.3818971. Fulltekst i vitenarkiv
• Johnson, James Ronald; Kobchenko, Maya; Mondol, Nazmul Haque & Renard, François (2021). Analogue modelling of primary migration in shales using organic-rich and organic-poor layered gel. Fulltekst i vitenarkiv
• Park, Joonsang; Griffiths, Luke; Dautriat, Jérémie; Grande, Lars; Rodriguez, Ismael Vera & Iranpour, Kamran [Vis alle 16 forfattere av denne artikkelen] (2021). Induced-seismicity geomechanics for controlled CO2 storage in the North Sea (IGCCS). SSRN Electronic Journal. doi: 10.2139/ssrn.3819665. Fulltekst i vitenarkiv
• Griffiths, Luke; Dautriat, Jérémie; Park, Joonsang; Rodriguez, Ismael Vera; Iranpour, Kamran & Sauvin, Guillaume [Vis alle 13 forfattere av denne artikkelen] (2021). The Influence of Super-critical CO2 Saturation on the Mechanical and Failure Properties of a North Sea Reservoir Sandstone Analogue. SSRN Electronic Journal. doi: 10.2139/ssrn.3818808. Fulltekst i vitenarkiv
• Rahman, MD Jamilur; Fawad, Manzar & Mondol, Nazmul Haque (2020). Mineralogy based geomechanical behavior of Draupne caprock shales in the northern North Sea, offshore Norway. EAGE extended abstracts. s. 1–5. doi: 10.3997/2214-4609.202011458. Fulltekst i vitenarkiv
• Rahman, MD Jamilur; Fawad, Manzar & Mondol, Nazmul Haque (2020). Reservoir fluid effect on caprock properties in the Horda Platform area, northern North Sea. International Conference on Greenhouse Gas Control Technologies. Fulltekst i vitenarkiv
• Rahman, MD Jamilur; Fawad, Manzar & Mondol, Nazmul Haque (2020). Caprock quality of potential CO2 storage site Smeaheia. NGF Abstracts and Proceedings of the Geological Society of Norway. Fulltekst i vitenarkiv
• Fawad, Manzar & Mondol, Nazmul Haque (2020). Monitoring subsurface CO2 storage using seismic and CSEM data – Modelling in Smeaheia area, northern North Sea. Fulltekst i vitenarkiv
• Rahman, MD Jamilur; Fawad, Manzar & Mondol, Nazmul Haque (2020). Depositional processes and shallow diagenesis effect on caprock elastic properties in Horda Platform area, northern North Sea. Fulltekst i vitenarkiv
• Grande, Lars; Griffiths, Luke; Park, Joonsang; Choi, Jung Chan; Bjørnarå, Tore Ingvald & Sauvin, Guillaume [Vis alle 7 forfattere av denne artikkelen] (2020). Acoustic Emission Testing of Shales for Evaluation of Microseismic Monitoring of North Sea CO2 Storage Sites, 82nd EAGE Conference & Exhibition. Fulltekst i vitenarkiv
• Griffiths, Luke; Park, Joonsang; Soldal, Magnus; Sauvin, Guillaume; Grande, Lars & Choi, Jung Chan [Vis alle 13 forfattere av denne artikkelen] (2020). Assessing the potential of microseismic monitoring of North Sea geological CO2 storage sites through laboratory testing. Fulltekst i vitenarkiv
• Grande, Lars; Park, Joonsang; Griffiths, Luke; Bjørnarå, Tore Ingvald; Sauvin, Guillaume & Soldal, Magnus [Vis alle 8 forfattere av denne artikkelen] (2020). Geomechanical and geophysical evaluations for safe CO2 storage in the North Sea. Fulltekst i vitenarkiv
• Bohloli, Bahman & Mondol, Md Nazmul Haque (2019). Assuring integrity of CO2 storage sites using ground surface deformation. Fulltekst i vitenarkiv
• Fawad, Manzar; Hansen, Jørgen André & Mondol, Nazmul Haque (2019). Seal characterization of the Amundsen Formation for CO2 storage in the northern North Sea. Fulltekst i vitenarkiv
• Hansen, Jørgen André; Johnson, James Ronald; Fawad, Manzar & Mondol, Nazmul Haque (2019). Quantitative characterization of the Central North Sea Jurassic petroleum system. Fulltekst i vitenarkiv
• Hansen, Jørgen André; Johnson, James Ronald & Mondol, Nazmul Haque (2019). Cap rock evaluation of Central North Sea shales, through log-derived Poisson’s ratio and Young’s modulus. Fulltekst i vitenarkiv
• Mondol, Nazmul Haque (2019). Geomechanical and Seismic Behaviors of Draupne Shale: A Case Study from the Central North Sea. Fulltekst i vitenarkiv
• Johnson, James Ronald; Hansen, Jørgen André; Mondol, Nazmul Haque & Renard, Francois (2019). Modeling maturation, elastic, and geomechanical properties of the Draupne Formation, Offshore Norway. Fulltekst i vitenarkiv
• Johnson, James Ronald; Hansen, Jørgen André; Renard, Francois & Mondol, Nazmul Haque (2019). Geomechanical Analysis of Maturation for the Draupne Shale, Offshore Norway. Fulltekst i vitenarkiv
• Griffiths, Luke; Dautriat, Jérémie; Rodriguez, Ismael Vera; Iranpour, Kamran; Sauvin, Guillaume & Park, Joonsang [Vis alle 13 forfattere av denne artikkelen] (2019). Inferring microseismic source mechanisms and in situ stresses during triaxial deformation of a North-Sea-analogue sandstone. Advances in Geosciences. ISSN 1680-7340. doi: 10.5194/adgeo-49-85-2019. Fulltekst i vitenarkiv
• Griffiths, Luke; Park, Joonsang; Sauvin, Guillaume; Soldal, Magnus; Grande, Lars & Mondol, Nazmul Haque [Vis alle 13 forfattere av denne artikkelen] (2019). Microseismic monitoring of reservoir rock and cap rock integrity at North Sea geological CO2 storage sites: insights from acoustic emission testing. Geophysical Research Abstracts. ISSN 1029-7006. Fulltekst i vitenarkiv
• Fawad, Manzar & Mondol, Nazmul Haque (2019). AVO Modelling Considering Various Caprock and Reservoir Scenarios for Potential CO2 Storage in Smeaheie Area, Northern North Sea. Fulltekst i vitenarkiv
• Fawad, Manzar & Mondol, Nazmul Haque (2019). OASIS - Overburden Analysis and Seal Integrity Study for CO2 Sequestration in the North Sea. Fulltekst i vitenarkiv
• Fawad, Manzar & Mondol, Nazmul Haque (2019). Comparison of Sealing Properties of Amundsen and Drake Formations for Potential CO2 Storage in North Sea. Fulltekst i vitenarkiv
• Smith, Halvard & Mondol, Nazmul Haque (2019). Engineering parameters of Draupne shale - Characterization of fractured samples and integration with mechanical tests. Universitetet i Oslo. Fulltekst i vitenarkiv

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