Md Nazmul Haque Mondol

• 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 978-82-536-1714-5. s. 127–134.
• 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 978-82-536-1714-5. s. 19–26.
• 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
• 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
• 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.
• 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.
• Fawad, Manzar & Mondol, Nazmul Haque (2021). Monitoring geological storage of CO2: a new approach. Scientific Reports. ISSN 2045-2322. 11(1). doi: 10.1038/s41598-021-85346-8.
• 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 978-1-7138-1362-0. s. 1977–1981. doi: 10.3997/2214-4609.202011984.
• 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
• 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.

• 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.

• 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.

• 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.

• 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. 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; 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.

• Fawad, Manzar & Mondol, MD Nazmul Haque (2019). Geological and geophysical investigation of CO2 storage site Smeaheia in the northern North Sea. SEG technical program expanded abstracts. ISSN 1949-4645. doi: 10.1190/segam2019-3215406.1.
• 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 978-1-5108-9281-1. doi: 10.3997/2214-4609.201901599. 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, 81st EAGE Conference and Exhibition 2019. European Association of Geoscientists and Engineers (EAGE). ISSN 978-1-5108-9281-1. doi: 10.3997/2214-4609.201900793. 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, 6th EAGE Shale Workshop 2019, Bordequx, France 28 April - 1 May 2019 . European Association of Geoscientists and Engineers (EAGE). ISSN 978-1-5108-8666-7. doi: 10.3997/2214-4609.201900272.
• 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 978-1-5108-8666-7. doi: 10.3997/2214-4609.201900277.
• 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 978-1-5108-8666-7. doi: 10.3997/2214-4609.201900269.
• Fawad, Manzar & Mondol, Nazmul Haque (2019). AVO Modelling Considering Various Caprock and Reservoir Scenarios for Potential CO2 Storage in Smeaheie Area, Northern North Sea, 6th EAGE Shale Workshop 2019, Bordequx, France 28 April - 1 May 2019 . European Association of Geoscientists and Engineers (EAGE). ISSN 978-1-5108-8666-7. 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.

• Griffiths, Luke; Dautriat, Jérémie; Vera Rodriguez, Ismael; 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.

• 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. ISSN 1949-4645. 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.

• 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. doi: 10.1144/petgeo2018-122. Fulltekst i vitenarkiv
• 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
• 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.

• Naseryan Moghadam, Javad; 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.

• 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
• 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. 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.

• Narongsirikul, Sirikarn; Mondol, Nazmul Haque & Jahren, Jens (2018). Acoustic and petrophysical properties of mechanically compacted overconsolidated sands: Part 2 - Rock physics modelling and applications. Geophysical Prospecting. ISSN 0016-8025. 67, s. 114–127. doi: 10.1111/1365-2478.12692.
• Mondol, Nazmul Haque (2018). Predicting Seal Brittleness of Conventional Hydrocarbon Reservoirs Using LMR - a Case Study from the Norwegian Barents Sea. I N/A, N/A (Red.), 80th EAGE Annual Conference & Exhibition 2018. European Association of Geoscientists and Engineers (EAGE). ISSN 978-94-6282-254-2. doi: 10.3997/2214-4609.201800675.
• Hansen, Jørgen André & Mondol, Nazmul Haque (2018). Predicting the Effects of Organic Content and Maturation on the Elastic Properties of Central North Sea Source Rocks. I N/A, N/A (Red.), 80th EAGE Annual Conference & Exhibition 2018. European Association of Geoscientists and Engineers (EAGE). ISSN 978-94-6282-254-2. doi: 10.3997/2214-4609.201800865.
• Yenwongfai, Honore Dzekamelive; Mondol, Nazmul Haque; Lecomte, Isabelle; Faleide, Jan Inge & Leutscher, Johan (2018). Integrating facies-based Bayesian inversion and supervised machine learning for petro-facies characterization in the Snadd Formation of the Goliat Field, south-western Barents Sea. Geophysical Prospecting. ISSN 0016-8025. 67, s. 1020–1039. doi: 10.1111/1365-2478.12654. Fulltekst i vitenarkiv Vis sammendrag

  Seismic petro‐facies characterization in low net‐to‐gross reservoirs with poor reservoir properties such as the Snadd Formation in the Goliat field requires a multidisciplinary approach. This is especially important when the elastic properties of the desired petro‐facies significantly overlap. Pore fluid corrected endmember sand and shale depth trends have been used to generate stochastic forward models for different lithology and fluid combinations in order to assess the degree of separation of different petro‐facies. Subsequently, a spectral decomposition and blending of selected frequency volumes reveal some seismic fluvial geomorphological features. We then jointly inverted for impedance and facies within a Bayesian framework using facies‐dependent rock physics depth trends as input. The results from the inversion are then integrated into a supervised machine learning neural network for effective porosity discrimination. Probability density functions derived from stochastic forward modelling of endmember depth trends show a decreasing seismic fluid discrimination with depth. Spectral decomposition and blending of selected frequencies reveal a dominant NNE trend compared to the regional SE–NW pro‐gradational trend, and a local E–W trend potentially related to fault activity at branches of the Troms‐Finnmark Fault Complex. The facies‐based inversion captures the main reservoir facies within the limits of the seismic bandwidth. Meanwhile the effective porosity predictions from the multilayer feed forward neural network are consistent with the inverted facies model, and can be used to qualitatively highlight the cleanest regions within the inverted facies model. A combination of facies‐based inversion and neural network improves the seismic reservoir delineation of the Snadd Formation in the Goliat Field.

• Hansen, Jørgen André & Mondol, Nazmul Haque (2018). Reservoir characterization of the Triassic Kobbe and Snadd formations — Bjarmeland Platform, Norwegian Barents Sea. First Break. ISSN 0263-5046. 36(2), s. 37–45. doi: 10.3997/1365-2397.2017024. Fulltekst i vitenarkiv Vis sammendrag

  A reservoir characterization study of the Triassic Kobbe and Snadd formations is carried out in the Bjarmeland Platform area, Norwegian Barents Sea, through detailed petrophysical analysis and rock physics diagnostics. Results are tied to depositional environments and discussed in the context of burial depth and cementation as present burial depth is less than maximum burial depth due to upliftment. Marginal marine sandstones in the Snadd Formation display marginally better reservoir quality on average than those of fluvial origin, yet higher quality individual reservoirs are observed within both facies. As expected, the Kobbe Formation reservoirs are consistently poorer. The sensitivity of existing rock physics models to the data is shown to be reasonably valid (via porosity, water saturation, shale volume). Snadd Formation reservoir sandstones not affected by cementation are only observed at shallow depth in the west of the study area. This is supported by comparison to an experimental compaction trend as well as rock physics models. All Kobbe Formation reservoir units show consistent signs of chemical compaction due to deeper burial. The main findings of this study are estimates of important reservoir properties and examples of how results from petrophysical analysis are validated and complemented in various rock physics domains.

• Nooraiepour, Mohammad; Bohloli, Bahman; Park, Joonsang; Sauvin, Guillaume; Skurtveit, Elin & Mondol, Nazmul Haque (2018). Effect of brine-CO2 fracture flow on velocity and electrical resistivity of naturally fractured tight sandstones. Geophysics. ISSN 0016-8033. 83(1), s. WA37–WA48. doi: 10.1190/GEO2017-0077.1. Fulltekst i vitenarkiv Vis sammendrag

  Fracture networks inside geological CO2 storage reservoirs can serve as primary fluid flow conduit, particularly in low-permeability formations. While some experiments focused on the geophysical properties of brine- and CO2-saturated rocks during matrix flow, geophysical monitoring of fracture flow when CO2 displaces brine inside the fracture seems to be overlooked. We have conducted laboratory geophysical monitoring of fluid flow in a naturally fractured tight sandstone during brine and liquid CO2 injection. For the experiment, the low-porosity, low-permeability naturally fractured core sample from the Triassic De Geerdalen Formation was acquired from the Longyearbyen CO2 storage pilot at Svalbard, Norway. Stress-dependence, hysteresis and the influence of fluid-rock interactions on fracture permeability were investigated. The results suggest that in addition to stress level and pore pressure, mobility and fluid type can affect fracture permeability during loading and unloading cycles. Moreover, the fluid-rock interaction may impact volumetric strain and consequently fracture permeability through swelling and dry out during water and CO2 injection, respectively. Acoustic velocity and electrical resistivity were measured continuously in the axial direction and three radial levels. Geophysical monitoring of fracture flow revealed that the axial P-wave velocity and axial electrical resistivity are more sensitive to saturation change than the axial S-wave, radial P-wave, and radial resistivity measurements when CO2 was displacing brine, and the matrix flow was negligible. The marginal decreases of acoustic velocity (maximum 1.6% for axial Vp) compared to 11% increase in axial electrical resistivity suggest that in the case of dominant fracture flow within the fractured tight reservoirs, the use of electrical resistivity methods have a clear advantage compared to seismic methods to monitor CO2 plume. The knowledge learned from such experiments can be useful for monitoring geological CO2 storage where the primary fluid flow conduit is fracture network.

• Hansen, Jørgen André; Mondol, Nazmul Haque; Tsikalas, F. & Doering, S. (2017). Improved Transition Zone Identification Using Relations Between Shear Wave Velocity and Density, Fourth EAGE Workshop on Rock Physics 2017. European Association of Geoscientists and Engineers (EAGE). ISSN 978-1-5108-5087-3. s. 95–99. doi: 10.3997/2214-4609.201702462.
• Hansen, Jørgen André; Yenwongfai, Honore Dzekamelive; Fawad, Manzar & Mondol, Nazmul Haque (2017). Estimating exhumation using experimental compaction trends and rock physics relations, with continuation into analysis of source and reservoir rocks: Central North Sea, offshore Norway. SEG technical program expanded abstracts. ISSN 1949-4645. s. 3971–3975. doi: 10.1190/segam2017-17783053.1. Fulltekst i vitenarkiv Vis sammendrag

  We present a quantitative estimate of exhumation in the Central North Sea by examining depth trends of velocity and density data compared to experimental compaction trends. Additionally, seismic inversion and attribute application from the study area is shown as an example of the connection to future work on quantitative analysis of source and reservoir rocks. Rock physics relations are demonstrated to be important for all parts of the study.

• Rahman, MD Jamilur & Mondol, Nazmul Haque (2017). Lateral changes in reservoir properties of the Stø Sandstone in the Snøhvit field, SW Barents Sea. First Break. ISSN 0263-5046. 35(7), s. 35–40. doi: 10.3997/1365-2397.2017015. Vis sammendrag

  The Stø sandstone being the main reservoir in the Barents Sea area is moderate to well sorted and mineralogically mature. This formation is thickest in the southwestern part of the Snøhvit field and gradually thinning eastward. The main objective of this study is to find out this variation using rock physics analysis. Two wells (7120/6-2S and 7121/5-1) from the field were used in this study to investigate lateral rock property variation within the Stø sandstone reservoir. Stress-dependent mechanical compaction varies because of mineralogy and textural difference from east to west despite similar effective stress regime during burial. Chemical compaction also plays a significant role which depends on the dissolution of quartz grains at stylolites and pressure solution of grain-to-grain contact and available specific surface area to precipitate quartz cement. More stylolites generated in shalye sandstone in the east compared to clean sandstone in the west suggested higher cementation in the eastern wells compared to the west. It can be concluded that both mechanical and chemical compaction processes resulted in rock property variations in the same reservoir rock within the field.

• Yenwongfai, Honore Dzekamelive; Mondol, Nazmul Haque; Faleide, Jan Inge; Lecomte, Isabelle & Leutscher, Johan (2017). Prestack inversion and multiattribute analysis for porosity, shale volume, and sand probability in the Havert Formation of the Goliat field, southwest Barents Sea. Interpretation. ISSN 2324-8858. 5(3), s. SL69–SL87. doi: 10.1190/INT-2016-0169.1. Fulltekst i vitenarkiv Vis sammendrag

  An integrated innovative multidisciplinary approach has been used to estimate effective porosity (PHIE), shale volume (Vsh), and sand probability from prestack angle gathers and petrophysical well logs within the Lower Triassic Havert Formation in the Goliat field, Southwest Barents Sea. A rock-physics feasibility study revealed the optimum petrofacies discriminating ability of extended elastic impedance (EEI) tuned for PHIE and Vsh. We then combined model-based prestack inversion outputs from a simultaneous inversion and an EEI inversion into a multilinear attribute regression analysis to estimate absolute Vsh and PHIE seismic attributes. The quality of the Vsh and PHIE prediction is shown to increase by integrating the EEI inversion in the workflow. Probability distribution functions and a priori petrofacies proportions extracted from the well data are then applied to the Vsh and PHIE volumes to obtain clean and shaly sand probabilities. A tectonic-controlled point-source depositional model for the Havert Formation sands is then inferred from the extracted sand bodies and the seismic geomorphological character of the different attributes

• Yenwongfai, Honore Dzekamelive; Mondol, Nazmul Haque; Faleide, Jan Inge & Lecomte, Isabelle (2017). Prestack simultaneous inversion to predict lithology and pore fluid in the Realgrunnen Subgroup of the Goliat Field, southwestern Barents Sea. Interpretation. ISSN 2324-8858. 5(2), s. SE75–SE96. doi: 10.1190/INT-2016-0109.1. Fulltekst i vitenarkiv
• Koochak Zadeh, Mohammad; Mondol, Nazmul Haque & Jahren, Jens (2017). Velocity anisotropy of upper jurassic organic-rich shales, Norwegian continental shelf. Geophysics. ISSN 0016-8033. 82(2), s. C61–C75. doi: 10.1190/GEO2016-0035.1. Fulltekst i vitenarkiv Vis sammendrag

  This study investigates the seismic velocity anisotropy of two organic-rich shales from the Norwegian Continental Shelf. The tested organic-rich shale samples were from the Upper Jurassic Draupne and Hekkingen formations collected from two wells (16/8-3S and 7125/1-1) drilled in the central North Sea and western Barents Sea, respectively. The two tested shales are different in organic matter richness and thermal maturation, and they have experienced different burial histories. The shale core plugs were tested in a triaxial cell under controlled pore pressure. Seismic velocities (V P VP and V S VS ) were measured along different orientations with respect to layering to identify the complete tensor of the rock elastic moduli, and to investigate the velocity anisotropy as a function of increasing effective stress. The measured velocity values exhibit strong anisotropy for the two tested organic-rich shales. The anisotropy for both shales is strongest for V S VS . Seismic velocities follow an increasing trend as the effective stress increases. The anisotropy decreases somewhat with increasing consolidation, probably due to the closing of preexisting fractures and microcracks. The reduction of anisotropy is more evident for the P-wave because it decreases from 0.32 to 0.25 for the Draupne sample and from 0.28 to 0.24 for the Hekkingen sample when the vertical effective stress increases from 26 to 50 MPa. In general, the Hekkingen sample indicates slightly higher velocity values than the Draupne sample due to more compaction and lower porosity. In spite of major differences between the two shale formations in terms of organic matter content, maturity and burial history, they indicate almost the same degree of velocity anisotropy. The outcomes of this study can contribute to better imaging of organic-rich Draupne and Hekkingen shales by constraining the rock-physics properties.

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• 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.
• 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.
• 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.
• Fawad, Manzar; Rahman, MD Jamilur & Mondol, Nazmul Haque (2021). Comparison of pore pressure estimation from P- and S- wave velocities.
• 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.
• Dombrovski, Elisaveta; Mondol, Nazmul Haque; Bohloli, Bahman & Torabi, Anita (2021). Applying machine learning on InSAR data for carbon sequestration site monitoring.
• Olsen, Håkon Berggren & Mondol, Nazmul Haque (2021). Reservoir characterization of Utsira High, central North Sea.
• Kizatbay, Alseit; Rahman, MD Jamilur & Mondol, Nazmul Haque (2021). Reservoir characterization of Jurassic sandstones in the SW Barents Sea.
• Shahid, Ali Asghar; Rahman, MD Jamilur & Mondol, Nazmul Haque (2021). Characterization of HTHP reservoir in the northern North Sea, offshore Norway.
• 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.
• 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.
• 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.
• 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.
• Rahman, MD Jamilur; Fawad, Manzar & Mondol, Nazmul Haque (2021). Caprock characterization of Longship CCS project. Abstracts and Proceedings of the Geological Society of Norway.
• 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.
• 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.
• 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.
• 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.
• 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.
• 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.
• 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.
• Fawad, Manzar & Mondol, Nazmul Haque (2020). Monitoring subsurface CO2 storage using seismic and CSEM data – Modelling in Smeaheia area, northern North Sea.
• Griffiths, Luke; Dautriat, Jérémie; Vera Rodriguez, Ismael; 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.
• Fawad, Manzar & Mondol, Nazmul Haque (2019). Comparison of Sealing Properties of Amundsen and Drake Formations for Potential CO2 Storage in North Sea.
• Fawad, Manzar & Mondol, Nazmul Haque (2019). AVO Modelling Considering Various Caprock and Reservoir Scenarios for Potential CO2 Storage in Smeaheie Area, Northern North Sea.
• Fawad, Manzar & Mondol, Nazmul Haque (2019). OASIS - Overburden Analysis and Seal Integrity Study for CO2 Sequestration in the North Sea.
• Fawad, Manzar; Hansen, Jørgen André & Mondol, Nazmul Haque (2019). Seal characterization of the Amundsen Formation for CO2 storage in the northern North Sea.
• Hansen, Jørgen André; Johnson, James Ronald; Fawad, Manzar & Mondol, Nazmul Haque (2019). Quantitative characterization of the Central North Sea Jurassic petroleum system.
• 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.
• Mondol, Nazmul Haque (2019). Geomechanical and Seismic Behaviors of Draupne Shale: A Case Study from the Central North Sea.
• Johnson, James Ronald; Hansen, Jørgen André; Renard, Francois & Mondol, Nazmul Haque (2019). Geomechanical Analysis of Maturation for the Draupne Shale, Offshore Norway.
• Johnson, James Ronald; Hansen, Jørgen André; Mondol, Nazmul Haque & Renard, Francois (2019). Modeling maturation, elastic, and geomechanical properties of the Draupne Formation, Offshore Norway.
• Rahman, MD Jamilur; Fawad, Manzar & Mondol, Nazmul Haque (2019). Geological and geophysical analyses of cap rocks for potential CO2 storage in the Smeaheia area, northern North Sea.
• Rahman, MD Jamilur; Fawad, Manzar & Mondol, Nazmul Haque (2019). Geophysical analysis and rock physics diagnostics of overburden rocks for potential CO2 storage site Smeaheia in the northern North Sea.
• Fawad, Manzar & Mondol, Nazmul Haque (2019). Geological and Geophysical investigation of CO2 storage site Smeaheia in the northern North Sea. SEG technical program expanded abstracts. ISSN 1949-4645. s. 3285–3289. doi: 10.1190/segam2019-3215406.1. Vis sammendrag

  For a subsurface CO2 storage it is imperative to evaluate the reservoir, seal and overburden viability to avoid any storagerelated problems, or subsequent leakage risks. Whereas, in case of a hydrocarbon trap, the presence of oil and gas itself validates a working reservoir, seal and overburden system. The upper Jurassic Sognefjord Formation is a potential CO2 storage formation overlain by the Heather and Draupne Formations considered to be the cap rocks in the Smeaheie area within the northern North Sea. In this study, we extracted spectral decomposition and similarity attributes at various levels from the top reservoir to the sea floor from a 3D seismic survey covering the area. The attributes facilitated to identify various fault systems and surface features. A prestack seismic inversion was also carried out to obtain elastic property cubes, i.e. acoustic impedance, Vp/Vs ratio, and density. These elastic properties showed changes as a function of compaction and will be used to build a geomechanical model in the next stage of the study. The geological and geophysical properties derived from the seismic attributes, well logs and laboratory measurements of cores/cuttings will be used to calibrate the model.

• 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.
• Mondol, Nazmul Haque (2018). Seal quality prediction using E-Poisson's ratio rock physics templet-A case study from the Norwegian Barents Sea.
• Sharifi, Javad; Mirzakhanian, Marzieh; Mondol, Nazmul Haque & Saberi, Mohammad Reza (2018). Integrated rock physics test and modelling to detect fluid changes in a carbonate reservoir: A case study from an Iranian oil field.
• Fawad, Manzar & Mondol, Nazmul Haque (2018). Reservoir Characterisation of Johansen Formation as Potential CO2 Storage Reservoir in The Northern North Sea.
• Nooraiepour, Mohammad; Soldal, Magnus; Park, Joonsang; Mondol, Nazmul Haque; Hellevang, Helge & Bohloli, Bahman (2018). Geophysical Monitoring of Gaseous and Supercritical CO2 Fracture Flow Through a Brine-Saturated Shale Caprock.
• Mondol, Nazmul Haque; Fawad, Manzar & Park, Joonsang (2018). Petrophysical Analysis And Rock Physics Diagnostics Of Sognefjord Formation In The Smeaheia Area, Northern North Sea. Fulltekst i vitenarkiv Vis sammendrag

  This study focuses on petrophysical characterization and rock physics diagnostics of the reservoir sandstones of Sognefjord Formation in the Smeaheia area that penetrated by an exploration well 32/4-1. The large scale CO2 storage site “Smeaheia” is located east of the Troll field in the Stord Basin. The CO2 storage formation is identified within a fault block bounded by major faults to the north, east and west, where the faults system in the east is the Øygarden Fault Complex and the fault to the west and north is the Vette Fault. The storage formation has pinched out towards the south. Petrophysical analysis and rock physics diagnostics suggest that the reservoir sandstone is uncemented and has good to excellent reservoir quality. The reservoir sandstone can be subdivided into three zones where the lower unit (Zone-3) has an excellent reservoir quality (high porosity, high permeability and less clay content) compared to the upper unit (Zone-1 and Zone-2). The two carbonate stringers are present in Zone-3 interpreted as extremely high resistivity, high density, high Vp and low porosity/permeability units which could be flow barriers based on their lateral extent.

• Nooraiepour, Mohammad; Hellevang, Helge & Mondol, Nazmul Haque (2018). From field-scale to pore-scale: Investigation of caprock properties for CO2 sequestration.
• Soldal, Magnus; Sauvin, Guillaume; Park, Joonsang; Mannseth, Trond; Tveit, Svenn & Agersborg, Remy [Vis alle 8 forfattere av denne artikkelen] (2017). Geophysical monitoring for offshore CO2 storage combined with rock physics lab data(based on SUCCESS WP3 final report Geophysics).
• Yenwongfai, Honore Dzekamelive; Mondol, Nazmul Haque; Lecomte, Isabelle & Faleide, Jan Inge (2017). Quantitative Seismic interpretation strategies for petrofacies discrimination within the Triassic: A Goliat Case Study.
• Bjørlykke, Knut; Jahren, Jens; Mondol, Nazmul Haque; Hellevang, Helge & Aagaard, Per (2017). Mechanical compaction of sand and clay: Constraints from experimental compaction, chemical reactions and fluid flow during burial-An overview.
• Choi, Jung Chan; Park, Joonsang; Grande, Lars & Mondol, Nazmul Haque (2017). Anisotropy resistivity measurement using Modified Triaxial Cell: Estimation of geometry factor using numerical simulation.
• Sharifi, Javad; Mirzakhanian, M; Mondol, Nazmul Haque & Saberi, M. R. (2017). Proposed relationships between dynamic and static Young modulus of a weak carbonate reservoir using laboratory tests.
• Mondol, Nazmul Haque (2017). Rock Physics Diagnostics of Exhumed Reservoir Sandstone.
• Hansen, Jørgen André & Mondol, Nazmul Haque (2017). Reservoir characterization of the Triassic succession of the Bjarmeland Platform, SW Barents Sea.
• Haider, Shahzeb & Mondol, Nazmul Haque (2017). Depositional pattern controlling the reservoir properties of the Middle Triassic Snadd Formation from the SW Barents Sea.
• Moghadam, Javad Naseryan; Mondol, Nazmul Haque; Aagaard, Per & Hellevang, Helge (2017). Determination of CO2-Brine relative permeability curves for CO2 storage sandstone reservoirs.
• Fawad, Manzar & Mondol, Nazmul Haque (2017). Source rock evaluation using elastic properties and resistivity from the borehole logs. Example from the Egersund Basin, Central North Sea.
• Park, Joonsang; Soldal, Magnus; Sauvin, Guillaume; Nooraiepour, Mohammad; Mondol, Nazmul Haque & Bohloli, Bahman (2017). On wave propagation in a CO2/Brine-saturated fractured core.
• Yenwongfai, Honore Dzekamelive; Mondol, Nazmul Haque; Lecomte, Isabelle; Faleide, Jan Inge & Leutscher, J (2017). Integrating prestack inversion, machine learning, and forward seismic modelling for petrofacies characterization: A Barents Sea case study.
• Yenwongfai, Honore Dzekamelive; Mondol, Nazmul Haque; Faleide, Jan Inge & Lecomte, Isabelle (2017). Petrofacies characterization using prestack inversion and neural networks within the Snadd Formation of the Goliat Field, SW Barents Sea. Vis sammendrag

  The studied Goliat Field is the first oil field to be in production in the Norwegian sector of the Barents Sea despite an exploration history spanning over three decades. The reserves within Triassic Snadd Formation were not included in PDO (Plan for Development and Operations). This was due to poorer reservoir properties compared to the Realgrunnen Subgroup and the Kobbe Formation which together constitute the primary reservoir target in the Goliat Field. The field has an expected life time of 15 years. However, this life time can potentially be extended by applying quantitative seismic reservoir characterization techniques within more challenging minor reservoir intervals like the Snadd formation. Fluid discrimination by geophysical technique in uplifted Barents Sea areas has additional challenges as a result of a reduction in the seismic fluid sensitivity associated with rock stiffening (overconsolidation) due to prior deeper burial and quartz cementation. A multidisciplinary approach involving geology, rock physics, and geophysics has been used for petrofacies characterization from long offset prestack angle gathers and petrophysical well logs. A rock physics feasibility and AVA forward modelling reveal the sensitivity of the defined petrofacies classes to different elastic properties. The optimum prestack inversion method is subsequently selected based on the rock physics feasibility. The output from the inversion is used to derive the PEIL (Pseudo-Elastic Impedance), PI (Poisson Impedance), and LMR (Lambda-Mhu-Rho) attributes. These derived prestack attributes are then combined with poststack trace attributes in a neural network analysis. Neural networks utilize the non-linear relationships between the parameters to further optimize the inverted result and to predict the effective porosity, gamma ray, and resistivity log responses. Finally probability density functions (PDFs) extracted from the best well log training dataset are applied to a composite seismic attribute volume from which probability estimates of the classified petrofacies are obtained. Geological interpretations are then inferred based on the seismic geomorphological character observed from the different attributes. Probability maps obtained from this integrated approach has the potential to guide petrophysical reservoir modelling workflows and optimization of reservoir drainage strategies.

• Smith, Halvard & Mondol, Nazmul Haque (2019). Engineering parameters of Draupne shale - Characterization of fractured samples and integration with mechanical tests. UIO.

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