MD Nazmul Haque Mondol

• 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.  210:103347, s 1- 18 . doi: 10.1016/j.earscirev.2020.103347
• Fawad, Manzar & Mondol, MD Nazmul Haque (2020). 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
• 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, s 1- 18 . 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.

• 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.

• 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.

• Rahman, Jamil Ur; 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, s 1- 25 . 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.

• 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.

• 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.
• Fawad, Manzar & Mondol, Nazmul Haque (2019). AVO Modelling Considering Various Caprock and Reservoir Scenarios for Potential CO2 Storage in Smeaheie Area, Northern North Sea, In  6th EAGE Shale Workshop 2019, Bordequx, France 28 April - 1 May 2019.  European Association of Geoscientists and Engineers (EAGE).  ISBN 978-1-5108-8666-7.  Tu P06. Fulltekst i vitenarkiv. Vis sammendrag

  We have performed a comparative study of undrained triaxial testing with five different laboratories, to explore the reproducibility of test results. Opalinus Clay was sourced as testing material from a borehole at the Mont Terri URL. Cores were vacuum-sealed, and resin impregnated immediately after recovery. Systematic determination of basic properties such as water content, grain density and bulk mineralogy of specimens after testing assisted in diagnostic test evaluation. A detailed testing protocol was requested to avoid specimen damage during initial loading («swelling») and to verify specimen saturation. A balanced pore fluid was used for testing, and a consolidation phase was performed to reach specific target effective stress levels prior to the shear phase. One laboratory deviated from these protocols, as it did not use an external pore fluid. Instead, specimens were brought to variable saturation levels in a desiccator prior to assembling them into the rig. For specimens with almost identical basic properties, the test results were indeed found to be in very good agreement, despite the different procedures applied. Differences in test results can be attributed to material heterogeneity. The study provides compelling evidence that robust triaxial testing can be achieved with shales.

• Fawad, Manzar & Mondol, Nazmul Haque (2019). Comparison of Sealing Properties of Amundsen and Drake Formations for Potential CO2 Storage in North Sea, In  81st EAGE Conference and Exhibition 2019.  European Association of Geoscientists and Engineers (EAGE).  ISBN 978-1-5108-9281-1.  Tu_R02_02. 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.

• Griffiths, Luke; Dautriat, Jérémie; Vera Rodriguez, Ismael; Iranpour, Kamran; Sauvin, Guillaume; Park, Joonsang; Sarout, Joel; Soldal, Magnus; Grande, Lars; Oye, Volker; Dewhurst, David; Mondol, MD Nazmul Haque & Choi, Jung Chan (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.

• 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, In  6th EAGE Shale Workshop 2019, Bordequx, France 28 April - 1 May 2019.  European Association of Geoscientists and Engineers (EAGE).  ISBN 978-1-5108-8666-7.  Mo P02. 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.

• 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.

• Hansen, Jørgen André; Mondol, Nazmul Haque; Jahren, Jens & Tsikalas, Filippos (2019). 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.

• Johnson, James Ronald; Hansen, Jørgen André; Renard, Francois & Mondol, Nazmul Haque (2019). Geomechanical Analysis of Maturation for the Draupne Shale, Offshore Norway, In  6th EAGE Shale Workshop 2019, Bordequx, France 28 April - 1 May 2019.  European Association of Geoscientists and Engineers (EAGE).  ISBN 978-1-5108-8666-7.  Mo P05. Vis sammendrag

  Understanding maturation of source rock is increasingly of interest in both conventional and unconventional plays. Shale diagenesis and hydrocarbon generation in shales has a direct relationship with the evolution of the mechanics of maturation. The Draupne Formation, a world class source rock, which stretches over a broad range of depths and maturity, provides the ideal candidate to study the interplay between maturation and geomechanical parameters. Wireline logs and Rock-Eval data from eight wells were used to analyse how seismic waves and rock strength interplays with the source rock shales. Results reveal that the Draupne shale behaves typically in terms of maturation, however the relationship between maturation and geomechanics counters the common trend for shale. There are a wide variety of factors that could impact the geomechanical trends, including but not limited to, lithology, mineralogy, pressure, temperature, fluid content, diagenesis, compaction, fracture density, and organic content. This paper identifies key relationships between geomechanical parameters and a number of these factors, while identifying further work that could be carried out in other areas. This further highlights the importance of in-depth play fairway analysis and presents questions that require answers for successful exploration and exploitation of hydrocarbon

• 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.

• Mondol, Nazmul Haque (2019). Geomechanical and Seismic Behaviors of Draupne Shale: A Case Study from the Central North Sea, In  81st EAGE Conference and Exhibition 2019.  European Association of Geoscientists and Engineers (EAGE).  ISBN 978-1-5108-9281-1.  Th_R10_08. 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.

• 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 (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.

• 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.

• 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.

• 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.

• Smith, Halvard; Bohloli, Bahman; Skurtveit, Elin & Mondol, Nazmul Haque (2019). Engineering Parameters of Draupne Shale - Fracture Characterization and Integration with Mechanical Data, In  6th EAGE Shale Workshop 2019, Bordequx, France 28 April - 1 May 2019.  European Association of Geoscientists and Engineers (EAGE).  ISBN 978-1-5108-8666-7.  Mo P10. 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 & Mondol, Nazmul Haque (2018). Predicting the Effects of Organic Content and Maturation on the Elastic Properties of Central North Sea Source Rocks, In N/A N/A (ed.),  80th EAGE Annual Conference & Exhibition 2018.  European Association of Geoscientists and Engineers.  ISBN 978-94-6282-254-2.  Tu P2 03. Vis sammendrag

  The maturity of source rocks due to their shallow burial is a critical factor in the Central North Sea. In order to examine lateral variations of maturity of the source rocks, quantitative analysis of seismic data is required. The motivation for this study is to investigate the effects and relative impact of organic content, thermal maturity and hydrocarbon generation on elastic properties of organic rich shales. Using some established models, realistic approximations and reference trends that are calibrated to our area and applicable to our well log data, we can begin to predict how our data will behave as conditions change. We observe consistent compaction trends for immature to early mature shales at similar levels of TOC, and can from there infer the effect of hydrocarbon generation in data from a deeply buried, mature source rock. These trends can potentially help us evaluate seismic inversion results and data from other wells where TOC content and source rock maturity are in question.

• 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.

• Mondol, Nazmul Haque (2018). Predicting Seal Brittleness of Conventional Hydrocarbon Reservoirs Using LMR - a Case Study from the Norwegian Barents Sea, In N/A N/A (ed.),  80th EAGE Annual Conference & Exhibition 2018.  European Association of Geoscientists and Engineers.  ISBN 978-94-6282-254-2.  Tu A11 13.
• 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.

• 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; Tsikalas, F. & Doering, S. (2017). Improved Transition Zone Identification Using Relations Between Shear Wave Velocity and Density, In  Fourth EAGE Workshop on Rock Physics 2017.  European Association of Geoscientists and Engineers (EAGE).  ISBN 978-1-5108-5087-3.  RP18.  s 95 - 99 Vis sammendrag

  In this study, we present a method for identification of the transition zone between mechanical and chemical compaction in data from shaly lithologies. By utilizing crossplots of wireline log-measured shear wave velocity (Vs) and bulk density (ρb), we observe an increased sensitivity compared to compressional wave velocity (Vp) to the onset of chemical compaction/cementation, while eliminating uncertainties related to porosity estimations. A clear change in the velocity (Vs) gradient with increasing density is shown to occur in data from eight exploration wells. Data above and below a certain velocity value (Vs = 1350 m/s) show substantially different behavior which is expected to be a result of cementation. A linear relation in the Vs –density domain is derived from the data and suggested as a representative trend for mechanical compaction in the study area. Our suggestion is that whenever recorded with sufficient vertical coverage, direct measurements of Vs and density are trust-worthy parameters for identifying the transition zone between mechanical and chemical compaction.

• 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.

• 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.

• Nooraiepour, Mohammad; Mondol, Nazmul Haque; Hellevang, Helge & Bjørlykke, Knut (2017). Experimental mechanical compaction of reconstituted shale and mudstone aggregates: Investigation of petrophysical and acoustic properties of SW Barents Sea cap rock sequences. Marine and Petroleum Geology.  ISSN 0264-8172.  80, s 265- 292 . doi: 10.1016/j.marpetgeo.2016.12.003 Vis sammendrag

  This study investigates petrophysical and acoustic properties of experimentally compacted reconstituted samples of seal sequences from the southwestern Barents Sea. The aggregates were collected from drill cuttings of mudstone and shale formations of two exploration wells, 7220/10-1 (Salina discovery) and 7122/7-3 (Goliat field). The washed and freeze-dried samples were characterized for grain size distributions, geochemical analyses, and mineralogical compositions. A total of 25 compaction tests (12 dry and 13 brine-saturated) were performed with a maximum effective vertical stress of 50 MPa. The laboratory measurements demonstrated that petrophysical and acoustic properties of argillaceous sediments can change within a sedimentary basin and even within a given formation. The results show that the collected aggregates from Goliat field are compacted more compared to Salina discovery. The maximum and minimum compaction are measured in samples collected from Snadd and Fuglen formations, respectively. The final porosity of brine-saturated specimens varies between 5% and 22%. The ultrasonic velocity measurements depict that samples with the same porosity values can have a broad range of velocity values. The resulting compaction trends in this study were compared to published compaction curves for synthetic mixtures of quartz and clay. All compaction trends show higher porosity reduction than the silt fraction with 100% quartz. Comparison of experimental compaction result of each mudstone and shale aggregate with its corresponding acquired well log data helps to delineate the burial history and exhumation in the study area. A net exhumation of 950 m and 800 m is estimated at Salina and Goliat wells, respectively. The outcomes of this study can provide insights for hydrocarbon prospect discovery in a pre-mature sedimentary basin in terms of exploration and production, and also for geological CO2 storage sites. The experimental results may provide information for well log and seismic interpretation, basin modeling and seal integrity of investigated horizons.

• 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 (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.
• 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

• Baig, Irfan; Faleide, Jan Inge; Jahren, Jens & Mondol, Nazmul Haque (2016). Cenozoic exhumation on the southwestern Barents Shelf: Estimates and uncertainties constrained from compaction and thermal maturity analyses. Marine and Petroleum Geology.  ISSN 0264-8172.  73, s 105- 130 . doi: 10.1016/j.marpetgeo.2016.02.024 Vis sammendrag

  The Barents Sea is believed to have been influenced in most parts by Cenozoic uplift and erosion episodes. The rocks in the area are not currently at their maximum burial depth. The exhumation of the sedimentary rocks has had large effects on rock physical properties and hydrocarbon maturation and migration. The current study seeks to estimate exhumation from shale compaction and thermal maturity techniques and discuss its implications for hydrocarbon exploration in the uplifted Barents Sea area. This study uses well logs and thermal maturity data together with widely distributed shot gather data along long-offset seismic reflection lines. The use of shale compaction techniques to estimate exhumation was focused particularly on the regionally preserved Aptian-Albian (Kolmule Formation) and Paleogene (Torsk Formation) shales. Normal compaction reference curves were established for these units in areas currently at their maximum burial depth (e.g. Sørvestsnaget Basin and Vestbakken Volcanic Province). The results suggest widespread Cenozoic exhumation throughout the southwestern Barents Sea. The exhumation magnitudes increase towards east and northeast. The average exhumation estimates from the three data sources range from ∼800 to 1400 m within the Hammerfest Basin, ∼1150–1950 m on the Loppa High, ∼1200–1400 m on the Finmark Platform and ∼1250–2400 m on the Bjarmeland Platform. The marked differences in glacial erosion from mass balance and average erosion estimates from the current study suggest a significant pre-glacial uplift and erosion in the southwestern Barents Sea area. The observed stratigraphy and presence of significant volumes of Late Oligocene-Middle Miocene sediments in basins at the outer margin, and increased erosion rates at the same time in source areas suggest that maximum burial in the southwestern Barents Sea may have occurred sometime during the Oligocene, or even earlier in the Eocene. The results from this study are useful input for modelling of source rock maturation, generation, migration and trapping of hydrocarbons in the area. These results are also an important input for the prediction of more precise reservoir and seal rock properties in frontier areas away from the exploration wells and provide valuable knowledge for the use of interval velocities in the uplifted areas.

• Koochak Zadeh, Mohammad; Mondol, Nazmul Haque & Jahren, Jens (2016). Compaction and rock properties of Mesozoic and Cenozoic mudstones and shales, northern North Sea. Marine and Petroleum Geology.  ISSN 0264-8172.  76, s 344- 361 . doi: 10.1016/j.marpetgeo.2016.05.024 Vis sammendrag

  In this study, rock physical properties and their evolution resulting from compaction processes are investigated for Mesozoic and Cenozoic mudstones and shales located in southern Viking Graben and adjacent areas within the Norwegian North Sea. The studied sediments are deposited within a progressively-subsided sedimentary basin with no major experience of exhumation events. A suite of well log data from 43 exploration wells was utilized to study the compaction behaviour of the Mesozoic and Cenozoic mudstone and shale intervals. The gamma ray log-derived shale volume (Vsh) was used to define different lithofacies and discriminate between the studied mudstones and shales. The rock properties as a function of burial depth were plotted for the identified mudstone and shale intervals. The trends could be divided into a mechanical compaction part and a chemical compaction part depending on the prevalent processes controlling the rock properties with burial depth. The transition from mechanical compaction domain to the zone of dominant chemical compaction takes place between 70 and 90 °C corresponding to a depth of 2–2.5 km. The onset of chemical compaction and cementation occurs in the same sediment found at the same depth range almost throughout the study area in spite of variable geothermal gradient indicating a lithological control on the development of chemical compaction. The degree of chemical compaction and cementation reflects the initial smectite content and the availability of potassium for the smectite to illite and quartz reaction to take place. This study contributes to the understanding of compaction processes in fine-grained siliciclastic sediments delineating the controlling factors in a region which can be regarded a natural laboratory to study compaction mechanisms due to being a subsiding basin with the extensive availability of pertrophysical data generated by hydrocarbon exploration and production activities in the area.

• Koochak Zadeh, Mohammad; Mondol, Nazmul Haque & Jahren, Jens (2016). Experimental mechanical compaction of sands and sand–clay mixtures: a study to investigate evolution of rock properties with full control on mineralogy and rock texture. Geophysical Prospecting.  ISSN 0016-8025.  64(4), s 915- 941 . doi: 10.1111/1365-2478.12399 Vis sammendrag

  Development of rock physical properties in well-sorted and poorly-sorted unconsolidated mono-quartz sands and sand–clay mixtures as a function of effective stress in both dry and brine-saturated conditions is assessed in this study. The tested samples were prepared with full control on their mineralogy, grain size, grain shape, sorting, and fabric. The experiments were performed in a high-stress uniaxial oedometer up to a maximum of 30 MPa vertical effective stress. Sand–clay samples were a mixture of sand grains and clay particles (kaolinite or smectite) in different proportions. The maximum clay volume fraction used in the experiments was at most 30%. The initial bulk density of the tested sand-dominated samples was adjusted to be close to the maximum index density expected for natural sediments (sand–clay mixtures) during deposition. In pure sand samples, finer grained sand show higher initial porosity than relatively coarser grained sands. Moreover, sand–clay mixtures have lower initial porosity than pure sands. Porosity decreases as a function of increasing clay content. The poorly-sorted sand samples are less compaction prone than the well-sorted sand samples. Among well-sorted sand samples, coarser grained sands are more compressible than finer grained sands. At a given effective stress level, sand–clay mixtures are more compaction prone compared with their sand component alone. Pure sands and clay-poor sand–clay mixtures (either sand–kaolinite or sand–smectite) show almost the same degree of compaction when tested in both dry and brine-saturated conditions. In contrast, clay-rich sand–kaolinite and sand–smectite mixtures (clay volume >20%) are significantly more compact in brine-saturated condition. The Vp values of brine-saturated sand–kaolinite mixtures shows a positive correlation with the kaolinite content, whereas Vp starts to decrease substantially when the volume fraction of smectite exceeds 10% of the whole sand–smectite samples. Saturated bulk moduli estimated by Gassmann's fluid substitution agree with measurements for brine-saturated clay-poor sand samples. However, the model does not yield proper predictions for sand–clay samples containing 20% clay volume and above, particularly when the clay is mainly smectite. The acoustic and physical properties derived from experimental compaction of pure sands and sand–clay mixtures show a good agreement with rock properties derived from well logs of mechanically compacted pure sands and shaly sands in progressively subsided basins such as Viking Graben in the North Sea. Thus, the outcome of this study can provide reliable constraints for rock physical properties of sands and shaly sands within the mechanical compaction domain and contribute to improved basin modelling and identification of hydrocarbon presence, overconsolidation, and/or undercompaction.

• Naseryan Moghadam, Javad; Mondol, Nazmul Haque; Aagaard, Per & Hellevang, Helge (2016). Effective stress law for the permeability of clay-bearing sandstones by the Modified Clay Shell model. Greenhouse Gases: Science and Technology.  ISSN 2152-3878.  6(6), s 752- 774 . doi: 10.1002/ghg.1612 Vis sammendrag

  In this study, the effective stress law for the permeability of two core plugs selected from Berea (Cleveland Quarries, OH, USA) and Knorringfjellet (Longyearbyen, Svalbard, Norway) sandstones is studied experimentally by measuring the core permeability (k) under varying confining stress (σc) and pore pressures (Pp). The obtained results demonstrate that the permeabilities of the two core plugs decrease with increasing σc or decreasing Pp. The effective stress coefficient for the permeability (αk) values are more than 1.0 for both sandstone core plugs indicating higher sensitivity of the permeability with respect to the applied Pp compared to the applied σc. The previously presented models for calculating αk, such as the Clay Free, Clay Shell, and Clay Particle models, are discussed and a new modified Clay Shell model considering spherical geometry is presented to account for the considerable contrast between the elastic moduli of quartz and clay minerals. The discussed models strongly depend on the magnitude of the considered elastic moduli for the clay minerals. While the Clay Shell and Clay Particle models are capable of describing the observed αk values by considering extremely low elastic moduli for clays, the new modified Clay Shell model is capable of predicting αk values by considering moderate to low values of elastic moduli of clays. The increasing trend of αk values by increasing the σc is discussed and a new correlation based on the observed k values for calculation of αk is presented.

• Naseryan Moghadam, Javad; Mondol, Nazmul Haque; Aagaard, Per & Hellevang, Helge (2016). Experimental investigation of seismic velocity behavior of CO2 saturated sandstones under varying temperature and pressure conditions. Greenhouse Gases: Science and Technology.  ISSN 2152-3878.  6(6), s 734- 751 . doi: 10.1002/ghg.1603 Vis sammendrag

  Subsurface storage of CO2 into geological formations is considered an important strategy to mitigate increasing atmospheric CO2. Time-lapse seismic monitoring is an integral component of a geological CO2 sequestration project because the seismic behavior of the rock is a function of both mineralogical composition and pore fluid properties. At the uppermost kilometer of the sedimentary basin, CO2 can be present at gaseous, liquid, and supercritical states, with the supercritical and liquid states preferred in CO2 storage operations due to the higher sweep efficiency. In this study, the seismic velocities [both compressional (Vp) and shear (Vs) waves] of two CO2-saturated sandstone core plugs (Red Wildmoor and Knorringfjellet formations) have been measured under a range of temperatures and pressures in which CO2 phase transitions occur. The experiments were done using a uniaxial hydrostatic cell equipped with seismic wave transmitting and receiving transducers. The experimental investigation illustrated that seismic velocities (both Vp and Vs) decreased until the critical point was reached. Further increases in the CO2 pressure above the critical point led to a gradual increasing of Vp while the Vs remained unchanged. The effect of CO2 on the seismic velocity of the sandstone was compared with the effects of N2 and distilled water at the same conditions. It was further indicated that the seismic velocity changes were mainly connected to significant changes of CO2 density and the corresponding bulk rock moduli over the critical point. The observed velocities are in good agreement with Gassmann-predicted velocities as well as literature data.

• Nooraiepour, Mohammad & Mondol, Nazmul Haque (2016). Petrophysical and acoustic properties of mechanically compacted shales - evaluating two Barents Sea top seal sequences, In .. .. (ed.),  7th EAGE Saint Petersburg International Conference and Exhibition.  European Association of Geoscientists and Engineers.  ISBN 9781510822498.  We STZ0 01. Vis sammendrag

  This study investigates petrophysical and acoustic properties of two experimentally compacted reconstituted seal sequences (Late Triassic Snadd and Early Cretaceous Kolmule Formations) from two localities (Goliat field and Saline discovery) in the SW Barents Sea. Four samples were chosen from cuttings of two exploration wells 7122/7-3 (Goliat) and 7220/10-1 (Salina) drilled in the study area. The washed and freeze dried cutting samples were characterized for grain size analysis, geochemical (organic content) and mineralogical compositions. A total of eight compaction tests (four dry and four brine-saturated) were performed in the laboratory to apply a maximum vertical effective stress of 50 MPa. The maximum compaction observed in Snadd shale aggregates collected from the Goliat well (4.5% porosity). In order to study compaction history and seal integrity, the experimental results were compared with well log data. It is clear from comparison that the mechanical compaction of reconstituted shale and mudstone samples can be capable of describing natural processes, providing valuable insights on the state of mechanical/chemical compaction, and helping the seal integrity assessments. The results of this study will have applications in rock physics, basin modelling and top seal integrity.

• Yenwongfai, Honore Dzekamelive; Mondol, Nazmul Haque; Faleide, Jan Inge & Lecomte, Isabelle (2016). Prestack inversion for porosity, shale volume and sand probability in the Havert Formation of the Goliat field, SW Barents Sea.. SEG technical program expanded abstracts.  ISSN 1949-4645.  s 3543- 3547 . doi: 10.1190/segam2016-13943690.1 Vis sammendrag

  This study implements a multidisciplinary approach to porosity (PHIE), shale volume (Vsh) and sand probability estimation from prestack angle gathers and petrophysical well logs. A rock physics feasibility study revealed the optimum petrofacies discriminating ability of extended elastic impedance (EEI) and PHIE. Multilinear regression analysis is then applied to the output of the simultaneous inversion of seismic data to estimate Vsh and PHIE. Probability distribution functions (PDFs) and a priori facies extracted from the well data are then applied to the Vsh and PHIE volumes to obtain a sand probability cube for the Lower Triassic Havert Formation in the Goliat field, SW Barents Sea.

• Yenwongfai, Honore Dzekamelive; Mondol, Nazmul Haque; Lecomte, Isabelle & Faleide, Jan Inge (2016). Prestack simultaneous inversion to predict lithology in the Realgrunnen subgroup of the Goliat Field, SW Barents Sea, In .. .. (ed.),  7th EAGE Saint Petersburg International Conference and Exhibition.  European Association of Geoscientists and Engineers.  ISBN 9781510822498.  We LHR3 03. Vis sammendrag

  This study describes a successful multidisciplinary work flow for quantitative lithology prediction from prestack angle gathers and petrophysical well log data within the Realgrunnen Subgroup in the Goliat Field, Norwegian Barents Sea. An amplitude-versus-angle (AVA) qualitative attribute analyses was performed to assess the spatial distribution of lithology anomalies from the seismic data. A simultaneous prestack elastic inversion was also carried out for quantitative estimates of P-impedance and Vp/Vs ratios which were subsequently analysed using 3D cross plots. Probability distribution functions (PDFs), and a priori lithology class proportions extracted from the well log training data are then applied to the inverted seismic volume. AVA qualitative analyses showed a class-IV top reservoir response, and lithology anomalies interpreted from the scaled S-wave reflectivity attribute map revealed a qualitative spatial distribution of the reservoir sands. The confusion matrix from the best training dataset shows the largest misclassification between shaly sands and shales. PDFs from a rule based ternary lithology classification provided the best resolution for the clean sands. A good match is obtained between horizon attributes generated from angle gathers and that obtained from the clean sand and shaly sand probability maps combined.

• Abbas, Mohsin; Bohloli, Bahman; Mondol, Nazmul Haque & Grande, Lars (2015). Brazilian Tensile Strength Test - Post-failure Behavior of Jurassic and Cretaceous Shales from Svalbard, In  77th EAGE Conference and Exhibition 2015: Earth Science for Energy and Environment: Proceedings of a meeting held 1-4 June 2015, Madrid, Spain.  Curran Associates, Inc..  ISBN 9781510806627.  N116 10.  s 940 - 944 Vis sammendrag

  This study presents results of indirect tensile tests on cap rock shale samples from Svalbard CO2 storage pilot. It elaborates on tensile strength and the relationship between loading direction and post-failure behaviour of cap rock shale samples. Several test plugs were sampled from Jurassic and Creataceous Age cores of borehole Dh2, Dh4 and Dh6 from depth range of about 400 to 700 m. Samples were tested both parallel and perpendicular to bedding plane. Result of the tests showed that cap rock shale samples subjected to the Brazilian test in different directions relative to bedding planes differs not only in terms of the peak strength but also in the shape of the post-failure curve. The cap rock shale loaded perpendicular to bedding have higher strength and those loaded parallel with bedding show lower strengths. Samples loaded perpendicular to bedding bear load up to a maximum peak followed by a large drop and never reaches the maximum peak load again. For samples loaded parallel with bedding a maximum load is reached at failure followed by sudden drop, but load can increase to the same or higher level than the initial failure stress.

• Kalani, Mohsen; Jahren, Jens; Mondol, Nazmul Haque & Faleide, Jan Inge (2015). Compaction processes and rock properties in uplifted clay dominated units, - The Egersund Basin, Norwegian North Sea. Marine and Petroleum Geology.  ISSN 0264-8172.  68, s 596- 613 . doi: 10.1016/j.marpetgeo.2014.08.015
• Kalani, Mohsen; Jahren, Jens; Mondol, Nazmul Haque & Faleide, Jan Inge (2015). Petrophysical implications of source rock microfracturing. International Journal of Coal Geology.  ISSN 0166-5162.  143(1), s 43- 67 . doi: 10.1016/j.coal.2015.03.009
• Kalani, Mohsen; Koochak Zadeh, Mohammad; Jahren, Jens; Mondol, Nazmul Haque & Faleide, Jan Inge (2015). Effect of diagenesis on pore pressures in fine-grained rocks in the Egersund Basin, Central North Sea. Norsk Geologisk Tidsskrift.  ISSN 0029-196X.  95(2), s 171- 189 . doi: 10.17850/njg95-2-03 Fulltekst i vitenarkiv. Vis sammendrag

  Pore pressure in fine-grained rocks is important with respect to drilling problems such as kicks, blowouts, borehole instability, stuck pipe and lost circulation. In this study, a succession of overpressured, fine-grained, sedimentary rocks located in the Egersund Basin, Central North Sea, was analysed with respect to mineralogical composition, source-rock maturation and log-derived petrophysical properties to highlight the effect of diagenetic processes on the pore pressure. Petrographic and geochemical analyses showed that the overpressure in the study area is largely linked to disequilibrium compaction, illitisation and source-rock maturation shown by log-derived physical properties. Pore-pressure prediction based on the difference of log-derived sonic transit time compared to the normal compaction trend (NCT) of fine-grained rocks can be used to infer the general trends of pore-pressure changes. However, during such pore-pressure prediction (e.g., using Eaton’s approach), one should note that with regard to sonic response of the above-mentioned processes, the sonic log-derived, predicted pore pressure in the chemically compacted intervals and organicrich thermally mature successions may show either underestimations or overestimations, respectively.

• Mondol, Nazmul Haque (2015). Well Logging: Principles, Applications and Uncertainties, In Knut Bjørlykke (ed.),  Petroleum Geoscience. From sedimentary environments to rock physics - second edition.  Encyclopedia of Global Archaeology/Springer Verlag.  ISBN 978-3-642-34131-1.  Chapter.  s 385 - 425 Vis sammendrag

  Well logging is a means of recording the physical, acoustic and electrical properties of the rocks penetrated by a well. It is carried out by service companies, which work under contract for the oil companies. Logging has the advantage that it measures in situ rock properties which cannot be measured in a laboratory from either core samples or cuttings.

• Skurtveit, Elin; Grande, Lars; Ogebule, Oluwakemi Yetunde; Gabrielsen, Roy; Faleide, Jan Inge; Mondol, Nazmul Haque; Maurer, R. & Horsrud, Per (2015). Mechanical testing and sealing capacity of the Upper Jurassic Draupne Formation, North Sea, In Peter Smeallie (ed.),  49th US Rock Mechanics/Geomechanics Symposium - ARMA.  American Rock Mechanics Association (ARMA).  ISBN 978 0 9794975 0 6.  ARMA 15-331.
• Soldal, Magnus; Park, Joonsang; Lameck, Omolo; Tran, Trung; Sauvin, Guillaume; Johnsen, Øistein & Mondol, Nazmul Haque (2015). Geophysical monitoring of CO2 flow during sandstone flooding experiments, In Marjolein van Kraanen (ed.),  Proceedings third EAGE workshop on rock physics: from rocks to basin - applying rock physics in prospect evaluation and reservoir characterization.  Curran Associates, Inc..  ISBN 978-94-6282-153-8.  26649. Vis sammendrag

  In this study, liquid CO2 is injected into fully brine saturated reservoir core samples in the laboratory, and consequently changes in electrical resistivity, acoustic velocities (ultrasonic frequency) and their anisotropy are measured. To enhance the spatial resolution, a system enabling velocity and resistivity measurements at different points and in different directions along the specimen's axial direction has been developed. Electrical resistivity and acoustic velocity and amplitude are all clearly influenced by pore-scale heterogeneity and fluid flow pattern and it is important to study this interaction. So far, focus has been related to CO2 geological storage, but the outline of the study is believed to also be applicable for CO2 injection for enhanced oil recovery (EOR). The study is still ongoing and some preliminary results are presented here and discussed.

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• Fawad, Manzar & Mondol, Nazmul Haque (2020). Monitoring subsurface CO2 storage using seismic and CSEM data – Modelling in Smeaheia area, northern 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.
• 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). Comparison of Sealing Properties of Amundsen and Drake Formations for Potential CO2 Storage in 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.

• Fawad, Manzar & Mondol, Nazmul Haque (2019). OASIS - Overburden Analysis and Seal Integrity Study for CO2 Sequestration in the North Sea.
• Griffiths, Luke; Dautriat, Jérémie; Vera Rodriguez, Ismael; Iranpour, Kamran; Sauvin, Guillaume; Park, Joonsang; Sarout, Joel; Soldal, Magnus; Grande, Lars; Oye, Volker; Dewhurst, David; Mondol, Nazmul Haque & Choi, Jung Chan (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: https://doi.org/10.5194/adgeo-49-85-2019
• Griffiths, Luke; Park, Joonsang; Sauvin, Guillaume; Soldal, Magnus; Grande, Lars; Mondol, Nazmul Haque; Choi, Jung Chan; Dautriat, Jérémie; Dewhurst, David; Sarout, Joel; Oye, Volker; Vera Rodriguez, Ismael & Iranpour, Kamran (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.
• 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. 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.

• Johnson, James Ronald; Hansen, Jørgen André; Mondol, Nazmul Haque & Renard, Francois (2019). Modeling maturation, elastic, and geomechanical properties of the Draupne Formation, Offshore Norway.
• Johnson, James Ronald; Hansen, Jørgen André; Renard, Francois & Mondol, Nazmul Haque (2019). Geomechanical Analysis of Maturation for the Draupne Shale, Offshore Norway.
• Mondol, Nazmul Haque (2019). Geomechanical and Seismic Behaviors of Draupne Shale: A Case Study from the Central North Sea.
• 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 (2018). Reservoir Characterisation of Johansen Formation as Potential CO2 Storage Reservoir in The Northern North Sea.
• 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.
• 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. Vis sammendrag

  Pre-existing and induced fractures and faults can play a role as bypass conduits and fast leaking channels in CO2 storage sites. They should therefore be well characterized during site selection, and monitored thoroughly during operation to track the movement and fate of the CO2 plume. Despite to date extensive research on the geophysical properties of brine- and CO2-saturated porous reservoir rocks, changes in acoustic velocity and electrical resistivity during a sole fracture fluid displacement are, however, rather little investigated. Hence, we herein present a laboratory study of core-scale geophysical monitoring during drainage-imbibition cycles of the brine-CO2 system through a shale caprock core sample with a vertical fracture. The experiments were conducted using both gaseous and scCO2 with 4 and 9 MPa pore pressures, respectively, at 12 MPa confining pressure. The tests were performed at 40°C during the loading and unloading stages in order to look into the hysteresis effect. We used a fractured core sample from the Upper Jurassic organic-rich shales of the Draupne Formation, which is the primary caprock for the Smeaheia CO2 storage site – a full-scale CCS project in Norway. The primary objective of the experiment was to compare the geophysical measurements using gaseous and scCO2 drainage-imbibition cycles during the tests in a core-scale experiment. Moreover, we were interested to see how sensitive acoustic velocity and electrical resistance techniques are to the fracture fluid displacement using different CO2 phase states. The outcomes of our high-pressure high-temperature experiment of simultaneous measurements of fracture flow and geophysical properties indicate that potential leakage of injected CO2 through the fractured-shale caprock can be detected in the core-scale laboratory experiments. The performed drainage-imbibition cycles using gaseous and scCO2 resulted in different behaviors in P-wave velocity (Vp) and electrical resistance in axial and radial directions for these two phase states. The measured Vp during the displacement of fracture fluid, CO2-brine subsequent cycles, showed a limited sensitivity in terms of magnitude and relative change. The electrical resistance, on the other hand, shows higher sensitivity and larger variation during fluid displacement along the fracture. It was also observed that the crossplot of Vp versus electrical resistance could detect and even differentiate the different phases during the loading and unloading stages.

• Baig, Irfan; Faleide, Jan Inge; Hjelstuen, Berit Oline Blihovde; Sejrup, Hans Petter; Nystuen, Johan Petter; Aagaard, Per; Jahren, Jens & Mondol, Nazmul Haque (2017). Seismic mapping of Quaternary sediment distribution in the central and northern North Sea.
• Baig, Irfan; Faleide, Jan Inge; Jahren, Jens & Mondol, Nazmul Haque (2017). Burial and exhumation history controls on shale compaction and thermal maturity along the Norwegian North Sea margin.
• 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.
• 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.
• Haider, Shahzeb & Mondol, Nazmul Haque (2017). Depositional pattern controlling the reservoir properties of the Middle Triassic Snadd Formation from the SW Barents Sea.
• Hansen, Jørgen André & Mondol, Nazmul Haque (2017). Reservoir characterization of the Triassic succession of the Bjarmeland Platform, 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.
• Mondol, Nazmul Haque (2017). Rock Physics Diagnostics of Exhumed Reservoir Sandstone.
• Nooraiepour, Mohammad & Mondol, Nazmul Haque (2017). Experimental mechanical compaction of reconstituted mudrocks from the SW Barents Sea: implication for exhumation estimation.
• Park, Joonsang; Soldal, Magnus; Sauvin, Guillaume; Nooraiepour, Mohammad; Mondol, Nazmul Haque & Bohloli, Bahman (2017). On wave propagation in a CO2/Brine-saturated fractured core.
• 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.
• Soldal, Magnus; Sauvin, Guillaume; Park, Joonsang; Mannseth, Trond; Tveit, Svenn; Agersborg, Remy; Aagaard, Per & Mondol, Nazmul Haque (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; 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.

• 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.
• 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.
• Nooraiepour, Mohammad & Mondol, Nazmul Haque (2016). Petrophysical and Acoustic Properties of Mechanically Compacted Shales - Evaluating Two Barents Sea Top Seal Sequences.
• Yenwongfai, Honore Dzekamelive; Mondol, Nazmul Haque; Faleide, Jan Inge & Lecomte, Isabelle (2016). Prestack Simultaneous Inversion to Predict Lithology in the Realgrunnen Subgroup of the Goliat Field, SW Bareants Sea.
• Yenwongfai, Honore Dzekamelive; Mondol, Nazmul Haque; Faleide, Jan Inge & Lecomte, Isabelle (2016). Quantitative seismic reservoir characterization within the Realgrunnen Subgroup and the Havert Formation in the Goliat Field, SW Barents Sea.
• Barrio, Maria; Stewart, Heather A.; Akhurst, M.; Aagaard, Per; Alcalde, J.; Bauer, Andreas; Bradwell, T.; Cavanagh, A.; Evans, D; Faleide, Jan Inge; Furre, Anne-Kari; Gent, C.; Haflidason, Haflidi; Haszeldine, S.; Hjelstuen, Berit Oline Blihovde; Johnson, G.; Mondol, Nazmul Haque; Querendez, Etor; Ringrose, P.S.; Sejrup, Hans Petter; Stewart, M.; Uriansrud, F.; Wilkinson, M; Mørk, Atle; Primio, R. de & Mørkved, Pål Tore (2015). Norway and UK cross-boundary initiative towards a limate motivated drilling operation in the North Sea.
• Faleide, Jan Inge; Kalani, Mohsen; Sassier, Caroline; Angeli, Matthieu; Ogebule, Oluwakemi Yetunde; Baig, Irfan; Jarsve, Erlend M.; Gabrielsen, Roy Helge; Mondol, Nazmul Haque; Jahren, Jens; Aagaard, Per; Skurtveit, Elin; Grande, Lars; Maurer, Rudolf & Horsrud, P. (2015). Caprock research in the CO2Seal project.
• Grande, Lars; Soldal, Magnus & Mondol, Nazmul Haque (2015). Dynamic to static relationships of shear modulus for sand and sandstones, 3rd International Workshop on Rock Physics, 13-17 April 2015, Perth, Australia.
• Mondol, Nazmul Haque (2015). Experimental compaction of dry smectite-silt mixtures, 3rd International Workshop on Rock Physics.
• Mondol, Nazmul Haque (2015). Norwegian Shale Gas/Oil- The Story So Far.
• Ogebule, Oluwakemi Yetunde; Mondol, Nazmul Haque & Jahren, Jens (2015). Seal Integrity of Late Jurassic to Early Cretaceous Mudrocks of the South-Western Barents Sea Area.
• Omolo, Lameck; Tran, Trung; Soldal, Magnus; Mondol, Nazmul Haque; Grande, Lars; Park, Joonsang & Johnsen, Øistein (2015). Multidirectional acoustic velocity measurement during CO2 flooding in sandstones.
• Soldal, Magnus; Omolo, Lameck; Tran, Trung; Johnsen, Øistein; Mondol, Nazmul Haque; Sauvin, Guillaume; Viken, Inge; Grande, Lars & Park, Joonsang (2015). CO2 flooding experiment of reservoir sandstones-monitoring changes in acoustic and electric properties. Vis sammendrag

  We present an advanced laboratory work to measure electrical resistivity, acoustic velocity (ultrasonic frequency) and anisotropy during injection of liquid CO2 into initially brine saturated reservoir core samples. A novel measurement system has been developed, where velocity and resistivity are measured at different points along the specimen axial direction. The changes in velocity and resistivity observed during the CO2 injection will be a critical element in interpreting geophysical field data to understand reservoir behaviour.

• Tran, Trung; Omolo, Lameck; Soldal, Magnus; Mondol, Nazmul Haque; Park, Joonsang & Johnsen, Øistein (2015). Tracking Co2 Front Development with Electrical Resistivity Measurements - An Experimental Study.
• Zadeh, Mohammad Koochak; Mondol, Nazmul Haque & Jahren, Jens (2015). Velocity-porosity Evolution of Mechanically Compacted Brine-saturated Sand-clay Mixtures.
• Zadeh, Mohammad Koochak; Ogebule, Oluwakemi Yetunde; Mondol, Nazmul Haque; Jahren, Jens & Faleide, Jan Inge (2015). A laboratory study to investigate velocity anisotropy of an oaganic-rich shale, Central North Sea, Offshore Norway.

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