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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 Oygarden 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.

To evaluate subsurface reservoirs for CO2 sequestration, the grain scale properties and role of diagenesis is important for the injectivity and the subsequent mobilization. This study focuses on Johansen Formation of Jurassic age in the vicinity of Troll field within the northern North Sea. Johansen Formation is a saline aquifer and no hydrocarbon discovery has been reported in this reservoir so far. We analysed 24 wells using petrophysics and rock physics techniques to obtain net reservoir, net to gross ratio, effective porosity, volume of shale and level of cementation, and attempted to relate these parameters with the factors influencing them. The reservoir properties were found to be optimal approximately around depths shallower than 2000m (below sea floor, BSF). Even the shallowest sandstones exhibited cementation indicating calcite precipitation while the sediments deposited. Presence of shale however found to inhibit the quartz cementation possibly preserving the porosity. These findings will help understanding the complexity of the Johansen Sandstone as storage reservoir and the influence of heterogeneity on CO2 migration.

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.

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.

Top seals are as important as reservoirs and source rocks for hydrocarbon exploration success. Upliftment is agreed to have a great influence on the petroleum system in the Barents Sea area. Seal integrity assessment is thus embarked upon to enhance the knowledge needed for future exploration and exploration targets. For the purpose of this study, two wells labelled Well A and Well B are investigated in the south-western Barents Sea Area. Well cuttings from possible sealing mudrocks to known reservoirs are provided for grain size analyses. A Suite of well logs including gamma ray, compressional wave velocity and bulk density are used. Brittleness index (BI) are estimated through different methods to determine the risk of seal failure. These methods include overconsolidation ratio for estimation of degree of upliftment; log-derived unconfined compressive strengths, Young’s modulus versus Poisson’s ratio, Lambda-Rho versus Mu-Rho, mineralogy and grain size. Brittleness index reveals that all the investigated mudrocks are good seals, but in Well A, the Fuglen and lower unit of the Hekkingen Formations may be more brittle than other Formations while in Well B, parts of the Kolmule Formation is of higher risk to fracturing than the other Formations.

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.

In this study, four brine-saturated specimens of unconsolidated sands and sand-clay mixtures are tested to infer velocity-porosity trends of sand-dominated facies when a full control on mineralogy is applied on the tested samples. The current results show consistency with the published experimentally derived compaction trends of natural sands. The iso-stress curves connecting the data points with the same effective stress in the velocity-porosity plot are comparable to the friable sand model curves proposed to estimate the rock properties of sands within the mechanical compaction domain. As expected, the achieved iso-stress curves for mechanically compacted samples are too far away from the empirical lines suggested estimating rock properties of sandstones within the chemical compaction domain. To check creditability of the rock physics models in both mechanical and chemical compaction domains, the log-derived petrophysical properties acquired from the North Sea are compared to the derived experimental compaction trends. The shallow unconsolidated sands follow closely the experimentally derived iso-stress curves and friable sand model but, the consolidated sandstones show a wide range of physical properties and may sometimes follow different trends compared to suggested rock physics models.

We present here results from studies of three Barents Sea wells including 7120/9-1 and 7121/7-1 from the Snohvit field of the Hammerfest Basin and well 7119/12-1 of the transition zone between the Troms 1 and the Hammerfest Basin. The study focuses on the effects of mineralogy, texture, cementation, clay volume, and fluid content on rock physics and petrophysical parameters of the Sto Formation sandstones. Although sample depths differ, but stratigraphic levels are similar, yet velocity-porosity relationships are quite different especially between the well 7119/12-1 and the other 2 wells. Cementation estimated on log data using cement models show similarities to those observed in point-counted samples. Velocity-porosity trend vary from one basin to another, and from one sandstone type to another. Mineralogy, sorting, amount of quartz cement, grain size, fluid type, clay volume content, burial depth/history all tend to redefine various trends in velocity-porosity, lambdarho-murho, and P-wave velocity/S-wave velocity-P-wave acoustic impedance. Our study gives a better understanding of the complexities of relationships between reservoir parameters in overconsolidated and uplifted sandstones.

Two different experimental approaches for studying CO2–brine displacement and relation to a heterogeneous (layered) rock drilled perpendicular and parallel to bedding under isotropic is presented: One uses CT imaging to locally resolve the structural heterogeneity effect on pore fluid distribution and saturation and directly linking it to the geophysical measurements (resistivity and sonic velocity), the other using a ring electrode sample sleeve design to resolve local changes in resistivity in the flow direction during displacement. The studies demonstrates the importance and impact of sub core scale heterogeneity and flow/permeability anisotropy in dictating the electrical conductivity and sonic velocity response, locally and globally, during drainage and imbibition.

This study focuses on relationships among porosity, permeability and seismic velocity of shales. A total of thirty well characterized, brine-saturated (35000 ppm NaCl) synthetic shale of varying textural and mineralogical compositions were compacted mechanically both in triaxial and oedometer cells under controlled pore pressure and proper drained conditions. Results show that kaolinite dominated shales compact more but have higher permeability and seismic velocity compared to smectite dominated shales at same stress/depth. Permeability differs a maximum five orders of magnitude at the same porosity for different shales. For velocity-permeability relationship between kaolinite- and smectite-dominated shales, a maximum four orders of magnitude are observed. Velocity/porosity can therefore not be good proxy to estimate reliable permeability in shales. Comparison of experimental and published data show a good agreement and illustrated that a better understanding of mineralogical and textural relationships can be significantly improved to establish relationships among porosity, permeability and seismic velocity of shales. In addition to the existing database, the new experimental data (this study) can improve the calibration of fluid flow modeling, seismic and well-log interpretation and evolution of shale rock properties. The experimental results may also be of importance for structural design, slope stability analysis and waste disposal efforts.

Production induced reservoir depletion in unconsolidated reservoirs may result in reservoir compaction and surface subsidence. The potential for such impacts can be assessed by integrating geomechanical models with reservoir properties obtained from laboratory measurements. The response of reservoir compaction to pressure depletion depends on the burial history. This study investigates reservoir compressibility and compaction due to depletion from reservoirs of shallow overconsolidated sands caused by uplift compared to normally compacted sands from experimental mechanical compaction. Static moduli obtained from the experimental mechanical compaction show that uniaxial compressibility of the overconsolidated sands is less compared to the normally consolidated sands. The reservoir compaction due to depletion in such a reservoir is therefore less compared to the normally compacted reservoir. The mineral compositions and textural variations do not influence the compressibility in the overconsolidated case. The preconsolidation stress associated to the maximum burial depth before uplift is an important estimation to predict when the pore pressure drawdown will change the compaction behaviour from poro-elastic to plastic. The results can be applied to reservoir compaction during hydrocarbon production in uplifted basins like the Barents Sea.

SUMMARY One of the important factors in formation of a petroleum reservoir and also a successful CO2 storage operation is an efficient seal that prevents migration of accumulated hydrocarbon or injected CO2 to the surrounding environments. In siliciclastic environment, shales and mudrocks are most common seals that prevent migration of hydrocarbon and CO2 from reservoirs. This study investigates the most common failure criteria (Mohr-Coulomb Criterion, Drucker-Prager Criterion, Mogi Empirical Criterion and Hoek and Brown Criterion) by using a triaxial data set. The maximum effective principal stress (σ1), one of the most important mechanical properties of caprocks that has crucial importance in rock strength calculations, has been predicted with the mentioned failure criteria. The applied data are obtained from a range of triaxial tests that were performed on a Barents Sea Shale cored from the Hekkingen Formation in two depth intervals. Among the applied failure criteria, Mogi failure criterion had the best performance in predicting the σ1 of the tested shales, while the traditional MohrCoulomb criterion showed good prediction compared to complicated calculations suggested by other criteria. Also the observed considerable discrepancies between the obtained mechanical parameters for horizontal and vertical samples at same depth reveals the anisotropy in the Hekkingen Formation.

Mudstones and shales are a major component of most sedimentary basins and are anisotropic because of the alignment of plate-line clay minerals. The results show that the shallow mudstone is weakly anisotropic with respect to P-wave anisotropy (Thomsen’s parameter e) on the order of 20% but strongly anisotropic for S-wave propagation (Thomsen’s parameter γ) on an order of 64% at higher stress. The anisotropy parameter δ is observed as maximum as 42%. The magnitude of P-wave anisotropy (e) seems to increase with increasing effective stress or depth of burial. The other anisotropy parameters (γ and δ) also increase with increasing stress upto certain stress levels (about 12 MPa mean effective stress) and than decrease gradually with increasing mean effective stress. Factors such as stress induced as well as alignment of plate-like clay minerals may causing the different anisotropic behavior for γ and δ compared to e where shear wave polarization may play an important role. The anisotropic behavior found in the shallow mudstone core may impact seismic imaging, AVO analysis, time-depth calculations and well to seismic tie of sonic log data of deviated wells.