Stratigraphy and petrophysical characteristics of Lower Paleocene cool-water carbonates, Faxe quarry, Denmark

The Faxe limestone quarry in eastern Denmark exposes Danian (Lower Paleocene) cool-water carbonate deposits. They constitute remnants of an apparent build-up that covers about 12 km2 today. The Danian deposits at Faxe are conspicuous due to their pronounced thickness of coral limestone relative to the regional carbonate system. In the Faxe quarry, scleractinian corals are uniquely exposed in up to 30 m high mounds. The rapid accumulation of scleractinians combined with induration of the mounds may locally have protected the limestone from Quaternary glacial erosion and created a Danian thickness anomaly at Faxe. The position of Faxe above a local fault-bounded basement high and the extent of coral limestone has been better defined by new mapping. A mapped lithostratigraphic surface in the quarry reveals the large-scale organisation of nested bryozoan mounds on three elongated ridges striking NW–SE. The main scleractinian coral mounds are located above this horizon. Data for reservoir characterisation, mainly of the bryozoan mounds, were collected as photographs of the outcrop, petrophysical and petrographical data from cored boreholes, and as ground-penetrating radar sections. Old boreholes and measured sections were used to reconstruct the build-up, and new nannofossil data allow a discussion of stratigraphy and accumulation rate. The petrophysical data show that common mound-building bryozoan packstone has higher permeability and lower capillary entry pressure than chalk, whereas less commonly occurring grain-dominated packstone and grainstone deposits from local higher-energy sites of the mound complex were found to have reduced amounts of coccolith mud, significantly higher permeability and a higher degree of lithification. Based on biostratigraphic age constraints, correlation of flint – limestone couplets and recog-nised hierarchical patterns, we develop a cyclostratigraphy for the middle Danian and suggest that cyclicity in lithology and petrophysical characteristics of bryozoan limestone are controlled by precession and eccentricity of the orbit of the Earth.

Effect of capillary pressure and geomechanics on multiphase fluid flow in rocks

<p>Understanding interactions between rock and fluids is important for many applications including CO<sub>2</sub> storage in the subsurface. Today significant effort is aimed at research on CO<sub>2</sub> flow through low-permeable shale formations. In some experiments, CO<sub>2</sub> is injected in a shale sample at a constant rate, and the upstream pressure exhibits rise until a certain moment followed by a decline, representing the so called breakthrough phenomenon. After the breakthrough, downstream flux significantly rises. This behavior was thought to be the result of fracture occurence or mechanical effects. <br><br>Here, we present a 3D numerical model of flow through experiments in shale. Our model accounts for poroelastic compaction/decompaction of shale, its time-dependent permeability, and two-phase flow, the fluid phases being CO<sub>2</sub> and air. The model also accounts for a capillary entry pressure threshold observed in experiments. The key feature of the model are saturation-based relative permeabilities which result in sharp overall permeability increases as the CO<sub>2</sub> moves through the shale sample. The model is implemented for 3D calculations with the finite volume method. Our results show that CO<sub>2</sub> breakthrough is a natural outcome of two-phase fluid flow dynamics and does not need a fracture to exhibit pressure behavior observed in experiments.</p>

Fault seal behaviour in Permian Rotliegend reservoir sequences: case studies from the Dutch Southern North Sea

Permian Rotliegend reservoir rocks are generally characterized by high net/gross (N/G) ratios, and faults in such sand-dominated lithologies are typically not considered likely to seal. Nevertheless, many examples of membrane sealing are present in Rotliegend gas fields in the Southern Permian Basin. This manuscript reviews examples of membrane sealing in the Dutch Rotliegend; it presents an extensive dataset of petrophysical properties of Rotliegend fault rocks and analyses two case studies using commonly used workflows.Fault (membrane) seal studies have been carried out on two Rotliegend fields to test the level of confidence and uncertainty of prediction of ‘across fault pressure differences’ (AFPD) based on existing SGR-based algorithms. From the field studies it is concluded that observable small AFPDs are present and that these are likely pre-production AFPDs due to exploration-time scale trapping and retention of hydrocarbons. Two shale gouge ratio (SGR)-based empirical algorithms have been used here to estimate AFPDs in lower N/G reservoir intervals with the aim of predicting membrane seal behaviour, and these results are compared to field data. It is concluded the selected SGR-based tools predict AFPD for Upper Rotliegend lower N/G reservoir rocks with reasonable results. Nonetheless, the core sample datasets show a much wider range of permeability and capillary entry pressure than predicted by the selected SGR transforms. This highlights the potential to modify existing workflows for application to faults in high N/G lithologies. Data sharing and collaboration between industry and academics is encouraged, so that in the long run workflows can be developed specifically for faults in high N/G lithologies.

Sensitivity analysis of gas leakage through a fault zone during subsurface gas storage in porous formations

Subsurface gas storage in porous media is a viable option to mitigate shortages in energy supply in systems largely based on renewable sources. Fault systems adjacent to or intersecting with gas storage could potentially result in a leakage of stored gas. Variations in formation pressure during a storage operation can affect the gas leakage rates, requiring a site and scenario specific assessment. In this study, a geological model of an existing structure in the North German Basin (NGB) is developed, parameterised and a methane gas storage operation is simulated. Based on the observed storage pressure, a sensitivity study aimed at determining gas leakage rates for different parametrisations of the fault damage zone is performed using a simplified 2-D model. The leakage scenario simulations show a strong parameter dependence with the fault acting as either a barrier or a conduit for gas flow. Furthermore, the storage operation greatly affects the gas leakage rates for a given parametrisation with significant leakage only during the injection periods and thus during increased overpressures in the storage formation. During injection, the peak leakage rates can be as high as 2308 Sm3 d−1 for damage zone permeabilities of 10 mD and a capillary entry pressure of 4 bar. Increasing capillary entry pressure results in a sealing effect. If the capillary entry pressure is scaled according to the damage zone permeability, peak leakage rates can be higher, i.e. 3240 Sm3 d−1 for 10 mD and 0.13 bar. During withdrawal periods, the pressure gradient between a storage formation and a fault zone is reduced or even reversed, resulting in greatly reduced leakage rates or even a temporary stop of the leakage. Total leakage volume from storage formation was assessed based on the 2-D study by considering the exposure of the gas-filled part of the storage formation to the fault zone and subsequently compared with gas in place volume.

Estimates of scCO2 Storage and Sealing Capacity of the Janggi Basin in Korea Based on Laboratory Scale Experiments

Laboratory experiments were performed to measure the supercritical CO2 (scCO2) storage ratio (%) of conglomerate and sandstone in the Janggi Basin, which are classified as rock in Korea that are available for CO2 storage. The scCO2 storage capacity was evaluated by direct measurement of the amount of scCO2 replacing the pore water in each reservoir rock core. The scCO2 sealing capacity of the cap rock (i.e., tuff and mudstone) was also compared by measuring the scCO2 capillary entry pressure (Δp) into the rock core. The measured average scCO2 storage ratio of the conglomerate and the sandstone were 30.7% and 13.1%, respectively, suggesting that the scCO2 storage capacity was greater than 360,000 metric tons. The scCO2 capillary entry pressure for the tuff ranged from 15 to 20 bar and for the mudstone it was higher than 150 bar, suggesting that the mudstone layers had enough sealing capacity from the aspect of hydromechanics. From XRF analyses, before and after 90 d of the scCO2-water-cap rock reaction, the mudstone and the tuff were investigated to assure their geochemical stability as the cap rock. From the study, the Janggi Basin was considered an optimal CO2 storage site based on both its high scCO2 storage ratio and high capillary entry pressure.

Validation and analysis procedures for juxtaposition and membrane fault seals in oil and gas exploration

We propose and validate methods for risk analysis of fault-bounded hydrocarbon traps in exploration. We concentrate on cross-fault leakage and consider lateral seals due to (1) juxtaposition and (2) high capillary-entry-pressure fault rock (membrane seal). We conclude that stochastic methods for fault seal analysis are essential, due to the large number of structural and stratigraphic parameters and the uncertainties. Central to the methods proposed is a Monte Carlo simulation which models geometrical and stratigraphic uncertainty. Multiple Allan maps (fault-parallel cross-sections) are produced and analysed for juxtaposition and shale gouge ratio (SGR). For validation, known discoveries with independently observed hydrocarbon–water contacts (IHWC) have been back-analysed. We present two case studies in this paper, and an additional 40 case studies are summarized (four public domain and 36 confidential case studies). The model outputs were compared with the IHWC. Juxtaposition analysis with no SGR contribution gives the smallest error. The inclusion of any fault rock seal mechanisms (such as SGR) matches or increases predicted hydrocarbon column heights compared to juxtaposition and gives larger errors. We conclude there is no reason to include fault rock membrane seals in exploration prospect risking.

Coupled hydro-thermal-mechanical analysis for cold CO2 injection into a deep saline aquifer

This study investigated the thermal effects of thermal stress and Joule-Thomson cooling on CO2 migration in a deep saline aquifer through a hydro-thermal-mechanical model. Firstly, the temperature variation of injected CO2 was analyzed through the coupling of two-phase flow, deformation of porous medium and heat transfer with Joule-Thomson effect. Then, the effect of capillary entry pressure on CO2 plume was numerically investigated and compared. It is found that injection temperature and Joule-Thomson effect can significantly affect the distributions of CO2 mass and temperature, particularly in the upper zone near the injection well. The reduction of capillary entry pressure accelerates the upward migration of CO2 plume and increases the CO2 lateral migration distance.

Propagation of viscous currents on a porous substrate with finite capillary entry pressure

We study the propagation of viscous gravity currents over a thin porous substrate with finite capillary entry pressure. Near the origin, where the current is deep, propagation of the current coincides with leakage through the substrate. Near the nose of the current, where the current is thin and the fluid pressure is below the capillary entry pressure, drainage is absent. Consequently the flow can be characterised by the evolution of drainage and fluid fronts. We analyse this flow using numerical and analytical techniques combined with laboratory-scale experiments. At early times, we find that the position of both fronts evolve as $t^{1/2}$, similar to an axisymmetric gravity current on an impermeable substrate. At later times, the growing effect of drainage inhibits spreading, causing the drainage front to logarithmically approach a steady position. In contrast, the asymptotic propagation of the fluid front is quasi-self-similar, having identical structure to the solution of gravity currents on an impermeable substrate, only with slowly varying fluid flux. We benchmark these theoretical results with laboratory experiments that are consistent with our modelling assumption, but that also highlight the detailed dynamics of drainage inhibited by finite capillary pressure.