Abstract 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.

Understanding reservoir performance and predicting hydrocarbon recovery in carbonate reservoirs are challenging due to the complexity of the pore system and the dynamic interplay of multiphase fluids that move through the pore network. A multiyear study of carbonate reservoirs across a broad spectrum of geologic conditions, fluid types, and field maturities has resulted in key insights on the links between pore-system characteristics and dynamic fluid-flow behavior with material relevance to carbonate resource assessment, field development optimization, and maximizing ultimate recovery. Pore-system heterogeneity is a primary control on hydrocarbon displacement efficiency. Multiphase flow through heterogeneous pore systems with a mix of pore types results in lower recovery than flow through more homogeneous pore systems. Due to the homogeneous nature of the micropore system, rocks dominated by micropores can have favorable hydrocarbon displacement with residual oil saturation to water displacement (Sorw) less than 5%. Rocks with a heterogeneous mix of interparticle and micropores have less favorable displacement, with Sorw as high as 20%, despite having higher permeability. A threshold of approximately 80% microporosity appears to distinguish: (1) more favorable displacement in micropore-dominated rocks vs. less favorable displacement in rocks with a mixed pore system, (2) the magnitude of permeability for a given porosity in mixed vs. micropore systems, and (3) the proportion of microporosity above which pore space of any type is connected exclusively through the micropore network and flow properties reflect the homogeneous nature of that pore system. Within the homogeneous micropore system, Sorw increases from about 5% to 20% as porosity and permeability decrease and micropore type transitions from type 1 (higher quality) to type 2 (lower quality). A major control on multiphase fluid movement in reservoirs with interlayered mixed and micropore-dominated flow units is the contrast in capillary pressure (Pc) and water relative permeability (Krw) between these distinct pore systems. When compared on a consistent basis, 60% water saturation, for instance, rocks with a mixed pore system have approximately neutral (0 psi, 0 kPa) Pc values and higher Krw values, whereas rocks dominated by microporosity have more strongly negative (−6 psi, (−41 kPa) Pc values and lower Krw values. In the case of a water flood operation, this contrast in Pc and Krw can lead to more heterogeneous sweep patterns and lower recovery. A new method for tagging in-place oil with xenon was coupled with flow-through micro-computed tomography imaging to directly investigate oil displacement under water flood conditions. The results provide a qualitative demonstration of how brine flooding displaces xenon-saturated oil. Displacement patterns in micropore-dominated rocks are homogeneous and compact with limited bypass of oil, consistent with relatively low Sorw. Conversely, the displacement pattern in rocks with a mixed pore system is more heterogeneous and exhibits significant regions of bypassed oil, consistent with higher Sorw and Krw.

Abstract A review of gas relative permeability ( k rg ) studies of low-permeability sandstones indicates that they can be modeled using the Corey equation, but scarce data near the critical gas saturation ( S gc ) limit k rg modeling at high water saturations. Confined mercury injection capillary pressure and coupled electrical resistance measurements on Mesaverde sandstones of varied lithology were used to measure critical nonwetting saturation. Most of these data support the commonly applied assumption that S gc < 0.05. However, a few heterolithic samples exhibiting higher S gc indicate the dependence of Sgc on pore-network architecture. Concepts from percolation theory and upscaling indicate that S gc varies among four pore-network architecture models: (1) percolation ( N p ), (2) parallel ( N // ), (3) series ( N ┴ ), and (4) discontinuous series ( N ┴d ). Analysis suggests that S gc is scale- and bedding-architecture-dependent in cores and in the field. The models suggest that S gc is likely to be very low in cores with laminae and laminated reservoirs and low (e.g., S gc < 0.03–0.07 at core scale and S gc < 0.02 at reservoir scale) in massive-bedded sandstones of any permeability. In cross-bedded lithologies exhibiting series network properties, S gc approaches a constant reflecting the capillarypressure property differences and relative pore volumes among the beds in series. For these networks, S gc can range widely but can reach high values (e.g., S gc < 0.6). Discontinuous series networks, representing lithologies exhibiting series network properties but for which the restrictive beds are not sample spanning, exhibit S gc intermediate between N p and N ┴ networks. Consideration of the four network architectures lends insight into the complications of heterogeneous lithologies at differing spatial scales and underscores the difficulty of upscaling laboratory-derived relative permeabilities for reservoir simulation. Analysis also indicates that for some architectures, capillary pressure and relative permeability anisotropy may need to be considered.