Abstract Three-dimensional (3D) seismic data and well logs from the Penobscot area, located within the Scotian Basin offshore Nova Scotia, are used to assess the role of mass-transport deposits (MTDs) on fault propagation. Four MTDs characterized by chaotic seismic facies were mapped, with the earliest hosted by the Late Cretaceous–Recent Dawson Canyon Formation and latest three hosted by the Banquereau Formation. Two types of faults were also mapped. R-faults are regional faults that cut across all the interpreted MTDs in the study area, while P-faults are polygonal faults that cut across MTDs 2 and 3 but tip out at the basal surfaces of MTDs 4 and 2. Representative seismic profiles and isochron maps of the MTDs and throw–depth (T–z) and throw–distance (T–x) plots allows us to distinguish the families and propagation history of the faults. Our results show that fault propagation is not affected by the presence or thickness variation of MTDs, and is also unaffected by lithological contrast in the Penobscot area of the Nova Scotian Shelf.

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 Geophysical electrical resistivity tomography (ERT) is a promising measurement technique for non-intrusive monitoring of an engineered barrier system (EBS) during the operational phase of geological disposal of high-level radioactive waste. Electrical resistivity is sensitive to water content and temperature, which are the key variables characterizing the response of the EBS. In order to assess the technology readiness level of the ERT technique for EBS operational monitoring, a field demonstrator has been developed at the underground research laboratory (URL) in Tournemire (France) within the project ‘Modern 2020’. Preliminary ERT surveys were carried out in January and November 2017 to establish the background resistivity of the experimental area and assess the quality of electrode installation and survey protocols. Results of the surveys confirmed that the resistivity of the host rock in the demonstrator area is quite homogenous and lower than 100 Ωm in accordance with independent measurements carried out in previous campaigns. In addition, the lesson learned from the blank tests allowed identifying key requirements for effective ERT measurements. These include the need for a 3D electrode configuration, bespoke measurement protocols designed on the basis of the sensitivity analysis of the geometric factor and the collection of reciprocal data for enhanced data quality control.

ABSTRACT Silurian-age (Niagaran) reefs in the Michigan Basin have long been interpreted as relatively homogeneous units, despite production histories that strongly suggest the reefs are heterogeneous in both lateral and vertical dimensions. In an attempt to better illustrate reservoir heterogeneity in these reefs, a three-dimensional (3-D) sequence stratigraphic model was produced for the Ray Reef field. The resulting 3-D Petrel model incorporates 28 wells in the field using a combination of gamma-ray and neutron logs, porosity and permeability data from whole-core analysis, and facies descriptions from eight cores evenly distributed within the reef complex. Comparison of porosity and permeability values within the diverse depositional facies clearly shows trends related to the individual facies and positioning within the sequence hierarchy. Incorporation of the sequence stratigraphic framework into the 3-D model illustrates the episodic nature of reef growth as exhibited by the stacked nature of reef and capping grainstones, often separated by well-developed exposure horizons. The model also suggests a distinct difference between windward and leeward margins in both the geometry of the reef complex and the distribution of reservoir-prone facies. Windward margins are steeper due to higher rates of aggradational growth, and they typically contain higher percentages of reservoir-quality rock in both the reef core and forereef facies. Utilization of the sequence stratigraphic approach illustrates that the vertical reservoir heterogeneity often predicted from production in these reefs may be controlled in large part by the combination of vertical stacking patterns of facies within third- and fourth-order sequences.