Per Kent Pedersen

Innovative methods for flow-unit and pore-structure analyses in a tight siltstone and shale gas reservoir

Tight gas reservoirs are notoriously difficult to characterize; routine methods developed for conventional reservoirs are not appropriate for tight gas reservoirs. In this article, we investigate the use of nonroutine methods to characterize permeability heterogeneity and pore structure of a tight gas reservoir for use in flow-unit identification. Profile permeability is used to characterize fine-scale (1 in. [2.5 cm]) vertical heterogeneity in a tight gas core; more than 500 measurements were made. Profile permeability, although useful for characterizing heterogeneity, will not provide in-situ estimates of permeability; furthermore, the scale of measurement is much smaller than log scale. Pulse-decay permeability measurements collected on core plugs under confining pressure were used to correct the profile permeability measurements to in-situ stress conditions, and 13-point averages of profile permeability were used to relate to log-derived porosity measurements. Finally, N2 adsorption, a new method for tight gas was used to estimate the pore-size distribution of several tight gas samples. A unimodal or bimodal distribution was observed for the samples, with the larger peak corresponding to the dominant pore-throat size, as confirmed by independent methods. Furthermore, the adsorption-desorption hysteresis loop shape was used to interpret the dominant pore shape as slot-shaped pores, which is typical of many tight gas reservoirs. The N2 adsorption method provides rapid analysis and does not suffer from some of the same limitations of Hg injection. In the future, we hope that the N2 adsorption method may prove useful for flow-unit characterization (based on dominant pore size) of fine-grained (siltstone-shale) tight gas reservoirs.

Production Analysis of Western Canadian Unconventional Light Oil Plays

Unconventional low-permeability (tight) light oil reservoirs have emerged as a significant source of oil supply in North America. As with unconventional gas reservoirs, these low-permeability oil plays exhibit a wide variety of reservoir characteristics, and consequently well-performance profiles. Further, different drilling and completion strategies are used to exploit them. In this work, we suggest that a categorization analogous to that used for unconventional gas reservoirs (i.e. based on reservoir/fluid properties) be used for unconventional light oil reservoirs because of the significant difference in reservoir and production characteristics observed to date in Western Canada. We propose the term “Unconventional Light Oil” (ULO) to capture the spectrum of play types and to distinguish them from unconventional heavy (high viscosity) oil plays. We further propose the following categories of ULO, which can be used as a practical guide for exploration and development:

Breakdown of the Gutenberg-Richter relation for microearthquakes induced by hydraulic fracturing: influence of stratabound fractures

Hydraulic fracturing, a powerful completion technique used to enhance oil or gas production from impermeable strata, may trigger unintended earthquake activity. The primary basis for assessment of triggered and natural seismic hazard is the classic Gutenberg-Richter (G-R) relation, which expresses scale-independent behaviour of earthquake magnitudes. Here we use a stochastic approach to simulate and test magnitude-distance trends expressed by microseismic catalogues derived from three hydraulic fracture monitoring programmes in North America. We show that a widely observed rapid fall-off in large-magnitude events, almost universally quantified using the G-R b value, may in our case be an artefact of the strongly laminated character of the stimulated oil and gas reservoirs. We also show that, for the three reservoirs considered, mechanical bed thickness can be approximated by a lognormal distribution. For a stratabound fracture network, this leads asymptotically to a Gaussian decay for induced magnitudes. We show that the stratabound model provides a more significant correspondence with our observations. If applicable in general, this result has important implications for determining the energy balance of hydraulic fracture systems (i.e. radiated seismic energy versus injected energy) as well as hazard assessments based on the probability of occurrence of anomalous seismic events. Key words: Monitoring, Passive Method, Reservoir Geophysics.

Porosity and pore size distribution in mudrocks from the Belle Fourche and Second White Specks Formations in Alberta, Canada

The distribution of porosity was examined on seven drill cores from west–central Alberta encompassing the Belle Fourche and Second White Specks Formations. These Cenomanian–Turonian mudrocks from the Western Canada Sedimentary Basin exhibit good organic richness (>2 wt. % total organic carbon) and marine kerogen type II with limited kerogen type III. With the increasing thermal maturity from approximately 0.43% vitrinite reflectance (Ro) to approximately 0.90% Ro, the total porosity decreases from approximately 9 to approximately 1 vol. %. This change translates to a reduction in total pore volume from approximately 0.05 to approximately 0.005 cm3/g and is accompanied by changes in relative proportions of micropore, mesopore, and macropore volumes. Variations in total porosity for the seven cores with different thermal maturities across Alberta are mainly related to mesoporosity and macroporosity, although the in-core variations in total porosity are mainly related to microporosity. In general, organic matter micropores contribute to the overall microporosity in the seven cores across the study area. The increase in the total pore volumes is in accordance with an increasing concentration of quartz, although increasing concentrations of chlorite and kaolinite may contribute to greater abundance of micropores in the seven cores. The in-core variations suggest that greater contents of kaolinite and illite may contribute to increasing mesopore volumes. Variations in pore volumes and pore size distribution with depth within individual cores (representing specific thermal maturity level) differ from what is observed laterally, when cores of various thermal maturity levels across Alberta are compared, indicating complex controls on porosity systems.

Reservoir characterization using microseismic facies analysis integrated with surface seismic attributes

AbstractWe have developed the concept of microseismic facies analysis, a method that facilitates partitioning of an unconventional reservoir into distinct facies units on the basis of their microseismic response along with integrated interpretation of microseismic observations with 3D seismic data. It is based upon proposed links between magnitude-frequency distributions and scaling properties of reservoirs, including the effects of mechanical bed thickness and stress heterogeneity. We evaluated the method using data from hydraulic fracture monitoring of a Late Cretaceous tight sand reservoir in central Alberta, in which microseismic facies can be correlated with surface seismic attributes (primarily principal curvature, coherence, and shape index) from a coincident 3D seismic survey. Facies zones are evident on the basis of attribute crossplots, such as maximum moment release rate versus cluster azimuth. The microseismically defined facies correlate well with principal curvature anomalies from 3D seismic...

Geologic Controls of Gas Production from Tight-Gas Sandstones of the Late Jurassic Monteith Formation, Deep Basin, Alberta, Canada.

This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s).

The influence of climate on early and burial diagenesis of Triassic and Jurassic sandstones from the Norwegian-Danish Basin

Climate changes preserved in sandstones are documented by comparing the sediment composition and early diagenetic changes in sandstones deposited during arid to semi‐arid conditions, the Skagerrak Formation, with sandstones of the Gassum Formation deposited in a humid well‐vegetated environment. The study area covers the easternmost part of the Norwegian–Danish Basin, for which the Fennoscandian Shield functioned as sediment source area. The depositional environments of the formations, their distribution and burial depths are well‐constrained, facilitating a comprehensive petrographical and geochemical study complemented by porosity and permeability measurements of cores widely distributed in the basin (1700 to 5900 m burial depth). The Skagerrak Formation had an immature composition with more abundant feldspar, rock fragments and a larger variability in the heavy mineral assemblage when compared to the Gassum Formation, which was characterized by quartz and more stable heavy minerals. The arid to semi‐arid climate led to early oxidizing conditions under which abundant iron‐oxide/hydroxide coatings formed, while the evaporative processes occasionally resulted in caliche and gypsum precipitation. Under the humid climate, kaolinite precipitated due to leaching of feldspar and mica, and the abundant organic matter caused reducing conditions, which led to other Fe‐rich phases, i.e. pyrite, Fe‐chlorite and siderite. The inherited early diagenetic pore fluids and mineral assemblage also affect the mineral changes occurring during deeper burial, so dolomite preferentially formed in the sandstones deposited in an arid environment, while ankerite characterizes sandstones deposited under humid conditions. In addition to climate‐induced burial diagenetic changes, there are also temperature‐dependent phases, such as illite and quartz cement. Despite the same sediment source area remaining active during the entire period, the sediments that reached the Norwegian–Danish Basin were immature during the arid interval, although mature during the humid period. This has implications for provenance investigations as well as diagenetic investigations of sandstone reservoir quality.