Flow Units: From Conventional to Tight-Gas to Shale-Gas to Tight-Oil to Shale-Oil Reservoirs

Abstract

Summary Core data from various North American basins with the support of limited amounts of data from other basins around the world have shown in the past that process speed or delivery speed (the ratio of permeability to porosity) provides a continuum between conventional, tight-, and shale-gas reservoirs (Aguilera 2010a). This work shows that the previous observation can be extended to tight-oil and shale-oil reservoirs. The link between the various hydrocarbon fluids is provided by the word “petroleum” in the “total petroleum system (TPS),” which encompasses liquid and gas hydrocarbons found in conventional, tight, and shale reservoirs. Results of the present study lead to distinctive flow units for each type of reservoir that can be linked empirically to gas and oil rates and, under favorable conditions, to production decline. To make the work tractable, the bulk of the data used in this paper has been extracted from published geologic and petroleum-engineering literature. The paper introduces an unrestricted/transient/interlinear transition flow period in a triple-porosity model for evaluating the rate performance of multistage-hydraulically-fractured (MSHF) tight-oil reservoirs. Under ideal conditions, this flow period is recognized by a straight line with a slope of –1.0 on log-log coordinates. However, the slope can change (e.g., to –0.75), depending on reservoir characteristics, as shown with production data from the Cardium and Shaunavon formations in Canada. This interlinear flow period has not been reported previously in the literature because the standard assumption for MSHF reservoirs has been that of a pseudosteady-state transition between the linear flow periods. It is concluded that there is a significant practical potential in the use of process speed as part of the flow-unit characterization of unconventional petroleum reservoirs. There is also potential for the evaluation of production-decline rates by the use of the triple-porosity model presented in this study.

Empirical Modeling of the Viscosity of Supercritical Carbon Dioxide Foam Fracturing Fluid under Different Downhole Conditions

“…The modified power law models for sCO 2 foam made from AOS and betaine were presented as a function of three crucial parameters: temperature, pressure, and shear rate.…”

“…Unconventional shales that contain huge amounts of stored reserves are difficult to produce due to their low permeability [1,2]. Enhanced recovery techniques, such as hydraulic fracturing, have been widely preferred to ease the gas flow.…”

“…Besides this, high fluctuations in temperature cause holes in the lamella because the foam undergoes high lamella rupture and bubble coalescence occurs [42]. Therefore, the apparent viscosity of sCO 2 foam is expected to decrease with rising temperature [5,33].…”

“…The aims of this study were to investigate the effect of temperature, pressure, and shear rate on the apparent viscosity of sCO 2 foam and to present an empirical model for foam apparent viscosity as a function of temperature, pressure, and shear rate. For this purpose, foam generation was performed using the widely used alpha olefin sulfonate (AOS) and a foam stabilizer (i.e., betaine) and foam viscosity was measured using a high pressure, high temperature foam rheometer.…”

Applications of digital core analysis and hydraulic flow units in petrophysical characterization

“…As reviewed by Mirzaei-Paiaman and Saboorian-Jooybari (2016) and Deng et al (2016), among various methods, FZI or the modified FZI method is considered as the most effective and widely-used method for classifing HFUs for various types of reservoirs, such as sandstone (Wargo et al, 2013), tight gas (Xie et al, 2010;Aguilera, 2014), carbonate Yang et al, 2017) and shale (Aguilera, 2010;Nie et al, 2015;Deng et al, 2016).…”