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

Abstract

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 (or delivery) speed provides a continuum between conventional, tight and shale gas reservoirs (Aguilera, 2010). This work extends the previous observation to tight oil and shale oil reservoirs. The link between the various fluids is provided by the word ‘petroleum’ in ‘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 have been extracted from published geologic and petroleum engineering literature. The paper introduces a new unrestricted transition flow period in tight reservoirs that is recognized by a straight line with a slope of -0.75 on log-log coordinates. This straight line occurs as a transition between 2 linear flow periods. Process speed is the ratio of permeability and porosity. The approximate boundary between viscous and diffusion dominated flow in gas reservoirs is estimated with Knudsen number which can be calculated from pore throat radius (a function of process speed). Viscous flow is present, for example, when the architecture of the rock is dominated by megaports, macroports, mesoports and sometimes microports (port = pore throat). Diffusion flow on the other hand is observed at the nanoport scale, which can occur in both tight and shale reservoirs. The process speed concept has been used successfully in conventional petroleum reservoirs for several decades and in tight and shale gas reservoirs during the past 3–4 years. The concept is extended in this paper to tight oil and shale oil reservoirs, and hence to the complete petroleum system, with the support of core and drill-cuttings data. The approach permits estimating volumes of petroleum-in-place, differentiating between viscous and diffusion dominated flow in gas reservoirs and the contribution of each flow mechanism with the use of a unified diffusion-viscous flow model. This is valuable, for example, in those cases where the formation to be developed is composed of alternating stacked layers of tight and shale reservoirs, or where there are lateral variations due to facies changes. It is concluded that there is significant practical potential in the use of process speed as part of the flow unit characterization and production performance prediction in unconventional petroleum reservoirs.

Crushed-Rock Vs. Full-Diameter Core Samples for Water-Saturation Determination in a Tight-Gas Siltstone Play

“…This observation suggests that (1) most of the water lost artificially from the crushed rocks during sample handling is free water and (2) most of the retained water is capillary-bound and clay-bound. Nuclear-magnetic-resonance measurements of core samples also indicate that Montney rocks contain clay-bound water (Akai and Wood 2014) in amounts compatible with the Dean-Stark data reported here (Figs. 11a through 11d).…”

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

“…The straight lines with slopes = -0.5 indicate linear flow. The straight lines with slopes =-1.0 indicate interlinear flow (Source:Aguilera, 2013). Note that this theoretical model displays the same slopes as the actual commingled production data from the Monteith A (upper), Monteith C (lower), and the overlying Cadomin Formation shown inFigure 28.…”

“…The interpretation when the Upper and Lower zones of the Monteith are produced commingled with the Cadomin Formation is somewhat more complicated but still possible with a recently developed theoretical model (Aguilera, 2013). This problem is discussed next.…”

“…This slope corresponds to a period termed interlinear or transition flow by Aguilera (2013). In the case of these wells the combination of linear and interlinear flow is the result of commingled completions.…”

“…A flow-unit has been defined by Hartmann et al, (1999) as "a reservoir subdivision defined on the basis of similar pore type". The determination of pore throat aperture represents a key parameter in the characterization of reservoir rocks which under favorable conditions can be related to possible flow gas/oil rates for tight and shale reservoirs, as showed recently Aguilera (2013). The following equation is used for determining pore throat radii (rp35) in microns (Aguilera (2002(Aguilera ( , 2004:…”