A method for evaluating resource potential and oil mobility in liquid-rich shale plays—An example from upper Devonian Duvernay formation of the Western Canada Sedimentary Basin

Abstract

This paper discusses methods of assessing oil and gas resources and evaluating their mobility in shale reservoirs using programed pyrolysis data in conjunction with reservoir engineering parameters derived from production data. The hydrocarbon resource is calculated from the measured free hydrocarbon by programed pyrolysis with correction of evaporative loss that occurred during coring, storage and sample preparation. The correction takes account of the loss of light hydrocarbon fluids as a result of phase change during core retrieval to the surface and evaporative loss related to storage and sample preparation. Based on their response to ramping temperature during sample pyrolysis and thermal equilibrium behavior of distinct petroleum products at different thermal maturities, the estimated oil and gas resources are divided into three categories: non-movable, restricted, and movable to characterize the mobility of the petroleum fluids. The mobility classification is compared with oil compositional grouping based on evaporative kinetics of petroleum products in rock samples to examine their affinity. Pyrolysis analysis results from naturally matured samples and production data from different fluid zones in the Duvernay Shale resource play in Western Canada Sedimentary Basin (WCSB) were used to demonstrate the application of the proposed method. While the mobility of petroleum fluids increases with thermal maturation in general, the total movable resource reaches its maximum at the end of oil generation window, then declines as a result of massive loss due to hydrocarbon expulsion towards to gas window where liquids are thermally cracked to gaseous hydrocarbons. Compositional grouping based on evaporative kinetics does not show a complete accordance with mobility grouping, suggesting composition is only one of many factors affecting hydrocarbon fluid flow in shale reservoir. More studies are required to better understand the fundamentals of oil mobility in shale reservoir.

Evaluating Shale Gas Sweet Spots of the Jurassic Da'anzhai Member in the Yuanba Area, Sichuan Basin

“…Previous researches indicated that clay mineral pores were mainly formed from the primary pores between clay minerals due to compaction, diagenesis, and mineral alteration. Therefore, the higher the clay mineral content is, the more developed the clay mineral pores (Chen et al 2019b). Compared with marine shale, the higher clay mineral content in terrestrial shale was the main reason for the more developed inorganic pores (Liu et al 2019).…”

“…Organic matter maturity. OM maturity determined the thermal evolution degree in source rock, and whether it was given priority to generate oil or gas, it was very important for evaluating the hydrocarbon generation potential (Chen et al 2019a;Passey et al 2010). Vitrinite reflectance (R o ) was currently the most effective indicator for determining OM maturity.…”

Natural gas potential of Neogene source rocks in the Yiliping area, Qaidam Basin: Using an improved hydrocarbon generation and expulsion model based on least‐squares Monte Carlo

“…Therefore, calibration of the lost light hydrocarbons is required. This study calibrated light hydrocarbons using the light hydrocarbon calibration model based on the phase equilibrium principle and laboratory test results of light hydrocarbon losses (Chen et al, 2019). The total light hydrocarbon loss (S L ) includes the light hydrocarbon loss (S LS ) in the sampling process and the light hydrocarbon loss (S LP ) during the sample preservation and preparation process (Equation ).…”

“…S LS is calculated by the formation volume factor (FVF) of crude oil (Equation ), while S LP is calculated from an average value of 15% obtained from light hydrocarbon loss experimental results. Therefore, the calibrated total free hydrocarbon (S 1c ) can be expressed in Equation (Chen et al, 2019). where, ρ oilS has a density of kg/m 3 , while ρ oilR has a density of kg/m 3 under surface conditions.…”

An Improved Method for Evaluating Hydrocarbon Generation of Shale: A Case Study of the Lower Cretaceous Qingshankou Formation Shale in the Songliao Basin

“…Additionally, research shows that the hydrocarbons that are difficult to volatilize before 300°C in S2 are mainly heavy components, which are considered adsorbed hydrocarbons of shale (Jarvie, 2012b;Chen et al, 2019). Adsorbed hydrocarbons are a part of the total hydrocarbon content in shale and are mainly adsorbed on the organic matter surface Zou et al, 2013;Jiang et al, 2016).…”