The Montney Formation, in north–eastern British Columbia and western Alberta, is a widely developed, low porosity and permeability shale gas and oil reservoir. Due to existing midstream infrastructure, it is an ideal candidate for CO2 sequestration which can potentially be coupled with CO2 enhanced hydrocarbon recovery (EHR). Extensive petrophysical analyses of representative Montney wells and cores validate that the characteristics of supercritical CO2 are more suitable for sequestration compared to either liquid or gas properties. The producing Montney reservoir has absolute permeabilities to helium in the order of 10−2 to 10−5 millidarcies and porosity ranging from 2.9 to 11.1%. At reservoir pressure and temperature conditions, sequestered carbon dioxide will be in the supercritical state. The measured apparent permeability of representative Montney cores matrix to supercritical CO2 is approximately 3.8×10−4 to 3.4×10−2 mD higher than either gas or liquid CO2 values (apparent supercritical CO2 permeabilities range between 4.0×10−4 and 1.4×10−2 mD). The difference between liquid and gas CO2 permeabilities ranges between 3.2×10−5 and 3.0×10−3 mD. Absolute permeabilities to helium were found to be higher than any of the three CO2 phases. The higher apparent permeability to supercritical CO2 compared to the gas or liquid phase is attributed to the higher molecular kinetic energy and the smaller impact of adsorption compared to gas CO2. Permeability data of gas CO2 show both volumetric and adsorption effects, resulting in a lower apparent permeability compared to both liquid and supercritical CO2. Helium data show the highest permeabilities since helium is a non-adsorbing gas and He molecular diameter is 74 pm smaller than the molecular diameter of CO2. The results of this study show that carbon dioxide in the supercritical state has favourable characteristics for the utilization and sequestration in depleted shale gas and oil plays compared to CO2 in either the liquid or gas phase. The relatively high density of the supercritical state – around 750 kg/m3 – will minimize leakage to adjacent formations. Upon reaching reservoirs’ minimum miscibility pressure, supercritical CO2 interfacial tension will approach zero and thus mixing with the residual liquid hydrocarbons will occur. The CO2 will cause the oil or condensate to swell, reducing the viscosity and thus improving the mobility and production rate of the remaining hydrocarbons in place.

The geochemistry of produced fluids has been investigated in the Triassic Montney Formation in the Western Canadian Sedimentary Basin (WCSB). Understanding the geochemistry of produced fluids is a valuable tool in the exploration and development of a complex petroleum system such as the Montney Formation. The petroleum system changes from in situ unconventional reservoirs in the west to more conventional reservoirs that contain migrated hydrocarbons to the east. The workflow of basin modeling and mapping of isomer ratio calculations for butane and pentane as well as the mapping of excess methane percentage was used to highlight areas of gas compositional changes in the Montney Formation play area. This workflow shows the migration of hydrocarbons from deeper, more mature areas to less mature areas in the east through discrete pathways. Methane has migrated along structural elements such as the Fort St. John Graben as well as areas that have seen changes in higher permeability lithologies (i.e., well 14-23-74-8W6M). Excess methane percentage calculations highlight changes due to fluid mixing from hydrocarbon migration. The regional maturation polynomial regression line was used to determine the gas dryness percentage for each well on the basis of its maturation level determined by the butane isomer ratio. The deviation from the calculated gas dryness according to the regression was determined as an excess methane percentage. The British Columbia (BC) Montney play appears to have hydrocarbon compositions that reflect an in situ generation, while the Montney play in Alberta (AB) has a higher proportion of its hydrocarbon volumes from migrated hydrocarbons. The workflow provides a better understanding of the hydrocarbon system to optimize operations and increase production efficiency. Understanding the distribution of gas compositions within a play area will provide key information on the liquid and gas phases present and an understanding of how gas composition may change over the well life, as well as helping to maximize liquid recovery during well operations.

The distribution and origin of hydrogen sulfide (H2S) within gas reservoirs is an important issue due to its toxicity and ability to corrode metal infrastructure, even at low concentrations (i.e. 50 ppm). H2S gas is regarded as a high priority for health and safety at drilling sites. The distribution of H2S, in some basins, can be inexplicable with a mix of sweet (no H2S) and sour (contains H2S) wells within one multi-well pad. Sour gas is a concern in some gas and coal fields in Australia which include Gippsland, Bowen and Cooper-Eromanga basins as well as in the North West Shelf with typical concentrations below 10 000 ppm. For example, the German Creek Formation (Bowen Basin) contains up to 77 ppm of H2S gas and coal seam gas producers will need to perform a risk assessment while exploring and developing this resource. There are multiple sources of H2S gas sulfur and this includes sulfate minerals, pyrite, organic sulfur or from frack water. This research utilises the isotopic variation in the sulfur and oxygen of potential sources, coupled with petrological analyses to determine H2S gas generation. Data is used to predict the gas distribution within the reservoirs to reduce exploration risks. One initial study on the Triassic Montney Formation in western Canada produces H2S gas at concentrations up to 220 000 ppm. Isotopic analyses suggest that the H2S is generated from either Triassic sulfates or a mixture of Triassic and Devonian sources and not solely from Devonian rocks as first expected.