Two of the major issues facing upstream and midstream operators and regulators in developing unconventional reservoirs in Western Canada are the presence of trace to significant amounts of hydrogen sulphide in produced gas and the seemingly inexplicable vertical/stratigraphic zonation and yield of producible hydrocarbon liquids.
The Doig and Montney Formations are an unconventional to hybrid petroleum system that provide significant contributions to the national energy portfolio. For example, the Montney Formation provided a significant proportion (34%) of natural gas to the total Canadian gas production in 2017 (NEB, 2018). This petroleum system is complex with initial formation of petroleum being generated in deeper western areas where secondary cracking of the hydrocarbons to drier gases migrated updip and mixed with in-situ wetter petroleum in less mature areas to the east. The mixing of the more mature petroleum changes the hydrocarbon composition and can reduce the confidence in the prediction of hydrocarbon composition based on its relationship to basin-scale maturation trend. This is further complicated by regional structures, such as the Peace River Arch, Fort St John Graben, Hay River Fault Zone, and the Laurier Embayment areas that modify depositional and subsidence rates as well as the depth of burial that affects the regional maturation trends and the generation of hydrocarbons. Chapters 3 to 4 illustrate the workflow that is needed to understand complex interactions between basin evolution, regional structural activity, sedimentation patterns, TOC content and type, maturation trends, as well as in-situ versus ex-situ hydrocarbon compositional trends to aid the prediction of the expected hydrocarbon composition. This prediction will help operators define the most efficient operations and development program to maximise profits and increase sustainability of the energy resource. Chapter 3 provides a workflow on mapping the essential elements to determine the petroleum system processes at play across the basin. Chapter 4 provides the workflow and tools needed to understand why hydrocarbon composition departs from the regional maturation correlation. Chapter 4 also illustrates the effective use of hydrocarbon geochemistry, particularly isomer ratios, to calculate an excess methane content (%), and when mapped, highlight areas that have seen migration of deeper, more mature hydrocarbons (i.e., methane) into less mature areas. These areas have been a focus by operators as the increase in methane can provide additional drive to reservoir systems and produce wetter gases that may normally drop out during production time.
Hydrogen sulphide (H2S) is a highly toxic non-hydrocarbon gas found within some petroleum systems. H2S gas is harmful to humans and the environment as well as, due to its highly corrosive characteristics, can increase operational costs as more expensive, sour specification infrastructure needs to be implemented. The H2S distribution within the Montney Formation is inexplicable. The majority of Montney producing wells are sweet gas (i.e., zero percent H2S) and more recently operators have encountered sour Montney wells that can produce alongside sweet wells on the same multi-well pad. The concentration of H2S is much lower in BC Montney producers (< 1%) than is observed in Alberta Montney producers (> 1%) which can point to different processes at play. Researchers (i.e., Liseroudi et al., 2020) using sulphur isotopic analysis, have concluded for Montney producing wells in Alberta that deep seated faults and fractures have provided conduits for sulphate and/or H2S gas to migrate from deeper sulphur sources in the Devonian strata. Chapter 5 provides an effective workflow using sulphur isotopic, SEM and XRD analyses to understand the cause of souring in Montney producing wells in BC. This workflow has shown that the source of sulphur for the majority of BC souring wells may have come from Triassic rocks and the Charlie Lake Formation is the likely source due to its close proximity and high concentration of anhydrite in its evaporite facies. The process is somewhat complex, with a geological model that suggests the sulphate has migrated from the Charlie Lake Formation prior to hydrocarbon generation in the Montney Formation and has concentrated in discrete zones due to direct deposition in conduits like fracture and fault systems.
SEM analysis confirms massive anhydrite within the Montney Formation that is likely from infilled fractures. The anhydrite in the fractures is most likely the source of the sulphur that reacts with the generated hydrocarbons to form H2S gas. The model fits the observation of very discrete sour zones within the Montney Formation and both sweet and sour wells producing on the same multi-well pad in BC. The sulphur isotopic analysis indicates the sulphur isotopic range for Triassic anhydrite is the same as the H2S sulphur that is produced from the Montney Formation. The sulphur from deeper sources in the Devonian are isotopically heavier and are not the likely source for sulphur. There are several wells that show a slightly heavier isotopic signature that is in close proximity to the deformation front and may have deep-seated faults that acted as a conduit for Devonian sulphur to migrate into the Montney Formation. The use of three-dimensional seismic data is essential in any workflow, but was not used in this study due to the nature of seismic acquisition by third party companies and their lack of appetite in providing data to scientific studies such as this project. Chapter 5 provides a workflow that operators can follow that will aid the risk management of encountering sour wells when developing the Montney Formation. Operators will need access to three-dimensional seismic data that will provide maps on structural features which can then be overlain with the distribution of the Charlie Lake Formation. Combining these maps with the sulphate ion concentrations in connate water of the Montney Formation will provide a robust risk map for the souring potential across their development lands. In chapter 6, the distribution of sulphate and other major ions in Montney and Doig formations flowback and produced waters are determined to provide insights into the origin and distribution of hydrogen sulphide in produced gas and nature of the connate water.The impact of fluid-rock interactions of produced fluids is determined through the use of aging-leach experiments carried out at reservoir temperature, using surface area to volume ratios anticipated during completion. The sulphate content of most produced Montney waters generally ranges from 50 mg/L to about 300 mg/L, although many exceptions occur. The variation in sulphate concentrations in produced water and the coeval production of H2S and CO2 gas are complex, and in many wells inexplicable. For some wells, there are trends of increasing or decreasing H2S and CO2 gas production with time, while in other wells there are no consistent trends.
In chapter 7, the sorption gas capacity is quantified for representative Doig and Montney Shales. At reservoir conditions for a shale with 2-3% total organic carbon, the sorbed gas represents about 20% of the reservoir gas. Since hydrogen sulphide has five to six times the sorption affinity and capacity of methane, it is selectively retained in the sorbed state to late in the reservoir’s life when the critical desorption pressure is reached. Due to much higher solubility of H2S in brines than CH4, high water cuts during production will be associated with higher H2S concentrations if H2S is present in the system.In chapter 8, the metrics derived in chapter 7 are used to study the impact of varying gas contents and initial concentrations of H2S on the producibility of H2Sthrough a series of 3D reservoir models based on a Montney shale gas reservoir. The models consider the confounding impacts of gas storage (solution, free and sorbed) that are dynamic with production, and the impact of different gas diffusivities. In chapter 9, the regional petrophysical properties of the Doig and Montney formations in Alberta and British Columbia are investigated to determine the controls on the distribution and production of hydrogen sulphide and hydrocarbon liquids. Reservoir properties in the Doig and Montney formations are controlled by a complex interplay between depositional environment, diagenesis and mechanical compaction. Using capillary pressures determined by mercury intrusion tests and wettability and interfacial tensions measured on Montney fluids, conventional and unconventional reservoir facies are readily differentiated. Upper Montney conventional reservoirs have low critical pressures and required a trap and seal to retain hydrocarbons whereas in the lateral continuous unconventional reservoirs, the reservoir is self sealing due to high capillary pressures.