Public Reports

 Geoscience BC has published the results of a project that assessed the potential amplification of ground motion associated with earthquakes generated by hydraulic fracturing and fluid injection in an area around Fort St. John and Dawson Creek in British Columbia’s Northeast Region. These results add detail to findings for a larger area completed earlier in 2019.

The project addresses public concerns relating to seismicity and oil and gas industry activity in northeastern BC, especially in areas close to communities and infrastructure. It examined how seismic waves from earthquakes can potentially be amplified in specific shallow geological conditions.

Lead researcher Dr. Patrick Monahan said at the project outset: “Most recent studies in this area have focused on the reduction of ground motion as you get further from the seismic event. But seismic ground motions can also be amplified significantly on sites underlain by certain sediments, compared to sites on bedrock or firm ground.”

Now complete, the information generated by the project is being made publicly available. The results will be particularly useful for regulators and industry operators managing energy industry activity to identify areas which may have an increased likelihood of felt events due to local surface conditions.

The researchers collected data from over 4,800 petroleum industry wells, water wells, and geotechnical boreholes. The data was used to prepare a new depth to bedrock contour map at a 1:100,000 scale. High resolution digital topographic mapping was also used to revise existing surficial geological mapping. Together, this map development better defines the surficial map unit boundaries and reflects the thickness variations in the deposits that are susceptible to amplification. To investigate this potential amplification, surface and subsurface shear velocity (Vs) data was compared with earthquake recordings.

The project also gives an update to the shear velocity (Vs) model for shallow geological materials, as compared to the already mentioned previous study.

The project concluded that, within the project area, susceptibility to amplification of seismic waves is widespread, occurring where the thickness of sediment over bedrock exceeds five metres. More specifically, the highest amplification may occur between five and fifteen metres thickness, where amplification of specific frequencies due to resonance can occur. Where the thickness exceeds fifteen metres, amplification can occur over a wide range of frequencies.

Geoscience BC Manager, Energy and Water Randy Hughes said: “The new maps and data generated by this project are giving a better understanding about which areas have the potential for increased ground motion during induced seismicity events associated with natural gas extraction. By sharing this information with industry, regulators, communities in the Peace River Regional District and Indigenous groups, it can be used to improve industry procedures to manage felt events.”  

Study page for download at Geoscience BC

 A new research report and data set provide detail on potentially suitable geologic storage for wastewater from natural gas operations in northeast British Columbia’s (NEBC) Montney Play region.

Deciding where to place a disposal well can be a complex process, especially in northeast BC’s maturing Western Canada Sedimentary Basin, where suitable disposal zones are increasingly difficult to find.

The Wastewater Disposal in the Maturing Montney Play Fairway of NEBC project includes 10 conclusions and eight recommendations. This includes that of 13 formations assessed, seven are potentially suitable for wastewater disposal. Each of these seven formations was mapped to highlight areas within them where wastewater disposal may be appropriate.

Research lead Dr. Brad Hayes said: “This report and accompanying data provide essential new knowledge about potentially suitable locations for disposal of wastewater from natural gas operations in the Montney Play region. It can be used by the regulator, operators, governments, community leaders and Indigenous groups to make informed, evidence-based decisions about continued natural gas development and to guide future research.”

“The BC Oil and Gas Commission is highly appreciative of the work by Geoscience BC and the report authors in providing information that supports safe and effective deep disposal,” said Ron Stefik, Supervisor, Reservoir Engineering. “The Commission has undertaken significant improvements in regulation and data collection of this activity, which the report supports, and it will be a valuable reference in identifying opportunities for sustainable development.”

The independent, peer-reviewed research addresses wastewater disposal knowledge gaps in the Montney Play region identified by the Scientific Hydraulic Fracturing Review Panel, operators, and the BC Oil and Gas Commission. It integrates hydrogeology, geomechanics, reservoir characterization (including petrophysics), and structural geology to evaluate suitable wastewater disposal zones below the base of usable groundwater.
Study page for download at Geoscience BC

Petrel Robertson Consulting Ltd. (PRCL) was engaged by the Nova Scotia Department of Energy to provide advice and support on assessing conventional and unconventional oil and gas resources of onshore Nova Scotia. PRCL has completed similar oil and gas resource assessments in other petroleum frontier areas of Canada, and principal Dr. Brad Hayes gained experience in service to the Nova Scotia Expert Panel on Hydraulic Fracturing in 2014. After consultation with Department of Energy staff on available data and timelines, PRCL agreed to focus on assessing conventional and unconventional oil and gas resources in the Windsor-Kennetcook and Cumberland basins. Ministry staff has compiled available geological and geophysical data to support the assessment, and Dr. D. Fraser Keppie visited PRCL offices during the project to provide support and to become more familiar with the assessment workflow. The joint goal of the Department of Energy and PRCL for this project is to produce a robust evaluation of resource potential that accurately reflects the quality and availability of data from the Windsor-Kennetcook and Cumberland basins of Nova Scotia – and to enable Department of Energy staff to undertake additional resource assessment work in the future.
Study page for download at the Nova Scotia government site

Seismicity has increased significantly in northeast British Columbia in recent years due to fluid injection by the petroleum industry for hydraulic fracturing and wastewater disposal.  The objective of this study is to map the susceptibility to amplification of seismic ground motions due to local soil conditions within the Montney play trend of northeast British Columbia.  Results of this study include: compilation of a surficial geological map from several published sources; compilation of a subsurface geological borehole database to characterize the geological units of the shallow subsurface; acquisition of new shear-wave velocity (V_s) data and development of a V_s model for the shallow geological units.  These data were used to assign NEHRP Site Classes and amplification susceptibility ratings to the surficial geological map units.  This analysis demonstrates that areas underlain by Holocene and recessional phase deposits of the last glaciation, where sufficiently thick, are in NEHRP Site Class D, and so susceptible to amplification of seismic ground motions.  Where these deposits are thinner, along their margins, amplification of ground motions may also occur due to resonance.  Ground motions recorded in recent induced seismic events are generally consistent with these conclusions, although there is considerable variability.

Study page for download at Geoscience BC

Geoscience BC Report 2016-04 Geoscience BC has worked with industry, government agencies, and local stakeholders to assess available water resources in the BC Montney play fairway. Substantial progress has been made in understanding water resources in deep saline aquifers and in surface water bodies, but non-saline groundwater resources in unconsolidated aquifers and shallow bedrock are not as well known. Geoscience BC has undertaken the Peace Project to map groundwater resources in an 8000+ km2 area in the Peace Region, through the use of airborne geophysics (Geoscience BC Report 2016-03).

In support, Petrel Robertson Consulting Ltd. (PRCL) and Quaternary Geosciences Inc.(QGI) have completed a geological characterization of Quaternary and other nearsurface formations in the Peace Project area. Building on existing geological mapping and hydrogeological reports, the investigations used cased-hole gamma logs run through surface casing in petroleum boreholes to map depth to bedrock (and hence thickness of Quaternary cover), and the distribution of aquifer sands in the Quaternary section.

Deliverables from the study include a stratigraphic database summarizing interpretations from all petroleum boreholes (Appendix 1), a database tabulating depth to bedrock picks for water wells (Appendix 2), and surficial geology maps showing composition and thickness of the Quaternary section (depth to bedrock surface), along with interpreted outlines of paleovalley systems (Map 1, 2). These will be used to calibrate interpretations of Quaternary thickness and aquifers derived from airborne geophysical mapping in the main phase of Geoscience BC’s Peace Project.

Study page for download at Geoscience BC

Horizontal drilling and multi-frac completions have greatly augmented B.C. gas and liquids resources and reserves by accessing unconventional (low-permeability) reservoirs.  However, relatively little new unconventional oil potential has been identified in what is generally regarded as a gas-prone area of the Western Canada Sedimentary Basin. 

Geoscience BC has tasked the PRCL project team with identifying new exploration and exploitation fairways for oil in unconventional reservoirs – “Resource oil”.  Our analysis spans the entire stratigraphic column, with the exception of the Montney Formation, which is the subject of numerous dedicated studies and is an active oil and liquids drilling target. 

We identified resource oil targets using regional geological assessments of reservoir and production trends in conventional, tight, and shale reservoirs.  We reviewed all existing files of analytical data – standard core analysis, geochemistry / maturity, mineralogy, geomechanical properties – submitted to the BC OGC, and tabulated them to support future detailed analyses.  Where analytical data were lacking on promising plays, we sampled cores and completed comprehensive laboratory analyses, which are included in this report and included in our discussions.  Finally, we analyzed test and production data from a reservoir engineering perspective to better understand the scope and quality of potential resource oil fairways.

Of 19 reservoir intervals deemed suitable for analysis, 10 were judged to have little realistic prospectivity (a ‘C’ prospectivity grade) for reasons including:  lack of extensive low-permeability reservoir facies, poor geomechanical properties (low “frackability”), and lack of viable oil charge.  Six others were assigned a ‘B’ grade – indicating some real resource oil potential based on existing oil shows or production and favourable geological / geomechanical characteristics, but generally lacking either substantial horizontal / multi-frac testing, or good evidence of extensive resource oil fairways.  One target – Doig Formation sandstones – was assigned an ‘A/B’ grade, as there is some very good existing production and possible scope to extend the development fairway into both conventional and tight areas.  Only two reservoirs – the Halfway and Chinkeh formations, were seen as ‘A’ targets.  The Chinkeh is prospective for tight oil across a broad, poorly-defined fairway downdip from the existing Maxhamish gas field, while the Halfway presents halo oil potential in lower-permeability shoreface sandstones offsetting historical conventional production focused on higher-quality tidal channel sandstones.

Study page for download at Geoscience BC

Intensive development of the Montney tight siltstone and shale play in northeastern B.C. presents new challenges to both operators and to the BC Oil & Gas Commission. One of the key challenges is in accessing appropriate water source and disposal zones to support horizontal drilling and multifrac completions. Source water can be obtained from surface water bodies, shallow non-saline aquifers, or deep saline aquifers. However, spent completion fluids and produced waters must be injected into deep saline aquifers to ensure complete isolation from surface waters and non-saline groundwater.

The Montney unconventional play fairway spans both Plains and Foothills areas in the Peace River region and northwestward. Potential disposal zones in deep saline aquifers exist across the fairway, but their distribution and injectivity characteristics are highly variable. Geoscience BC’s Montney Water Project provides a comprehensive regional inventory of water resources and potential for deep geological disposal sites in the Montney, and is an excellent starting point for detailed local work on specific water disposal issues.

Recent injection activity has shown that more work is required, as performance of some existing injection wells has not been satisfactory. Geoscience BC and the BC Oil & Gas Commission have collaborated to develop a scope of study that addresses many of the water disposal challenges. The Belloy, Kiskatinaw and Debolt formations have been identified as high-priority disposal zone targets requiring detailed assessment.

Petrel Robertson Consulting Ltd. (PRCL) was engaged by Geoscience BC to undertake regional reservoir characterization of the Belloy, Kiskatinaw, and Debolt formations, with emphasis on identifying their capacity to act as secure disposal zones. This report summarizes PRCL’s findings, and is designed to support future focused reservoir engineering assessments.

Study page for download at Geoscience BC

This report represents the conclusion of six months of intensive research and analysis overseen by an independent panel of experts assembled by the Verschuren Centre for Sustainability in Energy and the Environment at Cape Breton University. The report represents the considered views of the panel who represent expertise in a broad ranges of disciplines: Aboriginal wisdom, economics, environmental geography, water science, environmental science, public health, social science, social ecology, petroleum geology, geoscience, law (including Aboriginal law), and knowledge of the natural gas industry itself. Our experience was diverse; six of our 11 panelists were academics (including the Chair), four were independent consultants and one was a provincial employee (acting in an independent capacity). All of us had experience in domains beyond our primary discipline and professional affiliations.

This chapter builds on our understanding of the process of hydraulic fracturing described in Chapter 1 and looks at the resource and infrastructure potential for onshore oil and gas extraction in Nova Scotia, including the use of hydraulic fracturing techniques. The chapter also lays the groundwork for a range of plausible scenarios that illustrate the potential economic impacts and royalty streams associated with any future development of unconventional gas and oil in the province; those scenarios are used to introduce Chapter 3 on Development Scenarios and Potential Economic Impacts.

The physical geology does recognize resource potential for conventional and unconventional gas and oil in specific areas (sedimentary basins) in the province, mostly in rural areas. Limited on-shore petroleum exploration has occurred to date, but no commercial oil and gas production has been established. Local and export markets exist for both oil and natural gas with demand growing.

As knowledge of the subsurface, including sedimentary rocks and hydrocarbons, is extremely limited, it is very difficult to quantify the potential or even rank the various basins in terms of overall “prospectivity.” The shales in basins closest to New Brunswick are of most interest to developers to date, because New Brunswick basins have demonstrated commercial production of both oil and gas and because pipeline infrastructure is in place (M&NP, 2014). Using published information, potential gas volumes have been estimated at 17-69 TCF in the Windsor-Kennetcook Basin and coal bed methane volumes at .28-1.18 TCF in the Sydney, Stellarton and Cumberland Basins. Other basins may or may not have potential, but very limited data or information exists. Exploration activity is likely to be limited, at least for the next several years, until such time as the moratorium on hydraulic fracturing is reviewed, additional seismic and well data are acquired, and the complexities of developing frontier basins are addressed.

This chapter also lists a number of outstanding questions that could arise should the government decide to pursue the development of onshore oil and gas extraction in Nova Scotia through hydraulic fracturing.

Study page for download at the Nova Scotia government site

After the announcement of major shale gas discoveries in the Liard Basin in 2012, Petrel Robertson Consulting Ltd. (PRCL) commenced a six-month study on behalf of Geoscience BC to study deep subsurface aquifers in support of systematic sourcing and disposal of waters used for unconventional hydrocarbon development.

Relevant well data were collected across aquifer intervals from public and proprietary sources and supplemented with regional geological mapping and information from outcrop. Regional correlations were created by building a grid of regional stratigraphic cross-sections tied to core and sample cuttings data; these formed the basis for picking a stratigraphic database focused on potential aquifer intervals. Hydrogeological characterization was undertaken drawing on a well test database consisting of 256 tests from 157 well entities. Drillstem tests were used to interpret formation permeabilities and reservoir pressures.

Four aquifer intervals were investigated in detail:

• Mississippian platform carbonate rocks comprising the Rundle Group, including the Debolt Formation and the younger Fantasque Formation;
• Mattson Formation sandstone;
• Lower Cretaceous sandstone including chinkeh and Scatter Formations; and,
• Upper Cretaceous Dunvegan Formation sandstone and conglomerage.

Study page for download at Geoscience BC

The study has been undertaken to identify deep saline subsurface aquifers in the Deh Cho territory capable of supplying the large water volumes required for fracture stimulations, and to identify formations which have the capacity to safely accept contaminated drilling and completion fluids.

Subsurface aquifers were defined based upon existing regional mapping, and were characterized using lithological information and borehole log data from petroleum exploration wells. Drillstem test data were used to characterize formation fluids and reservoir quality. Ten aquifer intervals exhibiting substantial reservoir quality, regional extent and lateral continuity were mapped, and local aquifer potential in several other stratigraphic intervals was noted.

This study was undertaken to identify the deep saline subsurface aquifer potential which exists in seven subsurface units in Central Mackenzie Valley; from Lower Devonian Arnica carbonates to conglomerates of the Upper Cretaceous Summit Creek Formation. Specific objectives were: (1) Identify and characterize deep subsurface aquifers capable of supplying the large water volumes required for fracture stimulations supporting shale oil and gas development; and (2) Identify formations which have the capacity to safely accept contaminated drilling and completion fluids.

Mapping and aquifer characterization were based upon regional mapping from various Geological Survey of Canada reports, and specifically upon recent reports by Hogue and Gal (2008) and Hayes (2011). The following specific tasks were completed:

(1) Subsurface stratigraphic units with aquifer potential were identified using existing stratigraphic knowledge. Stratigraphic cross-sections were created for each aquifer to facilitate and illustrate correlations. (2) Potential aquifers were mapped in the subsurface using data from oil and gas wells, including well logs, cores (including quantitative core analysis data), sample cuttings, and well tests. (3) Maps to characterize the aquifers were created, including: gross thickness, net porous reservoir thickness, and reservoir capacity (porosity*thickness). Information from outcrop was also used to constrain mapping. (4) In order to ensure accurate and consistent aquifer characterization, all test and water analysis data were rigorously assigned to specific units within the stratigraphy mapped in this project,. Each well test was reviewed to determine reservoir pressure, fluid content, and permeability. Water analysis data were summarized to characterize water quality and chemistry. And (5) all data were compiled and interpreted to assess the potential for each stratigraphic interval to supply and accept drilling and completion fluids.

Link to download page on the NWT Geoscience website

Whitehorse Trough is a frontier intermontane basin that is prospective for oil and gas from both conventional and unconventional reservoirs. It straddles the Yukon-British Columbia border; the Yukon portion is a triangular-shaped area covering approximately 3.72 million hectares. It features a complexly-deformed sedimentary rock section more than 7000 metres thick, with interbedded and capping volcanic rocks. Since publication of the most recent assessment, by National Energy Board (2001), significant advances have taken place in our understanding of Whitehorse Trough, and of petroleum prospectivity of northern Canada in general.

Hydrocarbon prospectivity in Whitehorse Trough is assigned to nine plays and all nine plays are prospective for gas, and three have oil potential as well. Five plays are conceptual, as sufficient information exists to support estimates of play parameters and potential. The other four are speculative, as we do not have sufficient information to support numerical estimates.

The evidence for presence of both conventional and unconventional hydrocarbons in Whitehorse Trough is compelling, and assessed volumes are sufficiently substantial to support additional exploration and assessment work.

PDF link to Yukon Geological Survey Report (24MB)

This report represents the first systematic attempt to characterize unconventional hydrocarbon resources in Yukon. A review of the essential elements of unconventional accumulations, and a survey of activity in North America and worldwide set the stage for understanding prospectivity of Yukon reservoirs. Eight prospective basins are investigated, using stratigraphic, geochemical, and conventional play assessment information generated to guide conventional exploration. Because their geological histories are so varied, the basins offer a wide range of prospectivity for coals, tight reservoirs, and shales. Further work, primarily drilling and focused sampling and testing, is recommended for plays with the highest potential.

Considering current gas market conditions and distance from facilities and markets, Yukon is truly a frontier jurisdiction. However, a number of plays offer liquids potential, which is critical to economic success. As well, opportunities exist to acquire large land positions in highly prospective plays – opportunities that are becoming very scarce in more developed basins of North America.

PDF link to Yukon Geological Survey Report (29MB)

In late 2010, Petrel Robertson Consulting Ltd. was contracted by Natural Resources Canada to undertake a quantitative petrophysical assessment of the petroleum exploration wells drilled in the Eagle Plain Basin of the Yukon Territory. The purpose of the assessment was to highlight prospective conventional hydrocarbon accumulations, and generate input for use in future resource assessments.

The data necessary to undertake the assessment were provided by Natural Resources Canada, the Yukon Geological Survey and public data repositories. Thirty-one of the 34 wells drilled in the Eagle Plain Basin were deemed to have sufficient data to perform a meaningful analysis, and were subsequently interpreted with a consistent methodology and set of input parameters. Average values of shale volume, porosity, permeability and saturation were generated.

Based on three sets of cutoff criteria, determined in consultation with staff of the Yukon Geological Survey, reservoir and pay intervals were identified. The results support concluding that hydrocarbons were intersected in 19 discrete stratigraphic intervals, in 29 of the 34 wells drilled.

Link to project information on the YGS website

This report assembles available outcrop and subsurface data to systematically assess, at a very regional level, shale gas and oil potential in the NWT. Analytical work and production information from equivalent shales in other areas, particularly in adjacent NEBC, provide valuable insights in support of this analysis. Two study areas, based on stratigraphy and well control density, were defined: the southern Liard – Great Slave Study Area, and the northern Peel – Mackenzie Study Area. In Liard – Great Slave, good shale gas and oil potential is seen in the Devonian Muskwa-Horn River, Devonian/Mississippian Exshaw Formation, and Cretaceous Fort St. John Group. Other thick shales, such as the Fort Simpson, Kotcho, and Banff, do not contain sufficient organic material to present attractive targets. In Peel – Mackenzie, the Devonian Horn River Group and parts of the Cretaceous Slater River Formation are prospective for shale gas and oil, while the Imperial and Arctic Red shales are organic-lean, and thus less prospective.

Link to download page on the NWT Geoscience website

Deep subsurface aquifers carrying saline waters are ideal sources and sinks for the water volumes required. Following upon successful completion of the Horn River Basin Deep Subsurface Aquifer Characterization Project, Geoscience BC commissioned Petrel Robertson Consulting Ltd. and Canadian Discovery Ltd. to undertake a similar study of deep saline aquifers in the Montney play fairway, as a component of the regional Montney Water Project. To date, operators in the Montney play have not made systematic use of deep subsurface water source or disposal capacity.

The fairway was divided into Plains and Foothills study areas, based primarily on subsurface stratigraphic and structural aspects. In the Plains, potential aquifers ranging from Middle Triassic Halfway to Upper Cretaceous Cardium were assessed. The best aquifer characteristics – thick net porous sandstones, high storativity, good to excellent potential deliverability, moderate to low salinities, and little or no H2S – were found in the Cadomin and Nikanassin aquifers. The Baldonnel, Bluesky, and Peace River formations offer more modest aquifer characteristics, but may still have local importance.

In the Foothills, potential aquifers range from the Mississippian Debolt to the Lower Cretaceous Bluesky; younger Cretaceous strata have shaled out in this area. In general, more extensive diagenetic degradation has reduced aquifer quality in the sandstone reservoirs, compared to the Plains Study Area. Aquifer quality in Debolt and Baldonnel carbonates is difficult to assess from logs, but test data indicate variable aquifer quality, with waters of moderate salinity and some H2S present. Foothills drilling and gas production are focused on the crests of regional northwest-southeast structural (anticlinal) trends, so there are insufficient data to adequately characterize aquifer quality off-trend.

Key observations arising from the project include:

(1) Deep subsurface aquifers with sufficient quality to support Montney water requirements are distributed unevenly across the play fairway; (2) The northern Plains Study Area contains substantial stacked aquifer potential, while there is much less potential in the southern Plains area, where a Deep Basin (gas-saturated) regime occurs in many of the units; (3) Good aquifer potential is present only in the southeastern Foothills area. More detailed work is required to determine whether gas production along regional anticlinal trends can be linked to fracturing, and whether such fractured reservoirs are capable of water production outside of established pool areas.

Link to project information on the Geoscience BC website

This report represents the first systematic attempt to characterize unconventional gas resources of the NWT. Although the area is lightly explored, an abundance of stratigraphic, geochemical, and conventional play assessment data, combined with analogue information from producing and prospective unconventional gas reservoirs elsewhere, have enabled the identification of prospective unconventional resources. Three categories of unconventional gas are addressed: coalbed methane (CBM), tight (low-permeability) gas, and shale gas. Gas hydrates were not addressed in this study. As well, the potential for unconventional gas in the Mackenzie Delta was not considered, as unconventional gas development techniques, particularly dense well spacing, are not considered feasible in this remote and expensive area.

This report comprises the assessment, and addresses the following:

• A general overview of unconventional gas resources and their definitions;
• A discussion of applicable analogues, and a listing of key references from the literature for unconventional gas resources in other jurisdictions;
• An overview of NWT petroleum geology as it relates to unconventional natural gas resources, including: shale gas, tight gas, and coalbed methane. Methane gas hydrates are not addressed in this study. The characteristics of each unconventional gas resource type are discussed, and the potential for their occurrence within the NWT Phanerozoic succession is evaluated. Unconventional gas potential of the Mackenzie Delta was not considered, as unconventional gas development invariably requires dense well spacing, which is not feasible in this very remote and expensive environment;
• Recommendations for future geoscientific research related to NWT unconventional gas resources; and
• Additional relevant data and recommendations.

Link to download page on the NWT Geoscience website

Stratigraphic mapping and reservoir characterization were supported by interpretation of well logs, cores, sample cuttings, and well test data. The Horn River Basin well database comprises all available wells penetrating the pre-Cretaceous unconformity in the study area, 556 in total, including 43 wells confidential at the time of the study, but released to the study group by Horn River Basin Producers Group (HRBPG) members.

To establish a stratigraphic framework, 16 regional cross-sections were built. Correlations were established from the literature and previous studies, and were calibrated with observations from cores and sample cuttings. Logs from each well were tied to the cross-section grid to interpret stratigraphic tops, which were entered into a master stratigraphic database.

Cores were logged from 60 wells and all cores that appeared to provide significant reservoir or stratigraphic information were examined, omitting only a few short carbonate cores to the east and several Cretaceous sand/shale cores to the west.

Very few cores were cut in Mississippian carbonates within the Horn River Basin proper, and there is essentially no representation of the uppermost carbonate sections, which appear to have the best reservoir potential. Core coverage of Mattson reservoirs to the west is similarly scanty. A project was therefore commissioned, to systematically examine and document drill cuttings from Mississippian carbonates throughout the HRB, and from Mattson sandstone sections near HRBPG lands in the west. Sixty-three (63) wells were identified for the study by Producer Group members. John Clow (JC Consulting Inc.) examined cuttings across the prospective section in each, and performed semi-quantitative estimates of reservoir porosity and permeability. Jim Stepic (JMS Geological Consulting) prepared samples for standard petrography, SEM imaging, and XRD analysis, to provide additional reservoir characterization information.

Canadian Discovery Ltd. compiled well test data from public formation pressure and water chemistry databases, and also incorporated proprietary pressure, chemistry, and deliverability data provided by members of the HRBPG. Data were screened to ensure their validity, and hydraulic head, pressure over depth, available head, formation water chemistry, H2S chemistry, and resource volumes maps were created.

Permeability analyses were also completed, and used to estimate well deliverabilities.

Incorporating all these data and interpretations, PRCL produced regional maps of key stratigraphic surfaces and intervals throughout the aquifer section. Core and sample data were tied to logs to estimate reservoir quality, which was also systematically mapped. Finally, reservoir maps were combined with hydrogeological interpretations to generate a basin-scale aquifer characterization of each key unit.

Link to project information on the Geoscience BC website

A huge tight gas resource base exists within the Alberta Deep Basin, the development of which has been greatly aided by the creation of Development Entity #2 (also known as the Deep Basin Development Entity, or DBDE). The DBDE was designed in 2006 by a cooperative effort between the Alberta Energy Resources Conservation Board and industry partners, with geological support from Petrel Robertson Consulting Ltd. It was expanded in 2009, and now encompasses 464 townships in west-central Alberta.

In this review, we summarize the geological setting of each productive or potentially productive stratigraphic unit, using existing literature and internal PRCL reports. Reservoir units are reviewed in stratigraphic order (oldest to youngest). Results are presented as situation maps, in which production, tests, and key geological trends and controls are illustrated. Reservoir geology is illustrated by a type well log and graphic core logs; some of these are repeated from PRCL’s 2005 study “Geological Review of Cretaceous Reservoirs, B.C. Deep Basin, Applied to Gas Production Commingling Strategies”, while others specific to the Foothills have been added.

Fracturing of reservoirs arising from structural deformation is a key component of reservoir quality in the Foothills. We review briefly the genesis and importance of fracturing in Cretaceous reservoirs, with reference to structural / fractured reservoir trends currently producing in the N.E.B.C. Foothills.

Our final discussion of current multizone production / commingling practices, and geological / reservoir factors to be considered in future commingling, builds upon both stratigraphic and structural / fractured reservoir controls.

The Play Atlas was developed to provide a framework for the assessment process and will provide a reference point for future analyses. The Play Atlas contains both established and conceptual plays and also contains some plays that could arguably be identified as unconventional. A broad definition of “conventional gas resources” was used and play definitions generally include the spectrum of resources that have been traditionally exploited in BC’s portion of the Western Canadian Sedimentary Basin (WCSB), and are considered proven and developable with today’s [2005] technology. Unconventional Resources were deemed to be those resources that are generally not economic nor productive by today’s technology or those that exist as unproven geological concepts. Examples include coalbed gas (CBG),some tight gas, shale gas and gas hydrates. Although unconventional CBG and shale gas resources are now contributing significantly to U.S. production stream they are for the most part currently unproven in NEBC.

From the BC Ministry of Energy, Mines and Natural Gas website.

Part 1 Part 2  Part 3

In this review, the geological setting of each productive or potentially productive stratigraphic unit is summarized, using existing literature and internal PRCL reports. Results are presented as situation maps in which production, tests, and key geological trends and controls are illustrated.

Reservoir units are reviewed in stratigraphic order (oldest to youngest). For each unit, a situation map summarizes regional geology and production, while reservoir geology is illustrated by a type well log, type core log, and (in some cases) a stratigraphic cross-section.

This study reviews the Lower to Middle Devonian stratigraphic framework of northeastern B.C., and illustrates key units with a grid of regional cross-sections and gross isopach and porosity maps. This information is used to interpret depositional environments and to reconstruct regional paleogeography for each of the four major producing units.

We have identified regional networks of southwest-northeast and northwest-southeast faults, in addition to the Bovie Lake Fault Zone in the northwest and the Hay River Fault Zone in the southeast.

The most exciting potential occurs in the deep Plains and outer Foothills to the west, where westerly platform edges and potential reefal buildups offer deep, highly-pressured, unexploited reservoir trends. Platform embayments in the Slave Point and Keg River are also highly prospective, with the 2000 Ladyfern discovery being an excellent example of the potential rewards.

Geological Survey of Canada and Canadian Gas Potential Committee assessments of remaining gas potential in the Devonian of northeastern B.C. range from 6.7 to 10.2 TCF. We project that even more gas potential exists, and will be realized with the drilling of new exploratory trends.

Link to study on the BC Ministry of Energy, Mines and Natural Gas website.

The intermontane basins of British Columbia and the Yukon represent some of the best unconventional petroleum prospectivity in Canada today. This study summarizes the petroleum prospectivity of the Nechako Basin of south-central British Columbia. Information gained from exploratory wells, limited seismic and gravity work, and extensive surface mapping is sufficient to suggest that very large gas and oil resources may be found within the Nechako Basin.