Petroleum is typically found deep underground in small, connected pores or microfractures within sandstone or limestone. Such connectivity allows fluid to flow, giving the rock an inherent permeability. Carbon dioxide may similarly be pumped through and stored in the pore space (physical trapping). Petroleum remains in the subsurface permeable rock (reservoir) because the composition and geometry of the overlying rock have provided a long-term barrier (seal) to the upward flow of the petroleum, thus trapping the buoyant fluid at depth. The seal rock has either fractures or pores that are too small and disconnected for fluids to flow through (e.g., shale), or it lacks such spaces altogether (e.g., rock-salt). The effectiveness of a seal is dependent on the fluid present. Fractures that might be too small for large molecules of oil to pass through may be large enough to allow seepage of natural gas (methane) molecules. Carbon dioxide has a kinetic diameter even smaller than methane and so a rock might be impermeable to methane, but permeable to CO₂.

Injecting CO₂ under pressure can increase pressures in a petroleum reservoir, allowing more petroleum to be extracted. Some CO₂ can also be absorbed into the oil (Perez et al. 2006), essentially making it less viscous and improving its flow to the well-bore (Emberley et al. 2005). The extra oil produced, however, also brings the CO₂ back to the surface. The most widely reported trial and monitoring of such CO₂ injection is at the Weyburn oil field in Saskatchewan where over 18 Mt have already been stored under the 500 km² test area (Wildgust et al. 2013). The cost of piping the waste CO₂ from a power plant is being offset by an estimated additional 155 million barrels of oil produced at the field (Emberley et al. 2005). Note that this much oil, burnt as fuel, will itself produce over 40 Mt CO₂. The stored CO₂ eventually would be distributed between a dissolved phase in formation waters (“solubility” trapping) and, particularly if silicate mineral assemblages are present in the storage rock, precipitation of new carbonate-bearing mineral phases within the pores (“mineral” trapping) (Gunter et al. 2000).

Seams of coal can contain large amounts of methane-rich gas adsorbed onto the surface of small but often regular fractures (cleats) in the coal. Injecting CO₂ can cause the methane (natural gas) to be displaced with the CO₂ being left behind, locked by adsorption, onto the coal (White et al. 2005). Methane is also a much cleaner-burning fuel than the coal that might otherwise be mined. Shale also commonly contains organic matter (oil shale in particular) that may similarly act as an adsorption substrate for CO₂ storage. However, the networks of small fractures in these rocks are much more variable in interconnectedness and abundance than in coal seams, and the pore spaces much smaller than in sandstone. Most shale (likewise igneous and metamorphic rock) therefore has negligible permeability, which would limit the injection of CO₂ at any meaningful rate. Artificial means of fracturing (fracking) in the subsurface are an increasingly common method adopted by the petroleum industry to increase permeability in oil and gas reservoirs, but would further add to costs.

Many geologic formations contain pores that are filled not with oil or gas, but instead with connate (saline/ alkaline) water. Such salty water (>10 000 mg/L total dissolved solids) is of no use for drinking or agriculture. Carbon dioxide may therefore be pumped down into these formations if they are not in hydraulic connectivity with potable groundwater aquifers. Increased pore pressures and lowered alkalinity can result, and it is unclear how this might affect the integrity of the formation and whether the dissolved phase or the supercritical phase may escape. Unlike the preceding two types of geological formation, injection into saline aquifers produces no commercial by- product and so would be more costly to implement.

Large Final Emitters (LFEs) are stationary facilities emitting more than 100 000 tonnes (0.1 Mt) of CO₂/year, as reported to the Greenhouse Gas Division of Environment

Canada under the mandatory GHG Emissions Reporting Program introduced by the Government of Canada in March 2004 (see Fig. 1). Facilities emitting less than 0.1 Mt, and those whose emissions are distributed over a wide area, such as pipeline systems and major airports, are not considered as potential CO₂ capture sites because the economics of capture would not be viable.

Major costs that have to be assessed when considering capture and storage include transporting the captured gas by pipeline to the underground storage site (e.g., land procurement, pipe manufacture and installation, pressure booster stations, etc.). The greater the total CO₂ emissions, the more economical pipeline transport becomes per kilometre distance. The Technical Committee has suggested a ballpark figure of 500 km as the maximum distance above which CO₂ transport costs become prohibitive. A concentration of major LFEs contributing to one large pipeline that was constructed across flat grasslands can extend this distance; steep mountains and valleys, or lakes, estuaries and oceans that have to be crossed would reduce this distance. Since the distance across New Brunswick in any direction never exceeds ~425 km, and the topography is nowhere severe, this logistical factor is not a detrimental issue.

Climate plays a role in the logistics equation in that extreme conditions also tend to increase transport costs. Permanently frozen ground (permafrost) of arctic and sub- arctic zones prohibit burial of pipe. Hot, humid conditions can promote corrosion. Th e relatively temperate climate across all of New Brunswick is not a barrier to carbon transport.

The density of an onshore transport network (in particular, permanent roads) plays a role in the logistical equation, because pipeline routes have to be accessed for excavation and maintenance. Building and upkeep of dedicated roads for pipeline access are a significant expense that can be avoided if existing rights-of-way can be used. The expense, if necessary, is highly variable, depending on topography (steep slopes, expanses of floodplain and marsh, etc.), climate (duration of frozen ground), vegetation, and foundation (soil or bedrock). Good transport networks generally equate to workforce availability and existing industrial base, since the networks usually link larger settlements and urban areas. However, only very general guidelines have been adopted by the Technical Committee.

In New Brunswick, most of the central and northern parts of the province have only a few permanent transport routes and only small settlements. The St. Stephen – Saint John – Sussex – Moncton corridor, the north and east coasts, and Saint John River valley provide the greatest employment opportunities, existing industrial base, and transport links.

The expense of building and maintaining pipeline increases when the pipeline has to be submerged. The expense also increases with distance from shoreline, since technology, though expensive, can now allow near-to-shore subaqueous sites to be accessed from onshore via directional drilling of inclined and horizontal wells out beyond the coastline. Expense also increases with increasing water depth as larger, more costly, offshore drilling rigs must be used.

The offshore extent of New Brunswick’s jurisdiction in the Gulf of St. Lawrence is uncertain, since there are boundary disputes with, and between neighbouring provinces. Regardless, Gulf and Straits waters remain shallow for several tens of kilometres offshore, well beyond potential boundaries. Similarly for the Bay of Fundy, most waters remain relatively shallow (<60 m) out beyond potential boundaries. In terms of infrastructure, no permanent offshore rigs exist in New Brunswick waters, but for both offshore areas, there are ice-free deep water ports from which offshore installations could be serviced.

The pressurized transport, pumping, and storage of gases underground are regulated by government acts. For onshore New Brunswick, legislation exists in the form of the Underground Storage Act of 1978. However, it is unclear if the wording covers very long term storage and may need revision for carbon storage. Legislation for offshore beyond the coastline is further complicated by provincial disputes as to the location of provincial boundaries in the Gulf of St. Lawrence, and uncertainties as to whether joint federal- provincial governance is required in the New Brunswick portion of the Bay of Fundy.

Exploration for fossil fuels typically involves the drilling of deep subsurface boreholes (beneath the zone of potable drinking water, and the depth of groundwater drinking wells), and thus potentially close to depths where carbon storage may be attempted. Also, since there is the potential to encounter combustible fluids, such drilling is highly regulated and monitored, resulting in considerable amounts of subsurface information being collected and stored (in contrast to most metallic-mineral exploration boreholes, where limited data are collected). This subsurface data typically include information regarding the rock and fluid present and often information on the physical state of the subsurface, such as temperature and pressure. Such fossil fuel exploration data provide the basis for assessment and rating of geological criteria that are discussed in the following sections. The drilling of boreholes usually follows the assessment of geophysical properties of the subsurface, such as seismic, the collection of which also provides important geological information.

In areas where there has been no coal, oil, or natural gas exploration, there is a lack of subsurface data from which a geological assessment of storage capabilities can be made. In these situations, attempting carbon storage would be highly speculative: potentially high expense without any creditable expectation of success. In places where there have been no successful petroleum finds, or where only a few oil and gas wells have been sunk, the subsurface data remain limited and, typically, localized. Where oil and gas fields have already been in production, widespread, more regularly spaced, subsurface data exist. Potentially, the economic life of wells near exhaustion might be extended by injection of CO₂, thus offering an economic offset in storage costs.

Fossil fuel exploration in New Brunswick has mostly been confined to a belt running from Sussex to southeast of Moncton (Fig. 1) where a limited number of oil and gas fields are in production. More limited exploration, without success, has been attempted in the Bay of Fundy. Information from elsewhere is mostly lacking. Coal has also been mined in central New Brunswick, around Minto.

This criterion relates to whether the sedimentary rock present can act as a seal, or a reservoir (storage). Evaporite rock, such as gypsum, anhydrite, and rock salt are non- porous (no storage potential), but do provide a highly impermeable barrier (seal) to the migration of subsurface fluids. Fine grained clastic rock (mudstone, claystone) most commonly also acts as an impermeable barrier. The more fissile equivalent, shale, is usually a seal but may be fractured on the microscopic scale and act as a fluid store (the fracturing may even be engineered). Coal is similarly a potential storage rock when microfractured. Sandstone and, to a lesser extent, carbonate rock (limestone, dolomite) are the typical reservoir rock types and thus the major storage targets. Sedimentary basins in which only shale and evaporite are identified would not be suitable because of the lack of a storage rock, those primarily of sandstone would lack an effective seal. Non-sedimentary rocks, typically (igneous) rocks crystallized from lava flows, may also be interlayered with sedimentary rocks in a basin and act as an impermeable barrier.

The Matapédia Basin Complex and the Fredericton Belt contain both seal (shale) and reservoir (sandstone, limestone) rocks, although commonly these have undergone some degree of metamorphism (Carroll 2003), so reservoir porosity may be lacking. In the Maritimes Basin Complex, the strata are predominantly of sandstone (reservoir), conglomerate, siltstone, mudstone, and shale (seal), locally abundant evaporite (seal), thin limestone, occasionally mineable coal seams (reservoir), and rare basalt (seal). In the Moncton Basin, rocks assigned to the Albert Formation (Horton Group, Mississippian) host the only known petroleum system in onshore Maritime Canada. As such, this Basin has been the focus of most of the fossil-fuel exploration in the province and has by far the most sub-surface information available. Incorporating outcrops on the Nova Scotia side of the Bay of Fundy, the Fundy Basin Complex is known to contain predominantly siltstone, mudstone, some conglomerate and shale (all seal), locally abundant sandstone (reservoir) plus a considerable thickness of basalt (seal).

The surface area is a general two-dimensional representation of the scale of a basin that might reasonably be considered to hold a commercially viable amount of CO₂. A successful storage area might have a surface footprint equivalent to as little as 1000 km² (the approximate surface extent of the Weyburn Field in Saskatchewan). However, an entire basin with such a limited surface area in most cases would not have sufficient volume at depth simply because of basic basin geometry and the thickness of highly porous reservoir rock (and impermeable cap-rock) that would need to be present in the suitable depth window. These constraints need not apply once the surface area of the (sub-) basin exceeds the minimum cut-off of ~5000 km², provided that the other criteria are supportive. Basins with significantly larger surface area (e.g., >25 000 km²) would be most suitable, for they could provide several storage targets in the same vicinity so that, once one storage target is filled, a nearby target could be accessed with minimal additional logistical cost.

The Restigouche, Victoria and York, Saint John, Charlotte and Grand Manan sub-basins each cover a surface area of <1000 km² , and so could only ever be considered as potential satellite sites to larger storage options that might be found in the Matapédia or Fundy basin complexes. The Sackville sub-basin is of similar size, and the Cocagne Graben is <2000 km² in size. These two could be potential satellites to options in the Maritimes Basin Complex. The three Matapédia belts, the New Brunswick Platform, Moncton Basin, and Fundy sub-basin are of sufficient areal extent, and also extend into adjacent jurisdictions (Fig. 2), potentially allowing for storage collaborations with other governments.

The presence of a shallow basement (metasedimentary rock of an earlier basin or non-sedimentary rock) makes an area unsuitable for CO₂ storage. For CO₂ to be supercritical requires depths of 800 to 900 m under normal pressure- temperature gradients. Displacement of methane in the fractures of non-mineable coal requires depths of over 600 m. If a basin is over 1 km deep, it has obvious potential for both absorption on coal and supercritical fluid storage. This criterion can be directly measured in regions where boreholes have drilled through to basement. Elsewhere, depending on the forces active in forming the basin, depth may be estimated from summation of the vertical thickness of component sedimentary layers at the surface, geophysical analyses, or borehole information.

In the Matapédia belts, seismic data are lacking and only one 200 m borehole (Notre Dame de Lourdes, Fig. 4) has been drilled in New Brunswick, although the correlative rocks in Québec host the Galt and Haldimand oil fields at ~1.5 km depth on the eastern Gaspé Peninsula (Fig. 2). Carroll (2003) has calculated that over 12 km of tilted strata may be present to the west of Campbellton. In the Restigouche, Victoria and York sub-basins, no subsurface data are available and, based on surface structural relationships (e.g., Smith and Fyffe 2006a, b), the rocks are unlikely to extend over 0.6 km deep. For the Saint John and Charlotte sub-basins, no onshore seismic or borehole data exist. These basins may continue offshore, faulted down below strata of the Fundy Basin Complex but this is based only on marine seismic interpretations (Wade et al. 1996). The remaining basins, from boreholes, gravity maps, and seismic, are known to extend >1 km deep over wide areas (e.g., Gussow 1953; Martel 1987; Wade et al. 1996; Waldron and Rygel 2005; Wilson and White 2006). However, throughout the Maritimes Basin Complex, and particularly in the New Brunswick Platform, several boreholes have also encountered faulted and uplifted blocks of basement rock at depths of <500 m (e.g., Coal Branch #1 borehole, ~50 km ENE of Minto; Cape Bald #1 borehole penetrating the Westmorland Uplift, east of Moncton, St. Peter and Johnson 2009; Fig. 4).

This is another indicator of the depth at which CO₂ will behave as a supercritical fluid. Measured in the subsurface either via a mineshaft or borehole, low temperature gradients (<30°C/km = cold basins) require deeper storage for the CO₂ to be in a supercritical state than where the temperature gradient is steeper (>40°C/km = warm basins).

Unpublished data from the McCully gas field in the Moncton Basin (New Brunswick Department of Energy and Mines, borehole files) indicate that the basin is cold and this likely is also the case for all the other basins onshore. Similarly for the Fundy Basin Complex, unpublished data indicate a maximum geothermal gradient of only 24.4°C/km.

This is an indicator of the maximum temperature (proxy for depth) to which the rock has ever been buried. High temperatures (>225°C) and burial depth usually indicate more pore spaces have been filled by mineral cements, leaving a lower quality reservoir for storage. Similarly, the onset of metamorphic processes and cleavage development indicates high temperature and pressure and thus limited remnant porosity. The maximum temperature for oil generation is ~175°C; above which only natural-gas fields would be available to maintain pressure regimes. Maximum burial values can be calculated at the surface by looking at how “cooked” any contained fossil plant material (vitrinite) appears (Fig. 3). If rocks now uplifted back to the surface have previously been buried to a particular depth (temperature), underlying rocks in the subsurface should have been at least as hot.

Detailed vitrinite reflectance data have been presented for parts of the Matapédia and Maritimes basin complexes (Fig. 3) by St. Peter and MacIntosh (2005) and Lavoie et al. (2009). Data only exist for the northeastern third of the Matapédia Basin Complex and most surface rocks are thermally overmature. Only in the Tobique – Chaleur Belt, and specifically limited to the small area east and west of Campbellton, do vitrinite data suggest the rocks at the surface have only been buried down into the oil or condensate window, i.e., vitrinite reflectance, Ro, <2.0% = <200°C. In the New Brunswick Platform, data indicate an east to west trend of increasing thermal maturity, from the upper oil window (0.6% Ro) to the upper gas window (1.5%), with only the far southwestern corner potentially overcooked and unsuitable, with surface rock having been at >2.0% Ro. In the Cocagne Graben, Moncton Basin and Sackville sub-basin, surface vitrinite values are mostly in the oil and gas window, although there are anomalous locations along the basins’ mutual boundaries (the Berry Mills fault system including the Indian Mountain Deformed Zone, and the Caledonia – Dorchester fault system, Fig. 3) where higher values are recorded. Data from the two boreholes drilled in the Fundy Sub-basin indicate vitrinite reflectance of around 0.5, and 0.8 close to the base of the drilled sections (~3 km depth).

Carroll (2003) observed graphitic slate in the Aroostook – Percé Belt and widespread cleavage in the Connecticut Valley – Gaspé Belt, which support the high vitrinite data for the Matapédia Basin Complex and indicate that little porous storage rock will exist at depth. Cropping out along much of the southwestern and western margin of the New Brunswick Platform are additional Silurian strata assigned to the Fredericton Belt (Fig. 3). These rocks, likely continuous below at least the western half of the New Brunswick Platform, are also sedimentary in origin. However, they are not discussed in detail in this report because they widely display metasedimentary features such as cleavage (e.g., Park and Whitehead 2003), and can be considered the local basement. In the Cocagne Graben outcrop, Horton Group rocks locally also exhibit slight cleavage in the Indian Mountain Deformed Zone (Park and St. Peter 2008).

The presence of a large number of faults in an area, if sealed, would result in greater compartmentalization of the storage reservoir. More drilling would be required in order to penetrate the large number of small storage compartments that would need to be filled separately. Conversely, there is the possibility that some of the faults might not be sealed, which could lead to leakage of the stored gas if a fault cut through the cap rock or the fault formed part of the (supposed) seal. Basins that have been subject to a greater number of tectonic episodes, or deformation events, are typically more extensively faulted and thus less suited for storage.

Several deformation events are identified in the Matapédia Basin Complex (e.g., Wilson and Kamo 2012) and based on bedrock geological maps and reports, folding and faulting is inferred to be extensive. Similarly, the Maritimes Basin Complex has undergone numerous deformation events but most were intermittent with sedimentation in the basin (Wilson and White 2006; Park et al. 2007). Accordingly, Horton Group strata at the base of the Mississippian succession may have been subject to four or more deformational events (Park et al. 2007; Park and St. Peter 2008) whereas latest Pennsylvanian strata, widespread across the New Brunswick Platform, are mostly undeformed (e.g., St. Peter 2005; Smith and Fyffe 2006c). Early Pennsylvanian tectonics involved the formation of salt walls and diapirs in the Moncton and Sackville basins (Waldron and Rygel 2005; Wilson and White 2006). Seismic data from the Fundy Basin Complex indicate that faulting is relatively sparse (e.g., Wade et al. 1996) and primarily related to basin-bounding faults that have undergone only one phase of mostly extensional movement.

Movements on faults that cross a basin (earthquakes) would be a problem for pumping and storage infrastructure located at the surface, as well as posing a concern for storage reservoir integrity if the fault formed part of, or cut through what might be considered the seal of a saline reservoir. An historical earthquake record for the province has been documented by Burke (2009) and Natural Resources Canada (2010) has issued a national earthquake hazard map that includes New Brunswick (Fig. 3).

The hazard map indicates that most of the province has an acceptable moderate to moderately low risk of a major (>6 magnitude) earthquake. However, the risk south of St Stephen is rated moderately high, being close to a documented 5.9 earthquake epicentre (Burke 2009).

Properties of subsurface strata in the Platform are known from numerous boreholes, but supplemented by only a few seismic lines (Fig. 1). Several of these boreholes reached basement at less than 250 m depth, indicating that large portions of this region are unsuitable for storage. The strata offshore are known only by extrapolation downdip from the onshore, and from one borehole offshore Québec in the vicinity of New Brunswick’s jurisdiction (Bradelle L-49, Fig. 2). No boreholes have been drilled in New Brunswick waters.

Subsurface strata in the Moncton Basin (and to a lesser extent the potential satellite areas in the Cocagne Graben and Sackville sub-basin of the Maritimes Basin Complex) are the best understood in the province. There is both extensive seismic and borehole information available (Fig. 1) because the Basin hosts the only known petroleum system onshore Maritime Canada, and has been the focus of petroleum exploration (e.g., Stoney Creek Oil and Gas Field, McCully Gas Field, Fig. 4). The petroleum is present in the Albert Formation (Horton Group), which lies near the base of the Mississippian stratal succession. There is only sparse seismic offshore in the Northumberland Strait, but data also can be extrapolated from onshore PEI (e.g., Irishtown #1, Spring Valley, Fig. 2).

Subsurface strata in the Bay of Fundy are of Mesozoic age and form part of the Fundy Basin Complex. Neither coal nor petroleum has been encountered to date, and so the only targets are saline reservoirs. Although there is broad seismic coverage, borehole information is limited to two wells (Figs. 1, 5, 6).