Rock-Eval was originally designed for measuring the maturity of coal mackerel [5] [48] . It is a useful screening technique for recognizing source rock and kerogen quality, and has become a major oil and gas exploration tool that give insights to the exploration geologist in terms of source rock characteristics, and reservoir potential. The key parameters of Rock-Eval (TOC, Tmax, HI, OI, PI and S2 values) are fundamental to determining source rock richness, kerogen type, and maturation, which altogether form critical elements in the assessment of a petroleum system, risks segments and high grading resource plays.

The TOC content of a rock is determined by oxidation under air, in an oven from the organic carbon residue after pyrolysis [46] . The measured TOC values for the Montney Formation are shown in Tables 1-3. The geographical distribution of average TOC per well is shown in the study area in Figure 7. The general trend of TOC is low in the western part of study area, and TOC value increases eastwards into Alberta Province (Figure 7). TOC in the Montney Formation is variably and statistically grouped into low TOC (<1.5 wt%), medium TOC (1.5 - 3.5wt%), and high TOC (>3.5 wt%).

TOC is an indicator of the total amount of organic matter present in the sedi-

ment [49] . The standard criteria for ranking source-rock richness (Table 4) was proposed by [50] . The hydrocarbon generating potential is commonly interpreted using a semi quantitative scale (Table 3) according to [51] [52] . The Montney Formation TOC richness and distribution within the study area may be related to factors such as: 1) depositional condition of organic matter, its concentration and preservation, including oxygen content of the water column and sediment type, i.e. oxic versus anoxic as proposed by [50] [53] [54] ; 2) biological productivity influence and availability of nutrient and replenishment [50] [54] ), controlled by sunlight, temperature, pH and Eh of waters [52] . Within the study area, the depositional environment interpreted for the Montney Formation is generally an offshore setting (inner shelf-proximal offshore to distal environment). The environment of deposition affects organic matter productivity and preservation [50] [53] [55] .

Organic matter is preserved in oxygen-restricted environment at depths below wave base in waters where density or temperature stratified water columns form, or in locations where oxygen replenishment is low [53] [62] .

It is hypothesize herein that the TOC distribution in the study area (Figure 7) may be related to depositional environment’s proximity to organic matter source and preservation conditions. Where TOC values are greater than 2.4 wt% around Fort St. John (in a NW-SE transverse trending contour value 2) and

east of that contour boundary (Figure 7), TOC values increases eastwards into Alberta where [13] have reported TOC for the Montney Formation >4 wt% (Table 3). TOC data from well 16-17-83-25W6, provided by Oil and Gas Commission, Ministry of Energy, British Columbia, which is located outside of this study area also shows TOC upto 8.2wt% in Montney Formation (Table 2). In the western portion of study area (west of the boundary contour value 2 in Figure 7), the TOC values are generally lower. In the eastern portion where there is higher TOC value, the area lies within the region that has been interpreted as outer shelf depositional setting. Relatively higher TOC value in this geographical region (eastwards) is probably due to increase oxidation, while reducing condition may have dominated the western portion in the study area where TOC is low in a distal/deep basinal setting. Several workers [11] [50] [53] [54] [55] [57] have reported that high TOC content or richness in sediments are related to the depositional environment, transport of organic matter and preservation. The abundant supply of nutrient and upwelling condition may have dominated the region with higher TOC values in the NE-SE portion of the study area (Figure 7).

Determination of the original total organic carbon (TOC) of a source rock provides a quantitative means to estimate the total volume of hydrocarbons that it can generate depending on kerogen type [58] . However, it is common practice to rate carbonate rocks with lower TOC comparable with richer clastic rock [48] . Extractable Hydrocarbon yields from leaner carbonate rocks are comparable to richer clastic rocks [45] [59] . The organic matter associated with carbonate rocks are often more hydrogen-rich and thermally labile than that in fine-grained clastic rocks [1] [44] [47] . The Montney Formation is partly dolomitic and has variable TOC contents ranging from poor to excellent using the standard TOC richness metrics (Table 4). The low TOC content in Montney Formation in the study area may be related to the mixed siliciclastic-dolomite composition.

The Oxygen Index (OI) measure in mgCO₂/gTOC is calculated from the amount of CO₂ released and trapped at temperature ranging from 300˚C to 390˚C (Figure 6) during pyrolysis [46] . The Oxygen Index corresponds to the quantity of carbon dioxide from S3 peak (Figure 6) relative to the TOC (mgCO₂/gTOC); while Hydrogen Index (HI) corresponds to the quantity of pyrolyzable organic compounds or “hydrocarbons” (HC) from S2 peak relative to the total organic carbon (TOC) according to [11] . The hydrogen index (HI) was calculated from the ratio of S2/TOC using the method of [47] .

In the Montney Formation samples analyzed in this study, which shows that the HI is statistically distributed into three categories in the order of highest percentile: low HI values (0 - 150); medium values (150 - 300); and high values (300 - 900). Of these categories, ~88% of the values are within the low HI values, while about 10% falls into the category of medium values; 2% are of the high values bracket. The OI values are very low (Figure 8), mostly less than 160 and a couple of data point have exceptionally high HI and OI, which maybe outlier (Figure 8).

The Hydrogen (HI) and Oxygen (OI) indices are used to determine the type of kerogen (Table 5) present in a source-rock [11] [46] [47] [85] . Based on the data plot of HI and TOC on the pseudo Van Kravelen diagram, it shows that the Montney Formation in the study area is primarily a Type III/IV kerogen with some mixed Type II/III kerogen (Figure 8-10, Table 6). For organic matter to generate hydrocarbons, the carbon has to be associated with hydrogen [12] ). [1] [45] [48] define kerogen as a polymeric organic material from which hydrocar- bons are produced with increasing burial and temperature. Kerogen is composed of the remains of algae, spores, pollen, and vegetative tissues and they are the same groups of maceral found in coals: liptinite,vitrinite, and inertinite [11] [45] [48] [50] [55] .

Kerogen is mainly classified into three types: Type I, Type II, Type III, [1] [45] and Type IV [53] . Kerogen types are defined on the basis of hydrogen/carbon (H/C) and oxygen/carbon (O/C) values, i.e., Hydrogen Index (HI) and Oxygen Index (OI) according to [54] [60] [61] . The use of Van Krevelen diagram was extended by [45] from coals to include kerogen dispersed in sedimentary rocks.

The analyzed Montney Formation sediments in the study area show that Type II kerogen is present in the Montney Formation (Figure 9). Type II kerogen is oil prone [11] , relatively rich in hydrogen and characterized by its pure (monomaceral) form of exinite [54] . Examples of materials from which Type II kerogen are derived are spores and pollen grains of land plants, marine phytoplankton cysts, some leaf and stem cuticles [48] [54] . The occurrence of Type II kerogen depends on high biological productivity due to nutrient supply, low mineralogical dilution, and restricted oxygenation [54] .

Type III kerogen is present in Montney Formation sediments in the study area (Figure 9) Using the S2 values (remaining hydrocarbon generating potential) versus TOC, the ratio of Type III kerogen to Type IV kerogen is approximately 3:1 (Figure 11). [11] described Type III kerogen as primarily a gas prone kerogen, which contains dominantly vitrinite, and it is identical to macerel of humic coal [48] ) formed from land plant, or largely woody and cellulosic debris [48] . However, various macerel mixtures or degradational processes can contribute to the Type III kerogen formation [54] . Type III kerogen is the most reliable kerogen to estimate in terms of the degree of maturation using Tmax [47] .

Analyzed data in this study shows that Type IV kerogen constitutes the highest percentile in the Montney Formation. [48] [50] [53] [54] defined Type IV kerogen as inertinite (gas prone), composed of hydrogen poor (HI ≤ 50) constituent, difficult to distinguish from Type III kerogen by using only Rock-Eval pyrolysis [54] . A graphical plot of S2 versus TOC with pseudo HI indicates that Type IV kerogen constitutes about 80% of the kerogen based on Rock-Eval dataset (Figure 11, Figure 12 and Tables 1-3). Type IV kerogen is formed from materials of various origin, and has undergone extensive oxidation, or may in some cases represent detrital organic matter oxidized directly by thermal maturation, sedimentological recycling of materials [54] , or organic facies that has been reworked from a previous depositional cycle [48] [50] [53] [54] .

Thermal maturity of organic rich sediment is the resultant effect of temperature driven reactions dependent upon time duration that convert sedimentary or-

ganic matter (source-rock) to oil, wet gas, and finally to dry gas and pyrobitumen [50] . Thermal maturity is conventionally classified into three categories: 1) immature; 2) mature; and 3) post-mature sources rocks [48] [50] . Knowing a rock’s remaining source-rock capacity solves only one part of the source rock evaluation puzzle; it is also necessary to know what level of thermal maturity is represented by the source rock [12] . Maturity can be estimated by several techniques [11] [45] [46] [47] [48] . In this study, Tmax and vitrinite reflectance (Ro) measurements were used in the determination of thermal maturity of Montney Formation in the study area. The key to using maturity parameters effectively lies in evaluating the measured data carefully (and sometimes with skepticism), and whenever possible, it is better to obtain more than one maturity parameter [48] . Thus, Tmax, vitrinite reflectance (Ro) and Production index (PI) were interpreted separately in this study, and then, a comparison between the three maturity parameters were synchronized to verify similarity or dichotomy between the three data.

The amount and composition of hydrocarbons generated from a particular kerogen vary progressively with increasing maturity [55] . Thermal maturity of kerogen is commonly measured using Tmax and virtinite reflectance [3] [12] [63] [64] , however, there are other parameters that are used as indicators of thermal maturity [48] [51] . Tmax and transformation ratio for organic matter (OM) Type 1, II and Type III/IV, shows that the maximum paleotemperatures and vitrinite reflectance indicates the level of kerogen maturity [45] .

Tmax is defined as the maximum pyrolysis temperature at which the maximum amount of hydrocarbon is released by kerogen [5] . It is the maximum S2 peak in Rock-Eval pyrolysis (Figure 10 and Figure 11), the point at which the abundance of artificially generated hydrocarbons are at the greatest as a result of ramping up of temperature upto 550˚C [46] . The macromolecular kerogen network is cracked during pyrolysis to give an estimate of the thermal maturity of a source rock [3] [5] [65] .

Tmax values in analyzed core samples from the Montney Formation in the study area range from Tmax 347 to Tmax 526 (Tables 1-3). The average Tmax values range from Tmax 423 to Tmax 567 from each well and were plotted as Tmax contour map to show the geographical distribution of thermal maturity within the study area in Fort St. John, northeastern British Columbia. Statistical distribution of the analyzed Tmax values for the Montney Formation in the study area shows that >90% of the reported Tmax values are within Tmax 450 and Tmax 528.

The interpretation of thermal maturity using Tmax criteria of [51] indicates that more than 90% of the Montney Formation samples reported in this study are thermally matured (Figure 12 and Figure 13). The geographical distribution of

Tmax values in the study area prompted a consideration of what might be the controlling factors on thermal maturity and the relationships with geothermal gradient in the study area (Figure 13). The understanding of the geothermal regime in sedimentary basin is important for the studies of the evolution of a sedimentary basin as well as accumulation of hydrocarbons and other energy resources [66] . The generation of hydrocarbons (oil and gas) from any basin is dependent on the temperature reached by the organic-rich source rocks during their burial history [67] . Several workers [68] - [80] have reported heat transfer processes (convection and conduction), observed geothermal pattern, thermal and hydraulic conductivities, heat generated internally in the crust by the decay of radioactive elements, regional scale distribution of geothermal gradient, hydrogeological effects in establishing geothermal pattern, and statistical distribution of geothermal values in Western Canada Sedimentary Basin. Using geothermal calculations of [67] [72] [73] [74] [75] in Western Canada Sedimentary Basin, a comparison of the distribution of Tmax in the study area shows no particular striking relationship with the distribution of geothermal gradient owing to the small size of the study area. There appears to be no distinct distribution of Tmax values. [75] shows a regional-scale (basin-wide) distribution of the internal geothermal gradient across the entire Western Canada Sedimentary Basin, which shows a NW-SE increase in geothermal gradients. [69] reported a northerly trending increase in heat flow, which was interpreted to be caused by crustal thinning. The controlling mechanisms of heat transfer in the Western Canada Sedimentary Basin are conduction and convection by moving fluids or flow of formation water [75] , and hydrogeological effects [72] - [80] . This interpretation of geothermal distribution provides the underlying factors responsible for Tmax values in the study area. The geothermal gradient provides the answer to thermal maturity differences evident by the Tmax values in the Montney Formation within the study area in northeastern British Columbia (where the Montney Formation is mainly a gas prone reservoir) and in Alberta (the Montney Formation is mostly oil prone). The type of hydrocarbons produced (oil vs. gas) in the two Provinces (British Columbia and Alberta) from the Montney Formation is interpreted herein to be related to geothermal gradient that differentially affected source-rock thermal maturity in British Columbia and Alberta [75] [69] . The differential heating of the Montney Formation Kerogen at different temperatures (higher) in British Columbia than in Alberta (lower) as shown by [69] is responsible for the type of hydrocarbon that have been generated in Montney Formation in British Columbia and in Alberta.

The vitrinite data analyzed from the Montney Formation in this study is shown in Table 7. The available organic matter for each samples analyzed varies from 0 - 6 (Table 7). The vitrinite particles available for analysis in the analyzed samples range from 0 - 4. The measurement of vitrinite particles involves recording of the percentage of incident light, usually at a wave length of 546 nm, reflected from vitrinite particles under oil immersion [61] . The none availability (zero values in Table 7) of vitrinite particles, and very low vitrinite particles in the organic matter composition resulted in low level of confidence as shown in Table 7 (using a ranking scale 0 - 9). The level of thermal maturation of Montney Formation kerogen as revealed by vitrinite reflectance (R_o) analysis shows that data values range from (Ro 0.74% to 2.09%). Samples that have no vitrinite particles to measure are designated null (zero values) of vitrinite in Table 7.

Vitrinite is a type of kerogen particle formed from humic gels thought to be derived from the lignincellulose cell walls of higher plants [81] . Vitrinite is a common component of coal, and the reflectance of vitrinite particles was first observed to increase with increasing time and temperature in a predictable manner in coals [82] .

Based on the vitrinite reflectance data from Montney Formation in the study area, the results indicate that vitrinite reflectance (R_o) range from 0.74% - 2.09%, which is interpreted herein as primarily a gas prone kerogen (Figure 14) using standard vitrinite interpretation criteria (Table 5) of [51] . This interpretation has credibility because it corresponds to the same indication of gas window maturity using Tmax interpretive standard of [51] as shown in Figure 12. However, it is common, or not unusual to encounter low availability of vitrinite particles during laboratory analysis as seen in some of the samples shown in Table 7.

The low, or none availability of vitrinite particles can result to difficulty in differentiation of primary vitrinite coupled with insufficient grains to make a reliable determination of the reflectance of the samples constitute factors that affect the quality of vitrinite reflectance [64] . Similarly, inconsistencies or error can result from the measurements of vitrinite reflectance [12] [83] , and variation in chemical composition of vitrinite may lead to invalid comparison of vitrinite gradient [64] . Although the aforementioned analytical mechanics makes vitrinite reflectance results to be viewed with skepticism [48] , the method remains useful and conventionally implored in thermal maturity determination [63] .

Vitrinite reflectance in source-rock kerogen is related to the hydrocarbon generation history of sediments [64] . Vitrinite reflectance has been successfully used to demonstrate the reliability of the technique as indicator of organic maturation in source-rock, indicating potential areas of oil and gas generation

within a prospect [50] . Vitrinite reflectance (R_o) is one of the methods used in evaluation of thermal transformation of organic-rich sedimentary rocks [63] in hydrocarbon exploration [1] [45] [48] [57] . Vitrinite increases during thermal maturation due to complex, irreversible aromatization reactions [50] . It has been established that vitrinite reflectance correlates well with coal rank, which is primarily a function of time and temperature [60] .

The thermal transformation of vitrinite can be related to geothermal and paleotemperature [64] , which proceeds by a series of irreversible chemical reactions that cause organic matter alteration due to thermal cracking [63] [84] . Thus, vitrinite reflectance is used as thermal maturation indicator that provides a means of determining the maximum temperature exposure of sedimentary rocks [63] [84] .

The production index (PI) data in Montney Formation from the Rock-Eval analysis shows that PI has very low values (range from 0.11 to 2.6). More than 90% of PI values from the study area are less than 1. The relationship between production index (PI) and Tmax is shown in Figure 15.

The production index (PI) is also a parameter that is used in conjunction with other thermal maturity parameters to indicate type of hydrocarbon generated [50] , and was interpreted based on the geochemical parameters describing thermal maturation (Table 8). The PI values in this study indicate that the Montney Formation sediment is mostly matured and post matured (Table 8 and Figure 15).

Approximately thirty data point from the Montney Formation samples were analyzed for porosity (porosity of bulk volume and gas filled porosity) in relation to depth (Figure 16). The data show a side-by-side porosity value that nearly mimic bulk volume porosity and gas filled porosity (Figure 16). The highest value of porosity (Table 9) from well 16-17-82-25W6 is 5.67% and lowest value is 1.22%. Some cores of the Montney Formation have porosity greater than 5.6% (Figure 17). Visual observation of porosity from thin-section petrographic analysis revealed vuggy porosity (Figure 18).

Porosity is dependent on grain texture, which is determined largely by grain shape, roundness, grain size, sorting, grain orientation, packing, and chemical composition (cement precipitation and diagenetic modification). Distribution of pore structure, or pore-throat controls the porosity in tight rock matrix. The low values of measured porosity as observed in thin-section petrography are evidence of a combination of textural heterogeneity, mineral alteration, and transformation produced by diagenesis in the Montney Formation.

The petrographic analysis shows evidence of uniformity of grain size, and sorting of the Montney Formation sediments, which is dominantly siltstone with matrix of clay admixed very fine-grained sandstone and dolomite, precludes the effective inter-particle (inter-void communication), thus, average porosity is

considerably low as evident by the measured porosity values (Table 9). Observed vuggy porosity in some interval in the Montney Formation is associated with biogenic modification of textural fabric (Figure 18). The observed porosity in thin-section is partly associated with organic matter dissolution and replacement by pyrite, and biogenically produced secondary porosity. Also, relatively higher porosity in the Montney Formation is associated with bedding plane fractures. Bedding plane porosity observed in the Montney Formation results from varieties of concentrated parallel lamination to bedding planes. The larger geometry of many petroleum reservoirs are controlled by such bedding planes primarily formed by the differences of sediments calibre or particle sizes and arrangements influenced by the depositional environment [85] .

Measured pressured decay permeability from cores (Figure 19) shows very low permeability values that range from 0.000337 to 0.000110 mD. The statistical

vertical distribution of permeability values plotted in relation to depth show a cyclic pattern in variation (Figure 19).

Apart from the porosity of a reservoir, the ability of the rock to allow the flow of fluid through the interconnected pores, which is permeability (kv = kh), is a crucial reservoir parameter in the evaluation of any oil and gas play. The permeability of a rock depends on its effective porosity; which is controlled by grain size distribution, degree of sorting, grain shape, packing, and degree of cementation [84] [86] . The evaluation of permeability of heterogeneous clastic rocks from core or downhole is one of the most important goals of reservoir geoscience [87] .

The results from permeability analyses in this study are related to the overall textural heterogeneity, porosity, and in part, related to ichnofabric modification. The Montney Formation is composed of dolomitic, silt-size grains and subordinate very fine-grained sandstone. The implication of grains-size in-terms of permeability is in relation to the fact that smaller grain-sizes have smaller permeabilities than those with larger grain-sizes because smaller grain-sizes will produce smaller pores and smaller pore throats, which can constrain the fluid flow in a manner lower than flows in larger grains, which produce larger pore throats [86] . Furthermore, the smaller the grain-size, the larger the exposed surface area to the flowing fluid, which leads to larger friction between the fluid and the rock, and hence lower permeability [86] ). [88] have shown that there is strong correlation between permeability and grain-size of unconsolidated sands and gravels, with permeability increasing exponentially with increasing grain-size [88] .

Intervals were bedding plane fractures and ichnofabric modification occur shows relatively higher values in permeability. The observed porosity in thin-section (micron scale), shows that the porosity is associated with: 1) dissolution of organic matter or dolomitic material caused by diagenesis; 2) bioturbation-en- hanced porosity resulting from burrows by organisms; and 3) fracture porosity along bedding planes. [89] [90] have shown that reservoir enhancement in unconventional thinly bedded, silty to muddy lithologies of unconventional reservoir with low permeability can be enhanced by the activity of burrows.

Data analyzed for fluid saturation (gas saturation, mobile oil saturation, water saturation, and bound hydrocarbon saturation) indicates that water saturation is the second highest fluid, next to gas saturation; while, mobile oil saturation and bound hydrocarbon saturation (Figure 20) are negligible in comparison with gas saturation (Table 9) or water saturation. By far, gas saturation is very high throughout the interval of measurement, yielding as high as 99.56% at the depth of 2330.42m and the lowest value of gas saturation is 70.25% at the depth of 2415.82m (Figure 20, Table 9).

The amount of fluid in pore volume of a rock occupied by formation fluid (oil, gas, and water) refers to fluid saturation [91] . Results from this study shows that gas saturation is the most dominant fluid in the interstitial pores of the Montney Formation (Figure 20) varying from 99.64% to 62.59% through the depth profile. The oil saturation shows a near consistency graph level, particularly indicating a very low (0.81% to 7.64%) oil saturation through the depth profile. The implication of high gas saturation confirms that the Montney Formation in northeastern British Columbia is mainly a gas reservoir. Water saturation varies significantly in an inversely proportional correlative pattern with gas saturation. The relationship of water saturation with gas saturation is interpreted in relation to the proportion of the ratio of gas to water in the pore volume. The relative low water saturation is crucial because water in pore space of low-per-meability occupies critical pore-throat volume and can greatly diminish hydrocarbon permeability, even in rocks at irreducible water saturation [92] . Because of small pore-throat size, low-permeability, gas-producing sandstones are typically characterized by high water saturation and high capillary pressure [93] [94] .

For source-rock to have economic potential or exploration prospect, sufficient organic matter (OM) must have generated hydrocarbons. The measure of the quality of source-rock is the total organic carbon (TOC) content, and the guidelines for ranking source rock quality were proposed by [11] : 1) poor TOC richness range from 0.00 - 0.50 wt% in shale; while in carbonates TOC range from 0.00 - 0.12 wt%; 2) fair TOC range from 0.50 - 1.00 wt% in shale; while in carbonates TOC range from 0.25 - 0.50 wt%; 3) good TOC range from 1.00 - 2.00 wt% in shale; while in carbonates TOC range from 0.25 - 0.50; 4) very good TOC range from 2.00 - 4.00 wt% in shale; while in carbonates TOC range from 0.5 - 1.00 wt%; and 5) excellent TOC starts at values >4.00 wt% in shale; while in carbonates TOC must be >1.00 wt%.

Using the premise above as proposed by [11] , the Montney Formation in the study area, has TOC content that is variably and statistically distributed in the order of highest percentile into low TOC (<1.5 wt%), medium (1.5 - 3.5 wt%), and high (>3.5 wt%). Based on these results, the Montney Formation in the study area has good total organic carbon (TOC) richness (Figure 21). In addition to the TOC content, The Montney Formation Kerogen has been interpreted and classified into: 1) Type III kerogen, which is primarily a gas prone kerogen [11] [12] [48] ; 2) Type IV kerogen, which is inertinite (gas prone), composed of hydrogen poor constituent, difficult to distinguish from Type III kerogen by using only Rock-Eval pyrolysis; and 3) mixed Type II/III kerogen, which is oil prone [11] [46] [48] relatively rich in hydrogen and characterized by materials such as spores and pollen grains of land plants, marine phytoplankton cysts, some leaf and stem cuticles [48] [54] .

The Montney Formation exhibits different thermal maturities (immature, mature, and post-mature). However, statistical distribution of the Tmax values in the Montney Formation within the study area shows that >95% of the reported Tmax values are within 430 and 528 Tmax, which is within gas window [51] . Some of the sediments are thermally matured (Figure 12). Likewise, the vitrinite reflectance (Ro) results in this study shows that the Montney Formation in the study area is thermally matured, and it is composed mainly of gas with some oil (Figure 14). A comparison of the Tmax data, vitrinite reflectance data, and production index (PI), which show strong correlation in terms of using multiple maturity parameters as argued by [48] as a better method of assessing the accuracy of thermal maturity index. Tmax, R_o and PI (Figure 12, Figure 14 and Figure 15) produced the same thermal maturity, thus, the data boost the credibility of the thermal maturity synthesized and reported for the Montney Formation herein.