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Montney Formation Evaluation, Northeastern British Columbia Canada, Part B

Figure 1. Location map of study area showing wells (red color) that penetrated Montney Formation in northeastern British Columbia and Alberta, Canada.

Petroleum Source-Rock Evaluation and Hydrocarbon Potential in Montney Formation Unconventional Reservoir, Northeastern British Columbia, Canada (PART B)

4.13. Interpretation of Vitrinite Reflectance (Ro)

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].

Author
Edwin I. Egbobawaye

Department of Earth and Atmospheric Sciences, University of Alberta, Edmonton, Canada
Received: December 29, 2016; Accepted: November 27,2017
Copyright © 2017

 

Based on the vitrinite reflectance data from Montney Formation in the study area, the results indicate that vitrinite reflectance (Ro) 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.

Table 7. Vitrinite reflectance measured from the Montney Formation sediments in British Columbia.

Table 7. Vitrinite reflectance measured from the Montney Formation sediments in British Columbia.

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 (Ro) 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].

Figure 14. Total Organic carbon (TOC) vs. vitrinite reflectance (Ro) showing the thermal maturity of Montney Formation source-rock, and hydrocarbon generating phases in the Montney Formation sediments from study area, northeastern British Columbia [24].

Figure 14. Total Organic carbon (TOC) vs. vitrinite reflectance (Ro) showing the thermal maturity of Montney Formation source-rock, and hydrocarbon generating phases in the Montney Formation sediments from study area, northeastern British Columbia [24].

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].

4.14. Description: Thermal Maturity―Production Index (PI)

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.

Figure 15. Shows that the Montney Formation kerogen is thermally matured, and extensively composed of gas.

Figure 15. Shows that the Montney Formation kerogen is thermally matured, and extensively composed of gas.

4.15. Interpretation of Production Index (PI)

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).

Table 8. Geochemical parameters describing the level of thermal maturation [50].

Table 8. Geochemical parameters describing the level of thermal maturation [50].

5. Reservoir Characterization of the Montney Formation

5.1. Porosity Data-Description

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).

Table 9. Petrophysical characterization of the Montney Formation in well 16-17-82-25W6 (Data source: B.C Oil and Gas Commission).

Table 9. Petrophysical characterization of the Montney Formation in well 16-17-82-25W6 (Data source: B.C Oil and Gas Commission).

Figure 16. Shows porosity and gas filled porosity of the Montney Formation (well 16-17-82-25W6). The graph shows very excellent correlation between porosity and gas filled porosity. (Data source: B.C. Oil and Gas Commission).

Figure 16. Shows porosity and gas filled porosity of the Montney Formation (well 16-17-82-25W6). The graph shows very excellent correlation between porosity and gas filled porosity. (Data source: B.C. Oil and Gas Commission).

5.2. Interpretation of Porosity

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.

Figure 17. Porosity vs. permeability crossplot for the Montney Formation, well: 2-19-79-14W6 (depth 2037.40 - 2091.90 m). Data source: B.C. Oil and Gas Commission.

Figure 17. Porosity vs. permeability crossplot for the Montney Formation, well: 2-19-79-14W6 (depth 2037.40 – 2091.90 m). Data source: B.C. Oil and Gas Commission.

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).

Figure 18. Microphotograph showing dolomitic siltstone facies and the associated vuggy porosity resulting from dissolution of material. Yellow arrow labeled “P” is pointing to vuggy porosity.

Figure 18. Microphotograph showing dolomitic siltstone facies and the associated vuggy porosity resulting from dissolution of material. Yellow arrow labeled “P” is pointing to vuggy porosity.

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].

5.3. Permeability Data Description

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).

Figure 19. Graph showing permeability vs. depth of the Montney Formation from well 16-17-82-25W6, northeastern British Columbia (Data source: B.C. Oil and Gas Commission).

Figure 19. Graph showing permeability vs. depth of the Montney Formation from well 16-17-82-25W6, northeastern British Columbia (Data source: B.C. Oil and Gas Commission).

5.4. Interpretation Permeability

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.

5.5. Fluid Saturation-Data Description

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).

Figure 19. Graph showing permeability vs. depth of the Montney Formation from well 16-17-82-25W6, northeastern British Columbia (Data source: B.C. Oil and Gas Commission).

Figure 20. Illustrates fluid saturation (gas, oil, and water) of the Montney Formation from well 16-17-82-25W6, northeastern British Columbia (Data source: B.C. Oil and Gas Commission).

5.6. Interpretation of Saturation

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].

6. Discussions

6.1. Source-Rock Quality

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].

6.2. Thermal Maturity

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, Ro 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.

Montney Formation Evaluation, Northeastern British Columbia Canada, Part B

he Montney Formation source-rock characteristics presented in this study shows that TOC is statistically distributed into low (<1.5 wt%), medium (1.5 – 3.5 wt%), and high (>3.5 wt%). The analysis and interpretation in this study shows that the Montney Formation in the study area is rich in TOC, and thermally matured. The type of hydrocarbon associated with the Montney Formation is mainly thermogenic gas, derived from kerogens of Type III/IV and mixed Type II/III kerogen. Thermal maturity Geographical distribution in the study area shows that the kerogen is pervasively matured in the study area.
Emanuel Martin
Emanuel Martin is a Petroleum Engineer graduate from the Faculty of Engineering and a musician educate in the Arts Faculty at National University of Cuyo.
http://www.allaboutshale.com

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