Petroleum Source-Rock Evaluation and Hydrocarbon Potential in Montney Formation Unconventional Reservoir, Northeastern British Columbia, Canada
Source-rock characteristics of Lower Triassic Montney Formation presented in this study shows the total organic carbon (TOC) richness, thermal maturity, hydrocarbon generation, geographical distribution of TOC and thermal maturity (Tmax) in Fort St. John study area (T86N, R23W and T74N, R13W) and its environs in northeastern British Columbia, Western Canada Sedimentary Basin (WCSB). TOC richness in Montney Formation within the study area is grouped into three categories: low TOC (<1.5 wt%), medium TOC (1.5 – 3.5 wt%), and high TOC (>3.5 wt%). Thermal maturity of the Montney Formation source-rock indicates that >90% of the analyzed samples are thermally mature, and mainly within gas generating window (wet gas, condensate gas, and dry gas), and comprises mixed Type II/III (oil/gas prone kerogen), and Type IV kerogen (gas prone).
Edwin I. Egbobawaye
Department of Earth and Atmospheric Sciences, University of Alberta, Edmonton, Canada
Received: December 29, 2016; Accepted: November 27,2017
Copyright © 2017
Analyses of Rock-Eval parameters (TOC, S2, Tmax, HI, OI and PI) obtained from 81 samples in 11 wells that penetrated the Montney Formation in the subsurface of northeastern British Columbia were used to map source rock quality across the study area. Based on total organic carbon (TOC) content mapping, geographical distribution of thermal maturity (Tmax), including evaluation and interpretation of other Rock-Eval parameters in the study area, the Montney Formation kerogen is indicative of a pervasively matured petroleum system in the study area of northeastern British Columbia.
Source-rocks are precursors for hydrocarbon accumulation and reservoir potential. In general, source rocks are organic rich sediments that have, or may generate hydrocarbons , and are a primary element in any petroleum system . Successful exploration for oil and gas depends largely upon the quality of source-rock. To determine source rock quantity, total organic carbon (TOC) content, and quality, Rock-Eval technique is used. Rock-Eval pyrolysis methods have been utilized worldwide for more than three decades as an aid to determining source-rock parameters: Tmax, TOC richness, Hydrogen Index (HI), Oxygen Index (OI), Production Index (PI), the remaining hydrocarbon generating potential (S2), and a host of other products  – .
Rock-Eval pyrolysis is used to rapidly evaluate and depict the petroleum generating potentials of prospective source rocks  by providing information about their: 1) kerogen type and organic matter quality; 2) type of organic matter and characteristics; 3) thermal maturity of the organic matter; and 4) hydrocarbon type (oil, gas or both).
The geographical distribution of source-rocks parameters within a particular acreage of exploration objective constitutes part of the assessment mechanics of hydrocarbon exploration . Source-rock evaluation involves assessing the hydrocarbon generating potential of sediments by examining the sediment’s capacity for hydrocarbon generation, type of organic matter present and what hydrocarbons might be generated, including sediment’s thermal maturity and how it has influenced generation . To understand source-rock potential in Montney Formation, Rock-Eval method was utilized.
The Triassic Montney Formation in Forth St. John study area (T86N, R23W and T74N, R13W), northeastern British Columbia (Figure 1) is classified as unconventional hydrocarbon reservoir  –  ). In general, unconventional hydrocarbon reservoirs comprises tight gas, shale gas and coalbed methane . Until recently, these reservoirs were previously considered non-economical, unproductive, and non-exploitable geological formations owing to poor under- standing of lithological heterogeneity and variability in mineralogy coupled with less advanced technology. However, improved technology has revolutionised unconventional or tight reservoirs. The inherent petrophysical properties of unconventional reservoirs are low matrix porosity of ≤10% and permeability of ≤0.1 mD millidarcy, exclusive of fracture permeability . Typically, these reservoirs depend on stimulation for production, and in general, contain large amounts of hydrocarbons; although, gas recovery factors may be low .
Figure 1. Location map of study area showing wells (red color) that penetrated Montney Formation in northeastern British Columbia and Alberta, Canada.
The Montney Formation in the study area is a primary focus of unconventional gas reservoir exploration in Western Canada Sedimentary Basin (WCSB) because: 1) it is a source rock rich in organic matter  ; 2) it has a thermal maturity that lies within gas generating window, and it is primarily a gas prone mixed Type II/III kerogen  ; 3) the present study shows that the kerogen of the Montney Formation in the study area is mainly composed of Type III/IV and some mixed Type II/III kerogen with average TOC range of 0.5% – 4wt%; and upto 8.2wt% TOC (rare), but present); 4) it has a reservoir thickness upto 320 meters in the study area; 5) it hosts substantial volumes (Natural Gas reserve = 271 TCF), Liquefied Natural Gas (LNG = 12,647 million barrels), and oil reserve (29 million barrels) according to BC Ministry of Energy, Mines and Natural Gas  ; and 6) porosity range from 2% – 10%, and sporadically > 10% in some intervals where ichnofabric or dolomite dissolution have resulted in the formation of secondary porosity.
These criteria make the Montney Formation an unconventional resource play with high potential within Fort St. John study area, northeastern British Columbia (Figure 1). However, despite the strong economic significance of this hydrocarbon resource hosted in finer-grained lithologies “siltstone/very fine-grained sandstone” interval, the location and predictability of the best reservoir units remains conjectural: in large part because the geochemistry, lithologic variability, and mineralogy of the Montney tight-rocks hosting thermogenic gas in the subsurface of Western Canada has not been adequately characterized   .
The Montney Formation in the study area consists of siltstone with subor- dinate interlaminated very fine-grained sandstone.   shows that five lithofacies were identified in the study area: Lithofacies F-1 (organic rich, wavy laminated black siltstone); Lithofacies F-2 (very fine-grained sandstone interbedded with siltstone); Lithofacies F-3A (bioturbated silty-sandstone attributed to the Skolithos ichnofacies); Lithofacies F-3B (bioturbated siltstone composed of Cruziana ichnofacies); Lithofacies F-4 (dolomitic siltstone interbedded with very fine-grained sandstone); and Lithofacies F-5 (massive siltstone).
The depositional environments interpreted for the Montney Formation in the study area is characteristic of lower shoreface through proximal offshore to distal offshore settings  . The lower shoreface environment record trace fossils attributed to the Skolithos ichnofacies . The proximal offshore environment have sedimentary structures formed under quiescent depositional conditions typically found below the fair weather wave base  such as lamination and current ripples  ). The distal offshore environment has trace fossils attributed to distal expression of the Cruziana ichnofacies .
The observed sedimentary structures recorded in the logged Montney Formation cores includes current ripples, deformation structures, convolute lamination/bedding, etc. The sediment deformation structures, convolute lamination/bedding formed due to mechanical forces causing plasticity, commonly related to gravity acting upon weak sediments usually silt or sands, prior to or soon after, or at deposition along the sediment surface  ; and escape traces (Fugichnia?), which are evidence of small scale episodic deposition due to local transport from the lower shoreface or proximal offshore to distal setting.
This paper concerns itself with: 1) evaluation of the Montney Formation source-rock richness; 2) thermal maturity and hydrocarbon generation in the Montney Formation; and 3) geographical distribution of Rock-Eval (TOC and Tmax) parameters in the study area.
2. Geological Setting
The paleogeographic location of the Western Canada Sedimentary Basin (WCSB) during the Triassic time was situated at approximately 30˚N paleolatitude based on analyses of paleomagnetic data, paleolatitude and paleoclimatic zonation , and fauna record . The paleoclimate reconstruction suggests that the paleoclimate may have ranged from sub-tropical to temperate   . The region has been interpreted to be arid during the Triassic, and was dominated by winds from the west   .
The WCSB forms a northeasterly tapering wedge of sedimentary rocks with thickness of more than 6000 meters, which extends southwest from the Canadian Shield into the Cordilleran foreland thrust belt  . The Cordilleran of the WCSB provides the evidence that the origin and development of the basin was associated with tectonic activity  . Later epeirogenic episodes resulted in subsidence that created the basin for sediment accumulation, which were attributed to the effects of contemporaneous episodes of orogenic deformation in the Cordillera  .
This is interpreted to be post Triassic, especially due to mountain influences .    interpreted sediment loading, evidenced by the deformed bed, slump structures and small-scale faults as indicators of tectonic influences on the deposition of Triassic successions. Within the Foothills and Rocky Mountain Front Ranges, Triassic rocks were subjected to Jurassic – Cretaceous Columbian and Upper Cretaceous – Lower Tertiary Laramide orogenies, which caused a series of imbricate thrust faults and folds in the region .
In Alberta and British Columbia, Triassic sediments were deposited in a central sub-basin known as the Peace River Embayment, which extended eastward from the Panthalassa western ocean onto the North American craton . During the Triassic period, the Peace River Embayment was a low mini basin associated with minor fault block movement associated with a broad downwarp resulted in the rejuvenation of structural deformation within the Monias areas of southwest Fort St. John, British Columbia .
Figure 2. Type log of the Montney Formation in the study area, northeastern British Columbia, Western Canada Sedimentary Basin (WCSB), adapted from .
Stratigraphically (Figure 2), the Triassic Montney Formation is Griesbachian to Spathian in age . The Triassic succession thickened westward , and rests unconformably in most areas, upon the Belloy Formation in outcrop of northeastern British Columbia; Carboniferous in parts of northeastern British Columbia and Alberta; and Fantasque in outcrop at Williston . The thickness of Triassic deposits is about 1200 meters in the western-most outcrop in the Rocky Mountain Foothills . The Montney Formation structure map (Figure 3) indicates higher paleostructure in the east and low in the western portion of the study area. This structural tilt shows a depositional thinning to the east and north due to erosional removal   .
Figure 3. Structure contour map of the Montney Formation in the study area, northeastern British Columbia. Dash contour lines indicate no data point for well control. The structure map decreases in elevation westward, which indicates that sediment source area was from east, and prograded westward .
3. Method of Study
Drilled cores of the Montney Formation from the study area in Fort St. John vicinity, northeastern British Columbia were logged to assess sedimentological, ichnological and facies characteristics. The lithologic features and accessories, sedimentary texture, sedimentary structure, the nature of bedding contacts, and lithofacies were compiled in detail (Figure 4 and Figure 5).
Figure 4. Montney Formation core description from well 9-29-79-14W6.
Figure 5. Shows lithofacies of the Montney Formation (a) Plane lamination; (b) fractured siltstone along bedding plane; (c) silty-sandstone with current ripple sedimentary structure; (d) shows sediment deformation structure; (e) bioturbation by Phycosyphon?; (f) interbedded silty-sandstone.
Samples were crushed into powder using the pulverized shatter-box machine at the University of Alberta’s rock-crushing lab. Samples were sent to Geological Survey of Canada and Chesapeake Energy Corporation, Oklahoma City, USA, for Rock-Eval analyses (Table 1). Additional Rock-Eval data (Table 2) included in this paper comes from Oil and Gas Commission, Ministry of Energy, British Columbia, and (Table 3) comes from .
Table 1. Rock-Eval data from the Montney Formation, Fort St. John study area and environs, northeastern British Columbia, Canada.
Table 2. Rock-Eval data from the Montney Formation (outside of study area), northeastern British Columbia. Data source: B.C Oil and Gas Ministry of Energy, British Columbia.
Table 3. Montney Formation Rock-Eval data .
The anhydrous pyrolysis technique used in this study evaluates oil and gas shows, oil and gas generation potential, thermal maturity and identifies organic matter type      . The Montney Formation rock samples were pyrolyzed using Rock-Eval 6.  described the Rock-Eval technique as an apparatus, which consists of a programmed temperature heating of a small amount of rock sample (100 mg) in an inert atmosphere (Helium or Nitrogen) to determine the amount of free hydrocarbons present in a sample (usually denoted by the S1 peak). The amount of hydrocarbons and oxygen containing compounds (CO2) that are produced during the thermal cracking of the insoluble organic matter (kerogen) in the rock is represented by the S2 peak, which indicates the oil not yet released from the rock by natural processes and represents the residual petroleum potential (Figure 6).
Figure 6. Rock-Eval pyrolysis for Montney Formation sample (well 2-19-79-14W6, depth: 2085 m). (a) illustrates the effect of pyrolysis temperature with Rock-Eval. The S1 peak is the free hydrocarbon liberated during thermal decomposition at less than 300˚C. The S2 peak is derived from the conversion of total organic matter to kerogen during pyrolysis (pyrolyzed fraction). The S2 corresponds to the maximum temperature (Tmax); (b) shows the S3 peak (CO2) corresponding to 400˚C, which represents the oxidation of CO2. It also shows the difference in organic matter; (c) illustrates the pyrolysis carbon monoxide (CO); (d) shows the oxygen indices. The determination of oxygen index (OI) is based on using CO2 and CO; the CO = S3CO × 100/TOC Total oxygen index (OI) = CO2 + OI (CO); (e) shows the S4 peak, the oxidation carbon monoxide (CO); the peak shows the present of siderite mineral (400˚C – 600˚C); (f) Oxidation of CO and CO2. The red line is the temperature trace in 25 minutes from 300˚C to 650˚C. Distinctly bi-modal curve is due to pyrobitumen.