Methanogenic biodegradation of petroleum in the West Siberian Basin (Russia): Significance for formation of giant Cenomanian gas pools Alexei V. Milkov ABSTRACT Approximately 1700 tcf (∼48 trillion m3) of dry gas (>99% methane) reserves and resources occur in western Siberia, mostly in shallow (<1500 m [<4921 ft]) Cenomanian pools in the northern part of the basin. This dry gas constitutes about 11% of the world’s conventional gas endowment and about 17% of the annual gas production. The origin of the dry gas has been debated extensively over the last 45 yr but remains controversial. Widely discussed hypotheses on the origin include early-mature thermogenic gas from coal, primary microbial gas from dispersed organic matter or coal, and thermogenic gas from deep source rocks. However, all these hypotheses are in some ways inconsistent with the molecular or isotopic composition of the gases or the results of basin and petroleum systems modeling. Here, I present geochemical and geological evidence that a significant (although yet not quantified) part of the shallow dry gas in the northern West Siberian Basin originated from methanogenic biodegradation of petroleum. Circumstantial evidence includes the occurrence of heavily biodegraded oil legs and residual oil in many Cenomanian gas pools, as well as geochemical evidence of heavy to slight biodegradation in Jurassic–Albian reservoirs commonly underlying the Cenomanian pools. Direct evidence includes, most importantly, 13C-enriched CO2 in pools with biodegraded oil (although data are limited), which indicates 40–70 wt.% conversion of oil-derived CO2 to secondary microbial methane. Distinctive hydrocarbon molecular and Copyright ©2010. The American Association of Petroleum Geologists. All rights reserved. Manuscript received July 13, 2009; provisional acceptance October 9, 2009; revised manuscript received December 15, 2009; final acceptance January 5, 2010. DOI:10.1306/01051009122 AAPG Bulletin, v. 94, no. 10 (October 2010), pp. 1485–1541 1485 AUTHOR Alexei V. Milkov  BP Russia, 8 Novinskiy Bulvar, Moscow, Russia; alexei.milkov@bp.com Alexei Milkov holds degrees in geology from Saint-Petersburg State University, Russia (B.Sc., 1996; M.Sc., 1998) and Texas A&M University (Ph.D., 2001). He joined BP in 2003 and has worked as a petroleum systems analyst in exploration, appraisal, development, production, and environmental projects around the world. He has more than 110 publications (including 40 peer-reviewed articles) on gas hydrates, mud volcanoes, geological emissions of methane, reservoir geochemistry, and methanogenic biodegradation. He currently studies petroleum systems offshore Russia. ACKNOWLEDGEMENTS I acknowledge all BP and industry colleagues (A. Brown, P. Carragher, G. E. Claypool, J. Curiale, L. Dzou, A. Guryanov, A. S. NemchenkoRovenskaya, N. Piggott, I. Simpson, and many others) who helped to sharpen the arguments presented in this article through many stimulating discussions; GeolabNor/Fugro for the permission to present geochemical data; and BP for the permission to publish. I especially thank Ken Peters and Martin Schoell for editing the manuscript. The AAPG Editor thanks the following reviewers for their work on this article: Ken Peters and John Curtis. isotopic compositions of most gases in Cenomanian pools (average dryness C1/(sum C1-C5) is 0.9976; average d13C of methane is −51.8‰) suggest that they represent mixtures of biodegraded thermogenic gases from deep, mainly Jurassic, source rocks and secondary microbial methane with an occasional small addition of primary microbial methane. Contribution of early-mature coal-derived gas is possible in areas with the most significant thermal stress of Hauterivian–Aptian sediments but remains speculative. Review of petroleum habitats of five representative oil-gas-condensate fields in western Siberia (including the world’s second largest gas field, Urengoyskoe) suggests that methanogenic biodegradation may best explain the observed distribution and properties of fluids in the shallow reservoirs of those fields. Recognition of secondary microbial gas in western Siberia helps explain the observed dominance of gas in the shallow, cool northern part of the basin, where conditions were more favorable for prolonged petroleum biodegradation than in the central and southern parts of the basin. Secondary microbial gas has been recognized worldwide and may (1) represent a volumetrically significant exploration target in shallow reservoirs (perhaps more significant than primary microbial gas) and (2) indicate effective thermogenic petroleum systems in the deeper sections. Large volumes (up to ∼66,500 tcf [∼1884 trillion m3]) of secondary microbial methane could have been generated from biodegraded petroleum accumulations worldwide. Although a part of that gas accumulated as oildissolved, free, and hydrate-bound gas, most gas apparently escaped into the overburden, atmosphere, and ocean and could have affected global climate in the geologic past. INTRODUCTION The West Siberian Basin in Russia is the largest petroleum basin in the world both by area (∼3.8 million km2 [∼1.5 million mi2]) and by total petroleum endowment (Figure 1). According to Ahlbrandt et al. (2005), about 538 billion bbl of oil equivalent (BBOE) (∼77 billion tons of oil equivalent [BTOE]) 1486 Methanogenic Biodegradation in Western Siberia may occur in this basin (including the offshore part in the south Kara Sea), which is about 9.6% of the world’s petroleum endowment. In the West Siberian Basin, approximately 355 BBOE (∼51 BTOE) is known (∼83 BBOE [∼11.9 BTOE] has been produced and ∼272 BBOE [∼38.9 BTOE] remains as reserves) and approximately 183 BBOE (∼26.2 BTOE) is estimated to be undiscovered (Ahlbrandt et al., 2005). Approximately 64% of the endowment is gas (∼1913 tcf [54.2 trillion m3]) or about 342 BBOE [48.9 BTOE]), which occurs mostly in the northern part of the basin (Figure 1). Brekhunzov (2006) estimated that the total gas endowment in western Siberia may be as high as approximately 3500 tcf (99 trillion m3). A significant part of that gas (∼1679 tcf [∼47.6 trillion m3] or ∼11% of the world’s gas endowment) occurs at a relatively shallow depth (<1500 m [4921 ft], Figure 2) mostly in Cenomanian but also Turonian and Aptian– Albian reservoirs, and is very dry (i.e., predominantly methane). The origin of this enormous volume of dry gas remains an enigma despite numerous geochemical and basin modeling studies (e.g., Schaefer et al., 1999; Fjellanger et al., 2008). Secondary microbial gas forms during microbial degradation of thermogenic petroleum (oil, condensate, and hydrocarbon gas). Generation of secondary microbial gas, in which methane is the dominant hydrocarbon, has been demonstrated by many laboratory experiments conducted over the last 55 yr (Bokova, 1953; Jones et al., 2008). The biogeochemistry of the process is not yet fully understood but apparently includes fermentation of alkanes to acetate and hydrogen, syntrophic oxidation of acetate to CO2 and hydrogen, and reduction of CO2 by methanogens, whereas acetoclastic methanogenesis may be a less important pathway of methane generation (Zengler et al., 1999; Jones et al., 2008; Gray et al., 2009). Geological and geochemical evidence of secondary microbial methane in subsurface accumulations was reported from onshore and offshore sedimentary basins around the world (e.g., Jeffrey et al., 1991; Pallasser, 2000; Larter and di Primio, 2005; Milkov and Dzou, 2007). In this article, I present comprehensive basinwide geological and geochemical data and focus field studies to argue that methane in Figure 1. Map of western Siberia indicating the distribution of oil and gas fields and Cenomanian pools. Administrative units of the Russian Federation are outlined by thin red lines; petroleum areas as defined by Brekhunzov (2006) are outlined by thick blue lines and labeled by numbers (1 = South-Kara; 2 = Yamal; 3 = Gydan; 4 = Ust-Enisey; 5 = East-Ural; 6 = Near-Ural; 7 = Krasnoleninsk; 8 = Frolov; 9 = middle Ob; 10 = Nadym-Pur; 11 = Pur-Taz; 12 = Eloguy-Turukhan; 13 = Kaymyisov; 14 = Vasyugan; 15 = Paydugin; 16 = Near-Enisey); main cities and fields discussed in the text are indicated. AA′ is the location of geological cross section in Figure 2. the Cenomanian and some Neocomian–Albian and Turonian pools of western Siberia originated, at least in part, due to methanogenic biodegradation as originally proposed by Goncharov et al. (1983). This and other recently recognized worldwide occurrences of methane from biodegraded petroleum suggest that secondary methanogenesis is a highly important pathway of natural gas generation. GEOLOGY AND PETROLEUM SYSTEMS OF THE WEST SIBERIAN BASIN The onshore part of the West Siberian Basin (Figure 1) extends from the Ural Mountains in the west to the East Siberian platform in the east and from the Kara Sea in the north to the Kazakh highlands and Altay-Sayan in the south and covers an area ∼3.3 million km2 (∼1.3 million mi2) (Brekhunzov, Milkov 1487 Figure 2. Geological cross section across the West Siberian Basin illustrating present-day subsurface temperatures (modified from Kurchikov and Stavitskiy, 1987). The location is shown in Figure 1 as AA′. The following oil and gas fields are indicated: 1 = Semakovskoe; 2 = Yamburgskoe; 3 = Severo-Urengoyskoe; 4 = Urengoyskoe; 5 = Gubkinskoe; 6 = Vengayakhinskoe; 7 = Vengapurskoe; 8 = SeveroVaryeganskoe; 9 = Varyeganskoe; 10 = Chernogorskoe; 11 = Samotlorskoe; 12 = Vartovsko-Sosninskoe; 13 = Lomovoe; 14 = Klyuchevskoe; 15 = Luginezkoe; 16 = Ostaninskoe. Tops of formations are shown by solid lines and present-day isotherms are shown by broken lines. Formation symbols: J1–2 = Lower–Middle Jurassic; J3 = Upper Jurassic; K1b-h = Lower Cretaceous Berriasian–Hauterivian; K1br = Barremian; K1a-K2c = Lower–Upper Cretaceous Aptian–Cenomanian; K2t = Upper Cretaceous Turonian. 2006). The basin extends into the south Kara Sea for another approximately 0.5 million km2 (∼0.19 million mi2). Since initial exploration in 1948, more than 22,000 wells have been drilled in western Siberia and about 5100 wells penetrated pre-Jurassic sediments. About 820 fields have been discovered, and 392 fields are being developed (Brekhunzov, 2006). The geology, tectonics, evolution, and petroleum habitat of the basin were reviewed in many publications (Nesterov et al., 1971, 1990; Kontorovich et al., 1975; Peterson and Clarke, 1991; Ulmishek, 2003; Vyssotski et al., 2006). Here, I present a short summary of the main elements of the western Siberia petroleum systems relevant to this study. The West Siberian Basin is an intracratonic Mesozoic sag overlying Hercynian accreted terrane and an Early Triassic rift system (Ulmishek, 2003). Heterogeneous basement lies as much as 16 km (10 mi) below the surface and is composed of metamorphosed and folded Precambrian and Paleozoic rocks. The intermediate structural complex between basement and sedimentary cover is composed of Precambrian through Triassic slightly metamorphosed sedimentary (terrigenous, carbon1488 Methanogenic Biodegradation in Western Siberia ate, and coals) and volcanic rocks. This complex is up to 5.5 km (3.4 mi) thick in the northern and northeastern parts of the basin and is thin or absent in some areas in the central and southern parts of western Siberia. The sedimentary cover (Figure 2) is up to 11 km (7 mi) thick and is composed of Middle Triassic through Tertiary mostly clastic (40% marine, 60% continental) rocks (Chernikov et al., 1988). The main source rocks in the West Siberian Basin are the Bazhenovskaya (Bazhenov) Formation (Volgian–Berriasian, Upper Jurassic to Lower Cretaceous, Figure 3) and Togurskaya (Togur) Formation (lower Toarcian, Lower Jurassic) described by Kontorovich et al. (1997). The Bazhenov Formation was deposited as siliceous-carbonaceous muds during the major Late Jurassic marine transgression. It is generally organic-rich (total organic carbon [TOC] from 2 to 20%), oil prone (initial hydrogen index [HI] averages 400–500 mg hydrocarbons [HC]/g TOC), and is 20–40 m (66–131 ft) thick. However, the petroleum potential decreases from the middle Ob area (deep-water anoxic facies of the Bazhenov Sea with H2S contamination) toward the north and rims of the basin (shallower Milkov 1489 Figure 3. Simplified stratigraphy of Triassic–Cretaceous formations in western Siberia. Thickness of formations and occurrence of oil, condensate, and gas accumulations are shown. Modified from Chernikov et al. (1988), Kontorovich et al. (1994), Skorobogatov et al. (2003), and Skorobogatov and Stroganov (2006). Bazhenov Sea and shelf). The Bazhenov Formation is within the main oil window (at present) over much of the southern and central areas of the basin, and is in the gas-condensate to gas generation zone in the north (Figure 4b). Kontorovich et al. (1997) estimated that more than 80% of the oil found in the basin originated from the Bazhenov Formation. The Togur Formation, which is commonly considered as a bed in the lower part of the Tyumenskaya (Tyumen) Formation (Figure 3) (Ulmishek, 2003), is represented by 10–40 m (33–131 ft) of black argillites deposited in a shallow sea in the northern part of the basin ( Yamal, Gydan, and Ust-Enisey areas); interbedded muds, thick siltstones, and fine sandstones in the central and marginal parts of the basin; and continental or lacustrine deposits in the southern part of the basin (Kontorovich et al., 1997). Togur lacustrine deposits have TOC values of 1.5–3% (>5% in some intervals) and HI averaging approximately 500 mg HC/g TOC at 0.8% vitrinite reflectance (Ro). In the northern part of the basin, TOC values range mostly from 1.5 to 3% but can reach 17% in some coaly layers (Lopatin and Emets, 1987, although they describe Togur-equivalent lower Toarcian deposits as the Djangodskiy horizon of the Tyumen Formation). According to Kontorovich et al. (1997), the Togur Formation entered the oil window about 120 Ma in the northern part of the basin and about 75–100 Ma in the central part of the basin. At present, the Togur Formation and its age-equivalent formations are in the main gas window in the Yamal and Pur-Taz areas, but in some areas in the south, they did not reach the oil window (Figure 4a). Approximately 11% of the oil found in the basin is lacustrine and originated from organic matter in the Togur Formation. These Togur-sourced oils occur mostly in Paleozoic carbonate reservoirs and in Lower–Middle Jurassic sandstones (Kontorovich et al., 1997). In addition to the Togur bed, other transgressive shale beds (most importantly the bituminous Radom bed of late Toarcian to early Aalenian age) and Lower–Middle Jurassic argillites with occasional coals in the central and northern parts of the basin (including the Tyumen Formation, Figure 3) have fair to good partially realized generative potential and generated petroleum reser1490 Methanogenic Biodegradation in Western Siberia voired in Lower–Middle Jurassic sandstones where mature (especially in the northern part of the basin). In addition to the main Bazhenov and Togur source rocks, other source-prone formations in the basin exist and some of them could have generated petroleum. Ablya et al. (2008) suggested that Proterozoic carbonate source rocks may occur in the eastern part of the basin. Triassic deposits contain argillites with occasional coal inclusions (TOC of such rocks may be from <1 to 20%), which fully realized their generative potential in areas with significant burial (e.g., in the Nadym-Pur and Pur-Taz areas). Distal shales stratigraphically equivalent to Valanginian–Hauterivian clinoforms have good generative potential (present-day TOC of 4.5–9%) but are mostly immature and have not generated any known oils (Peters et al., 1994; Ulmishek, 2003). Hauterivian–Cenomanian deposits contain coal lenses and inclusions that have been proposed as source rocks for gas in Cenomanian accumulations (Nemchenko and Rovenskaya, 1968), although these rocks are mostly immature (Nalivkin et al., 1969; see discussion below). The Turonian Kuznetsovskaya (Kuznetsov, Figure 3) Formation, which is composed of transgressive shales, has generative potential but is immature in the basin. Petroleum accumulations occur in Paleozoic through Upper Cretaceous reservoirs (Figure 3). Sub-Jurassic reservoirs (sandstones, carbonates, weathered granites, and bauxites) contain more than 100 accumulations of oil and gas, with geological reserves (categories C1 + C2 in the Soviet and Russian reserves and resources classification scheme described by Poroskun et al., 2004) of about 1.5 BBOE (0.2 BTOE) (Zapivalov, 1999). However, most accumulations in western Siberia occur in Jurassic and Cretaceous clastic reservoirs (Figure 3). Oil accumulations occur mostly in the southern part of the basin (Figure 1) at a depth of 2000–3500 m (6562–11,482 ft) (Figure 5) in the Neocomian clinoform section (∼29% of the western Siberia oil endowment) and Lower–Middle Jurassic (mostly Tyumen Formation) continental sandstone reservoirs (∼20%). Brekhunzov (2006) estimated that 34% of the oil endowment in the basin has been found and 15% has been produced. Gas accumulations occur mostly in the northern part of the basin Milkov 1491 Figure 4. Maps of present-day maturity (expressed as standard thermal stress [STS], defined by Pepper and Corvi, 1995, as standard temperature quoted at a heating rate of 2°C/m.y.) of the regional Toarcian horizon (Togur Formation and age equivalents) (a) and the Bazhenov Formation (b) based on pseudo-3-D modeling. For the purpose of this regional study, the Toarcian horizon was assumed to be marine clay-rich shale with an initial hydrocarbon index (HI) of 250 mg hydrocarbon (HC)/g total organic carbon (TOC) in the northern part of the basin, and lacustrine shale with an initial HI of 500 mg HC/g TOC in the southern part of the basin. The Bazhenov Formation was assumed to be a homogenous siliceous marine shale across the basin with an initial HI of 400 mg HC/g TOC. Modeling was performed using Trinity (product of Zetaware) and multiple calibrated 1-D Genesis (product of Zetaware) models. Figure 5. Distribution of petroleum (including cumulative production and reserves with categories A-C2 in the former Soviet Union and Russian reserves and resource classification scheme described by Poroskun et al., 2004) versus depth in the West Siberian Basin (modified from Brekhunzov, 2006). (Figure 1). Most of the gas occurs at a depth of 700– 2000 m (2296–6562 ft) in Aptian–Cenomanian shallow-marine sandstone reservoirs (∼58% of the western Siberia gas endowment), whereas Neocomian (∼21%) and Lower–Middle Jurassic (∼13%) reservoirs are also important (Figure 5). Brekhunzov (2006) estimated that 49% of the gas endowment in the basin has been found and 12% has been produced. Condensates (25% of endowment is found, 2% is produced) occur mostly in Neocomian (39%) and Lower–Middle Jurassic (∼33%) reservoirs. Most of the Cretaceous oil and gas accumulations occur in structural traps. Traps in the Neocomian section are gentle anticlines with dips less than 2° and have closures from several tens of meters to 150 m (492 ft). The structural growth of anticlines in the southern part of the basin was most active in the Early–Middle Jurassic and continued to the Paleocene (Ulmishek, 2003). Most traps in 1492 Methanogenic Biodegradation in Western Siberia the Upper Cretaceous section in the northern part of the basin are elongated and have an amplitude of 1–1.5 km (0.6–0.9 mi). They began to form in the Neocomian and continued to grow in the postCenomanian. Some traps (including the Urengoyskoe field) formed mostly in the post-Cenomanian, with much of the structural growth during regional uplift and erosion in the Neogene (Ulmishek, 2003). Combination (structural-stratigraphic) and stratigraphic traps are less common in the basin, but they dominate in the Lower–Middle Jurassic section (Ulmishek, 2003). Upper Jurassic–Valanginian (Bazhenov Formation) and Turonian–Paleogene (Kuznetsov Formation) regional shale seals occur throughout the basin. Both seals become more sand prone and have less sealing capacity in the eastern part of the basin. Neocomian reservoirs are separated from Aptian– Cenomanian reservoirs by shales of the Kashayskaya and Alyimskaya formations of early Aptian age, but this seal is present mostly in the southern and central parts of the basin (Figure 3) and has sealing capacity generally poorer than the Upper Jurassic–Valanginian and Turonian–Paleogene seals (Korzenshtein, 1977). In addition to these main seals, subregional and local seals within the Jurassic–Cretaceous section exist (Peterson and Clarke, 1991). The petroleum system events charts presented by Ulmishek (2003) suggest that generation of petroleum by the Togur Formation started in the Late Cretaceous when Jurassic reservoirs, traps, and seals had already formed. Generation by the Bazhenov Formation also started in the Late Cretaceous and postdated trap and seal formation. Although several basin modeling studies were performed in the West Siberian Basin, most of them were either one-dimensional (Galushkin et al., 1999) or threedimensional (3-D) for a limited area and stratigraphy (Fjellanger et al., 2008). Basinwide pseudo3-D maturity modeling (Milkov, 2009) confirmed that the distribution of fluid phases in the basin (mostly gas in the north and oil in the south) is mostly controlled by source rock organofacies (Kontorovich et al., 1997) and the level of maturity (Nalivkin et al., 1969) of the main source rocks. Biodegradation of petroleum and generation of secondary microbial gas may be additional important factors affecting the fluid-phase distribution in western Siberia (Goncharov et al., 1983; Goncharov, 1987), which is discussed below. VOLUME OF SHALLOW DRY GAS IN THE WEST SIBERIAN BASIN Dry gas, defined here as greater than 99% methane and less than 1% C2+ compounds in total hydrocarbon gases, that is, dryness C1/(Sum of C1–C5) greater than 0.99, is abundant in the shallow reservoirs of the West Siberian Basin. Most Cenomanian pools (42 of the 44 studied fields or 95%) contain dry gas. Pangodinskoe (2.3% C2+ in hydrocarbon gases) and Etypurskoe (1.4% C2+ in hydrocarbon gases) are the only studied fields where Cenomanian pools do not contain dry gas as defined here, but these pools are relatively small and they are not discounted in the estimations of resources and reserves of dry gas. In the northern part of western Siberia, within the Yamal, Gydan, Nadym-Pur, and Pur-Taz petroleum areas (Figure 1), about 345 tcf (9.8 trillion m3) of gas has been produced from Cenomanian pools, and remaining reserves (A + B + C1 + C2 in Russian classification) were about 703 tcf (19.9 trillion m3) as of January 1, 2003 (Stroganov and Skorobogatov, 2004). Cenomanian gas pools are rare and relatively small in the middle Ob, Frolov, Kaymyisov, and Vasyugan petroleum areas, and gas reserves there perhaps do not exceed 15 tcf (0.4 trillion m3). In addition to reserves, Cenomanian gas pools may contain up to 422 tcf (12 trillion m3) of potential resource (C3 + D1 + D2 in Russian classification), mostly in the northern part of the basin (Brekhunzov, 2006). Therefore, the total volume of dry gas resource and reserves in Cenomanian pools of the West Siberian Basin may be approximately 1485 tcf (42.1 trillion m3). In addition to the giant Cenomanian pools, significant volumes of dry gas occur in other relatively shallow Cretaceous reservoirs. Although compositional data are limited (Stroganov and Skorobogatov, 2004), dry gas is present in Turonian reservoirs (Gazsolinskaya Formation) above the Cenomanian res- ervoirs in Russkoe, Zapolyarnoe, Yuzhno-Russkoe, Kharampurskoe, and some other fields. Brekhunzov (2006) estimated that Turonian reservoirs contain about 70 tcf (2 trillion m3) of gas in place as reserves and resources (A to D1–2 in Russian classification). Dry gas is also present in many (23% of 17 studied fields) Aptian–Albian reservoirs. Aptian– Albian reservoirs contain approximately 527 tcf (14.9 trillion m3) of gas resources and reserves (Brekhunzov, 2006), of which approximately 124 tcf (3.5 trillion m3) could be dry gas. Therefore, the total volume of dry gas resources and reserves in the Aptian–Albian (∼124 tcf [3.5 trillion m3]), Cenomanian (∼1485 tcf [42.1 trillion m3]), and Turonian (∼70 tcf [2 trillion m3]) pools of western Siberia is approximately 1679 tcf (47.6 trillion m3). If the world total mean endowment of conventional gas is 15,401 tcf (436 trillion m3) (Ahlbrandt et al., 2005), then shallow dry gas in western Siberia accounts for about 11% of that volume. In 2007, worldwide annual gas production was approximately 104 tcf (2.9 trillion m3) (BP, 2010), of which approximately 18 tcf (0.5 trillion m3) (or 17%) was produced from shallow pools in the northern part of western Siberia (Gazprom, 2010). Because most of the dry gas is located in the Cenomanian pools under good regional Turonian– Paleogene seal, I will concentrate mostly on those pools in the following discussion. CENOMANIAN POOLS More than 200 Cenomanian pools in more than 170 fields in the West Siberian Basin exist (Ermilov et al., 2004). Although most pools contain only gas (84.4% of pools), pools with both gas and oil (8.2%) and only oil (7.4%) are also seen, as found by Brekhunzov (2006) based on a study of the 96 largest Cenomanian pools. Most original gas reserves are concentrated in 74 Cenomanian pools, with greater than 50% of reserves in several supergiant pools (Ermilov et al., 2004), such as the Urengoyskoe (∼220 tcf [6.2 trillion m3]; Zhabrev, 1983) and Yamburgskoe (∼130 tcf [3.7 trillion m3]; Zhabrev, 1983) fields. Nemchenko et al. (1999) and Fjellanger et al. (2008) reported 330 tcf Milkov 1493 (9.3 trillion m3) in Cenomanian pools of the Urengoyskoe field, but this amount is actually total gas in all Cretaceous reservoirs. Most (and the largest) pools are located in the Nadym-Pur and Pur-Taz areas (Figure 1). Northern petroleum areas (Yamal, Gydan, and Ust-Yenisey) contain fewer and smaller Cenomanian gas pools, and the central and southern petroleum areas (middle Ob, Frolov, Kaymyisov, and Vasyugan) contain just a few of them. No significant Cenomanian gas pools are known (at least to the author) along the southern, southwestern (Near-Ural area), and southeastern (Paydugin area) borders of the West Siberian Basin. Dry gas is dominant in the Cenomanian pools, but oil also occurs, although very little has been produced. Seven pools with oil legs listed by Ulmasvay et al. (2008) contain approximately 20 billion bbl of oil (2.7 billion ton) reserves (A + B + C1 in Russian classification). All Cenomanian reservoirs may contain 7.3% of the oil reserves (A + B + C1 in Russian classification) and 2% of the oil resources (C3 + D1 + D2 in Russian classification) in the West Siberian Basin (Brekhunzov, 2006). Cenomanian pools occur mainly in structural traps (simple anticlines) with thick (100–700 m [328–2300 ft]), massive reservoirs composed of poorly cemented sandstones and siltstones of the Pokurskay (Pokur) Formation of Aptian, Albian, and Cenomanian age and its stratigraphic analogs (e.g., Marresalinskaya and Dolganovskaya formations, Figure 3). Crests of traps are relatively shallow and occur at depths ranging from 100 m (328 ft) in the western part to 1500 m (4921 ft) in the northern part of the basin (Brekhunzov, 2006) with most crests located at depths of about 400–1350 m (1300–4430 ft) (Khafizov, 1991). Column heights range from 5 to 235 m (16 to 770 ft) (average ∼70 m [230 ft]). Columns are largest in the area of the Urengoyskoe field, and they become progressively smaller away from that field (Ermilov et al., 2004). Many traps (13% according to Maksimov, 1987, or 46% according to Khafizov, 1991) are filled to spill point. Cenomanian pools are characterized by relatively cool present-day temperatures (∼5–43°C) and hydrostatic pressures (4.3–13.7 MPa [624–1987 psi]) at petroleum-water contacts. The Cenomanian reservoirs have high net-to-gross ra1494 Methanogenic Biodegradation in Western Siberia tios (average ∼82%), porosity (range 20–39%, normally 28–34%), and permeability (up to 7.6 d, normally 0.1–1 d) (Maksimov, 1987; Stroganov and Skorobogatov, 2004) and are believed to be connected by a common hydrodynamic system (Khafizov, 1991; Cramer et al., 1999). Petroleum accumulations are sealed by thick (up to 500– 850 m [1640–2789 ft]) Turonian–Paleogene shale. MOLECULAR AND ISOTOPIC COMPOSITION OF GAS IN CENOMANIAN POOLS Since the discovery of Cenomanian gas pools in the 1960s (first gas was found at the Tazovskoe field in 1962; Stroganov and Skorobogatov, 2004), numerous studies of the molecular and isotopic composition of the gas were performed to understand its origin (Ermakov et al., 1970; Vasiliev et al., 1970; Prasolov, 1990; Galimov, 1995; Cramer, 1997; Nemchenko et al., 1999; and others). For this study, I compiled a database with approximately 200 measurements of molecular composition from 46 Cenomanian gas and oil-gas pools (Figure 6). The average Cenomanian gas has 97.95% methane (C1), 0.23% C2+ gases, dominated by ethane (C2, 0.20%), 1.58% N2, 0.24% CO2, 0.029% He, 0.019% Ar, 0.019% H2, and no H2S. Such a dry composition (average dryness C1/Sum(C1–C5) is 0.9976, average C1/C2+ is ∼6120) of Cenomanian gases is confirmed by all researchers, and little disagreement between measurements from individual pools is observed. However, significant (up to 14‰) variations in published d13C of methane in gas samples from similar depth intervals in individual pools are observed. For example, in the Medvezhye field, seven carbon isotope measurements are performed on gas samples from 1127 to 1170 m (3697 to 3838 ft). In these samples, the d13C values of methane range from −58.3 (Ermakov et al., 1970) to −47.2‰ (Prasolov et al., 1981) and averages approximately −52.5‰ (relative to Peedee belemnite). This average value is closest to the most recent (late 1990s) and probably most accurate values of −52.3 and −53.3‰ (Cramer, 1997). I performed a statistical analysis of isotope measurements of similar (same field and Figure 6. Summary of molecular and isotopic composition of 887 free and dissolved gases from 266 pools in 185 oil, gas, and condensate fields of western Siberia. Minimum, maximum, and mean values for Cenomanian, Aptian–Albian, Neocomian, Jurassic, and Paleozoic pools of individual fields are shown. Minimum, maximum, and mean depths from which samples were obtained are indicated in the left graph next to ages of reservoirs. Data were compiled from numerous publications, most importantly from Ermakov et al. (1972), Alekseev (1974), Karpov and Raaben (1978), Prasolov (1990), Galimov (1995), Cramer (1997), Nemchenko et al. (1999), and Dvoretskiy et al. (2000). Milkov 1495 Figure 7. Comparison of d13C of methane measurements reported in the 1970s by Ermakov et al. (1970) and Alekseev (1974) (a) and d13C of methane measurements reported in the 1980s by Prasolov et al. (1981) and Prasolov (1990) (b) with more recent and likely more accurate measurements reported in the 1990s by Galimov (1995), Cramer (1997), and Nemchenko et al. (1999). Data for comparison were taken for gas samples at similar depths in 12 Cenomanian and 7 Jurassic–Lower Cretaceous reservoirs. reservoir, similar depths) gas samples from Cenomanian (16 sets) and Jurassic–Neocomian (7 sets) reservoirs by various researchers. Most measurements performed in the former Soviet Union in the 1970s (reported by Ermakov et al., 1970; Vasiliev et al., 1970; Alekseev, 1974; although data of Gavrilov et al., 1972, appear to be accurate) produced d13C values significantly (by 4.5– 10.6‰, average ∼7‰, Figure 7) more negative than recent and likely more accurate measurements made in the late 1990s in Russia (Galimov, 1995), United States (Nemchenko et al., 1999), and Germany and Russia (Cramer, 1997). In contrast, measurements performed in the former Soviet Union in the 1980s by Prasolov et al. (1981) and Prasolov (1990) produced d13C values significantly (by 1.5–6.7‰, average ∼4.5‰, Figure 7) more positive than those of Galimov (1995), Cramer (1997), and Nemchenko et al. (1999). For the purpose of this study, I corrected old (1970– 1980s) d13C values of methane to be more consistent with recent (1990s) presumably accurate measurements, and such corrected values are used in the presented data analysis (Figure 8). In addition, data from Nesterov et al. (1981) were ex1496 Methanogenic Biodegradation in Western Siberia cluded from the analyzed data set because they showed relatively poor correlation with reliable data obtained in the 1990s. Even after careful quality control of published isotope data, methane in 38 Cenomanian pools is characterized by a wide range of d13C values from −65.4 to −40.8‰, with an average of −51.8‰. Values of dD for methane (measured in 19 pools) range from −249 to −197‰ and average at −222‰ (relative to the standard mean ocean water). Only limited measurements of d13C of ethane (n = 8 pools, range from −42.8 to −25.4‰, average −31‰) and no isotope measurements of C3+ gases are observed because of low concentrations. A comparison of Cenomanian gas with gases in deeper reservoirs is shown in Figure 6, where molecular and isotopic compositions of free and oildissolved gases from 266 Cenomanian–Paleozoic pools in 185 fields from western Siberia are presented. Gas in Cenomanian pools is significantly drier and contains significantly less CO2 than gases in deeper pools. The amount of N2 in Cenomanian gases is approximately the same as in Aptian–Albian and Neocomian gases. Methane in Cenomanian pools is slightly depleted in 13C, but has dD similar Figure 8. Diagrams for interpreting gas origin in the West Siberian Basin. Each data point represents average values for one or more reservoirs of indicated age in one field. Reservoirs of fields specifically discussed in the article are labeled. Original values for individual samples come from numerous published sources, most importantly from Prasolov (1990), Galimov (1995), Cramer (1997), Nemchenko et al. (1999), and Dvoretskiy et al. (2000). (a) Relationship between stable carbon isotope composition (d13C) of methane and the ratio C1/(C2 + C3) in gases (Bernard diagram). The genetic fields of primary microbial and thermogenic gases are defined from Whiticar (1999), but with expansion of the thermogenic gas field based on findings of early-mature thermogenic gas (Milkov and Dzou, 2007), extension of the primary microbial gas field based on findings of primary microbial gas with 13C-enriched methane formed from 13Cenriched CO2 (Pohlman et al., 2009), and addition of the biodegraded and secondary microbial gas field defined in this study. (b) Relationship between stable carbon (d13C) and stable hydrogen (dD) isotope composition of methane. The genetic fields of primary microbial and thermogenic gases are defined from Whiticar (1999) but with extensions according to data of Milkov and Dzou (2007) and Pohlman et al. (2009). (c) Relationship between stable carbon isotope compositions (d13C) of methane and CO2. The genetic fields are defined from Whiticar (1999) but with extension according to data of Pohlman et al. (2009) and addition of a secondary microbial gas field defined in this study based on western Siberia data (from Schoell et al., 1997b), data from other locations with secondary methanogenesis, and the model of Jones et al. (2008). PM1, PM2, and PM6 are levels of biodegradation based on the scale of Peters and Moldowan (1993). (d) Relationship between stable carbon isotope compositions (d13C) of methane and ethane. The genetic fields are modified from Milkov (2005) using western Siberia data and published data from other basins. Milkov 1497 to methane in the deeper pools, whereas ethane has essentially the same carbon isotopic composition as gas in deeper pools. HYPOTHESES ON THE ORIGIN OF GAS IN CENOMANIAN POOLS Several hypotheses of the origin of dry gas in the Cenomanian pools have been suggested over the last 45 yr. Three most widely discussed hypotheses include (1) the thermogenic origin from early-mature coals within Hauterivian–Cenomanian formations (mostly the Pokur Formation) (Karogodin, 1964; Nemchenko and Rovenskaya, 1968; Galimov, 1995; Stroganov and Skorobogatov, 2004); (2) the primary microbial origin by reduction of CO2 liberated from dispersed organic matter or coals in the Pokur Formation (Ermakov et al., 1970; Schoell et al., 1997b) or organic matter in Turonian shales (Kuznetsov formation), which overlie the Cenomanian reservoirs (Clarke, 1989); and (3) migration of thermogenic gas from deeply (∼4–5 km [2.4– 3.1 mi]) buried Lower Cretaceous and Jurassic– Triassic source rocks (Prasolov, 1990). Grace and Hart (1990) and Fjellanger et al. (2008) argued for mixing of thermogenic (from Jurassic–Cretaceous sources) and primary microbial (from Pokur Formation) gases. Two hypotheses rarely discussed in the modern literature include an inorganic origin of Cenomanian gas from the basement or mantle (Nikonov and Shablinskaya, 1966) and biochemical formation from biodegraded oil (Goncharov et al., 1983). Early-Mature Thermogenic Gas from Coals Karogodin (1964) first implied that Cenomanian gas was generated during the maturation of humic organic matter within Cretaceous sediments. Nemchenko and Rovenskaya (1968) published a detailed study proposing that gas from Cenomanian pools in the Nadym-Pur and Pur-Taz areas (Tazovskoe, Urengoyskoe, Zapolyarnoe, and other fields) was generated by coals dispersed within Hauterivian–Cenomanian terrigenous sediments. These researchers observed coal inclusions (as thin 1498 Methanogenic Biodegradation in Western Siberia layers, lenses, and detritus) in cores, estimated the total weight (17.84 trillion tons) of coaly matter within the Hauterivian–Cenomanian sedimentary section (over area 223  109 m2 [86,100 mi2]), and calculated the amount of gas that was released by coals during metamorphism (1030 trillion m3 [36,260 tcf]) using simple assumptions about gas yields. Nemchenko and Rovenskaya (1968) concluded that even after accounting for gas loss (via sorption by coaly matter and sediments, escape to the atmosphere, and dissolution in water), pore waters of the Hauterivian–Cenomanian sediments were fully saturated with gas (total amount of 400 trillion m3 [14,120 tcf]) at the time of maximum burial (Neogene). Uplift in the Late Neogene led to exsolution of 200–250 trillion m3 (7060–8825 tcf) of this gas into a free phase and accumulation of free gas in Cenomanian reservoirs under the Turonian– Paleogene shale seal. In a later study (Nemchenko et al., 1999), more data were used and a similar workflow was applied to calculate that 1900 trillion m3 (67,070 tcf) was generated by coals within the Hauterivian–Cenomanian sediments, most of the gas was lost into the atmosphere, but 100–160 trillion m3 (3530–5650 tcf) exsolved into the free phase during uplift and became available for accumulation. Nemchenko et al. (1999) concluded that the amount of gas generated from early-mature coals was sufficient to explain the enormous volumes of dry gas in the West Siberian Basin. This conclusion contradicted the views of Nalivkin et al. (1969) who argued that the Hauterivian– Cenomanian section contains too little coaly organic matter (<1% on average), which is mostly immature and could not generate the amounts of methane necessary to saturate the pore waters. Assumptions made by Nemchenko et al. (1999) in mass-balance calculations are indeed inconsistent with conclusions from global evaluations of coal-derived gases. For example, Nemchenko et al. (1999) assumed an average methane yield from coals at the lignite (∼0.3% Ro) stage (most Aptian, Albian, and Cenomanian coals) of 68 m3 (2401 ft3)/ton and from coals at subbituminous to high-volatile bituminous (∼0.65% Ro) stage (most Hauterivian–Barremian coals) of 168 m3 (5933 ft3)/ton. However, numerous studies showed that methane is generated at maturity levels corresponding to Ro greater than 0.6%, most methane is generated at much higher maturity, and the cumulative methane yield is probably in the range of 150–200 m3/ton at ∼3% Ro (Rice, 1993). The Pokur Formation has Ro values ranging from 0.38 to 0.55% (Cramer, 1997) and may reach 0.65% (Nemchenko et al., 1999) in a small area near the Urengoyskoe field. The Ro of 0.6% is exceeded in the fetch area of the Urengoyskoe field only by sediments located at the present-day depth of 2.5–3 km (1.5–1.8 mi) (Galimov et al., 1990; Stroganov and Skorobogatov, 2004), which corresponds to the base of Hauterivian–Cenomanian sediments. In most other areas of the basin, Hauterivian– Cenomanian sediments were buried shallower than in the fetch area of the Urengoyskoe field (Ulmishek, 2003) and therefore are even less mature. Because of low maturity (generally <0.6% Ro), only very small amounts of methane (if any, Rice, 1993) could have been expelled by Hauterivian–Cenomanian coals, and the methane yields were significantly smaller than those assumed by Nemchenko et al. (1999). In addition, coals at such low maturity rank as observed in the Hauterivian–Cenomanian section retain most of the generated gas (Rice, 1993), which is inconsistent with another assumption of Nemchenko et al. (1999) that only approximately 16% (300 trillion m3 [10,590 tcf]) of methane generated by coals would be adsorbed. Velikovskiy et al. (1968) noted the dry (methanedominated) gas composition in Cenomanian pools and used arguments very similar to those of Nemchenko and Rovenskaya (1968) to conclude that gas formed from early-mature coal dispersed in the Pokur Formation. Ermakov et al. (1970) used the molecular and isotopic composition of gases from Cenomanian pools to further support the hypothesis of coalderived gas. They measured d13C of total hydrocarbon gases (which would be very similar to d13C of methane because gases are very dry) from eight Cenomanian pools and found values between −58.3 and −67.8‰ (as mentioned above, these values are ∼7‰ more negative than the accurate values). Ermakov et al. (1970) argued that gases in Cenomanian pools are similar to gases in modern swamps and thus were generated during the swamp stage (i.e., primary microbial origin) and early metamor- phism (i.e., early thermogenic origin) from coal within the Pokur Formation. Ermakov et al. (1970) dismissed the vertical migration of gas into Cenomanian reservoirs from Neocomian and Jurassic reservoirs because hydrocarbon gas in those older reservoirs is significantly more enriched in 13C (d13C from −45.6 to −38.5‰) than in Cenomanian pools. Galimov (1988) developed a concept that methane formation from humic organic matter is related to the condensation of aromatic rings, which is characterized by relatively low activation energies. An important consequence of the model is that humic organic matter should produce significant amounts of methane at relatively early stages of thermal maturation (0.4–0.7% Ro). Galimov et al. (1990) used this concept to suggest that the entire Pokur Formation was involved in gas generation because it experienced low levels (0.4–0.57% Ro) of thermal maturation. The authors presented new isotope measurements from Urengoyskoe and Samburgskoe fields and concluded that the d13C values of methane from Cenomanian pools (−49 to −48‰) is consistent with cumulative contributions from the Pokur Formation at early stages of transformation of organic matter. In a later article, Galimov (1995) presented the first measurements of dD for methane in Cenomanian pools. He argued that because methane is relatively depleted in deuterium, it likely originated from humic organic matter in Cretaceous sediments. The hypothesis of early-mature thermogenic gas from coals may be inconsistent with recent integrated geochemical and basin modeling studies of gas generation from coals in the Pokur Formation. Schoell et al. (1997b) performed gold-sealed-tube pyrolysis of immature Cenomanian coal and onedimensional (1-D) basin modeling in the area of the Urengoyskoe field. They found that because of high activation energy for methane (50–56 kcal/ mol) and low maturity of sediments within the Pokur Formation, coal-bearing sediments may yield (cumulatively) only 0.12 mL of methane per gram of coal in the location of the 1-D model. All Cretaceous coals in western Siberia (12–15  1012 tons) could have generated only 51–64 tcf (1.4–1.8 trillion m3) of methane (these values differ from Schoell Milkov 1499 et al., 1997b, because they were corrected according to communications with M. Schoell in 2009) if they were as mature as in the area of the Urengoyskoe field. These volumes are too small to explain the enormous volumes of dry gas in the basin (∼1679 tcf [47.6 trillion m 3] reserves and resources). Schaefer et al. (1999) performed an open-system programmed-temperature pyrolysis of eight sourcerock samples from the Pokur Formation and confirmed relatively high activation energy of coaly matter. At geological heating rates typical for the West Siberian Basin, methane generation peaks at temperatures of 160–190°C, and only a small amount of methane is generated at 100°C (onset of generation is ∼70°C). Schaefer et al. (1999) used 1-D basin models in the area of the Urengoyskoe field to estimate that the maximum paleotemperature of the Pokur Formation was 70°C at the top and 100°C at the base, and methane yield at the base varied from 0.4 to 2.1 mg/g TOC. Assuming an average cumulative methane yield of 1 mg/g TOC, an average TOC of 3%, a sediment thickness of 1000 m (3281 ft), and a catchment (fetch) area of 10,000 km2 (3861 mi2), 39 tcf (1.1 trillion m3) of methane could be generated from coals during thermal maturation. Based on present and paleostructural maps, the fetch area for the Urengoyskoe field (including the northern dome) is about 18,000–20,000 km2 (6950–7720 mi2). Therefore, the total amount of coal-derived gas should not exceed approximately 80 tcf (2.3 trillion m3) (before losses during migration, trapping, and preservation), which is significantly less than approximately 220 tcf (6.2 trillion m3) trapped in Cenomanian pools of the Urengoyskoe field (Zhabrev, 1983). Most recently, Fjellanger et al. (2008) performed a comprehensive 3-D basin modeling and found zero contribution of early-mature gas generated from Cretaceous sources to Cenomanian pools of the Urengoyskoe field. Several independent studies highlighted insufficient early-mature methane from coal to explain Cenomanian gas accumulations at the Urengoyskoe field. Estimates of methane yield from early-mature coals are apparently very sensitive to even small variations in paleotemperatures, as emphasized by 1500 Methanogenic Biodegradation in Western Siberia Schaefer et al. (1999). Existing basinwide estimates of paleotemperatures indicate that Aptian– Cenomanian sediments are mostly immature over the entire basin. Based on maps of Ermakov and Skorobogatov (1986), I estimated that the maximum paleotemperature (in early Oligocene prior to regional uplift) in the fetch area of the Urengoyskoe field was about 60–68°C (mean 62°C) at the top of Cenomanian and about 79–90°C (mean 82°C) at the base of Aptian, and paleotemperatures were similar or lower in the central and southern parts of the basin. Even lower maximum paleotemperatures in the fetch area of the Urengoyskoe field appear on maps of Kurchikov and Stavitskiy (1987): approximately 65–60°C (mean 58°C) at the top of Cenomanian and approximately 76–92°C (mean 79°C) at the base of Aptian (Figure 9). These paleotemperatures, which are cooler than estimated by Schaefer et al. (1999), would result in very small (<0.5 g/g TOC using kinetics of Schaefer et al., 1999) methane yields and would reduce the amount of coal-derived gas available for entrapment in the Urengoyskoe field (∼20,000 km 2 [7720 mi 2 ] fetch) to less than 50 tcf (1.4 trillion m3). Aptian–Cenomanian sediments in petroleum areas where most Cenomanian gas pools are concentrated (Nadym-Pur, Pur-Taz, Yamal, and Gydan) experienced maximum paleotemperatures of 47– 102°C (Kurchikov and Stavitskiy, 1987) (Figure 9) and perhaps could not have generated significant amounts of early-mature thermogenic gas. Schaefer et al. (1999) argued that some additional methane could have migrated from the southern part of the basin (Cramer et al., 1999), where the Pokur Formation is deeper and hence more mature. Maximum paleotemperatures could have reached approximately 85–113°C (mean 95°C) for the base of the Aptian sediments in the middle Ob area and approximately 63–107°C (mean 90°C) in the Kaymyisov and Vasyugan areas (Kurchikov and Stavitskiy, 1987). However, most of the basin has never experienced paleotemperatures greater than 100°C at the base of the Aptian section (Figure 9). Areas where the highest paleotemperatures (up to 122°C) were reached by the base of Aptian sediments (e.g., Krasnoleninsk area, Figure 9d) do not contain coal because sediments of the Pokur Formation were deposited in marine and lagoonal environments (Ulmishek, 2003). Gas and isotope compositional data obtained during pyrolysis experiments also do not support the hypothesis of early-mature gas from coal. Schaefer et al. (1999) showed that immature coaly organic matter (3–63 wt.% TOC) from the Pokur Formation generates significant amounts of ethane (C2) and propane (C3) gases, mostly during initial maturation. For a fully pyrolyzed sample of peat, dryness is 0.82–0.86, and first generated hydrocarbon gases, which are supposed to be captured in Cenomanian gas pools, appear to be even wetter. However, samples of gases from Cenomanian pools are very dry (average dryness is 0.9976, n = 44 pools). This inconsistency between pyrolysis results and natural observations argues against the earlymature thermogenic origin of Cenomanian gas and remained open in the discussion of Schaefer et al. (1999, p. 62). Cramer et al. (1998) measured d13C of methane generated during pyrolysis of two Pokur samples. They found that methane generated during the first 2.7% of total potential had d13C values of −53.5 to −38.2‰. In 38 Cenomanian gas pools, 12 (or 32%) pools have an average d13C methane value more negative than −53.5‰, which was the most negative value measured on earlymature methane from pyrolyzed samples of the Pokur Formation. Using data of Cramer et al. (1998), I calculated that the d13C of cumulative methane generated during the initial maturation (2.7% of total potential, which is similar to the realized generative potential of sediments near the base of the Pokur Formation in the area of the Urengoyskoe field) is approximately −40‰. However, all Cenomanian pools have average d13C of methane more negative than −40‰. Cramer et al. (1998) modeled that cumulative methane that could have been generated by the Pokur Formation would have a d13C of −46‰. However, 30 (or >80%) of the Cenomanian pools have methane significantly more depleted in 13C (Figure 8). Therefore, pyrolysis results suggest that early-mature thermogenic gas from coals is significantly wetter and has methane significantly more enriched in 13C than gas sampled from the Cenomanian pools. Coal-associated gases are commonly enriched in CO2 and N2 (Rice, 1993), but Cenomanian gases contain significantly less CO2 than gases in deeper pools and approximately the same amount of N2 as Aptian–Albian and Neocomian gases (Figure 6), which also suggests that gas in the Cenomanian pools was likely not generated by coals. The hypothesis of gas origin from early-mature coals is widely discussed and accepted in the recent literature (Stroganov and Skorobogatov, 2004; Ulmasvay et al., 2008). However, the above analysis of laboratory-derived kinetics data, gas geochemical data, and geological and thermal history of the Pokur Formation does not fully support it. Early-mature coals could have contributed some gas to Cenomanian accumulations, especially in areas of high paleotemperatures and wide coal distribution (e.g., the Bovanenkovskoe field in Yamal and the Leningradskoe field in the south Kara Sea, Fjellanger et al., 2008), but they apparently are not the main source of dry Cenomanian gas. Primary Microbial Gas Ermakov et al. (1970) suggested that Cenomanian gas pools formed as a result of the accumulation of swamp gases (i.e., primary microbial) and lowmature thermogenic gases from coals in the Pokur Formation. This hypothesis was supported by extreme dryness of the gas (almost pure methane) and d13C values of −67.8 to −58.3‰ measured in eight Cenomanian pools, which are typical of primary microbial gas (Schoell, 1983). As described above, these d13C values measured in the 1970s in the former Soviet Union are significantly more negative (by ∼7‰, Figure 7) than accurate values, which was also noted by Galimov et al. (1990). Goncharov et al. (1983) agreed that most Cenomanian pools could have formed from primary microbial gas by reduction of CO2 derived from organic matter. Rice and Claypool (1981) also accepted the interpretation of Ermakov et al. (1970) and used exceptionally large volumes of microbial gas in the former Soviet Union (dominated by presumably primary microbial gases in Cenomanian pools of western Siberia) to argue that greater than 20% of the world’s discovered gas reserves have a primary microbial origin. Milkov 1501 1502 Methanogenic Biodegradation in Western Siberia Based on pyrolysis of source rocks from the Pokur Formation, Schoell et al. (1997b) found that Cenomanian coals have a low activation energy distribution for CO2 (33–55 kcal/mol) and may release large amounts of CO2 during early maturation. Using results of 1-D basin modeling in the area of the Urengoyskoe field, they estimated that coals at the base of the Pokur Formation may release 21 mL of CO2 per gram of coal by low-temperature decarboxylation reactions. This process could produce 9000–10,000 tcf (255–283 trillion m3) of CO2 from 12–15  1015 tons of Cretaceous coal during their maturation. This large amount of CO2 could then be converted to methane by CO2-reducing microbes (Schoell et al., 1997b). Conditions in reservoirs within the Pokur Formation (low temperature and salinity, high porosity) are certainly favorable for the formation of primary microbial gas (Rice and Claypool, 1981; Clayton, 1992). In addition to the Pokur Formation, microbial gas could have been generated within Turonian shales (Kuznetsov Formation), which might then migrate downward into Cenomanian reservoirs (Clarke, 1989). However, gas geochemical data do not fully support the primary microbial origin of Cenomanian gas. Schoell et al. (1997a) concluded that only two of the analyzed gases (from Malyiginskoe and Zapadno-Seyakhinskoe fields in the northern Yamal, Figures 1, 8) have molecular and isotopic compositions of primary microbial gases, whereas the compositions of most Cenomanian gases are “inconsistent with a bacterial origin” (Schoell et al., 1997a, p. A103). Although Cenomanian gases are dry, the d13C of methane in most accumulations (36 pools out of 38 studied here, or 95%) is more positive than −60‰ (Figure 8), which commonly separates primary microbial methane from CO2 reduction and 13C-enriched methane of thermogenic or mixed origin (Whiticar, 1999) in conventional commercial petroleum accumulations. Although measurements of d13C of ethane are rare (n = 8), the average value of −31‰ is inconsistent with a primary microbial origin (Figure 8d). Acetate fermentation is important in freshwater environments, and the salinity of waters from the Pokur Formation is indeed relatively low: 8–19 g/L within gas caps and 18–19 g/L below gas-water contacts (GWCs; Khafizov, 1991). Acetate fermentation can produce methane with a d13C of −65 to −50‰ (Figure 8a) and thus could explain the origin of gas in 28 of 38 studied Cenomanian pools (74%). However, the average dD of methane (measured in 19 fields) is −222‰ (range from −249 to −197‰), which is more positive than −400 to −250‰ typical of methane from acetate fermentation (Figure 8b). Therefore, I agree with Schoell et al. (1997a), but not with Schoell et al. (1997b), that gas in most Cenomanian pools is not primary microbial gas, although the contribution of such gas to some accumulations cannot be excluded (Fjellanger et al., 2008). In contrast, shales and siltstones within the Turonian–Paleogene section obviously contain very dry primary microbial gases with a d13C methane value approximately of −75‰ (as measured within the Bovanenkovskoe field area by Bondarev et al., 2008), which, contrary to suggestion of Clarke (1989), apparently have not migrated downward in significant amounts. Deep Thermogenic Gas The hypothesis of deep thermogenic gas origin was initially rooted in the concept of oil and gas windows formulated in the 1960s in the former Soviet Union (Vassoevich, 1967) and later supported by gas geochemical data (Prasolov, 1990). Nalivkin and Chernikov (1967) studied rocks and oils from a limited petroliferous area discovered in western Siberia by the mid-1960s (mostly the middle Ob and Frolov areas) and argued for vertical migration of petroleum from Jurassic source rocks to Cretaceous Figure 9. Present-day (a, b) and maximum (c, d) paleotemperatures at the top Cenomanian (a, c) and base Aptian (b, d) of the Pokur Formation (based on maps of Kurchikov and Stavitskiy, 1987, with additions from Skorobogatov et al., 2003, and Skorobogatov and Stroganov, 2006). Cenomanian accumulations are outlined by brown polygons. Original maps of present-day temperatures were constructed using corrected data measured by mercury thermometer during well tests and temperature logging at 650 fields and prospects in western Siberia (Kurchikov and Stavitskiy, 1987). Maps of maximum paleotemperatures were constructed using models of basin evolution and heat conduction as described by Kurchikov and Stavitskiy (1987). Milkov 1503 reservoirs. Nalivkin et al. (1969) and Prozorovich (1973) stated that gas in giant Cenomanian pools in the northern part of the basin originated from cracked oil in deeply buried reservoirs and Jurassic source rocks buried in the gas window. They also suggested that a pressure drop caused by uplift in the Neogene led to gas exsolution from water, which played an important role in the formation of the gas pools. According to Neruchev et al. (1984), the gas in Cenomanian pools was generated by Lower–Middle Jurassic source rocks (Tyumen Formation) buried to the gas window at a depth of 4–4.5 km (2.4–2.7 mi). Prasolov et al. (1981) and Prasolov (1990) studied the molecular and isotopic composition of hydrocarbon gases as well as nitrogen, helium, and argon in a large number of petroleum pools in the Paleozoic–Cretaceous reservoirs of western Siberia. They found that methane in Cenomanian pools is depleted in 13C (n = 19, d13C = −46.7 ± 6.0‰) relative to methane in Jurassic and Lower Cretaceous pools (n = 35, d13C = −38.0 ± 3.5‰). As described above, these d13C values measured in the 1980s in the former Soviet Union are significantly more positive (on average by ∼4.5‰, Figure 7b) than accurate values. Based on the carbon isotope composition of methane, Prasolov (1990) suggested that the Cenomanian gases have a thermogenic origin and formed at an approximately 4-km (2.4-mi) depth in Triassic–Jurassic and Lower Cretaceous source rocks. These gases migrated vertically for 2–3.5 km (1.2–2.1 mi) to fill the traps. Gases in Jurassic and Lower Cretaceous pools formed at 7–8-km (4.3–4.9-mi) depths and migrated vertically for 4–5 km (2.4–3.1 mi) to fill the traps. Gases generated at two depth intervals (∼4 km [2.4 ft] and 7–8 km [4.3–4.9 mi]) mixed most extensively in the Nadym-Pur and Pur-Taz areas where most large Cenomanian gas pools are concentrated. Some Cenomanian pools (e.g., in Tazovskoe, Russkoe, Messoyakhskoe, Neitinskoe, Pangodinskoe, and Yamsoveyskoe fields) contain methane with carbon isotope compositions more similar to gases in the Neocomian pools, which suggests most vertical migration of gases from the deeper source. These conclusions based on carbon isotope data are broadly supported by isotopic compositions of noble gases. 1504 Methanogenic Biodegradation in Western Siberia For example, gases in Cenomanian pools have an average 40Arair/40Arradiogenic ratio of 8 (n = 14), whereas in the Jurassic and Lower Cretaceous pools, this ratio is 1.1 (n = 19) (Prasolov, 1990). However, in the Tazovskoe, Messoyakhskoe, and Pangodinskoe fields, where methane in Cenomanian pools is enriched in 13C relative to the other pools, gases are also enriched in 40Arradiogenic, supporting vertical migration from great depths. Prasolov (1990) concluded that vertical migration of gases is the dominant process in western Siberia, and only some gases dissolved in water may have originated in situ. The hypothesis of a deep thermogenic origin of the gas in Cenomanian pools is consistent with the geological setting of the northern part of western Siberia. Proven deep mature source rocks exist, especially Upper Jurassic (Bazhenov Formation) and Lower–Middle Jurassic sources (Chakhmakhchev et al., 1994; Peters et al., 1994). Many traps at the Cenomanian level have directly underlying structural (anticlines) traps in the Albian–Jurassic section with petroleum (e.g., Maksimov, 1987), and seals between the Jurassic source rocks and Cenomanian traps are mostly (except for the Bazhenov Formation) local and poor (Peterson and Clarke, 1991), which promotes vertical migration. However, gases in Cenomanian pools are much dryer (average C1/C2+ = 6121, n = 44 pools) than expected for thermogenic gases generated at approximately 4 km (2.4 mi) by Jurassic source rocks. In addition, gases in Jurassic–Neocomian reservoirs, which according to Prasolov (1990) were generated even deeper and therefore should be drier (Goncharov et al., 1983; Whiticar, 1999), actually are relatively rich in C2+ gases (Figure 8a), which is typical of thermogenic gas from oil-prone source rocks. Prasolov (1990) did not explain the high dryness of gases in Cenomanian pools. However, it is apparent that the almost pure methane composition is a well-documented distinctive feature of these pools, which is not fully consistent with the hypothesis of simple vertical migration of deep thermogenic gas. Gas from the Crust Nikonov and Shablinskaya (1966) studied the distribution of oil and gas fields in western Siberia and observed that oil fields in the middle Ob area occur mostly where basement formed during the ancient Archean–Baikalian orogeny and is overlaid by slightly metamorphosed Paleozoic sedimentary rocks. Gas fields (including Cenomanian pools of the Tazovskoe field) occur over the basement formed during the Hercynian orogeny that was penetrated by granite intrusions. Based on these observations, the authors (also Nikonov, 1967) suggested that petroleum enters the sedimentary cover from the basement, and compositional heterogeneities within the basement, as well as deep faults penetrating into the crust (conduits for gases) and below the crust (conduits for oil) are the main factors controlling the distribution of oil and gas in western Siberia. This hypothesis was developed based on observations of a limited number of petroleum accumulations discovered in the basin up to the mid-1960s. Numerous later geological and geochemical studies of the West Siberian Basin dismissed this hypothesis of inorganic origin of petroleum and found that the occurrence of oil and gas accumulations is controlled by richness and maturity of source rocks, distribution of reservoirs, presence of traps, and quality of seals (e.g., Kontorovich et al., 1975). Secondary Microbial Methane from Biodegraded Oil Goncharov et al. (1983) suggested that the molecular and isotopic composition of gases in the northern part of western Siberia can be explained by microbial reduction of CO2 to methane. They proposed that some CO2 may be derived from organic matter and that most Cenomanian pools formed from primary microbial gas. However, they argued that biodegradation of oil may also produce significant amounts of CO2. This oil-derived CO2 can then be reduced to methane by microbes, which may lead to formation of gas caps above oil pools in Cenomanian reservoirs (e.g., Russkoe field). This mechanism appears to be supported by elevated methane and relatively low CO2 concentrations near oil-water contacts (OWCs) in pools of biodegraded oil (e.g., in the Surgut area) as well as observations of carbonate cement depleted in 13C near the OWC (Golyshev et al., 1981). Therefore, Goncharov et al. (1983) found the first evidence of secondary microbial gas in the subsurface long before such evidence was reported in the Western literature (Scott et al., 1994; Pallasser, 2000). In a later publication, Goncharov (1987) further developed the idea of secondary microbial gas and suggested that many condensates in cool (<70°C) Aptian, Albian, and Cenomanian reservoirs in the northern part of western Siberia (e.g., in the Urengoyskoe field) resulted from dissolution of light oil compounds in secondary microbial methane. The hypothesis of secondary microbial gas in Cenomanian pools with oil leg and residual oil developed by I.V. Goncharov (Goncharov, 1981, 1987) was not accepted in the former Soviet Union and Russia where most researchers support either earlymature thermogenic coal-derived gas (Stroganov and Skorobogatov, 2004; Galimov, 2006) or deep thermogenic gas (Vyishemirskiy and Kontorovich, 1999). Because it was published only in Russian, Goncharov’s hypothesis did not come to the attention of Western researchers, and it was never mentioned in discussions of Cenomanian gas (Grace and Hart, 1986; Peterson and Clarke, 1991; Ulmishek, 2003), although Murris (2001, p. 1892) independently proposed that “…one may have to look for transformation of thermal gas by bacteria in the reservoir” to explain Cenomanian gas pools. However, the failure of all other hypotheses to fully explain the enormous volumes and the molecular and isotopic composition of Cenomanian gases, recent discoveries of secondary microbial methane around the world, and numerous laboratory experiments confirming secondary methanogenesis warrant a comprehensive evaluation of this hypothesis, which is the main objective of this study. SECONDARY MICROBIAL GAS: REVIEW OF LABORATORY STUDIES AND SUBSURFACE OCCURRENCES Although the term “secondary biogenic (microbial) gas” was introduced relatively recently by Scott et al. (1994), the process of secondary methanogenesis was observed in laboratory experiments and suspected Milkov 1505 to occur in the subsurface long ago in the former Soviet Union. Ginsburg-Karagitscheva (1933) conducted laboratory experiments showing that waters from Apsheron oil wells (maximum depth of 900 m [2953 ft]) contain microbes capable of generating methane, H2, CO2, N2, H2S, and NH3 under anoxic conditions. Bokova (1953) studied generation of gases in a flask containing a mixture of heavy oil from Sakhalin (2 mL), sand, mineral solution (1000 mL of water, 52 g of various salts, pH 7.2), and 2 mL of culture material. During the 2-yr experiment, 450 mL of gas composed of methane (20.9%), C2+ gases (0.008%), CO 2 + H2S (4.6%), H 2 (0.6%), and nonflammable gases (73.9%) formed in the flask. Microscopy showed numerous microbes populating oil drops. Based on this experiment, Bokova (1953) suggested that methane generation during oil biodegradation may be an important factor in the evolution of oil fields. Ekzercev (1960) studied cores, waters, and oils sampled from Permian, Carboniferous, and Devonian reservoirs from oil fields in the Volga-Ural Basin (Russia) and documented the presence of microbes that degrade oil while forming gas, degrade fatty acids to gas, form methane from CO2 and H2, and reduce sulfate. Laboratory experiments showed that gas (methane up to 40%) was generated from oil under anoxic conditions in the presence of core material from oil fields (supposedly with anaerobic microbes) and mineral solutions. Experiments with microbial cultures extracted from oil field core materials proved that microbes can generate gas while biodegrading oil under anoxic conditions. The formed gas was dominated by N2 (60–78%) and contained methane (15–35%), CO2 (1.6–5.0%) and in some cases H2 (0–5%). Ekzercev (1960) suggested that methane forms from (1) fatty acids in oils degraded to methane and CO2 and (2) CO2 reduction by H2. He proposed that methane from biodegraded oils may be a component of gas in petroleum reservoirs. In the Western literature, reports of methanogenesis during petroleum biodegradation in laboratory experiments started to appear only in the last decade. Zengler et al. (1999) used enrichment cultures to show that biological conversion of longchain alkanes to methane occurs under strictly an1506 Methanogenic Biodegradation in Western Siberia oxic conditions. They assumed that the active organisms are acetogenic (syntrophic) bacteria decomposing hexadecane to acetate and H2 (4C16H34 + 64H2O → 32CH3COO- + 32H+ + 68H2), a group of archaea cleaving acetate into methane and CO2 (32CH3COO- + 32H+ → 32CH4 + 32CO2), and another group of archaea converting CO2 and H2 to methane (68H2 + 17CO2 → 17CH4 + 34H2O). Anderson and Lovley (2000) confirmed anaerobic microbial conversion of hexadecane to methane and suggested that conversion of alkanes to methane is likely to be significant in many petroleum reservoirs. Jones et al. (2008) monitored the hydrocarbon composition of biodegraded oils and generated gases. They proposed that the dominant pathway of methane generation is syntrophic acetate oxidation (CH3COOH + 2H2O → 4H2 + 2CO2) coupled to hydrogenotrophic methanogenesis with no need for an external source of H2 (4H2 + CO2 → CH4 + 2H2O), whereas acetoclastic methanogenesis (CH3COOH → CH4 + CO2) may play a smaller role. Other laboratory studies further documented methanogenesis from biodegraded oil: Townsend et al. (2003) suggested that naphtalene-rich oils could be a result of methanogenic biodegradation; Siddique et al. (2006) showed methanogenic biodegradation of short-chain n-alkanes and an unusual biodegradation sequence (C10 > C8 > C7 > C6); Gieg et al. (2008) suggested the importance of acetoclastic methanogenesis; and Gray et al. (2009) measured the activity and growth of hydrogenotrophic methanogens but did not detect acetoclastic methanogenesis in formation waters from a North Sea oil-rimmed gas accumulation. Although laboratory studies have repeatedly demonstrated that methane can form during biodegradation of oil, limited studies of such methanogenesis in the subsurface still exist. Scott et al. (1994) studied coalbed gases in the San Juan Basin (United States) and proposed that a significant part (15–30%) of these gases was derived from microbial degradation of wet gas components, n-alkanes, and other organic compounds at relatively low temperatures. In coal beds, microorganisms generating secondary microbial methane are introduced into the coals by meteoric waters after burial, coalification, uplift, and erosion of basin margins (Scott et al., 1994). Evidence of secondary microbial gases in coal beds has been found in Australia (Ahmed and Smith, 2001), Poland (Kotarba, 2001), and China (Tao et al., 2007). Etiope et al. (2009) found that 50% of the terrestrial mud volcanoes from around the world expel thermogenic or mixed hydrocarbon gases with 13C-enriched CO2 (d13C> + 5‰), which may suggest the formation of secondary microbial methane in the underlying petroleum accumulations or along migration pathways. Secondary microbial methane may also occur in submarine seeps and mud volcanoes (e.g., Bourry et al., 2009). Chaplin et al. (2002) and Bekins et al (2005) documented a long-term progression of methanogenic biodegradation at a shallow crude-oil spill site near Bermidji, Minnesota. As discussed above, Goncharov et al. (1983) and Goncharov (1987) were perhaps the first to suggest that secondary microbial gas formed during biodegradation of oil in reservoirs may accumulate as gas caps or gas condensates. To date, evidence of secondary microbial methane in petroleum accumulations has been reported from 19 basins (Figure 10). Jeffrey et al. (1991) found that gases dissolved in biodegraded oil in shallow reservoirs of the Whittier and Salt Lake fields in the Los Angeles Basin (California) are biodegraded and have elevated CO2 (10–37.2%), which is enriched in 13C (d13C range from +14.6‰ to +21.7‰). They attributed the high concentration of CO2 to biodegradation and inferred that enrichment in 13C could result because the CO2 is residual gas from partial conversion of oil-derived CO2 into secondary microbial methane. Sandal (1996) described the Champion field offshore Brunei Darussalam where high (up to >80%) CO2 is probably related to the biodegradation of oil (17–25° API) at less than 1500 m (<4921-ft) depth. Associated hydrocarbon gas is dry (C1/C2 is approximately 1000), and methane is relatively enriched in 13C (d13C values range from −52 to −44‰), which may indicate that methane is, at least partially, secondary microbial (Jones et al., 2008). Pallasser (2000) interpreted some gases in the Australian North West Shelf and Gippsland and Otway basins as secondary microbial gases. These gases occur in relatively shallow (600–1700 m [1968–5577 ft]) and cool (<75°C) reservoirs, are rel- atively dry (mean dryness is 0.94 in the Gippsland and Otway basins and 0.99 in North West Shelf), contain 13C-enriched CO2 and relatively abundant N2, and are commonly underlain by biodegraded oil. Masterson et al. (2001) found that gas dissolved in moderately biodegraded oil in the West Sak field (North Slope, Alaska) is biodegraded, dry, and likely contains microbial methane generated during CO2 reduction under anoxic conditions. Methane (d13C from −56 to −40‰) in shallow (<2000 m [6562 ft]) biodegraded oil and gas pools in Azerbaijan was interpreted as mixed thermogenic and primary microbial methane (Katz et al., 2002) but may have, at least partially, secondary microbial origin because it associates with highly variable CO2 content (from 0.56% to 25%) and highly variable d13C of CO2 (from −20 to +22‰) (Feyzullayev and Movsumova, 2001; Katz et al., 2002). Dessort et al. (2003) and Duclerc et al. (2009) observed biodegradation of oil and C2+ gases offshore west Africa and suggested that a strong relationship between the d13C of methane (from −68 to −45‰) and the d13C of CO2 (from −19 to +10‰) indicates that 13C-enriched methane probably derived from CO2 reduction. Larter and Di Primio (2005) studied some of the oil-rimmed gas accumulations in the North Sea, including Troll field, which is the largest petroleum accumulation in the basin (2245 million tons or ∼15.7 BBOE, of which 74% is gas and 26% is heavily biodegraded oil, Horstad and Larter, 1997). These accumulations contain large gas caps that are biodegraded and relatively dry (>90 mol% methane), overlying biodegraded oil legs (up to 30 m [98 ft] thick). Methane addition to the accumulations during oil biodegradation could be an important process in these and other similar accumulations in the North Sea (e.g., Captain field, Pinnock and Clitheroe, 1997). Huang et al. (2005) suggested that secondary microbial gases occur in the Liaohe basin (northeast China). Zhu et al. (2005) described shallow gas accumulations in Neogene reservoirs (depth <1500 m [4921 ft], temperature <70°C) in the Jiyang superdepression of the Bohai Bay Basin (China). These accumulations of relatively dry gases (>95% methane) occur as gas caps overlying biodegraded oil pools or as free gas above or updip from Milkov 1507 1508 Methanogenic Biodegradation in Western Siberia Figure 10. Worldwide distribution of petroleum reservoirs where the presence of secondary microbial gas is supported by geological and geochemical evidence or is possible. Basins with heavy oil and bitumen are outlined based on Meyer et al. (2007) and basins with proven biodegradation are identified based on published data (more such basins may be identified in future studies). See the text for a description of specific areas and references. biodegraded oil pools, and their formation apparently resulted from anaerobic biodegradation of oil. Zhang et al. (2009) observed dry gas accumulated as gas caps and gas pools above and updip from biodegraded oil pools in the Songliao Basin (northeast China). They presented geochemical evidence, including high N2 content of gases and relatively high values of d13C of CO2, suggesting that secondary microbial gas is a component of petroleum accumulations in that basin. Milkov and Dzou (2007) presented geochemical evidence of secondary methanogenesis from slight biodegradation of oil in a deep (∼5300 m [17,388 ft] below sea floor) hot (∼115°C) reservoir in the Gulf of Mexico. Data suggest that methane generated by microbial degradation of thermogenic hydrocarbons, although masked by mixing with primary microbial methane, may also occur within the Nile Delta (Vandré et al., 2007). Lillis et al. (2007) observed a high concentration of CO2 (>2%) enriched in 13C (d13C is from +2 to +24‰) in relatively dry (<2% C2+) gases dissolved in biodegraded oils in shallow reservoirs of the San Joaquin Basin (California). They suggested that such CO2 is the residual gas from methanogenic petroleum biodegradation. Waseda and Iwano (2008) described gas accumulations with high (>5%) and 13C-enriched (d13C from +5 to +30‰) CO2 associated with biodegraded oil in Japan and suggested that methanogenesis during oil biodegradation is significant in the subsurface. Secondary microbial origin was proposed for gas in the Antrim Shale on the northern margin of the Michigan Basin (United States), where methane (d13C approximately −50‰) production is associated with established moderate biodegradation of extractable hydrocarbons (Formolo et al., 2008), 13C-enriched dissolved inorganic carbon (d13C approximately +30‰), and 13C-enriched CO2 (d 13 C between +15 and +20‰) (Martini et al., 2003). Larter et al. (2009) and Jones et al. (2008) suggested the presence of secondary microbial methane in oil-dissolved and free (as thin gas caps above biodegraded oils) phases across the Alberta (Canada) sands. Lorenson et al. (2009) proposed that hydrate-bound gas in the Mount Elbert gas hydrate stratigraphic test well, North Slope of Alaska, partially originated from deeper biodegraded oils. In addition to 19 basins with well-documented geological and geochemical evidence of secondary microbial methane listed above, secondary microbial methane is possible in petroleum accumulations from the Emba area and Buzachi peninsula in Kazakhstan; the Cuban, Volga-Ural, Timan-Pechora, and Leno-Viluy petroleum areas in Russia; the Dneprovo-Donetsk area in Ukraine (Ermakov et al., 1972; Zorkin et al., 1984); the Cook Inlet region in Alaska (Claypool et al., 1980); and Po Basin in northern Italy (Mattavelli et al., 1983) (Figure 10). Although subsurface occurrences of secondary microbial methanogenesis are now documented from sedimentary basins around the world (Figure 10), the global volumetric importance of this pathway of natural gas generation is unclear. Rice and Claypool (1981) and Rice (1992) suggested that about 20% of the global gas endowment may be composed of dry primary microbial gases. Pallasser (2000) argued that reassessment of this resource is probably warranted because oil may be an important source for many dry gases. Most of the gases described as primary microbial gases by Rice and Claypool (1981) and Rice (1992) occur in the Cenomanian pools of western Siberia. Therefore, further study of these pools is necessary to properly assess the contribution of gases of various origins to the world gas endowment. EVIDENCE FOR SECONDARY MICROBIAL GAS IN WESTERN SIBERIA Oil in Cenomanian Pools Although most Cenomanian pools contain gas, many contain oil ( Table 1, Figure 11). Pools in two fields (Ayyaunskoe in the Kaymyisov area and Kharampurskoe [PK3–13 pools] in the PurTaz area) contain oil without gas caps. At least nine fields exist (Pangodinskoe, Russkoe, Severnoe, Severo-Komsomolskoe, Tagulskoe, Tazovskoe, Vanyeganskoe, Vostochno-Messoyakhskoe, Zapadno-Messoyakhskoe) with 10–70-m (33– 230-ft)-thick oil legs below gas caps (Goncharov, 1987; Nemchenko et al., 1999; Ermilov et al., Milkov 1509 1510 Methanogenic Biodegradation in Western Siberia Table 1. Main Reservoir and Oil Characteristics of Some Cenomanian Petroleum Accumulations in Western Siberia* Field Petroleum Area Ayyaunskoe Kharampurskoe Messoyakhskoe Kaymyisov Pur-Taz Ust-Enisey 1 1 1 959 1417 848 Novoportovskoe Yamal 1 556 PK1 Pangodinskoe Russkoe Severnoe SeveroKomsomoslkoe Tazovskoe Vanyeganskoe Verhnepurpeyskoe Nadym-Pur Pur-Taz Vasyugan Nadym-Pur 3 11 1 1 1274 889 950 1106 PK1 PK1 PK1 PK1 Pur-Taz Nadym-Pur Nadym-Pur 1 7 1 1162 968 1071 PK1 PK1 PK1 ? 425 PK1 Verkhorechenskoe Polar Ural Number of Approximate Reservoir Samples Depth (m) Name PK1 PK3–11 DL1 Reservoir Fluid Oil Oil Gas, residual oil or leg Gas, residual oil or leg Gas, oil leg Gas, oil leg Gas, oil leg Gas, oil leg Gas, oil leg Gas, oil leg Gas, residual oil or leg ? Temperature API Gravity Sulfur Wax Nitrogen Resins Asphaltenes (°C) (°API) (wt.%) (wt.%) (wt.%) (wt.%) (wt.%) References** 43 (?) 41 12 14.7 27.6 20.7 1.7 0.36 0.1 1.87 nd 0 0.23 nd nd 20.7 nd 19.8 6.32 nd 0.63 1, 2 3 1, 2 6 22.3 nd nd nd nd nd 4, 2 39 19 35 35 22.4 18.8 15.3 16.8 0.215 0.36 0.98 0.7 1.1 1.06 2.08 1.98 0.15 0.2 0.44 0.24 5.31 9.77 18.2 11.6 0.24 1.4 4.79 1.83 1, 5, 2 1, 6, 2, 3 1, 2 1, 2 24.5 31 31 20.7 15.6 18.7 0.21 0.94 1.29 1.6 0.98 1.59 0.12 0.26 0.15 7.47 14.49 12.1 0.22 2.79 2.67 1, 2 1, 6, 2 1, 2 18.9 0.41 0.2 0.07 6.81 0.3 1 5 (?) *nd means no data and ? means that data are uncertain. **References: (1) Goncharov (1987), (2) Maksimov (1987), (3) unpublished GeolabNor data, (4) Punanov and Chakhmakhchev (1989), (5) Nemchenko et al. (1999), (6) Peters et al. (1994). Figure 11. Occurrence of live (oil pool or leg) and residual oil in Cenomanian pools of the West Siberian Basin. This map is based on published data, and it is likely that many more pools with live or residual oil occur in the basin. Milkov 1511 Figure 12. Distribution of biodegraded oils (a) and their present-day depth and temperature (b) in the West Siberian Basin. Heavy, moderate, and slight biodegradation is defined from Wenger et al. (2002), and typical whole oil-gas chromotogram traces are shown. Data are based on Goncharov (1987) and unpublished data from the GeolabNor/Fugro. The author believes that many more biodegraded liquids occur in the northern part of the basin. 2004). In addition, the Vyngapurovskoe and Komsomolskoe fields apparently contain thin oil legs (Ulmasvay et al., 2008). Many other heavy oil legs in Cenomanian traps were likely missed during exploration drilling because they are hard to identify on well logs (Brekhunzov, 2006). Geological reserves (A + B + C1 in Russian classification, as of January 1, 2003) of liquids (oil and condensates) in Cenomanian pools were estimated for five fields: Vyngapurovskoe (0.02 billion bbl of oil), Komsomolskoe (0.03 billion bbl of oil), VostochnoMessoyakhskoe (0.43 billion bbl of oil), ZapadnoMessoyakhskoe (1.65 billion bbl of oil), Tazovskoe (1.83 billion bbl of oil), Severo-Komsomolskoe (5.12 billion bbl of oil), and Russkoe (10.98 billion bbl of oil) (Ulmasvay et al., 2008). Where sampled and analyzed, oils and condensates in Cenomanian pools are heavily biodegraded to level 6 of Peters and Moldowan (1993) as determined by Peters et al. (1996). This is apparent from 1512 Methanogenic Biodegradation in Western Siberia bulk oil properties (average density 19.4° API, high viscosity, Table 1), bulk composition (napththenic polycyclic hydrocarbons prevail), dominance of unresolved complex mixture (UCM) of branched and cyclic compounds in whole oil-gas chromatograms (WOGCs, Figure 12), and the presence of 25-norhopanes as documented by Peters et al. (1996) for the Vanyeganskoe field. In addition, residual oil was observed within many Cenomanian gas pools. For example, in the Messoyakhskoe field (Ust-Enisey area) heavy oil occurs within the gas pool and in the interval 6–12 m (20–39 ft) below the gas-water contact (Ermakov et al., 1972) and may form a thin oil leg (Darovskih et al., 2007). In the Russkoe and Tazovskoe fields, oil was observed within gas caps as well as up to 30 m (98 ft) below the present-day OWC (Ermakov et al., 1972) and 50 m (164 ft) above the Cenomanian reservoir in the Turonian shale seal (in well 3 of the Tazovskoe field) (Khafizov, 1991). Residual oil within Cenomanian gas pools was found in the Samotlorskoe, Varyeganskoe, Gubkinskoe, Verkhorechenskoe (Goncharov, 1987), Verkhnepurpeyskoe (which may have an oil leg, Stroganov and Skorobogatov, 2004), Novoportovskoe (may have an oil leg, Maksimov, 1987), YuzhnoTambeyskoe (Punanov and Chakhmakhchev, 1989), and Yuzhno-Russkoe fields. Where observed, saturation of residual oil is low (1–3%) in clean sandstones, but reaches 10–20% in shaly sandstones (Khafizov, 1991). Based on core and well-log observations, residual oil is inferred in Cenomanian gas pools of the Urengoyskoe, Zapolyarnoe, Yubileynoe, and other fields, and saturation of residual oil appears to decrease from seal to GWCs (Khafizov, 1991). Where analyzed, residual oils are heavy (Table 1) and biodegraded (Chakhmakhchev et al., 1994). These direct and indirect observations of oil in at least 23 Cenomanian pools throughout the basin (Figure 11) suggest that liquid petroleum commonly migrated into shallow Pokur reservoirs, especially in the northern part of the basin. Some researchers argued that oils in Cenomanian pools could have been generated by the early-mature Pokur Formation (e.g., Punanov and Chakhmakhchev, 1989). However, biomarker data including distributions of steranes and diasteranes not affected by biodegradation clearly show that oil in the Cenomanian pools migrated from mature Jurassic source rock. The Upper Jurassic Bazhenov Formation was the source of Cenomanian oil in the Russkoe and Vanyeganskoe fields (Peters et al., 1994), whereas residual oil in the Novoportovskoe field arrived from the Bazhenov and Lower–Middle Jurassic formations (Chakhmakhchev et al., 1994). Although petroleum potential varies across the basin, the generally rich and oil-prone Bazhenov Formation expelled at least low- to medium-mature oil in the southern part and highly mature oil and gas in the northern part of the basin (Figure 4b) below all discovered Cenomanian pools. Lower–Middle Jurassic sources are also mature below most Cenomanian pools (Figure 4a). Migration from Jurassic source rocks to the Cenomanian reservoir was predominantly vertical from Jurassic–Neocomian structural traps (anticlines) through relatively poor seals, which cannot hold large columns and volumes of generated petroleum. From 54 Cenomanian pools listed by Maksimov (1987), 51 have proven petroleum accumulations in deeper traps within the same structure. As many as 55 pools occur at various stratigraphic levels within large structures (generally anticlines) in the West Siberian Basin (Ulmishek, 2003). Only three Cenomanian pools (in the Nakhodkinskoe, Maloyamalskoe, and Zapadno-Zapolyarnoe fields) listed by Maksimov (1987) do not have proven petroleum accumulations in the older reservoirs. However, it is possible that no deep wells at these structures exist or flow rates in deep pools were insufficient to declare discoveries. Therefore, based on available published geological data, we can reasonably argue that oil and gas in all Cenomanian pools could have vertically migrated from deeper Jurassic–Albian (or even Paleozoic–Triassic in places) reservoirs. Biodegradation in the West Siberian Basin Hydrocarbon-oxidizing microbes were isolated from oil fields in western Siberia (e.g., Borzenkov et al., 2006) where geochemical data suggest that biodegradation is a common process. Goncharov (1987) found geochemical evidence of biodegradation in approximately 40 reservoirs. For the purpose of this study, I evaluated more than 820 WOGCs from various reservoirs in about 325 fields to identify slight, moderate, and heavy biodegradation as defined by Wenger et al. (2002). Together with reservoirs listed by Goncharov (1987), geochemical evidence of biodegradation in at least 103 reservoirs in 60 fields is observed (Figure 12). Heavily degraded oils and condensates occur in 26 fields in 37 relatively shallow (425–1930 m [1390–6330 ft]) and cool (12–65°C) mostly Aptian, Albian, and Cenomanian (Pokur) reservoirs. Conditions in the Pokur reservoirs were favorable for petroleum biodegradation throughout geological history because they are characterized by cool present-day and paleotemperatures (Figure 9), high porosity and permeability, and low water salinity (16–20 g/L) (Korzenshtein, 1977). Moderately degraded oils occur in 14 fields in 15 mostly Neocomian reservoirs (1160–2650 m [3800–8700 ft], 36–70°C). Milkov 1513 Slightly degraded oils occur in 35 fields in 51 relatively deep (1446–3507 m [4740–11,500 ft]) and hot (47–91°C) reservoirs of mostly Neocomian age, although four of the reservoirs are Jurassic in age. Five reservoirs with slightly biodegraded oils are characterized by present-day temperatures of 88–91°C (Figure 12). This observation supports the suggestion of Milkov and Dzou (2007) that slight biodegradation may occur at temperatures higher than the currently accepted empirical biodegradation floor of 80°C (Wilhelms et al., 2001; Head et al., 2003; Larter et al., 2006). Because of the regional Neogene uplift of the basin, reservoirs with biodegraded oils experienced even higher temperatures in the past. Using paleotemperature maps from Kurchikov and Stavitskiy (1987), I estimate that reservoirs with slightly biodegraded oils had maximum paleotemperatures up to 115°C. This suggests that reservoir pasteurization, which should have occurred at approximately 80–90°C (Wilhelms et al., 2001), was either not efficient in these reservoirs or occurs at much higher temperatures in western Siberia. Elevated pressures at great depths possibly promote the activity of microbes (including methanogens) even at temperatures 95–100°C, as was shown in the experiments of Vladimirova (1980). Hyperthermophilic methanogens growing at 110°C have been identified (Kurr et al., 1991) and may be present in the reservoir of western Siberia as part of petroleum-degrading groups. Although 103 reservoirs with biodegraded oil and condensate occur throughout the basin (Figure 12), most (76%) are found in the northern part of the basin within the Nadym-Pur (30), PurTaz (25), and Yamal (23) petroleum areas. These are the areas that contain the most and largest Cenomanian methane-dominated gas pools, which suggests that the methane could originate from biodegraded petroleum. Direct Evidence of Methanogenic Biodegradation Biodegraded live and residual oil in the Pokur Formation, dry gas caps above biodegraded oil legs, geochemical evidence of petroleum biodegrada1514 Methanogenic Biodegradation in Western Siberia tion in the deeper Jurassic–Cretaceous reservoirs, and many laboratory experiments demonstrating methane formation during oil biodegradation are circumstantial evidence that methanogenic biodegradation affects fluids in western Siberia. More direct evidence also supports this hypothesis. Methanogenic microbes growing in a mixture of CO2 and H2 were isolated from high-temperature (60–80°C) oil-field waters in western Siberia (e.g., Davydova-Charakhchyan et al., 1992). Formationwater geochemistry data from western Siberia are very limited. Korzenshtein (1977) reported such data for Cenomanian pools in 12 fields in the northern part of the basin, two of which (Russkoe and Tazovskoe) contain biodegraded oil legs. One water sample taken apparently right below the OWC in the Tazovskoe field was anomalously enriched in HCO3− (1147.5 mg/L whereas the average value in the Cenomanian pools is 273 mg/L) and had relatively low Ca/Mg ratio (1.8 whereas the average value in the Cenomanian pools is 3.3), which are indicative of microbial methane production in the reservoir (McIntosh et al., 2004). Goncharov et al. (1983) discussed data from the Surgut area, where relatively heavy oil (presumably biodegraded) contains elevated concentrations of methane and reduced concentrations of CO2 relative to lighter oil. The authors interpreted that biodegradation of oil leads to increasing density, formation of CO2 near the OWC, and reduction of CO2 to methane, which increases methane near the OWC. Where relatively light and nonbiodegraded oils occur in deeper, hotter (>70–80°C) reservoirs, CO2 is not converted to methane and occurs in relatively high concentrations. However, because the total CO2 in a petroleum reservoir may be a mixture of CO2 from various sources, detailed isotope data are needed to unravel the importance of oil-derived CO2 as the source of secondary microbial methane. Elevated CO2 (up to 10%) enriched in 13C 13 (d C up to +15–30‰) is commonly associated with biodegraded oil in the subsurface, which may be the most direct evidence of methanogenic biodegradation (e.g., Pallasser, 2000; Larter and di Primio, 2005; Waseda and Iwano, 2008). However, reservoirs where heavy biodegraded oils associated with dry gas and 13C-enriched CO2 have less than 0.5% CO2 also exist, which is less than in nearby nondegraded oil fields (e.g., North Slope, Alaska; Masterson et al., 2001). In western Siberia, CO2 concentration has been measured extensively. Cenomanian pools contain less CO2 (average 0.24%, n = 40 pools) than the deeper, older reservoirs (Figure 6). However, Cenomanian pools with biodegraded oil legs contain more CO2 (0.38%, n = 6) than those with residual oil (0.36%, n = 6) or no reported oil (0.18%, n = 28). The additional CO2 in Cenomanian pools with oil could result from ongoing oil biodegradation and incomplete conversion of CO2 to methane. Several reasons exist why relatively low average concentrations of CO2 in Cenomanian pools may not contradict the hypothesis of methanogenic biodegradation. 1. Heavy biodegradation occurs not only in Cenomanian pools, but also in the smaller and deeper Aptian–Albian pools as well as in microaccumulations on the migration pathways from underlying Jurassic–Neocomian pools. Much of the oil-derived CO2 could be generated and converted to methane in those smaller pools, and secondary microbial methane could leak up into the Cenomanian pools. This could be a viable mechanism for fields where Cenomanian pools do not have oil legs or residual oil. On average, Aptian–Albian pools contain more CO2 (0.84%, n = 12 pools) than the deeper Neocomian pools (0.77%, n = 53 pools) (Figure 6). 2. Where oil charge was early and significant time was available for biodegradation, most CO2 could have been reduced to methane. This could be the case for fields with no or little residual oil in Cenomanian pools located in depocenters with deep, mature fetch areas (e.g., Bovanenkovskoe and Urengoyskoe fields described in detail below). 3. The most important reason may be that CO2 is a very reactive and highly soluble gas. The Aptian, Albian, and Cenomanian Pokur Formation is a basinwide thick (400–2300 m [1312–7546 ft], average ∼1300 m [4265 ft]) aquifer characterized by high porosity and permeability, relatively low water salinity (16–20 g/L in Cenomanian pools, increasing toward the north), relatively cold present-day temperatures (<80°C, average ∼45°C at the base of Aptian and ∼27°C at the top of Cenomanian, Figure 9), and regional filtration of water toward the north (Korzenshtein, 1977). Such a large cool aquifer is capable of dissolving huge volumes of CO2 in water. The basinwide well-connected aquifer differentiates Aptian, Albian, and Cenomanian pools of western Siberia from pools having biodegraded petroleum and secondary microbial gas in more confined reservoirs in other basins. The CO2 generated from biodegraded oil can precipitate as carbonate cement. Golyshev et al. (1981) observed that carbonate cement depleted in 13C occurs near OWCs in western Siberia fields, whereas carbonate cement away from OWCs is enriched in 13C. Goncharov et al. (1983) interpreted that this is because 13C-depleted CO2 from biodegraded oil concentrates near OWCs and precipitates there as 13C-depleted carbonate. During migration of oil-derived CO2 from the OWC zone, it is partially converted to methane, and residual CO2 now enriched in 13C precipitates as carbonate, also enriched in 13C. Unfortunately, no geochemical data on oil from specific fields discussed by Golyshev et al. (1981) are available to further test the interpretation of Goncharov et al. (1983). Carbon isotope measurements on CO2 are available from only three fields (Figure 8c), and in two of them, CO2 from Aptian, Albian, and Cenomanian reservoirs is heavily enriched in 13C (Schoell et al., 1997b). In the Messoyakhskoe field, where oil has been produced from the Cenomanian gas pool during well tests (Ermakov et al., 1972) and where a potential oil leg is observed (Darovskih et al., 2007), average CO2 is 0.53% (up to 0.942%, Darovskih et al., 2007, significantly higher than in an average Cenomanian pool with 0.24% CO2) and the d13C of CO2 ranges from +12 to +25‰ (average approximately +20‰), which suggests that CO2 is mostly a residual product of advanced methanogenic biodegradation. In cool Aptian–Albian reservoirs of the Verkhne-Teuteyskoe field, the d13C of CO2 is +27‰, which also indicates that most CO2 in the reservoir was converted to methane, Milkov 1515 although no other geochemical information is available. In the Cenomanian pool (gas over heavily biodegraded oil leg) of the Vanyeganskoe field, CO2 (0.5%) has d13C of −9‰, which is common for petroleum accumulations. The gas cap is relatively wet (C1/C2+ is 882, whereas the average Cenomanian pool has C 1/C2+ of 6121) and has a d 13C methane value of −53.5‰, which suggests that petroleum charge is relatively recent and ongoing. It is plausible that microbial conversion of oilderived CO2 into methane is not complete in this reservoir, and relatively little 13C-enriched CO2 residual from methanogenesis is present. Based on results of the modeled carbon isotopic composition of gases from biodegraded oil reservoirs (Jones et al., 2008), perhaps only approximately 30–40 wt.% conversion of CO 2 to methane occurred in the Cenomanian oil-and-gas pool in the Vanyeganskoe field, whereas approximately 60–70 wt.% conversion occurred in the Messoyakhskoe and VerkhneTeuteyskoe fields (Figure 8c). As discussed above, the molecular and isotopic compositions of hydrocarbon gases in Cenomanian pools are difficult to reconcile with either a primary microbial or thermogenic origin. Very dry Cenomanian gas (Figure 8a) may result from removal of C2+ compounds during biodegradation of thermogenic gas (James and Burns, 1984) supplied from deeper reservoirs (Figure 8b, d). However, if only biodegradation of gases without secondary methanogenesis was observed, methane in the Cenomanian pools would be enriched in 13C relative to Jurassic–Neocomian gas because of preferential removal of 12C during biodegradation (James and Burns, 1984), which is inconsistent with available data (Figure 6). According to the model of Jones et al. (2008), the d13C of secondary microbial methane formed from moderately and heavily biodegraded oils (levels 3–6 of Peters and Moldowan, 1993) at approximately 20°C (typical for most Cenomanian pools), and CO2-CH4 conversion of 20–80 wt.% should range from −54 to −48‰. Fifty-one percent of the Cenomanian pools have d13C values of methane in that range, and the average value (−52‰) also falls into that range. The most viable interpretation of dry Cenomanian gases is that these gases are mixtures of biodegraded ther1516 Methanogenic Biodegradation in Western Siberia mogenic gas and secondary microbial methane, with an occasional and small addition of primary microbial methane and, speculatively, early-mature coal-derived gas. I propose that an additional genetic field of biodegraded and secondary microbial gases may be added to the empirical C1/(C2+C3) versus d13C of methane plot (commonly called the Bernard diagram after Bernard et al., 1978) as is shown in Figure 8a. This genetic field is consistent not only with the data from western Siberia, but also with data from other biodegraded oil and gas accumulations having d13C values of methane in the range of −55 to −40‰ (Larter et al., 2006) and with the isotope model of Jones et al. (2008). EVIDENCE OF SECONDARY MICROBIAL GAS IN INDIVIDUAL FIELDS Based on the above, the most widely discussed hypotheses for the origin of gas in the giant Cenomanian pools are inconsistent with molecular and isotopic compositions and the results of petroleum systems modeling. Geochemical evidence for petroleum biodegradation exists throughout the basin. In some reservoirs, direct evidence for methanogenic biodegradation is observed. The molecular and isotopic composition of Cenomanian gas is consistent with methanogenic biodegradation. The contribution of secondary microbial methane to petroleum accumulations can be further demonstrated by considering the petroleum habitat of representative western Siberian fields. Severnoe Field The Severnoe gas, condensate, and oil field was discovered in 1962 in the southeastern part of the West Siberian Basin (Tomsk Oblast) within the Kaymyisov petroleum area (Figures 1, 13). Lower Jurassic to Paleogene sandstones and shales are 2230–2630 m (7316–8629 ft) thick and overlie carbonates in the field area. Twenty-two petroleum pools (13 of which contain gas or gas caps) at depths of 413– 2600 m (1354–8530 ft) are present (Nesterov et al., 1975; Goncharov et al., 2007). The shallowest Milkov 1517 Figure 13. Schematic geological cross section with wells (from Nesterov et al., 1971), temperature, and fluid properties of the Severnoe field based on data from Nesterov et al. (1971), Goncharov (1987), Maksimov (1987), and Goncharov et al. (2005, 2007) and unpublished GeolabNor/Fugro data, used with permission. Although the exact horizontal scale is unknown, the cross section is probably 15–20 km (9–12 mi) long. 1 = bituminous shales; 2 = shales; 3 = siltstones; 4 = interbedding of shales, siltstones, and sandstones; 5 = sands and sandstones; 6 = oil accumulations; 7 = gas accumulations; 8 = oil shows. The Ki index is calculated as (iC19 + iC20) / (nC17 + nC18). reservoir I2–3 (Turonian–Santonian) is up to 35 m (115 ft) thick and contains only gas. Within the Pokur Formation, gas pools with oil rims exist, such as the PK11 (Cenomanian) and PK15 (Aptian) reservoirs. Pools within the Valanginian–Hauterivian and Middle–Upper Jurassic section contain gas, oil, and gas-oil accumulations (Figure 13). Anticline traps are about 90 m (295 ft) high and are not filled to spill (column heights range from 3 to 58 m [10 to 190 ft]) (Maksimov, 1987). In addition to tested reservoirs, oil shows occur throughout the Pokur Formation and the Neocomian section (Nesterov et al., 1975). Ultimate recoverable reserves within the field are about 242 million bbl (34.6 million tons) of oil, about 81 bcf (2.3 billion m3) of dissolved gas, about 783 bcf (22.2 billion m3) of nonassociated gas, and about 16 million bbl (2.3 million tons) of condensate (Energy Information Administration, 1997). Severnoe field is rather unique for the southeastern part of the basin where most fields (∼95%) have petroleum accumulations only in the Middle Jurassic Vasyuganskaya Formation and not in Cretaceous sediments (Goncharov et al., 2005). This is likely because of the good sealing capacity of the Georgievskaya Formation, which underlies the Bazhenov Formation within the Severnoe field area and prevents significant downward migration into the Vasyuganskaya Formation. Most migration is upward into Cretaceous reservoirs (Kontorovich, 2002). Biomarker studies indicate that all oil in the Severnoe field originated from the Bazhenov Formation (Goncharov et al., 2007). Basin modeling suggests that the Bazhenov Formation in the fetch area of the field started to expel oil at approximately 75 Ma and reached maximum standard temperature (or standard thermal stress [STS], defined by Pepper and Corvi, 1995, as standard temperature quoted at a heating rate of 2°C/m.y.) about 115–130°C (Figure 4b), which corresponds to the middle oil window. Biodegradation affected oil and gas compositions at depths less than 1800 m (<5905 ft) (<65–70°C), which is obvious from the increasing density of oil and Ki index ((iC19 + iC20)/ (nC17 + nC18)) in the relatively shallow reservoirs (Figure 13). Gas is significantly drier (C1/C3 up to 6700) in the shallow pay zones than at greater 1518 Methanogenic Biodegradation in Western Siberia depths. This is likely because of gas biodegradation, which is supported by enrichment of propane in 13 C at depths less than 1800 m (5905 ft). However, the dry-gas composition could also be caused by some contribution of secondary microbial methane. Methane at depths greater than 1800 m (5905 ft) (not affected by biodegradation) has d13C values of −54.7 to −53.4‰, which is similar to other Bazhenov-sourced early-mature gases in the area (Goncharov et al., 2005). However, at shallower depths, methane becomes enriched in 13C and has d13C values approximately −49.1‰. This may be caused by biodegradation of methane (James and Burns, 1984) and also could result from addition of secondary microbial methane from biodegraded oil. All gases above the biodegradation floor have d13C values of methane about −50‰ despite various degrees of biodegradation (obvious from oil density and C1/C3), which suggests that most of the methane has a secondary microbial instead of thermogenic origin (Figure 13). No other conventional data (such as d13C of CO2) could support the addition of secondary microbial methane from biodegraded oils to petroleum accumulations in the Severnoe field. However, biodegradation of petroleum obviously occurs within most of the sedimentary section. Shallower pools contain biodegraded oil legs with gas caps, gas becomes progressively enriched in methane toward shallower depth, and the shallowest Turonian–Santonian reservoir contains only gas. No molecular or isotopic data for gas in the Turonian–Santonian reservoir exist, but it is likely dominated by methane like all other gases from Upper Cretaceous reservoirs in western Siberia. The Pokur Formation does not have much coal (total thickness ∼10 m [33 ft]) in this part of the basin and is immature (maximum paleotemperature less than ∼90°C; Kurchikov and Stavitskiy, 1987). The early-mature oil-prone Bazhenov source rocks generated only C2+-rich gases, and the gas-prone Tyumen Formation is mostly immature in the area. Perhaps the only source for dry gas in the Turonian–Santonian reservoir is methane generated from biodegraded oil in Cretaceous reservoirs, which first formed gas caps observed in many shallower accumulations and then leaked through poor local (within the Pokur Formation) and regional (Kuznetzov Formation) seals into the Turonian–Santonian trap. Russkoe Field The Russkoe oil and gas field discovered in 1968 (Nesterov et al., 1975) is located in the Pur-Taz area (Figures 1, 14). About 60 wells were drilled in the field. The field contains an oil pool with a gas cap in the Cenomanian (PK1–6) reservoirs at approximately 660–1000 m (2165–3281 ft) depths (deepest OWC is at −960 m [−3150 ft] depth; Maksimov, 1987) and a gas pool in the Turonian reservoir (Gazsolinskaya Formation) at 554–814 m [1820–2670 ft] depth (OGC at −770 m [2526 ft] depth; Maksimov, 1987). Geological reserves (A + B + C1 in Russian classification) of the Cenomanian pool are about 3 tcf (85 trillion m3) of gas (including ∼1 tcf [28 trillion m3] of oil-dissolved gas) and about 10.98 billion bbl of oil (1.57 billion tons) (Zhabrev, 1983; Ulmasvay et al., 2008). Ultimate recoverable reserves within the field are about 2.703 billion bbl of oil (387 million tons), about 403 bcf (11.4 billion m3) of dissolved gas, and about 2.804 tcf (79.4 trillion m3) of nonassociated gas (Energy Information Administration, 1997). In addition, small gas accumulations in the deeper Hauterivian–Aptian reservoirs are observed (Figure 14). The productive section of the Cenomanian reservoir is approximately 200 m (660 ft) thick, which includes approximately 35 sand and silt layers separated by shale layers (Ivanova et al., 1989). The anticline structure is compartmentalized by faults, which is not typical for the West Siberian Basin where most Cenomanian pools lack faults (Ermilov et al., 2004). The main fault has an amplitude of approximately 200 m (660 ft) and separates the reservoir into larger eastern and smaller western parts. All faults are sealing, which is apparent from the various depths of OWCs in separate fault blocks (Ivanova et al., 1989). Reservoir sandstones have high porosity (25–32%) and permeability (up to 1 d). However, the oil is heavy (15–21°API), viscous (226 cp), and has a low gas/oil ratio (GOR) (∼67 standard ft3 of gas per standard bbl of oil [scf/stb]), which result in low primary productivity of wells (∼25 m3/day  MPa) and natural recovery factors (8–10%) (Ivanova et al., 1989). Oil in the Cenomanian pool is heavily biodegraded (Figure 14), which is apparent from oil properties (low API gravity, high viscosity), bulk geochemical composition (naphthenic polycyclic hydrocarbons prevail), WOGC traces, and abundant 25-norhopanes. A predominance of C27 steranes (Figure 14) suggests that the oil originated from Jurassic marine anoxic siliciclastic source rock instead of nonmarine and nearshore-marine Aptian–Cenomanian source rock. Source-specific biomarkers do not distinguish Bazhenov (Upper Jurassic–Lower Cretaceous) from Lower–Middle Jurassic formations as the source of oil because these source rocks have similar organofacies in the area (marine shales). Limited available data suggest that Lower–Middle Jurassic rocks have poor source potential (<1% TOC), whereas the Bazhenov Formation is rich (10–15% TOC) and oil prone in the area. The oil has low maturity, which is apparent from the prevalence of 1-methyldibenzothiophene over 4-methyldibenzothiophene (MDR < 1, Figure 14). Maturity modeling indicates that the Bazhenov Formation started to slowly expel oil about 90 Ma and is currently in the middle oil window (maximum STS range from 120 to 145°C) within the fetch area of the Russkoe field (Figure 4b). Lowmaturity oil in the Cenomanian section likely originated from the Bazhenov Formation. Gas overlying oil in the Cenomanian reservoir of the Russkoe field is drier (dryness 0.9994) and has significantly more N2 (2.43%) and CO2 (0.44%) than an average Cenomanian pool (dryness 0.9976, N2 1.58%, CO2 0.24%). The additional methane, N2, and CO2 possibly originated from oil biodegraded within the reservoir. The methane is significantly enriched in 13C (d13C is −43.2‰) compared with an average Cenomanian pool (d13C is −51.8‰), which may indicate significant CO2 conversion to methane (>80–90 wt.% according to the model of Jones et al., 2008). The Cenomanian trap apparently was initially filled with oil because oil-saturated reservoir rocks within the gas cap are present (Ermakov et al., 1972; Milkov 1519 Figure 14. Schematic geological cross section, description of oil from well 37 (unpublished GeolabNor/Fugro data, used with permission), and average properties of gas in the PK1–6 gas caps of the Russkoe field based on data from Vasiliev et al. (1970), Ermakov et al. (1972), Alekseev (1974), Karpov and Raaben (1978), Prasolov et al. (1981), Prasolov (1990), Nemchenko et al. (1999), and Ermilov et al. (2004). The WOGC is the whole oil-gas chromatogram. Mass chromatograms m/z 217 and m/z 198 show distribution of steranes and methyldibenzothiophenes, respectively. In m/z 198, 1 is 1-methyldibenzothiophene, 4 is 4-methyldibenzothiophene, and MDR is the ratio of 4-methyldibenzothiophene to 1-methyldibenzothiophen, which is less than 1 and indicates a relatively low maturity of oil (<0.6 Ro) (Radke, 1988). 1520 Methanogenic Biodegradation in Western Siberia Nesterov et al., 1975). Ermakov et al. (1972) suggested that the reservoir was initially charged with oil during the Late Cretaceous–Paleogene. Then gas generated by coals and exsolved from waters of the Pokur Formation during the regional Neogene– Quaternary uplift replaced the oil in the most permeable layers. Ermakov et al. (1972) explained methane enrichment in 13C relative to many other Cenomanian gas pools by addition of oil-associated gas. However, gas associated with early-mature oil, as in the Russkoe field, should be significantly enriched in C2+ compounds (dryness as low as ∼0.5) while having methane relatively depleted in 13C (d13C as negative as −55‰), similar to reservoir gases derived from the low-mature Bazhenov Formation in the southeastern part of the basin (Goncharov et al., 2005). Mixing of coal-derived gas, which is commonly wet (Rice, 1993) with a d13C methane value of −51.8‰ (as in an average Cenomanian pool), with C2+-rich oil-associated gas having a d13C methane value about −55‰ cannot result in methane-dominated (dryness 0.9994) gas with a d13C methane value of −43.2‰ observed at the Russkoe field. An alternative model that explains the observed phases, physical properties, and chemical composition of fluids in the Russkoe field would be methanogenic biodegradation of petroleum within the Cenomanian reservoir. In this model, early-mature Bazhenov-sourced oil (with cumulative API gravity <28° and GOR < 240 scf/stb) migrated vertically and began to arrive in the Cenomanian reservoirs during the Eocene. The maximum temperature of the Cenomanian reservoirs was about 52°C in the early Oligocene prior to regional uplift (Kurchikov and Stavitskiy, 1987). The present-day temperature is 19–22°C (Maksimov, 1987). Therefore, the temperature in the reservoir promoted biodegradation during all phases of petroleum charge. Salinity of pore water within the reservoir is 11.5 g/L, which is anomalously low for Cenomanian reservoirs (16–20 g/L) (Korzenshtein, 1977) and also promotes biodegradation. In addition to heavy biodegradation of oil, which is apparent from WOGC, biomarkers and bulk-oil properties (Figure 14), oil-associated C2+-rich gas was likely biodegraded. Extensive biodegradation of natural gases removes all but traces of C2+ compounds and results in a dry-gas composition where methane and C2+ compounds are enriched in 13C (James and Burns, 1984), which is consistent with gas composition at the Russkoe field. No direct evidence is observed (such as d13C of CO2) that petroleum biodegradation at the Russkoe field was methanogenic. However, this additional source of methane would help explain the large gas cap over the biodegraded oil leg. Without methane from biodegraded oil, the gas cap could form from gas exsolved from oil when pressure and temperature decreased during petroleum migration to the reservoir or when regional uplift started in the early Oligocene. Biodegradation of oil and wet gas and divergent oil and gas pressure-volume-temperature (PVT) properties during biodegradation may also create oil leg and dry gas cap (Larter and di Primio, 2005). Petroleum system modeling suggests that the cumulative GOR of early-mature oil that reached the Cenomanian reservoir of the Russkoe field was likely less than 240 scf/stb. The present-day GOR for the Cenomanian PK1–6 reservoirs (accounting for free gas and oil-dissolved gas) is about 270 scf/ stb but is higher for the entire field when Turonian gas-only reservoirs are included. This increase of GOR could be a result of addition of methane generated during biodegradation. However, biodegradation also decreases the volume of oil and the amount of C2+ compounds in dissolved gas, and both would affect the GOR. Detailed mass-balance calculations are difficult to perform at this stage of qualitative understanding of the charge history and biodegradation processes at the Russkoe field, but this field would be an excellent natural laboratory to test future quantitative models of methanogenic biodegradation in the subsurface. Urengoyskoe Field The Urengoyskoe oil-gas-condensate field located in the Nadym-Pur area (Figure 1) was discovered in 1966 and has been producing since 1978. It is the largest gas field in western Siberia and the second largest in the world after the South Pars/North Dome gas-condensate field in the Persian Gulf (Aali Milkov 1521 1522 Methanogenic Biodegradation in Western Siberia Figure 15. Schematic geological cross section, temperature, pressure, and fluid properties of the Urengoyskoe field based on data from Velikovskiy et al. (1968), Ermakov et al. (1970), Korzenshtein (1977), Karpov and Raaben (1978), Prasolov et al. (1981), Goncharov et al. (1983), Grace and Hart (1986), Goncharov (1987), Maksimov (1987), Rudkevich et al. (1988), Galimov et al. (1990), Prasolov (1990), Peters et al. (1994), Galimov (1995), Cramer (1997), Cramer et al. (1999), Nemchenko et al. (1999), Kichenko (2004), and unpublished GeolabNor/Fugro data, used with permission. et al., 2006). The field is located within a very large anticline (180  20–40 km [112  12–25 mi] on top of the Jurassic section), which is a periodically reactivated basement feature (Grace and Hart, 1990). Petroleum occurs in about 46 pools at 1000– 5030-m (3300–16,500-ft) depth in Lower Jurassic– Cenomanian reservoirs (Figure 15). The field contains approximately 352 tcf (10 trillion m3) of gas in place, most of which (∼220 tcf [6.2 trillion m3]) occurs in the Cenomanian reservoir PK1 (Zhabrev, 1983). In addition to gas, the reservoirs (mostly Neocomian) contain more than 4.1 billion bbl (587 million tons) of condensate and more than 1.2 billion bbl of oil (172 million tons) in place (Grace and Hart, 1990). Jurassic reservoirs contain relatively small accumulations of gas and condensate. Analysis of source rocks from wells in the Urengoyskoe field suggests that the Bazhenov Formation has good (although poorer than in the central part of the basin) generative potential (average present-day TOC is ∼5%, average present-day HI is ∼220 mg HC/g TOC), which was partially realized (T max 433–456°C) (Lopatin and Emets, 1987; Cramer, 1997). The original HI of the Bazhenov Formation may be approximately 300 mg HC/g TOC, and gas slightly exceeds oil in the cumulative petroleum expelled from this source rock. The Lower–Middle Jurassic Tyumen Formation (∼1500 m [4921 ft] thick) is composed of interbedded sandstones and mudstones with coal inclusions. Analyzed mudstone samples have a presentday TOC of 0.11–41.2% (average 4.5%, n = 49) and an HI of 40–393 mg HC/g TOC (average 141 mg HC/g TOC, n = 44), and they realized a significant part of their generative potential (Tmax 443– 542°C, average 478°C, n = 44) (Lopatin and Emets, 1987; Cramer, 1997). The original HI of mudstones from the Tyumen Formation may average approximately 250 mg HC/g TOC in wells from the Urengoyskoe field, suggesting that gas is a major expelled product by these mudstones. In addition, the fetch area for the Urengoyskoe field contains a Triassic section composed of interbedded argillites, siltstones, and sandstones with coal inclusions. These sediments have residual TOC and HI of 0.03–17.8% and 9–37 mg HC/g TOC, respectively, and are highly mature (Tmax 505–544°C) in the SG-6 well located within the fetch area to the southeast of the field (Cramer, 1997). Biomarker analysis of liquids from Neocomian reservoirs (average Pr/Ph is 3.1, Figure 15) in the Urengoyskoe field suggests that they represent a mixture from the marine anoxic Bazhenov Formation (average Pr/Ph of extracts is 1.8) and nonmarine Tyumen Formation (average Pr/Ph of extracts is 5.0) and have medium to high maturity (0.7– 1% Ro). Liquids in Lower–Middle Jurassic reservoirs (average Pr/Ph is 5.4) were generated from the nonmarine Tyumen Formation and are very mature. The fetch area of the Urengoyskoe field has been about 17,000–20,000 km2 (6600–7700 mi2) since the Neocomian. Maturity modeling suggests that within the northern part of the fetch area, the Tyumen Formation (as modeled at the level of a regional Togur bed) started to expel oil about 125 Ma and gas about 115 Ma. The Bazhenov Formation started to expel oil about 105 Ma and gas at about 65 Ma, with the first fluids coming from the northwestern part of the fetch area. The Tyumen Formation is mostly in the present-day late gas window, whereas the Bazhenov Formation is in the early gas window in the northern part but in the medium to late oil window in the southern part of the fetch area (Figure 4). The anticline structure of the Urengoyskoe field was inherited from the basement high and developed mostly in the Berriasian–Valanginian and in the Cenomanian with small-scale inversions in the Aptian, Turonian, and Paleocene (as reviewed by Grace and Hart, 1990). Neocomian traps reached maximum size by the end of the Paleocene. However, the sealing capacity of local Neocomian seals apparently was insufficient to hold large petroleum columns, and the early petroleum leaked into the Aptian, Albian, and Cenomanian section. The Turonian (Kuznetsov Formation) regional shale seal (1) formed during a major transgression in a deep shelf or slope (water depth 300–500 m [984–1640 ft]) environment in a calm hydrodynamic regime; (2) is characterized by homogeneous lithology with 0–10% of sand or silt material and approximately 1% carbonate; (3) contained predominantly montmorillonite with some illite as the initial clay mineralogy; (4) was never heated above 65°C during burial; and Milkov 1523 (5) is characterized by low mineralization of pore water (10–20 g/L), which all are favorable factors for increased sealing capacity (Osipov et al., 2001). Turonian shale became a good seal with low permeability at approximately 500-m (1640-ft) burial depth (Osipov et al., 2001) approximately 70– 80 Ma. Therefore, the earliest petroleum (mostly oil) expelled from Jurassic formations was likely not lost to the surface but was trapped and biodegraded under the Turonian seal. Geochemical data suggest that biodegradation affected fluids located at less than 1800-m (5800-ft) depth and present-day temperature less than 55°C (Figure 15). The WOGC traces indicate heavy biodegradation of condensate in the PK1 reservoir and moderate biodegradation in the PK21 (Albian) reservoir (Rudkevich et al., 1988). Additional evidence of biodegradation includes increasing density of liquids, concentration of cyclic compounds, Ki index, and decreasing concentration of alkanes from approximately 1800 m (5800 ft) toward the Turonian–Paleogene seal (Figure 15). It is not clear if early-mature oil was captured by shallow Aptian, Albian, and Cenomanian reservoirs because of the lack of biomarker data on liquids from these pools in the Urengoyskoe field. However, the inferred presence of residual oil (Khafizov, 1991) and observations of heavily degraded condensate (Rudkevich et al., 1988) within the Cenomanian PK1 and Aptian PK21 pools (Figure 15) as well as conditions favorable for biodegradation through the geological history of the Cenomanian reservoirs suggest that petroleum that reached the Cenomanian reservoir was biodegraded. Although no direct evidence is observed (such as d13C of CO2) that this biodegradation was methanogenic, addition of secondary microbial methane is a viable process proven in laboratory studies (Bokova, 1953; Jones et al., 2008), which would help explain the dry-gas composition and enormous volume of gas in the PK1 accumulation of the Urengoyskoe field. The dryness of the gas (C2+ = 0.096%, dryness 0.9981) in the Cenomanian PK1 reservoir may be explained by simple removal of C2+ compounds from the gas during biodegradation of thermogenic C2+-rich (∼10%, Figure 15) gases migrated from deeper reservoirs. However, those deeper gases have 1524 Methanogenic Biodegradation in Western Siberia d13C values of methane mostly in the range of −40 to −35‰, and simple biodegradation in the Cenomanian reservoirs would make d13C values of methane even more positive. However, observed d13C of methane averages about −50.1‰, which is most consistent with the addition of secondary microbial methane. Biodegradation in the Urengoyskoe field was apparently very efficient, and the remaining biodegraded oil was dissolved in this secondary microbial methane to form biodegraded condensates sampled in the PK1 reservoir (Figure 15) as originally identified by Goncharov (1987). Novoportovskoe Field The Novoportovskoe oil-gas-condensate field in the southeastern part of the Yamal Peninsula (Figures 1, 16) was discovered in 1964, but production has not yet started. More than 145 wells drilled on the large anticline are present, and petroleum occurs at 470–3000-m (1541–9842-ft) depth in Paleozoic–Cenomanian reservoirs. The field has at least 31 pools (Skorobogatov et al., 2003) that contain approximately 4.5 billion bbl of oil (644 million tons) and approximately 6.4 tcf (0.18 trillion m3) of nonassociated gas (Zhabrev, 1983; Energy Information Administration, 1997). The terrigenous Cenomanian reservoir (PK1) contains a thin gas column of about 20 m (66 ft) and potentially a thin oil leg (Maksimov, 1987) with the OGC located at −435-m (–1427-ft) depth and gas reserves (category C2 in Russian classification) of 60.7 bcf (1.7 billion m3) (Zhabrev, 1983). Relatively small gas columns with oil rims occur in Albian KM1 and KM2 (Khanty-Mansiyskaya Formation) reservoirs at approximately 800–950-m (2625–3117-ft) depth. Most of the petroleum occurs in terrigenous Valanginian–Hauterivian reservoirs as oil legs with gas caps. Jurassic terrigenous and Paleozoic terrigenous and carbonate reservoirs contain oil and condensate. Biomarker studies suggest that oil obtained from a Cenomanian reservoir is slightly less mature than oil in Neocomian and Jurassic reservoirs, but it was generated by the same Jurassic source rocks (Bazhenov Formation and Lower–Middle Milkov Figure 16. Schematic geological cross section, temperature, pressure, and fluid properties of the Novoportovskoe field based on data from Ervye (1966), Alekseev et al. (1972), Gavrilov et al. (1972), Karpov and Raaben (1978), Prasolov et al. (1981), Goncharov et al. (1983), Goncharov (1987), Maksimov (1987), Chakhmakhchev et al. (1990), Prasolov (1990), Khafizov (1991), Cramer (1997), Nemchenko et al. (1999), Skorobogatov et al. (2003), and unpublished GeolabNor/Fugro data, used with permission. 1525 Jurassic formations) (Chakhmakhchev et al., 1994). Organic-rich shales of the Bazhenov Formation may be not present within the Novoportovskoe field (likely not deposited on the paleohigh), but they occur in the fetch area of the field (Figure 16). The Lower–Middle Jurassic formations are composed of interbedded sandstones and mudstones with coal inclusions. Mudstone samples have a presentday TOC of 1.14–13.85% (average 3.9%, n = 7) and an HI of 190–459 mg HC/g TOC (average 280 mg HC/g TOC, n = 7), and they are immature (Tmax 425°C, n = 1) (Lopatin and Emets, 1987). Gas is a dominant product expelled by these mudstones in the more mature fetch area surrounding the field. Maturity modeling suggests that, within the field fetch area, the Lower–Middle Jurassic formations (as modeled at the level of the regional Togur bed) started to expel oil at approximately 120 Ma and gas approximately at 100 Ma but mostly in the far-eastern part of the fetch 100–150 km (62–93 mi) from the structure. The present-day Lower–Middle Jurassic formations are in the late gas window and overmature in the far-eastern part of the fetch area but are in the oil window near the field and immature within the field. The Bazhenov Formation started to slowly expel oil at approximately 100 Ma and gas at approximately 60 Ma but also mostly in the far-eastern part of the fetch 100–150 km (62–93 mi) from the structure. The present-day Bazhenov Formation is immature within the field and early mature around the field and in the late gas window in the far-eastern part of the fetch area (Figure 4). Petroleum charge from the Bazhenov source rock to the Jurassic and Neocomian reservoirs of the Novoportovskoe field depends on long-distance (up to 140 km [87 mi]) lateral migration from the large fetch area. Relatively low maturity of both the Bazhenov and Lower–Middle Jurassic formations in the area surrounding the field and inefficient capture of gas from the deepest eastern part of the fetch area (because of likely limited connectivity of carrier beds) may explain why Novoportovskoe is the only field dominated by oil instead of gas in Yamal (Figure 1). Laterally migrated petroleum charged Upper Jurassic and Neocomian reservoirs and then apparently leaked upward into 1526 Methanogenic Biodegradation in Western Siberia the Neocomian–Cenomanian reservoirs. Vertical migration is promoted by the structural setting (large anticline with flanks dipping at 2–3°) and lack of effective seals between Paleozoic and Turonian sediments. No geochemical data are available for gas from the Cenomanian pools. However, the liquids in the Cenomanian pools may be heavily biodegraded (Chakhmakhchev et al., 1994). Oil in the Albian KM1 reservoir is heavily biodegraded, which is apparent from relatively high density (∼23.6°API), lack of n-alkanes, and large UCM hump in the WOGC (Figure 16). Some oil and condensate in the main Valanginian–Hauterivian reservoirs experienced moderate to slight biodegradation, which is apparent from partially removed n-alkanes in the WOGC, elevated Ki index, and relatively high concentrations of CO2 and N2 in the associated gases. Methane in Valanginian–Hauterivian reservoirs is depleted in 13C relative to gas in the deeper pools (Figure 16), which most likely indicates lower maturity of the gas derived mostly from the Bazhenov Formation. Slight biodegradation affected petroleum to at least approximately 2070-m (6800-ft) depth, where reservoirs in the Lower–Middle Jurassic formations contain oil where n-alkanes up to at least C17 were partially removed by microorganisms (Figure 16). The presentday temperature in all of these reservoirs with biodegraded petroleum does not exceed approximately 65°C, which is low enough for microbial activity. Paleozoic reservoirs at greater than 2500-m (8200-ft) depth and greater than 80°C contain petroleum without obvious evidence of biodegradation. Geological conditions and data on fluids provide convincing evidence that petroleum-degrading microorganisms are active in most reservoirs within the Novoportovskoe field (Figure 16). No direct evidence is observed that this biodegradation is methanogenic. Although oils in the Valanginian– Hauterivian reservoirs (NP1–12) are slightly biodegraded, associated gases are enriched in C2+ gases (∼10%), and the contribution of secondary microbial gases to these fluids is small or absent. However, small gas caps and gas accumulations in the Aptian–Cenomanian reservoirs could contain a significant part of the secondary microbial methane. Because petroleum charge in the Novoportovskoe field was relatively recent and slow (part of the fetch area closest to the field is still early mature for oil), little petroleum leaked from the Jurassic–Neocomian reservoirs into the Aptian– Cenomanian section, and little time was available for methanogenic biodegradation. These factors would explain the small size of Aptian–Cenomanian gas accumulations in the Novoportovskoe field. Bovanenkovskoe Field The Bovanenkovskoe oil-gas-condensate field was discovered in 1971 and is the largest field in the Yamal area (Figure 1) and the third largest gas field in western Siberia (after the Urengoyskoe and Yamburgskoe fields). Ninety-five wells drilled to 3700-m (12,140-ft) depth (Paleozoic section) discovered petroleum in about 30 pools at approximately 500–3200 m (1640–10,500 ft) within Jurassic–Cenomanian sandstone reservoirs (Skorobogatov et al., 2003) (Figure 17). The shallower (500–1600 m [1640–5250 ft]) Lower Aptian–Cenomanian reservoirs (TP11–PK1) contain mainly gas, whereas deeper reservoirs contain mostly condensate. Oil is found only in reservoir TP18. Geological reserves (A + B + C1 + C2 in Russian classification) of the field are about 174 tcf (4.9 trillion m3) of gas and about 919 million bbl (131 million tons) of condensate (Zhabrev, 1983; Dvoretskiy et al., 2000; Gazprom, 2009). The main gas resources are concentrated in Aptian reservoirs TP1–6 (∼78 tcf [2.2 trillion m3]) and Cenomanian reservoir PK1 (∼30 tcf [0.85 trillion m3]). The main condensate (with some minor oil) resources are located in Lower–Middle Jurassic reservoirs at greater than 2700-m (8900-ft) depth. Analyses from wells in the Bovanenkovskoe field suggest that Jurassic source rocks have good generative potential. The Bazhenov Formation has an average present-day TOC and HI of approximately 5% and approximately 330 mg HC/g TOC, respectively, and has already realized part of its generative potential (Tmax 447°C) (Lopatin and Emets, 1987). The original HI of the Bazhenov Formation may have been approximately 400 mg HC/g TOC, and oil slightly exceeds gas in the cumulative petroleum expelled from this source rock (Katz et al., 2003). Lower–Middle Jurassic formations (Malyshevskaya, Leontievskaya, Vymskaya, Laydinskaya, Djangodskaya, and Levinskaya) are composed of interbedded sandstones and mudstones with minor coal inclusions. Mudstone samples have a present-day TOC of 0.73–9.31% (average 2.5%, n = 28) and an HI of 33–285 mg HC/g TOC (average 157 mg HC/g TOC, n = 28), and have realized a significant part of their generative potential (Tmax 449–478°C, average 466°C, n = 5) (Lopatin and Emets, 1987; unpublished GeolabNor data). The original HI of mudstones from these formations is difficult to estimate but may average about 250 mg HC/g TOC in wells of the Bovanenkovskoe field, which implies that gas is a dominant product expelled by these mudstones. Basin modeling suggests that within the fetch area of the field, Lower–Middle Jurassic formations (as modeled at the level of regional Togur bed) started to expel oil at approximately 125 Ma and gas at approximately 115 Ma. The Bazhenov Formation started to expel oil at approximately 105 Ma and gas at approximately 65 Ma. The Lower–Middle Jurassic source rocks are in the late gas window and overmature, whereas the Bazhenov Formation is in the late oil window and present-day gas window (maximum STS 138–193°C, Figure 4). Biomarker data suggest that most liquids in the field originated from Jurassic source rocks (mainly shales with minor coal inclusions). The liquids in shallow Aptian pools were generated by Jurassic source rocks but are less mature than those in deeper Jurassic– Neocomian reservoirs. Basin modeling and geochemical data, including source-oil correlation, clearly indicate that thermogenic oil and gas migrated vertically from Jurassic source rocks into the Neocomian–Cenomanian reservoirs of the Bovanenkovskoe field. A significant amount (∼57 billion bbl [8155 million tons]) of oil was expelled by the originally oil-prone Bazhenov Formation within the field’s fetch area. The anticline structure formed during the Early Cretaceous (Melnikova, 1992) and could capture a significant part of the generated oil. Nonetheless, the main volume of fluid in the field is methane-dominated Milkov 1527 1528 Methanogenic Biodegradation in Western Siberia Figure 17. Schematic geological cross section, temperature, pressure, and fluid properties of the Bovanenkovskoe field based on data from Goncharov (1987), Maksimov (1987), Rudkevich et al. (1988), Chakhmakhchev et al. (1990), Khafizov (1991), Kleymenov et al. (1993), Cramer (1997), Galimov (1995), Nemchenko et al. (1999), Dvoretskiy et al. (2000), Skorobogatov et al. (2003), Ermilov et al. (2004), Kichenko (2004), Bondarev et al. (2008), and unpublished GeolabNor/Fugro data, used with permission. CGR = condensate/gas ratio. (dryness 0.9967) gas in the Cenomanian PK1 pool at approximately 680 m (2231 ft) (T ∼ 17°C) and condensate with a low condensate/gas ratio (CGR) (0.65 g/m3) and low C2+ (dryness 0.9667) at approximately 1365 m (4478 ft) (T ∼ 44°C) in the Aptian TP1–6 pools. The distribution of fluids in the field is consistent with at least a partial origin by methanogenic biodegradation of petroleum. Data from the Bovanenkovskoe field indicate that heavy to moderate biodegradation occurred at depths shallower than approximately 1750 (5741 ft) where the present-day temperature is less than 60°C (Figure 17) and where 77% of the gas and 8% of the condensate resources occur. Biodegradation at less than 1750-m (5741-ft) depth is apparent from the WOGC of condensates (Rudkevich et al., 1988). In addition, Figure 17 shows how concentrations of cyclic compounds increase toward the shallowest PK1 reservoir, whereas the CGR, concentrations of alkanes and C2+ gases decrease toward the shallow depths, which all are indicative of biodegradation. Based on results of basin modeling, established biodegradation in the Aptian–Cenomanian section, and viability of methanogenesis during oil biodegradation (Bokova, 1953; Jones et al., 2008), the following scenario may best explain the presentday distribution and composition of petroleum in the Bovanenkovskoe field. Initially expelled thermogenic petroleum filled the Jurassic and Neocomian reservoirs, leaked into shallower and cooler Aptian reservoirs, and accumulated under local Albian seals. Biodegradation in Aptian pools (most importantly in TP1–6) led to the formation of a significant amount of methane and dissolution of the remaining liquids in methane to form a condensate. Gases in the TP1–6 reservoirs apparently represent mixtures of biodegraded thermogenic and secondary microbial gases. These gases (mostly methane) accumulated at the crests of Aptian structures and leaked into the Albian–Cenomanian pools, where further biodegradation and possibly preferential dissolution of C2+ gases in pore waters resulted in the observed very dry gas. Gases in Cenomanian pools in the field (dryness 0.9967, d13C is −46.3‰) and in Aptian pools (dryness 0.9667, d13C is −41.3‰) are dryer and contain methane depleted in 13C rel- ative to gases in deeper Neocomian pools (dryness 0.9297, d13C is −35.8‰) and Jurassic pools (dryness 0.9170, d13C is −37.0‰), which is consistent with the addition of secondary microbial methane to the shallow pools. An alternative model of relatively less mature thermogenic gas in the Cenomanian pool is not valid because the less mature gas would be wetter instead of drier. Because most of the oil was generated by the Bazhenov Formation long ago and no good seals between the Bazhenov Formation and local Albian shales exist, most of the generated oil migrated above the biodegradation floor and was biodegraded into gas. More mature petroleum (mostly gas) arrived from Jurassic source rocks into Jurassic–Neocomian pools in geologically recent time, which resulted in deep condensate pools below the biodegradation floor. GENERAL MECHANISM OF DRY GAS ACCUMULATION IN CENOMANIAN POOLS ACCOUNTING FOR METHANOGENIC BIODEGRADATION By integration of relevant geological and geochemical data with the main results of source maturity modeling and understanding of elements of petroleum systems across western Siberia and at five representative fields, the following general mechanism of gas accumulation in Cenomanian pools in the northern part of the basin is proposed (Figure 18). When the Aptian–Albian section was deposited (120–100 Ma), Lower–Middle Jurassic source rocks started to generate petroleum, which was partially trapped in Jurassic reservoirs. Oil and gas were expelled from the Bazhenov Formation mostly after the Cenomanian section was deposited (∼90 Ma). This petroleum was first trapped mostly by overlying Neocomian reservoirs. After building maximum column heights allowed by relatively poorsealing Neocomian shales, petroleum leaked into the shallower Aptian–Cenomanian reservoirs. A methane-producing biodegradation factory existed in the Aptian–Cenomanian section throughout the geologic history of the northern part of western Siberia, and much of the incoming thermogenic petroleum charge was biodegraded and converted Milkov 1529 Figure 18. Schematic cross section across a typical field and partial fetch area in the northern part of western Siberia illustrating generation and migration of petroleum and formation of giant Cenomanian gas pools in the methane-producing biodegradation factory. See the text for details. Formation symbols: Tr = Triassic; J1 = Lower Jurassic; J1tog = the Togur Formation; J2 = Middle Jurassic; J3 = Upper Jurassic; J3K1bazh = the Bazhenov Formation; K1neoc = Neocomian; K1apt-alb = Lower Cretaceous Aptian–Albian; K2cen = Upper Cretaceous Cenomanian; K2tur = Upper Cretaceous Turonian. into methane. Secondary microbial gas (predominantly methane) accumulated mostly in Cenomanian pools under the excellent regional Turonian shale seal. In the central and southern parts of western Siberia, all source rocks experienced less thermal stress and expelled relatively less thermogenic petroleum, which was mostly oil. Neocomian reservoirs accumulated most of the expelled oil and little leaked into the Aptian–Cenomanian reservoirs in the southern and central parts of the basin. The leakage was further prevented by early Aptian shales of the Koshayskaya and Alyimskaya formations, which are subregional seals present only in the central and southern parts of the basin (Figure 3). In rare areas where petroleum leakage occurred, oil was biodegraded and secondary microbial methane accumulated in the Cenomanian pools (e.g., at the Samotlorskoe field), but in most southern and central fields, oil has not leaked into the Aptian– Cenomanian reservoirs. Depending on various factors, such as local generative potential, maturity of source rocks, development of seals, temperature history, timing of events, etc., some deviations from the above general scenario are observed. For example, in the Russkoe field, where the Bazhenov Formation started to expel oil at approximately 90 Ma but at a very 1530 Methanogenic Biodegradation in Western Siberia slow rate, charge into the Cenomanian pools was relatively recent because of the long vertical migration distance through the thick but sandy section (Figure 14). Biodegradation of oil was extensive but incomplete, and a significant oil leg was preserved. Generated methane accumulated at the crest of the Cenomanian traps and leaked through the locally poor regional seal of the Kuznetsov Formation into reservoirs of the Turonian Gazsolinskaya Formation (Figure 14). In the Severnoe and Novoportovskoe fields, the Bazhenov Formation started to expel oil at approximately 75–90 Ma but at a relatively slow rate. That oil migrated vertically and laterally within fetch areas and accumulated in overlying Neocomian and underlying Upper Jurassic reservoirs. Vertical migration through relatively poor seals as well as reservoir cooling during the regional uplift that started in the early Oligocene (∼30 Ma) led to biodegradation of petroleum in many Neocomian reservoirs (and even Jurassic reservoirs in the Novoportovskoe field), which continues at present (Figures 13, 16). Methane generated during biodegradation accumulated as gas caps over oil legs and leaked upward to form gas and condensate accumulations in Neocomian– Cenomanian reservoirs. Biodegradation was even more severe in these shallower accumulations and it further modified the molecular and isotopic composition of gas, resulting in extremely dry-gas accumulations. Because the Bazhenov Formation in fetch areas of those fields reached only mediumlate oil maturity, the generated petroleum had a relatively low GOR; the amount of petroleum generated and available for biodegradation as well as the duration of biodegradation was not significant, which resulted in relatively small dry-gas accumulations in these fields. For example, the Cenomanian PK1 trap in the Novoportovskoe field is significantly underfilled with gas (∼20-m [66-ft] gas column with only 60.7 bcf [1.7 billion m3] within the trap of ∼140-m [460-ft] amplitude; Zhabrev, 1983). In addition, oil relatively recently generated by the Bazhenov Formation that migrated above the biodegradation floor has not resided long enough in the reservoirs to be fully converted to gas, which explains the common occurrence of oil shows, legs, or even accumulations in the Aptian–Cenomanian section of the Russkoe, Severnoe, and Novoportovskoe fields. The Urengoyskoe and Bovanenkovskoe fields evolved very differently from the three fields described above. Lower–Middle Jurassic source rocks started to expel oil at approximately 120–110 Ma and the Bazhenov Formation started to expel oil at approximately 100 Ma. Both source rocks are currently in the middle to late gas window. The Triassic section is thick in the area of these fields and also produced petroleum (mostly gas). Petroleum generated by source rocks within the fetch areas of these fields is abundant and is characterized by a high cumulative GOR. The early-mature liquidprone part of that petroleum migrated into shallow, cool Neocomian–Cenomanian reservoirs and was either partially lost because of poorly developed seals (most importantly Turonian shales) or, most likely, was heavily biodegraded. Because of a relatively high GOR of initial petroleum feedstock and longer residence time of that petroleum in the shallow reservoirs, biodegradation was very efficient and resulted in the complete conversion of oil into methane with most residual biodegraded oil dissolved in the mixture of biodegraded thermogenic and secondary microbial gas. Later generated petroleum that was more mature and rich in gaseous compounds accumulated first in Neocomian reservoirs but eventually leaked into Aptian– Cenomanian reservoirs because of a lack of good regional Neocomian seals. Where good local Aptian– Albian seals exist, leaked petroleum accumulated in Aptian–Albian reservoirs and underwent significant biodegradation ( TP1–6 reservoirs of the Bovanenkovskoe field) and only then leaked into Cenomanian traps where it was further biodegraded (Figure 17). In settings where good Aptian–Albian seals are absent, petroleum migrated into shallow and cool Cenomanian reservoirs under the Turonian seal and was heavily biodegraded both in micro accumulations on the way to the trap and in the trap, as in the Urengoyskoe field (Figure 15). The scenario described for the Russkoe, Severnoe, and Novoportovskoe fields and that for the Bovanenkovskoe and Urengoyskoe fields represent two end-member cases. Depending on source rock facies and maturity, distribution of seals, thermal regime through geological time, and timing of events, most other fields in western Siberia with Cenomanian gas pools have evolved similarly. A biodegradation factory within the Aptian, Albian, and Cenomanian (and Jurassic–Neocomian in places) reservoirs is common throughout the northern and northeastern parts of the West Siberian Basin and appears to be partly responsible for the enormous volumes of dry gas trapped under the Turonian– Paleogene seal. At the very least, the molecular and isotopic composition of gases that migrated into that biodegradation factory was modified by removal of C2+ compounds and 12C. However, from the geological and geochemical evidence described above, significant amounts of secondary microbial methane were generated within the biodegradation factory from liquid and gaseous petroleum. In the central and southern parts of the basin (e.g., middle Ob area), oil was generated from the Bazhenov Formation relatively recently (from ∼80–60 Ma), and slowly and little of it migrated into the methane-producing biodegradation factory through well-developed lower Aptian seals (Koshayskaya and Alyimskaya formations, Figure 3). This explains why the Cenomanian reservoirs in the central and southern parts of the basin have only small gas accumulations (i.e., ∼20-m [66-ft] Milkov 1531 gas column in the Samotlorskoe field) or lack them entirely. The relative part of secondary microbial methane among gases of other origins apparently varies from pool to pool. For example, in the Severnoe field, most methane in gas pools and gas caps (especially in the shallowest reservoirs) may be secondary microbial methane and a minor part of the methane may be oil-associated thermogenic methane. This is because all potential source rocks in the fetch area of the Severnoe field are immature for nonassociated thermogenic gas, and oils with C2+-rich associated gases are the only fluids generated by conventional petroleum systems. However, within the fetch area of the Urengoyskoe field, a significant amount of oil-associated and nonassociated methane was generated by Jurassic source rocks, as well as Triassic mudstones and potentially Hauterivian coal. Although biodegradation apparently modified the fluid composition within shallow reservoirs of the Urengoyskoe field (Figure 15) and likely added secondary microbial methane (Figure 8), the relative part of secondary microbial methane among gases of other origins in that field may be small. In addition, primary microbial methane may dominate in a few very small or noncommercial (Ryisev, 1986) Cenomanian gas pools, such as in the Malyiginskoe and Zapadno-Seyakhinskoe fields in the Yamal area (Figure 8) (also noted by Schoell et al., 1997a) and may be present in relatively small amounts in other pools. Quantification of parts of methane of various origins (thermogenic, secondary microbial, primary microbial) requires advanced basin modeling calibrated with detailed geochemical data and represents an important direction of future research. IMPLICATIONS OF METHANOGENIC BIODEGRADATION Fluid-Phase Distribution in Western Siberia The distribution of fluid phases in the West Siberian Basin, mostly oil in the south and gas in the north as depicted in Figure 1, has been commonly noted (e.g., Peterson and Clarke, 1991, and nu1532 Methanogenic Biodegradation in Western Siberia merous Russian publications). Common explanations include variations of source rock organofacies (Kontorovich et al., 1997) and maturity (Nalivkin et al., 1969) across the basin, which was supported by a recent basinwide petroleum systems analysis (Milkov, 2009). In the central and southern parts of the basin, the Bazhenov Formation is a rich oilprone source rock, which accounts for most petroleum found in Jurassic and Neocomian reservoirs. Other Jurassic source rocks have relatively low generative potential and are more gas prone. None of the source rocks have entered the gas window (Figure 4). Because little petroleum leaked into the shallow, cool Aptian, Albian, and Cenomanian reservoirs, methanogenic biodegradation was insignificant. These factors led to the occurrence of mostly oil fields in the southern and central parts of the basin. In the northern part of the basin, the Bazhenov Formation and its stratigraphic equivalents are somewhat poorer and more gas prone than in the central part of the basin, and they have been buried in the gas window (Figure 4b). Although Lower– Middle Jurassic source rocks are somewhat more oil prone than in the southern and central parts of the basin, they entered the gas window at approximately 120–90 Ma and spent most of their generative potential (Figure 4a). A thick Triassic section of interbedded volcanics, mudstones, and sandstones with occasional coal is present in the north but not widely developed in the south and could have generated some amount of petroleum. Some early-mature oil expelled by Jurassic source rocks in the northern part of the basin could have been lost if the Turonian seal was ineffective at the time of migration through the Cretaceous section. However, large volumes of Jurassic-sourced oil apparently migrated into Aptian, Albian, and Cenomanian reservoirs and then were heavily biodegraded. This biodegradation likely resulted in the generation of secondary microbial gas (predominantly methane) that accumulated in giant Cenomanian pools under Turonian seals. As a result, the northern part of the basin is predominantly a gas province (Figure 1). Another important process controlling fluidphase distribution in the West Siberian Basin is the phase separation resulting from a change in pressure-volume-temperature conditions during upward migration of expelled petroleum. The importance of this factor will be demonstrated in future studies. Other, more speculative processes, such as a significant contribution of microbial and early thermogenic gas from Hauterivian–Cenomanian coal (Nemchenko et al., 1999) and exsolution of gas from water during regional uplift (Korzenshtein, 1977; Cramer et al., 1999; Littke et al., 1999), could also have contributed to the dominance of gas accumulations in the north but were perhaps minor and/or local factors (Murris, 2001). Recognition of Secondary Microbial Methane in Sedimentary Basins The presence of dry secondary microbial gas can be misinterpreted as late thermogenic gas charge postdating biodegradation, as was perhaps done in the study of the Captain field in the North Sea (Pinnock and Clitheroe, 1997). It is also easy to misinterpret shallow secondary microbial gas as primary microbial gas. However, recognition of secondary microbial gas in shallow pools is important for petroleum exploration because it indicates that effective thermogenic petroleum systems occur in the deeper section (Sweeney and Taylor, 1999). If biodegradation of liquid petroleum is established or predicted to occur in a sedimentary basin, then the presence of secondary microbial methane shall be assumed because methanogenesis is a terminal biodegradation process (Larter et al., 2006). However, secondary microbial methane may be difficult to recognize using gas plots commonly applied to interpret the origin of natural gases (Schoell, 1983; Chung et al., 1988; Whiticar, 1999). This is because of a significant overlap of empirical genetic fields (Figure 8) and common mixing of gases of different origins and from different source rocks in one accumulation. For example, the Bernard diagram (C1/(C2 + C3) versus d13C of methane, Figure 8a) is most commonly used to distinguish between primary microbial and thermogenic gases. When the original diagram was compiled (Bernard et al., 1978; Schoell, 1983), the boundary between 13C-depleted microbial meth- ane from CO2 reduction and 13C-enriched thermogenic methane was set at d13C of −60‰. However, later modeling and empirical studies demonstrated that early-mature thermogenic methane is 13Cdepleted and may have d13C as negative as −70‰ (Rowe and Muehlenbachs, 1999; Tang et al., 2000; Coleman, 2001; Milkov and Dzou, 2007). Primary microbial methane may form in the subsurface from 13C-enriched CO2 and have d13C values as positive as −39.5‰ (Pohlman et al., 2009), although it is unclear if such methane may accumulate in commercial quantities. Although thermogenic hydrocarbon gases are commonly wet (C1/ (C2 + C3) < 50), they become enriched in methane during maturation (Schoell, 1983) and biodegradation (James and Burns, 1984). Nevertheless, data from western Siberia and other biodegraded petroleum accumulations around the world (Figure 10) suggest that a field of biodegraded and secondary microbial gases can be defined on the Bernard diagram as shown in Figure 8a. Such gases tend to be drier than thermogenic gases but have methane more enriched in 13C than most primary microbial gases (d13C of methane generally between −55 and −40‰). Relatively high (>2%) concentrations of CO2 that is enriched in 13C (d13C > −10‰) are commonly interpreted as evidence of secondary methanogenesis (Pallasser, 2000; Larter and di Primio, 2005; Jones et al., 2008). However, CO2 is highly soluble in water and readily precipitates in carbonates, and concentration of CO2 is a less reliable indicator of secondary methanogenesis than d13C of CO2. Data from western Siberia, other biodegraded petroleum accumulations around the world (Figure 10), and modeling (Jones et al., 2008) suggest that a genetic field of secondary microbial gas can be defined on the d13C of methane versus d13C of CO2 diagram ( Whiticar, 1999) as shown in Figure 8c. Importance of Secondary Microbial Gas in Sedimentary Basins Data from western Siberia presented in this study suggest that enormous volumes of secondary microbial methane may be preserved in areas where Milkov 1533 good seals are present. As shown in Figure 10, accumulations with secondary microbial methane are documented worldwide. Gas hydrates represent an additional mechanism to preserve secondary microbial methane. For example, large volumes of hydrate-bound gas occur above biodegraded oil fields in Alaska (Collett, 1993), and the gas may be at least partly of secondary microbial origin (Lorenson et al., 2009). Molecular and isotopic compositions of hydrate-bound gases from the Mallik well in Canada (mean C1/C2+ is 2739, mean d13C methane value is −42.7‰, n = 12, Lorenson et al., 1999; Uchida et al., 1999) and the Mount Elbert gas hydrate well in the Alaska North Slope (Lorenson et al., 2009) are consistent with the secondary microbial genetic field in Figure 8a, although the dryness of these gases could also be related to molecular fractionation during gas hydrate formation. Because the subsurface occurrences of secondary microbial gas have only recently been recognized and the amounts of secondary microbial gas in individual accumulations have not been calculated, assessing how much secondary microbial gas is currently preserved in the subsurface is difficult at this time. However, at least eight fields (seven fields in the northern part of western Siberia and the Troll field in the North Sea) in the list of the 20 largest gas fields with remaining reserves in the world (Aali et al., 2006) contain some gas of secondary microbial origin. Rice and Claypool (1981) and Rice (1992) estimated that accumulations of primary microbial gas contain 535 tcf (15.2 trillion m3) or about 20% of world discovered gas reserves. However, 474 tcf (13.4 trillion m3) (or 89%) of that gas occurs in Cenomanian pools of western Siberia (Rice, 1992, their table 2) and apparently has mixed biodegraded thermogenic and secondary microbial origin. I speculate that secondary microbial gas generated from biodegraded petroleum may be volumetrically more important in the global natural gas endowment than primary microbial gas generated from decomposed organic matter. Updated estimates of global volumes of primary and secondary microbial gas are needed to better establish the relative importance of those pathways of natural gas generation. 1534 Methanogenic Biodegradation in Western Siberia Role of Secondary Microbial Gas in the Global Carbon Cycle and Climate Change Although secondary microbial gas in the Cenomanian pools of western Siberia is retained under an excellent Turonian seal, most of the methane generated in subsurface petroleum reservoirs worldwide may be lost to the overburden, atmosphere, and ocean. This is because heavy biodegradation commonly proceeds at low temperature and shallow depth, where mudstones overlying reservoirs have limited sealing capacity because of insufficient compaction. Meyer et al. (2007) estimated that 3396 billion bbl (486 billion tons) of heavy oil in 192 basins and 5505 billion bbl (788 billion tons) of natural bitumen in 89 basins (originally in place) exist, most of which originated from petroleum biodegradation in shallow sediments. If only 70% of approximately 8900 billion bbl (1273 billion tons) of heavy oil and bitumen are actually biodegraded residues (and the other heavy oils originated from, for example, low-mature carbonate source rocks), then approximately 6230 billion bbl (891 billion tons) of biodegraded oil remain. Assuming that the average level of degradation is PM5 (Peters and Moldowan, 1993) and 64 wt.% was removed (Jones et al., 2008), there would be about 11,075 billion bbl (1477 billion tons) of oil converted to CO2 and methane. Using stoichiometry of methanogenic alkane biodegradation (Zengler et al., 1999) and assuming 85% conversion of oil to methane, there would be approximately 66,500 tcf (∼1884 trillion m3 or ∼1.27  1015 kg) of secondary microbial methane generated in currently existing biodegraded petroleum accumulations. This methane was partially retained as oil-dissolved, free, and hydrate-bound gas in reservoirs (Figure 10), and partially dissolved in aquifers, but most of it apparently escaped into the shallow overburden, atmosphere, and ocean. This huge amount of methane exceeds the worldwide conventional gas endowment (Ahlbrandt et al., 2005) by about four to five times. The CO2 and methane generated during petroleum biodegradation represent potent greenhouse gases and likely affected both climate change and the global carbon cycle in the geological past. Evaluation of periods and magnitudes of such influence may represent an important direction of future research. CONCLUSIONS 1. Based on a comprehensive review, most widely cited hypotheses of the origin of dry gas in the giant Cenomanian pools of western Siberia are inconsistent with geochemical data and basin and petroleum systems models. These hypotheses include early-mature thermogenic gas from coals, primary microbial gas, and thermogenic gas from deep source rocks. 2. Many Cenomanian pools in the northern part of western Siberia contain not only dry gas, but also live and residual Jurassic-sourced oil, which apparently leaked from underlying Jurassic– Albian reservoirs. Oils in Cenomanian pools are heavily biodegraded, whereas oils in many Jurassic–Albian pools experienced heavy to slight biodegradation. Methanogenesis is a common terminal process during petroleum biodegradation, as demonstrated by many laboratory and, more recently, subsurface studies worldwide. The common occurrence of dry gas above biodegraded petroleum in the northern part of western Siberia leads to a hypothesis originally proposed by Goncharov et al. (1983) that dry gas in the Cenomanian pools may originate, at least partially, from biodegraded petroleum. 3. Direct evidence of methanogenic biodegradation in the northern part of western Siberia includes, most importantly, 13C enrichment of CO2 sampled from shallow, cool pools having biodegraded oil. However, the data set of d13C for CO2 is limited and will be expanded in further studies. 4. Hydrocarbon gases from Cenomanian pools take a unique position in the d13C of methane versus C1/(C2 + C3) plot (Bernard diagram): they have higher C1/(C2 + C3) ratios than thermogenic gas but more positive values of d13C of methane than primary microbial gas. The empirical field of these gases on the plot is defined as a new genetic field, biodegraded and secondary microbial gas, which is consistent with ob- servations from other areas having secondary microbial gas. 5. Review of the distribution, phase, and properties of fluids in five typical fields from western Siberia suggests that gas pools in shallow, cool Aptian, Albian, Cenomanian, and Turonian strata are most consistent with mixing of biodegraded thermogenic gas from Jurassic and potentially Triassic sources and secondary microbial methane with occasional and minor addition of primary microbial methane and, speculatively, coal-derived early-mature gas. Quantification of parts of methane of various origins represents a challenge for future research. 6. 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