The issue of chemical reactions and thermodynamic equilibrium in the water-gas system during formation and destruction of oil and gas accumulation is currently at the leading edge of petroleum geosciences. Phase equilibium between hydrocarbons and groundwater reflects the geochemical process of petroleum generation and migration, and this process controls the origins and evoution of groundwater and petroleum. Furthermore, the water-gas system has been proved highly mobile. Investigations of water-gas interactions in deep strata of sedimentary basins have been carried out by many research teams from different perspectives. For example, studies on water-gas interactions in the Sichuan basin ^[1-3], the Ordos basin ^[4-6], the Eastern Mediterranean basin ^[7], and Pearl River Mouth basin ^[8] have been fruitful. Another direction of the gas-water system study is the state and occurrence development of gas hydrates ^[9-13]. Basin simulating based on geophysical, geological, and geochemical survey data can’t meet the requirements of oil and gas exploration in the West Siberian basin anymore^[14-17]. In this respect, the water-gas thermodynamic equilibrium, regional hydrocarbon generation and conservation conditions, as well as mass exchange of oil and gas with formation water have become new research contents in predicting local-scale petroleum potential^[18-21]. Gas with high mobility is one of the most reliable tracers, which can point out oil and gas migration direction ^[22-24]. Field data and simulating results show that infiltration of water in the deep strata of the West Siberian basin is currently very slow and vanishing. Correspondingly, diffusion becomes the main way of mass transfer ^[25]. The state of Arctic reservoirs can be figured out by simulating water-gas equilibrium with reference to the wealth of data on water chemistry and groundwater circulation of producing beds ^[26]. Available algorithms for calculating water-gas equilibrium are suitable mainly for fresh water and not applicable to oil and gas bearing basins with saline water. The Jurassic and Cretaceous in the Arctic region of northern Siberia have saline water and brackish water in general, with NaCl content of up to 63.3 g/L. Meanwhile, the strata have abnormally high pressures and temperatures from 35 to 150 °C. In this work, the present state of Jurassic-Cretaceous oil and gas-bearing system in the Arctic region of West Siberia was evaluated for the first time by simulating water-gas equilibrium. Hopefully, this study can provide theoretical and technical support for oil and gas exploration in sedimentary basins with different isotope geochemical kinds of groundwaters from saline water to strong brine.

The water-gas system consists of multiple components involving in diverse processes and interactions. As available conventional methods aren’t suitable for calculating gas saturation of formation water, fugacities of certain gases, and other variables, the HG-32 (Hydrogeo) software designed by Bukaty ^[27] with the A.A. Trofimuk Institute of Petroleum Geology and Geophysics (Novosibirsk) was used in this work. This software considers almost all variables of the system (density, total salinity, gas saturation, composition of water-soluble gases, and PT conditions, etc.). It can be used either to determine the composition and parameters of equilibrated free gas phase from the composition of water and dissolved gases or, vice versa, the composition and other parameters of dissolved gases from free gas and water composition. Moreover, it is also applicable to simulate gas evasion and invasion patterns when pressure, temperature, and solvent composition change. The gas-water equilibrium simulation method is applicable for forward modeling and inversion calculation of water-soluble gases, free gas and associate gas. As the critical solubility of natural gas in water reflect information on the fluid types and natural gas saturation of the oil reservoir, the natural gas saturation of water can be replaced by this critical solubility. In addition, this method can simulate the interaction between oil and gas and formation water. In 197 Cretaceous and Jurassic reservoirs of the study area (Fig. 1), we examined the data of over 3800 tested points, 5600 formation water samples, 2500 dissolved gas samples and 1900 free gas samples, and simulated over 1200 oil and gas pools.

The features of hydrogeology and water chemistry in the Arctic petroleum province (northern West Siberia) have been extensively studied since the 1960s ^{[28⇓⇓⇓-32]}. The Mesozoic-Cenozoic of the West Siberian Artesian Basin comprises Paleogene-Quaternary, Upper Cretaceous, Aptian-Albian-Cenomanian (reservoir of PK_1-22, HM₁, and TP_1-19), Neocomian (AP_6-11, BP_1-21, SD_0-14), Upper Jurassic (Yu₁), Lower-Middle Jurassic (Yu_2-23), Triassic, and undifferentiated Paleozoic aquifer systems^[25,33]. All Mesozoic aquifers are composed mainly of permeable sandstone and siltstone and are sealed by mudstone. The continuous Turonian-Oligocene aquiclude isolates the aquifers from the surface water, but the aquiclude made up of more permeable lithologies along the basin borders has weaker blocking capacity ^{[34⇓⇓⇓-38]}.

Jurassic and shallower (till Neocomian) reservoirs at the depths of 2.8-6.0 km in the province are subject to overpressure (pressure coeffcient up to 2.26), the oil- and gas-bearing sandstone and siltstone have a porosity generally from 0.70% to 42.55% (mostly 10%-20%), and the porosity show a decreasing trend from the Aptian to Albian, Cenomanian aquifers, and the Paleozoic basement.

Groundwaters in the Arctic reservoirs generally have moderate salinity and mainly ions such as Cl^-, Na⁺ and HCO₃^-. In zone, groundwater at the basin margin has a total salinity (TDS) from 2-5 g/L, while that in the basin center has a total salinity of up to 63.3 g/L ^{[30,39 -40]}; in horizon, the Upper Jurassic aquifers have the highest ion contents (Table 1). Each water type has its specific pattern of salt-forming, and contents of major (Cl^-, Na⁺, Mg²⁺, Ca²⁺, and K⁺) and minor (Br^-, I^-, B⁺, NH₄⁺, and Sr^-, etc.) components are proportional to salinity. When the saline is 15 g/L or more in salinity, its content of HCO₃ decreases; the saline has an average SO₄^2- content of 20-60 mg/L as SO₄^2- ions are reduced to H₂S during ooze formation.

The total gas saturations (S_g) of aquifers in Jurassic- Cretaceous system change widely, and even have differences of two-times or more within a single aquifer. But the general trend is that the total gas saturation increases with the increase of depth, from 0.3-3.0 L/L in the Aptian to Cenomanian stage to 0.9-5.7 L/L in the lower part of Middle Jurassic ^[14,16,33]. The aquifers in of Jurassic-Cretaceous are rich in methane: aquifers in the Aptian-Albian-Cenomanian and Middle Jurassic have methane contents of 95.5% and 83.3% respectively, while deeper aquifers have lower methane contents.

Meanwhile, the contents of methane homologs increase from 1.3% in the Aptian-Albian-Cenomanian aquifers to 11.7% in the lower part of Middle Jurassic strata. The CO₂ content also increases with the increase of depth. The aquifers in the Aptian-Albian-Cenomanian and Middle Jurassic have a N₂ content of 15%, CO₂ content of 4%, H₂ content of 6%, He content of 0.14%, and Ar content of 0.19%.

As found previously ^[36], the groundwaters in the northern West Siberian and other Arctic basins are at the initial stage of chemical alteration, and are free from salt components in sediments. The Ca/Cl ratio in the region is no higher than 0.20, except for HCO₃ Ca water in the zones of active water exchange.

The gas saturation coefficients C_s of waters in the Aptian-Albian-Cenomanian aquifers of the Arctic, Gubkin, Zapolarny, Medvezhy, and some other oil and gas fields were estimated. For instance, aquifers within Cenomanian reservoir bed PK₁ exceptionally rich in gas resources have gas saturation coefficients C_s mostly from 0.80 to 1.00. These waters are NaCl type, with TDS of 20 g/L and S_g of 1.5-2.5 L/L. The dissolved gas in the water has about 98.5% of methane, 0.5%-1.5% of N₂, and still smaller amounts of other gases. The S_g and C_s values decrease markedly from the Yamal Kara Basin toward the margins of the West Siberian Basin (from 0.1-0.5 to 0.05-0.2), meanwhile, the main gas components change from methane and nitrogen to nitrogen and methane.

In the deeper (older) aquifers, the situation is different: in the central part of the province (Medvezhy, Urengoi, Vynga-Pur and other fields), C_s often approach the critical value (0.8-1.0), but it is much lower in the other areas. For example, the water samples from PK₁₅ of the Udmurt field have C_s from 0.08 to 0.10, lower salinity (3.3-6.3 g/L), dissolved gas made up of 96.3%-97.2% CH₄ and 2.6 to 3.4% N₂, and S_g from 0.3 to 1.5 L/L. The water samples from PK₁₃, PK₁₄, PK₁₅ and PK₁₆ in the Kharampur field have C_s from 0.34 to 1.00, while the water samples of NaCl type have S_g from 1.0-2.2 L/L to 1.5-3.0 L/L, TDS from 10.7-10.9 g/L (PK₁₃ and PK₁₅) to 15.0-17.8 g/L (PK₁₄ and PK₁₆), and 97.4%-97.9% (PK₁₃) to 84.3%-90.0% (PK₁₆) CH₄ and less than 2.2% N₂ in the dissolved gas. With the increase of depth, CH₄ and its homologs in the water increase (to 1.5%-5.0% in PK₁₆). The C_s is the lowest in PK₁₃ (0.34-0.37) and PK₁₅ (0.33-0.34) and the highest in PK₁₆ (0.68-1.00). Well 339 (depth interval 1798-1808 m) has a daily gas production of 451 400 to 584 600 m³ (depending on choke size). The Aptian to Cenomaina aquifers in Ozerny, Pelatka, Nerstinsky oilfields (Yamal Peninsula) have C_s values of 0.71-0.73, 0.53-0.70, and 0.19 respectively.

The coefficients C_s of the Neocomian aquifer system in the richest and best documented oil reservoirs in many oilfields (Barsukov, East Tarko-Sale, Gubkin, Deryabin, Etypur, West Tarko-Sale, Komsomolsky, and Ust`-Kharampur etc.) were estimated. This aquifer system formed during transgression-to regression transition in the Late Jurassic-Cenomanian deposition cycle, when rhythmically interbedded sand and clay deposited in shallow-marine shelf. Consisting of numerous laterally continuous reservoir sands and clay seals, this sequence is likely to form oil and gas reservoir beds. This has been proved by the existence of the mentioned oilfields. The C_s patterns in some of these oilfields are taken as examples to analyze.

The groundwaters of the East Tarko-Sale oilfield are Cl-Na-Ca and Cl-Na types, with a salinity range of 5 to 20 g/L and S_g range from 0.6 to 3.9 L/L (2.4 L/L on average). The dissolved gas in the water is primarily methane (84.4%) and a small amount of N₂ (smaller than 12%, 2% on average), and other gases.

The C_s pattern is especially distinct in the lower Neocomian Sortym Formation strata (Fig. 2), where the gas saturation coefficient decreases gradually from 0.8-1.0 in beds containing gas and condensate to 0.4-0.8 in oil reservoirs. Namely, C_s is the highest (0.95 to 1.00) in BP₁₂, slightly lower (0.80-0.86) in BP₁₄, decreases to 0.74 to 0.83 in BP₁₅, and becomes markedly lower at deeper part of pure oil reservoirs: 0.56 to 0.75 in BP₁₆ and is lowest (0.32-0.42) in BP₁₇.

Above the BP₁₁ and BP₁₂, the saturation coefficient also shows a general decreasing trend, but its behavior is more complicated, with variations from low C_s in some beds to the critical value (1.0) in others. For instance, average C_s values are 0.46 in BP₁₀, 0.73 (from 0.23 to 1.0) in BP₉, 0.33 in BP₆, 0.99 in BP₅, and 0.78 in BP₄. On the other hand, C_s is generally related to the fluid type, specifically, it is higher (0.8 to 1.0) in gas-condensate reservoirs and lower (smaller than 0.8) in oil reservoirs (Fig. 2).

The water samples from Neocomian reservoir in the West Tarko-Sale oilfield are Cl-Na type, with TDS from 4.3 to 28.5 g/L and S_g from 1.0 to 5.5 L/L (3.1 L/L on average). In the water-dissolved gas, methane accounts for 78.1%, and N₂ accounts for less than 10% (on average ~4%). Unlike the East Tarko-Sale oilfield, water samples from most beds of this oilfield reach the critical gas saturation (1.0).

Water samples from beds BP₄ (C_s = 0.5) and BP₈ (C_s = 0.37) have lower gas saturation coefficients, but water samples from deeper gas-condensate reservoirs with at a daily rate of 92 700 to 214 300 m³ (gas) and 38.6-88.7 m³ (stable condensate) have higher gas saturation coefficients. The C_s increases toward the gas-water contact from 0.59 to 1.00 and reaches 1.0 also in BP₇. The water samples from BP₈ and BP₉ have C_s up to 1.0; those from BP₁₁, BP₁₂, BP₁₆ and Achimov Member have C_s of 0.58 to 1.00; 0.68 to 1.00; 0.92, and 0.29 to 1.0 (0.79 on average) respectively. The zone of gas-bearing water in the West Tarko-Sale field is thicker than elsewhere, which is favorable for rapid degasification at the current evolution stage of the oil-gas system.

Water samples from Lower Cretaceous reservoirs in the Gubkin oilfield are Cl-Na type, with a total salinity of 4.4 to 29.5 g/L, 61.0%-92.3% methane and 1.4%-18.2% N₂ in the dissolved gas, and S_g from 0.4 to 3.5 L/L. The C_s pattern is almost identical to that in the West Tarko-Sale oilfield and reaches 1.0 in a zone larger than 500 m thick that encompasses beds from BP₆ to BP₁₆, except BP₉ with very low C_s of 0.17. C_s in BP₄ is lower (0.47), similar with that in the West Tarko-Sale oilfield (0.5).

The water samples from Lower Cretaceous reservoirs in the Etypur oilfield are Cl-Na type, with TDS of 4.0 to 23.9 g/L, S_g from 0.3 to 5.2 L/L, and 64.9% to 96.1% CH₄ and 0.6% to 23.6% N₂ in the dissolved gas. The contents of methane homologs and S_g value increase with the increase of depth. The interval from BP₃ to BP₁₂ corresponds to a thick zone of gas-saturated water, in which only BP₆ (C_s = 0.12-0.46) and BP₁₀ (C_s = 0.56) have low gas saturation coefficients. Some beds have saturation coefficients varying in a wide range (e.g., 0.32 to 1.0 (average 0.69) in BP₇; 0.36 to 1.0 in BP₁₁; 0.22 to 1.00 in BP₁₂) but deeper beds have stable C_s (0.8 in BP₁₄ and 0.53-0.54 in BP₁₇).

Formation water samples from the Ust’-Khrampur oilfield are Cl-Na type too, and have a salinity of 4.6 to 22.0 g/L, 69.0% to 94.4% CH₄ at 2.5% to 11.4% N₂ in the dissolved gas, S_g from 0.5 to 5.0 L/L; and content of methane homologs and S_g value increasing markedly with depth. Similar with the Etypur oilfield, water samples from beds BP₈, BP₉, and BP₁₁ have the highest C_s. Whereas C_s of waters from beds below BP₁₁ decrease from 0.74-0.84 (BP₁₂) to 0.46 (BP₁₇).

Thus, the gas saturation of the Lower Cretaceous aquifers system shows complex heterogeneity, though the general trend is similar with that in the Aptian-Albian-Cenomanin system, with C_s decreasing toward basin margins. The C_s values are related to the fluid type, and higher (0.8 to 1.0) in gas-condensate reservoirs and lower in oil reservoirs.

In addition, the gas saturation coefficients of the Jurassic aquifers in the Gubkin, Deryabin, Komsomolsky, Malygin, Kharampur, and other oilfields were studied. In Kharampur oilfield, the aquifers in Jurassic have lower saturation coefficient C_s (Fig. 3), while the deepest aquifer of the lower Tyumen Formation has higher C_s. The coefficient C_s increases with depth: for example, the C_s values in Upper Jurassic (Yu₁) bed are, respectively, 0.42-0.56 (Yu₁^1-2) and 0.31-0.55 (Yu₁^3-4); 0.45-0.75 and 0.63 (average) in Yu₁²; 0.60-0.75 and 0.55 in Yu₁³; and 0.60-0.85 in Yu₁⁴. The Lower-Middle Jurassic aquifer system (Yu₂) has laterally heterogeneous gas saturation, with lower C_s in the North Kharampur uplift and high C_s up to 1 in the Kharampur uplift (Fig. 3). Unlike Yu₂, water samples from bed Yu₃ reach critical saturation (1.0) throughout the oilfield. In general, C_s increases from 0.37-0.42 in the 2850-2910 m depth interval to 1.0 at greater depths of 3000-3050 m. The C_s contour lines generally reflect the geological structure of permeable strata and show strong correlation with depth (r = 0.84) and marked correlation with total water salinity (r = 0.56). C_s has the strongest correlation with salinity at the total salinity of formation water larger than 38 g/L; e.g., it is 0.37 at the salinity of 24 g/L and 1.0 at the salinity of 42 g/L. The Jurassic reservoirs of the Kharampur oil-gas-condensate field has two gas saturation zones (Fig. 3), the shallower aquifers have lower gas saturations, while the deeper aquifers have higher gas saturations. The upper zone corresponds mainly to the Vasyugan Fm. (Yu₁), except for the area of the North Kharampur local uplift where it also includes Yu₂. The water-gas system in this zone hasn’t reached equilibrium, and the formation water can dissolve additional amount of gas. The lower zone, with gas saturated water, corresponds to the Tyumen Fm. and comprises beds Yu₂ and Yu₃, except for the North Kharampur uplift. Dissolved gas in this zone can be released into free phase in the course of geological evolution.

The calculated C_s values may be inconsistent with practical data that is the presence of oil accumulation with gas cap in the permeable Yu₁ reservoir in the upper saturation zone. It is impossible to explain this contradiction by depth-dependent temperature, salinity, or pressure changes, which are much less significant than the C_s variations of 0.4 to 1.0 (Fig. 3). It is worth noting that gas accumulation originally was formed under the effect of dissolved phase, which was then in equilibrium with free gas. The non-equilibrium at present means that the setting has changed after the gas pool was formed, and the water becomes unsaturated, i.e., no longer release gas into free phase.

This can be explained by the correlation of C_s with salinity. The formation water in reservoir rock is often diluted by infiltration water seeping into the water-gas system. This hypothesis agrees with the water chemistry and hydrogeological setting of this region (Novikov et al.^[37]). In this area, the total salinity of formation water does not correlate with the Cl^-/Br^- value, which is possible only when saline water is diluted by fresh water with lower Cl^- and Br^- contents. On the other hand, the reservoir pressure in the southern part of the Kharampur oilfield is lower than that in the north, i.e., the water flows from north to south; so water in the northern part of the field has lower salinity and S_g values.

Thus, the water in the Yu₁ reservoir reached critical gas saturation and could originally contribute to the accumulation of free gas until unsaturated older infiltration water seeped into the system and broke the water-gas equilibrium. The non-equilibrium conditions in the system have been maintained due to limited contact of the formation water with the gas pool, while the deeper strata out of the reach of infiltration water have kept high gas saturation till present. This hypothesis can be used to estimate the destruction degree of hydrocarbon accumulation by groundwater.

The calculated C_s values for the adjacent areas of the Yenisei-Khatanga basin (Deryabin, Semenovka, Middle Yar, Turka, and Ushakovka areas) are the highest in bed Yu₂ (0.57 to 1.0), but lower in the deeper beds of Yu₄ (Ushakovka area) and Yu₁₇ (Semenovka area): 0.57 and 0.74, respectively. Highest C_s up to 1.0 is also the typical feature of Yu_2-3 of the Yamal Peninsula.

In conclusion, the aquifers in the Arctic reservoirs have complex variations and heterogeneity of gas saturation. The saturation coefficients C_s of Jurassic-Cretaceous aquifers vary from as low as smaller than 0.2 to as high as 1.0 (Fig. 4a). Almost all water samples with S_g larger than 1.8 L/L reach critical saturation, i.e., the conditions in the oil-gas system are favorable for the generation of hydrocarbon accumulation (Fig. 4b).

Thermodynamic calculations by the above method provide insights into interactions between oil and gas accumulations and the ambient formation waters. The Aptian-Albian-Cenomanian aquifer system was simulated with data from the Arctic, Zapolarny, Messoyakha, Krusenshtern, Malygin, Tasiy, Kharampur, and other oilfields, which showed different gas saturation patterns in different reservoir beds.

Bed PK₁ is extremely rich in gas (e.g., Urengoi, Medvezhy, Yamburg oilfields). We analyzed natural gas migration paths between the accumulations and the surrounding waters. Since gas in the PK₁ reservoir is mostly dry and free from the homologous compounds of methane, it is difficult to figure out the diffusion patterns from heavy hydrocarbons. Equilibrium phase studies of the Komsomolsky and Kruzenshtern oilfields used CH₄ and that of the Nerstinsky field used C₂H₆.

In the oil-gas-water systems in the Malygin (HM₁, TP₁, TP₃, TP₆, TP₈), Kruzenshtern (TP₉, TP_10. TP₁₃), Nurma (TP₃), Tasiy (TP₄², TP₅, TP₁₁, TP₁₃) oilfields etc., CH₄, Ar, and CO₂ are diffusing from the pools to the ambient waters, while heavy hydrocarbons, He, and N₂ are inputting from the waters to the oil and gas accumulations. The gas components in the pools are currently changing toward heavier ones, while non-hydrocarbon gases are changing in concentration. Therefore, generation, migration, and accumulation of oil may continue till the present while the formation and accumulation of gas has apparently stopped.

The gas-water exchange in reservoir beds PK₁₃, PK₁₄¹, PK₁₅ and PK₁₆ of the Kharampur oilfield in the central Nadym-Taz basin was studied. The results show that the gas and water interact in almost the same ways as in Yamal oilfield, except for beds PK₁₃ and PK₁₅ where the accumulations release also other hydrocarbon gases (C₂H₆, C₃H₈, and C₄H₁₀). In PK₁₅ of the Udmurt oilfield, hydrocarbon and non-hydrocarbon components of the gas cap diffuse into the ambient water.

The gas-water exchange patterns in the oil-gas-condensate fields were paid additional attention. In some Lower Cretaceous reservoir of the Gubkin oilfield (C₂H₆, C₃H₈ and C₄H₁₀ in AP_9-10, BP_4-5, BP₉¹ and BP₉², BP₁₅, and BP_16-21, as well as C₅H₁₂ and C₆H₁₄ in beds AP_9-10, BP₉², and BP_16-21), the gas phase hydrocarbons become heavier due to inputs of methane homologs from the ambient waters. Except BP₇ and BP₉, the gas exchange modes in the oilfield are: He and N₂ inputting from waters to the accumulations counterbalances with H₂, CH₄, CO₂ and Ar diffusing from the accumulations to the waters. The diffusion process involves almost the entire gas cap in beds BP₃, BP₇, BP₈ and BP₉.

Most of aquifers in the West and East Tarko-Sale oil-gas- condensate field are saturated with natural gas, with C_s of up to 1.0 (Fig. 2). This is consistent with the fact that C₂H₆, C₃H₈, C₄H₁₀, He and Ar diffuse into almost all beds except BP₁₀ and BP₁₄ (in East Tarko-Sale) and BP_2-3, BP_3-4, BP₆ and BP₇ (in West Tarko-Sale) while CH₄, CO₂, H₂, Ar, C₅H₁₂ and C₆H₁₄ diffuse from almost all oil and gas accumulations.

The oil and gas pools in the Etypur oilfield release H₂, CH₄, C₂H₆, C₃H₈, C₅H₁₂, C₆H₁₄, CO₂ and Ar and receive iC₅H₁₂ and nC₅H₁₂ (in BP₅, BP₆, BP₇, BP₈, etc.), He and N₂ (except BP₅).

Almost all gas pools in the Ust’-Kharampur oilfield release H₂, CH₄, C₆H₁₄, CO₂ and small amount of C₅H₁₂ into the ambient waters, and receive C₂H₆, C₃H₈, iC₄H₁₀, nC₄H₁₀, He, Ar, and N₂, as well as iC₅H₁₂ and nC₅H₁₂ in beds BP₁₀⁰, BP₁₁, BP₁₄², and BP₁₅. Note that C₅H₁₂ in beds BP₁₂ and BP₁₄¹ is in equilibrium with the formation water.

The oil and gas pools in the oilfields of the Yamal Peninsula (Malygin, Kharat, Kruzenshtern, Upper Tiutei, etc.) release H₂, CH₄, and CO₂ and receive He, N₂, as well as a large amount of methane homologs and small amount of Ar. The gas fugacity (parameter that can reflect the gas diffusion rate in formation water) increases with depth. The gas composition evolves toward heavier compounds in most of the accumulations.

The gas-water exchange patterns in the Lower Cretaceous strata of the Deryabin (SD₄), Ozerny (SD₆), Pelyatka (SD₃), and Suzun (SD₁₃) oilfields in the Yenisei- Khatanga basin are similar with those in the Nadym-Taz interfluve and the Yamal Peninsula: the accumulations release CH₄ and CO₂ into the waters and receive He, N₂, and methane homologs from the waters.

The water-gas thermodynamic equilibrium in the Jurassic aquifer system of large accumulations in the Kharampur, Gubkin, and Komsomolsky oil-gas-condensate fields in the Nadym-Taz interfluve; the Malygin gas-condensate field in the northern Yamal Peninsula; the South Solenoye gas-condensate field in the Yenisei-Khatanga basin, etc was examined. The gas-water interaction in the Kharampur gas field can be taken as a typical example to illustrate.

The gas exchange pattern in the Upper Vasyugan Fm. (Yu₁) of the Kharampur condensate oilfield is different from the above oilfields. In Yu₁¹, H₂, CH₄, He and N₂ input into the gas pool from the waters while the gas pool releases other gases, especially heavy hydrocarbons, to the waters. Therefore, the hydrocarbons in this condensate oilfield are currently changing from oil to gas-oil fluid. Unlike this, the gas-water system of bed Yu₁² is in equilibrium, after CH₄, C₂H₆, C₃H₈, C₅H₁₂, and CO₂ output from the reservoir to the waters and H₂, C₄H₁₀, He, and N₂ input to the reservoir from the waters. The gas pool of Yu₁⁴ releases CH₄, light hydrocarbons, and CO₂ to the formation water while receive heavy hydrocarbons, noble gases, and N₂ from the formation water, so the gas components are turning heavier, while non-hydrocarbon gases change in concentration. Therefore, the generation, migration, and accumulation of oil apparently still continues, whereas the generation and accumulation of gas has ceased. The gas components in the formation water are also affected by diffusion and dissolution.

The gas-water equilibrium in reservoirs of other oilfields (Komsomolsky, Gubkin, South Solenoye) is similar with the Kharampur oilfield. Among them, the gas-water exchange in bed Yu_2-3 of the Malygin field with gas and condensate at the deepest section (3612-3620 m and 3636-3644 m intervals in Well 35), is characterized by release of nitrogen, besides n-C₅H₁₂, CH₄, and CO₂, into the waters and input of heavier compounds (C₂H₆, C₃H₈, C₄H₁₀, and iC₅H₁₂) into the hydrocarbon accumulation.

Thus, the exchange patterns between oil and gas accumulations and edge waters around them in the Arctic reservoirs of the northern West Siberian basin show that the water-gas systems are unstable (Figs. 5-6), almost all accumulations release CH₄, CO₂, and Ar while receive He and N₂, and methane homologs. The gas components of many accumulations are changing toward heavier ones.

Analysis of gas saturation coefficient and total saturation of formation water samples through gas-water equilibrium modeling from Arctic oil and gas reservoirs in northern West Siberia shows that when S_g larger than 1.8 L/L, all formation water samples reach the critical C_s (1.0), which creates a possibility for the formation of hydrocarbon accumulation, whereas the undersaturated water can dissolve natural gas in the existent accumulations. The C_s of formation water is related to the fluid type in the reservoir bed, and is higher in condensate oilfield (0.8-1.0) and lower in oil reservoir. The complex gas-water exchange patterns in this area show the natural gas in Jurassic-Cretaceous reservoirs is diverse in origin.