Geologic Setting
Until the end of the Early Cretaceous Neocomian Epoch, the area adjacent to where the North Sakhalin Basin would develop was an offshore, eastern passive continental margin of the Bureinsk massif located on the Asian continent (Parfenov and Natal’in, 1985). Aptian to Paleogene plate collision resulted in subduction of oceanic crust from an eastern direction; the creation and subsequent consolidation of the Sikhote-Alin volcanic arc and its forearc and backarc basins (west of Sakhalin Island); and the accretion of sedimentary wedges that would form the core of Sakhalin Island.

North Sakhalin Basin is a deep (to 8 km), Tertiary strike-slip downwarp associated with the major, north-south trending Hokkaido-Sakhalin-Kashevarov en echelon dextral shear system (Mochalov, 1983; Worrall and others, 1996). The basin is filled with Paleocene and post-Paleocene siliciclastic marine sediments and eastward-prograding deltaic deposits of the paleo-Amur River (fig. 1 and fig. 2).

Sakhalin Island and most of the North Sakhalin Basin unconformably overlie Cretaceous to Paleocene deformed and metamorphosed accretionary rocks of a complex continental suture (fig. 2 and fig. 3a), including flysch, blueschists, melange and ophiolites. In westerly and northerly directions, approximate age-equivalent paleo-Amur strata are underlain by partly conformable Cretaceous to Paleocene flysch and forearc strata and by volcanic and intrusive rocks that crop out locally on western Sakhalin Island and on the Russian mainland. East of the suture zone (east of Sakhalin Island and under the Okhotsk Sea), Eocene to Recent strata are underlain by acoustically distinct basement rocks of the Okhotsk crustal block that collided with the Bureinsk massif.

NE-SW trending normal faults (Eocene to Early Miocene transtension) and slightly younger, NW-SE trending en echelon thrusts and folds (Late Miocene and Pliocene transpression) complement the major N-S vertical dextral shear faults of North Sakhalin Basin (figs. 3b, 3c and 3d). Most known hydrocarbon accumulations along the East Sakhalin shear zone of the island’s eastern side are associated with these structural features, especially those of compressional origin .

Early Tertiary transtension provided necessary accommodation space for deltaic progradation from the paleo-Amur River and its distributaries. Depositional rates were as high as 500-800 meters per million years (Nikolayev and Kleshchev, 1984; Tull, 1997). Continued wrench movement likely contributed to the strike (N-S) dispersal of sediments. Late Pliocene tectonism and orogenic inversion resulted in significant geologically recent folding, in modification and rupturing of pre-existing structures, and in uplift of the western and some central regions while other areas were subsiding (Mochalov, 1983; Tull, 1997). Offshore regions were less tectonically deformed than those onshore. Pliocene tectonism resulted in local onshore erosion of as much as 3.5 km and largely created the physiographic configuration of the province today. The Pleistocene Epoch was characterized by extension and transtension, which served to breach traps that contained accumulated hydrocarbons.

The North Sakhalin Basin’s overall structural configuration is compatible with modeled stress fields and complex strain signatures resulting from the collision of India and Eurasia, in which sinistral and dextral wrench systems act as regional conjugate shear sets (Worrall and others, 1996). Major sinistral shear systems are just north of the North Sakhalin Basin Province, and some dextral systems experienced sinistral movement in their past. Tectonism can be related to intermittent magmatic movements in the crust and mantle (Sychev and others, 1986) and to crustal microplate drift in the northwestern Pacific Ocean. Present thermal phenomena, mud volcanoes, and seismic activity are evidence of active movement on many faults.

Exploration and Discovery History
Petroconsultants (1996) document a field-discovery history over the years 1923 to 1992 (table 1, fig. 4). Six onshore fields were discovered from 1923 to 1935 in the North Sakhalin trough (northeastern part of the island, fig. 1) – including the Okha, Katangli, and Ekhabi complexes, which are among the top twenty fields of the province in terms of recoverable reserves. A more regular annual pattern of onshore drilling, with resulting discoveries, began in 1947. Numbers of annual onshore-field discoveries peaked in the 1960s, and most onshore development has been conducted by Sakhalinmoreneftegaz, a Russian state-run enterprise.

Offshore fields were discovered beginning in the 1970s. The Pogranichnyy trough (east of the central part of the island, fig. 1) was first explored by deep drilling from 1971 to 1975, and southernmost Okruzhnoye field within that trough was discovered in 1972. Offshore exploration and development occurred jointly with Japan between 1976 and 1982 and included discovery of the Chaivo and Odoptu fields, 2^nd and 4^th largest in terms of province reserves. Largest reserve volumes were added by field discoveries from about 1976 to 1986. The six largest fields (five of which are offshore) were discovered since 1975, but the next three largest fields (all onshore) are among the earliest discoveries made prior to 1936. Potential significant Eastern Asian markets for Sakhalin oil and gas include Japan, Korea and China.

All existing offshore fields are in water depths of less than 100 m. Ice conditions in the Sea of Okhotsk have challenged both exploration and development efforts. Typical 2-m-thick ice floes can move at speeds of 1 m/sec, and ice routinely scours the sea bottom.

PETROLEUM AND SOURCE ROCK
Geographic and Stratigraphic Occurrence
The North Sakhalin Basin Province has 32 onshore gas fields, 29 onshore oil fields, five offshore gas fields, and two offshore oil fields (table 1). Another two gas fields and three oil fields straddle the coastline. Offshore fields are larger both in closure areas and in petroleum volumes (table 2) than fields onshore. Onshore seeps are common along the trends of the major north-south faults, and production occurs to depths exceeding 4,000 m. Producible hydrocarbons or hydrocarbon shows are in more than 30 stratigraphic zones (Silverman, 1990) of Tertiary sandstones and fractured siliceous shales, and in pre-Tertiary serpentinites that are unconformably juxtaposed with Tertiary source rocks.
 

Table 2. Comparison of field-size statistics for onshore and offshore fields in the North Sakhalin Basin (data derived from Petroconsultants, 1996). *approximations ("close to"). (MMBOE, million barrels of oil equivalent)  [Back]
Location	Total Recoverable		Median	Mean		Minimum	Maximum
	(MMBOE)		(MMBOE)	(MMBOE)		(MMBOE)	(MMBOE)
Offshore Gas (n=5)	2800*		181	562		10*	1700*
Offshore Oil (n=2)	1400*		713	713		630*	800*
Onshore Gas (n=32)	650*		8	20		<1*	100*
Onshore Oil (n=29)	1100*		2	37		<1*	200*
On/Off Gas (n=2)	40*		19	19		10*	30*
On/Off Oil (n=3)	70*		33	22		<1*	35*

Source rocks are Middle to Upper Miocene alluvial, deltaic and prodeltaic marine shales, coaly shales and coals, which range from oil- to gas-prone, and Upper Oligocene(?) to Lower Miocene deep marine, diatomaceous, oil-prone shales (fig. 5). The formations in which the source-rock shales occur are hundreds of meters thick. Effective source rocks are somewhat less abundant in the more western, sand-rich facies of each formation, and overall source rock character changes from mostly gas-prone in the western onshore regions to oil-prone in eastern offshore areas (Huizinga and others, 1997).

Geochemistry
North Sakhalin crude oils are generally low in sulfur and paraffin, but high in resins. API gravities reported by Petroconsultants (1996) for oils and condensates in all fields range from 18° -62° . Low gas-oil ratios (GOR) and biodegradation are common because of the abundant seeps, and many fields need steam, gas and water injection for optimal recovery. Most of the Miocene to Oligocene source rocks have type II to type III organic matter, with total organic carbon (TOC) content ranging from <1 to 5 wt % (Mavrinski and Koblov, 1993; Khvedchuk, 1993).

Some published literature attributes significant hydrocarbon reserves to the deep-marine siliceous-shale source rocks. For example, Kodina and others (1989) discuss the isotopic similarity of Lower and Middle Miocene oils (d¹³C = -25.2 to -25.8 ^o/_oo) to Lower Miocene bitumen extracts (d¹³C = -26.4 to –23.9 ^o/_oo), and state that they both exhibit characteristics compatible with deep-marine diatomaceous oozes and siliceous source rocks.

Others believe that petroleum in the northern part of the province is sourced by the older, Upper Oligocene to Lower Miocene proximal-to-distal deltaic shales (rather than anoxic, deep-marine siliceous source rocks), based on biomarker, isotopic and chemometric oil-source correlations (Peters and others, 1997 (abstract only)).

Variable proportions of humic and sapropelic organic matter in the source rocks – related both to age and to paleogeographic setting (marine to continental) – result in differences in petroleum geochemical character, including normal sterane (C₂₇, C₂₈, C₂₉) ratios, cyclohexane to cyclopentane (ch:cp) ratios, and pristane-phytane (pr:ph) ratios, according to Popovich and Kravchenko, 1995, and Tull, 1997. These researchers believe that the northern part of the province is dominantly sourced by Middle to Upper Miocene shales (largely sapropelic), with petroleum characterized by subequal normal sterane content, ch:cp of 0.26-1.28, and pr:ph of 1.1-2. In contrast, they assert that central and southern parts of the province are sourced primarily by uppermost Oligocene and Lower to Middle Miocene (mostly humic) siliceous shales, with the petroleum characterized by C₂₉ dominance, ch:cp > 1.5, and pr:ph of 1.13-2.61.

Oil from the fractured, siliceous reservoirs in Okruzhnoye field (Pogranichnyy trough coastline) is characterized as low density (0.8 grams/cubic centimeter), high resin (20%), low-sulfur (0.26%), and low-paraffin (1.8%) (Tyutrin and others, 1982). The associated gas is typically 70-91% methane.

Gas data from Kalendo and Tungor fields (onshore northeastern Sakhalin Island) show methane ranging from 78-97%, C₂₊ ranging from 2-7%, CO₂ ranging from <1-15%, He ranging from 10-26 ppm, and N₂ at <1% (Kamenskiy and others, 1975).

Total Petroleum System Size
The North Sakhalin Neogene TPS contains 6.1 BBOE (billion barrels of oil equivalent) known ultimately recoverable reserves, 13% of which was produced through 1995 (Petroconsultants, 1996). Thirty-six percent of the reserves are oil (35% produced), 61% are gas (<1% produced) and 3% are condensate (2.5% produced). The largest oil field is nearly 800 MMBO (million barrels of oil) (offshore) (table 2), with known sizes of all oil fields having a mean of 90 MMBO and a median of 9 MMBO. The largest gas field is approximately 10 TCF (trillion cubic feet) (nearly 1700 MMBOE; offshore) (table 2), with known sizes of all gas fields having a mean of 456 BCF (billion cubic feet) (76 MMBOE) and a median of 18 BCF (3 MMBOE). The smallest field that has been produced is onshore and contains only a few hundred thousand barrels of ultimately recoverable oil.

BURIAL, MATURATION, AND MIGRATION
Neogene and Pleistocene siliciclastic overburden on the source rocks (fig. 5) locally can exceed 6 km in thickness, and it generally changes from more marine to more terrigenous in character upward and westward. Present geothermal gradients across the North Sakhalin Basin Province range from approximately 24° to 50° C/km (1.3° -2.7° F/100 ft) (Mavrinski and Koblov, 1993; Khvedchuk, 1993), and heat flow is irregular along the major fault zones (Kononov and others, 1991). The oil and gas window falls within 2.5 to 4 km depths currently, and peak generation, maturation and migration was likely in Late Miocene to Pliocene time (although local generation could have begun as early as Middle Miocene) (Mochalov, 1983; Silverman, 1990).

Migration paths include short to moderate lateral distances and significant vertical distances along faults, particularly along the major regional shears. Pleistocene leakage along these faults, especially from onshore accumulations, has resulted in many of those traps being underfilled relative to their spill points. Easternmost offshore basinal areas in the province expelled hydrocarbons westward and contributed to creating local overpressures.

TRAP STYLE AND DEVELOPMENT
Trap types in the most explored North Sakhalin trough (northernmost part of the east portion of the island and its adjacent offshore, fig. 1) – are Neogene in age and are known to consist of anticlines, complexly faulted anticlines, and fault traps with significant stratigraphic, truncational, and hydrodynamic components and complications (figs. 3b, 3c, and 3d).

Large, low-amplitude structural closures began to form in Early Miocene time, and more intense syn-sedimentary folding had occurred by the end of Middle Miocene time (fig. 5). The overall basin axis shifted progressively eastward throughout the Tertiary Period (Mochalov, 1983, 1985). Late Pliocene high-amplitude folding and inversion and later Pleistocene extension resulted in local loss of trap integrity and the redistribution or leakage of generated hydrocarbons. Thus, many onshore traps are not filled to spill point, but anticlines reportedly are less faulted in eastern offshore regions.

The northeastern part of the province is characterized by local overpressures (20% above normal; Tull, 1997) and by hydrodynamic impact, particularly in eastern areas where coastal or marine sandstones have a lithologic transition into offshore shales. This combination of phenomena causes oil-water contacts dip significantly westward in several fields.

North Sakhalin fault displacements range from tens to thousands of meters vertically and horizontally. Structural closures are characterized by areas of 5-300 km² and amplitudes of 80-600 m (Mavrinski and Koblov, 1993; Nikolayev, 1983). Some of the best anticlinal traps are reported to be associated with intersections of faults (Saprygin and others, 1978).

The Baykalo-Pomor synclinal area (offshore and onshore) on the northwest side of Sakhalin Island (fig. 1) was in existence by Middle Miocene time, and it contains eight major anticlinal zones and numerous folds with maximum dimensions of 30 km in length, six km in width, and 600 m in amplitude (Mustafin, 1983). Further Neogene structural deformation was contemporaneous with sedimentation. The structural closures are complicated by strike-slip (both dextral and sinistral) faults, with lateral displacements to 30 km, and by normal faults. There are no published penetrations in the offshore portions of the Baykalo-Pomor syncline, and less is known about the existence or extent of folds offshore.

The Pogranichnyy trough (south-central part of the east portion of the island and its adjacent offshore,fig. 1) has little published information, except for the Okruzhnoye field area at the coastline where traps consist of multi-directional block faults and thrusts (Silverman, 1990). Extension of paleo-Amur deltaic facies into the Pogranichnyy trough is questionable.

RESERVOIR ROCK
Identification and Description
North Sakhalin reservoir rocks are mostly Neogene in age (fig. 2 and fig. 5). Middle Miocene to Pliocene reservoir sandstones are continental to marine in origin, with the most recognized names being Dagi, Okobykai, and Nutovo. Their source rocks are laterally equivalent shale facies and perhaps underlying organic-rich siliceous rocks. Self-sourced Upper Oligocene to Lower Miocene fractured, siliceous-shale reservoir rocks (comparable to Monterey Formation of California) include the names Pilengskaya and Borskaya. These Neogene reservoirs produce at depths ranging from approximately 25 to 4150 meters within the province (Petroconsultants, 1996).

All Tertiary formations generally are more shale-rich and more marine in origin to the east. Reservoir sandstones and pay zones are commonly stacked. For example, East Ekhaba field (northern coastal area, schematically shown on fig. 3d) contains 18 hanging wall and 20 footwall Miocene sandstone pay zones (Nikolayev, 2000). Producing sandstones range from laterally continuous (shallow-marine deposits) to highly discontinuous (channel deposits), with maximum individual thicknesses as great as tens of meters, but more typically several meters. East Ekhaba channel sandstones trend east-west and are 0.1 to 0.4 km wide. At Mongi field (central coastal area), offshore-bar reservoir sandstones have maximum dimensions of 3.6 km by 14 km (Gololobov and others, 1983).

Many sandstone reservoirs associated with this active Tertiary margin are mineralogically immature. Hanging-wall sandstones from multiple formations in the East Ekhaba field are fine to medium grained, with 30-45% quartz, 15-57% feldspar and 10-27% rock fragments (Nikolayev, 2000). Okobykai and Dagi sandstone reservoir rocks in the Gilyako-Abunan field (northern onshore area) contain frameworks of quartz, feldspar and chert, with cements of chlorite, kaolinite, carbonate, and quartz (Kuklich and others, 1984). Common montmorillonite clays convert to illite and mica with increased depth of burial.

Fractured siliceous shales that form the "silicite" reservoirs have been described for Okruzhnoye field (Yurochko, 1982; Danchenko and Chochiya, 1983), which also produces from younger Miocene sandstones and contains a 600-m oil column. Many silicites formed from globules of oversaturated gels during gas-hydrothermal stages of subaqueous volcanic activity. The Pilengskaya formation at Okruzhnoye field is 100-500 m of siliceous and clay-siliceous rocks. It contains montmorillonite and illite clay, tuffaceous pyroclastic or terrigenous quartz and feldspar, and authigenic silica as globules, with lesser amounts of pyrite, siderite, calcite and glauconite. Much of the silica was derived organically from diatoms and sponge spicules. Pilengskaya silicites include opoka or opoka-like rocks (cristobalite globules with <1 to 4 micron pores, 50% of formation), chalcedonite (chalcedony with pores <1 micron, 5-10% of formation), siliceous argillites (cristobalite and opal with pores < 1 micron, 35-40% of formation), and some diatomites. All silicites contain both tectonic and diagenetic joints.

Underexplored reservoir rocks in the North Sakhalin Basin Province are eastern (offshore) Miocene sandstones of deep-marine origin, fractured siliceous shales, and pre-Tertiary serpentinites.

Reservoir Properties
North Sakhalin Miocene sandstone reservoirs have an average of 22% porosity (range 7-35%) and an average of 247 md permeability (range 0.01-4200 md). These data are derived from Petroconsultants (1996).

Reservoir quality figures have been published for several fields producing from Miocene sandstone reservoirs. East Ekhaba field sandstones have 14-36% porosity in the hanging wall, and even "better" reservoir properties in the footwall (Nikolayev, 2000). Mongi field reservoir sandstones are characterized by 20-25% porosity and 3 darcies permeability (Gololobov and others, 1983). Gilyako-Abunan field has porosities up to 40% and permeabilities up to one darcy at less than 1500 meters paleodepth, but at 3500-4000 meters paleodepth, porosity is less than 10% and permeability less than one millidarcy (Kuklich and others, 1984).

The fractured siliceous shale (silicite) reservoir rocks can have "interglobular" porosity ranging from 3-27% , but matrix permeabilities commonly are < 0.01 md (Saprygin and others, 1978; Margulis, 1996).

SEAL ROCK
Numerous and excellent local and regional, vertical and lateral seals exist in Miocene and Pliocene deltaic and marine shales (fig. 5), typically at least tens to many hundreds of meters thick (Nikolayev, 1983; Kononov and others, 1991; Bogdanchikov and Stytsenko, 1995). Adequate shale seals are more rare in the western, more sand-rich facies of each formation. The province and TPS also are characterized by abundant and imperfect vertical and lateral fault seals where sandstones and shales are in juxtaposition. Reverse (compressional) faults commonly are better seals than normal (extensional) faults. Offshore areas probably contain more numerous and better shale seals and fewer fault seals than regions onshore.

ASSESSMENT UNITS (AU)
The North Sakhalin Neogene gas-dominated TPS contains one established AU, Onshore and Offshore Northeastern Shelf #13220101, approximately 84,000 sq km in area and 72% in offshore areas (fig. 6). More future gas resources are expected than oil resources because the northern and northwestern offshore areas likely are dominated with gas-prone source rocks and many eastern offshore oil-prone source rocks are deeply buried. Eastern offshore regions will be less intensely deformed than those onshore. The fractured siliceous-rocks reservoirs are expected to be mostly oil-producing in both onshore and offshore locales.

Future fields will be in Middle Miocene to Pliocene sandstone reservoir rocks and in self-sourced Upper Oligocene to Lower Miocene fractured siliceous deposits comparable to the Monterey Formation of California. Some future reserves might be from pre-Cenozoic basement rocks that are unconformably overlain locally by Tertiary source rocks. Hydrocarbons will be found in anticlines, fault traps and stratigraphic traps. The expected total drill depth is approximately 3500 m for future oil fields and 6000 m for future gas fields. Future gas fields are expected to outnumber future oil fields by a 2:1 ratio. Province water depths do not exceed 200 m. No reserve growth factor is used in the assessment.