China has two large sedimentary basins that contain thick, organic-rich shales with excellent potential for shale gas development. These two basins, the Sichuan and the Tarim, contain marine-deposited shales with potentially favorable reservoir quality, including prospective thickness, depth, TOC, thermal maturity, and brittle mineralogical composition. In addition, China has five sizeable but less prospective shale gas basins with non-marine shales.
With shale exploration drilling just now being initiated, public information on shale formations in China is quite limited. Reservoir quality remains uncertain, while in-country shale drilling and completion services are still nascent. The future of shale gas development in China is promising, but it seems likely
that five to ten years will be needed before production will be at material levels.
The two large marine shale basins of China - - the Sichuan and Tarim - - contain an estimated 25,000 Tcf of total unrisked gas in place with 5,100 Tcf as the risked gas in place, These estimates are comparable with estimates of prospective gas resources (inplace) published by PetroChina.
The Sichuan Basin in south-central China covers a large 81,500-mi2. Two promising shale horizons have been identified in the Sichuan Basin. These are thick, organic-rich, thermally mature Lower Cambrian and Lower Silurian marine shales. Preliminary data indicate that these shales are low in clay and thus potentially favorable for hydraulic stimulation. However, the Sichuan Basin’s considerable structural complexity, with extensive folding and faulting, appears to be a significant risk for shale gas development. This cratonic to foreland-style basin contains four tectonic zones: a Northwest Depression, a Central Uplift, and the East and South Fold Belts. The Central Uplift, characterized by simple structure and relatively few faults, appears the most attractive region for shale gas development. In contrast, the East and South Fold Belts are structurally more complex, with numerous tight folds and large faults, less conducive to shale gas development. The Cambrian- and Silurian-age shales are the main targets for shale gas exploration in the Sichuan Basin.
These two shale horizons have provided gas shows in exploration wells and appear to have low-clay mineralogical composition owing to their deepwater marine depositional environment. Conventional and tight gas reservoirs of Upper Paleozoic- and Triassic-age in the Sichuan Basin were sourced primarily
by these Cambrian and Silurian black shales.
As China’s earliest natural gas producing region, the Sichuan basin has a well developed
network of natural gas pipelines. Large cities (Chongqing, Chengdu) and industrial gas consumers (fertilizer, ceramics manufacturers) offer a ready market for the gas. Well drilling services are available, including horizontal
drilling and hydraulic fracturing. The Sichuan
Basin hosts numerous large operators (PetroChina, Shell, Chevron, ConocoPhillips, EOG) who are evaluating and testing the shale- and tight-gas resources in the basin. However,
ConocoPhillips is the only operator in the Sichuan Basin to have selected its block based on shale gas exploration quality. The other PSC’s in Sichuan were previously signed based on tight gas sand and carbonate gas potential and are being opportunistically re-evaluated for
shale gas. These exploration programs are at an early data-gathering stage, with no commercial shale gas production reported yet.
The Tarim basin in western China’s Xinjiang Uyghur Autonomous Region is one of the world’s largest frontier petroleum sedimentary basins, covering a total area of 234,200 mi2.
The primary shale gas targets within the Tarim Basin are the lower Paleozoic sediments, particularly the extensive shale source rocks of Cambrian and Ordovician age. The Tarim Basin is sub-divided by fault systems into a series of distinct structural zones including: (1) the Manjiaer Depression in the north; (2) the Tangguzibasi Depression in the south; (3)
the Awati Sag in the west; and (4) the Tadong Sag in the east.
Ordovician black shales are the most important petroleum source rocks in the Tarim Basin. Formations grade from black and dark grey mudstone, to silty mudstone, to argillaceous limestone. TOC ranges from 0.3% to 2.5%, averaging about 2.0% in the richer sequences. Organics consist of kerogen, vitrinite-like macerals, as well as bitumen. Shale depths range from 2,000 m to over 6,000 m (6,500
to 20,000 feet).
The Tarim Basin in remote western China holds the Kuche-Tabei, Bachu-Taxinan and Tadong natural gas complexes, where 15 gas fields have been discovered with estimated recoverable resources of about 21 Tcf. The Kela-2, Dina-2, Yaha and Hetianhe gas fields have been developed. With productive capacity of close to 2 Bcfd, the Tarim Basin is China’s largest gas-producing basin and a major source
for the West-East Gas Pipeline.
China's Other Shale Gas Basins
China has five other large sedimentary basins that contain shales deposited in mainly non-marine environments, most often in ancient lakes (lacustrine) or fluvial settings that were close to terrigenous sediment sources. These non-marine shale basins are likely to be clay-rich and thus less prospective. In addition, many shale targets in these basins are thermally immature and oil-prone. China’s five major non-marine basins include the Ordos, the Junggar, the North China (Huabei), the Turpan-Hami, and the Songliao.
Natural Gas Profile
China produced 2,929 Bcf of natural gas in 2009, up 8 percent from 2008, with consumption slightly higher at 3,075 Bcf. Approximately 45 percent of the consumed gas was utilized for industrial purposes. As of January 2010, China’s proven natural gas reserves stand at 107 Tcf.
The level of industry interest in China shale gas is increasingly rapidly. China’s Ministry of Land and Resources (MLR) established a National Gas Shale Research Center in August 2010. PetroChina, Sinochem and CNOOC are initiating exploration in China, as are several foreign oil companies. MLR recently (October 28, 2010) announced plans to offer six shale gas exploration blocks within the next month. Bidding will be limited to four Chinese companies (PetroChina, Sinopec, CNOOC, and Shanxi Yanchang Petroleum Group). Foreign companies would be allowed to cooperate with
bid winners. MLR envisions opening blocks to foreign bidding eventually, but no timetable has been announced.
As China’s earliest natural gas producing region, the 230,000-km2 Sichuan Basin has a
well-developed network of natural gas pipelines. Large cities (Chongqing, Chengdu) and industrial gas consumers (fertilizer, ceramics manufacturers) are present PetroChina, Shell, Chevron, ConocoPhillips, BP, as well as EOG Resources are investigating the shale gas potential in Sichuan and further southwest in Guizhou Province.
India, Pakistan and Turkey contain a number of basins with organic-rich shales. India has four major basins: Cambay, Krishna Godavari, Cauvery and the Damoda Valley sub-basins such as Raniganj, Jharia and Bokaro. India also has several other basins such as the Upper Assam, Vindhyan, Pranhita-Godavari and South Rewa, however, these shales were thermally too immature for gas or the data with which to
conduct a resource assessment were not available.
Pakistan has one priority shale gas basin - - Southern Indus Shale basins in India and Pakistan are geologically highly complex. Many of the basins, such as the Cambay and the Cauvery, have horst and graben structures and are extensively faulted. The prospective area for shale gas in these basins is restricted to a
series of isolated basin depressions (sub-basins). While the shales in these basins are thick, considerable uncertainty exists as to whether (and what interval) of the shale is sufficiently mature for gas generation. Recently, ONGC drilled and completed India’s first shale gas well, RNSG-1, northwest of
Calcutta in West Bengal. The well was drilled to a depth of 2,000 meters and reportedly had gas shows at the base of the Permian-age Barren Measure Shale. Two vertical wells
(Well D-A and D-B) were previously tested in the Cambay Basin and had modest oil and shale gas production in the shallower, 4,300-foot thick intervals of the Cambay “Black Shale”. Overall, ARI estimates a total of 496 Tcf of risked shale gas in-place for India/Pakistan,
290 Tcf in India and 206 Tcf in Pakistan. The technically recoverable shale gas resource is
estimated at 114 Tcf, with 63 Tcf in India and 51 Tcf in Pakistan.
Cambay Basin, India
The Cambay Basin is an elongated, intra cratonic rift basin (graben) of Late Cretaceous
to Tertiary-age located in the State of Gujarat in northwestern India. The basin covers an onshore area of about 20,000 mi2. The basin is
bounded on its eastern and western sides by
basin-margin faults. It extends south into the offshore Gulf of Cambay, limiting its onshore area, and north into Rajasthan. The depth to the top of the Cambay “Black Shale” ranges from about 6,000 feet in the north to greater than 13,000 feet in the lows of the southern fault blocks. The “Black Shale”interval ranges from 1,500 feet thick to more than 5,000 feet
thick. In the northern Mehsana-Ahmedabad Block, the Kadi Formation forms an intervening 1,000-foot thick non-marine clastic wedge within the “Black Shale” interval. In this block, the organic-rich shale thickness varies from 300 to 3,000 feet, with the net completable gas bearing shale thickness located in the lower portion of the Cambay “Black Shale” interval, averaging about 500 feet, Thermal gradients are high, estimated at 3oF per 100 feet, contributing to accelerated thermal maturity of the organics.
Although the shales in the Cambay Basin have been identified as a priority area by ONGC,
no plans for exploring these shales have yet been publically announced. However, two shallower conventional exploration wells (targeting the oil-bearing intervals in the
basin) penetrated and tested the Cambay “Black Shale”. Well D-A, a vertical well, had gas
shows while drilling the Cambay “Black Shale” in a 90-foot section at a depth of about 4,300
feet. After hydraulic stimulation, Well D-A produced 13 B/D of oil and 11 Mcfd of gas.
Well D-B, an older vertical well drilled in 1989 to a depth of 6,030 feet, had also encountered the Cambay Shale at about 4,300 feet. The well was subsequently hydrofractured and produced 13 B/D of oil and 21 Mcfd of gas.
Krishna Godavari Basin, India
The Krishna Godavari Basin extends over a 7,800 mi2 area onshore (plus additional area
in the offshore) in eastern India. The basin consists of a series of horsts and grabens, as shown on Krishna Godavari Basin’s Horsts and
Grabens. The basin contains a series of organically rich shales, including the deeper Permian-age Kommugudem Shale, which is gas prone (Type III organics) and appears to be
in the gas window in the basin grabens. The Upper Cretaceous Raghavapuram Shale and
the shallower Paleocene- and Eocene-age shales are in the oil window.
Resources (Kommugudem Shale)
The 4,340 mi2 prospective area of the Kommugudem Shale in the Krishna Godavari
Basin is limited to the four grabens (sub-basins) where the thermal maturity is sufficiently high for wet to dry gas generation. Based on an average resource concentration of 156 Bcf/mi2. Activity for the four graben areas, estimate a risked shale gas in-place of 136 Tcf, with a risked technically recoverable resource of 27 Tcf.
Cauvery Basin, India
The Cauvery Basin covers an onshore area of about 9,100 mi2 on the east coast of India, plus an additional area of about 9,000 mi2. Cauvery Basin Horsts and Grabens in the offshore. The basin comprises numerous horsts and rifted grabens. The basin contains a thick interval of organic rich source rocks in Lower Cretaceous Andimadam and Sattapadi shale formations which overly the Archaean basement.
Upper Assam Basin, India
The Upper Assam Basin is an important onshore petroleum province in northeast India. The basin has produced oil and some associated gas, mainly from the Upper
Eocene-Oligocene Barail Group of coals and shales. In general, the TOC in the lower source rocks ranges from 1% to 2% but reaches 10% in the Barail Group. These source rocks are in the early thermal maturity stage (beginning of
the oil window) in the shallower parts of the Upper Assam Basin and may have sufficient thermal maturity for peak oil and onset of gas generation in the deeper parts of the basin toward the south and southwest. The thermal
maturity values range from Ro of 0.5 to 0.7% for the Sylhet and Kopili formations and range from Ro of 0.45% to 0.7% for the Barail Group, placing these shales in the early oil window. While the shales may reach the wet gas window in the deepest portion of the basin, the measured vitrinite reflectance is still at only 0.7% (oil window) down to a depth of 14,800 feet.
Prahnita-Godavari Basin, India
The Pranhita-Godavari Basin, located in eastern India, contains thick, organically rich shales in Permian-age (Lower Gondwana) Jai Puram and Khanapur formations. While the kerogen is Type III (humic) and thus favorable for gas
generation, the 0.67% Ro indicated the shales
are thermally immature for shale gas production.
Vindhyan Basin, India
The Vindhyan Basin, located in north central India, contains a series of Proterozoic-age
shales. While certain of these shales, such as the Hinota and Pulkovar, appear to have sufficient organic richness, no public data exists
on their thermal maturity.
Rajasthan Basin, India
The Rajasthan Basin covers a large onshore area in northwest India. The basin is structurally complex and characterized by numerous small fault blocks. The Permian-age Karampur Formation is the primary source rock in this basin. While the source rock is Type III and classified as mature, only limited data are available on the reservoir properties of this shale.
Southern Indus Basin, Pakistan
The Southern Indus Basin is located in southern Pakistan adjacent to the border
with India. The basin is bounded by the Indian Shield in the east and highly folded and
thrust mountains on the west. On the north, the Jacobabad Arch separates the Southern Indus Basin from the Central Indus Basin. Within the basin, the shales in the deeper portions of the Karachi Trough appear to have
reached the wet to dry gas window. The
Southern Indus Basin has five commercial oil discoveries and one gas discovery in the
conventional Cretaceous-age Goru Fm sands and three gas discoveries and one gas condensate discovery in shallower formations. While oil and gas shows have been recorded in
the Sembar Shale on the Thar Platform, no productive oil or gas wells have been drilled into the Sembar Shale.
Though India possess significant reserves of natural gas, 38 Tcf in 2009, it still relys on imports to satisfy domestic consumption. In 2009, the country consumed 5.1 Bcfd of
natural gas, while producing 3.9 Bcfd. Were India to develop the technically recoverable
shale gas resources, it may add an additional 63 Tcf of natural gas to its domestic reserve base.
At present, Pakistan’s natural gas production and consumption are in equilibrium, each at
3.7 Bcfd in 2009. The country possesses 28 Tcf of natural gas reserves, and has added to its
reserve base each year for the past decade.
There are two shale gas basins in Turkey - - the Thrace Basin in western Turkey and the Southeast Anatolia Basin along the border with Iraq and Syria. These two basins are under active shale and conventional gas exploration by the Turkish national petroleum company, TPAO, and international exploration companies.
Turkey may also have shale gas potential in the interior Blacklake and Taurus basins, as well
as the onshore portion of the Black Sea Basin. However, because detailed reservoir data on
shale formations in these basins is not readily available, their shale gas resource potential has not been assessed. Turkey is highly dependent on imports to meet its natural gas consumption needs. In 2009, the country consumed 3.4 Bcfd of natural gas, of which only 0.07 Bcfd was produced domestically. The country’s current
natural gas reserves are very limited. With estimated technically recoverable shale gas resources of 15 Tcf, successful development could contribute to Turkey’s energy independence.
Source: eia U.S. Energy Information Administration, April 2011, World Shale Gas Resources: An Initial Assessment of 14 Regions Outside the United States http://www.eia.gov/analysis/studies/worldshalegas/