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Two highly efficient accumulation models of large gas fields in China

Two highly efficient accumulation models of large gas fields in China RIKLJKDEXQGDQFHJHODUJDV¿HOGVGRPLQDWHGE\VWUXFWXUDOJDV UHVHUYRLUVW\SHWZRRIORZDEXQGDQFH JHJDV¿HOGVGRPLQDWHGE\VWUDWLJUDSKLFDQGOLWKRORJLFJDV7KHIRUPDWLRQRIWKHVHWZRW\SHVODUUHVHUYRLUV RIJHODUJDV¿HOGVLVUHODWHGWRWKHKLJKO\HI¿FLHQWDFFXPXODWLRQRIQDWXUDOJDV7KHDFFXPXODWLRQRIKLJK difference between the gas source kitchen and reservoir, which is the strong driving force for natural gas PLJUDWLRQWRWUDSV:KHUHDVWKHDFFXPXODWLRQRIORZDEXQGDQFHJDV¿HOGVLVPRUHFRPSOLFDWHGLQYROYLQJ ERWKYROXPHÀRZJHFKDUGXULQJWKHEXULDOVWDJHDQGIXVLRQGLIÀRZJHFKDUGXULQJWKHXSOLIWVWDJHZKLFK results in large area accumulation and preservation of natural gas in low porosity and low permeability reservoirs. This conclusion should assist gas exploration in different geological settings. Natural gas, gas source kitchen, highly efficient accumulation, large gas field, reserve Key words: abundance, resource potential 3 2 over 2 billion m /km ) and its periphery. Favorable conditions 1 Background and accumulation characteristics for forming medium-large In the last decade, natural gas exploration and JDV¿HOGVLQFOXGHUHJLRQDOFDSURFNVKLJKTXDOLW\UHVHUYRLUV development in Chinese onshore basins has accelerated. large-scale paleo-uplifts, traps in the deposition center Annual increased proven reserves are above 500 billion cubic of new tectonic movement, accumulation in low energy meters (bcm) from 2003, and annual natural gas production potential areas, and late-stage accumulation, which answer has increased from 50 bcm in 2000 to nearly 100 bcm in the common issues with natural gas accumulation in Chinese 2011 (Dai, 2009; Dai et al, 2010). The rapid development of basin environments and effectively guide the exploration for the natural gas industry takes advantage of the discovery of a JHJDV¿HOGVODU EDWFKJHRIJDVODU¿HOGVZLWKSURYHQJDVUHVHUYHVRIKXQGUHGV LWKWKHLQFUHDVLQJ:QXPEHURIJHGLVFRYHUHGJDVODU¿HOGV of billions of cubic meters, which are mainly distributed in Chinese large gas fields can be distinctly divided into three three large-scale superimposed basins in middle-western types (Zhao and Liu, 2008) (Table 1): type one is the large gas China, i.e. the Tarim, Ordos and Sichuan Basins (Fig. 1 3 2 and Fig. 2). Paleozoic marine-facies cratonic basins were abundance is greater than 800 million m /km ; type two is overlapped by Mesozoic and Cenozoic continental facies the large gas fields with low abundance, where recoverable 3 2 foreland & intra-continental depression basins forming the reserve abundance is less than 250 million m /km ; and type Chinese superimposed basins, where primary gas sources are WKUHHLVWKHJHODUJDV¿HOGVZLWKUHVHUYHDEXQGDQFHEHWZHHQ oil-cracked gas of marine facies basins (Zhao et al, 2007) and type one and type two. From Table 1 we can see the former coal-formed gas from continental facies (including marine to JHJDV¿HOGVPDNHXSWKHPDMRULW\WZRW\SHVRIODU continental transitional facies). Chinese scholars, represented Large gas fields with high abundance are dominated by by Academician Dai Jinxing, have undertaken long-term large-scale structural gas reservoirs and structural-lithologic UHVHDUFKRQIRUPDWLRQRIJHODU&KLQHVHJDV¿HOGV'DL gas reservoirs, where the reservoir physical properties Zhang and Zhu, 2008). They proposed that the formation and are favorable, with porosity commonly greater than 10%, GLVWULEXWLRQRIJHPHGLXPODUVFDOHJDV¿HOGVZHUHFRQWUROOHG permeability greater than 1 mD, and well-sorted sandstone by a gas-generating center (with a gas-generating intensity reservoirs or carbonate reef flat reservoirs which are thick and continuous in distribution (Zhao et al, 2007), and the gas column height can reach hundreds of meters. These gas *Corresponding author. email: whj@petrochina.com.cn reservoirs usually have distinct gas-water contact and are Received December 11, 2012 ¿HOGVZLWKKLJKUHVHUYHDEXQGDQFHZKHUHUHFRYHUDEOHUHVHUYH DEXQGDQFHJDV¿HOGVLVGHSHQGHQWRQWKHUDSLGPDWXUDWLRQRIWKHVRXUFHNLWFKHQDQGKXJHUHVLGXDOSUHVVXUH Marine facies Continental facies Continental facies Junggar Basin Pet.Sci.(2014)11:28-38 29 mostly abnormally high-pressure gas reservoirs. The gas- Large gas fields with low abundance consist of clusters bearing area of individual gas reservoirs is limited (dozens of multiple small-scale lithologic gas reservoirs and are to hundreds of km ), whereas its controlled reserves scale distributed extensively in the Ordos and Sichuan Basins. The is quite large (hundreds of billions of m ) and the reserve gas-bearing area of the whole gas field is large (thousands DEXQGDQFHLVKLJKVXFKDVWKH.HODJDV¿HOGLQWKHDULP7 to tens of thousands of km ) and the reserves scale is large %DVLQDQGWKH3XJXDQJJDV¿HOGLQWKH6LFKXDQ%DVLQ )LJ  (hundreds of billions to trillions of m ) as well, whereas the 3 Songliao Basin 6 7 Tarim Basin Tuha Basin Bohai Bay Basin Ordos Basin Sichuan Basin Large gas fields name 1. Kela2 2. Dina2 3. Tazhong 4. Tainan 5. Sebei 6. Sulige 7. Wushenqi 8. Yulin Main gas-bearing basin 9. Zizhou 10. Jingbian 11. Xushen 12. Qimianqiao South China 13. Puguang 14. Guang’an 15. Anyue 16. Kelameili Gas field Sea Islands JHJDV¿HOGVLQ&KLQHVHRQVKRUHEDVLQV'LVWULEXWLRQRIODU Fig. 1 Fault basin Top: Intracontinental sag basin Bottom: Craton basin Top: Foreland basin Bottom: Craton basin Gas source kitchen of lacustrine mudstone Structural gas Fractured-cavernous Biongas pool Coal-bed gas pool gas pool Carbonate inner Tight sandstone Sand lens pool Shale gas pool gas ƗKela-2 Gas Field in the Tarim Basin; ƘPuguang Gas Field in the Sichuan Basin; ƙSulige Gas Field in the Ordos Basin; ƚGuang'an Gas Field in the Sichuan Basin; ƛTazhong Gas Field in the Tarim Basin Fig. 2JHJDV¿HOGVLQ&KLQHVHEDVLQV'LVWULEXWLRQPRGHRIODU $ the gas-bearing area is nearly 7,980 km , among which about thousands of lithologic gas reservoirs with small individual 50-80 thousand individual gas reservoirs with gas column scale and presents a gas reservoir group as a whole (Zhao et height of 2-6 m can be divided by clear sand body shape. The al, 2013). Taking the Sulige gas field in the Ordos Basin as physical properties of the reservoirs are poor as a whole (Fig. an example, the proven gas reserves are 1,101 billion m and 3). Both conventional sandstone reservoirs with porosity over ORZFRQVLVWVXVXDOO\RIDEXQGDQFHUHVHUYH¿HOGLVJDVODUJH 30 Pet.Sci.(2014)11:28-38 JHJDV¿HOGVLQ&KLQD6WDWLVWLFVRIJHRORJLFDOSDUDPHWHUFKDUDFWHULVWLFVIRUODU Table 1 Technical Reserve Reservoir characteristics *DV¿HOG Area, Gas in place, Reserve abundance, Natural Gas reservoir No. Basin Trap type recoverable abundance Age 2 3 2 3 2 Permeability Permeability,, name km billion m ×10 million m /km gas origin g forming phase Lithology ithology Porosity Porosity,, % % reserves, billion m type mD Structural- Oil cracked 1 Puguang Sichuan 126 412 291 23 High T Dolomite 6-8 0.1-3000 K-N lithologic gas 2 Kela 2 Tarim 48 Structural 284 213 44.3 High K, E Sandstone 9-14 4.0-350 N-Q 3 Dina 2 Tarim 125 Structural 175 114 9.1 High N Sandstone 8-15.2 0.5-216 N-Q 4 Sulige Ordos 7980 Lithologic 1101 566 0.7 Low P Sandstone 7-11 0.01-10 K-N 5 Daniudi Ordos 1546 Lithologic 393 188 1.2 Low C-P Sandstone 5-11 0.001-10 K-N 6 Yulin Ordos 1716 Lithologic 181 124 0.7 Low C-P Sandstone 5-11 0.01-10 K-N Coal-formed 7 Zizhou Ordos 1189 Lithologic 115 68 0.6 Low C-P Sandstone 4-9 0.01-10 K-N gas 8 Wushenqi Ordos 872 Lithologic 101 52 0.6 Low C-P Sandstone 3.5-14 0.01-10 K-N 9 Shenmu Ordos 828 Lithologic 101 52 0.6 Low C-P Sandstone 4-12 0.01-10 K-N Structural- 10 Guang an Sichuan 579 136 61 1.1 Low T Sandstone 6-13 0.001-10 K-N lithologic 11 Anyue Sichuan 361 Lithologic 117 53 1.5 Low T Sandstone 6-14 0.001-14 K-N Lithologic- 12 Hechuan Sichuan 1058 230 103 1 Low T Sandstone 7-10 0.001-50 K-N structural Structural- Oil cracked 13 Tazhong Tarim 742 353 216 2.9 Medium O Carbonate 3-6 3.5-12 E-Q lithologic gas 10% and permeability of 0.01-10 mD and unconventional tight sandstone reservoirs with porosity less than 10% and permeability less than 1 mD are included, and the reservoir heterogeneity is strong (Zhang et al, 2009). This type of large 100 Conventional reservoir gas field is mostly formed in gentle structural areas above large-scale cratonic basins. These two types of large gas fields are quite different in 1 both feature and structure, which implies they are different 0.1 in thermal evolution of gas source rocks and charging T x of Sichuan Basin Pz of Ordos Basin accumulation processes (Law, 2002; Zhao et al, 2005a; 0.01 2 K-N of Kuche Depression 2005b; 2005c). Thus, this paper mainly studies the controlling O m in Jingbian gas field of Ordos Basin Tight reservoir 2 0.001 T f of Northeast Sichuan Basin factors of the evolution process of gas source kitchen and the 1 O y of Tarim Basin charging accumulation process of natural gas on the formation 0.0001 04 8 12 16 20 24 28 32 Porosity, % accumulation process of natural gas under different geological Fig. 3JHJDV¿HOGV5HVHUYRLUSK\VLFDOSURSHUW\SDUDPHWHUVRI&KLQHVHODU conditions. Triassic–Quaternary system, among which the Middle +LJKO\HI¿FLHQWDFFXPXODWLRQRIODUJHJDV Upper Triassic–Middle Lower Jurassic series are the humid ¿HOGV climate limnetic facies coal series which are proven effective gas source rocks. The Cretaceous deposit is a proluvial- 2.1 Favorable gas accumulation conditions fluvial facies dominated sedimentary assemblage formed in This paper takes a foreland basin as an example to relatively blocked and dry environment and is a set of strata investigate the highly efficient accumulation of high dominated by reservoir rock development. The Paleogene abundance large gas fields. The Kela 2 gas field, a typical and Neogene deposits are a blocked salty lagoonal facies KLJKDEXQGDQFHJDV¿HOGLVVLWXDWHGRQWKHVHFRQGURZWKUXVW sedimentary assemblage formed in a dry climate (Zhao et al, fault anticlinal belt in the north wing of the Kuqa Depression, 2005b), where a quite thick gypsum member was developed, Tarim Basin (Zhao et al, 2005b; 2006) (Fig. 4). The area of and plastic flow occurred in the later-stage deformation, trap at the top of the Paleogene of the Kela 2 structure is 48.1 affecting shallow layer structural deformation greatly. The km , the closure height is 455 m, and it is an anticline with premium coal-seam source rocks right next to high porosity a long axis. The gas field has a proven gas reserve of 284 high permeability clastic reservoirs, plus gypsum rock with billion m , and gas layer thickness of up to 448 m, with gas excellent seal ability constitute a very promising source- ¿OOLQJWKHWUDSIXOO\ reservoir-cap combination, laying a solid material foundation Mesozoic and Cenozoic deposition in the Kuqa for gas accumulation. Depression includes the entire depositional sequence from Rapid late stage subsidence is a typical characteristic of Permeability, mD UHYHDOLQJRIODUKRSHWKHKLJKO\¿HOGVRIWKHJDVHI¿FLHQLQJHW Depth, m Pet.Sci.(2014)11:28-38 31 Mi1 0 10203040 km Tuzi1 Minnan1 Heiying1 Kezi1 Yinan2 kela3 Kecan1 Kela2 Dina2 kela1 Dongqiu3 Dongqiu5 Bahe1 Yaken3 Ti1 Baicheng Lunxi1 Luntai Kuqa Yaha11 Dawan1 Yaha16 Wucan1 B Yaha1 Xinhe Qiucan1 Quele1 Legend A1 Yangta5 The first grade tectonic line Yingmai7 Reservoirs Yutong2 Yingmai17 The second grade tectonic line Akesu Yingmai21 Depth, m Kela 2 B N 1000 N K-Q N K 2000 1-2 N K-Q N J N K-Q E T8-2 4000 K T-J T8-3 J+T 5000 J T3 N K K 1-2 E T5 K J+T N j Legend T7 1 T6 T8 K J+T KT5 Seismic J+T Bed Fault Strata reflection boundary boundary Front fault-fold zone Foreland syncline zone Foreland thrust-anticline steep slope and foreland slope 010 km Fig. 4 Structural unit division and hydrocarbon reservoir distribution in the Kuqa Depression (Zhao et al, 2005b; 2006) Deposition rate in the Kuqa Depression (Zhao et al, 2005b) Table 2 VWUDWD¿OOLQJLQWKH.XTD'HSUHVVLRQVLQFHWKH1HRJHQH =KDR et al, 2005b) (Fig. 5). By the end of the Paleogene, affected by Stratum Deposition Geologic age Duration, Ma the collision between the Indian plate and the Qinghai-Tibet thickness, m rate, m/Ma plate, the northern Tarim Basin underwent intracontinental Neogene 4500 19 (24-5) 240 subduction underneath the Tianshan orogenic belt. The Cenozoic Paleogene 750 41 (65-24) 18 Tianshan Mountain uplifted rapidly and the Kuqa Depression Early was formed at the mountain front, and continental-facies 1340 39 (135-96) 34 Cretaceous red sedimentary formation with a thickness of 6,000 m was Mesozoic Jurassic 2500 73 (208-135) 34 deposited since Cretaceous due to rapid deposition in a dry environment. In the center of the depression, the Meso- Triassic 3300 42 (250-208) 78 Cenozoic sedimentary thickness was over 11,000 m and that of the Neogene was up to 4,500 m, among which, the Rapid late-stage subsidence in the Kuqa Depression since sedimentary thickness of the Pliocene Kuqa Formation the late Cretaceous is another favorable condition for highly exceeded 2,000 m and the maximum deposition rate reached efficient gas accumulation, which may be reflected in two 1,300 m/Ma. The deposition rates in various stages of the aspects: one is that Jurassic coal series source rocks have Mesozoic were lower, commonly varying from 20 m/Ma to large total gas generating volume and have experienced a 40 m/Ma (Zhao et al, 2005b) (Table 2). rapid gas-generating process under the effect of rapid later- stage burial, which could have led to highly efficient gas Age, Ma accumulation; the other is that the huge residual pressure 250 200 150 100 50 0 difference generated between the gas source kitchen and the T J K E+N+Q reservoir during rapid gas generation served as the strong driving force for natural gas migration to traps (Muggeridge et al, 2005; Xu et al, 2010; Zhao et al, 2005d; Liu et al, 2008). R =0.5% 2.2 Reservoir forming process and major controlling R =0.7% 4000 factors RFHVV+LJKO\HI¿FLHQWJDVNLWFKHQJHQHUDWLRQSU R =1.0% The distribution area of coal series source rocks from Triassic to Jurassic in the Kuqa Depression ranges from 2 2 R =1.5% 12,000 km to 14,000 km , with the maximum total thickness 8000 of about 1,000 m. Organic macerals are dominated by vitrinite (mostly more than 60%), followed by inertinite Fig. 5 Burial history of the Kela 2 gas reservoir (Zhao et al, 2005b) (10%-25%) and a little liptinite (mostly less than 10%). Southern Mountain Tianshan 32 Pet.Sci.(2014)11:28-38 Liptinite is dominated by exinite, with small amounts of within its radial range. The increment ǻ R of Jurassic sapropelinite, kerogen is dominated by Type III, and it is a set hydrocarbon source rock R (%) increased over 5 Ma, can of gas generating-dominated source rocks. The average gas- UHÀHFWWKHJDV\LHOGHI¿FLHQF\LQWKHSULPDU\JDVJHQHUDWLRQ generating intensity of Triassic and Jurassic source rocks is stage ( R 0.8%-2.0%) after the source rocks entered 3 2 above 2 billion m /km in the main depression and the gas- hydrocarbon generation threshold, which can characterize generating intensity of such source rocks is above 4 billion WKHGLVWULEXWLRQRIKLJKO\HI¿FLHQWJDVVRXUFHNLWFKHQ =KDR 3 2 m /km in the hinterland of the depression (Zhao et al, 2005a; et al, 2005a; 2005b), and its interior and periphery areas are Liang et al, 2003; Qin et al, 2007), forming a high-quality gas favorable places for discovering large gas fields with high VRXUFHNLWFKHQ6RIDUDOOWKHJHODUJDV¿HOGVGLVFRYHUHGWKHUH abundance (Fig. 6). are distributed within the high gas-generating center of this 2.2.2 The controlling effect of pressure difference between high-quality gas source kitchen. source rocks and reservoirs Total gas-generating intensity shows that the gas- The highly efficient gas accumulation process is also generating volume of the Triassic and Jurassic rocks in controlled by accumulation dynamics, dominant migration the Kuqa Depression is huge, providing material support and conduit system, and good sealing of caprocks. There for forming medium-large scale gas fields. From the gas- were a number of dominant migration paths from the source generating process of source rocks, this set of hydrocarbon rocks to traps inside the thrust nappe in the formation stages source rocks still has another prominent characteristic: of the Kela 2 gas reservoir, and the thick gypsum mudstone affected by late-stage rapid burial, the stage of generating a plays a good sealing and protecting role in gas accumulation JHDPRXQWODURIJDVLVTXLWHVKRUWDQGJDVVXSSO\HI¿FLHQF\LV and late-stage preservation (Liu et al, 2008). From the origin, very high. whether a strong driving force for charging is available The geothermal gradient of the Kuqa Depression was 3.1 depends on the combined effect of various geologic stresses °C/100m in Mesozoic, and has decreased from 2.8 °C/100m upon fluid in the accumulation stage. A strong tectonic to present 2.5 °C/100m since Paleogene (Zhao et al, 2005b). movement, such as the structural deformation caused by In addition, the overall Cenozoic in the depression was not the Cenozoic extrusion nappe structure, might generate thick enough, therefore gas source rocks had remained at an additional force for directional and accelerated migration of immature stage before Neogene and R was less than 0.6%. subsurface fluids. Overpressure could be generated during Over 5,000 m of strata has been stacked rapidly by intense the quick hydrocarbon generation process of the Jurassic subsidence of depression since Neocene (23 Ma), particularly, source rocks since 5 Ma ago, which could induce the acting the strata thickness that has been accumulated since the force of fluid pressurization in source rocks to generate a Pliocene (5 Ma) exceeds 3,500 m, which leads to quick burial great residual pressure difference, i.e. the difference between of the source rocks below 6,000-7,000 m (Zhao et al, 2005b). residual hydrocarbon supply pressure of gas source kitchen As shown in the source rock maturity evolution curve of the DQGUHVLGXDOSRUHÀXLGSUHVVXUHRIWKHUHVHUYRLULQWKHFULWLFDO Lower Jurassic top simulated with artificial points for the moment of gas accumulation, that is the direct driving force central Baicheng Depression, the Jurassic gas source rocks IRUKLJKO\HI¿FLHQWJDVPLJUDWLRQ entered the oil generation threshold (R =0.6%) no later than Research reveals that, the abnormal formation pressure 15 Ma and entered the oil generation peak (R =1.0%) by 5 in the Kuqa Depression is jointly controlled by multiple Ma, and R reaches 2.1% at present. R value of the Jurassic factors such as uneven compaction, tectonic compression, o o source rocks increased from 1.0% to 2.1% and the primary fluid charging, and sealing strata performance (Liang et al, gas generation process completed during a short period of 5 2003; Chen et al, 2004; Zhao et al, 2006; Liu et al, 2008). Ma. The Jurassic source rocks are characterized by rapid gas Through the establishment of an overpressure equation with generation in a short period as well as a large overall gas- its origin implications, necessary parameters were acquired JHQHUDWLQJYROXPHWKHUHIRUHLWFDQEHFDOOHGKLJKO\HI¿FLHQW with the multivariate statistics method, the abnormal pressure gas source kitchen (Zhao et al, 2005a). It is certain that the evolution history of the Kuqa Depression was evaluated, gas source kitchen possessed high gas supply efficiency, and then the pressure evolution from the Jurassic source ZKLFKLVIDYRUDEOHIRUIRUPLQJKLJKO\HI¿FLHQWJDVUHVHUYRLUV rock maturation stage to now was detailed. The reservoir Yishen4 0 40 km Kela3 Kubei1 Dila1 1 1..0 0 Kela1 Dila2 Kela2 Dongqiu8 1 1..0 0 Dabei1 Luntai N Kuche Dawan1 Talake Yaha5 0 0..0 05 5 1 1..0 0 Wucan1 Gas field Failure trap Oil field Wushi Yudong2 Maturation rate 1.0 Pinchout line R /Ma Fig. 6*DVVRXUFHURFNPDWXUDWLRQUDWHǻR (%/Ma) isoline of the Kuqa Depression since 5 Ma (>0.05 means highly HI¿FLHQWJDVVRXUFHNLWFKHQ  =KDRHWDOE Residual pressure difference between source and reservoir, MPa Pressure difference in gas accumulation period 45MPa - 100 - 200 - 1600 - 1800 - 2000 - 400 -2600 Pet.Sci.(2014)11:28-38 33 pressure in the accumulation stage was determined through 0 100km WKHFRPELQDWLRQRIPXOWLSOHPHWKRGVVXFKDVÀXLGLQFOXVLRQ analysis and under-compaction modelling, which showed that WKHUHVHUYRLUÀXLGSUHVVXUHZDVEDVLFDOO\XQGHUQRUPDOOHYHOV Etuokeqi during the accumulation stage of the Kela 2 gas reservoir, and its source-reservoir residual pressure difference was up to 45 Sulige Yulin MPa (Fig. 7), which served as the strong driving force for gas charging from source kitchens to traps. Through comparison of the average residual pressure difference and buoyancy of Jinbian the Kuqa Depression in the accumulation stage of primary gas reservoirs, we can see that the average residual pressure difference gradients in the structures of various reservoirs Yan’an were greater than 0.03 MPa/m, whereas the buoyancy gradients were less than 0.008 MPa/m. It is clear that the residual pressure difference and residual pressure gradient Qingyang were higher than the buoyancy and buoyancy gradient, and the difference between the gradients could be an order of magnitude, which indicates that source-reservoir residual pressure difference is the primary driving force for highly The top elevation The gas reservoirs HI¿FLHQWJDVPLJUDWLRQDQGDFFXPXODWLRQ structure of P s in Ordos Basin Fig. 8 Slope structure and gas reservoirs of Upper Paleozoic in the Ordos Basin Pressure from source Pressure from reservoir 60 reservoir. The gas primarily comes from the coal series of the Pressure of reservoir today 75 MPa Carboniferous and Permian Taiyuan and Shanxi Formations (Shanley et al, 2004). These coal series gas source rocks are widely distributed over the whole area with a stable thickness. The Ordos Basin is one of the important Middle 0 Paleozoic cratonic basins in middle-western China. The 0 Pressure of reservoir in gas accumulation period 66 MPa Upper Paleozoic geomorphology and geology of the middle 25 20 15 10 5 slope part are characterized by: 1) large area, the slope is Geologic age, Ma about 260 km wide from east to west and about 500 km long from north to south, covering an area of about 130,000 km , Fig. 76RXUFHUHVHUYRLUUHVLGXDOSUHVVXUHIHUHQFHGLILQWKH.HODJDV¿HOG which occupies 46% of the whole basin area; 2) monotonous in the accumulation stage structural feature and gentle dip, with dips usually from 1° to 2° with a maximum of 3°, and lack of local structure (Zhao et al, 2005c). 3 Highly efficient accumulation of low Under this stable and gentle structural setting, the highly DEXQGDQFHODUJHJDV¿HOGV efficient gas accumulation process is controlled by three favorable conditions: one is that the large-area coal series 3.1 Favorable reservoir forming conditions source rock is in close contact with the reservoir, forming a “lower-source upper-reservoir” combination, so that 7KH8SSHU3DOHR]RLF6XOLJHJDV¿HOGLQWKH2UGRV%DVLQ QDWXUDOJDVDFFXPXODWLRQEHQH¿WVIURPVRXUFHQHDU³SODQDU´ is a typical low abundance large gas field. Situated in the hydrocarbon supply (Fig. 10); the second is that tight QRUWKZHVWHUQSDUWRIWKH2UGRV JHVWJDV¿HO%DVLQLWLVWKHODU G individual sand bodies although small in scale and limited in discovered in recent years. By the end of 2010, its proven area, yet large in number, overlapping in plane and stacked gas reserves have exceeded 1 trillion m and its proven gas- vertically, make up a large-scale reservoir, which is favorable bearing area is nearly 8,000 km . Distributed on the gentle for large-scale accumulation of natural gas; the third is that hinterland slope of the cratonic basin, where faults are not the basin has gone through early-stage deep burial and late- developed, the gas field produces gas from the 8th member stage large-scale uplift (Fig. 11), with two accumulation ways of Permian Shihezi Formation and the 1st member of Shanxi volume flow charging and diffusion flow charging worked, Formation, and the gas layers are relatively thin, averaging at UDLVLQJJDVDFFXPXODWLRQHI¿FLHQF\VLJQL¿FDQWO\ that consists of tens of thousands of sand bodies with small 3.2 Reservoir forming characteristics individual scale (Figs. 8 and 9). The porosity of reservoir mainly ranges from 2% to 10%, with the maximum value of JH/DUJDV¿HOGVRIORZDEXQGDQFHZHUHIRUPHGSULPDULO\ 18%; whereas the permeability varies from 0.01 to 0.5 mD, in the intracontinental depression on a large-scale cratonic representing a typical low porosity and low permeability background. Gentle topography and inherited water -2000 - 0 - 2200 - 200 - 1800 - 3000 - 2800 - 2400 - 2200 - 1600 - 1400 - 1200 - 1000 - 800 - 3 0 - 3200 - 3000 - 2800 - 2600 - 240 Residual pressure difference between source and reservoir, MPa P7KHZKROHJDV¿HOGLVDOLWKRORJLFJDVUHVHUYRLUJURXS Reservoir Source rock Erosion area 34 Pet.Sci.(2014)11:28-38 38-14 38-16-1 38-16-2 S6 38-16-3 38-16-4 38-16 38-16-5 38-16-6 38-16-7 S4 38-16-8 P h P h P s 0 10km Wushenqi Sulige Coal bed Gas bed Tight sand 3816 - Su16 Su4 01km Su6 3814 - Horizontal scale GR R1 Fig. 9 *DVUHVHUYRLUVWUXFWXUHRIWKH6XOLJHJDV¿HOG2UGRV%DVLQ systems gave rise to a large area of sand bodies, which after belonging to nano-scale pore throat texture. Conventional constructive and destructive diagenesis formed a “reservoir reservoirs with a permeability of above 1 mD account for body group” (Zhao et al, 2013). Most of the reservoirs are 25%, with an average porosity of more than 13%, and the low in porosity and permeability, with sweet points with PHDQSRUHWKURDWGLDPHWHURIXVXDOO\PRUHWKDQȝP relatively high porosity and permeability developed locally. belonging to large pore throat texture. Large-scale reservoir Low porosity and permeability sandstone occupies around bodies formed under the gentle structural setting present 75% and tight sandstone with the permeability of 1-0.1 mD strong variation in three-dimensional space in both physical occupies about 62%. Porosity varies from 5% to 13 % with properties and internal structure, which led to cluster an average value of 8.5%, and the mean pore throat diameter development and the distribution of stratigraphic-lithologic LVDERXWȝPUHSUHVHQWLQJPLFURSRUHWKURDWWH[WXUH traps. These traps include lithologic traps formed by original The extremely tight reservoirs with a permeability of less deposition, physical property traps formed by diagenesis, than 0.1 mD make up 32%, with an average porosity of 4% and stratigraphic traps formed by epigenesis between WRDQGDPHDQSRUHWKURDWGLDPHWHURIOHVVWKDQȝP fracture-cavity bodies and surrounding rocks (Zou et al, TO C 08 % 0 P h 8x P h 8x P h P s P s C t Fig. 10 The source-reservoir structural model in the Ordos Basin Sulige gas field Yulin gas field Shenmu gas field Mizhi gas field Caprock thickness, m Depth, m Pet.Sci.(2014)11:28-38 35 10000 10000 300 280 260 240 220 200 180 160 140 120 100 80 60 40 20 0 High abundance Low abundance A ge, M a Geologic age CP P T J J K K T +T 3 E+N+Q 1 2 3 1 2 1 2 1 2 1000 1000 100 100 R =0.35% R =0.5% 10 10 R =1.0% 4000 R =1.5% 1 1 Fig. 11%XULDOKLVWRU\RIWKH6XOLJHJDV¿HOG Gas-bearing area Caprock thickness 2009). These independently–semi-independently distributed traps commonly appear in clusters, and a “gas reservoir Fig. 12 Statistics on the gas-bearing area and direct caprock JHJDV¿HOGVLQ&KLQDWKLFNQHVVRIODU group” would be formed in case of accumulation. Although individual reservoirs are limited in scale, the gas reservoir Actual tight reservoir core charging experiment reveals group consisting of thousands of reservoirs could be huge that natural gas must possess a certain start-up pressure to in scale, with the distribution area reaching up to several or charge the reservoir and migrate within the reservoir (Li tens of thousands of square kilometers, only the gas-bearing and Li, 2010). During the geological process, abnormally abundance is lower (Zhao et al, 2013). high pressure developed in source rocks is the necessary Low abundance gas reservoirs are characterized by gas- condition for natural gas charging tight reservoirs. In the case bearing in tight reservoirs and gas enrichment in sweet points. that overpressure of source rocks exceeds the displacement Sweet points have relatively high gas saturation, while widely pressure of reservoir, natural gas is able to charge tight distributed tight sandstones commonly bear gas as well. reservoirs and migrate within reservoirs in volume flow Statistics on porosity, permeability and gas saturation of tight PRGHZKLFKPHDQVWKHYROXPHÀRZJLQJFKDUDQGPLJUDWLRQ sandstones and sweet points in 116 wells of the Sulige gas driven by residual pressure difference is the primary natural ¿HOGUHYHDOWKDWWKHJDVVDWXUDWLRQRI8SSHU3DOHR]RLFVZHHW JDVFKDUJLQJPRGHGXULQJWKHKLJKO\HI¿FLHQWDFFXPXODWLRQ points is higher than that of tight sandstones. Sweet points process of low abundance gas reservoirs in the strata burial in the member He-8 have a gas saturation of 60%-70% with stage. the average value of 59%, and tight sandstone has lower gas Through quantitative diagenetic history research, saturation of 40%-50%, with the average value of 46%. The the evolution of tight reservoir displacement pressure in reservoir of the member Shan-1 is similar to the member geological history was detailed. Based on mercury injection He-8 in gas saturation, only slightly higher on the whole. Its data of 190 Upper Paleozoic samples from the Ordos Basin, average gas saturation of sweet points is 63%, while that of the relationship between reservoir porosity and displacement tight sandstones is 46.04%. pressure has been established. Reservoir displacement Higher in the north than the south, the gentle Upper pressure has a good exponential relationship with porosity, Paleozoic structure in the Sulige gas field is a monocline and reservoir displacement pressure decreases exponentially with a dip of 1º-3º (Fu et al, 2008). Gas layers in the Sulige with an increase in porosity. Thus the displacement pressure gas field are generally 5-15 m thick, individual gas-bearing variation of natural gas charging reservoirs and migrating sand bodies are commonly 1,000-2,500 m long and 100- within reservoir in geologic stages can be estimated on the 250 m wide, and the maximum buoyancy generated by the basis of porosity evolution research. gas column height is 0.15 MPa. Tight sandstone with low The critical condition of volume flow charging can be permeability as the direct caprock, provided sealing for the deduced by natural gas charging experiments on actual tight 6XOLJHJDV¿HOG,WVGUDLQDJHSUHVVXUHLVJUHDWHUWKDQ03D reservoir cores. Twelve sandstone samples with permeability -3 2 in experimental tests, and therefore the drainage pressure of (0.0043-1.37)×10 ȝP were selected to conduct methane difference between gas layer and caprock is greater than 0.5 charging experiment under different pressure gradient MPa. Therefore, the buoyancy generated by gas column is not conditions. The experiment reveals that a certain start-up high enough to break through the caprock so that gas reservoir pressure gradient must be available for the occurrence of can be preserved. Hence, large area gas accumulation could volume flow in low porosity and low permeability core. be formed within the whole basin, even without relatively The start-up pressure gradient varies exponentially with -3 2 thick gypsum acting as caprock like that in the Kela 2 high- physical properties. When the permeability is 0.1×10 ȝP , JHJDV¿HOG )LJ DEXQGDQFHODU the minimum laboratory start-up pressure gradient is 0.1 MPa/cm, and the start-up pressure gradient under geological 3.3 Process and modes of reservoir accumulation conditions is 5 MPa/100m via similarity analysis. When the -3 2 ROXPHÀRZFKDUJLQJGXULQJWKHEXULDOVWDJH9 permeability reaches 1×10 ȝP , the minimum laboratory Low abundance gas reservoirs are mainly tight reservoirs start-up pressure gradient decreases to 0.02 MPa/cm, which with low porosity and low permeability (Zou et al, 2009; equals to a subsurface pressure gradient of 0.25 MPa/100m. Zhao et al, 2013). Affected by high expulsion pressure, The buoyancy gradient induced by gas-water density natural gas generated by source rocks cannot charge the difference is (0.023-4.9)×10 Pa/m, which is much smaller reservoir or migrate freely in the reservoir under buoyancy. than the start-up pressure gradient for volume flow in low Gas-bearing area, km Kela2 Puguang Tainan Ya13-1 Sebei1 Tieshanpo Sebei2 Dina2 Dukouhe Dabei1 Xinchang Wolonghe Xushen1 Hetianhe Tazhong1 Moxi Daniudi Guang’an Hechuan Sulige Zizhou Jingbian 36 Pet.Sci.(2014)11:28-38 3.0 porosity and low permeability reservoirs. Only when the Residual pressure difference between source and reservoir residual formation pressure gradient exceeds the start-up Displacement pressure difference of P s pressure gradient, can volume flow charging and flowing 2.0 under the strata conditions take place. Fluid inclusion pressure testing and compaction analysis 1.0 reveal the conditions for the occurrence of volume flow charging in geologic history in the Sulige gas field. There 0.0 were multiple pressurization mechanisms in different stages 200 180 160 140 120 100 80 60 40 20 0 of basin development, most of which occurred in the deep Age, Ma burial stage. Mudstones (in particular hydrocarbon source rocks) in depositional series are the primary layers for Instantaneous hydrocarbon generation intensity abnormal pressure development (Magara, 1978; Hunt, 1990), 1.6 and sandstones are the main pressure relief layers, where a 1.2 residual source-reservoir pressure difference pointing from 0.8 source to reservoir is usually formed, which is the primary driving force for natural gas charging from source rock 0.4 towards the reservoir. Fluid inclusion pressure testing has also confirmed the 200 180 160 140 120 100 80 60 40 20 0 existence of obvious overpressure in the deep burial stage Age, Ma of the Upper Paleozoic formations in the Ordos Basin. The Fig. 13 Generation and evolution of residual source-reservoir pressure PD[LPXPSDOHRSUHVVXUHFRHI¿FLHQWRIWKH6KDQ[L)RUPDWLRQ difference (upper) and hydrocarbon generation intensity of source rock reaches 1.4, with the main frequency from 1.2 to 1.3. The ORZHU LQWKH6XOLJHJDV¿HOG Shihezi Formation is dominated by normal pressure, with WKHPD[LPXPSDOHRSUHVVXUHFRHI¿FLHQWRIDQGWKHPDLQ understanding of the effect of diffusion charging to the large- frequency ranges from 1.0 to 1.1. During the maximum scale accumulation efficiency of medium-low abundance buried depth stage of strata (Fig. 13), the residual pressure gas reservoirs, in particular, was insufficient (Nelson and difference of at least 2-3 MPa occurred between the Shanxi Simmons, 1992; Zhang and Krooss, 2001; Schlomer and Formation source rock and sand body with the occurrence of Krooss, 2004). the source rock gas-generation peak. This residual pressure Highly efficient accumulation in the Sulige gas field difference must lead to migration of natural gas generated by primarily occurs where there is extensive contact between source rocks towards the reservoir driven by overpressure, i.e. source rock and reservoir. During the accumulation natural overpressure charging (Fig. 13). gas underwent primary migration and short-distance vertical Based on the mudstone compaction curve (Liu and Wang, secondary migration, and insignificant lateral secondary 2001), fluid inclusions were used to calculate the pressure migration (Wang et al, 1998; Li et al, 2008). This special calibration (Mi et al, 2004), and basin simulation techniques accumulation condition made diffusion play a different were utilized to outline the pressure evolution history of role in large-scale accumulation of medium-low abundance source rocks and reservoirs in the Sulige gas field. Source gas reservoirs from that in conventional gas reservoir rocks and reservoirs are characterized by “high residual accumulation. In the burial stage of strata, when overpressure, pressure and low residual pressure difference”, i.e., source in particular, developed in source rocks, the efficiency of rocks and reservoirs have higher residual pressure, which is volume flow charging is obviously greater than that of commonly greater than 15 MPa, whereas the residual source- diffusion charging, and thus the contribution of diffusion reservoir pressure difference is lower, which is commonly charging is not obvious so that it is often ignored. However, less than 3 MPa. The existence of residual source-reservoir YROXPHÀRZJLQJFKDUWHQGVWRVWRSGXULQJWKHVWUDWDXSOLIWLQJ pressure difference will lead to large scale volume flow stage due to the decrease or disappearance of residual source- charging of natural gas in the study area. Volume flow reservoir pressure difference, but the diffusion charging charging is the primary mode of natural gas charging in the condition still remains at this time, and diffusion becomes deep burial stage. the main pathway for natural gas charging. The occurrence 'LIIXVLRQÀRZFKDUJHLQXSOLIWVWDJH of large-scale accumulation in gas-bearing basins during the Diffusion, a material transfer mode, often refers to a XSOLIWLQJVWDJHLVDVLJQL¿FDQW FKDUDFWHULVWLFRIKLJKO\HI¿FLH QW process in which a certain material transfers from a high accumulation of low abundance gas reservoirs. Diffusion concentration area to a low concentration area spontaneously DFFXPXODWLRQGXULQJWKHXSOLIWLQJSURFHVVLVUHÀHFWHGLQWKH along a concentration gradient eventually achieving IROORZLQJWZRDVSHFWVRQHLVWKDWXSOLIWLQJRIÀRDGLQJOHDGV concentration balance. Diffusion would occur as long as a to desorption and expansion of natural gas inside source concentration gradient exists (Lu et al, 2008; Korrani et al, kitchen, increasing the amount of free gas and providing a 2012). driving force for effective gas displacement; the other is that Previously, diffusion was commonly considered as the uplifting process involved overall large-scale uplifting of one of the main factors causing damage to gas reservoirs. sedimentary basin so that the hydrocarbon expulsion of the We had little idea about the contribution of diffusion gas source kitchen could reach a large scale, therefore the to gas accumulation under specific conditions, and the accumulation range could be large. Hydrocarbon generation Pressure, MPa 8 3 2 intensity, 10 m /km Pet.Sci.(2014)11:28-38 37 When large-scale uplifting and erosion happened, the volume flow charging amount is not sufficient enough to RYHUO\LQJSUHVVXUHRIGHHSVWUDWDLVUHGXFHG LHRIÀRDGLQJ  meet the diffusion loss of natural gas. Therefore, natural and the temperature and pressure in strata drop (Hunt, gas diffusion charging has made up for the diffusion loss of 1995). The volume of gas absorbed in source rock pores natural gas effectively, and made a positive contribution to may have greater expansion during the uplifting compared highly efficient accumulation and preservation of large gas to the volume of rock framework (Jiang et al, 2004), which ¿HOGVRIORZDEXQGDQFH FDQEHFRPHWKHVLJQL¿FDQWGULYLQJIRUFHIRUJDVJLQJGLVFKDU 4 Conclusions from source rock, leading to vast discharging of absorbed gas, increase of gas concentration around the source rock, 1) Chinese large gas fields can be divided into two providing the driving force for diffusion migration to types: Type one, large gas fields with high abundance, are reservoirs. Based on the gas state equation calculation, at excellent in accumulation conditions, but limited in number the end of the Early Cretaceous the paleo-strata pressure of and difficult to find; Type two are large gas fields with low 3HUPLDQ6KLKH]L)RUPDWLRQLQWKH6XOLJHJDV¿HOGZDVDERXW abundance. The formation of the latter is an inevitable result 48-53 MPa, 32-35 MPa after temperature dropping, and is of widely distributed continental facies basins in China. This 29-30 MPa at present. Without considering natural gas loss W\SHRI¿HOGKDVSRRUUHVHUYRLUSK\VLFDOSURSHUWLHVDQGGUDVWLF or supplement, pressure reduction in the Sulige area due to changes in gas-bearing properties, but is large in scale once temperature decrease can reach 30%-35%. gas accumulation occurs. As the main part of Chinese natural Based on geologic analysis of the Upper Paleozoic gas JDVUHVRXUFHVWKHVHJHODUJDV¿HOGVRIORZDEXQGDQFHFDQEH reservoirs in the Ordos Basin, a coupled diffusion-seepage effectively developed with the advancement of technologies. model has been established, which is used in numerical 'HVSLWHGLI¿FXOWLHVLQH[SORUDWLRQDQGGHYHORSPHQWWKLVNLQG simulation of volume flow charging and diffusion flow of low abundance gas field will be major targets in future charging of Upper Paleozoic low abundance gas reservoirs exploration and development. in the Ordos Basin and diffusion and dissipation processes. 2) In the formation of Kela2 large gas field with high Simulation results reveal that gas volume flow charging abundance, late-stage rapid subsidence is the key factor primarily occurred in the burial stage of basin, and the for highly efficient gas accumulation besides the common 6 3 maximum volume flow charging rate reached 13×10 m / favorable conditions such as source, reservoir, caprock, (km ·Ma) in the maximum hydrocarbon generating stage in migration, trap and preservation. On one hand, the source the Early Cretaceous. Natural gas diffusion flow charging rock generated a large amount of gas cumulatively and went mainly occurred in the uplifting stage of the basin, and the through a rapid gas-generating process in late-stage rapid 6 3 2 maximum charging rate was 18×10 m /(km ·Ma) (Fig. 14). burial, which led to a quite high accumulation efficiency; The overall basin simulation results reveal that the natural on the other hand, the great residual pressure difference JDVYROXPHÀRZJLQJFKDUDPRXQWZDVDERXWWULOOLRQP generated between gas source kitchen and reservoir during DQGWKHIXVLRQGLIÀRZJLQJFKDUDPRXQWZDVDERXWWULOOLRQ the rapid gas generation process became a strong driving m in the strata burial stage; whereas in the overall formation force for natural gas migration towards traps. XSOLIWLQJVWDJHWKHQDWXUDOJDVYROXPHÀRZJLQJFKDUDPRXQW 3) Large gas fields with low abundance represented was less than 10 trillion m and the diffusion flow charging by the Sulige gas field do not have good accumulation amount reached 70 trillion m , which indicates that the conditions such as reservoir, trap and caprock, however they primary mechanism for natural gas charging is diffusion VWLOOKDYHWKHIHDWXUHRIKLJKO\HI¿FLHQWDFFXPXODWLRQ7KHLU ÀRZJLQJFKDULQWKHVWUDWDXSOLIWLQJVWDJH'XULQJWKHZKROH accumulation is more complicated, involving volume flow geologic history, the natural gas volume flow charging JLQJLQFKDUWKHEXULDOVWDJHIXVLRQDQGJLQJÀRZGLILQFKDUWKH amount is 190 trillion m DQGWKHQDWXUDOJDVIXVLRQGLIÀRZ XSOLIWVWDJHDQGWKHVXI¿FLHQWJDVVXSSO\LQWKHVHWZRIRUPV charging amount is 130 trillion m , whereas the natural and continuous charging enable gas accumulation in low gas loss amount is 205 trillion m during this stage, and the porosity low permeability reservoir bodies on large scale. 1.4E+07 5HVHDUFKLQWRWKHKLJKO\HI¿FLHQWDFFXPXODWLRQSURFHVV Volume flow rate of filling of these two types of large gas fields is very useful for 1.2E+07 Diffusion flow rate of filling evaluation and potential analysis of natural gas resources, Dissipation rate 1.0E+07 especially the formation of large gas fields with low abundance. Some areas previously regarded unfavorable for 8.0E+06 gas accumulation, such as structural lows, structural uplift 6.0E+06 areas, poor reservoir and caprock areas turn out to possess conditions advantageous for forming large gas fields. The 4.0E+06 resources potential in these regions has been significantly 2.0E+06 enhanced, and these regions have become a potential new domain for natural gas exploration. 0.0E+06 180 160 140 120 100 80 60 40 20 0 Acknowledgements Age, Ma Gas charging and dissipation rate evolution This paper is sponsored by the National Key Basic Fig. 14 HOO6X6XOLJHJDV¿HOG:RI8SSHU3DOHR]RLFLQ Research Program of China (2007CB2095). 3 2 Rate, m /(km Ma) 38 Pet.Sci.(2014)11:28-38 Nel son J S and Simmons E C. The quantificaton of diffusive References K\GURFDUERQORVVHVWKURXJKFDSURFNVRIQDWXUDOJDVUHVHUYRLUVņ Che n S P, Tang L J, Jin Z J, et al. Thrust and fold tectonics and the role reevaluation: Discussion. 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Two highly efficient accumulation models of large gas fields in China

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Springer Journals
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Copyright © 2014 by China University of Petroleum (Beijing) and Springer-Verlag Berlin Heidelberg
Subject
Earth Sciences; Mineral Resources; Industrial Chemistry/Chemical Engineering; Industrial and Production Engineering; Energy Economics
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1672-5107
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1995-8226
DOI
10.1007/s12182-014-0315-8
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Abstract

RIKLJKDEXQGDQFHJHODUJDV¿HOGVGRPLQDWHGE\VWUXFWXUDOJDV UHVHUYRLUVW\SHWZRRIORZDEXQGDQFH JHJDV¿HOGVGRPLQDWHGE\VWUDWLJUDSKLFDQGOLWKRORJLFJDV7KHIRUPDWLRQRIWKHVHWZRW\SHVODUUHVHUYRLUV RIJHODUJDV¿HOGVLVUHODWHGWRWKHKLJKO\HI¿FLHQWDFFXPXODWLRQRIQDWXUDOJDV7KHDFFXPXODWLRQRIKLJK difference between the gas source kitchen and reservoir, which is the strong driving force for natural gas PLJUDWLRQWRWUDSV:KHUHDVWKHDFFXPXODWLRQRIORZDEXQGDQFHJDV¿HOGVLVPRUHFRPSOLFDWHGLQYROYLQJ ERWKYROXPHÀRZJHFKDUGXULQJWKHEXULDOVWDJHDQGIXVLRQGLIÀRZJHFKDUGXULQJWKHXSOLIWVWDJHZKLFK results in large area accumulation and preservation of natural gas in low porosity and low permeability reservoirs. This conclusion should assist gas exploration in different geological settings. Natural gas, gas source kitchen, highly efficient accumulation, large gas field, reserve Key words: abundance, resource potential 3 2 over 2 billion m /km ) and its periphery. Favorable conditions 1 Background and accumulation characteristics for forming medium-large In the last decade, natural gas exploration and JDV¿HOGVLQFOXGHUHJLRQDOFDSURFNVKLJKTXDOLW\UHVHUYRLUV development in Chinese onshore basins has accelerated. large-scale paleo-uplifts, traps in the deposition center Annual increased proven reserves are above 500 billion cubic of new tectonic movement, accumulation in low energy meters (bcm) from 2003, and annual natural gas production potential areas, and late-stage accumulation, which answer has increased from 50 bcm in 2000 to nearly 100 bcm in the common issues with natural gas accumulation in Chinese 2011 (Dai, 2009; Dai et al, 2010). The rapid development of basin environments and effectively guide the exploration for the natural gas industry takes advantage of the discovery of a JHJDV¿HOGVODU EDWFKJHRIJDVODU¿HOGVZLWKSURYHQJDVUHVHUYHVRIKXQGUHGV LWKWKHLQFUHDVLQJ:QXPEHURIJHGLVFRYHUHGJDVODU¿HOGV of billions of cubic meters, which are mainly distributed in Chinese large gas fields can be distinctly divided into three three large-scale superimposed basins in middle-western types (Zhao and Liu, 2008) (Table 1): type one is the large gas China, i.e. the Tarim, Ordos and Sichuan Basins (Fig. 1 3 2 and Fig. 2). Paleozoic marine-facies cratonic basins were abundance is greater than 800 million m /km ; type two is overlapped by Mesozoic and Cenozoic continental facies the large gas fields with low abundance, where recoverable 3 2 foreland & intra-continental depression basins forming the reserve abundance is less than 250 million m /km ; and type Chinese superimposed basins, where primary gas sources are WKUHHLVWKHJHODUJDV¿HOGVZLWKUHVHUYHDEXQGDQFHEHWZHHQ oil-cracked gas of marine facies basins (Zhao et al, 2007) and type one and type two. From Table 1 we can see the former coal-formed gas from continental facies (including marine to JHJDV¿HOGVPDNHXSWKHPDMRULW\WZRW\SHVRIODU continental transitional facies). Chinese scholars, represented Large gas fields with high abundance are dominated by by Academician Dai Jinxing, have undertaken long-term large-scale structural gas reservoirs and structural-lithologic UHVHDUFKRQIRUPDWLRQRIJHODU&KLQHVHJDV¿HOGV'DL gas reservoirs, where the reservoir physical properties Zhang and Zhu, 2008). They proposed that the formation and are favorable, with porosity commonly greater than 10%, GLVWULEXWLRQRIJHPHGLXPODUVFDOHJDV¿HOGVZHUHFRQWUROOHG permeability greater than 1 mD, and well-sorted sandstone by a gas-generating center (with a gas-generating intensity reservoirs or carbonate reef flat reservoirs which are thick and continuous in distribution (Zhao et al, 2007), and the gas column height can reach hundreds of meters. These gas *Corresponding author. email: whj@petrochina.com.cn reservoirs usually have distinct gas-water contact and are Received December 11, 2012 ¿HOGVZLWKKLJKUHVHUYHDEXQGDQFHZKHUHUHFRYHUDEOHUHVHUYH DEXQGDQFHJDV¿HOGVLVGHSHQGHQWRQWKHUDSLGPDWXUDWLRQRIWKHVRXUFHNLWFKHQDQGKXJHUHVLGXDOSUHVVXUH Marine facies Continental facies Continental facies Junggar Basin Pet.Sci.(2014)11:28-38 29 mostly abnormally high-pressure gas reservoirs. The gas- Large gas fields with low abundance consist of clusters bearing area of individual gas reservoirs is limited (dozens of multiple small-scale lithologic gas reservoirs and are to hundreds of km ), whereas its controlled reserves scale distributed extensively in the Ordos and Sichuan Basins. The is quite large (hundreds of billions of m ) and the reserve gas-bearing area of the whole gas field is large (thousands DEXQGDQFHLVKLJKVXFKDVWKH.HODJDV¿HOGLQWKHDULP7 to tens of thousands of km ) and the reserves scale is large %DVLQDQGWKH3XJXDQJJDV¿HOGLQWKH6LFKXDQ%DVLQ )LJ  (hundreds of billions to trillions of m ) as well, whereas the 3 Songliao Basin 6 7 Tarim Basin Tuha Basin Bohai Bay Basin Ordos Basin Sichuan Basin Large gas fields name 1. Kela2 2. Dina2 3. Tazhong 4. Tainan 5. Sebei 6. Sulige 7. Wushenqi 8. Yulin Main gas-bearing basin 9. Zizhou 10. Jingbian 11. Xushen 12. Qimianqiao South China 13. Puguang 14. Guang’an 15. Anyue 16. Kelameili Gas field Sea Islands JHJDV¿HOGVLQ&KLQHVHRQVKRUHEDVLQV'LVWULEXWLRQRIODU Fig. 1 Fault basin Top: Intracontinental sag basin Bottom: Craton basin Top: Foreland basin Bottom: Craton basin Gas source kitchen of lacustrine mudstone Structural gas Fractured-cavernous Biongas pool Coal-bed gas pool gas pool Carbonate inner Tight sandstone Sand lens pool Shale gas pool gas ƗKela-2 Gas Field in the Tarim Basin; ƘPuguang Gas Field in the Sichuan Basin; ƙSulige Gas Field in the Ordos Basin; ƚGuang'an Gas Field in the Sichuan Basin; ƛTazhong Gas Field in the Tarim Basin Fig. 2JHJDV¿HOGVLQ&KLQHVHEDVLQV'LVWULEXWLRQPRGHRIODU $ the gas-bearing area is nearly 7,980 km , among which about thousands of lithologic gas reservoirs with small individual 50-80 thousand individual gas reservoirs with gas column scale and presents a gas reservoir group as a whole (Zhao et height of 2-6 m can be divided by clear sand body shape. The al, 2013). Taking the Sulige gas field in the Ordos Basin as physical properties of the reservoirs are poor as a whole (Fig. an example, the proven gas reserves are 1,101 billion m and 3). Both conventional sandstone reservoirs with porosity over ORZFRQVLVWVXVXDOO\RIDEXQGDQFHUHVHUYH¿HOGLVJDVODUJH 30 Pet.Sci.(2014)11:28-38 JHJDV¿HOGVLQ&KLQD6WDWLVWLFVRIJHRORJLFDOSDUDPHWHUFKDUDFWHULVWLFVIRUODU Table 1 Technical Reserve Reservoir characteristics *DV¿HOG Area, Gas in place, Reserve abundance, Natural Gas reservoir No. Basin Trap type recoverable abundance Age 2 3 2 3 2 Permeability Permeability,, name km billion m ×10 million m /km gas origin g forming phase Lithology ithology Porosity Porosity,, % % reserves, billion m type mD Structural- Oil cracked 1 Puguang Sichuan 126 412 291 23 High T Dolomite 6-8 0.1-3000 K-N lithologic gas 2 Kela 2 Tarim 48 Structural 284 213 44.3 High K, E Sandstone 9-14 4.0-350 N-Q 3 Dina 2 Tarim 125 Structural 175 114 9.1 High N Sandstone 8-15.2 0.5-216 N-Q 4 Sulige Ordos 7980 Lithologic 1101 566 0.7 Low P Sandstone 7-11 0.01-10 K-N 5 Daniudi Ordos 1546 Lithologic 393 188 1.2 Low C-P Sandstone 5-11 0.001-10 K-N 6 Yulin Ordos 1716 Lithologic 181 124 0.7 Low C-P Sandstone 5-11 0.01-10 K-N Coal-formed 7 Zizhou Ordos 1189 Lithologic 115 68 0.6 Low C-P Sandstone 4-9 0.01-10 K-N gas 8 Wushenqi Ordos 872 Lithologic 101 52 0.6 Low C-P Sandstone 3.5-14 0.01-10 K-N 9 Shenmu Ordos 828 Lithologic 101 52 0.6 Low C-P Sandstone 4-12 0.01-10 K-N Structural- 10 Guang an Sichuan 579 136 61 1.1 Low T Sandstone 6-13 0.001-10 K-N lithologic 11 Anyue Sichuan 361 Lithologic 117 53 1.5 Low T Sandstone 6-14 0.001-14 K-N Lithologic- 12 Hechuan Sichuan 1058 230 103 1 Low T Sandstone 7-10 0.001-50 K-N structural Structural- Oil cracked 13 Tazhong Tarim 742 353 216 2.9 Medium O Carbonate 3-6 3.5-12 E-Q lithologic gas 10% and permeability of 0.01-10 mD and unconventional tight sandstone reservoirs with porosity less than 10% and permeability less than 1 mD are included, and the reservoir heterogeneity is strong (Zhang et al, 2009). This type of large 100 Conventional reservoir gas field is mostly formed in gentle structural areas above large-scale cratonic basins. These two types of large gas fields are quite different in 1 both feature and structure, which implies they are different 0.1 in thermal evolution of gas source rocks and charging T x of Sichuan Basin Pz of Ordos Basin accumulation processes (Law, 2002; Zhao et al, 2005a; 0.01 2 K-N of Kuche Depression 2005b; 2005c). Thus, this paper mainly studies the controlling O m in Jingbian gas field of Ordos Basin Tight reservoir 2 0.001 T f of Northeast Sichuan Basin factors of the evolution process of gas source kitchen and the 1 O y of Tarim Basin charging accumulation process of natural gas on the formation 0.0001 04 8 12 16 20 24 28 32 Porosity, % accumulation process of natural gas under different geological Fig. 3JHJDV¿HOGV5HVHUYRLUSK\VLFDOSURSHUW\SDUDPHWHUVRI&KLQHVHODU conditions. Triassic–Quaternary system, among which the Middle +LJKO\HI¿FLHQWDFFXPXODWLRQRIODUJHJDV Upper Triassic–Middle Lower Jurassic series are the humid ¿HOGV climate limnetic facies coal series which are proven effective gas source rocks. The Cretaceous deposit is a proluvial- 2.1 Favorable gas accumulation conditions fluvial facies dominated sedimentary assemblage formed in This paper takes a foreland basin as an example to relatively blocked and dry environment and is a set of strata investigate the highly efficient accumulation of high dominated by reservoir rock development. The Paleogene abundance large gas fields. The Kela 2 gas field, a typical and Neogene deposits are a blocked salty lagoonal facies KLJKDEXQGDQFHJDV¿HOGLVVLWXDWHGRQWKHVHFRQGURZWKUXVW sedimentary assemblage formed in a dry climate (Zhao et al, fault anticlinal belt in the north wing of the Kuqa Depression, 2005b), where a quite thick gypsum member was developed, Tarim Basin (Zhao et al, 2005b; 2006) (Fig. 4). The area of and plastic flow occurred in the later-stage deformation, trap at the top of the Paleogene of the Kela 2 structure is 48.1 affecting shallow layer structural deformation greatly. The km , the closure height is 455 m, and it is an anticline with premium coal-seam source rocks right next to high porosity a long axis. The gas field has a proven gas reserve of 284 high permeability clastic reservoirs, plus gypsum rock with billion m , and gas layer thickness of up to 448 m, with gas excellent seal ability constitute a very promising source- ¿OOLQJWKHWUDSIXOO\ reservoir-cap combination, laying a solid material foundation Mesozoic and Cenozoic deposition in the Kuqa for gas accumulation. Depression includes the entire depositional sequence from Rapid late stage subsidence is a typical characteristic of Permeability, mD UHYHDOLQJRIODUKRSHWKHKLJKO\¿HOGVRIWKHJDVHI¿FLHQLQJHW Depth, m Pet.Sci.(2014)11:28-38 31 Mi1 0 10203040 km Tuzi1 Minnan1 Heiying1 Kezi1 Yinan2 kela3 Kecan1 Kela2 Dina2 kela1 Dongqiu3 Dongqiu5 Bahe1 Yaken3 Ti1 Baicheng Lunxi1 Luntai Kuqa Yaha11 Dawan1 Yaha16 Wucan1 B Yaha1 Xinhe Qiucan1 Quele1 Legend A1 Yangta5 The first grade tectonic line Yingmai7 Reservoirs Yutong2 Yingmai17 The second grade tectonic line Akesu Yingmai21 Depth, m Kela 2 B N 1000 N K-Q N K 2000 1-2 N K-Q N J N K-Q E T8-2 4000 K T-J T8-3 J+T 5000 J T3 N K K 1-2 E T5 K J+T N j Legend T7 1 T6 T8 K J+T KT5 Seismic J+T Bed Fault Strata reflection boundary boundary Front fault-fold zone Foreland syncline zone Foreland thrust-anticline steep slope and foreland slope 010 km Fig. 4 Structural unit division and hydrocarbon reservoir distribution in the Kuqa Depression (Zhao et al, 2005b; 2006) Deposition rate in the Kuqa Depression (Zhao et al, 2005b) Table 2 VWUDWD¿OOLQJLQWKH.XTD'HSUHVVLRQVLQFHWKH1HRJHQH =KDR et al, 2005b) (Fig. 5). By the end of the Paleogene, affected by Stratum Deposition Geologic age Duration, Ma the collision between the Indian plate and the Qinghai-Tibet thickness, m rate, m/Ma plate, the northern Tarim Basin underwent intracontinental Neogene 4500 19 (24-5) 240 subduction underneath the Tianshan orogenic belt. The Cenozoic Paleogene 750 41 (65-24) 18 Tianshan Mountain uplifted rapidly and the Kuqa Depression Early was formed at the mountain front, and continental-facies 1340 39 (135-96) 34 Cretaceous red sedimentary formation with a thickness of 6,000 m was Mesozoic Jurassic 2500 73 (208-135) 34 deposited since Cretaceous due to rapid deposition in a dry environment. In the center of the depression, the Meso- Triassic 3300 42 (250-208) 78 Cenozoic sedimentary thickness was over 11,000 m and that of the Neogene was up to 4,500 m, among which, the Rapid late-stage subsidence in the Kuqa Depression since sedimentary thickness of the Pliocene Kuqa Formation the late Cretaceous is another favorable condition for highly exceeded 2,000 m and the maximum deposition rate reached efficient gas accumulation, which may be reflected in two 1,300 m/Ma. The deposition rates in various stages of the aspects: one is that Jurassic coal series source rocks have Mesozoic were lower, commonly varying from 20 m/Ma to large total gas generating volume and have experienced a 40 m/Ma (Zhao et al, 2005b) (Table 2). rapid gas-generating process under the effect of rapid later- stage burial, which could have led to highly efficient gas Age, Ma accumulation; the other is that the huge residual pressure 250 200 150 100 50 0 difference generated between the gas source kitchen and the T J K E+N+Q reservoir during rapid gas generation served as the strong driving force for natural gas migration to traps (Muggeridge et al, 2005; Xu et al, 2010; Zhao et al, 2005d; Liu et al, 2008). R =0.5% 2.2 Reservoir forming process and major controlling R =0.7% 4000 factors RFHVV+LJKO\HI¿FLHQWJDVNLWFKHQJHQHUDWLRQSU R =1.0% The distribution area of coal series source rocks from Triassic to Jurassic in the Kuqa Depression ranges from 2 2 R =1.5% 12,000 km to 14,000 km , with the maximum total thickness 8000 of about 1,000 m. Organic macerals are dominated by vitrinite (mostly more than 60%), followed by inertinite Fig. 5 Burial history of the Kela 2 gas reservoir (Zhao et al, 2005b) (10%-25%) and a little liptinite (mostly less than 10%). Southern Mountain Tianshan 32 Pet.Sci.(2014)11:28-38 Liptinite is dominated by exinite, with small amounts of within its radial range. The increment ǻ R of Jurassic sapropelinite, kerogen is dominated by Type III, and it is a set hydrocarbon source rock R (%) increased over 5 Ma, can of gas generating-dominated source rocks. The average gas- UHÀHFWWKHJDV\LHOGHI¿FLHQF\LQWKHSULPDU\JDVJHQHUDWLRQ generating intensity of Triassic and Jurassic source rocks is stage ( R 0.8%-2.0%) after the source rocks entered 3 2 above 2 billion m /km in the main depression and the gas- hydrocarbon generation threshold, which can characterize generating intensity of such source rocks is above 4 billion WKHGLVWULEXWLRQRIKLJKO\HI¿FLHQWJDVVRXUFHNLWFKHQ =KDR 3 2 m /km in the hinterland of the depression (Zhao et al, 2005a; et al, 2005a; 2005b), and its interior and periphery areas are Liang et al, 2003; Qin et al, 2007), forming a high-quality gas favorable places for discovering large gas fields with high VRXUFHNLWFKHQ6RIDUDOOWKHJHODUJDV¿HOGVGLVFRYHUHGWKHUH abundance (Fig. 6). are distributed within the high gas-generating center of this 2.2.2 The controlling effect of pressure difference between high-quality gas source kitchen. source rocks and reservoirs Total gas-generating intensity shows that the gas- The highly efficient gas accumulation process is also generating volume of the Triassic and Jurassic rocks in controlled by accumulation dynamics, dominant migration the Kuqa Depression is huge, providing material support and conduit system, and good sealing of caprocks. There for forming medium-large scale gas fields. From the gas- were a number of dominant migration paths from the source generating process of source rocks, this set of hydrocarbon rocks to traps inside the thrust nappe in the formation stages source rocks still has another prominent characteristic: of the Kela 2 gas reservoir, and the thick gypsum mudstone affected by late-stage rapid burial, the stage of generating a plays a good sealing and protecting role in gas accumulation JHDPRXQWODURIJDVLVTXLWHVKRUWDQGJDVVXSSO\HI¿FLHQF\LV and late-stage preservation (Liu et al, 2008). From the origin, very high. whether a strong driving force for charging is available The geothermal gradient of the Kuqa Depression was 3.1 depends on the combined effect of various geologic stresses °C/100m in Mesozoic, and has decreased from 2.8 °C/100m upon fluid in the accumulation stage. A strong tectonic to present 2.5 °C/100m since Paleogene (Zhao et al, 2005b). movement, such as the structural deformation caused by In addition, the overall Cenozoic in the depression was not the Cenozoic extrusion nappe structure, might generate thick enough, therefore gas source rocks had remained at an additional force for directional and accelerated migration of immature stage before Neogene and R was less than 0.6%. subsurface fluids. Overpressure could be generated during Over 5,000 m of strata has been stacked rapidly by intense the quick hydrocarbon generation process of the Jurassic subsidence of depression since Neocene (23 Ma), particularly, source rocks since 5 Ma ago, which could induce the acting the strata thickness that has been accumulated since the force of fluid pressurization in source rocks to generate a Pliocene (5 Ma) exceeds 3,500 m, which leads to quick burial great residual pressure difference, i.e. the difference between of the source rocks below 6,000-7,000 m (Zhao et al, 2005b). residual hydrocarbon supply pressure of gas source kitchen As shown in the source rock maturity evolution curve of the DQGUHVLGXDOSRUHÀXLGSUHVVXUHRIWKHUHVHUYRLULQWKHFULWLFDO Lower Jurassic top simulated with artificial points for the moment of gas accumulation, that is the direct driving force central Baicheng Depression, the Jurassic gas source rocks IRUKLJKO\HI¿FLHQWJDVPLJUDWLRQ entered the oil generation threshold (R =0.6%) no later than Research reveals that, the abnormal formation pressure 15 Ma and entered the oil generation peak (R =1.0%) by 5 in the Kuqa Depression is jointly controlled by multiple Ma, and R reaches 2.1% at present. R value of the Jurassic factors such as uneven compaction, tectonic compression, o o source rocks increased from 1.0% to 2.1% and the primary fluid charging, and sealing strata performance (Liang et al, gas generation process completed during a short period of 5 2003; Chen et al, 2004; Zhao et al, 2006; Liu et al, 2008). Ma. The Jurassic source rocks are characterized by rapid gas Through the establishment of an overpressure equation with generation in a short period as well as a large overall gas- its origin implications, necessary parameters were acquired JHQHUDWLQJYROXPHWKHUHIRUHLWFDQEHFDOOHGKLJKO\HI¿FLHQW with the multivariate statistics method, the abnormal pressure gas source kitchen (Zhao et al, 2005a). It is certain that the evolution history of the Kuqa Depression was evaluated, gas source kitchen possessed high gas supply efficiency, and then the pressure evolution from the Jurassic source ZKLFKLVIDYRUDEOHIRUIRUPLQJKLJKO\HI¿FLHQWJDVUHVHUYRLUV rock maturation stage to now was detailed. The reservoir Yishen4 0 40 km Kela3 Kubei1 Dila1 1 1..0 0 Kela1 Dila2 Kela2 Dongqiu8 1 1..0 0 Dabei1 Luntai N Kuche Dawan1 Talake Yaha5 0 0..0 05 5 1 1..0 0 Wucan1 Gas field Failure trap Oil field Wushi Yudong2 Maturation rate 1.0 Pinchout line R /Ma Fig. 6*DVVRXUFHURFNPDWXUDWLRQUDWHǻR (%/Ma) isoline of the Kuqa Depression since 5 Ma (>0.05 means highly HI¿FLHQWJDVVRXUFHNLWFKHQ  =KDRHWDOE Residual pressure difference between source and reservoir, MPa Pressure difference in gas accumulation period 45MPa - 100 - 200 - 1600 - 1800 - 2000 - 400 -2600 Pet.Sci.(2014)11:28-38 33 pressure in the accumulation stage was determined through 0 100km WKHFRPELQDWLRQRIPXOWLSOHPHWKRGVVXFKDVÀXLGLQFOXVLRQ analysis and under-compaction modelling, which showed that WKHUHVHUYRLUÀXLGSUHVVXUHZDVEDVLFDOO\XQGHUQRUPDOOHYHOV Etuokeqi during the accumulation stage of the Kela 2 gas reservoir, and its source-reservoir residual pressure difference was up to 45 Sulige Yulin MPa (Fig. 7), which served as the strong driving force for gas charging from source kitchens to traps. Through comparison of the average residual pressure difference and buoyancy of Jinbian the Kuqa Depression in the accumulation stage of primary gas reservoirs, we can see that the average residual pressure difference gradients in the structures of various reservoirs Yan’an were greater than 0.03 MPa/m, whereas the buoyancy gradients were less than 0.008 MPa/m. It is clear that the residual pressure difference and residual pressure gradient Qingyang were higher than the buoyancy and buoyancy gradient, and the difference between the gradients could be an order of magnitude, which indicates that source-reservoir residual pressure difference is the primary driving force for highly The top elevation The gas reservoirs HI¿FLHQWJDVPLJUDWLRQDQGDFFXPXODWLRQ structure of P s in Ordos Basin Fig. 8 Slope structure and gas reservoirs of Upper Paleozoic in the Ordos Basin Pressure from source Pressure from reservoir 60 reservoir. The gas primarily comes from the coal series of the Pressure of reservoir today 75 MPa Carboniferous and Permian Taiyuan and Shanxi Formations (Shanley et al, 2004). These coal series gas source rocks are widely distributed over the whole area with a stable thickness. The Ordos Basin is one of the important Middle 0 Paleozoic cratonic basins in middle-western China. The 0 Pressure of reservoir in gas accumulation period 66 MPa Upper Paleozoic geomorphology and geology of the middle 25 20 15 10 5 slope part are characterized by: 1) large area, the slope is Geologic age, Ma about 260 km wide from east to west and about 500 km long from north to south, covering an area of about 130,000 km , Fig. 76RXUFHUHVHUYRLUUHVLGXDOSUHVVXUHIHUHQFHGLILQWKH.HODJDV¿HOG which occupies 46% of the whole basin area; 2) monotonous in the accumulation stage structural feature and gentle dip, with dips usually from 1° to 2° with a maximum of 3°, and lack of local structure (Zhao et al, 2005c). 3 Highly efficient accumulation of low Under this stable and gentle structural setting, the highly DEXQGDQFHODUJHJDV¿HOGV efficient gas accumulation process is controlled by three favorable conditions: one is that the large-area coal series 3.1 Favorable reservoir forming conditions source rock is in close contact with the reservoir, forming a “lower-source upper-reservoir” combination, so that 7KH8SSHU3DOHR]RLF6XOLJHJDV¿HOGLQWKH2UGRV%DVLQ QDWXUDOJDVDFFXPXODWLRQEHQH¿WVIURPVRXUFHQHDU³SODQDU´ is a typical low abundance large gas field. Situated in the hydrocarbon supply (Fig. 10); the second is that tight QRUWKZHVWHUQSDUWRIWKH2UGRV JHVWJDV¿HO%DVLQLWLVWKHODU G individual sand bodies although small in scale and limited in discovered in recent years. By the end of 2010, its proven area, yet large in number, overlapping in plane and stacked gas reserves have exceeded 1 trillion m and its proven gas- vertically, make up a large-scale reservoir, which is favorable bearing area is nearly 8,000 km . Distributed on the gentle for large-scale accumulation of natural gas; the third is that hinterland slope of the cratonic basin, where faults are not the basin has gone through early-stage deep burial and late- developed, the gas field produces gas from the 8th member stage large-scale uplift (Fig. 11), with two accumulation ways of Permian Shihezi Formation and the 1st member of Shanxi volume flow charging and diffusion flow charging worked, Formation, and the gas layers are relatively thin, averaging at UDLVLQJJDVDFFXPXODWLRQHI¿FLHQF\VLJQL¿FDQWO\ that consists of tens of thousands of sand bodies with small 3.2 Reservoir forming characteristics individual scale (Figs. 8 and 9). The porosity of reservoir mainly ranges from 2% to 10%, with the maximum value of JH/DUJDV¿HOGVRIORZDEXQGDQFHZHUHIRUPHGSULPDULO\ 18%; whereas the permeability varies from 0.01 to 0.5 mD, in the intracontinental depression on a large-scale cratonic representing a typical low porosity and low permeability background. Gentle topography and inherited water -2000 - 0 - 2200 - 200 - 1800 - 3000 - 2800 - 2400 - 2200 - 1600 - 1400 - 1200 - 1000 - 800 - 3 0 - 3200 - 3000 - 2800 - 2600 - 240 Residual pressure difference between source and reservoir, MPa P7KHZKROHJDV¿HOGLVDOLWKRORJLFJDVUHVHUYRLUJURXS Reservoir Source rock Erosion area 34 Pet.Sci.(2014)11:28-38 38-14 38-16-1 38-16-2 S6 38-16-3 38-16-4 38-16 38-16-5 38-16-6 38-16-7 S4 38-16-8 P h P h P s 0 10km Wushenqi Sulige Coal bed Gas bed Tight sand 3816 - Su16 Su4 01km Su6 3814 - Horizontal scale GR R1 Fig. 9 *DVUHVHUYRLUVWUXFWXUHRIWKH6XOLJHJDV¿HOG2UGRV%DVLQ systems gave rise to a large area of sand bodies, which after belonging to nano-scale pore throat texture. Conventional constructive and destructive diagenesis formed a “reservoir reservoirs with a permeability of above 1 mD account for body group” (Zhao et al, 2013). Most of the reservoirs are 25%, with an average porosity of more than 13%, and the low in porosity and permeability, with sweet points with PHDQSRUHWKURDWGLDPHWHURIXVXDOO\PRUHWKDQȝP relatively high porosity and permeability developed locally. belonging to large pore throat texture. Large-scale reservoir Low porosity and permeability sandstone occupies around bodies formed under the gentle structural setting present 75% and tight sandstone with the permeability of 1-0.1 mD strong variation in three-dimensional space in both physical occupies about 62%. Porosity varies from 5% to 13 % with properties and internal structure, which led to cluster an average value of 8.5%, and the mean pore throat diameter development and the distribution of stratigraphic-lithologic LVDERXWȝPUHSUHVHQWLQJPLFURSRUHWKURDWWH[WXUH traps. These traps include lithologic traps formed by original The extremely tight reservoirs with a permeability of less deposition, physical property traps formed by diagenesis, than 0.1 mD make up 32%, with an average porosity of 4% and stratigraphic traps formed by epigenesis between WRDQGDPHDQSRUHWKURDWGLDPHWHURIOHVVWKDQȝP fracture-cavity bodies and surrounding rocks (Zou et al, TO C 08 % 0 P h 8x P h 8x P h P s P s C t Fig. 10 The source-reservoir structural model in the Ordos Basin Sulige gas field Yulin gas field Shenmu gas field Mizhi gas field Caprock thickness, m Depth, m Pet.Sci.(2014)11:28-38 35 10000 10000 300 280 260 240 220 200 180 160 140 120 100 80 60 40 20 0 High abundance Low abundance A ge, M a Geologic age CP P T J J K K T +T 3 E+N+Q 1 2 3 1 2 1 2 1 2 1000 1000 100 100 R =0.35% R =0.5% 10 10 R =1.0% 4000 R =1.5% 1 1 Fig. 11%XULDOKLVWRU\RIWKH6XOLJHJDV¿HOG Gas-bearing area Caprock thickness 2009). These independently–semi-independently distributed traps commonly appear in clusters, and a “gas reservoir Fig. 12 Statistics on the gas-bearing area and direct caprock JHJDV¿HOGVLQ&KLQDWKLFNQHVVRIODU group” would be formed in case of accumulation. Although individual reservoirs are limited in scale, the gas reservoir Actual tight reservoir core charging experiment reveals group consisting of thousands of reservoirs could be huge that natural gas must possess a certain start-up pressure to in scale, with the distribution area reaching up to several or charge the reservoir and migrate within the reservoir (Li tens of thousands of square kilometers, only the gas-bearing and Li, 2010). During the geological process, abnormally abundance is lower (Zhao et al, 2013). high pressure developed in source rocks is the necessary Low abundance gas reservoirs are characterized by gas- condition for natural gas charging tight reservoirs. In the case bearing in tight reservoirs and gas enrichment in sweet points. that overpressure of source rocks exceeds the displacement Sweet points have relatively high gas saturation, while widely pressure of reservoir, natural gas is able to charge tight distributed tight sandstones commonly bear gas as well. reservoirs and migrate within reservoirs in volume flow Statistics on porosity, permeability and gas saturation of tight PRGHZKLFKPHDQVWKHYROXPHÀRZJLQJFKDUDQGPLJUDWLRQ sandstones and sweet points in 116 wells of the Sulige gas driven by residual pressure difference is the primary natural ¿HOGUHYHDOWKDWWKHJDVVDWXUDWLRQRI8SSHU3DOHR]RLFVZHHW JDVFKDUJLQJPRGHGXULQJWKHKLJKO\HI¿FLHQWDFFXPXODWLRQ points is higher than that of tight sandstones. Sweet points process of low abundance gas reservoirs in the strata burial in the member He-8 have a gas saturation of 60%-70% with stage. the average value of 59%, and tight sandstone has lower gas Through quantitative diagenetic history research, saturation of 40%-50%, with the average value of 46%. The the evolution of tight reservoir displacement pressure in reservoir of the member Shan-1 is similar to the member geological history was detailed. Based on mercury injection He-8 in gas saturation, only slightly higher on the whole. Its data of 190 Upper Paleozoic samples from the Ordos Basin, average gas saturation of sweet points is 63%, while that of the relationship between reservoir porosity and displacement tight sandstones is 46.04%. pressure has been established. Reservoir displacement Higher in the north than the south, the gentle Upper pressure has a good exponential relationship with porosity, Paleozoic structure in the Sulige gas field is a monocline and reservoir displacement pressure decreases exponentially with a dip of 1º-3º (Fu et al, 2008). Gas layers in the Sulige with an increase in porosity. Thus the displacement pressure gas field are generally 5-15 m thick, individual gas-bearing variation of natural gas charging reservoirs and migrating sand bodies are commonly 1,000-2,500 m long and 100- within reservoir in geologic stages can be estimated on the 250 m wide, and the maximum buoyancy generated by the basis of porosity evolution research. gas column height is 0.15 MPa. Tight sandstone with low The critical condition of volume flow charging can be permeability as the direct caprock, provided sealing for the deduced by natural gas charging experiments on actual tight 6XOLJHJDV¿HOG,WVGUDLQDJHSUHVVXUHLVJUHDWHUWKDQ03D reservoir cores. Twelve sandstone samples with permeability -3 2 in experimental tests, and therefore the drainage pressure of (0.0043-1.37)×10 ȝP were selected to conduct methane difference between gas layer and caprock is greater than 0.5 charging experiment under different pressure gradient MPa. Therefore, the buoyancy generated by gas column is not conditions. The experiment reveals that a certain start-up high enough to break through the caprock so that gas reservoir pressure gradient must be available for the occurrence of can be preserved. Hence, large area gas accumulation could volume flow in low porosity and low permeability core. be formed within the whole basin, even without relatively The start-up pressure gradient varies exponentially with -3 2 thick gypsum acting as caprock like that in the Kela 2 high- physical properties. When the permeability is 0.1×10 ȝP , JHJDV¿HOG )LJ DEXQGDQFHODU the minimum laboratory start-up pressure gradient is 0.1 MPa/cm, and the start-up pressure gradient under geological 3.3 Process and modes of reservoir accumulation conditions is 5 MPa/100m via similarity analysis. When the -3 2 ROXPHÀRZFKDUJLQJGXULQJWKHEXULDOVWDJH9 permeability reaches 1×10 ȝP , the minimum laboratory Low abundance gas reservoirs are mainly tight reservoirs start-up pressure gradient decreases to 0.02 MPa/cm, which with low porosity and low permeability (Zou et al, 2009; equals to a subsurface pressure gradient of 0.25 MPa/100m. Zhao et al, 2013). Affected by high expulsion pressure, The buoyancy gradient induced by gas-water density natural gas generated by source rocks cannot charge the difference is (0.023-4.9)×10 Pa/m, which is much smaller reservoir or migrate freely in the reservoir under buoyancy. than the start-up pressure gradient for volume flow in low Gas-bearing area, km Kela2 Puguang Tainan Ya13-1 Sebei1 Tieshanpo Sebei2 Dina2 Dukouhe Dabei1 Xinchang Wolonghe Xushen1 Hetianhe Tazhong1 Moxi Daniudi Guang’an Hechuan Sulige Zizhou Jingbian 36 Pet.Sci.(2014)11:28-38 3.0 porosity and low permeability reservoirs. Only when the Residual pressure difference between source and reservoir residual formation pressure gradient exceeds the start-up Displacement pressure difference of P s pressure gradient, can volume flow charging and flowing 2.0 under the strata conditions take place. Fluid inclusion pressure testing and compaction analysis 1.0 reveal the conditions for the occurrence of volume flow charging in geologic history in the Sulige gas field. There 0.0 were multiple pressurization mechanisms in different stages 200 180 160 140 120 100 80 60 40 20 0 of basin development, most of which occurred in the deep Age, Ma burial stage. Mudstones (in particular hydrocarbon source rocks) in depositional series are the primary layers for Instantaneous hydrocarbon generation intensity abnormal pressure development (Magara, 1978; Hunt, 1990), 1.6 and sandstones are the main pressure relief layers, where a 1.2 residual source-reservoir pressure difference pointing from 0.8 source to reservoir is usually formed, which is the primary driving force for natural gas charging from source rock 0.4 towards the reservoir. Fluid inclusion pressure testing has also confirmed the 200 180 160 140 120 100 80 60 40 20 0 existence of obvious overpressure in the deep burial stage Age, Ma of the Upper Paleozoic formations in the Ordos Basin. The Fig. 13 Generation and evolution of residual source-reservoir pressure PD[LPXPSDOHRSUHVVXUHFRHI¿FLHQWRIWKH6KDQ[L)RUPDWLRQ difference (upper) and hydrocarbon generation intensity of source rock reaches 1.4, with the main frequency from 1.2 to 1.3. The ORZHU LQWKH6XOLJHJDV¿HOG Shihezi Formation is dominated by normal pressure, with WKHPD[LPXPSDOHRSUHVVXUHFRHI¿FLHQWRIDQGWKHPDLQ understanding of the effect of diffusion charging to the large- frequency ranges from 1.0 to 1.1. During the maximum scale accumulation efficiency of medium-low abundance buried depth stage of strata (Fig. 13), the residual pressure gas reservoirs, in particular, was insufficient (Nelson and difference of at least 2-3 MPa occurred between the Shanxi Simmons, 1992; Zhang and Krooss, 2001; Schlomer and Formation source rock and sand body with the occurrence of Krooss, 2004). the source rock gas-generation peak. This residual pressure Highly efficient accumulation in the Sulige gas field difference must lead to migration of natural gas generated by primarily occurs where there is extensive contact between source rocks towards the reservoir driven by overpressure, i.e. source rock and reservoir. During the accumulation natural overpressure charging (Fig. 13). gas underwent primary migration and short-distance vertical Based on the mudstone compaction curve (Liu and Wang, secondary migration, and insignificant lateral secondary 2001), fluid inclusions were used to calculate the pressure migration (Wang et al, 1998; Li et al, 2008). This special calibration (Mi et al, 2004), and basin simulation techniques accumulation condition made diffusion play a different were utilized to outline the pressure evolution history of role in large-scale accumulation of medium-low abundance source rocks and reservoirs in the Sulige gas field. Source gas reservoirs from that in conventional gas reservoir rocks and reservoirs are characterized by “high residual accumulation. In the burial stage of strata, when overpressure, pressure and low residual pressure difference”, i.e., source in particular, developed in source rocks, the efficiency of rocks and reservoirs have higher residual pressure, which is volume flow charging is obviously greater than that of commonly greater than 15 MPa, whereas the residual source- diffusion charging, and thus the contribution of diffusion reservoir pressure difference is lower, which is commonly charging is not obvious so that it is often ignored. However, less than 3 MPa. The existence of residual source-reservoir YROXPHÀRZJLQJFKDUWHQGVWRVWRSGXULQJWKHVWUDWDXSOLIWLQJ pressure difference will lead to large scale volume flow stage due to the decrease or disappearance of residual source- charging of natural gas in the study area. Volume flow reservoir pressure difference, but the diffusion charging charging is the primary mode of natural gas charging in the condition still remains at this time, and diffusion becomes deep burial stage. the main pathway for natural gas charging. The occurrence 'LIIXVLRQÀRZFKDUJHLQXSOLIWVWDJH of large-scale accumulation in gas-bearing basins during the Diffusion, a material transfer mode, often refers to a XSOLIWLQJVWDJHLVDVLJQL¿FDQW FKDUDFWHULVWLFRIKLJKO\HI¿FLH QW process in which a certain material transfers from a high accumulation of low abundance gas reservoirs. Diffusion concentration area to a low concentration area spontaneously DFFXPXODWLRQGXULQJWKHXSOLIWLQJSURFHVVLVUHÀHFWHGLQWKH along a concentration gradient eventually achieving IROORZLQJWZRDVSHFWVRQHLVWKDWXSOLIWLQJRIÀRDGLQJOHDGV concentration balance. Diffusion would occur as long as a to desorption and expansion of natural gas inside source concentration gradient exists (Lu et al, 2008; Korrani et al, kitchen, increasing the amount of free gas and providing a 2012). driving force for effective gas displacement; the other is that Previously, diffusion was commonly considered as the uplifting process involved overall large-scale uplifting of one of the main factors causing damage to gas reservoirs. sedimentary basin so that the hydrocarbon expulsion of the We had little idea about the contribution of diffusion gas source kitchen could reach a large scale, therefore the to gas accumulation under specific conditions, and the accumulation range could be large. Hydrocarbon generation Pressure, MPa 8 3 2 intensity, 10 m /km Pet.Sci.(2014)11:28-38 37 When large-scale uplifting and erosion happened, the volume flow charging amount is not sufficient enough to RYHUO\LQJSUHVVXUHRIGHHSVWUDWDLVUHGXFHG LHRIÀRDGLQJ  meet the diffusion loss of natural gas. Therefore, natural and the temperature and pressure in strata drop (Hunt, gas diffusion charging has made up for the diffusion loss of 1995). The volume of gas absorbed in source rock pores natural gas effectively, and made a positive contribution to may have greater expansion during the uplifting compared highly efficient accumulation and preservation of large gas to the volume of rock framework (Jiang et al, 2004), which ¿HOGVRIORZDEXQGDQFH FDQEHFRPHWKHVLJQL¿FDQWGULYLQJIRUFHIRUJDVJLQJGLVFKDU 4 Conclusions from source rock, leading to vast discharging of absorbed gas, increase of gas concentration around the source rock, 1) Chinese large gas fields can be divided into two providing the driving force for diffusion migration to types: Type one, large gas fields with high abundance, are reservoirs. Based on the gas state equation calculation, at excellent in accumulation conditions, but limited in number the end of the Early Cretaceous the paleo-strata pressure of and difficult to find; Type two are large gas fields with low 3HUPLDQ6KLKH]L)RUPDWLRQLQWKH6XOLJHJDV¿HOGZDVDERXW abundance. The formation of the latter is an inevitable result 48-53 MPa, 32-35 MPa after temperature dropping, and is of widely distributed continental facies basins in China. This 29-30 MPa at present. Without considering natural gas loss W\SHRI¿HOGKDVSRRUUHVHUYRLUSK\VLFDOSURSHUWLHVDQGGUDVWLF or supplement, pressure reduction in the Sulige area due to changes in gas-bearing properties, but is large in scale once temperature decrease can reach 30%-35%. gas accumulation occurs. As the main part of Chinese natural Based on geologic analysis of the Upper Paleozoic gas JDVUHVRXUFHVWKHVHJHODUJDV¿HOGVRIORZDEXQGDQFHFDQEH reservoirs in the Ordos Basin, a coupled diffusion-seepage effectively developed with the advancement of technologies. model has been established, which is used in numerical 'HVSLWHGLI¿FXOWLHVLQH[SORUDWLRQDQGGHYHORSPHQWWKLVNLQG simulation of volume flow charging and diffusion flow of low abundance gas field will be major targets in future charging of Upper Paleozoic low abundance gas reservoirs exploration and development. in the Ordos Basin and diffusion and dissipation processes. 2) In the formation of Kela2 large gas field with high Simulation results reveal that gas volume flow charging abundance, late-stage rapid subsidence is the key factor primarily occurred in the burial stage of basin, and the for highly efficient gas accumulation besides the common 6 3 maximum volume flow charging rate reached 13×10 m / favorable conditions such as source, reservoir, caprock, (km ·Ma) in the maximum hydrocarbon generating stage in migration, trap and preservation. On one hand, the source the Early Cretaceous. Natural gas diffusion flow charging rock generated a large amount of gas cumulatively and went mainly occurred in the uplifting stage of the basin, and the through a rapid gas-generating process in late-stage rapid 6 3 2 maximum charging rate was 18×10 m /(km ·Ma) (Fig. 14). burial, which led to a quite high accumulation efficiency; The overall basin simulation results reveal that the natural on the other hand, the great residual pressure difference JDVYROXPHÀRZJLQJFKDUDPRXQWZDVDERXWWULOOLRQP generated between gas source kitchen and reservoir during DQGWKHIXVLRQGLIÀRZJLQJFKDUDPRXQWZDVDERXWWULOOLRQ the rapid gas generation process became a strong driving m in the strata burial stage; whereas in the overall formation force for natural gas migration towards traps. XSOLIWLQJVWDJHWKHQDWXUDOJDVYROXPHÀRZJLQJFKDUDPRXQW 3) Large gas fields with low abundance represented was less than 10 trillion m and the diffusion flow charging by the Sulige gas field do not have good accumulation amount reached 70 trillion m , which indicates that the conditions such as reservoir, trap and caprock, however they primary mechanism for natural gas charging is diffusion VWLOOKDYHWKHIHDWXUHRIKLJKO\HI¿FLHQWDFFXPXODWLRQ7KHLU ÀRZJLQJFKDULQWKHVWUDWDXSOLIWLQJVWDJH'XULQJWKHZKROH accumulation is more complicated, involving volume flow geologic history, the natural gas volume flow charging JLQJLQFKDUWKHEXULDOVWDJHIXVLRQDQGJLQJÀRZGLILQFKDUWKH amount is 190 trillion m DQGWKHQDWXUDOJDVIXVLRQGLIÀRZ XSOLIWVWDJHDQGWKHVXI¿FLHQWJDVVXSSO\LQWKHVHWZRIRUPV charging amount is 130 trillion m , whereas the natural and continuous charging enable gas accumulation in low gas loss amount is 205 trillion m during this stage, and the porosity low permeability reservoir bodies on large scale. 1.4E+07 5HVHDUFKLQWRWKHKLJKO\HI¿FLHQWDFFXPXODWLRQSURFHVV Volume flow rate of filling of these two types of large gas fields is very useful for 1.2E+07 Diffusion flow rate of filling evaluation and potential analysis of natural gas resources, Dissipation rate 1.0E+07 especially the formation of large gas fields with low abundance. Some areas previously regarded unfavorable for 8.0E+06 gas accumulation, such as structural lows, structural uplift 6.0E+06 areas, poor reservoir and caprock areas turn out to possess conditions advantageous for forming large gas fields. The 4.0E+06 resources potential in these regions has been significantly 2.0E+06 enhanced, and these regions have become a potential new domain for natural gas exploration. 0.0E+06 180 160 140 120 100 80 60 40 20 0 Acknowledgements Age, Ma Gas charging and dissipation rate evolution This paper is sponsored by the National Key Basic Fig. 14 HOO6X6XOLJHJDV¿HOG:RI8SSHU3DOHR]RLFLQ Research Program of China (2007CB2095). 3 2 Rate, m /(km Ma) 38 Pet.Sci.(2014)11:28-38 Nel son J S and Simmons E C. The quantificaton of diffusive References K\GURFDUERQORVVHVWKURXJKFDSURFNVRIQDWXUDOJDVUHVHUYRLUVņ Che n S P, Tang L J, Jin Z J, et al. Thrust and fold tectonics and the role reevaluation: Discussion. 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Published: Jan 24, 2014

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