Reservoir accumulation conditions and key exploration & development technologies for Keshen gas field in Tarim Basin

Journal Pre-proof Reservoir accumulation conditions and key exploration & development technologies for Keshen gas field in Tarim Basin Haijun Yang, Yong Li, Yangang Tang, Ganglin Lei, Xiongwei Sun, Peng Zhou, Lu Zhou, Anming Xu, Jingjie Tang, Wenhui Zhu, Jiangwei Shang, Weili Chen, Mei Li PII:

S2096-2495(19)30063-8

DOI:

https://doi.org/10.1016/j.ptlrs.2019.09.004

Reference:

PTLRS 96

To appear in:

Petroleum Research

Received Date: 15 September 2019 Accepted Date: 23 September 2019

Please cite this article as: Yang, H., Li, Y., Tang, Y., Lei, G., Sun, X., Zhou, P., Zhou, L., Xu, A., Tang, J., Zhu, W., Shang, J., Chen, W., Li, M., Reservoir accumulation conditions and key exploration & development technologies for Keshen gas field in Tarim Basin, Petroleum Research, https:// doi.org/10.1016/j.ptlrs.2019.09.004. This is a PDF file of an article that has undergone enhancements after acceptance, such as the addition of a cover page and metadata, and formatting for readability, but it is not yet the definitive version of record. This version will undergo additional copyediting, typesetting and review before it is published in its final form, but we are providing this version to give early visibility of the article. Please note that, during the production process, errors may be discovered which could affect the content, and all legal disclaimers that apply to the journal pertain. © 2019 Chinese Petroleum Society. Publishing Services by Elsevier B.V. on behalf of KeAi.

Reservoir accumulation conditions and key exploration & development technologies for Keshen gas field in Tarim Basin Abstract: The Keshen gas field is located in the central part of Kuqa foreland thrust belt in Tarim Basin, and is another large gas field discovered in Kuqa depression after Kela 2 gas field. Since the breakthrough in 2008, a number of large and medium scale gas reservoirs including Keshen 2, Keshen 5 and Keshen 8 have been discovered, that are characterized by ultra depth, ultra-high pressure, ultra-low porosity, ultra-low permeability, high temperature and high pressure. With natural gas geological reserves of nearly trillion cubic meters and production capacity of nearly 5.5 billion cubic meters, the Keshen gas field is the main natural gas producing area in Tarim Oilfield. The Keshen gas field is located in a series of thrusting imbrication structures in the Kelasu structural belt of Kuqa foreland thrust belt. The salt roof structure, plastic rheology of salt beds and pre-salt faulted anticlinal structure constitute the large wedge-shaped thrust body. The thick delta sandstone of the Cretaceous Bashijike Formation is widely distributed, and it forms the superior reservoir-caprock combination with overlying Paleogene thick gypsum-salt bed. The deep Jurassic-Triassic oil and gas migrate vertically along fault system formed in Late Himalaya, break through the thick Cretaceous mudstone and move laterally along the fracture system of the pre-salt reservoirs, to form anticline and fault anticline high pressure reservoir groups. Through near ten years of studies, the three-dimensional seismic acquisition and processing technology for complex mountainous areas, extrusion salt-related structural modeling technology and fractured low-porosity sandstone reservoir evaluation technology have been established, which lay a foundation for realization of oil and gas exploration objectives. Logging acquisition and evaluation technology for high temperature, high pressure, ultra-deep and low-porosity sandstone gas reservoirs, and efficient development technology for fractured tight sandstone gas reservoirs have been developed, which provide a technical support for efficient exploration & development and rapid production of the Keshen gas field. Key words: oil and gas accumulation, three-dimensional mountainous seismic exploration, ultra-deep high temperature and high pressure gas reservoirs, high efficiency exploration and development, Keshen gas field, Tarim Basin.

1 Introduction The Kelasu structural belt in the Tarim Basin is an overlapping foreland thrust belt formed in Himalaya Movement, with an exploration area of more than 5000 km2, and its main exploration target layer is the Cretaceous Bashijike Formation. In 2008, the Well Keshen 2 achieved a major breakthrough, which led to discovery of the Keshen gas field. Up to this day, as continuous breakthroughs in exploration of the Keshen gas field have been obtained, gas reservoir evaluation and productivity construction are pushed forward steadily, and reserves of trillion cubic meters have been formed. At present, eleven oil and gas reservoirs have been discovered in the Keshen gas field, and the 3P geological reserves of natural gas have been confirmed to be nearly one trillion cubic meters. Ten gas reservoirs have been put into development and pilot production, a gas production capacity of 5.5 billion cubic meters has been constructed and lays an important strategic position for the Keshen gas field in Tarim Oilfield.

2 Exploration and development history Since remarkable discovery of the Kela 2 gas field in 1998, it has experienced through ten years of hardship and glory. 2.1 No significant exploration discovery period after discovery of Kela 2 gas field After discovery of Kela 2 gas field in 1998, in order to find large-scale oil and gas fields with high quality, high yield and shallow burial depth, four exploration battles were carried out on the main target strata of Cretaceous from 1998 to 2007. After discovery of the Dabei 1 gas reservoir, drilling results showed that distribution of gas reservoirs was dispersed. There was no gas exploration discovery besides the Kela 2 gas field. The simultaneous exploration of both oil and gas in the peripheral area of the Kela 2 gas field also fell in failure. The gas exploration below the Kela 2 gas field faced theoretical and technological challenges of ultra-deep strata. In eight years, only the Dabei 1 gas reservoir was found in the Cretaceous, which was far below the exploration expectation. A series of failures after the Kela 2 made explorers further realized that re-examination of exploration ideas, 1

geophysical prospecting technology, exploration direction, and main exploration areas and zones of large gas field were essential for discovery of large gas field in Kuqa depression. Two principles were determined, such as exploration in the pre-salt strata, innovation and continuous research of exploration technology. 2.2 Risk exploration breakthroughs of Keshen 2 gas filed and Keshen 5 gas filed The pre-salt strata had been re-emphasized. Although the gas exploration is difficult and faces many challenges, the Kelasu structural belt is still the key exploration area of the Kuqa foreland thrust belt, and geological condition of deep strata in Kelasu should be better than shallow strata. In 2006, based on operational guidelines for seismic exploration in Kuqa mountains, two main directions of improving signal-to-noise ratio and imaging quality was focused, and wide-line large combination acquisition were developed, thus, major risk target of Keshen 2 below salt beds were locked; meanwhile, the velocity field construction and mapping were further developed, and the risk exploration well of Keshen 2 was determined and drilled. In August, 2008, the interval of 6573-6697 m in Well Keshen 2 obtained daily gas of 0.46×106, realizing the breakthrough of deep oil and gas in Kelasu and leading the discovery of the Keshen large gas field. After the discovery of the Keshen 2 gas field, the risk exploration well of Keshen 5 was drilled and the Keshen 5 gas reservoir was discovered. The position of the main gas field in the Keshen block was determined, and the deep scale exploration was opened. 2.3 Overall breakthrough in the Keshen gas field After the discovery of Well Keshen 2, the explorationists gradually realized that the two-dimensional seismic exploration couldn’t meet need of fine exploration. Hence, large-area mountainous three-dimensional seismic exploration from simple tectonic zones in southern Keshen to complex overthrust superimposed zones in northern Keshen has beed carried out to realize overall breakthrough of the Keshen gas field together with seismic processing improvement. By the end of 2017, eleven large and medium-scale gas reservoirs, including Keshen 2 gas reservoir, Keshen 5 gas reservoir and Keshen 8 gas reservoir, had been discovered, and the 3P gas reserves is nearly one trillion cubic meters. So far, ten gas reservoirs have been put into development and trial production, and a gas production capacity of 5.5 billion cubic meters has been built, thus, this area is the main gas source in the Tarim Basin for the West-to-East Gas Transmission Project.

3 Regional geological backgrounds The Kuqa foreland basin located in the north of Tarim Basin, is separated from the South Tianshan fault-fold belt by thrusting faults in the north, and is near to the Tabei uplift in the south, the Yangxia sag in the east and the Wushi sag in the west; it is a superimposed foreland basin dominated by Mesozoic and Cenozoic strata (Fig. 1). The Keshen well block in the study area is administratively subordinate to Baicheng County, Aksu area; it is tectonically located in the Keshen section of the Kelasu structural belt in the Kuqa foreland thrust belt in Tarim Basin. Affected by the South Tianshan uplift, the Kelasu thrust belt underwent intense compression deformation; due to existence of huge thick gypsum-salt rock in the Kumugeliemu Group, the structural deformation is stratified. The suprasalt layer, with the gypsum rock strata as the detachment surface, forms relatively wide fault-related folds; while the salt layer develops salt diapir, salt dome, salt weld and other structures; the pre-salt layer has more intense deformation than the suprasalt layer, and forms a series of closely arranged thrusting imbricate structures, with fault angle gradually decreasing from north to south. Secondary faults and reservoir fractures are highly developed, and gas reservoirs are mostly low-porosity sandstone fractured structural gas reservoirs (Neng et al., 2013; Xie et al., 2015). The thickness of the target layer, Bashijiqike Formation of Cretaceous, is from 280 to 320m, and lithology of the reservoirs are mainly lithic feldspar sandstone with the porosity of 4%-9% and permeability of (0.05-1)×10-3µm2 in general. Fig. 1 Division of tectonic units in the Kelasu structural belt, Kuqa foreland basin showing that the Kuqa foreland basin is near to the Tabei uplift in the south, the Yangxia sag in the east and the Wushi sag in the west.

4 Petroleum geological characteristics 4.1 Tectonic characteristics In the Kuqa foreland thrust belt, different structural styles are formed above and below the salt bed, and generally are 2

characterized by "trinity" structural deformation, and include suprasalt structure and pre-salt thrust imbrication structural style (Fig. 2). The Kuqa foreland basin develops four sets of structural layers controlled by three sets of detachment layers: basement detachment, Triassic-Jurassic coal seam and Paleogene gypsum-salt rock from bottom to top. The strong compression of the South Tianshan Mountains results in differential shrinkage deformation of the suprasalt layer, salt layer and pre-salt layer; vertical combination pattern of huge thick salt body and wedge-shaped thrust body is formed. The three layers influenced each other and progressively are deformed toward the basin interior. The deformation is characterized by "whole compression, stratified shrinkage, vertical overlapping and linked progression (Yin et al., 2009; Li and Qi, 2013; Duan et al., 2017). The structural style of the suprasalt layer is mainly detachment thrust fault and related fold deformation, on the surface, it appear as a series of linear fold belts. From west to east, the suprasalt folds gradually decrease in amplitude, among which, the Kumugeliemu anticline and the Kasangtuokai anticline mainly distribute near well block of Well Keshen 1. The salt layer mainly distributes in the lower wall of the Kelasu fault in the form of salt weld and salt arch; the salt layer varies widely in thickness, for example, in Well Kela 4, it is more than 2200 m thick, while in Well Keshen 7, it is only 700 m thick. In the Keshen area, the pre-salt structure is characterized by low-angle basement involved in the deformation area, and the salt bed sharply thins toward the south, and forms the wedge-shaped thrust body; under the control of faults, a series of anticlines and fault anticlines are formed in Mesozoic from north to south. The structural model of the Keshen structural section reflects the stratified deformation characteristic of the salt-bearing foreland basin as a whole; under the action of double detachment layers, the suprasalt deformation system, salt deformation system and pre-salt deformation system are developed in the basin; from the orogenic belt to the pre-salt deformation system in the basin, the structural style gradually transits from the basement involvement style to the caprock detachment style, and deformation range of the pre-salt structural is obviously larger than that of the suprasalt structure. Fig. 2 Typical seismic profile of the Keshen section in the Kelasu tectonic belt showing that different structural styles are formed above and below the salt bed, including suprasalt structure and pre-salt thrust imbrication structural style.

4.2 Reservoir characteristics 4.2.1 Sedimentary characteristics In the Cretaceous, climate of the Kuqa foreland basin was hot and dry; the paleocurrent was mainly from north to south, and there were many provenance outlets in South Tianshan Mountains in the northern to carry a large amount of debris material. Due to gentle terrain, the water energy was reduced, thus, the debris material were deposited in large quantities into the lake quickly. Therefore, the sedimentary facies from north to south are alluvial fan, fan delta or braid river delta, shore-shallow lake sedimentary systems (Pan et al., 2013). For the alluvial fans and fan (or braided river) deltas, multiperiod fan bodies overlap each other vertically and connect with each other horizontally, and large-scale sand bodies in Cretaceous are formed. Among which, the fan delta front subfacies is developed in the third member of Bashijiqike Formation, and the braided river delta front subfacies is developed in the second member and first member of Bashijiqike Formation (Fig. 3). Fig. 3 Planar distribution of sedimentary facies in the second submember of Cretaceous Bashijiqike Formation in the Keshen area showing that the braided river delta front is developed.

4.2.2 Petrological characteristics of reservoirs Through observation and analysis of 750 rock slices of Bashijiqike Formation in the Keshen well block, the reservoir rock type is mainly brown fine-grained debris feldspar quartz sandstone with medium composition maturity. The content of quartz is high, and is generally from 40% to 60% with an average of 47%. The content of feldspar varies from 25% to 35% with an average of 31%. The lithic debris has a low content, and mainly consists of quartzite, siliceous rock, granite and other magmatic and metamorphic rock debris. The interstitial material is dominated by calcite, followed by siliceous material, gypsum and dolostone; the content of the calcite is generally from 1% to 14% with an average of 5%. The textural maturity is relatively high, the grain size is mainly fine-medium size; the sorting 3

and roundness of the sandstone is moderate, and the grain is generally subangular to subcircular in shape; the grains mainly contact with one another in point-line and line contact (Chu et al., 2014). 4.2.3 Reservoir physical property Statistical analysis of core and logging data shows the porosity of sandstone reservoirs in Bashijiqike Formation in the study area is from 4.0% to 7.0% in general, and the physical property decreases with the increase of depth (Fig. 4, Fig. 5). According to reservoir characteristics of the Keshen 5 gas reservoir, the reservoir vertically can be divided into tensional interval, transitional interval and compression-torsion interval (Frehner, 2011; Dean et al., 2013; Liu et al., 2014; Zhang et al., 2014; Zhou et al., 2016; Liu et al., 2017; Zhou et al., 2018). The tensional interval is dominated by porous reservoir which is located at the top of the Bashijiqike Formation, the thickness is from 40 to 170 m, and the sandstone percent is high and varies from 80% to 95%. Due to influence of super thick salt rock, the overburden stress and horizontal compression stress on the reservoir are relieved. The horizontal stress difference of the reservoir in this interval is from 20 to 35 MPa with an average of 27 MPa and the compression stress is relatively weak, which effectively protect the storage space, thus, the reservoir has good physical property; results of mercury injection test shows the displacement pressure of core samples is from 1 to 5 MPa with median pressure of 10-50 MPa, the maximum pore throat radius is from 0.10 to 1.00 µm with an average of 0.03-0.50 µm, the sorting coefficient varies from 0.02 to 0.08, and the structural coefficient ranges from 0.01 to 0.05; the porosity is from 6% to 9%, and the permeability rang from 0.1×10-3µm2 to 1×10-3µm2 in general. The transitional interval is dominated by fractured-porous reservoir, and the pore accounts for more than 70% of the reservoir space; the natural gas reserves in this interval account for about 30% of the natural gas geological reserves; the reservoir thickness is from 40 to 60 m, the reservoir characteristics are between the tensional interval and compressive-torsional interval; the porosity is from 3.6% to 7.5%, the permeability ranges from 0.05×10-3µm2 to 1.12×10-3µm2, and the horizontal stress difference is from 25 to 42 MPa with an average of 31 MPa. The compression-torsion interval is dominated by fractured reservoir, and the natural gas reserves in this interval only account for about 10% of the natural gas geological reserves; the reservoir in this interval is compact and heterogeneous, the porosity is from 2% to 4%; taking the Well Keshen 5 block as an example, results of mercury injection test shows the displacement pressure of core samples generally ranges from 5 to 20 MPa, the median pressure is from 50 to 75 MPa, and the maximum pore throat radius varies from 0.02 to 0.07µm; the capillary pressure curve is characterized by poor pore throat sorting and connectivity, and the permeability is from 0.04×10-3µm2 to 0.07×10-3µm2; this interval has complex stress situation, so different degrees and types of engineering complexities often occur in this interval; in this interval, the horizontal stress difference is from 34 to 45 MPa with an average of 38 MPa; reservoir testing of this interval generally show low production which fail to reach industrial gas flow. Fig. 4 Vertical characteristics of different intervals of stress neutralization surface of fault anticline in typical well in Keshen well area

Fig. 5

Histogram of reservoir physical properties under different stress environments in the Keshen area. (a) The porosity of the

tensional interval; (b) the permeability of the tensional interval; (c) the porosity of the transitional interval; (d) the permeability of the transitional interval; (e) the porosity of the compression-torsion interval; (f) the permeability of the compression-torsion interval.

4.2.4 Reservoir space characteristics Based on the study of 465 micro-cast thin sections, scanning electron microscopy, laser confocal imaging and electron probe (Fig. 6), the primary type of reservoir space in Cretaceous Bashijiqike Formation in the Keshen area is mainly mixed intergranular pore, including intergranular (feldspar, clay, carbonate) dissolution pore, residual primary intergranular pore and enlarged dissolution pore based on primary pore, intragranular dissolution pore mainly formed by supergene dissolution of feldspathic particles, and micro-pore in intergranular clay and some grains. Structural fractures are well developed, and account for about 3% of total pores; it are mainly high-angle and reticulate fractures, some of which are partially filled by anhydrite, calcite and a small amount of dolostone.

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Fig. 6 Microscopic characteristics of reservoirs in Cretaceous Bashijiqike Formation in the Keshen area. (a) Intergranular dissolution pore in medium sandstone at the depth of 7237.8 m in Well Keshen 802 (casting thin section); (b) Intergranular dissolution pore, intragranular dissolution pore, residual primary intergranular porein fine-medium grained lithic feldspar sandstone at the depth of 6784.83 m in Well Keshen 8-2 (casting thin section); (d) intergranular dissolution enlarged pore at the depth of 6775.05 m in Well Keshen 8003 (laser confocal imaging); (e) intragranular dissolution pore at the depth of 7326.5 m in Well Keshen 802 (laser confocal imaging); (e) K-feldspar dissolution pore at the depth of 6736.45-6736.52 m in Well Keshen 8 (SEM); (f) K-feldspar dissolution and secondary enlargement of feldspar at the depth of 6731.32 m in Well Keshen 8 (SEM); (g) structural fracture semi-filled by dolostone at the depth of 6778.9 m in Well Keshen 8003 (casting thin section); (h) unfilled structural fractures at the depth of 6736.45 m in Well Keshen 8 (laser confocal imaging); (i) structural fractures filled by anhydrite and dolostone at the depth of 6779.40 m in Well Keshen 8003 (electron probe).

4.3 Caprock characteristics In the Kuqa foreland basin, there is a set of widespread Paleogene-Neogene gypsum-salt strata which has big thickness of generally 200-900m or over 4000m in local areas (Fig. 7). The Paleocene-Eocene Kumugeliemu Group and Miocene Jidike Formation develop two main gypsum-salt beds. The Paleogene Kumugeliemu Group gypsum-salt beds are distributed in the west of Kuqa River, and the Neogene Jidike Formation gypsum-salt beds are distributed in the east of Kuqa River. The thickness of the Paleogene gypsum-salt beds in the central and western part is greater than that of the Neogene gypsum-salt beds in the eastern part. Generally, the gypsum-salt strata are thicker in the north and in the west, thinner in the south and in the east, and its thickness centers are consistent with distribution direction of tectonic belts and main reverse faults (NWW or near EW). The distribution of the gypsum-salt strata is obviously influenced by the later tectonic processes (Yang et al., 2009; Zhuo et al., 2013). The gypsum salt rocks can act as good regional caprocks. The stress and strain characteristics of gypsum salt rocks, especially salt rocks, are obviously different from those of clastic rock. The reason is that the gypsum salt rocks itself has different brittleness and plasticity under different temperatures and confining pressures, generally, with increase of burial depth or temperature, its rheological plasticity increases. Through physical simulation experiments, Zhuo et al (2014) consider that when the burial depth is greater than 3000 m, with increase of burial depth of caprocks, the rock plasticity increases, the salt-penetrating faults disappear in the caprocks or is welded and sealed, or top of new faults disappear in the plastic caprocks. This set of regional caprocks is tight, and has high breakthrough pressure and strong sealing ability; it belongs to super caprocks in caprock classification, and plays an important role in formation of the most important gas-rich unit in the Kuqa foreland basin, i.e. Triassic-Jurassic hydrocarbon source rocks-Cretaceous pre-salt sandstone petroleum system. Fig. 7 Paleogene and Neogene gypsum-salt rock thickness distribution in the Kuqa foreland basin showing that Paleogene-Neogene gypsum-salt strata are widespread and has big thickness of generally 200-900m.

4.4 Gas reservoir characteristics The gas reservoirs in the Keshen gas field are characterized by large burial depth, high formation pressure and high formation temperature (Table 1). The typical gas reservoirs in the Kelasu gas field have burial depths of 5500 m-7500 m, it belong to ultra-deep gas reservoirs; the pressure coefficient is from 1.54 to 1.86, indicating that it are high pressure and ultra-high pressure gas reservoirs; the reservoir thickness ranges from 280 to 320 m, and the structural amplitude is from 300 to 650 m, the structural amplitude is generally larger than the reservoir thickness, showing the characteristics of section gas reservoir (Feng and Wang, 2013; Zhang et al., 2013; Wang, 2014; Zhuo et al., 2014). According to characteristics of fluid phase, various types of gas reservoirs are developed in the Kelasu gas field, including condensate gas reservoirs, wet gas reservoirs and dry gas reservoirs. In the Keshen area, the dry gas reservoirs are mainly developed, for example, Dabei 3 gas reservoir, Keshen 1 gas reservoir, Keshen 2 gas reservoir, Keshen 3 gas reservoir, Keshen 5 gas reservoir. The property of gas reservoirs varies greatly from the Keshen area to the Dabei-Bozi area, the condensate gas reservoir mainly is the Bozi 1 gas reservoir, and the wet gas reservoirs are mainly the Dabei 1gas reservoir and the Dabei 201 gas reservoir. The Keshen area is generally characterized by normal differentiation of gas above water (Fig. 8 and 9). The gas in the gas reservoir has high methane content (>95%) and low non-hydrocarbon gas content, indicating high-quality natural gas. The gas has average molecular weight of 17.46, low relative density of 0.59, average methane content of 93.70%, 5

average ethane content of 1.84%, average propane content of 0.23%, average nitrogen (N2) content of 2.25%, very low acidic gas content, CO2 content of 1.36% and no H2S. The typical formation water in the Keshen area is featured by high daily water production, high chloride ion content and high total salinity. For example, the Well Keshen 7 has daily water production of 173 m3, a chlorine concentration of 120 000 mg/L and total salinity of 215 000 mg/L. Generally, the Keshen gas reservoir belongs to layered faulted anticline dry gas reservoir with ultra-deep burial depth, ultra-high pressure, normal temperature and edge water. Fig. 8

Typical gas reservoir profile through Well Keshen 9, Well Keshen 202 and Well Kela 203 in the Kelasu structural belt

Fig. 9

Regional tectonic map of the Keshen area in the Kelasu structural belt

Table 1 Temperature and pressure parameters of typical gas reservoirs in the Kelasu gas field in the Kuqa foreland basin showing that The gas reservoirs in the Keshen gas field are characterized by large burial depth, high formation pressure and high formation temperature.

5 Main controlling factors of formation of large oil and gas fields 5.1 The thrust belt located above Triassic-Jurassic hydrocarbon-generating center Due to existence of Paleogene gypsum-salt strata, the thrust deformation shows obvious stratification. The suprasalt structure is dominated by thrust faults and related folds formed by intraformational detachment of salt rocks, while the pre-salt structure is dominated by a large number of thrust-imbricated faults and related folds. Influenced by deep detachment, a series of thrust faults with the same dipping develop in the wedge block, giving rise to thrust imbrication structure and the vertical superimposition and thickening of deep source rocks. 5.1.1 Source rocks with large thickness, wide range, high abundance, good type and high thermal evolution degree The well developed Triassic and Jurassic dark mudstones are the main source rocks. There are five stratigraphic formations from top to bottom, namely the Huangshanjie Formation (T3h) and Taliqike Formation (T3t) of Upper Triassic, Yangxia Formation (J1y) of Lower Jurassic, Kezilenuer Formation (J2k) and Qiakemake Formation (J2q) of Middle Jurassic. Among which, the Huangshanjie Formation and Qiakemake Formation are dominated by lacustrine mudstone, while the Taliqike Formation, Yangxia Formation and Kezilenuer Formation are dominated by coal measure strata. The sedimentary center of Triassic source rocks is located in the Dabei-Kela area, where thickness of source rocks is about 500-600 m (Fig. 10). The source rocks of the Yangxia Formation and Kezilenuer Formation in Jurassic have two sedimentary centers respectively in the east and in the west. The east sedimentary center is distributed at the Well Kela 2-Kuqa River section-Well Yinan 2, and thickness of source rocks is about 600-800 m. The west sedimentary center is distributed at the Kapushaliang River section-Laohutai area, and thickness of source rocks is about 400 m. Source rocks of Jurassic Qiakemake Formation is thicker in the northwest in the Baicheng depression, reaches maximum thickness of 250m in the Awate River section in Wensu County, and gradually thin and pinches out toward surrounding areas. The Jurassic and Triassic mudstones have TOC of more than 2%, pyrolysis hydrocarbon-generating potential of 0.6-3.5mg/g, and chloroform asphalt "A" of 0.4-1.2‰ in general, indicating medium-good source rocks. The Jurassic and Triassic carbonaceous mudstones have TOC of less than 20%, pyrolysis hydrocarbon-generating potential of 27-35 mg/g, and pyrolysis hydrogen index of 150-290mg/g in general, indicating poor-medium source rocks. Generally, the carbonaceous mudstone and coal in the Kuqa foreland basin have little ability to generate liquid oil, and are not oil-prone source rocks; but it can generate a large amount of natural gas in the high and over-mature stages, and is a good gas source and gas-prone source rocks. The current vitrinite reflectance (Ro) of Triassic-Jurassic source rocks is more than 0.50%, and high in the west and low in the east. The current Ro of source rocks in the west is generally from 1.35% to 1.87%, indicating the source rocks is in the stage of high mature condensate oil-wet gas. The current Ro of source rocks in the east is generally from 0.56% to 0.79%, indicating the source rocks is in the low mature oil-generating stage. Fig. 10 Thickness contour map of Triassic source rocks in the Kuqa depression showing that the sedimentary center of Triassic source rocks is located in the Dabei-Kela area, where thickness of source rocks is about 500-600 m.

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5.1.2 Source rocks with high hydrocarbon-generating intensity and large hydrocarbon-generating amount Influenced by tectonic compression movement, regional shrinkage and deformation (with a shrinkage rate of about 40%) occur in the Kelasu pre-salt structure, thus, the thrust imbrication structures are formed, and at the same time, deep source rocks vertically are superimposed and thickened. The main source rocks in the Kuqa foreland thrust belt have zonal distribution of gas generation intensity and oil generation intensity, and high value of gas generation intensity and oil generation intensity are distributed in the Kelasu-Yiqikeli structural belt and Dongqiu structural belt. The areas with the highest gas generating intensity are distributed in the Dina area and Dabei-Keshen area, and the gas generating intensity is up to (35-40)×109m3/km2. The areas with the highest oil generating intensity are distributed in the Dabei area, south area of Kela 3 and Dina area, and the oil generating intensity is up to 10×106t/km2. The oil generating area of source rocks in Qikemake Formation is mainly located in the central and western part of the Kuqa foreland thrust belt, especially in the Dabei-Bozi area, the oil generating intensity is up to (1.6-2.0)×106t/km2. Therefore, the deep thrust zone is the largest hydrocarbon generation center, and combining with structural traps and reservoirs effectively, it is most favorable for oil and gas accumulation, especially for accumulation of late stage natural gas. The main source rocks in the Kuqa foreland thrust belt have total gas generation quantity of 204.10 trillion cubic meters and oil generation quantity of 75.416 billion tons. Among which, thrust belts overlapped by some source rocks have 26.9 trillion cubic meters of gas which accounts for 13.2% of total gas, it contributes greatly to total hydrocarbon generation quantity. 5.2 Good spatial configuration of reservoir-cap assemblage The main reservoir of the Keshen gas field is Cretaceous Bashijiqike Formation, where delta front deposits of wide and shallow lake basins are developed, the supply of materials is sufficient, so sand bodies are superposed vertically, connect with one another horizontally and cover the whole area; this main reservoir has thickness of 200-300 m and sand content of over 90%, and is dominated by medium-fine lithic feldspar sandstone. The high-quality sandstone reservoir in the Cretaceous Bashijiqike Formation is in close contact with overlying Paleogene thick widespread gypsum-salt caprocks to form most important regional high-quality reservoir-cap assemblage. 5.3 Good superimposition between source-reservoir-cap assemblages and pre-salt thrust belts In the Kuqa foreland thrust belt, the source-reservoir-cap assemblage of Triassic-Jurassic hydrocarbon source rock, Cretaceous Bashijiqike sandstone reservoir and Paleogene gypsum-salt rock is developed (Fig. 11), and is obviously affected by the paleo-uplift in the southern margin, the source-reservoir-cap assemblage is mainly distributed in the northern part of the paleo-uplift, and is in good superposition relationship with the pre-salt thrust belt. Fig. 11 Schematic map of the reservoir-cap assemblages in the Keshen area of the Kelasu structural belt showing that the source-reservoir-cap assemblage of Triassic-Jurassic hydrocarbon source rock, Cretaceous Bashijiqike sandstone reservoir and Paleogene gypsum-salt rock is developed.

5.4 Types and spatial-temporal distribution of traps Affected by intense tectonic compression in the Late Himalayan Movement, a large number of fault-related folds with zonal distribution, large scale and high amplitude are developed in the pre-salt structure layer in the Kuqa foreland thrust belt, thus, a large number of anticline and fault anticline traps are formed. The thrust faults usually are terminated in the above regional gypsum-salt strata and communicate with source rocks downward, so the pre-salt structural traps have superior oil and gas accumulation and preservation conditions. So far, some secondary structural belts have been found in the Keshen area. With development of deep strata exploration, large-scale ultra-deep natural gas reservoirs such as Keshen 2, Keshen 5 and Keshen 8 have been discovered successively, revealing the pre-salt imbricated thrust structural belts have the characteristics of gas-bearing and superimposed contiguous zones as a whole 5.5 Good match between hydrocarbon generation evolution and tectonic movements The Mesozoic source rocks in the Kuqa foreland thrust belt was in the mature stage during the sedimentary period of Neogene Jidike Formation-Kangcun Formation. Since the sedimentary period of Kuqa Formation, with formation of 7

foreland thrust belt and accelerated sedimentation of strata, the source rocks have rapidly evolved in the high maturity-over maturity stage, and are still in the burial evolution stage (Fig. 12). In the late stage, the source rocks have very high hydrocarbon generation intensity of more than 13×103 m3/m2, and generate large amount of hydrocarbon. At the same time, chance of easily loss natural gas with small molecule is reduced greatly, so possibility of large-scale hydrocarbon accumulation greatly increases. The intense compression tectonic movement in Late Himalayan causes formation of many thrust faults, these thrust faults cut through source rocks and reservoirs in Cretaceous Bashijiqike Formation, and provide driving force for large-scale hydrocarbon expulsion and pathways for hydrocarbon migration and accumulation. The thick widespread gypsum-salt caprocks have strong capillary sealing ability and overpressure sealing ability which greatly reduce risk of leakage and loss of pre-salt gas reservoirs. The hydrocarbon accumulation in the Kuqa foreland thrust belt is a dynamic process of continuous hydrocarbon charging with formation and evolution of pre-salt structural traps. Fig. 12 Structural thermal history simulation of the NS profile of the Keshen section in the Kuqa foreland thrust belt. Q1x represents Xiyu Formation; N2k represents Kuqa Formation; N1-2k represents Kangchun Formation; N1j represents Jidike Formation; E2-3s represents Suweiyi Formation; E1-2km represents Kumugeliemu Group.

5.6 Hydrocarbon accumulation model 5.6.1 Large distance between source rocks and reservoirs The Triassic-Jurassic source rocks are the main source of oil and gas in the Kuqa foreland thrust belt, which have large burial depth of more than 8000 m in general. The Cretaceous Bashijiqike Formation is the main oil and gas production layer. The distance between the Triassic-Jurassic source rocks and the reservoirs in the Cretaceous Bashijiqike Formation is large, and generally between 1500 m and 4000 m with an average of 3000 m. The large distance between the source rocks and the reservoirs provides a precondition for generation of vertical migration force. 5.6.2 Large pressure difference between source rocks and reservoirs The large distance between pre-salt source rocks and reservoirs in the Kuqa foreland thrust belt directly leads to pressure difference between source rocks and reservoirs. This pressure difference provides a dynamic condition for intense gas charging. The pressure difference between source rocks and reservoirs mainly depends on two factors. Firstly, the underlying source rocks are affected by intense tectonic movement since Neogene, the Triassic-Jurassic source rocks have undergone rapid deep burial thermal evolution stages of Ro>1.0%, Ro>1.3%, Ro>2.0% and Ro>2.5% in a short period of ten of million years; rapid hydrocarbon generation and expulsion also provide an internal condition for super-high formation pressure. Secondly, the altitude difference between source rocks and reservoirs is large; if the pressure drop gradient between source rocks and reservoirs is 2.61 MPa/100m in the Keshen area, the pressure difference between source rocks and reservoirs is at least 70 MPa; the large pressure difference between source rocks and reservoirs provides a dynamic condition for intense gas charging, which is a necessary condition for formation of high-efficiency gas reservoirs. 5.6.3 Fault-fracture network system as high-speed pathway of oil and gas migration (1) Fracture network system of vertical migration The reservoirs in the Kuqa foreland thrust belt are located above the Triassic-Jurassic hydrocarbon generation center. A series of mudstones, such as Cretaceous Shushanhe Formation and Jurassic Qigu Formation, are located between the Triassic-Jurassic main source rocks and the reservoirs of Cretaceous Bashijiqike Formation. Hydrocarbon entering sandstone reservoirs in Cretaceous Bashijiqike Formation should migrate across thick overlying mudstones, thus, deep faults play a very key role as bridge link. Three grades of faults are developed in the Kuqa foreland thrust belt, namely, the first-grade fault, the second-grade fault and the third-grade fault. The Kelasu fault and Keshen fault are the first-grade faults, the Keshen south fault and Baicheng fault are the second-grade faults, and the rest faults are the third-grade faults. The first-grade faults largely control the tectonic background, and the second-grade and third-grade faults complicate the internal structure. The pre-salt oil source faults serve as vertical migration pathways for oil and gas. Generally, oil and gas charging occurs in all permeable reservoirs cut through by faults. Discovery of the Keshen and Dabei oil and gas reservoirs 8

proves that all oil and gas migration is related to pathway of oil source faults. Oil and gas migrate to upper strata along source-reservoir faults, controlled by complex fault network composed of multi-order faults, oil and gas undergo adjustment and migration to realize high efficiency charging of oil and gas and result in high gas abundance in pre-salt sandstone reservoirs. From the perspective of property and composition of oil and gas in the Keshen area, vertical oil and gas differentiation is not obvious in the same well block, indicating that oil and gas have undergone roughly equal fault migration distances, and fault network system achieve efficient oil and gas migration. (2) Fracture network system of lateral migration Oil and gas migrate vertically along gas source faults to the reservoirs, and then migrate laterally within the reservoirs. The pre-salt Cretaceous sandstone reservoirs in the Keshen gas field have poor matrix physical property, and show ultra-low porosity and permeability. However, influenced by strong compression tectonic movement in the late stage, multi-scale fracture network system are developed in the reservoirs, which effectively communicate sandbodies with pores, thus, the reservoir permeability is increased and the sandbody transport property. According to scale and characteristic of fractures, the fracture can be divided into four-level fracture systems, including giant joints-microfracture, straight splitting fracture, grain penetrating fracture and grain margin fracture (Fig. 13). Fig. 13 Types of multi-scale fractures in ultra-deep reservoirs in the Kelasu structural belt showing that the fracture can be divided into giant joints-microfracture, straight splitting fracture, grain penetrating fracture and grain margin fracture.

(3) Fault-fracture network system enabling efficient oil and gas migration Vertical migration of multi-grade faults and lateral migration of multi-scale fractures in the Kuqa foreland thrust belt constitute a highly efficient network migration system from source rocks to traps, which is the main reason for oil and gas enrichment in the pre-salt thrust belt. Natural gas generated by Jurassic-Triassic source rocks rapidly are charged into the pre-salt reservoirs along deep gas source faults, and then migrate along multi-scale fracture network into sandbodies, thus, high efficient migration of oil and gas can be realized. Oil and gas properties can reflect high efficiency of fault-fracture network migration system (Zhou et al., 2016; Neng et al., 2017; Zhou et al., 2017). 5.6.4 Late intensive natural gas charging The Kuqa foreland thrust belt experiences slow subsidence in Mesozoic and is uplifted in Late Cretaceous, as a result, Triassic and Jurassic source rocks are kept at low maturity state (Ro<0.6%-0.7%) before Neogene, while rapid subsidence since Neogene result in rapid deep burial thermal evolution stages (Ro>1.0%, Ro>1.3%, Ro>2.0% and Ro>2.5%) of these two sets of source rocks within a short period of 12 Ma. Hence, oil generation peak period and dry gas generation period of these two sets of source rocks are very late. In the center of Baicheng sag, the Upper Triassic source rocks generate massive oil in Miocene (23-12Ma), while the Middle and Lower Jurassic source rocks produce massive gas after 5Ma, especially after 2Ma, it produce a large amount of dry gas, and the cumulative gas intensity is (35-40)×109m3/km2. 5.6.5 Hydrocarbon accumulation model of pre-salt faulted anticline The deep oil and gas reservoirs in the pre-salt deep formation in the Kuqa foreland thrust belt are characterized by high pressure, ultra-high pressure and high productivity. The reservoirs are mainly anticline and faulted anticline structural gas reservoirs, most of which are fully filled. Mesozoic source rocks are in the mature stage during the sedimentary period of Neogene Jidike Formation-Kangcun Formation. From the sedimentary period of Kuqa Formation to present, the sources rocks rapidly evolve to the high maturity-over maturity stage with formation of foreland thrust belt and sedimentation acceleration of strata, and are in the deep burial evolution till now. In the late stage, the source rocks have very high hydrocarbon generation intensity which can be over 13×103 m3/m2, and generate a large amount of hydrocarbon. Meanwhile, chance of easily-loss natural gas with small molecules is greatly reduced, so possibility of large-scale hydrocarbon accumulation is increased greatly. The pre-salt stress is released largely in the roof structure, to form multi-belt and multi-grade of faults which provide favorable pathways for oil and gas migration from source rocks to reservoirs. The undercompaction, tectonic compression and hydrocarbon generation result in formation of ultra-high pressure in deep source rocks, thus, large pressure difference between these source rocks and Cretaceous Bashijiqike reservoirs is formed, and provides strong driving force for migration of 9

deep ultra-high pressure gas to reservoirs. At the same time, the flow thickening of gypsum salt rock under the roof structure could create not only vertical sealing effect, but also lateral sealing effect on natural gas. Under the good match of hydrocarbon generation evolution, migration system and structural traps, the pre-salt deep gas in the Kelasu structural belt is continuously charged into fault anticline reservoirs in the late stage (Fig. 14); driven by huge pressure difference between source rocks and reservoirs, the natural gas generated by Jurassic-Triassic source rocks is rapidly charged into the pre-salt reservoirs along deep gas source faults, then migrate laterally along multi-scale fracture network in the reservoirs, and under vertical and lateral sealing of gypsum-salt layer, the high efficient gas accumulation in the pre-salt fault anticlines is realized. Fig. 14 Hydrocarbon accumulation model of the Kelasu structural belt in the Kuqa foreland thrust belt showing that the pre-salt deep gas in the Kelasu structural belt is continuously charged into fault anticline reservoirs in the late stage.

6 Key technologies for hydrocarbon exploration and development 6.1 3D data acquisition and processing technology for complex mountainous areas (1) 3D acquisition of high density and wide azimuth mountainous areas to improve imaging accuracy of pre-salt geological bodies Three-dimensional seismic exploration of the Kuqa foreland thrust belt began in 2000. In the initial stage, structures in the three-dimensional seismic area are simple, burial depth of target strata is relatively shallow and data signal-to-noise ratio is relatively high, so three-dimensional observation with narrow azimuth and low density is mainly used. In order to meet need of exploration and development of increasingly complex targets, three-dimensional seismic acquisition technologies for mountainous areas have been developed continuously in recent years. In 2010, a wide azimuth three-dimensional seismic survey was tested in the Dabei area for the first time, and obvious results was achieved; thus, a high density and wide azimuth three-dimensional seismic acquisition technology for mountainous areas is gradually formed, which satisfies need of exploration for pre-salt complex targets in the Kuqa foreland area. Compared with the narrow azimuth three-dimensional observation, the wide azimuth three-dimensional observation has many advantages, such as more accurate anisotropic parameters, more accurate imaging speed, and more accurate imaging. Continuous and complete reflected and diffracted seismic wave field can be obtained through the wide azimuth three-dimensional observation. After seismic wave excitation, the downward wave front is hemispherical; according to Huygens principle, when the wave front encounters the wave impedance change point, it can be regarded as a new point source to propagate outward, and when it returns to the surface, it is a circular isochronal surface. If the narrow azimuth three-dimensional observation system is used, only part of the reflected and diffracted wave signals can be obtained. If the observation azimuth is further increased, more abundant reflection and diffraction information can be obtained laterally, and the information is more from deep and steep dip strata, which is more conducive to solve imaging problem of highly steep pre-salt complex structures. Fig. 15 Comparison of images from the wide-azimuth and narrow-azimuth seismic data. (a) Narrow-azimuth prestack depth migration profile; (b) wide-azimuth prestack depth migration profile.

(2) Anisotropic prestack depth migration on irregular topography to ensure accurate homing imaging of deep pre-salt structures In order to solve the imaging problem of complex structures in piedmont, theoretically, the data should be processed by the prestack depth migration. This technology is one of the remarkable signs of the geophysical technology progress in recent 10 years. Internationally, the prestack depth migration technology has become the dominant technology to improve the imaging accuracy of complex structures and reduce the risk of exploration and development; it has been used successfully in offshore pre-salt oil and gas exploration. However, complex structures in the Kuqa salt-bearing foreland thrust belt in China have great challenges to application of the prestack depth migration technology. The irregular topography, complex surface structure changes and its violent structural deformation, plastic flow of underground salt layer and double high-steep structural characteristic, make seismic imaging of these areas difficult and complicated. 10

In the Kuqa salt-bearing piedmont complex tectonic area, due to irregular topography, shielding of gypsum-salt strata to lower reflection and low signal-to-noise ratio, the prestack processing before prestack depth migration processing, including static correction, prestack denoising and consistency, must be done well. Meanwhile, base level selection of the prestack depth migration and velocity modeling and anisotropic parameter calculation of low signal-to-noise ratio data must be done well too. Through study of many years, the signal-to-noise ratio and imaging quality of seismic data in the Kuqa salt-bearing complex piedmont area have been significantly improved, and the anisotropic prestack depth migration processing technologies have been formed, laying a solid foundation for definition of trap, well location deployment and reserve estimation. These technologies include the prestack depth migration velocity modeling technology, prestack depth migration method and parameter test, and anisotropic prestack depth migration technology. 6.2 Stratified modeling technology for extrusion salt-related structures The stratified modeling technology of extrusion salt-related structures is an important technology to study characteristics of pre-salt deep structures in the Kuqa depression, to establish a reasonable structural interpretation model and to define traps. It is used to solve problems of multi-solution of structural interpretation model in the complex structural deformation in the gypsum-salt strata development area. The stratified modeling technology of extrusion salt-related structures is to establish the shallow structural model by observing and describing large-scale salt-related structures on the surface and fine analysis of local structures. The salt structural deformation pattern, kinematic process and dynamic mechanism are determined through physical simulation experiments and numerical simulation experiments of salt-related structures. Combined with drilling and three-dimensional spatial interpretation results of seismic data and through comprehensive modeling method, different deformation patterns of suprasalt layer, salt layer and pre-salt layer are respectively established to guide seismic data interpretation and study of structure and trap. The stratified modeling technology of extrusion salt-related structures includes three key technologies: fine surface analysis technology of salt-related structures, simulation experiment technology of salt-related structures and comprehensive modeling technology of salt-related structures. 6.3 Logging acquisition and evaluation technology for sandstone gas reservoir with high temperature, high pressure, ultra deep burial depth and low porosity The Cretaceous Bashijiqike Formation in the Kuqa foreland basin belongs to ultra-deep, high temperature, high pressure, low porosity and fractured sandstone reservoirs. The reservoirs are characterized by tight lithology, small pores, fine throats, poor connectivity, strong heterogeneity and well-developed fractures. Meanwhile, influenced by strong tectonic movement, high-steep structures and strong horizontal compressive stress are formed in some well areas during formation of the Kuqa foreland basin. Moreover, different drilling fluid systems are used in drilling. All these factors make it difficult to interpret and evaluate reservoir fluid properties using conventional logging data and Archie sandstone model. Through the study, three methods for qualitative identification and evaluation of reservoir fluids as well as one quantitative correction technique of resistivity are proposed, which lay a concrete foundation for accurately calculating reservoir gas saturation and identifying fluid properties. 6.3.1 Porosity difference method to identify fluid properties Acoustic, neutron and density porosity logging methods have different logging principles and different numerical dimensions. Through conversion and comparison, gas-bearing formation has relatively large acoustic porosity and logging density, while has relatively small neutron porosity; therefore, reverse change characteristics of acoustic, neutron, density in gas-bearing formation can be used to identify gas layers and water layers, thus, effective gas-bearing reservoirs can be ensured. 6.3.2 Gas and water index method for identifying fluid properties in tight fractured sandstone reservoirs By using resistivity and acoustic logging data, and considering influence of fractures on fluid properties in reservoirs, the gas and water indexes to reflect change of gas and water layers have been established respectively, and the log response characteristics of gas and water layers are enlarged. The gas and water index charts have been established for different zones, intervals and mud types, which can more effectively distinguish deep gas layers and water layers in the Kuqa area. 11

6.3.3 Fluid property identification by fluid compression coefficient under fracture influencing factors The P-wave velocity of gas-bearing formations decreases obviously, but the S-wave velocity does not change much, so ratio of P-wave velocity to S-wave velocity of gas-bearing formations is much smaller than that of saturated water formations. This phenomenon can be used to identify gas layers and water layers. The reason to cuase this phenomenon is that the acoustic characteristics of water and gas phase in pore water is quite different, and the compressibility coefficient of water is much smaller than that of gas. Therefore, considering influence of reservoir fractures on fluid, the fluid compressibility coefficient can be obtained and it can be used to distinguish gas layer and water layer. 6.3.4 Log apparent resistivity correction technology under high-steep structure and strong compression stress condition In order to study high-steep structures and analyze variation law of reservoir physical properties, stress and log apparent resistivity of well logging, The first rock resistivity-porosity-pressure joint measurement experiment in the world has been carried out, and relationships between stress and porosity, between porosity and resistivity, between stress and resistivity also have been studied. Above experimental process is numerically simulated, and a stress resistivity correction model is established and is used in interpretation and evaluation process of actual logging data of the Kuqa area. For well blocks influenced by strong compression stress, the stress resistivity correction model is applied to obtain real resistivity of formation, and it can effectively identify gas layer and water layer, thus, coincidence rate of logging fluid property interpretation is improved. The four fluid property evaluation technologies lay a foundation for accurate logging interpretation and evaluation of fluid properties in the Kuqa area, and promote coincidence rate of logging interpretation to increase in the Kuqa area year by year. Since 2015, the coincidence rate of logging fluid interpretation is kept at over 85%. 6.4 Ultra-deep well drilling technology for complex salt layer and complex mountainous areas The gypsum-salt strata in the Kuqa area are not very pure gypsum or salt rocks, but contain clastic rock and carbonate rock interbeds, so lithological sequence in the gypsum-salt strata is complex. Relatively simple drilling engineering is complicated by existence of some special strata. Complex cases occur frequently in drilling process of composite salt formations, high-pressure salt water layer and thin sand layers in salt rocks are often drilled, and therefore, overflow, well leakage and sticking of tool occur frequently. 6.4.1 Development characteristics and disposal technology of high-pressure salt water layer Several sets of high-pressure salt water layers are distributed in the gypsum salt formation in the Kuqa piedmont, which are characterized by high salinity, narrow window of safe drilling fluid density and difficult drilling operation, this is one of the most difficult problems in drilling gypsum salt formations. High-pressure salt water layers are often distributed in reservoirs (thin siltstone or dolomite reservoirs) with good physical properties in the thick gypsum-salt rock. During the burial process, pore water is not released, under the static pressure, abnormal high-pressure layers are formed. These abnormal high-pressure layers are liable to cause overflow, so the salt water would pollute drilling fluid to cause a series of complex situation and seriously affect exploration and development process in the Kuqa piedmont. In view of development characteristic of high-pressure salt water layers in the Kuqa piedmont, geological engineers work out overall solution for high pressure salt water disposal based on oil-based drilling fluid through strengthening integration of geology and engineering. The overall solution is mainly to relieve water and pressure, supplemented by overflow killing. The high-pressure salt water layer in the Kuqa piedmont belongs to lenticular high-pressure salt water, and storage space is limited; the disposal technology of relieving pressure and water can effectively reduce energy of abnormal high-pressure layer in a short time, widen window of safe drilling fluid density, and reduce downhole complexity and risk of well control. The specific process steps are as follows: (1) the well is shut down to calculate pressure during the overflow, pressure coefficient of abnormal high-pressure salt water layer is calculated. (2) The circulation is throttled, and fluid property is determined, risk of salt crystal blocking circulation channels is observed. (3) If the overflow fluid is the salt water and there is no risk of blocking channels, the water is released to relieve pressure for dispose of high-pressure salt water layer. (4) If there is a risk of blocking channels, the well is killed by high-density killing fluid and then the water is released to relieve pressure for dispose of high-pressure salt 12

water layer; for high-pressure salt water layer with pressure coefficient of less than 2.35, the overflow killing technology is adopted directly, and then the salt formation drilling is quickly resumed. At present, the disposal technology of relieving water and pressure has been applied in Keshen 9, Keshen 11 and Keshen 13 blocks; during drilling of Well Keshen 1101, the high-pressure salt water layer is encountered, it take 9.2 days to resume drilling by the disposal technology of relieving water and pressure, this technology saves 52 days compared with the disposal scheme of overflow killing well. 6.4.2 Development characteristics and disposal technology of undercompacted mudstone Some mudstones with unequal thickness are also distributed in the huge gypsum-salt strata in the Kuqa piedmont. Under gravity action of overlying strata or lateral tectonic stress, the mudstones are compacted and the pore water is released, thus, the porosity and permeability become worse and the tight layers are formed. Blocked by gypsum-salt strata, a large amount of pore fluid in the thick mudstone layer couldn’t be released, thus, a large number of pore fluids are retained, and the diagenesis of mudstone is delayed; therefore, the mudstones have high porosity which is not suitable for burial depth, and thus local lenticular high-pressure sealing bodies are formed. During the drilling process, complex engineering accidents such as bit balling, blockage during tripping and sticking of tool often occur when drilling to undercompacted mudstone formation, which increases drilling risk and prolongs drilling time. In view of development characteristics of undercompacted mudstone, through strengthening geological knowledge and optimizing well structure, the overall undercompacted mudstone disposal scheme of sealing salt with two layers of casing has been formed: the first layer of casing seals all undercompacted mudstone and large set of pure salt formation, and the second layer of casing seals gypsum mudstone formation with weak loading capacity in the lower part. The creep of undercompacted mudstone is irregular and the creep shrinkage is fast. The bit balling will occur no matter high-density drilling fluid or low-density drilling fluid is used, and the blockage is serious; in this situation, frequent short up and down are needed, leading to loss of a lot of construction time; if this problem is not properly handled, the drill sticking accidents may occur. In view of this geological understanding and low pressure loading capacity in the lower part of gypsum mudstone, disposal plan of two layers of casing to seal salt is proposed, i.e. high density drilling fluid to effectively balance undercompacted mudstone and creep shrinkage of large set of pure salt in the upper part of the salt formation is used to reduce downhole blocking and risk of sticking, thus excellent and fast drilling can be achieved; relatively low density drilling fluid is used in the lower part of gypsum mudstone to avoid complex accidents such as well leakage and sticking of tool. At present, this plan has been widely applied in Keshen 24 and Keshen 11 blocks. The drilling technology of two-layers casing to seal salt is used in the drilling Well Keshen 242, and saves 38 days than the drilling technology of one-layer casing to seal salt; on the whole, this technology can reduce downhole complexity, shorten drilling cycle, reduce well control risk and enhance exploration speed. 6.5 Stimulation technology for ultra-deep sandstone reservoirs with high temperature, high pressure and low porosity The Kuqa foreland area has the complex geological condition, it is characterized by high temperature, high pressure and large depth, and develops thick salt-gypsum layers and reservoir matrix with low porosity and low permeability, leading to long well building cycle, large investment of single well, high operation safety and technical risks, and low natural production of single well. Only through reservoir stimulation, can the gas reservoir be developed economically and gas source of West-East Gas Transmission be guaranteed. The natural productivity per well in the Dabei and Keshen areas is low, which can’t meet the requirement of production allocation, restricting the benefit development of this area. Therefore, the reservoir stimulation is an urgent technology needed for exploiting such resources. The high temperature, high pressure and ultra-deep fractured tight sandstone reservoirs in the Kuqa foreland area are unique in China and rare in the world. At present, only a few oilfields in such the Gulf of Mexico are similar with it and can be referred in the world. However, there is no mature experience to refer for stimulation of reservoirs with complex condition, high temperature, high pressure and ultra depth. For this kind of reservoirs, the stimulation faces three major difficulties: (1) Large burial depth, high pressure coefficient and high ground stress lead to high operation pressure, difficult reconstruction and operation as well as high risk. 13

(2) The reservoirs develop fractures with large vertical span, and have strong heterogeneity within and between layers, thus, the effective reservoirs is difficult to be fully utilized by conventional stimulation technologies. (3) The reservoirs develop many natural fractures, and influencing factors of initial open and extension of artificial fractures are still unclear. Fractures are the main contributor to production and natural fractures are controlled by geostress, so establishment of pertinent geomechanical model is the basis of effective stimulation. Therefore, in view of difficulties and challenges in stimulation of this kind of reservoir, followed an idea of combining theory and practice, reservoir evaluation, fracture system spatial distribution and three-dimensional geostress distribution are well studied. Comprehensive evaluation and analysis of gas reservoirs is carried out to gradually improve the dynamic and static model, providing the reliable geomechanical model and fracture model for design and effect evaluation of reservoir stimulation. Key basic theory of reservoir stimulation, matching technology of reservoir stimulation, implementation of reservoir stimulation, and post-fracturing evaluation are studied based on comprehensive research results of geomechanics and fracture, thus, the stimulation effect is constantly improved, which provide the technical support for well block development and optimization. From 2010 to 2012, with development of 140 MPa ultra-high pressure fracturing unit and exploration of sand control and sand fracturing method, the sand fracturing at the depth of 7000 m was realized. In the fracturing of Well Dabei 301, Well Dabei 6 and Well Keshen 5, problems such as high pumping pressure (pumping pressure of 75% wells over 100 MPa), small sand dosage (about 10 m3), limited effect of yield increase (1.5 times) occurred. The pilot tests of separate layer fracturing with “packer+sliding sleeve” and “cable perforation+quick drilling bridge plug” were carried out, it was found that separate layer tools for vertical simulation in high temperature, high pressure and ultra-deep reservoirs had not yet matured, and the operation risk was high. From 2013 to 2015, by reference to the concept of shale reservoir reconstruction abroad and through introduction, digestion and absorption, geomechanical modeling, integrated fracture study, reservoir simulation material development, design and process optimization, technology integration and matching were carried out, popularized and applied, thus, the fracture network fracturing and acid fracturing simulation technology suitable for high temperature, high pressure and ultra-deep fractured tight gas reservoirs in the Kuqa foreland area have been developed. During the "Twelfth Five-Year Plan" period, the fracture network fracturing and acid fracturing simulation technology was applied in 54 well times in the Kuqa foreland area. Before the reservoir simulation, the single well had an average tubing pressure of 49 MPa and gas production of 150×103m3 per day; after the reservoir simulation, the single well had an average tubing pressure of 76 MPa and gas production of 600×103m3 per day. The cumulative gas production reached 6.2×109m3 so far, realizing economic development of the Kuqa foreland area and guaranteeing gas source of West-East Gas Transmission. At the same time, this technology greatly expands depth of exploration and development from 5000 m to 8000 m. 6.6 High efficient development technology for ultra-deep and ultra-high pressure fractured tight sandstone gas reservoir In view of development difficulties of the Keshen gas field, such as large production difference among wells, rapid productivity decline, fast water invasion and difficult dynamic monitoring, some key researchs of geological modeling of fractured tight sandstone gas reservoir, development mechanism experiment of ultra-high pressure gas reservoir, dynamic monitoring of ultra-high pressure gas well and well layout optimization design of fractured gas reservoir are carried out, thus, the high-efficiency development technology for ultra-deep and ultra-high pressure fractured tight sandstone gas reservoir is developed. The full-diameter core seepage experimental device with high temperature and ultra-high pressure is developed, which can simulate the gas-water seepage under formation condition (maximum experimental temperature of 160 oC, maximum experimental pressure of 116MPa). The fishing pressure testing technology for ultra-high pressure gas wells is developed, which realizes downhole pressure measurement at the depth of 7000 m with temperature of 175 oC and wellhead tubing pressure of 90 MPa. The pressure wave front tracing technology and streamline numerical simulation technology are formed, which can quickly and accurately evaluate remaining recovery capacity of gas reservoirs. Results of research and practice show that for Keshen gas field with ultra-deep depth and ultra-high pressure fractured 14

tight sandstone gas reservoir, it has strong inter-well interference and good overall connectivity, the pressure wave in the fracture system can spread to the whole gas reservoir in a very short time, thus, the centralized well placement can be used to realize overall utilization of reserves. The matrix of fractured tight sandstone reservoir is the main reservoir space, and the gas well has certain stable production capacity; however, rate of the matrix supplying gas to fracture system is slow, so the relatively low gas production rate is applied to ensure the balance between the matrix and the fracture system, and then the matrix reserves can be effectively utilized. The displacement efficiency of water flooding gas under formation condition is low, the relative permeability of gas phase drops sharply after the water breakthrough, and the gas productivity decreases rapidly; meanwhile, the phenomenon of "water blocking gas" is obvious, causing low recovery percent of reserves. Therefore, the water prevention, water control and water drainage are key issues to be considered in the whole life cycle of gas reservoir development. Therefore, centralized well placement at structural highs, mild production and water drainage during water breakthrough are the main development technical measures for fractured tight sandstone gas reservoirs with ultra-deep depth and ultra-high pressure. The ultra-deep reservoirs in the Kelasu structural belt are always considered to be controlled by sedimentary facies. But with increase of exploration degree, drilling and evaluation of ultra-deep reservoirs are facing a series of world-class problems in conflict with facies-control theory: in the same sedimentary facies zone of ultra-deep reservoirs, the reservoir quality, fracture development degree and scale, geological engineering complexity for reservoir drilling and testing productivity could differ widely. Through joint research of multi-disciplines including mud logging, drilling, well logging and reservoir data, it is found that the fractured low-porosity sandstone of Cretaceous Bashijiqike Formation has vertical stress stratification and the reservoir quality is controlled by stress environment. The multi-scale and multi-parameter progressive characterization technology of pre-salt ultra-deep reservoirs is established, and the difference characteristic and formation mechanism of the ultra-deep vertical reservoir quality are explored, and the main controlling factors of high-quality reservoirs are determined. Several high-quality reservoir prediction technologies, such as structural arch angle method, structural curvature method and two-wing angle method for different drilling purposes of exploration, evaluation and development, are developed; the continuous development characterization of fractures under multi-scale and multi-parameters is established; thus, the fracture scale, development characteristic and distribution in ultra-deep reservoirs in the Kelasu structural belt are clarified, and the fractures occurring in groups and belts in the Kelasu structural belt are found. The study shows that the reservoirs have vertical stress stratification, and the ultra-deep drilling completion depth can be optimized effectively. From top to bottom, the reservoirs can be divided into tensional interval, transitional interval and compression-torsion interval, among which, the tensional interval has the best reservoir quality, large fracture scale and high effectiveness. Evaluation of Keshen 2, Keshen 5 and Keshen 8 gas reservoirs shows that the amount of natural gas in the tensional interval accounts for more than 60% of total natural gas resource; therefore, in the development stage, drilling through this interval not only ensures high and stable production of gas reservoirs, but also reduces drilling risk and improves exploration efficiency. The reservoir quality of the transitional interval is slightly lower than that of the tensional interval, but its natural gas resource account for more than 30% of total natural gas resource. Therefore, drilling through reservoirs of the transitional interval can meet the need of gas reservoir evaluation.

7 Conclusions The Kuqa area in Tarim Basin has complex geological condition and difficult exploration, but through study of nearly ten years, some exploration and development key technologies continuously have been developed, so in a short time, the Keshen gas field with high gas abundance has been proved and achieved economical development. The main conclusions are as follows. (1) The Cretaceous Bashijiqike Formation in the Keshen gas field is dominated by delta deposits with vertical overlapping of sandstone layers and horizontal joining to form large-scale high-quality reservoirs. The Paleogene develops widespread thick gypsum-salt beds which form good reservoir-cap association with underlying super-thick sandstone. Plastic gypsum-salt rocks affected by fault activity and good lateral sealing ability formed by mudstone 15

coating on fault surface are favorable for reservoir formation of structural traps. (2) The Kuqa foreland basin was finalized in the Late Himalayan corresponding to peak period of hydrocarbon generation and expulsion of Jurassic and Triassic source rocks, which is conducive to hydrocarbon accumulation in pre-salt traps. Thus, the late hydrocarbon accumulation model is proposed. (3) The three-dimensional seismic acquisition and processing technology for complex mountainous areas has been developed, and the compressive salt-related structural modeling and the evaluation technology of pre-salt fractured low-porosity sandstone reservoirs are formed, laying a solid foundation for confirming oil and gas exploration targets in piedmont complex structural areas. (4) Through continuous study, some technologies such as ultra-deep high-temperature and high-pressure logging acquisition, fluid evaluation and efficient development have been gradually developed, which support high efficient development and rapid production of the Keshen gas field.

Acknowledgements The work was supported by the National Science and Technology Major Project of China (No. 2016ZX05003-004) References： ： Chu, G.Z., Shi, S., Shao, L.Y., Wang, H.Y., Guo, Z.H., 2014. Contrastive study on geological characteristics of Cretaceous Bashijiqike Formation in Keshen 2 and Kela 2 gas fields in Kuqa depression. Geoscience. 28(3), 604-610 (in Chinese). Dean, S.L., Morgan, J.K., Fournier, T., 2013. Geometries of frontal fold and thrust belts: Insights from discrete element simulations. Journal of Structural Geology. 53, 43-53. Duan, Y.J., Huang, S.Y., Li, W.B., Zhang, H.F., Ma, X.D., Liao, F.R., 2017. Using discrete element numerical simulation method to study salt tectonic deformation mechanism of Kelasu structural belt. Xinjiang Petroleum Geology. 38(4), 414-419 (in Chinese). Feng, S.B., Wang, H.Z., 2013. Geochemical characteristics of natural gas in overpressured large gas field of Kelasu tectonic belt in Kuqa depression. Natural Gas Geoscience. 24(4), 784-788 (in Chinese). Frehner M., 2011. The neutral lines in buckle folds. Journal of Structural Geology. 33, 1501-1508. Li, Y.Y., Qi, J.F., 2013. Structural segmentation and mechanism in Dabei-Keshen area of Kelasu structural belt, Kuqa depression. Chinese Journal of Geology. 48(4), 1177-1186 (in Chinese). Liu, C., Zhang, R.H., Zhang H.L., Huang, W., Mo, T., Zhou, L., 2017. Genetic types and geological significance of micro pores in tight sandstone reservoirs: A case study of the ultra-deep reservoir in the Kuqa foreland thrust belt, NW China. Acta Petrolei Sinica. 38(2), 150-158 (in Chinese). Liu, F., Zhu, X.M., Pan, R., Li, Y., Xue, M.G., Di, H.L., 2014. Formation of low permeability reservoir and typical case analysis in Kuqa depression. Lithologic Reservoirs. 26(3), 28-36 (in Chinese). Neng, Y., Li, Y., Xu, L.L., Zhou, P., Wang, B., Shang, J.W., Cao, S.J., 2017. Patterns of fracture zone in the deep subsalt layer of Kelasu structural belt and prospecting method. Geotectonica et Metallogenia. 41(1), 61-68 (in Chinese). Neng, Y., Xie, H.W., Sun, T.R., Lei, G.L., Xu, L.L., 2013. Structural characteristics of Keshen segmentation in Kelasu structural belt and its petroleum geological significance. China Petroleum Exploration. 39(2), 1-6 (in Chinese). Pan, R., Zhu, X.M., Liu, F., Li, Y., Ma, Y.J., Di, H.L., Zhang, R.H., 2013. Sedimentary characteristics of braided delta and relationship to reservoirs in the Cretaceous of Kelasu tectonic zone in Kuqa depression, Xinjiang. Journal of Palaeogeography. 15(5), 707-716 (in Chinese). Wang, Z.M., 2014. Formation mechanism and enrichment regularities of Kelasu subsalt deep large gas field in Kuqa depression, Tarim Basin. Natural Gas Geoscience. 25(2), 153-163 (in Chinese). Xie, H.W., Yin, H.W., Tang, Y.G., Wang, W., Wei, H.X., Wu, Z.Y., Li, W., 2015. Research on subsalt structure in the central Kelasu structure belt based on the area-depth technique. Geotectonica et Metallogenia. 39(6), 1033-1039 (in Chinese). Yang, X.Z., Lei, G.L., Zhang, G.W., Zhao, D.Y., 2009. Effect of gypsum-salt rocks on hydrocarbon accumulation in Kelasu structural belt of Kuqa depression. Xinjiang Petroleum Geology. 30(2), 201-204 (in Chinese). Yin, H.W., Zhang, J., Meng, L.S., Liu, Y.P., Xu, S.J., 2009. Discrete element modeling of the faulting in the sedimentary cover above an

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active salt diaper. Journal of Structural Geology. 31(9), 989-995. Zhang, J., Morgan, J.K., Gray, G.C., Harkins, N.W., Sanz, P.F., Chikichev, I., 2013. Comparative FEM and DEM modeling of basement-involved thrust structures, with application to Sheep Mountain, Greybull area, Wyoming. Tectonophysics. 608, 408-417. Zhang, R.H., Yang, H.J., Wang, J.P., Shou, J.F., Zeng, Q.L., Liu, Q., 2014. The formation mechanism and exploration significance of ultra-deep, low-porosity and tight sandstone reservoirs in Kuqa depression, Tarim Basin. Acta Petrolei Sinica. 35(6), 1057-1067 (in Chinese). Zhou, H.B., Liu, Y.L., Liu, J., Gu, Y.X., Zhang, J.M., Gao, N.X., 2016. Geological characteristics and vertical location of fold neutral plane in Krasu tectonic belt: A case study of S structure in Krasu tectonic belt. Petroleum Geology and Engineering. 30(3), 69-72 (in Chinese). Zhou, L., Lei, G.L., Zhou, P., Wang, W., Zhang, X., Shi, C.Q., Wang, Z.H., Zhang, Q., 2016. Fracture combination patterns and distribution of ultra-deep reservoirs beneath salt in the Kelasu structural belt. Geological Journal of China Universities. 22(4), 707-715 (in Chinese). Zhou, P., Tang, Y.G., Yin, H.W., Zhao, S.F., Mo, T., Zhang, X., Zhu, W.H., Li, C.S., 2017. Relationship between characteristics of fracture belt and production of Keshen 2 gas reservoir in Kelasu tectonic zone, Tarim Basin. Natural Gas Geoscience. 28(1), 135-144 (in Chinese). Zhou, P., Yin, H.W., Zhou, L., Tang, Y.G., Li, C.S., Zhu, W.H., Xie, Y.N., Shang, J.W., 2018. Reservoir controlling factor and forecast of tensional zone in geostrain neutral plane of faulted anticline: Example from Kelasu fold-thrust belt. Geotectonica et Metallogenia. 42(1), 50-59 (in Chinese). Zhuo, Q.G., Li, Y., Song, Y., Yang, X.Z., Zhao, M.J., Fang, S.H., Liu, S.B., 2013. Evolution of Paleogene saline deposits and effectiveness of traps in Kelasu tectonic zone, Kuqa depression, Tarim Basin. Petroleum Geology & Experiment. 35(1), 42-47 (in Chinese). Zhuo, Q.G., Zhao, M.J., Li, Y., Wang, Y., 2014. Dynamic sealing evolution and hydrocarbon accumulation of evaporate cap rocks: An example from Kuqa foreland basin thrust belt. Acta Petrolei Sinica. 35(5), 847-854 (in Chinese).

17

Gas reservoir

Bozi 1

Dabei 1

Dabei 3

Keshen 2

Keshen 5

Keshen 6

Keshen 8

Keshen 13

Temperature/ C

124.26

88.65

151.41

163.33

151.60

141.20

168.53

185.5

Formation

120.420

125.39

119.02

115.96

109.36

98.76

122.23

136.73

6976.4

5746.0

7230.6

6987.3

6697.3

6235.0

7127.7

7641.79

1.79

1.62

1.72

1.76

1.66

1.79

1.78

1.86

Gas reservoir

Stratiform

Edge-water

Edge-water

Edge-water

Edge-water

Stratiform

Stratiform

Stratiform

type

faulted-anticline

stratiform

stratiform

stratiform

stratiform

faulted-anticline

faulted-anticline

faulted-anticline

condensate

faulted-anticline

faulted-anticline

faulted-anticline

anticline

dry gas

dry gas

dry gas

gas reservoir

condensate

dry gas

dry gas

dry gas

reservoir

reservoir with

reservoir with

gas reservoir

reservoir

reservoir

reservoir

normal

normal

with high

temperature

temperature

pressure

and high

and high

pressure

pressure

o

pressure/MPa Central burial depth/m Pressure coefficient

Drive type

Edge water

Edge water

Edge water

Edge water

Edge water

Edge water

Edge water

Edge water

Height of gas

425

320

696

475

600

373

650

400

0.36

0.27

0.29

0.29

0.281

0.29

0.29

0.29

1.71

2

2.06

2.2

2.16

2.2

2.21

2.1

C1 content/%

88.61

91.78

96.99

97.4

98.72

97.8

97.8

93.70

Water type

/

CaCl2

CaCl2

CaCl2

CaCl2

CaCl2

CaCl2

CaCl2

column/m Pressure gradient MPa/100m Geothermal gradient o

C/100m