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Origin of abnormal high pressure and its relationship with hydrocarbon accumulation in the Dina 2 Gas Field, Kuqa Depression
Petroleum Research (2016) 1,93-102
Origin of abnormal high pressure and its relationship with hydrocarbon accumulation in the Dina 2 Gas Field, Kuqa Depression Fengqi Zhang1,2*, Zhenliang Wang2, Hongli Zhong3, Yubin Song4, Weiming Liu1 and Chi Wei1 School of Earth Sciences and Engineering, Xi’an Shiyou University, Xi’an 710065, China Department of Geology, Northwest University, Xi’an 710069, China 3 College of Geology & Environment, Xi'an University of Science and Technology, Xi'an 710054 , China 4 Tazhong Exploration & Development Research Management Department, Petrochina Tarim Oilfield Company, Korla 841000, China Received February 4, 2016; Accepted July 25, 2016 1 2
Abstract: Based on distribution of formation pressure by indirect estimation and formation testing, this study investigates origin of abnormal high pressure in the Dina 2 Gas Field in the Kuqa Depression in combination with the latest research findings. Contribution of major overpressure mechanisms to this gas field is estimated, and generation of the abnormal high pressure as well as its relationship with natural gas accumulation is explored. Disequilibrium compaction, tectonic stress, and overpressure transfer are the major overpressure mechanisms. Overpressure transfer resulted from vertical opening of faults and folding is the most important cause for the overpressure. Gas accumulation and abnormal high pressure generation in the reservoirs of the Dina 2 Gas Field show synchroneity. During the early oil-gas charge in the Kangcun stage, the reservoirs were generally normal pressure systems. In the Kuqa deposition stage, rapid deposition caused disequilibrium compaction and led to generation of excess pressure (approximately 5–10 MPa) in the reservoirs. During the Kuqa Formation denudation stage to the Quaternary, reservoir overpressure was greatly increased to approximately 40–50 MPa as a result of vertical pressure transfer by episodic fault activation, lateral overpressure transfer by folding and horizontal tectonic stress due to intense tectonic compression. The last stage was the major period of ultra-high pressure generation and gas accumulation in the Dina 2 Gas Field.
Key words: abnormal high pressure; overpressure transfer; tectonic compression; Dina 2 Gas Field; Kuqa Depression
1 Introduction The Dina 2 Gas Field, a major new discovery following the Kela 2 Gas Field in the Tarim Basin, is a large-scale coal-derived gas field with a reserve of 100×109 m3(Yan et al., 2009). The Dina 2 Gas Field is an ultra-high pressure gas field, which has a formation pressure of 106 MPa and pressure coefficient of 2.14–2.29 in the central part (Ma et al., 2003). This gas field has
experienced intense tectonic compression in the Late Himalayan. Previous studies indicated that the late Himalayan tectonic compression imposed strong influences on ultrahigh pressure generation in the Dina 2 Gas field (Ma et al., 2003; Sun et al., 2004; Zeng et al., 2004a; Shi et al., 2007), but these researches have mainly focused on fluid pressurization caused by tectonic stress (Zeng et al., 2004a; Shi et al., 2007). In the context of
* Corresponding author. Email: [email protected]
© 2017 Chinese Petroleum Society. Publishing Services by Elsevier B.V. on behalf of KeAi. This is an open access article under the CC BY-NC-ND license (http://creativecommons.org/licenses/by-nc-nd/4.0/). 93
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et al., 2004). The Kuqa Depression comprises several tectonic units, and the Dina 2 Gas Field lies in the eastern Qiulitage tectonic belt in the central part of the depression (Fig. 1) (Yan et al.,2009). The development and evolution of the eastern Qiulitage tectonic belt are controlled by the north-dipping thrust faults developed in its south and north: one is the Dina north fault developed in the Himalayan; the other is the eastern Qiulitage fault initiated in the Yanshanian, continuously evolving through the Himalayan, and for med the final configuration in the Late Himalayan (Yan et al., 2009). Both faults disappear upward in the gypsum mudstone sequences and cut through downward into the basement. The two faults not only control tectonic framework of the eastern Qiulitage tectonic belt but also control generation of the Dina tectonic strata. The faults connect to oil source kitchens but do not expose to the ground surface, and thus are ideal conduits for vertical oil and gas migration (Sun et al., 2004). Beneath the gypsum mudstone and salt rock sequences of the Jidike Formation, the Mesozoic - Cenozoic tectonic strata have developed fault-bend folds and duplexes. The Dina-2 structure is a fault-bend fold of sub-salt reservoirs of the Jidike Formation (Ma et al., 2003).
intense tectonic compression, overpressure transfer caused by strata deformation (e.g. folding) and episodic opening of faults can also lead to fluid pressurization (Osborne and Swarbrick, 1997; Liu, 2002; Luo, 2004a; Guo et al., 2010), which may greatly influence hydrocarbon accumulation. Presently, there is little work on the generation mechanism of ultra-high pressure and its relationship to hydrocarbon accumulation under the joint action of multi-factors in the context of tectonic compression. An in-depth study on the issues is needed, especially for the quantitative assessment and process analysis. This study examines lateral distribution of pressure in sandstone-mudstone formations in the Dina 2 Gas Field using directly measured pressure data of permeable layers and indirectly estimated pressure data in mudstone layers. Building upon some already published work, a recognition model of major overpressure mechanism is established. The origin of abnormal high pressure in the Dina 2 Gas Field is discussed. Additionally, relative contribution of major overpressure mechanisms to the present abnormal high pressure is estimated and the generation process of abnormal high pressure as well as its relationship with gas accumulation in the gas field is studied. Theses findings will improve understanding of origin of abnormal high pressure under complex effect of multi-factors in the foreland compression zones, and provide new insights into generation mechanism of overpressure in the Dina 2 Gas Field, thereby guiding regional hydrocarbon exploration.
In the Dina 2 Gas Field, source rocks are the Middle - Upper Triassic and Jurassic coal measure formations. The reservoirs are the lower Neogene Jidike Formation and the Paleogene Kumugeliemu - Suweiyi formations, mainly composed of sandstone, pebbly sandstone and siltstone. The reservoircap rock is a several hundred-meter-thick gypsum salt rock gypsum mudstone - mudstone interval of the Jidike Formation, which has strong sealing capacity and forms good reservoir-cap rock assemblages in the cross-section (Sun et al., 2004).
2 Regional setting The Dina 2 Gas Field is located in the Kuqa Depression, a Mesozoic - Cenozoic foreland basin between the southern Tianshan orogenic belt and the Tabei uplift belt (Fig. 1) (Ma
0
5km
B
DN102
DN1 DN22 DN204
A
DN201
DN203
In the Dina 2 area, the basin has experienced long-term multi-
N DN11
DN202
DN2
Basin boundary
ld G as F ie D in a 2
Second-level Well location First-level tectonic unit line tectonic unit line
Gas field
City/County
0
Fault
40km
Northern monoclinic belt
K DB 1
B a ic h
Wushi Sag
i te
Y e-
eng S
cto
nic
t bel
Baicheng
ag
Qi
150km
0
Quele 1
库尔勒
ft
YM 1
Tarim Basin
un
Upli
提5
nl M
i Ta b e
Ku ou
Aksu
p li ft
Kuqa
Xinhe
Qiulitage tectonic belt U We n s u
u
Ke - Yi tec to ni c be lt YN 2 Ke - Yi tecto nic belt DN 1 KL 2 Yangxia Sag g a DN 2 eng S B a ic h e l t b ic Yang 1 lift ton Luntai i Up tec Ta b e ge a t M ou nt ain i l Ti an sh an
nt ai n
tu Al
nM
ou
nta
in
Fig. 1 Division of tectonic units and location of the Dina 2 Gas Field in the Kuqa Depression, Tarim Basin
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stages evolution. In the Pliocene, the eastern Qiulitage tectonic belt rapidly deposited the strata (He et al., 2004). Since the Late Pliocene, intense tectonic compression occurred N- to S-trending in the basin, leading to generation of stress field of the maximum principal horizontal stress (Zeng et al., 2004b). The tectonic compression was associated with high-magnitude uplift and erosion, large-scale faulting and closely related intense fold deformation (Li et al., 2008). The above tectonic activities played a crucial role in controlling distribution and evolution of formation fluid pressure in the study area.
3 Distribution of formation test pressure The results of formation testing show that the Cretaceous, Paleogene, and Neogene formations at Dina 2 Gas Field are
Buried depth (m)
4500
5000
1.0
Pressure coefficient 1.5 2.0
4500
Well DN 11 Well DN 2 Well DN 202 Well DN 204 Well DN 102 Well DN 201
5500
6000
6500
10 4000
2.5
Buried depth (m)
0.5 4000
associated with overpressure to strong overpressure (Fig. 2). The Paleogene and Neogene formations are both associated with strong overpressure, with the pressure coefficient of 1.93–2.26 and relatively high excess pressure of 48.8–55.9 MPa. In the deep Cretaceous formations, formation testing is only performed in Well ND 11 where the pressure coefficient drops to 1.5–1.7 with corresponding excess pressure of 26–33 MPa. In the DN 2, DN 201, DN 202, and DN 204 at Dina 2 wells, excess pressure is generally within range of 52–55 MPa and occasionally at 48.8 MPa in reservoirs of the Paleogene Kumugeliemu Formation. The excess pressure is 53.5–54.5 MPa in the reservoirs of the Paleogene Suweiyi Formation and 50.8 MPa at the only pressure testing point in the reservoirs of the Neogene Jidike Formation. The above results show that the excess pressure in the Paleogene
Jidike Formation Suweiyi Formation Kumugeliemu Formation Cretaceous
(a)
5000
20
Excess pressure(MPa) 50 30 40
60
Well DN 11 Well DN 2 Well DN 202 Well DN 204 Well DN 102 Well DN 201
5500
6000
6500
Jidike Formation Suweiyi Formation Kumugeliemu Formation Cretaceous
(b)
Fig. 2 Distribution of formation testing pressure in Dina 2 Gas Field, Kuqa Depression, Tarim Basin
Kumugeliemu–Suweiyi formations is generally consistent with or slightly higher than that in the overlying Neogene Jidike Formation.
4 Origin of abnormal high pressure Overpressure generation and development mechanisms are complex and can be classified into compaction disequilibrium and unloading (Ramdhan and Goulty, 2011). Herein, unloading refers to pressurization that tends to reduce vertical effective stress. The major unloading mechanisms of overpressure are fluid expansion, tectonic stress, and overpressure transfer. Fluid expansion is primarily caused by gas generation, hydrothermal pressurization, and clay mineral dehydration (Bowers, 2002; Ramdhan and Goulty, 2011). Previous numerical simulations demonstrated that pressurization from hydrothermal pressurization and clay mineral dehydration is weak and negligible (Luo, 2000). In the widely developed source rock, gas generation can cause a wide-range of overpressure (Tingay et al., 2009). As for the reservoirs, the major unloading mechanisms of overpressure are tectonic stress and overpressure transfer.
Under action of vertical disequilibrium compaction, porosity generally remains unchanged (Fig. 3a). Variations in fluid pressure with depth approximately parallels to that of the lithostatic pressure(Tingay et al., 2009; Ramdhan and Goulty, 2011) (Fig. 3b); variations in the vertical effective stress and porosity of the overpressured formations comply with normal compaction relationship (Fig. 3c) (Tingay et al., 2009), and variation relationship should be exponential (Luo, 2004a). The variation relationship can be expressed as follows:
0 eb
(1)
Where φ 0 is the surface porosity,%; φ is the porosity at a certain depth, %; b is a constant; and δ is the effective stress at the same depth, MPa. Equation (1) can be transformed into
1 0 1eb
(2)
According to equation (2), the recognition model of Tingay et al (2009) is modified by replacing the DC trend line to the DC-X
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Pressure
Porosity
Reciprocal of porosity or acoustic velocity at the maximum depth
Li tho
Fluid sealing depth
sta tic
Unloading pressurization path
pr es
Normal compaction
su
co
m
Depth
ss u re
Depth
DC- X
M o pa dif ct ied io n p dis re eq ss ui ur lib iz ri at um io np at h
at ic p re
Overpressure transference or fluid-expansion overpressure (a)
DC
Di
Reciprocal of porosity or acoustic velocity
H y d ro st
Porosity path of disequilibrium compaction pressurization
se q pr uili es br su ium riz at com io n p pa at ctio h n
re
FE Disequilibrium compaction pressurization paralleling to lithostatic pressure curve
Overpressure transference or fluid-expansion overpressure (b)
Vertical effective stress (c)
Fig. 3 A recognition model of major overpressure mechanisms, (a) relationship between porosity and depth, (b) relationship between pressure and depth, (c) relationship between vertical effective stress and acoustic velocity (modified from Tingay et al (2009))
trend line (Fig. 3c). After fluid pressurization is caused by fluid expansion, overpressure transfer, and tectonic stress, changes in porosity related to tectonic stress may be relatively larger and those related to fluid expansion and overpressure transfer are smaller. All of the pressurization processes can contribute to reduction of the vertical effective stress. Thus, variations in the vertical effective stress and porosity of the overpressured formation should deviate from the exponential curve, as shown in the FE trend line (Fig. 3c) (Tingay et al., 2009). Accordingly, the unloading mechanism for overpressure can be recognized based on variation relationship between porosity (or acoustic velocity) and vertical effective stress of the overpressured formation.
4.1 Disequilibrium compaction Pressurization mechanism of compaction can be classified into two geological factors, the relatively thick low-permeability formation and the relatively rapid overlying load deposition (Audet and McConnell, 1992; Luo et al, 2004). The eastern Paleogene formations of the Qiulitage tectonic belt have mainly developed fan delta and lake facies, with lagoon facies locally. The Paleogene Kumugeliemu Group has a drilling thickness of 146–192 m and its average ratio of mudstone thickness-to-stratum thickness (M/S) is 40%. The Paleogene Suweiyi Formation is drilled to 184–218.5 m and its average ratio of mudstone thickness to stratum thickness is 35% (Yan et al., 2009). The Neogene Jidike Formation develops a 1400-m-thick interval of gypsum-salt rock, gypsum-mudstone, and mudstone with low permeability, thus providing a good regional seal for the Dina 2 Gas Field. The low-permeability
mudstone constitute+s an environment for abnormal pressure generation. Since the Neogene, subsidence rate of the eastern Qiulitage tectonic belt has apparently increased. The subsidence rate was <50 m/Ma in the Triassic to Paleogene, approximately 175 m/Ma in Well Dongqiu 5 adjacent to Dina-2 Gas Field in the Jidike stage, and approximately 133 m/Ma in Well Dongqiu 5 in the Kangcun stage; subsidence rate of the Yangxia Sag at southern Dina 2 Gas Field in the Kuqa stage was approximately 1286 m/Ma, and the subsidence rate of the Dina 2 Gas Field during the Kuqa stage was estimated to be approximately 1000 m/Ma (He et al., 2004). Such rapid deposition allowed generation of overpressure in the Jidike Formation as well as its underlying formation of low permeability gypsum-mudstone and mudstone. Based on analysis of mudstone compaction process, the abnormal pressure is estimated in the mudstone formation caused by disequilibrium compaction using a depth balancing method (Luo et al., 2004). The mudstone compaction curves show that in DN11, DN 22, and DN 202 wells, the acoustic travelling time difference starts to deviate from normal compaction trend line from the Jidike Formation (Fig. 4), and abnormal high pressure exists in the mudstone. The generation of abnormal high pressure in mudstone is generally related to regional deposition of large intervals of thick mudstone formation, and the rapid deposition during the Kuqa stage led to generation of abnormal high pressure in the mudstone. The upper boundary of the abnormal pressure belt at Dina2, is basically that of the Jidike Formation, which is widely distributed (Fig. 5). The magnitude of excess pressure in the
100 95 75
25 5 0
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4.2 Pressurization of tectonic stress
mudstone of the upper Jidike Formation is relatively large, with the maximum pressure coefficient generally within range of 1.6– 1.7 and the maximum excess pressure up to 25 MPa. In certain wells such as Well DN 11, the maximum pressure coefficient of the upper mudstone of the Jidike Formation is up to 1.8–2.0 and the maximum excess pressure reaches 45 MPa (Fig. 5). The excess pressure declines to 5–15 MPa in the mudstone of the lower Jidike Formation and Paleogene to Cretaceous formations, with the pressure coefficient generally in the range of 1.1–1.3.
Being a major overpressure mechanism, tectonic stress has received substantial attention in recent years, however, related studies on tectonic stress have primarily focused on qualitative evaluations with few quantitative evaluations of overpressure mechanism (Berry, 1973; Osborne and Swarbrick, 1997; Luo et al., 2004; Wang et al., 2005; Bilotti and Shaw, 2005; Feyzullayev and Lerche, 2009). Tectonic stress does not act
Pressure (MPa) Acoustic travel time (µs/m) Pressure (MPa) Acoustic travel time (µs/m) Pressure (MPa) Acoustic travel time (µs/m) 200 400 600 -40 0 40 80 120 100 200 400 600 -40 0 40 80 120 100 200 400 600 -40 0 40 80 120 100 600
4200
E 2-3 s E 1-2 km K 1 bs Formation testing pressure (a)
re
Depth /m
re Hy dro sta tic pre ssu
N1j
Hy dro sta tic pre ssu
Depth(m)
re Hy dro sta tic pre ssu
3600
N 1-2 k 3000
3600
4200
N1j
4800 4800 E 2-3 s E 1-2 km
5400 (b)
ss u re
6000
3000
2400
at ic p re
5400
N 1-2 k
ss u re
4800
2400
at ic p re
4200
L it h o st
ss u re
N 1-2 k
1800
1800
a ti c p re
3000
N2k
L it h o st
L it h o st
2400
3600
1200
1200 N 2 k
1800 N 2 k
Depth(m)
600
600
1200
N1j
E 2-3 s E 1-2 km K 1 bs Formation testing pressure (c)
Fig. 4 The compaction curves and lateral pressure distribution in the Well DN 11 (a), Well DN 22 (b), and Well DN 202 (c) of the Dina 2 Gas Field in the Kuqa Depression, Tarim Basin. N2k is Pliocene Kuqa Formation; N1-2k is Mioc ene-Pliocene Kangcun Formation; N1j is Miocene Jidike Formation; E 2-3s is Eocene-Oligocene Suweiyi Formation; E1-2km is Paleocene-Eocene Kumugeliemu Formation; K1bs is Lower Cretaceous Bashijiqike Formation.
A 1500 1000 500
Excess pressure (MPa) 0
20
40
Excess pressure (MPa) 0
20
40
Excess pressure Excess pressure Excess pressure (MPa) (MPa) (MPa) 0 20 40 0 20 0 20 40
Excess pressure Excess pressure (MPa) (MPa) 0 20 40 0 20
0
Q+N 2 k
B
5km
0
Elevation (m)
- 500 - 1000
N1-2k
- 1500 - 2000 - 2500
N1j
Top of overpressure
- 3000 E2-3s E 1 - 2 km
- 3500 - 4000 - 4500
Well DN203
Well DN204
Well DN201
Well DN22
Well DN202 Well DN102 Well DN11
Fig. 5 The distribution of the top of overpressure in the Dina 2 Gas Field, Kuqa Depression, Tarim Basin. Section location sees Fig.1.
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directly on sediment particles but function through compaction of the formation pressure. Thus, the action of tectonic stress to formation pressure is considered to be lateral compaction (Osborne and Swarbrick, 1997; Luo et al., 2007). During the late Himalayan, the maximum principal stress in the study area changed direction to horizontal. The tectonic deformation at the southern Tianshan Mountains and the basinmountain boundary was dominated by nearly N-S-trending compressional deformation, whereas in the Kuqa Depression, nearly NS- and NW-SE-trending compressional deformation was the dominating tectonic deformation (Wang et al., 2003). The maximum effective principal stress in the Late Himalayan was investigated by the acoustic emission experiments (Zeng et al., 2004b; Zhang et al., 2004). Comparative analysis demonstrated that the horizontal effective principal stress was greater than the vertical effective principal stress, proving that the Kuqa Depression experienced intense tectonic compression in the late Himalayan. Tectonic stress accomplished compaction through lateral compaction, which, combined with vertical compaction, led to generation of obvious abnormal pressure in the Jidike Formation (pressure coefficient up to 2.0, excess pressure up to 45 MPa). The abnormal pressure resulted from tectonic compaction of mudstone is relatively low in other formations (Fig. 4). Assuming that the maximum excess pressure generated by total compaction of the Jidike Formation is completely transferred to the underlying formation, it is still insufficient to generate such high excess pressure at Dina 2 Gas Field (Fig. 2). When comparing the measured pressure of sandstone layer and the compaction curve estimated pressure of the adjacent mudstone layer in the same well, great differences between two sets of data are observed: the measured pressure of sandstone layer is generally greater than the calculated pressure of mudstone layer (Fig. 4). Based on the concept of tectonic compaction, previous work has established a quantitative evaluation model for f luid pressurization caused by tectonic compaction under actual formation conditions (Zhang et al., 2011)
Δp = ξ (σ 1 − S)
(3)
Where Δp is the fluid pressurization caused by tectonic stress, MPa; σ1is the largest horizontal principal stress, MPa; S is the load prior to pressurization, MPa; ζ is the sealing coefficient that measures the actual sealing ability of the underground geologic body (0–1; 0 represents a completely open fluid system, and 1 represents a completely sealed fluid system). The evaluation results show that fluid pressurization caused by tectonic stress in the Cretaceous formations is relatively small in the Well DN 201 (1.2 MPa) and Well DN 202 (1.3 MPa) (Zhang et al., 2011). Following equation (3), the fluid pressurizeation caused by tectonic stress in the Cretaceous
98
formations in the Well DN 204 is estimated to be approximately 1. 5 MPa. The maximum horizontal principal stress of the Cretaceous formations in the Well DN 11 and Well DN101 are less than the overlying loads, indicating that the tectonic stress in the Cretaceous formation of the DN 1 anticline at eastern Dina 2 Gas Field basically causes no fluid pressurization. As for the Cretaceous and Paleogene reservoirs at the same tectonic position and with the same tectonic morphology, the fluid pressurization caused by tectonic stress is quite similar. Overall, the fluid pressurization caused by tectonic stress in the Paleogene reservoirs at Dina area is low, e.g., <2 MPa, whereas the tectonic stress in the DN 1 anticline basically causes no fluid pressurization.
4.3 Pressurization of overpressure transfer Previous studies on the overpressure generation mechanism have found that over pressure transfer has played an important role in the generation of abnormal high pressure in the Brunei Baram region, and China’s Junggar, Bohai Bay and Yingge Sea basins (Audet and McConnell, 1992; Liu, 2002; Luo, 2004b; Tingay et al., 2009; Guo et al., 2010). Folding can cause ununiform changes in the overlying load along the horizontal direction, whereas different generation conditions of formation pressure in the lateral direction lead to fluctuations of formation depth. Formations sharing the same permeability are in contact with those of different excess pressures, resulting in generation of fluid pressure and lateral fluid migration (Luo et al., 2004). Deep overpressure will drive fluid migration up-dip and thus overpressure transfer, leading to generation of overpressure in the up-dip part of permeable sand bodies (Liu, 2002). When a fault cuts through two overpressure systems with different excess pressures, reactivation of the fault will allow fluid to flow along the fault conduits, thereby rapidly adjust excess pressure and lead shallow formation (previously with low excess pressure) to form relatively high overpressure (Osborne and Swarbrick, 1997; Liu, 2002; Luo, 2004a; Guo et al., 2010). The Dina 2 structure is a fault-bend fold of sub-salt reservoirs of the Jidike Formation, which has oil-bearing faults developed in the south and north sides. The formation of folds could cause the lateral overpressure transfer in the sub-salt reservoirs of the Jidike Formation that shared the same permeability and pressurization of the excess pressure in the upper reservoirs of the anticline with the same permeability (Fig. 6). Oil and gas sources were accumulated the Middle - Upper Triassic and Jurassic formations. Rapid burial in the Pliocene to Quaternary led to fast hydrocarbon generation of the Triassic and Jurassic source rocks (Sun et al., 2004). The process of hydrocarbon generation caused fluid pressure increases in the source rock formation (Barker, 1990; Osborne and Swarbrick, 1997). During the rapid burial period, the deep source rock formations and the upper Paleogene to Neogene formations
F.Zhang et al./Petroleum Research (2016) 1,93-102
Well YN2
Well DN202 0
5km Q +N 2 k
Elevation (km)
0
N1j
N 1-2 k
-1.0 -2.0
E N1j
-3.0 -4.0 -5.0 -6.0
N
E K
E
K
J
J T
J T
K
T
Overpressure transfer direction
Fault
Fig. 6 Overpressure transfer in the north-south section of the Dina 2 structure, in the Dina 2 Gas Field, Kuqa Depression (Sun et al., 2004)
The overpressure that is caused by overpressure transfer via fault connection can be evaluated in view of following geological phenomena: (1) a hydrostatic pressure gradient is maintained between the upper and lower formations connected by faults; (2) pressure coefficient of the shallow formation is extremely high; (3) great pressure difference between permeable formation and wall rock; and (4) a thin upper transition zone of the overpressured formations (Luo, 2004b). In the Dina 2 Gas Field, the excess pressure occurs in the sub-salt Paleogene and Neogene reservoirs of the Jidike Formation. The Dina 2 structure is relatively low. Excluding one point of the Neogene Jidike Formation in the Dina 2 Gas Field, all of testing points have excess pressure <3 MPa (Fig. 2). The upper and lower formations connected by faults generally maintain a hydrostatic pressure gradient. Sub-salt reservoirs of the Jidike Formation in the Dina 2 structure have an extremely high pressure coefficient, and shallow reservoirs have an even greater pressure coefficient than deep reservoirs (Fig. 2). As compared to the surrounding mudstone, the sub-salt reservoir of the Jidike Formation in the Dina 2 structure has relatively the large excess pressure (Fig. 4). All above observations suggest that overpressure transfer of the Dina 2 structure along faults is one of the key mechanisms for the abnormal high pressure generation in the sub-salt reservoirs of the Jidike Formation. With the measured geological data of the Dina 2 Gas Field, a
normal compaction fitted trend line is achieved with vertical effective stress and acoustic velocity of normal compaction points, and then projections of the vertical effective stress and acoustic velocity of the abnormal pressure points are done in a coordinate system. The results show that the data points of the vertical effective stress vs acoustic velocity apparently deviate from the normal compaction trend line, and degree of deviation is quite large (Fig. 7). 6.0 5.5
Acoustic velocity(km/s)
were subject to pressurization of hydrocarbon generation in addition to the similar pressurized conditions. Therefore, the deep source rock formations formed greater excess pressure than the overlying formations during the rapid burial period. During the intense tectonic compression in the late Himalayan, the faults experienced episodic opening and each opening event would allow rapid adjustment between the relatively high excess pressure in the deep source rock of overpressure system and the relatively low excess pressure in sub-salt reservoirs of the Jidike Formation. That is, the vertical overpressure transfer occurred and thus increased the excess pressure in the sub-salt reservoirs of the Jidike Formation. Such pressurization process was commonly associated with lateral transfer (Fig. 6).
5.0 4.5 4.0 Normal pressure point Abnormal pressure point in well DN11 Abnormal pressure point in well DN204 Abnormal pressure point in well DN102 Abnormal pressure point in well DN201 Abnormal pressure point in well DN202 Normal compaction trend line
3.5 3.0 2.5 2.0
0
10
40 30 20 Vertical effective stress (MPa)
50
60
Fig. 7 The relationship between the effective stress and the acoustic velocity of overpressured formations in the Dina 2 Gas Field of the Kuqa Depression
Based on the above analysis, the tectonic stress and overpressure transfer jointly are considered to cause the fluid pressurization in the sub-salt reservoirs of the Jidike Formation. Assuming that after the late Himalayan fluid pressurization caused by unloading, the formation porosity was unchanged, then the corresponding acoustic velocity remained basically unchanged as well. With this hypothesis, the reduction of vertical effective stress resulted from fluid pressurization by tectonic stress and the overpressure transfer can be quantified. The reduction of the vertical effective stress is due to the fluid pressurization caused by the tectonic stress and overpressure transfer (Table 1). Results show that the overpressure transfer caused relatively large fluid pressurization, generally in the range of 40–50 MPa, accounting for 65%–90% of the measured excess pressure with an average of 81.2% (Table 1). The pressurized hydraulic fluid caused by the compaction and horizontal tectonic stress can be obtained from the excess pressure in the adjacent mudstone formations (Table 1). As compared to the measured excess pressure, sum of estimated pressurization generated by different mechanisms has an absolute error <8 MPa (generally <5 MPa) and an relative error <15% (generally <10%). The estimates of pressurization generated via different overpressure mechanisms generally show small differences from the measured excess pressures, thus are considered reliable. According to the estimated fluid pressurization generated by different overpressure mechanisms,
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Table 1 Estimation of fliud pressurization generated by different overpressure mechanisms in some typical wells of the Dina 2 Gas Field, Kuqa Depression Well
Ratio between overpressure Absolute error between sum Testing Formation Measured excess Effective stress Acoustic velocity Overpressure transfer Tectonic stress Adjacent mudstone transfer pressurization and pressurization and measured depth (m) pressure (MPa) pressure (MPa) (MPa) (km/s) pressurization (MPa) pressurizzation (MPa) excess pressure (MPa) measured excess pressure (%) excess pressure (MPa)
DN 11
5768.48
112.14
52.16
20.71
5.17
39.70
0
12.42
76.11
DN 11
5336.33
110.97
55.48
11.93
4.76
36.69
0
12.65
66.13
-6.14
DN 204
5154.63
107.99
54.38
10.73
5.08
45.74
1.5
5.37
84.11
-1.77
DN 204
5318.49
107.52
52.21
14.97
5.17
43.93
1.5
4.69
84.14
-2.09
DN 102
5699.73
108.10
48.83
23.16
5.44
44.81
0
4.21
91.75
0.18
DN 102
5508.09
111.25
53.97
15.60
5.35
49.80
0
7.48
92.27
3.31
DN 201
4975.03
105.92
54.19
8.65
5.00
45.72
1.2
9.12
84.37
1.85
DN 201
4987.84
106.34
54.47
8.53
5.08
48.24
1.2
10.57
88.56
5.53
DN 202
5159.65
109.61
55.96
9.21
4.92
42.70
1.3
7.11
76.30
-4.85
DN 202
5060.85
106. 16
53.53
10.40
4.69
34.67
1.3
9.81
64.77
-7.75
DN 202
4964.36
105.39
53.77
8.94
5.00
45.33
1.3
8.16
84.30
1.03
the overpressure transfer appears to be the major cause for the overpressure in the Dina 2 Gas Field.
5 G enerat ion proce ss of abnor mal high pressure and its relationship with hydrocarbon accumulation Previous studies have investigated hydrocarbon accumulation in the Kuqa Depression, and a two-stage accumulation model was proposed with an early oil accumulation followed by a late gas charge. It has been suggested that the Early Miocene (23–12 Ma) was the major oil accumulation period, whereas the Pliocene (5–0 Ma), especially the Kuqa stage (2.5 Ma) was the major gas accumulation period (Liang et al., 2002; Zhao and Lu, 2003). Additionally, a three-stage hydrocarbon accumulation model has also been proposed as follows: Neogene early - middle Kangcun stage (17–10 Ma), late Kangcun stage to early - middle Kuqa stage (10–3 Ma), and late Kuqa stage to Late Quaternary period (3–1 Ma) (Zhao and Dai, 2002). The results of the K-Ar isotope dating analysis with two authigenic illite samples from the Paleogene sandstone reservoir in Well DN 22 showed that ages of the illite are 11.3 ± 1.4 and 10.4 ± 1.2 Ma, corresponding to the middle Kangcun stage. The results of previous analyses of the hydrocarbon generation history indicated that the Middle - Upper Triassic source rock in the Yangxia Sag entered the early maturity stage in the Paleogene, peak oil generation stage in the Neogene - Late Miocene (approximately 5 Ma), and overmaturity stage since the Pliocene - Quaternary due to a rapid burial. The Jurassic source rock entered the peak oil generation period in the Neogene - Late Miocene, mature and over-mature in the Pliocene - Quaternary, and peak gas generation in the Late Pliocene (Sun et al., 2004). In summary, the Dina 2 Gas Field experienced an early oil-gas charge during the Kangcun stage, and a late natural gas charge mainly in the late Kuqa stage (5 Ma). The latter appears to be the key hydrocarbon accumulation period for the Dina 2 Gas Field. In the late Kangcun stage, a low-magnitude structure was
100
-0.04
formed in the Dina area and the deep source rock formation entered peak oil generation stage. Hydrocarbon generation led to formation of abnormal high pressure, and high-pressure oilgas was charged into the upper sub-salt reservoirs of the Jidike Formation. Despite the excellent sealing capacity of the gypsumsalt rocks of the Jidike Formation, the Dina low-magnitude structure had good reservoir properties such as porosity, permeability and lateral continuity, thus had poor lateral sealing of the reservoir. After the high-pressure oil and gas was charged into reservoirs of the Dina low-magnitude structure, it was difficult to generate abnormal high pressure and reservoirs retained normal pressure system due to poor lateral sealing. In this period, low-magnitude structural oil-gas reservoirs were formed (Fig. 8a). In the Kuqa stage, deep source rock entered into mature and over mature stages. Undercompaction and hydrocarbon generation led to generation of ultra-high pressure with great excess pressure. Due to rapid deposition, the gypsum-salt rocks of the overlying Jidike Formation formed relatively high abnormal pressure, thereby enhancing its sealing capacity. In the sub-salt reservoirs of the Jidike Formation, a relatively sealed system was formed under effects of diagenesis, lateral sealing of faults, and vertical sealing of cap rocks. Compaction disequilibrium resulted in a low magnitude of excess pressure (approximately 5–10 MPa). During this period, tectonic activity was not intense and reactivation of faults was relatively weak. The deep high-pressure gas could only slowly charge into the sub-salt reservoirs of the Jidike Formation along faults, without producing the overpressure transfer. Therefore, only a low magnitude of overpressure was formed in the sub-salt reservoirs of the Jidike Formation in this period, and the previously formed low-magnitude structural oil-gas reservoirs were subject to slow gas flushing by deep natural gas, thus remaining as lowmagnitude oil-gas reservoirs (Fig. 8b). During denudation stage of the Kuqa Formation to the Quaternary, the study area experienced intense tectonic compression and episodic opening of faults. Deep source rock formations generated even higher excess pressure due to gas
F.Zhang et al./Petroleum Research (2016) 1,93-102
Gypsum salt rock
N1-2k
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N1j
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N2k
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k s -2 E 2 -3 E 1
K
E 2-3 s
E 1-2km K J
J
m
T
T
(c)
Fig. 8 Hydrocarbon accumulation model of the Dina 2 Gas Field from middle–late Kangcun stage (a), Kuqa stage (b) to denudation stage of Kuqa Formation–Quaternary (c) in the Kuqa Depression
generation. The resulting overpressured natural gas was charged into the upper reservoirs with the lower excess pressure, and the overpressure transfer led to increases in the excess pressure in the upper sub-salt reservoirs. As faults might have experienced multi-stage openings, the vertical overpressure transfer would cause multiple-f luid pressurization in the upper sub-salt reservoirs. During this period, intense tectonic compression resulted in stratigraphic deformation and folding, which caused lateral overpressure transfer into the reservoirs. Additionally, the lateral compaction of relatively large horizontal tectonic stress enhanced the compaction disequilibrium. All above conditions would increase magnitude of abnormal pressure in the sub-salt reservoirs of the Jidike Formation. In summary, under action of intense tectonic compression, the vertical overpressure transfer formed by episodic opening of faults, the lateral overpressure transfer caused by folding, and the horizontal tectonic stress significantly increased magnitude of abnormal pressure in sub-salt reservoirs of the Jidike Formation during the Kuqa Formation denudation stage to the Quaternary, and formed an excess pressure of approximately 40–50 MPa. This stage was the major period of ultra-high pressure generation in the Dina 2 Gas Field. Additionally, the intense tectonic compression led to formation of the large-magnitude faulted anticline structure
in this field, and rapid charge of deep overpressured-gas transformed the pre-existing oil-gas reservoirs into the present Dina 2 gas reservoirs (Fig. 8c).
6 Conclusions (1) The major generation mechanisms of abnormal high pressure in the Dina 2 Gas Field include disequilibrium compaction, tectonic stress, and overpressure transfer. The overpressure transfer resulted from vertical opening of faults and folding are the primary causes for the abnormal high pressure in this gas field with an estimated contribution of 65–90%. (2) The reservoirs of the Dina 2 Gas Field were a normal pressure system during the early oil-gas charge in the Kangcun stage (17-5Ma). During the Kuqa stage (5-2Ma), a rapid deposition caused compaction disequilibrium and formed an excess pressure of approximately 5–10 MPa. During denudation stage of the Kuqa Formation to the Quaternary, vertical overpressure transfer from episodic opening of faults, the lateral overpressure transfer due to folding, and the lateral tectonic stress under an intense tectonic compression setting significantly increased magnitude of the abnormal pressure in the sub-salt reservoirs of the Jidike Formation and formed an excess pressure of approximately 40–50 MPa. This is the major overpressure generation period for the Dina 2 Gas Field. (3) The present Dina 2 gas reservoirs were formed along with generation of ultra-high pressure in the reservoir formations, that is, the two processes were synchronous. The field area formed the normal pressure reservoirs in the low magnitude anticline during the late Kangcun stage (10-5Ma), the low overpressure reservoirs in the low magnitude anticline during the Kuqa stage, and the ultra-high pressure natural gas reservoirs in the large magnitude anticline during the denudation stage of the Kuqa Formation to the Quaternary.
Acknowledgements The authors would like to thank Yan Song, Mengjun Zhao, Shaobo Liu, Shihu Fang, Qingong Zhuo, Qingyang Meng, Lin Jiang, and Xuesong Lu from PetroChina Exploration & Development Research Institute for their guidance and advice, and the Research Institute of Exploration and Development of the Tarim Oilfield Company for research assistance and logistic support. This work was funded by National Science and Technology Major Project of China (Grant No. 2008ZX05003, 2011ZX05003001).
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Origin of abnormal high pressure and its relationship with hydrocarbon accumulation in the Dina 2 Gas Field, Kuqa Depression Fengqi Zhang1,2*, Zhenliang Wang2, Hongli Zhong3, Yubin Song4, Weiming Liu1 and Chi Wei1 School of Earth Sciences and Engineering, Xi’an Shiyou University, Xi’an 710065, China Department of Geology, Northwest University, Xi’an 710069, China 3 College of Geology & Environment, Xi'an University of Science and Technology, Xi'an 710054 , China 4 Tazhong Exploration & Development Research Management Department, Petrochina Tarim Oilfield Company, Korla 841000, China Received February 4, 2016; Accepted July 25, 2016 1 2
Abstract: Based on distribution of formation pressure by indirect estimation and formation testing, this study investigates origin of abnormal high pressure in the Dina 2 Gas Field in the Kuqa Depression in combination with the latest research findings. Contribution of major overpressure mechanisms to this gas field is estimated, and generation of the abnormal high pressure as well as its relationship with natural gas accumulation is explored. Disequilibrium compaction, tectonic stress, and overpressure transfer are the major overpressure mechanisms. Overpressure transfer resulted from vertical opening of faults and folding is the most important cause for the overpressure. Gas accumulation and abnormal high pressure generation in the reservoirs of the Dina 2 Gas Field show synchroneity. During the early oil-gas charge in the Kangcun stage, the reservoirs were generally normal pressure systems. In the Kuqa deposition stage, rapid deposition caused disequilibrium compaction and led to generation of excess pressure (approximately 5–10 MPa) in the reservoirs. During the Kuqa Formation denudation stage to the Quaternary, reservoir overpressure was greatly increased to approximately 40–50 MPa as a result of vertical pressure transfer by episodic fault activation, lateral overpressure transfer by folding and horizontal tectonic stress due to intense tectonic compression. The last stage was the major period of ultra-high pressure generation and gas accumulation in the Dina 2 Gas Field.
Key words: abnormal high pressure; overpressure transfer; tectonic compression; Dina 2 Gas Field; Kuqa Depression
1 Introduction The Dina 2 Gas Field, a major new discovery following the Kela 2 Gas Field in the Tarim Basin, is a large-scale coal-derived gas field with a reserve of 100×109 m3(Yan et al., 2009). The Dina 2 Gas Field is an ultra-high pressure gas field, which has a formation pressure of 106 MPa and pressure coefficient of 2.14–2.29 in the central part (Ma et al., 2003). This gas field has
experienced intense tectonic compression in the Late Himalayan. Previous studies indicated that the late Himalayan tectonic compression imposed strong influences on ultrahigh pressure generation in the Dina 2 Gas field (Ma et al., 2003; Sun et al., 2004; Zeng et al., 2004a; Shi et al., 2007), but these researches have mainly focused on fluid pressurization caused by tectonic stress (Zeng et al., 2004a; Shi et al., 2007). In the context of
* Corresponding author. Email: [email protected]
© 2017 Chinese Petroleum Society. Publishing Services by Elsevier B.V. on behalf of KeAi. This is an open access article under the CC BY-NC-ND license (http://creativecommons.org/licenses/by-nc-nd/4.0/). 93
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et al., 2004). The Kuqa Depression comprises several tectonic units, and the Dina 2 Gas Field lies in the eastern Qiulitage tectonic belt in the central part of the depression (Fig. 1) (Yan et al.,2009). The development and evolution of the eastern Qiulitage tectonic belt are controlled by the north-dipping thrust faults developed in its south and north: one is the Dina north fault developed in the Himalayan; the other is the eastern Qiulitage fault initiated in the Yanshanian, continuously evolving through the Himalayan, and for med the final configuration in the Late Himalayan (Yan et al., 2009). Both faults disappear upward in the gypsum mudstone sequences and cut through downward into the basement. The two faults not only control tectonic framework of the eastern Qiulitage tectonic belt but also control generation of the Dina tectonic strata. The faults connect to oil source kitchens but do not expose to the ground surface, and thus are ideal conduits for vertical oil and gas migration (Sun et al., 2004). Beneath the gypsum mudstone and salt rock sequences of the Jidike Formation, the Mesozoic - Cenozoic tectonic strata have developed fault-bend folds and duplexes. The Dina-2 structure is a fault-bend fold of sub-salt reservoirs of the Jidike Formation (Ma et al., 2003).
intense tectonic compression, overpressure transfer caused by strata deformation (e.g. folding) and episodic opening of faults can also lead to fluid pressurization (Osborne and Swarbrick, 1997; Liu, 2002; Luo, 2004a; Guo et al., 2010), which may greatly influence hydrocarbon accumulation. Presently, there is little work on the generation mechanism of ultra-high pressure and its relationship to hydrocarbon accumulation under the joint action of multi-factors in the context of tectonic compression. An in-depth study on the issues is needed, especially for the quantitative assessment and process analysis. This study examines lateral distribution of pressure in sandstone-mudstone formations in the Dina 2 Gas Field using directly measured pressure data of permeable layers and indirectly estimated pressure data in mudstone layers. Building upon some already published work, a recognition model of major overpressure mechanism is established. The origin of abnormal high pressure in the Dina 2 Gas Field is discussed. Additionally, relative contribution of major overpressure mechanisms to the present abnormal high pressure is estimated and the generation process of abnormal high pressure as well as its relationship with gas accumulation in the gas field is studied. Theses findings will improve understanding of origin of abnormal high pressure under complex effect of multi-factors in the foreland compression zones, and provide new insights into generation mechanism of overpressure in the Dina 2 Gas Field, thereby guiding regional hydrocarbon exploration.
In the Dina 2 Gas Field, source rocks are the Middle - Upper Triassic and Jurassic coal measure formations. The reservoirs are the lower Neogene Jidike Formation and the Paleogene Kumugeliemu - Suweiyi formations, mainly composed of sandstone, pebbly sandstone and siltstone. The reservoircap rock is a several hundred-meter-thick gypsum salt rock gypsum mudstone - mudstone interval of the Jidike Formation, which has strong sealing capacity and forms good reservoir-cap rock assemblages in the cross-section (Sun et al., 2004).
2 Regional setting The Dina 2 Gas Field is located in the Kuqa Depression, a Mesozoic - Cenozoic foreland basin between the southern Tianshan orogenic belt and the Tabei uplift belt (Fig. 1) (Ma
0
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In the Dina 2 area, the basin has experienced long-term multi-
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i Ta b e
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u
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nt ai n
tu Al
nM
ou
nta
in
Fig. 1 Division of tectonic units and location of the Dina 2 Gas Field in the Kuqa Depression, Tarim Basin
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stages evolution. In the Pliocene, the eastern Qiulitage tectonic belt rapidly deposited the strata (He et al., 2004). Since the Late Pliocene, intense tectonic compression occurred N- to S-trending in the basin, leading to generation of stress field of the maximum principal horizontal stress (Zeng et al., 2004b). The tectonic compression was associated with high-magnitude uplift and erosion, large-scale faulting and closely related intense fold deformation (Li et al., 2008). The above tectonic activities played a crucial role in controlling distribution and evolution of formation fluid pressure in the study area.
3 Distribution of formation test pressure The results of formation testing show that the Cretaceous, Paleogene, and Neogene formations at Dina 2 Gas Field are
Buried depth (m)
4500
5000
1.0
Pressure coefficient 1.5 2.0
4500
Well DN 11 Well DN 2 Well DN 202 Well DN 204 Well DN 102 Well DN 201
5500
6000
6500
10 4000
2.5
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0.5 4000
associated with overpressure to strong overpressure (Fig. 2). The Paleogene and Neogene formations are both associated with strong overpressure, with the pressure coefficient of 1.93–2.26 and relatively high excess pressure of 48.8–55.9 MPa. In the deep Cretaceous formations, formation testing is only performed in Well ND 11 where the pressure coefficient drops to 1.5–1.7 with corresponding excess pressure of 26–33 MPa. In the DN 2, DN 201, DN 202, and DN 204 at Dina 2 wells, excess pressure is generally within range of 52–55 MPa and occasionally at 48.8 MPa in reservoirs of the Paleogene Kumugeliemu Formation. The excess pressure is 53.5–54.5 MPa in the reservoirs of the Paleogene Suweiyi Formation and 50.8 MPa at the only pressure testing point in the reservoirs of the Neogene Jidike Formation. The above results show that the excess pressure in the Paleogene
Jidike Formation Suweiyi Formation Kumugeliemu Formation Cretaceous
(a)
5000
20
Excess pressure(MPa) 50 30 40
60
Well DN 11 Well DN 2 Well DN 202 Well DN 204 Well DN 102 Well DN 201
5500
6000
6500
Jidike Formation Suweiyi Formation Kumugeliemu Formation Cretaceous
(b)
Fig. 2 Distribution of formation testing pressure in Dina 2 Gas Field, Kuqa Depression, Tarim Basin
Kumugeliemu–Suweiyi formations is generally consistent with or slightly higher than that in the overlying Neogene Jidike Formation.
4 Origin of abnormal high pressure Overpressure generation and development mechanisms are complex and can be classified into compaction disequilibrium and unloading (Ramdhan and Goulty, 2011). Herein, unloading refers to pressurization that tends to reduce vertical effective stress. The major unloading mechanisms of overpressure are fluid expansion, tectonic stress, and overpressure transfer. Fluid expansion is primarily caused by gas generation, hydrothermal pressurization, and clay mineral dehydration (Bowers, 2002; Ramdhan and Goulty, 2011). Previous numerical simulations demonstrated that pressurization from hydrothermal pressurization and clay mineral dehydration is weak and negligible (Luo, 2000). In the widely developed source rock, gas generation can cause a wide-range of overpressure (Tingay et al., 2009). As for the reservoirs, the major unloading mechanisms of overpressure are tectonic stress and overpressure transfer.
Under action of vertical disequilibrium compaction, porosity generally remains unchanged (Fig. 3a). Variations in fluid pressure with depth approximately parallels to that of the lithostatic pressure(Tingay et al., 2009; Ramdhan and Goulty, 2011) (Fig. 3b); variations in the vertical effective stress and porosity of the overpressured formations comply with normal compaction relationship (Fig. 3c) (Tingay et al., 2009), and variation relationship should be exponential (Luo, 2004a). The variation relationship can be expressed as follows:
0 eb
(1)
Where φ 0 is the surface porosity,%; φ is the porosity at a certain depth, %; b is a constant; and δ is the effective stress at the same depth, MPa. Equation (1) can be transformed into
1 0 1eb
(2)
According to equation (2), the recognition model of Tingay et al (2009) is modified by replacing the DC trend line to the DC-X
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Pressure
Porosity
Reciprocal of porosity or acoustic velocity at the maximum depth
Li tho
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sta tic
Unloading pressurization path
pr es
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su
co
m
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ss u re
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M o pa dif ct ied io n p dis re eq ss ui ur lib iz ri at um io np at h
at ic p re
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DC
Di
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H y d ro st
Porosity path of disequilibrium compaction pressurization
se q pr uili es br su ium riz at com io n p pa at ctio h n
re
FE Disequilibrium compaction pressurization paralleling to lithostatic pressure curve
Overpressure transference or fluid-expansion overpressure (b)
Vertical effective stress (c)
Fig. 3 A recognition model of major overpressure mechanisms, (a) relationship between porosity and depth, (b) relationship between pressure and depth, (c) relationship between vertical effective stress and acoustic velocity (modified from Tingay et al (2009))
trend line (Fig. 3c). After fluid pressurization is caused by fluid expansion, overpressure transfer, and tectonic stress, changes in porosity related to tectonic stress may be relatively larger and those related to fluid expansion and overpressure transfer are smaller. All of the pressurization processes can contribute to reduction of the vertical effective stress. Thus, variations in the vertical effective stress and porosity of the overpressured formation should deviate from the exponential curve, as shown in the FE trend line (Fig. 3c) (Tingay et al., 2009). Accordingly, the unloading mechanism for overpressure can be recognized based on variation relationship between porosity (or acoustic velocity) and vertical effective stress of the overpressured formation.
4.1 Disequilibrium compaction Pressurization mechanism of compaction can be classified into two geological factors, the relatively thick low-permeability formation and the relatively rapid overlying load deposition (Audet and McConnell, 1992; Luo et al, 2004). The eastern Paleogene formations of the Qiulitage tectonic belt have mainly developed fan delta and lake facies, with lagoon facies locally. The Paleogene Kumugeliemu Group has a drilling thickness of 146–192 m and its average ratio of mudstone thickness-to-stratum thickness (M/S) is 40%. The Paleogene Suweiyi Formation is drilled to 184–218.5 m and its average ratio of mudstone thickness to stratum thickness is 35% (Yan et al., 2009). The Neogene Jidike Formation develops a 1400-m-thick interval of gypsum-salt rock, gypsum-mudstone, and mudstone with low permeability, thus providing a good regional seal for the Dina 2 Gas Field. The low-permeability
mudstone constitute+s an environment for abnormal pressure generation. Since the Neogene, subsidence rate of the eastern Qiulitage tectonic belt has apparently increased. The subsidence rate was <50 m/Ma in the Triassic to Paleogene, approximately 175 m/Ma in Well Dongqiu 5 adjacent to Dina-2 Gas Field in the Jidike stage, and approximately 133 m/Ma in Well Dongqiu 5 in the Kangcun stage; subsidence rate of the Yangxia Sag at southern Dina 2 Gas Field in the Kuqa stage was approximately 1286 m/Ma, and the subsidence rate of the Dina 2 Gas Field during the Kuqa stage was estimated to be approximately 1000 m/Ma (He et al., 2004). Such rapid deposition allowed generation of overpressure in the Jidike Formation as well as its underlying formation of low permeability gypsum-mudstone and mudstone. Based on analysis of mudstone compaction process, the abnormal pressure is estimated in the mudstone formation caused by disequilibrium compaction using a depth balancing method (Luo et al., 2004). The mudstone compaction curves show that in DN11, DN 22, and DN 202 wells, the acoustic travelling time difference starts to deviate from normal compaction trend line from the Jidike Formation (Fig. 4), and abnormal high pressure exists in the mudstone. The generation of abnormal high pressure in mudstone is generally related to regional deposition of large intervals of thick mudstone formation, and the rapid deposition during the Kuqa stage led to generation of abnormal high pressure in the mudstone. The upper boundary of the abnormal pressure belt at Dina2, is basically that of the Jidike Formation, which is widely distributed (Fig. 5). The magnitude of excess pressure in the
100 95 75
25 5 0
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4.2 Pressurization of tectonic stress
mudstone of the upper Jidike Formation is relatively large, with the maximum pressure coefficient generally within range of 1.6– 1.7 and the maximum excess pressure up to 25 MPa. In certain wells such as Well DN 11, the maximum pressure coefficient of the upper mudstone of the Jidike Formation is up to 1.8–2.0 and the maximum excess pressure reaches 45 MPa (Fig. 5). The excess pressure declines to 5–15 MPa in the mudstone of the lower Jidike Formation and Paleogene to Cretaceous formations, with the pressure coefficient generally in the range of 1.1–1.3.
Being a major overpressure mechanism, tectonic stress has received substantial attention in recent years, however, related studies on tectonic stress have primarily focused on qualitative evaluations with few quantitative evaluations of overpressure mechanism (Berry, 1973; Osborne and Swarbrick, 1997; Luo et al., 2004; Wang et al., 2005; Bilotti and Shaw, 2005; Feyzullayev and Lerche, 2009). Tectonic stress does not act
Pressure (MPa) Acoustic travel time (µs/m) Pressure (MPa) Acoustic travel time (µs/m) Pressure (MPa) Acoustic travel time (µs/m) 200 400 600 -40 0 40 80 120 100 200 400 600 -40 0 40 80 120 100 200 400 600 -40 0 40 80 120 100 600
4200
E 2-3 s E 1-2 km K 1 bs Formation testing pressure (a)
re
Depth /m
re Hy dro sta tic pre ssu
N1j
Hy dro sta tic pre ssu
Depth(m)
re Hy dro sta tic pre ssu
3600
N 1-2 k 3000
3600
4200
N1j
4800 4800 E 2-3 s E 1-2 km
5400 (b)
ss u re
6000
3000
2400
at ic p re
5400
N 1-2 k
ss u re
4800
2400
at ic p re
4200
L it h o st
ss u re
N 1-2 k
1800
1800
a ti c p re
3000
N2k
L it h o st
L it h o st
2400
3600
1200
1200 N 2 k
1800 N 2 k
Depth(m)
600
600
1200
N1j
E 2-3 s E 1-2 km K 1 bs Formation testing pressure (c)
Fig. 4 The compaction curves and lateral pressure distribution in the Well DN 11 (a), Well DN 22 (b), and Well DN 202 (c) of the Dina 2 Gas Field in the Kuqa Depression, Tarim Basin. N2k is Pliocene Kuqa Formation; N1-2k is Mioc ene-Pliocene Kangcun Formation; N1j is Miocene Jidike Formation; E 2-3s is Eocene-Oligocene Suweiyi Formation; E1-2km is Paleocene-Eocene Kumugeliemu Formation; K1bs is Lower Cretaceous Bashijiqike Formation.
A 1500 1000 500
Excess pressure (MPa) 0
20
40
Excess pressure (MPa) 0
20
40
Excess pressure Excess pressure Excess pressure (MPa) (MPa) (MPa) 0 20 40 0 20 0 20 40
Excess pressure Excess pressure (MPa) (MPa) 0 20 40 0 20
0
Q+N 2 k
B
5km
0
Elevation (m)
- 500 - 1000
N1-2k
- 1500 - 2000 - 2500
N1j
Top of overpressure
- 3000 E2-3s E 1 - 2 km
- 3500 - 4000 - 4500
Well DN203
Well DN204
Well DN201
Well DN22
Well DN202 Well DN102 Well DN11
Fig. 5 The distribution of the top of overpressure in the Dina 2 Gas Field, Kuqa Depression, Tarim Basin. Section location sees Fig.1.
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F.Zhang et al./Petroleum Research (2016) 1,93-102
directly on sediment particles but function through compaction of the formation pressure. Thus, the action of tectonic stress to formation pressure is considered to be lateral compaction (Osborne and Swarbrick, 1997; Luo et al., 2007). During the late Himalayan, the maximum principal stress in the study area changed direction to horizontal. The tectonic deformation at the southern Tianshan Mountains and the basinmountain boundary was dominated by nearly N-S-trending compressional deformation, whereas in the Kuqa Depression, nearly NS- and NW-SE-trending compressional deformation was the dominating tectonic deformation (Wang et al., 2003). The maximum effective principal stress in the Late Himalayan was investigated by the acoustic emission experiments (Zeng et al., 2004b; Zhang et al., 2004). Comparative analysis demonstrated that the horizontal effective principal stress was greater than the vertical effective principal stress, proving that the Kuqa Depression experienced intense tectonic compression in the late Himalayan. Tectonic stress accomplished compaction through lateral compaction, which, combined with vertical compaction, led to generation of obvious abnormal pressure in the Jidike Formation (pressure coefficient up to 2.0, excess pressure up to 45 MPa). The abnormal pressure resulted from tectonic compaction of mudstone is relatively low in other formations (Fig. 4). Assuming that the maximum excess pressure generated by total compaction of the Jidike Formation is completely transferred to the underlying formation, it is still insufficient to generate such high excess pressure at Dina 2 Gas Field (Fig. 2). When comparing the measured pressure of sandstone layer and the compaction curve estimated pressure of the adjacent mudstone layer in the same well, great differences between two sets of data are observed: the measured pressure of sandstone layer is generally greater than the calculated pressure of mudstone layer (Fig. 4). Based on the concept of tectonic compaction, previous work has established a quantitative evaluation model for f luid pressurization caused by tectonic compaction under actual formation conditions (Zhang et al., 2011)
Δp = ξ (σ 1 − S)
(3)
Where Δp is the fluid pressurization caused by tectonic stress, MPa; σ1is the largest horizontal principal stress, MPa; S is the load prior to pressurization, MPa; ζ is the sealing coefficient that measures the actual sealing ability of the underground geologic body (0–1; 0 represents a completely open fluid system, and 1 represents a completely sealed fluid system). The evaluation results show that fluid pressurization caused by tectonic stress in the Cretaceous formations is relatively small in the Well DN 201 (1.2 MPa) and Well DN 202 (1.3 MPa) (Zhang et al., 2011). Following equation (3), the fluid pressurizeation caused by tectonic stress in the Cretaceous
98
formations in the Well DN 204 is estimated to be approximately 1. 5 MPa. The maximum horizontal principal stress of the Cretaceous formations in the Well DN 11 and Well DN101 are less than the overlying loads, indicating that the tectonic stress in the Cretaceous formation of the DN 1 anticline at eastern Dina 2 Gas Field basically causes no fluid pressurization. As for the Cretaceous and Paleogene reservoirs at the same tectonic position and with the same tectonic morphology, the fluid pressurization caused by tectonic stress is quite similar. Overall, the fluid pressurization caused by tectonic stress in the Paleogene reservoirs at Dina area is low, e.g., <2 MPa, whereas the tectonic stress in the DN 1 anticline basically causes no fluid pressurization.
4.3 Pressurization of overpressure transfer Previous studies on the overpressure generation mechanism have found that over pressure transfer has played an important role in the generation of abnormal high pressure in the Brunei Baram region, and China’s Junggar, Bohai Bay and Yingge Sea basins (Audet and McConnell, 1992; Liu, 2002; Luo, 2004b; Tingay et al., 2009; Guo et al., 2010). Folding can cause ununiform changes in the overlying load along the horizontal direction, whereas different generation conditions of formation pressure in the lateral direction lead to fluctuations of formation depth. Formations sharing the same permeability are in contact with those of different excess pressures, resulting in generation of fluid pressure and lateral fluid migration (Luo et al., 2004). Deep overpressure will drive fluid migration up-dip and thus overpressure transfer, leading to generation of overpressure in the up-dip part of permeable sand bodies (Liu, 2002). When a fault cuts through two overpressure systems with different excess pressures, reactivation of the fault will allow fluid to flow along the fault conduits, thereby rapidly adjust excess pressure and lead shallow formation (previously with low excess pressure) to form relatively high overpressure (Osborne and Swarbrick, 1997; Liu, 2002; Luo, 2004a; Guo et al., 2010). The Dina 2 structure is a fault-bend fold of sub-salt reservoirs of the Jidike Formation, which has oil-bearing faults developed in the south and north sides. The formation of folds could cause the lateral overpressure transfer in the sub-salt reservoirs of the Jidike Formation that shared the same permeability and pressurization of the excess pressure in the upper reservoirs of the anticline with the same permeability (Fig. 6). Oil and gas sources were accumulated the Middle - Upper Triassic and Jurassic formations. Rapid burial in the Pliocene to Quaternary led to fast hydrocarbon generation of the Triassic and Jurassic source rocks (Sun et al., 2004). The process of hydrocarbon generation caused fluid pressure increases in the source rock formation (Barker, 1990; Osborne and Swarbrick, 1997). During the rapid burial period, the deep source rock formations and the upper Paleogene to Neogene formations
F.Zhang et al./Petroleum Research (2016) 1,93-102
Well YN2
Well DN202 0
5km Q +N 2 k
Elevation (km)
0
N1j
N 1-2 k
-1.0 -2.0
E N1j
-3.0 -4.0 -5.0 -6.0
N
E K
E
K
J
J T
J T
K
T
Overpressure transfer direction
Fault
Fig. 6 Overpressure transfer in the north-south section of the Dina 2 structure, in the Dina 2 Gas Field, Kuqa Depression (Sun et al., 2004)
The overpressure that is caused by overpressure transfer via fault connection can be evaluated in view of following geological phenomena: (1) a hydrostatic pressure gradient is maintained between the upper and lower formations connected by faults; (2) pressure coefficient of the shallow formation is extremely high; (3) great pressure difference between permeable formation and wall rock; and (4) a thin upper transition zone of the overpressured formations (Luo, 2004b). In the Dina 2 Gas Field, the excess pressure occurs in the sub-salt Paleogene and Neogene reservoirs of the Jidike Formation. The Dina 2 structure is relatively low. Excluding one point of the Neogene Jidike Formation in the Dina 2 Gas Field, all of testing points have excess pressure <3 MPa (Fig. 2). The upper and lower formations connected by faults generally maintain a hydrostatic pressure gradient. Sub-salt reservoirs of the Jidike Formation in the Dina 2 structure have an extremely high pressure coefficient, and shallow reservoirs have an even greater pressure coefficient than deep reservoirs (Fig. 2). As compared to the surrounding mudstone, the sub-salt reservoir of the Jidike Formation in the Dina 2 structure has relatively the large excess pressure (Fig. 4). All above observations suggest that overpressure transfer of the Dina 2 structure along faults is one of the key mechanisms for the abnormal high pressure generation in the sub-salt reservoirs of the Jidike Formation. With the measured geological data of the Dina 2 Gas Field, a
normal compaction fitted trend line is achieved with vertical effective stress and acoustic velocity of normal compaction points, and then projections of the vertical effective stress and acoustic velocity of the abnormal pressure points are done in a coordinate system. The results show that the data points of the vertical effective stress vs acoustic velocity apparently deviate from the normal compaction trend line, and degree of deviation is quite large (Fig. 7). 6.0 5.5
Acoustic velocity(km/s)
were subject to pressurization of hydrocarbon generation in addition to the similar pressurized conditions. Therefore, the deep source rock formations formed greater excess pressure than the overlying formations during the rapid burial period. During the intense tectonic compression in the late Himalayan, the faults experienced episodic opening and each opening event would allow rapid adjustment between the relatively high excess pressure in the deep source rock of overpressure system and the relatively low excess pressure in sub-salt reservoirs of the Jidike Formation. That is, the vertical overpressure transfer occurred and thus increased the excess pressure in the sub-salt reservoirs of the Jidike Formation. Such pressurization process was commonly associated with lateral transfer (Fig. 6).
5.0 4.5 4.0 Normal pressure point Abnormal pressure point in well DN11 Abnormal pressure point in well DN204 Abnormal pressure point in well DN102 Abnormal pressure point in well DN201 Abnormal pressure point in well DN202 Normal compaction trend line
3.5 3.0 2.5 2.0
0
10
40 30 20 Vertical effective stress (MPa)
50
60
Fig. 7 The relationship between the effective stress and the acoustic velocity of overpressured formations in the Dina 2 Gas Field of the Kuqa Depression
Based on the above analysis, the tectonic stress and overpressure transfer jointly are considered to cause the fluid pressurization in the sub-salt reservoirs of the Jidike Formation. Assuming that after the late Himalayan fluid pressurization caused by unloading, the formation porosity was unchanged, then the corresponding acoustic velocity remained basically unchanged as well. With this hypothesis, the reduction of vertical effective stress resulted from fluid pressurization by tectonic stress and the overpressure transfer can be quantified. The reduction of the vertical effective stress is due to the fluid pressurization caused by the tectonic stress and overpressure transfer (Table 1). Results show that the overpressure transfer caused relatively large fluid pressurization, generally in the range of 40–50 MPa, accounting for 65%–90% of the measured excess pressure with an average of 81.2% (Table 1). The pressurized hydraulic fluid caused by the compaction and horizontal tectonic stress can be obtained from the excess pressure in the adjacent mudstone formations (Table 1). As compared to the measured excess pressure, sum of estimated pressurization generated by different mechanisms has an absolute error <8 MPa (generally <5 MPa) and an relative error <15% (generally <10%). The estimates of pressurization generated via different overpressure mechanisms generally show small differences from the measured excess pressures, thus are considered reliable. According to the estimated fluid pressurization generated by different overpressure mechanisms,
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F.Zhang et al./Petroleum Research (2016) 1,93-102
Table 1 Estimation of fliud pressurization generated by different overpressure mechanisms in some typical wells of the Dina 2 Gas Field, Kuqa Depression Well
Ratio between overpressure Absolute error between sum Testing Formation Measured excess Effective stress Acoustic velocity Overpressure transfer Tectonic stress Adjacent mudstone transfer pressurization and pressurization and measured depth (m) pressure (MPa) pressure (MPa) (MPa) (km/s) pressurization (MPa) pressurizzation (MPa) excess pressure (MPa) measured excess pressure (%) excess pressure (MPa)
DN 11
5768.48
112.14
52.16
20.71
5.17
39.70
0
12.42
76.11
DN 11
5336.33
110.97
55.48
11.93
4.76
36.69
0
12.65
66.13
-6.14
DN 204
5154.63
107.99
54.38
10.73
5.08
45.74
1.5
5.37
84.11
-1.77
DN 204
5318.49
107.52
52.21
14.97
5.17
43.93
1.5
4.69
84.14
-2.09
DN 102
5699.73
108.10
48.83
23.16
5.44
44.81
0
4.21
91.75
0.18
DN 102
5508.09
111.25
53.97
15.60
5.35
49.80
0
7.48
92.27
3.31
DN 201
4975.03
105.92
54.19
8.65
5.00
45.72
1.2
9.12
84.37
1.85
DN 201
4987.84
106.34
54.47
8.53
5.08
48.24
1.2
10.57
88.56
5.53
DN 202
5159.65
109.61
55.96
9.21
4.92
42.70
1.3
7.11
76.30
-4.85
DN 202
5060.85
106. 16
53.53
10.40
4.69
34.67
1.3
9.81
64.77
-7.75
DN 202
4964.36
105.39
53.77
8.94
5.00
45.33
1.3
8.16
84.30
1.03
the overpressure transfer appears to be the major cause for the overpressure in the Dina 2 Gas Field.
5 G enerat ion proce ss of abnor mal high pressure and its relationship with hydrocarbon accumulation Previous studies have investigated hydrocarbon accumulation in the Kuqa Depression, and a two-stage accumulation model was proposed with an early oil accumulation followed by a late gas charge. It has been suggested that the Early Miocene (23–12 Ma) was the major oil accumulation period, whereas the Pliocene (5–0 Ma), especially the Kuqa stage (2.5 Ma) was the major gas accumulation period (Liang et al., 2002; Zhao and Lu, 2003). Additionally, a three-stage hydrocarbon accumulation model has also been proposed as follows: Neogene early - middle Kangcun stage (17–10 Ma), late Kangcun stage to early - middle Kuqa stage (10–3 Ma), and late Kuqa stage to Late Quaternary period (3–1 Ma) (Zhao and Dai, 2002). The results of the K-Ar isotope dating analysis with two authigenic illite samples from the Paleogene sandstone reservoir in Well DN 22 showed that ages of the illite are 11.3 ± 1.4 and 10.4 ± 1.2 Ma, corresponding to the middle Kangcun stage. The results of previous analyses of the hydrocarbon generation history indicated that the Middle - Upper Triassic source rock in the Yangxia Sag entered the early maturity stage in the Paleogene, peak oil generation stage in the Neogene - Late Miocene (approximately 5 Ma), and overmaturity stage since the Pliocene - Quaternary due to a rapid burial. The Jurassic source rock entered the peak oil generation period in the Neogene - Late Miocene, mature and over-mature in the Pliocene - Quaternary, and peak gas generation in the Late Pliocene (Sun et al., 2004). In summary, the Dina 2 Gas Field experienced an early oil-gas charge during the Kangcun stage, and a late natural gas charge mainly in the late Kuqa stage (5 Ma). The latter appears to be the key hydrocarbon accumulation period for the Dina 2 Gas Field. In the late Kangcun stage, a low-magnitude structure was
100
-0.04
formed in the Dina area and the deep source rock formation entered peak oil generation stage. Hydrocarbon generation led to formation of abnormal high pressure, and high-pressure oilgas was charged into the upper sub-salt reservoirs of the Jidike Formation. Despite the excellent sealing capacity of the gypsumsalt rocks of the Jidike Formation, the Dina low-magnitude structure had good reservoir properties such as porosity, permeability and lateral continuity, thus had poor lateral sealing of the reservoir. After the high-pressure oil and gas was charged into reservoirs of the Dina low-magnitude structure, it was difficult to generate abnormal high pressure and reservoirs retained normal pressure system due to poor lateral sealing. In this period, low-magnitude structural oil-gas reservoirs were formed (Fig. 8a). In the Kuqa stage, deep source rock entered into mature and over mature stages. Undercompaction and hydrocarbon generation led to generation of ultra-high pressure with great excess pressure. Due to rapid deposition, the gypsum-salt rocks of the overlying Jidike Formation formed relatively high abnormal pressure, thereby enhancing its sealing capacity. In the sub-salt reservoirs of the Jidike Formation, a relatively sealed system was formed under effects of diagenesis, lateral sealing of faults, and vertical sealing of cap rocks. Compaction disequilibrium resulted in a low magnitude of excess pressure (approximately 5–10 MPa). During this period, tectonic activity was not intense and reactivation of faults was relatively weak. The deep high-pressure gas could only slowly charge into the sub-salt reservoirs of the Jidike Formation along faults, without producing the overpressure transfer. Therefore, only a low magnitude of overpressure was formed in the sub-salt reservoirs of the Jidike Formation in this period, and the previously formed low-magnitude structural oil-gas reservoirs were subject to slow gas flushing by deep natural gas, thus remaining as lowmagnitude oil-gas reservoirs (Fig. 8b). During denudation stage of the Kuqa Formation to the Quaternary, the study area experienced intense tectonic compression and episodic opening of faults. Deep source rock formations generated even higher excess pressure due to gas
F.Zhang et al./Petroleum Research (2016) 1,93-102
Gypsum salt rock
N1-2k
Source rock
Normal-pressure oil-gas reservoir
N1j
E 1 - 2 km
Gas reservoir Oil reservoir
E 2-3 s
K
Overpressure
J T
(a) N2k
Oil-gas migration direction Fault
Excess pressure (MPa) 0 20 40 60
N1-2k
Low-magnitude overpressure oil-gas reservoir
N1j
E 2-3 s E 1 - 2 km K J T
(b) Excess pressure (MPa) 0 20 40 60
N2k
Q
N1-2k
N2k N1-2k N1j
k s -2 E 2 -3 E 1
K
E 2-3 s
E 1-2km K J
J
m
T
T
(c)
Fig. 8 Hydrocarbon accumulation model of the Dina 2 Gas Field from middle–late Kangcun stage (a), Kuqa stage (b) to denudation stage of Kuqa Formation–Quaternary (c) in the Kuqa Depression
generation. The resulting overpressured natural gas was charged into the upper reservoirs with the lower excess pressure, and the overpressure transfer led to increases in the excess pressure in the upper sub-salt reservoirs. As faults might have experienced multi-stage openings, the vertical overpressure transfer would cause multiple-f luid pressurization in the upper sub-salt reservoirs. During this period, intense tectonic compression resulted in stratigraphic deformation and folding, which caused lateral overpressure transfer into the reservoirs. Additionally, the lateral compaction of relatively large horizontal tectonic stress enhanced the compaction disequilibrium. All above conditions would increase magnitude of abnormal pressure in the sub-salt reservoirs of the Jidike Formation. In summary, under action of intense tectonic compression, the vertical overpressure transfer formed by episodic opening of faults, the lateral overpressure transfer caused by folding, and the horizontal tectonic stress significantly increased magnitude of abnormal pressure in sub-salt reservoirs of the Jidike Formation during the Kuqa Formation denudation stage to the Quaternary, and formed an excess pressure of approximately 40–50 MPa. This stage was the major period of ultra-high pressure generation in the Dina 2 Gas Field. Additionally, the intense tectonic compression led to formation of the large-magnitude faulted anticline structure
in this field, and rapid charge of deep overpressured-gas transformed the pre-existing oil-gas reservoirs into the present Dina 2 gas reservoirs (Fig. 8c).
6 Conclusions (1) The major generation mechanisms of abnormal high pressure in the Dina 2 Gas Field include disequilibrium compaction, tectonic stress, and overpressure transfer. The overpressure transfer resulted from vertical opening of faults and folding are the primary causes for the abnormal high pressure in this gas field with an estimated contribution of 65–90%. (2) The reservoirs of the Dina 2 Gas Field were a normal pressure system during the early oil-gas charge in the Kangcun stage (17-5Ma). During the Kuqa stage (5-2Ma), a rapid deposition caused compaction disequilibrium and formed an excess pressure of approximately 5–10 MPa. During denudation stage of the Kuqa Formation to the Quaternary, vertical overpressure transfer from episodic opening of faults, the lateral overpressure transfer due to folding, and the lateral tectonic stress under an intense tectonic compression setting significantly increased magnitude of the abnormal pressure in the sub-salt reservoirs of the Jidike Formation and formed an excess pressure of approximately 40–50 MPa. This is the major overpressure generation period for the Dina 2 Gas Field. (3) The present Dina 2 gas reservoirs were formed along with generation of ultra-high pressure in the reservoir formations, that is, the two processes were synchronous. The field area formed the normal pressure reservoirs in the low magnitude anticline during the late Kangcun stage (10-5Ma), the low overpressure reservoirs in the low magnitude anticline during the Kuqa stage, and the ultra-high pressure natural gas reservoirs in the large magnitude anticline during the denudation stage of the Kuqa Formation to the Quaternary.
Acknowledgements The authors would like to thank Yan Song, Mengjun Zhao, Shaobo Liu, Shihu Fang, Qingong Zhuo, Qingyang Meng, Lin Jiang, and Xuesong Lu from PetroChina Exploration & Development Research Institute for their guidance and advice, and the Research Institute of Exploration and Development of the Tarim Oilfield Company for research assistance and logistic support. This work was funded by National Science and Technology Major Project of China (Grant No. 2008ZX05003, 2011ZX05003001).
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