Introduction
Carbonate reservoirs are important global oil and gas resources, of which deep and ultra-deep marine carbonate reservoirs are one of the most important fields for increasing reserves and production of onshore oil and gas in China in recent years [1⇓-3]. Large carbonate oil and gas fields (reservoirs) discovered all over the world are mainly located in North America, the Middle East, Siberia and Asia-Pacific. They are vertically distributed in many formations, including Sinian, Cambrian, Ordovician, Devonian, Carboniferous, Permian, Jurassic and Cretaceous, and are mainly karst fractured-cavity reservoirs, biogenic reef-shoal reservoirs and dolomite reservoirs [1-2]. The large carbonate oil and gas fields discovered in China have distinct characteristics that differ from the foreign ones. They are mainly distributed in deep and ultra-deep layers (below 4 500 m) in superimposed basins (i.e., Tarim Basin, Sichuan Basin and Ordos Basin in China), and have higher temperature and pressure conditions, older geological age, and more complicated reservoir formation and accumulation processes [3].
For deep and ultra-deep marine carbonate oil and gas exploration, the important issues that need further study include the development and distribution of high-quality and large-scale reservoirs and the law of oil and gas reservoir formation and enrichment. Deep and ultra-deep marine carbonates have diverse reservoir space types and complex reservoir formation mechanisms. The reservoir types mainly include biogenic reef-shoal, microbial mound, dolomite and karst reservoirs. In addition, fault-controlled reservoirs induced by faulting activities are important too [4]. Based on the research on the reef-shoal reservoirs in Puguang and Yuanba gas fields, a theoretical understanding of three-element controlling reservoirs (TECR) [3-4] was proposed. The depositional and diagenetic environment controls early pore development, the coupling effect of structure and pressure controls fracture development, and fluid-rock interaction controls deep dissolution and pores preservation. In the following deep and ultra-deep carbonate oil and gas exploration, the TECR theory has been continuously enriched and developed. Deep and ultra-deep marine carbonate reservoirs in the central and western superimposed basins in China have multiple hydrocarbon source kitchens at different temperature, pressure and reservoir environments in the middle and shallow layers, and have undergone multiple phases of reservoir formation and reformation, and developed into oil and gas plays in various phases and with differential enrichment degrees [5⇓⇓-8].
Deep and ultra-deep marine carbonate oil and gas development faces technical challenges on long-term stable production from old oil and gas fields and effective development of new types of oil and gas reservoirs. The flow regimes at high temperature and pressure during the development of deep and ultra-deep marine carbonate reservoirs are complex [9⇓-11]. Taking Puguang gas field in Sichuan Basin as an example for reef-shoal high-sulfur sour gas reservoirs, during deep burial, oil and gas reservoirs suffer from thermal sulfate reduction reaction (TSR), and produce acidic fluids such as H2S. Although it is beneficial to long-term preservation of existing pores [12-13], it brings difficulties to subsequent efficient development [14-15]. In recent years, ultra-deep faults-controlled oil and gas reservoirs newly discovered in Shunbei oil-gas field in the Tarim Basin have significant differences in reservoir type, spatial distribution and development characteristics compared to fractured-cavity karst reservoirs [3]. More studies should be done on fluid flow mechanism and development methods of oil and gas reservoirs.
Focusing on the types and formation mechanism of high-quality reservoirs, the diversity of hydrocarbon source kitchens, the conversion of hydrocarbon phases, the driving factors and laws of hydrocarbon accumulation, the fluid flow regimes in typical oil and gas reservoirs and development methods for deep and ultra-deep marine carbonate reservoirs, this study carries out multidisciplinary and cross research covering geology, geochemistry, geophysics, development mechanism experiment and numerical simulation, obtains a new understanding of the mechanism of reservoir formation and hydrocarbon accumulation of deep and ultra-deep marine carbonates and proposes a new method for efficient development by making a full use of latest drilling, seismic, logging, test and experiment data. The findings are expected to provide technical supports for the exploration and development of deep and ultra-deep carbonate oil and gas reservoirs.
1. Types and formation mechanism of high-quality carbonate reservoirs
With the discovery of large oil and gas fields (e.g., Tahe in Tarim Basin, Puguang and Yuanba in Sichuan Basin), significant progress has been achieved on unconformity- controlled karst reservoirs and reef-shoal facies-controlled reservoirs [16-17], and massive high-quality deep and ultra-deep marine carbonate reservoirs have been discovered in deep wells at 7 000-8 000 m in the Tarim Basin and Sichuan Basin, and mainly include two types: (1) reservoirs associated with faulting activities and (2) ancient dolomite reservoirs in Sinian, Cambrian and Ordovician. The former can be divided into three types: fractured-cavity reservoir formed by tectonic disruption during fault activity (referred to as fault-controlled fractured-cavity reservoir), reservoir reformed by fault and fluid (referred to as fault-fluid controlled reservoir), and reservoir developed on high-energy facies such as early reefs and shoals and altered by faults and fluid dissolution (referred to as fault-facies-dissolution co-controlled reservoir). The latter one can be divided into two types: microbial mound-shoal dolomite reservoir and dolomite reservoir in gypsum-bearing strata (Fig. 1 ).
Fig. 1. Development model of deep and ultra-deep carbonate reservoirs in the Cambrian-Ordovician strata of the Tarim Basin. Z2—Upper Sinian; —C1—Lower Cambrian; —C2—Middle Cambrian; —C3x—Upper Cambrian Lower Qiulitag Formation; O1p—Lower Ordovician Penglaiba Formation; O1-2y—Lower-Middle Ordovician Yingshan Formation; O2yj—Middle Ordovician Yijianfang Formation; O3—Upper Ordovician. |
1.1. Carbonate reservoirs associated with faulting activities
In the Shunbei area, strike-slip faults successively developed from the Middle Caledonian to the Late Hercynian periods in multiple stages. On the one hand, strike-slip faulting activities created fault-controlled fractured-cavity reservoirs by mechanically cracking carbonate rocks. On the other hand, strike-slip fault and fracture systems are preferential channels for the migration of multiple geological fluids to dissolve the carbonate rock by fluid-rock interaction, forming fault-fluid controlled carbonate reservoirs.
The development fractured-cavity reservoirs associated with faulting activities is supported by the investigation of outcrop profiles in the Tarim Basin and a large number of wells drilled in the Shunbei area. The reservoir space is composed of fault cavities (caves), structural fractures, and inter-breccia pores and fractures. According to the study of major faults and reservoirs in Shunbei area, the development and degree of the fault-controlled reservoir is mainly controlled by the scale and activity intensity of strike-slip faults that were influenced by regional stress field [18-19]. Detailed fault analysis and reservoir characterization show that the fault-controlled reservoirs have a typical characteristic of "core-zone" structure and "cluster" development [18⇓-20]. Especially, the fault-controlled fractured-cavity reservoirs with a cluster pattern drilled by multiple wells in Shunbei No. 4 fault Zone and No. 8 fault Zone show a certain degree of drilling break and drilling fluid loss, which have been proved to be high- yield pays [20].
In addition to fault-controlled reservoirs, different types of diagenetic fluids migrate along the strike-slip faults and dissolve the carbonate rocks, forming fault-fluid controlled reservoirs distributed in Tahe oil field of Tabei Uplift and depression zones in Shunbei oil-gas field. The identification of regional diagenetic fluid indicates that the Tahe area of the Tabei Uplift was dominated by the dissolution of meteoric water, forming the fault-controlled karst fractured-cavity reservoirs. Meteoric water permeated in the strike-slip faults from the Tabei Uplift to the Shunbei area, influencing the development of reservoir to a certain degree in the northern Shunbei area, but becoming weak toward south. Some evidences have been found from wells, e.g., Well SHB1-3, in No. 1, No. 5, and No. 7 fault zones, proving the existence of calcite with meteoric water origin [21], but the contribution of meteoric water for reservoir space still needs further clarify. From the No. 12 fault zone in the southeastern Shunbei area toward east to the Shunnan-Gucheng area, the phenomena of strong fault and hydrothermal fluid alternation were found in cores (e.g., in wells SHB 121, SHT 1, SHN 4, and GC 18). Silicified reservoirs formed by siliceous hydrothermal activity were discovered in the Shunnan area, and hydrothermal dolomitized reservoirs in the Gucheng area [22⇓-24].
Similar to the Tarim Basin, the Sichuan Basin was also affected by dissolution of various fluids along strike-slip faults. Detailed interpretation and characterization indicated that NW strike-slip faults were developed in Langzhong area of northern Sichuan Basin and Tailai area of southeastern Sichuan Basin [25-26], and broomlike strike- slip faults in Hebaochang, Yunjin and Lizi areas of southern Sichuan Basin. Wells TL 6 and TL 601 revealed the movement of hydrothermal fluids upward along faults and altered the carbonate rocks of the Middle Permian Maokou Formation to form fault-dissolution controlled hydrothermal dolomitized reservoirs [27-28]. The hydrothermal activity was closely related to the Emeishan large igneous province. Hydrothermal fluid preferentially reformed grain shoal facies into hydrothermal dolomite along faults, thus forming dominant facies (such as Permian Qixia Formation in western Sichuan) in early stage and fault-facies-dissolution co-controlled reservoirs in later stage. Under the influence of the Dongwu tectonic movement, local uplifts occurred in the southern broomlike fault development zone, providing a necessary condition for meteoric water to flow downward along the faults. Fubao 1, Xiantan 1 and other wells confirmed that the fault-controlled karst fractured-cavity reservoir was formed by the dissolution of meteoric water along the faults.
1.2. Dolomite reservoirs in ancient strata
1.2.1. Microbial mound-shoal dolomite reservoir
The latest wells drilled in the Sichuan Basin and Tarim Basin revealed that the Sinian Dengying Formation and Qigebulake Formation have developed high-quality microbial dolomite reservoirs of mound-shoal facies with large thickness and wide distribution. The lithology mainly includes stromatolite/thrombolite dolomite, and the reservoir space is dominated by primary stromatolite and thrombolite pores associated with sedimentary structures, followed by intercrystal pores, fractures, and dissolution vugs with porosity up to 6%.
The multiple types of microbialite widely developed are closely related to the Precambrian paleo-oceanic environment and microbial interactions. Based on field observation, petrological, geochemical and crystal optical studies [29-30], the physicochemical properties of the Precambrian seawater were significantly different from those of the Phanerozoic seawater. The marine environment throughout the Neoproterozoic period was a special aragonite-dolomite sea [29], which was globally comparable. The aragonite-dolomite sea occurred intermittently during the interglacial period between the Middle Neoproterozoic snowball earth events. In that aqueous environment, microbial-mediated effects promoted primary dolomite precipitation and the formation of large-scale microbial dolomite in the Precambrian. During the formation of microbial dolomite, frequent changes in sea level and coupling process between water environment and micro-organisms resulted in the formation of microbial dolomite framework with different sedimentary configurations and laying a material basis for pore formation and preservation. Studies on microbial mound-shoal facies dolomite reservoirs in the Sinian Dengying Formation of the Sichuan Basin and the Sinian Qigebulake Formation of the Tarim Basin indicate that microbial-mediated precipitation of primary dolomite during the sedimentary period provided a compaction-resistant framework, and dissolution vugs were formed by penecontemporaneous intermittent exposures and meteoric water leaching. Subsequently, superimposed epigenetic karstification resulted in large-scale fractures and vugs, while the acidic fluid environment (high CO2 and H2S contents) during early hydrocarbon charging would favor the long-term preservation of the reservoir space [31].
1.2.2. Dolomite reservoir of gypsum-bearing strata
The evaporite-dolomite system deposited in an evaporative platform environment is widely distributed in deep and ultra-deep Cambrian-Ordovician strata of superimposed basins in west and central China. High-quality reservoirs have been encountered in the Cambrian inter-salt and pre-salt intervals (Wusonger and Xiaoerbulake formations) from wells ZS 1, ZS 5 and LT1 in the Tarim Basin [32], and the fourth Member of Ordovician Majiagou Formation from Well DS 1 in the Ordos Basin.
There are three main lithological associations of evaporite and dolomite: (1) Lateral associated gypsum type. Soluble evaporite minerals as a part of reservoir structure were dissolved to form pores; (2) Carbonate-beneath- evaporite type. The sealing effect of massive evaporites can reduce the intensity of burial diagenesis and is beneficial to the burial preservation of early pores; (3) Interbedded type. The rhythmic and rapid stacking of the multi-sets of layered evaporites is conducive to the preservation of primary structure and pores (Fig. 2 ). The high-quality reservoirs in the evaporite-dolomite system are characterized by the development of early-stage pores. Specifically, on the basis of high energy carbonate shoal- mound or gypsum-bearing dolomite deposited in the relatively geomorphic high, meteoric water dissolution and evaporated seawater-associated regional dolomitization during the penecontemporaneous-eogenetic stage could result in the formation of diverse pores, such as inter/intra-grain pores, intercrystalline pores, framework pores in microbialites and gypsum-dissolution pores in dolomite.
Fig. 2. Reservoir models in different lithological associations of evaporites and dolomite. |
During the burial diagenesis process, evaporites played a crucial role in the preservation of early-formed pores. In the lateral-associated-gypsum type, most pores formed through the dissolution of early gypsum nodules are relatively isolated and less affected by buried diagenetic fluids and can be well preserved. In the carbonate-beneath-evaporite type such as the Cambrian Xiaoerbulake Formation in the Tarim Basin [33] and the Triassic Leikoupo Formation in the Sichuan Basin [34], the strong sealing and capping properties of evaporite can block downward diagenetic fluids and form fluid overpressure, which is helpful to decreasing compaction and cementation in the pre-salt strata. Furthermore, the higher thermal conductivity of evaporite layers can reduce the temperature of the underlying strata, so that the water-rock equilibrium in mineral cements shifts to the direction of dissolution, which inhibits cementation and facilitates the preservation of early-formed pores. In the interbedded type such as the Ordovician Majiagou Formation in the Ordos Basin [35-36], the rhythmic thin-interlayered formed during the depositional period can accelerate the interbedded carbonates enter a relatively closed diagenetic environment in the early diagenetic stage, in which the water-rock reaction tends to be stabilized and the fluids are inactive. This is also conducive to the early preservation of the primary structure and primary pores. To summarize, three major factors, namely favorable shoal-mound facies, early dolomitization and dissolution, and fluid overpressure and pore preservation associated with evaporite sealing, are the keys to the formation and maintenance of high- quality reservoirs in the evaporite-dolomite system.
Case studies have been carried out on the fracture- controlled reservoir in the Shunbei oil-gas field and the fracture-hydrothermal fluid-controlled reservoir in Shunnan-Gucheng area in the Tarim Basin, the fracture-facies- dissolution controlled reservoirs in Tailai area and Sinian-Cambrian microbialites in Anyue area in the Sichuan Basin, and the gypsum-bearing dolomite reservoirs in the Ordos Basin, which revealed the key role of coupled deposition and fracture-fluid alteration in the formation of reservoirs and enriched the theory of TECR.
2. The law of hydrocarbon accumulation and enrichment
The research on oil and gas accumulation and enrichment in deep and ultra-deep marine carbonate reservoirs carried out in large oil and gas fields, such as Tahe, Puguang, Yuanba, Anyue, and so on, has yielded a substantial understanding [37⇓⇓-40]. We employed new data to conduct deep research, and made significant progress in the understanding of the diversity and effectiveness of hydrocarbon source kitchens, the mechanism of phase transformation of oil-gas reservoir, the dynamics of hydrocarbon accumulation, and the model of formation and enrichment of large oil and gas fields.
2.1. The diversity and effectiveness of hydrocarbon source kitchens
The diversity of marine hydrocarbon source kitchens in deep sedimentary strata was inherited from the diversity of the development models of hydrocarbon source rock. Macroscopically, earlier studies revealed the distribution patterns of marine source rock in the context of paleoclimate, paleo-ocean currents, paleotectonics, and several (basin-wide) regional source rocks have been identified in the Tarim Basin, Sichuan Basin and Ordos Basin [41⇓⇓-44], e.g., the Lower Cambrian Yuertusi Formation in the Tarim Basin, the Lower Cambrian, Lower Silurian and Middle-Upper Permian in the Sichuan Basin.
Based on outcrops and new drilling data in the Tarim, Sichuan and Ordos basins, five geological models have been recognized for the development of the organic-rich shale, deepening the understanding of prevailing tectonic settings, sedimentary facies, litho-facies and organo-facies, as well as the spatial distribution of litho-facies and organo-facies [45] (Fig. 3 ). The first model is exemplified by the Lower Cambrian Qiongzhusi Formation in the Sichuan Basin and the Lower Cambrian Yuertusi Formation in the Tarim Basin, dominated by siliceous shale of deepwater shelf facies deposited along passive continental margins [46]. The second model is represented by the Lower Cambrian Maidiping and Qiongzhusi formations and the Upper Permian Wujiaping and Dalong formations in the Mianyang-Changning rift trough and Kaijiang-Liangping continental shelf, dominated by deepwater shelf siliceous shales and carbonate-rich shales deposited in the intra-platform rifts [46⇓-48]. The third model is represented by the Upper Ordovician Wufeng- Lower Silurian Longmaxi formations, including the deepwater shelf siliceous shales in the intra-continental Southeastern Sichuan Depression, and distributed between two paleohighs [46⇓-48]. The fourth is carbonate-rich source rock represented by the calcareous shale, argillaceous limestone and micritic limestone in the first Member of the Middle Permian Maokou Formation, formed in the mid-outer parts of a carbonate ramp. The clay-rich mudstone in the Upper Permian Longtan Formation is a typical example of the fifth model, which was formed in a transitional tidal flat-lagoon setting [47].
Fig. 3. Development models and characteristics of organic rich shales. TOC—total organic carbon content. |
Detailed study of the Upper Sinian-Lower Cambrian profiles in the western Hubei-eastern Guizhou provided lithologic, organic and inorganic geochemical evidences for the differential development of deepwater shelf source rocks in passive continental margins and intra-platform rifts.organic-rich sediments in passive continental margins were benefited mainly from high productivity and favorable preservation conditions [47].organic enrichment in the intra-platform rifts was mainly controlled by preservation conditions. Upwelling oceanic currents as well as frequent sea-floor hydrothermal activities brought in abundant nutrients to stimulate the primary productivity of the surface water in the outer shelf.organic enrichment enhanced bacterial sulfate reduction to produce a large amount of hydrogen sulfide, ultimately leading to sulfurization in the slope zone [48]. Detailed sedimentary microfacies and geochemical analysis from new drilling in the first Member of Maokou Formation have provided ample evidences for the high potential of carbonate-rich source rock and source-reservoir integration of carbonate ramp deposition. Deep lagoon facies is the new exploration target due to its high TOC values and developed micro-nano pores, where clay mineral contents, TOC and micro-nano pores are highly intercorrelated [45]. The marlstone sections are developed in carbonate ramp of the Lower Cambrian Yuertusi Formation and the lower part of the Xiaoerbulake Formation in the Tarim Basin, which is the potential exploration target with characteristics of self-generation and self-accumulation for unconventional oil and gas.
Oil and gas in deep reservoirs could derive either from deep burial and transformation of oil and gas generated in shallow formations [49], or from late thermal cracking of deep and highly matured kerogen and dispersed organic matter at high temperature [50-51]. Elemental, molecular and isotopic tracers are very useful for validating the effectiveness of deep hydrocarbon source kitchens under the constraint of a tectonic-sedimentary differential development framework. Correlative study on the Tarim Basin and the upper Yangtze block found the difference in stable carbon isotopes between organic-rich black shale and marlstone [52]. Data from both natural sample sets and laboratory simulation revealed limited effect of isotopic fractionation during thermal maturation. Compound-specific stable carbon isotopic compositions of the n-alkanes in the crude oil indicate hydrocarbon contributions from both black shale and marlstone, with some affected by secondary reaction such as thermochemical sulfate reduction (Fig. 4 ).
Fig. 4. Compound-specific stable carbon isotopic compositions of the n-alkanes in crude oil collected from typical wells of different faults in Shunbei oil-gas field. |
2.2. Phase and transformation of reservoir fluid
Light oil reservoirs were discovered at depth more than 7 000 m in Shunbei oil and gas field where oil is distributed in west and north, and gas in east and south [33]. The fluid phase and transformation mechanism of deep and ultra-deep oil and gas reservoirs aroused widespread attention. The evolution of geothermal field, hydrocarbon accumulation and secondary alteration processes were studied in typical areas in the Tarim Basin and Sichuan Basin, revealing hydrocarbon accumulation and phase transformation processes controlled by tectonic-thermal evolution. The secondary alteration of petroleum reservoirs, especially crude oil cracking under the control of the geothermal field, and the hydrocarbon phase generated from source kitchens during hydrocarbon accumulation, jointly controlled the present fluid phase in the deep reservoir.
The main area of Tahe oil and gas field and the north and southeast of Shunbei oil and gas field underwent different tectonic thermal evolution in the Tarim Basin. The differential thermal evolution experienced by Lower Cambrian source rocks and Ordovician carbonate reservoirs in different areas controls the distribution of hydrocarbon reservoirs with different fluid phases. Tahe oilfield is located in the main body of the Tabei Uplift. Study on the thermal history in Well TS 5 revealed a relatively high geothermal field with a geothermal flow at 35-52 mW/m2 [53-54]. Since the Caledonian Period, the Lower Cambrian source rock entered its mature stage, and then continued evolving slowly to be highly mature in the Himalayan period. The Ordovician carbonate reservoirs experienced slow heating-up in the early stage and rapid heating-up in the late stage, so that the present-day temperature is 110-135 °C. Fluid inclusions and U-Pb dating of calcite in fractures and cavities in wells TS 3 and TS 5 revealed that the Ordovician carbonate rock generally experienced liquid hydrocarbon accumulation and destruction from Late Caledonian to Early Hercynian, and then underwent multiple stages of liquid hydrocarbon accumulation during the Late Hercynian Period [55], leaving the present-day medium and heavy oil reservoirs in the main body of the Tahe area [33].
The Cambrian-Ordovician interval in the northern part of Shunbei oil and gas field experienced early slow burial and late rapid burial since the Himalayan period. There was a continuously low geothermal field (the heat flow was 32-45 mW/m2) [53-54]. Due to the relatively deep burial in geological history, the Lower Cambrian source rock underwent a thermal evolution process earlier than the Tabei Uplift. The present temperature of the Ordovician carbonate reservoir is 135-180 °C [54]. Study on hydrocarbon accumulation and secondary alteration in several wells in the Shunbei No. 1 fault zone found that the Ordovician carbonates underwent early filling of liquid hydrocarbon with different maturity [56], and the characteristics of crude oil geochemistry indicate that early reservoirs have not suffered secondary alteration such as crude oil cracking. Therefore, light oil and volatile oil and gas reservoir are generally developed in this area. Oil-cracking kinetics experiments based on the tectonic-thermal evolution background of the northern part of Shunbei oil and gas field suggested that marine oil can be kept at 178 °C to 185 °C [57]. The low geothermal background makes light oil still exist in ultra-deep reservoirs. The heat flux in the southeast of Shunbei oil and gas field is 42-58 mW/m2 [53]. The Lower Cambrian source rocks entered a high maturity stage during the Caledonian Period and evolved slowly in the later stage. The present formation temperature of the Ordovician carbonates is 180-195 °C, which are mainly dry gas reservoirs [58]. Researches on the evolution process of hydrocarbon accumulation and secondary alteration in Well SHB 16X revealed that the Ordovician reservoirs experienced early liquid hydrocarbon filling, late gas hydrocarbon filling and in-situ liquid hydrocarbon cracking [56]. The identification of natural gas genesis further clarified that the natural gas in this area is almost oil-cracking gas [59-60].
The Sichuan Basin is generally a “warm basin” [53]. The paleo-uplift in the central part and the northeastern part experienced a tectonic thermal event related to the Emeishan large igneous province during the Permian period [53] when the geothermal flow was 57-86 mW/m2. Studies on the hydrocarbon accumulation process in the marine strata in wells CS1, RT1 and TL6 showed that the synergistic effect of rapidly burial and relatively high geothermal field made crude oil crack into gas in the central, northern, and southeastern parts of the Sichuan Basin during late Hercynian period [61-62], so that dry gas is dominant at present deep formations.
2.3. Hydrocarbon accumulation dynamics and differential accumulations
Hydrocarbon accumulation is controlled by buoyancy or non-buoyancy, depending on dynamic boundaries and their spatiotemporal configuration [62⇓-64]. The types of hydrocarbon reservoirs change with the dynamics of hydrocarbon migration and accumulation in the process of basin evolution. Petroliferous basins may be divided into three dynamic fields as free, limited and bound fields according to buoyancy-driven hydrocarbon accumulation depth, hydrocarbon accumulation depth limit and active source rock depth limit [63⇓-65]. A free fluid dynamic field is where conventional hydrocarbon reservoirs are developed and distributed, and where buoyancy has a dominant effect on the migration and accumulation of hydrocarbon. The development and distribution of hydrocarbon reservoirs in a free fluid dynamic field is controlled by structural trap, appearing in features as accumulated in the high spot of the trap, enriched in the zone with high porosity, sealed with cap rocks at high position, and formed reservoirs at high pressure, separated from source rock. A limited fluid dynamic field is where tight hydrocarbon reservoirs are developed and distributed, and where hydrocarbon migration and accumulation are neither dominated by buoyancy nor controlled by traps. Such reservoirs in a limited fluid dynamic field are featured by low-depression accumulation, low-stand inversion, low-porosity enrichment, low-pressure stability and adjacency of source rock and reservoir. Shale oil and gas distribution and accumulation controlled by bound fluid dynamic fields are not dominated by trap structure but under the influence of non-buoyancy. Such reservoirs in a bound fluid dynamic field have the characteristics of source-reservoir integration, generally tight and extensive distribution, low permeability and low production [66-67].
Due to the complex and diverse reservoir space types, origins, and distribution, as well as the great variation in formation temperature and pressure and fluid phase during the dynamic evolution of hydrocarbon accumulation, the deep and ultra-deep marine carbonate reservoirs in the central and western superimposed basins in China do not fully conform to the characteristics of free, limited, and bound dynamic fields, but exhibit characteristics of modified dynamics fields. A large number of fractures and vugs were developed after stress and fluid reformation. Hydrocarbon accumulation is not entirely controlled by buoyancy or non-buoyancy, instead it is jointly controlled by various dynamic forces such as buoyancy, non- buoyancy, stress and fluid activity. Hydrocarbon accumulation mainly controlled by stress and fluid activity in deep and ultra-deep marine carbonate reservoirs is the unique feature of the central and western superimposed basins in China compared to other regions in the world [68]. Low fluid potential areas such as unconformity, fault zones, ancient buried hills, and reef-shoal bodies formed under multiple dynamic forces are favorable exploration targets for deep and ultra-deep carbonate reservoirs.
2.4. Accumulation and enrichment law of the large oil and gas fields
Tahe Oilfield and Shunbei oil and gas field in the Tarim Basin are typical fault-controlled large oil and gas fields characterized by lower source and upper reservoir, fault transport, orderly distribution, and fault-controlled hydrocarbon enrichment (Fig. 5 ) [33,69 -70]. The marine source rock of the Lower Cambrian Yuertusi Formation is widely distributed, and the tectonic-thermal regime controls differential hydrocarbon generation and reservoir adjustment and modification [53,71]. Multiple stages of fault activities control the hydrocarbon migration and accumulation [56,69]. Production statistics further indicated that faults controlled the hydrocarbon enrichment. In the main body of Tahe oil field, oil is found in karst fractured-cavity reservoirs overall, and those connecting with major faults deliver high yield. In the Shunbei area and other depressions, the strike-slip zone is also featured by pervasive oil and gas distribution, and the scale and connectivity of reservoirs control oil and gas enrichment and yield [72-73].
Fig. 5. Distribution and accumulation of oil and gas reservoirs in the Tahe and Shunbei oil and gas fields in the Tarim Basin. —C3—Upper Cambrian; O1-2—Middle-Lower Ordovician; O3—Upper Ordovician; S—Silurian; D—Devonian; C—Carboniferous; P—Permian; T—Triassic; J—Jurassic; K—Cretaceous; E—Paleogene; Q—Quaternary. |
According to the previous research, the tectonic-depositional differentiation of the Kaijiang-Liangping shelf controls the formation of large reef-shoal gas field. Recent studies further revealed that faults and fractures play an important role in controlling the development of high-quality reservoirs and hydrocarbon enrichment in the Sichuan Basin by comparing the hydrocarbon migration, accumulation and adjustment in Puguang-Yuanba and Hebachang gas fields [74]. Deep and ultra-deep marine carbonates in the Sichuan Basin can form in-situ enriched oil and gas fields (reservoirs) adjacent to source rocks in marginal platform reef-shoals, such as Puguang Gasfield, Yuanba Gasfield, and Dengying Formation gas reservoirs in Anyue Gasfield. It can also form oil and gas fields (reservoirs) with fault-controlled hydrocarbon migration and enrichment in intra-platform shoals, such as Hebachang Gasfield, the Longwangmiao Formation gas reservoir in Anyue Gasfield, and gas reservoirs in the Permian Qixia-Maokou formations of central Sichuan Basin (Fig. 6 ). By comparing the hydrocarbon accumulation process in Anyue Gasfield [75-76] with new wells such as CS1 in the north slope of the paleo-uplift in the central Sichuan Basin, it is found that the Sinian gas reservoirs underwent early oil accumulation and late petroleum phase transformation and adjustment. The distribution of present Sinian gas reservoirs is the result from the joint control of hydrocarbon generating center (hydrocarbon source kitchen), cracking gas generating center (paleo-oil reservoir), gas accumulating center (paleo-gas reservoir) and gas preserving center (effective preservation) [61-62,77].
Fig. 6. A geological section of deep marine carbonate reservoirs in the Sichuan Basin. Z—Sinian; O—Ordovician; T1—Lower Triassic; T2—Middle Triassic; T3—Upper Triassic; K—Cretaceous. |
Based on the previous research of the hydrocarbon accumulation in large marine oil and gas fields such as Jingbian Gasfield, Tahe Oilfield, Puguang Gasfield, Yuanba and Anyue Gasfield, this study deepens the understanding of the development of large-scale deep and ultra-deep marine carbonate reservoirs, hydrocarbon source diversity and phase transformation of oil-gas reservoir, hydrocarbon accumulation dynamics, hydrocarbon accumulation and distribution, as well as the evolution process of Tahe and Shunbei fault-controlled large oil and gas fields and Puguang-Yuanba facies-controlled large gas fields. It is further recognized that the deep marine carbonate reservoirs are characterized by “three- element controlling reservoirs, multi-stage and multi- source hydrocarbon supply, and multi-field-controlled hydrocarbon accumulation” (Fig. 7a ), and “large-scale source rock and reservoir development, effective filling and accumulation, and effective preservation” ensure the high-quality reservoirs (Fig. 7b ).
Fig. 7. Evolution (a) and enrichment model (b) of deep and ultra-deep marine fault-controlled/facies-controlled oil and gas reservoirs in central and western superimposed basins. |
Large-scale mound-shoal dolomite reservoirs with efficient configuration of source rock and reservoirs are favorable for oil and gas accumulation. Typical examples are the platform-edge mound-shoals on both sides of the paleo-rift of the Sinian Dengying Formation in the Sichuan Basin, the intra-platform mound-shoals and peritidal shoals around paleo-uplifts in the Cambrian-Ordovician in the Tarim Basin and the Sichuan Basin. Large overthrust faults are developed in the basin margins and strike-slip faults developed within the basins in the central and western superimposed basins in China. The faults contribute to reservoir development, and play an important role in connecting source rocks and reservoirs, and controlling oil and gas migration and accumulation [8,78]. Fault zones and connected reservoirs are favorable areas for hydrocarbon accumulation controlled by multi-dynamic fields. Multiple vertically stacked reservoirs can be formed in the fault zones, which are important targets for oil and gas exploration.
3. A new efficient development method for deep marine carbonate oil and gas reservoirs
Two most typical types of deep and ultra-deep marine carbonate reservoirs in China are reef-shoal sour gas reservoirs and fractured-cavity oil-gas reservoirs. A great deal of researches have been carried out on multi-phase flow mechanism in composite media and efficient development methods, and provided an important guarantee for the efficient development of large oil and gas fields [79⇓⇓⇓⇓⇓-85]. This study investigated sulfur deposition and water intrusion after steady production and recovery enhancement in Puguang Gasfield as a high sulfur-containing sour gas reservoir of reef-shoal facies, and detailed description, flow mechanism and development methods in the ultra-deep fault-controlled fractured-cavity reservoirs in Shunbei oil and gas field.
3.1. Reef-shoal high-sulfur sour gas reservoir
Successful development of high-sulfur sour gas reservoirs in Puguang and Yuanba fields has been done. However, challenges such as sulfur depositing and blocking the wellbore, and rapid breakthrough of edge and bottom water, always result in a notable decline in gas production and recovery in late stable production stage.
3.1.1. Sulfur deposition laws and countermeasures in reservoir and wellbore
Previous studies on sulfur deposition primarily depended on empirical formulas and dynamic monitoring to qualitatively predict sulfur deposition in wellbore and formation [86]. We carried out numerous physical experiments and numerical simulations on the phase characteristics of sulfur-sour gas mixing system and the flow of sulfur and natural gas in reservoir to summarize the law of sulfur deposition in reservoir and wellbore, and finally developed a numerical simulation technology for predicting sulfur deposition quantificationally in reservoir and wellbore [85,87]. The coincidence between prediction and field measurement is 92%. Effective countermeasures have been proposed for removing sulfur deposit in gas wells with high sulfur content.
A newly developed non-toxic elemental sulfur absorption solvent and an experimental method utilizing chromatography-mass spectrometry for determining sulfur content have been proposed to facilitate safe and high-precision measurement of sulfur solubility in sour gas. The sulfur content of the Puguang Gasfield is 0.35-0.78 g/m3, and the liquid sulfur precipitation pressure is 24.1-29.5 MPa. In the Dawan gas reservoir, the sulfur content is measured at 0.1-0.22 g/m3, and the solid sulfur precipitation pressure is 19.2-28.6 MPa [87-88]. A three-phase relative permeability chart for gas, water and liquid sulfur in Puguang Gasfield was built by using a novel unsteady state method and device for measuring water-liquid sulfur relative permeability. At 40% liquid sulfur saturation in the reservoir pores, gas permeability decreased by 70%, and 6% solid sulfur saturation resulted in a 40%-60% decrease in gas permeability (Fig. 8 ).
Fig. 8. Gas permeability loss for gaseous and solid sulfur. Cores I, porosity of 20.94%, permeability of 404×10−3 μm2; Cores II, porosity of 9.35%, permeability of 3.08×10−3 μm2. |
A numerical simulation model was developed to achieve quantitative prediction of sulfur deposition in both wellbore and reservoir. Quantitative prediction for development wells in Puguang Gasfield indicates that as formation pressure decreases, sulfur blocking point gradually shifts downward to approximately 2 500 m in the wellbores, with increasing downward velocity. Elemental sulfur primarily accumulates within 3 m near the wellbore while peak saturation occurring approximately 0.5-1.0 m away from the wellbore [87]. Sulfur deposition in Dawan gas reservoir can be divided into three stages: no deposition, early slow sulfur deposition and later rapid sulfur deposition. The simulated sequence of sulfur precipitation is consistent with the observed change of formation pressure in all wells. Based on the quantitative prediction, two unblocking methods, i.e., wellbore sulfur solubilizer, and sulfur solubilizer + coiled tubing, and unblocking models were proposed for determining the timing and frequency of unblocking gas wells. Field application has proved their unblocking effectiveness.
3.1.2. Water invasion laws and countermeasures
Early prediction and identification of water invasion in gas reservoirs relied primarily on the material balance method to establish a dynamic prediction model. The model calculates the advancing distance and height of the gas-water contact and predicts the water breakthrough in gas wells [89]. This study takes Puguang Gasfield as a case to conduct a comprehensive analysis of reservoir heterogeneity, identify the front of water invasion and analyze the pattern of water invasion, and finally formulates a full life-cycle water control plan for reef-shoal gas reservoirs with edge and bottom water.
Fractures (structural and dissolution fractures) significantly impact producing reserves and water intrusion, so a reservoir classification scheme for reef-shoal reservoir was proposed based on reservoir space and porosity-permeability characteristics combined with liquid production profile [90]. A refined modeling method for dual-porosity reservoir based on sedimentary simulation was developed, alongside a geological model for strongly heterogeneous reservoir of reef-shoal facies. Innovative application of the “controllable source time-domain electromagnetic method” combined with seismic attributes was employed to identify and characterize the front of water intrusion. Integration of modeling and numerical simulation finely delineated the changes in the front of water intrusion and its three-dimensional spatial distribution [87,90]. It is predicted that the front of water intrusion in Puguang Gasfield has advanced over 1 000 m on average. To control water breakthrough, a development plan focusing on controlling production pressure difference and improving vertical production profile and plane water invasion path was proposed. Specifically, for water-free gas wells, production prediction models based on advantageous water invasion channels and non-advantageous channels are used to conduct differential production allocation. This can reduce the pressure difference in gas wells in high-permeability zones while increasing the pressure difference in gas wells in non-high- permeability zones to slow down water breakthrough and make gas-water-contact advance evenly. For gas wells producing water or flooded, water discharge and plugging are effective measures. Water production-based chart and water flooding based chart are established to determine the geological and technological conditions for water discharge and plugging, ultimately forming a comprehensive water control strategy for the entire life cycle of gas wells [87]. Implementation of this strategy has led to a 32.4% reduction in the water intrusion velocity of the Puguang Gasfield. Furthermore, it is forecasted that the overall water invasion front will maintain equilibrium after 2026.
3.2. Fault-controlled fractured-cavity oil and gas reservoirs
The geological characteristics and development laws of the ultra-deep fault-controlled fractured-cavity reservoirs in Shunbei oil and gas field are significantly different from those of the weathering karst fractured-cavity reservoirs in Tahe oilfield. Shunbei oil and gas wells are characterized by high initial production, fast decline (by 25% yearly), and short stable production (1-2 a). It is urgent to investigate the flow mechanism in the composite medium at high temperature and high pressure, and make out effective development methods.
3.2.1. Flow mechanism and development methods
During the development process, Ultra-deep fault-controlled fractured-cavity oil and gas reservoirs in Shunbei exhibit characteristics of stress-sensitivity in the reservoir and complex phase changes in condensate reservoirs.
In order to study the fluid flow mechanism, a large stress-sensitive flow experimental device that can work at high pressure and temperature was developed. By uniformly and simultaneously increasing pressure inside and outside and following optimal procedures, fractured- cavity-type core samples are free from damage, and physical simulation can be conducted to simulate the process of in-situ stress recovery, depletion and water injection [91]. The experimental results showed that the effective stress coefficient of the fractured-cavity reservoir was not fixed at 1, but fluctuated between 0 and 1 depending on the changes in confining pressure and pore pressure. Four effective stress coefficient calculation methods were established for single-fractured reservoir, double-parallel-fractured reservoir, fractured-cavity reservoir and cavity reservoir, respectively. Furthermore, the relationship between effective stress and permeability is established based on experimental results from above. It is found that as effective stress increases, permeability may decrease by 25% to 50%, and production practice also indicates that as pressure drops, permeability decreases and production declines rapidly.
To investigate the complex phase changes, continuous sampling was applied at an equal interval (every three months). It's found the phase change in ultra-deep fault-controlled fractured-cavity condensate gas reservoirs is different from conventional condensate gas reservoirs. Specifically, the dew point pressure gradually increases during the development of ultra-deep fault-controlled fractured-cavity condensate gas reservoirs, while it gradually decreases in conventional carbonate oil and gas reservoirs. This indicates that fault-controlled reservoirs are thick with significant fluid gravity differentiation [92]. Moreover, in fault-controlled reservoirs, once the reservoir pressure drops below the dew point, the retrograde condensate volume rapidly increases, whereas in conventional reservoirs, this increase is gradual. Therefore, to enhance the condensate oil recovery of fault-controlled reservoirs, it is more important to keep the reservoir pressure above the dew point. Experimental results show that condensate oil recovery is the highest when reservoir pressure is kept 3-5 MPa above the dew point.
Based on the understanding of flow mechanism and fluid phase behavior, development methods suitable for present oil reservoir and condensate gas reservoir were established. To cope with the large change in effective stress and rapid production decline, a water and natural gas injection method was proposed, which is featured by low- pressure water injection, high-pressure gas injection and low-intensity injection and production for producing fractured-cavity reservoirs. Field application in the Shunbei No. 1 fault zone increased oil production from 1 000 t/d to 1 456 t/d, and the cumulative oil production has been increased by 78×104 t. Following the characteristics of large thickness and rapid phase change, a "top injection and bottom production" method was proposed for producing condensate gas reservoir because gas injection at structural top can supplement energy, suppress channeling and plug water. Four gas injection plans were prepared for the four units in the Shunbei No. 4 fault zone. It’s predicted that condensate oil production will increase by 69.9×104 t, and the oil recovery will be enhanced by 8% to 13%.
3.2.2. Fine geological model, numerical simulation and production prediction
The ultra-deep fault-controlled fractured-cavity reservoirs in Shunbei are mainly controlled by strike-slip faults whose scale and activity control the scale and spatial heterogeneity of the reservoirs [4,20,35]. Based on the understanding of the reservoir characteristics, three-dimensional geological modelling procedures were proposed [93] by first establishing a fault framework and then internal structures and attribute parameters (Fig. 9 ).
Fig. 9. Technical procedures for geological modeling of deep fault-controlled fractured-cavity reservoirs. |
Based on the controlling effect of faults, various geophysical sensitive attributes such as wave impedance, structural tensor, frequency division energy, coherence, ant tracking, likelihood and others were utilized to describe middle-large fractures and caves, small fractures and pores by combining drilling and testing data. Machine learning was adopted for porosity modeling and prediction. 4D geo-mechanical analysis and dynamic inversion of physical parameters were conducted for spatial depiction and quantitative characterization of external profile and internal structures. The characterization accuracy of the fault-controlled fractured-cavity reservoir at 8 000 m has been improved from 30 m to 15 m based on the model built for the Shunbei No. 1 and No. 4 fault zones in the Tarim Basin.
In the development of ultra-deep fractured-cavity reservoirs, the impact of stress deformation and fluid temperature changes on production must be taken into accounts. A fluid-solid-thermal coupling mathematical model was established to describe the variations in porosity and permeability of composite media in response to stress and temperature changes [93]. To solve the coupled model with multiple equations and variables, the explicit solution method was used. Compared with the fully implicit solution method, the former avoids the calculation of nodal displacement and reduces the number of equations and primary variables in the numerical model [94]. By incorporating the varying stress fields of different fractures and caves, as well as the effect of stress on porosity and permeability, the simulation results are more consistent with the measured data. Using the fluid-solid-thermal multi-field coupling numerical simulation software specially developed for composite media, production indicators including production, water cut and pressure were predicted in Well group SHB1-15 in the Shunbei No. 1 fault zone. The compliance rate between the production history and the predicted data is 85.4% (Fig. 10 ), and the distribution of remaining oil is clear.
Fig. 10. Model and simulation results of a typical well group in Shunbei No. 1 fault zone. |
4. Conclusions
Fault-controlled carbonate reservoir and ancient dolomite reservoir are two important types of reservoirs in deep and ultra-deep marine carbonate formations. According to their genesis, fault-controlled reservoirs can be divided into three types: fault-controlled fractured-cavity reservoir, fault-fluid controlled reservoir and fault-facies- dissolution co-controlled reservoir. Ancient dolomite reservoirs include two types: microbial mound-shoal dolomite reservoir and gypsum-bearing dolomite reservoir in evaporite platform. The compressive frame of Sinian microbial dolomite was formed in an aragonite-dolomite sea environment. The reservoir space was created through penecontemporaneous meteoric water leaching and supergene karstification. Early hydrocarbon charging and acidic fluid in the burial process are favorable for long-term preservation of reservoir space of microbial mound-shoal facies. Three factors, namely dominant mound-shoals associated with evaporite, early dolomitization and dissolution, and evaporite caprock and overpressure, are important for the development and preservation of high-quality dolomite reservoirs in gypsum-bearing evaporite platforms.
The organic-rich shale of marine carbonate facies is developed in five types of depositional environments, including deep-water shelf on passive continental margin, deep-water shelf in intra-platform rift, deep-water shelf in intra-continental depression, carbonate ramp, and transitional tidal flat-lagoons. The original hydrocarbon phases from hydrocarbon source kitchens and late secondary modification control the fluid phase in present deep and ultra-deep reservoirs, and the tectonic-thermal system is an important controlling factor as well. Dynamic fields control the distribution of oil and gas reservoirs. The deep and ultra-deep marine carbonate reservoirs in the superimposed basins in central and western China are influenced by a modified dynamic field. Deep and ultra-deep marine carbonate reservoirs are characterized by "three-element controlling reservoir, multi-source and multi-stage hydrocarbon supply and multi-field controlling hydrocarbon accumulation", and the enrichment law of "large and developed source rocks and reservoirs, effective hydrocarbon accumulation and preservation".
During the development of high-sulfur sour gas reservoirs, sulfur deposition can cause wellbore and reservoir blocking. Liquid sulfur precipitation takes place at 24.1-29.5 MPa in Puguang sour gas field and solid sulfur precipitation at 19.2-28.6 MPa in Dawan gas reservoir. Sulfur deposits occur in wellbore and near-wellbore zones. Based on the prediction results of sulfur deposition, an optimization model is available for determining the timing and frequency of removing sulfur deposits in gas wells. It is proposed that the combination of wellbore sulfur solubilizer with coiled tubing is an effective measure for removing sulfur deposits. Water invasion front can be traced through controllable source (time-domain) electromagnetic survey with seismic attributes. The spatial distribution and changes of water invasion front can be described by building a dual-medium numerical model. Following the changing law of water invasion front, water control measures for the entire life cycle of a gas well are proposed, including water drainage and plugging, with significant effects.
The ultra-deep fault-controlled fractured-cavity reservoirs in Shunbei are stress-sensitive. As pressure drops, the permeability of the fault-controlled fractured-cavity reservoirs decreases greatly, leading to a rapid decline in production. Fault-controlled condensate gas reservoir is different from conventional condensate gas reservoir in the changing law of fluid phase. The dew point pressure of fault-controlled condensate gas reservoir rises in the development process, and the retrograde condensate volume rises rapidly when pressure is as low as the dew point pressure. Pressure drop significantly affects the condensate recovery. Gravity-driven development method for oil reservoirs known as "water injection + natural gas injection" and gas-driven method for condensate gas reservoirs known as "top injection and bottom production" have improved the production significantly. A hierarchical geological modeling approach and fluid-solid-thermal numerical simulation by considering porosity and permeability changing with stress and temperature can precisely predict the dynamics of development and production of fault-controlled fractured-cavity reservoirs.
Acknowledgments
We thank Sinopec Northwest Oilfield Company, Exploration Company, Southwest Oil and Gas Company, Zhongyuan Oilfield Company and North China Oil and Gas Company for providing valuable information in preparation of this paper.