An Overview of the Differential Carbonate Reservoir Characteristic and Exploitation Challenge in the Tarim Basin (NW China)

Abstract

The largest marine carbonate oilfield and gas condensate field in China have been found in the Ordovician limestones in the central Tarim Basin. They are defined as large “layered” reef-shoal and karstic reservoirs. However, low and/or unstable oil/gas production has been a big challenge for effective exploitation in ultra-deep (>6000 m) reservoirs for more than 20 years. Together with the static and dynamic reservoir data, we have a review of the unconventional characteristics of the oil/gas fields in that: (1) the large area tight matrix reservoir (porosity less than 5%, permeability less than 0.2 mD) superimposed with localized fracture-cave reservoir (porosity > 5%, permeability > 2 mD); (2) complicated fluid distribution and unstable production without uniform oil/gas/water interface in an oil/gas field; (3) about 30% wells in fractured reservoirs support more than 80% production; (4) high production decline rate is over 20% per year with low recovery ratio. These data suggest that the “sweet spot” of the fractured reservoir rather than the matrix reservoir is the major drilling target for ultra-deep reservoir development. In the ultra-deep pre-Mesozoic reservoirs, further advances in horizontal drilling and large multiple fracturing techniques are needed for the economic exploitation of the matrix reservoirs, and seismic quantitative descriptions and horizontal drilling techniques across the fault zones are needed for oil/gas efficient development from the deeply fractured reservoirs.

1. Introduction

With the quick depletion of the shallow oil/gas resource, the ultra-deep (>6000 m) marine carbonate resource has become one of the most important oil/gas exploration and development domains on Earth [1,2,3,4]. Owing to the pre-Mesozoic carbonate porosity decrease with depth during the long and deep burial environments, the high primary porous reservoirs controlled by high-energic facies and dolomitization are the major hydrocarbon exploitation targets in the deep subsurface [3,4,5]. Unfortunately, there are still many tight carbonate reservoirs (porosity less than 8%, permeability less than 1 mD) in deep pre-Mesozoic carbonate rocks [6,7,8,9]. In this context, karstic and fractured reservoirs with a much higher secondary porosity in tight carbonates have attracted much attention in deep reservoir exploitation [10,11]. The geological characterization and seismic description of the secondary high porosity–permeability reservoirs have been used to optimize target and enhance oil/gas recovery in the deep tight carbonates [10,11,12,13,14,15]. Whereas the secondary reservoirs of the ultra-deep pre-Mesozoic carbonates generally show varied reservoir features with strong heterogeneity, which resulted in a fundamental challenge in reservoir description of the deep reservoirs. Therefore, it is important to describe different types of reservoirs and carry out targeted technologies for oil/gas exploitation in the ultra-deep fields.

The deep Ordovician limestone is the major hydrocarbon exploitation strata in the Tarim Basin (NW China) [10,16,17,18]. Since the 2000s, the average well depth in the Ordovician carbonate rocks has been more than 6000 m. The largest ultra-deep carbonate oilfield and condensate field in the Ordovician have been discovered in the central intracratonic basin, which includes the oilfield in the karstic reservoirs, condensate field in the reef-shoal reservoirs and oil/gas field in the strike-slip fault-controlled reservoirs [16,17,18]. Owing to the fact that the primary pores in the ancient carbonate rocks have almost been lost during the long diagenesis history, the secondary pore (aperture less than 2 mm), vug (aperture from 2 mm to 100 mm), cave (aperture more than 100 mm) and fracture formed the complex heterogeneous carbonate reservoir networks [16,19]. In this way, the carbonate reservoirs have been divided into pore-, vug-, cave- and fracture-types, and the mixed fracture–vug and fracture–cave types by logging data [16,20]. Furthermore, the major controlling element has been widely used to divide the carbonate reservoirs into reef-shoal, karstic and fault-controlled reservoirs in the deep subsurface [8,10,16,17,18]. These reservoir classifications and studies are favorable for oil/gas exploration in the ancient carbonate rocks. However, it is a much more complicated fluid and oil/gas production compared to other kind of reservoirs [10,16]. The horizontal drilling technique and large-scale fracture acidizing technology have been used to enhance hydrocarbon production in heterogeneous reservoirs [8,10,16,17]. Although production can be enhanced several times, there are still a lot of low-production wells in the ancient carbonate reservoirs [10,16,17]. Furthermore, only some stable and high-production wells support most oil/gas production [16,17], and most exploitation wells cannot obtain economic oil/gas production. These have constrained the economic exploitation of the large quantity oil/gas resource from the ultra-deep reservoirs.

For this contribution, we have an overview of the deep Ordovician carbonate oil/gas reservoirs by the static and dynamic reservoir data in the central Tarim intracratonic basin. Furthermore, we discussed the exploitation strategy and challenge of the different reservoirs in the ultra-deep ancient carbonate reservoirs.

2. Geological Setting

The Tarim Basin is the largest petroliferous basin covering an area of 56 × 10⁴ km² in northwestern China (Figure 1). It has undergone multistage tectonic–sedimentary evolution and deposited more than 15,000 m thick Cryogenian–Quaternary strata [16,17]. In a weak extensional setting, a Cambrian–Ordovician carbonate platform of more than 24 × 10⁴ km² area formed in the cratonic basin [16]. With the progressive compression from the southern margin from the middle Ordovician, the E-W trending uplifts initiated to form the uplift–depression architecture in the intracratonic basin [17]. Subsequently, the E-W trending northern and central isolate carbonate platforms has taken shape during the late Ordovician (Figure 1a). Multistage unconformity and fault activities have occurred from the Ordovician to Eogene in the central Tarim Basin [16,17]. The karstification has been widely developed during the late Caledonian period (late Ordovician–Silurian) and early Hercynian period (Devonian) in the central uplift and inherited to the Yanshanian (Jurassic–early Cretaceous) period in the northern uplift [16]. The Cenozoic foreland depressions developed in the basin margins and resulted in quick subsidence of the Lower Paleozoic carbonates in the Tarim Basin [17].

The 100,000 km² circum-Aman petroleum system has formed in the central basin (Figure 1). The petroleum system comprises the south-slope of the Northern Uplift, the Aman transition zone and the north-slope of the Central Uplift [17]. The stratigraphy included Phanerozoic strata with thick Cambrian–Ordovician carbonates (Figure 1c). Several tectonic events that occurred with regional unconformities have influenced the regional uplifting and subsidence of the Paleozoic–Mesozoic strata [16,17]. There is an agreement that there are two sets of source rocks have been confirmed in the early Cambrian shales and some middle–late Ordovician shales in the Tarim Basin [10,16], although their relative contribution to the discovered reserve is still debated. It is thought that the basin has experienced three stages of hydrocarbon generation and accumulation, including the oil emplacement in the late Ordovician–Silurian and Permian periods and gas accumulation in the Cenozoic period [10,16,17]. As a result of multistage oil/gas accumulation, 14 production zones have been formed in the Lower Paleozoic carbonate reservoirs and Silurian–Cretaceous siliciclastic reservoirs in the circum-Aman petroleum system [16,17,18]. The middle–upper Ordovician carbonate reservoirs are the major exploitation strata at a depth of 5000–8500 m. The north-slope of the Central Uplift is enriched in condensate gas in the Upper Ordovician reef-shoal reservoirs and paleokarstic reservoirs in the Middle Ordovician weathering crust [8,16,17]. The south-slope of the Northern Uplift are prolific in oil resource at the top of the Middle Ordovician unconformity [16,17,18]. In the Aman transition zone, the oil/gas resource occurred in the strike-slip fault zones [10]. Recent exploitation suggests that most oil/gas production depends on large-scale fracture-cave reservoirs along the fault damage zones [8,10,16,17,18].

3. The Carbonate Reservoir, Fluid and Production

3.1. Carbonate Reservoir

The middle–upper Ordovician reservoir mainly occur in the grainstones and minor reef limestones (Figure 2) [16]. Due to intense cementation during burial, almost all the primary pores in the Ordovician carbonate have been absent [8,17,19]. More than 90% of the secondary porosity exists in a cave, dissolution vug and pore and fractures (Figure 2). In this context, the carbonate reservoirs can be subdivided into matrix reservoirs and fractured reservoirs.

Although most primary pores are absent by intense cementation, the matrix reservoir developed well along the residual primary porosity in the reef-shoal limestones [16]. The major porosity is from intergranular dissolution pores and vugs (Figure 2a), and a few intragranular and intercrystal dissolution pores. The dissolved pores and vugs generally occur in the grainstones of reef-shoal facies. Core plugs investigation indicates that matrix porosity is 1–15%, and low permeability is less than 0.5 mD (Figure 3a). The porosity from logging data ranges from 0.5% to 8%, and most permeability values are lower than 3 mD in vugs. The pore throat radius is generally less than 0.1 μm in the matrix reservoir. This is in contrast with the fractured samples that exhibit a pore throat radius of more than 5 µm (Figure 3a). The matrix reservoirs in the reef-shoal facies have extremely low permeability to share tight reservoir features.

Fractures are developed in vertical, high-angle occurrence with a narrow aperture in the fractured reservoirs. Generally, multiple sets of fractures form connected fracture networks. Although most fracture porosities have been filled by calcite, dissolved pore and vug are developed along the fracture (Figure 2b). The fractures and their related dissolution vugs and caves formed a large fracture-cave system (Figure 2e,f). The large fracture-cave reservoir presents a high porosity of more than 8% and a high permeability of more than 5 mD (Figure 3b) [10,17]. In addition, the fractured reservoir is characterized by intense vertical and horizontal heterogeneity. These suggest that the fracture reservoir is quite different from the matrix reservoir. It has been shown that most oil/gas wells have penetrated large fracture-cave (diameter >1000 mm) reservoirs. These reservoirs can be identified in seismic profiles (Figure 2f) within the tight matrix carbonates [16]. A large fracture-cave zone is characterized by borehole diameter enlargement, natural gamma increase and resistivity decrease in logging response (Figure 2e) [8]. Log interpretation estimated that porosity and permeability are more than 5% and 2 mD, respectively (Figure 3b). High-production wells generally targeted “bead-shape” reflections in seismic profiles (Figure 2f). Furthermore, most of the high oil/gas production wells have penetrated fracture-caves in fault zones [2]. Although cores are hard to be obtained from large caves, drilling breaks and mud overflow and loss indicated that wells encountered large fracture-cave reservoirs during the drilling process [8,16].

The matrix reservoirs are generally developed along the reef-shoal facies in large areas (Figure 4a) [8,16]. Through seismic and borehole data, the microfacies and lithology have large variations, and the porosity and permeability vary frequently in vertical and horizontal directions. On the other hand, the large caves are only scattered in localized areas less than 10% of the matrix reservoirs and changed in vertical more than 300 m with multiple layers. Recently, the largest strike-slip fractured reservoirs have been found in the ultra-deep Aman depression [10,18]. The exploitation targets are mainly fracture-cave reservoirs in strike-slip fault damage zones (Figure 4b). The high-resolution seismic acquisition and processing have been carried out to detect the small strike-slip fault and fracture-cave reservoirs [10,21]. Generally, the seismic attributes have been used to identify strike-slip fault zones. Furthermore, large fracture-cave bodies are identified by seismic inversion, amplitude attributes and structural tensor attributes [10]. These seismic data suggest that the fractured reservoirs are characterized by strong heterogeneity in the strike-slip fault zones.

3.2. Fluid Distribution

In the circum-Aman petroleum system, heavy oil, normal oil, volatile oil and dry (CH₄ content > 90%) and wet (C₂+ content > 10%) gas coexist with different fluid properties in the Ordovician carbonates (Figure 5) [10,16,17].

In the condensate field in the Central Uplift (Figure 5a), the oil density varies between 0.72 and 0.87 g/cm³ (20 °C), oil viscosity varies between 0.8847 mPa·s and 8.117 mPa·s (50 °C), sulfur content varies between 0.05 and 0.5% and wax content is varied in a large range of 1.1–20.6%. The gas contents are variable in a large range, including CH₄ (61.2–95.98%), C₂H₆ (0.72–10.35%), CO₂ (0.12–5.08%) and N₂ (1.04–16.34%). The average relative gas density is 0.58–0.88. H₂S is commonly in a large range of 0–23,600 mg/m³. It noted that dry gas can coexist with normal oil that presents a density of up to 0.85 g/cm³ from a well. The GOR (oil/gas ratio) varies from 0 to 3600 m³/m³. Although most GOR values are more than 1200 m³/m³, some values are lower than 500 m³/m³ and present higher oil density.

In the Lunnan area of the Northern Uplift, there is a progressive transition from heavy oil to light oil and to condensate gas from the western to the eastern area (Figure 5b). Crude oil is characterized by high density, high viscosity, high sulfur and high wax content [16], whereas some oil data present low density and low wax content. These suggest that there are complex oil origins and distributions. There is generally wet gas in the western area and dry gas in most eastern wells. The CH₄ content varies at 65–98% with a drying coefficient of 0.79–0.98, suggesting a combination of wet gas and dry gas.

3.3. Oil/Gas Production

Generally, the large-scale fracture-cave reservoir in the ancient carbonates could yield high oil/gas production [8,10,16]. Through the statistical data, more than 90% of high production wells are from localized “sweet spots” of fracture-cave reservoirs, whereas most high matrix reservoirs cannot obtain economic oil/gas production (Figure 6a). Even through the DST (drill stem test) and acid fracturing, the matrix reservoirs only provided low and unsteady production [8,16,17]. The test data suggest that there is a large range of permeability in the Ordovician reservoirs (Figure 6b).

Many wells have periodical variations in the production of oil/gas and water, with some even experiencing sudden output increases during production [8,17]. Oil/gas production can vary vastly during the production period. For example, oil density in a well increased from 0.78 g/cm³ to 0.86 g/cm³, and the gas/oil ratio of ~2000 m³/m³ decreased to about ~500 m³/m³ during the production period. This indicates changes in different fluid properties and phases from different reservoir compartments. Thus, reserve assessment based on assumed traps using a volumetric method is challenging, which in turn, complicates the evaluation and development of these reservoirs [8,10,16]. It is noted that most high oil/gas production wells fall into the fault zones (Figure 7), although they are assumed to be large-scale layered reef-shoal facies-controlled reservoirs and unconformity-controlled karstic reservoirs. This is contrary to the previous studies from the exploration data.

Fracture-cave reservoirs show a bottom water that often led to fast water flooding during the production. In contrast, production wells in reef-shoal reservoirs have a relatively lower water ratio [8]. This indicates that there are inactive bottom-water and edge-water in most reef-shoal reservoirs, whereas there are still a few water wells with high production in localized heights. These complex fluid behaviors provide difficulties in predicting production performance and management of water flooding during production [8,16]. In addition, the oil density and gas/oil ratio are unpredictable during production. Even in the same well, fluid may vary during production. This indicates strong heterogeneity and complicated connectivity in different reservoir compartments.

Production data generally show a quick decrease in oil/gas production in many wells (Figure 8a) [8,16,17]. The unstable production and water flooding are big challenges for the development of the Ordovician oil/gas fields. According to the statistical data analysis, about 30% of exploitation wells cannot turn to economical production, and most wells have low oil/gas production from the initial production period. Furthermore, only 30% of wells penetrated the “sweet spots” of fracture-cave reservoirs could yield stable oil/gas productions. Statistically, less than 30% of wells have supported more than 80% oil/gas production in the carbonate fields. Well production has also rapidly declined to a rate of more than 20%, and most production wells cannot provide economical production for more than 6 years. In the Central Uplift, the composed decline rates of gas and condensate oil are in the range of 21.6–14.9% and 26.9–27.3%, respectively (Figure 8b). Through new production methods and technology, the decline rate of oil decreased from 34.6% to 22.1% in one block in the Northern Uplift. Furthermore, the estimated oil and gas recovery ratios are less than 20% and 50%, respectively.

4. Discussions

4.1. The Production in Different Reservoirs

Generally, the high-energy facies in the Ordovician period have been assumed as the basic condition for the porosity development in the ancient reservoirs [16,22,23,24]. This agrees with the fact that high oil/gas production wells in the reef-shoal facies are much more than that in the carbonate intraplatform [8,16]. However, more than 90% of primary pores are absent in the long diagenetic history [16,17,19,25]. The residual primary porosity is less than 0.5% in the reef-shoal reservoirs. It has beenargued that the Ordovician platform margin is favorable for the penecontemporaneous dissolution [16,22,23,24], whereas more borehole data have shown that most reef-shoals along the Ordovician carbonate platform margins present tight reservoirs with low-porosity (<2%) and low-permeability (<0.2 mD). Further studies suggest that the high matrix porosity is related to transitional karstification by the thrust uplift in the central Tarim Basin [8,17,26]. Even so, the highly porous matrix reservoirs cannot support the high oil/gas production of their low permeability (<2 mD) (Figure 6b). It has been suggested that the karstification and thrust fault-related fracture network could have resulted in the development of large fracture-cave reservoirs [8,26]. Furthermore, a recent study indicates that fracturing plays an important role in the dissolution porosity development in the strike-slip fault zone [27]. In the fault damage zones, the fracturing and dissolution could increase the porosity by more than 50% and the permeability of more than 1–2 orders of magnitude. These suggest that the matrix reef-shoal reservoir cannot support economical oil/gas production, and the fractured reservoir is the major target for the effective exploitation of the deep hydrocarbon resource.

Generally, karstification has contributed to the major factor of the unconformity reservoirs [16,28,29,30]. More studies suggest that multistage fracturing is important for the development of the “sweet spots” of fracture-cave reservoirs on the unconformity [10,13,17,21]. During multiple faulting periods, the fracture networks developed well in the strike-slip fault zones and the thrust fault zones [17,31,32]. Generally, the fracture porosity is less than 0.5% in the fault zone, but the permeability of the fractured reservoir could be increased more than one order of magnitude in the fault damage zone (Figure 3 and Figure 6b). Furthermore, the fracture network is favorable for the contemporaneous karstification in the fault zone. In addition, the fracture network is the preferential passage for dissolution porosity development during the long burial history [16]. Particularly, the fracture-cave reservoir developed well in strike-slip fault zone which is favorable for these karstic and burial dissolutions (Figure 1) [10,13,33]. The permeability and porosity in the fractured reservoirs can be more than 10 mD and 10%, respectively (Figure 3). This suggests that fractured reservoirs developed well along the fracture network by multiple dissolution processes during the diagenetic history. This is in agreement with the fault damage zone controlled the distribution of the fractured reservoirs that are composed of strong heterogeneous multi-modal pore system of fracture, pore, vug and cave. In contrast to the tight matrix reservoirs, the large-scale fractured reservoirs are favorable for high oil/gas production in the Ordovician carbonate fields, particularly in the deeper Aman depression.

Subsequently, the ancient complex carbonate reservoirs can be divided into matrix reservoirs and fracture-cave reservoirs. The matrix reservoir is composed of intergranular and intragranular dissolution porosity and is absent from the fracture network and cave system. This kind of reservoir has extremely low porosity (<5%) and low permeability (<0.5 mD) that are consistent with the tight reservoir [34,35,36]. It generally occurs in the high-energy reef-shoal bodies to show large areas of the continuous tight reservoir (Figure 4a). The matrix reservoirs generally lack a uniform oil/gas/water contact and it is hard to obtain economical oil/gas production by conventional and unconventional exploitation methods. On the contrary, the fracture-cave reservoir is generally developed in the localized fracture network in the fault zone and cave system at the top of the Ordovician carbonate unconformity [17]. This kind of reservoir can enhance permeability by more than one order of magnitude and porosity more than two times in the carbonate reservoirs. The fracture-cave reservoir is generally characterized by relatively high porosity (>6%) and high permeability (>2 mD). Recent oil/gas development and studies suggest that most high-production wells occurred in the fault zone [10,17,33]. The large fracture-cave body has been the “sweet spot” for the high production well optimization in the Ordovician carbonate oil/gas fields [8,10,18].

4.2. Technology Advance and Challenge for Effective Exploitation

The oil/gas geological reserve discovered in the Ordovician fields is more than 10 × 10⁸ t oil equivalent in the Tarim Basin. Recently, large amounts of oil/gas reserves have been found in the Aman depression with a production of over 5 million t/y, which has been the largest ultra-deep strike-slip fault-controlled oilfield on the Earth. However, there are serious challenges to exploit economically with conventional and unconventional technologies in the ultra-depth [10,16]. Unconventional reservoirs are generally defined by their low porosity (<10%) and low permeability (<1 mD) [6,34]. Unconventional carbonate reservoirs have been documented in the Tarim Basin [8,16], and share the same poro/perm characteristics of tight siliciclastic reservoirs [34,35,36,37], whereas large amounts of oil/gas resources could be exploited from fractured tight carbonates with low petrophysical properties from the ultra-deep Tarim Basin. In this view, the ancient reservoir in the Tarim Basin is quite different from conventional reservoirs in line with the state of hydrocarbon, the geological nature of reservoirs, fluid and production and particularly the required technology to exploit these hydrocarbon resources. Their complicated fluid distribution and lack of distinct oil/water contact are inconsistent with Darcy flow in the conventional reservoirs [8,16]. Given that low and/or unstable oil/gas production from the complicated reservoirs, economic exploitation has been a tough challenge for more than 20 years [18].

Generally, the trapping mechanism for the Ordovician reservoirs is assumed to be stratigraphic controlled by laterally vertically sealed reef-shoals and by unconformities [16]. The identification of the boundaries and shape of these traps remains difficult, although there are extensive analyses of reservoir correlation, geochemistry comparison, seismic attribution predictions, and production dynamic data. High-resolution 3D seismic acquisition under the thick desert, seismic reservoir prediction methods have been used in the deep reservoir description [10,16]. The advance in seismic attribute and inversion technology has increased the reservoir prediction accuracy for well optimization [10,16,18,21]. Some studies showed that the prestack attribute seismic wave attenuation has a great potential to predict fractured reservoirs [37,38]. Many wells targeted the “sweet spot” reservoirs and have gained high oil/gas production in the Tarim Basin [8,10,21,33]. As a result, the mud leakage rate increased by more than 10%, and the reservoir encountering rate increased by more than 10% in the ultra-deep Tarim Basin. With the advance of the seismic reservoir description, more than 90% of high production wells have been penetrated the large fracture-cave reservoir, whereas the small cave, fracture system and high-porosity matrix reservoirs are quite difficult to be identified precisely in the deep carbonate rocks at more than 6000 m [10,21]. Furthermore, the connectivity among the fracture networks and reservoirs in the fault damage zone is a big challenge during well employment and oil/gas production.

Large-scale acid fracturing technology has been used in most wells (Figure 6a), which is favorable for reservoir connection and remodification in the Tarim Basin [10,17]. Acid fracturing can connect the adjacent fracture-cave reservoirs and enhance the permeability of the matrix reservoirs, whereas most matrix reservoirs cannot gain economic oil/gas production, although the production can increase 2–5 times. Except for the several high-output wells that fell into caves, most wells had low production even after fracturing in the matrix reservoirs. Regardless of a high initial productivity by large-scale fracturing from some matrix reservoirs, there is still a very low yield during production. Thus, more than 30% of wells cannot provide economically beneficial yields. This indicates that the tight matrix reservoirs could not obtain a high production with the application of unconventional technology to enhance reservoir permeability. New methods need further study to enhance the oil/gas production in the matrix reservoirs.

A horizontal well has been carried out in the tight matrix reservoir [8,16,17]. The horizontal penetration often reaches a long distance in excess of 1000 m and aims to penetrate multiple fracture-cave zones. This method, together with multistage acid fracturing, provides production increase five times more production and production stability when compared to simple vertical wells (Figure 9). For example, the horizontal segment length of TZ62-11H reaches 933 m in reef-shoal reservoirs, and the oil and gas production is up to 64 t/d and 32 × 10⁴ m³/d, respectively. By staged fracturing, the production increased 2–4 times to provide considerable benefits. On the other hand, it is hard to manage water flooding during the production of horizontal wells. To enhance the oil/gas recovery, the techniques of water and gas injection have been in experiments and potential to enhance the recovery by more than 5%. Considering the intense heterogeneity and complicated fluid distribution in the deep reservoirs, the challenge mainly involves unstable and low oil/gas production and complicated water flooding.

In conclusion, the integration of advanced methods to analyze high-quality 3D seismic data with horizontal drilling and acid fracturing has resulted in the economic production in the ultra-deep Pre-Mesozoic reservoirs, but there are still challenges in the unstable and quick decline of the oil/gas production. The technique portfolio targeted for different reservoirs is being in the application to enhance the oil/gas production in the ultra-deep reservoirs, including the fractured reservoirs by seismic quantitative description and horizontal drilling, and matrix reservoirs by horizontal drilling and multiple fracture acidizing.

5. Conclusions

Regardless of the complicated ultra-deep Ordovician carbonate reservoirs in the Tarim Basin, we argue the following major conclusions.

• The ancient carbonate reservoirs can be divided into matrix and fractured reservoirs, which correspond to the low and high poro/perm reservoirs, respectively.
• The localized fracture-cave reservoirs are the “sweet spots” for ultra-deep oil/gas field exploitation, but the matrix carbonate reservoirs are too tight to obtain economic production by conventional/unconventional development methods.
• It needs further advances in horizontal drilling and large multiple fracturing techniques for the matrix reservoir exploitation, and seismic quantitative description and horizontal drilling techniques across the fault zone for the fractured reservoir production.