The Lower Paleozoic carbonate rocks represent an important exploration target in craton area of the Tarim Basin. Since the 1990s, a number of large- and medium-sized oil and gas fields, such as Tahe, Lunnan, Yingmaili, Tazhong and Halahatang, have been discovered in this region, contributing a cumulative petroleum in place exceeding 22×10⁸ t^[1]. The Lower Paleozoic in the Gucheng area lies on the margin of the carbonate platform transiting from the Taxi platform to the eastern Tarim Basin (or Tadong), with platform margin reef beach complex over 1000 m in thickness, and is adjacent to the Cambrian-Lower Ordovician source rocks, possessing favorable reservoir-forming conditions^[2]. Over nearly 10 years, 18 exploration wells have been drilled, of which 3 wells revealed commercial gas flow. Nevertheless, no proven reserves have been obtained so far, which makes many people question the exploration potential of the Lower Paleozoic carbonate rocks in this area. Based on a systematic review of previous studies, it is found that four main problems restrict oil and gas exploration in the study area. (1) With the drilling of a series of deep wells in the Tazhong and Bamai regions, it is confirmed that there is a pre-Cambrian paleo-uplift in EW trend in the southwest of the Tangnan-eastern Tazhong-Gucheng. It is controversial whether the Cambrian Yuertusi source rocks are developed in the Gucheng area under the background of the paleohigh geomorphology. (2) The Gucheng area, located on the slope of the Tazhong uplift, is low in structural position and has not experienced prolonged uplift and denudation^[3,4], so the carbonate has suffered little exposure and dissolution, and the genetic type and distribution scale of reservoirs remain murky. (3) In the Gucheng area, the source rocks mature earlier^[5], structures are complex and experienced multi-stages of reformation, making the gas-water distribution unclear. (4) Oil and gas shows are found in the dolomite and limestone strata from the Cambrian to the Ordovician of up to 1000 m thick over a wide stratigraphic span, but the target strata are not definite.

Regarding the Lower Paleozoic carbonate rocks in the Gucheng area, previous studies focused on the sedimentary evolution^[6,7], genetic types of dolomite^[8,9,10,11], and fault characteristics^[12,13], but rarely dealt with the major source rocks, reservoir characteristics, hydrocarbon accumulation pattern, and key exploration targets.

We have examined continuously key factors affecting hydrocarbon accumulation and evaluated prospective areas for the Lower Paleozoic carbonate rock in the Gucheng area. Based on the analysis of core, thin section, well logging, seismic and testing data, we investigated the source rock conditions, reservoir conditions, caprock conditions and accumulation conditions of the Lower Paleozoic carbonate rock in the Gucheng area, and evaluated the exploration potential of four sets of reservoirs in the Lower Paleozoic, in the hope to promote oil and gas exploration in this area.

The Gucheng low bulge is located in the middle part of the central uplift of the Tarim Basin, and the slope of the Tazhong uplift. It is adjacent to the Tazhong uplift in the southwest through the Tazhong I fault, the Manxi low bulge in the north, and the Tadong uplift and Manjiaer sag in the east and northeast through the Cambrian-Middle-Lower Ordovician platform margin slope break zone. Overall, the Gucheng low bulge is a large, wide and gentle nose-like structure in the Lower Paleozoic dipping to the northwest (Fig. 1a).

The Cambrian-Ordovician strata are complete in the Gucheng area, with the stratigraphic sequence in the Cambrian to the Early Upper Ordovician consistent with the Taxi platform facies area, and the stratigraphic sequence in the Middle-Late Upper Ordovician consistent with the Tadong basin facies area (Table 1).

In the Cambrian-Early Ordovician, the Tarim Basin was in a weak extensional tectonic setting^[5], leading to a sedimentary pattern of "E-W differentiation, with basin in the east and platform in the west": very thick carbonate rock deposited in the platform facies area in the west, and dark mudstone deposited in the basin facies area in the east. The Gucheng area, at the platform-basin transition part^[14,15], was a gentle slope in the Early Cambrian^{[15,16,17,18,19]}, with granular limestone developed on middle gentle slope and marlstone on outer gentle slope. In the Middle-Late Cambrian, it evolved into a rimmed platform, with reef beach facies deposits at the platform margin^[15]. In the early stage of Early Ordovician, the Gucheng area changed from rimmed platform to weak rimmed platform with the sea level rise^[20], with semi-restricted platform tidal flat deposits and intraplatform shoal deposits of Penglaiba Formation developed. From the late stage of Early Ordovician to the Middle Ordovician, the stress state of the area turned into weak compression; with the rise of sea level, the weak rimmed platform evolved into an untrimmed carbonate platform^[20,21], accompanied with the deposition of platform shoal facies. Typically, the lower Yingshan Formation was dominated by fine- to medium-grained dolomite with residual granular structure, and the upper Yingshan Formation by calcarenite; the Yijianfang Formation was dominated by oolitic limestone, calcarenite and bioclastic limestone. In the early stage of Late Ordovician, with the sea level rising continuously, the carbonate platform was submerged^[7], and deep- water platform marlstone in the Tumuxiuke Formation deposited. In the late stage of Late Ordovician, with the enhancement of peripheral compression and the continuous rise of sea level, the Gucheng area gradually evolved from the deep-water platform to overcompensated mixed shelf, receiving super-compensated deposits such as mudstone and argillaceous siltstone of the Que’erqueke Formation^{[3, 7]} (Fig. 1b).

Previous studies on source rocks around Gucheng revealed several sets of source rocks, such as Middle-Lower Cambrian, Middle-Lower Ordovician and Middle-Upper Ordovician^[22]. In recent years, as more exploration wells were drilled in the Gucheng area, it is increasingly convinced that there is no effective source rock in the Middle-Upper Ordovician^[23,24]. Especially, the breakthrough of Well ZS1 made more and more researchers believe that the Lower Cambrian source rock is the main source rock in craton area^[25,26]. Based on field outcrops and new drilling and seismic data, we re-examined the development of source rocks around the Gucheng area.

The Lower Cambrian source rocks are mainly distributed in the Yuertusi Formation in the platform facies area in the west and the Xidashan-Xishanbulake Formation in the basin facies area in the east.

In the platform facies area in the west, the Lower Cambrian source rocks were only drilled by Well XH1 in the Tabei uplift, but not by the deep wells in the Bachu uplift and the Tazhong uplift. According to the drilling data of Well XH1^[27], this set of source rocks are black mudstone with a thickness of 31 m, total organic carbon content (TOC) of 1.00-9.43% (averagely 5.40%) and vitrinite reflectance (R_o) of 1.38-1.55%, representing a set of high-maturity and high-quality source rock. In the basin facies area in the east, the Cambrian Xidashan- Xishanbulake Formation source rock encountered by Wells TD1, TD2, DT1, YD2 and YL1 are 39 m, 33 m, 43 m, 57 m and 61 m thick, respectively. This set of source rocks are dominated by black siliceous mudstone, with TOC of 0.50-3.26% (averagely 2.67%) and R_o of 1.73-2.91%, suggesting as a set of high-over mature source rocks.

In the northeastern part of the Tarim Basin, the Lower Cambrian source rocks were found in several outcrop of Kuruktag area, and they are mainly distributed in the intervals from the upper Xishanbulake Formation to the Xidashan Formation. The source rocks of upper Xishanbulake Formation are mainly siliceous mudstone, with a thickness of 13-48 m and TOC of 0.63-2.90% (averagely 1.66%). The source rocks of Xidashan Formation are black mudstone, with a thickness of 15-30 m, TOC of 0.58-3.56% (averagely 2.67%) and R_o of 1.09-1.93% (averagely 1.87%), suggesting as a set of high-over mature high-quality source rocks, similar to the basin facies area.

The Lower Cambrian source rock is thin and less encountered by wells. So, it is difficult to predict its distribution accurately only by using the drilling and seismic data, and the most reliable method to predict its distribution is based on the Precambrian paleogeomorphology^[28,29]. In this study, the Sinian residual thickness map (Fig. 2a) and Lower Cambrian thickness map (Fig. 2b) of Tadong were plotted using the seismic profiles of the Tarim Basin updated in recent years. It can be seen that the Sinian residual thickness center in Tadong is located in the western part of the Kunan-Manjiaer sag, and the Sinian is missing in the ZS1C-TZ32-Gucheng area in the south (Fig. 2c, 2d). This means that before the Cambrian sedimentation, the terrain was low in the Kunan area and high in the Well TZ32 area. The Lower Cambrian, controlled by the Sinian paleogeomorphology, also has the thickness center located in the Kunan area, and is thick in the north and west, and thin in the south and east.

Based on the Sinian residual thickness map, the Lower Cambrian thickness map, field outcrop and drilling data, the thickness map of Lower Cambrian source rock in Tadong was plotted (Fig. 3). It can be seen that the Lower Cambrian source rock in Tadong mainly occurs in the north of the ZS1C-TZ32-CT1 area, with the thickness center in the Kunan area. The source rock is 30-80 m thick and better in quality in the north than in the south. It is inferred that the source rock of the Lower Cambrian Yuertusi Formation doesn’t exist in the Gucheng area of southwest Tadong.

The Middle Cambrian source rocks are mainly distributed in the Mohe’ershan Formation in the platform margin slope-basin facies areas in Tadong. In the basin facies area, the source rock encountered by Wells TD2, TD1, DT1 and YD2 are 35 m, 31 m, 33 m and 60 m thick, respectively. They are composed of calcareous mudstone, with TOC of 0.51-2.58% (averagely 1.60%) and R_o of 2.54%, representing medium-good source rock. In the Kuruktag outcrop area, the source rocks of the Mohe’ershan Formation are 16-85 m thick, and composed of calcareous mudstone, with TOC of 0.60-0.86%, representing medium source rock. In the platform margin slope facies area, the source rock has not been revealed by any well. However, according to Zhang Shuichang and Jin Zhijun^[30,31], the formation of source rock depends on the productivity of hydrocarbon-generating parent material and the preservation conditions of organic matter. The platform margin slope had moderate water depth and sunlight, frequent ocean current activities, higher bio-productivity and better preservation conditions of organic matter than the basin facies area, and was a favorable area for the development of source rock with high organic matter abundance. Therefore, it is speculated that the high frequency continuous strong reflection from the platform margin towards the basin represent the source rock of platform margin slope facies (Fig. 4a). Through tracing this set of continuous strong reflections in seismic data, the thickness map of the Middle Cambrian source rocks of platform margin slope facies in Tadong were compiled (Fig. 4b). It can be seen that the thickness center of the platform margin slope facies source rock is located in the arc belt on the east side of the Lunnan-Gucheng platform margin, which is about 100 km wide and 150 m thick. This set of source rocks is one of the main source rocks developed in the Gucheng area. The estimated abundance and maturity indices are similar to those of the Lower Cambrian source rocks, but the thickness is larger than that of the Lower Cambrian source rocks.

The Middle-Lower Ordovician source rocks are mainly developed in the Heituao Formation in Tadong, which are a set of basin facies black shale deposits. In Tadong, the Middle-Lower Ordovician source rocks encountered by Wells TD1, TD2, DT1 and YD2 are 48 m, 56 m, 84 m and 151 m thick, respectively, with TOC of 0.63-2.18% (averagely 1.67%) and R_o of 1.78-2.44%. In the Kuruktag outcrop area, the source rocks of Heituao Formation are 30-100 m thick, and composed of black mudstone, with TOC of 0.50-1.64% and R_o of 1.16-2.10%, representing a set of medium-high maturity moderate-good source rock.

According to drilling calibration, the source rocks of Heituao Formation show obvious "double track" continuous strong reflection on the seismic profiles (Fig. 5a, 5b). Through tracking the "double track" continuous strong reflection, the plane distribution of the Middle-Lower Ordovician Heituao Formation source rocks is determined (Fig. 5c). In Fig. 5c, the Heituao Formation source rocks, 50-150 m thick, are mainly distributed in the deep-water basin facies area held by the Gucheng-Lungu East and Luoxi platforms. This set of source rocks are also the main source rocks in the Gucheng area.

In summary, it is inferred that the Middle Cambrian and Middle-Lower Ordovician slope-basin facies source rocks are the main source rocks in the Gucheng area, while the Lower Cambrian Yuertusi Formation source rocks may only develop in the depression to the north of the Gucheng area. The source rock conditions in the Gucheng area may not be as good as those believed previously ^{[5, 22]}.

In the Gucheng area, the Cambrian-Ordovician system has experienced a sedimentary evolution process of gentle slope-rimmed platform-weak rimmed platform-untrimmed platform-deep-water platform-mixed shelf. Controlled by sedimentary environment and tectonic activity, four sets of carbonate reservoirs in two types (reef beach and karst) have developed in the Lower Paleozoic in the Gucheng area. In this paper, the reef beach reservoirs include platform margin reef beach complex and intraplatform grain beach, and they occur in both Cambrian and Ordovician, including the dolomitization beach reservoirs in the lower Yingshan Formation of Middle-Lower Ordovician and the platform margin reef beach reservoirs in the Upper-Middle Cambrian. The karst reservoirs mainly come up in the Ordovician, including the fault- related limestone karst reservoirs in the upper Yingshan Formation of Middle-Lower Ordovician and the interlayer karst reservoirs in the Yijianfang Formation of Middle Ordovician.

3.1.1. Dolomitization beach reservoir in the lower Yingshan Formation of Ordovician

During the deposition of the Yingshan Formation of Ordovician, the Gucheng area was a broad and gentle untrimmed shallow-water carbonate platform (Fig. 6). Influenced by frequent sea level rise and fall, intraplatform beach developed extensively in the area. The medium- to high-energy grain beaches were reworked by dolomitization and later diagenetic fluids to form dolomitization grain beach reservoirs in large area^[32]. So far, many wells have obtained commercial gas flow from this set of reservoir.

According to the core slice data, the reservoir in the lower Yingshan Formation is composed of crystalline dolomite, mainly fine- to medium-grained, which can be divided into two types: (1) fine- to medium-grained dolomite with visible residual grains or phantom grain structure (Fig. 7a, 7b); and (2) medium- to coarse-grained dolomite with unrecognizable original structure (Fig. 7c). The reservoir space comprises intercrystalline pores, intercrystalline dissolution pores, vugs and fractures. The intercrystalline pores and intercrystalline dissolution pores are mainly developed in automorphic- hypautomorphic fine- to medium-grained dolomites, with relatively uniform distribution (Fig. 7b). The vugs are unevenly distributed along fractures, and usually filled with hydrothermal minerals such as quartz and saddle-shaped dolomite (Fig. 7c). The dolomite reservoirs in the lower Yingshan Formation have a core-measured porosity of 0.2-18.6% and logging porosity of 0.1-5.6%, in which the high-quality reservoir section has a core-measured porosity of 1-3% (averagely 1.9%), and logging porosity of 2-5% (averagely 3%). The reservoirs are generally low-porosity and low-permeability fracture-pore and cavern reservoirs.

The high-quality dolomite reservoirs in the lower Yingshan Formation usually have residual grains or phantom grain structure, so it can be inferred that the primary sedimentary facies zone of the reservoir was high-energy grain beach. The fine- to medium-grained dolomites with intercrystalline pores exhibit flat crystal planes, indicating that the dolomitization temperature was low and the dolomite is the product of penecontemporaneous-shallow burial period. The filling of quartz and other hydrothermal minerals in dissolution pores indicates that the reservoir development was affected by hydrothermal dissolution. Seepage silt filling in vugs and fractures is found in the core slices (Fig. 7d), indicating that the reservoir suffered atmospheric freshwater dissolution. In conclusion, the dolomitized beach reservoir in the lower Yingshan Formation might be formed by the process as follows: due to short-term exposure and dissolution and the penecontemporaneous- shallow burial percolation-reflux dolomitization, high-energy grain beach bodies evolved to fine- to medium-grained dolomites with intergranular pores; with the increase of burial depth, the reservoir was gradually compacted under the actions of burial dolomitization and recrystallization; affected by fracturing and hydrothermal dissolution, the reservoir property was improved in the later stage to form the present facies-controlled or layer-controlled fractured-vuggy reservoir.

On the basis of drilling calibration, the distribution of dolomitizaed beach reservoir in the lower Yingshan Formation was predicted by using paleogeomorphology and seismic facies analysis techniques. The dolomitized beach reservoir mainly occurs in the higher paleogeomorphologic positions, has wide and gentle mound-shape on seismic profile, weakly continuous-disordered reflections in the interior, and overlapping of parallel continuous strong reflections on both wings (Fig. 6a). Based on these characteristics, three beach zones and 11 beach bodies were identified in the 3D area of the Gucheng area, covering about 500 km² (Fig. 6b). Among them, the middle beach zone is characterized by high energy and moderate dolomitization, where the reservoir is best developed.

3.1.2. Platform margin reef beach reservoir in the Middle-Upper Cambrian

The platform margin reef beach bodies in the Middle-Upper Cambrian constitute the best reservoir in the Gucheng area, featuring Type I and II reservoirs. Well CT1 encountered the platform margin reef beach body of Phase 3; according to the logging interpretation, there are 9 layers of Type I fractured-vuggy reservoirs of 54 m thick combined, with a porosity range of 4.0-11.2%, and there are 6 layers of Type II vuggy reservoirs of 36 m thick combined, with a porosity range of 2.0-3.2%. Well GC4 encountered the platform margin reef beach body of Phase 4; according to the logging interpretation, there are 4 layers of Type I fractured-vuggy reservoirs with a thickness of 23.5 m combined and a porosity range of 4.0-9.1%, and there are 2 layers of Type II vuggy reservoirs with a thickness of 6.5 m combined and a porosity range of 2.7-3.7%. The platform margin reef beach reservoirs have a core-measured porosity range of 1.2-5.1% (averagely 2.4%) and permeability range of (0.06-30.24) ×10^-3 μm² (averagely 1.03×10^-3 μm²). The core and slice data analysis shows that the Middle-Upper Cambrian platform margin reef beach reservoirs in the Gucheng area are mainly composed of granular dolomite (Fig. 7e), reef (mound) microbial dolomite (Fig. 7f), breccia dolomite (Fig. 7g) and crystalline dolomite. The reservoir space can be divided into two types: 1) fabric-selective pore, including intergranular solution pore, intragranular solution pore, intercrystalline pore, and intercrystalline solution pore; and 2) non-fabric-selective pore, including various vugs and fractures. The intergranular and intragranular dissolution pores mainly exist in micrite dolomite with residual arenaceous structure (Fig. 7h). Such pores were often formed in the early diagenetic stage, and related to the selective dissolution of unstable minerals. Vugs appear in all kinds of dolomites and are typical in breccia dolomite where the gravel margin vugs are dominant (Fig. 7g). They also exist in medium- to coarse-grained hypautomorphic-xenomorphic dolomite in various shapes and often associated with fractures and dissolution fractures (Fig. 7i). The vugs are usually filled with several hydrothermal minerals, such as saddle dolomite, calcite and authigenic quartz, indicating that they might be formed by corrosion of various hydrothermal fluids.

The results of geochemical analysis show that the carbon isotopic compositions of granular dolomite and microbial dolomite range from -1.01‰ to 1.40‰ (averagely -0.08‰), similar to that (from -1.5‰ to 0.5‰) of marine calcite in the same period. The oxygen isotopic compositions range from -8.68‰ to -5.73‰ (averagely -7.41‰), slightly negative compared to that (from -6.9‰ to -4.8‰) of marine calcite in the same period. Moreover, these dolomites have low Fe-Mn content (Fe content of 873-7005 ug/g and Mn content of 40-80 ug/g), and high Sr-Na content, (Sr content of 75-187 ug/g and Na content of 1800-2200 ug/g), and no obvious abnormities of Eu and Ce, with δEu of 0.97-1.07 and δCe of 0.88-1.07, indicating that the granular dolomite and microbial dolomite may be of penecontemporaneous marine origin: the formation of the reservoirs is related to the formation of structural selective pores due to the dissolution of grain beaches by atmospheric freshwater in the penecontemporaneous period, and the inheritance and reworking of preexisting pores by later diagenesis. The breccia dolomite has positive carbon isotope composition (0.69‰-0.16‰), negative oxygen isotope composition (-10.01‰--7.89‰), positive δEu anomaly (1.01-1.44), and negative δCe anomaly (0.86-0.96). Moreover, it has high Fe-Mn content, with Fe content of 2000-30000 ug/g (averagely 12730 ug/g) and Mn content of 300-2000 ug/g (averagely 963 ug/g), and low Sr-Na content, with Sr content of 10-50 ug/g (averagely 16.6 ug/g) and Na content of 200-600 ug/g (averagely 350 ug/g). These parameters indicate that the breccia dolomite reservoir might be intensely reworked by hydrothermal fluids, and the formation of reservoir is related to the generation of breccia overhead cavities due to the karst collapse of microbial reef beach in the early stage and the later reworking of hydrothermal fluids and filling.

According to the characteristics of seismic reflection structure, four phases of platform margin reef beach bodies were depicted in the 3D seismic area of the Gucheng area: Phases I and II developed in the Middle Cambrian and Phases III and IV developed in the Upper Cambrian. These reef beach bodies appear in north-south belts and migrate eastward step by step. Each phase is about 5-10 km wide and 200-500 m thick. The four phases have the overlapping area of about 1200 km² (Fig. 8).

The reservoir space of karst reservoirs is represented by karst pore, karst cave and karst fracture, and has strong heterogeneity^[33]. Traditionally, karst reservoirs are related to obvious surface denudation and peak-mound landform, or to large-scale angular unconformity. Karst fractures and vugs are distributed in quasi-layered form along large-scale unconformity surface or peak-mound landform, concentrating in the range of 0-50 m below the unconformity surface^[34]. The karstification referred to in this paper is not confined to the traditional sense of karstification, but also includes the atmospheric freshwater dissolution in the contemporaneous or penecontemporaneous period and the reworking of carbonate rock by hydrothermal fluid in the burial period^{[11, 35-37]}.

3.2.1. Fault-controlled karst reservoir in upper Yingshan Formation of Ordovician

Fault-controlled karst reservoir refers to the reservoir formed by fluid dissolution of surrounding rock along faults^[35]. As important fluid channels, faults play an important role in the formation of reservoir. When fluid flows through a fault, a series of dissolution-filling processes take place, forming a set of pore-vug-fracture system closely related to the fault.

During the deposition of the upper Yingshan Formation, the water body in the Gucheng area was deep and low in energy; and the open platform facies medium- to low-energy limestone grain beach bodies developed, which is composed of mainly packstone and wackestone. The primitive sedimentary facies belt had poor physical properties and the reservoirs were tight. However, the reservoir physical properties are improved somewhat after reworked by fractures and hydrothermal dissolution. Since no wells have encountered this type of reservoir in the Gucheng area, this paper takes the Shunnan area with similar geological setting as an example to illustrate. In the Shunnan area, wells often had lost circulation or drill break when drilling to the limestone reservoir in the upper Yingshan Formation. For example, Well SN4 had a drill break of 5.48 m in the upper Yingshan Formation, loss of 3700 m³ drilling fluid, and tested a daily gas production of 26×10⁴ m³. The core taken from the well shows that the tight limestone interval has abundant dissolution pores and vugs (Fig. 7j) with quartz, fluorite and other hydrothermal minerals filling in the vug walls, and the granular siliceous rock interval has dissolution pores (Fig. 7k), with granular quartz crystals and intercrystalline dissolution pores observed. These phenomena show that the development of the reservoir may be closely related to fault and hydrothermal dissolution along fault.

The fault-controlled karst reservoirs in the Shunnan area exhibit strong amplitude anomalous reflections related to N-E strike-slip faults on the seismic profiles^[37]. In the Gucheng area, strong amplitude anomalous reflections related to N-E strike-slip faults are also observed (Fig. 9a). On the plane, strong amplitude anomalous reflections are small in scale. The fault-controlled karst reservoirs are 96 km² in the 1500 km² 3D seismic area (Fig. 9b). Vertically, however, the extension thickness of the reservoirs is large, reaching 500-600 m (Fig. 9).

3.2.2. Interlayer karst reservoir in Yijianfang Formation of Ordovician

The interlayer karst reservoir in the Yijianfang Formation of Ordovician is a small-scale interior karst complex, i.e. a paleokarst reservoir occurring in carbonate strata formed by dissolution exposure at different time scales. Its scale is controlled by dissolution exposure time, and amplitude and range of tectonic uplift. Small-scale interior karst is contemporaneous-penecontemporaneous karst, while large-scale interior karst is weathering crust karst related to unconformity. The former can be called interior interlayer karst, and the latter interior weathering crust karst^[36].

The karst reservoir in the Yijianfang Formation of Ordovician in the Gucheng area is small-scale interlayer karst in the contemporaneous-penecontemporaneous period. Its formation mechanism is related to the exposure and leaching of high-frequency sequence and the upward shallowing sequence of third-order sequence^[38,39]. The limestone grain beach of Yijianfang Formation, reworked by interlayer karst with short exposure and leaching at the early stage, formed the reservoir. The reservoir is composed of calcarenite, bioclastic limestone (Fig. 7l) and oolitic limestone (Fig. 7m). The main reservoir space is dominated by moldic pores and intragranular dissolution micro-pores (Fig. 7o, 7p), followed by dissolution fractures (Fig. 7n), of which the dissolution pores have obvious lithofacies selectivity. The physical property analysis shows that the reservoir has a porosity range of 0.4-6.0% (averagely 2.47%, or mostly 2-4%), and a permeability range of (0.007- 6.000)×10^-3 μm² (averagely 0.02×10^-3 μm², or mostly (0.01- 0.02)×10^-3 μm²), representing medium- to low-porosity and low-permeability reservoir. The porosity and permeability have obvious correlation, indicating that the reservoir is pore type. Due to the shielding effect of strong lithologic interface of overlying mudstone/limestone, the reservoir doesn’t have obvious seismic responses, making it difficult to predict (Fig. 10).

There are two sets of caprocks in the Lower Paleozoic in the Gucheng area: (1) the composite regional caprocks composed of silty mudstone in the Upper Ordovician Que’erqueke Formation and tight limestone in the Middle-Upper Ordovician; and (2) the local caprocks composed of tight dolomite, argillaceous dolomite and tight limestone in the Cambrian-Middle-Lower Ordovician. Separated by these two sets of caprocks, two major gas-bearing strata (Ordovician and Cambrian) arise (Fig. 11).

The composite regional caprocks consist of the open platform facies tight limestone direct caprock in the upper Yingshan Formation-Tumuxiuke Formation with a thickness of 500 m and the silty mudstone in the Que’erqueke Formation with a thickness of about 2000-3000 m, which lays above the Lower Ordovician dolomite gas reservoir in the Gucheng area. Previous studies have shown that when there is no large-scale reservoir bed between the regional caprock and the direct caprock, the combined sealing capacity of them is comparable to that of the regional caprock^[40,41]. In the Gucheng area, there is no large-scale reservoir bed between the direct caprock of the Middle-Upper Ordovician tight limestone and the regional caprock of the Upper Ordovician Que’erqueke Formation mudstone. Therefore, the sealing capacity of the composite regional caprocks is equivalent to that of the regional caprock of the Que’erqueke Formation. To date, almost all the gas discoveries found in the Gucheng area are located under the composite caprocks, and the oil and gas shows are rare above the caprocks.

It can be seen from the comprehensive stratigraphic column of the Gucheng area (Fig. 1b) that the Cambrian-Middle and Lower Ordovician does not have traditional high-quality caprocks such as salt rock, gypsum rock and mudstone, and the tight carbonate rock acts as caprock of the Cambrian platform margin reef beach body^[15]. Tight carbonate rocks have been reported as caprocks in large oil and gas fields^[42,43], but the distribution prediction of this kind of caprock has always been a challenge. Currently, the prediction of tight carbonate caprock distribution mainly relies on well data^[44]. There are few wells drilled in the Gucheng area. Phase I and II platform margin reef beach bodies of Cambrian have not been drilled by any well, and Phase III and IV platform margin reef beach bodies have only been drilled by Wells CT1 and CT2. Therefore, the distribution of the Cambrian caprock is mainly predicted according to the sedimentary evolution of platform margin zone and seismic facies analysis under well calibration.

From the Middle Cambrian to the early stage of Late Cambrian, the Gucheng area was a rimmed platform margin, with evaporite facies depositing within the platform under the blocking of the platform margin. Seismic data shows that the western overlying strata of Phases I and II platform margin reef beach bodies exhibit continuous strong amplitude reflections (Fig. 12a). They are calibrated as gypsum dolomite deposits of evaporative platform facies according to the drilling data of Tazhong. Moreover, it is inferred that weak amplitude reflections of Phases I and II platform margin reef beach bodies indicate argillaceous dolomitic flat deposits of evaporative platform margin facies according to the Walther facies law. At the end of Late Cambrian, the rimmed platform margin evolved into a weakly rimmed platform margin, the shielding effect of the platform margin on the platform interior weakened, and the restricted environment inside the platform changed to a semi-restricted environment, so weak amplitude continuous reflections are observed on the seismic profile (Fig. 12a). According to the drilling data of Well CT1, the tidal flat facies micrite dolomite deposit of about 20 m thick covers on Phase Ⅲ platform margin (Fig. 12b). The breakthrough pressure of the micrite dolomite was measured at 2.5-4.0 MPa. Four water layers of 30.8 m thick combined were interpreted from logging data at the top of reef beach body, reflecting poor caprock conditions. In the Early-Middle Ordovician, the platform evolved into a weakly rimmed-untrimmed carbonate platform, within which open platform deposits developed since the platform margin had no shielding effect on the platform interior anymore. Thus, weak amplitude discontinuous reflections are observed on the profile (Fig. 12a). According to the drilling data of Well CT2, the open platform facies calcarenite and micrite of Penglaiba Formation of about 180 m thick cover on Phase IV platform margin reef beach bodies (Fig. 12b). The limestone has a porosity of 0.3-0.7%, and tested breakthrough pressure of 7-25 MPa; and five gas layers and poor gas layers were interpreted from logging data beneath the caprocks, with the highest hydrocarbon content of 48.4%, reflecting good caprock conditions.

In summary, Phases I and II platform margin reef beach bodies are covered by argillaceous dolomite of restricted platform argillaceous dolomitic flat facies with good sealing capacity. Phase III platform margin reef beach bodies are covered by micrite dolomite of semi-restricted platform tidal flat facies with poorer sealing capacity. Phase IV platform margin reef beach bodies are covered by tight limestone of open platform facies with good sealing capacity.

The recent exploration results show that the Gucheng area is dominated by gas reservoirs. In this study, the source and enrichment conditions of natural gas in the Gucheng area were comprehensively examined through composition analysis and genetic identification of gas.

At present, the commercial gas in the Gucheng area is produced from the dolomite in the lower Yingshan Formation of Ordovician. Well GC6 has a daily gas production of 26.4×10⁴ m³ with 8 mm nozzle, Well GC8 47.84×10⁴ m³ with 8 mm nozzle, and Well GC9 107.8×10⁴ m³ with 13 mm nozzle. As shown in Table 2, the gas composition is dominated by hydrocarbon gas (65.83-90.96%). The hydrocarbon gas has a high methane content of about 65.6-90.7%. The gas has a drying coefficient (C₁/∑C_1—5) of 99.5-99.7%, representing typical high maturity dry gas. The non-hydrocarbon gases mainly consist of CO₂ (4.71-29.10%, or averagely 16.5%) and N₂ (2.30-4.77%, or averagely 4.08%), showing the characteristics of high CO₂ content, medium N₂ content and no H₂S.

The analysis shows that the natural gas in the Gucheng area is high mature oil cracking gas derived from the Cambrian and the Middle-Lower Ordovician, with the specific evidences as follows. First, the carbon isotope composition of natural gas in the Gucheng area ranges from -35.1‰ to -33.6‰, and the carbon isotope composition of ethane from -38.7‰ to -32.9‰ (Table 1). The carbon isotope compositions are lower than the threshold value derived from humic parent material^[45], which is -28‰. The gas belongs to the oil-type gas from the typical marine sapropelic parent material. Second, according to the regression formula of oil-type gas maturity established by Dai Jinxing, the R_o value of the corresponding gas source rock was calculated at 2.40-3.32%, indicating over-mature stage. Third, projecting the measured natural gas data on the identification chart of cracking gas types established by Li Jian^[46], it is concluded that the natural gas in the Gucheng area belongs to oil cracking gas (Fig. 13a). Fourth, comparing the natural gas in the Gucheng area with that in other blocks from different sources in craton area, it is found that the natural gas in the Gucheng area is similar to that in Tazhong and East Lungu sourcing from Cambrian to Middle-Lower Ordovician, but quite different from that in Halahatang derived from the Middle-Upper Ordovician source rock (Fig. 13b)^[47].

The distribution of natural gas in the Ordovician is macroscopically uncontrolled by structure, and has no uniform gas-water contact. The natural gas accumulation is mainly controlled by reservoirs and gas source faults (Fig. 14). When reservoir strata are well developed and faults can communicate with the gas source, gas-bearing reservoirs are widely distributed. The gas filling degree in the high part of the structure is higher, while the gas filling degree in the low part of the structure is lower. For example, the dolomitization beach of the third member of Yingshan Formation is almost full of gas without water in Wells GC6 and GC8 located in the high part of the structure, the gas is mainly distributed at the top of a large set of dolomite reservoirs in Well GC13 in the low part of the structure, and even if there are relatively good reservoirs in the lower part, the gas-bearing property is poor. When there is no gas source fault, even if good reservoir has poor gas-bearing property. Take Type I reservoir in the lower part of the third member of Yingshan Formation in Well GC10 as an example, with a thickness of 8.6 m and the porosity of 8%, the reservoir was interpreted as a water layer from logging data. In a word, the scale of Ordovician reservoir controls the scale of gas reservoir, caprock and gas source faults control the vertical accumulation horizon of natural gas, tectonic setting controls favorable accumulation area, and fracture development degree and reservoir physical properties determine well productivity.

The distribution of natural gas in the Cambrian is not macroscopically controlled by structure either, and has no uniform gas-water contact (Fig. 14). When the caprock of reef beach bodies and preservation conditions are good, a single reef beach body can form a single gas reservoir. When the lateral sealing, caprock condition or preservation condition of reef beach body are poor, the gas-bearing property of reef beach body trap is poor. For example, in Well CT1 encountering the Phase III platform margin reef beach body, the caprock above the reef beach body is thin (only 25 m thick tidal flat facies tight dolomite was encountered), several faults cut the reef beach body, so the preservation condition is poor, resulting in the poor gas-bearing property of the whole reef beach body and only a small amount of gas in the lower poor reservoir interval. All Types I and II reservoirs at the top of more than 30 m thick are water layers, showing the characteristics of lithologic traps controlled by trap effectiveness. Therefore, the effectiveness of lithologic traps in reef beach body may determine whether reef beach body can effectively form reservoir, the scale of reef beach body trap may determine the scale of gas reservoir, and the physical properties of reservoir may determine the well productivity.

There are four sets of reservoirs in two types in the Lower Paleozoic carbonate rocks of the Gucheng area. Based on the basic conditions of gas accumulation and exploration results, the exploration potential and direction of the four sets of reservoirs were evaluated.

The Cambrian platform margin zone has a set of reef beach reservoir with the best physical properties and largest scale in the Gucheng area, moreover, the reservoir is very close to the Cambrian-Middle-Lower Ordovician source rock, constituting good reservoir-forming conditions. Once a breakthrough is made, a large-scale monolithic gas field can be expected, with the predicted gas resources of up to 5000×10⁸ m³. So far, good oil and gas shows have been found in three risk exploration wells targeting the Cambrian platform margin reef beach body, which, however, all failed to detect oil and gas reservoir because of poor caprock and preservation conditions. Therefore, to strengthen the evaluation of caprock and preservation conditions is the key to successful exploration of the Cambrian platform margin reef beach bodies in the Gucheng area. As mentioned above, the platform margin reef beach caprocks of Phases I and II are favorable for risk exploration of Cambrian because of its good caprock conditions, undeveloped northward faults in the late period and good hydrocarbon source conditions. As the northward structural position becomes lower, more efforts should be made on the study of upward sealing.

The dolomite in the lower Yingshan Formation of Ordovician is a reservoir with the best reservoir-caprock assemblage in the Gucheng area. It is a dolomitized beach reservoir widely distributed in macro-scale and highly heterogeneous due to hydrothermal dissolution along faults. The caprocks is a set of composite regional caprocks consisting of very thick mudstone in the Que’erqueke Formation and tight limestone in the Middle-Upper Ordovician, commonly known as the "black cover". Although the dolomite in the lower Yingshan Formation does not contact directly with the source rock, N-E strike-slip faults are abundant in the Gucheng area, and the N-E strike-slip faults developed in the late Caledonian-early Hercynian period are in accordance with the current principal stress direction and have good openness, and are the main gas source channels of Himalayan cracking gas^{[48,49,50,51,52]}.

At present, the dolomite in the lower Yingshan Formation is also the reservoir with the best exploration results in the Gucheng area. Since 2011, 18 exploration wells targeting the dolomite in the lower Yingshan Formation of Ordovician have been drilled. Of them, three obtained commercial gas flow, four low-yield gas flow. The predicted gas resources of this set of reservoir are about 1500×10⁸ m³. In spite of the broad exploration prospects, the dolomite reservoir in the lower Yingshan Formation has strong heterogeneity, making it difficult to form large-scale monolithic gas reservoir, rather groups of small gas reservoirs distributed in large area are likely to occur there. Strengthening accurate reservoir prediction and fine target evaluation has become the key for the exploration. According to the previous evaluation results, the middle beach zone with high water energy, moderate dolomitization and gas source faults is the major target to find new reserves and increase production.

The upper Yingshan Formation of Ordovician is dominated by limestone depositing in unfavorable primary sedimentary facies belt with strong compaction and cementation. According to the successful experience in the Shuntuo-Shunnan area in the north slope of Tazhong^{[48,49,50,51,52]}, the limestone reservoir in the upper Yingshan Formation is mostly developed near the N-E fault zone. The N-E strike-slip faults not only control the development of the Ordovician carbonate vuggy-fractured reservoirs, but also oil and gas transportation and accumulation. Compared with the Shuntuo-Shunnan area, the strike-slip faults in the Gucheng area are more developed. In addition to rows of NE faults, there are also many NNE faults, and the NE faults are mostly tensional normal faults^[52] with better openness, and are more conducive to the reworking of reservoirs by hydrothermal fluids and the transport of oil and gas. Therefore, the fault-controlled karst limestone reservoir in the upper Yingshan Formation of Ordovician in the Gucheng area is also a risk area worth exploring.

Many wells in the Gucheng area and its adjacent areas have good oil and gas shows in the Yijianfang Formation of Ordovician. Commercial oil and gas discovery only exists in the adjacent areas. For example, Well SB1-1H obtained a high- yield commercial production (87 t oil and 4×10⁴ m³ gas); Well SN7 produced 13.3×10⁴ m³ commercial gas flow per day by acid fracturing; Well GC11 encountered 37.43 m/5 layers of reservoirs, with the total hydrocarbon of 97.77% according to gas logging; Well GC17 drilled 53.54 m/17 layers of reservoirs, with the total hydrocarbon of 65.94% according to gas logging. Reservoir is the key to the exploration potential of granular limestone in the Yijianfang Formation. Wells drilled reveal that the Yijianfang Formation is fractured-porous reservoir controlled by grain beach and early supergene karstification, with selective pores. The reservoir space is mainly composed of intragranular dissolution pores and intercrystalline micropores in calcite within algal debris. The reservoir has moderate to poor storage capacity, small thickness of single layer, but is distributed widely on plane. Its resource potential is considerable. With the improvement of seismic data quality and the advancement of reservoir stimulation technologies such as acid fracturing, it is possible to transform it into practical field in the future.

The Lower Paleozoic strata in the Gucheng low bulge are located in the platform margin zone transiting from the Taxi carbonate platform to the Tadong basin, and are adjacent to the Cambrian-Middle-Lower Ordovician source rocks. There are four sets of reservoirs in two types, i.e. the platform margin reef beach in the Middle-Upper Cambrian, the dolomitized beach in the lower Yingshan Formation, the faulted karst limestone in the upper Yingshan Formation, and the interlayer karst in the Yijianfang Formation.

In the Gucheng area, the Middle Cambrian and Middle- Lower Ordovician slope-basin facies source rocks are the major source rocks, and it is speculated that the Lower Cambrian Yuertusi Formation source rock doesn’t occur in this area.

A set of composite regional caprocks composed of the Middle Ordovician tight limestone and the Upper Ordovician Que’erqueke Formation mudstone cover the Lower Ordovician dolomite gas reservoir, providing good sealing conditions. There is no good regional caprock between Cambrian and Ordovician, so the tight carbonate rock serves as direct caprock, providing ordinary sealing conditions.

The natural gas in the Gucheng area is gas from oil cracking at high temperature sourcing from deep Cambrian and Middle-Lower Ordovician strata. The Ordovician gas reservoirs are mainly lithologic gas reservoirs controlled by reservoirs and gas source faults. Reservoir bed scale controls gas reservoir scale, caprock and gas source faults control vertical oil and gas accumulation horizons, structural setting controls favorable accumulation areas, fracture development degree and reservoir physical properties determine well productivity. The Cambrian may have lithologic gas reservoirs controlled by the effectiveness of reef beach traps. The caprock and preservation conditions are the key to oil and gas accumulation. The effectiveness of reef beach lithologic traps determines the effectiveness of reef beach reservoirs. The scale of reef beach traps determines the scale of gas reservoirs and the physical properties of reservoirs determine the well productivity.

Based on the basic accumulation conditions and exploration results of natural gas, the exploration potential of the four sets of reservoirs in two types in the Lower Paleozoic carbonate rocks was evaluated. The dolomite reservoir in Lower Yingshan Formation has good quality reservoir-caprock association with large exploration potential, and the middle beach zone is the major target to increase reserves and production. The Cambrian in this area has good reservoir forming conditions, Phases I and II platform margin reef beach bodies of Cambrian in the northern part have good preservation conditions, and the risk exploration in them should be accelerated. The fault-controlled karst limestone in the upper Yingshan Formation related to NE strike-slip faults is a risk area worth exploring. It is necessary to strengthen the description of fault-controlled karst body and the preparation of targets. The grain beach in the Yijianfang Formation controlled by interlayer karst is a potential exploration area, which needs to be further studied.