Distribution Of High-quality Reservoirs Research Articles

Technological issues in shale oil development using horizontal wells in Ordos Basin, China

The PetroChina Changqing Oilfield Company has successfully achieved large-scale economical development of continental low-pressure freshwater lake interlayer shale oil in the Ordos Basin, China, targeting the gravity-flow sandstone thin interlayers in the organically rich mud shale formation of the seventh member of Yanchang Formation (Chang 7 Member) of Triassic,. Their significant discovery of the 1-billion-ton-level Qingcheng shale oil field, with a proven reserve of 1.052 × 109 t, has marked the establishment of China's first million-ton shale oil development zone. However, the extensive growth in production and construction has brought attention to notable challenges, including geological variances, low initial production, rapid decline, low recovery rates, and high development costs. Based on extensive field experience, this paper identifies several technological issues in shale oil development and offers comprehensive recommendations through systematic analysis. The encounter rate of horizontal shale oil wells, crucial for enhancing individual well productivity, can be improved both vertically and horizontally by prioritizing the extension direction of high-quality reservoirs during the deployment of horizontal wells. The contribution of fracturing fluid elasticity to the recovery rate is relatively low. Reservoir modification should not overemphasize large sand volume, fluid volume, or discharge. Additionally, optimizing parameters such as well spacing, vertical interlayer distribution, and fracture development is essential for maximizing the efficiency of fracturing scale, operation discharge, and other parameters. Variability in hydrocarbon source rock quality and the strength of diagenesis significantly impact oil saturation in sand bodies, affecting the selection of favorable areas and the distribution of high-quality reservoirs. Furthermore, the utilization of pre-fracturing with CO2 proves to be an effective approach in reducing viscosity and increasing the ultimate recovery rate. To ensure the efficient development of shale oil in the Changqing Oilfield, this paper emphasizes the necessity of deepening integrated geological studies, clarifying the main controlling factors of shale oil heterogeneous accumulation, and meticulously depicting three-dimensional sweet spots while exploring more effective development methodologies.

Sedimentary Features and Distribution of High-Quality Reservoirs in the Ledong Area, Yinggehai Basin

Sedimentary Features and Distribution of High-Quality Reservoirs in the Ledong Area, Yinggehai Basin

Fine Logging Evaluation of Fractures in Continental Tight Oil Sandstone Reservoirs of Yanchang Formation in the Ordos Basin

Fractures are the main seepage channels in tight reservoirs, and they affect the distribution of high-quality reservoirs and the enrichment of hydrocarbons. Fine logging identification of fractures in the strongly heterogeneous continental tight oil reservoirs of the Upper Triassic Yanchang Formation in the Ordos Basin is a hot and difficult point in the field of petroleum geology. In this paper, taking the Yanchang Formation as an example, a fractal model was constructed to identify fractures in tight oil reservoirs using a large number of cores, conventional and micro-resistivity imaging logging data. The results show that high-angle, vertical and bedding fractures are mainly developed in the Yanchang Formation tight sandstones. There is a negative correlation between sand body thickness and fracture development degree. The fracture sensitivity parameters were used to construct a coupled fractal fracture index. The fractal model incorporates logging information from natural gamma, acoustic wave time difference, rock density, and shallow lateral resistivity. In addition, the constructed fracture fractal index realizes the functions of multi-conventional logging information fusion, which can effectively identify fracture development segments in sandstone. According to the statistics, the fracture identification rate is 83.3%. The study also found that with the increase of sandstone brittleness index, the fracture index has a “S” shape increasing trend. Therefore, the content of brittle mineral components in sandstone is an important factor affecting the development degree of natural fractures, and fractures are more likely to occur in high brittle, thin sand bodies. The highly brittle framework minerals have strong stress-supporting capacity, which can keep fractures open by resisting high overlying loads.

Reservoir Characteristics of the Lower Silurian Longmaxi Shale in Zhaotong Region, Southern China

The lower Silurian Longmaxi Formation hosts a highly productive shale gas play in the Zhaotong region of southern China. According to core observation, X-ray diffraction analyses, and scanning electron microscopy (SEM) observations, the shale comprises primarily quartz, carbonate minerals, and clay minerals, with minor amounts of plagioclase, K-feldspar, and pyrite. The clay mineral content ranges from 15.0% to 46.1%, with an average of 29.3% in the Zhaotong region. Organic geochemical analyses show that the Longmaxi Formation has good potential for shale gas resources by calculating total organic carbon, vitrinite reflectance, and gas content. Scanning electron microscope images demonstrate that reservoir pore types in the Longmaxi shale include organic pores, interparticle pores, intercrystalline pores, intraparticle pores, and fractures. Reservoir distribution is controlled by lithofacies, mineral composition, and geochemical factors. In addition, we investigated the relationships between reservoir parameters and production from 15 individual wells in the Zhaotong region by correlation coefficients. As a result, the brittleness index, total organic carbon (TOC), porosity, and gas content were used to define high-quality reservoirs in the Longmaxi shale. Based on these criteria, we mapped the thickness and distribution of high-quality reservoirs in the Longmaxi Formation and selected highlighted several key sites for future exploration and development.

Cambrian faults and their control on the sedimentation and reservoirs in the Ordos Basin, NW China

Comprehensively utilizing the seismic, logging, drilling and outcrop data, this research studies the characteristics of the Cambrian faults and their control on the sedimentation and reservoirs in the Ordos Basin. The results show that: (1) Three groups of faults striking North-East (NE), near East-West (EW), and North-West (NW) were developed in the Cambrian. The NE and near EW faults, dominated by the normal faults, are the synsedimentary faults and the main faults of the Cambrian. (2) According to the roles of faults in tectonic units and the development scale of the faults, the Cambrian faults can be divided into three grades. The second-grade faults, large in scale, controlled the boundary of the Cambrian sags of the Ordos Basin. The third-grade faults, smaller in scale than the second-grade fault, controlled the high and low fluctuations of local structures. The fourth-grade faults, very small in scale, were adjusting faults developed inside the local tectonic units. (3) The Cambrian faults had strong control on the sedimentation and reservoir of the Cambrian. Controlled by the second-grade and the third-grade faults, the paleogeographical framework of the Cambrian presents combination characteristics of the bulge-sag macro-structures and the high-low differentiation micro-geomorphology. This paleogeographical pattern not only controlled the development of the oolitic beach facies in the Cambrian but also the distribution of high-quality reservoirs. (4) Under the control of the faults, the micro-paleogeomorphological high parts closely adjacent to the margin of the Cambrian sags are the favorable exploration areas.

Diagenetic evolution characteristics of Paleogene lacustrine carbonate reservoirs in central Bohai sea, China

The distribution of high-quality reservoirs in Shahejie Formation of the Shijiutuo Uplift, Central Bohai Sea, is the key factor to determine the oil and gas accumulation. Likewise, diagenesis is the key factor to control the development of lacustrine carbonate reservoirs in Shahejie Formation. So, accurately analyzing the diagenesis is very important for improving reservoir prediction. By means of polarizing microscopy, fluorescence microscopy, scanning electron microscopy, cathodoluminescence and electron probe analysis techniques, reservoir characteristics and diagenetic evolution sequence are determined. The diagenetic stage was determined by X-ray diffraction of clay minerals. Gas-liquid inclusion homogenization temperature and oxygen isotope geothermometer are used to analyze the formation period of authigenic carbonate minerals. Bioclastic dolostone is the main type of carbonate rocks, followed by dolarenite. The visceral cavity pores and residual primary intergranular pores are the main reservoir space. The diagenetic evolution sequence is established based on the different occurrences of multistage dolomites and their relationship with other diagenesis phenomena, and the final diagenetic stage is the phase B of mesodiagenesis. The favorable diagenesis for reservoir physical properties is the early formation of the pore-lining dolomite deposited in the eodiagenesis and the grain-coating dolomite deposited in the syndiagenesis, both of which weaken the subsequent mechanical compaction to the reservoir porosity.

Differences between reservoirs in the intra-platform and platform margin reef-shoal complexes of the Upper Ordovician Lianglitag Formation in the Tazhong oil field, NW China, and corresponding exploration strategies

Abstract The Upper Ordovician Lianglitag Formation in the Tazhong oil field, NW China, is dominantly composed of shallow marine carbonates, and it can be subdivided into five members lithologically. Unclear understanding of the reservoir evolution in the platform margin and intra-platform reef-shoal complexes resulted in difficulty in locating reservoirs and poor drilling success in the intra-platform. By comparing the basic characteristics, diagenesis, and porosity evolution of the two types of reservoirs, this study established their development patterns and proposed corresponding exploration strategies based on comprehensive analysis of core, thin-section, well-logging, three-dimensional seismic, and geochemistry data. The major difference between the platform margin and intra-platform reservoirs lied in their pore types. The platform margin reservoirs had fabric-selective intragranular dissolution pores, intergranular dissolution pores, moldic pores, and non-fabric-selective karst fractures and caves, and tectonic fractures, whereas the intra-platform ones only had tectonic fractures, intercrystalline dissolution pores, and intergranular vugs. In terms of distribution, the platform margin reservoirs were mainly distributed in the parasequence top and landform highlands of the highstand system tract in Members 3 to 1, appearing in two to six cycles, with large single layer and accumulative thicknesses and a quasi-bedded continuous distribution in the lateral. However, the distribution of the intra-platform ones was not obviously correlated with sedimentary facies and paleogeomorphology, with smaller single layer and accumulative thicknesses and poorer lateral continuity. The evolution and distribution of high-quality reservoirs in the platform margin were jointly controlled by eogenetic marine diagenetic and meteoric dissolution including karst, burial dissolution, and tectonic fractures. In comparison, eogenetic marine diagenetic and meteoric dissolution in the intra-platform reef-shoal complexes were weak, accompanied by persistent cementation. The favorable reservoirs were primarily controlled by fractures and later burial dissolution. Hence, for the exploration of the platform margin reef-shoal complex reservoirs, the priority should be given to the areas with the superimposition of eogenetic marine diagenetic and meteoric dissolution, burial dissolution, and tectonic fracturing. For the exploration of intra-platform reef-shoal complex reservoirs, more attention should be paid to areas with overlapped fractures and burial dissolution, especially where Hercynian strike-slip faults and early fractures were superimposed. Less attention should be paid to the areas with eogenetic marine diagenetic and meteoric dissolution.

Seismic prediction on the favorable efficient development areas of the Longwangmiao Fm gas reservoir in the Gaoshiti–Moxi area, Sichuan Basin

The Lower Cambrian Longwangmiao Fm gas reservoir in the Gaoshiti–Moxi area, the Sichuan Basin, is a super giant monoblock marine carbonate gas reservoir with its single size being the largest in China. The key to the realization of high and stable production gas wells in this gas reservoir is to identify accurately high-permeability zones where there are dissolved pores or dissolved pores are superimposed with fractures. However, high quality dolomite reservoirs are characterized by large burial depth and strong heterogeneity, so reservoir prediction is of difficult. In this paper, related seismic researches were carried out and supporting technologies were developed as follows. First, a geologic model was built after an analysis of the existing data and forward modeling was carried out to establish a reservoir seismic response model. Second, by virtue of well-oriented amplitude processing technology, spherical diffusion compensation factor was obtained based on VSP well logging data and the true amplitude of seismic data was recovered. Third, the resolution of deep seismic data was improved by using the well-oriented high-resolution frequency-expanding technology and prestack time migration data of high quality was acquired. And fourth, multiple shoal facies reservoirs were traced by using the global automatic seismic interpretation technology which is based on stratigraphic model, multiple reservoirs which are laterally continuous and vertically superimposed could be predicted, and the areal distribution of high quality reservoirs could be described accurately and efficiently. By virtue of the supporting technologies, drilling trajectory is positioned accurately, and the deployed development wells all have high yield. These technologies also promote the construction of a modern supergiant gas field of tens of billions of cubic meters.

Pore fluid evolution, distribution and water-rock interactions of carbonate cements in red-bed sandstone reservoirs in the Dongying Depression, China

The compositions, distribution and its interaction with rocks of the evolving pore fluids controls the distribution of carbonate cements and reservoir storage spaces. The reservoir quality of the red-bed sandstone reservoirs in the Dongying Depression was investigated by an integrated and systematic analysis including carbonate cement petrology, mineralogy, carbon and oxygen isotope ratios and fluid inclusions. The investigation was also facilitated by probing the mineral origins, precipitation mechanisms, pore fluid evolution and distribution, and water-rock interaction of carbonate cements and their influences on reservoir quality. Diagenetic-evolving fluids in the interbedded mudstones are the main source for the precipitation of calcite cements that completely fill the intergranular volume (CFIV calcite) with heavier oxygen and carbon isotopes. The ferro-carbonate cements in the reservoir sandstone are enriched in lighter carbon and oxygen isotopes. In addition to the cations released by the conversion of clay minerals in reservoirs, products of organic acid decarboxylation and the associated feldspar dissolution process provide important sources for such carbonate cementation. The carbon isotopes of CO2 and the oxygen isotopic composition of fluids equilibrated with the CFIV calcite, ferro-calcite, dolomite and ankerite cements indicate that the pore in the red-bed reservoirs experienced high salinity fluids, which evolved from the early-formed interbedded mudstones, through organic acid input and to organic acid decarboxylation. Pore fluids from nearby mudstones migrated from the edge to the centre of sandbodies, causing strong calcite cementation along the sandbody boundaries and forming tight cementation zones. Pore fluids associated with organic CO2 and acids and organic acid decarboxylation are mainly distributed in the internal portion of sandbodies, causing feldspar dissolution and precipitation of ferro-carbonate cements. The distribution of pore fluids caused the zonal distribution of carbonate cements in sandbodies during different periods. This may be advantageous to preserve the porosity of reservoirs as exemplified by the distribution of high-quality reservoirs in the red-bed sandbodies.

Formation mechanisms and distribution of high quality reservoirs in deep strata in Palaeogene in northern steep slope zone of Bonan sag, Jiyang depression, China

Petrographic analysis combined with various techniques, such as thin section identification, petro-physical property testing, mercury penetration, oil testing results, was used to assess basic reservoir characteristics of deep strata in Palaeogene in the northern steep slope zone of the Bonan sag, China. The formation mechanisms of high quality reservoirs in deep strata were discussed according to evolution characteristics of paleopressures and paleofluids in geological period. The deep reservoirs have poor physical properties and mainly develop extra-low porosity, extra-low and ultra-low permeability reservoirs. Reservoir spaces mainly consist of secondary pores and overpressure fractures. Early overpressure, early hydrocarbon filling and dissolution by early organic acids are the major formation mechanisms of high quality reservoirs. The conglomerate in inner fan which had a poor primary physical property mainly experienced strong compaction and calcareous matrix recrystallization. The physical properties of the inner fan were poor with weak dissolution because of poor mobility of fluid. The reservoirs mainly are type IV reservoirs and the distribution extends with the burial depth. The braided channel reservoirs in the middle fan had relative good primary physical properties and strong ability to resist compaction which favored the preservation of primary pores. Large amounts of the secondary porosities were created due to dissolution by early organic acids. A series of micro-fractures generated by early overpressures would be important migration pathways for hydrocarbon and organic acids. Furthermore, early overpressures had retarded maturation of organic matters and organic acids which had flowed into reservoirs already and could keep in acid environment for a long time. This process would contribute significantly to reinforcing the dissolution and enhancing the reservoir quality. The braided channel reservoirs were charged with high oil saturation preferentially by early hydrocarbon filling which could inhibit later cementation. Therefore, the braided channel reservoirs develop a great quantity of reservoir spaces with type I, type II and type III reservoirs in the majority in the deep strata. With the burial depth, distributions of type I and type II reservoirs are narrowed and distribution of type III reservoirs decreases first and then extends. The reservoirs both in outer fan and in interdistributary of the middle fan have extremely poor physical properties because of extensive carbonate cementation. The type of the reservoirs mainly is type IV.

The influence of fracture cements in tight Paleogene saline lacustrine carbonate reservoirs, western Qaidam Basin, northwest China

Paleogene saline lacustrine carbonate rocks are important fractured reservoirs in the western Qaidam Basin. Core data show that most fractures are small, steeply dipping faults; bedding-plane slip faults; and subvertical opening-mode fractures. Other fractures are diagenetic in origin. Fracture occurrence and abundance patterns are controlled by lithology, bed thickness, and proximity to larger faults. Fractures are generally filled with calcite, gypsum, or glauberite (Na2Ca[SO4]2); the degree of fracture filling determines the effectiveness of fractures as fluid conduits and the distribution of high-quality reservoirs. Open fractures not only provide the main pathways for fluid flow, but also enhance the free fluid index and the free fluid saturation measured by nuclear magnetic resonance and determine the potential production rates of tight carbonate reservoirs. The open fractures are parallel to and occur near faults, and many do not coincide with the present-day direction of the maximum horizontal compressive stress.