The largest ultra-deep (>6000 m) strike-slip fault-controlled oilfield in the world is found in the Tarim Basin of Northwestern China. The localized fractured reservoirs are the major production targets along the strike-slip fault zones. Different from its use in the primary porous-type reservoirs, however, the conventional technology is not favorable for use in oil/gas development in Ordovician carbonate reservoirs. For this reason, high-density seismic acquisition and high-resolution seismic processing were carried out to provide high-precision data for fault and fractured reservoir identification. In addition, the multi-filtering process and the maximum likelihood method are typically used to identify small faults and fault segments along a strike-slip fault zone. Further, seismic facies-constrained inversion and amplitude attributes are favorable for large fracture-cave reservoir description. With the advancements in seismic technology, the high and stable production well ratio has been doubled in the “sweet spots” of fractured reservoir optimization, and the first ultra-deep strike-slip fault-controlled oilfield with an annual oil production of over 1 million tons has been realized, achieving economic development in the ultra-deep fractured reservoirs. However, unstable production and high rates of production decline are still significant challenges in the economic exploitation of the ultra-deep fractured reservoirs. Seismic technology requires further improvement for the description of small fractured reservoirs and matrix reservoirs, as well as reservoir connectivity prediction and hydrocarbon detection in the deep subsurface.

The identification of structural diagenesis and the reconstruction of diagenetic paragenesis in fault damage zones is important for understanding fault mechanisms and fluid flow in the subsurface. Based on the examination of core and sample thin section data, we deciphered the diagenetic parasequence and their fault controls for Ordovician carbonates in the northern Tarim intracratonic basin in NW China (Halahatang area). In contrast to the uniform nature of diagenesis observed in country rocks, there is a relatively complicated style of compaction and pressure solution, multiple fracturing, and cementation and dissolution history along the carbonate fault damage zones. The relative paragenetic sequence of the structure related diagenesis suggests three cycles of fracture activities, following varied fracture enlargement and dissolution, and progressively weaker calcite cementation. These processes of structure related diagenesis are constrained to the fault damage zones, and their variation is affected by the fault activities. The results of this study suggest that the carbonate reservoir and productivity could be impacted by the structure related diagenesis locally along the fault damage zones.

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.

A giant strike-slip fault-controlled Fuman Oilfield has been found in the Ordovician fractured carbonates of the Tarim Basin. However, conventional seismic methods are hardly able to distinguish the fractured reservoir and its connectivity in the ultra-depth (>7000 m) carbonate fault zones. We propose thin-likelihood and tensor-thickness process methods to describe the fracture network and large cave reservoir, respectively. Together with the two methods for 3D visualization of fracture-cave reservoirs, we had an application in the ultra-deep well deployment in Fuman Oilfield. The results show that the fracture network and cave reservoir can be 3D-imaged more clearly than conventional methods. The fracture network and cave reservoir show distinct segmentation by the fault assemblage in Fuman Oilfield. Furthermore, 3D modeling is favorable for the reservoir connectivity description along the carbonate fault zones. There are three distinct reservoir models: fault core-, fault damage zone- and overlap zone-controlling fractured reservoirs along the fault zones. This revealed variable fractured reservoirs that are related to fault maturity and segmentation. The method has been widely used in fracture-cave reservoir description and subsequent well optimization, suggesting a favorable method for economic oil exploitation in the ultra-depth reservoirs. This case study is not only useful for the complicated reservoir 3D description and modeling but also helpful for well employment to provide support for the target evaluation and optimization in ultra-depth fractured reservoirs.

The largest carbonate condensate field in China has been found in the central Tarim Basin. Ordovician carbonate reservoirs are generally attributed to reef-shoal microfacies along a platform margin. However, recent production success has been achieved along the NE-trending strike-slip fault zones that intersect at the platform margin. For this contribution, we analyzed the strike-slip fault effects on the reef-shoal reservoirs by using new geological, geophysical, and production data. Seismic data shows that some NE-trending strike-slip faults intersected the NW-trending platform margin in multiple segments. The research indicated that the development of strike-slip faults has affected prepositional landforms and the subsequent segmentation of varied microfacies along the platform margin. In addition, the strike-slip fault compartmentalized the reef-shoal reservoirs into multiple segments along the extent of the platform margin. We show that fractured reef-shoal complexes are favorable for the development of dissolution porosity along strike-slip fault damage zones. In the tight matrix reservoirs (porosity < 6%, permeability < 0.5 mD), the porosity and permeability could be increased by more than 2–5 times and to 1–2 orders of magnitude in the fault damage zone, respectively. This suggests that high production wells are correlated with “sweet spots” of fractured reservoirs along the strike-slip fault damage zones, and that the fractured reservoirs in the proximity of strike-slip fault activity might be a major target for commercial exploitation of the deep Ordovician tight carbonates.

Multi-trace amplitude variation with angle inversion (MAVAI) is a vital tool for estimating the physical parameters of subsurface media, and it plays an important role in oil and gas exploration. However, the existing MAVAI method relies on the Kronecker product to construct an extremely large-scale inverse problem, and its computational inefficiency limits its widespread application. Furthermore, regarding regularization constraints, the existing MAVAI method only considers the smoothness of the inversion parameters, which leads to ambiguous formation boundaries and hinders accurate identification for complex reservoirs. To address these issues, a compressed MAVAI method with elastic half-norm regularization is proposed. Specifically, we first developed a compressed MAVAI (CMAVAI) framework that uses compressed measurements of seismic data and reference models in a sparse domain to construct the CMAVAI objective function, thereby reducing the scale of the inversion problem and improving inversion efficiency. Subsequently, the elastic half-norm is introduced into the CMAVAI framework as a regularization constraint for reservoir parameter estimation. Since the elastic half-norm can simultaneously characterize both the smoothness and blocky features of the subsurface medium, it effectively improves inversion accuracy compared to the MAVAI method. Finally, the performance of the proposed method is evaluated using a theoretical model and field data. The results demonstrate that, compared with the traditional MAVAI algorithm, the CMAVAI framework can effectively improve inversion efficiency while maintaining inversion accuracy. Moreover, the CMAVAI method regularized by the elastic half-norm can improve the accuracy of inversion parameters while retaining the high prediction efficiency of the CMAVAI framework.