Ya Deng

Important hydrocarbon resources are preserved in deeply buried (>6500 m), intensely karstified Ordovician carbonates of the Tarim Basin, where reservoir development is closely associated with strike–slip fault systems. However, the links among faulting, karstification, reservoir formation, and subsequent diagenetic modification remain poorly understood because of the complex tectonic and burial history of the basin. In this study, we compared deeply buried Ordovician karst reservoirs from the Halahatang oil field in the Tabei Uplift, Tarim Basin, with near-surface Cretaceous karst systems at Fontaine de Vaucluse, southeastern France. Both of these systems were influenced by multiphase strike–slip faults. Despite their contrasting deposition timing and burial histories, the two systems exhibited comparable linear reservoir distributions controlled by a sequential evolution process that formed under compressional stress. In both cases, diagenetic fluids were characterized by mixing between two end-members, meteoric water and formation water, although they may have been circulated to different depths. Moreover, epigenic karstification was the principal mechanism of reservoir formation in both cases, although hypogenic products occur locally. These similarities indicated that the deeply buried (>8000 m) Ordovician paleokarst reservoirs of the Halahatang area formed primarily because of fault-controlled epigenic karstification and associated meteoric-water diagenesis. This comparative framework increases our understanding of the evolution of ultradeep carbonate reservoirs and has implications for hydrocarbon exploration in the Ordovician carbonates of the Tabei Uplift.

The pore architecture of the Nahr Umr Formation sandstone reservoirs is highly complex and heterogeneous, severely limiting efficient oilfield development. Conventional methods often fail to adequately characterize such intricate pore systems, necessitating the application of fractal theory. Focusing on sandstone samples from the Nahr Umr-B Member, this study integrates thin section identification, XRD, HPMI, and NMR to characterize the fractal features of the reservoir pore structure and evaluate fluid mobility. The results indicate that from Type I to Type III reservoirs, displacement pressure and median pressure gradually increase, whereas the average and median pore-throat radius gradually decrease, and the pore-throat sorting coefficient decreases. For instance, Type I reservoirs exhibit an average displacement pressure of 0.15 MPa, a median pressure of 0.81 MPa, an average pore-throat radius of 1.96 μm, and a median pore-throat radius of 2.85 μm; in contrast, Type III reservoirs show averages of 14.43 MPa, 45.32 MPa, 0.02 μm, and 0.03 μm, respectively. These trends reflect a gradual deterioration in pore connectivity, increased resistance to fluid flow, and a reduction in the development of larger pore throats. From Type I to Type III reservoirs, both the total fractal dimension (D_H) and the movable fluid pore fractal dimension (D_N2) show a gradual increasing trend. This indicates that the pore structure becomes increasingly complex and heterogeneous, the complexity of the movable fluid pore space increases, and fluid mobility progressively weakens. Furthermore, higher quartz content and lower cement and clay mineral contents correspond to smaller reservoir pore fractal dimensions and stronger fluid mobility. For example, Sample No. 3 (Type I) has a quartz content of 91.97%, a cement content of 1.64%, and a clay mineral content of 6.4%, with a D_H of 2.4385 and D_N2 of 2.9323. Conversely, Sample No. 4 (Type III) has a quartz content of 49.72%, a cement content of 11.21%, and a clay mineral content of 39.07%, with a D_H of 3.9099 and D_N2 of 2.9762. Compared to D_H, D_N2 reduces the prediction error for dynamic quality by over 70% on average, offering a more reliable prediction of fluid mobility and providing a more precise scale for evaluating reservoir development potential.

Thin-bedded carbonate reservoirs face significant challenges in characterization and development due to their thin formation thickness, strong interlayer heterogeneity, and rapid sedimentary transformation. In recent years, horizontal wells have played an increasingly important role in improving the productivity of thin-bedded carbonate reservoirs. However, building accurate geological models from horizontal well data is a major challenge for geoscientists. Using Middle East Oilfield A as a case study, this paper analyzes the specific challenges of horizontal well geomodeling and proposes a dedicated strategy for integrating horizontal well-derived constraints into the geological modeling workflow. To address the challenges of structural modeling constrained by horizontal well data, this study proposes three methodologies: stratigraphic layer iteration, virtual control point generation, and localized grid refinement. These techniques collectively enable the construction of a higher-fidelity structural framework that rigorously honors hard well data constraints while incorporating geological plausibility. To address the challenges posed by the spatial configuration of vertical and horizontal wells and the dominant trajectory patterns of horizontal wells, this study introduces two complementary approaches: the exclusion of horizontal well section data (relying solely on vertical wells) and the selective extraction of representative horizontal well section data for variogram derivation. These methods collectively enable the construction of a geologically realistic reservoir model that accurately captures the spatial distribution of reservoir properties. These methodologies not only effectively leverage the rich geological information from horizontal wells but also mitigate spatial clustering effects inherent to such data. Validation through development well production data confirms robust performance, providing transferable insights for reservoir characterization in analogous fields worldwide.

Reservoir characterization in carbonate formations plays a crucial role in understanding the complex pore structures and permeability properties. While absolute pore-throat radius (APTR) and R35 have been widely accepted in pore-scale rock typing, they fall short of providing detailed pore-throat distribution (PTD) information. To address this limitation and enhance PTD indication during rock classification, we introduce a novel approach—the R35 and fractal joint rock typing method—incorporating a new parameter, Dn (fractal dimension). This method is developed based on the analysis of mercury injection capillary pressure (MICP) data obtained from 20 carbonate samples in the Middle East, specifically Iraq. We delve into the discussion of APTR and R35 methods, employing both PTD and thin-section images to gain comprehensive insights into rock typing. Our approach incorporates a whole curve fractal-based model to determine the fractal dimension, Dn. The analysis reveals that Dn in each R35 rock type exhibits a decreasing trend with higher Hg intrusion peaks and wider pore-throat radius, providing valuable information on the distribution of pores within the rock samples. Furthermore, we extend our analysis to include the surface fractal dimension, Ds, obtained through two-dimensional (2D) fractal analysis on typical pores in binary thin-section images. The consistent decreasing trend of Dn aligns with the findings from Ds analysis, underscoring the effectiveness of parameter Dn in capturing the intricate pore structures within carbonate formations. Our results suggest that parameter Dn has the potential to serve as a standalone criterion in rock typing, eliminating the need for pretyping by R35 or APTR. The versatility of Dn as an indicator of pore distribution and complexity underscores its significance in advancing our understanding of carbonate reservoirs. As a recommendation, further exploration through additional fractal-based analyses is encouraged to solidify the role of parameter Dn in becoming a pivotal factor in the evolving field of rock typing.

The Cenomanian–Early Turonian Mishrif Formation is a great contributor to oil production in Iraq. Integrating petrographic, mineralogical, and wireline logging data from 52 wells, this study provides an improved understanding of the sequence stratigraphy, depositional evolution, and reservoir characteristics of the Mishrif Formation in the Mesopotamian Basin, south Iraq. Five types of facies associations are classified: lagoon, shoal, rudist bioherm, shallow marine, and deep marine. Such a classification allows convenient differentiation and interpretation of wireline logs. A sequence stratigraphic framework including five third-order sequences (Mhf 1 to Mhf 5) for the Mishrif Formation is established mainly using wireline logging data of close-distance wells, with the aid of cores and thin sections. Two end-member depositional evolution stages are recognized, from clinoform-like progradational shoal complexes in Mhf 1 within a shallow marine environment, to tidal channels in Mhf 2–3 within a lagoon environment. For Mhf 4–5, abrupt changes in facies associations from north to south indicate the development of an intra-shelf basin where organic-rich mudstones directly overlie the shallow marine grainstone shoals and lagoonal wackestones. Reservoir characteristics and compartmentalization are directly controlled by the sequence stratigraphic framework. Sequence boundaries are featured by wackestones and mudstones overprinted by cementation; they are regionally correlatable and work as regional barriers. Shoal complexes in Mhf 1 and tidal channels in Mhf 2–3 are the main reservoir units. Mudstones and wackestones are intra-reservoir baffles and become more frequently developed towards the south, reflecting the increasing water depth towards south. The characterization of the tidal channels, clinoform-like shoals, and intrashelf basinal deposits in the current study could benefit later development of the Mishrif Formation.

The effect of stylolite caused by the pressure dissolution process on the reservoir petro-physical properties is still controversial. This study aims to reveal the effect of stylolite on the porosity and permeability of packstone and wackestone in the Mishrif Formation from the Ah oilfield in the Middle East. Based on the observation of thin sections and cores, X-ray diffraction analysis and porosity and permeability measurement, the lithofacies, diagenesis and patterns of stylolites have been investigated. There are six lithofacies in the Mi4 member, including bivalve green algae packstone, green algae packstone, pelletoid green algae packstone, echinoderm packstone, rudist packstone, planktonic foraminifera wackestone and bioclastic wackestone. The mechanical compaction and pressure dissolution could be observed in these lithofacies, with the development of dissolution seams and stylolites. The density of stylolite has a relationship with the lithofacies and early cementation. The boundary between the echinoderm packstone and the green algae packstone mostly developed as stylolites. There are four types of stylolite on the cores. Type A is the wave-like stylolite developed at the boundary between the echinoderm packstones and green algae packstones. Type B is the zigzag stylolite with high amplitude in the green algae packstones. Type C is the stylolites with low amplitude in the bioclastic wackestones. Type D is the high-angle stylolite, which is oblique to the bedding plane. The permeability of reservoir rocks could be improved by dissolution along the type B stylolite, while the type A and type C stylolite have little effect on permeability. The permeability of green algae packstone and echinoderm packstone will decrease with the development of stylolites. The porosity and permeability of bivalve green algae packstone will decrease after stylolitization, resulting from the relatively high density of stylolite. The physical properties of bioclastic wackestone could be improved by the bioturbation and formation of stylolite. According to the analysis of production performance in the same lithofacies, the occurrence of stylolites could result in the development of oil baffles. This study could be extended to evaluate the effect of stylolite in carbonate reservoir rocks.

Combining both geological and petrophysical properties, a reliable rock typing scheme can be achieved. Two steps are included in rock typing. Step 1: rocks are classified into lithofacies based on core observations and thin sections; Step 2: lithofacies are further subdivided into rock types according to petrophysical properties such as MICP (Mercury Injection Capillary Pressure) and K-Phi relationships. By correlating rock types to electrofacies (clusters of log data), we can group the target formation into 12 rock types. Then it is possible to predict the distributions of rock types laterally and vertically using wireline logs. To avoid the defect of the classical J-function saturation model that includes permeability which is quite uncertain especially in carbonate rocks, a modified J-function was created and used in the paper. In this function, water saturation is simply expressed as a function of height above free water level for a specific rock type. Different water saturation models are established for different rock types. Finally, the water saturation model has been successfully constructed and verified to be appropriate.