Carbonate Reservoirs Research Articles

Heavy oil recovery from oil-wet carbonate reservoirs remains a major challenge due to the high oil viscosity, unfavorable mobility ratio, and poor sweep efficiency in such systems. Understanding oil production under various enhanced oil recovery (EOR) mechanisms and predictive modeling/simulation in these reservoirs has also been particularly difficult due to the limited knowledge of the governing pore-scale displacement processes. This gap in understanding becomes even more evident for viscoelastic fluids. Hence, this study is designed to probe these pore-scale subtleties while injecting viscoelastic polymer and surfactant-polymer (SP) solutions. To this end, a series of multistage waterflooding, polymer flooding, and SP flooding tests were conducted across both capillary-dominated and viscous-dominated flow regimes under reservoir-representative conditions and on oil-wet miniature Prairie Shell carbonate rock samples. The flow tests were performed using a core-flooding apparatus integrated with a high-resolution X-ray imaging system to acquire three-dimensional pore-scale fluid distribution maps. These data were analyzed to characterize in situ wettability, quantify fluid saturations, and evaluate sweep efficiencies and displacement mechanisms. The results showed that the waterfloods recovered only 51-54% of the initial oil in place under capillary-dominated conditions and 67-68% under viscous-dominated conditions. In contrast, polymer and SP flooding increased recovery factors to, respectively, 61 and 69% under the capillary-dominated flow regime and 91 and 93% under the viscous-dominated flow regime. Pore-scale data analysis revealed that oil production occurred primarily through interface movement and piston-like displacements. The polymer and SP solutions have also mobilized wetting oil layers on pore walls and in the corners through viscoelastic pulling effects, which were not observed during the waterfloods. Moreover, the SP flooding outperformed polymer flooding at low injection rates since the surfactant solution lowered the oil-brine interfacial tension, reduced the entry capillary pressures, and emulsified some of the trapped oil clusters into smaller globules. Both polymer and SP solutions yielded comparable recoveries at higher flow rates as globule mobilization and ganglion dynamics dominated the displacement processes in both cases. These findings were further validated through pore-by-pore analysis of fluid occupancies.

Efficient wettability alteration in carbonate reservoirs using hydrophilic nanoparticles: a comparative study of silica, alumina, and titania for enhanced oil recovery

Numerical simulation and analysis of acid-etched surface morphology in carbonate reservoirs under stress

Investigation of alkyl ether carboxylate surfactant flooding efficiency in carbonate reservoirs using NMR and X-ray in situ saturation monitoring techniques

Development of an adaptive mesh refinement technique for field-scale simulation of matrix acidizing in carbonate reservoirs

Enhanced residual oil mobilization in carbonate reservoirs using novel superhydrophilic SiO2-TiO2 nanoparticles with Tween 80 and Carbomer 940: A synergistic approach

Counter-current, spontaneous imbibition of brine into oil-saturated rocks is a critical process for recovery of bypassed oil in carbonate reservoirs. However, the classic Amott-cell test introduces experimental artifacts that distort the true dynamics of oil recovery, complicating the interpretation and modeling of recovery histories. In this study, we applied a modified Amott procedure to eliminate these artifacts, producing smooth and reproducible recovery histories for both water-wet and mixed-wet carbonate core plugs saturated with brine and oil. By applying Generalized Extreme Value (GEV) statistics, we modeled cumulative oil production and showed that a GEV model is able to capture the essentially non-equilibrium nature of spontaneous imbibition. Our results demonstrate that water-wet systems exhibit faster recovery rates and shorter induction times due to favorable capillary forces, while mixed-wet samples have slower dynamics and longer induction times, reflecting the influence of wettability alterations. We demonstrate that the GEV fitting parameters systematically correlate with key rock–fluid properties, such as wettability, oil viscosity, and pore network characteristics, offering a semi-quantitative approach to analyze recovery behavior. This study demonstrates the potential of a GEV-based statistical model to deepen understanding of the spontaneous imbibition mechanisms and to enhance predictive capabilities for oil production dynamics.

Evaluating the toxicity of produced water from carbonate reservoirs in the North sea using oyster Embryo development tests.

Janus silicon quantum dots-stabilized microbubbles for optimizing CO2 sequestration and oil recovery in low-permeability carbonate reservoirs

Multistage fluid activity as a control on the Ediacaran carbonate reservoirs in the Sichuan Basin, SW China

Evaluation of comprehensive acid fracturing performance of a new environmentally friendly acid for high-temperature carbonate reservoirs

A novel post-fracturing evaluation method for fractured-vuggy carbonate reservoir by using pumping-stop pressure drop

Insights into modelling hydro-chemical interactions in colloid-brine-mineral systems.

Image logs aid in accurate fracture network characterization by providing detailed information about natural fractures in reservoirs. Moreover, larger-scale fracture mapping and detection can be accomplished by extracting seismic attributes offering important insights into the distribution of reservoir fractures. Through the extraction of seismic attributes from image logs the current study offers a novel method for locating naturally occurring fractures in a carbonate reservoir of southwest Iran. Extending the application of seismic attributes to image log data is made possible for the first time in this study by using data from electrical and ultrasonic image logs converted from DLIS to SEGY format. After converting the format of the image logs, seismic attributes were extracted and assessed for possibility of enhanced image log interpretation. To examine and compare the results of various attributes, a total of 23 structural, stratigraphic, and signal processing attributes were derived. The newly tested attributes, including the iso-frequency component, RMS amplitude, and variance (edge method), showed improved performance in identifying fractures. However, the iso-frequency component attribute was found to be very powerful in emphasizing the fractures among the different attributes examined. The findings of this study show how seismic attributes can be used to detect the natural fractures based on image logs in a reservoir resulting in more accurate fracture detection and modeling.

Formation damage caused by wellbore fluids remains a key concern in carbonate reservoirs, where pore plugging and filtrate invasion can severely reduce permeability. This study investigates the influence of filtrate-control components in cellulose-based polymeric fluids on the potential for formation damage in carbonate rocks and evaluates the performance of HPA starch as an alternative to cellulose, focusing on its comparative effects on formation permeability. Experimental tests were performed using Indiana Limestone cores to measure filtration behavior and permeability recovery after exposure to different polymeric solutions. The results revealed distinct mechanisms associated with each additive: PAC LV controlled fluid loss mainly by adsorption and pore plugging, while HPA starch formed more deformable and permeable structures. Glycerin, when used alone, did not induce formation damage but increased fluid viscosity, favoring more stable dispersion of the polymeric phase. Micronized calcite enhanced external cake consolidation through particle bridging. The combined use of PAC LV, glycerin, and calcite provided the most efficient filtration control and minimized formation damage. These findings contribute to understanding the isolated and synergistic roles of filtrate-control agents and support the design of optimized polymer-based fluids for well intervention and abandonment operations.

Abstract. Understanding the carbon cycle of the terrestrial critical zone, extending from the tree canopy to the aquifer, is crucial for accurate quantification of its total carbon storage and for modelling terrestrial carbon stock responses to climate change. Caves and their catchments offer a natural framework to sample and analyse carbon in unsaturated zone reservoirs across various spatial and temporal scales. In this study, we analyse the concentration, stable carbon isotopic ratio (δ13C), and radiocarbon (14C) compositions of CO2 from the atmosphere, boreholes (0.5 to 5 m depth), and cave sampled every 2 months over 2 years at Milandre cave in northern Switzerland. High concentrations of up to 35 000 ppmV CO2 are measured in the boreholes. The δ13C values of CO2 in the boreholes reflect the δ13C of C3 plants (∼ −26 ‰), which dominate the catchment ecosystem. Shallow meadow boreholes host older CO2 in winter and modern CO2 in summer, while forest ecosystems consistently export modern CO2 (F14C = ∼ 1) to the unsaturated zone. Cave CO2 concentrations exceed atmospheric levels and are diluted by temperature-driven seasonal ventilation. Keeling plot intercepts indicate that the cave CO2, which mixes with atmospheric CO2, is younger in summer (F14C = 0.94) and older in winter (F14C = 0.88), with a δ13C consistent with the C3-plant-dominated catchment. Mixing models utilizing drip water dissolved inorganic carbon 14C suggest that varying carbonate dissolution and degassing dynamics do not explain the F14C variation and concurrent δ13C stability of the mixing endmember. Rather, contributions from aged carbon reservoirs in the deeper unsaturated zone are likely. This study provides valuable insights into CO2 source dynamics and cycling within the karstic critical zone, highlighting the impact of seasonal variations and ecological factors on downward carbon export from terrestrial ecosystems.

Waterflooding, the predominant secondary recovery method in global sandstone and carbonate reservoirs, faces challenges including premature water breakthroughs, rapid water cut rise, limited well pattern adjustments and restricted stimulation treatments due to complex geological constraints. This demands enhanced optimization techniques. Leveraging streamline simulation’s flow diagnostic capabilities, this study introduces two novel metrics: “real-time streamline revenue” (RTSR), quantifying the economic effectiveness via flux, time of flight and saturation data integration along streamlines, and “well-pair revenue efficiency” for injection-production unit characterization. Integrating corresponding rate optimization criteria, we develop an RTSR-based production optimization methodology which enables rapid generation of optimal injection-production schedules, improving recovery while controlling water production. Validation using synthetic and field-scale models (Reservoir M) demonstrated significant improvements by the proposed method: Synthetic case achieved 29.42% NPV increase, 26.88% oil production rise, and 8.60% water reduction compared to the base schedule; Reservoir M yielded 20.80% higher NPV, 20.41% more oil, and 72.69% less water. The approach outperforms existing streamline methods, proving effective for stabilizing/enhancing oil production and reducing water cut. Future work can refine weighting functions within optimization criteria using surrogate-optimization algorithms and extend the framework to integrate layer series, well patterns, or well placement with injection-production control.Supplementary InformationThe online version contains supplementary material available at 10.1038/s41598-025-21646-7.

Understanding the role of crude oil properties, especially the asphaltene content of crude oil is crucial for enhancing the efficiency of smart water flooding, as it significantly impacts wettability and recovery factors. This study evaluates the predictive capabilities of a developed geochemical model for predicting wettability alteration during smart water flooding in carbonate reservoirs. Three types of oil samples with varying asphaltene content were employed: crude oil (8.5% asphaltene), deasphalted oil (1.8% asphaltene), and asphaltene-enriched toluene (98% asphaltene). Core flooding experiments were conducted using five types of brines: seawater, twice the sulfate concentration (2SO₄), four times the sulfate concentration (4SO₄), four times the calcium concentration (4Ca), and four times the magnesium concentration (4Mg). The model integrates DLVO (Derjaguin, Landau, Verwey, and Overbeek) theory and calculates zeta potential and disjoining pressure based on the crude oil/brine/rock (COBR) system properties such as ionic composition and oil properties. Recovery factor measurements and contact angle analyses confirmed the model’s accuracy, with seawater injection in asphaltene-rich oil resulting in the most negative electrical double layer (EDL) pressure (− 350 MPa) and a recovery factor of 10%. Conversely, 4Mg brine demonstrated superior performance in promoting water-wet conditions for both crude oil (21.34% recovery factor) and deasphalted oil (18.41% recovery factor). This study underscores the critical role of brine composition and crude oil properties in optimizing smart water flooding strategies and validates the geochemical model as a robust tool for tailoring brine compositions to enhance oil recovery in carbonate reservoirs.

The paper presents the results of selecting flow-diverting technologies (FDT) and their testing at a facility with a carbonate reservoir type, which is developed using a network of horizontal wells and has complicating factors such as high reservoir temperature (90 °C) and high salinity of formation water (over 150 g/L). These conditions significantly limit the application of conventional enhanced oil recovery (EOR) methods, as the use of common technologies such as precipitation-forming and polymer-dispersion compositions in extended-reach and horizontal wells carries the risk of irreversible blockage of the horizontal wellbore sections due to the settling of dispersed particles under gravity. Additionally, some reagents lose their technological properties and stability under high salinity and temperature conditions.Thus, the objective of this work was the selection and adaptation of FDT capable of functioning under extreme conditions to block high-permeability channels and optimize oil displacement. At the first stage, a theoretical analysis of existing technologies was conducted, and their selection was carried out considering the geological and physical characteristics of the test site. Subsequently, laboratory studies of optimal technologies for the given conditions were performed, along with field implementation support for the selected FDT.The conducted research revealed that the efficiency of flow-diverting technologies largely depends on their stability under high-temperature and high-salinity conditions. Various polymer and gel-forming systems were analyzed, among which the most degradation-resistant at 90 °C and in a high-salinity environment were identified. Laboratory experiments also assessed the compatibility of the selected compositions with reservoir fluids and rock, minimizing the risks of precipitate formation and permeability reduction in low-permeability intervals. As a result, compositions suitable for enhancing oil recovery in carbonate reservoirs with challenging geological and physical conditions were identified.The experience of applying FDT highlights the importance of laboratory testing and technology adaptation to field-specific conditions. The obtained results demonstrate that the use of adapted FDT can increase the oil recovery factor even in complex geological and technical conditions typical of carbonate reservoirs with high temperature and formation water salinity.

Underground gas storage (UGS) facilities are fundamental for national energy security and global decarbonization efforts. However, solid phase production in carbonate reservoirs, such as Qianmi Bridge, poses a significant operational challenge by compromising wellbore integrity and formation permeability. To address this, this study develops a novel, comprehensive methodology for predicting and mitigating solid phase production risk in carbonate UGS under dynamic operating conditions, specifically focusing on the Qianmi Bridge gas storage. This approach systematically integrates qualitative susceptibility assessments (using acoustic time difference, B index, and S index) with quantitative models for critical and ultimate pressure difference forecasting. Crucially, the methodology rigorously accounts for dynamic process parameters, including rock strength degradation due to acidizing, in situ stress variations, and fluid flow dynamics throughout the reservoir’s operational life cycle, a critical aspect often overlooked in conventional models designed for sandstone reservoirs. Analysis reveals that the safe operating pressure window dramatically narrows as formation pressure declines and rock strength is weakened, especially under high-intensity, multi-cycle alternating loads. Specifically, acidizing treatments can reduce the critical pressure difference by over 50% (e.g., from 40.49 MPa to 19.63 MPa), and under depleted conditions (0.6 P0, 0.8 UCS), the reservoir’s ability to resist solid phase production approaches zero, highlighting an extremely high risk. These findings provide an essential theoretical and technical basis for formulating robust operational control strategies, enabling data-driven decision-making to enhance the long-term safety, efficiency, and overall process integrity of carbonate gas storage operations.