Fractured Carbonate Reservoirs Research Articles

Three‐dimensional simulation of the acidizing process under different influencing factors in fractured carbonate reservoirs

AbstractMatrix acidizing is widely used to enhance oil/gas production in the exploitation of carbonate reservoirs. In this work, a three‐dimensional (3D) hydro‐chemical‐thermal (H‐C‐T)‐coupled model was presented to improve the understanding of the acidizing process. The influence of different influencing factors was analyzed, especially the coupling effect of natural fractures and in situ stress. With the increase in acid injection concentration, the minimum pore volume of acid required for breakthrough (PVBT) decreases. The optimal injection rate and the minimum PVBT increase with increasing initial reservoir temperature. With the increasing initial reservoir permeability, the minimum PVBT increases. With the increasing initial reservoir pore diameter and specific surface area, the minimum PVBT and the optimal acid injection rate increase. When the fracture direction is perpendicular to the direction of the maximum principal stress, the fracture apertures decrease with the increase of the maximum principal stress, which leads to an increase in PVBT and wider paths of wormholes. Lastly, the present H‐C‐T‐coupled model was applied in the context of Tahe reservoir exploitation, which shows that optimizing the acid injection rate is able to enhance the connection between wellbores and natural caves.

Characterizing Seismogenic Fault Structures of the Lake Pertusillo Reservoir Induced Seismicity (Southern Italy) Using a Relocated Template‐Matching Catalog

AbstractWe present a detailed analysis of the small magnitude (ML < 3) Reservoir Induced Seismicity associated with the Pertusillo water reservoir located in the high seismic hazard zone of Val d'Agri (Southern Italy). We apply template‐matching detection to a 13‐month‐long dense passive survey, obtaining a final high‐precision double‐difference catalog of 5,070 earthquakes (−0.7 < ML < 2.6, MC = 0.2). The new catalog allows precisely tracking the spatiotemporal distribution of the swarm‐seismicity and to map the b‐value of the Gutenberg‐Richter law. We combine seismicity data with available subsurface geophysical data, fostering an improved interpretation of the induced seismicity. We identify four seismicity‐clusters showing rapid changes in seismic rate which correlate to severe seasonal oscillations. Seismicity unravels new km‐scale faults or better define faults partially‐illuminated by template earthquakes. b‐value shows a significant spatial variability, with very‐high b‐value (up to 2) within areas of distributed seismicity and lower (∼1.3) b‐value for on‐fault seismicity featuring larger magnitude events. Seismicity is confined within a brine‐saturated fractured carbonate reservoir, while earthquake distribution and rate are controlled by the fault architecture and rock properties (e.g., inherited fluid pathways, rock fracturing, pore fluid pressure). In particular, most earthquakes reactivate, with extensional kinematics, pre‐existing reverse/transpressional faults favorably oriented in the present‐day extension. All observations suggest that a poroelastic stress transmission mechanism, due to the seasonal water level oscillation, can explain the Pertusillo lake seismicity. This study confirms the importance of investigating the complex interaction among stress changes caused by human activities, pre‐existing faults and local stress field to correctly assess the hazard posed by induced seismicity.

Special Connections for Representing Multiscale Heterogeneities in Reservoir Simulation

Summary The significant quantities of oil contained in fractured karst reservoirs in Brazilian presalt fields add new challenges to the development of upscaling procedures to reduce time on numerical simulations. This work aims to represent multiscale heterogeneities in reservoir simulators based on special connections between matrix, karst, and fracture mediums, both modeled in different grid domains within a single porosity flow model. The objective of this representation is to strike a good balance between accuracy and simulation time. Therefore, this work extends the approach of special connections developed by Correia et al. (2019) to integrate both karst and fracture mediums modeled in different grid domains and block scales. The transmissibility calculation between the three domains is a combination of the conventional formulation based on two-point flux approximation schemes and the matrix-fracture fluid transfer formulation. The flow inside each domain is governed by Darcy’s equation and implicitly solved by the simulator. For proper validation and numerical verification, we applied the methodology to a simple case (two-phase and three-phase flow) and a real case (two-phase flow). For the simple case, the reference model is a refined grid model with (1) an arrangement of large conduits (karsts), which are poorly connected; (2) a well-connected and orthogonal system of fractures; and (3) a background medium (matrix). The real case is a section of a Brazilian presalt field, characterized as a naturally fractured carbonate reservoir. The reference is the geological model. The simulation model consists of a structural model with different gridblock sizes according to the scale of the heterogeneities—small-scale karst geometries, medium-scale matrix properties, and larger-scale fracture features—interconnected by special connections. The results for both cases show a significant performance improvement regarding a dynamic matching response with the reference model, within a suitable simulation time and maintaining the dynamic resolution according to the representative elementary volume of heterogeneities, without using an unstructured grid. In comparison to the reference model, for the simple case and the real case, the simulation time was reduced by 42% and 87%, respectively. The proposed method contributes to a multiscale flow simulation solution to manage heterogeneous geological scenarios using structured grids while preserving the high resolution of small-scale heterogeneities and providing a good relationship between accuracy and simulation time.

Development of Novel Nanodetectors in Drilling Fluids To Identify the Contribution of Different Producing Zones in Naturally Fractured Carbonate Reservoirs: From the Laboratory to Field-Level Implementation

The objective of this research was to develop and incorporate nanodetectors (NDs) in drilling fluids to identify the contribution of the different producing zones in naturally fractured carbonate reservoirs. The NDs were designed to interact with the crude oil and release the active compound that allows for fluorescence emission for surface detection. Novel nanocapsules based on carbon quantum dots (CQDs) were synthesized using various nanomaterials as the core and soy lecithin as the shell. Four CQDs were used: CQD green, CQD light blue, CQD red, and CQD dark blue. CQD red was discarded as a result of high retention in calcium carbonate, and encapsulation was performed with the others to form ND1, ND2, and ND4, respectively. The technology was assured through compatibility tests with reservoir fluids, static efficiency tests, and static retention. NDs had sizes smaller than 75 nm. Also, solubility tests showed that the active compound was released upon contact with oil-based systems. The characterization of the drilling fluids indicated that properties, such as the yield point and plastic viscosity, remained the same in the presence of the ND, which allows for its use under field conditions and secure wellbore stability. The technology was successfully implemented in a Colombian oil field. Filed results showed correlations between the gas profiles, brittleness of the zone, open fractures, and concentration of nanodetectors, which allows for the conclusion of the effectiveness of the nanostructures for the detection of naturally fractured zones of the evaluated wells.

Screening, classification, capacity estimation and reservoir modelling of potential CO2 geological storage sites in the NW Adriatic Sea, Italy

In Italy, the central-northern Apennines and Adriatic Sea domains have been identified as potential CO2 storage areas. Although capacity estimates have been undertaken at a regional scale, more detailed research is required to reduce uncertainty. The present study helps address this gap by conducting a detailed screening of a representative area in the north-western Adriatic Sea for suitable CCS sites, using an extensive dataset composed of both public and private seismic and borehole data. Work included selecting suitable sites based on proposed selection criteria, calculating their theoretical and effective storage capacities applying a probabilistic approach, and then performing dynamic flow modelling on one of the selected sites that is representative of fractured carbonate reservoirs. Based on the screening results, a total of 21 out of 38 structures were selected as having the required characteristics suitable for CO2 storage. As expected, the clastic rock reservoirs have the greatest potential capacity, although some fractured carbonate reservoirs did yield important volumes due to their dual porosity / permeability characteristics. Modelling of one such site highlighted the complex interplay between primary and secondary porosity / permeability on plume migration and capacity estimation. Our results highlight the need to integrate analytical calculations with dynamic simulations for more detailed, site-specific studies to improve the estimates of CO2 storage capacity.

Optimization of design variables and control rules in field development under uncertainty: A case of intelligent wells and CO2 water alternating gas injection

This paper focuses on life-cycle optimization of oil field development plan under uncertainty. The optimization problem included a wide range of design variables and control rules related to wells and platform in a realistic benchmark case (UNISIM–II–D) with a known ground truth reservoir model, UNISIM–II–R, that resembles Brazilian pre-salt fractured carbonate reservoirs in their early development stage. The design variables were the number and location of wells, the fluid processing capacity of the platform, and the location of internal control valves (ICVs), whereas the control rules were the setting of ICVs, production and injection rates, and the duration of the water-alternating-gas (WAG-CO2) cycle. An iterative sequential optimization framework was developed to deal with the massive search space and complex parameterization. The optimization further took into consideration the subsurface, operational and economic uncertainties, and used iterative discrete Latin hypercube method as the search algorithm. The robust optimization was carried out on a subset of representative models derived from the reduction of a large ensemble of data-assimilated models. As a low-fidelity representation of the compositional fluid model, a black-oil model was used to reduce simulation runtime. To validate our optimization framework, we applied the optimal development strategy to the ensemble of compositional simulation models, as well as the ground truth model. The true model's responses were within the ranges predicted by the compositional ensemble, confirming the optimization framework's reliability. The general methodology developed in this study, as well as our findings, can be used to optimize other similar real-world complex and high-risk field development projects, and are especially useful in closed-loop field development and management practices.

Geophysical appraisal of fractured carbonate reservoirs: a case study of Abu Roash D Member, Abu Gharadig Field, Western Desert, Egypt

Geophysical appraisal of fractured carbonate reservoirs: a case study of Abu Roash D Member, Abu Gharadig Field, Western Desert, Egypt

Novel Approach for Rate Transient Analysis of Fractured Wells from Carbonate Reservoirs with Heterogeneous Natural Fractures.

This paper developed a new methodology for rate transient analysis of fractured wells in carbonate reservoirs. Both the heterogeneity and dual-permeability flow behavior are incorporated into the proposed model, and the fractured carbonate reservoir was simulated with a two-zone composite model. In each zone, a traditional dual-porosity model was applied to describe the characteristics of the natural fractures and matrix. With the Laplace transform, we derived the solution of the mathematical model and plotted new type curves for transient rate decline analysis. Then, the flow regimes were divided and analyzed based on the new type curves. The influences of several critical parameters on transient rate response were also examined. A field case was studied further to demonstrate the precision and application of the proposed method. The results show that the new type curves are mainly composed of eight flow stages. The difference in physical properties (k 2,1, η2,1) between the two zones significantly impacts the transition and boundary-dominated flow regimes. When the values of k 2,1 and η2,1 are smaller, the derivative curve of the transition flow stage will move down, and the duration of this stage on the derivative curve is longer, while the duration of the boundary dominant flow stage will decrease. The dimensionless radial radius of the inner zone (r 1D) can significantly influence the transition flow regime. When r 1D is larger, the production rate and its derivative curve of the transition flow stage will move up, and the duration of this stage will be longer. The results also show that the proposed methodology can effectively fit the field production data. This method can be applied in well productivity evaluation for fractured carbonate reservoirs.

Assessment of the deep oil and gas bearing potential onshore in the west of Azerbaijan (Tarsdallar area)


 
 
 The Tarsdeller oil and gas field, which has a brachyoanthicline structure, is the most promising area of the oil-gas region (OGR) in the Kura-Gabirri interfluve. Goal: Based on the reservoir characteristics of rock samples obtained from exploration wells drilled in the area adjacent to the field, petrophysical models have been compiled, reflecting the spatial variation in porosity and permeability of oil-containing reservoirs. Objects: Consideration of the petrophysical properties of core samples taken in the study area made it possible to confirm the oil and gas potential of deep-seated reservoirs. Methods: This analyzed the values and variation of petrophysical properties by depth, age and various physical factors. The observed wide range of changes in the reservoir properties of rocks in the study area is mainly due to tectonic changes, lithological heterogeneity of the sedimentary complex, differences in the depth of bedrocks, as well as the complexity of tectonic conditions. As a result, to predict the oil and gas content in deep reservoirs of the same structures, it is advisable to use the methods of exploration geophysics, as well as the results of changes inthe reservoir characteristics of rocks, determined by petrophysical data. At the same time, it is most expedient to focus on the study of Paleogene-Cretaceous tectonics for the search for oil and gas objects using prospecting and exploration (preferably aerial-photo-space) works at the field. Results: Models made in 3D format illustrate the predicted oil and gas potential and patterns of distribution of productive horizons involved in the geological structure of oil and gas deposits, along the depths and stratigraphic units. It is shown that although the permeability of the rocks in the area is low, the porosity values are favorable for the industrial accumulation of hydro-carbons. Fractured carbonate reservoirs of the Upper Cretaceous are the most promising among the Mesozoic sediments in the OGRbetween the Kura and Gabirri rivers. Deep-seated structural uplifts complicated by large-amplitude fractures are recommended as the priority targets for further geological exploration. However, the real potential of the Eocene deposits, which are widespread in the NGR between the Kura and Gabirri rivers, remains unexplored by deep drilling. This is due, on the one hand, to the incomplete opening of the Eocene section in the structures prepared for deep drilling, structural-tectonic and lithofacies features, as well as insufficient knowledge of drilling for oil and gas, and on the other hand, poor development of promising intervals of the section.
 
 

Fracture characterization of Asmari Formation carbonate reservoirs in G Oilfield, Zagros Basin, Middle East

The Asmari Formation in the G oilfield on the Iran-Iraq border is a fractured-porous multi-lithology mixed reservoir, for which fracture is an important factor affecting oil productivity and water cut. The characterization and modeling of fractures in the carbonate reservoir of G oilfield are challenging due to weak conventional well log responses of fractures and a lack of specific logs, such as image logs. This study proposes an integrated approach for characterizing and modeling fractures in the carbonate reservoir. The features, formation mechanism, influencing factors, and prediction methods of fractures in the Asmari Formation carbonate reservoirs of G oilfield were studied using core observation, thin section, image log, cross-dipole acoustic log (CDAL), geomechanics numerical simulation (GNS), and production data. According to CDAL-based fracture density interpretation, GNS-based fracture intensity prediction between wells, and DFN-based rock fracture properties modeling, the quantitative fracture characterization for G oilfield was realized. This research shows that the fractures in the Asamri Formation are mainly medium-to high-angle shear fractures. The substantial compression stress during the Miocene played a major role in the formation of the prominent fractures and determined their trend in the region, with primary trends of NNW-SSE and NNE-SSW. The fracture distribution has regularity, and the fractures in zone A dolomites are more highly developed than that in zone B limestones vertically. Horizontally, fractures intensity is mainly controlled by faults and structural location. The results of this study may benefit the optimization of well design during field development. From 2019 to 2021, three horizontal wells pilot tests were deployed in the fractures belt in zone A, and these fractures prominently increased the permeability of tight dolomite reservoirs. The initial production of the wells is four to five times the average production of other wells in the area, showing a good development effect. Meanwhile, the updated numerical simulation validates that the history match accuracy of water cut based on the dual-porosity model is significantly improved, proving the fracture evaluation and prediction results to be relatively reliable and applicable.

Gas condensate well productivity in fractured vuggy carbonate reservoirs: A numerical modeling study

The spatial distribution of fractures and cavities may generate important impact on the fluid flow behavior in fractured vuggy carbonate reservoirs. However, the recovery mechanism of gas condensate wells is not well understood due to the lack of effective reservoir simulation methods that coupled porous-medium and free flows occurring in fractured vuggy carbonate reservoirs. In this work, a novel compositional reservoir model is developed for modeling the production dynamics of gas-condensate well in complex fractured vuggy reservoirs. The compositional multiphase fluid flow through rock matrix and fractures is assumed to follow Darcy's law, while the free flow in cavities is modeled based on the assumptions of instantaneous thermodynamic equilibrium and phase segregation controlled by gravity. An advanced numerical calculation method combining finite volume method (FVM) and embedded discrete fracture-vug model (EDFVM) is developed to efficiently solve the multi-component multiphase flow problem. Case studies are conducted to investigate the gas-condensate flow behavior and well production performance under various configurations of fracture-cavity patterns. Two scenarios are considered by placing the production well at the top and bottom of the models, which aim to mimic different locations of directional well target. The results indicate that when cavities are present, condensate oil accumulates mainly beneath the cavities due to the effect of gravity segregation. Thus, more condensate oil may be produced with depletion at the bottom of the reservoir. However, condensate oil distributes surrounding the production well when cavities are absent, and the production performance of gas-condensate well is less affected by depletion location. Furthermore, the cumulative condensate oil and gas production are higher when cavities are present because of the continuous supplement of condensate gas by cavities. Our research findings have important implication for the design of directional well planning in the fractured vuggy gas condensate reservoirs.

Experimental Study of Acid Etching and Conductivity of High-Temperature-Resistant Cross-Linked Acid

Acid fracturing is one of the effective techniques for developing low-permeability carbonate reservoirs economically. With the increasing reservoir depth, the reservoir temperature and closure pressure increase, posing new challenges to the acid system. In this paper, a high-temperature-resistant cross-linked acid system is selected, which maintains a viscosity above 80 mPa·s in the temperature range of 120 °C to 140 °C and can effectively reduce acid leak-off. The acid system can not only open the reservoir and ensure the extension of the fracture, but also reduce the reaction rate between the acid and the reservoir and increase the etching distance. The rock slab acid etching and conductivity tests show that the optimum injection rate is 50 mL/min, the rock etching morphology is channel type, and the conductivity remains above 110 D·cm. However, as the acid concentration decreases, the rock slab conductivity decreases considerably, especially at 10% acid concentration, where the closure pressure rises to 15 MPa, and there is almost no conductivity. In particular, after the acid system is broken, the reacted acid can form a filter cake on the core surface, hindering further intrusion of the residue into the core and reducing reservoir damage. The study shows that high-temperature-resistant cross-linked acid systems can effectively improve the stimulation of deeply fractured carbonate reservoirs at high temperatures.

A novel approach for fracture porosity estimation of carbonate reservoirs

AbstractThe quality of carbonate reservoirs is linked to their rock properties and surrounding stress settings which can play a vital role in their production optimization and development programs. Imposing various stresses can increase porosity and permeability by creating joints and cracks across the rock mass. Therefore, developing methods to identify and accurately evaluate fractures in carbonate reservoirs is very significant in reservoir characterization. To deal with this necessity, we developed a fracture porosity estimation method using empirical and analytical solutions based on the wireline data considering stress conditions. The proposed methodology was applied to a carbonate reservoir as the case study. As fracture porosity is sensitive to stress, experimental tests were conducted on the core samples using triaxial hydrostatic tests. These tests are needed to simulate reservoir conditions to investigate the relationships between fracture volume fraction and the applied stress. A substantial porosity loss was observed during the hydrostatic test, which can be linked to the crack porosity closure. The reliability of our results was validated by thin section, computed tomography–scan images, velocity deviation method, elastic boundary laws, and image logs. Eventually, we introduced an equation to estimate in situ fracture porosity from the relationship between porosity and effective confining pressure. We verified the repeatability and generality of our proposed methodology using a blind well, and the results indicate a comparable level of accuracy. Our findings are applicable for estimating crack porosity for rock physics modelling purposes of detecting fracture zones in the absence of image logs and core data. Moreover, by calibrating and optimizing the constant parameters in our proposed relationship, one may further estimate crack density in any other given carbonate reservoirs.

Effect of Acid Type on Acid-Etched Fracture Surface Morphology and Conductivity along the Fracture

Laboratory measurement of acid fracture conductivity is the most direct method for acid system selection during acid fracturing in carbonate reservoirs. However, the fracture in the laboratory test is too short compared with the in-situ fracture. Thus, the acid concentration and viscosity variation and their impacts on fracture morphology and conductivity along the fracture are seldom considered, leading to inaccurate estimation of conductivity and providing uncertainty in acid selection, especially for ultra-deep carbonate reservoirs with high temperatures. To fill this knowledge gap, a series of acid-etching experiments were performed utilizing the viscoelastic surfactant-based (VES) acid and gelled acid. Fresh acid with 20 wt % and spent acid with 15 wt % concentration were used to represent the acid at the fracture-wellbore interface and that in the inner fracture. A 3D laser scanner was applied to collect fracture morphology data, which were further used to build the 2D fracture-surface roughness model via the fractal theory. Based on the model, the distribution of acid-fracture width and its roughness were exhibited, while the conductivity was tested under different closure stress. Results indicate that in comparison with gelled acid, the fresh VES acid with low viscosity exhibits strong corrosion of rock and results in the heaviest dissolved-rock weight and the maximum acid-fracture surface roughness, but the situation is just the opposite for spent acid. Conductivity shows obvious segmentation characteristics because the acid fracture narrows with the increase of closure stress. Three contact modes of acid-fracture surface cause the loss of conductivity, including longitudinal strip-like, transverse strip-like, and longitudinal and transverse flaky modes. The VES acid is selected in the YSW block based on the experimental results. The field application proves that VES-acid hybrid fracturing could result in a large increase in well production. This study gives a new horizon to selecting reasonable acid systems by testing acid-fracture conductivity.

Effect of Tilted Uniaxial Electrical Anisotropy Parameters on Signals of Electric and Electromagnetic Logging Soundings according to Results of Numerical Simulation

Abstract —To study the effect of tilted uniaxial electrical anisotropy parameters on electric and electromagnetic logging signals, their numerical simulation and comparative analysis in homogeneous and layered models have been performed. An algorithm for three-dimensional numerical simulation of resistivity logging signals in spatially heterogeneous models with tilted principal axes of the electrical conductivity tensor, based on the finite-element method, was used in the calculations. The obtained results indicate the potential for a more accurate estimation of electrophysical properties of fractured carbonate reservoirs of the pre-Jurassic basement of West Siberia, which are characterized by the tilt of the electrical conductivity tensor principal axes.

Exploring the role of the structural heterogeneity of fractured carbonate reservoirs in contact with dissolved CO2 based on fracture-water-rock simulation experiments

Based on the geological background of ultra-deep fractured carbonate reservoirs in the Shunbei oil and gas field, the objective of this study was to clarify the interactions between fractured carbonate reservoirs and formation fluids (brine with dissolved CO2) under deep strata, and the potential impact of these interactions on reservoirs. In this study, high-temperature and high-pressure simulation experiments and numerical simulations based on the Yijianfang Formation in the Shunbei area were designed to investigate the influence of temperature, pressure, fluid, and structural heterogeneity on fluid transport and mass transfer, calculate the ion diffusion characteristics and the trend of mineral dissolution/precipitation along the fractures, and clarify the change in the reservoir space. The results indicated that the volume of the main fracture increased after the reaction between an acidic solution and a formation sample, the permeability of the sample increased by orders of magnitude, and its porosity increased accordingly. The overall reaction during the experimental period was dominated by the dissolution of calcium carbonate, and no calcium carbonate precipitated. The structural heterogeneity and hydraulic properties of the sample make the main flow channel a main fracture. The flow and reaction processes in the flow channel promoted each other. The effects of temperature and pressure on the overall reservoir space were insignificant. Branch fractures or microfractures can weaken the main fluid flow rate and tend to result in the accumulation of solutes, the ends of which may be potential locations for mineral precipitation. Therefore, the priority exploration location for deep and ultra-deep fractured reservoirs should be the main fractures upstream of the fluid flow.

An Overview of Deep Geothermal Energy and Its Potential on the Island of Ireland

Summary This paper provides a short overview of geothermal energy, including a discussion on the key geological controls on heat distribution in the subsurface, and on the different types of geothermal resource and their potential uses. We then discuss the island of Ireland as an example of the role that geothermal energy can play in decarbonising the heat sector in a region characterised by relatively low-enthalpy (temperature) resources. Significant shallow geothermal potential exists across the island via the deployment of ground source heat pumps. The geology of onshore Ireland provides relatively limited potential for deep hydrothermal aquifers with primary porosity and permeability. Therefore, deep geothermal exploration on the island is likely to be focused on fractured carbonate reservoirs of Carboniferous age, with recorded groundwater temperatures reaching 38°C at 1 km depth, or on lower permeability petrothermal reservoirs developed as Enhanced or Advanced Geothermal Systems. The exception to this occurs within Mesozoic basins in Northern Ireland where porous and permeable Permo-Triassic sandstones are preserved beneath Paleogene basalts. Geothermal potential also exists in equivalent basins immediately offshore Ireland. For example, Triassic sandstones within the Kish Bank Basin, a few kilometres off the coast of Dublin, have estimated reservoir temperatures of 20–120°C across the basin.

Experimental investigation of formation damage during drilling of ultradeep fractured carbonate reservoir

Severe formation damage easily occurs in ultradeep fractured carbonate reservoirs during drilling, yet the formation damage mechanisms have not been studied extensively. This study focused on typical fractured carbonate reservoirs in the Shunbei field, China. The multiscale reservoir space characteristics and core wettability of ultradeep fractured carbonate reservoirs were investigated. The results showed that the reservoirs mainly comprise a fourth-order fracture network. The high-temperature and high-pore-pressure steady-state method also identified fluid sensitivity and phase trapping damage. The fluid sensitivity damage at the formation temperature (170 °C) indicated that this reservoir is affected by water sensitivity, salt sensitivity (critical value: 3/4 formation water salinity (FWS)), alkali sensitivity (critical value: pH 7.5), and liquid phase trapping damage. Particle movement and deposition and liquid phase trapping damage are thought to be the primary damage mechanisms. Furthermore, abnormally low water saturation, mixed wettability, abundant clay minerals, and the fourth-order fracture network contribute to fluid sensitivity and liquid phase trapping damage. Finally, a formation damage control strategy was proposed.

Nanoparticle-Surfactant Stabilized Strong Foam for Enhanced Oil Recovery in High-Salinity Fractured Carbonate Reservoirs

Summary Foam flooding can minimize bypassing in gasfloods in fractured reservoirs. Finding a foam formulation effective in high-salinity brine is challenging, especially with divalent cations, e.g., American Petroleum Institute (API) brine (8% NaCl with 2% CaCl2). When formulating with nanoparticles, the colloidal dispersion stability is difficult due to the dramatic reduction in zeta potential and the Debye length at high salinity. The aim of this work was to develop a strong foam in API brine at the ambient temperature, using a nonionic surfactant and ethyl cellulose nanoparticles (ECNP), for gasflooding in fractured carbonate reservoirs. ECNPs was synthesized and dispersed in API brine using a nonionic surfactant (also denoted as SF). SF and SF/ECNP foams were generated, and their stability was studied at atmospheric pressure and 950 psi. Foam mobility was measured in a sandpack at high pressure. Foam flood experiments were conducted in oil-saturated fractured carbonate cores. The nonionic surfactant proved to be a good dispersion agent for ECNP in API brine. The SF/ECNP mixture stabilized foam in API brine, even in the presence of oil. Injecting a partially miscible gas (below its minimum miscibility pressure) as an SF foam into a fractured core more than doubles the oil recovery over injection of the gas alone. The injection of the strong foam (SF/ECNP) further improves the oil recovery over that of the SF foam, indicating the synergy between ECNP and surfactant. ECNP accumulates in the foam lamella and induces larger pressure gradients in the fracture to divert more gas into the matrix for oil displacement.

Numerical Simulation of the Wormhole Propagation in Fractured Carbonate Rocks during Acidization Using a Thermal-Hydrologic-Mechanics-Chemical Coupled Model

Acidizing is a widely adopted approach for stimulating carbonate reservoirs. The two-scale continuum (TSC) model is the most widely used model for simulating the reactive process in a carbonate reservoir during acidizing. In realistic cases, there are overburden pressure and pore pressure at present. When the injected acid reacts with the rock, the dissolution of the rock and the consumption of the acid in the pore will break the mechanical balance of the rock. Many experimental studies show that cores after acidizing have lower strength. However, it is still not clear how the deformation of rocks by the change of ground stress influences the acidizing dynamics. For fractured carbonate reservoirs, fractures play a leading role in the flow of injected acid, which preferentially flows into the fractures and dissolves the fracture walls. The effect of the combined action of rock mechanical balance broken and fracture wall dissolution on the formation of wormholes in fractured carbonate reservoirs remains to be studied. To address the above-mentioned issues, a thermal-hydrologic-mechanical-chemical coupled model is presented based on the TSC model for studying the wormhole propagation in fractured carbonate reservoirs under practical conditions. Linear and radial flow cases are simulated to investigate the influences of fracture distribution, reaction temperature, and effective stress on acidizing dynamics. The simulation results show that more wormhole branches are formed by acidizing if the fractures are perpendicular to the flow direction of acid. Temperature is a key parameter affecting the acidification dissolution patterns, so the influence of temperature cannot be ignored during the acidification design. As the effective stress of the formation increases, the diameter of the wormhole gradually decreases, and the branching decreases. More acid is needed for the same stimulation result under higher effective stress.