Petroleum Research最新文献

{"title":"Facies-controlled diagenesis and its impact on reservoir quality of carbonate sequences: Cretaceous Sarvak Formation in the Zagros Basin, Iran","authors":"Hanieh Mollaali ,&nbsp;Hamzeh Mehrabi ,&nbsp;Mohammadfarid Ghasemi","doi":"10.1016/j.ptlrs.2025.07.008","DOIUrl":"10.1016/j.ptlrs.2025.07.008","url":null,"abstract":"<div><div>The Cretaceous Sarvak Formation in the Zagros Basin exhibits complex reservoir heterogeneity controlled by depositional facies and sequence stratigraphy-constrained diagenesis. This study integrates petrographic and petrophysical analyses of an Abadan Plain oilfield to establish predictive relationships between microfacies, diagenesis, and automated hydraulic flow units (HFUs). Eight microfacies were identified, representing four depositional environments: open marine, shoal complex, patch-reefs, and lagoon, supporting a ramp model. Reservoir quality varies systematically across four HFU classes, ranging from poor (HFU1: 0–0.1 FZI, 2.76 mD permeability, 10.85% porosity) to excellent (HFU4: &gt;0.7 FZI, 45.99 mD permeability, 17.4% porosity). Diagenetic processes show distinct relationships with sequence stratigraphy: marine cementation dominates transgressive systems tracts, while meteoric dissolution and fracturing prevail in regressive systems tracts and at sequence boundaries. Maximum flooding surfaces record chemical compaction and authigenic mineralization. Facies-selective diagenesis primarily controls reservoir quality. Grain-supported facies develop dissolution-enhanced porosity, whereas mud-dominated facies experience porosity reduction through cementation and compaction. Dolomitization and fracturing provide secondary permeability enhancement, particularly in mid-ramp settings. HFU classification reveals optimal reservoir performance in zones where dissolution and fracturing enhance pore networks (HFU3–HFU4). In contrast, non-reservoir zones (HFU1–HFU2) are affected by extensive cementation and compaction. These findings highlight the predictive potential of integrating sequence stratigraphy with diagenetic analysis for reservoir characterization in carbonate systems. The established facies-to-diagenesis relationships provide a robust framework for understanding reservoir heterogeneity and fluid flow behavior in the Sarvak Formation and analogous carbonate reservoirs.</div></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"11 2","pages":"Pages 309-332"},"PeriodicalIF":3.8,"publicationDate":"2026-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"148280954","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Comprehensive permeability-transform solutions for shale and sandstones using data sets from around the globe","authors":"Ruud Weijermars","doi":"10.1016/j.ptlrs.2025.08.006","DOIUrl":"10.1016/j.ptlrs.2025.08.006","url":null,"abstract":"<div><div>This study uses 13 proprietary data sets from sedimentary basins around the globe to constrain the permeability and porosity ranges occupied by clastic rocks (sandstones and shale). The combined data sets represent a total sample size of 21,767 data pairs of measured porosity and permeability. The data are combined in various ways and analyzed in considerable detail, in what is presently assumed the most comprehensive permeability analysis of clastic data sets. First, comprehensive porosity-permeability transforms are plotted with the aim to understand how well the two quantities actually correlate, and what may be the root cause(s) of the huge variation in their correlation. The analysis of the empirical data is embedded in a review of prior work related to permeability transforms. The Kozeny-Carman relationship is revisited and a modified scaling approach is proposed. First, it is shown how hydraulics of pore tubes of various shapes and tortuosity relate to macroscopic permeability. The key scaling factor, called here the permeability-reduction factor, <span><math><mrow><mi>β</mi><mo>/</mo><mi>τ</mi></mrow></math></span>, is the ratio of the coefficient of hydraulically effective pore space, <span><math><mrow><mi>β</mi></mrow></math></span>, and the tortuosity, <span><math><mrow><mi>τ</mi></mrow></math></span>. Whereas it is concluded that the porosity is a very poor predictor of the permeability, there appears to exist a close relationship between the permeability-reduction factor and the permeability, confirming the fundamental physical nature of <span><math><mrow><mi>β</mi><mo>/</mo><mi>τ</mi></mrow></math></span> as an excellent predictor of hydraulic transmissibility in porous media made up of sedimentary mineral aggregates. The inferred relationship provides the basis for a new method to construct permeability transforms, from bootstrapped data sets, using Monte-Carlo simulation.</div></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"11 2","pages":"Pages 361-398"},"PeriodicalIF":3.8,"publicationDate":"2026-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"148268459","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Cellulose bionanomaterial design for enhanced oil recovery: A review of existing, emerging technologies and future outlook","authors":"Francis Nyah ,&nbsp;Norida Ridzuan ,&nbsp;Emmanuel Epelle ,&nbsp;Mohd Aizudin Bin Abd Aziz ,&nbsp;Barima Money ,&nbsp;David Abutu ,&nbsp;Augustine Agi","doi":"10.1016/j.ptlrs.2025.12.002","DOIUrl":"10.1016/j.ptlrs.2025.12.002","url":null,"abstract":"<div><div>Cellulose nanoparticles are attracting interest in diverse fields because of their availability, low cost, and benign nature. Albeit previous studies have reported excellent experimental results, the application of cellulose nanoparticles in oilfield remains a challenge. Therefore, the objective of this research is to provide vital information on how to design cellulose nanoparticles for oilfield applications. Herein, the sources of cellulose and their derivatives were presented. Subsequently, cellulose pretreatment and extraction methods were elucidated. Likewise, the design of cellulose nanoparticles for oilfield applications were discussed. Also, the enhanced oil recovery (EOR) mechanisms of cellulose nanoparticles for high temperature high pressure (HTHP) reservoirs were identified and their application in EOR was reviewed. The challenges hindering full scale field application of cellulose nanoparticles were presented while concurrently shedding light on diverse methodologies employed to maintain their stability in HTHP oil reservoirs. The results indicate that wettability alteration, asphaltene precipitation, interfacial tension and viscosity reduction are the dominant EOR mechanisms by cellulose bionanomaterials, it also demonstrate that cellulose bionanomaterials can increase the viscosity of injected fluid by 10–100%, improve sweep efficiency by 52–98% and improve oil recovery by 10–35% original oil in place. It can be concluded that bionanomaterial have potential for oil field applications and are economically viable due to their high recovery rate.</div></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"11 2","pages":"Pages 641-686"},"PeriodicalIF":3.8,"publicationDate":"2026-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"148268456","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Paleocene spatiotemporal structure and evolution of the Dongying depression in the eastern Bohai Bay Basin: Evidence from seismic interpretation and basalt 40Ar/39Ar dating","authors":"Chuanxin Li,&nbsp;Jiaying Feng","doi":"10.1016/j.ptlrs.2025.09.002","DOIUrl":"10.1016/j.ptlrs.2025.09.002","url":null,"abstract":"<div><div>The Paleocene marked a critical structural transition period from tectonic subduction to extensional rifting in the Bohai Bay Basin. To reconstruct the spatiotemporal structural framework, evolutionary process, and basin prototype during the Paleocene Kongdian period of the Dongying Depression in the eastern Bohai Bay Basin, this study integrated seismic interpretation, core observation, ⁴⁰Ar/³⁹Ar dating, and structural restoration. The ⁴⁰Ar/³⁹Ar dating of basalts (approximately 57.58 ± 0.77 Ma) revealed that the depression entered an active rifting stage with intense volcanism in the early Paleocene Kongdian period. Regional faults, including the Chennan, Wangjiagang Shicun, and Gaocheng faults, were well developed during the first member of the Kongdian sedimentary stage. Their activity indicates rapid rift expansion and resulted in a half-graben pattern characterized by faulting in the north and onlap in the south. Structural restoration showed that the stretching ratio during the Paleocene Kongdian period was approximately 7.3%, which reflects rapid rifting. The development of the early Paleocene rift has important implications for deep hydrocarbon exploration in the Bohai Bay Basin.</div></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"11 2","pages":"Pages 333-345"},"PeriodicalIF":3.8,"publicationDate":"2026-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"148501951","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Seismic attribute integration and neural network analysis for quantitative reservoir characterization: A case study from the Offshore Nile Delta (Egypt)","authors":"Adel Mahmoud Negm,&nbsp;Mohamed I. Abdel-Fattah,&nbsp;Mansour H. Al-Hashim,&nbsp;Mohamed Reda","doi":"10.1016/j.ptlrs.2025.09.004","DOIUrl":"10.1016/j.ptlrs.2025.09.004","url":null,"abstract":"<div><div>Accurate reservoir characterization is essential for optimizing hydrocarbon exploration and production, particularly in complex deep-water environments. The Simsat Field, Offshore Nile Delta, features a Pliocene deep-water turbidite reservoir, primarily composed of interbedded sand channels and shale, which poses significant challenges for reservoir delineation due to lateral lithological variations, limited well control, and complex stratigraphic architecture. Traditional seismic interpretation methods often struggle to capture the heterogeneity and connectivity of these reservoirs, leading to uncertainties in hydrocarbon prospect evaluation. To address these challenges, this study integrates seismic attributes, post-stack seismic inversion, and a multi-layer feed-forward neural network (MLFN) to enhance quantitative reservoir characterization. This integrated approach outperforms the limitations of individual techniques by combining the spatial resolution of seismic attributes, the lithology-fluid sensitivity of inversion, and the non-linear predictive capabilities of machine learning. The workflow provides a synergistic solution that improves property prediction accuracy and reduces interpretation uncertainty, particularly in data-limited, structurally complex settings. Spectral decomposition improves the visualization of channel morphology and stratigraphic variations, while seismic inversion generates acoustic impedance volumes that aid in lithology differentiation and fluid detection. The MLFN model, trained using well log data and multiple seismic attributes, provides high-accuracy predictions of shale volume (Vsh), porosity, and water saturation, significantly improving the assessment of reservoir quality. The results confirm a well-defined gas-bearing sandstone reservoir with high porosity (&gt;18%) and low water saturation, indicating strong hydrocarbon potential. This integrated approach demonstrates the effectiveness of combining advanced seismic interpretation with machine learning techniques to reduce interpretation uncertainties, improve reservoir connectivity analysis, and optimize field development strategies in the West Delta Deep Marine (WDDM) concession. The findings provide valuable insights into reservoir heterogeneity and contribute to more effective hydrocarbon exploration and production in the Offshore Nile Delta.</div></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"11 2","pages":"Pages 346-360"},"PeriodicalIF":3.8,"publicationDate":"2026-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"148501899","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Fracture conductivity damage in shale oil reservoirs: Mechanism model and its impact on oil production","authors":"Liang Zhang,&nbsp;Runzhen Wu,&nbsp;Chuan He,&nbsp;Xiang Li,&nbsp;Yige Qi,&nbsp;Linchao Yang,&nbsp;Zilin Zhang","doi":"10.1016/j.ptlrs.2025.11.003","DOIUrl":"10.1016/j.ptlrs.2025.11.003","url":null,"abstract":"<div><div>Shale oil reservoirs often experience severe hydraulic fracture stress sensitivity and conductivity damage, leading to rapid production decline and low oil recovery. Understanding fracture damage mechanisms is crucial for optimizing stimulation and production strategies. This study established a novel conductivity damage model of hydraulic fracture incorporating stress sensitivity, gel-breaking residue deposition, and the process of shale particle hydration, expansion, shedding, and blockage. A sensitivity analysis was conducted by numerical simulation to evaluate the impact of different damage mechanisms on fracture conductivity and oil production. The simulation results indicate that different damage mechanisms have varying impacts on fracture conductivity and production. Stress sensitivity significantly reduces main fracture conductivity, but broken gel residue is the primary cause of oil production decline. In branch fractures, both stress sensitivity and broken gel residue decrease conductivity, with stress sensitivity having the greatest impact on production. Shale particle expansion and deposition can further impair fracture conductivity, while particle detachment and output help restore it. Oil production of branch fractures is more sensitive to conductivity damages. These insights can guide fracture design, fracturing fluid optimization, and production control. It is recommended to increase proppant concentration to mitigate the adverse effect of stress sensitivity on oil production, enhance the concentration of anti-swelling agents in the pre-slug of fracturing fluid to better protect branch fractures, and control drawdown pressure to prevent shale particles from detaching and depositing in the fractures.</div></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"11 2","pages":"Pages 556-573"},"PeriodicalIF":3.8,"publicationDate":"2026-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"148501904","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Pressure transient analysis of commingled multilayer reservoirs: A deconvolution-based approach for individual layer characterization using sparse PLT data","authors":"Mina S. Khalaf","doi":"10.1016/j.ptlrs.2025.11.006","DOIUrl":"10.1016/j.ptlrs.2025.11.006","url":null,"abstract":"<div><div>Layering is common in hydrocarbon reservoirs due to stratified sedimentary deposition, with each layer exhibits distinct characteristics. Multilayer reservoirs are typically classified as systems with interlayer/formation crossflow and systems without interlayer crossflow (commingled systems). This study focuses on the latter, where fluid exchange between layers occurs solely through the wellbore. Accurately interpreting pressure transient data from commingled systems to extract individual layer properties remains a persistent challenge. Most existing interpretation techniques rely on assumed reservoir models (typically homogeneous, isotropic, and infinite in extent) that involve numerous unknown parameters (such as permeabilities and skin factors) and require nonlinear history matching. These assumptions not only introduce subjectivity but can also yield unreliable estimates. The most reliable way to characterize individual layers has traditionally required isolating and testing each layer separately, which is a process that is both technically complex and costly to implement. This study introduces a testing and analysis methodology developed specifically for commingled multilayer reservoirs. The proposed approach utilizes deconvolution to remove rate variation effects from bottomhole pressure data and generate pressure responses equivalent to constant-rate conditions. This transformation enables the recovery of distinct pressure signatures for each individual layer without requiring assumptions. The recovered pressure signals are wellbore storage (WBS) free and extend over the entire test duration, offering a clearer window into the dynamic behavior of each contributing formation. Deconvolution needs complete sandface rate data for each layer, data that are typically unavailable in field practice. To address this, the study develops a simple yet effective power-law model that reconstructs layer-specific rate profiles using only a few discrete production logging tool (PLT) measurements, making the overall approach feasible for real-world applications. The method was implemented and validated on three simulated oil reservoir scenarios, each exhibiting different reservoir/boundary characteristics. The results show that the estimated rate profiles, when input into a stable deconvolution algorithm, produce layer-specific pressure responses. The technique successfully distinguishes the flow behavior and boundary conditions of each individual layer, even under complex conditions such as heterogeneity, no-flow boundaries, dual-porosity formations, and wellbore crossflow during shut-in periods. This advancement enables efficient reservoir description and production optimization, by eliminating the need for mechanical isolation or extended shut-in periods, offering a practical alternative that is aligned with the industry demands for minimum well intervention and cost-effective surveillance.</div></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"11 2","pages":"Pages 574-589"},"PeriodicalIF":3.8,"publicationDate":"2026-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"148501905","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Physicochemical characterization of oilfield produced water and its treatment constraints","authors":"Sandro Duarte César,&nbsp;Debbie De Jager,&nbsp;Mahomet Njoya","doi":"10.1016/j.ptlrs.2025.10.003","DOIUrl":"10.1016/j.ptlrs.2025.10.003","url":null,"abstract":"<div><div>Produced water is the largest waste stream generated during oil and gas production, presenting significant environmental risks due to its complex chemical composition. Characterizing the contaminant profile of produced water is crucial for assessing its environmental impact, ensuring compliance with discharge standards, and developing effective pollution mitigation strategies. This study characterizes untreated produced water from Angolan offshore Block 15 over a 50-day sampling period, analyzing over 30 target constituents. Results reveal substantial variability in key parameters, including chemical oxygen demand (394.02–526.00 mg/L), biochemical oxygen demand (9.80–20.40 mg/L), phenol (2.70–4.12 mg/L), benzene, toluene, ethylbenzene and xylene (BTEX, 2.77–7.00 mg/L), polyaromatic hydrocarbons (0.20–1.20 mg/L), total organic compounds (248–918.45 mg/L), total oil and grease (19–206 mg/L), and total petroleum hydrocarbons (12–105.02 mg/L). Metals and anions exhibited significant fluctuations, with sodium ranging from 1167.77 to 2100.00 mg/L and chloride from 400 to 2146.84 mg/L. The biodegradability index (0.028) indicates limited potential for biological treatment due to toxic and refractory organics. The results emphasize the necessity for advanced treatment technologies and stricter environmental regulations to reduce contaminant discharge and minimize the ecological footprint of offshore oil production.</div></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"11 2","pages":"Pages 633-640"},"PeriodicalIF":3.8,"publicationDate":"2026-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"148501901","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Synergizing foam stability, gas mobility control, and oil recovery: A new approach combining silane-silica oxide and MFomax","authors":"Mohammed Falalu Hamza ,&nbsp;Hassan Soleimani ,&nbsp;Bashir Abubakar Abdulkadir ,&nbsp;Saifullahi Shehu Imam ,&nbsp;Sabiha Hanim Saleh ,&nbsp;Yarima Mudassir Hassan","doi":"10.1016/j.ptlrs.2025.09.008","DOIUrl":"10.1016/j.ptlrs.2025.09.008","url":null,"abstract":"<div><div>Oil reservoirs subjected to a gas recovery technique are commonly challenged by early gas breakthroughs affecting the production rate. Foam is injected to block and divert gas to reservoir sections, however, achieving this mechanism requires stable foam to withstand extreme reservoir conditions, such as temperature, pressure and salinity. In this work, synergy actions between aminopropyltriethoxysilane doped SiO₂ nanoparticles (NPs) and MFomax were investigated on rheology, interfacial tension (IFT), wettability, foam stability and quality to reduce gas mobility and enhance oil recovery (EOR). The formulation was guided by optimization, and the foam studies were carried out at optimum concentrations. Core-flood equipment was used to assess the gas mobility reduction factor (MRF) and EOR. From the findings, the foamability of the nanofluid is primarily governed by synergy action between the NPs and MFomax due to significant R² value (0.9; p &lt; 0.05). Presence of NPs in the formulation resulted in good fluid properties such viscosity and IFT. The nanofoam stability has improved tremendously to 119% relative to MFomax foam. According to the IFT and contact angle, the detachment energy of the NPs (1.4 × 10⁸ eV) is higher than 1 eV suggesting strong adsorption at aqueous interface leading to foam stability. The nanofoam reached a maximum of 50 MRF, while MFomax was below 40 MRF. Subsequently, all the foam descended to lower quality regions around 5 PVI due to the change in foam morphology. Furthermore, the EOR recorded by nanofoam demonstrates a 7% increase on top of MFomax recovery factor. Thus, it can be deduced that the synergy of SiO₂ NPs with MFomax offer several benefits in improving the foam stability, quality, MRF and EOR.</div></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"11 2","pages":"Pages 441-450"},"PeriodicalIF":3.8,"publicationDate":"2026-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"148268461","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"A review on cementing system for CO2 storage wells: Mechanisms, testing protocols and screening criteria","authors":"Muhammad Hammad Rasool,&nbsp;Syahrir Ridha,&nbsp;Raja Rajeswary Suppiah,&nbsp;Suhaib Umer Ilyas,&nbsp;Shwetank Krishna,&nbsp;Muhammad Galang Mardeka,&nbsp;Muhammad Adeem Abbas,&nbsp;Husnain Ali","doi":"10.1016/j.ptlrs.2025.10.001","DOIUrl":"10.1016/j.ptlrs.2025.10.001","url":null,"abstract":"<div><div>Long-term containment of CO₂ in geological formations demands cementing systems that can withstand highly aggressive downhole environments, where carbonic acid, brine, and other reactive species threaten the integrity of cement sheath. This review critically examines the deterioration mechanisms of Portland-based cements under CO₂-rich conditions, emphasizing acid-induced decalcification, carbonation, and leaching processes. It further categorizes and compares a broad range of acid-resistant alternatives including modified Portland systems, non-Portland systems (CAC: Calcium Aluminate Cement, CAPC: Calcium Aluminate Phosphate Cement, MPC: Magnesium Phosphate Cement, geopolymers), resin-based sealants, and nano-engineered formulations, focusing on their chemistry, resistance mechanisms, performance metrics, and field applicability. The review then proposes a detailed laboratory testing system aligned with API standards and introduces a phase-wise testing protocol. A novel conceptual screening criterion (HSR framework) is developed based on operational, design, and sustainability parameters to guide material selection and validation for CO₂-brine exposed cementing systems. Among the systems evaluated, CAC, CAPC, and MPC have shown superior results in terms of post-exposure compressive strength retention and reduced carbonation depth. Key knowledge gaps and challenges are identified, particularly regarding long-term behavior under thermobaric and acidic exposure. Finally, a future roadmap is outlined, calling for systematic field validation, deeper mechanistic insights into CAC and CAPC systems, and innovations in multifunctional, low-carbon binders suited for emerging CCS frontiers.</div></div>","PeriodicalId":19756,"journal":{"name":"Petroleum Research","volume":"11 2","pages":"Pages 471-500"},"PeriodicalIF":3.8,"publicationDate":"2026-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"148501903","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}