SPE Journal最新文献

{"title":"Reversing Thermal Thinning and Enhancing Solids Suspension in Ultrahigh-Temperature Oil-Based Fluids Using a Smart Gelling Agent","authors":"Mingliang Du, Yanhua Lv, You Guo, Yinbo He, Guancheng Jiang","doi":"10.2118/231864-pa","DOIUrl":"https://doi.org/10.2118/231864-pa","url":null,"abstract":"Summary Drilling reservoirs with bottomhole temperatures exceeding 220°C is challenging due to the severe thermal thinning of oil-based drilling fluids (OBDFs). Conventional modifiers often degrade under these extremes, leading to barite sag. In this paper, we evaluate a novel amphiphilic, temperature-responsive oil-phase gelling agent (TR-OPG) designed to stabilize fluid rheology in ultrahigh-temperature environments. The TR-OPG features a thermally stable polyamide-imide backbone. Characterization reveals a “coil-to-stretch” transition at approximately 180°C, triggered by intramolecular hydrogen bond dissociation. This activates an “inverse-temperature gelation” mechanism where unfolded polymer chains bridge emulsion droplets to construct a shear-thinning weak gel, providing sufficient suspension capacity. Performance evaluation demonstrates that 1.0 wt% TR-OPG creates a “U-shaped” rheological profile, maintaining manageable surface viscosity to minimize equivalent circulating density (ECD) while boosting viscosity at bottomhole temperature. High-temperature and high-pressure (HTHP) testing confirmed a sharp rebound in the 6-rev/min reading (θ6) from 10.2 at 180°C to 17.3 at 220°C, effectively compensating for base oil thermal thinning. TR-OPG significantly outperformed commercial organoclay and amide modifiers. Furthermore, the formulation exhibited exceptional stability, maintaining a sag factor < 0.52 and electrical stability (ES) > 1,200 V after static aging at 220°C for 10 days. The developed TR-OPG offers a robust solution for managing rheological risks in ultrahigh-temperature drilling.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":"31 03","pages":"1728-1742"},"PeriodicalIF":0.0,"publicationDate":"2026-01-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147885072","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"A Polycyclic Side-Chain Filtration Reducer for Water-Based Drilling Fluids: Experimental Evaluation and Artificial Neural Network–Based Apparent Viscosity Prediction","authors":"X. B. Zhang, Kaihe Lv, Xianbin Huang, Jinsheng Sun","doi":"10.2118/231830-pa","DOIUrl":"https://doi.org/10.2118/231830-pa","url":null,"abstract":"Summary Fluid loss control under harsh conditions remains a major challenge in the field of drilling fluid. In this work, a polycyclic side-chain polymer (ASAA) was synthesized and characterized by Fourier transform infrared spectra (FTIR) and thermogravimetric analysis (TGA), which was evaluated as filtration control additive for water-based drilling fluids (WDFs) under high-temperature and high-salinity conditions. The rheological and filtration performance of bentonite-based mud (BM) with additional ASAA were explored over a range of temperatures and sodium chloride (NaCl) concentrations, and the dynamical stability was examined via the multilight scattering method. Mechanism studies involving FTIR, adsorption capacity, zeta potential, particle-size distribution (PSD), and scanning electron microscopy (SEM) of ASAA-treated BM (ASAA-BM) were systematically investigated in detail. The result suggested that the additional ASAA significantly improved the tolerance of BM, with a filtration loss of 6.2 mL under saturated salt contamination after aging at 200°C. It was revealed that ASAA strongly adsorbed on bentonite even under high-temperature and saturated salt conditions, resulting in the enhanced particle dispersion and the formation of dense, low-permeability filter cakes. In addition, the rheological behavior of WDFs was influenced by additives; thus, an artificial neural network (ANN) model was developed to predict the apparent viscosity of drilling fluids with varying additive and salt contents under different aging temperatures. Trained with fivefold cross-validation, the model achieved high accuracy of the test set (Pearson correlation coefficient R = 0.9884) and exhibited strong agreement between predicted and experimental values. These findings indicated that ASAA was a promising additive for WDFs in harsh drilling environments, and the ANN model provided a credible tool for predicting and optimizing WDF performance, demonstrating its potential as a practical “mud-laboratory assistant” for drilling fluid design and optimization.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":"31 03","pages":"1547-1562"},"PeriodicalIF":0.0,"publicationDate":"2026-01-07","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147920184","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Novel Slightly Crosslinked Hydrophobic Zwitterionic Polymer for Modifying Rheology and Filtration Loss of Clay-Free Water-Based Drilling Fluids","authors":"Taifeng Zhang, J. Sun, Li Wang, Kaihe Lv, Jingping LIU, Yuanwei Sun, Zhe Xu, Han Yan, Kai Yang, Haijiang Yi","doi":"10.2118/231434-pa","DOIUrl":"https://doi.org/10.2118/231434-pa","url":null,"abstract":"Summary In this study, a novel, slightly crosslinked hydrophobic zwitterionic polymer (RMJ-1) was synthesized to modify the rheology and filtration loss (FL) of clay-free water-based drilling fluids (CFWBDFs) for use under high-temperature, high-salinity conditions. The temperature resistance of RMJ-1 was up to 180°C, and the salt (Na+, Ca2+) tolerance was up to saturated. RMJ-1 exhibited a contracted linear shape in fresh water, and it was capable of forming a “pea-pod”-shaped network structure through covalent bonding, electrostatic force, and hydrophobic association. Due to the combined effects of antipolyelectrolyte and hydrophobic association, RMJ-1 was able to stretch in a saturated-salt environment and formed a denser “honeycomb”-shaped network. The network structure formed by RMJ-1 imparted desirable shear-thinning, viscoelastic, and thixotropic properties to CFWBDFs, effectively reducing FL. Especially at higher salt concentrations, RMJ-1 salt solutions exhibited higher viscosity, higher yield point (YP), higher modulus, stronger thixotropy, greater shear resistance, and lower FL. The CFWBDFs exhibited appropriate rheological properties and FL within the density range of 1.20–1.60 g/cm³, both before and after aging at 180°C. RMJ-1 surpassed the reference-grade polymer (RGP) at 180°C and under saturated-salt conditions, and it is expected to be widely applied in oil fields in the future. This research introduces novel concepts for developing high-performance additives in CFWBDFs.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":"31 02","pages":"824-844"},"PeriodicalIF":0.0,"publicationDate":"2025-12-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147902031","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Preparation of Self-Healing Polyurethane Based on the Phase-Locking Effect and Application for Lost Circulation Control","authors":"Ren Wang, Cheng Wang, Yang Bai, Yifu Long, Jie Yang","doi":"10.2118/231433-pa","DOIUrl":"https://doi.org/10.2118/231433-pa","url":null,"abstract":"Summary Lost circulation is a critical technical challenge in the process of drilling. Lost circulation materials (LCMs) with self-healing properties offer an effective method for lost circulation control by forming an integrated plugging layer within fractures. The phase-locking effect enables the confinement of dynamic bonds within the hard segment phase of self-healing polyurethane (PU), thereby restricting their kinetic exchange and controlling the self-healing properties of the material. In this work, a PU elastomer (HS-PU) with heat resistance and self-healing properties was prepared by using hydroxyl-terminated polybutadiene (HTPB) as the soft segment and 4,4'-diphenylmethane diisocyanate (MDI) as the hard segment and introducing dynamic disulfide bonds. HS-PU was systematically characterized by Fourier transform infrared (FT-IR) spectroscopy, atomic force microscopy (AFM), and thermogravimetric analysis. HS-PU exhibited excellent water resistance, and the retention rate of the tensile strength was as high as 91.3% after soaking in water for 36 hours. Besides, HS-PU has good heat resistance and can achieve self-healing in the range of 110–150°C, and the self-healing rate increases with increasing temperature. The pressure-bearing capacity of HS-PU at 130 and 150°C is 4 and 3.5 MPa, respectively, and the capacity can reach 13 MPa after the addition of bridge-plugging materials. Moreover, HS-PU still has excellent pressure-bearing performance in water-based muds (WBMs). This work provides a new approach for controlling lost circulation in complex formations at the field and developing heat-resistant self-healing LCM, holding significant practical importance for ensuring safe and efficient drilling operations.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":"31 02","pages":"808-823"},"PeriodicalIF":0.0,"publicationDate":"2025-12-10","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147910143","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"CO2 Conformance Control and Carbon Storage Performance of Particle Gels in Fractured Reservoirs Using Nuclear Magnetic Resonance Methods","authors":"Daoyi Zhu, Yongliang Yang, Honggen Tan, Si Guo, Jiabin Lu, Tao Zhang, Jiong Zhang, Yingqi Gao, Hongyu Li, Hongbin Cheng","doi":"10.2118/231408-pa","DOIUrl":"https://doi.org/10.2118/231408-pa","url":null,"abstract":"Summary Particle gels, as high-efficiency materials for large flow channels like fractures, demonstrate significant potential in controlling CO2 channeling and enhancing carbon sequestration during CO2 flooding in fractured reservoirs. While preformed particle gels (PPGs) and flexible particles (FPs) represent two prevalent conformance control agents, their comparative performance in CO2 diversion remains poorly understood. This study evaluated these two structurally distinct particle gels through static swelling tests, rheological analyses, fracture transport/plugging experiments, and core dynamic plugging tests. Nuclear magnetic resonance (NMR) was also used to elucidate the microscale mechanisms of CO2 channeling control and sequestration enhancement. Results show that PPGs exhibited a swelling ratio of 36.15 in brine but underwent dehydration after 7-day CO2 exposure. In contrast, FPs exhibited no aqueous swelling but demonstrated a CO2-induced expansion ratio of 1.13 with reduced viscoelasticity. Both gels maintained excellent injectivity (> 1 mm fractures, i.e., >0.0394 in fractures) when brine-transported though coreflooding confirmed FPs’ superior CO2 channeling control capability. Innovatively, NMR T2 analysis provided pore-scale evidence of enhanced carbon sequestration mechanisms, FPs created stronger fracture blockages with less core matrix damage (e.g., avoiding water blocking caused by PPG dehydration), enabling FP selection as the optimal CO2 conformance agent. Notably, storage modulus (G’) showed no direct correlation with plugging strength. This work established a theoretical framework for selecting optimal particle gels to mitigate CO2 channeling and enhance carbon storage efficiency in fractured reservoirs.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":"31 01","pages":"588-601"},"PeriodicalIF":0.0,"publicationDate":"2025-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147881164","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Microemulsion-Assisted Fracturing-Flooding: An Eco-Technical Alternative to Thermal Recovery for Marginal Extraheavy Oil","authors":"Yeliang Dong, Sen Wang, Xi Lu, Jiaqiang Wang, Dexin Liu","doi":"10.2118/231177-pa","DOIUrl":"https://doi.org/10.2118/231177-pa","url":null,"abstract":"Summary Low-permeability, water-sensitive extraheavy oil reservoirs with abundant reserves in China remain unapproved for commercial development using thermal recovery or other existing technologies due to their carbon emission problems and/or techno-economic limitations. This study proposes injecting microemulsions via fracturing-flooding to unlock the production potential of these challenging reservoirs. Alkyl polyglucoside and sodium dodecyl diphenyl ether disulfonate were used to formulate multifunctional microemulsions specifically tailored for harsh reservoir conditions. High-rate/high-pressure fracturing-flooding technology was used to establish significant pressure gradients for enhanced oil displacement. Experimental results demonstrated that the bicontinuous microemulsions effectively cleaned the oil sands and inhibited clay swelling, thereby improving permeability. The key mechanism for improving extraheavy oil mobility involved two sequential steps: (1) the oil phase of the microemulsions reduced the extraheavy oil viscosity to below 5,000 mPa·s through dilution, followed by (2) the surfactant components subsequently emulsifying the diluted crude oil into oil-in-water droplets with viscosity <500 mPa·s. Coreflooding tests revealed that moderately elevated injection rates enhanced pore-throat connectivity and achieved higher oil recovery, whereas excessive rates reduced chemical retention time, leading to a sharp decline in ultimate oil recovery. A development strategy centred on microemulsion-assisted fracturing-flooding, comprising four key steps, was implemented in a marginal heavy oil reservoir of Sinopec Shengli Oil Field, achieving a multifold increase in crude oil production and being assessed as economically viable at oil prices above 48 USD/bbl. This milestone achievement represents a groundbreaking advancement in the development of marginal heavy oil resources under escalating carbon emission regulations.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":"31 01","pages":"602-620"},"PeriodicalIF":0.0,"publicationDate":"2025-10-31","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147898966","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"A Hyperbranched Copolymer as High-Temperature and Salt-Resistance Fluid Loss Reducer for Water-Based Drilling Fluids: Preparation, Evaluation, and Mechanism Study","authors":"Jian Li, Junhao Fan, Jinsheng Sun, Zhaoyang Wang, Kaihe Lv, Yuanzhi Qu, Guiqin Xu, MA Fu-bo, Wen Li, Wenlong Ma","doi":"10.2118/231144-pa","DOIUrl":"https://doi.org/10.2118/231144-pa","url":null,"abstract":"Summary In the high-temperature and high-salt environment of deep and ultradeep wells, conventional linear polymer fluid loss reducers for drilling fluids have high viscosity and are prone to conformational changes (such as curling, crosslinking, and degradation), posing significant challenges to the control of drilling fluids performance (e.g., viscosity, filtration, weighting). We developed an innovative high-temperature and high-salt-resistance hyperbranched copolymer fluid loss reducer (HBPSiO-DADV) using N, N-dimethylacrylamide (DMAA), 2-acrylamide-2-methylpropyl sulfonic acid (AMPS), diallyl dimethyl ammonium chloride (DMDAAC), and 1-vinylimidazole (VIm) through the initiation polymerization of cerium ammonium nitrate (CAN) and hyperbranched polysiloxane with amino and hydroxyl groups at the end. For comparison, a linear copolymer fluid loss reducer (DADV) was prepared by initiating monomer polymerization in equal proportions using an oxidation-reduction system composed of ammonium persulfate (APS) and sodium bisulfite. Compared with DADV, HBPSiO-DADV has significantly lower molecular weight and relatively lower solution viscosity. Thermogravimetric analysis (TGA) revealed that the initial degradation temperature of HBPSiO-DADV (295°C) was obviously superior to that of DADV (258°C), indicating that the hyperbranched copolymer had excellent temperature resistance. When 3 wt% HBPSiO-DADV was added to the base slurry, the apparent viscosity (AV) before and after aging at 200°C was 45 mPa·s and 39 mPa·s, respectively, values that were significantly lower than those of DADV (80 mPa·s and 50 mPa·s, respectively). In addition, after aging at 200°C, the salt-contaminated base slurry [30 wt% sodium chloride (NaCl)] containing 3 wt% HBPSiO-DADV had a high-temperature and high-pressure filtration loss of 21 mL, which was notably lower than that of DADV (30 mL) at the same concentration, as well as that of commonly used anti-high-temperature fluid loss reducers such as Driscal-D (52 mL) and Dristemp (58 mL). Therefore, the unique hyperbranched structure of HBPSiO-DADV endowed it with excellent performance in low viscosity, temperature, and salt resistance, which would point out new directions for the design and manufacture of high-performance drilling fluids treatment agents and provide strong support for the regulation of rheological and filtration properties in deep and ultradeep wells.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":"30 12","pages":"7347-7363"},"PeriodicalIF":0.0,"publicationDate":"2025-10-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147910249","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Pore-Scale Variations of Remaining Oil in Fractured-Porous Volatile Reservoirs under Associated Gasflooding","authors":"Yue Pan, Huiqing Liu, Song Zhou, Chen Luo, Tianyi Fan, Xiang Li, Hong Huang, Zuochen Wang","doi":"10.2118/231178-pa","DOIUrl":"https://doi.org/10.2118/231178-pa","url":null,"abstract":"Summary Waterflooding is an effective method to enhance oil recovery in carbonate reservoirs. However, due to the complex depositional environments, highly developed fractures, and intricate pore-throat structures of carbonate reservoirs, waterflooding often exhibits inefficient performance. Volatile oil reservoirs, with their abundant associated gas resources, can benefit from associated gasflooding, which has become an economical and effective enhanced oil recovery (EOR) method under favorable conditions. Although the mechanisms of associated gasflooding have been well-documented, there remains a significant gap in understanding of the microscopic remaining oil production characteristics and the occurrence states of remaining oil during associated gasflooding. To address this issue, we used nuclear magnetic resonance (NMR) and cryogenic thin-section fluorescence analysis (CTFA) techniques to investigate the microscopic remaining oil production characteristics and the occurrence states of remaining oil during associated gasflooding. Initially, NMR was used to study the microscopic remaining oil production characteristics of cores under different reservoir types, fracture orientations, and gas injection rates. CTFA was then applied to examine the occurrence states of microscopic remaining oil. Based on the formation mechanisms, the remaining oil is classified into different types. We found that waterflooding primarily produces volatile oil in microscale micropores (1–10 μm), with a maximum recovery of 20.2%, while volatile oil in nanopores (<0.1 μm) remains largely nonproductive. Associated gasflooding not only improves oil recovery in existing microscale micropores but also enhances oil production in submicron pores (0.1–1 μm). Through this study, we identified four types of microscopic remaining oil, which are clustered, throat, droplet, and pore lining adsorbed. Notably, associated gasflooding has a limited effect on altering the morphology of deeply trapped oil in the matrix, with remaining oil predominantly occurring in a clustered form. This phenomenon becomes more pronounced with increasing fracture aperture. This nuanced understanding of remaining oil under associated gasflooding offers valuable insights into optimizing EOR strategies in fractured-porous volatile reservoirs.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":"30 12","pages":"7859-7872"},"PeriodicalIF":0.0,"publicationDate":"2025-10-24","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147889963","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Investigation of Novel Modified Nanoparticle-Enhanced Viscoelastic Surfactant Clean Fracturing Fluid System for Improving Oil Recovery in Low-Permeability Reservoirs","authors":"Shengming Huang, Guancheng Jiang, Zilun Chang, Chunping Guo, Quan‐De Wang, Tengfei Dong, Yinbo He, Lili Yang, Zhehui Jin","doi":"10.2118/230307-pa","DOIUrl":"https://doi.org/10.2118/230307-pa","url":null,"abstract":"Summary Nanoparticle-enhanced viscoelastic surfactant (VES) fracturing fluid systems have attracted significant attention for their exceptional rheological properties and superior resistance to temperature and shear. In this study, we introduce a novel modified nano-silica (nano-SiO2)-enhanced VES clean fracturing fluid system developed to optimize performance and enhance oil recovery. We achieved this by deeply investigating the fluid’s rheological characteristics, thermal and shear stability, and self-assembly behavior. From both fracturing and spontaneous imbibition perspectives, we formulated and tested two VES systems: VES-A (without nano-SiO2) and VES-B (incorporating modified nano-SiO2 materials). These systems were based on a synthesized zwitterionic surfactant, erucamidopropyl hydroxysultaine (EAPHS), along with sodium salicylate (NaSal) and potassium chloride (KCl). Our findings indicate that modified nano-SiO2 can effectively alter the surface charge of the VES system, promoting the formation of more uniform and stable wormlike micelles (WLMs). Moreover, nano-SiO2 particles act as effective crosslinking sites for micelles through electrostatic adsorption or hydrogen bonding, thereby constructing a longer, more robust 3D micellar network that significantly enhances the system’s viscoelasticity and shear resistance. The VES-A system maintained a viscosity of 32 mPa·s after shearing at 120°C and 170 s⁻¹ for 60 minutes, yielding an imbibition oil recovery rate of 35.21%. In stark contrast, the VES-B system’s viscosity remained at 61 mPa·s after shearing under more demanding conditions (140°C and 170 s⁻¹ for 60 minutes), and its imbibition oil recovery rate reached 47.35%. Throughout the entire imbibition process, the VES-B system demonstrated superior oil displacement efficiency compared with the VES-A system, which is of great significance for the development of low-permeability and tight oil reservoirs. Crucially, the developed VES-B fracturing fluid system has demonstrated significant engineering success through its successful field application in multiple wells within a low-permeability shale gas block in the Sichuan Basin, China. For instance, the SW-1 well achieved a daily gas production of 1.5×10⁶ m³/d, a remarkable 18.7% increase compared to adjacent wells stimulated using conventional polymer slickwater systems. Collectively, these comprehensive laboratory findings and successful field applications highlight the substantial potential of nano-SiO2 materials for enhancing reservoir use in low-permeability oil and gas formations, thereby promoting the efficient development of shale gas resources.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":"30 11","pages":"7177-7191"},"PeriodicalIF":0.0,"publicationDate":"2025-09-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147920851","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Development and Evaluation of a Nano-SiO2-Enhanced Fluid Loss Additive for High-Temperature, High-Salinity Cementing Applications","authors":"Yuaojie Huang, Xu Wang, Hong Dai, Qin He, Mengdong Yao, Lei Tang, Yuanqiang Zhu","doi":"10.2118/230300-pa","DOIUrl":"https://doi.org/10.2118/230300-pa","url":null,"abstract":"Summary Deep well cementing often faces high temperatures and saline environments, which can degrade polymer-based fluid loss additives (FLAs) through hydrolysis, impacting the cement quality. We synthesized a novel polymer-based FLA by copolymerizing 2-acrylamido-2-methylpropanesulfonic acid (AMPS), itaconic acid (IA), and allyl-alcohol polyoxyethylene ether (APEG) with γ-methacryloyloxypropyltrimethoxysilane (KH570)-modified nano-SiO2 (KH570@SiO2) and named it AIAN. Thermal stability tests indicated the decomposition temperature of AIAN was 373°C. Filtration tests demonstrated that AIAN effectively controlled fluid loss. When AIAN was added to the oilwell cement (OWC) slurry at a mass fraction of 3% and a temperature of 180°C, the fluid loss volume measured according to American Petroleum Institute (API) standards reached only 42.4 mL. In 36% saturated brine, fluid loss in the OWC slurry with 3% AIAN was 52.5 mL. This FLA demonstrated outstanding tolerance to high-temperature and high-salinity conditions. Mechanistic studies, including zeta-potential measurement, X-ray diffraction (XRD), and scanning electron microscopy (SEM) examination, demonstrated that the introduction of KH570@SiO2 further enhanced the stability of the polymer FLA through structural pore blocking and denser filter-cake formation. Meanwhile, the strong adsorption and film-forming properties of AIAN still effectively promoted cement hydration, resulting in a denser paste structure. Thus, AIAN has excellent potential for high-temperature deep-well-cementing applications.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":"30 11","pages":"6812-6824"},"PeriodicalIF":0.0,"publicationDate":"2025-09-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147890980","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}