SPE Reservoir Evaluation & Engineering最新文献

{"title":"Benzimidazole Derivative and its Mixture as Novel Corrosion Inhibitors for Carbon Steel in High-Pressure Supercritical CO2 Environment","authors":"Jiang Yang, Xu Chen, Xilin Jia","doi":"10.2118/224323-ms","DOIUrl":"https://doi.org/10.2118/224323-ms","url":null,"abstract":"Abstract The carbon capture, utilization, and storage (CCUS) process plays a crucial role in reducing carbon dioxide (CO2) emissions. Additionally, CCUS-enhanced oil and gas recovery (CO2-EOR) is widely used. During CCUS process, CO2 exists in the downhole tubing as a supercritical (SC) fluid under high pressure. Severe corrosion occurs in the presence of water in supercritical CO2 environments. Corrosion inhibitors are among the most economical cost-effective methods for controlling corrosion. However, most conventional corrosion inhibitors are ineffective to control corrosion in high-pressure supercritical CO2 environments. In this study, the benzimidazole derivative 2-benzylthiobenzimidazole (BTBI) was investigated for its ability to inhibit the corrosion of carbon steel in high-pressure (10 MPa) supercritical CO2 at 60 °C. Additionally, the low molecular weight thiochemical compound 2-mercaptoacetic acid was studied to improve the inhibition efficiency. The corrosion inhibition mechanism and adsorption process were investigated by weight loss and electrochemical methods. The morphology and composition of the corrosion product films formed on the samples coupon surface after exposure to supercritical CO2 were characterized using scanning electron microscopy (SEM), energy dispersive X-ray spectroscopy (EDX), and X-ray photoelectron spectroscopy (XPS). The results showed that the combination of BTBI and 2-mercaptoacetic acid exhibited a synergistic effect, significantly enhancing the corrosion inhibition. The optimal performance was achieved at a 1:3 ratio of BTBI to 2-mercaptoacetic acid, forming a more protective film on carbon steel. This protective film effectively inhibited the migration of corrosive media, reducing both general and localized corrosion. This study showed the potential of this novel inhibitor for inhibiting corrosion in challenging high-pressure supercritical CO2 environments.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2025-04-02","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147895696","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"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 of Dilution-Resistant Gel for Deep-Source Water Control in Deep Fractured-Vuggy Reservoirs","authors":"Dongfang Lv, Guang Zhao, Yifei Liu, Caili Dai, Shuanghu Si, Zhe Li","doi":"10.2118/224241-ms","DOIUrl":"https://doi.org/10.2118/224241-ms","url":null,"abstract":"Abstract Fractured-vuggy reservoirs have the characteristics of large reservoir space and extreme heterogeneity, which can easily cause water channeling. The commonly used water channeling regulator is gel. However, a large amount of formation water in the water channel will dilute the gelling fluid injected into it, thus losing its gelling ability and leading to the failure of water plugging operation. Therefore, a concept has been introduced that employs a dilution-resistant interfacial membrane to isolate formation water, thus preventing the dilution of the gelling solution and ensuring successful gelation. A novel, dilution-resistant gel for deep-source water control in deep fractured-vuggy oil reservoirs has been developed. The gelation effect under simulated reservoir conditions was systematically evaluated, and its dilution resistance and strengthening mechanism were clarified. In the formulation of this gel, the salt-sensitive and dilution-resistant additive sodium alginate is incorporated, which can interact with calcium ions in the formation water to form an impermeable interfacial membrane. Based on the stability of interfacial membrane, the optimal concentration of sodium alginate utilized is determined to be 0.4%-0.6%. The rheological characteristics showed that sodium alginate could enhance the elasticity and viscosity of the gel by 60.17% and 24.52%. At 10 times the volume of water, the dilution-resistant gel has a good gelation effect. A systematic study focusing on the reinforcement mechanism of sodium alginate in the gel was conducted from multiple angles including interfacial rheology, microstructural morphology, and thermal stability. The elastic and viscous modulus of the interfacial membrane are stable at 5.99 Pa and 3.52 Pa in the amplitude of 0-100%. Relative to conventional gels, the dilution-resistant gel possesses a more intricate three-dimensional network structure, which aids in improving its water retention capabilities. The thermal stability of dilution-resistant gel before and after aging at high temperature and high salt (130°C, 220,000mg/L) increased by 3.9°C and 9.3°C. As a result, this dilution-resistant gel presents itself as a potential option for deep-source water control in complex deep fractured-vuggy oil reservoirs, providing an effective strategy to manage water production and enhance hydrocarbon recovery.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2025-04-02","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147915404","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Bio-Based Long Chain Gemini Surfactants for Unconventional Reservoirs","authors":"Japan Trivedi","doi":"10.2118/224317-ms","DOIUrl":"https://doi.org/10.2118/224317-ms","url":null,"abstract":"Abstract Surfactants in hydraulic fracturing face challenges like stability under elevated temperature, high salinity, and pH, shear resistance, and compatibility. They complicate waste treatment due to their persistence, potential environmental harm, and impact on water surface tension. While some surfactants degrade into harmless substances, they often slow down when adhering to soil or sand, potentially releasing heavy metals. Inexpensive fatty acid-based surfactants can mitigate these environmental and many operational issues. In this work, fatty acid based viscoelastic biosurfactant (BioSurfUA) is synthesized and tested for their properties for the use in unconventional reservoirs. A series of tests including thermal stability, interfacial tension, rheology, and surface tension were performed under reservoir brine and temperature conditions and compared against industry standards anionic and non-ionic surfactants, and surfactant-nanoparticle formulations. Stability in the presence of iron (iron chloride) was also performed. Moreover, BioSurfUA was also tested for oil recovery performance from tight cores and analyzed for wettability alteration agent, compared with various other surfactant-nanoparticle formulations. The produced BioSurfUA has unique advantages compared to the conventional surfactants as it demonstrated higher viscoelasticity along with ultra-low IFT at extremely low concentrations. At room temperature the shear viscosities of 0.1 wt% BioSurfUA in Tap water were measured as 850 cP, and 70 cP at the shear rate of 0.1s-1, and 100 s-1 respectively. At the higher shear rates, the domination of temperature, and salt seems negligible. In addition, it also showed great stability against a considerable amount of iron (Fe+3), and a range of alkaline pH even at the elevated temperature combinations. The diluted BioSurfUA solutions were able to stabilize the iron sulfide (FeS) in the dispersion form. BioSurfUA showed ultralow IFT (<0.01) oil and outperformed the recovery performance of conventional anionic and nonionic surfactants, and surfactant-nanoparticle formulation at low dosages, thereby offering significant cost savings. BioSurfUA, derived from sustainable and renewable sources, is more environmentally friendly and biodegradable compared to many synthetic surfactants. It addresses existing barriers to using synthetic surfactants, is relatively inexpensive to produce, and has a long shelf life. The BioSurfUA showed excellent interfacial properties, and brine and iron-tolerant behavior at low dosage.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2025-04-02","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147916475","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"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-Induced <i>In-Situ</i> Rapid Mineralization in Fractures to Remedy CO2 Leakage for Safe Carbon Geo-Sequestration","authors":"Bing Wei, Zhibo Zhang, Runxue Mao, Qi-Hang Ye, Yiwen Wang, Jun Lu, Qinhao Yin","doi":"10.2118/224267-ms","DOIUrl":"https://doi.org/10.2118/224267-ms","url":null,"abstract":"Abstract Carbon Capture, Utilization, and Storage (CCUS) is a promising strategy to mitigate global climate change. However, the risk of CO2 leakage poses a significant challenge, as conventional sealing materials frequently fail to ensure long-term stability. Therefore, there is an urgent need to explore new sealing technologies to improve the security of geo-sequestration. Inspired by carbon mineralization sequestration in basalts, we propose an innovative method that utilizes in-situ mineralization reactions to remedy leakage pathways. This involves injecting a system containing reactive minerals into fractures, where CO2 leakage triggers mineralization reactions, generating carbonates with cementing properties, thereby effectively preventing and controlling CO2 leakage. Static experiments were conducted in high-temperature and high-pressure reactors to investigate the reaction characteristics of five silicate minerals with CO2. Wollastonite exhibited the best cementation effect and the highest degree of reaction. To evaluate the feasibility of this approach, the sealing performance of the method was evaluated by comparing the permeability of shale cores with simulated fractures before and after reactive system injection. Results showed a significant reduction in gas permeability, with further decreases observed as the reaction progressed. Microscopic techniques, including XRD and SEM, were employed to elucidate the sealing mechanism. XRD spectra showed a mineral phase transformation from silicate minerals to carbonate minerals, while SEM images revealed the accumulation and growth of cubic calcite and rod-shaped aragonite on the rock and fracture walls. These findings confirm that the proposed method effectively seals leakage pathways by promoting the formation of carbonate minerals, which consolidate the fracture surfaces and reduce permeability. This study demonstrates the potential of in-situ mineralization as a reliable and efficient technique for mitigating CO2 leakage in geo-sequestration.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2025-04-02","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"147885568","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"The Role of Diffusion on Reservoir Performance in Underground Hydrogen Storage","authors":"Vladislav Arekhov, Torsten Clemens, Jonas Wegner, Mohamed Abdelmoula, Taoufik Manai","doi":"10.2118/214435-pa","DOIUrl":"https://doi.org/10.2118/214435-pa","url":null,"abstract":"Summary Underground hydrogen storage (UHS) has the potential to balance fluctuating sustainable energy generation and energy demand by offering large-scale seasonal energy storage. Depleted natural gas fields or underground gas storage fields are attractive for UHS as they might allow for cost-efficient hydrogen storage. The amount of cushion gas required and the purity of the backproduced hydrogen are important cost factors in UHS. This study focuses on the role of molecular diffusion within the reservoir during UHS. Although previous research has investigated various topics of UHS such as microbial activity, UHS operations, and gas mixing, the effects of diffusion within the reservoir have not been studied in detail. To evaluate the composition of the gas produced during UHS, numerical simulation was used here. The hydrogen recovery factor and methane-to-hydrogen production ratio for cases with and without diffusive mass flux were compared. A sensitivity analysis was carried out to identify important factors for UHS, including permeability contrast, vertical-to-horizontal permeability ratio, reservoir heterogeneity, binary diffusion coefficient, and pressure-dependent diffusion. Additionally, the effect of numerical dispersion on the results was evaluated. The simulations demonstrate that diffusion plays an important role in hydrogen storage in depleted gas reservoirs or underground gas storage fields. Ignoring molecular diffusion can lead to the overestimation of the hydrogen recovery factor by up to 9% during the first production cycle and underestimation of the onset of methane contamination by half of the back production cycle. For UHS operations, both the composition and amount of hydrogen are important to design facilities and determine the economics of UHS, and hence diffusion should be evaluated in UHS simulation studies.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"20 3","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-11-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"135340406","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Experimental Measurements and Molecular Simulation of Carbon Dioxide Adsorption on Carbon Surface","authors":"Ibrahim Gomaa, Javier Guerrero, Zoya Heidari, D. Nicolas Espinoza","doi":"10.2118/210264-pa","DOIUrl":"https://doi.org/10.2118/210264-pa","url":null,"abstract":"Summary Geological sequestration of carbon dioxide (CO2) in depleted gas reservoirs represents a cost-effective solution to mitigate global carbon emissions. The surface chemistry of the reservoir rock, pressure, temperature, and moisture content are critical factors that determine the CO2 adsorption capacity and storage mechanisms. Shale-gas reservoirs are good candidates for this application. However, the interactions between CO2 and organic content still need further investigation. The objectives of this paper are to (i) experimentally evaluate the adsorption isotherm of CO2 on activated carbon, (ii) quantify the nanoscale interfacial interactions between CO2 and the activated carbon surface using Monte Carlo (MC) and molecular dynamic (MD) simulations, (iii) evaluate the modeling reliability using experimental measurements, and (iv) quantify the influence of temperature and geochemistry on the adsorption behavior of CO2 on the surface of activated carbon. These objectives aim at obtaining a better understanding of the behavior of CO2 injection and storage in the kerogen structure of shale-gas formations, where activated carbon is used as a proxy for thermally mature kerogen. We performed experimental measurements, grand canonical Monte Carlo (GCMC) simulations, and MD simulations of CO2 adsorption and diffusion on activated carbon. The experimental work involved measurements of the high-pressure adsorption capacity of activated carbon using pure CO2 gas at a temperature of 300 K. The simulation work started with modeling and validating an activated carbon structure by calibrating the GCMC simulations with experimental CO2 adsorption measurements. Then, we extended the simulation work to quantify the adsorption isotherms at a temperature range of 250–500 K and various surface chemistry conditions. Moreover, CO2 self-diffusion coefficients were quantified at gas pressures of 0.5 MPa, 1 MPa, and 2 MPa using MD simulations. The experimental results showed a typical CO2 excess adsorption trend for the nanoporous structures, with a density of the sorbed gas phase of 504.76 kg/m3. The simulation results were in agreement with experimental adsorption isotherms with a 10.6% average absolute relative difference. The self-diffusion results showed a decrease in gas diffusion with increasing pressure due to the increase in the adsorbed gas amount. Increasing the simulation temperature from 300 K to 400 K led to a decrease in the amount of adsorbed CO2 molecules by about 87% at 2 MPa pressure. Finally, the presence of charged functional groups (e.g., hydroxyl–OH and carboxyl–COOH) led to an increase in the adsorption of CO2 gas to the activated carbon surface. The outcomes of this paper provide new insights about the parameters affecting CO2 adsorption and sequestration in depleted shale-gas reservoirs. This in turn helps in screening the candidate shale-gas reservoirs for carbon capture, sequestration, and storage to maximize the CO2 storage capacity.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"25 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-09-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"135385325","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Measurement of Effective Hydrogen-Methane Gas Diffusion Coefficients in Reservoir Rocks","authors":"Vladislav Arekhov, Timur Zhainakov, Torsten Clemens, Jonas Wegner","doi":"10.2118/214451-pa","DOIUrl":"https://doi.org/10.2118/214451-pa","url":null,"abstract":"Summary If hydrogen is stored in depleted gas fields, the remaining hydrocarbon gas can be used as cushion gas. The composition of the backproduced gas depends on the magnitude of mixing between the hydrocarbon gas and the hydrogen injected. One important parameter that contributes to this process of mixing is molecular diffusion. Although diffusion models are incorporated in the latest commercial reservoir simulators, effective diffusion coefficients for specific rock types, pressures, temperatures, and gas compositions are not available in the literature. Thus, laboratory measurements were performed to improve storage performance predictions for an underground hydrogen storage (UHS) project in Austria. An experimental setup was developed that enables measurements of effective multicomponent gas diffusion coefficients. Gas concentrations are detected using infrared light spectroscopy, which eliminates the necessity of gas sampling. To test the accuracy of the apparatus, binary diffusion coefficients were determined using different gases and at multiple pressures and temperatures. Effective diffusion coefficients were then determined for different rock types. Experiments were performed multiple times for quality control and to test reproducibility. The measured binary diffusion coefficients without porous media show a very good agreement with the published literature data and available correlations based on the kinetic gas theory (Chapman-Enskog, Fuller-Schettler-Giddings). Measurements of effective diffusion coefficients were performed for three different rock types that represent various facies in a UHS project in Austria. A correlation between static rock properties and effective diffusion coefficients was established and used as input to improve the numerical model of the UHS. This input is crucial for the simulation of backproduced gas composition and properties which are essential parameters for storage economics. In addition, the results show the impact of pressure on effective diffusion coefficients, which impacts UHS performance.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"53 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-09-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"136015182","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Flow-Through Experiments of Reactive Ba-Sr-Mg Brines in Mons Chalk at North Sea Reservoir Temperature at Different Injection Rates","authors":"Pål Østebø Andersen, Sander Sunde Herlofsen, Reidar Inge Korsnes, Mona Wetrhus Minde","doi":"10.2118/214367-pa","DOIUrl":"https://doi.org/10.2118/214367-pa","url":null,"abstract":"Summary North Sea Chalk reservoirs in Norway are potential candidates for enhanced hydrocarbon recovery by modifying the injected brine composition. This work investigates how barium (Ba), strontium (Sr), and magnesium (Mg) brines interact when injected into chalk. Ba and Sr are often associated with mineral precipitation and occur in formation water, while Mg is present in seawater, commonly injected in chalk. Relatively clean (&amp;gt;99% calcite) outcrop chalk cores from Mons, Belgium, were flooded at 130°C in triaxial cells with four brines containing 0.12 mol/L divalent cations, either 0.06 mol/L Sr and Ba, 0.06 mol/L Sr and Mg, or 0.12 mol/L Ba or Sr. Each brine was injected in a separate core, with 100–150 pore volumes (PV). The injection rate varied between 0.5 and 8 PV/D. Produced brine was analyzed continuously and compared with the injected composition. After flooding, the cores flooded with only Ba or only Sr were cut into slices and analyzed locally in terms of scanning electron microscopy (SEM), matrix density, specific surface area (SSA), and X-ray diffraction (XRD). In all experiments, the produced divalent cation concentration was reduced compared with the injected value. The total reduction of injected cation concentration closely equaled the produced Ca concentration (from calcite dissolution). When flooding 0.12 mol/L Sr, the Sr concentration depleted 55%, while when flooding 0.12 mol/L Ba, 15% Ba depleted. When injecting equal concentrations of Ba and Sr, 40% Sr and 7% Ba depleted, while with equal concentrations of Mg and Sr injected, ~50% Sr was retained and almost no Mg depleted. Sr appeared to dominate and suppress other reactions. There was less sensitivity in steady-state concentrations with variation in injection rate. The similar modification of the brine regardless of residence time suggests the reactions reached equilibrium. Cutting the cores revealed a visually clear front a few centimeters from the inlet. The material past the front was indistinguishable from unflooded chalk in terms of density, SSA, microscale structure, porosity, and composition [XRD and SEM-energy-dispersive spectroscopy (EDS)]. The material near the inlet was clearly altered. Images, XRD, SEM-EDS, and geochemical simulations indicated that BaCO3 and SrCO3 formed during BaCl2 and SrCl2 flooding, respectively. Geochemical simulations also predicted an equal exchange of cations to occur. The matrix densities, porosities, and the distance traveled by the front corresponded with these minerals and suggested that the chalk was completely converted to these minerals behind the front. It was demonstrated that Ba, Sr, and Mg brines and their mixtures can be highly reactive in chalk without clogging the core, even after 100 + PV. This is because the precipitation of minerals bearing these ions is associated with simultaneous dissolution of calcite. The Ca-, Ba-, and Sr-mineral reactions are effectively in equilibrium. Previous investigations with MgCl2 ","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"11 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-08-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"135033693","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Genesis, Distribution, and Characterization of a Paleokarst Subsurface River System in the Tahe Area, Tarim Basin, Western China","authors":"Xinrui Lyu, B. Ju, Xingwei Wu, Fengying Xiao","doi":"10.2118/217450-pa","DOIUrl":"https://doi.org/10.2118/217450-pa","url":null,"abstract":"\u0000 Subsurface river systems constitute one of three major paleokarst types that make up Ordovician reservoirs in the Tahe area of the Tarim Basin. The total length of the river system is approximately 400 km, and the reserves associated with this karst type are more than 200 million tons. However, it is manifested that 47% of drilled wells have not encountered river paleokarst, while 50% of wells that have encountered river paleokarst are fully filled due to the poor understanding of the paleokarst of this region, resulting in a significant variation of production capacities. In this study, we propose a detailed data integration approach with outcrops, drilling, logging, seismic profiles, and dynamic data to delineate the complex paleokarst river system in the Tahe area. The karst geological theory with reservoir characterization is combined in particular. The workflow of clarifying the main controlling factors, architecture types, and development distribution modes of the subsurface river system is established. Fill material type, sequence of fill structure, and fill controlling factors are also revealed. A quantitative characterization method of the subsurface rivers is established adopting predictions based on seismic data and high-resolution geostatistical and geological modeling. The Ordovician reservoirs in the Tahe area comprise three paleokarst river systems with different characteristics. Karst paleogeomorphology is the main control over the overall flow direction and plane distribution of the subsurface rivers. Changes in the surface of the phreatic zone are crucial in controlling the vertical layers and scale of the rivers. The combined action of faults plays a decisive role in controlling the anastomosing pattern of the rivers. Single-branch channels, reticulated channels, and structural corridors in single-layer or multilayer styles are the main subsurface river types. Trunk channels, branch channels, hall caves, and inlets/outlets are dominant structures in the architecture of the river system. Sand-mud, breccia, and chemically precipitated materials are the most common fill types. Three typical sequences of fill structure and four spatial combination modes exist in the subsurface river system. The morphology and fill characteristics of rivers are predictable using seismic attributes, such as frequency division energy, frequency division inversion, and coherent energy gradient. 3D models are constructed by multivariate control multipoint geostatistical method, which can characterize the strong heterogeneity characteristics of subsurface river systems. This complex paleokarst system enables remarkable results for the adjustment of the reservoir development plan through quantitative characterization.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"19 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2023-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84844492","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Evaluation of Effects of Waterflooding-Induced Bilayer Fractures on Tight Reservoir Using Pressure-Transient Analysis Method","authors":"Zhipeng Wang, Z. Ning, J. Zhan, Wen-ming Guo","doi":"10.2118/217442-pa","DOIUrl":"https://doi.org/10.2118/217442-pa","url":null,"abstract":"\u0000 Waterflooding will open natural fractures to form induced fractures, which differ from hydraulic fractures because the hydraulic fracture is filled with proppant but the induced fracture is not. Natural fractures are connected by waterflooding. However, because the waterflooding pressure is limited, induced fractures cannot run through the entire reservoir but instead form multiple parallel induced-fracture bands in the vertical direction. Currently, using conventional finite-conductivity methods to match field data will obtain unreasonable results, especially the half-length, conductivity of fracture, and reservoir permeability, which lead to the water breakthrough, which cannot be found in time. This paper presents the waterflooding-induced bilayer fracture (WIBF) model, considering induced-fracture dynamic closure (IDC), dynamic induced-fracture storage (DIS), and induced-fracture radial flow (IRF) effects. Two innovative flow regimes are interpreted, which are dynamic induced-fracture flow and early radial flow regimes. Five innovation parameters are introduced into the WIBF model to describe the IDC, DIS, and IRF effects. The WIBF model is calculated and solved by the Green equation and Newman product methods. Induced-fracture storage coefficient and half-length closure equations are derived to characterize the unique induced-fracture properties. Analytical and numerical methods verify the model’s accuracy. The WIBF model matches a type field case to prove its practicability. Results show that compared with the conventional finite-conductivity model, the proposed model matches the field case well and the interpreted parameters are consistent with the water injection profile and actual field data. The pressure derivative curve shows an early horizontal line, identified as a pressure response of bilayer-induced fractures. If the flow regime is misidentified as pseudoradial flow, some obtained parameters will be absurd, and permeability will be amplified many times. In conclusion, physical and mathematical models are established to describe induced fracture. Induced-fracture storage coefficient and half-length equations are derived. Model matching and equation calculation methods are mutually validated to improve the accuracy of the obtained parameters. Dynamic induced-fracture half-length is interpreted quantitatively to make the engineer take action before the water breakthrough. The model in this paper also provides some parameters for infilling well patterns or determining well spacing economically.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"28 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2023-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84215750","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}