SPE Reservoir Evaluation & Engineering最新文献

{"title":"Long-Term Microbial DNA-Based Monitoring of the Mature Sarukawa Oil Field in Japan","authors":"H. Kobayashi, A. Goto, X. Feng, K. Uruma, Y. Momoi, S. Watanabe, K. Sato, Y. Zhang, R. Horne, T. Shibuya, Y. Okano","doi":"10.2118/214313-pa","DOIUrl":"https://doi.org/10.2118/214313-pa","url":null,"abstract":"\u0000 Microbial DNA-based monitoring is a promising tool for reservoir monitoring that has been used mainly for shale reservoir development. In this study, long-term microbial DNA-based monitoring was applied to the Sarukawa oil field, which has a complex reservoir structure with no practical simulation model available. Fluid samples were collected periodically from nine production wells and two injection wells from October 2019 to July 2021. DNA was extracted from the samples, and the microbial composition was analyzed by 16S ribosomal ribonucleic acid (rRNA) gene amplicon sequencing and real-time polymerase chain reaction (PCR). Based on similarities between the microbial profiles, the samples were classified into seven clusters that corresponded closely to the original fluid type (i.e., injection or production fluid) and specific environment (e.g., geological strata or compartments). A comparative analysis of the microbial profiles suggested possible well connectivity and water breakthrough. These results demonstrate that microbial DNA-based monitoring can provide useful information for optimizing production processes (e.g., waterflooding) in mature oil fields.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"7 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2023-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84967381","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":"Lithofacies and Diagenetic Controls on Tight Silty and Sandy Upper Triassic Reservoirs of the Heshui Oil Field (Ordos Basin, North China)","authors":"Chen-xia Hu, C. Han, Jijun Tian, Zhiqiang Fu, Jinghui Ma, T. Algeo","doi":"10.2118/214289-pa","DOIUrl":"https://doi.org/10.2118/214289-pa","url":null,"abstract":"Tight oil, present in reservoirs of low porosity and permeability, can be regarded as a kind of unconventional resource. The tightening process in this kind of reservoir is controlled by the lithology and diagenetic history of the host formation. Upper Triassic Yanchang Formation siltstones and sandstones are the main reservoirs for hydrocarbon accumulation in the Heshui Oil Field (HOF), southwestern Ordos Basin. The reservoirs exhibit low porosity, low permeability, and strong heterogeneity. In recent years, numerous drillcores have been recovered from these units, but the porosity-permeability characteristics and burial history of these silty and sandy reservoirs have not yet been reported in detail. In this study, an integrated analysis of the lithofacies, diagenesis, and reservoir characteristics of the siltstones and sandstones was achieved using a combination of core and thin section, grain size, scanning electron microscopy (SEM), X-ray diffraction (XRD), δ13C and δ18O, mercury intrusion capillary pressure (MICP), and porosity and permeability data. Our primary goals were to quantify the porosity-permeability characteristics of these silty and sandy reservoirs, restore their diagenetic histories, and examine the paragenetic relationship of reservoir tightness to hydrocarbon accumulation. The silty and sandy reservoirs represent braided river delta facies consisting of compositionally and texturally immature sediments. In the burial environment, they underwent complex diagenetic processes that reduced porosity from an initial average of ~38% to the present ~8%. Porosity-destructive processes included compaction (~ –12.5%) and cementation (~ –21%), with increases in porosity related to grain dissolution (~ +2.2%) and tectonic fractures (~ +1.1%). The reservoirs underwent four diagenetic stages: (1) Penesyngenetic and Eogenetic A Stage (Late Triassic-Early Jurassic); (2) Eogenetic B Stage (Late Jurassic); (3) Early Mesogenetic A Stage (Early Cretaceous); and (4) Late Mesogenetic A Stage (Late Cretaceous to recent). Hydrocarbon charging of these reservoirs occurred in three pulses. Existing pore space was partly filled by hydrocarbons during the Eogenetic B Stage. A second hydrocarbon charging event occurred during the Early Mesogenetic A Stage, when residual primary intergranular pores and secondary dissolution pores were filled. A third hydrocarbon charging event occurred during the Late Mesogenetic A Stage, when the reservoirs were tight. Siltstone beds deposited in delta front environments are the main future exploration targets in the Chang 6 to 8 members. The results of this study provide a useful reference framework for future exploration of hydrocarbon resources in the Upper Triassic Yanchang Formation of the HOF, as well as potential insights into the evolution of similarly tight reservoirs in other basins.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"46 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2023-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76045004","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":"A Comprehensive Review on the Capillary Desaturation Curves for Sandstone and Carbonate Reservoirs","authors":"Amaar Siyal, Khurshed Rahimov, W. Alameri, E. Al-Shalabi, Shehzad Ahmed","doi":"10.2118/207595-pa","DOIUrl":"https://doi.org/10.2118/207595-pa","url":null,"abstract":"\u0000 Various enhanced oil recovery (EOR) methods are applied after primary and secondary recovery stages to target remaining oil saturation (ROS). This remaining oil is divided into bypassed oil and capillary-trapped residual oil. Mobilizing the residual oil in the reservoir is usually achieved when viscous or gravity forces exceed capillary forces. The recovery of the microscopically trapped residual oil is mainly studied using capillary desaturation curve (CDC). To optimize the design of various EOR methods in carbonate and sandstone reservoirs, a fundamental understanding of CDC is needed. A thorough and well-documented research study has been performed for determining the residual oil and generating CDC in sandstone rocks. However, a very limited amount of work has been reported on carbonate rocks. Thus, the main objective of this paper is to provide the recent development made over the last few decades on the CDC studies for carbonate and sandstone reservoirs. Different CDC studies were discussed based on the trapping/bond/capillary number and were critically analyzed. Furthermore, the effects of different controlling factors—wettability, permeability, interfacial tension (IFT), and heterogeneity—on CDC were investigated.\u0000 This review analysis indicates that CDC in carbonate rocks is broader as opposed to sandstone rocks. This is because of the presence of micropores, large pore size distribution, complex geological characteristics, chemical reactivity, mixed-to-oil-wet characteristics, and heterogeneity of carbonate rocks. Moreover, the critical capillary number for water injection in carbonate rocks reported in the literature lies between 10–8 and 10–5. On the other hand, for sandstone rocks, the number ranges between 10–5 and 10–2. Furthermore, a major influence of wettability on the shape of the CDC was observed. The CDC shape is broader for oil-wet rocks, and capillary number values are higher compared to water-wet and mixed-wet rocks. On the other hand, the lowest capillary number values are observed in water-wet rocks. The outcome of this research study will provide a way forward for CDC studies in both sandstone and carbonate rocks. Additionally, it will serve as a baseline for understanding various CDCs and hence better screening of various EOR methods for different types of reservoir rocks.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"40 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2023-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79019423","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":"Carbonated Water Injection Effects on Lacustrine Carbonates of Mupe Member, Lower Purbeck Group (Upper Jurassic), United Kingdom","authors":"Isabela D. de Albuquerque, S. L. B. Bermúdez, G. C. Stael, C. Rabe, C. Harper","doi":"10.2118/214304-pa","DOIUrl":"https://doi.org/10.2118/214304-pa","url":null,"abstract":"\u0000 This paper describes the study of dissolution and mineralogical alteration caused by saline carbonated water injection (CWI) and its effects on the petrophysical properties (porosity and permeability) of limestone samples from the Mupe Member, composed of lacustrine microbialites from the Upper Jurassic, part of the Purbeck Group lower portion. These limestones are a partial analog of the Brazilian presalt Aptian carbonates, the most important oil reservoir in Brazil. These reservoirs present large amounts of CO2 that are reinjected into the formation, which given the high reactivity of carbonate rocks in the presence of carbonic acid generated by the reaction between CO2 and water, can cause damage to the rock’s pore space. To achieve the proposed objectives, four laminated/massive samples with very low permeability (<5 md) and two vuggy/microbial samples with very high permeability (>1,700 md) underwent laboratory tests carried out before, during, and after CWI, including gas porosity and permeability measurement, nuclear magnetic resonance (NMR), microcomputed tomography (micro-CT), and ion chromatography. X-ray diffraction (XRD) analysis and petrographic thin-section observations were also performed. The experimental results showed that samples with high permeability showed a small decrease in permeability, possibly indicating formation damage, while low-permeability samples presented a significant increase in permeability with little change in porosity, indicating feasibility for carbon capture and storage (CCS) in similar samples in likewise experimental conditions (20°C and 500 psi). For samples with more pore volumes injected, the pressure stabilization seems to have favored dissolution in the later injection stages, indicated by the highest output of calcium ions. In all samples occurred salt precipitation during injection, especially in the more heterogeneous rocks, presenting a possible issue.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"69 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2023-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83124711","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":"Polysulphate: A New Enhanced Oil Recovery Additive to Maximize the Oil Recovery From Carbonate Reservoirs at High Temperature","authors":"M. Khan, I. D. Piñerez Torrijos, S. Aldeen, T. Puntervold, S. Strand","doi":"10.2118/211443-pa","DOIUrl":"https://doi.org/10.2118/211443-pa","url":null,"abstract":"\u0000 Seawater (SW) injection is an enhanced oil recovery (EOR) success in the North Sea carbonate reservoirs due to wettability alteration toward a more water-wet state. This process is triggered by the difference in composition between injection and formation water (FW). “Smartwater” with optimized ionic composition can easily be made under laboratory conditions to improve oil recovery beyond that of SW. However, in the field, its preparation may require specific water treatment processes, e.g., desalination, nanofiltration, or addition of specific salts. In this work, a naturally occurring salt called Polysulphate (PS) is investigated as an additive to produce smartwater.\u0000 Outcrop chalk from Stevns Klint (SK), consisting of 98% biogenic CaCO3, was used to investigate the potential and efficiency of the PS brines to alter wettability in chalk. The solubility of PS in SW and deionized water, and brine stability at high temperatures were measured. Energy dispersive X-ray and ion chromatography were used to determine the composition of the PS salt and EOR solutions, and to evaluate the sulphate adsorption on the chalk surface, a catalyst for the wettability alteration process. Spontaneous imbibition (SI), for evaluating wettability alteration of PS brines into mixed-wet chalk was performed at 90 and 110°C and compared against the recovery performance of FW and SW.\u0000 The solubility tests showed that the salt was easily soluble in both deionized water and SW with less than 5% solid residue. The deionized PS brine contained sulphate and calcium ion concentrations of 31.5 and 15.2 mM, respectively, and total salinity was 4.9 g/L. This brine composition is very promising for triggering wettability alteration in chalk. The SW PS brine contained 29.6 mM calcium ions and 55.9 mM sulphate ions, and a total salinity of 38.1 g/L. Compared with ordinary SW, this brine has the potential for improved wettability alteration in chalk due to increased sulphate content.\u0000 Ion chromatography revealed that the sulphate adsorbed when PS brines were flooded through the core, which is an indication that wettability alteration can take place during brine injection. The reactivity was also enhanced by increasing the temperature from 25 to 90°C. Finally, the oil recovery tests by SI showed that PS brines were capable of inducing wettability alteration, improving oil recovery beyond that obtained by FW imbibition. The difference in oil recovery between ordinary SW and SW PS imbibition was smaller due to the already favorable composition of SW.\u0000 PS brines showed a significant potential for wettability alteration in carbonates and are validated as a potential EOR additive for easy and on-site preparation of smartwater brines for carbonate oil reservoirs. PS salt, added to the EOR solution, provides the essential ions for the wettability alteration process, but further optimization is needed to characterize the optimal mixing ratios, ion compositions, and temperature ranges at which","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"51 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2022-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83295189","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":"Improvement to Gravity Drainage Recovery by Repressurization as a Criterion to Screen and Rank Naturally Fractured Reservoirs for Gas Injection","authors":"N. Alimohammadi, M. Pooladi-Darvish, B. Rostami, M. Khosravi","doi":"10.2118/212302-pa","DOIUrl":"https://doi.org/10.2118/212302-pa","url":null,"abstract":"\u0000 Many of the naturally fractured carbonate reservoirs of the Middle East exhibit low natural-depletion recoveries. The reason is that most of their oil reserves are stored in the low-permeability host rocks and are left behind by the fast advancing gas/oil contact (GOC) and water/oil contact (WOC) in fractures. Producing the remaining oil in the large gas-invaded zone of these reservoirs has been a crucial reservoir management issue. We show in this study using experimental observations, analytical calculations, and numerical investigations that repressurizing naturally fractured reservoirs (NFRs) by crestal immiscible gas injection has the potential to produce a large portion of this remaining oil by improving gravity drainage (GD) through two main mechanisms. One is that at higher pressures, the gas-oil interfacial tension (IFT) and hence the capillary forces that control recovery by GD are lessened, allowing additional recovery. This mechanism is aided by the other one, which is swelling of the oil at higher pressures. In this way, repressurization is thought to be not only a means for pressure maintenance but also a methodology for enhanced-oil recovery (EOR). This is confirmed by both laboratory studies and field performance of large-scale gas injection projects. Despite the desire for implementation of projects of repressurization, gas availability and cost of these projects are important concerns, requiring a cost-benefit analysis.\u0000 Screening and ranking methodologies have been previously presented for some EOR techniques but not for repressurization by gas in NFRs. Evaluating the performance of gas injection in NFRs is often done using methodologies such as numerical simulations, which are in-depth, costly, and tedious. The methodology developed here is simple, requiring spreadsheet calculations. To develop the methodology, we first obtain simple relations to calculate additional GD recovery by considering the interplay of capillary and gravity forces in a matrix block subjected to pressurization by equilibrium gas injection and then use experimental data from literature to show that these relations can predict primary and secondary GD recoveries to a good approximation. We also show by mechanistic studies using a history-matched numerical model that IFT reduction and oil swelling are the main mechanisms contributing to additional oil recovery. Then, we propose a methodology to screen and rank candidate NFRs for gas injection that uses commonly available reservoir data and is based upon two criteria, these being additional oil recovered from a matrix block by pressurization and required volume of gas to produce an additional barrel of oil. We then implement this methodology to more than 20 Iranian NFRs and identify six reservoirs with potential for additional recovery of more than 20%. By quantifying and including the uncertainties associated with the reservoir data, we illustrate that for the reservoirs under study, capillary pressure p","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"89 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2022-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85951856","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":"Performance Evaluation of Nanocellulose-Engineered Robust Preformed Particle Gel upon Extrusion Through 1 to 1.5 mm Bead-Packed Porous Media","authors":"B. Wei, Runxue Mao, Qintao Tian, Wenhai Lei, Jun Lu, Jinyu Tang","doi":"10.2118/210259-pa","DOIUrl":"https://doi.org/10.2118/210259-pa","url":null,"abstract":"\u0000 Preformed particle gel (PPG) holds promising potential for conformance control in fractured tight reservoirs as it enables mitigation of fracture channeling with insignificant leak off to matrix. However, conventional PPG is very susceptible to shrinkage, breakage, fatigue, and even degradation when extruding through narrow fractures due to its weak and brittle network. This hampers its development and application in the oilfields. This paper presents a comprehensive laboratory evaluation of a new kind of nanocellulose (NCF)-engineered robust particle gel (N-PPG) for this application. The results demonstrated that the presence of NCF noticeably improved the mechanical properties of N-PPG. The swelling kinetics and swelling ratio (SR) of N-PPG were almost independent of salinity. We packed porous media using millimeter-sized glass beads to replicate proppant-filled fractures after hydraulic fracturing. As anticipated, N-PPG exhibited a greater resistance factor (Fr) and residual resistance factor (Frr), and its plugging efficiency reached more than 99.3%. N-PPG was hardly broken even after extruding from pore-throat geometries with Dg/Dp up to 21.4, whereas the control PPG was notably ruptured at Dg/Dp = 14.7. Herein, this tough N-PPG could provide a solution to conformance control of fractured tight reservoirs.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"12 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2022-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82095180","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":"Azimuthal Investigation of a Fractured Carbonate Reservoir","authors":"F. Bouchaala, A. Mohamed, M. S. Jouini, Y. Bouzidi, M. Y. Ali","doi":"10.2118/212873-pa","DOIUrl":"https://doi.org/10.2118/212873-pa","url":null,"abstract":"\u0000 Oil production and enhanced oil recovery in carbonate reservoirs in Abu Dhabi, UAE, are largely affected by fracture systems that control the fluid path and the permeability of reservoirs. Most fracture properties, such as fracture orientations and density, are obtained by interpreting petrophysical data acquired at the wellbores, whereas fracture properties between wells are typically derived from nonzero offset seismic data. However, deriving fracture properties from seismic data is challenging, as it requires a robust methodology and a careful seismic processing procedure. In the current case study, we used the azimuthal amplitude vs. offset (AVAz) method on 3D seismic data acquired in onshore Abu Dhabi, to generate maps of fracture orientation and density in a carbonate reservoir. A sophisticated processing series was carefully performed to increase signal-to-noise ratio (SNR) and preserve seismic amplitudes. The main parameters controlling the AVAz method were investigated and optimized before being applied to the 3D seismic data. The reservoir has a high fracture density in the lower regions, but a low fracture density in the upper parts, indicating a weaker anisotropy. The resulting dominant fracture directions span from north-northwest/south-southwest to north-northeast/south-southwest, as well as from northwest/southeast to east/west, which is consistent with the primary fracture orientations determined from the interpretation of fullbore formation microimager (FMI) data acquired at well locations. These fracture systems are the result of the Late Cretaceous obduction of the Semail ophiolite, which was oriented east/west and northeast/southwest, followed by the south/north to southwest/northeast trending Late Oligocene-Miocene continent-continent collision of the Arabian and Central Iran plates along the Zagros orogenic front.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"102 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2022-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75737662","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":"Modeling Water Injectivity Tests under Multiple Rate Schedule: An Approximate Solution","authors":"J. L. F. B. Neto, S. Pesco, A. B. Barreto Jr","doi":"10.2118/212867-pa","DOIUrl":"https://doi.org/10.2118/212867-pa","url":null,"abstract":"\u0000 An injectivity test consists of continuously injecting a phase (water or gas) into an oil-saturated reservoir during a period. According to the analysis of the wellbore pressure behavior, this procedure estimates reservoir parameters, such as permeability and skin factor, and the volume of recoverable oil. In this context, this study proposes an approximate analytical solution for the pressure behavior during a water injectivity test on a multilayer reservoir considering multiple injection flow rates. The accuracy of the proposed solution was evaluated through comparison with a commercial finite-difference-based flow simulator in different scenarios. The results indicate a considerable agreement between the data provided by the numerical simulator and the proposed model. In addition, we successfully estimated the equivalent reservoir permeability using the proposed model with satisfactory results.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"50 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2022-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82712601","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":"Lessons Learned from a Prematurely Ended High-Pressure Air Injection Test in a Light Oil Naturally Fractured Reservoir","authors":"Jose Antonio Gonzalez Guevara, Silvia Maria Chavez Morales, Thalia Iveth Hernandez Hernandez, Heron Gachuz-Muro, Bruno A. Lopez Jimenez","doi":"10.2118/212856-pa","DOIUrl":"https://doi.org/10.2118/212856-pa","url":null,"abstract":"\u0000 Sixty billion barrels of oil still reside in the matrix of mature onshore and offshore Mexican reservoirs located in the southeast basins after primary and secondary recovery. Capillary and viscous forces are responsible for this amount of oil retained within the pore structure of the matrix (immobile oil). Gravitational forces are not enough to counterattack these forces due to the high fracturing intensity. On the other hand, laboratory testing demonstrates that oil residing in the matrix could be mobilized by the exothermic reaction that takes place with air injection.\u0000 Air injection in homogeneous heavy and light oil sandstones and nonfractured limestones, at small or large scales during short and long periods of time, is feasible for producing resources technically and economically nonrecoverable by other means. However, to the best of our knowledge, the published literature does not report any application of an air injection project in naturally fractured reservoirs.\u0000 During 2015, an air injection pilot test was performed in a light oil naturally fractured reservoir in Mexico, referred to as “A” field. The implementation of the pilot test was preceded by its corresponding laboratory study, which consisted of five accelerating rate calorimeter (ARC) tests and two combustion tube (CT) experiments. The analysis of the aforementioned experimental work led us to corroborate that air and oil react at reservoir conditions. Based on the above finding, the pilot test was conducted by injecting air at a rate of 10 MMscf/D with a wellhead pressure of 4,500 psia for 1.5 years, which was followed by a 1.5-year production period giving a total of 3 years for the pilot test.\u0000 The results indicate that combustion was successfully applied in the reservoir. However, no oil was produced. This paper discusses the results of a prematurely ended air injection pilot test in “A” field and the main lessons learned from it, which could help in the design and its subsequent implementation in other naturally fractured reservoirs.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"113 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2022-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79736980","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}