SPE Production & Operations最新文献

{"title":"Multiphase Flowmeter Health Monitoring Strategy: Maximizing the Value of Real-Time Sensors and Automation for Industrial Revolution 4.0","authors":"Mohammad S. Al-Kadem, Mohammed Gomaa, Karam Al Yateem, Abdulmonam Al Maghlouth","doi":"10.2118/206281-pa","DOIUrl":"https://doi.org/10.2118/206281-pa","url":null,"abstract":"\u0000 Metering with multiphase flowmeters (MPFMs) is a well-proven intelligent field technology, which utilizes complex flow models to accurately measure multiphase flow (oil, gas, and water) on a real-time basis. The major realized benefits of utilizing MPFM real-time sensor data technology are reduced maintenance costs, optimized maintenance schedules, and improved safety via minimizing visits and predicting well performance.\u0000 MPFMs also have the capability to perform comprehensive real-time test validation in a short period of time, making them a valuable tool. Leveraging their capabilities, engineers can perform various production analysis scenarios remotely using continuous data streaming to reduce and ultimately eliminate reliance on operators and vendors in remote fields. Nevertheless, such MPFMs require frequent maintenance, which could be quite difficult to manage when having a large number of meters.\u0000 An in-house application was developed to support those objectives and to remotely monitor the health of all MPFMs on a real-time basis. The in-house analytics system comprises four modules: Field Overview, MPFM Overview, Well Test Management, and Alarm Management. The steps used to avail this kind of solution cover infrastructure requirements, visualization requirements, optimization, and prediction. The solution was designed as the major interface for engineers to proactively detect and prevent major MPFM component failures and highlight all types of projected MPFM component failures. It proactively harvests preset alarms, which leads to preventing internal MPFM parts from failing. These alarms are generated based on critical parameters measured by the MPFM such as rates, differential pressure (DP), and radioactive measurements. Annual savings are realized through use of the monitoring solution by minimizing costly offshore visits and optimizing the visits based on problematic MPFMs.\u0000 The authors will discuss a newly developed MPFM health monitoring strategy based on real-time solutions, driving migration from a preventative to a predictive maintenance concept to reduce costs and optimize manpower time by eliminating unnecessary visits.","PeriodicalId":153181,"journal":{"name":"SPE Production & Operations","volume":"63 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130573893","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":"Experimental Investigation of Polymer-Induced Fouling of Heater Tubes in the First-Ever Polymer Flood on Alaska North Slope Part II","authors":"Anshul Dhaliwal, Yin Zhang, A. Dandekar, S. Ning, J. Barnes, W. Schulpen","doi":"10.2118/209800-pa","DOIUrl":"https://doi.org/10.2118/209800-pa","url":null,"abstract":"\u0000 A polymer flood pilot has been ongoing in the Schrader Bluff viscous oil reservoir at Milne Point on the Alaska North Slope. The results from the pilot are encouraging. However, a major concern of the operator is the influence of polymer on the production system after breakthrough, especially the fouling in heat exchangers. This work applies a multiexperimental approach to study the severity of polymer-induced fouling in both dynamic and static states of produced fluids to determine safe operating conditions. Dynamic scale loop (DSL) tests were conducted to study fouling due to polymer at different skin temperatures (165–350°F) in a dynamic state of fluid flow where the fluids’ flow mimics the residence time of fluids in the heat exchanger of the field pilot. Static deposit tests were also conducted at similar skin temperatures of 165–250°F using a novel experimental apparatus designed and built in-house. It was found that at higher skin temperatures of 250–350°F, tube blocking was observed in the DSL tests, whereas the tests at 165–200°F did not show any tube blocking, even in a more extended test period. The deposit test showed that the deposit rate generally increases with skin temperature, and the presence of polymer aggravates the fouling. The copper tube performs best when the skin temperatures are 165–200°F, while the stainless steel tube performs best at a skin temperature of 250°F. These experiments also manifested the influence of the cloudpoint of the solution as the deposit rate increased significantly when the skin temperature was higher than the solution cloudpoint. The study provides a source of practical guidance to the field operations.","PeriodicalId":153181,"journal":{"name":"SPE Production & Operations","volume":"13 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"134562451","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":"Compositional Analysis of Conventional and Unconventional Permian Basin-Produced Waters: A Simple Tool for Predicting Major Ion Composition","authors":"Bibian Ogbuji, A. Nnanna, M. Engle, Raiel Amesquita","doi":"10.2118/209599-pa","DOIUrl":"https://doi.org/10.2118/209599-pa","url":null,"abstract":"\u0000 Treatment methods for produced water (PW) are significantly affected by a high concentration of total dissolved solids (TDS), a summation of dissolved organic and inorganic compositions. Understanding the constituents of TDS to eliminate or prevent chemical reactions is critical in the design optimization of the treatment processes. In this paper, two PW geochemical data sets generated from conventional and unconventional reservoirs in the Permian Basin were analyzed to correlate constituents with TDS. Compositional data sets from over 115,000 PW samples originally reported by the U.S. Geological Survey (USGS) and 45 oil and gas operations were analyzed. Data preprocessing, culling, systematized- and meta-analysis, and statistical techniques were adapted to associate the data. Subcompositional geochemical data were transformed into isometric log ratios and are presented in bivariate and multivariate plots.\u0000 Results indicate that Na+ and Ca2+ were the dominant cations and Cl− was the dominant anion. No observable trend differences in the Na+, Cl−, Ca2+, Mg+, and SO42− concentrations between PW from conventional and unconventional wells were registered. Variations in the isometric log ratio of Na/Cl and Ca/SO4 with TDS revealed that Na/Cl was nearly constant over the range of TDS, suggesting mineral buffering or a lack of significant water/rock reactions involving Na and Cl, and that Ca/SO4 increased with TDS, indicating that low-salinity fluids may have dissolved anhydrite producing a value near zero, with Ca gain and/or SO4 loss with increasing salinity. In all 10 counties and 8 formations investigated in this work, the ln (Ca/SO4) denotes Ca gain/SO4 loss relative to their composition in anhydrite or Permian seawater. Likely mechanisms leading to elevated ln (Ca/SO4) include sulfate reduction, dolomitization of calcite, Na/Ca cation exchange, albitization, and anhydrite precipitation from Ca-rich fluids. Results from this work are important as it is revealed that Ca/SO4 and Na/Cl can potentially be predicted from PW TDS concentrations. This information was combined to create a reservoir or location-specific model to estimate Na, Cl, Ca, and SO4 concentrations in Permian Basin PW, a powerful tool to improve treatment and reuse options in areas with few direct data.","PeriodicalId":153181,"journal":{"name":"SPE Production & Operations","volume":"29 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"134355496","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":"Experimental Research on Cationic Surfactants in the Drag Reduction of Water Injection Pipeline","authors":"Ying Yuan, J. Jing, Ran Yin, Peiyu Jing, Jianfei Hu","doi":"10.2118/209593-pa","DOIUrl":"https://doi.org/10.2118/209593-pa","url":null,"abstract":"\u0000 To achieve the throughput increase and drag reduction of the water injection pipeline for offshore oil fields, this paper takes the cationic surfactant solution as the research object and explores the feasibility of applying the additive drag reduction technology to the water injection pipelines through the rheological test and drag reduction simulation device. The experimental results show that the cetyltrimethylammonium chloride (CTAC) selected initially has excellent thixotropy, and the viscosity recovery rate within 300 seconds can reach more than 97%. In addition, CTAC/NaSal (sodium salicylate) solution has strong oil resistance and salt tolerance. As the oil concentration increases from 0 to 6,000 ppm, the viscosity only decreases by 8.24%; as the salt concentration increases from 0 to 6,000 ppm, the maximum viscosity growth rate is 87.08%. Furthermore, the CTAC/NaSal has good temperature resistance, which enhances with the increase of concentration. The recommended concentration of drag reducer is 400 ppm, and the maximum drag reduction rate, throughput increase rate, pressure drop reduction rate is 74.19, 76.76, and 67.99%, respectively. Therefore, the CTAC/NaSal solution has broad application prospects in the drag reduction of water injection pipelines.","PeriodicalId":153181,"journal":{"name":"SPE Production & Operations","volume":"46 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"123067054","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":"The Use of Formic Acid and Organic Mud Acid for Stimulation of Volcanic Rocks in Minami-Nagaoka Gas Field, Japan","authors":"Keisuke Yamamura, N. Yoshida, Keisuke Shimoda, Shunjiro Shimada, R. Matsui, M. Ziauddin","doi":"10.2118/209224-pa","DOIUrl":"https://doi.org/10.2118/209224-pa","url":null,"abstract":"\u0000 Unlike acid stimulation in sandstone and carbonate formations, acid stimulation of volcanic formations is not well documented in the literature, and its effectiveness and applicability are not well understood. This study aims to evaluate acidizing of volcanic rocks (especially rhyolite) as a well stimulation technique through a comprehensive experimental and modeling investigation using formation samples from a volcanic reservoir, the Minami-Nagaoka gas field in Japan.\u0000 The experimental study consists of rock characterization, solubility tests, coreflooding tests, and batch reactor tests. The rock samples are investigated with computed tomography (CT) for textural characteristics and with X-ray diffraction (XRD) analysis for lithological characteristics. With these results, candidate acid systems are selected, and their effectiveness in terms of the capability of dissolving volcanic rocks is evaluated through acid solubility tests. Acid coreflooding tests are performed using undamaged plug cores to evaluate permeability responses caused by acid/rock reactions under high-temperature and high-pressure conditions (300°F and 3,000 psi, respectively). Batch reactor tests are conducted to quantify damage due to secondary/tertiary reactions.\u0000 The mineralogical and textural characteristics of the rock samples let us select formic acid as the preflush acid and a mixture of formic acid and hydrofluoric acid (HF) called organic mud acid (OMA) as the main treatment acid. The composition of OMA was a mixture of 9% formic acid and 1% HF or 10% formic acid and 0.5% HF in this work. Results of the coreflooding tests with the preflush acid indicated permeability enhancement in all the samples and, especially in cores with cemented fractures filled by carbonate minerals, substantial permeability enhancement was observed. On the other hand, cores treated with OMA after the preflush indicated further permeability enhancement in some cases without cemented fractures, whereas other cases showed permeability impairment after the OMA injection. Furthermore, results of the batch reactor tests with formic acid indicated low precipitation risks, whereas those with OMA suggested higher precipitation risks. Detailed analysis on the thin sections and residuals of the batch reactor tests with OMA highlighted the precipitation of unique fluorides, and the precipitation risk was modeled and quantitatively evaluated with geochemical simulations. Although there is more room to investigate the risks of the usage of OMA for the volcanic rocks, the results in this work suggest the use of formic acid as a main treatment acid, as in carbonate acidizing, for wells with abundant cemented fractures in near-wellbore regions.\u0000 This paper provides insights on acid stimulation in volcanic rocks (especially rhyolite). The results provide a fundamental understanding on the acid/rock reactions and the potential benefits/risks for productivity enhancement of wells in the subject volcanic reserv","PeriodicalId":153181,"journal":{"name":"SPE Production & Operations","volume":"14 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"122206019","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":"Improving Decision-Making Process in Oil and Gas Development by a Context-Based Capital Value Process","authors":"H. Yananto, U. Putro, Y. Sunitiyoso","doi":"10.2118/209792-pa","DOIUrl":"https://doi.org/10.2118/209792-pa","url":null,"abstract":"\u0000 This paper demonstrates the application of a combination of action research-based soft system methodologies (SSM) and system dynamics (SD) to improve the decision-making process for oilfield development in state-owned enterprises (SOEs). The long dynamic investment phases often result in the delay of long-term oil and gas development projects, leading to loss of early production opportunities and increased capital investment. The existing decision-making process may not adequately value the initiative of an oilfield development, which results in uncertainty and leads to the rejection of investment decisions. Hence, it was assessed whether the decision-making process was differentiated based on the criteria and complexity of the proposed development project as compared to the existing project. A new context-based and scalable stage-gate model was developed for the oil and gas industry based on the stage-gate theory of new product development. The results indicate that the number of review cycles in the decision-making process reduced significantly based on the project’s complexity, ensuring the allocation of essential and scarce resources to the project, and reducing the total time for completion. In contrast, some bottlenecks still exist at the middle and higher levels of the decision-making process. A significant implication of this finding is that management decision-making will be better off if they consider delegating authorities for decision-making at every stage.","PeriodicalId":153181,"journal":{"name":"SPE Production & Operations","volume":"72 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"134599587","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":"Novel Simulator for Design and Analysis of Wax Removal Treatment from Well Flowlines Using Thermochemical Fluids","authors":"M. Qamruzzaman, D. Roy, R. Raman","doi":"10.2118/205754-pa","DOIUrl":"https://doi.org/10.2118/205754-pa","url":null,"abstract":"\u0000 Treatment of well flowlines with thermochemical/exothermic fluid has shown good results for wax removal compared with conventional hot oil, hot water, or solvent treatments. However, the technique has not gained widespread use because of the lack of sufficient scientific publications that can give more insights into its use and help in designing a safe and effective treatment. This paper presents a novel transient mathematical model for the design and analysis of thermochemical treatment for well flowlines by accounting for the chemical kinetics, heat transfer, fusion of wax, and associated two-phase flow. The governing equations have been solved using the finite-volume method. The resulting simulator can be used to prepare an optimum thermochemical plan by analyzing the effects of important factors including wax details, deposition profile, heat loss, formulation composition, and injection strategy. Simulation results obtained with the developed model indicate that the entire filling of flowline with thermochemical fluid is not necessary for complete wax removal. Injection of a small thermochemical spacer (TCS) in the flowline followed by its displacement with crude oil can be sufficient in the case of short flowlines of onshore fields. Selection of initial reactant concentration and pH has to be done judiciously based on the maximum allowed temperature in the flowline and the desired extent of chemical utilization. A sensitivity analysis has shown the existence of an optimum range of injection rate below which wax removal efficiency is compromised by excessive heat loss and above which it is reduced by insufficient residence time. The major limitation of this technique is encountered for large flowlines where a possibility of resolidification of removed wax deposits exists because of excessive heat loss. Flowlines of length less than 5 km are found to be ideal candidates as in that case, sufficiently high temperatures can be maintained throughout the journey of TCS in the flowline, which will prevent resolidification.","PeriodicalId":153181,"journal":{"name":"SPE Production & Operations","volume":"46 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133528105","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":"Influence of Reduced Graphene Oxide on Crude Oil/Water Separation","authors":"S. Al-Kamiyani, T. Mohiuddin","doi":"10.2118/209609-pa","DOIUrl":"https://doi.org/10.2118/209609-pa","url":null,"abstract":"Despite the progress made in recent years in the involvement of graphene and its derivatives in oil/water emulsions as stabilizers or demulsifiers, materials’ interaction still needs to be understood. Reduced graphene oxide (rGO) is one of the graphene derivatives that has promising implications in oil/water separation. It has unique physical properties that include large surface area, structural defects, and several functional groups on its surface. This study presents and highlights the influence of rGO in oil/water separation. Crude oil was examined at different concentrations of rGO and in different phase ratios of oil/water). The results reveal that rGO has an excellent performance. However, this depends on the oil-in-water (O/W) phase ratio, rGO dosage, and interaction time. The interphase interactions were evident in electrical capacitance analysis, where the quasimetallic effect of rGO is dominant. We believe that this work will inspire researchers to further investigate the performance of rGO in oil/water separation, where in the future it can be easily tailored by controlling rGO properties.","PeriodicalId":153181,"journal":{"name":"SPE Production & Operations","volume":"4 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"121804855","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":"Application of Gel for Water Shutoff: A Case Study of Kelebija Oil Field","authors":"Irina Zahirović, Petar Skrobonja, D. Danilovic","doi":"10.2118/209590-pa","DOIUrl":"https://doi.org/10.2118/209590-pa","url":null,"abstract":"\u0000 This paper focuses on the results of water shutoff operations using polymer gel in the Kelebija oil field. The methodology of candidate wells’ selection and the manner of performing the operation will also be included. The Kelebija oil field is characterized by a complex reservoir system with heterogeneous layers of different permeability and dual porosity with a strong waterdrive aquifer, which led to the early breakthrough of water. For the last 25 years, the average water cut was above 90%. Implementation of water shutoff operations began in 2019 and was performed on seven wells with an 85.7% success rate. It proved to be very effective with a water-cut reduction from 23% to as much as 72%. The average water cut for the entire Kelebija oil field has dropped by 12% and oil production increased by 210%.","PeriodicalId":153181,"journal":{"name":"SPE Production & Operations","volume":"30 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130107189","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}