Day 4 Thu, November 14, 2019最新文献

{"title":"Success Story of Utilizing Real Time Drilling Data to Remotely Support Drilling Operations and Identifying the Areas of Drilling Performance Improvement","authors":"Abdul Salam Awad Mohamad, Omar Ahmed Al Dhanhani, Ashish Joshi, A. Hussein, Khadija Alsawwafi, Alberic Clergier, Anurag Dubey, Wiliem Pausin, Firas Al Fardan, Amin Jradat","doi":"10.2118/197263-ms","DOIUrl":"https://doi.org/10.2118/197263-ms","url":null,"abstract":"\u0000 Upstream Oil & Gas industry has been continuously focusing on reducing the operating cost, while targeting higher operational efficiencies. To that extent we are seeing a continuous move towards remote operations with efficient utilization of available data to identify operational issues and provide benchmarks for improving drilling performance. The industry is putting significant efforts into using instrumentation and software to optimize operations in all domains for exploration and production (E&P) to move towards the Digital Oil field of the future.\u0000 With a similar vision, ADNOC Onshore have implemented Real Time Data Management project in partnership with Schlumberger for enabling remote real-time drilling operations and performance reporting across its entire active rig fleet. The objective is to provide a single platform to users for: Technological solution enabling real-time data transmission from all rigs to ADNOC Onshore Headquarters and enabling real-time visualizations of the drilling data.Engineering solution to transform real-time data into information to easily identify the areas of operational improvement allowing to implement specific measures to reduce ILT and NPT which can help in reducing costs and risk.\u0000 This project has also provided an automated Drill Well on Paper (DWOP) process where high frequency real-time data is utilized along with low frequency Daily Drilling report data to provide better insights for well planning and generate ideas for improving performance and reducing costs.","PeriodicalId":11328,"journal":{"name":"Day 4 Thu, November 14, 2019","volume":"74 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90395856","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":"Pre-Khuff Exploration Data Gathering Strategy – Learnings and Best Practices from Abu Dhabi Offshore Fields","authors":"S. Steiner, Amogh Chitrao, Pradeep Menon, A. Vantala","doi":"10.2118/197222-ms","DOIUrl":"https://doi.org/10.2118/197222-ms","url":null,"abstract":"\u0000 Drilling deep exploration wells to Pre-Khuff formations requires considerable investment and therefore data gathering through logs and cores should be of highest quality to maximize value of information. The abrasive nature combined with high downhole temperatures and bit sticking present a uniquely hostile environment. In this paper, we discuss challenges in data acquisition and propose best practices for logging and coring programs tailored for Pre-Khuff exploration targets.\u0000 The oldest Pre-Khuff stratigraphic unit penetrated offshore is Silurian Qusaiba equivalent. Apart from Permo-carboniferous Unayzah, the other stratigraphic units encountered in Abu Dhabi Offshore are Permian Basal Khuff Clastics (BKC), Early Carboniferous Berwath, Silurian Tawil /Sharawra Formations. In recent years, a number of deep exploration wells penetrated Pre-Khuff in various offshore fields, often under challenging high temperature and high pressure conditions. Considering extensive data gathering programs, this includes mud logging, LWD, wireline logging, and core extraction followed by detailed core analysis.\u0000 Log data acquired through wireline is frequently impaired by wash outs and bad hole conditions, hence posing a challenge to assess rock properties reliably. Cores were successfully acquired as whole core and sidewall core and extensive core analysis programs were conducted.\u0000 The key objectives for data gathering in Pre-Khuff are lithostratigraphy, sedimentology and age dating, petrophysical properties and prove hydrocarbon presence as well as geomechanical properties for hydraulic fracturing of the formation for subsequent well testing operations.\u0000 Palynological analysis at well site is important for age determination. Correlation of mud logging results with open hole logs and Borehole image logs proved essential to determine hydrocarbon presence. The complex lithology mix is best resolved with elemental spectroscopy logging. LWD log acquisition is preferred over wireline because of a reduced risk of stick and pull and minimum invasion. However, some useful measurements such as Dielectric log are currently only available through wireline and industry should develop this tool for LWD. NMR tools generally cannot cope with the high temperature environment. Hence, service industry is encouraged to provide higher spec NMR tools. Due to low matrix permeability, core analysis for crushed rock or retort methods are preferred to obtain permeability measurements through pulse decay and pressure decay methods.\u0000 Recommendations are given for optimal data gathering to ensure maximum value of information and best possible data quality. Logging operations should be a combination of Logging-While –Drilling and Wireline operations. Core acquisition will have to exclude BKC (Basal Khuff Clastic) to limit the risk of core jamming. A typical core analysis program to assess petrophysical and geomechanical properties for Pre-Khuff is proposed, leading to a successful risk asse","PeriodicalId":11328,"journal":{"name":"Day 4 Thu, November 14, 2019","volume":"40 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85082943","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":"Increasing Reliability of Stress Characterization through Optimum Design and Sensitivity Analysis of Fracture Injection Tests, Coupled with Enhanced Geomechanical Analysis","authors":"Oswaldo Perez, F. Fragachán, M. Omer","doi":"10.2118/197516-ms","DOIUrl":"https://doi.org/10.2118/197516-ms","url":null,"abstract":"\u0000 Diagnostic fracture injection tests (DFIT) are conducted to estimate the magnitude of the minimum horizontal stress (tectonic) and characterize essential reservoir properties, such as reservoir permeability and actual reservoir pressure in conventional and unconventional reservoirs. When properly designed, and conducted, this type of transient test can help operators to reliably extract important reservoir data and reduce related operational costs and time. This paper provides a state of the art sensitivity analysis based on real pressure data that describes the impact of DFIT design on reservoir parameters acquisition.\u0000 In this study, the engineering steps to optimize the design, conduct the test and interpret acquired data are examined through a sensitivity analysis to obtain reliable results. Furthermore, the interpretations of the performed tests can be combined with an enhanced image log analysis (if available) to constrain the in-situ stress conditions, including the magnitude and direction for all three principal stress components.\u0000 Multiple operational parameters, such as injection rate, injection duration, rate reduction, leak-off mechanism and fall-off duration could significantly impact the fracture extent and mechanical response of the rock, thus affecting the fluid flow regime after shut-in. Therefore, all these variables should be evaluated in the proposed methodology to optimize the test, which is the key difference between conventional design and the presented reservoir driven design. To quantify the impact of operational parameters in reservoir response and validate the proposed approach, extensive sensitivities are performed with a complete well data set from a typical unconventional play by running in-house fracture models, considering multiple testing parameters (such as injection schedule, fluid type, leak-off, and net pressure analysis). Eventually, the optimal injection scenario can be determined, which could be applicable for regions with similar geological conditions.\u0000 This study demonstrates how uncertainties can be narrowed down when estimating the stress condition from fracture injection tests. The proposed approach can identify critical parameters and suggest best practices for diagnostic fracture tests under certain reservoir conditions. It can also be coupled with an enhanced image log analysis to fully determine the in-situ stresses magnitude and direction, which will increase the reliability of related geomechanical and reservoir analyses.","PeriodicalId":11328,"journal":{"name":"Day 4 Thu, November 14, 2019","volume":"12 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75239542","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":"Understanding the Performance and Application Window of Autonomous ICD","authors":"Oscar Becerra Moreno, Kousha Gohari, Alex Kendall","doi":"10.2118/197331-ms","DOIUrl":"https://doi.org/10.2118/197331-ms","url":null,"abstract":"\u0000 While it is understood that Inflow Control Devices (ICDs) can be an extremely valuable tool for reservoir management in certain applications, an engineering analysis is used to determine viability of ICDs for future developments. Typically, reservoir and production engineers use numerical reservoir simulation and/or steady state simulation to determine their applicability, evaluate various devices and configure their completions. Hence it is critical that the methods used to characterize the performance of the ICDs in these simulators are accurate.\u0000 For passive ICDs, the characterization is fit for purpose; however for Autonomous Inflow Control Devices (AICDs), despite their recent rise in popularity, the performance characterization has been limited to mathematically derived correlations that are adjusted to initial data. By using these mathematically derived correlations rather than physics-based modeling, the characterization is unable to predict critical flow for compressible fluids and critical flow caused by cavitation in the case of pure substance flow, such as water. By neglecting the effects of the physical phenomenas such as compressibility and cavitation, the simulation will result in higher gas production than reality for gas coning control applications and higher water production in thermal applications where the operational condition is close to water saturation.\u0000 Furthermore, fitting the correlations parameters for a wide range of fluid viscosities is complicated. This has led to several variants of correlation parameters that are dependent on specific ranges of viscosity. Hence, dynamic simulations can be complicated by the fact that the performance correlation factor has to be changed according to the fluid that is produced.\u0000 In an attempt to remedy these limitations, a typical AICD, considered an industry standard, was modeled using a mechanistic approach to capture the physics of the process as closely as possible. Existing sets of test data, some of which were publically available, for fluids ranging from 0.011 to 500 cP, were used to tune the mechanistic model and test the ability of reproducing the data.\u0000 The results have shown that the model has the ability to reproduce the flow loop test, effectively being able to predict compressible critical flow and performance of the device for a wide range of fluid viscosities. Furthermore, new experimental data was generated to test cavitation conditions that were included in a unified model. The unified model consolidates the expected operational window of the device, allowing accurate interpolation of non-tested conditions.","PeriodicalId":11328,"journal":{"name":"Day 4 Thu, November 14, 2019","volume":"145 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75960191","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":"Research on Hydrate Risk Prediction in Deepwater Submarine Natural Gas Transmission Pipelines","authors":"Wenyuan Liu, Jinqiu Hu, Fengrui Sun, Zheng Sun, Hongyang Chu, Xiangfang Li","doi":"10.2118/197907-ms","DOIUrl":"https://doi.org/10.2118/197907-ms","url":null,"abstract":"\u0000 Hydrates generation-blockage in submarine natural gas pipelines has always been related to the safety of deepwater natural gas production and transportation. However, the current hydrate formation risk prediction in subsea pipelines is still immature.\u0000 In this paper, a model for evaluating the risk of hydrate formation in submarine natural gas pipelines has been established. The model has been applied and the sensitivity analysis of typical factors has been carried out. The results show that: (a) owing to the low temperature of the seabed, hydrate formation region (HFR) often exists in submarine pipelines. Avoiding HFR by injecting inhibitors is the key to ensure the safe transmission. (b) the decrease of gas temperature in the pipeline is determined by the heat loss of gas from inside to outside of the pipe. At a lower gas transport rate, the decrease of gas temperature is more significantly affected by the heat exchange rate. (c) at the same gas transport pressure and temperature, the pressure drop increases with the increase of gas transmission rate, while the temperature drop and the length of HFR decrease with the increase of gas transmission rate. (d) at the same gas transport rate and pressure, the pressure drop in the submarine pipeline is not significantly affected by the gas transport temperature, but the gas temperature at the end of the pipeline increases with the increase of the gas transport temperature and and the length of HFR decreases with the increase of gas transport temperature. (e) at the same gas transport rate and temperature, the temperature drop and HFR in the submarine pipeline is not significantly affected by the gas transport pressure, but the pressure drop loss decreases gradually with the increase of gas transport pressure. (f) reasonable setting of gas transport temperature and gas transport rate can help to reduce the hydrate risk and consumption of inhibitors in the submarine natural gas transportation.\u0000 Accurate prediction of hydrate risk in deepwater submarine pipelines is essential for safe gas transportation. The research provides the theoretical guidance for safe and efficient natural gas resources development and transportation.","PeriodicalId":11328,"journal":{"name":"Day 4 Thu, November 14, 2019","volume":"31 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77965389","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":"Applying a Foamed Cement Operation for Surface Casing in a Deepwater Well: Case Study, French Guiana","authors":"D. Ribeiro, Leonardo Souza, J. L. Paredes, P. Michon, Cyril Szakolczai","doi":"10.2118/197190-ms","DOIUrl":"https://doi.org/10.2118/197190-ms","url":null,"abstract":"\u0000 Lightweight or, alternatively, foamed cement slurries for surface casing operations are often necessary during special situations (i.e., low fracture gradients) for the required zone to be isolated. The foamed cement technique reduces the heat of hydration (HoH) of the slurries, reducing potential risk of shallow hydrate flow and losses because of its reduced hydrostatic pressure. This alternative for lightweight slurries has been used globally with successful results.\u0000 The foamed cement operation was designed and executed considering specific aspects and details, including a combination of factors, such as expected low fracture gradient, mechanical property requirements, logistic constraints in terms of the difficulty managing two types of cement (large tonnage of Blend and G cement vs. rig capacity and safety volume requirements), long sections to be cemented, and the uncertainty of the cement volume excess necessary to achieve return in the seabed. Because this was the first cement operation for the operator at this remote deepwater field, the planning phase required extensive discussions. Rig silo capacities and deck space on the rig were limited, which constrained the possibility of considering backup for all bulks, chemicals, and equipment.\u0000 Execution of the cement operation was as per the approved program without deviation. The cement volume returned at seabed indicated an openhole diameter with ±100% washout. A tracer additive (fluorescent dye) mixed with the spacer was successfully used to indicate fluid return at seabed (2120-m water depth). As part of the best practices to execute this operation, a liquid additive system was used to provide pump volume flexibility. Foamed cement laboratory tests were performed, considering field samples and the foaming agent (surfactant) were injected straight at the suction of the pump. As expected, the foamed cement operation is an extremely efficient and effective technique to achieve zonal isolation in a surface casing string of a deepwater well. Currently, this procedure is frequently used in fields globally. A case study of the first foamed cement application for surface casing in French Guiana is discussed.","PeriodicalId":11328,"journal":{"name":"Day 4 Thu, November 14, 2019","volume":"16 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78653826","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":"Enhance the Operating Capacity - Maximize the Revenue","authors":"Murali Muthukrishnan, Fatima H. Alraeesi","doi":"10.2118/197898-ms","DOIUrl":"https://doi.org/10.2118/197898-ms","url":null,"abstract":"\u0000 To explore the opportunity for maximum utilization for one of gas processing facilities in line with ADNOC strategy to enhance profitability and asset utilization. A Technical study was conducted to increase the processing capacity up to 115% of its design limit. This was to identify the potential bottlenecks in the facility and suggest debottlenecking options with a reasonable investment.\u0000 The Technical study covers the following activities: Rigorous process simulation including the licensor units of NGL & AGRU.Line sizing adequacy check and detailed hydraulic evaluation of the major piping.Equipment adequacy check.Relief & blowdown and flare system adequacy check.Proprietary equipment/design evaluation of licensed units.Adequacy check for In-line instruments like control valves, flow elements/transmitters, ThermowellsRotating equipment adequacy checks performed with the concurrence from OEMs.Obtained Endorsement of NGL licenser (Ortloff) for the methodology of 115% adequacy check, with a recommendation to gradually increase the plant rate in 1% at a time and monitor the performance until achieving the required targetRisk assessment was conducted before the capacity testActual plant capacity test run to verify the study findings.\u0000 The study has concluded the following observations for processing 115% of the design capacity: High flow alarms set points need to be changed at some locations due to increase gas flow rates.550 oo 1133 of thermowell are not adequate based on new design CODE. These thermowells are to be replaced for the continuous operation.6 Filters to be upgraded with required capacity.\u0000 A Successful two days Test-run was conducted in June 2018 and there are no additional limitations identified other than identified in the study. Following are the outcome. Reduction of the C2 recovery by 1.2 % with no significant change in C3 recovery level.Increase in Residue Gas by 30 MMSCFD per trainIncrease in NGL by 235 TPD per trainIncrease in condensate by 2100 BPD per train\u0000 Overall Product wise revenue per train was identified at a sum of 62.5 MMUSD/Y.","PeriodicalId":11328,"journal":{"name":"Day 4 Thu, November 14, 2019","volume":"28 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78942537","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":"Co-Development Aspects of Super Giant Reservoirs With Condensate-Rich Gas Cap","authors":"Yulia Ziablitckaia, A. Sharif, M. Abdou","doi":"10.2118/197200-ms","DOIUrl":"https://doi.org/10.2118/197200-ms","url":null,"abstract":"\u0000 Conventional strategy for developing of giant oil reservoirs with a gas cap involves an optimal production from the oil column before the gas cap is blown down. This paper investigates technical aspects of co-development strategies where demand for the gas may entail earlier exploitation of the gas cap along with the existing oil column development.\u0000 Co-development of giant reservoirs with condensate-rich gas cap are particularly challenging due to the presence of significant condensate volumes. The basic strategy of the co-development plan involves producing from a gas cap first under full gas recycling so as to accelerate condensate recovery. This is followed by sales gas production by means of partial gas recycling in conjunction with water injection at gas-oil contact for pressure maintenance purposes. The injection of water at gas-oil contact is intended to provide a water barrier or fence that separates and / or minimize gas cap expansion toward oil. The degree at which sales gas is produced is under pressure maintenance scheme is thus linked to the level of the partial gas recycling and the efficiency of the barrier or fence water injection.\u0000 To explore the feasibility of this process, reservoir simulations of mechanistic models were first used to study the reservoir physics of water injection at gas-oil contact for the purpose creating water barrier and /or fence. This was followed by implementation of the co-development scheme using sector models that represent two giant carbonate gas cap reservoirs. The feasibility and merits of the co-development strategy were measured by performance metrics that include condensate recovery, sales gas production, minimum oil loss and fluid migration at gas-oil contact and overall water demand.\u0000 The results show that partial recycling along with barrier water injection may provide a mechanism for concurrent gas cap and oil column exploitation. A key factor that underlies the success of the co-development plan is the ability of the water injection at gas-oil contact to recover potential pressure drop in time as gas recycling ratio is reduced by forming effective barrier. This, in turn depends mainly on the reservoir geology and water injection volume and scheme. Moreover, reservoir characteristics that are favorable to the process are lower formation dip angle, smaller surface area at fluid contact and good injectivity of the reservoir rock.","PeriodicalId":11328,"journal":{"name":"Day 4 Thu, November 14, 2019","volume":"37 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"72887269","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"A Novel Approach in Handling Water Breakthrough in Fractured Carbonate Reservoir Through Dynamically Integrated Fracture Characterization: A Case Study","authors":"L. F. Rodríguez, Erich Funk","doi":"10.2118/197540-ms","DOIUrl":"https://doi.org/10.2118/197540-ms","url":null,"abstract":"\u0000 A key management guideline for water-driven, naturally fractured reservoirs (NFR) is to minimize water production. Water breakthrough is undesirable as it reduces oil production rate and lowers oil recovery. Managing these reservoirs involves delaying water breakthrough and mitigating its effects. This paper describes a cross-disciplinary workflow, which serves such purposes by making use of downhole pressure gauges (DHG) pressure data-based well models along with a dynamically validated fracture model.\u0000 The data-based well model is developed from our DHG pressure-production database. It has been field tested for forecasting water breakthrough, predicting water level in wells and planning for counteractive actions. The data-based well model is combined with a detailed fracture model whose elements were derived from the systemic integration of fracture types, genetic context and interaction with the carbonate host rock during diagenesis. The resulting workflow enables the well and reservoir management team (WRM) to put the well back in production after water-breakthrough in a way that maximizes oil re-saturation from tributary fractures into the main conductive features connected to the wellbore.\u0000 A field case illustrating the application of this workflow is discussed. The outcome of the application of this workflow is compared with the performance of other wells in which water breakthrough was dealt with by merely reducing their liquid rates till water cut became manageable. A complete set of relevant measured data, including downhole pressure gauge and a post breakthrough production logging tool (PLT), is discussed in the paper. Well performance puts in evidence that the workflow discussed in this paper allows for higher oil production rates and significantly lower water production rates following water breakthrough compared against more traditional approaches for handling wells after water breakthrough.\u0000 The workflow was developed through frequent iterations between near-wellbore flow performance data-based modeling and multi-scale fracture characterization, aimed to address the impact of the main conductive features and tributary fractures on well productivity. It is of interest to anyone involved in managing NFR, especially those engaged in preserving the sustainability of the oil potential of the well (both duration and rate).","PeriodicalId":11328,"journal":{"name":"Day 4 Thu, November 14, 2019","volume":"40 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79339374","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":"Optimization of Corrosion Inhibitor for a Gas and Condensate Field","authors":"S. Hirano, Toshiyuki Sunaba, Kazuyo Sasaya, Atsushi Kobayashi, Hirokazu Yorozu, H. Iijima","doi":"10.2118/197188-ms","DOIUrl":"https://doi.org/10.2118/197188-ms","url":null,"abstract":"\u0000 Qualification of a new corrosion inhibitor was carried out for both tubing and flowline services in a gas and condensate field because the production condition changed. The methodology and result of the inhibitor evaluation under a sweet condition was summarized. The depth of production well is 4,500 m and the bottom hole temperature and pressure are 180 °C and 50 MPa respectively. Two brands of corrosion inhibitors had been used for production tubing and flowline respectively in the field. A new inhibitor was investigated for the both applications. The performance of corrosion inhibitor efficiency was evaluated with a rotating cage autoclave. In order to evaluate the tendency of emulsion forming, Oil, brine and an inhibitor were poured into a centrifuge tube and it was shaken intensely. Gas chromatograph - mass spectrometer (GC-MS) and Fourier transform infrared spectroscopy (FT-IR) were studied to measure the residual amount of inhibitor. Finally the field trial was carried out with the new inhibitor. The new inhibitor was adopted successfully for the both services. The GC-MS analysis showed the flow back lasted more than two hours. The risk of emulsion forming became lower because the mixing of two brands of inhibitors was avoided. Reducing the number of the chemicals contributed to reduction of the operation cost too.","PeriodicalId":11328,"journal":{"name":"Day 4 Thu, November 14, 2019","volume":"68 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80271841","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}