Day 2 Tue, November 01, 2022最新文献

{"title":"Enabling Synthetic PLT Through Integration of Brittleness Indicator and Porosity-Independent Permeability to Improve Understanding of Expected Flow Profile in an Unconventional Reservoir: Case Study from Kuwait","authors":"Anar Abdulkarim, Sabry Abd El-Aziz","doi":"10.2118/211643-ms","DOIUrl":"https://doi.org/10.2118/211643-ms","url":null,"abstract":"\u0000 Mauddud carbonates in the Bahrah Field of Kuwait, with their low permeability, are often considered as unconventional reservoirs, which require multi-stage hydraulic fracturing stimulation. Optimal stage distribution is one of the key elements in this type of completion design. This paper presents the forecasting methodology for estimating the production performance of each stage which can later help to optimize stage placement in long horizontal sections.\u0000 High-resolution micro-resistivity imaging and an azimuthal sonic tool, in combination with conventional triple-combo logs and formation pressure testing, were run in a 6.125-in. section to help develop an effective and sustainable production plan, based on the petrophysical and geomechanical properties of the heterogeneous tight carbonate reservoir. The use of image data helped to evaluate the permeability distribution close to the borehole wall more accurately than conventional porosity-based permeability relationships, which showed marginal correlation with actual permeability. Sonic and density logs helped to estimate rock mechanical properties. Mobilities derived from the formation pressure build-up curve were used to normalize permeability indicators.\u0000 The porosity-independent image permeability indicator, which was developed specifically for carbonate formations and is based on the electrical conductivity distribution around the circumference of the borehole, showed fair correlation with the brittleness indicator. The brittleness indicator, on the other hand, exhibited a high degree of correlation in all completion stages with the production logging (PLT) data. The good correlation of production information with the brittleness indicator, derived from Poisson's ratio and Young's modulus, is in line with the main inputs for hydraulic fracture design, which use these mechanical properties. Both brittleness and image permeability indicators were used to improve well placement in the sweet part of the reservoir and played an important role in the success of this complex process. This process also enables the potential for synthetic PLT derivation, which can help to improve understanding of the expected flow profiles from different frac stages.\u0000 The case study presented in this paper demonstrates the promising benefits of integration of open-hole logs to derive synthetic PLT data that can improve completion design and enhance production forecasting in an unconventional reservoir. The availability of several years of production and formation pressure dynamics data also helped to extend the application of the methodology to forecast future production stability for the field.","PeriodicalId":249690,"journal":{"name":"Day 2 Tue, November 01, 2022","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-10-31","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"115313216","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":"Centralized Predictive Analytics & Diagnostics Value Creation","authors":"Aysha Mubarak AlSulaimani, Pradip Majumdar, Reem Alhammadi, Badhria AlHammadi","doi":"10.2118/211226-ms","DOIUrl":"https://doi.org/10.2118/211226-ms","url":null,"abstract":"\u0000 The implemented maintenance strategy for rotating equipment in the field was conventional time-based (6months-1year) maintenance. Due to this maintenance philosophy, many equipment's were serviced every 6-12 months including the stand-by equipment. Thus, material, spare parts and man-hours are consumed very frequently. In 2019, company decided to convert the maintenance philosophy from time-based to running-hours based and based on OEMs recommendations, 4000 running-hours was the optimum running-hours before the equipment maintenance. By implementing this technique, the frequency of equipment maintenance was reduced and thus maintenance cost and service cost were reduced as well. Moving towards the deployment of AI technology and digitalization world, a new requirement to deploy predictive maintenance analytics and tools elevated. The Centralized Predictive Analytics & Diagnostic (CPAD) which is a centralized ret time predictive monitoring solution for critical assets. The asset specific real time data from site historian will be replicated a centralized historian to enable continuous monitoring of these assets and failure predictions. The CPAD modules get these data streams and execute performance calculations for each asset based on first principle models and also monitor for the failure predictions through data driven models using APR methods. CPAD will generate fault notifications that will be transmitted to site experts for follow-up. CPAD project will be implemented in multiple phases. The first phase will be a pilot implementation as prove of concept and will include the deployment, commissioning and monitoring of all core applications. Once pilot prove of concept implementation schussed, it will to be followed by further implementation of remaining critical rotating equipment. The deployment of predictive maintenance and analytic diagnostics solutions will add value in different forms. It will support shutdown deferrals and planning for critical equipment, it will help in reducing maintenance cost of material, consumables, spares & man hour. In addition, it will help in the transition from preventive maintenance to proactive/predictive maintenance. Furthermore, the predication ability will help in early prediction and identification of potential failures and gives advisory recommendations to support rectifications of failures before the actual failure occur.\u0000 The pilot implementation started in 2020 with the deployment of 54 critical rotating equipment. The cases reported in phase-1 pilot implementation reported around $3.000.000 savings and proved the CPAD concept. A plan were put in place to capture additional assets in the CPAD system. Additional 108 equipment were deployed in phase-3 implementation of the project.","PeriodicalId":249690,"journal":{"name":"Day 2 Tue, November 01, 2022","volume":"185 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-10-31","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"114481393","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":"Accelerated FDP Reservoir Studies in Challenging Brownfields Utilizing Digital Could Technologies","authors":"A. Abdullah, Yong Han Seah, Stefanie Mei Mei Chuah, M. S. N. B. A Wahi","doi":"10.2118/211350-ms","DOIUrl":"https://doi.org/10.2118/211350-ms","url":null,"abstract":"\u0000 PETRONAS Baronia field is a mature oil field with over 45 years of production history, located offshore Sarawak, Malaysia. It consists of several vertically stacked clastic sandstone reservoirs, namely two major reservoirs: S and V2 reservoirs. Both reservoirs have been on production since 1970's with the production strategy evolving over the years to maximize recovery. Natural depletion, infill drilling, water and gas injection, and recently Immiscible Water-Alternating-Gas (IWAG) IOR/EOR strategies have been implemented. All these elements combined with the subsurface uncertainties pose challenges to history match and to conduct probabilistic forecast studies on the dynamic models. Conventionally, the development scenarios for subsurface investigation are limited due to finite computing resources. As PETRONAS is shifting its portfolios to develop more complex and challenging fields, the need for transformation in development concept evaluation is evident. This is key for proper risk and uncertainties quantification. The notable challenges are a) limited number of development scenarios being investigated, evaluated, and compared; b) limited software licenses and infrastructure availability; c) lack of data and decisions traceability.\u0000 These limitations are addressed by the PETRONAS LiveFDP digital transformation initiative commenced in 2019, through deployment of digital cloud technologies and solutions with scalable High- Performance Computing (HPC) environment. The cloud-based native and Petrotechnical applications enable remote work, ensure full data traceability and auditability, enable multi-realization ensemble analysis, and streamline the automated integration from the reservoir engineering ensemble workflow to economic analysis. Unlimited cloud computing power and licenses facilitate a broader spectrum of reservoir simulation cases to be investigated in a fast-tracked manner.\u0000 The cloud HPC infrastructure has shortened the history matching cycle from 3 months to 1.5 months. The team has also observed over 5 times speed enhancement on simulation run performance using cloud computing compared to virtual machine and on-premise infrastructure. Utilizing the cloud solutions and ensemble probabilistic approach, the team has achieved over 90% of history match quality through 300 realizations per ensemble running concurrently and completed within 2 hours. The optimized IWAG injection resulted in 2% (~1MMStb) higher oil reserves with 37% less gas injection and 40% shorter injection cycles. This has improved gas sales and prioritization in the field while also monetizing the oil\u0000 reserves. The ensemble analyses are then visualized using cloud-based data analytics system whereby key realizations and uncertainty parameters are further reviewed and highlighted across various disciplines collaboratively at real time.","PeriodicalId":249690,"journal":{"name":"Day 2 Tue, November 01, 2022","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-10-31","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"115479401","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":"Onshore Abu Dhabi Carbonate Saline Aquifer CO2 Storage - An Integrated Technical Feasibility Study","authors":"C. Mascagnini, Aaesha Khalfan Al Keebali, Siqing Xu, Humberto Parra, S. Masalmeh, M. Chughtai, S. Perumalla, C. Harper, Hemant Singh, Anirban Banerjee, C. Cranfield, R. Khamatdinov","doi":"10.2118/210812-ms","DOIUrl":"https://doi.org/10.2118/210812-ms","url":null,"abstract":"\u0000 Carbon capture and storage (CCS) is recognized as an important technology in the decarbonisation of the energy system and saline aquifers are potential geological storage candidates. A major integrated feasibility study was conducted to screen and rank carbonate saline aquifer candidates for subsurface CO2 storage, onshore Abu Dhabi. The objectives were to obtain a range of potential CO2 storage capacities and annual injection rates and establish CO2 technical feasibility by integrating subsurface, well performance, cap rock integrity and economic analysis.\u0000 A candidate screening matrix was developed taking into account onshore Abu Dhabi saline aquifer geological characteristics. Saline aquifers \"A\" and \"B\" within the syncline area were among the highest ranked candidates. A large-scale 3D static model was developed, utilising seismic and well data. Extensive CO2 storage simulation runs were performed, covering sensitivities and capturing major storage process/mechanisms applicable to carbonate formation. Combining geomechanics, geoscience, well performance, integrity and dynamic modelling, a CO2 storage site design was completed with slanted/horizontal injectors drilled radially from a centralised well pad. Ranges of CO2 storage capacity and maximum injection rates were obtained, depending on number of injectors and accounting for water offtake in nearby areas. Additionally, CO2 plume migration within several tens of thousands of years was simulated to aid CO2 containment assurance. Separate studies were performed to locate potential CO2 storage surface sites and used as part of the input for CO2 pipeline and surface facilities high level design. CAPEX, OPEX and abandonment cost estimates were generated as input for economic analysis. A multi-disciplinary risk assessment was performed, identifying potential risk factors throughout the life cycle of CO2 storage. De-risking and mitigation measures were considered and a detailed measurement, monitoring and verification (MMV) plan was developed.\u0000 This paper presents the first integrated study on saline aquifer CO2 storage technical feasibility in this syncline area. A novel integrated workflow is employed, from initial candidate screening through dynamic modelling, surface facilities and risk assessment to recommendations for additional data acquisition. Key aspects which improved on published major international CO2 sequestration assessments are highlighted. The results and conclusions offer valuable insights for other Operators considering or planning CO2 sequestration in saline aquifer projects.","PeriodicalId":249690,"journal":{"name":"Day 2 Tue, November 01, 2022","volume":"34 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-10-31","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"123274876","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":"Digital Wellhead Integrated System for Production Management","authors":"Ricardo Avila Reyes, M. Machado, M. Torre, Jitender Sharma, G. Gey, Johnson Koa, Thomas Edwards","doi":"10.2118/211158-ms","DOIUrl":"https://doi.org/10.2118/211158-ms","url":null,"abstract":"\u0000 The oil and gas industry is lagging behind many industries in the adoption of technology and digital transformation. Our industry must transform at speed and scale to reap the available benefits of such technologies. Managing well integrity through personnel physical presence at the wellsite to take recordings increases the time to react to issues, the time to collect data, and the time to implement actions, and the high field trip rates introduce an increased risk to employees.\u0000 A digital wellhead integrated system (DWIS) provides information on wellhead parameters from smart instrumentation and achieves operational intelligence via edge computing. This solution improves the response time between production data and field actions to optimize and improve operational performance following workflow parameters. DWIS provides real-time monitoring, data collection, and management of well conditions, which minimizes the effects of human interactions, while providing consistent information that can be used for future health maintenance activities thus mitigating the risk of unexpected events. Cost efficient remote monitoring and control of well activities prolongs the life of the well and promotes savings.\u0000 The DWIS has been deployed and successfully tested in North America, South America, and the Middle East. A single DWIS implemented with a client resulted in production gains of 400,000 bbl./yr. and reduced 10,000 miles of driving—reducing the carbon footprint in a harsh environment. By providing human intelligence at the wellsite through edge computing and smart instrumentation, data can be generated, and actions taken to reduce expensive unplanned maintenance, offline outages, resource-intensive costs, and carbon footprint. Furthermore, this infrastructure at the wellsite enables ideas for new workflow implementation such as site monitoring via computer vision and more elaborate production and optimization workflows, creating a truly intelligent asset. DWIS maintain well integrity and provide continuous monitoring to optimize oil and gas production.\u0000 This DWIS supports well integrity maintenance strategies providing real-time control and well optimization enabled by smart instrumentation, surveillance systems, and intelligent workflows powered by artificial intelligence/machine learning algorithms executed at the edge and, in some instances, at the cloud level.","PeriodicalId":249690,"journal":{"name":"Day 2 Tue, November 01, 2022","volume":"30 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-10-31","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"122925336","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":"Managing CO2 Phase Behaviour in Depleted Reservoirs","authors":"Luis A. Acevedo, O. Tucker","doi":"10.2118/210796-ms","DOIUrl":"https://doi.org/10.2118/210796-ms","url":null,"abstract":"\u0000 Dealing with the phase behaviour management of Carbon Dioxide (CO2) in Carbon, Capture and Storage (CCS) (CCS) in depleted gas reservoirs generates technical challenges related to low temperatures. These challenges are not observed in Enhanced Oil Recovery (EOR) (EOR) or aquifer injection as these are normally carried out at pressures above hydrostatic. This paper shares some of the experience in selecting/developing solutions for depleted reservoirs (for reservoir pressures higher than 45bar).\u0000 It describes the technical challenges related to uncontrolled injection of CO2 in depleted reservoirs and the requirement to manage the phase behaviour, then proposes different concept solutions for steady injection and highlights the selection process considering the different project conditions. Advantages and disadvantages and issues for the different concept solutions are presented with an emphasis on projects where the CO2 arrives cold.\u0000 The paper gives an overview of the installation of simple and reliable long term solutions using the friction concept. It considers the applicability of the planned solution, its limitations and how to manage them.\u0000 Very low temperatures along the well can be observed under uncontrolled phase behaviour injection of CO2 in depleted reservoirs. Simulation models and analysis of the well elements indicate the requirement to manage the CO2 phase behaviour to avoid integrity problems. Conceptual solutions like friction with relatively small tubing, downhole choke,, heatingheating are required to be considered early in the maturation phase by the projects. The selection process depends on project variables and project life limitations.\u0000 The use of the friction concept has been favoured in different projects because of its long term reliability. The alternative of heating is variable and mainly influenced by injection bottomhole pressure. In general this incurs high expenditure. The downhole choke concept is promising but reliability needs to be improved and delta pressure across the choke needs to be increased.\u0000 There are limitations to the operating envelope per well using the friction concept. However, a combination of multiple wells allows for managing the desired ranges of injection in the project.\u0000 This paper also highlights the level of integration along the chain required for developing CCS in depleted reservoirs. This level of integration must not be neglected.","PeriodicalId":249690,"journal":{"name":"Day 2 Tue, November 01, 2022","volume":"28 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-10-31","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"123822015","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 Uncertainties in Laboratory PVT Data","authors":"Younus Bilal, Whitson Curtis Hays, Martinsen Sissel","doi":"10.2118/211391-ms","DOIUrl":"https://doi.org/10.2118/211391-ms","url":null,"abstract":"\u0000 Accuracy of phase behavior and volumetric calculations from a cubic equation of state (EOS) depends on the accuracy of the molar compositions used as input to the model. Lab-reported compositions have uncertainty, like all other measured PVT data. This paper discusses different sources of uncertainty in lab-reported compositions, the magnitude of uncertainty, and we propose methods to correct for uncertainty that improve PVT calculations of individual samples.\u0000 Lab-reported molar compositions can have uncertainty due to (a) baseline shift and (b) internal standard used in gas chromatography, (c) component molecular weights used to convert measured mass fractions to mole fractions, and (d) the gas-oil molar ratio (i.e., gas-oil ratio) used in recombination. A molar distribution model is used to assess and quantify uncertainty in chromatographic measurements of heptanes and heavier (C7+) fractions, also providing a method to correct for possible errors.\u0000 As a theoretical basis, synthetic examples are used to demonstrate the application of the gamma molar distribution model to quantify and correct compositional uncertainty in C7+ mass fractions due to baseline shift and internal standard. The workflow includes use of a distribution model that describes more than 50 PVT samples with widely varying gas-oil ratios and API densities, all from the same basin / field, and analyzed by several PVT laboratories over an entire decade.\u0000 Examples show that a common distribution model reliably corrects for compositional uncertainty from baseline shift and internal standard errors. The model also provides consistent and representative estimates of C7+ component molecular weights that are used to convert masses to moles. The same model provides consistent sample-specific average C7+ molecular weights that are used in correlating property variations across the basin.\u0000 Most engineers use the lab-reported molar composition \"as is\" from a PVT report, often directly as input to an EOS model. We show quantitatively the four reasons why a lab composition may have systematic error. We also provide methods to quality check and correct lab-reported compositions. A molar distribution model is used to model heavier (C7+) components quantified by gas chromatography, where the model can be used to identify errors introduced by internal standard and baseline shift issues. The proposed methods are illustrated for an entire basin where more than 50 samples have been used, covering a wide range of GOR and API.\u0000 To our knowledge, this is the first attempt to identify and deal with composition errors with a systematic and comprehensive workflow.","PeriodicalId":249690,"journal":{"name":"Day 2 Tue, November 01, 2022","volume":"23 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-10-31","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125123184","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":"Significant Stuck Pipe Event Reduction Realized Through Structured Holistic Approach Machine Learning and Artificial Intelligence","authors":"Y. Salehi, Attia Ziada, Z. Rawahi","doi":"10.2118/211738-ms","DOIUrl":"https://doi.org/10.2118/211738-ms","url":null,"abstract":"\u0000 Wellbore stability problems, such as stuck pipe and tight spots, are one of the most critical risks that affect drilling operations. Over several years, Oil and Gas Operators in the Middle East have been facing problems associated with stuck pipe and tight spot events, which have a major impact on drilling efficiency, well cost, and the carbon footprint of drilling operations. On average, the operator loses around 200 days per year in terms of Non-Productive Time(NPT) on stuck events and associated fishing operations.\u0000 Wellbore stability problems are hard to predict due to the varying conditions of drilling operations: different lithologies, drilling parameters, pressures, equipment, shifting crews, and multiple well designs. All these factors make the occurrence of stuck events quite hard to mitigate when relying on human intervention only.\u0000 In Petroleum Development Oman (PDO), we lost, between 2013 and 2017, a total of 1,568 days due to stuck events. This equated to a cost of US$15.5 million/year on average, which included the cost of tools lost in hole. In 2018 PDO's Management formed an interdisciplinary taskforce with the objective of analysing stuck events to find solutions which would reduce the cost of stuck events by 50% per year.\u0000 At the same time PDO decided to develop an Artificial Intelligence (AI) driven tool that leverages the whole breadth and depth of data (reports, sensor data, well engineering data, lithology data, etc.) available to predict and prevent wellbore stability problems. The tool, known as the \"Stuck Pipe & Tight-Spot Event Prediction\" (STEP) tool, informs well engineers and rig crews about possible risks, both during the well planning and well execution phase, suggesting possible mitigation measures to avoid getting stuck.\u0000 The taskforce's hard and diligent work, along with the use of the STEP tool, resulted in a significant reduction in stuck events, associated time, cost, HSE exposure and production deferment.","PeriodicalId":249690,"journal":{"name":"Day 2 Tue, November 01, 2022","volume":"76 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-10-31","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"126207311","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":"Achieving Remarkable Long ESP Run Life Exceeding 9 Years Continuously in Brown Oil Field Thru Leak Free Production in Highly Corrosive Environment","authors":"M. Kortam, Hany Rafat Elrayek, Amr Alkhouly","doi":"10.2118/211560-ms","DOIUrl":"https://doi.org/10.2118/211560-ms","url":null,"abstract":"\u0000 A very interesting case in mature field in Egypt, has embarked on a project of replacing Oil Production wells, originally constructed with API 5L carbon steel pipe, with fiberglass lined API 5CT Threaded and coupled tubing.\u0000 Previously, all wells had a conventional EUE carbon steel string producing with different ranges of production within 600 - 3000 bbls/day of oil without water production in early stage of the field. Later on, water injection commenced in 2004 in order to arrest reservoir pressure decline and increase the oil offtake. Accordingly, the water production progressively rose since in 2011 the measured water cut was up to 90% of with much salt content as high as 330,000 ppm, and fully saturated with dissolved oxygen. As a result, the field has been facing severe corrosion related failures in Carbon steel strings in producer wells. Furthermore, the problem has been escalated and the average pull out of hole workover jobs of each well reached two times per year due to tubular failure resulting from corrosion. The tubing leakage failure increased the OPEX of the field by which impacted negatively on the value of the asset. Many actions had been taken attempting to sole or at least reduce the severity of the problem such as; using 13% Chrome steel tubing, and placing down hole injection of corrosion inhibitor chemicals. But each solution has a drawback and the improvement in the runlife of wells were below expectations. Upon all the above repeated workovers were done to replace the frequently leaked tubing, affecting on the field performance.\u0000 GRE lining technology proved as the best erosion and corrosion resistance method that save ell integrity with the lowest cost in the field of discussion where the water salinity is 330,000 ppm, high dissolved oxygen, high temperature, and high co2 up to 6%.\u0000 Three wells were chosen as trial to be completed using Glass Reinforced Epoxy (GRE) lined tubing for internal corrosion protection. However, one of these wells has lasted for over nine years of continuous production without the even ESP fails. Such positive results of achieving Outstanding Performance in attaining longer tubing life with less workover operation with very cheaper technology.\u0000 Afterwards, the company decided to try 3%Chrome tubing for the oil production wells with a premium thread connection. In this paper, we will demonstrate the pros and cons of utilizing such a material and connection failure.\u0000 Guided by the successful trail, a shift in the inventory was done toward such application that turned up the economic value of the field. Special components were engineered to provide a transition between GRE lined tubulars and plain end unlined fittings and flanges.\u0000 This paper chronicles the history of the Oil Production, the nature, reasons and consequences of the multiple corrosion failures and the failed corrosion mitigation strategies. It will highlight the reasons why this specific well lasted for 9 continuous years and the ro","PeriodicalId":249690,"journal":{"name":"Day 2 Tue, November 01, 2022","volume":"40 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-10-31","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"126502798","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":"Generation of a Regional Fluid Database for Gas Condensate Assets in a Thrusted Carbonate Environment of the Northern Emirates","authors":"H. Saradva, Christna Golaco, M. Robert, Siddharth Jain, Thurley Callum, Abdulhafid Bentaher, Masoud Al Hamadi","doi":"10.2118/211363-ms","DOIUrl":"https://doi.org/10.2118/211363-ms","url":null,"abstract":"\u0000 Sharjah National Oil Corporation (SNOC) operates 4 onshore fields, the largest of which has been in production since the 1980's, in addition to over 50 years of exploration activity in the region. The producing fields exhibit a wide range of condensate-gas ratio (CGR) productivity and other properties. The scope of this paper is to discuss how the data from these exploration and development wells was combined to develop a trend of the fluid properties within the Northern Emirates to assist in the Future SNOC activities.\u0000 A detailed data scouting and processing workflow was undertaken and all available legacy pressure-volume-temperature (PVT) reports were digitized. All available separator recombined samples reports and bottomhole sample reports were compiled into a master database. The well test reports were thoroughly examined to understand the field operations and determine the reliability of the PVT reports while the fluid samples were collected during the well tests. An equation of state was generated for each field using all available information taking into account their production history over 30+ years and the results were then used for the regional PVT study.\u0000 A distinct trend of CGRs, specific gravity and other reservoir fluid properties were observed which co-related with the formations. These prospects which are spread out all over the Emirate of Sharjah were compared on the same parameters to develop a regional guideline. A regional trend of changing fluid properties was also observed which helps define the fluid properties expected in the Thamama Group formations in the Northern Emirates from any exploration well. The results will assist in determining the valuation of any exploration prospect if it is deemed successful and also plan ahead for the value of the prize. These trends also helped fill in missing data and perform quality control (QC) on older fields where comprehensive lab data was unavailable. In some cases, gas condensate fluid properties were unattainable at the mature stage of the field and this study provided the necessary information to plan enhanced recovery opportunities.\u0000 This paper aims to be a leading reference for the PVT fluid properties in the complex Thamama Group of the Northern Emirates to support future exploration and development activities. The regional data provides a strong correlation and this information is novel in terms of utilizing legacy data for potential opportunities. The new database also helps QC the dataset of existing PVT reports along with aiding in identifying the sources of hydrocarbon origin in this region.","PeriodicalId":249690,"journal":{"name":"Day 2 Tue, November 01, 2022","volume":"31 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-10-31","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125765570","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}