Day 1 Mon, September 30, 2019最新文献

{"title":"Casing Connection Break Detection Through Tubing in Canadian Thermal Projects. Case Study.","authors":"M. Ghanavati, M. Volkov, V. Nagimov, Hamzeh Ali Mohammadi","doi":"10.2118/195956-ms","DOIUrl":"https://doi.org/10.2118/195956-ms","url":null,"abstract":"\u0000 Production casings of Cyclic Steam Stimulation (CCS) or steam-assisted gravity drainage wells are exposed to significant temperature variations which in many cases resulted in casing breaks in the weakest part which are typically connection joints. The paper focuses on the new downhole logging approach, in monitoring and detecting production casing connection breaks through tubing without requirement for tubing retrieval.\u0000 The metal well barriers can be assessed by utilizing electromagnetic (EM) pulse defectoscopy. This is done by running multiple coaxial sensors downhole in tandem. Each sensor generates EM pulse and then records EM decay from surrounding metal tubes. Modeling of recorded EM decay enables precise assessment of metal loss or metal gain in up to four concentric barriers. However, the tool had never been used previously to detect minor defect features as casing breaks through the tubing. To identify casing breaks several yard and field tests have been conducted and new methodologies were developed. The last one included the recognition of specific patterns of raw EM responses, analysis of hole sensors and utilization of data from all coaxial sensors utilized during the downhole survey.\u0000 The new approach including downhole EM pulse tools and new data analysis have been implemented to detect casing connection breaks in over a hundred Cyclic Steam Stimulation (CCS) and SteamAssisted Gravity Drainage (SAGD) wells. The paper demonstrates the testing of the application feasibility in a comprehensive yard test and extends to real field examples. All detected breaks were confirmed after tubing removal and were successfully repaired. Paper highlights detection challenges due to different casing connection break types: minor breaks, partial breaks (contrary to fully circumferential), and casing breaks aligned with tubing connections. The technology has helped Operators to fulfil the objectives of connection break detection without tubing removal through a non-intrusive, safe, quick and economical approach.\u0000 Today, CSS and SAGD Operators should confirm casing integrity repeatedly prior to each subsequent steam cycle through the time and resource consuming approach of tubing removal and checking the casing integrity mechanically. Utilizing through tubing electromagnetic diagnostics, enables Operators to pick up multiple casing connection breaks in a single run without tubing retrieval.","PeriodicalId":325107,"journal":{"name":"Day 1 Mon, September 30, 2019","volume":"16 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125537098","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":"Automated Surveillance of Subsurface Wellbore Integrity in a Heavy Oil Field using Passive Seismic Systems","authors":"Lolla Sri Venkata Tapovan, J. R. Bailey, O CostinSimona, S HonsMichael, Liu Xinlong, Yam Helen, Akhmetov Arslan, W HaywardTim, C. Brisco","doi":"10.2118/195810-ms","DOIUrl":"https://doi.org/10.2118/195810-ms","url":null,"abstract":"\u0000 Continuous subsurface surveillance is important for heavy oil in-situ recovery processes where induced stresses in the overburden can compromise the integrity of the wellbores. Wellbore failure may lead to the undesirable loss of fluids into the overburden. In recent years, there has been a rapid growth in the use of Passive Seismic monitoring systems to aid in subsurface surveillance activities, with the ultimate goal of detecting potential integrity issues as early as possible. However, the massive volume of data recorded by these instruments is time-consuming and error-prone to process manually. This paper introduces EMMAA (ExxonMobil Microseismic Automated Analyzer), an automated workflow to reliably process continuous microseismic data, detect subsurface integrity issues, and ultimately reduce the latency in responding to wellbore integrity issues.\u0000 A novel cloud-based technology for managing microseismic data is briefly described. The seismic waveforms, recorded by a distributed array of geophone receivers, are automatically analyzed to determine the type and source of subsurface disturbances (‘events’).\u0000 First, novel frequency-domain and deep learning analyses are used to distinguish noisy signals from the seismic waveforms such as compressional and shear waves produced by the events. Next, the location of the event is calculated and its seismic attributes are computed. Finally, the type and severity of the seismic event are determined by an event classifier.\u0000 The performance of the automated workflow is examined in the context of accurate detection of casing failures in a heavy oil Cyclic Steam Stimulation (CSS) application. The event features that distinguish casing breaks from other seismic events are described. It is shown that the methodology is able to achieve a high detection rate when back-tested against a historical data-set of known casing failures. False positives are adequately contained by preventing waveforms of electrical or mechanical noise from being processed.\u0000 In a production environment, the event processing workflow is run on distributed servers and analyzes triggered seismic data in real-time. Depending on the severity of the microseismic events detected, operators are immediately alerted via email and text messages, so that remedial actions may be swiftly initiated. The utility of this integrated system is further exemplified by the massive reduction in the time taken to detect casing breaks—from up to 36 hours historically, down to less than one hour in most instances.\u0000 Extensions of EMMAA that enable the detection of a wide variety of microseismic events are also discussed. These events include surface casing slips that occur at the casing shoe, cement de-bonding events near the wellbores, and events indicative of potential fluid migration in the overburden.","PeriodicalId":325107,"journal":{"name":"Day 1 Mon, September 30, 2019","volume":"146 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"127510539","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":"Huff-N-Puff Gas Injection for Enhanced Condensate Recovery in Eagle Ford","authors":"Reza Ganjdanesh, Wei Yu, M. Torres, K. Sepehrnoori, E. Kerr, R. Ambrose","doi":"10.2118/195996-ms","DOIUrl":"https://doi.org/10.2118/195996-ms","url":null,"abstract":"\u0000 As the pressure drops below dew point in an unconventional gas-condensate reservoir, the liquid drops out of gas phase and forms an oil phase in matrix and fracture. The volume of oil phase formed in the matrix mostly stays below the residual oil saturation, i.e., the oil will be trapped in matrix permanently if enhanced oil recovery techniques are not applied. The huff-n-puff process has been performed and shown the potential of improving the recovery from tight oil reservoirs. The objective of the study was to investigate the feasibility of huff-n-puff EOR in a gas condensate reservoir in Eagle Ford. The studied section of the field contains 13 horizontal producers. The wells have been producing for 4 to 8 years and the oil production rate of each well declined below 10 barrels per day.\u0000 Compositional reservoir simulation was used to predict the performance of enhanced oil recovery. A sector model was built for the area selected as the prospective candidate for gas injection. The embedded discrete fracture model (EDFM) was used for modeling the fractures. A Peng-Robinson equation-of-state model was prepared based on the early produced samples from the wells. The only available gas for injection was the produced gas from the surrounding producers. A thorough phase behavior analysis was conducted to understand the miscibility of the injected gas and the in-situ fluid.\u0000 The field production data was used to history match the sector model. The field data of the initial huff-n-puff cycles were incorporated into the history match to fine tune the model. The robust sector model was employed to forecast the performance of gas huff-n-puff in 4 infill wells for 5 years of EOR operation.","PeriodicalId":325107,"journal":{"name":"Day 1 Mon, September 30, 2019","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130895082","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":"Unconventional Shale Hydraulic Fracturing Under True Triaxial Laboratory Conditions, the Value of Understanding Your Reservoir","authors":"A. Abdelaziz, Johnson Ha, H. A. Khair, M. Adams, C. Tan, I. H. Musa, G. Grasselli","doi":"10.2118/196026-ms","DOIUrl":"https://doi.org/10.2118/196026-ms","url":null,"abstract":"\u0000 The Montney Formation of the Western Canadian Sedimentary Basin has emerged as one of the most prolific unconventional resource plays in the North American unconventional space. The authors propose a novel method to better understand the failure mechanics associated with hydraulic fracturing through laboratory testing under true triaxial conditions. This adds essential fundamentals with respect to upscaled field hydraulic fracturing operations in the formation. A representative source rock block recovered from outcrop was prepared into a cube and hydraulically fractured in the laboratory under true triaxial stress conditions. Field outcrop mapping of this quarry has confirmed that samples collected are of the same geological time and spatially equivalent to the source rock (Zelazny et al. 2018). This novel laboratory experiment mimics a single stage open hole hydraulic fracturing using a slickwater system, composed of surfactant, friction reducer, and biocide as the injection fluid. Micro-computed tomography (μCT) scans were used to identify the presence of preexisting fractures and bedding planes. A mini-well was drilled to the center of the cube, parallel to the direction of the minimum principal stress (σ3) and along the strike of the bedding planes, such that there is a 5 mm long down-hole open cavity. The existing true triaxial test system at the University of Toronto was retrofitted to accommodate a custom designed mini-packer system. Stresses were applied hydrostatically, and then differentially until the stress regime, replicating the field observed reservoir depth at about 2 km depth, was reached. The bottom hole was subsequently pressurized by pumping the injection fluid through the mini-packer.\u0000 The test was numerically modeled in three-dimensions using the hybrid finite-discrete element method (FDEM) with the mechanical properties input determined through a series of standard laboratory rock mechanics tests discussed within. Post-test μCT of the tested cube revealed a fracture trace, and scan contrast was enhanced by injecting the cube with 5% wt potassium iodide solution. Interestingly, the highest fluid pressure recorded is slightly higher than σ3 whilst the plane of failure is normal to the intermediate principal stress (σ2) direction, which is parallel to the bedding planes. The results of the mechanical tests and hydraulic fracturing under true triaxial stress conditions reveal the significance and dominance of the macroscopic features and material anisotropy in dictating the overall strength and fracture plane orientation. Features which were unaccounted for in classical reservoir mechanics and the numerical model simulation, resulted in higher than predicted fracture initiation and propagation pressures than the laboratory experiment. This laboratory test approach allows a convenient and flexible method to capture the influence of the reservoir stress regime and its interaction with the sample anisotropy. Coupled with numeric","PeriodicalId":325107,"journal":{"name":"Day 1 Mon, September 30, 2019","volume":"110 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"131537254","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":"Evolution of Open-Hole Gravel Pack Methodology in a Low Frac-Window Environment: Case Histories and Lessons Learned From the Kraken Field Development","authors":"Kevin Alexander, D. Bruce, Colin Williamson, Nicholas Moses, E. Ismayilov, J. Sallis, Tertius De Kock, H. Sendel, Maye Beldongar, B. Gadiyar, M. Parlar","doi":"10.2118/195937-ms","DOIUrl":"https://doi.org/10.2118/195937-ms","url":null,"abstract":"\u0000 The Kraken field development was planned and executed through several batch drilling and completion phases to allow a review of each phase and incorporate the lessons learned in the next phase. All producers were drilled with an oil-based reservoir drilling fluid (OB-RDF). The lower completion with shunted sand control screens was installed in conditioned OB-RDF, followed by displacements to water-based fluids after the packer was set. Gravel packing was performed with a visco-elastic surfactant fluid, and a breaker treatment was spotted across the open hole prior to isolating the open hole with a fluid loss control valve.\u0000 This paper discusses the design, execution and evaluation of the lower completion phase for the development of the Kraken field in the North Sea. This includes detailed reservoir evaluation, methodology followed for sandface completion selection, steps taken to improve efficiency through lessons learned and continuously extend well lengths to be gravel packed in a low frac-window environment, and well performance results in this 24-well field development, with focus on the 7 out of 13 oil producers, detailing 3 of them.","PeriodicalId":325107,"journal":{"name":"Day 1 Mon, September 30, 2019","volume":"100 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"131950978","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":"Sedimentary Rock Compressibility Related to Porosity Under Hydrostatic Loading: New Approach with Uniaxial Corrections","authors":"Ricardo de Souza Fasolo, R. Misságia, M. Ceia","doi":"10.2118/196218-ms","DOIUrl":"https://doi.org/10.2118/196218-ms","url":null,"abstract":"\u0000 Rock compressibility has great influence in the original oil in place estimation, history matching, and production forecasting. The majority of the reservoir engineers consider the compressibility as a constant throughout the life of a field, but it is well known that rock compressibility is pressure and porosity dependent. During the life of an oil field, the pore pressure decreases with oil production, which increases the net pressure over the reservoir which induces changes in porosity and in compressibility. Neglect compressibility variation may induce several errors during reservoir simulation. To reduce errors, and to provide a simple and easy procedure for calculation of rock compressibility, this paper presents the correlation between rock compressibility and porosity under hydrostatic confining test, as well as the corrections made to translate unrealistic hydrostatic data into more representative uniaxial data. The measurements were developed in 5 sandstones and 5 carbonate rocks with a diversified range in porosity and rock strength to obtain results more capable to describe any other set of data. The results of the corrections were then plotted against porosity and a new general equation was derived from the plots through data fitting. The new equation proved to be very representative, but it faced an issue related to the inverse problem. To fix the problem, the Poisson ration was applied to the general equations to capture the mechanical characteristics of the rocks. The results showed that rock compressibility has a direct relation to porosity. Further, the conversion factors displayed high efficiency in the translation from hydrostatic data to uniaxial data, and hydrostatic compressibility may increase the errors during estimation of the volume of original oil in place by a factor of 1E+6 STB. Also, the error in the volume of OOIP calculated using CpA and CpAc varies from 0,22% to 0,05%, and the difference between CpA (converted) and CpAc (estimated) is around ±1,8%. Therefore, this work aims to correct the sedimentary rock compressibility obtained under hydrostatic compressional tests and establish a new relationship between compressibility and porosity. These procedures focus on the reduction of laboratory analysis, increase the quality of reservoir forecasting and reservoir monitoring.","PeriodicalId":325107,"journal":{"name":"Day 1 Mon, September 30, 2019","volume":"15 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"123274065","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 Stress Shadowing Impact on the Production Performance of Marcellus Shale","authors":"Mohamed El Sgher, K. Aminian, S. Ameri","doi":"10.2118/196005-ms","DOIUrl":"https://doi.org/10.2118/196005-ms","url":null,"abstract":"\u0000 It is very difficult to predict the hydraulic fracture properties in shale gas reservoirs, such as Marcellus shale, because of the complex nature of hydraulic fracture growth, lack of good quality reservoir information, and very low matrix permeability. Furthermore, Marcellus shale is more sensitive to stress changes caused by hydraulic fracture shadowing and the net stress increase with production. The inclusion of the stress shadowing and the geomechanical factors provide a more realistic approach to predict the production performance of the horizontal wells with multiple hydraulic fracture stages in Marcellus Shale. The objective of this study is to investigate the impact of the stress shadowing on the hydraulic fracture properties in Marcellus Shale horizontal wells and consequently the production performance.\u0000 The natural gas in the Marcellus Shale is produced most effectively by horizontal wells with multiple hydraulic fracture stages. The propagating fracture causes a stress change, commonly known as a stress shadow, in the vicinity of the fracture. The stress shadowing effects may result in a decrease in the width and conductivity of the subsequent fracture stages. In this study, a commercially available software which accounts for the stress shadowing was utilized to predict the hydraulic fracture properties based on the available information from a Marcellus Shale horizontal well. The available information included gamma ray (GR), density (RHOB), resistivity, and sonic (DTC & DTS) logs as well as the fracture stimulation treatment data. Treating pressures were calibrated by modifying the frictional parameters such as pipe friction and tortuosity factors. The predicted hydraulic fracture properties with stress shadowing effects as well as the Marcellus Shale properties were then utilized as the inputs for a reservoir simulation model in order to predict the production performance. Laboratory measurements and published studies on Marcellus shale core plugs provided the foundation for evaluating the impact of net stress on the matrix and fissure permeabilities as well as the relation between fracture conductivity and the net stress. The geomechanical factors were then incorporated in the production simulation model. Finally, parametric studies were performed to investigate the impact of fracture spacing on stress shadowing. The hydraulic fracture properties for different spacing were then incorporated in the production simulator to investigate their impact on the gas production.\u0000 The inclusion of the stress shadowing and the geomechanical factors provided a closer agreement between the simulated and actual production history for the well under study. The stress shadowing effects were found to increase with closer fracture spacing. The fracture half-length, fracture height and especially, fracture width stress were impacted by stress shadowing. Additionally, it was observed that the stress shadowing impact is more significant in Marcellus","PeriodicalId":325107,"journal":{"name":"Day 1 Mon, September 30, 2019","volume":"24 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"121219863","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":"Successful Collaboration of Vendors for Detection of Micro-Leak in Corrosion Resistant Monobore Completion And Remedial Action To Restore Well Integrity","authors":"Artur Tleulin, Claudia Porretta-Serapiglia, M. Freeman","doi":"10.2118/196024-ms","DOIUrl":"https://doi.org/10.2118/196024-ms","url":null,"abstract":"\u0000 This document describes the process of planning and the execution of the production tubing micro-leak’s location detection with the use of Spectral Noise-High Precision Temperature Logging and globally novel technology of multi-set bridge plug services and its isolation with an ISO 14310 V0 rated (bubble tight) Straddle Packer assembly, fully compliant to H2S service per NACE TM0177 / ISO 11960\u0000 Accurate location identification of communication between production tubing and annulus in the corrosion resistant monobore completion of a raw gas injector well with ultra-high concentration of H2S and CO2 led to intense research for optimal solutions to detect micro-leak location and its further remedial solution.\u0000 The micro leak exhibited unique behavior which occurred mainly in a gas phase with a long duration build-up of annulus pressure. This required a complex leak detection campaign, involving Spectral Noise-High Precision Temperature Logging as the primary method of determination, and pressure testing of tubing string with the multiset retrievable bridge plug, being set on an electric wireline at different depths, as the secondary method of leak and confirmation.\u0000 The most suitable method of isolation from a feasibility and reliability points of view was to manufacture specific H2S/CO2 resistant straddle packer capable of withstanding the raw gas injection requirements.\u0000 During the non-intrusive testing it was possible at an early stage to confirm the location of the leak above the downhole safety valve. The noise-temperature surface read-out mode logging tools were run down to safety valve depth in a liquid and gas phase, indicating a zone of suspicion. The zone of suspicion matched the tubing tally with a tubing connection.\u0000 In order to confirm the presence of micro-leak at suspected points a multiset retrievable bridge plug was utilised. The tool used was a new to market multiset bridge plug with a unique technology which gave the possibility to re-set the plug multiple times within one electric wireline run. Considering the unique behaviour of the leak which appeared mostly when a production tubing was containing a gas phase under a high pressure the pumping of nitrogen in the top section of the tubing string was performed. The Multi Set bridge plug confirmed the location of the leak flawlessly showing a perfect results of execution and reliability. Checking the zone of interest with multiset bridge plug installed across and pressure tested with nitrogen confirmed the presence of leak at a tubing joint connection.\u0000 The next step after the leak location had been identified was to restore the well integrity with the installation of V0 rated Straddle Packer, which was successfully installed at the first attempt. It is important to note the highest available grade of H2S/CO2 resistant materials (Inconel 718 and FFKM elastomer) was selected during the design, manufacturing and qualification of the Straddle Packer. Restoration of well integrity h","PeriodicalId":325107,"journal":{"name":"Day 1 Mon, September 30, 2019","volume":"379 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124727230","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 Comprehensive Microbial Assessment of Hydraulic Fracturing Stimulations using State-of-The-Art Molecular Methods: Three Western-Canadian Case Studies","authors":"Marc A. Demeter, V. Wornstaff, C. Wiggins, D. Maley","doi":"10.2118/195995-ms","DOIUrl":"https://doi.org/10.2118/195995-ms","url":null,"abstract":"\u0000 Experience has shown that hydraulic fracturing operations can introduce and/or stimulate microbial populations in the wellbore that in turn may lead to undesired corrosion, souring or other production issues. Biocides are applied to prevent the establishment of problematic microbes. Characterizing and quantifying which microbes will be introduced to a well using molecular techniques allows for optimized or even proactive treatment and prevention strategies to be implemented, whereas, traditional microbial testing methods have proven insufficient.\u0000 Once the standard for microbial assessments in the oil and gas industry, culture media bottles are now just one of many available tests. Tests vary by their resolution (culturable, active and living, total microbes), and the information they yield. Some tests target very specific microbial subgroups of concern (culture media, qPCR), while others evaluate all microbes within the sample (ATP, qPCR, 16S rRNA sequencing). In the case studies presented, water and produced fluids were collected from all pertinent frac sample points (source waters, pre- and post-chem and post completions) and were assessed using the suite of microbial methods stated above.\u0000 Three case studies are presented with several noteworthy observations regarding the value microbial tests provide to frac operations. First, culture media-based testing consistently resulted in incoherent and confusing data that failed to correlate with the remaining testing technologies. Second, ATP technology provided efficient and timely testing which lent itself well to on-site, evidence-based decision making. During one of the fracs, ATP results were used to modify and optimize a microbial control program on-the-fly. Third, DNA-based testing (qPCR and 16S rRNA sequencing) provided the most comprehensive insight into the microbial communities exposed to the well, and those that established post-completions.\u0000 Overall, holistic microbial testing offers the user key information required to design and implement successful microbial control programs for frac. Without it, microbial issues plagued production efforts. Culture media tests provided limited and unreliable information and were deemed not suitable for frac operations. ATP provided a useful microbial load in real-time but could not elucidate the types of microbes present. DNA testing filled this gap by providing quantities and types of microbes present.\u0000 Apart from assessing microbial control programs during the frac, monitoring the production fluids is essential to assuring continued well performance. The acknowledgment of the role microbes play in well completions, and the testing technology to evaluate oilfield microbes is rapidly advancing. Here we present some of the first case studies highlighting the use of molecular, DNA-based technology for assessing hydraulic fracturing operations and showing the fallacy of culture media-based testing which is the current industry standard.","PeriodicalId":325107,"journal":{"name":"Day 1 Mon, September 30, 2019","volume":"87 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124416586","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":"100th Intelligent Completion Installation: A Milestone in Brazilian Pre-Salt Development","authors":"E. Schnitzler, L. F. Gonçalez, Roger Savoldi Roman, Djalma Atanásio Santos da Silva Filho, M. Marques, Ricardo Corona Esquassante, N. J. Denadai, Manoel Feliciano Silva, Fábio Rosas Gutterres, Danilo Signorini Gozzi","doi":"10.2118/195935-ms","DOIUrl":"https://doi.org/10.2118/195935-ms","url":null,"abstract":"\u0000 Pre-salt heterogeneous carbonate reservoirs typically present long net pays, high production/injection rates and some flow assurance risks. This paper presents general information, results and lessons learned regarding the installation of Intelligent Well Completion (IWC) in Santos Basin Pre-Salt Cluster (SBPSC) wells. It also presents some important improvements to be introduced in the future IWC systems specification and qualification based on the lessons learnt in these projects, setting some new challenges to the industry.\u0000 The benefits expected with the use of IWC are achieved at the expense of challenging well engineering, since well completion design becomes more complex and well construction risks increase. Detailed and integrated planning is essential for the success of the operations, starting at the earliest phases of the well design and continued through detailed execution plans. The use of standardized practices and procedures has led to significant increases on installation performance. On the other hand, an open mind and a constant search for improvements allowed new solutions and procedures to be developed throughout the years. Regarding the system integration, a flexible and standardized control architecture was developed to allow combining different IWC providers and subsea vendors, which proved to be a successful approach.\u0000 The most important improvement in IWC installation was the anticipation of the acid stimulation, nowadays performed before the vertical Wet Christmas Tree (WCT) installation. In order to achieve this goal some crucial improvements were gradually implemented in the stimulation practices, such as, an initial injectivity increase solution and some new acid diversion solutions, which allowed eliminating the use of coiled tubing and, as a consequence, the need of a subsea test tree. The well design team conducted an integrated risk assessment to properly evaluate the new practices and establish some actions to reduce the risks. Intense communication between production zones was observed during the acid job in some of the initial wells, ruining the gains of the IWC. After a comprehensive analysis, some possible causes were identified and with the new stimulation practices this issue was eliminated.\u0000 Over the years, with the introduction of several improvements, some of them presented in this paper, the well completion duration was reduced to less than 50% of the one observed in the initial wells. This major performance increase has been essential to keep this deepwater projects feasible, especially in the oil scenario seen in recent years. Some of the new practices and lessons learned in this 100 wells equipped with IWC has set groundbreaking practices for Brazilian pre-salt fields development and may stand as a reference for the industry in similar deepwater projects. Additional requirements for future systems are expected to improve even further the performance in this scenario.","PeriodicalId":325107,"journal":{"name":"Day 1 Mon, September 30, 2019","volume":"13 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125517582","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}