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Yan, Shi (School of Civil Engineering, Shenyang Jianzhu University) | Wu, Jianxin (School of Civil Engineering, Shenyang Jianzhu University / Shandong Electric Power Engineering Consulting Institute Co., Ltd.) | Wang, Xuenan (School of Civil Engineering, Shenyang Jianzhu University) | Zhang, Shuai (School of Civil Engineering, Shenyang Jianzhu University / CSCEC Jinan Architectural Design Institute Co., Ltd)
In order to apply a PZT-based pipeline structure damage detection technology in engineering, in this paper, a PZT wave-based active detection technology as theoretical foundation was used, combining with the characteristics of pipeline structure cracking, to develop a new type of portable detection system, which is based on virtual instrument (VI) technology. The developed system was validated through testing, and the results indicated that the system is stable and reliable, enabling to identify different crack damage states of pipeline structures in real-time and online. The proposed damage detection system can be used in pipeline structures with the low cost, portable, rapid diagnose and high-precision characteristics.
Pipeline structure has been widely used in petroleum, chemical, electric power, and natural gas industries, etc. However, due to environmental impacts or man-made disoperation pipeline will have cracks, corrosion and other defects, which will cause a great threat to the pipeline system safe operation, especially in the event of an accident, will cause huge economic losses and environmental pollution. To avoid possible accidents and ensure the safe use of pipeline structures, periodic safety inspections or long-term health monitoring of the piping system are of particular and great importance. Due to characteristics of long distance and large area of pipeline structures, applications of commonly used nondestructive testing (NDT) technologies are greatly restricted. At present, a new non-destructive testing method - the use of a piezoceramic active wave sensing detection technology for pipeline structures is gradually developed and good results are achieved (Song, Gu and Mo, 2008; Song, Gu and Mo, 2007; Song, Gu and Mo, 2006; Du, Kong, Lai and Song, 2013; Gazis, 1959; Alleyne and Cawley, 1996; Yan, Sun, Song, Gu, Huo, Liu and Zhang, 2009; Silk and Bainton, 1979; Lowe, Alleyne and Cawley, 1998; Park and Payne, 2011).
Piezoceramics, (such as Lead Zirconate Titanate, PZT), is a kind of intelligent material with sensing and driving dual characteristics. It is simple in manufacture, high in strength, resistant to moisture, heat and frequency response, etc. Due to a unique piezoelectric effect, the PZT material can be used as both a sensor element and an actuator component. The basic principle of the active detection technology applying the PZT wave based method is using the piezoelectric effects of piezoceramics to manufacture transducers which are arranged in the detected structures in a form of array for transmitting and receiving detection signals, thereby establishing an excitation and sensing channel. Based on the received data combining with a special damage detection algorithm, a structural damage identification and diagnosis can be realized by analyzing the signal difference between the healthy structure and the damaged one. The principle is shown in Fig. 1.
Methane (CH4), the primary constituent of natural gas and is the second-most abundant greenhouse gas after carbon dioxide (CO2), accounts for 16% of global emissions. The lifetime of methane in the atmosphere is much shorter than CO2, but CH4 is more efficient at trapping radiation than CO2. Pound for pound, the comparative effect of CH4 is more than 25 times greater than CO2 over a 100-year period. Natural-gas emissions from oil and gas facilities such as well sites, refineries, and compressor stations can have significant safety, economic, and regulatory effects. Continuous emission detection systems enable rapid identification and response to unintended emission events.
Al Gharbi, Salem (King Fahd University of Petroleum & Minerals) | Al-Majed, Abdulaziz (King Fahd University of Petroleum & Minerals) | Abdulraheem, Abdulazeez (King Fahd University of Petroleum & Minerals) | Patil, Shirish (King Fahd University of Petroleum & Minerals) | Elkatatny, Salaheldin (King Fahd University of Petroleum & Minerals)
Drilling is considered one of the most challenging and costly operations in the oil and gas industry. Several initiatives were applied to reduce the cost and increase the effectiveness of drilling operations. One of the frequent difficulties that faces these operations is unexpected drilling troubles that take place and stops the operation, resulting in losing a lot of time and money, and could lead to safety issues culminating in a fatality situation. For that, the industry is in continues efforts to prevent drilling troubles. Part of these efforts is utilizing the artificial intelligence (AI) technologies to identify troubles in advance and prevent them before maturing to a serious situation. Multiple approaches were tried; however, errors and significant deviation were observed when comparing the prediction results to the actual drilling data. This could be due to the improper design of the artificial intelligent technology or inappropriate data processing. Therefore, searching for dynamic and adequate artificial intelligent technology and encapsulated data processing model is very essential.
This paper presents an effective data-mining methodology to determine the most efficient artificial intelligent technology and the applicable data processing techniques, to identify the early symptoms of drilling troubles in real-time. This methodology is CRISP-DM that stands for Cross Industry Standard Process for Data Mining. This methodology consists of the following phases: Business Understanding, Data Understanding, Data Preparation, Modeling, Evaluation and Deployment. During these phases, multiple data-quality techniques were applied to improve the reliability of the real-time data.
The developed model presented a significant improvement in identifying the drilling troubles in advance, compared to the current practice. Parameters such as hook-load and bit-depth, were studied. Actual data from several oil fields were used to develop and validate this smart model. This model provided the drilling engineers and operation crew with bigger window to mitigate the situation and resolve it, prevent the occurrence of several drilling troubles, result in big time and cost savings. In addition to the time and cost savings, CRISP-DM provided the artificial intelligent experts and the drilling domain experts with a framework to exchange knowledge and sharply increase the synergy between the two domains, which lead to a common and clear understanding, and long-term successful drilling and AI teams collaboration.
The novelty of this paper is the introduction of data-mining CRIPS methodology for the first time in the prediction of drilling troubles. It enabled the development of a successful artificial intelligence model that outperformed other drilling troubles prediction practices.
Jing, Cui (Sichuan Changning Natural Gas Development Co., Ltd.) | Chen, Yanyan (Schulmberger) | Jing, Xianghui (Research Institute of Exploration and Development, PetroChina Changqing Oilfield Company) | Wang, Bing (Schulmberger) | De, Heng (Sichuan Changning Natural Gas Development Co., Ltd.) | Huang, Zheyuan (Schulmberger) | Wen, Ran (Sichuan Changning Natural Gas Development Co., Ltd.) | Zhang, Caiyun (Schulmberger) | Zhou, Nie (Sichuan Changning Natural Gas Development Co., Ltd.)
The highly complex geology of the Sichuan Shale gas play, especially in relation to natural fracture systems at different scales, affects the hydraulic completion efficiency and performance. Ant-tracking-based workflows and borehole image data are regularly used to optimize completion campaigns, but bridge-plug-stuck and screen-out risks are still high. The lack of sufficient understanding and accurate identification of the natural fracture systems are the major challenges to address these engineering risks.
Surface microseismic monitoring campaigns were conducted over several wells of the Changning field, Sichuan Basin, China. The surface receivers were placed in a radial pattern to record microseismicity generated by hydraulic fracturing. The failure mechanism of all mapped microseismic events (i.e., strike, dip, rake, etc.) was extracted using a moment tensor inversion (MTI) method. Improved understanding of the natural fracture systems and their influence during the hydraulic fracturing process has been achieved by integrating the regional geological data, pumping data and MTI results.
Several hydraulic fracturing cases that stimulated near natural fracture systems were investigated. The microseismic monitoring results show that (i) most of the hydraulically induced fractures located in the vicinity of the natural facture or fault did not propagate along the regional maximum stress direction, (ii) the bridge plug got stuck and (iii) screen-out happened frequently in these areas. Moment tensor inversion reveals that (i) the dominant failure mechanism of the natural fractures different from hydraulically induced fractures, (ii) more than one group of natural fractures develop along different directions.
Real-time adjustments of the pumping schedule and bridge-plug settings were conducted to reduce engineering risks based on the improved understanding of natural fractures, which proved effective. The innovation of using surface microseismic monitoring results to improve understanding of natural fractures and reduce the engineering risks in real time represents a key step forward to mitigate natural fracture influence and improve the effectiveness of stimulation.
Oka, Fabian (Petronas) | Orient, Samuel (Petronas) | Farhan, Suratman (Petronas) | Hazim, Kamarulzaman (Petronas) | Haydn, Brendt Sinanan (Petronas) | Sylvia, Mavis Ak James Berok (Petronas) | Tomaso, Ceccarelli (Schlumberger) | Supakit, Rugsapon (Baker Hughes) | Jennie, Chin Pui Ling (Schlumberger) | Maisara, Arsat (Schlumberger)
Located in the South China Sea, B oil field was first discovered in 1971 and has been in production since 1982; it is located in offshore of Sarawak, Malaysia, with a water depth of approximately 70 metres. The field has an interval of over 7000 ft. of stacked reservoir sands and thin continuous shale layers, making up approximately 165 individual reservoir units with Late Miocene to Early Pliocene in age, with the stratigraphic intervals reservoir section.
With the objective to find a technically and economically viable enhanced oil recovery (EOR) development concept for B oil field, a feasibility study was conducted by taking several EOR strategies into considerations – low-salinity waterflood, chemical EOR, and immiscible water alternating gas (IWAG). By evaluating individual layers of the field, the study concluded with a recommendation to implement EOR via IWAG on EF reservoirs on the basis of value, timeline, and flexibility for future EORs; IWAG would yield the best result from technical and economical point of view, and also with the ability to be implemented as earliest as possible.
The theory behind IWAG implementation in the field is that the gas component of IWAG injection will help to sweep oil that is left along the top of reservoir sands due to poor water-oil mobility ratio and gravity effects, and due to the fact that gas moves quickly in the reservoir, the water component of IWAG injection will come into assistance by controlling gas mobility and maintaining reservoir pressure as more drainage points are introduced into the reservoir. Additionally, water injection provides the control to improve the aquifer's sweep, three-phase hysteresis effects and reduced residual oil (in gas) is expected to improve recovery mobilizing more oil in the reservoir, and gas injection may also assist to drain oil that are trapped in attic accumulations. In B field, IWAG injection involves gas and water injections into wells that are located down-dip of the reservoir.
Out of four IWAG injector wells in the recent B field drilling campaign, one well was selected to be equipped with a Distributed Temperature Sensing (DTS) system after considering the following benefits that the DTS system would provide:
Conformance monitoring specifically for water to qualitatively identify which sand the water is being injected to or any potential internal crossflow Quantitative flow into each reservoir layer derived from warm-back analysis for the short term and hot-slug propagation for the long term instead of running wireline production logging tool (PLT) Hydraulic fracturing profiling to prevent the formation from fracturing unintentionally due to the water hammer effect or cooling of formation with injection water (i.e., thermal fracture); inversely, when zonal fracturing is intentional and required, profiling to gauge effectiveness and fracture spread Real-time injection issues or zonal anomaly identification to eliminate the need to perform well intervention to obtain information which often results in delayed action Injected gas or water fluid front monitoring when combined with existing DTS in producer wells Reduced intervention risks in a highly deviated well that could lead to fish in hole and potential workover
Conformance monitoring specifically for water to qualitatively identify which sand the water is being injected to or any potential internal crossflow
Quantitative flow into each reservoir layer derived from warm-back analysis for the short term and hot-slug propagation for the long term instead of running wireline production logging tool (PLT)
Hydraulic fracturing profiling to prevent the formation from fracturing unintentionally due to the water hammer effect or cooling of formation with injection water (i.e., thermal fracture); inversely, when zonal fracturing is intentional and required, profiling to gauge effectiveness and fracture spread
Real-time injection issues or zonal anomaly identification to eliminate the need to perform well intervention to obtain information which often results in delayed action
Injected gas or water fluid front monitoring when combined with existing DTS in producer wells
Reduced intervention risks in a highly deviated well that could lead to fish in hole and potential workover
Kirthi Singam, Chandrasekhar (Schlumberger) | Hafezi, Farshid (Schlumberger) | Rebello, Clyde (Schlumberger) | Bartul, Miroslav (Schlumberger) | Ali, Anis (Schlumberger) | Naveed, Muhammad (Schlumberger)
The emergence of Real-Time Well Construction Performance Monitoring Centers has significantly improved the service delivery for Operators across numerous offshore oil fields in Australia. New technologies and workflows were implemented for 3 Australian offshore wells, with the primary objective being to improve drilling efficiency while managing the associated risks. Additional objectives included optimizing daily operational performance, thus delivering time savings for the Operator and highlighting areas of possible improvements.
The workflows combined proven technologies, software and wellbore surveillance services, which delivered risk-free wells ahead of Authority for Expenditure (AFE), by targeting the reduction of nonproductive time (NPT) and invisible lost time (ILT), together with risk management.
The workflow began with a preliminary field analysis to identify the main challenges and areas that needed improvement. The key learnings were then consolidated on a comprehensive drilling road map by well section that outlined prevention and mitigation measures, expected rate of penetration (ROP) and recommended drilling parameters. The study also identified performance benchmarks such as average and on bottom ROP and connection time. Key performance indicators (KPI) were developed to monitor progress and track the well with respect to well improvements versus the benchmarks identified. The selection of the monitoring tools and modules required during the Execution Stage were developed based on the risks and KPIs identified during the field study and were further tailored to target specific challenges such as stuck pipe prevention, hole cleaning, shock and vibration and connection time.
The workflows enabled the flawless execution of 3 offshore wells 29.0 days ahead of AFE which saved the Operator USD 15.5M. The closed loop monitoring enabled real time interventions which aided in preventing risks such as stuck pipe, ensured efficient shoe-to-shoe drilling and avoided potential lost-in-hole (LIH) costs. This case study demonstrates the use of a novel approach to increase well construction efficiency by eliminating lost time while enhancing risk control. The main basis for success of this workflow was using existing and cost-effective technologies while capitalizing on the renewed synergy between different departments such as Drilling, Mudlogging and Well Operations analysis.
The workflow was and can be customized based on different needs, by combining specific modules for monitoring, analysis and wellbore surveillance services, to increase the efficiency of any well construction.
Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract The supergiant field under study is one of largest oil producers in Middle East and been producing for more than 50 years from a multilayered carbonate reservoir. Long-term sustainability of production of the field is a key mission for the field operator and national oil company, considering both productivity and recovery of the field. Gas lift has been considered as an effective and economically feasible method to increase production of the wells and as a solution to revive the closed wells and to maintain the production of flowing wells.
Hohl, Andreas (Baker Hughes) | Kulke, Vincent (Institute of Dynamics and Vibrations, TU Braunschweig) | Kueck, Armin (Baker Hughes) | Heinisch, Dennis (Baker Hughes) | Herbig, Christian (Baker Hughes) | Ostermeyer, Georg-Peter (Institute of Dynamics and Vibrations, TU Braunschweig) | Reckmann, Hanno (Baker Hughes)
Vibrations impact the drilling process by reducing reliability, increasing maintenance costs and reducing rate of penetration and drilling efficiency. Herein, torsional vibrations are typically distinguished into low-frequency torsional oscillations and stick/slip with frequencies below 1 Hz and high-frequency torsional oscillations (HFTO) with frequencies up to 450 Hz. HFTO is associated to high accelerations with critical values above 150 g and dynamic torsional torque values above the make-up torque. A HFTO mitigation strategy is mandatory for prone applications to guarantee high reliability and drilling efficiency.
In this work different best practices for mitigation of HFTO and their interdependency are discussed along with their operational efficiency. The discussed scenarios include coupling between stick/slip and HFTO, different formation properties, and tools that are used for vibration mitigation such as isolators and mud motors. The analysis includes the review of time-based acceleration and load data with a sampling frequency of 1000 Hz and 2500 Hz and numerical modeling to determine the application and environment specific critical range of operational parameters in a holistic approach. The extracted critical range of operational parameters enables operations to optimally adjust parameters with a minimum of torsional loads and optimal drilling efficiency.
This analysis again unveils that the general effect of HFTO is triggered by the cutting forces between PDC bits and hard and dense formation. It is shown qualitatively and quantitatively that high WOB values and low rotary speed values correspond to HFTO. The case study shows opportunities of a reduction of HFTO related loads by increase of the rotary speed without compromising the ROP in specific applications and environments. It is shown that special tools for vibration mitigation influence the stable operational window and need to be considered.
Depending on the scenario a complete mitigation of HFTO or at least a significant reduction of loads can be achieved by targeted adjustment of operational parameters and use of tools for vibration mitigation. The drilling process can be optimized leading to a reduced cost of the well delivery since HFTO can be a major cause for non-productive time if not handled properly.
Coiled tubing (CT) intervention in a subhydrostatic gas injector well carries several challenges. For example, excessive fluid leakoff during a CT sand cleanout operation requires nitrifying the cleanout fluids to achieve a stable solid return rate, which necessitates a huge volume of liquid nitrogen. For perforation with CT, methods of activating the firing head are limited because the fluid column in the well cannot be sustained if a hydraulically activated firing head is used.
Alternatively, cleanout operations for such wells can be done by pushing all the solids into the formation instead of taking returns through surface solids-handling equipment. For this case describing such an operation, real-time downhole measurements were used to accurately determine the top of fill, monitor for signs of formation plugging during the cleanout, and detect sudden increases in downhole overpull indicating solids starting to plug around the bottomhole assembly (BHA). The fiber optic telemetry within the real-time CT system also enabled use of an electrical firing head powered by downhole batteries, which allows CT perforation without the need to pump fluids.
The method of cleanout by injecting into the formation through a sacrificial open perforation can be considered an unconventional CT intervention. Solvent was used with a high-pressure jetting tool to break down asphaltene residues across the open perforation before injecting into the formation at high flow rate. Real-time downhole weight measurements on the BHA provided valuable information to continuously locate the top of fill because the depth changes as the solids are pushed into the formation. This cleanout method reduced the equipment footprint on the offshore installation since no surface solids-handling equipment was needed. Early detection of formation plugging through real-time monitoring of downhole pressure eliminates the need to take solid returns to the surface production separator because the injection flow rate was adjusted in real time before gaining back the desired leakoff as pressure built in the wellbore to create a breakthrough. The ability to add new perforations with the same CT setup and using a fiber-optic–enabled electrical firing head avoiding the need to replace CT with wireline equipment, increasing the overall efficiency and saving more than 48 hours of operational time. Downhole measurements were also used to correlate depth and indicate perforation gun firing.
The newly perforated zone contributed 13% of the injected gas into the targeted formation and no further intervention was required after the CT cleanout and perforation. The underbalanced perforation for the new zone was critical to minimize near-wellbore damage for this gas injector well. Two surrounding producers that were not producing before have benefited from this CT intervention, producing hydrocarbon at 500 Sm3/d and 350 Sm3/d post-intervention.
Cheng, Zhong (Xi'an Shiyou University and CNOOC Ener Tech-Drilling & Production Co.) | Xu, Rongqiang (CNOOC Ener Tech-Drilling &Production Co.) | Yu, Xiaolong (CNOOC Ener Tech-Drilling &Production Co.) | Hao, Zhouzheng (CNOOC Ener Tech-Drilling &Production Co.) | Ding, Xiangxiang (CNOOC Ener Tech-Drilling &Production Co.) | Li, Man (CNOOC Ener Tech-Drilling &Production Co.) | Li, Mingming (CNOOC Ener Tech-Drilling &Production Co.) | Li, Tiantai (Xi'an Shiyou University) | Gao, Jiaxuan (Xi'an Shiyou University)
Upstream Oil & Gas industry recognizes that there are significant gains to be had by the implementation of new digital technologies. For offshore exploration and development, the goal is to bring together all domains, all data, and all engineering requirements in a seamlessly interconnected solution. 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. an innovative digital solution has been designed and implemented to cover all different aspects of the well planning and engineering workflows, delivering a step change in terms of capabilities and efficiency.
As part of this transformation process, CNOOC have implemented integrated data management project of geological engineering for covering all different aspects of the well engineering workflows, delivering a step change in terms of capabilities and efficiency. The objective is to provide a continuous improvement platform to users for:
Digitalization can reduce the time spent with daily documentation and simultaneously increase the quality by removing an error prone way of work.
Technological solution enabling real-time data transmission from all rigs to CNOOC onshore headquarters and enabling real-time visualizations of the drilling data. This includes workload, number of needed rigs, daily performance, key performance indicators and even operation time forecasts based on real data.
Engineering solution to transform expert experience and accident cases into information to easily identify the areas of operational improvement allowing to implement specific measures to reduce intangible loss time (ILT) and non-productive time (NPT) which can help in reducing costs.
This project has also provided a real geological drilling environment where high frequency real-time drilling 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 risk.
This paper presents a full description of a new industry standard digital well construction solution that has the potential to transform the well operation process by providing a step change in collaboration, concurrent engineering, automation, and data analytics. Furthermore, the cloud-deployed solution challenges will be briefly discussed.
The learned lessons and gained experiences from this project construction presented here provide valuable guidance for future demands E&P and digital transformation.