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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.
The fiber-optic distributed temperatrue sensor (DTS) has been used for flow profiling in horizontal multi-stage fractured wells, and there were some reservoir/wellbore coupled thermal models presented by researchers. Although current theoretical models are developed for some certain application scenarios, the industry have realized the great potential of DTS for production prediction in unconventional resources. This paper presents a DTS flow profiling case for a horizontal multi-stage fractured well in tight gas reservoirs with open-hole packer completion scenarios by applying a newly improved theoretical model.
In this paper, we started with the conventional semi-analytical wellbore-fracture-reservoir coupled flow/thermal model which have been developed for cased, perforated, and multi-stage fractured wells, and revised it to consider the special feature of openhole packer completion scenario. Since the formation fluid firstly flows through the fracture into the open-hole annular space between formation and the packer liner, then flow along the annular space until meet the frac port on the production pipe, we add a simulation sub-region representing open-hole annular which helps to understand the flow and heat transfer inside it. The presented model successfully simulated the two-fold flow regime caused by the simultaneous flow and heat transmission in the annular space and the production pipe. In each stage, the DTS temperature data possibly show double drops due to Joule-Thompson cooling effects at the fracture and frac port locations if they are not consistent.
With the improved mathematical model, DTS monitoring data during a three-rate production test in a horizontal multi-stage fractured well in Erdos Basin of China was simulated and analyzed. The improved model with open-hole packer completion was applied and then the gas rate prediction was accomplished.
In this case study, high resolution temperature array data, acquired during a Drill Stem Test (DST), were able to identify and quantify flow behind the liner. Quantifying the flow rate behind the liner between the production zones was of significant value to the operator to reduce the uncertainty in the Pressure Transient Analysis (PTA).
The high resolution temperature array was deployed clamped to the outside of the Tubing Conveyed Perforating (TCP) guns, which were used to selectively perforate multiple zones. Using wireless acoustic technology the temperature data were transmitted to surface to enable real time feedback during the DST. A novel thermal heat exchange model was built that could take advantage of the high resolution temperature array data acquired during the entire test. The results of the model were compared to the real data to validate the results and provide accurate flow rate measurements of the flow behind the liner in real time during the test. A sensitivity study on the various model input parameters was also carried out to reduce the uncertainty in the thermal model, the results of which are detailed within the paper. Being able to quantify the flow behind the liner allowed the operator to adjust their PTA results and provided a more robust reservoir model.
Typical thermal models in the industry are unable to quantify flow behind the liner in this environment. A new thermal model had to be developed that could take into account the complex heat transfer processes and take advantage of the high resolution thermal array data acquired during the DST. Despite the challenging wellbore environment during the test, the high resolution temperature data were used to provide a robust zonal flow confirmation and rate allocation during the flow periods.
Whilst Distributed Temperature Systems (DTS) are gaining popularity in the oil and gas industry, typically the current technology does not provide the high resolution required to be able to quantify flow behind the casing. This new model, when combined with high resolution thermal array data, has wide ranging applications not only during the DST but also in long term completions where monitoring well integrity is a real industry challenge.
Wang, Quanbin (Research Institute of Petroleum Exploration and Development, CNPC) | Jia, Deli (Research Institute of Petroleum Exploration and Development, CNPC) | Hu, Gaixing (Oil& Gas Engineering Institute of ChangqingOilfield, CNPC) | Sun, Fuchao (Research Institute of Petroleum Exploration and Development, CNPC) | Zhang, Jiqun (Research Institute of Petroleum Exploration and Development, CNPC)
Zonal water injection technique has been proved an effective method for enhanced oil recovery of multi-layer heterogeneous oil reservoirs. Higher zonal injection qualified rate is an important index for improving the effect of waterflooding development, so frequent monitoring and adjusting flowrate of separated layer is necessary. However, when traditional zonal water injection techniques are used, periodic flowrate testing and adjusting are realized by an armored cable with steel wire, which lead to a large number of testing work. This paper proposes a smart zonal water injection system based on pressure wave downhole communication technique. In this system, an integrated water distributor and a wellhead control device with pressure sensor and flow regulated assembly is developed. Continuous pressure wave can be generated by controlling the opening of downhole water distributor and wellhead control valve, and the pressure changes in wellbore can be monitored by sensors. Based on the time shift keying coding and decoding techniques, control command and downhole monitoring data are loaded into the continuous pressure wave. The pressure wave communication between wellhead control valve and downhole water distributor can be realized with injection water as the medium. With the help of General Packet Radio Service (GPRS) and Internet technology, the smart system can also be used for remote monitoring of downhole parameters and remote regulating of zonal flowrate. The smart technique for zonal water injection wells has been implemented in 89 wells in China National Petroleum Corporation (CNPC) Changqing M1 Block. Testing and adjusting work by testing vehicle in traditional zonal water injection technology is eliminated. The results of 27 tracked wells show that the maximum effective distance of pressure wave communication is 2879 m, the minimum pressure change that can be identified is 0.5 MPa, and the time of uploading a flowrate data takes 70 min. The effect of waterflooding development is improved after applying the smart technique. Zonal injection qualified rate is improved from 63.6% to 90.3%. Reservoir water absorption thickness is increased from 18.5 m to 19.4 m. Reserves producing degree of waterflooding development is improved from 68.7% to 70.2%. Natural decline rate is reduced from 5.2% to 4.8%. This paper illustrates a technology of pressure wave downhole communication for smart zonal water injection and an integrated case study, which can obtain vast amounts of real-time pressure data, and help reservoir engineers adjust development plan of waterflooding reservoirs. In addition, it offers a methodology for downhole wireless control.
Surveillance of well work-overs and downhole operations is not trivial but is becoming increasingly feasible with recent improvements in the technology of fibre optics. Well cementing operations are critical for providing zonal isolation over the life of a well. However, there are limited downhole options to monitor and inform operations in real-time. Installing a permanent fibre optic cable enables surface to reservoir permanent surveillance. In this work, fibre optic cables were deployed in 4 different wells using different configurations and test passive and active distributed temperature sensing (DTS) setups to interpret the quality of the cement injection and hydration processes.
Well cementing can occur during well installation and decommissioning. For 3 wells, fibre optic sensing cables were installed for the purpose of monitoring the casing cementing installation, detect zones of isolation and any background lateral flow in the formation.
For one of the well, fibre optic cables were installed inside casing to monitor a full wellbore decommissioning cementing operation. Following the same process, datasets were acquired prior to and during cement injection.
Dataset acquired during mud circulation highlights interval of thief zones and potential leakage zones for the cement into the formation. The real-time surveillance of cement injection informs about the top of cement but also the in-fill of breakout intervals and the blockage of thief zones.
The long-term surveillance of the vertical temperature distribution enabled to determine the timing and intensity of the cement hydration process and provided a unique insight on the quality of the cementing operations and its possible correlation to breakout intervals and thief zones.
Active DTS was also used to confirm the completion installation as temperature diffuses differently depending on the presence or absence of gravel pack and the thickness of the cement sheath.
Our results show that downhole surveillance of cementing operations is possible using DTS. This technology enables high vertical accuracy in real-time and long-term surveillance providing insights on the quality of the cement bond. In this case study, DTS has proven to be a very valuable and reliable tool throughout the cementing operations at 4 wells.
Minggu, Nur'ain (PETRONAS Carigali Sdn Bhd) | Kamarulzaman, Ammar (Schlumberger WTA Malaysia Sdn Bhd) | Riyanto, Latief (PETRONAS Carigali Sdn Bhd) | Ting, Chang Siong (PETRONAS Carigali Sdn Bhd) | Kamat, Dahlila (PETRONAS Carigali Sdn Bhd) | Ho, Dylan Zhe Xin (PETRONAS Carigali Sdn Bhd) | Zamdy, Siti Nurdyana (PETRONAS Carigali Sdn Bhd) | P. Mosar, Nur Faizah (Schlumberger WTA Malaysia Sdn Bhd) | Kalidas, Sanggeetha (Schlumberger WTA Malaysia Sdn Bhd) | Tan, Chee Seong (Schlumberger WTA Malaysia Sdn Bhd)
This study aims to validate and track valve positions for all the zones applying recorded distributed temperature sensing (DTS) data interpretation to propose the best combination of downhole inflow control valve (ICV) openings to optimize Well X-2 multizone commingled production. Fiber DTS is relied on as an innovation against downhole conditions that has compromised the three out of four downhole dual-gauges and valve position sensors.
For zonal water control purpose, ICV cycling and positioning have been attempted in 2019. The valve position tracking derived from the compromised downhole dual gauges and valve position sensors does not tally with the surface flow indication overall. Consequently, the original measurement intention of the fiber DTS as back-up zonal-rate calculation profiling and as potential sub-layer flow-contribution indicators is brought in as contingency zonal valve-opening tracking and guide that proved valuable for subsequent production optimization.
Downloaded DTS data is depth matched and validated against known operating conditions like time of each cycling stage and surface well test parameters (i.e. Liquid Rate, Watercut, Tubing Head Pressure (THP), Total Gas, Gas-Oil Ratio (GOR)), etc. To establish a baseline, several DTS traces of historical operating condition during a known stable period were selected, i.e. stable flowing condition at only Zone 4 stable shut-in condition at surface with only ICV Zone 4 is opened
stable flowing condition at only Zone 4
stable shut-in condition at surface with only ICV Zone 4 is opened
Downhole valve-position tracking can be interpreted alternatively from induced fiber temperature activities across the valve depth with a good temperature baseline benchmarking from DTS temperature profiling. In one of these alternative interpretations based on fiber temperature, it is found and validated that Zone 1 ICV is Closed, Zone 2, 3 and 4 are in opened position and continuously producing at any cycles. This is in conflict of zonal production control understanding initially based on the compromised downhole sensor indicating that all the zonal valves are supposedly in fully closed position.
In this case-study, DTS data has been proven useful and as an innovative alternative to determine downhole valve opening with analogue to flow contribution derivation methodology. Therefore, anytime in the future where Well X-2 valves cycling is planned to be carried out, there is a corresponding operating procedure that needs to incorporate onsite real-time DTS data monitoring to validate tracked valves positioning.
Minggu, Nur'ain (Petronas Carigali Sdn Bhd) | Ting, Chang Siong (Petronas Carigali Sdn Bhd) | Ho, Dylan Zhe Xin (Petronas Carigali Sdn Bhd) | Kamat, Dahlila (Petronas Carigali Sdn Bhd) | Riyanto, Latief (Petronas Carigali Sdn Bhd) | Zamdy, Siti Nurdyana (Petronas Carigali Sdn Bhd) | Kalidas, Sanggeetha (Schlumberger WTA Malaysia Sdn Bhd) | Tan, Chee Seong (Schlumberger WTA Malaysia Sdn Bhd) | Kamarulzaman, Ammar (Schlumberger WTA Malaysia Sdn Bhd) | Malaniya, Georgy (Schlumberger) | Kortukov, Dmitry (Schlumberger)
As part of the reservoir monitoring effort in Field X (Offshore East Malaysia), five oil producers were deployed with double-ended fiber optics cable across reservoir sections and permanent downhole gauges (PDG). Each well has between 2 to 4 zones. This has enabled various distributed temperature sensing (DTS) benefits such as gas-lift monitoring, well integrity, zonal-inflow profiling, and stimulation job evaluation, etc. This paper demonstrates and discusses the approach of incorporating both DTS & PDG data in Well B-1 to intrepret temperature signatures andanomalies during recent tubing-integrity tests, matrix acidizing and post-job production performance. Well B-1 is a gas lifted well that consists of three zones, and its production has been declining over years due to potential formation damage during drilling and fines migration issue. Hence, Well B-1 has been selected for matrix acidizing treatment to enhance the productivity. Prior to execution of the acidizing job, several conformance jobs such as tubing-integrity tests, injectivity test, and tubing pickling were performed. A baseline temperature was acquired to assist in the evaluation.
Due to operational challenges, the DTS data transmission wasn't acquired in real-time. However, each event's temperature profile has been studied thoroughly against the actual event schedule. Some significant findings are i) completion accessories effect (feedthrough packers) creates temperature anomalies, and ii) several leak points detected mainly between two upper zones where there was significant cooling effect due to injected fluid. The first-stage main treatment was conducted focusing on Zone 3. Due to leak points between the two upper zones, Zone 3 didn't get the designated main treatment volume. Second-stage main treatment, Zone 1 & 2 were treated together due to time constraint unlike Zone 3.
Post job production temperature profiles showed significant changes in the flowing temperature slope compared to pre-treament profile where there is an increase in overall wellbore temperature indicating increase in liquid volume and Zone 2 indicating higher Joule-Thompson cooling effect (more gas production).
Minggu, Nur’ain (PETRONAS Carigali Sdn Bhd) | Kamarulzaman, Ammar (Schlumberger WTA Malaysia Sdn Bhd) | Ting, Chang Siong (PETRONAS Carigali Sdn Bhd) | Kamat, Dahlila (PETRONAS Carigali Sdn Bhd) | Riyanto, Latief (PETRONAS Carigali Sdn Bhd) | Ho, Dylan Zhe Xin (PETRONAS Carigali Sdn Bhd) | Zamdy, Siti Nurdyana (PETRONAS Carigali Sdn Bhd) | P Mosar, Nur Faizah (Schlumberger WTA Malaysia Sdn Bhd) | Kalidas, Sanggeetha (Schlumberger WTA Malaysia Sdn Bhd) | Tan, Chee Seong (Schlumberger WTA Malaysia Sdn Bhd)
Over the last few years, the oil and gas industry had observed a rapid increase in deployment of fiber optic sensing for downhole monitoring. In Field B, 7 wells have been permanently completed with Distributed Temperature Sensing (DTS) fibers that extend through the reservoirs section 2009 and 2015 respectively. After more than 40 years of production history, this was the first permanent installation of fiber-optic in SX Region. Undeniably the DTS provides a new surveillance experience for Field B; multiple conventional monitoring system can be replaced with permanent fiber monitoring while also effectively minimize production deferments.
This paper presents the real-life challenges of fiber optic applications in Field B, offshore Malaysia. DTS wells are located in satellite platforms which are not accessible on daily basis. While the focus is always on downhole monitoring deliverables, a large proportion of upfront deployment is to invest on the surface equipment that can be complex and costly for data acquisition continuity. As such, biggest challenges faced by Field B are essentially surface-related. Challenges encountered post DTS fiber installations in Field B includes digital oil field set-up, surface hardware replacement and maintenance, local electric room (LER) power-supply stability, data transfer protocol, continuous streaming of DTS data from offshore to onshore, reduced data resolutions, software and capability development. Over the life of the well, these challenges possess significant cost impact and most of time are not captured during the project planning and development stages.
In Field B, throughout 5 years post fiber-optics installation, multiple challenges have been overcome in order to maximize value of information from the downhole monitoring. Knowing that these challenges might impact the downhole monitoring deliverables, the plan for future permanent fiber optic installation in any asset should incorporate all the possible challenges with its mitigation plans identified and set in-place. The lesson-learnt highlighted are turned into future project best practices.