As a Flow Measurement Consultant at NEL, Craig’s responsibilities include working on a large variety of R&D, training and consultancy projects focused on single and multi-phase metering technology. He performs a variety of roles including project formulation, project management, technical lead, planning/delivering test work, data analysis and report writing. Craig has spent 10 years at NEL completing work in the technical areas of engineering design and review for custody transfer and fiscal metering measurement systems, measurement allocation philosophy documents, measurement system audits and financial exposure calculations. Currently, Craig is undertaking a doctorate degree at Coventry University in heavy oil and bitumen flow measurement and as part of the work has developed a Reynolds number correction method calculating flow and fluid physical properties in real-time. Risk management in thermal wellbore integrity can be promoted by the proper collection, processing and interpretation of data from various types of wellbore instrumentation.
Saudi Aramco studied such algorithms to produce images simulating the flow inside a pipe’s cross section, possibly reducing the need for separator-based multiphase flowmeters. A former technical manager with Petrobras discusses the development of the company’s flow assurance philosophies and strategies. Looped lines are used to reduce pressure drop and increase flow capacity, but information on the flow behavior or predictive methods are not available for these systems. Bypass pigging has advantages over conventional approaches. Its application to multi-phase flow with high wax content crude is discussed.
Megaprojects have come to define many of the world’s new resource projects but they are also a testament to the awesome engineering capabilities of the oil and gas industry. Find out who took home this year’s honors. The new deal covers production deck manifolds and subsea pipelines for Zuluf and Berri, two large fields undergoing expansion projects. The agreement calls for the two companies to partner on techno-economic feasibility studies and jointly assess investment opportunities across the LNG value chain. Saudi Aramco studied such algorithms to produce images simulating the flow inside a pipe’s cross section, possibly reducing the need for separator-based multiphase flowmeters.
The XLe Spirit from Forum Subsea Technologies is the first observation-class ROV to utilize the comp ... Clock Spring Co. announced a technology licensing and distribution agreement for the Pipeotech AS De ... The S88 pH sensors from ECD are one part of the Model S88 Intelligent Sensors product line of sensor ... Allweiler GmbH’s OptiFix is a pump designed for wastewater treatment applications. It can be disasse ... The Tri-Strakes Combi from Trelleborg is a vortex-induced vibration suppression system for risers an ... InsightCM from National Instruments is application software for condition monitoring with full acces ... FieldCare from Endress + Hauser is a universal software program for configuring field devices in a f ... Siemens’ Revive oily water membrane systems replace filtration and flotation with a single step, eli ... LMI’s Liquitron 7000 Series controller provides multi-parameter monitoring and control for metering ... PlantSight from Siemens and Bentley Systems mirrors the ...
The two technology startups aim to bring scale to the visual side of oilfield automation with a new deal that will cover 90% of US energy assets. Current production from the phase is 400 MMcf/D and expected to peak at 700 MMcf/D. A third phase also is slated to come on stream this year. Saudi Aramco studied such algorithms to produce images simulating the flow inside a pipe’s cross section, possibly reducing the need for separator-based multiphase flowmeters. Anadarko aims to maximize immediate short-cycle value through tiebacks and platform relocations in the Gulf of Mexico.
Virtual Metering technology has been used in offshore oil and gas wells for over a decade with great success. They provide a cost-effective, yet reliable solution to monitor production continuously. They also serve as ready back-up to "physical" multiphase meters, which are both expensive and less reliable. On one asset that has been producing for over 18 years, Virtual Metering enabled reliable production metering, where it was previously not possible to do any type of well testing. In this case, the production metering process was successful because the Virtual Metering utilized multiple methods to predict flowrates and was able to keep predicting accurate flowrates, even as various pressure/temperature measurements / sensors in and around the wells failed over time.
Sun, Hehui (No.1 Mudlogging Company, BHDC, CNPC) | Lao, Liyun (SWEE school, Cranfield University) | Li, Dengyue (No.1 Mudlogging Company, BHDC, CNPC) | Tao, Qinglong (No.1 Mudlogging Company, BHDC, CNPC) | Ma, Hong (No.1 Mudlogging Company, BHDC, CNPC) | Li, Huaiyu (No.1 Mudlogging Company, BHDC, CNPC) | Song, Changhong (No.1 Mudlogging Company, BHDC, CNPC)
More and more early kick/loss detection (EKLD) devices are being used in drilling operations, whether in the field of onshore or offshore drilling. In the field of deepwater and offshore drilling, high-precision electromagnetic flowmeters and Coriolis flowmeters was used to measure the inlet and outlet flow rates of drilling fluids. Good effect was achieved, but are affected by drilling fluids, space limitation of the wellsite and production costs when in the field of shore drilling, engineers usually use the paddle- flowmeter and ultrasonic liquid level meter to measure the inlet and outlet flow. It exists the problem of low measurement accuracy and prolonged warning time. In order to improve the accuracy of measurement and the accuracy of early warning, the electromagnetic flowmeter has been studied in terms of flow measurement at the outlet of on-shore drilling. The study found that the installation position of the electromagnetic flowmeter in the V-shaped test pipeline is a key factor that determines the accuracy of measurements. The influence of different fluid types on the measurement was studied by fluid dynamics. The fluid model was established using Ansys fluent software, and the boundary conditions were set in conjunction with the relevant parameters of the drilling fluid. It was found that the descending segment of the V-shaped pipeline was suitable in the state of laminar and dispersed flow. It is an appropriate mounting position for the electric flow meter; for the slug flow, the rising section is a suitable installation position. The theoretical conclusion is verified by laboratory simulation and field tests. The results of theoretical research were used to optimize the design of the test pipeline, and the problems of transient large flow passage and solid-phase debris deposition in the field were solved, and good results were achieved. An automatic grouting module was developed based on the accurate measured outlet flow data. The automatic grouting operation is very helpful for the construction process of drilling and triping, improved the safety level of well control, and laid a good foundation for the large-scale application of EKLD devices in the field of shore drilling.
Multiphase flow meters are available from sometime, however, there still remain unresolved challenges. Dependable flow sensing is essential for reservoir management and production optimization. Most commercial water-cut and multiphase flow meters have limitations while measuring over the full range of flow conditions. Exiting meters need recurrent calibration, and have significant capital and operational overheads. In this paper an ultrasonic tomography based meter for water holdup measurement is presented and the the experiences and challenges of testing the system in the field are shared. The designed system has the potential to resolve the shortcomings of available multiphase metering solutions.
Replacing all analogue sensors in the oil field is very costly and normally only a fraction of them is done. Currently, there is no cost-effective method to efficiently, reliably and accurately capture analogue meter readings in a digital format. Operators are then left with only two options: either replace them with digital (high capex) or continue with manual gathering (high opex). This paper shows how computer vision and artificial intelligence was used for the first time to capture analogue field gauges data with dramatic reduction of cost and increase reliability.
This unique solution was implemented in the Cheleken Oil field, Caspian Sea, Turkmenistan. In the offshore platforms, only low-cost cameras were necessary, and gauges were identified using QR codes. During the field trial, operators were only required to take pictures of the gauges at a given interval of time and upload the photos to the application. After an innovative process of calibration, the acquired images were processed using artificial intelligence and deep learning computer vision.
Routine manually gathered data was compared with data collected using this solution with the following observations made: Date/time: Operators usually round time. The solution described records time on the captured pictures automatically. Value: Manually gathered data is subject to reading, typing and transcription errors. This solution has no error (provided a good calibration is done). Data Modification: Data gathered automatically with this solution has no human intervention. Therefore, is not subject to alteration, copying or duplication. Data collection with pictures was completed in 1/10th of the time that manual processes take. The business benefits from quicker operator rounds with improved accuracy in meter reading data, and time stamps. The administrative burden for operators of filling in extensive spreadsheets which are prone to error was reduced, this allowed them to collect more meter readings or be reassigned by management to more important scopes of work that bring greater value to the business. Once more it was proved that "a picture is worth a thousand words ".
Date/time: Operators usually round time. The solution described records time on the captured pictures automatically.
Value: Manually gathered data is subject to reading, typing and transcription errors. This solution has no error (provided a good calibration is done).
Data Modification: Data gathered automatically with this solution has no human intervention. Therefore, is not subject to alteration, copying or duplication.
Data collection with pictures was completed in 1/10th of the time that manual processes take.
The business benefits from quicker operator rounds with improved accuracy in meter reading data, and time stamps. The administrative burden for operators of filling in extensive spreadsheets which are prone to error was reduced, this allowed them to collect more meter readings or be reassigned by management to more important scopes of work that bring greater value to the business. Once more it was proved that "a picture is worth a thousand words ".
This solution offers an excellent opportunity for digitizing the marginal section of the field and provides a unique way to turn all analogue data into digital with a very low cost of implementation, on an infinitely scalable platform that is vendor agnostic and simple to manage.
The Offshore Technology Conference (OTC) announced 18 technologies that will receive the 2019 Spotlight on New Technology Award. The awards will be presented 6 May at the 2019 Offshore Technology Conference. The Spotlight on New Technology Awards—a program for OTC exhibitors—showcase the latest and most advanced hardware and software technologies that are leading the industry into the future. Stress Engineering Services Inc., producer of Condition Based Maintenance of Drilling Riser Systems The technology must have been offered to the marketplace in a ready-for-commercialization state less than 2 years prior to the application date. The technology must be original, groundbreaking, and capable of having a major impact on the offshore E&P industry.