NEL’s Emmelyn Graham discusses multiphase flow measurement – where is it going and what is needed.
NEL’s flow measurement facility. Photos from NEL.
Accurately measuring a complex mixture of oil, water and gas in the field has remained a major challenge. Traditionally, separators were used to separate out individual component streams to allow subsequent single phase metering.
However, there are many disadvantages to using separators, including their excessive cost and infrastructure needs. To overcome these issues, multiphase flow meters were developed in the early 1990s, to support more economical development of marginal, deeper and more complex fields.
The first generation of multiphase flow meters failed to meet the required performance criteria to allow their uptake. However, several decades on, and following successive technological advances, industry has now gained greater confidence in their use and, more importantly, recognizes the vital role these meters will play moving forward.
Multiphase meters offer reduced capital and operational expenditure; increased capability to monitor individual wells in real-time; less dependence on high-maintenance separators; and minimal loss of production through well test shutdowns. Overall they have become more accepted by industry for allocation and well/reservoir monitoring.
These types of flow meters will play a major role in the colossal shift to subsea production in deeper waters. Confidence in the technology has significantly improved with some new field developments no longer relying on separators. However, the sole reliance on multiphase and wet-gas meters for subsea applications brings unique challenges that need to be better understood and addressed.
Despite the huge advances in meter development there is still considerable scope for improvement in terms of accuracy and reliability. Materials and sensors need to be more robust to cope with the harsher environments subsea, including surviving sand-entrained flows. They have to be more compact and lighter to allow their effective deployment in deep water environments. Greater consideration also has to be given to the power and communication bandwidth which can in itself restrict their use subsea.
Different sensing methods have been used in multiphase flow technology, ranging from differential pressure devices, gamma densitometers, capacitance, microwave and ultrasonic sensors. However, many commercial meters have now adopted a similar strategy as most include a blind-tee or a similar mixing element, a Venturi, a densitometer and/or capacitance measurement. Cross-correlation of sensor data can also be used to determine flow velocity. While this industry homogenisation to a single design is a practical solution to meet current flowmetering requirements, the future of multiphase flow metering will be driven by the industry’s need to develop cheap, light-weight, flexible production systems that efficiently and safely exploit increasingly difficult fields.
The reliability of multiphase meters installed in subsea locations is a key goal for oil and gas operators, especially in times of reduced oil profits, as the cost of repairing or replacing failed subsea equipment is excessive. The drive to develop deeper subsea wells increases the cost exponentially.
The trend for deeper water wells, longer subsea tie-backs and increased distance to processing facilities means that subsea equipment must be robust and able to cope with extreme conditions. Equipment must be reliable for efficient operation and easily maintained; it is also extremely important to identify any potential flow assurance issues.
Flow assurance issues can have a major impact on the reliability of subsea multiphase flow meters including the formation of hydrates, waxes, scaling, slugging, chemical deposits, erosion and corrosion. Failure to quickly identify and mitigate these problems can cause serious damage to equipment, affect measurements, and have catastrophic consequences in terms of safety, production and reduced revenue. In some cases multiphase meters can be used to identify certain flow assurance issues to allow early mitigation.
Another challenge for flow metering technologies today is that the majority of the world’s remaining oil reserves are classed as heavy oils, yet most of the multiphase meters on the market have been designed to operate with relatively low viscosity oils. To date very few multiphase meter technologies have been validated for heavy oil applications, nor have they been assessed for use when emulsions are present. Both these areas are expected to come under increased focus in the medium-term.
The development of four-phase meters (to include sand monitoring) will assist in detecting and mitigating the major flow assurance issue of erosion in subsea infrastructures. This is an increasing problem for industry due to the higher sand content from deeper waters, more complex field development and the dependence on long piping tie-backs and increased distance to processing facilities.
Many multiphase meters use radioactive sources to determine fluid densities. However, the unknown degradation of the radioactive source over the lifetime of the meter, together with safety and environmental implications, has seen a push for alternative operating technologies.
Potential game-changing, tomography-based visualization systems are currently under development to support the critical need of identifying flow assurance issues as early as possible. This includes detecting slugs, which can have a catastrophic effect on plant and equipment due to the induced pressure fluctuations.
New clamp-on technologies have emerged onto the market over recent years. In particular these allow retrofitting to existing flow lines and the ability for temporary assignment. The early first generation of ROV-retrievable clamp-on subsea multiphase have been developed and tested. The focus is to now have these deployed and tested in the field.
Downhole measurement technologies are a big must for industry to better control and optimize the well and reservoir. The ability to monitor and react closer to the source presents major advantages and a step change in optimization and recovery. Although some multiphase meters have been developed and integrated into Xmas trees at the wellhead, much innovation and research is still needed in this area to achieve the required level of accuracy and robustness.
Another new area of focus over recent years has been around virtual flow metering. This is software that combines distributed measurements to calculate the flow rate. For example, the pressure drop across a choke, wellhead temperature and the downhole pressure could be used as inputs to derive flow rate. Furthermore, these systems can potentially be easily integrated into existing infrastructure so eliminating the need for additional hardware. Both well and pipework flow simulation software are also being integrated with these systems to allow real-time modelling and optimization of production. Multiphase flow meters can be used to tune virtual metering systems. Ultimately, utilizing virtual metering can provide an effective back-up in the event of multiphase metering dysfunction.
Since their introduction many years ago multiphase flow metering techniques have continuously evolved to meet industry needs. Their use is expected to increase due to the cost reductions and diverse applications they provide, including supporting reservoir engineering, sand management, leak detection, process optimization, condition monitoring, fiscal/allocation reporting and integrated production management. However, in the eyes of industry, multiphase technology is still cost-prohibitive to allow them to be deployed on a well by well basis.
Emmelyn Graham is a flow measurement consultant with over eight years’ experience at NEL, specializing in wet-gas and multiphase flow metering. Graham has been involved in producing new equations for the correction of gas flows with entrained liquid for Venturi tubes, which has been included in a new ISO wet-gas technical report. In addition, she has used her experience to provide training on flow measurement globally. She is currently the UK representative within EURAMET (European Association of National Metrology Institutes) for the Technical Committee of Fluid Flow and is working on a large European collaboration with operators and equipment suppliers to advance multiphase flow metrology and reduce measurement uncertainty. She has a PhD in science and engineering from Edinburgh University.