Multi-phase flow metering gains acceptance in upstream applications

Tim Shea
ARC Advisory Group

Accurately measuring multi-phase flow is challenging under any circumstances, but particularly so in today's increasingly demanding offshore operating environments.

While not all industry participants are convinced that today's multi-phase/multi-component flow metering solutions represent a practical or cost-effective solution due to measurement uncertainty, initial cost, and other concerns, the technology has clearly been gaining traction since its introduction in the early 1990s. This is due both to technical maturity and efforts by independent third parties to validate accuracy. Energy companies such as Statoil, PDVSA, BP, and Petrobras are deploying multi-phase flow meters (MPFMs) on a broad scale to enable continuous measurement of the individual components in co-mingled oil, gas, and water streams.

ARC is investigating both the technical and market issues surrounding this still-emerging technology. Most MPFM solutions today employ multiple sensor technologies to provide true physical multi-phase flow measurements, with the most popular combination being differential pressure across venturi and gamma ray attenuation. Typical applications for multi-phase flow meters include well testing, production monitoring, production optimization, flow assurance, production allocation, and fiscal metering/custody transfer.

MPFMs are complex systems that are often employed with other instruments such as water cut meters, and pressure and temperature transmitters. Some suppliers incorporate IR absorbance, while others rely on microwave technology for wet gas and water cut metering. While experts mostly agree that MPFM solutions may never reach the accuracy provided by a full separator, but suppliers continue to strive for that objective.

Accurately measuring the multiple components (typically oil, water, dry gas, and condensate) in multi-phase flow applications is far more complex than traditional single-phase flow measurement. Since the real opportunity for MPFM solutions lies in convincing users to either replace or complement full separators, MPFM suppliers should focus development and marketing efforts on targeting applications in which MPFMs clearly provide a more attractive option. Opportunities to replace and/or complement separators include:

• Offshore platforms with limited space (assuming the well is productive enough to justify the investment)
• Applications in which heavy oil is produced
• Formations in which the steam-assisted gravity drainage (SAGD) process is employed in heavy oil and/or oil sand reservoirs
• Platforms operating in mature fields in which the well profiles change constantly and traditional monthly well testing is insufficient
• Fine-tuning artificial lift solutions such as electrical submersible pumps (ESPs)
• Subsea projects in which the deployment of separators is not feasible and/or MPFM is used as a complementary solution to provide more timely well testing, monitoring, and/or flow assurance/allocation
• Any project in which the MPFM will provide sufficient ROI via more real-time information to help enhance recovery or improve production.

When considering MPFMs for a particular application, operators should:

1. Investigate the expected flow regimes from the wells to be measured and determine the production envelope

2. Identify MPFMs with a corresponding measuring envelope

3. Select an MPFM capable of continuously measuring the applicable components and volumes with appropriate (ideally, independently validated) accuracy/measurement uncertainty for the application

4. Ensure the availability of appropriate onsite resources to allow regular calibration/adjustment and verification

On a dollar basis, subsea applications compose the largest segment within the overall MPFM market. This is due in part to the more expensive price tag of subsea MPFM solutions, which can range as high as $1 million or more, but more typically fall between $500,000 and $750,000. In many cases, an MPFM is the only viable solution to make a subsea production project work, since the depths, pressures, and logistics make deploying three-phase separators infeasible.

However, as with most technologies, initial purchase cost is just one component to consider. With MPFMs, operating experience suggests that overall lifetime costs can be considerably less than alternate approaches in a variety of applications, due to reduced installation, operating, and maintenance costs.

ARC has found that the greatest inhibitor to more rapid adoption of MPFM solutions is the plethora of different reservoirs and formations, and the variations of types of gas and oil compositions these contain. In most cases, the testing of an MPFM is validated for a specific reservoir or shale formation and its specific parameters; the performance of that MPFM may not be validated for another reservoir or formation, which could possess different gas and oil compositions, and require deployment of a different pipe diameter or different materials to handle variations, such as a greater presence of corrosives.

Organizations such as the Research Partnership to Secure Energy for America (RPSEA), NEL, and DNV KEMA can serve as valued partners for MPFM suppliers and end users alike. Earlier this year, DNV KEMA announced the opening of the organization's new multi-phase flow lab in Groningen, the Netherlands, to enable equipment manufacturers and oil and gas companies to test, validate, and calibrate multi-phase technologies (including both multi-phase separators and flow meters) to ensure the quality of the measurements. The new test lab is designed to recreate the kind of conditions that this equipment faces in the field, including a full range of multi-phase fluid compositions at realistic temperatures, pressures, and flow rates. Another objective is to accelerate industry efforts to develop standards for equipment and testing protocols, which will be critical for increasing acceptance of the technology.

Research indicates that owner/operators are implementing MPFM solutions for flow allocation - and, in some cases, for fiscal metering - in a growing number of subsea projects. As an MPFM product manager at a major oilfield services company recently commented to ARC, "As long as two parties contractually agree to accept a certain level of uncertainty, then it works. In some cases, there is really no other alternative to make the project work effectively, so it's either a case of using an MPFM, or no project at all."

As the technology improves, and new industry standards are developed for MPFM equipment and testing protocols, ARC expects that the adoption rates of MPFM solutions will accelerate.

Only a handful of suppliers currently offer multi-phase flow meters. But this could change in the future. Based on the current maturity of the technology, the successful field experience of operating companies in selected applications, the availability of independent test labs to calibrate products and confirm accuracy, and - in some cases - the sheer lack of alternate approaches, ARC recommends that owner/operators keep an open mind about MPFM solutions. They should ask suppliers to provide contact information for reference clients, and do their own evaluation, on a small scale, of the business and operational benefits prior to widespread deployment.

While not perfect, it appears that MPFM technology can often provide a viable - and in some applications the only - solution.