Flow measurement is common practice in the oil and gas industry and plays a critical role in hydrocarbon allocation and taxation. Traditionally flow is measured to distribute produced assets fairly among proprietors, but recent advances enable measurement devices to be applied to other important applications such as well productivity and reservoir performance monitoring. Given the low oil price predicament, the onus is on field operators to reduce costs and increase efficiencies during hydrocarbon production, and the use of multiphase flowmeters (MPFMs) is seen as a modern approach to achieve this.
Although exploration and production companies took measures to reduce costs and delay any capital expenditures to remain competitive in the market in 2015 and 2016, tightened budgets and bootstrapped strategies had significant impacts on equipment in the industry.
Conventional measurement techniques (test separators) generally offer superior stability and confidence compared to MPFMs. However, these advantages come with the price of higher costs and less flexibility to the complex field architectures in subsea environments. Real-time production monitoring is one key multiphase measurement advantage; It utilizes data gathering for process workflows to support production optimization. This feature has raised the profile of MPFMs globally with regard to their operational benefits.
It is estimated that more than 5,000 MPFMs are in use worldwide. Some of these meters are installed within existing infrastructure, accompanying the traditional test separator or possibly supporting tieback extensions, while some will be selected as the primary measurement points for new fields or perhaps chosen for cost-benefit reasons when exploiting marginal fields. The versatility of MPFMs enables a diverse applicability to onshore, topside and subsea operations, having been successfully utilized for production optimization, allocation and fiscal measurement purposes.
It is not surprising that field operators choose to have one MPFM installed per well. However, unlike well performance monitoring using single-phase flowmeters (operating with test separators), no desire exists to extract MPFMs for routine, high-accuracy calibration in accredited laboratories. Many reasons for this are given, but a more important consideration is its impact from a flow measurement perspective.
All flowmeters are subject to performance changes over time, resulting in poorer repeatability and drift from the last calibration. Drift effectively means the meter is likely subject to a systematic bias that progressively worsens, causing a loss of accuracy. Therefore, a beneficiary of hydrocarbon production may be short-changed. Thus it is important to accurately characterize device performance using a reference system. Otherwise, how would its accuracy be determined?
Analogous to mass measurement, a primary reference must exist for good calibration. In this case, it is the international prototype kilogram (IPK) in France, which is the primary reference standard for the unit of mass. All mass measurement devices are, in one way or another, calibrated with respect to the IPK, reflecting a level of confidence and uncertainty to which their value is justified.
Multiphase flowmeters are quite different in comparison to their single-phase relatives, but the fact that they are not calibrated with respect to a reference standard throughout their working lives is a disadvantage that ultimately results in concerns over measurement confidence and accuracy over time.
MPFMs are common in extreme conditions, enduring high pressures, high temperatures, highly corrosive contaminants (e.g., hydrogen sulfide and carbon dioxide), erosion (e.g., sand) and heightened susceptibility to solid deposition (e.g., wax and hydrates). These variables, as well as the volumes of the primary fluids themselves, are subject to change over time and must be accounted for to retain measurement performance.
No physical technique currently exists for real-time MPFM validation. It is reasonable to assume the near future will bring an increased reliance on and higher performance expectation of multiphase measurement systems, hence, this issue will affect the allocation and taxation of hydrocarbon assets. Several aspects of MPFM validation need to be addressed:
1. Standards & guidelines
MPFM users would look to standards to ensure correct commissioning and operation. Because of the diversity of field infrastructure and locations, guidance from standards and best practices does not yet account for in-situ performance monitoring and only extends as far as preinstallation procedures. Then, meter system maintenance and validation is often governed by user preference.
The most commonly used standard for multiphase flowmetering is API 20.3; A committee recently addressed these requirements for in-situ validation and is working toward introducing it in the next revision of the document.
2. Lack of direct validation techniques
A transferable reference calibration (as used for single-phase meters) is not available. The closest means of MPFM calibration is to use a test separator, which is often regarded as a questionable source of reference given the associated uncertainties and reliance on accurate pressure, volume and temperature (PVT) data. If no direct physical reference system is present (i.e., no test separator) for comparison, sampling may help verify aspects of MPFM performance.
Valuable samples must be representative of flowing conditions, but this can be difficult to achieve for certain systems. In addition, subsea sampling is costly and labor-intensive, generally making sampling less of a priority when purely for flow measurement verification purposes.
4. PVT correlation
PVT models are used to relate the fluid volumes at MPFM conditions to those nearer standard conditions further downstream. This is a critical aspect of the MPFM validation process since incorrect PVT correlations can lead to significant uncertainties.
Various PVT models are often applicable to particular situations, all of which can yield different answers. Which one is correct? Often manufacturers will conduct lab analyses of the produced fluids during well startup to define a PVT correlation tailored to their specific fluid properties. However, it is common knowledge that fluid properties are subject to change over time, therefore deviating from the initial PVT specification.
5. Heavy oil measurement
Heavy oil measurement is challenging in any environment and often has larger errors associated with it than for conventional, light crude production. Therefore, comparison with the test separator and sampling are inadequate and MPFMs can be required to operate without robust verification procedures for heavy oils.
Generally multiphase flow measurement systems rely on two devices for measurement: a radiation source for phase (oil-water-gas) fraction determination and a Venturi nozzle for mass flow rate determination. The performance of both is influenced by higher density and higher viscosity fluids.
Even in the absence of major developments over the next 10 years, it will be important to investigate the finer details of multiphase flow measurement to assess its impact on current MPFMs, but such knowledge will be vital for developing the next generation of MPFMs.
Are complex flows encountered in service conditions really known? Are flow structures understood? Is the development of these structures’ influence on mathematical models that provide the backbone of MPFM calculations known?
If not, perhaps it is unfair to expect accurate MPFM performance. Understanding provides the basis of measurement stability, traceability and confidence.
Using live hydrocarbons during laboratory qualification tests before field deployment can better reflect service conditions. However, just because it is a live fluid test (i.e., crude oil and hydrocarbon gas), does not necessarily mean it is representative of conditions.
It will be important to address these knowledge limitations to improve design, qualification, specification and in-situ measurement performance of multiphase flow measurement systems over their working lives. This will involve technology investment and research to explore the impacts of flow structure and fluid property variations over time alongside the lack of understanding of these variables at more extreme line conditions.
The final piece of the jigsaw puzzle will be the development of robust in-situ verification techniques for MPFMs. Conventional recalibration is not generally an option for most MPFMs, so in-situ verification will be the only method for ensuring continued accuracy. The development of such techniques will require answers to the questions posed above. It may also require the application of knowledge and techniques from other areas beyond flow metrology.