Gary Miller - TUV NEL
Metering and allocation of the oil and gas industry is more complicated than ever. Production flows are no longer straightforward. Instead, various streams made up of differing mixes of oil, water, and gas from different fields belonging to different operators and sometimes even under different tax regimes, are being commingled as an increasing number of marginal fields enter production.
A new approach to metering is required and “per-well” multiphase meters appear to be the best way. But, is the technology ready? Meter manufacturers believe so, but TUV NEL, which has performed independent testing of multiphase meters over the past 20 years, believes more testing and verification is required to give field operators the confidence and experience to meet their commitment to partners and regulatory bodies.
Most offshore fields developed 20 or 30 years ago were designed to cope with flow from a single field. While it always has been important to monitor individual well production, it generally has not been essential to know which well every single barrel of oil came from when it all belonged to one operator. However, when you add the complexities of multiple flows belonging to different operators, each with varying oil/water/gas mixes, things become much more complex.
The traditional approach to offshore multiphase flow metering has been to use a test separator and separate oil and gas flowmeters, with periodic testing of flows from each well. This is adequate to provide regular information about what each well is producing in terms of oil, water, and gas, but in terms of allocation, when every drop of oil counts, its suitability and applicability is questioned.
On a typical platform with 10 - 20 producing wells feeding into a single production separator, changes to a specific well’s production could remain unnoticed for weeks, even months, until the well flow takes its turn in the test separator. As more established offshore assets become production hubs for multiple fields, any undetected changes to flow rates, water, and gas content can have cost implications. For example, a sudden water breakthrough in a well which previously produced several thousand barrels per day could reduce revenues for all of the stakeholders and fiscal bodies, as well as financially affecting the operator of the facility.
What is really required is continuous, individual “per well” flow metering. Separation systems are costly, large, and heavy. It is not practical in terms of deck space or cost to have individual separation for each well, so multiphase metering has to be the way forward. However, uncertainty remains about the application, suitability, and performance of multiphase meters.
Multiphase metering – is it ready?
Multiphase flow measurement has been developing in the oil and gas industry over the last 20 years. When multiphase metering was first introduced, unrealistic claims led to great expectations and ultimately disappointment when the technology failed to meet its initial promise. However, in recent years the technology has developed to a point where multiphase metering is considered as a key enabler in development of many marginal fields.
The technology’s accuracy certainly has improved and it is fair to say that many of the meters being marketed today are more than capable of meeting the levels of accuracy required for operations such as well testing, i.e. up to 20% uncertainty, where approximate performance and repeatability of measurement are the main requirement. However, for allocation and fiscal measurement with required uncertainties of less than 10%, or in some cases below 5%, there is still a challenge.
There are a handful of multiphase meters currently available that can meet the accuracy required for allocation under specific conditions, but so far no multiphase meters are available commercially with less than 5% uncertainty over the full range of conditions.
With more than 1 million production wells around the world, the “per well” market for flowmeters is attractive for meter manufacturers and they are working to improve technology. However, with multiple stakeholders in terms of allocation and fiscal reporting, independent verification of meter accuracy is essential. Furthermore, the current cost of multiphase meters is prohibitive for “per well” metering to become common.
Developing technology
There are a number of factors multiphase meter manufacturers need to research. These include:
- Transparency of accuracy through independent testing
- Uncertainty less than 5%
- More gas volume fraction (GVF) capabilities
- Higher water cut capability
- Lower cost.
Improving reliability, packaging
Accuracy of multiphase flowmeters has been tested by independent specialists TUV NEL over a number of years via joint industry projects (JIPs) funded by a wide range of oil companies including most of the major international operators and meter manufacturers.
There are two keys to accuracy claims that require independent verification: the hardware and the software. Manufacturers claim significant accuracy advances for hardware with improved sensor technology in meters such as nuclear gamma ray detectors and dielectric sensors. In terms of software, manufacturers have worked to refine algorithms to interpret the measured signals and to correct for flow regime effects.
Complete multiphase metering systems need independent verification across a full range of well conditions with varying levels of water cut and GVF. This can be done at a specialist multiphase testing laboratory such as TUV NEL’s facility in East Kilbride, Scotland, which combines a full scale three-phase test separator with single-phase reference meters to provide real time comparisons with multiphase meters on test. (This facility forms part of the UK National Standards for flow measurement).
The TUV NEL facility can operate at flow rates up to 16,000 b/d, water cuts from 0 -- 100%, gas fractions up to 98%, line pressures of 10 bar, and at operating temperatures of 20º-0º C (68º-32º F). This allows the physical testing of multiphase meter systems over a range of well conditions and can lead to increased confidence in the reliability of their measurements. However, in addition to the performance of a meter itself, the ultimate accuracy of the system depends on the PVT (pressure, volume, temperature) modeling software used as part of the overall metering package.
Multiphase meters measure the flowrates of each phase at line conditions, often at elevated pressures. These measurements must then be converted to standard conditions using a PVT model. This conversion adds to the uncertainty of the measurement when converted to standard or any other conditions.
The PVT model requires physical property or composition input data for the oil, water, and gas phases. It is used to determine the change in both densities of the phases and, more significantly, the amount of phase transfer between the phases from line conditions to standard conditions. The phase transfer is almost exclusively between the oil and gas hydrocarbon phases, with a reduction in pressure causing some of the lighter liquid hydrocarbon components to evaporate or “flash off” into the gas phase. This is commonly referred to as “oil shrinkage.”
Despite the almost universal use of PVT models in multiphase meters, there is little information on how these calculations are performed, and indeed how one manufacturer’s model compares with another. There is also little, if any, information on the sensitivity of these models to errors in the input physical property or composition data. In discussion, regulators say this as an area of concern. The UK regulator, for example, has experienced serious errors in allocation measurement due to poor PVT information.
Given the potential financial impact of PVT calculations, there is a clear need to evaluate independently the performance of the PVT models used in different multiphase meters to determine the consistency between models and the sensitivity to input variations.
Analysis of multiphase technology helps identify areas where manufacturers can focus development efforts. For example, as increasingly marginal wells become viable with high oil prices, multiphase meters will need to handle ever higher water cuts. In late-life fields, viable water cuts of over 90% are common and in the future it is possible that flows with even the smallest oil content may be economic.
Multiphase meters also need to be able to cope with GVFs ranging from less than 10% to more than 98% at various flow rates.
Future challenges, opportunities
With so many variables, multiphase metering development is a complex process. However, meter manufacturers are making headway with the issues and further independent testing will highlight the general progress of the technology.
Although multiphase meters are still cost prohibitive as a widespread alternative where pre-existing test separator capacity exists, they are cost effective for new developments where test separators are not available because they offer both lower capex and opex.
Multiphase meters probably will play an important role in unlocking the potential of heavy oil, much of which will be produced with the aid of steam, creating a multiphase mixture of evaporated hydrocarbons, oil, solids, and water.
In addition to metering production, multiphase meters also promise other benefits. Multiphase meters can optimize gas lift by providing real-time data. In a recent project by an oilfield services company in Brazil, gas lift was optimized in old wells by applying of a conventional single-phase meter to monitor gas injection flows, while simultaneously monitoring production with a commercially available multiphase meter. Test result analyses found that in most of the wells tested, increased gas injection benefited production, although in the case of one well, optimization required a reduction in the volume of gas injected.
In high water cut wells, multiphase meters may determine accurately when production becomes non-viable by providing real-time information about what is being produced.
Readying the technology
With so many variables, multiphase metering is a complex business, but it is clearly the way for operators to maximize asset values, develop marginal fields, or manage challenging wells.
“Per well” multiphase flowmeters will become the long-term norm for most new developments and for many existing wells. The technology is developing quickly and with increasing understanding of accuracy, capability, and application needs, greater trust of multiphase meters will grow quickly to increase demand and reducing meter cost.
