As evolving technologies enable North Sea platforms to produce beyond their original design life, many operational factors come into play. Issues that directly impact productivity and downtime are a high priority. Among these, metering systems should be regarded as critical. They determine the quantity and quality of oil and gas recovered, and their control systems effectively form the "cash register" of the whole production process. In the UK, they also act as the fiscal tax point with the Department of Energy & Climate Change (DECC). Consequently, unreliable, poorly designed, or obsolete metering systems can result in significant financial exposure.
Thirty years on from the North Sea boom of the 1980s, many platforms remain viable, but produce far less than in their heyday. Metering technologies from the '80s generally perform best when flow rates are at the higher end of their design spectrum. Production declines stretch the limits of their operating envelopes. It follows that metering systems on these aging platforms are likely to have diminishing performance from a metering uncertainty perspective.
Whether metering for allocation on a shared network (as is common in the North Sea), for custody transfer (where tax liabilities are calculated), or for operational purposes, optimum measurement uncertainty is vital. When loading a large crude carrier, a 0.5% measurement uncertainty typically equates to more than $2 million. If an official audit discloses a measurement error, DECC must be alerted. From that point, the operator has three weeks to identify the problem. DECC will calculate how the miscalculation applies to royalties and consult with the operator to agree an acceptable solution and timescales.
Good oilfield practice dictates that when the original operating range changes, a review should be undertaken to ensure the metering system remains fit for purpose. This is a specific requirement of the Measurement Model Clause of petroleum production licenses in the UK. What's more, it protects the operator's bottom line.
Repeated metering system failure or poor audit performance usually indicates that attention is needed. However, selecting the most appropriate course of action is not simple. There are many factors involved, including the weight, space, and time constraints familiar to all offshore hardware designers.
When upgrading or replacing metering systems on existing platforms, the usual challenges are compounded by the fact that original sales agreements from the platform's inception need to be considered. Often, these inflexible contracts involve measurement principles that do not dovetail with today's best available technologies. Specifying metering systems for aging platforms is almost as much about contract interpretation and mediation as it is about engineering skill. Historic measurement standards and contracted agreements need to be considered alongside production challenges, good oilfield practice, and appropriate technologies to ensure a good fit.
The fact that metering instruments are mounted on skids along with other equipment also has a bearing on their design and selection. Integrator engineers plan and build every system as a bespoke project because each application is individual. Sometimes with aging platforms, decisions surrounding metering technologies are shaped by the dimensions or accessibility of an existing component on the skid. This scenario can influence whether to retrofit or replace equipment.
Despite these challenges, specifying metering systems for an existing platform has one critical advantage over the same challenge for a greenfield site. Available empirical data enables engineers to predict the flow rates likely to be experienced over time. Typically, engineers consider the projected productivity of a platform over five years, and develop a solution equipped for shifting flow rates as well as likely pressure and temperature changes. This knowledge informs technology choices and enables integrators to optimize system design and configuration.
Any metering strategies or instruments changes need to bear witness to official guidelines from DECC. However, the guidance is not prescriptive and does not approve or recommend specific meters. Rather, it should be expertly interpreted by metering specialists, in consultation with both the operator and DECC representatives.
Prior to field start-up, operators provide DECC with a Functional Design Specification for the agreed measurement approach. This includes diagrams of piping systems immediately upstream and downstream of metering and sampling systems, as well as details of calculations, software, calibration procedures, and uncertainty analyses. When metering systems are upgraded or replaced, DECC must be consulted and notified of the strategy and its justification. Upon successful completion, installation, calibration, and testing of the new system, DECC issues a "notice of non-objection" to the operator for use with custody transfer systems.
DECC's recommendations are best described as an "ethos." To quote the guidelines, their purpose is to "provide operators with guidance on DECC's expectations as to what constitutes 'Good Oilfield Practice', as required by the Measurement Model Clause of an operator's Petroleum Production Licence, for the full range of fiscal measurement scenarios that are likely to be encountered in practice."
That is to say, if a platform produces several million barrels per day, it needs to use the best available metering systems appropriate to the application, with the lowest levels of uncertainty.
Uncertainty versus accuracy
Oil and gas metering involves intricate statistical analysis surrounding uncertainty values. The words "accuracy" and "uncertainty" are sometimes interchanged, but the actual difference between them is significant.
"Accuracy of measurement" is the older phrase and its internationally agreed definition is "…the closeness of the agreement between the result of a measurement and a true value of the measurand" (the medium being measured). The definition also notes that "accuracy is a qualitative concept" - it can be high or low, for example, but strictly speaking should not be used quantitatively.
However, in practice it is often used quantitatively by bending the definition to something like "the difference between a measured value and the true value." This leads to the use of phrases like "accurate to ±X." Unfortunately this unofficial definition breaks down because it inherently assumes that a "true" value can be defined, known, and realized perfectly. Even the finest national measurement laboratories cannot realize perfect values.
"Uncertainty of measurement" acknowledges that no measurements can be perfect, and is defined as a "parameter, associated with the result of a measurement, that characterizes the dispersion of values that could reasonably be attributed to the measurand." It is typically a range in which the value is estimated to lie, within a given statistical confidence, but it does not attempt to define or rely on a unique, "true" value.
So, common usage of the word "accuracy" for quantitatively describing the characteristics of measuring instruments is incompatible with its official meaning. What's more, its common usage definition is significantly cruder than the proper metrological term "uncertainty."
An important facet of metering best practice lies in understanding and interpreting ISO 5168, the international standard for evaluating uncertainty of a fluid flow rate or quantity. This standard provides a global landmark and creates a level playing field for all oil and gas metering specialists and operators. ISO 5168 looks at contributing components and uses sophisticated statistical methods to determine whether metering values comply with project specifications. It establishes common principles for procedures surrounding uncertainty calculations and forms the basis of the DECC guidelines.
A clear alignment with ISO 5168 from the outset of system development brings advantages. Understanding and referring to its principles throughout the engineering process can inform the selection and justification of different technologies integrated into a metering system. It enables recommendations to be qualified and can provide strong, evidence-based rationale for any deviations from the initial client brief for a project.
On an ongoing basis, metering specialists can assist operators in scheduling audits and calibrations. This helps prolong the life of older systems or maximize the working life of new systems while maintaining an acceptable level of uncertainty.
Condition-based monitoring is becoming more mainstream, using available data to ascertain whether a system is behaving as it should. Typically, software uses the data to generate diagnostic information and sound alarms for early detection of imminent failures or possible measurement errors. This is an advantage, but the extent to which it can be accomplished depends on the available diagnostic data from the instrumentation.
Metering best practice
When uncertainty measurements regularly exceed the agreed level, any equipment upgrade or replacement decisions are dictated partly by opex relative to the asset. There is a clear synergy between operator and DECC requirements. The more productive the platform, the more the operator can lose if uncertainty is too high. Likewise, a high-production platform pays a larger petroleum revenue tax (PRT) to DECC.
The combined challenges of aging platform performance, existing sales contract restrictions, and DECC guidance make metering best practice a balancing act. Even within these tight parameters there is a range of variables that can make the difference between a satisfactory metering system and an outstanding one.
Initially, specialist metering engineers conduct a detailed front-end engineering design study that analyzes past metering reports and log files. Understanding historic flow rates facilitates predictions of production trends over time. It is useful to see how productivity fluctuates as well as the upper and lower flow rates expected. Metering specialists normally collaborate with the operator's engineers to understand weight and size restrictions, as well as other practicalities surrounding installation. The logistics of removing obsolete equipment and shipping and maneuvering the new systems has a bearing on design. It is often necessary to manufacture skids in segments, since their route across the platform is as significant as the final space envelope.
Metering control systems need to follow the same philosophy of design strategy. Thorough, up-front understanding of operational and reporting requirements can ensure the system is intuitive and provides full data accountability.
Consideration of existing infrastructure and data reporting is paramount to facilitate integration. Comprehensive electrical and instrumentation design can ensure expensive, time-consuming installation work is at a minimum through measures such as reusing existing field cabling. And use of long life, standard form-factor servers designed for industrial/commercial use - as opposed to PCs - reduces the risk of obsolescence.
Various factors influence the selection, assembly, and configuration of a metering system. Making the most effective technology choices to minimize uncertainty is an important part.
Good repeatability - the ability of an instrument to produce the same result when measuring the same quantity - is one consideration. However, repeatability should not be confused with accuracy, since an instrument can be repeatedly wrong.
In addition to good design and careful manufacture, metering system performance depends on accurate and traceable calibration at an accredited laboratory. Complete metering systems need a traceability chain for every item that contributes to the final measurement. The uncertainty of all the relevant devices then must be combined in the correct manner and in the correct proportions to calculate the uncertainty for the whole system.
Further practical considerations include viscosity of process medium, pressure and temperature ranges, and fluctuation in typical flow rates and quantities. Decisions are also influenced by associated sampling and analysis technologies, which need to be precisely integrated to enhance overall performance. The quality of oil or gas produced - in terms of viscosity, density, and composition - can be as important as the quantity. For instance, the extent of any contamination (e.g. basic sediment and water in crude) impacts its value.
Different technologies have different benefits and features. Turbine meters are cost-effective with good short-term linearity for in-situ verification against a volumetric prover. Positive displacement meters are used for some high-viscosity liquids, but their maintenance costs make them bad choices for other fluids. The latest generation of proven technologies includes both ultrasonic meters with diagnostic capabilities, and coriolis meters, which generally are more tolerant of gas entrainment and provide a direct mass output.
To maintain a system's uncertainty credentials, a proving system often is integrated for in-situ verification of the liquid meter performance. Typically this involves a bi-directional prover, but other solutions may be more suited to the footprint available on an aging platform.
Dissemination of data must also be considered. Metering control systems can provide a wealth of information far beyond just totalized flow. With access to the entire spectrum of data from metering instruments, control systems can provide full traceability of operational alarms and events.
Industry-wide collaboration to address metering challenges objectively is the surest way to enhance future metering performance on aging platforms.
Consultation on international standards is one important area. This helps ensure a more level playing field between aging platforms, with their associated challenges and limitations (such as older contracts), and newer platforms being developed both on nearby fields and globally.
The science of measurement is always evolving, and in the face of increased North Sea asset longevity, operators seek greater responsibility from metering specialists. Clearly the deployment of proven flow measurement technologies is one part of this. But it goes beyond the supply of integrated packages to include involvement in the complete chain of the metering process, from concept through operational support.
Offshore metering is on the cusp of a significant new phase in its development to secure the extended life of older platforms. Long-term performance and traceability remain paramount, but pinpointing the right time to intervene where reduced measurement uncertainty is evidenced or predicted is also a key factor. More intelligent, expert-led metering strategies can bring significant bottom-line benefits to forward-thinking operators seeking to optimize aging offshore assets.