Regulations relating to fiscal measurement in the petroleum activities
Statutory authority: Issued by the Norwegian Petroleum Directorate on 21 April 2023 pursuant to Section 4-10 of the Act of 29 November 1996 No. 72 relating to petroleum activities, cf. Sections 26 and 86 of the Regulations of 27 June 1997 No. 653 to the Act relating to petroleum activities, and Section 5 of Act No. 72 of 21 December 1990 relating to tax on discharge of CO₂ in connection with petroleum activities on the continental shelf, cf. Decision on delegation of 27 December 1990 No. 1229.
EEA citations: EEA Agreement, Annex II, Chapter IX, paragraph 27e (Directive 2014/32/EU).
Table of contents
Chapter 1. Introductory provisions
Chapter 2. Requirements relating to management systems
Chapter 3. Requirements relating to measurement units and reference conditions
Chapter 4. General requirements relating to measurement
Chapter 5. Requirements relating to chemical analyses in laboratories
Chapter 6. Allocation requirements
Chapter 7. General requirements for measuring systems for dynamic measurement
Chapter 8. Special requirements for measuring systems for dynamic measurement of oil
Chapter 9. Special requirements for measuring systems for dynamic measurement of gas
Chapter 11. Special requirements for measuring systems and measurement of LNG
Chapter 12. Requirements for verification and calibration before a measuring system is used
Chapter 13. Requirements for operation and maintenance of measuring systems
Chapter 14. Requirements for materials and information
Chapter 15. General provisions
Chapter 1.
Introductory provisions
Section 1.
Objective
(1) The objective of these regulations is to ensure that accurate and reliable measurements form the basis for the calculation of taxes and fees to the Norwegian state, as well as the licensees’ revenues from the petroleum activities.
(2) These regulations provide additional provisions on the requirements for measuring quantities of produced petroleum and quantities subject to CO2 tax, cf. Section 26 of Regulation No. 653 of 27 June 1997 to the Act relating to petroleum activities (Petroleum Regulations) and Section 5 of Act No. 72 of 21 December 1990 relating to tax on discharge of CO2 in the petroleum activities on the continental shelf (CO2 Tax Act), as well as the requirements for management systems, measuring systems and documentation.
Section 2.
Scope of application
(1) These regulations relate to petroleum activities in areas covered by Section 1-4 of Act No. 72 of 29 November 1996 relating to petroleum activities (the Petroleum Act) and Section 2 of the CO2 Tax Act.
(2) Directive 2014/32/EU of the European Parliament and of the Council of 26 February 2014 (the Measuring Instruments Directive) shall apply for measuring systems for the continuous and dynamic measurement of quantities of liquids other than water (MI-005).
Section 3.
Definitions
The following definitions shall apply for these regulations:
- allocation, a mathematical process for determining what quantity of produced petroleum of a total production from the entire production system shall be assigned to an individual field/production licence,
- allocation measurement, measurement where the measurement result is included in an allocation. This does not comprise delivery measurement and CO2 tax measurement,
- working range, range defined by two values of a quantity that, under specific conditions, can be measured using a given measuring instrument or measuring system with a specified instrumental uncertainty. A measuring instrument or measuring system can have multiple working ranges,
- automatic sampler, a system capable of taking representative samples from fluids flowing through a pipe. The system consists of at least a sampling probe, an associated control unit and a sample container,
- indication, value given by a measuring instrument or measuring system,
- CO2 tax measurement, measurement where the measurement result forms the basis for calculating CO2 tax,
- direct measurement or direct measurement method, measurement method where the value of a measurand is obtained directly without the need for supplemental calculations based on a functional relationship between the measurand and other measured quantities. The measurement method remains direct even if supplemental measurements of influence quantities are necessary to make corrections,
- operating conditions, values of the measurand and influence quantities under which measuring instruments and measuring systems operate,
- disturbance, an influence quantity with a value that is outside the designated rated operating conditions for a measuring instrument or measuring system,
- limit value, maximum value for measurement error or uncertainty in the measurement of fluid characteristics and metrological characteristics,
- indirect measurement or indirect measurement method, measurement method where the value of the measurand is calculated through a functional relationship between other measurands, where these were obtained through direct measurement methods,
- installation effects, any difference in the performance of a measuring instrument or measuring system that occurs between the calibration under ideal conditions (laboratory conditions) and the actual operating conditions. For flow meters, this difference may be caused by different flow conditions due to the speed profile and disturbances, or by different operating conditions,
- instrumental measurement uncertainty, part of measurement uncertainty coming from a measurement instrument or measuring system in use,
- adjustment, set of operations carried out on a measuring system so that it provides prescribed indications corresponding to given values of a quantity to be measured. A calibration is a prerequisite for an adjustment,
- calibration, operations to determine, under specific conditions, the relationship between the indication of the instrument being calibrated and the value of a traceable measurement standard with documented uncertainty,
- calibration factor, concrete or abstract number indicating the relation between indication and reference value. The expression covers both what is called "meter factor" and "K-factor" internationally,
- linearity, a measuring instrument's ability to respond proportionally to the value of a quantity,
- calibration curve, expression of the relation between indication and corresponding value measured with a measurement standard,
- correction, a quantity in a measurement model that compensates for an estimated systematic error.
- delivery measurement (Custody transfer measurement), measurement with the purpose of obtaining quantity and quality information for use as physical and financial documentation in the event of changes in ownership and/or in connection with transporting petroleum by ship or pipeline to an onshore terminal,
- master meter, calibrated meter that is used to prove other meters,
- master meter prover, system of one or more master meters and associated equipment used to prove other meters,
- measurement error, measured quantity value minus a reference quantity value,
- measurement method, generic description of operations involved in a measurement,
- measurement model, mathematical relation among all quantities known to be involved in a measurement,
- measurement period, time interval between first and last measurement in a series or time interval for one measurement,
- meter or flow meter, instrument to perform continuous measurements of the volume and mass of a fluid under dynamic conditions,
- measurement result, values attributed to a measurand along with other relevant information, including measurement uncertainty,
- meter tube, pipe section with meter(s) and potentially sections for flow conditioning upstream and downstream of meter(s),
- measurand, quantity intended to be measured,
- measuring system, set of one or more measuring instruments and often other components, assembled and adapted to provide information that is used to produce measurement values within specified intervals for quantities of specified kinds,
- metrological traceability, property of a measurement result whereby the result can be traced to a reference through a documented and uninterrupted series of calibrations that each contribute to the measurement uncertainty,
- measurement uncertainty or uncertainty, parameter which characterises the dispersion of the values being attributed to a measurand. Measurement uncertainty is understood as expanded or relative expanded measurement uncertainty calculated with a coverage factor of 2, giving a confidence level of 95.45 %,
- measurement, process of experimentally obtaining one or more quantity values that can reasonably be attributed to a quantity. In addition to direct physical comparison, the process can include use of models and calculations based on theoretical considerations,
- rated operating conditions, operating conditions that must be fulfilled during a measurement in order for a measuring instrument or measuring system to perform as designed,
- produced (quantity) of petroleum, petroleum produced and sold, as well as petroleum produced for sale from fields in production and fields that have been shut down. Petroleum delivered free of charge or as compensation for another party is not considered sold.
- prover, equipment for proving flow meters in measuring systems for continuous and dynamic measurement of oil,
- proving or prove, in situ calibration to determine the calibration factor of a meter,
- sampling, all steps carried out to obtain a sample that is representative of the content of a pipe, tank or other container where the content shall be analysed,
- influence quantities, a quantity that is not the measurand, but which affects the measurement result. For example, influence quantities may be linked to weather-related, electrical and mechanical ambient conditions,
- repeatability, the degree of concurrence between the results of subsequent measurements of the same quantity, carried out using the same method, under the same conditions, by the same observer, using the same measuring system and with brief time intervals,
- representative sample, sample with a composition equal to the composition of the quantity from which the sample was taken,
- audit trail, documentation that makes it possible to reconstruct the course of events,
- displacement prover, equipment for proving oil meters, based on displacement of a body through a calibrated pipe,
- systematic measurement error, component of a measurement error that in replicate measurement remains constant or varies in a predictable manner,
- maximum permissible measurement error or error limit, the greatest permitted deviation from a reference value for a measurement, measuring instrument or measuring system,
- uncertainty budget, statement of a measurement uncertainty, of the components comprised by this measurement uncertainty and of their calculation and combination,
- uncertainty limit (target measurement uncertainty), upper limit for measurement uncertainty, determined based on the intended use of measurement results,
- associated measuring instrument, an instrument used to measure certain quantities that are characteristic for the fluid, and which are used as input quantities or a correction in a validation, confirmation that the requirements for a certain intended use or application have been fulfilled,
- verification, confirmation that specified requirements have been fulfilled.
Definitions in the Petroleum Act and Petroleum Regulations apply for these regulations. - verification, confirmation that specified requirements have been fulfilled.
Definitions in the Petroleum Act and Petroleum Regulations apply for these regulations.
Section 4.
Responsibility according to these regulations
(1) The licensee and other parties participating in petroleum activities comprised by these regulations are responsible according to these regulations and individual administrative decisions issued pursuant to these regulations.
(2) The licensee has a duty to ensure that anyone carrying out work for them, either personally, through employees, contractors or sub-contractors, complies with these regulations and individual administrative decisions issued pursuant to these regulations.
Chapter 2.
Requirements relating to management systems
Section 5.
Management system
(1) The licensee shall establish, follow up and further the development of a management system to ensure compliance with these regulatory requirements. The management system shall be part of the licensee’s overarching management system.
(2) The management system shall comprise internal requirements and routines for compliance with these regulatory requirements. The risk of inadequate compliance with requirements shall be taken into account in the design of internal requirements and routines.
(3) The management system shall include requirements to establish and maintain an archive for documents necessary to demonstrate compliance with these regulatory requirements.
(4) The management system shall describe the functions and responsibilities for all personnel with tasks relating to measuring instruments and measuring systems. The duties, responsibilities and authority of the personnel shall be described.
(5) The management system shall define functions with responsibility for following up measurements and measuring systems, including the responsibility for reviewing compliance with internal requirements and routines.
(6)The management system shall specify the necessary competence and how competence will be developed and transferred.
Section 6.
Internal audits
The licensee shall regularly conduct internal audits to ensure that the management system is effectively implemented and in accordance with these regulatory requirements. Audit results shall be documented. The frequency of internal audits shall be specified in the management system.
Chapter 3.
Requirements relating to measurement units and reference conditions
Section 7.
Measurement units
(1) Measurement units, including names and symbols, that comply with the International System of Units (SI system) shall be used. Standardised SI prefixes shall be used in front of a measurement unit to indicate a multiple or fraction of a measurement unit.
(2) Other measurement units and prefixes may be used in addition to those that follow from the first paragraph if this is in accordance with established practice or agreements with foreign states.
Section 8.
Reference conditions
(1) Standard volume [Sm3] shall be calculated at a reference temperature of 15 °C and a reference pressure of 101 325 Pa (absolute). For fluids with a vapour pressure higher than 101 325 Pa at 15 °C, the reference pressure shall be the equilibrium vapour pressure at 15 °C.
(2) The calorific value (energy per standard volume and energy per mass) shall be calculated at a reference temperature of 25 °C for the combustion and a reference pressure of 101 325 Pa.
(3) Other reference conditions may be used in addition to those that follow from the first and second paragraph if agreements with foreign states prescribe specific reference conditions.
Chapter 4.
General requirements relating to measurement
Section 9.
Measurement
Measurements of quantities of produced petroleum, burnt petroleum and gas emitted to air shall fulfil the requirements in this Chapter. When measuring other measurands, the licensee shall clarify measurement requirements with the .
Section 10.
Measurands and uncertainty limits
(1)Measurement of quantities of produced petroleum shall fulfil the requirements for measurands and uncertainty limits in Table 1. For allocation measurement, the licensee can define other uncertainty limits for measurands than those listed in Table 1, if it can be documented that fulfilling the listed uncertainty limits is not technically feasible or would lead to unreasonably high costs.
Table 1 (Requirements for measurement of produced quantities of petroleum)
| Measurement type: | Measurand | Uncertainty limit |
| Delivery measurement | Net quantity (standard volume or mass) of oil in a delivery or in a measurement period of one month | 0.30 % |
| Delivery measurement | Quantity (standard volume, mass or energy) of gas in a measurement period of one month | 1.0 % |
| Delivery measurement | Quantity (mass or energy) of LNG in a delivery | 0.5 % |
| Allocation measurement | Net quantity (standard volume or mass) of oil in a measurement period of up to one month | 0.5 % |
| Allocation measurement | Quantity (standard volume or mass) of gas in a measurement period of up to one month | 1.5 % |
(2) Measurement of quantities of burnt petroleum and natural gas emitted to air, as well as CO2 that is separated from petroleum and emitted to air, shall fulfil the requirements for measurands and uncertainty limits in Table 2. Wen particular reasons so warrant, the may, upon application, grant exemption from the uncertainty limit requirement in Table 2 for flared petroleum and natural gas emitted to air.
Table 2 (Requirements for measurement of quantities of burnt petroleum and natural gas emitted to air, as well as CO2 that is separated from petroleum and emitted to air)
| Measurement type: | Measurand | Uncertainty limit |
| CO2 tax measurement | Quantity (standard volume) of natural gas used as fuel for power and heat production in a measurement period of one month | 1.5 % |
| CO2 tax measurement | Quantity (volume) of diesel used as fuel for power and heat production in a measurement period of one month | Set by licensee |
| CO2 tax measurement | Quantity (standard volume) of flared petroleum in a measurement period of one month | 7.5 % |
| CO2 tax measurement | Quantity (standard volume) of natural gas emitted to air in a measurement period of one month | 7.5 % |
| CO2 tax measurement | Quantity (standard volume) of CO2 separated from petroleum and emitted to air in a measurement period of one month | 7.5 % |
Section 11.
Methods for measuring produced petroleum
(1) Measurement of quantities of produced petroleum shall be based on continuous dynamic direct measurement of single-phase flow variables. Other measurement methods can be used in the following situations:
- Measurement of quantities of oil and gas delivered to pipelines for transport to an onshore terminal or gathering system for further processing can be based on indirect measurement if it can be documented that direct measurement of single-phase flow variables is not technically feasible or would lead to unreasonably high costs.
- Measurement of quantities of petroleum delivered to a gathering system (allocation measurement) for further processing can be based on direct measurement or indirect measurement of multiphase flow variables if it can be documented that direct measurement of single-phase flow of petroleum is not technically feasible or would lead to unreasonably high costs.
(2) Measurement of quantities of LNG delivered to ships shall be based on static measurement of loaded volume. Measurement of quantities of LNG loaded onto tankers shall be based on weighing.
(3) Oil density shall be determined through continuous direct measurement under dynamic conditions. If it can be documented that it is not appropriate or would lead to unreasonably high costs to determine density through direct measurement, density can be determined through chemical analysis of representative oil samples.
(4) Trace quantities of water in oil shall be determined through chemical analysis of representative samples. Continuous direct measurement under dynamic conditions can be used if the method can be documented as equally accurate.
(5) Gas composition shall be determined through periodic or continuous gas chromatography of representative samples. For delivery measurement of gas, gas composition shall be measured continuously under dynamic conditions.
(6) The calorific value of natural gas shall be calculated from the gas composition.
(7) The density of natural gas shall be determined by continuous direct measurement under dynamic conditions or calculated from gas composition. Density calculated from gas composition can be used if the uncertainty is in accordance with the uncertainty limit for the relevant measurand in Section 10.
Section 12.
Methods for measuring burnt petroleum and gas emitted to air
(1) Measurement of quantities of burnt petroleum and natural gas emitted to air through a shared cold-venting system, as well as CO2 that is separated from petroleum and emitted to air, shall be based on continuous dynamic direct measurement of flow variables. Other measurement methods can be used in the following situations:
- Measurement of quantities of natural gas emitted to air through systems other than shared cold-venting systems, can be based on indirect measurement methods.
- Measurement of quantities of diesel used as fuel can be based on purchased diesel quantities.
(2) The gas composition of natural gas used for fuel shall be determined through periodic or continuous gas chromatography of a representative sample.
(3) The density of natural gas shall be determined by continuous direct measurement under dynamic conditions or calculated from gas composition.
Section 13.
Measurement principles
The licensee shall use measurement principles documented as suitable for use in the relevant measurement.
Section 14.
Measurement model
(1) The licensee shall establish a measurement model that in use is capable of providing values for the measurand and the associated measurement uncertainty that are consistent with the requirements in Section 10. The measurement model and input quantities, output quantities and corrections included in the resulting model and linked models, shall be documentable.
(2) The measurement model shall include correction for known measurable systematic effects if this improves the measurement. The correction's contribution to measurement uncertainty shall be low in relation to the measurands’ uncertainty limit. This does not apply for corrections for water vapour and shielding gas (inert gas) in flared petroleum and natural gas emissions if a higher target measurement uncertainty is defined for measuring these measurands pursuant to the section 10 second paragraph second sentence.
Section 15.
Uncertainty budget
(1) The licensee shall establish and maintain an uncertainty budget to demonstrate compliance with uncertainty limit requirements in Section 10.
(2) The budget shall be established in accordance with internationally recognised guidelines for evaluating and expressing measurement uncertainties.
(3) The uncertainty budget shall specify the measurement model, estimates and measurement uncertainty related to quantities in the measurement model, covariances, type of applied probability distributions, type of evaluation of measurement uncertainty and coverage factors. Uncertainty in estimates for missing or inadequate measurement data shall be taken into account in the uncertainty budget.
Section 16.
Measurement procedure
The licensee shall establish a measurement procedure. This shall be designed in a manner such that operating personnel can perform measurements in accordance with these regulatory requirements.
Section 17.
Measurement result
A measurement result shall
- have a measurement uncertainty within the uncertainty limit for the measurand,
- be metrologically traceable, and
- be expressed as a numerical value with a measurement unit.
Section 18.
Replacement for missing measurement data
The licensee shall replace missing measurement data with data calculated in a prudent manner. The replacement data and method used to calculate them shall be documentable.
Section 19.
Correction of measurement results
If significant systematic errors are proven in a measurement result, the licensee shall correct the result. The correction shall be performed in a prudent manner. The method, basis and result shall be documentable.
Chapter 5.
Requirements relating to chemical analyses in laboratories
Section 20.
Measurands and uncertainty limits
Chemical analysis of oil and gas samples shall comply with requirements for measurand and uncertainty limits in Table 3. Compliance with uncertainty limit requirements shall be demonstrated in an uncertainty budget.
Table 3 (Requirements for chemical analysis of oil and gas samples)
| Analysis type: | Measurand | Uncertainty limit |
| Physical properties of oil sample | Trace quantity of water (mass or volume percent) in an oil sample | Set by licensee |
| Physical properties of oil sample | Density (mass per standard volume) of an oil sample | 1.0 kg/Sm3 |
| Physical properties of gas sample | Molar mass (mass per mol) of a gas sample | 0.20 % |
| Physical properties of gas sample | Density (mass per standard volume) of a gas sample | 0.3 % |
| Physical properties of gas sample | Calorific value (energy per standard volume and energy per mass) of a gas sample | 0.3 % |
Section 21.
Requirements for analysis methods
(1) Trace quantities of water in oil samples in the range of 0.02 to 5.00 mass or volume percent shall be determined using coulometric Karl Fisher titration. Other methods can be used if the method can be documented as equally accurate. Analyses shall be performed on representative test samples.
(2) The density of oil samples shall be determined using a digital density analyser. Analysis shall be performed on representative test samples.
(3) The gas composition of gas samples shall be determined using gas chromatography.
(4)The molar mass, density and calorific value of gas samples shall be calculated from gas composition.
(5) Reference materials shall be suited to verify the performance of the analysis instruments.
Section 22.
Laboratory requirements
The licensee shall ensure that laboratories that carry out analyses of quantities in Table 3 have documented expertise in relevant analysis methods and traceability to national or international measurement standards.
Chapter 6.
Allocation requirements
Section 23.
Allocation system
(1) The licensee shall have an allocation system which ensures that produced petroleum is allocated fairly between licensees. It shall be possible to quality-assure and audit allocated quantities of petroleum.
(2) The choice of allocation method and equations of state (equations that specify the relationship between pressure, volume and temperature for a fluid) shall be documentable.
(3) Measuring instruments and measuring systems used to obtain values for input quantities in an allocation shall be identifiable.
Section 24.
Allocation procedures
Allocation procedures shall be established before the allocation system is utilised.
Section 25.
Verification and validation
(1) The licensee shall verify allocation calculations before they are utilised and following changes.
(2) The allocation system shall be validated within a reasonable period of time after it has been utilised and thereafter following changes that could affect the validity of the system.
Chapter 7.
General requirements for measuring systems for dynamic measurement
Section 26.
Design of measuring instruments and measuring systems
Measuring instruments and measuring systems shall have a design that complies with these regulatory requirements, including performance, operation and maintenance requirements, and shall be suitable for their intended use.
Section 27.
Rated operating conditions
Rated operating conditions for measuring instruments and measuring systems shall be documentable.
Section 28.
Instrumental measurement uncertainty
(1) Instrumental measurement uncertainties shall be in accordance with the uncertainty limit for the relevant measurand in Section 10.
(2) Instrumental measurement uncertainties shall be documented in an uncertainty budget.
Section 29.
Meter tubes and adjacent piping
(1) Meter tubes and adjacent piping (pipes and pipe components) shall be constructed and installed such that
- rated operating conditions for measuring instruments and the measuring system are met under normal operating conditions,
- maintenance and repairs, to the greatest possible extent, can be performed without losing measurement data and without affecting oil and gas production, and
- installation effects are minimised.
(2) Meter tubes shall
- have upstream and downstream flow conditioning sections adapted to the meter,
- include a flow conditioner if necessary to prevent or reduce flow disturbances at the meter. This does not apply to meter tubes with a flare gas meter or multiphase meter,
- have an internal surface that prevents or minimises pollutant build-up, and
- have no protrusions and irregularities in internal diameter that can cause turbulence, vortexes or a skewed flow profile that could disturb the measurement.
(3) Delivery measuring systems shall be constructed such that, during use under normal operating conditions, they can have at least one meter tube in reserve. This does not apply to measuring systems for delivery measurement of oil and gas transported by pipeline to an onshore terminal, if the meter tube is equipped with meters in series and frequent inspection and cleaning of the meter tube is not necessary.
Section 30.
Bypassing the measuring system
(1) It shall not be possible to bypass the measuring system during a measurement.
(2) Bypasses around meters and measuring systems shall be secured with line blinds or valves with a double block and bleed system. This does not apply for valves in pressure relief systems.
Section 31.
Measurement of temperature and pressure
(1) The temperature and pressure of the fluid shall be measured under dynamic conditions in each meter tube.
(2) Thermowells shall be installed in each meter tube. The thermowells shall be adapted to the temperature sensor and installed such that the temperature being measured corresponds to the temperature of the fluid flowing in the meter tube. An adjacent thermowell shall be available for verification purposes. Thermowells shall withstand flow-induced vibrations.
(3) Pressure taps and instrument pipes shall be constructed and installed such that measured values are representative for the quantity being measured.
Section 32.
Protection
(1) Measuring instruments and measuring systems shall be protected against disturbances, including electrical disturbances, mechanical disturbances and disturbances caused by weather-related conditions.
(2) Outdoor areas where control and calibration take place shall have sufficient weather protection.
(3) Measuring systems shall be protected against unauthorised intervention.
Section 33.
Monitoring and control
(1) The metrological condition of measuring instruments and measuring systems shall be monitored automatically, to the extent this is appropriate to achieve efficient operations and maintenance.
(2) The measuring instruments' built-in diagnostic parameters shall be used for control purposes.
(3)The integrity of all valves with significance for measurement shall be monitored. The method and equipment used for leak monitoring shall be assessed in relation to the risk of incorrect measurements.
Section 34.
Electronics
(1) Measurement data shall be transferred digitally from electronics to the measuring system’s computer system. Analogue transfer of measurement data can be used if it can be documented that digital transfer is impractical. The documentation requirement does not apply for pulsed data from meters. As regards pulsed data from meters, the greatest permitted error rate is one pulse per 100,000 pulses.
(2) It shall be possible to revise configuration and calibration data in electronics.
Section 35.
Computer system
(1) The measuring system shall include a computer system with algorithms for management, control, data collection and calculations ensuring that quantities of oil and gas can be determined in accordance with requirements in Section 10.
(2) Dynamic flow variables shall be sampled every second. The interval can be increased up to every five seconds if it can be documented that the measurement uncertainty does not increase by more than 0.05 %.
(3) Algorithm and rounding errors when calculating values for measurands shall be less than ± 0.001 % of the calculated value. This does not apply to pressure-volume-temperature (PVT) calculations. The licensee shall define acceptance limits for PVT calculations.
(4) The computer system shall generate an audit trail. As a minimum, the audit trail shall include a measurement report, configuration log, incident log, alarm log and calibration report.
(5) Data shall be secured against loss and manipulation. Algorithms shall be secured against unauthorised changes. Software versions with algorithms for calculating quantities shall have unique identifiers.
Chapter 8.
Special requirements for measuring systems for dynamic measurement of oil
Section 36.
Components of the oil measuring system
(1) Measuring systems for dynamic measurement of oil shall include meters, associated instruments, valves, computer system, manual sampling equipment and other equipment that is used to produce a measurement result.
(2) The delivery measuring system shall also include a stationary prover and automatic sampler.
Section 37.
Calibration methods for oil meters
(1) The calibration method for oil meters in a delivery measuring system shall be direct proving against a displacement prover or against a reference meter in series with a displacement prover. If it can be documented that such a calibration method will lead to unreasonably high costs and requirements in Section 28 for instrumental measurement uncertainty are safeguarded, proving against a master meter prover can be used.
(2)The calibration method for oil meters in an allocation measuring system shall be proving against a displacement prover, proving against a master meter prover or flow calibration at a laboratory. The choice of calibration method shall be based on the need for accuracy and characteristics of the fluid.
Section 38.
Oil meter
(1) An oil meter shall be suited to the measurement in question and operating conditions under which it will be used.
(2) in connection with laboratory flow calibration and calibration in situ, oil meters shall comply with the performance requirements in Table 4. The requirements apply over a flow rate range of at least 10:1 and before adjustment to a calibration curve. The quantities in the table shall be determined as follows:
- Measurement errors shall, at each flow rate, be determined as the mean value of subsequent single calibrations.
- The random uncertainty of the measurement error/calibration factor shall, at each flow rate, be determined through a type A evaluation of the uncertainty of the mean value of subsequent single calibrations.
- Linearity shall be determined as the difference between the highest and lowest measurement error over the flow rate range or as the relative difference between the highest and lowest calibration factor over the flow rate range. A calibration factor shall, at each flow rate, be determined as the mean value of subsequent single calibrations.
Table 4 (Requirements for oil meters during flow calibration)
| Limit value for: | Delivery measurements | Allocation measurement |
| Measurement error | ±0.20 % | ±0.25 % |
| Random uncertainty of measurement error or calibration factor | 0.027 % | 0.04 % |
| Linearity | 0.40 % | 0.50 % |
Section 39.
Displacement prover
(1) A displacement prover shall be adapted to the oil meters in a measuring system.
(2) In connection with calibration, the displacement prover shall comply with the performance requirements in Table 5. Base prover volumes shall be determined as the mean value of subsequent single calibrations. The quantities in the table shall be determined as follows:
- Repeatability in the base prover volumes measurement shall be determined as the relative difference between the highest and lowest value of three or more subsequent single calibrations.
- The combined uncertainty of the base prover volumes shall be determined through a type A evaluation of the uncertainty of the mean value of three or more subsequent single calibrations combined with the uncertainty of the calibration setup.
Table 5 (Displacement prover requirements in connection with calibration)
| Limit value for: | |
| Repeatability (three or more subsequent single calibrations) | 0.02 % |
| Combined uncertainty of base prover volumes (values on certificate) | 0.04 % |
Section 40.
Master meter prover
(1) A master meter prover shall
- be adapted to the oil meters in a measuring system, so that the meters can comply with the performance requirements in Table 4 in connection with proving,
- be constructed such that the risk of a disturbance resulting in the same error both on master meters and on a meter is minimised, and
- be adapted for in situ flow calibration. Flow calibration may take place ex situ if it can be documented that the contributions from installation effects to instrumental measurement uncertainty are insignificant, in addition to facilitating the monitoring of fluid effects and detection or inspection of deposits from the fluid in the meter tube.
(2) In connection with laboratory flow calibration or calibration in situ, master meters shall comply with the performance requirements in Table 6. The requirements apply over a flow rate range of at least 10:1 and before adjustment to a calibration curve. The quantities in the table shall be determined as follows:
- Measurement errors shall, at each flow rate, be determined as the mean value of subsequent single calibrations.
- The random uncertainty of the measurement error shall, at each flow rate, be determined through a type A evaluation of the uncertainty of the mean value of subsequent single calibrations.
- The combined uncertainty of the measurement error shall, at each flow rate, be determined as the random uncertainty of the measurement error combined with the uncertainty of the calibration setup.
- Linearity shall be determined as the difference between the highest and lowest measurement error over the flow rate range.
| Limit value for: | |
| Measurement error | ±0.20 % |
| Random uncertainty of measurement error | 0.027 % |
| Combined uncertainty of measurement error (value on certificate) | 0.06 % |
| Linearity | 0.20 % |
Section 41.
Measuring instruments associated with oil measuring system
(1) When used under rated operating conditions and in the absence of disturbances, associated measuring instruments shall comply with requirements relating to the greatest permitted measurement errors in Table 7.
(2) In connection with laboratory calibration, associated measuring instruments shall comply with requirements relating to the greatest permitted measurement error in Table 8.
Table 7 (Requirements for associated measuring instruments in use)
| Limit value for measurement error in the measurement of: | Delivery and allocation measurement |
| Temperature | ±0.20 °C |
| Pressure | ±20 kPa |
| Density | ±0.3 kg/m3 |
Table 8 (Requirements for associated measuring instruments during laboratory calibration)
| Limit value for measurement error in the measurement of: | Delivery and allocation measurement |
| Temperature | ±0.20 °C |
| Pressure | ±20 kPa |
| Density | ±0.3 kg/m3 |
Section 42.
Sampling equipment
(1) An automatic sampler shall
- be able to take a representative sample of the quantity of oil passing through the measuring system during the measurement period, and
- be configured for flow-proportional sampling.
(2) A manual sampler shall be able to take a sample that is representative of the quantity of oil passing through the measuring system at the time of sampling. The sampler shall include a sampling probe and isolation valve.
(3) Mixing equipment shall be installed in the pipeline if this is necessary to ensure that the oil is homogeneous during sampling.
Section 43. Algorithms and equations
Standardised and suitable algorithms and equations shall be used in the measuring system in order to
- correct for temperature and pressure effects on the density and volume of the oil,
- determine calibration factors, and
- calculate quantities of oil.
Chapter 9.
Special requirements for measuring systems for dynamic measurement of gas
Section 44.
Components of the gas measuring system
(1) Measuring systems for dynamic measurement of gas shall include gas meters, associated instruments, valves, computer system, sampling equipment and other equipment that is used to produce a measurement result.
(2) The delivery measuring system shall also include doubled online gas chromatographs.
Section 45.
Calibration methods for gas meters
(!) The calibration method for gas meters shall be flow calibration at an accredited calibration laboratory with documented measurement uncertainty and metrological traceability.
(2) The calibration method for flare gas meters and the primary element in differential pressure meters can be based on theoretical prediction procedures (a procedure for determining the dynamic performance of a meter theoretically without flow calibration).
Section 46.
Gas meter
(1) A gas meter shall be suited to the measurement in question and the operating conditions under which it will be used.
(2) During laboratory flow calibration, the gas meter shall comply with the performance requirements in Table 9. The requirements apply for calibration at flow rates within the specified flow rate range for the meter and before adjustment to the calibration curve. The transitional flow rate (flow rate through a meter where performance requirements can be changed) shall not exceed 20 % of the maximum flow rate. The quantities in the table shall be determined as follows:
- Measurement errors shall, at each flow rate, be determined as the mean value of subsequent single calibrations.
- The combined uncertainty of the measurement error shall, at each flow rate, be determined through a type A evaluation of the uncertainty of the mean value of subsequent single calibrations, combined with the uncertainty of the calibration setup.
- Linearity shall be determined as the difference between the highest and lowest measurement error over the flow rate range.
Table 9 (Requirements for gas meters during flow calibration)
| Limit value for: | Delivery measurement | Allocation measurement | CO2 tax measurement (fuel gas) |
| Measurement error | |||
| Flow rate ≥ transitional flow rate | ±1.0 % | ±1.5 % | ±1.5 % |
| Flow rate < transitional flow rate | ±2.0 % | ±3.0 % | ±3.0 % |
| Combined uncertainty of measurement error | |||
| Flow rate ≥ transitional flow rate | 0.33 % | 0.5 % | 0.5 % |
| Flow rate < transitional flow rate | 0.67 % | 1.0 % | 1.0 % |
| Linearity | |||
| Flow rate ≥ transitional flow rate | 1.0 % | 1.0 % | 1.0 % |
| Flow rate < transitional flow rate | 2.0 % | 2.0 % | 2.0 % |
Section 47.
Measuring instruments associated with gas measuring system
(1) When in use under rated operating conditions and in the absence of disturbances, associated measuring instruments shall comply with requirements relating to the greatest permitted measurement error in Table 10.
(2) In connection with laboratory calibration, associated measuring instruments shall comply with requirements relating to the greatest permitted measurement error in Table 11.
Table 10 (Requirements for associated measuring instruments in use)
| Limit value for measurement error in the measurement of: | Delivery and allocation measurement | CO2 tax measurement |
| Temperature | ±0.3 °C | ±0.5 °C |
| Pressure | ±1.5 kPa for pressure ≤ 0.5 MPa ±0.3 % for pressure > 0.5 MPa |
±1.5 kPa for pressure ≤ 0.5 MPa ±0.3 % for pressure > 0.5 MPa |
| Differential pressure | ±30 Pa for pressure ≤ 10 kPa ±0.3 % for pressure > 10 kPa |
±30 Pa for pressure ≤ 10 kPa ±0.3 % for pressure > 10 kPa |
| Density | ±0.3 % | ±0.3 % |
Table 11 (Requirements for associated measuring instruments in connection with laboratory calibration)
| Limit value for measurement error in the measurement of: | Delivery and allocation measurement | CO2 tax measurement |
| Temperature | ±0.2 °C | ±0.3 °C |
| Pressure | ±0.5 kPa for pressure ≤ 0.5 MPa ±0.1 % for pressure > 0.5 Mpa |
±0.5 kPa for pressure ≤ 0.5 MPa ±0.1 % for pressure > 0.5 Mpa |
| Differential pressure | ±10 Pa for pressure ≤ 10 kPa ±0.1 % for pressure > 10 kPa |
±10 Pa for pressure ≤ 10 kPa ±0.1 % for pressure > 10 kPa |
| Density | ±0.2 % | ±0.2 % |
Section 48.
Online gas chromatograph
(1) During verification and calibration, an online gas chromatograph shall be able to separate gas components and measure them individually, so that the quantities in Table 12 can be determined with an uncertainty that is within the described uncertainty limits.
(2)Regular verification and calibration against certified calibration gas shall be facilitated.
(3)Monitoring of long-term tendencies in response factors and retention times shall be facilitated.
Table 12 (Requirements for online gas chromatographs during verification and calibration)
| Limitvalue for uncertainty of calculated: | |
| Molar mass (mass per mol) | 0.20 % |
| Calorific value (energy per mass and energy per standard volume) | 0.30 % |
Section 49.
Sampling equipment
(1) A system for direct sampling shall be constructed such that representative single-phase gas samples are transferred to the gas chromatograph. The sampling equipment shall include a sampling probe, transfer line and a pressure reduction device with pressure and temperature measurement. The equipment shall be constructed such that the sampler can be flushed with inert gas. It shall be ensured that there is no leakage between calibration gas and sample.
(2) A manual sampler shall be able to fill a suitable cylinder with a sample that is representative for the gas flowing in the pipe at the time of sampling. The sampler shall include a suitable sampling probe and isolation valve.
Section 50.
Algorithms and equations
- calculate quality parameters for gas, including density and calorific value,
- correct for temperature and pressure effects, and
- calculate gas quantities.
Chapter 10.
Special requirements for measuring systems for dynamic measurement of multiphase petroleum
Section 51.
Components of the multiphase measuring system
Section 52.
Calibration methods for multiphase meters
(1) The calibration method for multiphase meters on deck facilities shall be in situ calibration against measurements of single-phase flows on the separator outlet.
(1) The calibration method for meters on subsea facilities shall be in situ calibration against measurements of single-phase flow of oil, gas and water on the separator outlets, in situ calibration against a reference measuring system or flow calibration at a laboratory. The chosen method shall be based on what is technically feasible and financially prudent.
Section 53.
Multiphase meter
Section 54.
Separator measuring system
(1) A separator measuring system shall include flow meters on oil and gas outlets. The water meter on the separator water outlet is a part of the separator measuring system if it is used for fiscal purposes. Sampling equipment shall be connected to the separator outlets.
(2)Meters on oil and gas outlets on the separator shall comply with the performance requirements for meters in allocation measuring systems in Chapters 8 and 9. The licensee shall be able to specify the uncertainty limit for instrumental measurement uncertainty of water meters that are part of the separator measuring system.
(3)Measuring instruments associated with the separator measuring system shall comply with performance requirements for measuring instruments associated with allocation measuring systems in Chapters 8 and 9.
Section 55.
Algorithms and equations
Chapter 11.
Special requirements for measuring systems and measurement of LNG
Section 56.
General requirements for measurement of LNG
(1) Refrigerated liquefied natural gas (LNG) shall be measured and analysed at the terminal where LNG is loaded onto ships or tanker trucks.
(2) Measurement of LNG that is loaded onto ships shall be witnessed by an independent surveyor. The surveyor shall calculate the loaded quantity of LNG and issue a final quantity report.
(3) The licensee shall verify and be able to document that the measuring system and measurements used to determine that loaded quantities of LNG comply with these regulatory requirements.
Section 57.
Static measurement of volume and mass
(1) Measuring systems, including level measuring equipment and associated measuring instruments used to measure the quantity of LNG loaded onto ships, shall be calibrated and certified. Tank tables and correction tables shall be certified.
(2)The weighbridge used to weigh the quantity of LNG loaded onto tanker trucks shall be calibrated and certified.
Section 58.
Sampling equipment
The sampling equipment shall be constructed and installed such that conditioned and representative samples of LNG flowing in the transfer line from terminal to ship, are transferred to an analyser. The sampling shall be continuous during loading of LNG to ships.
Section 59.
Gas chromatography
(1) Online gas chromatographs shall be used to measure the LNG composition.
(2) In connection with verification and calibration, gas chromatographs shall comply with the performance requirements in Table 12.
Section 60.
Density and calorific value
Calorific value and density shall be calculated from the measured average gas composition of LNG loaded onto ships or tanker trucks. Calculations shall be based on recognised methods and equations of state.
Section 61.
Measurement of the energy of displaced gas and consumed gas
(1) The quantity of energy of gas displaced from LNG tanks while loading LNG on board ships and returned to onshore facilities, shall be determined by measurement.
(2) The quantity of energy in evaporated gas used for fuel on LNG ships during loading shall be determined by measurement.
Chapter 12.
Requirements for verification and calibration before a measuring system is used
Section 62.
Preconditions for using measuring instruments and measuring systems
Verifications and calibrations shall be performed before measuring instruments and measuring systems are used at the usage location for the first time and following major reconstructions or modifications.
Section 63.
Plans and procedures for verifications and calibrations
(1) The licensee shall establish plans and procedures for verifications and calibrations. These procedures shall include acceptance criteria for verifications and calibrations that are consistent with these regulatory requirements.
(2) The shall be given the opportunity to be present in connection with verifications and calibrations.
Section 64.
Calibration and adjustment of measuring instruments
(1) Measuring instruments shall be calibrated such that instrumental measurement uncertainty can be determined and metrological traceability established.
(2) Calibration shall take place in such a manner that systematic effects as a result of differences between calibration and operating conditions are avoided or compensated for.
(3) Meters shall be adjusted following calibration. Other measuring instruments shall be adjusted if calibration reveals significant instrumental biases. The adjustment shall take place in a manner ensuring the lowest possible measurement uncertainty in the working range. Adjustments shall be verified. Instrumental biases shall not be exploited for financial gain or other benefits.
Section 65.
Use of laboratories for calibration
Calibrations shall be performed at laboratories accredited in accordance with the internationally recognised standards for the relevant calibration methods. If it can be documented that use of an accredited laboratory is not possible or would lead to unreasonably high costs, non-accredited laboratories can be used, given that the licensee can document that the laboratory can carry out calibrations with accuracy equivalent to that of accredited laboratories.
Section 66.
Measurement standards
The licensee shall be able to document measurement uncertainty and metrological traceability of measurement standards used for verification and calibration. The measurement standard shall have a measurement uncertainty that is sufficiently low as to allow verification of these regulatory requirements relating to metrological performance of the equipment being tested.
Section 67.
Flow calibration of oil meters
(1) An oil meter shall be flow calibrated. A calibration curve shall be established with at least five calibration points over a flow rate range covering the meter’s working range. The performance requirements in Section 38 second paragraph shall apply in connection with flow calibration of oil meters.
(2) Calibration shall be carried out under conditions as close to the operating conditions for the meter as practicable and with a representative fluid.
(3) The meter shall be calibrated along with the upstream pipe section. The meter can be calibrated in a pipe configuration that is similar to the meter tube if this yields sufficient accuracy and it can be documented that calibration along with the upstream pipe section is not technically feasible or would lead to unreasonably high costs.
(4) Data that can form a baseline for the meter in use shall be collected during the calibration if possible. As regards electronic meters, configuration data and checksums shall be registered during a calibration and after adjustment.
Section 68.
Calibration of displacement prover
(1) The base volume of the displacement prover shall be calibrated prior to functional testing and inspection of the measuring system at the construction site. The performance requirements in Section 39 second paragraph shall apply in connection with calibration of displacement provers.
(2) The base volume of the displacement prover shall be re-calibrated immediately before the measuring system is used at the usage location. Simultaneously, checks shall be made to ensure that there are no leaks in valves or around the displacement medium (ball or piston). All detectors shall be sealed following calibration. The entire signalling pathway, from each detector to the computer system, shall be checked.
Section 69.
Flow calibration of master meters
(1) A master meter shall be flow calibrated. A calibration curve shall be established with at least five calibration factors over a flow rate range covering the working range of the meters that the master meters shall prove during operation. Discrepancies between two adjacent calibration factors on the calibration curve shall not exceed 0.05 %. The performance requirements in Section 40 second paragraph shall apply in connection with flow calibration of master meters.
(2) Calibration shall be carried out under thermodynamic conditions as close to the operating conditions for the master meter as practicable and with a representative fluid.
(3) The master meter shall be calibrated in the meter tube along with pipe sections for flow conditioning.
(4) The master meter shall be adjusted following a calibration.
(5) Data which can form a baseline for the master meter in use shall be collected during calibration if possible.
Section 70.
Flow calibration of gas meters
(1) A gas meter shall be flow calibrated. A calibration curve shall be established with at least five calibration points over a flow rate range covering the meter’s working range. The performance requirements in Section 46 second paragraph shall apply in connection with flow calibration of gas meters.
(2) The calibration shall be carried out under conditions as close to the operating conditions for the meter as practicable and with a representative fluid.
(3) The meter shall be calibrated along with the upstream pipe section. The meter can be calibrated in a pipe configuration equivalent to the meter tube if this yields sufficient accuracy and it can be documented that calibration along with the upstream pipe section is not technically feasible or would lead to unreasonably high costs.
(4) Data that could form a baseline for the meter in use shall be collected during the calibration if possible. As regards electronic meters, configuration data and checksums shall be registered during a calibration and after adjustment.
Section 71.
Flow calibration of multiphase meters
Multiphase meters, individually or selected ones in a series, shall be flow calibrated over a selection of gas, oil and water fractions that are as representative as possible for the meter's expected operating conditions.
Section 72.
Calibration and verification of associated measuring instruments
(1) Measuring instruments for temperature, pressure and density shall be calibrated over a range covering, as a minimum, the working range for the measuring system.
(2) The entire signal path, from each sensor to the computer system, shall be checked and verified.
Section 73.
Verification of gas chromatographs
(1) Gas chromatographs shall be tested for repeatability and response linearity. Working ranges shall be established, including for response linearity.
(2) Response functions for all gas components shall be validated.
(3) Calibration gas and test gases shall be certified. The certificates shall state the uncertainty of all gas components. The gases shall have a range of variation in composition that covers the working range of the gas chromatographs.
Section 74.
Verification of sampling equipment
The performance of the sampling equipment shall be verified.
Section 75.
Measurement and control of physical constants
(1) Geometric constants included in the measuring system, and which are used to calculate the measurand shall be metrologically traceable and have a measurement uncertainty that corresponds with requirements for the measuring system’s instrumental measurement uncertainty in Section 28.
(2) All material constants used in calculations shall be controlled.
Section 76.
Verification of computer systems
(1) Before the measuring system’s computer system is used, all algorithms shall be tested and verified at the supplier and at the usage location.
(2) It shall be verified that all functions are operative and that all calculations have an accuracy corresponding to these regulatory requirements.
(3) Verification of fluid flow calculations shall be performed for at least one value in the working range.
(4) Verification of the accumulation of measured volume and mass increments shall be performed. The accumulation for at least one value in the working range shall be checked.
(5) Calculations of calorific value and density shall be verified.
(6) Tests shall be performed verifying that data, including calibration data and configuration data, are preserved in the event of power outages.
(7) This provision shall not apply for computer systems that have undergone conformity assessment pursuant to requirements in the Measuring Instruments Directive.
Section 77.
Testing of assembled measuring systems and automatic sampling systems
(1) Assembled measuring systems shall be tested at the usage location before being used.
(2) Assembled measuring systems for delivery measurements of oil shall also be tested with liquid flow at the construction site. These tests shall include testing of the proving function.
(3) Assembled automatic sampling systems shall be tested at the construction site.
Chapter 13. Requirements for operation and maintenance of measuring systems
Chapter 13.
Requirements for operation and maintenance of measuring systems
Section 78.
General requirements for operation and maintenance
(1) The licensee shall ensure that operation and maintenance of measuring instruments and measuring systems comply with these regulatory requirements, thus ensuring that they can be operated and function as planned and such that the level of quality is maintained.
(2) The licensee shall establish, follow up and further develop procedures for operation and maintenance of measuring systems. Personnel with operating and maintenance responsibilities shall be familiar with these procedures.
(3) The licensee shall have a maintenance and spare parts system. The maintenance system shall comprise all components of a measuring system and satisfy these regulatory requirements concerning maintenance, verification, control, etc. The licensee is responsible for ensuring spare parts are available so that repairs and replacements can take place within a reasonable timeframe.
(4) Incidents concerning measuring instruments and measuring systems and which could result in deviations from these regulatory requirements shall be registered.
(5) Deviations from these regulatory requirements due to malfunctions in measuring equipment and measuring systems shall be registered in a nonconformance management system. A registered deviation shall be corrected as soon as practicable. The causes of the deviation shall be clarified and corrective measures implemented to prevent recurrence of the deviation.
(6) Measuring instruments and measuring systems shall be re-calibrated following modifications and repairs if necessary to maintain accuracy and metrological traceability.
Section 79.
Maintenance programme
(1) The licensee shall establish and implement a maintenance programme for measuring instruments and measuring systems, including shut-off valves and other valves of significance for measurement.
(2) The programme shall include activities for checking the performance and technical condition of measuring instruments and measuring systems, and for monitoring trends that could lead to deviations from these regulatory requirements.
(3) A plan shall be established with associated deadlines for executing the individual activities in the maintenance programme.
Section 80.
Calibration programme
(1) The licensee shall establish and implement a calibration programme for measuring instruments and measuring systems. The programme shall include all measuring instruments of significance for the accuracy and metrological traceability of the measurement result.
(2) A plan shall be established with associated deadlines for implementing the individual calibrations in the programme.
(3) Calibration intervals shall be evaluated following calibration and shortened if necessary to ensure compliance with performance requirements.
Section 81. Working standards
(1) Working standards shall be calibrated with traceability to the SI system and with an accuracy corresponding to the intended use. Maintenance and calibration shall take place pursuant to the maintenance programme and calibration programme.
(2) Working standards shall only be used for verification and calibration of measuring instruments or measuring systems unless it can be documented that the performance as a standard will not be invalid if used for other purposes.
Section 82.
Evaluation of measurement data during verification
Uncertainty in measurement data shall be determined and taken into account when results from verification are assessed against these regulatory requirements as regards performance and when stipulating acceptance limits.
Section 83.
Operation and maintenance of oil meters
(1) An oil meter shall be used in the working range under operating conditions corresponding to the meter's rated operating conditions. Maintenance and calibration shall take place pursuant to the maintenance programme and calibration programme.
(2) A meter in a measuring system with a prover shall be proved:
- As soon as possible after start-up to verify compliance with performance requirements in Section 38 and to determine the sensitivity of the calibration factors in relation to variations in the measurand and in influence quantities, as well as to determine validity ranges for the calibration factors.
- At least every four days, if the meter is being used to measure oil delivered to pipeline. The interval can gradually be increased to every 14 days if stable operating conditions and acceptable reproducibility can be documented.
- At least once per loading period if the meter is used when measuring oil delivered to tanker.
(3) A meter in a measuring system without a prover shall be calibrated at least annually in situ or in a laboratory. This shall not apply if the meter or meter tube is subject to a preventive maintenance system which ensures that requirements for instrumental measurement uncertainty are fulfilled.
(4) A control chart for monitoring the long-term trends of calibration factors shall be established and maintained for each meter and for each fluid, if the meter is used to measure different fluids. The chart shall have expedient control limits.
(4) A meter shall be proved or recalibrated if the calibration factor is no longer valid.
Section 84.
Operation and maintenance of provers
(1) A prover (displacement prover or master meter prover) shall be used in the working range and under operating conditions corresponding to rated operating conditions for the prover. Maintenance and re-calibration shall be carried out pursuant to the maintenance programme and calibration programme.
(2) Proving shall take place pursuant to the operational procedure and under conditions as similar as practicable to the normal operating conditions of the meter being proved. The operating pressure at the meter and prover shall during proving be higher than the vapour pressure of the fluid.
(3) The proving result shall be in accordance with the performance requirements in Section 38 for the meter to be proved and be based on an evaluation of three to 20 subsequent single calibrations. If the proving result is outside set control limits, it shall be verified before being used. The quantity of oil loaded onto ships shall be re-calculated following the first approved proving. The calibration factor established in the first approved proving shall be used to calculate the remaining quantity or until a new calibration factor is established.
(4) As a minimum, a displacement prover shall be calibrated in situ annually. The calibration interval can be gradually increased to every three years if it can be documented that annual calibration would lead to unreasonably high costs and it can be substantiated that performance requirements in Section 39 will be met.
(5) As a minimum, a master meter prover shall be calibrated annually.
Section 85.
Operation and maintenance of gas meters
(1) A gas meter shall be used in the working range under operating conditions corresponding to rated operating conditions for the meter. Maintenance and calibration shall be carried out pursuant to the maintenance programme and calibration programme.
(2) As a minimum, a gas meter shall be calibrated every five years. This shall not apply if the meter or meter tube is subject to a preventive maintenance system which ensures that requirements for instrumental measurement uncertainty are fulfilled.
(3) As a minimum, metrological characteristics of flare meters shall be verified annually.
(4) Meter tubes shall be regularly inspected internally at an interval set in the maintenance plan and in the event of indication of conditions that could impact meter performance. The choice of inspection interval shall take into consideration the risk of measurement errors. Requirements concerning periodic interior inspection shall not apply for meter tubes on subsea facilities or where the meter tube's condition can be monitored without interior inspection.
Section 86.
Operation and maintenance of multiphase meters
(1) A multiphase meter shall be used in the working range under operating conditions corresponding to rated operating conditions for the meter. Maintenance and calibration shall be carried out pursuant to the maintenance programme and calibration programme.
(2) The flow regime shall be monitored. A control chart for basic parameters, including differential pressure and density, shall be established and maintained. The chart shall have expedient control limits for the parameters.
(3) The maintenance plan shall, where practicable, comprise verification of flow calculations, maintenance of PVT data and inspection of the instrument pipes, sensors and instruments that are an integrated part of the multiphase meter.
Section 87.
Operation and maintenance of associated measuring instruments
(1) Measuring instruments associated with the measuring system shall be used in the working range under operating conditions corresponding to rated operating conditions for the instrument. Maintenance and calibration shall be carried out pursuant to the maintenance programme and calibration programme.
(2) Gas densitometers shall be verified against calculated density.
(3) Differential pressure transmitters calibrated at atmospheric conditions shall be verified under normal operating conditions.
Section 88.
Operation and maintenance of online gas chromatographs
(1) An online gas chromatograph shall be used in the working range under operating conditions corresponding to rated operating conditions. Maintenance and calibration shall be carried out pursuant to the maintenance programme and calibration programme.
(2) If a gas chromatograph is outside the limit values in Section 48 in connection with verification, calibration and adjustment shall be carried out and new factors established. Following such adjustment, a new verification shall be carried out to confirm that the gas chromatograph's performance is within set limit values.
(3) Gas composition shall be monitored. If measured components are outside established linearity intervals, the cause shall be clarified and new linearity intervals established.
(4) The calibration gas shall have a composition representative of the gas being analysed. The components of the calibration gas shall have documented uncertainty limits and shall be certified by a laboratory that is accredited on the relevant analysis method.
(5) Gas chromatograms, response factors and retention times shall be checked regularly.
(6) Fallback values for gas composition shall be regularly checked and updated when necessary.
Section 89.
Operation and maintenance of samplers
(1) A sampler shall be used in a manner ensuring that representative samples form the basis for chemical analyses. Verification, validation and maintenance shall be carried out pursuant to the maintenance programme.
(2) Sampling with an automatic sampler shall be monitored in a manner ensuring acceptable samples. Manual samples shall be taken if the automatic sampler does not function as intended.
Section 90.
Operation and maintenance of computer systems
(1) The measuring system’s computer system shall be checked according to established routines. Manually entered parameters shall be individually checked, including against the calibration certificate and supplier documentation.
(2) Appropriate alarm and control limits for measuring instruments and measuring systems shall be established and maintained. Measurement uncertainties, including the uncertainty of the discrepancy in values provided by two instruments, shall be taken into account when control limits are set.
(3) A clear audit trail shall be established and maintained. Critical data shall be regularly archived.
(4) Procedures shall be established for handling error alerts from the computer system or errors discovered another way.
(5) A verification of calculations shall be carried out in connection with changes that are significant for calculation accuracy, including programme changes, replacement of computer parts and changes in instrumentation.
(6) Essential computer files shall be backed up.
Chapter 14.
Requirements for materials and information
Section 91.
General requirements for materials and information
(1) The licensee shall store the materials and information necessary to document and ensure that the activities are planned and carried out in compliance with these regulatory requirements. The licensee shall store materials and information pursuant to Section 55 of the Petroleum Regulations.
(2) The can demand access to materials and information as mentioned in the first paragraph.
Section 92.
Information prior to BOV
Prior to a Decision to Continue (BOV), the licensee shall inform the of its measurement concept.
Section 93.
Information about measurement in PDOs and PIOs
Plans for development and operation of a petroleum deposit (PDOs) and plans for installation and operation of facilities for utilisation of petroleum (PIOs) pursuant to Sections 4-2 and 4-3 of the Petroleum Act shall, to the extent necessary, contain information about the measurement concept and any non-compliance from provisions in these regulations.
Section 94.
Applications for consent for start-up and continuation of measuring systems
(1) Before the licensee can conduct petroleum activities as mentioned in items a) through c) in the second paragraph, consent for start-up or continuation from the is required.
(2) Consent as mentioned in the first paragraph must be obtained:
- before the measuring system is used for the first time,
- before the measuring system or parts of it are used after major reconstructions or modifications, and
- before changing the purpose of use that is not comprised by consent pursuant to Item a).
(3) An application for consent pursuant to the second paragraph shall contain information demonstrating that the measuring system complies with these regulatory requirements.
Section 95.
Information about measurement in the annual status report
The annual status report pursuant to Section 47 of the Petroleum Regulations shall, to the extent necessary, contain information about measurement, measuring systems and allocation, cf. Section 35 of the Resource Regulations.
Section 96.
Uncertainty budget for CO2 tax measurements
Each year, the licensee shall submit uncertainty budgets for CO2 tax measurements to the Norwegian Offshore Directorate pursuant to Section 15. The uncertainty budget for each measurement period shall be submitted by 1 March the following year.
Section 97.
Other information
(1) The licensee shall submit information about the following to the Norwegian Offshore Directorate as soon as possible:
- errors that may provide a basis for major corrections of measurement results,
- errors in the essential components of measuring systems and plans to correct such errors,
- expansion of calibration intervals,
- agreements and procedures that are significant for measurement, including transport agreements, loading replacement procedures that apply for the sale of oil (crude oil, condensate, NGL) and allocation procedures.
(2)Upon request, the licensee shall submit information to the Norwegian Offshore Directorate concerning cargoes of oil and other petroleum products.
(3) Upon request, operators of pipeline systems shall submit a complete overview of material balances in pipeline systems to the Norwegian Offshore Directorate.
Chapter 15.
General provisions
Section 98.
Supervisory authority – authority to make individual administrative decisions, etc.
(1) The Norwegian Offshore Directorate shall supervise compliance with provisions laid down in or decisions made pursuant to these regulations.
(2) The Norwegian Offshore Directorate may make individual administrative decisions to ensure compliance with these regulations.
Section 99.
Exemption
(1) The Norwegian Offshore Directorate may in particular cases grant exemption from provisions laid down in these regulations.
(2)Applications for exemptions pursuant to the first paragraph shall be substantiated.
Section 100.
Penal provision
Violation of these regulations or of decisions made pursuant to these regulations shall be punishable as stipulated in Section 10-17 of the Petroleum Act and Section 7 of the CO2 Tax Act.
Section 101.
Entry into force and transitional provisions
(1) These regulations enter into force on 1 May 2023. From the same date, the Regulation No. 1234 of 1 November 2001 relating to measurement of petroleum for fiscal purposes and for calculation of CO2 tax shall be repealed.
(2) Decisions made pursuant to Regulation No. 1234 of 1 November 2001 relating to measurement of petroleum for fiscal purposes and for calculation of CO2 tax shall apply until they are potentially revoked or changed by the Norwegian Offshore Directorate.
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English version is not necessarily updated according to recent changes at any time.
Updated: 15/03/2024