Statutory authority: Issued by the Norwegian Offshore 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 10. Special requirements for measuring systems for dynamic measurement of multiphase petroleum

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 calculating 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, measurement methods, 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:

1. 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 or production licence,
2. allocation measurement, a measurement where the measurement result is included in an allocation. This does not comprise delivery measurement and CO2 tax measurement,
3. working range, a 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 measurement uncertainty. A measuring instrument or measuring system can have multiple working ranges,
4. 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,
5. indication, a value of a quantity obtained by a measuring instrument or measuring system,
6. CO2 tax measurement, a measurement where the measurement result forms the basis for calculating CO2 tax,
7. direct measurement or direct measurement method, a measurement method where the value of a quantity is obtained directly by means of a measuring instrument or measuring system, without the need for supplemental calculations. The measurement method remains direct even if it is necessary to measure influence quantities to make corrections,
8. operating conditions, the values of the measurand and influence quantities under which measuring instruments and measuring systems operate,
9. disturbance, an influence quantity with a value that is outside the designated rated operating conditions for a measuring instrument or measuring system,
10. limit value, a maximum value for a measurement error or measurement uncertainty,
11. indirect measurement or indirect measurement method, a measurement method where the value of a quantity is determined from direct measurements of other quantities that are related to the measurand through a known relationship,
12. installation effect, any difference in the performance of a measuring instrument or measuring system that occurs between calibration under ideal conditions (laboratory conditions) and actual operating conditions,
13. instrumental measurement uncertainty, the part of measurement uncertainty that come from a measurement instrument or measuring system in use,
14. adjustment, a set of operations carried out on a measuring instrument or measuring system so that the indication corresponds to given values of a quantity to be measured. A calibration is a prerequisite for an adjustment,
15. calibration, a set of operations to determine, under specific conditions, the relationship between an indication of the instrument being calibrated and value of a traceable measurement standard with documented uncertainty,
16. calibration factor, a number with or without units, that indicates the relation between an indication (reading) and a reference value. The term covers both what is internationally referred to as "meter factor" and "K-factor",
17. calibration curve, a curve or graph that describes the relationship between instrumental indications and corresponding value measured with a measurement standard,
18. correction, a quantity in a measurement model that compensates for an estimated systematic error.
19. delivery measurement, a measurement to obtain quantity and quality information for use as physical and economic documentation in the event of changes in ownership and/or transport of petroleum by ship, tanker truck, or pipeline to an onshore terminal,
20. linearity, a measuring instrument's ability to respond proportionally to the value of a quantity,
21. master meter, a calibrated meter that is used to prove other meters,
22. master meter prover, a system of one or more master meters and associated equipment used to prove other meters,
23. 1. measurement error, a dimensioned or dimensionless number indicating the difference between a measured value and a reference value. The term is used in these regulations to refer to absolute measurement errors (measured value minus reference value), relative measurement errors (absolute measurement error divided by reference value), and mean relative measurement errors (mean value of relative measurement errors over several measurements),
24. measurement method, a generic description of the operations involved in a measurement,
25. measurement model, a mathematical relation among all quantities known to be involved in a measurement,
26. measurement period, a time interval between the first and last measurement in a series or time interval for one measurement,
27. meter or flow meter, an instrument for measur the volumetric and mass flow of a fluid through a pipe,
28. measurement result, a set of values attributed to a measurand together with other relevant information, including measurement uncertainties,
29. meter tube, a pipe section with one or more meters and, if applicable, sections for flow conditioning upstream and downstream of meters,
30. measurand, the quantity intended to be measured,
31. measuring system, a set of one or more measuring instruments and any other components, assembled and adapted to give information used to generate measure values within specified intervals for quantities of specified kinds,
32. metrological traceability, a property of a measurement result whereby the result can be related to a reference through a documented and unbroken chain of calibrations, each contributinge to the measurement uncertainty,
33. measurement uncertainty or uncertainty, a 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 %,
34. measurement, a process of experimentally obtaining one or more values that can reasonably be attributed to a quantity. The process can include the use of models and calculations based on theoretical considerations,
35. rated operating conditions, the operating conditions that must be met during a measurement for a measuring instrument or measuring system to perform as intended,
36. produced petroleum, petroleum that has been produced and sold, and petroleum that is produced for sale from fields in production and fields that have been shut down. Petroleum delivered free of charge or as compensation to another party is not considered sold,
37. prover, a system for proving flow meters in a measuring system for continuous and dynamic measurement of oil,
38. proving or prove, an in-situ calibration to determine a meter’s calibration factors,
39. 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 is to be analysed,
40. influence quantity, 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,
41. reference value, a value with associated measurement uncertainty that is used as a basis for comparison with values of quantities of the same kind,
42. 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,
43. representative sample, a sample with a composition equal to the composition of the quantity from which the sample is taken,
44. audit trail, documentation that makes it possible to reconstruct a sequence of events,
45. displacement prover, equipment for proving oil meters, based on displacement of a body through a calibrated pipe,
46. quantity, a property of a physical object, a phenomenon, or something else that can be quantified by measurement,
47. maximum permissible measurement error or error limit, the greatest permitted deviation from a reference value for a measurement, measuring instrument or measuring system,
48. systematic measurement error, the component of a measurement error that in replicate measurement remains constant or varies in a predictable manner,
49. uncertainty budget, a statement of a measurement uncertainty, of the components comprised by this measurement uncertainty and of their calculation and combination,
50. uncertainty limit, an upper limit for the measurement uncertainty of a measured value, determined based on the intended use of a measurement results,
51. associated measuring instrument, an instrument used to measure certain quantities that are characteristic of 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,
52. validation, a confirmation that the requirements for a certain intended use are fulfilled,
53. value of a quantity or value, a product of a number and a unit of measurement, where the number indicates how many units of measurement the quantity consist of,
    
    
54. verification, a confirmation that specified requirements are 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 covered by these regulations are responsible according to these regulations and the 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 the 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 on, and further develop a management system to ensure compliance with the requirements of these regulations. The management system shall be part of the licensee’s overarching management system.

(2) The management system shall, to the extent necessary, contain internal requirements and routines to ensure compliance with the requirements in these regulations. When designing internal requirements and procedures, the risk of non-compliance with these regulations shall be taken into account.

(3) The management system shall include requirements for the establishment and maintenance of an archive. This archive shall contain documents necessary to demonstrate compliance with the requirements of these regulations.

(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 contain descriptions of functions responsible for the following- up of measurements, measuring system, and measuring instruments, including responsibility for ensuring that internal requirements and routines are followed.

(6) The management system shall contain specifications of the competence necessary to ensure compliance with the requirements in these regulations, as well as descriptions of how competence development and competence transfer shall be ensured.

Section 6.

Internal audits

    The licensee shall conduct regular internal audits to ensure that the management system is effectively implemented and complies with the requirements of these regulations. The results of the audits 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) Calorific values (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 specified in the first and second paragraphs 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 quantities other than those specified in Section 10, the licensee shall clarify the measurement requirements with the Norwegian Offshore Directorate.

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 measurements, the licensee may 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 measurements of quantities of produced 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) Measurements of quantities of petroleum that is burnt, natural gas that is emitted to air, and CO2 that is separated from petroleum and emitted to air, shall fulfil the requirements for measurands and uncertainty limits in Table 2. When particular reasons so warrant, the Norwegian Offshore Directorate may, upon application, grant exemption from the uncertainty limits requirement in Table 2 for flared petroleum and natural gas emitted to air.

Table 2 (Requirements for measurements of quantities of petroleum burnt, natural gas emitted to air, and CO2 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 and other petroleum in liquid form 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 petroleum flared 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) Measurements of quantities of produced petroleum, excluding LNG, shall be based on continuous dynamic direct measurement of single-phase fluid flow. Other measurement methods may be used in the following cases:

1. Measurements of quantities of oil and gas delivered to pipelines for transport to onshore terminals or to gathering systems for further processing may be based on indirect measurement of single-phase fluid flow, if it can be documented that direct measurement of single-phase fluid flow is not technically feasible or would lead to unreasonably high costs.
2. Measurements of quantities of petroleum delivered to a gathering systems (allocation measurements) for further processing may be based on direct measurement or indirect measurement of multiphase fluid flow, if it can be documented that direct measurement of single-phase fluid flow is not technically feasible or would lead to unreasonably high costs.

(2) Measurements of quantities of LNG delivered to ships shall be based on static measurement of loaded volume. Measurements of quantities of LNG loaded onto tank trucks shall be based on weighing of tank trucks.

(3) Densities of oils 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 densities through direct measurement, densities may be determined through chemical analysis of representative oil samples.

(4) Trace quantities of water in oil shall be determined through chemical analysis of representative oil samples. Continuous direct measurement under dynamic conditions may be used if the method can be documented as equally accurate.

(5) Gas compositions shall be determined through periodic or continuous gas chromatography of representative gas samples. For delivery measurements of gas, gas compositions shall be measured continuously under dynamic conditions.

(6) Calorific values of natural gas shall be calculated from gas compositions.

(7) Densities of natural gas shall be determined through continuous direct measurement under dynamic conditions or calculated from gas composition. Densities calculated from gas composition may be used if the measurement 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) Measurements of quantities of burnt petroleum, natural gas emitted to air through a shared cold-venting system, and CO2 separated from petroleum and emitted to air, shall be based on continuous dynamic direct measurement of fluid flow. Other measurement methods may be used in the following cases:

1. Measurements of quantities of natural gas emitted to air through systems other than shared cold-venting systems, may be based on indirect measurements.
2. Measurements of quantities of diesel used as fuel may be based on purchased diesel quantities.

(2) Gas compositions of natural gas used for fuel shall be determined through periodic or continuous gas chromatography of representative gas  samples.

(3) Densities of natural gas used as fuel shall be determined by continuous direct measurement under dynamic conditions or calculated from gas compositions.

Section 13.

Measurement principles

     The licensee shall use measurement principles documented as suitable for use in the relevant measurement.

Section 14.

Measurement models

(1) The licensee shall establish and use measurement models that can provide values for measurands and the associated measurement uncertainties that comply with the requirements in Section 10. The measurement models and input quantities, output quantities, and corrections included in the resulting models and linked models, shall be documentable.

(2) Measurement models shall include corrections for identified effects that can be quantified and that may cause significant systematic measurement errors. The uncertainty in a correction shall be low relative to the specified uncertainty limit for the quantity to be measured

Section 15.

Uncertainty budgets

(1) The licensee shall establish and maintain uncertainty budgets to demonstrate compliance with uncertainty limit requirements in Section 10.

(2) The uncertainty budgets shall be established in accordance with internationally recognised guidelines for evaluating and expressing measurement uncertainties.

(3) The uncertainty budgets shall include measurement models, estimates and measurement uncertainties in quantities in the measurement model, covariances, types of applied probability distributions, types of evaluation of measurement uncertainty, and coverage factors.

Section 16.

Measurement procedures

    The licensee shall establish a measurement procedures. Theise shall be designed in a manner such that operating personnel can perform measurements in accordance with the requirements of these regulations.

Section 17.

Measurement results

Measurement results shall

1. have a measurement uncertainty within the uncertainty limit for the measurand,
2. be metrologically traceable, and
3. be expressed as a set of values attributed to the measurand.

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 the requirements for measurands and uncertainty limits in Table 3. Compliance with the uncertainty limit requirements shall be demonstrated in uncertainty budgets.

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 Fischer titration. Other analysis methods may be used if the method can be documented as equally accurate. Analyses shall be performed on representative test samples.

(2) Densities of oil samples shall be determined using a digital density analyser. Analysis shall be performed on representative test samples.

(3) Gas compositions of gas samples shall be determined through gas chromatography.

(4) Molar masses, densities and calorific values of gas samples shall be calculated from gas compositions.

(5) Reference materials shall be suitable to verify the performance of the analysis instruments.

Section 22.

Laboratory requirements

  The licensee shall use laboratories that have the personnel, competence, facilities, equipment, systems, and support services necessary to manage and perform laboratory activities in compliance with the requirements of these regulations, including those related to analysis methods, accuracy, and metrological traceability.

Chapter 6.

Allocation requirements

Section 23.

Allocation systems

(1) The licensee shall have allocation systems that ensures that quantities of produced petroleum are allocated fairly. 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 an allocation system is utilised.

Section 25.

Verification and validation

(1) The licensee shall verify allocation calculations before they are utilised and after any changes.

(2) An 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 the requirements of these regulations, including the requirements for performance, operation and maintenance, 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 uncertainties

     Instrumental measurement uncertainties shall comply with the uncertainty limits in Section 10. and be documented in uncertainty budgets.

Section 29.

Meter tubes and adjacent piping

(1) Meter tubes and adjacent piping systems (pipes and pipe components) shall be constructed and installed such that

1. rated operating conditions for measuring instruments and the measuring system are met under normal operating conditions,
2. maintenance and repairs, to the greatest possible extent, can be performed without losing measurement data and without affecting the oil and gas production, and
3. installation effects are minimised.

(2) Meter tubes shall

1. have upstream and downstream flow conditioning sections adapted to the meter,
2. include 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,
3. have an internal surface that prevents or minimises pollutant build-up, and
4. have no protrusions and irregularities in internal diameter that can cause turbulence, vortieces 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 tubes are equipped with meters in series and frequent inspection and cleaning of the meter tubes are not necessary.

Section 30.

Bypassing the measuring system

(1) Flows of petroleum shall not be able to bypass the measuring system during a measurement.

(2) Bypasses around meters and measuring systems shall be secured with line blinds or valves with double barriers and equipment that facilitates control of leaks. This does not apply to valves in pressure relief systems.

Section 31.

Measurements of temperature and pressure

(1) The temperature and pressure of the fluids shall be measured under dynamic conditions in each meter tube.

(2) Thermowells shall be installed in each meter tube. A thermowell 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 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 that this is appropriate to achieve efficient operations and maintenance.

(2) The built-in diagnostic parameters of measuring instruments shall be used for control purposes.

(3) The integrity of all valves significant to measurement shall be monitored. The methods and equipment for leak monitoring shall be assessed in relation to the risks of systematic measurement errors.

Section 34.

Electronics

(1) Measurement data shall be transferred digitally from the 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 to pulsed data from meters. For pulsed data from meters, the greatest permitted error rate is one pulse per 100,000 pulses.

(2) It shall be possible to audit configuration and calibration data in the electronics.

Section 35.

Computer system

(1) A 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 measurement reports, configuration logs, event logs, alarm logs and calibration reports.

(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) A measuring systems for dynamic measurement of oil shall include one or more oil meters, associated measuring instruments, valves, computer system, manual sampling equipment, and other equipment necessary to produce a measurement result.

(2) A delivery measuring system shall additionally include a stationary prover and an automatic sampler.

Section 37.

Calibration methods for oil meters

(1) The calibration method for an oil meter 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 the requirement in Section 28 for instrumental measurement uncertainty are safeguarded, indirect proving against a master meter prover may be used.

(2) The calibration method for an oil meter 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 the characteristics of the fluid.

Section 38.

Oil meter

(1) an oil meter shall be suited to the measurement in question and the operating conditions under which it will be used.

(2) During flow calibration in a laboratory and in situ, the oil meter 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 the calibration curve. The quantities in the table shall be determined as follows:

1. A measurement error shall, at each flow rate, be determined as the mean value of successive single calibrations.
2. The random uncertainty of the measurement error or / calibration factor shall, at each flow rate, be determined by a statistical analysis of the uncertainty of the mean value of successive single calibrations.
3. The linearity of an oil meter shall be determined over the flow rate range by the largest difference in measurement errors or the largest relative difference in calibration factor. A calibration factor shall, at each flow rate, be determined as the mean value of successive single calibrations.

Table 4 (Requirements for an oil meter 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 the measuring system.

(2) During calibration, the displacement prover shall comply with the performance requirements in Table 5. Base prover volumes shall be determined as the mean value of successive single calibrations. The quantities in the table shall be determined as follows:

1. The repeatability in the base prover volumes measurement shall be determined as the relative difference between the highest and lowest value of three or more successive single calibrations.
2. The combined uncertainty of the base prover volumes shall be determined by a statistical analysis of the uncertainty of the mean value of three or more successive 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

1. be adapted to the oil meters in the measuring system, so that the meters can comply with the performance requirements in Table 4 during proving,
2. be constructed such that the risk of a disturbance resulting in the same type of error on both a master meters and an oil meter is minimised, and
3. be adapted for in situ flow calibration. Flow calibrations may take place ex situ if it can be documented that the contributions from installation effects to instrumental measurement uncertainties are insignificant, and that provisions are made for monitoring fluid effects and for the detection or inspections of deposits from the fluid in the meter tube.
   
   

(2) A master meter shall, during flow calibration in a laboratory or in situ, 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 the calibration curve. The quantities in the table shall be determined as follows:

1. A measurement error shall, at each flow rate, be determined as the mean value of successive single calibrations.
2. The random uncertainty of a measurement error shall, at each flow rate, be determined by a statistical analysis of the uncertainty of the mean value of successive single calibrations.
3. The combined uncertainty of a 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.
4. The linearity of a master meter shall be determined over a flow rate range by the largest difference in measurement errors.

 

Section 41.

Measuring instruments associated with oil measuring system

(1) Associated measuring instruments shall, when used under rated operating conditions and in the absence of disturbances, comply with the maximum permissible measurement errors in Table 7.

(2) During calibration, associated measuring instruments shall comply with the maximum permissible errors 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 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

1. be able to take a representative sample of the quantity of oil passing through the measuring system during the measurement period, and
2. 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 to

1. correct for temperature and pressure effects on the density and volume of oils,
2. determine calibration factors, and
3. 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 one or more gas meters, associated measuring instruments, valves, computer system, sampling equipment and other equipment necessary to produce a measurement result.

(2) A delivery measuring system shall additionally include duplicate online gas chromatographs.

Section 45.

Calibration methods for gas meters

(!) The calibration method for a gas meter shall be flow calibration at an accredited calibration laboratory with documented measurement uncertainty and metrological traceability.

(2) For flare gas meters and the primary element of differential pressure meters, the calibration method may be based on a theoretical prediction procedure (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 flow calibration in a laboratory, the gas meter shall comply with the performance requirements in Table 9. The requirements apply for calibrations 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:

1. A measurement error shall, at each flow rate, be determined as the mean value of successive single calibrations.
2. The combined uncertainty of a measurement error shall, at each flow rate, be determined by a statistical analysis of the uncertainty of the mean value of successive single calibrations, combined with the uncertainty of the calibration setup.
3. The linearity of a gas meter shall be determined over a flow rate range by the largest difference in measurement errors.

Table 9 (Requirements for a gas meter 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) Associated measuring instruments shall, when in use under rated operating conditions and in the absence of disturbances, shall comply with the maximum permissible measurement errors in Table 10.

(2) During calibration, associated measuring instruments shall comply with the maximum permissible errors 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) An online gas chromatograph shall, during verification and calibration, be capable of separating gas components and measuring them individually, so that the quantities in Table 12 can be determined with an uncertainty within the specified uncertainty limits.

(2) Provisions shall be made for regular verifications and calibrations of the gas chromatograph against a certified calibration gas.

 (3) Provisions shall be made to monitor long-term trends the gas chromatograph’s response factors and retention times.

Table 12 (Requirements for an online gas chromatograph 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, a 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 the calibration gas and the sample.

(2) A manual sampler shall be capable of filling a suitable cylinder with a sample that is representative of 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

1. calculate quality parameters for gas, including densities and calorific values, 
2. correct for temperature and pressure effects, and
3. calculate quantities of gas.

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 a multiphase meter on a deck facility shall be in situ calibration against a reference system with measurements of single-phase flows at the outlets of a separator (separator measurement system).

(2) Calibration methods for a multiphase meter on a subsea facility shall include in situ calibration against a reference system with direct measurements of single-phase flows of oil, gas, and water at the outlet of a separator, in situ calibration against a reference system with indirect measurements of single-phase flows of oil, gas, and water, 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. A 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 the 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) Measurements 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 the measuring systems and measurements used to determine the loaded quantities of LNG comply with the requirements of these regulations.

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 the 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) During verification and calibration, gas chromatographs shall comply with the performance requirements in Table 12.

Section 60.

Density and calorific value

    Calorific values and densities shall be calculated from measured average gas compositions of LNG loaded onto ships or tanker trucks. The 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 the gas displaced from LNG tanks during the loading of LNG onto ships and returned to the 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 site 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 comply with the requirements of these regulations.

(2) The Norwegian Offshore Directorate shall be given the opportunity to be present when verifications and calibrations are carried out.

Section 64.

Calibration and adjustment of measuring instruments

(1) Measuring instruments shall be calibrated such that instrumental measurement uncertainties can be determined and metrological traceability established.

(2) Calibrations shall take place in such a manner that systematic effects resulting from 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 the 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 internationally recognised standards for the relevant calibration methods. If it can be documented that the use of an accredited laboratory is not possible or would lead to unreasonably high costs, a non-accredited laboratory may be used, given provided that the licensee can document that the laboratory can carry out calibrations with accuracy and metrological traceability equivalent to that of accredited laboratories.

Section 66.

Measurement standards

    The licensee shall be able to document the measurement uncertainty and metrological traceability of the measurement standards used for verification and calibration. The measurement standards shall have a sufficiently low measurement uncertainty to ensure that the requirements of these regulations for the metrological performance of the measuring equipment under test can be verified.

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 the oil meter.

(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 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 calibration and after adjustment.

Section 68.

Calibration of displacement prover

(1) The base volume of a 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 to the calibration of the displacement prover.

(2) The base volume of the displacement prover shall be re-calibrated immediately before the measuring system is used at the site. 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. The deviation 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 the master meter.

(2) The Calibration shall be carried out under 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 that 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 the gas meter.

(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 calibration and after adjustment.

Section 71.

Flow calibration of multiphase meters

    Multiphase meters, individually or selected in a series, shall be flow calibrated over a range of gas, oil, and water fractions that are as representative as possible of the expected operating conditions for the meters.

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 gases and test gases shall be certified. The certificates shall state the uncertainty of all gas components. The test 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 in calculations of the measurand, shall be metrologically traceable and have a measurement uncertainty that complies with the 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 on site.

(2) It shall be verified that all functions are operative and that all calculations have an accuracy that complies with the requirements of these regulations.

(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) An assembled measuring system shall be tested on site before being used.

(2) An 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) An assembled automatic sampling systems shall be tested at the construction site.

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 the requirements of these regulations, such that they can be operated and function as intended, and such that the quality level 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 the requirements of these regulations 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 that may result in deviations from these regulatory requirements shall be registered.

(5) Deviations from the requirements of these regulations due to malfunctions of measuring instruments and measuring systems shall be registered in a deviation 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 after 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) 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 the requirements of these regulations.

(3) Calibration intervals shall be evaluated following calibration and shortened if necessary to ensure compliance with performance requirements in these regulations.

Section 81. Working standards

(1) Working standards shall be calibrated with traceability to the SI system and have 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 the performance requirements in these regulations, 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:

1. As soon as possible after start-up to verify compliance with the 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.
2. 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.
3. 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 appropriate control limits.

(5) 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) A 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) A displacement prover shall, at a minimum, be calibrated in situ annually. The calibration interval may be gradually extended 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) A gas meter shall be calibrated at least every five years. This shall not apply if the meter or meter tube is subject to a preventive maintenance system which ensures compliance with requirements for instrumental measurement uncertainty.

(3) The metrological characteristics of flare meters shall be verified at least annually.

(4) Meter tubes shall be inspected internally on a regular basis, at intervals set in the maintenance plan, and upon indication of conditions that could impact meter performance. When selecting the inspection interval, consideration shall be given to the risks of systematic measurement errors. The requirements for periodic internal inspection does not apply to meter tubes on subsea facilities or where the condition of the meter tube can be monitored without internal 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 charts for basic parameters, including differential pressure and density, shall be established and maintained. The charts shall have appropriate control limits for the parameters.

(3) The maintenance plan shall, where practicable, include 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 the 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 at 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 the rated operating conditions. Maintenance and calibration shall be carried out pursuant to the maintenance programme and calibration programme.

(2) If a gas chromatograph, upon verification, is outside the limit values in Section 48 , calibration and adjustment shall be carried out, and new factors established. After such an adjustment, a new verification shall be carried out to confirm that the performance of the gas chromatograph is within set limit values.

(3) The gas composition shall be monitored. If the measured components are outside the 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 compositions 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 calibration certificates and supplier documentation.

(2) Appropriate alarm and control limits for measuring instruments and measuring systems shall be established and maintained. Measurement uncertainties, including the uncertainties of observed deviations between the indication of two instruments, shall be taken into account when setting control limits.

(3) An unambiguous audit trail shall be established and maintained. Critical data shall be regularly archived.

(4) Procedures shall be established for handling alerts from the computer system or errors discovered in another ways.

(5) Verification of calculations shall be carried out when changes that may affect the accuracy of calculations occur, 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 the requirements in these regulations. The licensee shall store materials and information pursuant to Section 55 of the Petroleum Regulations.

(2) The Norwegian Offshore Directorate may require the submission of 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 Norwegian Offshore Directorate of the 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 with the requirements 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 d) in the second paragraph, consent for start-up or continuation from the Norwegian Offshore Directorate is required.

(2) Consent as mentioned in the first paragraph must be obtained:

1. before the measuring system is used for the first time,
2. before the measuring system or parts of it are used after major reconstructions or modifications,
3.  before changing the purpose of use that is not comprised by consent pursuant to Item a),
4. before the measuring system is taken into use after cessation of use, if the maintenance and calibration programme have not been carried out during the period the measuring system has not been in use.

(3) An application for consent pursuant to the second paragraph shall contain information demonstrating that the measuring system complies with the requirements of these regulations.

Section 95.

Reporting of measured quantities

     Quantities measured in accordance with Section 10 shall be submitted monthly to the Norwegian Offshore Directorate.

Section 96.

Annual reports from onshore terminals

    Operators of onshore terminals shall submit a report to the Norwegian Offshore Directorate by 15 October each year. The report shall, to the necessary extent, contain information about measurement, measurement systems, and allocation.

Section 97.

Information about measurement in the annual status report

     The annual status report for fields in production 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 98

Uncertainty budgets 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. Uncertainty budgets for each measurement period shall be submitted by 1 March the following year.

Section 99

Other information

(1) The licensee shall submit information about the following to the Norwegian Offshore Directorate as soon as possible:

1. errors that may provide a basis for major corrections of measurement results,
2. errors in the essential components of measuring systems and plans to correct such errors,
3. expansion of calibration intervals,
4. 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,
5. plans for reconstruction, modification, or change of use of a measurement system that will require consent for start-up or continuation under Section 94,
6. plans for permanent or temporary cessation of use of a measurement system.

(2) The licensee shall, upon request, submit information to the Norwegian Offshore Directorate concerning cargoes of oil and other petroleum products.

(3) Operators of pipeline systems shall, upon request, submit a complete overview of material balances in pipeline systems to the Norwegian Offshore Directorate.

Chapter 15

General provisions

Section 100.

Supervisory authority – authority to make individual administrative decisions, etc.

(1) The Norwegian Offshore Directorate supervises compliance with the requirements of these regulations and decisions made pursuant to them.

(2) The Norwegian Offshore Directorate may make individual decisions to ensure compliance with the requirements of these regulations.

Section 101.

Exemption

(1) The Norwegian Offshore Directorate may in particular cases grant exemption from the requirements of these regulations.

(2) Applications for exemptions pursuant to the first paragraph shall be substantiated.

Section 102.

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 103.

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.

Information

English version is not necessarily updated according to recent changes at any time.