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The Regulation On The Measurement Of Petroleum For Fiscal Purposes And For The Calculation Of Co ₂-Fee

Original Language Title: Forskrift om måling av petroleum for fiskale formål og for beregning av CO₂ -avgift

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The regulation on the measurement of petroleum for fiscal purposes and for the calculation of CO ₂-fee date of-2001-11-01-1234 Ministry the Ministry of petroleum and energy published in 2001 booklet 13 (notes) the entry into force 01.01.2002 Recently changed-2013-03-15-284 from 01.07.2013 Change FOR-1991-07-03-532, FOR-1993-08-12-806 applies to Norway the legal authority FOR-1997-06-27-653-section 26, FOR-1997-06-27-653-section 86, LAW-1990-12-21-72-section 5, FOR-1990-12-27-800, FOR-2001-12-11-1451-section 3-19-7 Announced 06.11.2001 Directed 15.11.2006 (§ 8a, section 13a and section 26).

Short title regulations on fiscal measurement of petroleum Chapter overview: chapter I. Initial provisions (sections 1-4) chapter II. Requirements for the management system etc. (§§ 5 - 7)
Chapter III. General requirements for measurement and measurement system (§ § 8-12) chapter IV. Requirements to the execution of the measurement system (§ § 13-17) chapter V. Requirements for calibration and verification etc. before the measurement system is taken into use (§ § 18-22) Chapter VI. Requirements for the measurement system in use (§ § 23-27) Chapter VII. Documentation requirements (sections 28-31) Chapter VIII. General provisions (§§ 32-35) reference list Appendix 1: form 1, CO ₂-fee, half-yearly payment Annex 2: form 2, CO ₂-fee, tax calculation per release notes to the regulation on the measurement of petroleum for fiscal purposes and for the calculation of CO ₂-fee legal authority: set by the Norwegian Petroleum Directorate 1. November 2001 under the legal authority of the regulations 27. June 1997 No. 653 of the law on petroleum activities § 86 last paragraph, cf.. section 26, jf. Law 29. November 1996 No. 72 if petroleum activities section 4-10 and law 21. December 1990 No. 72 about tax on emissions of CO ₂ in the petroleum business on the continental shelf, cf. section 5. the delegation decision 28. June 1985 No.. 1419 and delegation decision 27. December 1990 No. 1229. Added title: regulations 11. December 2001 No. 1451 about excise duties section 3-19-7.
EEA EEA referrals: annex II, chap. IX Nr. 27B (Directive 2004/22/EC).
Changes: modified by regulations 5 des 2003 Nr. 1720, 13 des 2004 Nr. 1853, 22 aug 2006 Nr. 1014, 11 Oct 2007 Nr. 1205, 24 nov 2008 Nr. 1253, 7 Dec 2009 Nr. 1845, 8 March 2012 No. 209, 15 March 2013 No. 284. Foreword the purpose of this regulation is to ensure that accurate measurements is the basis for the calculation of Government taxes and fees, including CO ₂-tax, and intellectual property holders ' income. Regulation expands on the petroleum law and CO ₂-tax law requirements for the measurement of petroleum and draws up the framework conditions for facilitation, planning and execution of business as shown to the petroleum law and CO ₂-tax law. The requirements for flow meters for liquids other than water is with effect from 30. October 2006, modified in accordance with Directive 2004/22/EC on measuring instruments (MID) and is harmonized with the regulations 21. December 2007 Nr. 1738 about requirements for flow meters (for liquids except water) established by the Ministry of trade and industry and Metrology jf. Notes to section 13a. In practice, this measurement system for oil and gas in liquid form.
Measure regulation sets functional and specific requirements for measuring equipment's design and the use of it, elaborates on the individual of the attendee's responsibility to comply with the requirements laid down in or pursuant to the law and should help to ensure that the measuring equipment and method at any time to meet this forskriftens requirements for the total measure uncertainty. The regulations stipulate as to how the quantities of fuel and flare gas should be reported and documented. It is added on to the right for an adequate oversight of the business. This regulation replaces the previous regulation on the fiscal measurement of volume oil and gas etc. and former regulations on fuels and flare gas measurement in the calculation of CO ₂-fee in the petroleum business. Special conditions regarding ₂ tax CO-measurement is given in the note to section 14. If the provisions of this Regulation include either fuel gas or flare gas, this will be stated in the text.
In the comments to section 1 of this regulation are described case time regarding equipment and methods for determination of NOx emissions.
The regulation adds that not all documentation sent to the Norwegian Petroleum Directorate need, but may be available at the operator and is sent to the Norwegian Petroleum Directorate upon request. It added further to facilitate the electronic dissemination of information.
It has been prepared note to the individual provisions of this regulation. The notes provide explanation and guidance to regulatory provisions. It is given examples of how forskriftens claims can be met, or it is shown to the recognized norms, including industry standards, as a way to meet the regulatory requirements. Standards that are not mentioned in the regulations, if any, can be used with comments after consultation with the Norwegian Petroleum Directorate. The buying and selling of petroleum takes place across borders and the players are international. Technical standards should therefore be internationally accepted. It will be shown by the way to the notes to section 4. Guide to the plan for development and operation of a petroleum occurrence, PDO, and plan for the construction and operation of facilities for transport and for the exploitation of petroleum, PAD, 18. May 2000, refers to what information a PDO//PAD should contain about fiscal measurement systems.

In the Introductory chapter. section 1 provisions. Scope this Regulation applies to the petroleum business on areas covered by the law of 29. November 1996 No. 72 if petroleum activities § 1-4 and the Act of 21. December 1990 No. 72 about tax on emissions of CO ₂ in petroleum activities on the continental shelf section 2, specifically, a) the planning, engineering, construction and use of measurement systems for the measurement of the produced, transported and sold quantities of oil and gas (fiscal measurement systems) b) by planning, engineering, construction and use of measurement systems and measuring equipment for determination and reporting of quantities used for fuel and flare gas in the petroleum business.

For flow meters for liquids other than water will regulation 26. April 2006 no. 466 on the requirements to the flow meters (for liquids except water) established by the Ministry of trade and industry and Metrology apply with the clarifications provided by the regulations here.

§ 2. Definitions in this regulation means: accreditation: an official recognition that an organisation working in accordance with documented quality assurance system and has shown that it has the competence to carry out specific tasks. 
Allocation: allocation of petroleum between different owner groups and owns the company. 
Recognized norm: Standard, guidance, and more, as within a subject area is internationally and/or nationally recognized. Law or regulation that does not directly apply, but governing similar or adjacent areas can also be recognized norm. 
Fuel: natural gas, oil, condensate or diesel fuel used for the operation of internal combustion machinery such as turbines and the like. 
Usage place: gadgets or terminal where the measuring system is in use. 
Construction site: Fabrikasjonssted where one or more of the measuring system's main parts fabricated, assembled and tested. 
Computer part: the part of the measurement system consisting of computers, and who receives the measure signals from analog to digital converter or from digital measuring loops. 
Flare gas: natural gas burnt or vented to the atmosphere. 
The fiscal measurement: Measurement in connection with the purchase and sale and the calculation of tax/fee. 
Donor: Element which responds to the size to be measured, so that the dealer gives out a signal which is representative of this size. 
Flow meter for other liquids than water: an instrument designed for continuous measurement, registration and display of the amount of fluid flowing through a closed and completely filled tube in appropriate measure conditions. 
Instrument: A compilation of transducer and one or more donors. The signal from an instrument represents a physical condition.
Technical gadgets that are used for measuring a physical parameter. 
Instrument part: part of the measurement system from the instrument to the digital input to the computer section. 
Calibration: Determination of the relationship between the measured value and the reference value with known uncertainties. By calibration of meters against a known volume are often used the English term proving. 
The calibration factor, K-factor: relationship between measurement value read from the gauge and measure value from a reference measurement system. (Often named value that specifies the amount of pulses per unit.) 
The calibration factor for the flow meter: Named or ubenevnt value that indicates the relationship between flow and volume målers registration from the historical square. In this regulation is the term intended to cover the international definitions m factor and K-factor. 
The calibration factor (meter factor) for flow meter: Ubenevnt value that indicates the relationship between the flow målers registration and flow. 
Calibration mode: the Selectable State of the computer part to perform verification, while its målerør is shut down. 
Control: monitoring, supervision, inspection, and the like of States, process events, products, etc. to ensure that these are in accordance with the specifications. 
Linearity: 1) expression of how well a applying a lot-for equipment be approximated a straight line.

2) Expression for the relationship between the sizes where a change of the one causing a unique and proportional change of the other. 

Liquefied Natural Gas (LNG): natural gas is mainly composed of methane (CH4) cooled to liquid form at around minus 160 degrees C, with density at atmosphere pressure of approximately 430-460 kg/m ³. The default density is typical in the area to 0.67-0,74 kg/Sm ³. 
Mechanical part: All mechanical equipment that is part of an oil or gas measurement system. 
Målerør: the right barrel draw where the flow meter is mounted. 
Measure the bow:

Hook-up that includes all equipment and data lines and more, from the entrance of the donor to Visual rendering in computer part. 
Gauging station: compilation of measuring equipment that is used for the determination of measured quantities. 
Measuring uncertainty: an expression of the result of a measurement that characterizes the area where the true value is believed to be located. 
Measurement system: consists of the mechanical part, instrument part and computer part, as well as documentation and procedures associated with these. 
Resolution: sets the smallest variation in the signal level that gives the registrerbart result for measuring instruments. 
Petroleum products: Marketable products that are separated from the crude oil or natural gas. Example: ethane, propane, gasoline, kerosene. 
Tubes normal: equipment for calibration of dynamic flow meter, based on the displacement of a body through a calibrated tubes. 
Compliance marking: marking of the flow meters with "CE" mark, supplemental metrologisk marking and the identification number to the appropriate technical control body as described in the regulation on the requirements for flow meters (for liquids other than water), Appendix 5. 
The compliance assessment: an assessment of whether a product meets the technical requirements, etc., that are set out for flow meters in the regulation on the requirements for flow meters (for liquids other than water). 
Flow meter (gas): equipment inserted into or applied to a tube with its signal converter that provides a primary signal that is proportional to the flow. 
Transducer: technical equipment that changes the energy the wearer's character. Be used in this regulation only for ultrasonic meters.

§ 3. Responsibility for this regulation rights holder and others who participate in the petroleum activities covered by this regulation, is responsible for this regulation and individual decisions given under the legal authority of the same.
In addition, the duties of the copyright holder to make sure that anyone who performs work for them, either in person, by employees or by contractors or subcontractors, to comply with this regulation and the individual decisions given under the legal authority in it.

§ 4. Requirements of the petroleum industry in General Business, as mentioned in section 1 of this Regulation shall be conducted in accordance with the requirements set out in or pursuant to this regulation, and in accordance with recognized norms for such business.
Through the use of technology or methods that are not described in the recognized norm, required criteria for development, prepared the trial and use.

Chapter II. Requirements for the management system etc.

§ 5. Management system copyright holder and others who participate in the petroleum industry to establish, follow up and further develop a management system to include organization, processes, procedures and resources that are necessary to ensure compliance with the requirements of this regulation.
A management system for the measurement shall be drawn up and maintained in a systematic and controlled manner. Updates should be made known within the own organization, for the Norwegian Petroleum Directorate and other affected parties. Management system to ensure that transfers are maintained at the change of personnel and by the transition between construction and operating phase.
Overall responsibility for, and supervision of, the control system should be added to the device that is responsible for the company's other management system.
A quality assurance manual for operation of the measurement systems to be worked out.

section 6. Organization and competence-responsibility Function and for personnel who have oversight of or perform tasks pertaining to the measurement system shall be documented in the licensee's organization plan. Their duties, responsibilities and authority should be described.
The licensee shall appoint the person in charge for the measurement system. The person in charge should have responsibility for the procedures for the operation, maintenance, calibration and control followed.
All personnel who perform tasks related to measuring systems shall have documented expertise within the subject area. It should be a system that displays that update and expertise building are taken care of.

section 7. Verification planning, engineering, procurement, construction and use of fiscal measurement systems as mentioned in these regulations, the licensee shall be able to verify that the provisions of the regulation or individual decisions are met. Independent verification of the critical parameters may be required.
The licensee shall ensure verification of the fiscal number and calibration reports for equipment covered by this regulation.

Chapter III. General requirements for measuring and metering system section 8. Allowed to measure uncertainty measurement system Uncertainty limit by 95% level of confidence (expanded uncertainty with the coverage factor k = 2) sales and allocation measurements of oil 0.30% of the standard volume sales and allocation measurements of gas mass 1.0% of the Fuel gas measuring 1.5% of the standard volume Torch gas measurement standard volume 5.0% of Sales measurement of LNG 0.50% of the measured energy content per ship load measurement system should be designed so that the systematic measurement error be avoided or compensated for.
Measuring the system's total uncertainty should be able to be documented. It should be worked out proper risk analysis for the measurement system within the 95% level of confidence. In this regulation be used confidence interval equal to ± 2 σ, that is. the coverage factor k = 2. This provides a level of confidence a bit higher than 95%.
The LNG will be measured and analyzed in utskipingsstedet. The operator is responsible for, and shall be able to document, that the measurement system is in accordance with recognized norms.
Volume of LNG can when loading is determined by the use of traceable metered ship thoughts and calibrated level measuring equipment.
For measuring the system's component parts applies to the following maximum limits: the Part component Sløyfeusikker-hetsgrenser Risk limits to the component/Linearitetsbånd Repeterbarhets-limits (band) tubes normal oil NA 0.04% for all 4 volume for all 4 0.02% volume Turbine measures oil 1 pulse of 100 000, 0.001%, by pulse transmission of the measuring signal 0.25% of the work-area (10:1) band: 0.50% (10:1) and 0.30% (5:1) 0.027%, uncertainty, ref. Table B1, API MPMS ch. 3.6.

Ultrasound measures the oil 1 pulse of 100 000, 0.001%, by pulse transmission of the measuring signal 0.20% of the workspace (10:1) band: 0.30% (10:1) 0.027%, uncertainty, ref. Table B1, API MPMS ch. 3.6.

Coriolis meter oil 1 pulse of 100 000, 0.001%, by pulse transmission of the measuring signal 0.20%, in the workspace. Band: 0.30% (10:1) 0.027%, uncertainty, ref. Table B1, API MPMS ch. 3.6.

Turbine meter gas (sales and allocation) 1 pulse of 100 000 0.001%, by pulse transmission of the measuring signal 0.70% of the workspace (10:1) band: 1.0% (10:1) 0.28% in the workspace (10:1) Ultrasound measures the gas (sales and allocation) 1 pulse of 100 000, 0.001%, by pulse transmission of the measuring signal 0.70% of the workspace (20:1) after the zero point correction and the k-factor into the laying is carried out. Deviation from the reference see NORSOK in-104.
0.40% of the workspace (20:1) after the zero point control is performed Coriolis measuring gas (allocation) 1 pulse of 100 000, 0.001%, by pulse transmission of the measuring signal 0.70% of the workspace 20:1 0.40% for gas speeds greater than the minimum specified speed.

Press metering oil, gas 0.30% of the measured value in the work area of 0.10% measured value in the workspace NOW Press measuring fuel gas, flare gas 0.50% of the measured value in the work area 0.20% of the measured value in the workspace NOW temperature measurement oil, gas 0.20 0.30 ° C ° C NA temperature measurement fuel gas, flare gas 0.30 0.50 ° C ° C NA Densitetsmåling oil 0.50 kg/m ³ 0.30 kg/m ³ NA Densitetsmåling gas 0.30% of the measured value 0.20% of the measured value NA Difference-trykkmåling 0.30% of the measured value in the work area of 0.10% measured value in the the workspace NOW Water in oil measurement 0.05 volume% absolute for 0 to 1.0 volume% water content, ± 5.0% of the measured value over volume water content 1.0% 0.50% of the measured value by the water content of 0.01 volume% Densitetsmåling LNG NA 0.30% of the measured value NA Volume measurement LNG NA 0.30% of the measured value NA Online GC NA 0.30% of the calorific 0-25 mol%: 0.02 mol% 25-100 mol%: 0.05 mol%.

The calorific gas NA 0.30% of the calorific NA Uncertainty computer part for oil and gas NOW 0.001% NA Uncertainty computer part for fuel and flare gas NA 0.1% NA For fuel gas: see note to section 14.

Linearitetsbånd can be used as the test criterion by acceptance of meters and is specified in the risk limit for the component where it is relevant.
Repeterbarhetskravet for liquid meters are now a uncertainty requirements on 0.027%, ref. Table B1, in API MPMS ch. 3.6.

§ 8a. Allowed to measure uncertainty for flow meters (for other liquids than water) For flow meters for liquids other than water, jf. This regulation § 13a, the minimum requirements for risk limits contained in regulation 21. December 2007 Nr. 1738 about requirements for flow meters (for liquids except water) section 29, cf. § 3. The same applies for part components of a measurement system if this follows from the regulation on requirements for flow meters (for liquids other than water).

§ 9. Units of measurement the measurement system to give readings in SI-units. Reporting of fiscal measurement data to the Norwegian Petroleum Directorate to be in SI-units.
Reporting of fuel and flare to the Norwegian Petroleum Directorate should be in standard cubic meters of natural gas and liters for diesel or other hydrocarbons in liquid phase.
Determination of the measuring system's critical parts by surveying to be in SI-units.

§ 10. Reference conditions Standard reference conditions of pressure and temperature to measurement of oil and gas be 101.325 kPa and 15 ° c. Measurement of petroleum products can different reference pressure used.

section 11. Determination of energy content, etc. Gas composition from continuous flow proportional gasskromatografi or from automatic flow proportional sampling to be used for the determination of the energy content.
For sale gas metering stations to two independent systems will be installed.

When oil or gas is analyzed for determination of physical and/or chemical properties and the analysis results be used for sales or allocation purposes, this should be performed by a competent laboratory.

§ 12. Extension of gas and oil flow out of the measurement system the flow of gas or oil shall not be entered outside of the measurement system.

Chapter IV. Requirements to the execution of the measurement system section 13. Requirements to the measuring system in general measurement system should be scheduled and will be built after the requirements in this regulation and in accordance with recognized norms of measurement systems. For flow meters (for liquids except water) applies to the additional requirements imposed by § 13a.
The measurement system shall be able to measure all the scheduled hydrokarbonstrømmer without any part of the measuring equipment is operating outside its area of work.
The measurement system to the extent possible be equipped with duplicate instrument features for signals from the primary gauges and instrumentation to facilitate health monitoring and reduce the need for preventive maintenance. Signals from the parallel meter run will be able to be used in connection with health monitoring.
Wireless communication between different parts of the fiscal measurement system can be used if it is demonstrated that the solution integritetsmessig corresponds to the traditional solution with communication cable.
On the sales measure the number of drives in parallel to målerør be such that maximum hydrokarbonstrøm to be able to be measured by one målerør out of service, while the remaining operating within their workspace.
The measurement system shall be suitable for the particular type of measurement, the given fluid properties and the volumes of hydrocarbons to be measured.
When needed to flow rather be installed.
In areas where control and calibration are made there should be adequate protection against uteklima and shake.
Målerør and related equipment should be isolated upstream and downstream in the length that is required to prevent temperature change for the instruments that provide input to the fiscal estimates.
Isolation valves shall be of the blocking-and avblødningstype. All valves of the importance to the integrity of the gauging station should be able to be checked to ensure against leakage.
All parts of the measurement system should be easily accessible for maintenance, control and calibration. 
Multiple-phase measurement if the traditional enfasemåling of hydrocarbons is not possible for economic reasons, the multiple-phase measurement could be used. Multiple-phase meter will then be able to be used as the fiscal measures.
The following conditions must be documented satisfactory for a concept based on multiple-phase measurement to be able to put to use is allowed. Chapter VII and § 18:-the operator must submit a concept for the Norwegian Petroleum Directorate for the comments and formal treatment in good time before the submission of the Plan for development and operation (PDO). An estimate of the expected measurement uncertainty to be presented, combined with financial numbers for the risk of loss between production licences (REF. NORSOK in-105), Annex C).

-the main principles in operations and maintenance philosophy is described.

-the calibration option for meters against testseparator or other reference.

-redundancy in sensors and robustness in design of measure concept.

-Relevant PVT (State equation) model and representative sampling opportunity to be able to perform a good PVT calculation.

design of feeder pipe in order to ensure equal conditions for more monitors in parallel can be used.

-flexibility in the system to be able to deal with the varying GVF (gas liquid fraction).

-Planned method of tilstandsmonitorering and/or planned the calibration interval is described.

-Planned method and interval for sampling and update of PVT data are described.

Multiple-phase meters to once they are part of the fiscal system is treated as other fiscally measurement equipment and the administrative requirements that apply after this regulation must therefore be followed.

section 13a. Flow gauges (for other liquids than water) Flow meters for liquids other than water that is purchased for use in the petroleum business or that will be taken into use after 30. October 2006 within the scope of this forskriftens must be approved by the technical control body for the procedures for conformity assessment, jf. regulations on the requirements for flow meters (for liquids except water) section 4 and regulation 20. December 2007 Nr. 1723 about measurement units and measurement section 4-11. It will be shown by the way to the regulations on the measurement units and measurement section 8-1 «transitional provisions for measuring instruments covered by Directive 2004/22/EC ". This provision applies accordingly.
Flow meters for liquids other than water should have the compliance assessment and compliance labeling, including the supplementary meterologisk marking. This applies also if a flow meter is constructed and produced solely for use for their own purposes. The same applies for part components of a measurement system if this follows from the regulation on requirements for flow meters (for liquids other than water).
During use, flow meters for liquids other than water as a minimum meet the requirements as stated by this regulation § 8a.

section 14. Measuring the system's mechanical part Measure the system's mechanical part should be designed so that the representative measuring values generated as input for the fiscal calculations (cf. section 8).
It should be added to facilitate the necessary redundancy and the possibility for verification of gas and liquid meters.
When the turbine meters are used for liquid measurement, should permanently be available for tubes normal calibration of gauges.
Stir the standard should be able to be calibrated on site.
If other types of flow meters are used for liquid measurement, permanent equipment for calibration of measurement will be available.
It should be documented that the surrounding equipment will not affect the measuring signals.

section 15. Measuring the system's instrument part pressure, temperature, density and compositional analysis should be measured in such a way that the representative measuring values generated as input for the fiscal calculations (cf. section 8).

section 16. Measuring the system's computer part Measure the system's computer part should be designed so that the fiscal calculations can be performed within the set measuring uncertainty (cf. section 8).
Computer section should be equipped with various protection functions so that the fiscal number cannot be changed as a result of adverse events of technical nature or as a result of manual error operation.
Computer section should be able to document at the various reports fiscal parameters and the fiscal amounts calculated by these.
Computer part to have uninterruptible power supply. It should be ensured that the error is recorded with alarm and that the reserve system is activated. Power outages are not going to be able to cause the fiscal measurement data is deleted from your computer's storage device.

§ 17. Sampling requirements Sampling should be carried out in a way that ensures that the sample amount of is representative.
Sampling should be automatically and flow proportional. In addition, it should be possible to make manual sampling.
For oil and condensate to the necessary equipment for homogenization is installed upstream of the outlet for the sampling tubes.

Chapter v. requirements for calibration and verification etc. before the measurement system is applied to section 18. Application for consent rights holder to obtain consent from the Norwegian Petroleum Directorate before the measurement system is taken into use. It should also be sought consent for performing major renovations or change of use of a measurement system.
If the prerequisites for a consent that is given in pursuance of this paragraph the first paragraph, change significantly, the Norwegian Petroleum Directorate require that the Licensee obtains a new consent before the activities be continued.
Before the measurement system is applied to it be worked out procedures for the operation, maintenance, calibration, and verification. The procedures should ensure that the measurement system is maintained to the standard it is designed to.
Procedures for calibrations and out verification procedures to be performed in order to clarify the measure the drive to boot, will be submitted to the Norwegian Petroleum Directorate as an attachment to the application.

§ 19. In General, Calibrations and out verification procedures described in this chapter should be performed before the measure using the system on site.
The Norwegian Petroleum Directorate shall have the opportunity to be present when the tasks are performed.

section 20. Calibration of mechanical part pipe normalens volume to be calibrated, a) before delivery of the measuring system from the construction site, b) before measuring using the system on site.

The mechanical parts that are critical for measuring the uncertainty to oppmåles or calibrated to flow for document applying a lot-.
The assembled fluid metering system to be tested with the liquid power at the construction site and functional test of flow meters should be made.
Statistical methods to document the repeterbarhetskrav can be used.

§ 21. Calibration of the Measuring instrument to be part the coils calibrated and the calibration results to be available.
Measure the coils should be calibrated with a number of points so that the linearitetsavvik are exposed within the workspace. Calibration of the measuring wires is executed by Visual readout of the signals in the computer section.

§ 22. Verification of computer part For each målerør to perform verification of computer section to confirm that all the features are operational.
For all independent program routines should be verified that the calculations are performed with the requirements equal to or better than what is mentioned in this Regulation section 8. Integration should be verified with at least three values in the flow area.
The calculations for calibrations as mentioned in this Regulation section 20 shall be verified. This includes the K-factor for the individual calibration and the average value within the permitted variation site.

Chapter VI. Requirements for the measurement system in use section 23. Maintenance the measurement system to be maintained to the norm it is constructed according to the.

The equipment, which are included in the measurement system, and that has significant importance to measure the uncertainty, should be calibrated with traceable equipment before starting, and then maintained to this default.
Control to ensure that the equipment as mentioned in this first paragraph is paragrafens within the given limit values shall be carried out regularly by qualified personnel. If the equipment by calibration is outside the given limit values, shall be carried out by qualified personnel correction or by calibration and its correction in a competent laboratory. Traceable calibration of test instruments to be performed regularly by competent laboratories.

section 24. Operating requirements for pipes Tubes volume to normal normalens be calibrated annually.
Calibration should also be performed if the volume may have changed as a result of equipment failure.

§ 25. Operating requirements for flow meters Turbine meters for oil should be calibrated against the permanent pipe standard with a repeatability so that a sequence of five successive single calibrations fall within a band of 0.05% of the average calibration factor.
Calibration factor of the flow meters shall be within the control limits as mentioned in recognized norm. Flow meters that are installed after the overhaul, modification or replacement shall immediately be calibrated to verify requirements for linearity and repeatability.
After the start of the measurement system shall be performed calibrations of the flow meters to verify requirements for repeatability and linearity. It should also be verified to what extent the calibration factor are affected by the flow amount, temperature, pressure and composition by changes within the variation site.
Calibration of flow meters shall meet the following requirements, a) it to be established limits for the calibration factor and oil flow, temperature, pressure, density, viscosity, or composition if there is a connection between these. By exceeding the limits to new calibration is performed, b) time interval between the calibration of flow meters shall not exceed four days. For each shipment to the calibration factor for flow meters in use is determined.

Statistical methods to document the repeterbarhetskrav can be used.
Measure the dazzling should be checked for edge sharpening, surface roughness and flatness. Control will be done at startup and once per month in the first six months. After this can be extended if the intervals, but it later detected damage or wear to the interval for the control of the measurement is reduced. dazzling Measure the aperture should also be checked for events that may have affected the fiscal measure the quality. Measure the dazzling to certified prior to installation in the målerør and later if there are visible injuries.
For ultrasonic measurement of gas going to the health parameters be verified.
Gas measurement with measurement or to dazzle the ultrasound measures the ears is controlled by indication of the change of the interior surface.

§ 26. Operating requirements for instrument part all donors should continuously be monitored and/or regularly be calibrated according to the requirements in section 8, cf. § 8a. When calibration is performed to this include multiple values in the dealer's workspace. If the dealers ' output signals differs from the limits that are set out, to the necessary maintenance and then new calibration is performed.
The calibration methods to be so that the systematic measurement error be avoided or compensated for.
Gassdensitometere should be verified against the estimated density or other relevant method.
Online gasskromatografer should be validated against traceable reference gas with a fixed frequency. Derived from the risk statement in section 8, the criteria for validation is determined. If the gas chromatograph by validation is outside the specified criterion should be performed and new calibration factors be established. After such a correction to new validation is performed to confirm that the gas chromatograph is now within the given test criterion.
Variations in gas composition will be monitored and by variety beyond ± 5%, should reference gas with different calorific and possibly new linearitetstest be considered.

§ 27. Operating requirements for the computer part critical data should be archived on a regular basis. It should be established procedures for handling error messages from the computer section or error that is detected by other means.
By program changes and by change of computer parts to perform an independent verification of the computer part's calculation requirements, the CF. This regulation § 22.

Chapter VII. Documentation requirements section 28. Documentation before the measurement system is taken into use after the plan for development and operation of a petroleum occurrence (PDO) and the plan for the construction and operation of the facility and for the exploitation of petroleum (PAD) is approved and before the measurement system is applied, the operator shall have the following documents available, a) technical description of the measurement system, b) overview showing the location of the measurement system in the process-and transport system , c) drawings and description of the equipment which are included in the measurement system, d) documentation overview for measurement system, e) work schedule for the project to the application for consent to the use, f) description of the operator's and the vendor's management system for follow-up of the measurement system, g) risk analysis.

The Norwegian Petroleum Directorate to request documentation on tilsendes as mentioned in this paragraph the first paragraph.

section 29. Documentation for the measurement system in use it should be established and maintained an archive that will include the documentation pertaining to the measurement system. It should be able to be documented that the quality of measurements are referred to in this regulation and that it is the discrepancy between the reported and measured quantities.
Fixed inserted parameters should easily be able to be verified.
Documented error measurement it should be corrected for. The correction shall be made if the deviation is greater than 0.02% of the total volume. If the error has a lower percent value to be executed when the correction total value is considered to be significant.
If it is unclear how long there have been errors made, the correction is made for half of the time period the maximum may have been errors made.
Reporting of CO ₂-free measurements for payment of CO ₂-fee to happen every six months as mentioned in CO ₂-tax law § 4 and according to the form published by the Norwegian Petroleum Directorate.
If the measured number of technical reasons are not available, the reported numbers could be documented on a computationally proper way.
Diesel delivered to the facility in the tax period shall be reported as the basis of CO ₂-tax calculation. Deductions for diesel which is not used for combustion shall be documented and reported to the Norwegian Petroleum Directorate as mentioned in this paragraph fourth paragraph.
All measurement data that this regulation includes should be reported in the PetroBank-system.

section 30. Information after the PDO is approved to the licensee inform the Norwegian Petroleum Directorate on all essential "conditions" that affect the quality of the fiscal measurements or figures reported from these.
The Norwegian Petroleum Directorate shall be informed of the, a) annual plan for activities within subject area b) procedure for the allocation of ownership of petroleum between the different partners in production licences c) error measurement d) when fiscal measurement data has been corrected based on calculations e) change in calibration interval f) change in calculation programs g) changes in the assumptions that underlie agreed h) download the replacement procedures that apply to the sale of hydrocarbons in liquid phase.

section 31. Calibration documents description of procedure by calibration and control, as well as the overview of results which measure deviation before and after calibration appears, should be documented. The documentation should be available for verification on site.

Chapter VIII. General provisions section 32. Supervisory authority-the authority to make individual decisions, etc. The Norwegian Petroleum Directorate oversees that the provisions provided in this regulation or decision which is made in pursuance of it, are being complied with. The Norwegian Petroleum Directorate can make the easy decisions that are necessary to carry out the provisions of this regulation.

section 33. Exemption the Norwegian Petroleum Directorate can in particular cases from provisions which dispense with is given in this regulation.

section 34. The penalty provision in violation of this regulation or decision which is made in pursuance of it, be punished as provided in the petroleum law § 10-17, and CO ₂-tax law § 7, align the Penal Code chapter 3a.

section 35. The effective and transitional provisions 1.
This Regulation shall enter into force 1. January 2002.

2. from the same date the following changes a) regulations on the fiscal measurement of volume oil and gas in the petroleum industry, established by the Norwegian Petroleum Directorate 3. July 1991 No. 532.

b) regulations on fuels and torch gas measurement in the calculation of CO ₂-fee in the petroleum business, established by the Norwegian Petroleum Directorate 12. August 1993 No. 806.

3. Decisions made in pursuance of the regulations mentioned in this paragraph number 2 shall apply until they are revoked or changed by the Norwegian Petroleum Directorate.

4. a) this forskriftens General requirements and requirements concerning testing and operation of the measuring equipment (chapter I, II, III, V, VI, VII and VIII) applies to all measurement systems.

b) requirements for execution (chapter IV) only applies to the measuring system in which the execution was begun after 1. January 2002. The Norwegian Petroleum Directorate can by individual decisions facing the individual operator claim to execution in whole or part the current for measuring equipment or measuring system that is performed before the time mentioned in the preceding period, refer to this regulation § 32.

Reference list-AGA, the American Gas Association-AGA Report No 8, Natural Gas density and compressibility factor executable program and Fortran Code-AGA Report No 9, Measurement of gas by multipath ultrasonic meters-AGA Report No 10, Speed of sound in the natural gas and other related hydrocarbon gases-ASTM 1945, Standard test method for analysis of natural gas by gas chromatography-

API MPMS,, American Petroleum Institute, Manual of Petroleum Measurement Standards-API Recommended Practice 86. Recommended practice for multiphase flow-ISO Natural Gas. Upstream Area-Allocation of gas and condensate (TR ISO TC 193)-multiple-phase NFOGM manual-manual for risk calculation CMR/NFOGM/OD-ISO/OIML The Guide to the expression of uncertainty in measurement-OIML R 117 Measuring systems for liquids other than water, Annex A-ISO 3171 Petroleum liquids-Automatic pipeline sampling ISO 5024 Petroleum liquids and liquefied petroleum gases. Measurement Standard reference conditions-ISO 5167-1 Measurement of fluid flow by means of orifice plates, nozzles and venturi tubes inserted in circular cross section conduits running full-ISO 6551 Petroleum Liquids and Gases-Fidelity and Security of Dynamic-ISO 6976. Natural gas-Calculations of calorific values, density, relative density and Wobbe index from composition-ISO 7278 Liquid hydrocarbons-Dynamic measurement-Proving systems for volumetric meters-ISO 9002 Quality systems, Model for quality assurance in production, installation and servicing-ISO 9951 Measurement of gas flow in closed conduits-Turbine meters-ISO 1000 SI units and recommendations for the use of their multiples and certain other units-ISO/IEC 17025 General requirements for the competence of testing and calibration laboratories-ISO/CD 10715 Natural Gas-Sampling Guidelines-NORSOK in-104, Fiscal measurement systems for hydrocarbon gas-NORSOK in-105, Fiscal measurement systems for hydrocarbon liquid-NORSOK P-100, process system-NS-NS-4900 1024 LNG Custody Transfer Handbook (CTH), G.I.I.G.NL-ISO 13398 Refrigerated light hydrocarbon fluids-Liquefied natural gas-Procedure for custody transfer on board ship-regulations 21. December 2007 Nr. 1738 about requirements for flow meters (for liquids except water)-Regulation 20. December 2007 Nr. 1723 about measurement units and measurement.

Annex 1: form 1, CO ₂-fee, half-yearly payment form 1-CO ₂-FEE EVERY SIX MONTHS PAYMENT half: company: field/gadgets AVG. amount Gas AVG. amount oil/condensate AVG. amount Total Total this period Total interest payments Total corrections Biannual date/sign.
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ for internal use in the Norwegian Petroleum Directorate Account Debit Credit Total Annex 2: form 2, CO ₂-fee, tax calculation per product form 2-CO ₂-FEE TAX CALCULATION PER PRODUCT half: field/Gadgets: Norwegian share: product: Month fuel (Sm/³ 1) Flaring (Sm/³ 1) emissions (Sm/³ 1) total (Sm/³ 1) AVG. rate Avg. AMT. (LCY) 1 2 3 4 5 6 Total former Yugoslav Republic. paid the Difference interest rates a total of date/sign: _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Revised Form 2 is filled out by correction of the earlier settlement.
Specification of interest calculation.

Notes to the regulation on the measurement of petroleum for fiscal purposes and for the calculation of CO ₂-fee to the chapter in the Introductory provisions Of § 1 scope After the Petroleum Law § 1-4 applies to the regulations also for plants on land if the petroleum is transported to the plant by pipeline from the continental shelf and the measurement for practical reasons be made on land in Norway. The Norwegian Petroleum Directorate will, in such cases, to coordinate the supervisory activity with Metrology (JV) as shown to the cooperation agreement between the two agencies. At terminals abroad where Norwegian petroleum landed with the pipeline make the Norwegian Petroleum Directorate measure technical supervision in collaboration with the relevant authorities of the State concerned, cf. the Petroleum Law § 1-4 first paragraph other periods. 
CO ₂-free measurement: CO ₂-tax is calculated per field/gadgets. According to the CO ₂-tax law § 5 is the Ministry of finance that hits the provisions regarding the size and scope of the fee.
The regulation applies to the measurement of natural gas that is used for the operation of internal combustion machines, and for the natural gas being burnt or vented to the atmosphere. Discharge of pure CO ₂ being taxed for the same tax rate as natural gas that is used for combustion. This regulation does not apply to other fuels than natural gas when it comes to requirements to the measuring system.
The regulation also applies to the use of diesel fuel for the operation of internal combustion machines. Diesel amounts are fee-based for removable devices that perform help functions for devices and is associated with the facilities that produce oil or gas, Diesel quantities should be documented and reported as provided in this regulation, § 29. Diesel constitute a relatively limited part of the fuel consumption in the petroleum business. The Norwegian Petroleum Directorate has therefore not found it appropriate to detaljregulere in this regulation how diesel to mengdebestemmes.
At startup of new fields begin CO ₂-fee to run from the time when the petroleum from the first producing well inserted in the facility's process system. From this point all the burning of natural gas or diesel on the person in question be taxable. device
Drilling of production wells from removable devices are not covered by the fee. Removable device that has a direct connection to a production facility is taxable. Wells that are identified as exploration wells will be except tax duty, even when they drilled from the plant with the tax duty.
When the production of petroleum in cease connection with the shutdown of a field, that is, when the recovery of petroleum from the instance terminates and the plant is without hydrocarbons, it shall no longer be paid CO ₂-fee. For devices without own production of petroleum should not be paid CO ₂-fee after the facility's main function is stopped. With devices without own production is meant for example, pump/compressor platforms.
Water vapour or nitrogen as of prosessmessige causes included in the gas amounts to flaring, it may upon application for deduction. 
NOx-free measurement the Norwegian Petroleum Directorate is the competent authority for fixed installed devices on the continental shelf and can authenticate the source-specific emission factor upon application from the taxable, including method of measurement or calculation method to determine the size of the NOx emissions, jf. Regulation 11. December 2001 No. 1451 about excise duties section 3-19-7.
Customs and Excise (TAD), by Customs regions manages the innkrevingsmessige and legal matters regarding the fee. Oil's (OD) responsibilities include the technical responsibility for the firm installed the devices on the continental shelf.
The technical monitoring of NOx emissions from mobile drilling rigs and other maritime business is the maritime's responsibility.
Tax calculation is subject to the requirements provided in regulation on excise duties section 3-19-6.
The fee is calculated for a source-specific emission factor, there should be documentation from the operator that specifies the factors and the method of such determination. This documentation must be submitted for the Norwegian Petroleum Directorate. If no objection is received from the OD, within 4 weeks from the documentation is received, the new factors be taken ibruk.
When the new factors to be taken into use should be informed in writing, TAD. Copy of this correspondence is to be sent and the Customs region.
At introduction of Predictive Emission Monitoring Systems (PEMS), applies the same principle. The operator informs the OD that the PEMS is introduced and that one wants to take the system in use for NOx-tax reporting from a scheduled date. Technical explanations of PEMS must medfølge. If no objections are received within 4 weeks, this is accepted as the basis for NOx-tax reporting. TAD, OD and customs region be informed accordingly as at the source-specific emission factor that the new method of calculation is current.
For flare gas is now a factor of 1.4 g/Sm ³ gas burned in use as the emission factor. The assessment work is in progress to get a better experience the basis for determining this factor.
For the various gas turbines and diesel engines in use can the stencil values are given in regulations on excise duties section 3-19-9, can be used.
The operator will be for the individual installation at any given time have an up to date list of equipment that is NOx-taxable and the factors or measurement methods that are in use to determine discharge.

To section 2 Definitions Definitions as follows of the parent regulations is not repeated in this regulation.

To § 3 Responsibility for this regulation It should be noted that this paragrafens the first paragraph involves a material obligation to conform forskriftens provisions and individual decisions given in pursuance of these regulations. The obligation to do this through the implementation of required systematic measures imposed by this Regulation section 5.
The duties that the licensees in the community have for the petroleum law and CO ₂-tax law, the operator of each individual facility have the direct responsibility for, as by design, procurement and operation of measuring systems and with the reporting and payment of the fee. This will therefore be forskriftens provisions addressed to the operator on behalf of the licensees.

To section 4 requirements of the petroleum industry in General in the comments to the individual paragraphs it is recommended the use of a number of industry standards or other normative documents, possibly with additional points as stated in the note, as a way to meet the forskriftens requirements. The recommended solution is through this referral a recognized norm. In areas where there is no industry standards, describes the regulations in some cases in the comment to the provision solutions that specifies ways to meet forskriftens requirements. Such recommendations will get the same status as the reference to industry standards as mentioned. According to § 4 rights holder can normally add to the reason that the recommended solution to meet the current regulatory requirement.

It is assumed that the regulations and notices be seen in context to get the best possible understanding of the level that will be achieved through regulation. Norms recommended in the comments will be central at the interpretation of the individual regulatory requirements.
Total measurement uncertainty as mentioned in section 8, this regulation will be crucial for the measurement methods that can be used.
The use of recognized norms as mentioned in the first paragraph is voluntary in the sense that it can be selected other technical solutions, methods, or practices.
The basis for the use of alternative methods can be, a) documentation that shows that the measurement uncertainty and the reliability is equal to or better than that of conventional equipment, b) by allocation where measurement disparity between the cost of conventional system compared to a simplified system (cf. Norsok in-105, Annex C).

Clarification regarding the measurement concept should occur at the treatment of the plan for development and operation of a petroleum occurrence (PDO) or plan for the construction and operation of facilities for transport or for the exploitation of petroleum (PAD) or by the processing of application for exemption for such a plan.
Approval of the PDO or PAD means that measuring the concept of associated risk level is approved. Any dispensation, jf. section 33, will only apply to the deviations from regulatory requirements that are not identified in the PDO or PAD.

Chapter II requirements for the management system etc.

The chapter deals with the requirements for management system within both the petroleum law and CO ₂-free the active areas. One has found it appropriate to fix common provisions for the two sites. It also appears to the petroleum law § 10-6 and petroleum regulation § 56, section 57 and section 58.

To section 5 management system a management system for the measurement should include: a) the uncertainty limits the total and for some components, b) lines of responsibility for the follow-up of the quality of the measurement system, c) areas of responsibility between different departments in your organization and the interfaces between them.

For verification of documentation: a) who receives the documentation, and in what order, b) what be done with documentation, c) how information from the documentation are handled, d) how and where the documentation is kept after finished treatment, e) what action is performed if the assessment of the data require further action.

For verification of equipment: a) a description of the purpose, guidelines for execution and the entity that is responsible, b) a description of the equipment verified and specification of the equipment used to this, c) a description of the necessary preparations, d) a systematic description of how the verifications carried out, e) a description of how the results achieved are processed to ensure quality, f) a reference to the journaling for measuring systems , g) an example that shows how the results, notes, and the deviation limits should be registered.

For the use of the equipment: a) a description of the equipment that is used during normal operation, b) a procedure for the treatment of equipment that fails during normal operation c) an overview of important information and experience transfer, d) a list of alarms and a procedure for how they are handled.

The control system can include items other than those listed in this enumeration.

To § 6 Organization and expertise the licensee should ensure that the person in charge as mentioned in this paragraph the second paragraph caters to a particular academic responsibility to see to it that the measurement system at any time meets the applicable provisions. Furthermore, the rights holder should ensure that the person in charge for the measurement system is kept informed about the monitoring systems during the planning, construction and commissioning.
Copyright holder should make sure that: a) there is a job description for each position including skill requirements b) it is established and maintained procedures to identify training needs c) it be ensured that all personnel have been trained to carry out their assigned tasks d) will be established and maintained a record of the qualifications, training and experience for all personnel with the tasks covered by this regulation.

To section 7 Verification the purpose of verification is to confirm, by examining and produce evidence, that specified requirements have been met. With independent verification as mentioned in this paragraph other periods, meant that the operator can be ordered to use third party for execution.

Chapter III General requirements for metering and measurement system to the section 8 Allowed measuring uncertainty Principles for risk analysis is given in ISO "Guide to the Expression of Uncertainty in Measurement" (the Guide).
Manual for risk calculation, CMR/NFOGM/OD, 1999 includes both oil and gas measurement.
± is removed, from the tables, then it when one specifies the 95% level of confidence is enough to enter the numeric value.
When the reference (master) gauges used for the calibration of gauges in operation, should the master meters have significantly better (30%) linearity and repeatability than that specified as the maximum limits in table 2.
A total uncertainty better than the set measuring uncertainty for fuel gas Dazzle metering stations (1.5%) requires that the density is determined so that the total uncertainty comes within the fixed limit.
For a number of parameters is defined in relative measurement uncertainty to the measured value. The workspace for the donors must be adapted to the area it normally is measured in. At startup or shutdown of målerør, one for short periods be outside the workspace and limits for the measuring uncertainty.
In some special cases, the workspace for the press so that the donors requirements as specified for pressure measurement oil, gas; Press metering fuel, flare gas and differansetrykkmåling cannot be met. For information to the Norwegian Petroleum Directorate, as provided for in section 30, the equipment still could be used for the purpose.
When tubes normal calibration is carried out with liquids with low density, such as condensate and LPG, repeatable unit be slightly higher because of the. CTL temperatursensitivitet.
Requirements for ultrasonic fuel gas meter should be as specified in the NORSOK in-104, paragraph
For the sampling and analysis of LNG will be shown it to LNG Custody Transfer Handbook (CTH), NORSOK in-104 and ISO 13398 Refrigerated light hydrocarbon fluids-Liquefied natural gas-Procedure for custody transfer on board ship (1997).

To section 9 measurement units Recognized norm is ISO-1000 or NS-1024. For the device can be used, press the bar.

To § 10 Reference conditions that Reference conditions mentioned in this paragraph are from NS-4900, ISO-5024 or NORSOK in-104 and I-105. From the sale of petroleum products should mass (weight in vacuum) in accordance with SI-units are used as the fiscal size.

To section 11 Provision of energy content, etc.

Recognized norm for the provision of energy content will be ISO-6976 or equivalent. The reference temperature for the energy calculation should be 25 ° C/15 ° C (° C forbrenningens temperature/° C reference volume). Through the use of continuous gasskromatografi will recognized norm be NORSOK in-104.

To § 12 keeping of gas and oil flow out of the measurement system when the oil is loaded to the tanker will resirkulasjonslinje for the oil measure the drive could be allowed.
For shipments of petroleum products in small loads, a need for resirkulasjonslinje at the gauging station. A prerequisite is that a system of ventilintegritet is used.
Any forbikoblingsrør be closed with blind flange or with a isolation valve with double block and avblødningsmulighet, so that the oil can not pass without being measured.

Chapter IV requirements for the execution of the measurement system to the section 13 Requirements to the measuring system in General Gauges that do not have their own calibration device (tube normal) should uttestes with liquid or gas by test conditions that are so similar the operating conditions as possible.
When the regulations mention duplicate instrument features it doesn't mean that the primary measures necessarily should be duplicated. For newer measure principles that ultrasound and coriolis, duplication/surveillance effect is achieved by different signal types.
About it in a measuring with ultrasound allocation drive solution is selected a solution with only one målerør, one should have opportunities to control measures during operation and to have the necessary reserve equipment ready for installation in the målerør.
For gas should flow rate measurement maximum by ultrasound measurement does not exceed 80% of the manufacturer's specified maximum flow rate.
One målerør where it is added to facilitate the maintenance, will fulfill the requirements for a forskriftens fuel gas measuring station.
For the maintenance of fuel gas measuring station with only one målerør it should be circulation.
If the flow rather be used, they should be of recognized product.
Recognized norms of shutdown valves is NORSOK in-104, I-10 and NORSOK P-001.
Valves with double seal and intermediate expanding Chamber can be used.
Shutdown valves should have omkoplingslinje, so that the press can be leveled before they are opened.
It should be considered in need of that electronic equipment should be type approved as specified in OIML R 117 Measuring systems for liquids other than water, Annex A (1995).

To section 13a Flow gauges (for other liquids than water)

Measure regulation is by regulatory amendment 22. August 2006 no. 1014 changed because of Norway's implementation of the Directive 2004/22/EC on measuring instruments (MID), cf. The EEA Agreement-annex II, chap. IX if measuring instruments no. 27. For the measurement in the petroleum business, including measurement of land terminals, this includes only flow gauges (for other liquids than water). The requirements of these measuring instruments are modified in accordance with the directive and are harmonized with the regulations 21. December 2007 Nr. 1738. about the requirements for flow meters (for liquids other than water), established by the Ministry of trade and industry and Metrology. It will be shown and to regulation 20. December 2007 Nr. 1723 about measurement units and measurement. The said regulations sets out in Chapter 4 which requirements flow meters shall meet to be made available on the market and to be able to be used for the calculation of the financial statements. Procedure for conformity assessment noted by § 4-11 in this regulation. The modules that the procedures consists of, are described in annex 1 to the aforementioned regulations. The requirements of the annexes are to be regarded as minimum requirements, so that measuring instruments at least must meet these basic requirements. The licensee that uses and manufacturers, have full opportunity to add stricter requirements as to the reason.
The changes will not affect existing flow gauges in the petroleum business. It applies to both the technical requirements and requirements during use.
The directive is first and foremost aimed at manufacturers of measuring instruments, but have and importance for others that translates measuring instruments. Measuring instruments covered by the MID must meet the technical requirements of the directive before they are made available on the market. Before the completion of the market involves a control compliance rating by use of technical control body and compliance labeling that would show that the requirements of the directive are met. It follows from the instrument-specific annexes in MID which modules the individual measuring device to be approved for, here MI-005, jf. and section 4 of the regulations on the requirements to the flow meters (for liquids other than water). As the manufacturer of the measuring device after the directive is considered too the one who designs and manufactures a measuring device for your use.
For existing flow meter that has been applied or made available on the market before the effective time (October 30, 2006) comes to the requirements of these regulations before the measure that. The same will apply to the flow gauges that are sold in the European economic area before the effective time, and which can then be resold for use. It also applies to the transition rules for flow gauges that are type approved prior to the effective time, cf. section 8-1 in the regulation on the measurement units and measurement.
The changes provide the application where the measure has as a result the regulation the application of the agreement with a foreign State, cf. the Petroleum Law § 1-4 first paragraph last sentence.
The implementation of the MID directive for liquid measuring stations will in practice mean that the operator order a liquid measurement system with a provider/manufacturer. The operator shall be made before the order, and after dialogue with the Norwegian Petroleum Directorate, clarify about the issue of MID is relevant to the respective certificate liquid measurement station. If the certificate should be issued MID, it will be the manufacturer's task to use a recognized technical control body (TKO) in Norway or abroad to be issued a MID certificate.
It is liquid measurement stations that deliver to the ship or into the pipeline systems that are covered by the MID.

To section 14 Measuring the system's mechanical part execution of the measurement system for hydrocarbons in liquid phase Recognized norms is NORSOK in-105 and the American Petroleum Institute (API), Manual of Petroleum Measurement (MPMS) ch. 4 and ch. 5.
By the use of ultrasound to measure measurement for fluid allocation, should the concept of reference measures and portable tube normal is used. 
Tubes normal oil Recognized norms for pipe normal design is NORSOK in-105 and the API, MPMS ch. 4.
Sizing of pipe normal volume based on pulsinterpolasjon can be after ISO7278.
It is not recommended to reduce the volume of the pipe down to the normal minimum limit, as this can lead to repeterbarhetsproblemer.
Compact tubes normal can be used. 
Compact tubes normal Equipment and staffing should be available so that new volume on demand can be established within 4 24.
The following should be met by the design and calibration: a) water calibration b) overview of the critical parts that should be available when needed for maintenance c) compact tubes normal should have equipment for leak detection in the whole of the calibrated area d) a filter should be installed in upstream e) compact tubes normal should be mounted vertically f) compact tubes normal should be installed upstream of the flow meter so that the downstream volume is used. 

Flow meters liquid By ultrasonic liquid measures oppstrømslengde should be 10 d including flow dishes. 
Execution of the measurement system for hydrocarbons in the gas phase Recognized norms is NORSOK in-104, ISO 5167-1, AGA Report no 9 and ISO-9951. 
Flow conditions gas by the use of measure should not exceed dazzle Reynoldstall the highest that there are basic calibration data for (3.3107).
The differential pressure should not exceed 500 mBar. 
Execution of the measurement system for fuel gas widely recognized norms is NORSOK in-104, ISO 5167-1, AGA report No. 9, ISO-9951.
Measurement methods for fuel gas can be: a) measure the dazzle with pressure and temperature measurement b) turbine meter with its pressure and temperature measurement (not push-in turbine) c) ultrasound measures with a minimum of two first rays and its pressure and temperature measurement.

Diameter ratio β can be varied between the outer limits ISO-5167. Differential pressure should not exceed 1 Bar.
Measurement of density can be omitted and will be calculated after the AGA report no 8. 
Execution of the measurement system for torch gas Recognized norm is NORSOK in-104. 
Alternative methods For allocation of oil and gas measurement can testseparatormåling in combination with multiple-phase meters, which is calibrated against the testseparator, is used. Testseparatormåling should in such cases be improved compared to conventional systems.

To section 15 Measure the system's instrument part Recognized norms is NORSOK in-104 and I-105.
The signals from the donors and should be transferred so that the transducers to measure the uncertainty is at least possible. The transfer should take place via the fewest number of signal converters. Signal cables and other parts of the measuring coils should be carried out and be fitted so that they are not affected by electromagnetic interference.
By the use of densitetsmålere by measuring the station's expiration, these should be installed a minimum of 8 D after upstream disturbance.
When oil loading to the tanker carried out, can be determined by density analysis of content in prøvekanne.
When petroleum products are measured, the density is calculated from the recognized norm.
Measurement of petroleum products may be needed to assess the simplifications in the instrumentation.
By gas density measurement can be determined by continuous gasskromatografi, if the decision can be made within the uncertainty requirements for densitetsmåling. If only a gas chromatograph is used, for example, the collation feature a densitometer is performed. This will ensure independent monitoring of densitetsverdi and that the density still is measured when the GC is out of service.
Measured density should be monitored.

To section 16 to measure the system's computer part Recognized norms NORSOK in-104 and I-105.
Computer section should not have other functions than those who are attached to the measuring system. Where multiple digital computers is used it should be defined where the various calculations are performed. To avoid error sources should the computer part that performs fiscal calculations, be linked to other computer equipment in such a way that errors are avoided.
For pulse transfer from flow meters should signal could be read as the number of pulses.
Quantities recorded during calibration should be registered separately, independent of the measured quantities.
Numbers for cumulative fiscal quantities, that this regulation includes, for the individual målerør and the measurement system a total of stored in electronic storage devices. The storage devices should be secured so that they cannot be reset or changed without a protection system followed.
By ultrasound measurement should computer part contain control functions for continuous monitoring of the quality of the measurements. Time measurement should be able to be verified.
By CO ₂ tax measurement can alarm function is transferred as a general alarm to the manned control room.
For fuel gas measurement by use of the flow meter, easier signal transfer than ISO-6551 Class to be considered.

To section 17 requirements for sampling Recognized norms is NORSOK in-104 and I-105, ISO-3171 (oil) and ISO-10715 (gas), NFOGM-Guide for water in oil measurement (2001).
For oil and gas sampling, it should be ensured that the equipment in direct contact with hydrocarbons are consumed not by the medium it takes samples from. The operating instructions should be mounted in the sampling.
Oil samples from the sample taker system should be analyzed in the laboratory according to. ISO-10337, Crude petroleum-Determination of water-Coulometric Karl Fischer titration method. Certified syringes of digital type should be used.
Homogenization of the sample to be analyzed, if necessary, should be documented.
Sampling enclosure for oil and condensate at pipeline transport should have a daily and a monthly prøvekanne. By tank boat loading is a prøvekanne sufficient. The equipment should be designed so that the samples can be transported to the laboratory for analysis. The filling of the prøvekanner should be monitored and the number of samples should be a minimum of 10,000 in the trial period.
Water in the oil can be determined at measurement stations fiscally allocation by using the continuous measurement.
When the water content is over 5 per cent in volume of water should the oil be determined by direct measurement with a water in oil gauge.

Sampling enclosure for gas should have instrument tubes and hoses of such a material that cannot be gassmolekyldiffusjon.
It should be possible to remove the air from the system by attaching new prøvekanner.
Of CO ₂-free measurements will not be required to install automatic sampling equipment.

To chapter V requirements for calibration and verification etc. before the measurement system is applied to the section 18 Application for consent Application for consent should be released no later than 20 working days prior to the scheduled start of the task it sought consent for.
A prerequisite for being able to obtain a consent is that there be established a good dialogue between the operator and the NPD in the construction period to ensure a common understanding for the safeguarding of the requirements for functionality for the fiscal measurement system.
How the events regarding the fiscal measurement system shall be recorded, and how the follow-up of these will take place, should be described.
Consent application should further contain the allocation procedures and any load the replacement procedures.
Consent the application should also include a system for calculating the mass balance for hydrokarbonstrømmen through the plant, so that the flare gas quantities can be calculated when needed.

To § 19 in General when the equipment is taken into use, the manufacturer's calibration data used, if these have adequate traceability and quality. If this is not the case, the equipment should be calibrated by a competent laboratory. With a competent laboratory is meant a laboratory that is accredited as mentioned in recognized norm a 45,000/ISO-17025, or otherwise have documented expertise and ensures traceability to international or national normals.
On the basis of the operator's work schedule to the Norwegian Petroleum Directorate to which tasks will be witnessed.
For all tests of critical equipment components should be worked out in advance a test procedure where the requirements clearly stated. Test procedure should in addition have the references to the relevant regulations and standards.

To section 20 calibration of mechanical part the controls referred to, for example, will be surveying of critical mechanical parameters with traceable equipment.
Requirements for the calibration of flow meters and pipes normal cf. This Regulation section 8.
Hollow target normal used for the calibration of tubes normal should certified annually. The volume of the hollow target standard should be certified by gravimetrisk method with reference to the national norm of uncertainty better than ± 0.01%.
For small one-way pipes it should be verified that the normals 4 volumes are mutually consistent. The spread should not exceed 0.02% for k-factors or flow rates.
There should be a distinct difference between the 4 volumes.
For all pipe, it should be verified that the normals 4 volumes are consistent by volume calibration or remodeling activities. This is done by establishing k-factor for a meter and so shift the volume and repeat the calibration sequence.
Recommended calibration methods for pipe normal: a) "Master trying/master meter" method.

Before and after or at the same time with this calibration should "master meter" is checked against the "master" the brat with the same requirements for repeatability as mentioned in section 8. Calibration requirement is met if "master meters» calibration factor before and after calibration of the tubes normal, has a deviation that is less than 0.02%.

b) "Master tank/master meter" method.

Here comes the same calibration requirements that letter a c) water calibration method.

Three consecutive single calibrations are performed, where one of them has a flow rate that is different from the other two. Repeatability is as for the methods in the letter a and b. Provision with volumetric reference will be acceptable at the factory testing (FAT), about the provision with the gravimetrisk reference is carried out before the start site.
By calibration as in point a) and b) should 5 consecutive single calibrations in each measure is carried out.
Flow gauge linearity and repeatability should be tested in the highest and lowest part of the workspace, and in three points the limits natural divided between.

To section 21 calibration of the instrument part measure results should be from the calibration equipment equivalent to that which will be used for the calibration of the donors on the site. The dealer can be omitted and replaced with the signal generator. Barrierenes the influence on the measuring signal should be mapped.
Verification of turbine målernes pulse transmission system should be carried out. Recognized norm is ISO-6551. Reading of the pulses should be made on the computer section and on external counter. It should be simulated 100,000 pulses and by deviation of two pulses should simulated pulse number of doubles.
At the start-up of new measurement systems can remain on the instruments the inventory beyond the time that is recommended for the calibration. In this case the calibration is performed by a competent laboratory before the instruments be taken into use.
By calibration of the turbine meters with low k-factor and/or by the use of compact tubes normal it may be appropriate that each calibration consists of several repetitions, to increase the volume and the number of calibration pulses from turbine meter.

To § 22 verification of computer part Alarm handling and reporting should be verified with manually posted measurements for each målerør and the whole measuring system. The system should be verified for the voltage error and data line transmission errors.
Verification of the pulse alarm for turbine measures should be carried out and the alarm activated in the event of discrepancies between the two pulse trains.
The verification of the electronic equipment's performance should be carried out and be in accordance with the climatic and mechanical environment measuring equipment will be exposed.

To chapter VI requirements for the measurement system in use to section 23 Maintenance through the use of the e-mail operation based maintenance systems must follow up of the fiscal parameters and scheduled maintenance occur on a systematic and controlled manner.
To ensure continuous quality in the polls it must at all times be relevant professionals available for interpretation, analysis and eventual correction of error conditions encountered.
When two instruments performs the same type of measurement of the same quality, then one of the meters is identified as in operation and the other will have a monitoring/reserve function. Switch between the two instruments should only happen when the measures in operation fails.

To section 24 operating requirements for pipe normal calibration of tubes normal is featured in the note to section 20. If the tubes normal volume differs more than ± 0.04% from the volume at the previous calibration, troubleshooting should be made to uncover the cause of the anomaly.
Lower the calibration frequency can be used for pipe normals, based on a technical assessment of the stability of previous calibrations (better than ± 0.02% of the average volume for 3 consecutive), considered in a cost benefit perspective.
Existing tubes normal calibration interval on the basis of the assessment in section above increased to double the existing interval. When you've got experience from this calibration frequency can new assessment be done.
If the assessment of the calibration result from multiple pipe normals shows systematic deviation, the Norwegian Petroleum Directorate should be consulted regarding questions about the calibration result should be implemented.
For measuring systems used for fluids with low density, such as condensate and LPG, can limit the values that are given in this notice, cf. Note to section 8.

To § 25 operating requirements for flow meters Recognized norm for the monitoring of turbine meter k-factors is the API MPMS ch. 13.
For flare gas meters should zero point control are made regularly with an external device. Other types of controls can it depends on the product of the measures be relevant to carry out in order to verify the quality of the measures.
Tilstandsbaserte audit packages for multiple beam ultrasonic gauges "Condition Based Monitoring (CBM)" should be used. Examples of parameters that can be included in a health monitoring system:-the first health check (foot print), recorded at the flow laboratory-Signal to noise ratio (SNR)-Signal quality (Gain and Burst)-Flow profile monitoring (flatness, symmetry, turbulence and swirl) sound speed (VOS)-various forms of densitetssammenlikning-Speed of each audio path.

Monitoring systems will vary slightly between the different vendors.
The deviation limits for the different parameters is determined before startup, or as soon as possible then.
Recalibration should be performed if the meter has a poor maintenance history.
For shipments of petroleum products in small loads will it could be appropriate to use the K-factor that is established under the recycling.
For requirements for repeatability and linearity of the calibration of the flow meter will be shown it to this Regulation section 8.
Control and cleaning of the measuring tube, if necessary, should be made by the dismantling of the measure the duct sections.
Operating requirements for turbine measures differ from the design requirements given in section 8 and is specified in section 25.

To § 26 operating requirements for instrument part using the monitoring features can be used condition based maintenance to extension of the calibration intervals.
Instruments used for calibration should be kept separate from other instruments.
The interval between the calibrations can be increased if the documented stability for measuring equipment.
By condition based maintenance should a number of donors for each parameter on the gauging station be calibrated at least once a year to ensure traceability. A comparison of these to the corresponding donors on measurement stations should be carried out to ensure traceability.
By preparation of control limits for the individual component by online gasskromatografer (benchmark test), one should start with the parent GC risk requirements, and divide on the square root of the number of components. Deviation of the individual component and for the combined values should always be checked against the normalized values to reduce the weather impact on the numbers. Deviation for each component should not involve more than 0.1% deviation in the calorific or standard density.

Transition to benchmark principle for GC, for facilities that operated with regular calibration and correction should be carried out as soon as it is convenient is appropriate. For example, in connection with the upgrading of equipment.
Recognized norm to the insecurity of traceable reference gases are given in NORSOK in-104.

To § 27 operating requirements for the computer part alarms from the measurement system should be reviewed after the startup, to systematically reduce the number of and get an appropriate data interface with large control room equipment.
The calculation requirements should be verified using an independent system (PC).

To Chapter VII requirements for documentation to section 28 documentation before using the system measurement is no comment.

To section 29 Documentation for the measurement system in use this paragrafens the first and second paragraph applies to all measurement as is referred to in this regulation. Documentation as mentioned in this paragraph the first paragraph will cycle be specifications, calculations and drawings pertaining to the measurement system, as well as operating procedures and other relevant documentation.
The general rule in the Petroleum Act section 10-4 of the material and information means that the documentation pertaining to fiscal measurement as referred to in this Regulation shall be available in Norway no matter how operating organization is located. This does not imply anything forbidden to save the documentation out of the country, as long as it can be made available to the Norwegian Petroleum Directorate within a reasonable time. In some cases, eg. under the supervision of the measuring stations that are located abroad, it will be most convenient that the Norwegian Petroleum Directorate given access to documentation on the spot. By operating organizations located outside Norway documentation should be available on the usage location and available for the Norwegian Petroleum Directorate upon request.
If any of the equipment components within their area driver variation and this detected by routine calibration, this is not the basis for the correction.
The correction should not be implemented, however, about the cost of corrective work exceeds the value of the amount of the measured error to be corrected for.
The standard form for the reporting of CO ₂-fee is given as annex 1 and 2 to this regulation.
The operator can, if appropriate, to report diesel consumption to the NPD by the same principle as the corresponding report to the Environment Agency according to the climate quota regulations note to § 30 Information Download the replacement procedures should be designed so that when the oil is sold in tanker loads from the buoy to the Mediterranean, should corrective limit be the internationally accepted for oil trading, 0.5%. Correction should only be carried out if both the ship's number in the unload port and terminal number differs from the measure the drive numbers with 0.5% or more. it should Further be proven wrong by the official measuring equipment, can be performed before the corrections. 0.3% has often been used for ship loads from the petroleum in the Norwegian part of the continental shelf.

To the section 31 Calibration documents is no comment.

Chapter VIII General provisions section 32 supervisory authority-the authority to make individual decisions, etc.

The Ministry of petroleum and energy is complaint authority for Oil's decision that has been made in pursuance of this regulation.
When it comes to the Foundation for and the extent of CO ₂-fee, is the Ministry of finance appeal authority.
Any complaints on the decision to be sent through the Norwegian Petroleum Directorate, cf. Administrative Law Chapter VI.

To § 33 Exemption Exemption denotes the authorities ' decision, normally for an application, whether to accept a deviation from a regulatory requirement. Deviation in this context denotes a discrepancy between the selected solutions and regulatory requirements.
It must apply for an exemption if a want to use a different solution than the one that goes out of a specific regulatory requirements, or a solution that does not meet the level requirements of the regulations.
Any applications for exemption should normally contain, a) a list of the provisions that it sought an exemption from, b) an account of the special circumstances that make an exemption necessary or reasonable, c) an account of how dispensasjons case has been dealt with internally in the business, d) a description of the deviation and the scheduled duration of the anomaly, e) a description of any measures that fully or partially to compensate for deviation , f) a description of any measures taken to correct the deviation, if the variance is of a temporary nature.

To § 34 Penalty provision is no comment.

To section 35 the effective-and transitional provisions this regulation is material terms essentially a continuation of the earlier right. The regulation does not skjerpelser that necessitates the exception from the entry into force or transitional arrangements.