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According to Section 1-4 of the Petroleum Act the regulations apply also to onshore facilities if petroleum is transported to the facility by pipeline from the continental shelf and the metering for practical reasons is carried out onshore in Norway. The Norwegian Petroleum Directorate will in such cases coordinate the supervisory activities with the Office of Weights and Measures (Justervesenet-JV) as referred to in Agreement on co-operation between the two agencies. At terminals abroad where Norwegian petroleum is landed by pipeline the Norwegian Petroleum Directorate carries out supervision of the metering in co-operation with the relevant authorities of the state in question, cf. Section 1-4 first paragraph second sentence of the Petroleum Act.
The CO2 tax is calculated per field/facility. In accordance with the Act relating to CO2 Tax Section 5, decisions relating to the basis and extent of the tax are made by the Ministry of Finance.
These regulations are applicable to the measurement of natural gas used for the operation of combustion machinery and to the measurement of natural gas burned off or vented to the atmosphere. Discharge of pure CO2 should be taxable according to the same tax rate as natural gas used for combustion. These regulations are not applicable to other fuel than natural gas with regard to requirements applicable to metering system.
The regulations are also applicable to diesel oil used for operation of combustion machinery. Diesel is taxed for mobile facilities which undertake service functions for facilities and are associated with facilities which produce oil or gas. The diesel quantities should be documented and reported as ment ioned in Section 29 of these regulations. Diesel constitutes a relatively limited part of the fuel consumption in the petroleum activities. The Norwegian Petroleum Directorate has consequently considered it to be inappropriate to impose a detailed procedure in these regulations with regard to determination of the volume of diesel oil.
When putting new fields on stream, the CO2 tax starts to run from the time when petroleum from the first producing well enters into the process system of the facility. From this point on, all burning of natural gas or diesel on the facility in question wi ll be taxable. Wells which are classified as exploration wells will also be exempted from the CO2 fee when they are drilled from facilities which pay the CO2 fee.
Drilling of exploration wells from mobile facilities should not be taxable. A mobile facility with a direct connection to a production facility should be subject to CO2 tax.
When petroleum production ceases in connection with shutdown of a field, i.e. when the reco very of petroleum from the deposit ceases and the installation is without hydrocarbons, no further CO2 tax should be payable. In the case of facilities without own production of petroleum no CO2 tax should be payable after the principal function of the facility has ceased. By facilities without own production is meant for example pumping/compressor platforms.
Deduction may on application be made for water vapour or nitrogen accompanying volumes of gas for flaring for process related reasons.
The Norwegian Petroleum Directorate is the competent authority for permanent facilities on the continental shelf and can, among other things, approve a source-specific emission factor following an application from the party liable for tax, including the measurement or calculation method used to determine the size of NOx emissions, cf. Section 3-19-7 of the Regulations dated 11 December 2001 no. 1451 relating to Excise duties.
The Directorate of Customs and Excise (TAD), represented by the Customs Regions, manages the collection and legal aspects of the tax. The Norwegian Petroleum Directorate‟s (NPD) responsibility covers the technical responsibility for fixed facilities on the continental shelf.
The technical follow-up of NOx emissions from mobile drilling rigs and other maritime activities is the responsibility of the Norwegian Maritime Directorate.
The tax will be calculated pursuant to requirements stipulated in Section 3-19-6 of the Regulations relating to excise duties.
If the tax is calculated according to a source-specific emission factor, documentation should be available from the operator which states the factors and method for such stipulation. This documentation should be presented to the Norwegian Petroleum Directorate. If no objections have been received from the NPD within four weeks after the documentation has been received, the new factors can be utilised.
TAD should be informed in writing when the new factors are utilised. Copies of this correspondence should be submitted to the NPD and Customs Region.
The same principle applies for introduction of Predictive Emission Monitoring Systems (PEMS). The operator should inform the NPD that PEMS has been introduced and that it is desirable to use the system for NOx tax reporting starting on a specified date. Technical explanations of PEMS should be enclosed. If no objections have been received within four weeks, this will have been accepted as a basis for NOx tax reporting. TAD, NPD and the Customs Region should be informed correspondingly as for the source-specific emission factor that a new calculation method is in effect.
With regard to flare gas, a factor of 1.4 g/Sm3 of gas combusted is currently used as the emission factor. Consideration to establish a better background experience to stipulate this factor is in progress.
The standard values listed in Section 3-19-9 of the Regulations relating to excise duties may be used for the different gas turbines and diesel motors in use.
The operator should , at all times and for each individual facility, have an updated list of equipment subject to NOx tax, as well as the factors or measurement methods in use to determine the emissions.
Definitions according to superior legislation are not repeated in these regulations.
It is emphasised that the first paragraph of this section entails a material duty to comply with the provisions of these regulations and with individual decisions issued pursuant to the regulations. The duty to do this through implementation of necessary systematic measures follows from Section 5 of these regulations.
The operator of the individual facility will be directly responsible in relation to the duties placed with the licensees jointly pursuant to the Petroleum Act and the Act relating to CO2 Tax, such as the design, purchase and operation of metering systems with associated reporting and payment of tax. The provisions of these regulations are consequently addressed to the operator on behalf of the licensees.
In comments to the individual sections the use of a number of industry standards or other normative documents is recommended, in some cases with additional reference as stated in the comments, as a way to comply with the requirements of the regulations. Through this reference the recommended solution becomes a recognised standard. In areas where no industry standards are available, these regulations in some cases contain, in the comments to the provision in question, a description of solutions that represent ways in which to comply with the requirements of the regulations. Such recommendations will have the same status as reference to industry standards as mentioned. According to Section 4 the licensee may as a rule assume that the recommended solution will satisfy the regulation requirement in question.
The regulations and the comments are meant to be seen as a whole in order to achieve the best possible understanding of the level aspired for through these regulations. Standards recommended in the comments will be central in the interpretation of the individual regulation requirements.
Total measuring uncertainty as mentioned in Section 8 of these regulations will be decisive in selecting the measuring methods to be used. The use of recognised standards as mentioned in the first paragraph is optional inasmuch as other technical solutions, methods or procedures may be selected.
The basis for using alternative methods may be:
a) documentation demonstrating that measuring unc ertainty and operational reliability is equal to or better than conventional equipment,
b) in metering for allocation purposes, when there is a cost disproportion between a conventional system compared to a simplified system (cf. NORSOK I-105, Annex C).
Clarification with regard to the measurement concept should emerge from the process in connection with approval of Plan for development and operation of a petroleum deposit (PDO) or Plan for installation and operation of fac ilities for transport and utilisation of petroleum (PIO) or an application for exemption from such plan.
Approval of PDO or PIO entails authorisation of the measurement concept with associated uncertainty level. A possible exemption, cf. Section 33, shoul d only be applicable to deviations from regulation requirements which are not identified in the PDO or PIO.
This chapter contains requirements to management control systems within the scope of application of both the Petroleum Act and the Act relating to CO2 Tax. It has been deemed appropriate that common provisions are applicable to both these areas.
Reference is further made to Section 10-6 of the Petroleum Act and Sections 56, 57 and 58 of the Petroleum Regulations.
A management control system for measuring should contain:
a) uncertainty limits accumulated and by component;
b) the chain of responsibility for the follow-up of measuring equipment quality;
c) apportionment of responsibility between different sections of the organisation and interfaces between them.
For verification of documentation:
a) persons who receive the documentation and in what order;
b) what is done with the documentation;
c) how information from the documentation is handled;
d) after processing, how and where the documentation is filed;
e) what action is taken if the evaluation of data requires follow-up.
For verification of equipment:
a ) a description of purpose, guidelines for implementation and definition of the section responsible;
b) a description of equipment verified and specification of equipment to be used in the process;
c) a description of the necessary preparations;
d) a systematic description of how the verifications are carried out;
e) a description of how the derived results are handled to ensure quality;
f) a reference to the log book for the metering systems;
g) an example showing how results, remarks and deviation limits should be registered.
For use of equipment:
a) a description of the equipment in service during normal operation;
b) a procedure on how to handle situations where any of the in-service equipment fails during normal operation;
c) a summary of important information and how relevant experience and information is conveyed from one shift of personnel to the next;
d) a list of alarms and a procedure on how they are handled.
The management control system may comprise other elements than those mentioned in this list.
The licensee should see to it that the person responsible as mentioned in this section second paragraph exercises a particular professional responsibility to see that the metering system at all times complies with the provisions in force. Furthermore the licensee should see to it that the person responsible for the metering system is kept informed about metering systems under planning, manufacture and completion.
The licensee should ensure that:
a) a job description exists for each position, which includes qualifications requirements;
b) procedures are established and maintained to identify training needs;
c) all personnel are properly trained to perform their dedicated tasks;
d) a summary of qualifications, training and experience is established and maintained in respect of all personnel with tasks comprised by the present regulations.
The intention with verification is to confirm, by checking and ac quiring evidence for, compliance with specified requirements. By independent verification as mentioned in the second sentence of this section is meant that the operator may be required to use a third party for the execution of this function.
The basic principles for uncertainty analysis are stated in the ISO “Guide to the Expression of Uncertainty in Measurement” (the Guide).
Manual for uncertainty calculation, CMR/NFOGM/OD, comprises both oil and gas measurement.
± has been removed from the tables, as it is sufficient to state a numerical value when a 95% confidence level is used. When reference (master) meters are used to calibrate operational meters, the meters should have a significantly better (30%) linearity and repeatability than what are specified as maximum limits in Table 2.
A total uncertainty better than the stipulated measurement uncertainty for fuel gas blend measurement stations (1.5%) requires that the density is determined, so that the total uncertainty is within the stipulated limit.
In relation to a number of parameters, measuring uncertainty is defined in relation to measured value. The operating range for sensing elements should be adapted to the normal range of measurement. When a metering tube is started up or shut down, there will be short periods where one is outside the operating range and uncertainty limits.
In some special cases the working range for pressure sensing elements is such that the requirements given for pressure measurement oil, gas; pressure measurement fuel, flare gas and differential pressure measurement cannot be fulfilled. After informing the Norwegian Petroleum Directorate, as given in section 30, the given equipment can be used for the purpose.
When prover calibration is carried out with low-density fluids, as condensate and LPG, the repeatability will be slightly higher because of CTL temperature sensitivity.
Requirements for ultrasonic fuel gas meter should be as given in NORSOK I-104, article 18.104.22.168.
With regard to sampling and analysis of LNG reference is made to LNG Custody Transfer Handbook (CTH), NORSOK I- 104 and ISO 13398 Refrigerated light hydrocarbon fluids – Liquefied natural gas – Procedure for custody transfer on board ship.
Recognised standard is ISO 1000 or NS 1024. With regard to pressure, the unit „bar‟ may be used.
The reference conditions mentioned in this section are from NS 4900, ISO 5024 or NORSOK I-104 and I-105. When petroleum products are sold, the mass (vacuum weight) should in accordance with SI units be used as fiscal quantity.
Recognised standard for determination of energy content will be ISO 6976 or equivalent. Reference temperature for energy calculation should be 25°C/ 15°C (°C reference temperature of combustion/°C volume). When continuous gas chromatography is used, recognised standard will be NORSOK I-104.
When oil is loaded into tankers a recirculation line for the oil metering station may be allowed.
When loading petroleum products in small batches, there will be a need to install a by-pass loop for recirculation at the metering station. A prerequisite is that a system for valve integrity is used.
Any bypass tube should be closed using blind flense or shutoff valve with double block and blee d system, so that oil can not pass without being measured.
Meters without a separate calibration unit (in-line prover) should be tested with liquid or gas using test conditions that are as close to the operational conditions as possible.
When the Regulations mention duplicated instrument functions, this does not mean that the primary meter should be duplicated. The duplication/monitoring can i.e. for Coriolis and ultrasonic meters be achieved using different signal types.
In gas metering the maximum flow velocity during ultrasonic metering should not exceed 80 percent of the maximum flow rate specified by the supplier.
One metering tube where maintenance is provided for will fulfil the regulation requirement to a fuel gas metering station.
With regard to maintenance of a fuel gas metering station with only one metering tube, there should be a bypass.
If flow straighteners are used, they should be of a recognised make.
Recognised standards for shut-off valves are NORSOK I-104, I-105 and NORSOK P-001.
Vents with double tightening and intermediate expanding chamber can be used.
The block-and-bleed valves should have an equalising line to allow pressure to be equalised before they are opened.
The need for electronic equipment being approved as given in OIML R 117 Measuring systems for liquids other than water, Annex A should be considered.
The NPD metering regulation is the amendment of 22 August 2006 no. 1014, changed as a consequence of Norway‟s implementation of the Directive 2004/22/EU, Measuring Instrument Directive (MID), cf. the EEA treaty, annex II chap. IX, concerning measuring ins truments no. 27. For measurement in the petroleum sector, included onshore terminals, this requirement only comprises measuring systems for liquids other than water. The requirements for these measuring systems are changed according to the MID and are har monized with the Regulation of 21 December 2007 no. 1738, “Requirements for measuring systems for liquids other than water” adopted by Department for Industry and Trade (NHD) and Norwegian Metrology Service. The regulation mentioned above section 4, determ ines which requirements measuring systems should fulfil to be made available on the market and to be used in connection with economical transactions. The procedure for conformity evaluation is in section 4-11 of this regulation. The modules to which the pr ocedures refer to is described in attachment 1 to the above mentioned regulation. The requirements in the annex are regarded as minimum requirements, such that the measuring equipment should at least fulfil these minimum requirements. The Licensee, as user, and the manufacturers are thereby free to introduce more stringent requirements.
The changes are not valid for existing flow meters used in the petroleum industry. This exemption applies to both technical requirements and requirements for use.
The Directive is primarily directed to the manufacturer of measuring instruments, but is also applicable for others selling measuring instruments. Measuring instrume nts covered by MID should fulfil technical requirements stated the directive before they are made available on the market. The pre market survey includes conformity assessment done by a notified body and a conformity marking to prove that the requirements of the Directive are fulfilled. It follows of the instrument specific annexes to MID which module s a specific measuring instrument (system) should be approved in accordance to, cf. MI-005 and section 4 in Regulation for measuring systems for liquids other than water. According to the directive a manufacturer which produce an instrument for own use, is considered a manufacturer of a measuring instrument regulated by MID.
For existing measuring systems which have been in use or made available on the market before the entry into force date (30 October 2006), the requirements of the NPD metering regulati on apply as in the past (MID does not apply). Same apply to measuring equipment sold in the EEA before the time of implementation, and thereafter resold for use. Transitional provisions are prevailing for measuring systems which are type approved before the time of implementation, cf. section 8-1 in the regulation for measurement units and measurement.
The changes will not apply where the Regulations relating to measurement of petroleum for fiscal purposes come into force as a consequence of a treaty with a foreign state, cf. the Petroleum Act section 1-4 first paragraph.
Implementation of the MID Directive for liquid measurement stations will, in practice, entail that the operator orders a liquid measurement system from a supplier/manufacturer. Before ordering, and following a dialogue with the Norwegian Petroleum Directorate, the operator should clarify whether issuance of an MID certificate will be relevant for the liquid measurement station in question. If a MID certificate is to be issued, it will be the supplier‟s responsibility to use an approved notified body (TKO) in Norway or abroad to issue a MID certificate.
Liquid measurement stations for crude oil/product ships or pipeline systems are covered by MID.
Design of the metering system for hydrocarbons in liquid phase
Recognised standard is NORSOK I-105 and American Petroleum Institute (API), Manual of Petroleum Measurement (MPMS) ch.4 and ch.5. When an ultrasonic met er is used in allocation metering for liquid, a concept with reference meter and portable prover should be used.
Recognised standards for prover design are NORSOK I-105 and API, MPMS ch.4.
Determination of prover volume based on pulse interpolation may be according to ISO7278.
It is not recommended to reduce the prover volume down towards the design criterion, as this may lead to repeatability problems.
Compact prover may be used.
Equipment and manning should be available so that it is possible if required to establish a new volume within four days.
With regard to design and calibration the following should be complied with:
a) water calibration;
b) list of critical parts, which should be available for necessary maintenance;
c) compact provers should be equipped with leak detection facilities in the total calibrated area;
d) filters should be installed upstream;
e) compact provers should be installed vertically;
f) compact provers should be installed upstream of the flow meter so that the downstream volume is used.
Flow meters liquid
At the ultrasonic liquid gauge the upstream length should be 10D including the flow straightener. Design of the metering system for hydrocarbons in gas phase Recognised standards are NORSOK I-104 , ISO 5167-1, AGA Report no. 9 and ISO 9951.
Flow profile gas
When orifice plate is used, the Reynolds number should not exceed the highest number for which there exists basic calibration data (3,3 10 7).
Differential pressure should not exceed 500 mBar.
Design of the metering system for fuel gas
Recognised standards are NORSOK I-104, ISO 5167-1, AGA Report no. 9 and ISO 9951.
Measurement methods for fuel gas may be:
a) orifice plate with pressure and temperature compensation;
b) turbine meter with associated pressure and temperature compensation; (not insertion turbine)
c) ultrasonic meter with minimum two output beams and associated pressure and temperature compensation.
The diameter ratio β may vary between the outer limits referred to by ISO 5167. The differential pressure should not exceed 1 Bar.
Density measurement may be omitted and be calculated according to AGA report no.8.
Design of the metering system for flare gas
Recognised standard is NORSOK I-104.
When metering oil and gas for allocation purposes test separator measurement in combination with multiphase meters, which are calibrated against the test separator, may be used. Test separator measurement should in such cases be improved in relation to conve ntional systems.
Recognised standards are NORSOK I-104 and I-105.
The signals from the sensors and transducers should be transmitted so that measurement uncertainty is minimised. Transmission sho uld pass through as few signal converters as possible. Signal cables and other parts of the instrument loops should be designed and installed so that they will not be affected by electromagnetic interference.
When density meters are used at the outlet of the metering station, they should be installed at least 8 D after upstream disturbance.
When oil is loaded into tankers, the density may be determined by analysing the contents of a sample container. When petroleum products are measured, density may be calculated by using a recognised standard.
In measuring petroleum products, there may be a need to consider simplifications in the instrumentation.
When gas metering takes place, density may be determined by continuous gas chromatography, if such determin ation can be done within the uncertainty requirements applicable to density measurement. If only one gas chromatograph is used, a comparison function against for example one densitometer should be carried out. This will provide independent control of the density value and that density is still measured when GC is out of operation.
Measured density should be monitored.
Recognised standards are NORSOK I-104 and I-105.
The computer part of the metering system should not have any functions other than those associated with the metering system. Where a number of digital computers are used, the locations where the different calculations are performed should be defined. To avoid sources of error, the part of the computer performing the fiscal calculations should be connected to the other computer equipment in such a way that errors are avoided.
With regard to pulse transmission from flow meters it should be possible to read the signal as a number of pulses.
Quantities registered during calibration should be registered separately, irrespective of measured quantities.
Figures for accumulated fiscal quantities, which are comprised by the present regulations, should for each meter run and the total mete ring system be stored in electronic storage units. The storage units should be secured in such a way that they cannot be zeroed or altered unless a security system is followed.
In ultrasonic measuring the computer part should contain control functions for continuous monitoring of the quality of the measurements. It should be possible to verify time measurement.
With regard to CO2 tax measurements the alarm function may be carried out by transferring a general alarm to a manned control room.
With regard to fuel gas metering using flow meter, a simpler signal transmission than ISO 6551 Class A may be considered.
Recognised standards are NORSOK I-104 and I-105, ISO 3171 (oil) and ISO 10715 (gas), NFOGM - manual for water in oil measurements (2001).
In respect of oil and gas sampling it should be ensured that equipment in direct contact with hydrocarbons is not corroded by the substance from which it is sampling. Operating instructions should be mounted in t he sampling cabinets.
The liquid samples from the sampling system should be analysed at a labor atory according to ISO 103337, Crude petroleum - Determination of water - Coulometric Karl Fischer titration method. Certified syringes of digital model should be used.
Homogenisation of samples to be analysed should if necessary be documented.
The sampling cabinet for oil and condensate should in the case of pipeline transportation have a daily and a monthly sample container. When loading into a tanker one s ample container will be sufficient. The equipment should be designed so that the samples can be transported to a laboratory for analysis. The filling of sample containers should be monitored and the number of samples should be not less than 10.000 during the sampling period.
Water in oil may be determined fiscally at allocation metering stations by using continuous metering.
When the water content is in excess of 5 volume percent, water in oil should be determined by direct measuring using a water-in-oil meter.
The sampling cabinet for gas should have instrument pipes and hoses of such a material that gas molecule diffusion cannot take place.
It should be possible to evacuate air out of the system before placing new sampling cylinders in service.
Installation of automatic sampling equipment will not be required in respect of CO2 tax metering.
Application for consent should be submitted no later than 20 working days prior to planned start-up of the activity that the application for consent refers to.
It is important that it during the project phase is established a good communication between the operator and the NPD. This is to ensure a common understanding of the requirements between the authority and the licensee.
How incidents connected with the fiscal measurement system are to be registered, and how follow-up is to be carried out, should b e described.
The application for consent should furthermore contain allocation procedures and cargo claims procedures, if any. The application for consent should also contain a system for calculation of the mass balance for the flow of hydrocarbons through the processing plant, so that flare gas quantities can be calculated when necessary.
When equipment is taken into use, the calibration data furnished by the supplier may be used, if they are having adequate traceability and quality. If such is not the case, the equipment should be recalibrated by a competent laboratory. By competent laboratory is meant a laboratory which has been accredited as mentioned in recognised standard EN 45000/ISO 17025, or in some other way has documented competence and ensures traceability to international or national standards.
Based on the work progress plan of the operator, the Norwegian Petroleum Directorate will decide which activities it will want to be witnessed.
A test procedure which clearly states the requirements should be prepared in advance for all tests of critical equipment components. The test procedure should contain references to relevant regulations and standards.
The checks referred to will for example be measuring of critical mechanical parameters by means of traceable equipment.
With regard to requirements to calibration of flow meters and provers, reference is made to Section 8 of these regulations.
Volumetric measure used for calibration of prover should be certified annually. The volumetric measure volume should be certified by gravimetric method with reference to national standard with uncertainty better than ± 0.01%.
With regard to small one-way provers it should be verified that the 4 volumes are mutually consistent. The spread should not exceed 0.02 % for K-factors or flow rates.
There should be a clear distinction between the four volumes.
Following volume calibration or rebuilding activities it should be verified for all in-line provers that the four volumes are consistent. This is done by establishing a K factor for a meter, then changing the volume and then repeating the calibration sequence.
Recommended calibration methods for provers:
a) “Master prover/master meter” method. Before and after or simultaneously with this calibration the “master meter” should be checked against the “master prover ”, with the same requirements to repeatability as mentioned in Section 8. The calibration requirement is met if the “master meter” calibration factors before and after the calibration of the prover deviate from each other by less than 0.02%.
b) “Master tank/ master meter” method. The same calibration requirements as in item a) are applicable.
c) “Water draw” method. Three consecutive individual calibrations should be carried out, and one of these should have a flow rate which is different from the two others. The repeatability requirements are the same as for the methods mentioned in items a) and b). Determination with volumetric reference will be acceptable in the case of factory testing (FAT) if determ ination with gravimetric reference is carried out before start-up at the place of operation.
During calibration as per item a) and b) five consecutive individual calibrations should be carried out at each measurement location.
The linearity and repeatability of the flow meter should be tested in the highest and lowest part of the operating range, and at three points naturally distributed between the minimum and the maximum values.
Measurement results should be from calibration equipment equivalent to that which will be used for calibration of the transmitters at the place of operation. Transmitter may be omitted and replaced by a signal generator. The effect of the barriers on measurement signals should be determined.
Verification of the system for pulse transmission from the turbine meters should be carried out.
Recognised standard is ISO 6551. The reading of the pulses should be undertaken on the computer part and also on external counters. 100 000 pulses should be simulated and in the event of deviation of two pulses the simulated pulse number should be doubled.
When new metering systems are started up, instruments may be kept in storage for a period of time exceeding the recommended time for calibration. In such cases calibration should be carried out by a competent laboratory before the instruments are taken into use.
During calibration of turbine meters with a low K factor and/or during use of a compact in-line prover, it may be appropriate for each calibration to consist of multiple repetitions, so as to increase the calibration volume and the number of pulses from the turbine meter.
Alarm handling and reporting should be verified with manually entered measurements for each metering tube and for the entire metering system. The system should be verified for voltage failure and data link transmission failure.
Verification of pulse alarm for the turbine meters should be carried out and alarm should be activated if deviation occurs between the two pulse trains.
Verification of the performance of the electronic equipment should be carried out and should be in accordance with the climatic and mechanical environment that the equipment will be subjected to.
When using maintenance systems based on integrated operations, then it should be ensured that the supervision of the fiscal parameters and scheduled maintenan ce should be performed in a systematic and controlled manner.
To ensure continuous quality in the measurements, it should at all times be relevant technical support personnel available for interpretation, analysis and eventual correction of error modes.
When two instruments do the same measurement with the same quality, then one of the instruments should be identified as in use and the other should then have a monitoring/back up function. A change between the two instruments should just take place when the instrument in service fails.
Calibration of provers is dealt with in the comments re. Section 20. If the meter prover volume deviates by more than ± 0.04% compared with the volume at the last calibration, a troubleshooting procedure should be carried out in order to discover the reason for the deviation.
A lower calibration frequency can be used for in-line provers, based on a technical assessment of the stability of previous calibrations (better than ± 0.02% of the average volume for three consecutive), considered in a cost-benefit perspective.
On the basis of the assessment in the paragraph above, the existing in-line prover calibration interval may be increased to double the existing interval. A new assessment can be made when experience has been gathered from this calibration frequency.
If an assessment of the calibration results from multiple in-line provers indicates systematic deviations, the Norwegian Petroleum Directorate should be consulted concerning the issue of whether to implement the calibration result.
For measurement systems used with low density fluids, as condensate and LPG, the limiting values given in this remark can be increased, ref. re. Section 8.
Recognised standard for monitoring of turbine meter K-factors is API MPMS ch.13.
With regard to flare gas meters the zero point check should be carried out regularly with an external unit. Depending on the meter manufacturer, it may be relevant to perform other checks to verify the meter‟s quality.
Condition Based Monitoring (CBM)” should be used for multi-beam ultrasonic meters. Examples of parameters that may be included in a con dition based monitoring system:
The monitoring systems will vary somewhat between the different suppliers.
Deviation limits for the various parameters should be determined before start-up or as soon as poss ible thereafter.
Recalibration should be carried out if the meter has a poor maintenance history.
When petroleum products are loaded into tankers in small batches it may be expedient to utilise K-factor established during recirculation.
With regard to requirements to repeatability and linearity for calibration of flow meters, reference is made to Section 8 of these regulations.
Inspection and cleaning of the meter tube should if necessary be carried out when the meter tube sections are disassembled.
The operating requirements for the turbine meter deviate from the design criteria given in Section 8 and are specified in Section 25.
When monitoring functions are in operation, condition based main tenance may be used to extend calibration intervals.
Instruments used for calibration should be kept separated from other instruments.
The interval between calibrations may be increased if stability of the measuring equipment is documented.
In the case of condition based maintenance a number of transmitters for each metering station parameter should be calibrated at least once annually in order to ensure traceability. A comparison of these with corresponding metering station transmitters should be carried out in order to ensure traceability.
During preparation of control limits for the individual components of online gas chromatographs (benchmark tests), the start point should be the GC uncertainty requirement and divide by the square root of the number of components. Deviations for the individual component and for combined values should always be checked against normalized values to limit the effect of weather conditions on the figures. Deviations for each individual component should not entail a deviation exceeding 0.1% of the calorific value or standard density.
With regard to facilities operated with regular calibration and correction, the transition to the benchmark principle for GC should be carried out as soon as practically feas ible, for example in connection with equipment upgrades.
Recognised standard for uncertainty of traceable reference gases is given in NORSOK I-104.
Alarms from the metering system should after s tart up be reviewed in a systematic way, to reduce numbers and establish an effective interface against other control room equipment.
Calculation requirements should be verified by using an independent system (PC).
The first and second paragraphs of this section apply to all measuring referred to in these regulations. Documentation as mentioned in the first paragraph of this section will include specifications, calculations and drawings relating to the metering system, as well as operating procedures and other relevant documentation.
The general rule referred to in the Petroleum Act Section 10-4 with regard to material and information entails that documentation relating to fiscal metering as referred to in these regulations should be available in Norway irrespective of where the operational organisation is located. This does not entail any prohibition against storing documentation abroad, as long as it can be made available to the Norwegian Petroleum Directorate within a reasonable length of time. In some cases, e.g. during supervision of metering stations located abroad, the most practical solution will be that the documentation is made available to the Norwegian Petroleum Directorate on location. Operational organisations located outside Norway should have the documentation available at the place of operation and available to the Norwegian Petroleum Directorate on request.
If any of the equipment components drift inside their variation range and this is detected by routine calibration, this will not constitute basis for correction.
A correction should, however, not be implemented if the cost of the correction work is higher than the value of the wrongly measured quantity that should be corrected for.
Standard forms for reporting of CO2 tax are included as Appendix 1 and 2 to these regulations. The operator may, if practical, report diesel consumption to the NPD according to the same principle as for reporting to Klif for the Climate Quota Regulations.
The cargo claims procedures should be drawn up in such a way that when oil is sold in tanker loads from an offshore loading buoy, the correction limit should be the one which is internationally accepted for trade in oil, 0.5%. A correction should only be implementable when both the ship‟s figures in port and the terminal‟s figures deviate from the figures of the metering station by 0.5% or more. Furthermore, failure in connection with the official measuring equipment should be demonstrated before corrections may be carried out. On the Norwegian part of the continental shelf, 0.3% has often been used for crude oil cargoes from the petroleum activities.
The Ministry of Petroleum and Energy is the appeal body in relation to decisions made by the Norwegian Petroleum Directorate pursuant to these regulations.
With regard to the basis for and extent of the CO2 tax, the Ministry of Finance is the appeal body.
Any appeal against a decision should be forwarded through the Norwegian Petroleum Directorate, cf. Chapter VI of the Public Administration Act.
Exemption constitutes a decision by the authorities, normally as a result of an application, to accept a deviation from a regulation requirement. Deviation in this connection denotes a discrepancy between selected solutions and regulation requirements.
Application for exemption should be filed if one intends to apply a solution different from the one referred to by a specific regulation requirement, or a solution which does not meet the level required by the regulations.
Applications for exemption, if any, should as a rule contain:
a) a l ist of the provisions from which exemption is sought;
b) an account of the particular reasons for why an exemption is necessary or reasonable;
c) an account of the internal procedure of the enterprise in dealing with the exemption issue;
d) an account of t he deviation and its planned duration;
e) an account of measures, if any, to compensate for the deviation, in full or in part;
f) an account of measures, if any, to correct for the deviation, if the deviation is of a temporary nature.
In a material sense these regulations mainly constitute a continuation of previous legislation. The regulations do not represent any increased stringency which necessitates exemptions from entry into force or transitional arrangements.
Last translated 2 July 2012
English version is not necessarily updated according to recent changes at any time.