Introduction This standard is designed to provide production operations personnel with detail information concerning Fieldwood's Measurement Standard Operating Procedures. Included are the following: Meter Proving Measurement Principles S&W, Gravity & Temperature Orifice Plate Holder & Calibration Custody Transfer Measurement Meters & Meter Proving Sampling Procedures Witnessing Responsibilities Meter Proving & Calibration The purpose of Meter Proving/Meter Calibration is to obtain accurate results so Fieldwood Energy will receive appropriate income for the measured volumes and report correct data/volumes on the morning reports (i.e. Accurate Measurement). The reason meters are proven and calibrated is: So all parties are treated fairly It's a tool for troubleshooting To report exceptions on Morning Reports Uniformity in Measurement Equipment and Procedures Fixed Methods for Problem Solving Repeatable Procedures and Practices Data Retention and Recordkeeping Here are the data retention and recordkeeping requirements: Well Test Documentation = 2 Years on Platform Gas & Oil Meter Proving & Run Tickets = 2 Years on Platform Chart and/or EFM (Electronic Flow Measurement) Data = 2 Years on Platform Note: All inquiries by BSEE for production audit information should be directed to Safety Environmental and Compliance Department. Page I-2-1
Gas Measurement Daily gas volumes will be obtained from the Pipeline Gas Sales Meter and note readings on the morning report. All gas FMP points will have a gas sample procured and a gas analysis performed every six (6) months. Copies of the gas analysis will be kept in the gas measurement file on the platform for 2 years. The check meter readings are for backup purposes in the event the pipeline meter(s) fail. Ensure Fieldwood's check meter recording devices have the same parameters as the gas sales meters (i.e. plate size, meter run I D, calculation methods and analytical data). Ideal Beta (β) range is.20 to.60 for Daniels Senior Fittings Beta Ratio = d / D d = Orifice Plate Diameter in Inches (ID) D = Meter Tube Diameter in Inches (ID of meter tube) Below is an example of a meter tube that is oversized and needs to be changed: 3 inches of differential on a 10 tube means we are operating out of the acceptable differential of 10 to 80 inches for EGM and 20 to 80 for Charts. Installing a 1 plate brings the (β) to.10, but will not raise the differential up enough to meet the differential range. Meter tube needs to be downsized. The minimum differential for gas measurement is 20 Inches for charts. (20% of the flow range is recommended) The minimum differential when using smart transmitters EFM (Electronic Flow Measurement) is 10 Inches. Typical Measurement Errors The following table will describe conditions that can cause gas measurement errors and result in loss of income or over measurement. Page I-2-2
Chart Recorders and Charts When using a chart recorder, the Red pin should read between 20 inches and 80 inches of differential. (Maintain beta ratio of.20 to.60 β) The following pertinent data must be on each chart: Location (Vessel ID) Tube ID Plate Size Average Temperature (if applicable) Date and Time Chart Installed Initialed or Signed by Person Changing Chart Charts must be zeroed as follows: 24 Hour Charts = Zeroed Every Chart Change 7 Day Charts = Zero Verified Daily Note any unusual conditions on the chart and store charts properly until they are mailed. Chart Measurement Differential Minimum 20% of operating range 20% of 100 Inches = 20 Inches (20% of 250 Inches - 45 Inches) See Percent (5) of Error in Calibrations Chart below: Example Error: A 1/2 (4.5) error in 5 = 11.11% At 5,000 MCF/day 11.11%= 555.5 MCF/day X 365 X $ 4.30 MCF = $ 871,857/year Chart recorders may be used as custody/royalty meters with a departure from the regulations and/or agreement. The charts are to be integrated and volume statements generated as an audit trail with these statements to be sent to BSEE for royalty purposes. Page I-2-3
Typical EGM Installation Pictured is a typical EGM installation: These are the minimum parameters that should be programmed into an EGM meter: Plate Size Temperature Pressure Meter Run ID Calculation Methods Analytical Data (i.e. CO2, Nitrogen, Specific Gravity) Sediment & Water S & W tubes need to be certified/verified. Order certified tubes with certifications attached and keep certifications on file on the platform. Some S&W tubes have been found to be as much as 5 to 7 % out of calibration. Example an Error Could Cost: 0.50% - 0.025 = 0.475% 60,000/day x 0.50% = 300 barrels 60,000/day x 0.475% = 285 barrels 300 minus 285 = 15 bbls/day x 365 days/year x $100.00/bbl.= $ 547,500 Centrifugal Recommendations: Read tubes to the nearest 1/10 of 1 % Each sample should shakeout (ground-out) for a period of 5 minutes at 1500 rpm Misreading a centrifugal test by 1/10 of 1% from a full 1,000 barrel tank is equal to 1,000 x.001 (1 barrel) Page I-2-4
Gravity Oil Surface must be within ½ inch of the top of the thief before taking reading for gravity. This rise of liquid along the stem above the level surface is called the MENISCUS and the reading should be taken at its top. Subtract from this reading 0.1 to obtain the Indicated Gravity reading. In determining the Gravity Temperature with draw the hydrometer from the liquid only high enough to expose the thermometer scale at the bottom. Temperature Temperature is very important, for example: 1 degree Fahrenheit for a typical crude = 0.05% (1.0005) CTL correction factor. Note: CTL is: Correction for the effect of temperature on a liquid Impact to Fieldwood Income Example: 60,000 bbls/day = 10,950/ bbls/year 10,950 X $ 100/bbl = $ 1,095,000 Orifice Plate Holder Assembly There are three types of orifice plate holder assemblies in general use. Each of these assemblies is used for a specific purpose, however, they all provide the same basic features: To hold the plate centered in the line of flow. To seal around the plate so that all the gas flow passes through the plate opening. To provide taps for the upstream and downstream pressure sensing lines. To provide for the removal, reinstallation or replacement of the orifice plate. Inspection Frequency: Senior Orifice Fitting = Every Meter Calibration Orifice Junior & Simplex Fitting = Every Meter Calibration (If Possible) Flange Type Fitting = Annually (If Possible) Orifice Plates The Orifice Plate is the most important part of the primary element. This is the heart of the orifice measurement system and there are two types of orifice plates: 1. The Universal Type plate is used in the junior and senior type orifice assemblies. 2. The Paddle Type is used in the orifice flange type assemblies. Page I-2-5
REMEMBER, the sharp edge of the orifice must always be facing upstream and the beveled edge must always be facing downstream. NEVER, hang the orifice on metal pegs, nails or other devices as this will destroy the edge of the orifice. Plates should be sized to maintain differential readings between 10-100 % where EGM devices are used. Orifice Plate Inspection and Storage Plates should be taken out of the fitting and visual inspected as often as possible. Inspection: Inspect for dirty, bowed, bent, nicked,eroded or backward installation which may produce large metering errors. Plate seal rings should be part of every inspection. Anytime it is suspected that a plate has been damaged, it should be inspected immediately. Damaged plates should be discarded. Storage: Plates should be stored in such a manner to protect the surface and edge of the plate from damage. Plates should be stored in an orifice plate box and out of the weather. Orifice Beta Ratios As mentioned earlier Beta Ratio = d / D d = Orifice Plate Diameter in Inches (ID) D = Meter Tube Diameter in Inches (ID of meter tube) Maintain beta ratios from.20 to.60 Report all plate sizes to 3 Decimal places (Example.875) Orifice Meter Calibration Orifice meter measuring elements include; differential pressure transmitters, temperature transmitters, static pressure units and thermal systems electronic (EGM) chart recorders pneumatic. Page I-2-6
Prior to testing differential pressure units or transmitters... all leaks on tubing fittings, valves, etc. should be repaired. Orifice meter measuring elements should be verified at flowing conditions. Differential and Pressure elements should be verified at specified test points (i.e. 6 up 5 down) Calibration should occur if element is not within Company or contract tolerances Example: Differential.25 Inches Temperature.5 Degrees) On EGM s, markers (platesize, temperature, differential, static and analysis data) should be logged into the EGM as found and as left: Example: Found 20 Inch Differential Left 22 Inches Example: Pressure found 750 psi Left 775 psi Plate changes should be logged into EGM s using the manufacturer s specified procedure. NOTE: Fieldwood personnel are "NOT" allowed to change an orifice plate in a Pipeline Gas Sales Meter Run. Checking Temperature Transmitters When checking a temperature transmitter, the calibration report will show the Temperature of the Standard used to test the online temperature device, the as found temperature and the as left temperature. The as left temperature will not exceed 0.5 Degrees Fahrenheit of the test standard. Example: Test Standard = 80.7 As found = 80.0 As left = 80.3 Ensuring this test standard will minimize or eliminate INCs (Incidents of Non-Compliance) Custody Transfer Liquid Measurement Custody Transfer Liquid Measurement is the point which is acceptable to all parties involved in measurement agreement. (LACT Units, Shore Tanks, Barge Loading Facilities). API Standards are utilized to assure all transactions are correct and all parties involved are treated fairly. Parameters are normally 0.05% repeatability for proof runs and 0.25% for meter factors. Page I-2-7
Some agreements may have more stringent guidelines, 0.02% and 0.20% respectively. EMPCO (EXXONMOBIL PIPELINE COMPANY). Allocation Measurement Allocation Measurement is individual measurements to determine what fraction of the total production from a system is attributable to an individual lease. Quality and Quantity must be representative of the lease and provide a sound basis for distributing production and income through contracts and agreements for different companies and interests, without requiring Custody Transfer procedures. Meter Proving The table below shows meter proving requirements: Meter Proving Volume Frequency Production Meters (LACT) Calibrated monthly not to exceed 42 days BSEE requirements Allocation Sales Meter To Pipeline >50 BPD Monthly Allocation Sales Meters to Pipeline <50 BPD Quarterly Master Meters (prover) used to prove Custody Transfer meters All As required by BSEE 30 CFR Custody Meters reproducibility factor from previous proving BSEE requirements 30 CFR.25% Consecutive proving runs within BSEE requirements 30 CFR.0005 Allocation metering repeatability factor from previous proving BSEE requirements 30 CFR 2 to 7 % Under Volume Calibrated monthly not to exceed 42 days Typical LACT Unit This drawing shows components for a typical LACT unit: Page I-2-8
Prover Water Draw Calibration: Water draw provers are calibrated using NIST Certified Test Measures. Always ask the water draw technician for a copy of the calibration certificates before starting the water draw procedure. The Bi Directional prover is calibrated and the corresponding volume is calculated using the forward and reverse passes, or round trips. A minimum of two fast flow rates and one slow flow rate is used to determine the prover volume. The allowable tolerance between calibration runs is 0.02% Calibration Frequencies: Water draw calibration shall be conducted per API guidelines that include but not limited to: The provers calibrated every 5 years. When a Sphere detector switch has been repaired or changed. Upon inspection the internal coating is deteriorated. Additionally, prover spheres should be sized 2-3 % over the pipe ID of the prover calibrated section. Morning Reports See example below (red section) when applying correction factors: Page I-2-9
Typical Allocation Meter Skids Pictured above right is a typical dual allocation meter skid: Pictured below right is a typical single allocation meter with API sample loop: Turbine Typical Turbine Meter Components (Drawing Right) Two factors that affect turbine meter accuracy are the velocity and viscosity of the flowing stream. Where two phase flow occurs, gas and hydrocarbon liquids, the turbine will over measure. K-Factors for Fieldwood turbine meters are normally stated as Pulses per barrel Typical Turbine Meter Installation With Flow Conditioning Without a flow conditioning 10 upstream diameters and 5 downstream diameters Volumetric Shrinkage Liquid flowing at separator conditions, the pressure at which a liquid and its vapor are in equilibrium at a given temperature; contains light hydrocarbons, which at atmospheric conditions will flash. Example: Separator volume 10,000 bbls x Shrinkage factor of.9800 = 9800 BBLS Oil and condensate are sold at stock tank conditions. The Shrink Factor (SF) corrects metered fluid volumes (Theoretical volumes) at equilibrium to stock tank conditions. When procuring a spot liquid hydrocarbon sample to determine a Shrink Factor (SF), the slower the sampling rate, the more accurate the analytical results will be. A liquid sample must be representative of the product in the line and should be gas only. The sample should be taken by using a sample probe, if possible. (center third of flowing stream) Page I-2-10
Sampling Natural Gas Procedures A gas sample must be representative of the product in the line and should be gas only. In order to obtain a representative and repeatable sample, proper procedures must be followed: 1. The gas sample must be taken from the top of a horizontal line. 2. The sample should be taken by using a sample probe, if possible. (center third of flowing stream) 3. The sample point should be located in a section of the line that always has a positive velocity, a minimum of turbulence, and the tap mounted on top of the pipe. 4. Samples should not be taken too close to obstructions such as control valves, orifice plates, elbows, tees, or other fittings. 5. The sample valve should be one that does not restrict flow 6. Use stainless steel cylinder bottles for pulling gas samples. Cylinders of at least 300 ccs should be used to ensure adequate sample volumes. 7. Check for leaks on sample cylinder. Leaks can cause gas contents to empty or cause the contents of the sample to change before it is analyzed. 8. Sample cylinders should be cleaned and evacuated before being used again. This will prevent the contamination of the new sample due to gas left from the previous sample. 9. Sample cylinders should be transported by conforming to Fieldwood's Hazardous aterials Shipping located on the SEMS Portal. It is also required that sample cylinders be in a case or box that will protect the valves. For additional information on spot sampling refer to the Fieldwood SOP - Natural Gas Sample Procurement- GAS M 1.0 Sampling Manifold and Purge Cycles Review example of typical gas sampling cycles and manifold hookup for purge/empty method. Page I-2-11
Measurement Witnessing Responsibilities The Fieldwood PIC must personally verify all tests, all inputs into flow computers, all temperatures and pressures. If the proving reports are computer generated, a Fieldwood PIC on the platform "MUST" perform QA/QC (Quality Assurance / Quality Control) on the reports to validate the calculations, using the current meter proving program. All volume statements "MUST" be verified to assure proper analyses and calculations of the volumes allocated are correct. All test equipment, prover, temperature, pressure, and any device used in the calibration procedures "MUST" have a certification traceable to NIST (National Institute of Standards and Technology) at the time of the proving process. NO ASSUMPTIONS... VERIFY, VERIFY, VERIFY When a witness signs reports for Pipeline and third party providers, it is a legal document stating you have "PERSONALLY witnessed all procedures and the results are acceptable". Gas Meter Calibration Witnessing Minimum responsibilities to witness during a technician gas meter calibration are as follows: 1. You "MUST" verify the technician has current certifications for all test equipment to be used "PRIOR" to beginning the proving process. Test equipment must be Certified Annually to NIST (National Institute of Standards and Technology) standards. Test equipment must be at least Two (2) Times the Accuracy of the equipment being tested. 2. Differential and Static calibration points to be at least 6 up and 5 down. 3. The orifice plate and seal ring must be pulled and examined for damage or deficiencies such as: Water Marks, Nicks, Flatness, Sharpness, Smoothness, etc. Reinstalled with the bevel facing the downstream section of the meter tube 4. The seal ring must be examined for Cuts, Pinch Points, etc. Any abnormalities must be noted on the report. NOTE: All four of the above steps must be performed/verified for calibration to be considered legitimate. Page I-2-12
Test Equipment Below are samples of test equipment requiring certifications to be verified: Meter Swap and Proving The Fieldwood PIC is required to be: Present On-Site, At the Meter During the Following Activities. During Sales Meter Proving During Allocation Meter Swap or Proving During Production & Test Meter Swap or Proving Witnessing Lact Units Custody Transfer Proving Custody Transfer proving should be performed at normal operating conditions. Assure all valves associated with the prover and the meter have means of checking seal integrity (Proving Manifold Block and Bleed, Prover Four Way Diverter Valve). A leaking Proving Manifold block valve will result in a "LOW" meter factor. Verify API gravity and Temperature of the FLOWING STREAM are accurately taken and recorded. Flow rate must be within the operating range of the meter. Some pipelines allow the flow rate to be within 10% of the normal operating flow rate. 5 (Five) consecutive out of 6 (Six) proof runs to be made with repeatability of 0.0005. (.05%). The average of the 5 out of 6 consecutive runs should be used to calculate the meter factor. Deviation from the above is acceptable if the pipeline company s procedures are different. These procedures must be understood by the witness and followed. Page I-2-13
Verify all calculations used to determine the meter factor are properly recorded and the meter factor is within tolerance. Meter factor deviation should not exceed.0025 (.25%), since the last proving. The pipelines we sell our oil to have guidelines they follow for meter factor deviation from the initial proving. Deviation differencies range from 0.50% to 0.075%. Fieldwood witness will sign and receive a copy of the proving report to document in the Meter File. Do not sign report if you differ with anything about the proving. Notify the supervisor immediately. Page I-2-14