Natural Resources Oil, Gas & Chemicals
Services Level 2 Training Handbook
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Disclaimer
Copyright
This manual is designed and written to provide information about the subject matter involved. SGS makes no warranty, express or implied that it is fit for any purpose; or to the absolute sufficiency of the material presented.
This manual has been written for the exclusive use of the employees of SGS Natural Resource Oil, Gas, & Chemicals Services. Certain procedures contained in the manual may require or assume expertise or experience. Caution is therefore advised and SGS assumes no responsibility for any use by unauthorised or untrained persons. This manual has been compiled from publicly available material, appropriate industry standards, government publications and proprietary SGS data and documentation. The SGS generated portions of this manual have been produced as copyright material and SGS reserves all rights under all applicable copyright laws both national and international. No SGS generated portion of this manual may be reproduced, in any form, without the express written permission of SGS SA. Use of any portion of this manual is subject to the conditions of the disclaimers.
SGS assumes no responsibility for any inaccuracies in reproduction or errors in
interpretation of any authority. SGS reserves the right to modify or amend this manual, without prior notification, but SGS assumes no responsibility to update or issue corrections.
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Contents
2.7.6 Summary
19
2.4.1 Portable Electronic Thermometer
15
Introduction
7
2.8 Stratification
19
2.4.2 Liquid-in-Glass Thermometer
15
Our History
8
2.8.1 What is Stratification?
19
2.4.3 Dynamic Temperature Determination
Our Purpose
8
15
2.8.2 Problems caused by Stratification
Our Value to Society
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19
2.4.4 Automatic Temperature Systems
16
Petroleum Measurement Standards
8
2.8.3 Sampling
19
2.5 Sampling
16
A Word on Compliance
9
2.5.1 Manual Tank Sampling
16
Vessel Inspection and Sampling 22
Independent Inspection and the Role of the Inspector
10
2.5.2 Automatic Sampling
16
3.1 Before Transfer
23
2.6 Meters
17
3.1.1 Vessel Experience Factor (VEF)
23
1.1 Independent Inspection
11
2.7 The Use of Automatic Shore Tank Gauges for Custody Transfer
17
1.2 Independence
11
3.1.2 Draft, Trim, & List
23
1.3 The Role of the Inspector
11
2.7.1 Custody Transfer Usage
17
3.1.3 Remaining Ballast
23
Shore Inspection and Sampling 13
2..7.2 Factory Calibration Accuracy
17
3.1.4 Vessel Lines and Tanks
23
2.1 General
14
3.1.5 On-board Quantity (OBQ) Measurement 3.1.6 Small Volume On-board Quantity (OBQ) Sampling
2.7.3 Error Caused by Installation and Operational Conditions
18
24
2.2 Shore Lines and Tanks
14
2.3 Shore Tank Measurement
14
2.7.4 Initial and Subsequent Verification
18
24
2.4 Temperature Determination
15
2.7.5 Precautions
18
3
3.1.7 On-board Quantity (OBQ) Temperatures
3.4.2 Vessel Pipeline
27
5.1.1 What are Records?
34
24
3.4.3 Conclusion
27
5.1.2 Prove it or Lose it
34
3.1.8 Slop Tanks
24
5.1.3 Primary Data
34
Calibration
29
3.1.9 Sea Valves
24
5.1.4 Non-SGS Documents and Data
35
4.1 Introduction
30
3.1.10 Bunker Inspection
24
5.1.5 Signing Documents for Other Parties 35
4.1.1 Calibration vs. Verification
30
3.2 During Transfer
24
5.1.6 Summary on Signing Non-SGS Documents
4.1.2 Records
30
3.2.1 Communications
24
37
4.1.3 Interval or Schedule
30
3.2.2 Line Samples
25
Dynamic Measurement
38
4.1.4 Traceability
30
3.2.3 First Foot Samples
25
6.1 Introduction
39
4.1.5 Documentation
30
3.3 After Transfer
25
6.2 Displacement Meter
39
4.2 Equipment Requirements
30
3.3.1 Vessel Lines
25
6.3 Turbine Meter
40
4.2.1 Liquid-in-Glass Thermometers
31
3.3.2 Vessel Measurements
25
6.4 Coriolis Meter
41
4.2.2 Portable Electronic Thermometers (PET)
3.3.3 Free Water Measurement
25
31
6.4.1 Coriolis Effect
41
3.3.4 Vessel Temperature
25
4.2.2.1 Annual Calibration
31
6.4.2 Mass Flow Meters
41
3.3.5 Vessel Sampling
26
4.2.2.2 Monthly Verification
31
6.4.3 System Description
42
3.3.6 Sample Handling
26
4.2.2.3 Daily (Prior to Use) Verification
31
Cargo Quantity Differences
43
3.3.7 Sea Valves
26
4.2.3 Gauge Tapes, Bobs, & Rulers
32
7.1 Introduction
44
3.3.8 Volume Calculations
26
4.3 Conclusion
32
7.1.1 Apparent Loss/Gain
44
3.4 Pipeline Contents and First-Foot Samples
Documentation
33
7.1.2 Physical Loss/Gain
45
27
5.1 Document Management
34
3.4.1 Contract Review/Order Confirmation
27
4
7.2 Meters
45
7.6.10.4 Volume Correction Factors (VCF)
53
8.1.13 Tank Cleaning
59
7.3 Static Shore Tank Measurements
46
7.6.10.5 Volumetric Shrinkage
53
8.1.14 Cleaning Machines
59
7.4 Floating Roof Tanks
46
7.6.10.6 Letter of Protest / Notice of Apparent Discrepancy
8.1.15 Precleaning
59
54
7.5 Determination of Line Fullness
47
8.1.16 Cleaning
60
7.6.10.7 Lightering
54
7.6 Vessel Measurements
48
8.1.17 Cleaning Categories
60
7.6.10.8 Measurement Uncertainties and Errors
7.6.1 Vessel Tank Capacity Tables
48
8.1.17.1 Animal and Vegetable Oils
60
54
7.6.2 Transit Differences
49
8.1.17.2 Mineral Oils
60
Marine Vessel Particulars
55
7.6.3 Changes in Cargo Stowage
49
8.1.17.3 Petrochemicals and Solvents
60
8.1 Introduction
56
7.6.4 Cargo Diversion
49
8.2 Conclusion
61
8.1.1 Direct Main piping System
56
7.6.5 OBQ and ROB
49
8.3 Requests for Tank Cleaning Guidance 61
8.1.2 Ring Main Piping System
56
7.6.6 Undetected ROB
50
Sample Plans
63
8.1.3 Other Piping System
57
7.6.7 Crude Oil Washing
50
9.1 Sample Plans
64
8.1.4 Drop Lines
57
7.6.8 Slops
51
Automatic Sampling of Petroleum and Petroleum Products
8.1.5 Centrifugal Pumps
57
65
7.6.9 Water Determination
51
8.1.6 Positive Displacement Pumps
57
7.6.9.1 Free Water
51
10.1 Introduction
66
8.1.7 Deep Well / Submersible Pumps
57
7.6.9.2 Sediment and Water (S&W)
52
10.2 Automatic Sampling
66
8.1.8 Cargo Separation
58
7.6.9.3 Water Balance
52
10.3 Performance Criteria
67
8.1.9 Sea Suction and Overboard Discharge Valves
7.6.10 Additional Factors
52
10.4 Performance Data
67
58
7.6.10.1 Temperature
52
8.1.10 Safety
58
7.6.10.2 Evaporation Losses
53
8.1.11 Procedures
58
7.6.10.3 Density (degrees API/kg/m3)
53
8.1.12 Isolation of Inert Gas Lines on Marine Vessels
58
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14.1 Introduction
84
15.1.4.1 Letters of Protest (vessel/barge related)
Sampling for Vapour Pressure and H2S Analysis
90
70
14.2 Primary and Alternate Methods
84
15.1.4.2 Letters of Protest (terminal related) 91
11.1 Sampling for Vapour Pressure Analysis 71
14.2.1 Measurement Data
84
15.1.4.3 Notice of Apparent Discrepancy
92
11.1.1 Equipment
71
14.2.2 Data Gathering
84
15.2 Conclusion
92
11.1.2 Types of Samples
71
14.2.3 Primary Method
84
Recording of Times
93
11.1.3 Closed System Sampling
71
14.2.3.1 Primary Method – Rejected Voyages 14.2.3.2 Primary Method - Calculation of a VEF
85
16.1 Introduction
94
11.1.4 Sample Handling
72
16.1.1 Demurrage and Charter Party Compliance
11.2 Sampling for Hydrogen Sulphide (H2S) Analysis
85
94
72
14.2.4 Alternate Method
85
16.1.2 Cargo Price
94
Floating Roof Adjustment & Correction
14.2.4.1 Alternate Method - Rejected Voyages 14.2.4.2 Alternate Method - Calculation of a VEF
86
16.1.3 Payment of Services
94
75
16.1.4 Internal Pricing Calculation
94
12.1 Floating Roof Adjustment & Correction 76
16.2 Recording Times
95
12.1.1 Floating Roof Adjustment (FRA)
76
86
16.3 Conclusion
96
12.1.2 Floating Roof Correction (FRC)
77
14.3 Load and Discharge VEF
86
Communication
97
Correction for Temperature of the Tank Shell 13.1 Correction for Temperature of the Tank Shell
Letters of Protest
88
79
17.1 Client Communication
98
15.1 Introduction
89
17.1.1 Real Time Communication
98
15.1.1 Protecting the Client’s Interests
89
80
Glossary & Conversions
99
15.1.2 Acknowledgement
89
13.1.1 Calculation of CTSh
80
15.1.3 Title of the Document
89
13.1.2 Application of CTSh
82
15.1.4 When to Protest
90
Vessel Experience Factor (VEF)
83
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Introduction
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Today, our focus is on innovative ways to deliver business benefits. This enables us to help our customers improve quality, safety, efficiency, productivity and speed to market while reducing risk and building trust in sustainable operations. Petroleum Measurement Standards Strict adherence to the agreed upon measurement standards, as specified in the sales contract, is the principal way in which we demonstrate our independence, impartiality and quality. In the petroleum and petrochemical industry, the technical procedures that guide all measurement activities have been written into standards by a consensus of experts with years of measurement, sampling, tank calibration and data management experience. In the US, the American Petroleum Institute (API) sponsors the writing of the Manual of Petroleum Measurement Standards . Most members of API standards writing working groups are from refining companies, pipeline companies, independent inspection companies, and equipment suppliers.
Our History
Our Value to Society
We are SGS – the world’s leading testing, inspection and certification company. We are recognized as the global benchmark for quality and integrity. Our 96,000 employees operate a network of 2,600 offices and laboratories, working together to enable a better, safer and more interconnected world.
Through our integrated leadership approach, we strive to become an increasingly sustainable company, maximizing the positive impact we have. We add more than just financial value to society. All our stakeholders (employees and suppliers, investors, customers, governments and industries, consumers, and communities and society) are the ultimate beneficiaries. In order to measure our success, we are developing an innovative impact valuation model to quantify our value to society. Established in 1878, SGS transformed grain trading in Europe by offering innovative agricultural inspection services. From those early beginnings, we steadily grew and scope as our agricultural inspection services spread around the world. During the mid-20th century, we began to diversify and started offering inspection, testing and verification services across a variety of sectors, including industrial, minerals, oil, gas, and chemicals. In 1981, SGS was listed on the Swiss Stock Exchange and forged an unrivaled reputation as the industry leader in finding solutions to the complex challenges faced every day by organizations.
Our Purpose
Our purpose is to enable a better, safer and more interconnected world.
How do we do this?
We enable a better world by helping businesses everywhere to work efficiently, to deliver with quality, and to trade with integrity and trust. We enable a safer world by ensuring that your car is safe to drive, that the environment you work in is secure and clean, and that the food you eat is safe. We enable a more interconnected world by, for example, helping new technology to reach consumers quickly and affordably, by ensuring the security of IT systems and data, and by using AI and the Internet of Things to help develop smart cities.
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▪ Do not engage into any transaction which does not have a genuine, legitimate business purpose. ▪ Ask yourself whether any contemplated transaction or business practice would withstand the scrutiny of the public eye if exposed. ▪ Do not do anything which could require you to be untruthful.
A Word on Compliance as
Integrity is at the core of our business; it is the common thread through all of our activities. The SGS Code of Integrity defines the main principles of professional integrity for the SGS Group and is an expression of the values that are shared throughout our organization, our businesses and our affiliates. These rules apply to all employees of the SGS Group. Our joint venture partners, agents, intermediaries, consultants and subcontractors are also required to comply with them. It is the responsibility of all of us, at all levels of our organisation, to comply with, and live by our Code. No deviation can or will be tolerated and no employee will suffer any adverse consequence for having complied or for having reported suspected violations. Our Code of Integrity and Professional Conduct has been approved by our Board of Directors and the Operations Council. Its rules are fairly simple. However, if you have any difficulty in a particular situation, you should apply the following common- sense principles:
▪ Seek advice when in doubt.
Reports on suspected violations of the Code can be submitted, or advice obtained by calling the Integrity Helpline or by filing a written report online or sending it by fax or mail to the Chief Compliance Officer. See Integrity at SGS for further details about contacting the hotline. Parties other than SGS employees may utilise the contact information contained on our website as they deem appropriate.
▪ Do not do anything which you know or believe to be illegal or unethical.
▪ Do not use any Company property for your own benefit.
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1. Independent Inspection and the Role of the Inspector
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It is important for procedures and accuracy levels to remain consistent throughout the entire cargo movement; bearing in mind that load and discharge facilities are frequently in different countries.
One of the more difficult aspects of the job of ‘Operations Supervision’ is that of managing disputes between clients. Typically, these disputes fall into areas that are commercial in nature and not addressed by any of the internationally recognized standards that we work to. In these situations, it is important for us not to fall into the trap of trying to become the arbitrator to the dispute. Commercial disputes must be resolved by the commercial parties. It is important to keep in mind that standards rarely address issues that are commercial in nature; in fact, the American Petroleum Institute [API] has a policy that it will not include anything in a standard that might impinge on its members (the oil companies) commercial rights.
1.1 Independent Inspection
Simply defined, independent inspection is, ‘the independent verification of quantity and/or quality
of a commercially traded product.’ This independent inspection helps to ensure:
1.2 Independence
• Contract compliance and improve the speed and efficiency of transactions • The safety and reliability of plant and equipment • The respect of delivery and production schedules Inspections are carried out using the three fundamental principles of:
A question that is often asked is,
‘how do we maintain independence while still being a commercial entity in our own right and getting paid for our services?’ The primary way in which we achieve this is by strict adherence to the agreed upon measurement standards, as specified in the sales contract or other commercial document controlling the transfer of goods. Most of the industries that we provide services to have produced technical procedures, usually called standards or norms, which guide our measurement and inspection activities. Most standards writing bodies are national in nature, however, the use of these standards frequently extends across borders and some, such as ASTM [American Society for Testing and Materials] are almost international in nature, although only ISO [International Organization for Standards] is truly international.
• Independence
• Impartiality
1.3 The Role of the Inspector
• Quality
The scope of work provided by independent inspection companies is determined by contractual agreement which typically takes the form of a nomination order. This scope of work usually includes some, or all, of the following:
This can only be achieved by the use of trained, competent and conscientious inspectors and technicians whose primary interest is the integrity of the cargo from point of shipment to the point of delivery. The activities of independent inspection services have always been determined by the needs of the industries that use their services.
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documents detailing the events of the job performed.
• Measuring, sampling and making required observations to verify that cargo transfer is carried out according to agreed standards. • Working closely with refineries, terminals, factories, warehouses, customs agents, shipping companies and other parties engaged in the custody transfer. • Performing calculations and completing reports according to standards and company requirements. • Protesting any actions or omissions of the terminal or vessel might lead to a discrepancy. • Promptly reporting findings to the parties who have requested services. • Examining all available information to determine if there are apparent discrepancies; and, if there are, taking a leading role in the systematic analysis of data to determine the likely cause of any variances. • Maintaining an ethical level of confidentiality between cargo trading partners. Independent inspectors must be qualified to perform field work safely and according to standards, apply correct calculations, interact professionally with others and produce accurate, complete and legible
The function of independent inspection and the role of the independent inspector is not always easy but is nevertheless very important in the facilitation and movement of trade goods, whether they are being moved around the corner or around the globe.
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2. Shore Inspection and Sampling
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• A Letter of Protest should be issued to any party failing to comply with recommended procedures. • Agreement should be reached on the method to be used to determine line fullness. • Determine which tanks will be transferred, the capacity of the tanks, the condition of the lines, the nature of the last three cargoes, and the method of cleaning the cargo tanks. • If ‘first foot’ samples are required, a decision on the tanks to be used for such samples and the quantity of cargo to be transferred for the sampling should be made. On multi grade transfers, it may be necessary to transfer the vessel’s tanks in a certain order to avoid contamination and to comply with vessel operational requirements. This should be discussed and the order by grade and/or product should be agreed upon before transfer operations begin.
loaded into one cargo compartment on the vessel, gauged, sampled, and tested. Determine the shoreline fill condition. Report the condition and method used. Additionally, record and report the total capacity of the shorelines used. Line fullness determination is covered in more detail in the NR OGC Level 1 Training Handbook. Although, ultimately, it is the terminal’s responsibility to ensure that all lines and valves are set in the correct position for the operation, when feasible, these settings can be confirmed by the Inspector, and where appropriate and instructed to do so, valves sealed. When non dedicated transfer lines are used, consider transfer sequences of products flowing through the lines in order to minimize the potential for contamination caused by line-content displacement. This determination should include an agreement on how the lines will be displaced and/or how the different product interfaces will be handled.
2.1 General
Before transfer begins, one or more meetings should be held among cargo inspectors, vessel representatives, and shore operational personnel who are involved in the transfer operation. At these meetings, key operational people are identified, responsibilities are defined, communication procedures are arranged, and everyone concerned reviews transfer procedures and plans to ensure a full understanding of all activities. • All parties should agree on the cargo’s quality specification and quantity. • An agreement should be reached on whether shore or ship personnel will terminate the transfer. • Check with the vessel’s representative for reports of any unusual events that may have occurred during the sea passage or at the previous port and that may require special vigilance during transfer. • The vessel’s representative should confirm the vessel’s ability to heat the cargo as instructed. • Check with shore personnel to agree on procedures for handling any special conditions that exist on shore that may adversely affect the transfer activity or measurements.
2.2 Shore Tanks and Lines
Determine the nature and quantities of material in the shorelines up to the vessel’s flange. When line contents are questionable or when the possibility of cargo contamination exists, line samples should be tested to verify compatibility with the cargo that will be loaded. Alternatively, shoreline contents may be
2.3 Shore Tank Measurement
Record the reference height from the tank capacity tables before gauges and water cuts are taken.
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Take opening gauges, temperatures, samples, and water measurements of each tank to be used in the transfer. Any significant difference between the observed reference height and the reference height shown on the tank capacity tables should be noted and questioned. Manual gauging requires obtaining either two identical consecutive gauge readings or three consecutive readings within an absolute range of 3 mm (1/8 inch), as per “API MPMS Chapter 3.1A - Standard Practice for the Manual Gauging of Petroleum and Petroleum Products”. If the first two readings are identical, this reading shall be reported to the nearest 1 mm if metric tapes are used or to the nearest 1/8 inch. if customary tapes are used. When three readings are taken, all three readings must be within the 3 mm (1/8 inch.) range and readings averaged to the nearest 1 mm for metric tapes and 1/8 inch. for customary tapes. If the tank contents are determined to be in motion and waiting for equilibrium is not possible, the tank measurements should be recorded, and all parties advised. If the situation cannot be resolved, a letter of protest should be issued. If available, record the automatic gauges for comparison purposes. In the case of tanks with floating roofs, gauging should be avoided while the roof is in the critical zone. The placement of roof legs in high or low position and the critical zone should be recorded.
preferred equipment for obtaining temperatures. The PET should have a calibrated range of accuracy that meets the desired temperature range of the material from which a temperature is to be taken. For example, a PET with a calibrated microchip accurate to 300 ° F/149 ° C is not acceptable for asphalt products that are stored at 350 ° F/177 ° C. (See API MPMS Chapter 7.2)
2.4 Temperature Determination
Temperature determination of cargoes in a storage tank is critical to the custody transfer process at the time of gauging, therefore, temperatures should be carefully taken. Heavy cargoes, heated cargoes, blended cargoes, and cargoes in unheated tanks in very cold weather may tend to have temperature stratification within each tank. When this situation is determined, extra temperature measurements should be taken. On high heat cargoes such as asphalt, it may be impossible to obtain representative temperatures with the use of a liquid-in-glass or portable electronic thermometer (PET); therefore, it may be necessary to use permanently installed temperature measuring devices. The use of a permanently installed measuring device should be noted in the report, along with when and how the device’s accuracy was verified. Caution: temperatures taken at or near heating elements may distort temperature profiles.
2.4.2 Liquid-in-Glass Thermometer
Liquid-in-glass thermometers must remain in the liquid long enough to reach the temperature of the liquid that is being measured (see API MPMS Chapter 7.1). Some liquids have the potential for temperature stratification to occur; in these scenarios, the time constraints involved in using a liquid-in-glass thermometer to profile a tank will usually necessitate the use of a PET. 2.4.3 Dynamic Temperature Measurement If a temperature probe in the shore pipeline is used to determine the temperature for the correction of metered quantity loaded or establish the product temperature in the shore pipeline that is then used in the quantification of a load, discharge, or transfer operation, verify and record the last two times that the probe was checked for accuracy.
2.4.1 Portable Electronic Thermometer
The portable electronic thermometer (PET) is the
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Each tank to be used in the transfer should be sampled in sufficient quantity to meet any analysis, retain, and distribution requirements. Sample containers must be clean and, in the case of petroleum products, should be flushed with product prior to drawing the sample. Sample containers must meet certain requirements (see API MPMS Chapter 8.1, 8.3, & 8.4). Containers that are used for transport and storage of samples must meet appropriate regulatory requirements. When non-homogeneous products are sampled, upper, middle and lower spot samples are usually obtained. If stratification is suspected, or upper, middle, and lower spot samples confirm significant stratification, samples at additional levels must be taken to ascertain an accurate profile of the tank contents. If only part of the product in a tank will be used for the transfer, zone (spot) samples may be taken from that part of the tank, in order to draw samples that will represent what is to be transferred out of the tank. All concerned parties should be notified if the material is deemed to be stratified (i.e., nonhomogeneous), and each party should agree on further actions before proceeding. Note whether the tank is equipped with mixers, a circulating system, or aerators, and the extent of mixing that was performed on the tank.
2.4.4 Automatic Temperature Systems Automatic temperature systems with accuracy and/or measurement tolerances consistent with “API MPMS Chapter 7.3” may be used for custody transfer by mutual agreement among the parties involved. If an automatic temperature system is used and the readings are not verified by manual measurements, record the last two times that the automatic system and the manual measurements were compared, and if any differences were noted. Record on the inspection report that automatic temperatures were used. 2.5 Sampling All samples should be promptly labelled after drawing the sample with the appropriate tank number and other pertinent data. 2.5.1 Manual Tank Sampling The objective of manual sampling is to obtain a small portion (spot sample) of material from a selected area within a container that is representative of the material in the area, or in the case of running or all-levels samples, a sample whose composition is representative of the total material in the tank. A series of spot samples may be combined to create a representative sample.
2.5.2 Automatic Sampling
Automatic sampling is the preferred method of sampling a cargo transfer. If an automatic sampling system is installed, it should meet the requirements and be operated in conformance with “API MPMS Chapter 8.2”. When instructed to confirm automatic sampler system performance that SGS do not own or operate, we are reliant on the terminal providing the required data. However, in these instances the SGS Inspector should observe and record the following: • Confirm that the automatic sampler receiver, via visual inspection, is both empty and clean prior to the commencement of the transfer. • On at least three occasions during the transfer, observe by non-intrusive means whether the automatic sampling system is operating. • Note the starting time of the automatic sampling system and the amount of oil in the sample receiver (weight or volume) when periodically observing the sampler in operation. • Record the actual weight of the sample from the scale (which can then be converted into volume) or volume of sample in the sample receiver (via a graduated sight glass) at the end of the sampling operation.
Any deficiencies should be noted and reported.
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• The ATG should have met the factory calibration tolerances specified in “API MPMS Chapter 3.1B”, prior to installation. • The ATG should meet the field verification tolerance for custody transfer as specified in “API MPMS Chapter 3.1B”, including the effects of installation methods and changes in operating conditions.
2.7 The Use of Automatic Shore Tank Gauges for Custody Transfer The use of automatic shore tank gauging systems for custody transfer measurement is becoming more frequent. The API MPMS standard that covers this is “Chapter 3.1B – Standard Practice for Level Measurement of Liquid Hydrocarbons in Stationary Tanks by Automatic Tank Gauging”. This standard separates the application of automatic tank gauges into two functions; inventory control and custody transfer. The use of automatic tank gauges [ATG] for custody transfer application requires a higher degree of accuracy than that of inventory control. There are numerous types of automatic gauging systems. While it requires little or no involvement from the inspector in obtaining a liquid level gauge there are several requirements that these units must comply with, if they are to be used for custody transfer, and verification of these requirements is part of the inspection process. These verification requirements are independent of the type of gauging system being used.
2.6 Meters
Terminal operators are responsible for the operation of their meters and meter provers. If meters are to be used for custody transfer, meters shall be proved in accordance with “API MPMS Chapters 4, 5, 12.2.4, and 12.2.5”, and this proving data should be provided to the Inspector. Prior to transfer, record the opening meter readings. Meter measurement tickets should be provided for each custody transfer and should include the information required in “API MPMS Chapter 12.2 - Calculation of Petroleum Quantities Using Dynamic Measurement Methods & Volumetric Correction Factors”. Terminal operators or inspectors who are aware of meter difficulties that could affect accuracy should report the problem immediately to all parties involved in the custody transfer. The incident and the resolution must be recorded in the inspection report. If manual and/or automatic shore tank measurements are taken, show a comparison with metered volumes. If volumes cannot be reconciled, recheck meter factors, shore tank measurements, and calculations. Report all results in the inspection report.
2.7.2 Factory Calibration Accuracy
Prior to installation, the reading of an ATG to be used for custody transfer should agree with a certified measurement instrument over the entire range of the ATG, traceable to a national standard, within ± 1 mm or ± 1/16-inch, and should be provided with a calibration correction table, with the exception of crude oil lease tank ATG’s used for custody transfer, which are required to agree within ± 3 mm or ± 1/8 inch. ATG’s for custody transfer applications installed prior to the effective date of the second edition of API MPMS Chapter 3.1B (2001), and crude oil lease tank ATG’s used for custody transfer which were installed prior to the effective date of the third edition of API MPMS Chapter 3.1B (2018) may not have factory calibration documentation.
2.7.1 Custody Transfer Usage
When used for custody transfer, an ATG must meet the following:
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The ATG is considered suitable for custody transfer if it meets the accuracy tolerance requirements. The subsequent (periodic) verification of an ATG used in custody transfer is recommended to be inspected and have its accuracy verified at a single level on a monthly schedule. The liquid level where the ATG is verified at should be randomly chosen and should be within normal opening and closing gauge readings of the tank. The procedure for performing this verification should be the same as required for the initial verification, as specified in “API MPMS Chapter 3.1B”, except that the accuracy is verified at a randomly chosen single level, within the normal operating range of the tank.
• The measurement tape and weight used for ATG setting or verification should be a reference master tape/weight (bob) combination certified by an accredited calibration laboratory and traceable to a national measurement standard, or a working tape/weight (bob) combination that has been recently compared with a certified reference tape and weight meeting the maximum permissible error limits specified in “API MPMS Chapter 3.1A”. • If we are hired to perform initial or monthly verification, then this must be performed according to the procedures in “API MPMS Chapter 3.1 B”. A note regarding the conversion of US customary units to metric. Although API standards are required to use metric units as primary and customary units as secondary the people drafting API standards tend to think in US customary units and convert to metric. The closest metric unit to 1/16-inch is 1mm, however the closet conversion to 3/16-inch is 4 mm.
2.7.3 Error Caused by Installation and Operational Conditions The error caused by installation and operational conditions of an ATG in custody transfer service, should not be more than ± 3 mm or ± 1/8 inch.
2.7.4 Initial and Subsequent Verification
API MPMS Chapter 3.1 B requires both initial and subsequent verifications to be performed to verify the accuracy of the ATG’s. The initial and subsequent tolerance for ATG’s in custody transfer service is no more than ± 4 mm or ± 3/16 inch, when compared to manual measurements, apart from crude oil lease tanks used for custody transfer, which is no more than 6 mm or ± 1/4 inch. The initial verification of an ATG requires measurement comparisons to be made with the liquid level within regions of the tank corresponding to upper, middle and lower thirds of the tank’s working capacity. The time interval between the verification measurements at the three different levels should be kept as short as possible. The overall accuracy is verified by comparing the ATG against manual reference level measurement at three different levels and evaluating the differences between the readings.
2.7.5 Precautions
Where possible ATG’s should be read at the tank rather than in the control room as the level resolution from the transmitted signal can cause a variation in the reading. ATG’s may or may not be housed in still pipes. If they are, however, the still pipe must be slotted, as required for manual gauging. In certain locations, still pipes without slots (solid or non-perforated) have been used to comply with local air pollution regulations. Solid still pipes can lead to serious errors in level and temperature readings and should not be used for measurement.
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Generally, the heavier material at the bottom of the tank is the least valuable, both in terms of cost and specification. Therefore, the entity receiving this portion will receive off specification product and will either reject the cargo or claim financial compensation. The balance of the tank’s contents will either stay in the tank or go to another receiver. In the latter situation, this entity will receive product that is of higher specification than that which was contracted for. While this entity will most likely not reject the cargo, it is unlikely that the shipper will have any recourse to charge more for the better product.
2.8.1 What is Stratification?
2.7.6 Summary
If an ATG is used for custody transfer purposes, it is necessary to verify and record that there is documentation to support: • A factory calibration showing an accuracy of ± 1 mm or ± 1/16 inch, if the unit was installed after June 2001, and for crude oil lease tanks a factory calibration showing an accuracy of ± 3 mm or ± 1/8 inch, if the unit was installed after 2018. • An initial verification at approximately upper, middle and lower levels showing an accuracy of ± 4 mm or ± 3/16 inch, except for crude oil lease tanks which require an accuracy of 6 mm or ± 1/4 inch. • Monthly periodic verifications at a single level within the normal operating range showing an accuracy of ± 4 mm or ± 3/16 inch, or 6 mm or ± 1/4 inch for crude oil lease tanks. 2.8 Stratification It is not unusual for the contents of a shore tank to be stratified. This is most common when dealing with heavy fuel oils; however, stratification can also occur in light products such as diesel, gasoline, or naphtha.
Stratification is the incomplete mixing of a tank’s contents, also referred to as non-homogenous.
This usually results in layers of material which have different compositions and specifications.
The layer with the highest density (lowest API gravity) will be at the bottom of the tank and the layer with the lowest density (highest API gravity) will be at the top of the tank.
2.8.2 Problems caused by Stratification?
There are several problems associated with stratification and incomplete mixing of tanks.
2.8.3 Sampling
Although sampling requirements are specified by the client(s); typically, an upper, middle, lower and/or running sample is taken from the custody transfer tanks. API MPMS Chapter 17.1, states, ‘When the material is known or suspected to be stratified, spot samples may be drawn and analyzed to determine the degree of stratification’. Some of our clients instruct us to take spot samples at different levels, however, some do not. When this is the case, we must advise the client that testing for stratification is recommended as good practice. An example of such an advice is:
• If less than the entire contents of the tank are transferred, the product delivered out of the tank will not have the same analytical specifications as those of the entire tank, which are determined from the representative tank sample. • Even if the entire contents of the shore tank are shipped onto a marine vessel, it is likely that product on the marine vessel will vary in specification from tank to tank. If this product is then discharged into more than one shore tank, the receiving shore tanks will have differing specifications. This situation becomes even more problematical when different receivers are involved.
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3. If the entire tank contents will not be used, but only a portion of it, the samples taken which will be subsequently analysed, should only be taken from the levels which will be transferred out of the tank. 4. Individual ship tank samples must be drawn on every job. If we only draw ship composite samples, we will be unable to localize a problem after the event. If a one-quart (which is 0.946 litres) tank composite sample is to be made from individual quart upper, middle and lower samples, one third of a quart should be taken from each level sample. The balance should be retained as individual samples should they need testing (individually) in the event of a dispute. 5. If a client asks us to determine the density of a tank, something that is almost universal whatever our nomination for trade work and a prerequisite to even quantity jobs, we MUST determine if that tank is homogenous or not. 6. The standards are clear. If upper, middle, and lower samples indicate that a tank is not homogeneous then additional samples are to be drawn until an adequate tank profile is obtained and reported. This is not optional; it is a 100% binding obligation under the method and standards. If we agree under a contract or nomination to establish a tank density, then this is the way we must proceed.
‘ We wish to draw to your attention that the material we are inspecting on your behalf could be susceptible to stratification. For this reason, and as recommended in API MPMS Chapter 17.1, we strongly recommend that spot samples be taken, at a minimum of upper, middle, and lower, and individually tested for evidence of stratification ’. NOTE: homogeneity is only defined for petroleum products in one place, and then only for one product, that is aviation fuel. For all other types of products, it is a rather unclear concept. The common assumption made is that homogeneity is established by reference to a narrow band of density or API between samples taken at various points (often upper, middle, and lower) or between tanks (e.g. on a ship); please be careful. Homogeneity with respect to density is no guarantee of homogeneity with respect to another analyte. For example, fuel oil density, viscosity, metals content and water within a large shore tank; the profiles for each property may be very different in each case, and not linked. Do not assume that because a tank is homogenous with respect to density it is also homogenous with respect to all other analytes.
capable of retaining water and sediments in suspension such as crude oils and heavy fuel oils, please bear in mind that any kind of petroleum product can stratify, resulting commonly from differences in cargo temperature and density. If we assume tanks to be homogeneous when they are not, then we will receive claims and complaints on a regular basis.
To manage this issue, it is our responsibility to:
a) Take adequate samples to establish if the contents of any tank are homogeneous or not - it is not the client’s obligation to tell us to do this. b) Retain sufficient sample to demonstrate after the fact if any given tank was homogeneous or not.
c) Communicate and document clearly if any cargo/tank is found to be non-homogeneous.
Please be mindful that:
1. Running or all levels samples WILL NOT highlight if a tank is homogeneous or not. Upper, middle, and lower spot samples or even more extensive layer / zone sampling can. 2. If we fail to take and to retain upper, middle, and lower spot samples or similar individual level samples we cannot demonstrate either before or after the fact that a tank was homogeneous or not.
Whilst stratification is most prominent when blending products or when working with materials
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If it is established that a tank is stratified for any analyte tested for, this must be communicated to the client(s) as soon as possible, as well as discussing and agreeing what to do next. Following the verbal conversation, ensure that the details of the discussion and how we have been instructed to proceed are documented in an email. In addition, make sure all samples collected are retained to allow us to defend ourselves when necessary.
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3. Vessel Inspection and Sampling
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it. Indicate single/double valve separations, if any, between clean/dirty ballast and cargo systems.
• Request to see raw data to support information on the voyage log.
3.1 Before Transfer This section considers the steps on a loading operation.
• Record the date of last dry-dock and whether measurement equipment was modified.
3.1.4 Vessel Lines and Tanks
Inspect for the presence of cargo in void spaces, ballast tanks, cofferdams, and non-designated cargo compartments. Before measuring On Board Quantity (OBQ), the condition of the vessel’s lines should be determined. The inspector may request that the vessel lines be drained, and the valves opened. Caution should be exercised on multigrade cargoes to avoid commingling the line contents of different products. Measure the amount of cargo or ballast water drained into the tank and sample, if possible. Record the capacity of the lines that were drained. Report the transfer of any engine room slops or other liquid into the cargo or slop tanks. If the previous cargo poses a contamination problem, all lines and pumps should be cleaned thoroughly and drained. Note how cleaning and draining was accomplished. When the vessel is inspected for tank acceptability prior to loading, tank inspection should be performed in accordance with “API MPMS Chapter 17.8 - Guidelines for Pre-loading Inspection of Marine Vessel Cargo Tanks and Their Cargo- handling Systems”.
3.1.1 Vessel Experience Factor (VEF)
Where issues such as these cannot be adequately explained by the vessel’s officer -in charge/operator, appropriate notations should be made on the VEF report and a Letter of Protest (LOP) issued to the vessel.
Data on previous voyages must be obtained from the vessel for use in calculating the vessel experience factor - See “API MPMS Chapter 17.9 / EI HM 49 - Vessel Experience Factor (VEF)”. It is important not to simply take all the VEF information supplied by the vessel at face value. The data should be reviewed to indicate possible inconsistencies. For example, some points that that should be raised with the vessel’s officer -in-charge are (but not limited to) the following. • Why is there is a missing voyage on the voyage log (e.g., Voyage 17-05)? • What was the vessel doing for the approximate 11-week period between Voyages 17-17 and 18- 01? • Are consistent units of measure used throughout the form? • Verify voyage entries where vessel and shore TCV are the same, although possible is most likely vessel figures were used for Bill of Lading purposes.
3.1.2 Draft, Trim, & List
Record the draft, trim, and list. These should be physically observed at the time of intervention. Both trim and list can significantly affect the liquid level of the product stored within the vessel tanks; therefore, this is an important part of the Inspection survey.
3.1.3 Remaining Ballast
For most cargoes, there should be no ballast remaining in the cargo tanks, lines, or pumps. Any ballast on board should be totally segregated. Measure and record the quantity of any ballast left on board prior to loading. Record the presence of and sample any measurable petroleum in ballast tanks. The vessel should not be gauged during de- ballasting. If simultaneous de-ballasting is performed during loading operations, determine the reason from the vessel’s representative and record
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3.1.5 On-board Quantity (OBQ) Measurement
3.1.6 Small Volume On-board Quantity (OBQ) Sampling When OBQ is accessible, samples should be obtained from all compartments containing liquid volume. An attempt should also be made to sample nonliquid volumes. Samples taken should be in sufficient quantity to permit any required analysis. Samples shall be taken in accordance with “API MPMS Chapter 8.1 - Standard Practice for Manual Sampling of Petroleum and Petroleum Products”.
3.1.9 Sea Valves
Confirm in the presence of the vessel’s personnel that sea valves and overboard discharge valves are in the closed position and sealed before and after cargo transfer. Seal valves to the extent possible, so as to be able to determine whether they were used during the cargo operation. Record the seal numbers.
Obtain and record reference heights from the calibration tables prior to taking opening cargo and water measurement. Record the observed gauge heights; investigate any discrepancies between the reference and observed heights. Determine the amount and nature of any material on board (OBQ) prior to transfer. Where On-board Quantity (OBQ) is found prior to transfer, it must be quantified. Determine the OBQ as specified in “API MPMS Chapter 17.4 - Method for Quantification of Small Volumes on Marine Vessels (OBQ/ROB)”: • For liquid material and water, use trim/list corrections if the liquid is in contact with all bulkheads in the compartment and the vessel is not on an even keel or has list. Use a wedge
3.1.10 Bunker Inspection
A bunker inspection should, when necessary, be performed before and after the cargo transfer operation. Measure the contents of all service, settling, and bunker storage tanks before and after transfer. If bunkering was conducted during cargo transfer operations, request from vessel personnel a copy of the BDR (Bunker Delivery Receipt).
3.1.7 On-board Quantity (OBQ) Temperatures
Temperatures shall be obtained, recorded, and used for cargo volume correction whenever depth of material and the nature of the material permits. If the temperature cannot be measured, the gross observed volume (GOV) shall be reported as Gross Standard Volume (GSV).
Vessel cargo gauging should not be performed during bunkering operations.
formula if the liquid does not touch all the bulkheads of the vessel’s compartments.
3.1.8 Slop Tanks
• For nonliquid material, multipoint gauging is recommended to determine if a wedge condition exists. If the material measured is not a wedge, the average of the multiple readings should be used for volume determination. However, if only one gauge point is available, the material shall be assumed to be evenly distributed over the tank bottom.
3.2 During Transfer
Obtain gauges and temperatures of the contents of slop tanks to determine the interface and the separate quantities of Free Water (FW) and slop oil. Take a separate sample of the water layer, if possible. Calculate the quantities; if any slops are to be commingled with the cargo, they are to be treated as OBQ and recorded appropriately. Keep slops samples separate from cargo samples.
3.2.1 Communications A reliable means of communication between the shore and vessel should be arranged. Vessel, shore, or measurement personnel who notice a problem during any stage of the transfer that could affect subsequent events should promptly notify all key personnel so that timely action can be taken.
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