BP_Measurement Manual PART1

Measurement Manual, Part I Crude and Petroleum Products

Copyright 2002 BP Pipelines (North America), Inc. In this book, the corporate entity BP Pipelines (North America) Inc. is usually referred to as “BP Pipelines” or “BP.”

BP Pipelines

Measurement Manual for Crude and Petroleum Products

Foreword The BP Pipelines Measurement Manual is broken into three parts. Part I covers crude oil and petroleum products, Part II covers natural gas, and Part III covers chemicals and petrochemicals. This book, Part I, documents the current policies of BP Pipelines regarding measurement of crude oil and liquid petroleum products. BP Pipelines’ objective is to provide the basis for measurement that is fair and equitable for all parties. To this end, the manual is based on recognized industry standards, industry practices, and prudent operating procedures. The procedures and policies in this manual are to be used by BP Pipelines employees and contract personnel engaged in custody transfer. It is not intended to serve as a training manual. If you use the procedures and equipment described in this manual, you should be able to pass an audit. The measurement policies in this manual are to be used throughout BP Pipelines operations. BP Pipelines recognizes, however, that unique circumstances, such as regulatory or contractual requirements or unusual operating conditions, may require some variance from the standard policy or procedure. In such cases, exceptions will be considered; however, a request must be submitted to the BP Pipelines Measurement Team. This request must contain all relevant information pertaining to the particular operation and the basis for the exception request. Measurement Team Technical Services Engineering and Maintenance Department BP Pipelines (North America) Every effort has been made to ensure the accuracy and reliability of the information in this manual; however, the Measurement Team solicits feedback from users regarding perceived errors.

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Contents List of Illustrations. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .iv List of Tables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . vii 1. Manual Sampling in Tanks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.1 Quick Reference . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.3 Procedures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.4 More About It . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.12 Reference Documents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.17 2. Gravity and Temperature Measurement in Tanks . . . . . . . . . . . . . . . . . . . . . . . . . . 2.1 Quick Reference . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.4 Procedures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.5 More About It . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.14 Reference Documents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.17 3. Gauging Lease Tanks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.1 Quick Reference . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.4 Procedures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.5 More About It . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.13 Reference Documents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.14 4. Gauging Large Tanks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.1 Quick Reference . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.4 Procedures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.5 More About It . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.16 Reference Documents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.17 5. Testing Crude Oil for Suspended Sediment and Water. . . . . . . . . . . . . . . . . . . . . . 5.1 Quick Reference . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.3 Procedures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.4 Reference Documents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.15 6. Other Tests for Crude and Products. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.1 Quick Reference . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.2 Tests for Crude Oil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.3 Tests for Products . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.13 More About It . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.17 Reference Documents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.18

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7. Tank Strapping. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7.1 Quick Reference . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7.3 Procedures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7.4 More About It . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7.12 Reference Documents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7.14 8. Seals and Security . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.1 Quick Reference . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.3 Procedures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.4 More About It . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.8 Reference Documents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.9 9. LACT/ACT Verification and the ELM System. . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.1 Quick Reference . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.4 Procedures for Checking the Operation of LACT and ACT Units . . . . . . . . . . 9.5 Overview of the ELM System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.11 More About It . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.14 Reference Documents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.16 10. Automatic Sampling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.1 Quick Reference . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.4 Procedures for Handling Samples . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.5 Design and Operation of an Automatic Sampling System . . . . . . . . . . . . . . . 10.8 More About It . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.12 Reference Documents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.14 11. Positive Displacement Meters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11.1 Quick Reference . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11.3 Inspecting the Meter and Accessory Equipment . . . . . . . . . . . . . . . . . . . . . . . 11.4 Design and Operation of a Positive Displacement Meter . . . . . . . . . . . . . . . . 11.6 Reference Documents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11.13 12. Turbine Meters. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12.1 Quick Reference . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12.3 Inspecting the Meter and Accessory Equipment . . . . . . . . . . . . . . . . . . . . . . . 12.4 Design and Operation of a Turbine Meter. . . . . . . . . . . . . . . . . . . . . . . . . . . . 12.5 Reference Documents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12.14 13. Other Meters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13.1 Quick Reference . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13.2 Orifice Meter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13.3 Ultrasonic Meter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13.5

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Coriolis Meter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13.7 Reference Documents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13.9 14. Proving a Meter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14.1 Quick Reference . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14.4 When to Prove a Meter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14.5 Procedures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14.6 More About It . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14.14 Reference Documents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14.16 15. Design of Prover Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15.1 Quick Reference . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15.2 Installation and Operating Requirements for Provers . . . . . . . . . . . . . . . . . . . 15.3 Reference Documents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15.9 16. Waterdraw Calibration. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16.1 Quick Reference . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16.2 When To Calibrate a Prover . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16.3 Preparation Procedures for Waterdraw Calibration. . . . . . . . . . . . . . . . . . . . . 16.4 Procedures for Calibrating a Pipe Prover Using the Waterdraw Method . . . . 16.8 Calibration Calculations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16.11 More About It . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16.12 Reference Documents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16.18 17. Claims and Adjustments, Using SMART . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17.1 Quick Reference . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17.3 Procedures for Making Claims and Adjustments . . . . . . . . . . . . . . . . . . . . . . 17.4 Procedures for Using the SMART Measurement Software for Ticketing and Reports . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17.6 More About It . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17.8 Reference Documents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17.14 Abbreviations. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . G.1 Glossary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . G.3 Index . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .I.1

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List of Illustrations Figure 1.1.

Thief . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .1.5

Figure 1.2.

Examples of labels on sample containers . . . . . . . . . . . . . . . . . . . . . . .1.7

Figure 1.3.

Sample bottle . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .1.9

Figure 1.4.

Where to take samples in a large tank . . . . . . . . . . . . . . . . . . . . . . . . .1.14

Figure 2.1.

Using a thermohydrometer to measure API gravity . . . . . . . . . . . . . . .2.6

Figure 2.2.

Reading a hydrometer for transparent liquids . . . . . . . . . . . . . . . . . . . .2.7

Figure 2.3.

Locations for determining the temperature of the liquid in a large tank with liquid height more than 15 feet . . . . . . . . . . . . . . . . . . . . . . .2.8

Figure 3.1.

Checking the tank before gauging . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3.6

Figure 3.2.

Checking the depth of settled S&W in the tank. . . . . . . . . . . . . . . . . . .3.9

Figure 3.3.

Innage method of gauging . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3.10

Figure 4.1.

Gauging an external floating roof tank from the platform. . . . . . . . . . .4.5

Figure 4.2.

Gauging an external floating roof tank from the floating roof. . . . . . . .4.6

Figure 4.3.

Gauging an internal floating roof tank . . . . . . . . . . . . . . . . . . . . . . . . . .4.7

Figure 4.4.

Checking the tank before gauging . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4.8

Figure 4.5.

Innage method of gauging . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4.10

Figure 5.1.

Free water in the bottom of centrifuge tube when preparing water-saturated toluene . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5.6

Figure 5.2.

Solubility of water in toluene. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5.6

Figure 5.3.

Sequence for determining S&W by the field centrifuge method using 100-ml (6-inch) centrifuge tubes . . . . . . . . . . . . . . . . . . . . . . . .5.10

Figure 6.1.

Bar chart for determining haze. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .6.16

Figure 7.1.

Recommended tape paths for measuring tank circumference on a welded tank . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.5

Figure 7.2.

Recommended tape paths for measuring tank circumference on a bolted tank . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.6

Figure 7.3.

Vertical measurements of a tank . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.7

Figure 7.4.

Measuring the shell height of a tank with a protruding bottom . . . . . . .7.8

Figure 7.5.

Measuring the shell height of a tank with a recessed bottom . . . . . . . .7.8

Figure 7.6.

Determining effective inside tank height . . . . . . . . . . . . . . . . . . . . . . .7.10

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Figure 7.7.

Sample page of strapping report . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7.13

Figure 8.1.

Boxcar seal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .8.8

Figure 9.1.

LACT unit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .9.6

Figure 9.2.

Sample LACT/ACT inspection form . . . . . . . . . . . . . . . . . . . . . . . . . .9.14

Figure 9.3.

Blank LACT/ACT inspection form . . . . . . . . . . . . . . . . . . . . . . . . . . .9.15

Figure 10.1. Design of an automatic sampling system. . . . . . . . . . . . . . . . . . . . . . .10.8 Figure 10.2. Fixed sample receiver (stationary sample pot). . . . . . . . . . . . . . . . . . .10.9 Figure 10.3. Portable sample receiver (pot) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .10.10 Figure 10.4. Sample mixing system for portable receivers . . . . . . . . . . . . . . . . . .10.11 Figure 11.1. Sealing points on a PD meter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .11.4 Figure 11.2. Typical positive displacement meter . . . . . . . . . . . . . . . . . . . . . . . . . .11.6 Figure 11.3. Design of a PD meter installation . . . . . . . . . . . . . . . . . . . . . . . . . . . .11.8 Figure 12.1. Conventional turbine meter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .12.5 Figure 12.2. Helical turbine meter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .12.6 Figure 12.3. Typical turbine meter installation for refined products . . . . . . . . . . . .12.8 Figure 12.4. Turbine meter with preamp . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .12.11 Figure 12.5. Turbine meter without preamp. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .12.11 Figure 13.1. Orifice meter installation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .13.3 Figure 13.2. Ultrasonic meter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .13.5 Figure 13.3. Path of the sound waves in an ultrasonic meter . . . . . . . . . . . . . . . . . .13.6 Figure 13.4. Coriolis meter. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .13.7 Figure 13.5. Vibration of the flow tubes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .13.8 Figure 13.6. Coriolis effect (twisting of the flow tubes) . . . . . . . . . . . . . . . . . . . . .13.8 Figure 14.1. Sample proving report . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .14.15 Figure 16.1. Waterdraw calibration unit. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .16.7 Figure 16.2. Waterdraw calibration worksheet . . . . . . . . . . . . . . . . . . . . . . . . . . .16.13 Figure 17.1. Example of a claim letter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .17.9 Figure 17.2. Example of a notarized affidavit . . . . . . . . . . . . . . . . . . . . . . . . . . . .17.11 Figure 17.3. Example of a SMART tank custody transfer ticket . . . . . . . . . . . . . .17.12 Figure 17.4. Example of a SMART meter ticket for a lease meter . . . . . . . . . . . .17.13

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List of Tables Table 1.1. Summary of Sampling Procedures and Applications. . . . . . . . . . . . . . . . . 1.13 Table 1.2. Samples for Determining S&W . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.14 Table 1.3. Number of Samples to Take from a Product Tank. . . . . . . . . . . . . . . . . . . 1.15 Table 1.4. Recommended Mixing Procedures. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.16 Table 2.1. Locations for Determining Temperature in Small and Large Tanks . . . . . 2.14 Table 2.2. Recommended Immersion Times for PETs and Cupcase Woodback Assemblies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.15 Table 2.3. Correction of API Gravity to 60°F for Generalized Crude Oils. . . . . . . . . 2.16 Table 5.1. Size of Test Sample Based on the Expected Water Content . . . . . . . . . . . 5.12 Table 6.1. Typical Sulfur Levels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.3 Table 6.2. Quality Guidelines for Metals in Crude Oils . . . . . . . . . . . . . . . . . . . . . . . 6.7 Table 6.3. Typical Distillation Fractions of a Crude Oil and Their Uses . . . . . . . . . . 6.10 Table 6.4. Typical Minimum Flash Points of Various BP Pipelines Products . . . . . . 6.15 Table 7.1. Fill Condition Required for Different Tanks while Strapping . . . . . . . . . . 7.12 Table 10.1. Recommended Mixing Procedures. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.12 Table 10.2. Typical Sizes of Sample Receivers for Various Operations . . . . . . . . . . 10.13 Table 11.1. Recommended Combinations of Meter Size, Measuring Element, and Gear Ratio . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11.9 Table 11.2. Recommended Operating Range for Various Sizes of PD Meters. . . . . . 11.10 Table 11.3. Effect of Changes in the Conditions of the Fluid and PD Meter on Measurement Accuracy. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11.11 Table 12.1. Recommended Operating Range for Various Sizes of Conventional Turbine Meters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12.9 Table 12.2. Recommended Operating Range for Various Sizes of Helical Turbine Meters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12.10 Table 12.3. Effect of Changes in the Conditions of the Fluid and Turbine Meter on Measurement Accuracy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12.13 Table 14.1. Causes of Meter Factor Fluctuation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14.10 Table 15.1. Effect of Various Criteria on the Design of a Prover System . . . . . . . . . 15.3 Table 15.2. Approximate Detector Error for Pipe Provers . . . . . . . . . . . . . . . . . . . . . 15.6

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Table 15.3. Typical Actuator Times for Four-way Valves . . . . . . . . . . . . . . . . . . . . . 15.7 Table 15.4. Type of Sphere to Use for Various Liquids . . . . . . . . . . . . . . . . . . . . . . . 15.8 Table 16.1. Type of Sphere to Use for Various Liquids . . . . . . . . . . . . . . . . . . . . . . . 16.14 Table 16.2. Sphere Roundness Verification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16.15 Table 16.3. Minimum Inflation Percentages for Given Pipe Sizes . . . . . . . . . . . . . . . 16.17 Table 17.1. When to File a Claim or Adjustment . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17.4

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Chapter 1

Manual Sampling in Tanks Quick Reference Summary of Tank Measurement Procedures

Safety •

Do not smoke during sampling.

•

Before taking any measurements, ground your bare hands and tools by touching the handrail.

•

Stand upwind and turn your face away when opening the tank hatch.

•

Monitor H2S while sampling.

•

Never sample during an electrical storm.

•

Wear appropriate personal protective equipment.

•

When sampling hazardous liquids, follow the applicable safety procedures in the Pipelines (NA) Business Unit Safety Manual.

•

Dispose of all samples and security seals properly.

•

Follow all applicable safety rules in the Pipelines (NA) Business Unit Safety Manual.

Scope This chapter includes the procedures for taking manual samples in upright cylindrical tanks of all sizes containing crude oil or products.

1. Suspend a cupcase thermometer in the tank, if used (Chapter 2). 2. Take appropriate samples (Chapter 1). 3. Gauge the height of the liquid in the tank (Chapter 3 and Chapter 4). 4. Determine the level of free water and/or sediment on the bottom of the tank (Chapter 5). 5. Determine the temperature of the tank – either with a cupcase thermometer or with a portable electronic thermometer (PET) (Chapter 2). 6. Analyze the samples as required for the specific type of transaction and product (Chapter 2, Chapter 5, Chapter 7). 7. Record all results (Chapter 17).

Summary of Sampling Procedures •

Take samples from the top down.

•

Which tests are performed on which samples depends on the size of the tank, the liquid level, and whether it contains crude oil or a petroleum product (see “More About It” at the end of this chapter).

•

If using a thief, pour about 6 inches of oil from the thief back into the tank before pouring the sample into the sample container.

•

Pour the sample from the thief or bottle into the sample container or put the stopper in the bottle as quickly as possible to avoid losing light ends.

•

Properly label all samples.

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September 2002

Chapter 1 Quick Reference

Equipment You Will Need for Gauging Tanks For gauging and manual sampling: • Steel gauge tape and bob (innage or outage)

For S&W testing by the laboratory centrifuge method:

• Water-indicating paste (if applicable)

• Two verified 8-inch centrifuge tubes

• Gasoline-indicating paste (if applicable)

• Water-saturated toluene or Stoddard solvent

• Thief or sample bottle

• Demulsifier solution

• Cotton cord or chain for raising and lowering thief or sample bottle

• Sample heater

• Graduated cylinder

• Centrifuge

• Bimetal, pocket-type thermometer

• Sample containers (for storing samples) For water testing by the Karl Fischer titration method:

For gravity and temperature testing:

• Nonaerating, high-speed shear mixer

• Thermohydrometer or Hydrometer, hydrometer cylinder, filter paper, and constant-temperature bath

• Clean glass syringes • Reagent-grade xylene • Karl Fischer reagents

• cupcase woodback thermometer

• Karl Fischer coulometric titrator

• Portable electronic thermometer (PET) • Circulating bath and ice bath or PET calibrator (for verifying a PET)

For security (lease tanks): • Seals for securing all pipeline connections • Side cutters for cutting and removing tank seal

For S&W testing by the field centrifuge method:

• Pliers

• Two verified 6-inch centrifuge tubes • Water-saturated toluene or Stoddard solvent • Demulsifier solution

Other: • Carrying case for all equipment

• Sample heater • Bimetal, pocket-type thermometer • Centrifuge

BP Pipelines

September 2002

Equipment for Gauging Tanks

BP Pipelines


Introduction Manual sampling involves lowering a thief or bottle into the tank one or more times to get representative samples of the liquid. The purpose of sampling crude oil is to determine suspended and settled sediment and water, API gravity, and occasionally other properties like vapor pressure. Liquid petroleum products stored in tanks require sampling for API gravity, vapor pressure, and other properties like flash, haze, and color. Manual sampling is necessary in tanks that do not use a LACT or ACT unit. You take samples to determine S&W and API gravity in the field and return them to the laboratory for other types of testing (see Chapter 6, “Other Tests for Crude and Products” for more information).

Equipment You Will Need for Sampling •

Thief or sample bottles

•

Cotton cord or brass chain for raising and lowering thief or sample bottle

•

Graduated cylinder

•

Sample containers for storing samples

•

Solvent for washing sample containers

•

Security seals and seal cutters

Manual Sampling in Tanks

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Procedures Table 1.1 is a summary of sampling procedures for different types of tanks and liquids. Table 1.2 and Table 1.3 show how many samples to take in different tanks. Table 1.4 shows how to mix samples for different tests. You will find all these tables under “More About It” at the end of this chapter. Although sampling procedures are the same for crude oil and products, you must make sure the samples are representative of the entire volume in the tank, either by turning on mixers or taking a greater number of samples.

Before You Sample Crude Oil The contents of any large tank containing crude oil (except lease tanks) must be thoroughly mixed before sampling. Because different grades of crude require different mixing times, each facility must conduct tests to determine the ideal mixing time. Follow these guidelines: •

Mix tanks that are less than 1/3 full for at least 2 hours (normal when receiving crude).

•

Mix tanks that are more than 1/3 full for 4 hours (normal when delivering crude).

Be sure to wait at least 2 hours after turning off the mixer before gauging the height of the liquid.

Before You Sample Petroleum Products Since refined products are usually homogeneous, most product tanks do not have mixers. However, after receiving product into a tank, you should sample as soon after the transfer as is safely possible, for the most accurate results. Wait at least 1 hour for the static charge to dissipate. See Table 1.3 under “More About It” at the end of this chapter for the number of samples required.

Types of Samples This chapter gives procedures for taking the following types of samples: •

Spot sample—bottle or thief

•

Composite spot sample—bottle or thief

•

All-levels sample—bottle

•

Running sample—bottle

•

Sample cocks (taps) on tanks or pipes—bottle


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Thief Spot Sampling Procedures Use a thief for spot sampling and composite spot sampling.

Hook

15 14 13 12 11 10 9 8 7

Petcocks

6 5 4 3 2

Trip Rod

Figure 1.1. Thief

Safety Reminder •

Do not replace the sample cord with a cord containing synthetic materials. The cord must be 100% cotton to prevent a buildup of static electricity.

•

Saturate new cotton cords with oil before using them the first time to assure that they are conductive.


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Before sampling, assure that the conditions are safe, as listed under “Safety” on the Quick Reference page. If you find any unsafe conditions or if the security of the tank has been compromised, do not take the samples and report these conditions to your supervisor.

Procedures for All Types of Tanks 1. Use clean, dry equipment. •

Before using a thief, rinse it with Stoddard solvent or another naphtha of similar volatility. If necessary, use sludge solvents to remove all traces of sediment and sludge from previously used containers.

•

Wash the thief with a strong soap solution, rinse it thoroughly with tap water, then rinse it with distilled water. If you are sampling crude oil in the field, you may omit this step.

•

Dry the thief either by blowing a current of clean, warm air into it or by placing it in a hot, dust-free cabinet at 100°F or higher.

2. Cock the valve at the bottom of the thief in the open position and trip the hook in the eye of the trip rod. •

Always lower the thief in the open position so that the thief fills from the bottom.

•

Always start at the top and work down so you disturb the oil as little as possible.

•

Do not disturb the cupcase thermometer hanging inside the tank, if you are using one (see Chapter 2, “Gravity and Temperature Measurement in Tanks”).

3. Lower the thief to the proper level. •

For lease tanks, take an upper sample just below the surface of the liquid, a middle sample from the center of the liquid, and a lower sample just above the suction line.

•

For large tanks, see Table 1.2 and Figure 1.4 under “More About It” at the end of this chapter for proper sampling levels.

4. Jerk the cord sharply to close the bottom valve on the thief and trap the sample. 5. Pull the thief to the surface. 6. Pour about 6 inches of the liquid in the thief back into the tank. 7. Pour the sample into a small, clean sample container until it is about 3/4 full. Cap the sample container, wipe it clean, and label it as an “upper” or “lower” sample (see Figure 1.2). Put it into a compartment in your tool box.


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BP Pipelines


Crude Oil Top Tank XXX

Sample bottles must • be clean and dry • be clear or brown glass • be unpigmented linear polyethylene for certain oils • have cork or glass stoppers or screw caps • not have rubber stoppers • be clearly labeled with bottle contents

Wide-mouth bottle with screw cap

Fill bottle up to 2/3 full Crude Oil Middle Tank XXX

Typical label

Narrow-mouth bottle with cork stopper

Figure 1.2. Examples of labels on sample containers 8. If you are compositing samples, measure out the proper amount of sample into a graduated cylinder and put it in the sample container. 9. Pour the remaining liquid back into the tank.

Additional Procedures for Lease Tanks When gauging a lease tank, use the upper and lower samples to determine the suspended S&W content (see Chapter 5, “Testing Crude Oil for Suspended Sediment and Water”). Use the middle sample to determine the API gravity. 1. To determine the API gravity and temperature of a sample in the thief, hang the thief containing the sample on the inside of the gauge hatch to test it (see Chapter 2, “Gravity and Temperature Measurement in Tanks” for details). 2. When finished testing, fill the storage bottle 3/4 full, cap it, and place it in your tool box. 3. Pour the remaining liquid back into the tank. Take a bottom or outlet/clearance sample to determine the level of settled S&W. 4. Adjust the trip rod so that it will trip the thief shut when it is bumped on the tank bottom (normally at 4 inches). 5. Slowly lower the thief through the liquid and S&W until it touches the bottom of the tank. 6. Let the thief rest on the bottom to allow the S&W to reach its natural level inside the thief. Do not use a pumping motion to force the thief through the S&W.


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BP Pipelines


7. Carefully raise the thief 2 to 4 inches and then allow it to bump the bottom hard enough to close the valve. 8. Pull the thief to the surface. 9. Slowly pour the contents over a glass plate or your gloved hand. Stop when you see S&W. 10. Return the thief to an upright position and measure the distance between the end of the trip rod and the surface of the S&W. This measurement is the depth of the S&W layer on the tank bottom. 11. Record the level of settled S&W. 12. Clean the thief.


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BP Pipelines


Bottle Sampling Procedures You can use a sample bottle for any sampling method.

Lead weight

Bottle in sampling cage

Figure 1.3. Sample bottle First assure that the conditions are safe, as listed under “Safety” on the Quick Reference page. If you find any unsafe conditions or if the security of the tank has been compromised, do not take the samples and report these conditions to your supervisor.

Spot Sampling Procedures 1. Use clean, dry equipment. •

Before using a bottle, rinse it with Stoddard solvent or another naphtha of similar volatility. If necessary, use sludge solvents to remove all traces of sediment and sludge from previously used containers.

•

Wash the bottle with a strong soap solution, rinse it thoroughly with tap water, then rinse it with distilled water. If you are sampling crude oil in the field, you may omit this step.

•

Dry the bottle either by blowing a current of clean, warm air into it or by placing it in a hot, dust-free cabinet at 100°F or higher.

2. Estimate the liquid level in the tank.


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BP Pipelines


3. Attach a weighted line to the bottle or place the bottle in a sample cage. 4. Put the stopper in the bottle. 5. Lower the weighted, stoppered bottle to the proper depth. 6. When the container reaches the selected level, pull out the stopper with a sharp jerk of the line and allow the bottle to fill completely. 7. When you judge that the container is full, raise the bottle. 8. If the bottle is not at least 3/4 full, pour out the contents and repeat steps 4–7. 9. If taking only one sample, pour off a small amount from the full bottle, and put the stopper in it immediately. 10. Repeat steps 5–8 for each sample needed. 11. Close the sample container, and return it to your toolbox.

Multiple Tank Composite Sample Prepare a composite sample in the laboratory (not in the field) by mixing equal portions of the upper, middle, and lower samples. If samples are taken from multiple tanks used in a transfer, you will usually composite the samples in proportion to the volume of product in (or transferred from) each tank.

All-Levels Sample 1. Use clean, dry equipment. •


•


•


2. Lower the weighted, stoppered bottle as near as possible to the draw-off level. 3. Pull out the stopper with a sharp jerk of the line, then raise the bottle at a uniform rate so that it is about 3/4 full as it emerges from the liquid. •

For light products or deep tanks, a restricted opening may be needed to avoid filling the bottle before it reaches the surface of the liquid.

•

The bottle should not be more than 3/4 full.


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BP Pipelines


4. If the container is full when it emerges from the liquid, pour the liquid back and try again. •

The goal is to get portions of sample from all levels of the tank. If the bottle is full, it did not sample any of the oil past the point that it filled.

•

If you are unable to fill the sample container at the proper rate, use a different method, such as taking multiple spot samples, to obtain a representative sample.

Running Sample 1. Use clean, dry equipment. •


•


•


2. Lower the unstoppered bottle at a uniform rate as nearly as possible to the level of the bottom of the outlet connection or swing line. 3. Raise the bottle to the top of the oil at the same rate so that it is about 3/4 full when withdrawn from the liquid. •

For light products or deep tanks, you may need a notched cork or other restricted opening to avoid filling the bottle too quickly.

•

The bottle should not be more than 3/4 full.

4. If the container is full when it emerges from the liquid, pour the liquid back and try again. •

The goal is to get portions of sample from all levels of the tank. If the bottle is full, it did not sample any of the oil past the point that it filled.

•

If you are unable to fill the sample container at the proper rate, use a different method, such as taking multiple spot samples, to obtain a representative sample.


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More About It Here you will find tables and instructions for the following: •

Summary of manual sampling procedures for products and crude oil

•

Number of samples of crude oil to take with a bottle or thief

•

Number of samples to take from a product tank

•

Mixing procedures


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Summary of Manual Sampling Procedures for Products and Crude Oil Table 1.1 shows the manual sampling procedure to use for different applications. Alternative procedures are acceptable if a mutually satisfactory agreement has been reached by the parties involved. Such an agreement must be in writing and signed by authorized officials.

Table 1.1.

Summary of Sampling Procedures and Applications Application

Type of Storage Container

Procedure

Liquids of more than 16 lb. and not more than 26 lb. RVP (e.g., propane, butane, and pentane)

Storage tanks, ship and barge tanks, tank cars, tank trucks

Precooled bottle sampling

Liquids of more than 16 lb. and not more than 26 lb. RVP (e.g., propane, butane, and pentane)

Storage tanks with taps

Cooler tap sampling

Liquids of more than 2 lb. and not more than 16 lb. RVP (e.g., crude oil and products like gasoline, distillates, and kerosene)

Storage tanks, ship and barge tanks, tank cars, and tank trucks

Bottle sampling and thief sampling

Liquids of 2 lb. RVP or less (e.g., heavy fuel oils and asphalt)

Storage tanks, ships, barges

Bottle sampling


Drums, barrels, cans

Tube sampling


Tank cars, storage tanks

Bottom or thief sampling

Liquids and semi-liquids of 2 lb. RVP or less (e.g., heavy fuel oils and asphalt)

Free or open-discharge streams, open tanks or kettles with open heads, tank cars, tank trucks, drums

Dipper sampling

Crude and petroleum products

Pipelines

Automatic sampling or manual spot samples from the line


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BP Pipelines


Number of Samples of Crude Oil to Take with a Bottle or Thief The number of samples used for S&W testing depends on the size of the tank. Table 1.2 shows guidelines for obtaining samples from tanks of different sizes.

Table 1.2.

Samples for Determining S&W Number of Samples and Sampling Levels

Tank Capacity/Liquid Level Upper

Middle

Lower

1

1*

1

1 1

1* 1**

1 1

1

1**

1

1,000 barrels or less More than 1,000 barrels (no mixer)

Liquid level less than 15 feet Liquid level more than 15 feet More than 1,000 barrels (with mixer) *

The middle sample here is taken to determine the API gravity of the liquid. This sample is not included in the composite sample or in the tests for S&W.

**

This middle sample may be used to determine the API gravity and then added to the composite sample for testing for S&W, but normally all three samples are tested for gravity and S&W and the results averaged. Alternately the three samples are composited and then tested.

Note: Additional tests may require additional samples.

In small tanks, test the upper and lower samples separately for suspended S&W. In addition to these samples, you may also take a bottom sample to determine the height of the settled S&W. Figure 1.4 shows where to take samples in a large tank.

Liquid level

UPPER — midpoint of upper 1/3

1/3 depth level

MIDDLE — midpoint of middle 1/3

2/3 depth level

LOWER — midpoint of lower 1/3

Figure 1.4. Where to take samples in a large tank


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BP Pipelines


Number of Samples to Take from a Product Tank The number of samples to take from a product tank depends on the height of the liquid in the tank.

Table 1.3.

Number of Samples to Take from a Product Tank

Depth of Liquid

Number of Samples

Location of Samples

Up to 10 feet

1

Middle

10 to 15 feet

2

Upper — 1/4 of liquid depth Lower — 3/4 of liquid depth

Over 15 feet

3

Middle of upper 1/3 Middle of middle 1/3 Middle of lower 1/3

Note: Depending on the actual tests to be performed, additional samples may be required.


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BP Pipelines


Mixing Samples A sample may or may not need to be mixed before testing it, depending on the type of test and how homogeneous the sample is. Because an automatic sampling system takes samples over a period of many hours, some settling almost always occurs. You can mix a sample with a stand-alone power mixer, with an internal mixer in the sample pot, or by shaking it. When using a stand-alone power mixer, be sure to use the correct type for the container or pot you have, as the mixer/container combination has been tested and proven effective. Table 1-4 lists the mixing recommendations for various tests.

Table 1.4.

Recommended Mixing Procedures Recommended Mixing Procedure Test Purpose* Power

Density for crude and heavy fuels

X

Sediment and water

X

Density for other hydrocarbons

*

Shaking

None

X

Vapor pressure

X

Cloud point

X

Sample transferred from a container. For tests not listed, refer to the specific test procedure.


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BP Pipelines


Reference Documents 1. API Manual of Petroleum Measurement Standards, Chapter 3.1A “Standard Practice for the Manual Gauging of Petroleum and Petroleum Products” 2. API Manual of Petroleum Measurement Standards, Chapter 8.1 “Standard Practice for the Manual Sampling of Petroleum and Petroleum Products” 3. API Manual of Petroleum Measurement Standards, Chapter 18.1 “Measurement Procedures for Crude Oil Gathered from Small Tanks by Truck” 4. Pipelines (NA) Business Unit Safety Manual


September 2002

1.17

Chapter 2

Gravity and Temperature Measurement in Tanks Quick Reference Safety

Summary of Tank Measurement Procedures

•

Do not smoke while working around tanks.

•

Before taking any measurements, ground your bare hands and tools by touching the handrail.

1. Suspend a cupcase thermometer in the tank, if used (Chapter 2).

•


•


•

Never sample during an electrical storm.

•


•


Scope This chapter includes the procedures for determining API gravity and temperature of crude oil and liquid petroleum products in nonpressurized tanks.

Summary of Gravity Procedures

2. Take appropriate samples (Chapter 1). 3. Gauge the height of the liquid in the tank (Chapter 3 and Chapter 4). 4. Determine the level of free water and/or sediment on the bottom of the tank (Chapter 5). 5. Determine the temperature of the tank – either with a cupcase thermometer or with a portable electronic thermometer (PET) (Chapter 2). 6. Analyze the samples as required for the specific type of transaction and product (Chapter 2, Chapter 5, Chapter 7). 7. Record all results (Chapter 17).

•

Use the middle sample to measure gravity in tanks that hold less than 1,000 barrels.

•

Use the upper, middle, and lower samples to measure gravity in tanks that hold more than 1,000 barrels. These samples may be composited for testing, or they may be tested separately and the results averaged.

•

For tanks of less than 1,000 barrels (lease tanks), use a clean thermohydrometer and leave it in the thief for at least 3 minutes (longer in heavier oils or during extreme heat or cold).

•

For tanks holding more than 1,000 barrels, pour the samples into a hydrometer cylinder in the laboratory for testing with a thermohydrometer.

•

When the liquid is opaque, deduct 0.1°API from the gravity reading to correct for the meniscus.

•

Record the gravity to the nearest 0.1°API.

BP Pipelines

September 2002


•

Record the thermohydrometer temperature to the nearest 1.0°F.

Summary of Temperature Procedures •

Take one reading from the middle of tanks under 1,000 barrels.

•

Take 3 readings, one each from the middle of the top, middle, and bottom thirds of tanks 1,000 bbls and larger. Report the average of the 3 readings as the temperature of the tank.

•

BP Pipelines’ preferred procedure for determining tank temperature for custody transfer is to use a portable electronic thermometer (PET); however, cupcase thermometers are acceptable for inventory purposes or for lease operations where only one middle temperature is required.

•

When using a PET, keep the sensor probe in motion within the fluid by raising and lowering it 1 foot above and below the desired depth.

•

Leave a cupcase thermometer in the liquid for at least 10 minutes before reading the temperature (15 minutes in heavier oils and when the ambient temperature is below 32°F). See Table 2.2 for additional information on recommended immersion times.

•

Record the temperature to the nearest 0.1ºF when using a PET and 0.5ºF when using a cupcase thermometer.

•

For safety reasons, the temperature of the liquid must be 120°F or less. If the tank is above 120ºF, notify your supervisor.

BP Pipelines

September 2002











• Sample heater


• Centrifuge







• Cupcase woodback thermometer





• Pliers




BP Pipelines

September 2002


BP Pipelines


Introduction After sampling the liquid in the tank, you will gauge the tank to determine the amount of liquid in it. Part of the gauging process includes measuring the API gravity and temperature of the liquid. A tank’s volume varies due to expansion and contraction of the liquid and the metal tank shell with changes in temperature. Each tank has a capacity table that is based on the volume at a certain temperature. Getting an accurate temperature reading allows you to correct the volume for the actual temperature of the liquid in the tank. Density, like volume, depends on temperature, and so you will also measure the temperature of the sample while determining the API gravity. One purpose of measuring API gravity is to allow conversion of the volume you measure by gauging to the volume at the standard temperature of 60°F. API gravity is also a property of the oil that may affect the price paid for the oil.

Equipment You Will Need for Determining Gravity and Temperature •

Thief or bottle containing a sample from the middle of the tank (small tanks) or the upper, middle, and lower samples (large tanks)

•

Hydrometer cylinder, thermohydrometer (or hydrometer and glass thermometer), and a constant-temperature bath if the temperature of the sample is very different from the ambient temperature

•

Portable electronic thermometer and ASTM glass thermometer for verifying the PET (preferred) or cupcase woodback thermometer

•

Circulating bath and ice bath or PET calibrator (when verifying a PET)

Gravity and Temperature Measurement in Tanks

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BP Pipelines


Procedures The contents of large tanks containing crude oil should be thoroughly mixed before you make temperature measurements (lease tanks do not have mixers). Because different grades of crude require different mixing times, a facility may conduct tests to determine the ideal mixing time for each grade it handles. Unless otherwise instructed, follow these guidelines: •

Mix tanks that are less than 1/3 full for at least 2 hours.

•

Mix tanks that are more than 1/3 full for 4 hours.

Be sure to wait at least 2 hours after turning off the mixer before gauging the height of the liquid to allow the liquid to stop moving.

Procedures for Measuring API Gravity Measure the gravity as soon as possible after collecting the sample(s) and after the temperature of the sample(s) has stabilized.

Thermohydrometer Method 1. Use a sample from the middle of the column of liquid (small tanks) or 3 samples from the top, middle, and bottom of the column of liquid (large tanks). •

For small tanks, you may hang the thief in the hatch and determine the gravity before transferring the sample to a storage container.

•

For large tanks, transfer the sample, without splashing, to a clean hydrometer cylinder for the test.

2. Insert a clean thermohydrometer into the thief or hydrometer cylinder until it floats freely, and then push it down another 1/4 inch (see Figure 2.1). 3. Leave the thermohydrometer in the thief or hydrometer cylinder for at least 3 minutes to allow the temperature to stabilize. Note: Do not allow the thermohydrometer to touch the side of the thief. 4. After at least 3 minutes, read the observed gravity at eye level. Take the measurement at the bottom of the meniscus for clear liquids (see Figure 2.1). 5. When the liquid is too opaque to see the meniscus (for example, crude oil), deduct 0.1°API to correct for it.


September 2002

2.5

BP Pipelines


Stem

Thermohydrometer Meniscus

Gravity scale

Liquid sample

Temperature scale

Thief

Figure 2.1. Using a thermohydrometer to measure API gravity 6. Record the gravity to the nearest 0.1°API. 7. Read the temperature at eye level. Note: The thermohydrometer bulb must remain in the liquid while you are reading it. 8. Record the observed temperature to the nearest 1.0°F.

Hydrometer Method 1. Transfer the sample to a clean hydrometer cylinder without splashing. •

Remove any air bubbles from the surface by touching them with a piece of clean paper towel or filter paper before inserting the hydrometer.

2. Place the cylinder upright in a location away from air currents to keep the temperature of the sample liquid from changing during the test. •

If the temperature of the sample is much above or below the ambient temperature, put the cylinder in a constant-temperature bath.


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BP Pipelines


3. Lower the hydrometer gently into the sample. Do not let the hydrometer stem get wet above the level where it floats in the liquid (see Figure 2.2). 4. Use the thermometer to stir the sample continuously. •

Keep the mercury completely immersed.

•

Keep the hydrometer stem dry while stirring the sample.

5. Read and record the temperature to the nearest 0.5°F. •

Immerse the thermometer as far as you can while still being able to read the scale.

•

Wait about 30 seconds for the reading to stabilize.

•

Keep the thermometer immersed while reading the temperature.

6. Push the hydrometer about 2 scale divisions into the liquid and release it. •

If the liquid has a low viscosity, spin the hydrometer slightly as you release it.

•

Allow the hydrometer to come to rest and wait for all air bubbles to come to the surface.

7. Read the hydrometer scale to the nearest 0.0001 (relative density) or 0.05°API. •

For transparent liquids, look at the scale with your eye just below the liquid’s surface, then raise your head until the surface appears to become a straight line cutting the scale (see Figure 2.2).

•

For opaque liquids, read the scale at eye level and subtract 0.1º API to correct for the meniscus.

Meniscus

Read gravity scale at this point

Liquid Horizontal plane surface of liquid Hydrometer cylinder

Figure 2.2. Reading a hydrometer for transparent liquids


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BP Pipelines


8. Immediately after reading the hydrometer scale, stir the sample with the thermometer and record the temperature to the nearest 0.5°F. If this temperature differs by more than 1°F from your first measurement, repeat steps 7 and 8 until the temperature stabilizes. 9. Record the final hydrometer reading to the nearest 0.1°API and the temperature reading to the nearest 1°F. 10. Convert the observed API gravity to API gravity at standard temperature (60°F) (see Table 2.3 under “More About It”).

Where to Take Temperature Readings In tanks where the liquid depth is more than 10 feet, take temperature readings at 3 levels: in the middle of the top, middle, and bottom third of the column of liquid. When the liquid depth is less than 10 feet, take 1 measurement in the middle of the column of liquid. The temperature of a liquid in a storage tank can vary throughout its depth; therefore, when the difference in temperature between any two readings is greater than 2ºF, calculate an average temperature. Do this by taking temperatures at different levels that are equally spaced apart, averaging the readings, and rounding off the result to the nearest 0.1ºF. Report the result as the average temperature for the entire volume. In some cases, such as when a tank has a nonuniform cross-sectional area, it may be necessary to calculate a volume-weighted average temperature.

Hatch

Upper temperature Liquid height

Middle temperature Lower temperature Outlet

} } }

1/3

1/3

1/3

Figure 2.3. Locations for determining the temperature of the liquid in a large tank with liquid height more than 15 feet


September 2002

2.8

BP Pipelines


Procedures for Measuring Temperature You may use a portable electronic thermometer (PET) or a cupcase woodback thermometer to measure temperature in tanks. PETs are preferred in all types of liquids and required when working in a heated fuel oil tank. First assure that the conditions are safe, as listed under “Safety” on the Quick Reference page. If you find any unsafe conditions or if the security of the tank has been compromised, do not take the measurements and report these conditions to your supervisor.

Portable Electronic Thermometer (PET) See Table 2.1 and Table 2.2 under the heading “More About It” at the end of this chapter for information about temperature measuring locations and thermometer immersion times. 1. Attach the grounding cable from the thermometer to the tank before opening the hatch. 2. Verify that the thermometer battery is working. 3. Set the temperature range selector. 4. Lower the sensing probe to the correct level. If taking more than one reading, start with the position closest to the top of the tank. •

Position the thermometer as far from the tank shell as practical.

5. Repeatedly raise and lower the probe about 1 foot in each direction until the temperature reading stabilizes; that is, when the readout varies by no more than 0.2°F for at least 30 seconds. 6. After the temperature has stabilized, read and record the temperature. 7. Repeat steps 4, 5, and 6 in large tanks for each level needed. 8. When taking more than one reading, average the readings, round to the nearest 0.1°F, and record the average. T1 + T2 + T3 -------------------------------- = average temperature 3 9. Clean the thermometer (and tape) with a solvent and dry it with a cloth.


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2.9

BP Pipelines


Safety Reminder •

The temperature must be 120°F or less. If the tank is above 120ºF, notify your supervisor.

Cupcase Woodback Thermometer Because a cupcase woodback thermometer assembly takes so long to reach the temperature of the liquid in the tank (up to 1 hour, depending on the difference in temperature between the liquid and the air), you must immerse the thermometer when you first begin gauging and read the temperature after you finish. See Table 2.1 and Table 2.2 under the heading “More About It” at the end of this chapter for locations of measurements and immersion times. If the conditions are safe, begin as follows: 1. Attach the thermometer to a conductive lowering device (e.g., cotton cord, brass chain, or gauging tape). 2. If the atmospheric temperature differs by more than 20°F from the anticipated temperature of the liquid in the tank, immerse the thermometer twice just below the liquid’s surface and empty the cup after each immersion. 3. Lower the thermometer to the correct level, keeping the lowering device in contact with the hatch. •

Position the thermometer as far from the tank shell as practical.

•

Repeatedly raise and lower the thermometer about 1 foot to help stabilize the reading.

4. After the temperature has stabilized, pull the thermometer from the liquid. •

Keep the assembly sheltered below the edge of the hatch to prevent the wind or air temperature from affecting the reading.

•

Make sure the cup is full while you are reading the temperature.

•

Do not hold the assembly by the brass cup, as heat from the hand may change the temperature of the oil.

•

Read the temperature to the nearest 0.5ºF immediately after pulling the thermometer out.

5. For a custody transfer repeat steps 3 and 4. For inventory or for small tanks, usually only one middle temperature reading is all that is required.


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2.10

BP Pipelines


•

If the readings agree within 2°F, average them and record the average to the nearest 0.1ºF. T1 + T2 ------------------- = average temperature 2

•

If the readings differ by more than 2°F, take additional readings and average the results.

6. For tanks that hold 1,000 bbls or more, repeat steps 3, 4, and 5 at the top, middle, and bottom of the column of oil. •

Average the 3 temperature readings: T1 + T2 + T3 -------------------------------- = average temperature 3

7. When taking readings from more than one location in the tank, average the readings, round to the nearest 0.5°F, and record the average. 8. After using the thermometer in a heavy, high-viscosity, or high-pour-point oil, clean all parts of the assembly. •

Rinse the cupcase thermometer with Stoddard solvent or another naphtha of similar volatility. If necessary, use sludge solvents to remove all traces of sediment and sludge.

Safety Reminder •

The temperature must be 120°F or less. If the tank is above 120ºF, notify your supervisor.

Procedures for Verifying Thermometers Thermometers are precision instruments. Ensuring their accuracy is an important part of your job.

Verifying PETs A PET must be calibrated in a laboratory before using it the first time and recalibrated once a year thereafter.


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2.11

BP Pipelines


Spot-check the PET before each use or once a day, and make a more thorough check monthly. Do not use a PET that does not pass these checks. Document the monthly checks and keep the documentation on file at the location for at least two years.

Daily Check 1. Place the PET and an ASTM glass thermometer in a liquid. 2. After the temperatures have stabilized, compare the readings of the two thermometers. 3. If the readings differ by more than 0.5°F, do not use the PET in a custody transfer until it has been recalibrated.

Monthly Check 1. Place the PET and a NIST-certified or equivalent thermometer side by side in a circulating hot-water bath, if available. •

Leave them undisturbed for at least 10 minutes.

•

Compare the readings of the two thermometers. If they differ by more than 0.5°F, do not use the PET.

2. Place the PET and a NIST-certified or equivalent thermometer side by side in ice water. •

Leave them undisturbed for at least 10 minutes.

•

Compare the readings of the two thermometers. If they differ by more than 0.5°F, do not use the PET.

3. If the PET is out of calibration, follow the manufacturer’s procedures for recalibration. Note: You will probably do this with a calibrator box attached to the PET. 4. Check the junction between the cable and the probe for damage. 5. Check the cable insulation for cuts, breaks, and abrasions. 6. Check the grounding cable for damage. 7. Check the case body for cracks or damage. 8. If the PET is damaged, do not use it until it is repaired.

Verifying a Glass Thermometer (including a Cupcase Thermometer) A glass thermometer must be verified in a laboratory before using it the first time and reverified once a year thereafter. You should spot-check the thermometer before each use or once a day. Do not use it if it fails these checks. 1. Make sure the thermometer is clean. An oil film can insulate the thermometer and


September 2002

2.12

BP Pipelines


cause an inaccurate reading. 2. Check that the paint on the engraved scale is still present. Do not use a thermometer that has lost this paint. It is too difficult to see the reading. 3. Check that the liquid column has not separated. If the column separates, then rejoins, do not use the thermometer until it has been verified in a laboratory. 4. Compare the reading on the thermometer to that on a similar thermometer. If the readings differ by more than 1.0ºF, do not use the thermometer.


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2.13

BP Pipelines


More About It Here you will find the following tables and instructions for using them: •

Table 2.1. Locations for Determining Temperature in Small and Large Tanks

•

Table 2.2. Recommended Immersion Times for PETs and Cupcase Woodback Assemblies

•

Table 2.3 Correction of API Gravity to 60°F for Generalized Crude Oils

Table 2.1.

Locations for Determining Temperature in Small and Large Tanks

Tank Capacity/Liquid Level 1,000 barrels or less

Number of Measurements

Locations of Measurements

1

Middle of liquid height

Liquid level under 10 feet

1

Middle of liquid height

Liquid level 10 to 15 feet

2

3 feet from top of liquid surface and 3 feet from bottom of tank

Liquid level over 15 feet

3

Middle of top third Middle of middle third Middle of bottom third

More than 1,000 barrels


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2.14

BP Pipelines


Table 2.2.

Recommended Immersion Times for PETs and Cupcase Woodback Assemblies Recommended Immersion Times PET*

Cupcase Woodback Assembly**

API Gravity at 60°F In Motion

In Motion

Stationary

When Temperature Differential <5°F In Motion

Stationary

>50°

30 seconds

5 minutes

10 minutes

5 minutes

10 minutes

40 to 49°

30 seconds

5 minutes

15 minutes

5 minutes

15 minutes

30 to 39°

45 seconds

12 minutes

25 minutes

12 minutes

20 minutes

20 to 29°

45 seconds

20 minutes

45 minutes

20 minutes

35 minutes

<20°

75 seconds

45 minutes

80 minutes

35 minutes

60 minutes

*

While measuring, keep the sensor probe in motion by raising and lowering it 1 foot above and below the desired depth.

**

Can be used in either an in-motion or a stationary mode. “In motion” is defined as repeatedly raising and lowering the assembly 1 foot above and below the desired depth. If additional mass is placed in the liquid near the thermometer (such as a weight to make the cupcase woodback assembly sink), the immersion time of the assembly will be longer than those listed in this table. Immersion times should be established by testing, and all parties involved should agree on the times.

Note: Immersion times are based on test procedures outlined in API MPMS Chapter 7. Failure to use these recommended times may result in incorrect temperature readings.


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BP Pipelines


The following table, which is an excerpt from API Table 5A, can be used to correct the observed API gravity at the observed temperature to the standard API gravity at 60°F when gauging crude oil. API Table 6A can be used to correct the observed API gravity at the observed temperature to the standard API gravity at 60ºF when gauging products. Both tables are available at the field locations or from the Measurement Team. These corrections are made automatically if you input the data into SMART (measurement ticketing software).

Table 2.3.

Correction of API Gravity to 60°F for Generalized Crude Oils API Gravity at the Observed Temperature (°API)*

Observed Temperature

30.0

30.5

31.0

31.5

32.0

32.5

33.0

33.5

Corresponding API Gravity at 60°F (°API)

*

40.5°F

31.4

31.9

32.4

32.9

33.4

33.9

34.5

35.0

41.0°F

31.3

31.9

32.4

32.9

33.4

33.9

34.4

34.9

41.5°F

31.3

31.8

32.3

32.8

33.4

33.9

34.4

34.9

42.0°F

31.3

31.8

32.3

32.8

33.3

33.8

34.3

34.9

Round the observed gravity to the nearest 0.5°API.

Note: Based on API Table 5A.

Example: If the observed gravity is 31.7 °API (round it to 31.5°API) and the observed temperature is 41.3°F (round it to 41.5°F), the API gravity is 32.8°API. Take the difference between the observed gravity and API gravity in the table (31.7 - 31.5 = 0.2) The corrected API gravity is 32.8 + 0.2 = 33.0°API. Note: API does not recommend interpolation of temperature.


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BP Pipelines


Reference Documents 1. API Manual of Petroleum Measurement Standards, Chapter 3.1A “Standard Practice for the Manual Gauging of Petroleum and Petroleum Products” 2. API Manual of Petroleum Measurement Standards, Chapter 7 “Temperature Determination” 3. API Manual of Petroleum Measurement Standards, Chapter 8.1 “Manual Sampling of Petroleum and Petroleum Products” 4. API Manual of Petroleum Measurement Standards, Chapter 9.1 “Hydrometer Test Method for Density, Relative Density (Specific Gravity), or API Gravity of Crude Petroleum and Liquid Petroleum Products” 5. API Manual of Petroleum Measurement Standards, Chapter 9.3 “Thermohydrometer Test Method for Density and API Gravity of Crude Petroleum and Liquid Petroleum Products” 6. API Manual of Petroleum Measurement Standards, Chapter 11.1, Volume I, Table 5A “Generalized Crude Oils – Correction of Observed API Gravity to API Gravity at 60ºF” 7. API Manual of Petroleum Measurement Standards, Chapter 11.1, Volume I, Table 5B “Generalized Products – Correction of Observed API Gravity to API Gravity at 60ºF” 8. Pipelines (NA) Business Unit Safety Manual


September 2002

2.17

Chapter 3

Gauging Lease Tanks Quick Reference Safety


•

Do not smoke during gauging.

•

Ground your bare hands and equipment before gauging.


•

Keep the gauge tape in contact with the hatch while gauging to prevent sparking.

2. Take appropriate samples (Chapter 1).

•


•

Check the condition of the ladder and catwalk before gauging.

3. Gauge the height of the liquid in the tank (Chapter 3 and Chapter 4).

•

Determine whether you need to take precautions for H2S before gauging.

•

Never gauge during an electrical storm.

•


•


Scope This chapter describes the procedures for measuring crude oil from upright cylindrical tanks with a capacity of less than 1,000 barrels.

Reasons for Rejecting the Oil

4. Determine the level of free water and/or sediment on the bottom of the tank (Chapter 5). 5. Determine the temperature of the tank – either with a cupcase thermometer or with a portable electronic thermometer (PET) (Chapter 2). 6. Analyze the samples as required for the specific type of transaction and product (Chapter 2, Chapter 5, Chapter 7). 7. Record all results (Chapter 17).

•

Valves on the bottom or side of the tank cannot be sealed or are leaking.

•

The tank’s oil level is above the maximum height stenciled on the side of the tank.

•

The suspended S&W is greater than 1.0% (see Chapter 5, “Testing Crude Oil for Suspended Sediment and Water”).

•

The free water in the tank is greater than 0.3% (see this chapter). (Note: Texas, New Mexico, and Louisiana allow 1.0% free water.)

•

The settled S&W (tank bottoms) is less than 4 inches from the bottom of the pipeline (P/L) connection (see Chapter 1, “Manual Sampling in Tanks”).

• •

Leaks are present in the tank bottom or sides. The oil has not weathered (settled) for at least 2 hours before gauging.

BP Pipelines

September 2002


Exceptions •

You may reject the tank if the oil height is less than 1/2 the normal height of the tank (with supervisor’s approval).

•

The total S&W content must be less than 1.0%. Of this 1.0%, the free water content may be no more than 0.3%. In Texas, New Mexico, and Louisiana, the allowable free water content is 1.0%, with no S&W.

BP Pipelines

September 2002











• Sample heater


• Centrifuge












• Pliers




BP Pipelines

September 2002


BP Pipelines


Introduction This chapter includes the procedures for taking the opening and closing gauges of any lease tank that does not use a LACT unit. Gauging provides a measure of the amount of oil transferred from the tank.

Equipment You Will Need for Gauging This is the equipment you need to gauge the height of the crude oil in a tank: •

Steel gauge tape and bob

•

Thief

•

Thermometer – PET or cupcase

•

Thermohydrometer

•

Centrifuge tubes

•

Water-indicating paste

•

Seals for securing all pipeline connections

•

Side cutters for cutting and removing tank seals

•

Carrying case for all gauging equipment

Gauging Lease Tanks

September 2002

3.4

BP Pipelines


Procedures Sampling and S&W testing are somewhat different in lease tanks than in large tanks.

Sampling in Lease Tanks versus Large Tanks Manual sampling of lease tanks differs from sampling of larger tanks in the following ways: 1. In a lease tank, take the top sample just below the surface of the liquid, not from the middle of the top third of the liquid, as in large tanks. Use a thief and then pour the sample into a small sample bottle or directly into a centrifuge tube for S&W determination. 2. Take the middle sample from the middle of the tank, and in a lease tank use it only for gravity determination. While you are still on top of the tank, insert a hydrometer directly into the thief. 3. Take the lower sample from a lease tank just above the suction line, not from the middle of the bottom third of the liquid, as in large tanks. Use a thief and then pour the sample into a small sample bottle or directly into a centrifuge tube for S&W determination.

Procedures for Gauging by the Innage Method The innage method of gauging directly measures the height of the liquid with a tape and bob that extend to the bottom of the tank. First assure that the conditions are safe, as listed under “Safety” on the Quick Reference page. If you find any unsafe conditions or if the security of the tank has been compromised, do not run the tank and report these conditions to your supervisor.

Gauging Lease Tanks

September 2002

3.5

BP Pipelines


All valves should be sealed closed

Hatch Oil level— no greater than stenciled tank height

Tank stop valve

Oil surface— no foaming or boiling

Fill lines that extend into top of tank should have notch to prevent siphoning

Tank 101 Lease 49203 Tank Ht. 15' Verify stenciled tank information

Figure 3.1. Checking the tank before gauging

Opening Gauge If the conditions are safe, run the tank as follows: 1. Before taking the opening gauge, inspect the tank (see Figure 3.1): •

Check the tank and valves for leaks or distortions.

•

Check the seal on the tank stop valve for any signs of tampering.

•

Check all bottom and side valves to make sure they are closed and have sealing devices for attaching seals.

•

Make sure the ladders and catwalk are safe.

•

Check the tank and lease numbers stenciled on the tank.

•

Ground yourself before climbing on the tank. Be especially cautious on dry days, since the potential for static electricity is greater in low humidity.

•

Check that the top valves are closed and can be sealed.

•

Open the hatch using all safety precautions. Wear an approved breathing apparatus if H2S is a potential hazard.

•

Make sure the fill lines at the top of the tank are notched to prevent siphoning.

Gauging Lease Tanks

September 2002

3.6

BP Pipelines


Safety Reminder Do not run the tank if: •

The oil’s surface is foaming or boiling.

•

The oil level is higher than the stenciled tank height.

2. Suspend the cupcase thermometer, if used, at the midpoint of the tank. 3. Take an upper sample for S&W testing (see “Procedures for Testing Suspended S&W in Lease Tanks by the Field Centrifuge Method” in Chapter 5, “Testing Crude Oil for Suspended Sediment and Water”). •

Use clean, dry equipment.

•

Cock the valve at the bottom of the thief in the open position and trip the hook in the eye of the trip rod.

•

Lower the thief to just below the surface of the liquid.

•

Jerk the cord sharply to close the bottom valve on the thief and trap the sample.

•

Pull the thief to the surface.

•

Pour about 6 inches of the liquid in the thief back into the tank.

•

Pour the sample into a small, clean sample container until it is about 3/4 full. Cap the sample container, wipe it clean, and label the sample. Put it into a compartment in your tool box.

•

If you are compositing samples, measure out the proper amount of sample into a graduated cylinder and put it in the sample container.

•

Pour the remaining liquid back into the tank.

4. Take and test the middle sample for API gravity (see Chapter 2, “Gravity and Temperature Measurement in Tanks” for details of testing). •

Hang the thief containing the sample on the inside of the gauge hatch.

•

Determine the API gravity of the oil.

•

Pour the remaining liquid back into the tank.

5. Follow the same procedures as under step 1 above to take a lower sample just above the suction line and test it for suspended S&W (see “Procedures for Testing Suspended S&W in Lease Tanks by the Field Centrifuge Method” in Chapter 5, “Testing Crude Oil for Suspended Sediment and Water”).

Gauging Lease Tanks

September 2002

3.7

BP Pipelines


6. Take an outlet/clearance sample (tank bottoms) to determine the level of settled S&W (see Figure 3.2). •

Adjust the trip rod so that it will trip the thief shut when it is bumped on the tank bottom (normally at 4 inches).

•

Slowly lower the thief through the liquid and S&W until it touches the bottom of the tank.

•

Let the thief rest on the bottom to allow the S&W to reach its natural level inside the thief. Do not use a pumping motion to force the thief through the S&W. (The length of time depends on the type and temperature of S&W.)

•

Raise and trip the thief to trap an S&W sample.

•

Make sure the distance between the tank bottoms and the bottom of the P/L connection is greater than 4 inches.

Gauging Lease Tanks

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BP Pipelines


Notes: 1. If there is more S&W in the tank at closing, tank settling time before run was too short (2-hour minimum recommended).

Thief 15 14

2. If there is less S&W in the tank at closing, the balance has likely been pumped into the pipeline.

13 12

Tube

11 10 9 8 7 6 5 4 3

Depth of S&W in tank

2

Trip rod "Tank stop" outlet valve

Tank contents Tank bottoms

Distance between tank bottoms and bottom of P/L connection must be greater than 4 inches

Figure 3.2. Checking the depth of settled S&W in the tank 7. Take the opening gauge to the nearest 1/4 inch. Two consecutive readings must be the same before recording the opening gauge on the measurement ticket (see Figure 3.3). •

If necessary, apply a thin coat of water-indicating paste to the bob to read the free-water level.

•

Hold the gauge line over the hatch and allow the plumb bob to sink through the oil.

Gauging Lease Tanks

September 2002

3.9

BP Pipelines


•

Be sure to keep the gauge tape in contact with the edge of the hatch to prevent dangerous sparking as the plumb bob enters the fluid. If the tape has a grounding wire, attach it to the tank.

•

Allow the plumb bob to penetrate the oil and S&W until it touches the tank bottom or datum plate. Don’t let the bob tilt. (Use the known gauge height to estimate when the bob should reach bottom.)

•

Always take the gauge reading from the same location or reference point on the hatch so the bob hits the same point on the tank bottom or datum plate. Using the same reference point for each gauging ensures a comparable gauge reading each time, even if the tank bottom is sloped.

•

When using a water-indicating paste, leave the tape and bob in the liquid long enough for the paste to react with the water (usually 30 to 60 seconds). Slowly reel in the tape and stop when you see where the oil has wet the tape.

•

Read and record the measured liquid level and free-water level.

•

To verify the measurement, wipe off about 2 feet of the oil-wetted tape and lower the tape again, repeating the procedures under step 6 until you get two consecutive readings that agree.

•

When you have completed the opening gauge, clean the gauge tape and bob thoroughly before putting it away.

Gauge tape Reference point

11

12

Tape cut

10

Liquid level

9

Tape

Gauge hatch

Reference height 6

Innage

5

Innage bob

Innage bob

4

Datum plate

3 2 1

Zero point

Innage Method

Figure 3.3. Innage method of gauging

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8. Determine the temperature of the oil in the tank (see Chapter 2, “Gravity and Temperature Measurement in Tanks” for details). 9. Record all of your readings. 10. Seal the equalizer and fill lines. 11. Test the top and outlet samples for suspended S&W (see Chapter 5, “Testing Crude Oil for Suspended Sediment and Water” for details). 12. Accept or reject the oil. 13. If accepted, run the tank. •

Break the seal on the tank stop valve to the pipeline and remove it. Enter the number of the “Off Seal” on the ticket.

•

Slowly open the tank stop valve. If the lease requires a pump to inject the oil into the pipeline, set the proper time on the pump’s time clock and start the pump.

Closing Gauge After the oil has been transferred, follow these steps for taking the closing gauge: 1. Before taking the closing gauge, inspect the tank: •

Close and seal the tank stop valve. Record the seal number.

•

Inspect the pipeline, tank connections, seams, and the ground around the bottom of the tank for leaks or distortions.

•

Check all seals that were put on when the tank was run for tampering.

•

Make sure the seal numbers match the seal numbers written on the ticket.

•

Make sure that the ladders and catwalk are safe.

•

Check the tank and lease numbers stenciled on the tank to be sure you are turning off the correct tank.

•


•

Open the hatch using all safety precautions, including an approved breathing apparatus if H2S is a potential hazard.

•

Use a mirror to reflect light into the tank. Check for any buildup of sediment or encrustations above the level of the remaining oil in the tank. If excessive buildup is present, ask the producer to clean the tank.

2. Determine the temperature of the oil remaining in the tank (see Chapter 2, “Gravity and Temperature Measurement in Tanks” for details). 3. Gauge the height of the remaining oil and free water (repeat the same steps as under step 6 of “Opening Gauge”).

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4. Measure the depth of the settled S&W in the tank with a thief (see Chapter 1, “Manual Sampling in Tanks” for details). The depth of the tank bottoms should remain about the same before and after the tank is run. •

If the settled S&W in the tank is deeper at closing than at opening, you did not allow the tank to settle long enough before running it (a minimum of 2 hours).

•

If the settled S&W is lower after you shut the tank off, some of it has most likely moved down the pipeline. Check around the tank for temporary gas rolling lines. If the tank was rolled while the tank was running, excessive S&W may have entered the pipeline. Report this to your supervisor.

If you are satisfied with the closing gauge: 5. Break all the seals you placed on the tank. Don’t break any seals put on by other parties. 6. Make sure that all proper information is on the run ticket before obtaining the witness signature. 7. Sign the ticket printed from the SMART program and include the name of the producer’s representative (witness).

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More About It To calculate the volume of transferred crude, use the opening and closing gauge readings, temperature, gravity, and S&W readings you have taken. You will also need a tank capacity table for the specific tank you measured and tables for volume correction.

Summary of Calculations for Determining Net Standard Volume First, match the liquid height to the same height in that tank’s capacity table to obtain the Total Observed Volume (TOV). Subtract the volume of free water or tank bottoms (CFW), if any. This calculation gives the Gross Observed Volume (GOV). GOV = TOV – CFW Multiply the GOV by the Correction for Temperature of the Liquid (CTL), also known as the Volume Correction Factor (VCF). This value, which is determined from API Table 5B for crude oil, represents the volume at the standard temperature (60°F), which is the Gross Standard Volume (GSV). GSV = GOV × CTL Convert the percentage of any suspended sediment and water to the Correction for Sediment and Water (CSW). % S&W CSW = 1 – -------------------100 Finally, multiply GSV by CSW to obtain NSV. Round NSV to the nearest 0.01 barrel. NSV = GSV × CSW

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Reference Documents 1. API Manual of Petroleum Measurement Standards, Chapter 3.1A “Standard Practice for the Manual Gauging of Petroleum and Petroleum Products” 2. API Manual of Petroleum Measurement Standards, Chapter 7 “Temperature Determination” 3. API Manual of Petroleum Measurement Standards, Chapter 11.1, Volume I, Table 5A “Generalized Crude Oils – Correction of Observed API Gravity to API Gravity at 60ºF” 4. API Manual of Petroleum Measurement Standards, Chapter 11.1, Volume I, Table 6A “Generalized Crude Oils – Correction of Volume to 60ºF Against API Gravity at 60ºF” 5. API Manual of Petroleum Measurement Standards, Chapter 12.1 “Calculation of Static Petroleum Quantities, Part 1 – Upright Cylindrical Tanks and Marine Vessels” 6. API Manual of Petroleum Measurement Standards, Chapter 18.1 “Measurement Procedures for Crude Oil Gathered from Small Tanks by Truck” 7. Pipelines (NA) Business Unit Safety Manual

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Chapter 4

Gauging Large Tanks Quick Reference Safety


•

Do not smoke during gauging.

•

Ground your bare hands and equipment before gauging.


•

Keep the gauge tape in contact with the hatch while gauging to prevent sparking.

2. Take appropriate samples (Chapter 1).

•


3. Gauge the height of the liquid in the tank (Chapter 3 and Chapter 4).

•

Check the condition of the ladder and catwalk before gauging.

•

Determine whether you need to take precautions for H2S before gauging.

•

Never gauge during an electrical storm.

•

Do not climb onto a floating roof if ◊ liquid is being pumped into or out of the tank, ◊ the tank mixer is running, ◊ the roof is leaking or the floating roof seal is leaking, or ◊ local regulations prohibit it.

•

When the floating roof is more than 4 feet below the shell top, a second person using a self-contained breathing apparatus must be standing on the platform while the first person is working from the floating roof.

•

Follow OSHA’s confined space regulations.

•


•


BP Pipelines

September 2002

4. Determine the level of free water and/or sediment on the bottom of the tank (Chapter 5). 5. Determine the temperature of the tank – either with a cupcase thermometer or with a portable electronic thermometer (PET) (Chapter 2). 6. Analyze the samples as required for the specific type of transaction and product (Chapter 2, Chapter 5, Chapter 6). 7. Record all results (Chapter 17).


Scope This chapter describes the procedures for measuring the level of crude oil or liquid petroleum products in upright cylindrical tanks with a capacity of more than 1,000 barrels with fixed or floating roofs. Tank gauges may be used for inventory or custody transfer purposes, but the preferred method is to use meters for custody transfer.

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• Sample heater


• Centrifuge












• Pliers




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BP Pipelines


Introduction This chapter includes the procedures for taking gauges of a large-volume tank.

Equipment You Will Need for Gauging This is the equipment you need to gauge the height of the crude oil in a tank: •

Steel gauge tape and bob

•

Thief

•

Thermometer – PET or cupcase

•

Thermohydrometer

•

Centrifuge tubes

•

Water-indicating paste

•

Seals for securing all pipeline connections

•

Side cutters for cutting and removing tank seals

•

Carrying case for all gauging equipment

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Procedures To gauge large tanks with internal or external floating roofs, follow the guidelines below for safety and accuracy.

Sampling in Large Tanks versus Lease Tanks Manual sampling of large tanks differs from sampling of lease tanks in the following ways: 1. In a large tank, take the sample from the middle of the top third of the liquid. 2. Take the middle sample in the middle of the tank. 3. Take the bottom sample from the middle of the bottom third of the liquid.

Gauging Tanks with an External Floating Roof You can gauge an external floating roof tank from the platform or from the floating roof. If gauging from the roof, you must use the innage method. Since the roof of an external floating roof tank is classified as a confined space, you must follow all appropriate safety procedures.

Gauge tape

Seal (typical) Gauge tube

Floating roof

Innage bob

Roof support (typical)

Datum plate

Figure 4.1. Gauging an external floating roof tank from the platform

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Gauge tape Seal (typical) Gauge tube

Floating roof

Innage bob

Roof support (typical)

Datum plate

Figure 4.2. Gauging an external floating roof tank from the floating roof To get an accurate reading, follow these precautions: •

For both the opening and closing gauges, the roof must be either floating freely or fully supported. For example, do not take the opening gauge while the roof is floating or the closing gauge while the roof is partly or completely resting on the bottom.

•

If the roof is not floating, its legs must be resting directly on the tank bottom, not on the settled S&W.

•

Do not gauge the tank for custody transfer if the roof is in the “critical zone” (the vertical range in which the level of the stored oil is high enough to lift a tank’s floating roof off the tank floor but too low to make the entire roof float freely in a level position).

•

The leg settings must match the settings listed on the tank table.

•

The roof must be free of ice, snow, water, dirt, and scale.

•

If possible, do not gauge on windy days.

•

If the gauges will be used for custody transfer, the tank must have a recent tank calibration table calculated in accordance with API standards.

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Gauging Tanks with an Internal Floating Roof You must use the innage method when gauging an internal floating roof tank.

Gauge tape Hatch

Seal (typical) Gauge tube

Floating roof Roof support (typical)

Innage bob Datum plate

Figure 4.3. Gauging an internal floating roof tank To get an accurate reading, follow these precautions: •

Since an internal floating roof is lighter than an external floating roof, the oil will continue to move longer than in an external floating roof tank. Therefore, leave plenty of settling time.

•

The roof must be either floating freely or fully supported for both gauges. For example, do not take the opening gauge while the roof is floating or the closing gauge while the roof is partly or completely resting on the bottom.

•

If the roof is at rest, it must be resting directly on the tank bottom, not on the settled S&W.

•

Do not gauge the tank for custody transfer if the roof is in the “critical zone” (the vertical range in which the level of the stored oil is high enough to lift a tank’s floating roof off the tank floor but too low to make the entire roof float freely in a level position).

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Procedures for Gauging by the Innage Method The innage method of gauging directly measures the height of the liquid with a tape and bob that extend to the bottom of the tank. First assure that the conditions are safe, as listed under “Safety” on the Quick Reference page. If you find any unsafe conditions or if the security of the tank has been compromised, do not gauge the tank and report these conditions to your supervisor.

Opening Gauge If the conditions are safe, gauge the tank as follows: 1. Before taking the opening gauge, inspect the tank (see Figure 4.4): •

Check the tank and valves for leaks or distortions.

•

Check all bottom and side valves to make sure they are closed.

•

Make sure the ladders and catwalk are safe.

•

Check the tank number stenciled on the tank.

•


•

Open the hatch using all safety precautions. Wear an approved breathing apparatus if H2S is a potential hazard.

Hatch

Liquid surface— no foaming or boiling

Tank stop valve

Liquid level— no greater than maximum fill height

If tank has mixer, turn mixer off at least 2 hours before gauging the tank

Tank 201 Tank Ht. xx P/L conn. Ht. xx Verify

Figure 4.4. Checking the tank before gauging

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Safety Reminder Do not gauge the tank if: •

The liquid’s surface is foaming or boiling.

•

The liquid level is higher than the stenciled tank height.

2. Suspend the cupcase thermometer, if used, at the midpoint of the tank. 3. Sample the liquid. The number and location of samples depends on the level of oil in the tank (see Chapter 1, “Manual Sampling in Tanks” for details). 4. Take the opening gauge to the nearest 1/8 inch. Two consecutive readings must be the same before recording the opening gauge on the measurement ticket (see Figure 4.5). •

Apply a thin coat of water-indicating paste to the bob to read the free-water level.

•

If necessary, apply a thin coat of a gasoline-indicating paste to the tape (product tanks).

•

Hold the gauge line over the hatch and allow the plumb bob to sink through the liquid.

•

Be sure to keep the gauge tape in contact with the edge of the hatch to prevent dangerous sparking as the plumb bob enters the fluid. If the tape has a grounding wire, attach it to the tank.

•

Allow the plumb bob to penetrate the liquid and S&W until it touches the tank bottom or datum plate. Don’t let the bob tilt. (Use the known gauge height to estimate when the bob should reach bottom.)

•

Read the tape at the reference point. ◊ Compare this reading to the reference gauge height (which should be indicated on the top of the tank). ◊ A difference of more than 1/2 inch could indicate that the bob has not reached the bottom or datum plate.

•

Always take the gauge reading from the same location or reference point on the hatch so the bob hits the same point on the tank bottom or datum plate. Using the same reference point for each gauging ensures a comparable gauge reading each time, even if the tank bottom is sloped.

•

If the tank does not have an indicated reference gauge point, gauge opposite the gauge hatch hinge.

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•

When using a water-indicating paste or gasoline-indicating paste, leave the tape and bob in the liquid long enough for the paste to react with the water (usually 30 to 60 seconds). Slowly reel in the tape and stop when you see where the oil has wet the tape.

•

Read and record the measured liquid level and free-water level.

•

To verify the measurement, wipe off about 2 feet of the wetted tape and lower the tape again, repeating the procedure above. Repeat the procedure until you get two consecutive readings that agree.

•

When you have completed the opening gauge, clean the gauge tape and bob thoroughly before putting it away.

Gauge tape Reference point

11

12

Tape cut

10

Liquid level

9

Tape

Gauge hatch

Reference height 6

Innage

5

Innage bob

Innage bob

4

Datum plate

3 2 1

Zero point

Innage Method

Figure 4.5. Innage method of gauging 5. Determine the temperature of the liquid in the tank (see Chapter 2, “Gravity and Temperature Measurement in Tanks” for details). •

For custody transfer, the use of a portable electronic thermometer (PET) is preferred.

•

Take the recommended number of temperature readings (see Chapter 2, “Gravity and Temperature Measurement in Tanks” for details).

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◊ For greater than 10 feet of product, take 3 temperatures — middle of the upper, middle, and lower thirds of the liquid level. ◊ For less than 10 feet of product, take 1 temperature in the middle of the liquid level. •

Read a PET to the nearest 0.1ºF, or read a cupcase thermometer to the nearest 0.5ºF.

•

If you have taken multiple temperature readings, average the readings to the nearest 0.1ºF.

6. Record all of your readings. 7. Test the samples for suspended S&W (see Chapter 5, “Testing Crude Oil for Suspended Sediment and Water” for details).

Closing Gauge After the liquid has been transferred, follow these steps for taking the closing gauge: 1. Before taking the closing gauge, inspect the tank: •

Close the tank isolation valve.

•

Inspect the pipeline, tank connections, seams, and the ground around the bottom of the tank for leaks or distortions.

•

Make sure that the ladders and catwalk are safe.

•

Check the tank number stenciled on the tank to be sure you are turning off the correct tank.

•

Ground yourself before climbing on the tank. Be especially cautious on dry days, since the charge of static electrical sparks is greater in low humidity.

•

Open the hatch using all safety precautions, including an approved breathing apparatus if H2S is a potential hazard.

2. Sample the liquid remaining in the tank (see Chapter 2, “Gravity and Temperature Measurement in Tanks” for details). 3. Gauge the height of the remaining liquid and free water (repeat the same steps as under step 4 of “Opening Gauge”). If you are satisfied with the closing gauge: 4. Make sure that all proper information is on the measurement ticket before obtaining the witness signature. 5. If the gauging was for custody transfer, sign the ticket printed from the SMART program and include the name of the producer’s representative (witness).

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Determining and Reporting Inventory Tanks will be gauged and the inventory reported monthly. An annual inventory report will be included in the inventory ticket that closes October 1 at 7:00 a.m.

Monthly Inventory and Reporting To effectively monitor fixed loss allowance, reconcile book to physical inventory, and maintain accurate “gain/loss” metrics, BP Pipelines field specialists will report tank inventories on a monthly basis. To do this, they will insert the appropriate information in the designated fields on the tank inventory tickets located under the non-custody tab of the Measurement Management Module of SMART.

Monthly Procedure 1. Grade •

Select appropriate grade from pull-down list.

•

Verify with Tulsa Control Center (TCC) if necessary.

2. Preferred gauging option •

Handline gauge at 7:00 a.m. on the first of the month per this chapter of the Measurement Manual for Crude and Petroleum Products.

•

Tanks inactive at 7:00 a.m. may be gauged either before or after 7:00 a.m. if no activity occurs between 7:00 a.m. and the time the tank is gauged.

3. Sideline gauge option •

Record sideline gauge reading taken at 7:00 a.m.

•

Tanks inactive at 7:00 a.m. may be gauged either before or after 7:00 a.m. if no activity occurs between 7:00 a.m. and the time the tank is gauged.

•

This option is only acceptable if appropriate maintenance activities on tank gauging hardware have been performed prior to month end with necessary calibrations made.

•

In extenuating circumstances, an adjustment can be made to the sideline gauge reading if recalibration could not be completed on a timely basis (note this in the Remarks field of the SMART ticket).

•

Recalibration is necessary if the sideline gauge and handline gauge vary by more than 1 inch.

4. Temperature options, in order of preference •

Take temperature while handline gauging at 7:00 a.m. on the first of the month in accordance with Chapter 2, “Gravity and Temperature Measurement in Tanks” of the Measurement Manual for Crude and Petroleum Products.

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•

Record and report a temperature taken while performing tank gauging maintenance activities prior to month end, if the tank has been inactive since the hand gauging.

•

For a tank inactive over the entire month, it may be acceptable (if noted in the Remarks field) to use the prior month’s gauge and temperature readings.

5. Tank bottom S&W level •

SMART will automatically fill in this field with a default value acquired from the corresponding tank screen in the SMART Reference Module. This value is updated every October as part of the annual inventory procedure.

•

If significant amounts of free water are placed or identified in a tank, a monthly entry in SMART Operations (not SMART Mobile) will be required to override the default value (also note this in the Remarks field of the SMART ticket).

•

If tank cleaning is completed during the month, an entry will be required to override the default value (also note this in the Remarks field of the SMART ticket), and the corresponding tank screen in the SMART Reference Module must be updated.

6. Observables —crude sampling options in order of preference •

Sample and analyze crude oil from each tank on the first of the month in accordance with Chapter 2, “Gravity and Temperature Measurement in Tanks” and Chapter 5, “Testing Crude Oil for Suspended Sediment and Water” of the Measurement Manual for Crude and Petroleum Products.

•

Sample and analyze crude oil for each grade on site near the end of the month.

•

In sampling and analyzing crude oil, follow all safety advisories specified in Chapter 1, Chapter 2, and Chapter 4 of the BP Pipelines Measurement Manual for Crude and Petroleum Products.

Annual Inventory and Reporting To effectively monitor fixed loss allowance, reconcile book to physical inventory, maintain accurate “gain/loss” metrics, and comply with generally accepted accounting principles, BP Pipelines field specialists will be responsible for conducting a complete physical inventory of all BP Pipelines-owned and -operated tanks each year. This information will be reported as part of the September SMART tank inventory ticket, which closes on October 1 at 7:00 a.m. The appropriate information will be inserted in the designated fields on the tank inventory tickets located under the non-custody tab of the Measurement Management Module of SMART. A designated person(s) in each core team will be responsible for annually updating the “Sediment and Water Level” on the appropriate Tank Maintenance screen in the SMART Reference Module.

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Notification On or before September 1 of each year, the BP Pipelines Measurement Team will issue a formal advisory to each BP Pipelines core team leader of the mandatory physical tank inventory, which occurs on October 1.

Annual Procedure 1. Grade •

Select appropriate grade from pull-down list.

•

Verify with TCC, if necessary.

2. Gauging •

Designated tanks will be handline gauged at 7:00 a.m. on October 1st in accordance with this chapter of the Measurement Manual for Crude and Petroleum Products.

•

Tanks not gauged at 7:00 a.m. can be gauged either before or after 7:00 a.m. However, these tanks must remain inactive between the time of gauging and 7:00 a.m. (before) or 7:00 a.m. and the time of gauging (after). Exceptions to this requirement must be approved by TCC.

•

Appropriate maintenance personnel are to be advised of any variances between the handline gauge, sideline gauge, and/or SCADA that exceed 1 inch.

•

Field specialists must “zero out” empty tanks that have been taken out of service.

•

Maintenance personnel will issue written confirmation when the cause of these variances has been corrected.

3. Temperature •

While handline gauging, take and record crude oil temperatures in accordance with Chapter 2, “Gravity and Temperature Measurement in Tanks” of the Measurement Manual for Crude and Petroleum Products.

4. Tank bottom S&W level •

The depth of sediment and water at the bottom of each tank must be measured using a thief in accordance with Chapter 1, “Manual Sampling in Tanks” of the Measurement Manual for Crude and Petroleum Products.

•

The new tank bottom S&W levels must be updated in the appropriate field on all tank inventory tickets with an October 1 close date.

•

Prior to the next close date, a designated field specialist(s) must update the S&W level on the corresponding tank screen in the SMART Reference Module. Subsequent months will automatically default to this value unless otherwise handled.

•

If possible, the S&W level obtained for the annual inventory should be used on the

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monthly inventory report dated October 1 (September’s closing inventory). 5. Observables — crude sampling and analysis •

Sample and analyze crude oil from each tank in accordance with Chapter 2, “Gravity and Temperature Measurement in Tanks” and Chapter 5, “Testing Crude Oil for Suspended Sediment and Water” of the Measurement Manual for Crude and Petroleum Products. Insert sample gravity, sample temperature, and S&W percent in the appropriate fields on the monthly tank inventory tickets.

•

Unless a more frequent sampling program is in place, insert the annually determined values as monthly observables.

•

Exceptions need to be made in a month when very wet crudes are suspected.

•

In sampling and analyzing crude oil, follow all safety advisories specified in Chapter 1, Chapter 2, and Chapter 4 of the Measurement Manual for Crude and Petroleum Products.

6. Remarks •

To differentiate this monthly tank ticket from other months, it is essential that the responsible field specialist type “Annual Physical Inventory” and his/her name in the Remarks field.

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More About It To calculate the volume of transferred liquid, use the opening and closing gauge readings, temperature, gravity, and S&W readings you have taken. You will also need a tank capacity table for the specific tank you measured and tables for volume correction.

Summary of Calculations for Determining Net Standard Volume First, match the liquid height to the same height in that tank’s capacity table to obtain the Total Observed Volume (TOV). Subtract the volume of free water or tank bottoms (CFW), if any. This calculation gives the Gross Observed Volume (GOV). GOV = TOV – CFW Multiply the GOV by the Correction for Temperature of the Liquid (CTL), also known as the Volume Correction Factor (VCF). This value, which is determined from API Table 5B for crude oil, represents the volume at the standard temperature (60°F), which is the Gross Standard Volume (GSV). GSV = GOV × CTL Convert the percentage of any suspended sediment and water to the Correction for Sediment and Water (CSW). % S&W CSW = 1 – -------------------100 Finally, multiply GSV by CSW to obtain NSV. Round NSV to the nearest 0.01 barrel. NSV = GSV × CSW

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Reference Documents 1. API Manual of Petroleum Measurement Standards, Chapter 3.1A “Standard Practice for the Manual Gauging of Petroleum and Petroleum Products” 2. API Manual of Petroleum Measurement Standards, Chapter 7 “Temperature Determination” 3. API Manual of Petroleum Measurement Standards, Chapter 11.1, Volume I, Table 5A “Generalized Crude Oils – Correction of Observed API Gravity to API Gravity at 60ºF” 4. API Manual of Petroleum Measurement Standards, Chapter 11.1, Volume I, Table 6A “Generalized Crude Oils – Correction of Volume to 60ºF Against API Gravity at 60ºF” 5. API Manual of Petroleum Measurement Standards, Chapter 12.1 “Calculation of Static Petroleum Quantities, Part 1 – Upright Cylindrical Tanks and Marine Vessels” 6. API Manual of Petroleum Measurement Standards, Chapter 18.1 “Measurement Procedures for Crude Oil Gathered from Small Tanks by Truck” 7. Pipelines (NA) Business Unit Safety Manual

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Chapter 5

Testing Crude Oil for Suspended Sediment and Water Quick Reference Safety •

Stopper centrifuge tubes securely and keep them away from your face when mixing samples.

•

Always balance the centrifuge before spinning by placing filled centrifuge tubes in opposite trunnion cups.

•

Know the safety and health risks of chemicals used for testing. Xylene and toluene, for example, are extremely flammable and toxic to the skin, eyes, and lungs. ◊

Do not handle chemicals with bare hands or breathe the vapors. Wear gloves and use a respirator.

◊

Keep chemicals away from the mouth.

◊

Keep chemical containers closed when you are not using them.

◊

Keep your work area clean and well-ventilated.

◊

Clean up spills promptly.

•


•


Scope This chapter includes the procedures for determining the amount of sediment and water suspended in crude oil.

Summary of Field Centrifuge Method •

Use certified or verified 100-ml centrifuge tubes.

•

Use water-saturated toluene at 140°F as a solvent.

•

Use a demulsifier solution if the crude oil you are testing requires it.

•

Heat samples to 140 ± 5°F. (Some samples may need to be heated higher.)

•

Spin the samples in the centrifuge for at least 5 minutes and repeat until results are duplicated.

•

In most areas, the maximum acceptable total S&W is 1% (maximum acceptable free water is 0.3%).

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September 2002


Exceptions •

Heat samples to greater than 140°F if the crude is waxy or paraffinic (with your supervisor’s approval).

•

In locations where the free-water content is greater than 0.3%, you may only extend the allowable free water if the total S&W content remains below 1.0% and you get your supervisor’s approval before doing so.

•

In Texas, New Mexico, and Louisiana, the total allowable S&W content is 1.0%. You may have free water up to 1.0% if no sediment is present.

•

You may use other solvents (Stoddard solvent, Varsol, etc.) instead of toluene, if it can be shown that they produce the same results.

Summary of Karl Fischer Titration •

Prepare the Karl Fischer (KF) titration unit: ◊

Add anode solution.

◊

Add cathode solution.

◊

Assemble all parts of the titrator, sealing all joints with the appropriate grease.

•

Start the titrator and allow it to titrate any moisture in the titrator.

•

Homogenize the sample.

•

Inject a measured amount of sample (usually 1.0 ml or less) into the titrator.

•

When the instrument indicates that the titration is completed (usually less than 1 minute), record the water content indicated on the digital display.

•

Analyze a second, duplicate sample and average the results. The two results must agree within 0.01%. If they do not agree, run additional samples until the results do agree.

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BP Pipelines


Introduction You may test for suspended S&W by one of two methods that use a centrifuge, the field method or the laboratory method. Another test method is the Karl Fischer test for suspended water content. The amount of sediment and water in crude oil is important because the buyer pays only for the crude and subtracts the S&W content from the total volume.

Equipment You Will Need for Determining S&W •

Upper and lower samples from a small tank or

•

Individual samples or a composite sample made from all samples from a large tank (see Chapter 1, “Manual Sampling in Tanks”) and

•

Sample containers (for storing samples)

•

If using the field centrifuge method:

•

•

◊

Two certified or verified 6-inch, 100-ml centrifuge tubes

◊

Diluent — water-saturated toluene or Stoddard solvent

◊

Demulsifier solution

◊

Sample heater

◊

Bimetal pocket thermometer

◊

Centrifuge

If using the laboratory centrifuge method: ◊

Two certified or verified 8-inch centrifuge tubes

◊

Water-saturated toluene as the diluent

◊

Demulsifier solution

◊

Sample heater

◊

Bimetal pocket thermometer

◊

Centrifuge

If using the Karl Fischer titration method: ◊

Nonaerating, high-speed shear mixer

◊

Clean glass syringes

◊

Karl Fischer reagents — anode solution and cathode solution

◊

Karl Fischer check solution

◊

Karl Fischer titrator

Testing Crude Oil for Suspended Sediment and Water September 2002

5.3

BP Pipelines


Procedures Before beginning, you must prepare the water-saturated toluene and demulsifier solution.

Procedure for Preparing Water-Saturated Toluene Use the following equipment and reagents: •

A liquid bath deep enough to immerse a 1-quart bottle to its shoulder and a means to maintain the temperature at 140 ± 5°F.

•

A 1-quart glass bottle with a screw top

•

Toluene that meets the standard of ASTM D-362 or IP Specification for Toluol.

•

Distilled or tap water

Follow these steps to water-saturate the toluene: 1. Adjust the heating bath to 140 ± 5°F. 2. Fill the bottle with 700 to 800 milliliters of toluene. Add 25 ml of water. Screw on the cap and shake vigorously for 30 seconds. 3. Loosen the cap and place the bottle in the bath for 30 minutes. 4. Remove the bottle, tighten the cap, and shake cautiously for 30 seconds. 5. Repeat these steps 3 times.

Procedure for Preparing the Demulsifier Solution To aid in the separation of the water from the crude oil with the centrifuge test, the use of a demulsifier solution is recommended. Tests have shown that DMO-46X, from Baker Petrolite, works best with the wide range of crude oils encountered in the BP Pipelines system. Other demulsifiers may be used, if approved by the Measurement Team. All demulsifiers need to be diluted with solvent before use. Excessive demulsifier may show up after centrifuging as a separate immiscible component in the bottom of the tube and may be misinterpreted as water, overstating the S&W. Preparing the demulsifier solution: 1. Using a centrifuge tube to measure, pour 5 mL of DMO-46X into a dark glass dropper bottle (approximately 35 mL capacity). 2. Then measure 20 mL of solvent (toluene or xylene) into the centrifuge tube, and pour this into the dropper bottle. 3. Shake the dropper bottle.


5.4

BP Pipelines


4. Write the date on the dropper bottle. 5. The mixed solution should be replaced on an annual basis. The pure DMO-46X should be replaced every two years. Using the demulsifier solution: 1. Shake the dropper bottle before each use. 2. Add one or two drops (with a maximum of four drops) to the centrifuge tube after the solvent is added to the tube. Excessive demulsifier may show up after centrifuging as a separate immiscible component in the bottom of the tube and may be misinterpreted as water, overstating the S&W.

Procedures for Preparing the Sample To a clean 100-ml centrifuge tube: 1. Add about 2 ml of water. 2. Fill the centrifuge tube to the 100-ml mark with toluene. 3. Add one or two drops of demulsfier solution. 4. Secure the stopper and shake the tube to mix. 5. Loosen the stopper and heat the tube in the sample heater to 140 ± 5°F (about 30 minutes). 6. Secure the stopper and shake the tube again to mix. 7. Allow free water to settle to the bottom of the tube (Figure 5.1). If no free water settles out, add more water and repeat steps 3, 4, and 5. 8. Pour off toluene from the top half of the tube for S&W tests. Notes: •

You must maintain the water-saturated toluene at 140 ± 5°F or it will not remain saturated.

•

Do not pour any of the free water into the centrifuge tubes used in the test.

•

Some locations may use another solvent, such as Stoddard solvent, which does not need to be water-saturated. However, BP Pipelines’ preferred solvent is water-saturated toluene.


5.5

BP Pipelines


Water-Saturated Toluene

100 ml Toluene

Free water

Figure 5.1. Free water in the bottom of centrifuge tube when preparing water-saturated toluene

0.200

Volume Percent

0.175 0.150 0.125 0.100 0.075 0.050 0.025

20

40

60

80

100

120

140

160

Temperature ºF

Figure 5.2. Solubility of water in toluene


5.6

BP Pipelines


Procedures for Testing Suspended S&W in Lease Tanks by the Field Centrifuge Method These procedures apply to the upper and lower samples from lease tanks. You will use 100-ml centrifuge tubes (Figure 5.3). Some companies use 200-part centrifuge tubes, but BP Pipelines prefers 100-ml tubes. If you encounter 200-part tubes, contact the Measurement Team for training on how to use and read these tubes. 1. Fill one centrifuge tube with exactly 50 milliliters of the upper sample. Fill another centrifuge tube with 50 milliliters of the lower sample. 2. Fill each tube with solvent to the 100-ml mark. 3. Add a few drops of demulsifier solution, if needed. 4. Stopper the tubes tightly and invert them 10 times to mix the sample and solvent. 5. Loosen the stoppers and immerse the tubes in a sample heater. Heat the samples to 140 ± 5°F. 6. Stopper the tubes tightly and turn them over 10 times. 7. Put the tubes in the centrifuge and spin for at least 5 minutes. Note: Make sure the tubes are balanced in the centrifuge. 8. Immediately after the centrifuge comes to rest, use a sample thermometer to verify that the sample temperature is 125ºF or above. •

If the temperature is 125ºF or above, continue to the next step.

•

If the temperature is below 125ºF, repeat step 4, raise the temperature of the sample higher than it was the first time, and continue with steps 5–7.

9. Record the volume of water and sediment in each tube. These amounts will not necessarily agree. Add the readings from the two tubes and report this sum as the percentage of S&W. 10. Multiply the reading for the top tube by 2; then multiply the reading for the bottom tube by 2. Record these values. 11. If any of these readings (top plus bottom, top times 2, or bottom times 2) is greater than 0.3% (1.0% in Texas, New Mexico, and Louisiana), reject the tank. Note: The test is valid only if you see a clear separation between the oil and water layers. No emulsion should be present above the oil/water interface. If present, see the Exception, below. Exception If an identifiable emulsion layer is present immediately above the oil/water interface: •

Shake the mixture just enough to disperse the emulsion, and repeat the test.


5.7

BP Pipelines


•

Use a different demulsifier or an increased amount of demulsifier. (The demulsifier should not, however, contribute to the volume of sediment and water.)

•

Use a different solvent.

After a satisfactory procedure for a particular type of oil has been developed, it will normally be suitable for all samples of the same crude oil.

Procedures for Testing Suspended S&W in Samples from Large Tanks and Automatic Samplers by the Field Centrifuge Method Samples from large tanks and from automatic sampling systems are normally tested for suspended S&W by the field centrifuge method. These procedures apply to 100-milliliter centrifuge tubes (Figure 5.3). Some companies use 200-part centrifuge tubes, but BP Pipelines prefers 100-ml tubes. If you encounter 200-part tubes, contact the Measurement Team for training on how to use and read these tubes. 1. Fill each of two centrifuge tubes with exactly 50 milliliters of one of the samples. 2. Fill each tube with solvent to the 100-ml mark. 3. Add a few drops of demulsifier solution, if needed. 4. Stopper the tubes tightly and invert them 10 times to mix the sample and solvent. 5. Loosen the stoppers and immerse the tubes in a sample heater. Heat the samples to 140 ± 5°F. 6. Stopper the tubes tightly and turn them over 10 times. 7. Put the tubes in the centrifuge and spin for at least 5 minutes. Note: Make sure the tubes are balanced in the centrifuge. 8. Immediately after the centrifuge comes to rest, use a sample thermometer to verify that the sample temperature is 125ºF or above. •

If the temperature is 125ºF or above, continue to the next step.

•

If the temperature is below 125ºF, repeat step 4, raise the temperature of the sample higher than it was the first time, and continue with steps 5–7.

9. Read and record the volume of water and sediment at the bottom of each tube. 10. Reheat the tubes to the initial spin temperature and return them to the centrifuge. 11. Do not agitate them this time. 12. Spin the tubes for at least 5 minutes more. Read and record the volume of water and sediment at the bottom of each tube.


5.8

BP Pipelines


13. Continue to repeat steps 8 and 9 until two consecutive S&W readings are the same for each tube. •

If the difference between the readings for two tubes of the same sample is more than one subdivision on the tube, the test is invalid and you must repeat it.

Note: The test is valid only if you see a clear separation between the oil and water layers. No emulsion should be present above the oil/water interface. If present, see the Exception, below. 14. Record the final volume of water and sediment in each tube. Add the readings from the two tubes and report this sum as the percentage of S&W. Exception If an identifiable emulsion layer is present immediately above the oil/water interface: •

Shake the mixture between spins in the centrifuge just enough to disperse the emulsion.

•

Use a different demulsifier or an increased amount of demulsifier. (The demulsifier should not, however, contribute to the volume of sediment and water.)

•

Use a different solvent.

After a satisfactory procedure for a particular type of oil has been developed, it will normally be suitable for all samples of the same crude oil.


5.9

BP Pipelines


Shake sample bottle, then pour

Heat to 140ºF

Add toluene to 100 ml

Add liquid sample to 50 ml

Take all readings at top of meniscus

Balance centrifuge, then spin

100-ml Tube

Temperature must remain above 125ºF

2

1.0 ml 0.50 ml

1 0.60 ml

0.25 ml

1/2

0.80 ml X 2 = 1.6 ml

Read S&W

0.30 ml 0.20 ml 0.15 ml 0.10 ml 0.05 ml

0.175 ml X 2 = 0.35 ml Below 0.025 ml read zero

Figure 5.3. Sequence for determining S&W by the field centrifuge method using 100-ml (6-inch) centrifuge tubes


5.10

BP Pipelines


Procedure for Determining Sediment Only by the Field Centrifuge Method Use this test to determine the amount of sediment in a sample. Combine the test result with the amount of water determined by Karl Fischer titration to report the total S&W in a sample. 1. Follow the basic procedure as for the field centrifuge method above. 2. Add about 1 ml (3 to 4 drops) of water to the sample just after adding the demulsifier (step 3 above). The water will improve the interface between the sediment and the water. 3. Read and record only the volume of sediment in each tube. 4. Add the readings together and report the sum as the percentage of sediment in the sample.

Procedures for Testing Suspended S&W by the Laboratory Centrifuge Method The equipment needed for centrifuge testing in a laboratory is similar to that for field testing. The main difference is that the centrifuge tubes are larger — 8 inches tall, but they still hold 100 ml of sample. The procedure is basically the same as for the field centrifuge test. 1. Fill each of two centrifuge tubes to the 50-ml mark with sample from the sample container. 2. Add 50 ml of water-saturated toluene to each tube with a pipette. 3. Add 0.2 ml of demulsifier solution to each tube. 4. Stopper the tubes tightly and turn them over 10 times. 5. Loosen the stoppers and immerse the tubes to the 100-ml mark in a bath at 140 ± 5°F. 6. Stopper the tubes tightly and turn them over 10 times. 7. Put the tubes in trunnion cups on opposite sides of the centrifuge, and spin them for 10 minutes at a minimum relative centrifugal force of 600. 8. Immediately after the centrifuge comes to rest, read and record the combined volume of water and sediment at the bottom of each tube to the nearest 0.05 ml (where the gradations are in 0.1 ml) or to the nearest 0.1 ml. 9. Return the tubes to the centrifuge without agitation and spin for another 10 minutes.


5.11

BP Pipelines


10. Repeat steps 8 and 9 until the combined volume of sediment and water is the same for two consecutive readings. •

If the difference between the 2 readings for the same sample is more than one subdivision on the tube or more than 0.025 ml for readings of 0.10 ml or less, the test is invalid and you must repeat it.

11. Record the final volume of water and sediment in each tube. Add the readings and report this sum as the percentage of S&W.

Procedures for Testing for Water in Crude Oil by Karl Fischer Titration Karl Fischer titration determines water content only. In this method, you will use a test sample of a certain volume taken from the sample you have already collected. Table 5.1 shows how much sample to use, depending on the water content you expect to find in the sample. If you have no idea what the water content is, start with the smallest amount of sample as a test. You may then repeat the titration with a larger amount if needed.

Table 5.1.

Size of Test Sample Based on the Expected Water Content

Expected Water Content

Sample Size, ml

0.005–0.1%

1.0

0.1–0.5%

0.5

0.5–5.0%

0.25

Procedure for Determining the Water Content in Percent by Volume 1. Add the mixture of xylene and Karl Fischer anode solution to the anode (outer) compartment of the titrator to the level recommended by the manufacturer, normally 100 ml. Note: The anode solution normally used by BP Pipelines will already contain the required amount of xylene.


5.12

BP Pipelines


2. Add the Karl Fischer cathode solution to the cathode (inner) compartment to a level 2 to 3 millimeters (1/16 to 1/8 inch) below the level of the solution in the anode compartment, normally 5 ml of solution. Note: The cathode solution normally used by BP Pipelines is supplied in premeasured 5-ml portions. 3. Seal all joints and connections to the titrator with the appropriate grease to prevent moisture in the air from entering. 4. Turn on the titrator and start the magnetic stirrer. Allow the moisture that may be in the titrator to be titrated until the end point is reached. •

Do not continue with testing until the background current or background titration rate is constant.

5. Homogenize (mix) the sample using a nonaerating mixer. During mixing, the temperature of the oil should not increase more than 20ºF, otherwise a loss of water may occur. Note: You may test a sample taken from the circulating system of an automatic sampler receiver without remixing if it you test it within 5 minutes of drawing it from the system. 6. Immediately after mixing, use a clean, dry syringe to withdraw at least 3 samples from the tank sample and discard them. 7. Then withdraw the test sample and expel the excess (see Table 5.1 for amount to leave in the syringe). Note: It is very important to leave exactly the right amount in the syringe and to have no air bubbles in the syringe. •

Minimize the air bubbles by keeping the tip of the needle below the surface of the sample and pulling the sample into the syringe slowly.

•

Before expelling the excess sample, point the syringe up to allow any air to collect in the top and slowly expel it (covering the end of the needle with a cloth or tissue).

8. Clean the needle with a tissue. Record the volume of the sample. Verify that the titrator is set for the same volume of sample. 9. Insert the needle through the inlet port, start the titration, and inject all of the sample into the titration cell. •

Place the tip of the needle just below the surface of the liquid.

10. Take the needle out and wipe it clean. 11. When the titrator reaches the end point, record the percentage of water from the digital readout.


5.13

BP Pipelines


12. Take a second sample and inject it into the titrator after pushing the rest button. •

The two results should agree within 0.01%. If they do not agree, continue testing additional samples until they do agree.

13. Average the two results, rounding to the nearest 0.01%. 14. Every day (or before each test, whichever is longer), verify that the titrator is functioning properly by accurately injecting a very small amount (10 µl) of pure water or an approved check solution.


5.14

BP Pipelines


Reference Documents 1. API Manual of Petroleum Measurement Standards, Chapter 10.3 “Determination of Water and Sediment in Crude Oil by the Centrifuge Method (Laboratory Procedure)” 2. API Manual of Petroleum Measurement Standards, Chapter 10.4 “Determination of Sediment and Water in Crude Oil by the Centrifuge Method (Field Procedure)” 3. API Manual of Petroleum Measurement Standards, Chapter 10.9 “Standard Test Method for Water in Crude Oils by Coulometric Karl Fischer Titration” 4. Pipelines (NA) Business Unit Safety Manual


5.15

Chapter 6

Other Tests for Crude and Products Quick Reference Safety Employees and contractors should be familiar with the hazards of the products and the test instruments associated with the particular test they are performing. Look in ASTM, API, and equipment manufacturers’ manuals for safety precautions. Observe any hazardous material handling precautions stated in the MSDS or on the container of the commodity.

Scope This chapter gives an overview of the procedures for quality testing of crude and products. Most of these tests are done in a nonpipeline laboratory, but some are done on site.

Summary of Tests Crude Oil

Liquid Petroleum Products

•

Sulfur content

•

Reid vapor pressure

•

Mercaptan content

•

•

Organic chloride content

Viscosity, pour point, and cloud point

•

Reid vapor pressure

•

Flash point

•

Metals content

•

Water content and haze

•

Types and amount of light ends

•

Color

•

Hydrogen sulfide content

•

Particulate contamination

•

Viscosity and pour point

•

Corrosion tendency

•

Boiling point range

•

Electrical conductivity

•

Neutralization number

•

Oxygenate content

•

Nitrogen content

•

Dye content

BP Pipelines

September 2002


Introduction Both crude oil and petroleum products are tested for composition and characteristics other than gravity, S&W, and temperature that affect their quality and therefore their value. Since most of these tests are done in a (nonpipeline) laboratory, this chapter contains a general discussion of these tests rather than giving specific procedures. If you do the tests on site, follow local procedures.

BP Pipelines

September 2002


BP Pipelines


Tests for Crude Oil Most tests on crude oil determine what it consists of, including contaminants. Other tests determine purely physical characteristics, such as Reid vapor pressure, viscosity, and pour point.

Sulfur The test method for sulfur (ASTM D-4294) determines total sulfur in a crude oil from all its various forms. Sulfur is primarily present as organic sulfur (attached to hydrocarbon molecules) but can also be present as hydrogen sulfide, mercaptans (see “Mercaptans” below), and inorganic salts (sulfates).

Test Summary The common method used today to test samples for sulfur is by x-ray. A sample of crude oil is placed into a cup with a clear plastic Mylar window at the bottom. The cup is placed into the x-ray instrument and the sample is irradiated with x-rays. The signal received by the detector, coming from the sample, indicates the level of sulfur. The test result is total sulfur in weight percent.

Table 6.1.

Typical Sulfur Levels

Crude Designation

Sulfur Content

Sweet crude

< 0.50 wt%

A crude

0.40 to 0.60 wt%

Light sour

0.60 to 1.30 wt%

Medium sour

Not more than 2.70 wt%

Heavy

Not more than 3.50 wt%

Significance and Refinery Impact The sulfur level of a crude oil is an indicator of its quality as a grade — sweet or sour — and affects its value (see Table 6.1). Sulfur has a significant impact on refinery processing. The refinery needs to accurately know the sulfur level of the crude oil being refined, because of effects on product specifications and the cost of handling sulfur recovered from processing. The expense of refining operations increases drastically with increasing crude sulfur content. The sulfur level indicates how much treatment and removal are needed during the refining process. Refineries

Other Tests for Crude and Products

September 2002

6.3

BP Pipelines


recover sulfur from the refining process to comply with environmental regulations on plant emissions. Many governmental regulations limit the sulfur content of refined products, thus limiting the types of crude oils that some refineries can process. In the case of contamination, increased sulfur levels can jeopardize a refinery’s ability to comply with these regulations. In general, high-sulfur crudes tend to be heavier (lower API gravity).

On-Line and Portable Sulfur Analyzers Some pipeline locations have on-line x-ray sulfur analyzers that help track crude oil sulfur content in real time on the pipeline. This assists with batch cutting and quality monitoring. Several pipeline stations also have portable sulfur analyzers that you can take into the field. This allows stations to quickly determine sulfur levels where needed and to do field testing at remote locations where a quality problem is being investigated.

Mercaptans Mercaptans are naturally occurring sulfur compounds. Ethyl mercaptan is used to add odor to natural gas. Higher-molecular-weight mercaptans are a problem in jet fuel and gasolines due to specification levels of not more than 30 ppm in jet fuel product and not more than 40 ppm in gasolines. Levels of mercaptans in crude oil vary and depend on the field from which the crude is produced.

Test Summary A sample is diluted with isopropanol and titrated with silver nitrate solution.

Significance and Refinery Impact Maximum mercaptan level in crude is limited by refinery treating capacity. A crude with a mercaptan level higher than expected can lead to a fuel product that is over specification on mercaptans. Many refineries use processes that either remove mercaptans (hydroprocessing) or convert them to less harmful disulfides (Merox, Bender, Doctor plants). Mercaptans introduce odor and are corrosive to metal fuel system components. Jet A has a mercaptan specification of 0.003% (30 ppm). Gasoline products have a mercaptan specification of 40 ppm.


September 2002

6.4

BP Pipelines


Organic Chlorides Organic chlorides are primarily chlorinated hydrocarbons that remain in the hydrocarbon phase and are not removed in the refinery desalting process. Also, certain refinery processes inject chloride chemicals for operational needs. They do not occur naturally in crude oil and indicate contamination of the crude stream, typically from solvents such as dry cleaning fluids, carburetor cleaners, and other halogenated hydrocarbons as well as transformer PCBs, degreasing agents, and used motor oils.

Test Summary Testing for organic chlorides is a multistep process. First the crude oil is distilled to fractionate out the naphtha cut (initial boiling point to 400°F). Next the naphtha fraction is washed with caustic and then with water to remove inorganic chlorides, which can interfere in the detection step. The final step is to quantify the chloride level by either titration or combustion/coulometric analysis, both of which detect the level of organic chloride in ppm. The organic chloride level of the whole crude is then calculated from the chloride level in the naphtha fraction and the percentage of the naphtha fraction in the crude oil.

Significance and Refinery Impact Organic chlorides pose a hazard to refiners because they carry over into process streams where they break down under more severe process conditions and form corrosive compounds such as hydrochloric acid, primarily in the naphtha streams. These compounds attack piping, which can cause leaks and lead to fires or explosions. It does not require a great deal of contamination to cause serious problems, so specifications for organic chloride are set at a very low limit.

Typical Levels Organic chlorides do not occur naturally in crude oils and indicate contamination. BP Pipelines has a specification for organic chloride of not more than 1 ppm by weight in the whole crude and not more than 5 ppm by weight in the naphtha fraction.

Reid Vapor Pressure Reid vapor pressure (RVP) is a laboratory measure of volatility, or how readily a compound evaporates at low temperatures.


September 2002

6.5

BP Pipelines


Test Method Testing for RVP is done by placing the sample in a fixed volume cell at 100°F. When stabilized, an automated analyzer uses a transducer to obtain the pressure. If the test is done manually, the sample is shaken several times and the pressure gauge is read.

Significance and Impact RVP is a good indicator of the amount of light ends (C2 to C6 hydrocarbons) a crude contains and therefore the pressure the crude can create in an enclosed space such as a tank or pipeline. BP Pipelines’ RVP specification is 10 psi for crude oils based upon NSPS (New Source Performance Standards) tank regulations. Too much pressure from a crude oil can pop relief valves and cause pumping problems and meter errors. High RVP can lead to noncompliance with above-ground storage tank RVP limits. This includes unwanted hydrocarbon releases into the atmosphere, upsetting of tank roofs, and other undesirable tank problems. Refineries are interested in RVP for similar reasons while crude is in tanks and during initial handling in desalting and in the distilling process. Refinery problems can include distillation tower upsets, overloading of the light-end unit separation, reaching gas compressor capacity limits, and a decrease in crude oil refining value when light ends are fraudulently blended.

Metals Metals content generally refers to heavy metals in crude oil such as arsenic (As), iron (Fe), vanadium (V), and nickel (Ni). It may also refer to such metals as sodium, magnesium, and calcium. Table 6.2 shows the maximum amount of some of these metals allowed in crudes.

Test Summary Metals in crude oil can be analyzed directly by x-ray spectroscopy, similar to the sulfur analysis, or by an alternative lab method. A more detailed analysis for metals would include distilling the crude to isolate either the 650°F+ reduced crude fraction or 1050°F+ resid fraction before doing the lab analysis.

Significance and Refinery Impact Vanadium and nickel occur naturally in crude and are concentrated in the resid portion. Iron is often introduced into crude at the wellhead, during transportation by pipeline or vessel, or in tankage. Metals poison catalysts used in the refining process for producing finished petroleum products (that is, they deactivate or decrease the reactivity of catalysts). This is a concern when resid is


September 2002

6.6

BP Pipelines


being run on the fluid catalytic cracker unit, in platformers and magnaformers used in gasoline production, in hydrocrackers used in jet and gasoline production, and in hydrotreaters producing jet, gasoline, and diesel — these all use catalysts in the processing stage. Some vanadium compounds can damage turbine blades and refractory furnaces. BP Pipelines’ concern about metals in crude is to prevent contamination of low-metal crudes (West Texas intermediate/West Texas sour) with heavy high-metal crudes such as Mayan. This is one reason for small buffer batches of West Texas sour surrounding Mayan batches on the Cushing Chicago Pipeline System.

Table 6.2.

Quality Guidelines for Metals in Crude Oils

Type of Crude

Metal Contaminant

Maximum Amount Allowed

Sweet crude

Iron Nickel Vanadium

Not more than 10 ppm Not more than 5 ppm Not more than 5 ppm

Sour and heavy crudes

Iron Nickel Vanadium

Not more than 40 ppm Not more than 30 ppm Not more than 75 ppm

Typical Levels Metals content in crude oils varies widely. Mayan heavy has 700 ppm vanadium in the resid fraction, which equates to 260 ppm on a whole crude basis (37% resid). Arabian heavy crude oil has much less vanadium, 180 ppm in the resid fraction, 50 ppm whole crude basis (28% resid). To make a valid comparison of metals content of two or more crude oils, make sure you know whether the amounts are for the whole crude or for the resid fraction.

Light Ends Light ends are the gaseous light hydrocarbons in crude oil: ethane (C2); propane (C3); isobutane and normal butane (C4); and isopentane and normal pentane (C5).

Test Summary Light ends are generally analyzed in the laboratory by gas chromatography. This method essentially separates the C2 through C5 hydrocarbons from the crude oil and individually quantifies each component.


September 2002

6.7

BP Pipelines


Significance Light ends in crude oils are an important component to control. Since they are volatile, they can lead to a pressure over the pipeline specification of 10 psi (see “Reid Vapor Pressure”). A large amount of light ends in the pipeline can lead to pumping problems, metering errors, and noncompliance with above-ground storage tank regulations. In the past, some producers added low-cost butane to the crude oil to increase volumes and therefore increase profits. Extensive sampling and testing programs have essentially stopped this type of activity. At times in the past, some producers have created what is called a dumbbell crude oil. This refers to an artificial crude oil mixture created from the blending of light ends/condensate with 650+/1050+ heavy-end bottoms to produce a material that meets gravity and sulfur specifications but is not a valid full-boiling-range virgin crude oil.

Refinery Impact The refinery’s biggest concern with light ends is with unanticipated high levels of them, which lead to several problems: higher than predicted light-end yields (vs. computer models, which help plan and schedule refinery operations); exceeding gas compressor capacity limits; and potential distillation tower upsets. A crude with a high light-end content loads up refinery units such as the isomerization unit and the light ends unit that processes C3 to C5 hydrocarbons, which necessitates placing the excess in storage/inventory. This adds to processing costs.

Hydrogen Sulfide Hydrogen sulfide (H2S) is a poisonous gas that occurs naturally in crude oil and can break out from it. Higher H2S levels are generally found in heavy sour crudes. You must use respiratory protection when levels in the air reach 10 ppm. At 300 ppm H2S is an Immediate Danger to Life and Health (IDLH).

Test Summary In the laboratory, H2S can be determined by gas chromatography or the wet chemical method. The wet chemical method involves driving the H2S from the crude oil with nitrogen gas and heat, chemically trapping the H2S, and then finishing with a titration to quantify the level. Hydrogen sulfide levels in the air can be determined using Draeger tubes or other H2S detectors.

Significance and Impact Crude oil sitting in tanks, sample bottles, etc. can release hydrogen sulfide, or H2S can escape during refinery processing, causing an immediate danger. Knowledge of a crude oil’s H2S content


September 2002

6.8

BP Pipelines


is vital to prevent accidents and can aid a refinery in its ability to process the sulfur as a by-product from the refining process. Determination of the H2S content is now a standard test when crude oils are analyzed in the laboratory for economic assays.

Viscosity and Pour Point Viscosity is formally defined as the resistance to flow under gravity. It also refers to the time a fluid takes to move a specified distance and is a measure of the shear rate of crude. Pour point is the lowest temperature at which a fluid will move. It is close to the solidification point.

Test Summary Viscosity is tested by measuring how long it takes a crude oil to move through a calibrated capillary tube at a specified temperature. This is done in a constant temperature bath. Pour points of petroleum products are tested in a low-temperature refrigerated bath. The sample is tested until solid. The pour point is the temperature at which flow was last observed — generally 5°F above the solidification point.

Significance and Impact The high viscosity of heavier crudes decreases its flow rate in the pipeline, can increase line pressure, and therefore extends the time to move a batch of crude oil. On some pipeline systems, crude oils having too high a viscosity are penalized, with higher tariffs, for the extra time it takes to move them through the system. Pour point is necessary information to know for a crude oil, especially in the winter. If a crude solidifies in the line, then steps need to be taken to get it moving. This could involve adding chemicals to liquefy the crude at lower temperatures (pour point depressants). A high pour point can also increase line pressure. Condensate or other lighter crude oils may be added to some heavy crudes to make it possible to transport them through the pipeline without solidifying.


September 2002

6.9

BP Pipelines


Distillation A distillation analysis obtains data on the boiling point range of a crude oil and finished petroleum products. It determines the percentages or yields of crude fractions over their typical boiling point ranges.

Table 6.3.

Typical Distillation Fractions of a Crude Oil and Their Uses

Crude Fraction

Boiling Range

Use

Naphtha

Up to 400°F

Gasoline

Distillate

400–650°F

Diesel fuel, jet fuel, furnace oil

Gas oil

650–1050°F

Waxes, greases

Resid

1050°F and over

Asphalt

Test Summary Distillation of a crude oil can be carried out in two ways. An economic assay distillation, sometimes called a crude assay, which mimics a refinery distillation operation, starts with distillation at atmospheric pressure (pot still) of the crude oil to fractionate out the naphtha. Then the bottoms are transferred to a vacuum still, where lower pressure allows separation of the distillate, gas oil, and resid portions. In both processes, temperatures are monitored as each fraction distills. The laboratory quantifies the percentage of each fraction, combines this with the temperature data, and creates a boiling point curve for the crude oil being analyzed. A second method is high-temperature simulated distillation, called Sim-Dis (a special type of gas chromatography, or GC). A small quantity of crude oil is diluted into a solvent and injected into a GC analyzer. The crude oil components are separated by boiling point on a long capillary tube (“column”), and data is obtained as the ever higher boiling portions of the crude oil emerge from the analyzer. A computer program then creates the boiling point curve. Either method may be used. Distillation allows further tests to be conducted on the fractions, whereas Sim-Dis gives only a boiling point curve.

Significance and Impact Refiners use distillation data to determine the yield vs. temperature relationship for the crude fractions and assign a refining value to the crude. Distillation data is also useful for identifying fraudulent blends of crude with materials such as NGLs and resid. Unscrupulous blenders try to obtain whole crude prices for these mixtures (“dumbbell” crudes). Errors in distillation and


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“dumbbell” crudes both cause incorrect product yields and result in shortages or overages for market demands, which leads to profit losses for the refinery. Similarly, distillation determines resid content (fraction boiling at 1050°F or more, in vol%). High resid levels may indicate fraudulent blending.

Neutralization Number Neutralization number is also referred to as total acid number. It is an indication of the amount of acidic components present in the crude oil.

Test Summary The crude oil is diluted into a solvent and titrated with a standard base (potassium hydroxide, or KOH). The base neutralizes the acidic components. The test result, or neutralization number, is given in the unit “mg KOH/gram sample.”

Significance and Impact The neutralization number indicates the level of organic acids present in the crude. Organic acids typically concentrate in gas oil fractions. The corrosion that these organic acids can cause, especially to carbon steel, is of concern to the refinery. Typically, crude oils having neutralization numbers higher than 0.50 may cause corrosion and quality problems for refineries. Heidrun crude from the North Sea is an example of a crude oil with a high level of organic acids.

Nitrogen Nitrogen in crude refers to the amount of “organic” nitrogen that is bound (attached) to hydrocarbon molecules.

Test Summary The test for organic nitrogen is performed by first diluting the crude oil into a solvent. This mixture is then injected into a combustion furnace, which burns the sample under controlled conditions. The products of this process are swept by a flowing gas stream into a reaction chamber where the level of nitrogen is determined by the response of the detector module.


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Significance and Impact Nitrogen is a concern as a catalyst poison to refiners when it is present in naphtha feed streams to isomerization, reformers (platformers), and ultraformer units. These units use expensive catalysts (which contain precious metals such as platinum and others) that can lose reactivity when poisoned. Lower catalyst reactivity increases refinery processing expense. Catalyst poisoning also decreases the life of the catalyst, which leads to the expense of replacing it earlier than scheduled.


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Tests for Products Tests on petroleum products may include those to determine Reid vapor pressure, flash point, water and haze, color, particulate contamination, corrosion tendency, electrical conductivity, oxygenate content, and dye content.

Reid Vapor Pressure RVP stands for Reid vapor pressure and is a laboratory measure of volatility, or how readily a compound evaporates at low temperatures.

Test Method Testing for RVP may be done by placing the sample in a fixed volume cell at 100°F. When stabilized, an automated analyzer uses a transducer to obtain the pressure. If the test is done manually, the sample is shaken several times and the pressure gauge is read. Most gasoline samples are now tested for RVP using a Grabner RVP analyzer. A small portion of sample is injected into the analyzer and the resulting RVP is displayed on a digital readout.

Significance and Impact The higher the RVP of a gasoline, the greater its volatility, and therefore the more volatile organic compounds (VOCs) evaporate from it. VOCs combine with nitrogen oxides in the air in the presence of sunlight to form smog. VOCs evaporate at all stages of gasoline marketing, from truck loading to vehicle refueling. The U.S. Environmental Protection Agency and some state agencies regulate the maximum RVP of gasoline. For this reason, BP Pipelines has standardized sampling procedures to ensure consistent RVP test results (see Chapter 10, “Automatic Sampling”).

Viscosity, Pour Point, and Cloud Point Viscosity is formally defined as the resistance to flow under gravity. It also refers to the time a fluid takes to move a specified distance. Pour point is the lowest temperature at which a fluid will move. It is close to the solidification point. Cloud point is the temperature at which paraffin begins to congeal out of a heating oil or diesel fuel.


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Test Summary Viscosity is tested by measuring how long it takes a liquid to move through a calibrated capillary tube at a specified temperature. This is done in a constant temperature bath. Pour points of petroleum products are tested in a low-temperature refrigerated bath. The sample is tested until solid. The pour point is the temperature at which flow was last observed — generally 5°F above the solidification point.

Significance and Impact The viscosity of finished products depends upon whether the fuels are for heating oils or diesel oils, as they have fluidity needs. Pour point and cloud point tests are necessary for heating oils and diesel fuels whose compositions vary seasonally with temperature. Also, congealed wax is harmful to engine performance.

Flash Point The flash point of a petroleum product is the lowest temperature at which the vapors above it ignite in air.

Test Summary A liquid sample is poured into a cup, a thermometer inserted, and the cup covered. The sample is then heated slowly until a flash, or small explosion, occurs that consumes the vapors inside the closed cup. The temperature when the flash occurs is the flash point.

Significance and Impact The consumer buys a petroleum product assured that it is safe to use in a furnace, space heater, diesel engine, and so on. This assurance is actually the result of a flash point test conducted after the marketing distribution terminal receives product from a tank. A product with a flash point lower than it should be for its intended use could be very dangerous. All BP Pipelines distillation products must meet certain flash specifications. Table 6.4 shows some typical flash specifications.


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Table 6.4.


Typical Minimum Flash Points of Various BP Pipelines Products Product

Minimum Flash Point

Jet A Diesel Supreme Diesel (high- and low-sulfur/fuel oil) Kerosene (K-1)

105°F 125°F 140°F 125°F

Water Content and Haze Petroleum products that contain water or other contaminants appear hazy.

Test Summary One liter of sample in a transparent, colorless bottle is inspected by placing the bottle in front of a white card with several black lines marked on it (Figure 6.1). The visibility of the lines through the sample describes its haze. ASTM (American Society for Testing and Materials) provides a numbered standard (1 to 6) for describing haze so that no one has to rely on another’s description of “pretty cloudy” or “almost clear.” Another test for water and contaminants is millipore sampling. In this test, a liquid sample of a distillate fuel is filtered through a millipore membrane and then assessed visually. The water separator index modified (WSIM) test measures the ability of water to separate from fuel. A fuel sample in a syringe is emulsified with water using a high-speed mixer and then expelled from the syringe through a fiberglass coalescer. The effluent is analyzed for uncoalesced water by light transmission measurement.


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5

4

3

2

1

Figure 6.1. Bar chart for determining haze

Oxygenate Content An oxygenated fuel is a gasoline that is blended with compounds containing oxygen (commonly MTBE or ethanol). Oxygenate content is determined by a number of procedures and instruments, including portable analyzers, on-line analyzers, and detailed laboratory testing.

Significance and Impact Oxygenation promotes more efficient combustion and reduces tailpipe emissions of carbon monoxide up to 30%. The result is cleaner air. The U.S. Environmental Protection Agency and some state agencies require oxygenated gasoline to be sold in certain parts of the country at certain times of the year.


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More About It See the BP Crude Quality Manual for more detailed information about testing crude oil.


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Reference Documents The following list includes some of the ASTM standards used to analyze crude oil and petroleum products. 1. ASTM D-56 Tag closed cup for jet fuel 2. ASTM D-93 Pensky Marten for diesel fuels 3. ASTM D-97 Pour point of petroleum products 4. ASTM D-323 Vapor pressure of petroleum products (manual method) 5. ASTM D-396 Heating oil specifications 6. ASTM D-445 Kinematic viscosity 7. ASTM D-664 Total acid number (potentiometric method) 8. ASTM D-974 Neutralization number (colorimetric method) 9. ASTM D-975 Diesel fuel oil specifications 10. ASTM D-1655 Jet fuel specifications 11. ASTM D-1796 Water content


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12. ASTM D-2276 Particulate contamination of petroleum products 13. ASTM D-2276 Millipore color for jet fuel 14. ASTM D-2622 Sulfur in petroleum products by X-ray spectroscopy 15. ASTM D-2624 Electrical conductivity of petroleum products 16. ASTM D-2709 Water content 17. ASTM D-2887 Simulated distillation for petroleum products 18. ASTM D-2892 Distillation of crude petroleum (to 400°F) 19. ASTM D-3227 Mercaptan sulfur in gasoline, kerosene, aviation turbine, and distillate fuels 20. ASTM D-3237 Lead content 21. ASTM D-3240 Aqua Glo for jet fuel 22. ASTM D-3710 Boiling point range 23. ASTM D-4176 Haze of petroleum products


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24. ASTM D-4629 Trace nitrogen in liquid hydrocarbons by syringe injection 25. ASTM D-4814 Gasoline specifications 26. ASTM D-4929 Determination of organic chloride content in crude oil 27. ASTM D-5191 Vapor pressure of petroleum products (Grabner method) 28. ASTM D-5236 Distillation of heavy hydrocarbon mixtures (vacuum potstill method) 29. ASTM D-5307 Determination of boiling range distribution of crude petroleum by gas chromatography 30. ASTM D-5762 Nitrogen in petroleum and petroleum products by the Boat-Inlet method 31. ASTM D-5949 Pour point Other references: 32. ATA 103 manual from airlines for pipeline requirements 33. BP Crude Quality Manual 34. BP General Operations Manual 35. Pipelines (NA) Business Unit Safety Manual


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6.20

Chapter 7

Tank Strapping Quick Reference Safety •

Get the required permits and clearances before entering any tank.

•

Report any tank conditions that appear unsafe. Post warning signs in strategic locations—near all ladders and stairways and around the lower tank shell—before you leave the area.

•

Keep the outer tank surfaces clean to reduce the risk of slipping and fire.

•

Always keep one hand on the handrail when climbing tank stairs—for maintaining balance and preventing the buildup of static electricity. Before taking any measurements, ground your bare hands and tools by touching the handrail. Avoid causing sparks, especially when opening gauge hatches. Sparks can be caused by metal tools, cleats, rings and watches, and other objects.

•

Watch out for ice and oil on tank stairs and platforms.

•

Do not walk on any ladder, stairway, or platform if you suspect that it is weakened by corrosion.

•


•

Monitor the atmosphere for H2S, combustible vapors, and adequate oxygen content while strapping.

•

Never strap a tank during an electrical storm or in strong winds.

•

Keep the area around the tank clear of obstructions and tripping hazards.

•

Some petroleum products are extremely flammable and/or poisonous. Follow the applicable safety procedures in the Pipelines (NA) Business Unit Safety Manual when strapping tanks that contain these dangerous liquids.

•


Scope This chapter describes the procedures for calibrating small (less than 1,000 barrels) upright, cylindrical tanks by the manual tank strapping method. Larger tanks and tanks with floating roofs will be strapped by third-party contractors following procedures similar to these.

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September 2002


Summary of Strapping Procedures •

Record the ambient temperature and temperature of the tank contents to the nearest 1.0°F.

•

Measure the shell plate thickness to the nearest 1/64 inch.

•

Measure the bottom ring to the nearest 0.005 foot using a NIST-certified standard tape.

•

Measure subsequent rings from bottom to top using a working tape that has been calibrated against the standard tape.

•

Measure vertical tank measurements to the nearest 1/16 inch.

•

Locate deadwood and record measurements to the nearest 1/8 inch.

•

Measure the height and width of the manhole.

•

Record all other tank information that could affect tank volume.

Good Practices •

Take all strapping measurements on the same day without interruption.

•

Take strapping measurements while the liquid level in the tank is static. Allow the tank contents to settle at least 24 hours before strapping.

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BP Pipelines


Introduction Strapping is a method of measuring the exact dimensions of a tank to develop a capacity table for that tank and increments for the measurement ticketing software. The capacity table allows the field specialist to calculate the volume of liquid in the tank. These measurements include the circumference of each tank ring and shell plate thickness; the height of the shell, gauging height, and effective inside tank height; and the dimensions of any obstructions inside the tank (deadwood) that reduce its nominal capacity.

When to Strap a Tank You must strap a tank when •

the tank is new;

•

a tank is moved from one location or lease to another;

•

a tank is restored to service after being disconnected or abandoned;

•

the tank’s deadwood changes.

Equipment You Will Need for Strapping a Tank •

Strapping tape (long enough to encircle the tank completely)

•

NIST-certified standard tape

•

Strapping pole

•

Tape clamp and tension gauge

•

Spring tension scale

•

Rope and ring for raising and lowering the strapping tape

•

Calipers and level or transit

•

Ladders

•

Ultrasonic device or depth gauge for measuring thickness of the shell plate

•

Pitch indicator and level or protractor

•

Innage gauge tape and bob

•

H2S monitor

•

Equipment for measuring temperature and gravity

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Procedures When you arrive at a tank location, follow these procedures before beginning strapping: 1. Check for hazardous atmosphere using a hydrogen sulfide monitor. Also use a monitor to analyze the atmosphere for combustible vapors and adequate oxygen content. •

During the strapping, keep both monitors activated so that an alarm will sound if atmospheric conditions change.

2. Make sure no ice or snow has accumulated on the tank. If it has, postpone the strapping until the ice or snow has melted. 3. Clean any incrustations (for example, ice, mud, etc.) that will affect the circumference measurements. 4. Check the fill level. •

In general, welded tanks with a capacity of 500 barrels or less can be strapped in any condition of fill as long they have been filled at least once at their present location.

•

Welded tanks with capacities over 500 barrels and all bolted and riveted tanks should be at least two-thirds full when strapped.

Note: The amount of liquid in the tank affects strapping, as do the size and type of tank. Table 7.1 under “More About It” shows what the fill condition must be for each type of tank. 5. Be sure that the tank is level by measuring the tank’s tilt with a pitch indicator and level or a protractor. •

Don’t strap the tank if the amount of tilt is greater than 1 part in 70, which equals 0.82° (about 1°) from vertical.

6. Look for the strapping identification number stenciled on the side of the tank. If there is no number, locate the builder’s nameplate on the side of the tank. Record the information on the strapping report. 7. Determine the ambient temperature as well as the gravity and temperature of the tank’s contents (see Chapter 2, “Gravity and Temperature Measurement in Tanks”).

Plate Thickness For small lease tanks, get the plate thickness from the nameplate on the tank. For larger tanks (greater than 500 barrels), measure the thickness of the shell plate with an ultrasonic device or a depth gauge. •

Make at least two measurements to the nearest 1/64 inch on each ring, and record the average on the strapping report (see Figure 7.7 under “More About It”).

•

Do not measure plate thickness where the edges have been distorted by caulking.

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Circumference Measurements Measure the circumference of each ring of the tank. Do not take circumference measurements over insulation. 1. Calibrate the working (strapping) tape against a NIST-certified standard tape. •

Using the standard tape, measure the bottom ring of the tank (see steps 3–8 below) and score a vertical reference mark at the zero reading, at 100-foot intervals, and where the tape laps over the starting point. Use a tape clamp and a tension gauge to apply the tension specified in the NIST report.

•

Using the working tape, measure the tank along the same path and apply the same amount of tension that you applied to the standard tape. Note any differences in the measurements of the working tape and the standard tape.

•

If the working tape circumference is the same as the standard tape circumference, the tape is in calibration and no correction is needed.

•

If there is a difference, add or subtract this amount to the measurements taken with the working tape. If the correction is more than 0.01 foot (approximately 3/32 inch) per 100 feet of tape, the working tape is not within the recommended tolerances. Use another tape.

2. Begin strapping with the bottom ring (ring 1). 3. Mark the tank shell to indicate the tape path with the aid of the strapping pole. •

For welded tanks, scribe a path for the tape at a position one-fifth (or 20%) of the ring's height, measured from the top of the weld down (see Figure 7.1). For bolted tanks, the position for scribing is 25% and 75% above the bottom of each ring (see Figure 7.2).

20%

20% Ring 20%

Figure 7.1. Recommended tape paths for measuring tank circumference on a welded tank

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Ring

75% 25%

Figure 7.2. Recommended tape paths for measuring tank circumference on a bolted tank 4. If you cannot follow the recommended path because of obstructions on the tank, mark a substitute path that is as near to the recommended path as possible. •

If an obstruction is unavoidable, use a stepover caliper to span the obstruction.

•

Place the caliper in the horizontal position, determined with a level, against the tank shell near the center of the ring. Scribe marks on the tank shell with the points of the caliper. Place the working tape under the correct tension around the tank, and measure the distance between the scribed marks to the nearest 0.005 foot.

5. Make sure to get the tape straight along the scribed path. 6. When you have pulled the tape to the correct tension, slide it back and forth to spread the tape tension evenly around the shell. If friction causes the tape to cling to any point along the path, the measurement will not be accurate. Note: The part of the tape that laps over the starting point (where you read the measurement) must be at least 2 feet from an upright joint. 7. Holding the tape flat against the side of the tank, read it to the nearest 0.005 foot, slide it back and forth for a few inches, then read it again. •

If these 2 measurements do not agree within 0.005 foot, repeat until you obtain the same reading for two consecutive measurements.

•

Correct the measurement as required by the tape calibration, if needed.

•

Record the average of the 2 readings for this ring on the strapping report (see Figure 7.7 under “More About It” at the end of this chapter).

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8. If butt straps or lap joints cause uniform voids between the tape and the tank shell at each joint, measure and record the width and thickness of the butt straps or lapped plates and the number of butt straps or lap joints in each ring. •

If possible, measure the shell plate thickness of each ring at 2 locations using an ultrasonic measurement device.

•

If no direct measurement is possible, use the shell thickness on the tank’s nameplate or the construction prints for the tank.

9. Repeat steps 3–8 for each ring of the tank.

Height and Tilt Measurements After measuring the circumference of the tank’s rings, take these vertical measurements: shell height, gauging height, and effective inside tank height. If liquid is present in the tank, also gauge the liquid height.

Reference point

Gauging tape

Gauging height

Effective inside tank height

Shell height

Datum plate

Figure 7.3. Vertical measurements of a tank

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Shell Height and Tilt The shell height is the distance between the bottom of the bottom angle and the top of the top angle (see Figure 7.4 and Figure 7.5), measured on the outside of the tank.

Roof

Shell

Bottom

Figure 7.4. Measuring the shell height of a tank with a protruding bottom

Roof

Shell

Bottom

Figure 7.5. Measuring the shell height of a tank with a recessed bottom 1. If the tank bottom does not protrude beyond the shell, dig out the dirt at the base of the tank so that you can get a straight-edge or level underneath the tank bottom. 2. Measure near the reference point on the gauge hatch and at 3 other points equidistant from the first around the shell with an innage gauge tape, using a level as a point of measurement.

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3. Check the amount of tilt in the shell height at each measuring point with a theodolite, optical plummet, or plumb bob. Note: The tilt must be less than 1 part in 70 (less than 1.3°). If it is more, stop the strapping and notify your supervisor and the Measurement Team. The tank will need to be leveled before it can be restrapped and used. 4. Measure the height of each ring to the nearest 1/16 inch. The combined ring heights should add up to the overall shell height. If they do not match, remeasure the heights. 5. Record your measurements on the strapping report (see Figure 7.7 under “More About It” at the end of this chapter).

Gauging (Reference) Height The gauging height, or reference height, is the distance from the striking point on the tank floor or a datum plate to the reference point on the hatch (see Figure 7.3 above). See Chapter 3, “Gauging Lease Tanks” or Chapter 4, “Gauging Large Tanks” for more detailed information on gauging the liquid in the tank. 1. Lower the gauging tape into the tank until the tip of the bob touches the gauge striking point or datum plate. 2. Record the distance to the reference point on the hatch on the strapping report (see Figure 7.7 under “More About It” at the end of this chapter). 3. Also record the height of the liquid in the tank, if any, by looking where the liquid cut the tape.

Effective Inside Tank Height The effective inside gauging height is usually the distance from the gauge striking point or datum plate to the top of the tank wall (called the top angle, or where the tank contents would begin to overflow). This distance defines the upper and lower limits of the capacity table and must be measured on the gauge path (the same path where the liquid height is gauged). See Figure 7.6.

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Top angle line

Gauging height

Anchor line

Effective inside tank height Datum plate

Datum plate

Figure 7.6. Determining effective inside tank height 1. Anchor a line at the reference point on the hatch. 2. Extend the line at a right angle from the tank wall (parallel to the ground). 3. Level the anchored line, and measure the distance between the line and the top angle. 4. Subtract this measurement from the gauging height to get the effective inside tank height. 5. Record your measurements on the strapping report (see Figure 7.7 under “More About It” at the end of this chapter).

Overflow Location Some tanks have an overflow line near the top of the tank shell. Note the size and location of this line on the strapping report and whether it can be closed. If the line cannot be closed, measure the effective inside tank height as the distance from the gauge striking point or datum plate to the bottom of the overflow line.

Connection Height Connection height is the point near the base of the tank shell where liquid exits the tank and enters the pipeline. 1. Use the gauge tape to measure the distance from the tank floor to the bottom of the nipple where it protrudes from the shell. 2. Add 1/4 inch to this measurement to allow for the approximate thickness of the nipple, and record the measurement on the strapping report.

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Deadwood Measurements Deadwood includes internal piping, roof supports, ladders, and other fixtures that occupy volume inside the tank. If the tank contains liquid, it may not be possible to measure deadwood. For most tanks, you can find the necessary dimensions on construction drawings if actual measurement is impossible. If the tank is empty, follow these procedures for measuring deadwood. 1. Inspect the tank for cleanliness. •

The inside vertical surface and roof supporting members should be clean and free of any foreign matter, such as liquid residues, rust, dirt, emulsion, and paraffin.

•

Clean the tank if needed.

2. Measure the highest and lowest levels where deadwood affects the tank’s capacity. •

Measure from the tank bottom next to the shell.

3. Clearly identify work sheets containing the details of deadwood locations, shapes, and dimensions, and make these worksheets part of the strapping record.

Manhole Dimensions Manhole measurements involve specialized tools and procedures depending on the size and shape of the manhole. These are presented in on-the-job training.

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More About It Here you will find the following: •

Table 7.1. Fill Condition Required for Different Tanks while Strapping

•

Figure 7.7. Sample page of strapping report

The amount of liquid in the tank affects strapping, as do the size and type of tank. Table 7.1 shows what the fill condition must be for each type of tank.

Table 7.1.

Fill Condition Required for Different Tanks while Strapping Butt-Welded

Lap-Welded

Bolted

Riveted

<500

>500

<500

>500

<500

>500

<500

>500

Filled at present location before strapping

X

X

X

X

X

X

X

X

Any fill during strapping

X

X

X

X

X

X

X

Fill Condition

Must be 2/3 full during strapping Small amount of inflow or outflow allowed during strapping

X

X

X

X

X

X

Note: Tank capacity is in barrels.

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Figure 7.7. Sample page of strapping report

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Reference Documents 1. API Manual of Petroleum Measurement Standards, Chapter 2.2A “Measurement and Calibration of Upright Cylindrical Tanks by the Manual Tank Strapping Method” 2. BP Self-Study Guide, Field Specialist III, Module 1 “Tanks and Tank Strapping” 3. Pipelines (NA) Business Unit Safety Manual

Tank Strapping

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Chapter 8

Seals and Security Quick Reference Safety •

Exercise care when handling seals and side cutters to prevent cuts.

•


Scope These procedures apply to lease tanks and LACT/ACT unit systems (including the ELM).

When and Where to Use Seals and Security •

Seal tanks when making new connections, when welding, when oil is being delivered, and when the tank is on line.

•

Seal LACT/ACT units at the prover connector valves, S&W monitor, sampler system, back-pressure valve, meter and meter accessory stack, control panel and power panels, temperature averagers, head switches and level controls, diverter valves, and piping and control conduits.

Note: At some locations, the seals may be installed by the other party. Also some ACT meters, depending on location, manning, and products, may not be sealed. •

Flow computers shall be password protected.

What to Do If a Seal Is Broken While the tank is still on line: •

Seal off the tank.

•

Take a closing gauge.

•

Write the ticket as usual, but do not fill in the closing gauge.

•

Attach a note to the ticket giving the reason for not completing it; include the closing gauge and temperature at the time of sealing.

•

Make a full report to your team leader.

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September 2002


When you find a seal on a LACT/ACT system broken: •

Replace the boxcar seal with a wire seal.

•

Do not transfer oil to/from that facility until your supervisor instructs you to do so.

•

Conduct an immediate investigation and report your findings to your supervisor.

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BP Pipelines


Introduction Seals protect the company and the operator by assuring that no one has tampered with the oil run. They are placed on any part of a lease tank or LACT unit that could be tampered with. Seals are also part of assuring safety when working on tanks—for example, when welding a line. Electronic liquid measurement (ELM) flow computers require security in the form of software password protection, as well as physical locking of the area where they are located.

Equipment You Will Need for Working with Seals •

Boxcar seals

•

Wire seals

•

Pliers

•

Side cutters

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Procedures The purpose of using seals and security procedures is to make sure that the equipment containing and monitoring crude or product has not been not tampered with. The following will give you an overview of where you should check for seals and how to use them.

Using Seals The two types of seals are boxcar seals and wire seals (see Figure 8.1 under “More About It” at the end of this chapter). Boxcar seals are numbered; record the numbers as a reference on the run ticket. •

Use a wire seal if you encounter a defective boxcar seal. Attach the defective boxcar seal to the wire seal, and record both seal numbers on the run ticket.

•

If you find that a boxcar seal has been used where a wire seal should have been used, replace the boxcar seal with a wire seal or use the boxcar seal with a wire seal attached to it.

•

Replace any seals that were broken during LACT/ACT checkout, as well as any missing seals and any seals showing signs of deterioration.

When and Where to Seal a Tank 1. When making new connections: •

Seal tank stops closed when new tanks are connected to the BP Pipelines gathering system or when a new gathering system is brought on line.

•

Seal tank stops closed after tanks have been connected to a BP Pipelines system.

2. When oil is being delivered by tank truck: •

Seal pipeline connections on lease tanks used for receiving oil delivered by tank truck.

•

Close and seal all draw-off connections when the tank is on line.

•

Request the operator to make sure that the tank’s gauge and thieving hatches can be sealed while still allowing venting.

•

Seal the tank’s gauge and thieving hatches.

3. When the tank is on line — to make sure that unwanted hydrocarbons or contaminants cannot be introduced or removed from the pipeline system undetected — do the following: •

Seal all closed valves on draw-off connections, filling lines, overflow lines, and equalizer lines.

•

Seal steam lines.

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•

BP Pipelines does not require you to seal off fire protection lines.

•

Break all BP Pipelines seals when a tank is returned to the operator.

Where To Seal LACT/ACT Units The following list is an overview of where you should check for seals to ensure that no one has tampered with LACT/ACT components. 1. Prover connector valves •

Place a lock bar with seals across prover valves. On gate valve installations, use a lock and chain along with the seals.

2. S&W monitor and probe •

Seal each connection on the probe and detector. Also, seal the electronic module at the hinges, cover latch, and at any other connections.

3. Sampler system •

Place a seal at any point where tampering may affect the system’s accuracy. All container openings, valves, pipe unions, pump drains, and other locations on the system should be sealed.

4. Back-pressure valve •

Seal back-pressure valves through the adjustment bolt.

5. Meter and meter accessory stack •

Seal the following on the meter and meter stack: the main meter body bolting, temperature and pressure averagers, right-angle drive dust cover, and meter totalizer.

6. Control panel and power panels •

All electronic devices are wired through the control box and can be disabled by entry into the panels. Seal all electronic devices at hinges, latches, and other points of access.

7. Tank head switches and level controls •

Seal the high- and low-level switches as well as the low-level limit switch just above the sales outlet.

8. Diverter valves •

Seal the diverter valve in such a way as to prevent tampering and the sale of “bad oil.”

Seals and Security

September 2002

8.5

BP Pipelines


9. Piping and control conduits •

Seal all pipe couplings and screwed plugs located downstream from the meter to guard against the removal of metered liquid from the pipeline.

Signs of Tampering Look for the following signs of tampering each time you check the LACT/ACT or gauge a tank: •

Forced entry

•

Broken BP Pipelines security seals or seals that have been tampered with

•

Electrical connections that have been tampered with (e.g., jumper wires)

•

Small holes drilled in the weatherproof box housing the electronics (possible signs of an attempt to insert wires for manipulating controls)

•

Monitor alarm and trip set points that don’t agree with previous settings

In addition to checking the unit for signs of tampering, be sure to pick up and dispose of all security seals and wires you have removed.

Procedures When a Seal Has Been Broken When you find a broken seal on a foreign line while the tank is still on line: •

Seal off the tank.

•

Take a closing gauge.

•

Write the ticket as usual, but do not fill in the closing gauge.

•

Attach a note to the ticket giving the reason for not completing it; include the closing gauge and temperature at the time of sealing.

•

Make a full report to your supervisor.

The supervisor may authorize you to run oil from other tanks on the lease, but do not run any oil from the tank with the broken seal until you have permission from the District Manager. When you find a broken seal on a pipeline connection: •

Replace the boxcar seal with a wire seal.

•

Do not run oil from that tank or any other tank on the lease until your supervisor instructs you to.

•

Conduct an immediate investigation and report your findings to your supervisor. Specifics of the investigation will depend on the circumstances, location, etc.

Seals and Security

September 2002

8.6

BP Pipelines


Other Security Measures BP Pipelines prefers that flow lines enter a tank through the roof at a point near the regular gauge hatch. If the flow line extends through the roof into the liquid contents, a hole or slot must be cut in the pipe at a point not lower than the top of the tank shell. This precaution prevents the liquid from being siphoned from one tank to another. On older locations where the flow lines enter the tank so far from the gauge hatch that the gauger cannot make a fingertip inspection, BP Pipelines will not require the operator to change the location of the lines, provided the tank can be inspected to see that the line has an opening no lower than the top of the tank shell. On future installations, BP Pipelines will advise the operator to locate these lines close enough to the gauge hatch that BP Pipelines personnel can inspect them from the hatch. Some operators prefer that flow lines enter the tank through the shell, usually near ground level. This is acceptable; however, any filling line that enters through the shell of the tank must have a valve or stop with an approved and conveniently accessible sealing device. It must be sealed closed whenever the tank is on line.

Security for ELM Systems The flow computer is the main component of an ELM system that requires security measures.

Software Security Passwords provide security for software. The first level of security allows measurement personnel to enter routine data from gauging, metering, and proving. Higher levels of security allow only the appropriate personnel to change basic data (for example, tank strapping data, meter data, and prover calibration data), computational procedures, and/or algorithms.

Physical Security The computer should be maintained in a secure location by locking the cabinet, house, or area where it is located. If this is not possible, then other means should be used to make the equipment inaccessible to tampering. Some other equipment, like temperature/pressure averagers, may be sealed to prevent tampering.

Seals and Security

September 2002

8.7

BP Pipelines


More About It

0 4 1 0 B P

Figure 8.1. Boxcar seal

Seals and Security

September 2002

8.8

BP Pipelines


Reference Documents 1. Pipelines (NA) Business Unit Safety Manual

Seals and Security

September 2002

8.9

Chapter 9

LACT/ACT Verification and ELM Overview Quick Reference Safety •


•

Some petroleum products are extremely flammable and/or poisonous. Follow the applicable safety procedures in the Pipelines (NA) Business Unit Safety Manual when sampling these dangerous liquids.

Summary of Measurement Procedures for Flowing Liquids 1. Check the operation of the LACT/ACT unit and ELM system or meter installation (Chapter 9).

•

Wear safety glasses or goggles at all times while handling pressurized receivers.

•

Keep containers closed when not in use.

•

Keep work areas as clean as possible and well-ventilated.

2. Check meter operation (Chapter 11, Chapter 12, Chapter 13).

•

Clean up spills promptly and in accordance with safety, health, and environmental regulations.

3. Mix and withdraw samples (Chapter 10).

•

Observe established exposure limits, and wear suitable protective clothing and equipment.

•


•


4. Analyze the samples as required for the specific type of transaction and product (Chapter 2, Chapter 5, Chapter 6).

Scope This chapter lists procedures to verify the operation of LACT units on lease tanks containing crude oil and of ACT units measuring weathered crude oil or liquid petroleum products. This chapter also describes the components and operation of the electronic liquid measurement (ELM) system.

BP Pipelines

September 2002

5. Prove the meter (Chapter 14). 6. Verify/calibrate the temperature and pressure devices, as appropriate (Chapter 9). 7. Verify/calibrate the densitometer, as appropriate (Chapter 9). 8. Record all results (Chapter 17).


Summary of LACT/ACT Unit Checks •

Check for signs of leaks.

•

Check for tampering.

•

Check the level of sample in the sample pot to make sure it has increased since the previous observation.

•

Check the sampler operation.

•

Check that all monitoring, control, and recording devices are operating properly.

Summary of ELM System ELM equipment: •

Flow computer

•

Pressure and temperature transducers/transmitters

•

Communication equipment

ELM functions: •

Meter ticketing

•

Meter proving control

•

Sampling system control

•

Communication link to the SCADA system

BP Pipelines

September 2002


Equipment You Will Need for Measuring Flowing Liquids For checking LACT/ACT units:


• Inspection form or checkout list


• Stopwatch


• Security seals and seal cutters


• Tools for checking the meter and accessories

• Sample heater

• Equipment for calibrating or verifying temperature and pressure transducers and/or signal-receiving devices


• Equipment for gravity and temperature testing (see below)

• Centrifuge For S&W testing by the laboratory centrifuge method:

• For LACT units, equipment for determining S&W (see below)


For automatic sampling: • Sample containers (cans or bottles)

• Sample heater

• Portable receivers, when applicable


• Sample(s)

• Centrifuge

• Solvent for washing sample containers • Security seals and seal cutters

For water testing by the Karl Fischer titration method: • Nonaerating, high-speed shear mixer


• Clean glass syringes


• Reagent-grade xylene • Karl Fischer reagents • Karl Fischer coulometric titrator

• Cupcase woodback thermometer • Portable electronic thermometer (PET)

For security (lease tanks):

• Circulating bath and ice bath or PET calibrator (for verifying a PET)

• Seals for securing all pipeline connections • Side cutters for cutting and removing seals • Pliers Other: • Carrying case for all equipment

BP Pipelines

September 2002

Equipment for Measuring Flowing Liquids

BP Pipelines


Introduction In addition to verifying the operation of LACT/ACT units, you may also prove the meter and densitometer on ACT units, calibrate temperature and pressure devices, take samples, and test for S&W (in crude). See the appropriate chapters in this manual for these procedures. The ELM system uses a computer to simplify meter ticketing and to control proving and sampling by actuating the proving sequence and signaling the PLC to operate the appropriate valves. It also signals the sampler to sample the liquid.

Equipment You Will Need for Checking LACT/ACT Units •

Inspection form or checkout list

•

Stopwatch

•

Seals and cutters

•

Certified reference thermometer

•

Equipment for verifying or calibrating temperature and pressure transducers and/or signal receiving devices (see “Equipment You Will Need for Measuring Flowing Liquids”)

•

Equipment for gravity and temperature testing (see “Equipment You Will Need for Measuring Flowing Liquids”)

•

For LACT units, equipment for determining S&W (see “Equipment You Will Need for Measuring Flowing Liquids”)

LACT/ACT Verification and ELM Overview

September 2002

9.4

BP Pipelines


Procedures for Checking the Operation of LACT and ACT Units Programming LACT Unit Run Time Many of BP Pipelines’ gathering systems require that several LACT units be used to pump into one or more field pumping units. Under these conditions, it may be necessary to program the starting time and duration of each LACT unit’s run time. This is done on a case-by-case basis according to local requirements.

Checkout Procedures for LACT and ACT Units Use the appropriate form or checkout list when you inspect the unit to help keep track of each component and the condition in which you found it. The form you use should contain spaces to record the following kinds of information (see Figure 9.2 under “More About It” for a sample form): •

Date

•

Time

•

Lease or location number

•

Meter make and model

•

Volume on the meter register

•

Line pressure and meter pressure

•

Temperature and pressure averager readings

•

Flow rate

•

Sample level in storage pot

•

Percentage of S&W in samples (if appropriate)

•

Tank gauge (if appropriate)

•

Position of diverter valve

•

State of alarm system

•

Your initials

•

Miscellaneous information


September 2002

9.5

BP Pipelines


High-level switch

Control panel

Deaerator and strainer Water monitor

Sample probe and extractor

Storage container and mixer

Temperature probe

Densitometer Meter

Low-level switch

Back pressure valve

Pressure sensor

Strainer Pump

Divert valve

Pump

Straightening vanes in pipe

Check valve

Figure 9.1. LACT unit Some of the following procedures apply only to LACT units. 1. Check for signs of leaks. •

Check the entire unit, particularly downstream from the meter and in the sampling system, for signs of leaks.

•

If you find any leaks, shut the unit down and have the leaks fixed.

2. Check for tampering. •

Check the seals for signs of tampering or missing seals. Also check the entire unit for any signs of tampering or any indication of repair since the last inspection (see Chapter 8, “Seals and Security”).

3. Remove necessary seals (see Chapter 8, “Seals and Security”). 4. Record the meter reading. 5. Read and record the total hours run on the elapsed time counter (hour meter), if so equipped. 6. Check the level of the liquid in the sales tank. •

Make sure there is enough liquid in the tank to check the LACT operation.


September 2002

9.6

BP Pipelines


7. Check the flow rate. •

Calculate the current flow rate in barrels per hour. Do this by timing the flow with a stopwatch for 36 seconds and multiplying by 100.

•

Check that the flow rate has not changed more than ±15% from the last meter proving.

•

If it has changed more than ±15%, readjust the flow rate or reprove the meter. If the change in flow rate is the result of equipment malfunctioning, shut down the unit until the problem is repaired.

•

Calculate the volume run through the meter since the last checkout and ensure that it is reasonable.

8. Check the programmable clock on the control panel. •

If the LACT is equipped with a clock to control on-off scheduling, check it for proper setting and operation. Follow the manufacturer’s instructions.

9. Check the height of the low-level switch on the LACT tank. •

If the sales tank is equipped with an adjustable pressure-activated level switch, check that the shutdown level is at least two feet above the connection height.

10. Check the LACT operation. •

If the LACT unit is not running and there is enough liquid in the tank, turn on the LACT by switching the Hand/Off/Auto switch to “Hand.” If the unit is running, perform the following checks without adjusting the Hand/Off/Auto switch.

•

Observe the unit’s operation. ◊ Check for smooth startup and operation. ◊ Check for leaks, excessive vibrations, high pressure, and unusual noises.

•

Check the level of sample in the sample pot to make sure it has increased since the previous observation. The pot should be filling the entire time the LACT unit is running. If it is not, the sample probe may be plugged or broken and may need to be repaired or replaced.

•

Check the sampler operation. ◊ Note whether the sampler is sampling at the proper interval. The interval frequency is based on the size of the parcel, extractor grab size, and the sample receiver (pot) volume. The flow meter volumetrically paces sampler operation. The interval may be preset in a flow computer, PLC, Durant counter, or sampler controller. ◊ Check that the sampler is completing its cycle and not hanging in the open or closed position. To do this, you may need to disconnect the sample line from the extractor and catch one or two samples from the sampler in a 100-ml centrifuge tube.


September 2002

9.7

BP Pipelines


◊ Measure the amount of sample being taken per grab. Then verify that the correct amount of sample is being taken for the amount of liquid being transferred. ◊ Use the number of milliliters per grab to calculate how many gallons per transfer (batch or parcel) are being taken: bbls per transfer --------------------------------------------------------- = grabs per transfer number of bbls per grab grabs per transfer × ml sample per grab = ml sample per transfer ml sample per transfer ----------------------------------------------------- = gallons of sample per transfer 3,785 •

Check the pressure in the sample storage pot, if one is available and operable. The sample pot should have some pressure in it, but no more than 15 psi.

•

Check the S&W monitor. ◊ After the LACT has run for two minutes (to purge the liquid in the line), obtain a line sample and grind it out in the centrifuge. ◊ Reset the S&W Limit knob to the grindout value obtained to verify that the “bad oil” indicator light comes on. Check that the timer times out after 30 seconds and the diverter valve moves to the “divert” position. After the valve diverts, make sure the meter has stopped completely. ◊ Turn the S&W Limit knob back to the maximum allowable percentage of water. Check that the “merchantable oil” light comes on, the timer times out, and the diverter valve returns to the pipeline position. If this does not happen, grind out another sample to check that the S&W level has not gone above the maximum allowable percentage of water. If the monitor does not divert or diverts at the wrong S&W level, then it must be repaired or recalibrated. Follow the manufacturer’s recommendations for repairing or calibrating the monitor. ◊ Record the S&W percentage from the line sample on the LACT/ACT checklist.

•

If the Hand/Off/Auto switch is set to “Auto,” check the meter monitor on the control panel. Close a suction valve on the LACT pump to stop the meter. Check that the unit shuts down on “meter failure” within 5 minutes. After shutdown, open the suction valve and reset the LACT control panel. Make sure the unit starts operating again.

•

Check the temperature and pressure averagers. ◊ Insert a glass thermometer into the thermowell adjacent to the meter. Read the temperature on the glass thermometer and the temperature shown on the temperature averager (TA) display. Record these two temperatures on the form or checklist.


September 2002

9.8

BP Pipelines


◊ Check the pressure averager by comparing that reading with the pressure indicated on the pressure gauge on the unit. Record the two pressure readings on the form or checklist. ◊ If the temperatures disagree by more than 0.2°F and/or the pressure disagrees by more than 5 psi, shut down the equipment and repair or recalibrate it. •

Check the mechanical meter register (PD meter) for jerky or erratic movement. Monitor the register for at least 10 barrels to make sure it is operating properly. If the system also has a flow computer, compare the mechanical register’s total barrels to the flow computer’s total barrels. If they do not agree, shut down the system and arrange for repairs.

•

If the meter has a local electronic register, record the batch total barrels and compare this to the batch total barrels on the flow computer display. If these do not agree, shut down the system and arrange for repairs.

•

Note any unusual observations in the Remarks section on the checklist. Sign or initial the checklist.

•

Return the LACT to normal operation. If you encountered no problems during the LACT checkout and you had previously turned the Hand/Off/Auto switch to “Hand,” turn the switch back to the “Auto” position.

11. Replace any seals that were broken during the LACT/ACT checkout, as well as any missing seals and any seals showing signs of excessive age (see Chapter 8, “Seals and Security”).


September 2002

9.9

BP Pipelines


Calibrating Temperature Devices Temperature transmitters can be located at the following points in a metering system: •

Downstream of the meter run

•

At the inlet and outlet of the meter prover

•

At the densitometers

If during verification a temperature is out of tolerance (greater that 0.2°F), check both the RTD and the transmitter to determine which is in error. Check or calibrate the RTD and transmitter independently in accordance with the manufacturer's instructions.

Calibrating Pressure Transducers Pressure transducers are located at the following points in the metering system: •

At the upstream header

•

At the inlet and outlet of the meter prover

•

At the densitometers

•

Across the differential pressure points of the upstream in-line filter or strainer in each meter run

If during verification, a pressure is out of tolerance (greater that 5 psig), use a certified deadweight tester for calibration.


September 2002

9.10

BP Pipelines


Overview of the ELM System An ELM is a metering system that uses calculation equipment with API liquid measurement algorithms and security/auditing features, on-line temperature and pressure inputs, density inputs (optional), and linear meter pulse inputs. ELM provides real-time, on-line measurement. An ELM can be a flow computer or a properly programmed PLC or SCADA system. To function properly the system requires certain protections: •

All sources of transient electrical noise must be eliminated. ◊

Do not use a 2-way radio near the flow computer.

◊

Do not locate or run an electric motor near the flow computer.

•

Use three- or four-wire 100-ohm platinum RTDs to eliminate error due to changes in ambient temperature.

•

The flow computer must be secure from unauthorized access. See Chapter 8, “Seals and Security” for more information about security for an ELM system.

Functions of the Flow Computer The flow computer receives information either manually from authorized BP personnel or as live input from transducers on the LACT/ACT unit. It generates meter tickets that meet API standards for reporting and calculating quantities of liquid petroleum that pass through a meter. The computer can also display custody transfer and meter ticket information.

Manual Input You may need to enter some or all of the following information into the flow computer: •

Product name and grade

•

Product’s physical properties ◊

API gravity at 60°F

◊

Vapor pressure

◊

S&W content (crude only)

•

Month, day, year, and start and finish of each transfer/batch

•

“K” factor (pulses per barrel)

•

Meter factor

•

Batch volume required


September 2002

9.11

BP Pipelines


Live Input The computer will receive the following input data: •

Meter pulses

•

Pressure transducer signal

•

Temperature transducer signal

•

Densitometer signal, where applicable

Meter Ticket Output The computer may automatically add the following information: •

Trunk receipt or delivery

•

State, county, section, township, range

•

Operator or field location

•

Company name

•

“Delivery to” or “Receipt from”

•

“For account of”

•

Crude grade

•

Consignee

•

Reid vapor pressure

•

Credit

•

“Moved to line or station”

•

Month, day, year, ticket number, batch number

•

Meter number

•

Observed gravity, observed temperature, API gravity at 60°F

•

Product code

•

Percentage of S&W

•

Meter data ◊

Transaction number

◊

Ticket or batch number

◊

“Off” reading (in barrels to the nearest tenth)

◊

“On” reading (in barrels to the nearest tenth)

◊

Flow-weighted average pressure (psig)

◊

Flow-weighted average line temperature (°F)

September 2002

9.12

BP Pipelines


◊

Metered volume (in barrels to the nearest tenth)

◊

“Temperature compensated” (yes or no)

◊

Meter factor

◊

Compressibility factor

◊

Indicated (metered) barrels

◊

Gross standard barrels

◊

Net standard barrels

◊

Station totals (if multiple meters)

•

Name of BP Pipelines representative, electronic ID, date — “on” meter volume

•

Name of BP Pipelines representative, electronic ID, date — “off” meter volume

Data from the ELM is usually transmitted electronically via the SCADA system to the Tulsa Control Center.


September 2002

9.13

BP Pipelines


More About It In this section you will find Figure 9.2, an example of a LACT/ACT inspection form, and Figure 9.3, a blank inspection form that you can copy and use.

Figure 9.2. Sample LACT/ACT inspection form


September 2002

9.14

BP Pipelines


Figure 9.3. Blank LACT/ACT inspection form


September 2002

9.15

BP Pipelines


Reference Documents 1. API Manual of Petroleum Measurement Standards, Chapter 6.1 “Metering Assemblies – Lease Automatic Custody Transfer (LACT) Systems” 2. API Manual of Petroleum Measurement Standards, Chapter 6.6 “Pipeline Metering Systems” 3. API Manual of Petroleum Measurement Standards, Chapter 21.2 “Flow Measurement – Electronic Liquid Measurement” 4. BP Self-Study Guide, Field Specialist IV – Module 4 “LACT/ACTs and their Components” 5. Pipelines (NA) Business Unit Safety Manual


September 2002

9.16

Chapter 10

Automatic Sampling Quick Reference Safety •


•

Some petroleum products are extremely flammable and/or poisonous. Follow the applicable safety procedures in the Pipelines (NA) Business Unit Safety Manual when sampling these dangerous liquids.

Summary of Measurement Procedures for Flowing Liquids 1. Check the operation of the LACT/ACT unit and ELM system or meter installation (Chapter 9).

•

Wear safety glasses or goggles at all times while handling pressurized receivers.

•

Keep containers closed when not in use.

2. Check meter operation (Chapter 11, Chapter 12, Chapter 13).

•

Keep work areas as clean as possible and well-ventilated.

3. Mix and withdraw samples (Chapter 10).

•

Clean up spills promptly and in accordance with safety, health, and environmental regulations.

•

Observe established exposure limits, and wear suitable protective clothing and equipment.

•


•


Scope These procedures apply to crude oil and products flowing through LACT or ACT units.

4. Analyze the samples as required for the specific type of transaction and product (Chapter 2, Chapter 5, Chapter 6). 5. Prove the meter (Chapter 14). 6. Calibrate temperature and pressure devices (Chapter 9). 7. Verify/calibrate the densitometer, as appropriate (Chapter 9). 8. Record all results (Chapter 17).

Summary of Procedures for Handling Automatic Samples •

Keep transfers between containers to a minimum to prevent loss of light ends, loss of water, and contamination of the sample.

•

Do not reuse disposable cans or bottles.

•

Make sure that sample containers are clean.

•

Inspect sample receivers (pots) regularly.

BP Pipelines

September 2002


•

Mix samples for the correct amount of time.

•

Label each sample before taking it to the laboratory for testing.

•

Test for S&W, temperature, and gravity, as required.

Summary of Automatic Sampling System Design •

Conditioning equipment upstream of the sampling location to mix the liquid

•

Sample probe and extractor to collect the sample from the center of the pipe

•

Automatic controller to control the frequency and thus the volume of sample taken per batch

•

One or more sample receivers (pots) to hold the extracted sample

•

Sample receiver mixing system

BP Pipelines

September 2002






• Stopwatch





• Sample heater








• Sample heater



• Sample(s)

• Centrifuge











BP Pipelines

September 2002


BP Pipelines


Introduction An automatic sampler, which is part of a meter installation, periodically withdraws small amounts of liquid from a pipeline and delivers it to a stationary or portable sample receiver (pot). The amount it removes is proportional to the flowthrough the pipeline. If the automatic system is set up and maintained properly, it provides a more representative sample of the liquid in the pipeline than manual sampling. After taking the sample from the automatic sampler, your job is to continue to handle it in such a way that the sample you deliver for analysis is still representative of the flowing fluid.

Equipment You Will Need for Automatic Sampling •

Sample containers (cans or bottles)

•

Portable receivers (when applicable)

•

Sample(s)

•

Solvent for washing sample containers

•

Security seals and seal cutters

•

Equipment for gravity and temperature testing (see “Equipment You Will Need for Measuring Flowing Liquids”)

•

For LACT units, equipment for determining S&W (see “Equipment You Will Need for Measuring Flowing Liquids”)

Automatic Sampling

September 2002

10.4

BP Pipelines


Procedures for Handling Samples The best way to handle a sample is to test directly from the container that first received the sample, as is usual when sampling from tanks. However, samples from automatic systems fill stationary or portable receivers, from which you withdraw samples for testing. •

Keep transfers between containers to a minimum to prevent loss of light ends, loss of water, and contamination of the sample.

•

Do not reuse disposable cans or bottles.

•

Make sure that sample containers are clean.

Preparing and Maintaining Stationary and Portable Sample Receivers Inspect sample receivers regularly. •

Replace septa, seals, diaphragms, and other expendable parts before they fail.

•

Make sure the inside coating is intact and free of rust.

See “More About It” at the end of this chapter for more information about what type of mixing procedure to use for different tests.

Handling Portable Sample Receivers When handling portable receivers, follow these steps. 1. Disconnect the receiver from the sampling system. 2. Connect a clean receiver to the sampling system. 3. Take the receiver to the mixing skid and connect it to the skid. 4. Mix the sample for the required time and extract a sample for analysis.

Automatic Sampling

September 2002

10.5

BP Pipelines


Handling Samples Taken from a Stationary or Portable Sample Receiver When the system has more than one stationary sample pot, it will have manual valves or solenoid valves to switch from one receiver to another (see BP Self-Study Guide “Sediment and Water Determination” for more information). Handle samples taken from a stationary or a portable receiver in the same way. 1. Mix the contents of the sample pot for at least 5 minutes, depending on the temperature, density, and viscosity of the sample. Determine this mixing time for each specific mixing system and crude oil. 2. Purge the sample tap and draw the required samples. If the water is to be determined by Karl Fischer, the circulating system may have a septum installed to allow the sample to be drawn directly into a syringe. 3. Test the samples for S&W and gravity, as required (see Chapter 5, “Testing Crude Oil for Suspended Sediment and Water” and Chapter 2, “Gravity and Temperature Measurement in Tanks”). 4. Empty, inspect, and clean the sample pot with a solvent, such as Varsol or the equivalent. 5. Label the sample before delivering it to the laboratory for testing. Clearly mark the sample can or bottle, preferably with an oil-resistant, wired-on label, with the following information: •

Date and location of the sampling operation

•

Name of pipeline terminal, marine vessel, or platform

•

Type of crude oil or product

•

Batch transfer size

•

Volume of collected sample

•

Sampling period duration, including the date and start and finish of each transfer/batch

•

Type or tag number of automatic sampling system

•

Name of the pipeline operator responsible

6. Take the marked container(s) immediately to the laboratory for analysis, as gravity testing must take place within 2 hours of taking the sample. 7. Empty the sample receiver, and flush it with solvent. Take extra care to clean the receiver after sampling a high water content batch of crude oil. 8. Periodically open the receiver and wipe it clean with a lint-free rag. Make sure the top is clean and dry.

Automatic Sampling

September 2002

10.6

BP Pipelines


Acceptance Testing of the Sampling System Testing the sampling system confirms that its design allows it to take accurate samples. The test methods fall into two general categories: component testing and total system testing. The two methods are equally valid. Once a system’s design has been proven by testing, subsequent systems of the same design operated under the same or less critical conditions need not be tested.

Total System Testing Total system testing is a volume balance test in which a known amount of water is injected into a known amount of oil. The sampling system collects a sample of the injected volumes, which is then analyzed for water content. The result is compared to the known baseline water in the oil plus the injected water. One method of total system testing involves only the sampler being tested. You must know the amount of baseline water in the oil to use this method. A second method uses an additional sampler to measure baseline water in the oil. Testing the total system requires that the data from two consecutive tests repeat within the tolerance stated for the test.

Receiver Testing The sample receivers are also tested to assure that they properly mix the oil collected in the receiver. Tests are conducted at both low and high levels in the receiver, as well as low and high water concentrations. An independent third party usually performs the testing of the sample and receiver, in accordance with API procedures. This testing is required by U.S. Customs for sampling systems associated with foreign trade zones (FTZ).

Automatic Sampling

September 2002

10.7

BP Pipelines


Design and Operation of an Automatic Sampling System To assure a representative sample, an automatic system must do the following: •

It must disperse free and entrained water and sediment uniformly at the sampling point.

•

It must extract and collect individual grabs (samples) in a flow-proportional manner, and each grab must have the same volume.

•

It must maintain the sample in the sample receiver without changing the composition of the sample.

The following equipment is part of the sampling system (see Figure 10.1): •

Conditioning equipment upstream of the sampling location to mix the liquid

•

Sample probe and extractor to collect the sample from the center of the pipe

•

Automatic controller to control the frequency (number of grabs) based on the flow and thus the volume of sample taken per batch

•

One or more sample receivers (pots) to collect and hold the extracted sample grabs

Conditioning equipment (pump, vertical pipe, elbows, tees, reduced-diameter pipe)

Flow Sample extractor and probe

Flow signal Controller

Sample grab discharge

Sample receiver

(in downward sloping line)

Figure 10.1. Design of an automatic sampling system

Automatic Sampling

September 2002

10.8

BP Pipelines


Sample Receivers (Pots) Sample pots may be stationary or portable, pressurized or nonpressurized. A fixed, or stationary, sample receiver holds the sample under sufficient pressure to prevent the escape of vapors (Figure 10.2). It usually has a capacity of between 5 and 15 gallons (see Table 10.2 under “More About It”).

Flow

Sample extractor and probe

Fixed sample receiver Gauge glass Sample discharge line

Mixing system

Figure 10.2. Fixed sample receiver (stationary sample pot)

Automatic Sampling

September 2002

10.9

BP Pipelines


Portable receivers (Figure 10.3) vary in size from 5 to 10 gallons. Normally they are not pressurized; if they are, the pressure is less than 15 psig.

Quick connection

Vacuum relief

Level gauge

Pressure relief

Optional high-level switch

Sample inlet port

Pressure gauge

Downcomer

Quick connection

Figure 10.3. Portable sample receiver (pot) Constant-pressure receivers may be used for high-vapor-pressure crude oils and products. They may also be used for low-pressure liquids if loss of light ends is a problem. Automatic sampling systems on stabilized crude oil pipelines usually use nonpressurized receivers.

Automatic Sampling

September 2002

10.10

BP Pipelines


Mixing Equipment Fixed sample receivers come equipped with mixing elements so you can properly mix the composite sample before testing for S&W or other components. Different types of mixers are available. Portable receivers require a separate mixing system (Figure 10.4).

Mixing system Sample draw-off valve

Flex hose Portable receiver

Motor starter switch

Static mixer Quick connects

Motor

Figure 10.4. Sample mixing system for portable receivers BP Pipelines prefers a centrifugal pump installed as close as possible to the sample pot outlet connection. This pump must be capable of displacing the entire sample volume at least twice per minute. The piping from the pump back to the sample pot must also be arranged so that no sediment and water can be trapped in low spots and so that you can withdraw a sample while mixing is taking place. A pressure gauge on the return line to the pot indicates that the pump is working properly while mixing. When emptying the container, watch the pressure gauge, which will indicate when the container is empty by a decrease in pressure.

Automatic Sampling

September 2002

10.11

BP Pipelines


More About It This section includes the following tables and instructions for using them. •

Table 10.1. Recommended Mixing Procedures

•

Table 10.2. Typical Sizes of Sample Receivers for Various Operations

Mixing Samples A sample may or may not need to be mixed before testing it, depending on the type of test and how homogeneous the sample is. Because an automatic sampling system takes samples over a period of many hours, some settling almost always occurs. You can mix a sample with a stand-alone power mixer (see Figure 10.4), with an internal mixer in the sample pot, or by shaking it. When using a stand-alone power mixer, be sure to use the correct type for the container you have, as the mixer/container combination has been tested and proven effective. Table 10.1 lists the mixing recommendations for various tests.

Table 10.1. Recommended Mixing Procedures Recommended Mixing Procedure Test Purpose* Power Density for crude and heavy fuels

X

Sediment and water

X

Density for other hydrocarbons

*

Shaking

None

X

Vapor pressure

X

Cloud point

X

Sample transferred from a container. For tests not listed, refer to the specific test procedure.

Automatic Sampling

September 2002

10.12

BP Pipelines


Sizes of Sample Pots The size of a sample receiver depends on the total volume of sample needed for all tests, the number of grabs required, the volume of each grab, and the transportability if the receiver is portable. Table 10.2 shows typical receiver sizes for different applications.

Table 10.2. Typical Sizes of Sample Receivers for Various Operations Type of Operation

Receiver Size

LACT unit

3–15 gallons

Pipeline (crude oil)

5–15 gallons

Pipeline (products)

1–5 gallons

System with portable receiver

1 quart to 10 gallons

Tanker loading/unloading

5–20 gallons

Line fill (marine)

Volume required for tests

Automatic Sampling

September 2002

10.13

BP Pipelines


Reference Documents 1. API Manual of Petroleum Measurement Standards, Chapter 8.2 “Automatic Sampling of Petroleum and Petroleum Products” 2. API Manual of Petroleum Measurement Standards, Chapter 8.3 “Mixing and Handling of Liquid Samples of Petroleum and Petroleum Products” 3. API Manual of Petroleum Measurement Standards, Chapter 21.2 “Flow Measurement — Electronic Liquid Measurement” 4. BP Self-Study Guide, Field Specialist III — Module 1 “Sediment and Water Determination” 5. Pipelines (NA) Business Unit Safety Manual

Automatic Sampling

September 2002

10.14

Chapter 11

Positive Displacement Meters Quick Reference Safety •


Scope This chapter lists procedures for inspecting PD meters used for custody transfer of crude oil or liquid petroleum products. It also describes the design and operation of positive displacement meters.

Summary of Inspection Procedures •

Inspect the meter and accessory equipment.

•

Verify correct combination of gearing and stack accessories to ensure accurate measurement (during repair or original installation). ◊ Use 100% gearing with a dummy calibrator.

Summary of Measurement Procedures for Flowing Liquids 1. Check the operation of the LACT/ACT unit and ELM system or meter installation (Chapter 9). 2. Check meter operation (Chapter 11, Chapter 12, Chapter 13). 3. Mix and withdraw samples (Chapter 10). 4. Analyze the samples as required for the specific type of transaction and product (Chapter 2, Chapter 5, Chapter 6). 5. Prove the meter (Chapter 14).

•

Meter should operate between 40% and 80% of the manufacturer’s rated capacity.

6. Calibrate temperature and pressure devices (Chapter 9).

•

Possible meter maintenance required when the meter factor varies from the previous proving at the same flow conditions by more than

7. Verify/calibrate the densitometer, as appropriate (Chapter 9).

◊ ±0.0015 for ACT meters.

8. Record all results (Chapter 17).

◊ ±0.0025 for LACT meters. •

Meter maintenance required when the meter factor varies by more than ±0.0050 from the original meter factor.

•

Meter factors should be trended to monitor the condition of the metering system.

BP Pipelines

September 2002






• Stopwatch





• Sample heater








• Sample heater



• Sample(s)

• Centrifuge











BP Pipelines

September 2002


BP Pipelines


Introduction Displacement meter systems normally perform well for long periods with a minimum of maintenance. In addition to proving the meter to establish its accuracy (see Chapter 14, “Proving a Meter”), a positive displacement meter and its accessory equipment need to be inspected on a routine basis. The frequency of inspections depends on volume through the meter, but should be at least weekly.

Equipment You Will Need for Checking the Meter •

Seals and cutters

•

Tools for checking the meter and accessories

Positive Displacement Meters

September 2002

11.3

BP Pipelines


Inspecting the Meter and Accessory Equipment Meters and meter accessories are installed in a variety of configurations, so sealing devices and locations will vary. Figure 11.1 shows the sealing points on a typical PD meter.

Meter head 4 6 3 7

0

Proximity switch Right-angle drive PEXP (pulse electronic transmitter)

Typical seals

Flow

Figure 11.1. Sealing points on a PD meter To repair a meter, disassemble it, inspect it, clean and adjust it, reassemble it, and prove it. Perform all maintenance according to the manufacturer’s instructions and procedures. Keep records of all maintenance and testing you do. Inspect the equipment routinely (at least weekly, depending on throughput) following the list below. 1. Meter •

Listen for noisy operation, which may indicate that the meter is wearing and may fail soon. If necessary, shut the meter down and use alternative measurement methods until it can be taken apart and repaired.

•

Inspect the meter for vibrations and leaks.

•

Inspect the lubrication system.

•

Verify the pulse transmitters by comparing the barrels on the mechanical register with the barrels on the electronic register.

•

Meter proving verifies meter performance. Watch for and report meters that fail the repeatability requirements or that have a meter factor that varies by more than ±0.0015 for ACT meters or ±0.0025 for LACT meters since the last proving.


September 2002

11.4

BP Pipelines


•

Maintenance is necessary when the meter factor varies by more than ±0.0050 from the original meter factor.

•


2. Strainer and air eliminator •

Inspect the strainer and air eliminator before every custody transfer.

•

Clean the strainer whenever the differential pressure is greater than normal.

•

Repair the strainer and eliminator as needed.

3. Flow computer •

Follow the manufacturer’s instructions for verifying the status of batch information on the flow computer before every custody transfer.

4. Counters, indicators, and volume-averaging devices •

Follow the manufacturer’s recommendations for maintenance, if any.

•

Inspect the device for defects before every custody transfer and notify your supervisor if any part of the device appears defective.

5. Double block-and-bleed valves •

Check these valves for leaks before every custody transfer.

•

Drain or monitor the cavity between the dual seals. If you see a leak, notify your supervisor and initiate repairs as soon as possible.

When you suspect measurement error with a meter, use the following checklist to determine the specific problem: 1. Check for air or vapor in the system. 2. Determine whether there have been any changes in the physical properties of the metered liquid, especially its viscosity. 3. Check pressure, temperature, and density-sensing devices for error. 4. Check all electrical equipment for any failures, including the pulse generator, counters, coil, preamplifiers, signal transmission system, power supply, and all readout devices. 5. Check for leakage from all isolation and diversion valves. 6. Check for proper gearing in the meter accessory drive.


September 2002

11.5

BP Pipelines


Design and Operation of a Positive Displacement Meter The positive displacement (PD) meter is used throughout the industry and is one of the oldest of the mechanical devices for measuring liquid. This type of meter breaks up the flow of liquid into discrete portions of known volume and then counts those portions. PD meters are preferred for higher-viscosity fluids and for lower flow rates. A positive displacement meter consists of the external housing, the internal measuring element, and the counter drive train. Mounted on top of the meter housing are meter accessories, collectively known as the meter stack. A typical PD meter is shown in Figure 11.2.

Meter head 4 6 3 7

0

Proximity switch Right-angle drive PEXP (pulse electronic transmitter)

Flow

Figure 11.2. Typical positive displacement meter


September 2002

11.6

BP Pipelines


Design of a PD Meter Installation The following lists some of the equipment that a PD meter installation may include in addition to the meter. See Figure 11.3 below. Shaft-driven (mechanical) accessories: •

Gear train that transmits force and motion from the rotating meter shaft to the accessories

•

Primary register to totalize and display the measurement units

•

Pulse generator that provides pulses in direct proportion to the meter throughput

•

Preset device to stop the flow at a preselected quantity

•

Rate-of-flow indicator (mechanical)

Pulse-driven (electronic) accessories: •

Readout that indicates the volume

•

Flow computer that receives signals from the meter and other sensors to calculate volume or mass flow quantity and displays, transmits, and prints the data

•

Preset totalizer to stop the flow at a preselected quantity

•

Proving counter that displays the pulsed output from the meter

•

Flow-rate indicator that converts an electrical signal to a visual display of flow rate

Protection and control equipment: •

Strainers and filters to prevent solids from entering the meter

•

Air or vapor eliminator to remove gases from the liquid flow

•

Valve for starting, stopping, and controlling the flow of liquid

•

Pressure-reducing valves

•

Temperature, pressure, density, and viscosity monitors

•

Thermometer

•

Temperature and pressure averagers

•

Pressure gauges


September 2002

11.7

BP Pipelines


Sample receivers

Flow computer To SCADA

Static mixer

Liquid density transducer

Mixing pump (optional)

Flow

Pulse transmitter

Pressure/ differential gauge

Sample probe

RTD transmitter

Flow scoop

Backpressure or flowcontrol valve, if required

Twin seal valves

PD meter Strainer

Sample controller

For test Drain thermoPressure valve well transmitter

Pressure gauge local

Detector switch Bidirectional prover Detector switch

Connections for master meter check or recalibration of prover

Gating circuit to flow computer above

4-way diverter valve with electric motor operator

Figure 11.3. Design of a PD meter installation

Some Specifications for PD Meter Installations PD meters are very accurate when the installation is properly designed and the equipment is maintained. The installation should take into account the following considerations. 1. It should be able to handle the maximum and minimum flow rates, the maximum operating pressure, and the temperature range of the liquid being measured. If necessary, it should include protective devices that keep the operation of the meter within design limits. This could include flow control valves, use of multiple meters, and flow limit set points in the flow computer. 2. The electronic counter must count the same number of pulses that the meter generates to determine a volume. 3. The installation should include strainers, filters, air/vapor eliminators, or other protective devices to remove solids in the flow that could cause the meter parts to wear out prematurely or to remove air/vapor that could cause measurement errors. 4. The installation should ensure enough pressure on the flow that it remains liquid at all times. 5. It should allow meter proving under normal operating conditions. 6. It should comply with all company specifications and applicable regulation and codes.


September 2002

11.8

BP Pipelines


API Manual of Petroleum Measurement Standards, Chapters 5.2 and 5.4, provides guidelines for choosing the appropriate accessory equipment and designing the piping configuration for a PD meter installation. It is important that an installation use the accessory equipment that the manufacturer recommends, that the flow rates are within those that the manufacturer specifies, and that meters are operated only with the liquids the installation was designed for. For example, the combination of measuring element, gear train, and stack accessories must be carefully matched to provide accurate volume registration. Use 100% gearing with a dummy calibrator. Table 11.1 offers some recommended combinations.

Table 11.1. Recommended Combinations of Meter Size, Measuring Element, and Gear Ratio Meter Size

Typical Measuring Element (volume per revolution)

Gear Ratio of Meter’s Gear Train

Output to Calibrator (volume per revolution)

2"

0.364 gal

13.7:1

5 gal

3"

1.4 gal

3.57:1

5 gal

4"

2 gal

5:2

5 gal

6"

3 gal

5:3

5 gal

6"

0.0714 bbl

14:1

1 bbl

8"

0.1428 bbl

7:1

1 bbl

10"

0.236 bbl

4.24:1

1 bbl

12"

0.5 bbl

2:1

1 bbl

16"

1 bbl

1:1

1 bbl


September 2002

11.9

BP Pipelines


PD meters should be sized to operate between 40% and 80% of the manufacturer’s rated capacity. Operating a meter in this range improves accuracy and extends meter life. The following table gives examples of recommended operating ranges for PD meters typically used by BP Pipelines.

Table 11.2. Recommended Operating Range for Various Sizes of PD Meters Flow Rate (bph) Meter Size 20%

40%

80%

100%

2"

36

72

144

180

3"

120

240

480

600

4"

172

344

688

860

6"

286

572

1,144

1,430

8"

458

916

1,832

2,290

10"

700

1,400

2,800

3,500

12"

1,300

2,600

5,200

6,500

16"

2,500

5,000

10,000

12,500

Note: Shaded columns are outside the optimum range.


September 2002

11.10

BP Pipelines


Operation of a PD Meter The accuracy of a meter depends on the properties of the liquid being measured, the condition of the meter and its accessories, the meter’s operating conditions, and variations, if any, between operating and proving conditions. Table 11.3 shows the results of changes in some of these factors.

Table 11.3. Effect of Changes in the Conditions of the Fluid and PD Meter on Measurement Accuracy Factor Fluid properties

Meter conditions


Change in Conditions

Result

Meter Factor Change

Increase in • temperature • viscosity • gravity

Increased slippage → underregistration

Increases

Decrease in • temperature • viscosity • gravity

Decreased slippage → overregistration

Decreases

Entrained air in the liquid

Air or gas measured along with the hydrocarbons → overregistration

Decreases

Low lubricating properties of the liquid

Increased wear on meter parts → underregistration

Increases

Contaminants in the liquid

Possible damage to meter parts → underregistration

Increases

Wear


Increases

Friction


Increases

Deposits (for example, paraffin)

Coating on meter surface → overregistration

Decreases

September 2002

11.11

BP Pipelines


Table 11.3. Effect of Changes in the Conditions of the Fluid and PD Meter on Measurement Accuracy (continued) Factor


Operating conditions

Control valve chatter

Pulsating flow → overregistration

Decreases

Use of a reciprocating pump ahead of the meter


Decreases


Result

September 2002

Meter Factor Change

11.12

BP Pipelines


Reference Documents 1. API Manual of Petroleum Measurement Standards, Chapter 5.1 “General Considerations for Measurement by Meters” 2. API Manual of Petroleum Measurement Standards, Chapter 5.2 “Measurement of Liquid Hydrocarbons by Displacement Meters” 3. API Manual of Petroleum Measurement Standards, Chapter 5.4 “Accessory Equipment for Liquid Meters” 4. BP Self-Study Guide, Field Specialist IV — Module 4 “Meters and Meter Proving” 5. Pipelines (NA) Business Unit Safety Manual


September 2002

11.13

Chapter 12

Turbine Meters Quick Reference Safety •


Scope This chapter lists procedures for inspecting turbine meters used for custody transfer of crude oil or liquid petroleum products. It also describes the design and operation of turbine meters.

Summary of Inspection Procedures •

Inspect the meter and accessory equipment.

•

Conventional turbine meters should operate between 50% and 100% of the manufacturer’s rated capacity, while helical turbines can be operated down to 20% of the manufacturer’s rated capacity.

•

Possible meter maintenance required when the meter factor varies from the previous proving at the same flow conditions by more than ±0.0015.

• •

Meter maintenance required when the meter factor varies by more than ±0.0050 from the original meter factor. Meter factors should be trended to monitor the condition of the metering system.

BP Pipelines

September 2002

Summary of Measurement Procedures for Flowing Liquids 1. Check the operation of the LACT/ACT unit and ELM system or meter installation (Chapter 9). 2. Check meter operation (Chapter 11, Chapter 12, Chapter 13). 3. Mix and withdraw samples (Chapter 10). 4. Analyze the samples as required for the specific type of transaction and product (Chapter 2, Chapter 5, Chapter 6). 5. Prove the meter (Chapter 14). 6. Calibrate temperature and pressure devices (Chapter 9). 7. Verify/calibrate the densitometer, as appropriate (Chapter 9). 8. Record all results (Chapter 17).






• Stopwatch





• Sample heater








• Sample heater



• Sample(s)

• Centrifuge











BP Pipelines

September 2002


BP Pipelines


Introduction Turbine meter systems normally perform well for long periods with a minimum of maintenance. In addition to proving the meter to establish its accuracy (see Chapter 14, “Proving a Meter”), a turbine meter and its accessory equipment need to be inspected on a routine basis. The frequency of inspections depends on volume through the meter, but should be with each batch or at least weekly.

Inspection and Maintenance Procedures Turbine meter systems normally perform well for long periods without an established maintenance schedule. Your main maintenance job is proving the meter to determine its accuracy (see Chapter 14, “Proving a Meter”). Proving establishes a number called the meter factor, which is a correction factor for that particular meter. The meter factor also indicates when a meter’s performance changes to the extent that it needs repair.

Turbine Meters

September 2002

12.3

BP Pipelines


Inspecting the Meter and Accessory Equipment Do not indiscriminately make adjustments or disassemble a turbine meter, as it is neither necessary nor recommended. Perform all maintenance according to the manufacturer’s instructions and procedures. Keep records of all maintenance and testing you do. Inspect the equipment during every transfer. 1. Meter •

Inspect the meter for vibrations and leaks.

•

Verify the pulse transmitters by comparing the local registered volume (if available) to the electronically registered volume.

•

Meter proving verifies meter performance. Watch for and report meters that fail the repeatability requirements or that have a meter factor that varies by more than ±0.0015 for ACT meters or ±0.0025 for LACT meters since the last proving at the same flow conditions (see Chapter 14, “Proving a Meter”).

•

Meter maintenance required when the meter factor varies by more than ±0.0050 from the original meter factor.

•


2. Strainer and air eliminator •

Inspect the strainer and air eliminator before every custody transfer.

•

Clean the strainer whenever the differential pressure is greater than normal.

•

Repair the strainer and eliminator as needed.

3. Flow computer •

Follow the manufacturer’s instructions for verifying the status of batch information on the flow computer before every custody transfer.

4. Counters, indicators, and volume-averaging devices •

Follow the manufacturer’s recommendations for maintenance, if any.

•

Inspect the device for defects before every custody transfer and notify your supervisor if any part of the device appears defective.

5. Double block-and-bleed valves •

Check these valves for leaks before every custody transfer.

•

Drain or monitor the cavity between the dual seals. If you see a leak, notify your supervisor and initiate repairs as soon as possible.

6. When you suspect measurement error with a meter, check it immediately. See Chapter 14, “Proving a Meter” for a checklist to determine the specific problem.

Turbine Meters

September 2002

12.4

BP Pipelines


Design and Operation of a Turbine Meter Turbine meters are used in the custody transfer of lighter hydrocarbons like gasoline, diesel fuels, and distillates as well as crudes. Turbine meters measure liquids by detecting the velocity, or flow rate, of the liquid, which is then used to determine volume. Turbine meters are in a class of meters known as inferential meters because they measure volume indirectly. Turbine meters are preferred for lower-viscosity fluids and for higher flow rates.

Conventional Turbine Meters The turbine meter consists of a meter housing containing a rotor in a closed conduit (Figure 12.1). Liquid flowing into a turbine meter turns the rotor, much like wind turns the blades of a windmill. The velocity of the liquid drives the rotor at a speed that is directly proportional to the volume flow rate. Typically, turbine meters include some form of electronic system for readouts and corrections.

Pickup coil Downstream stator

Rotor

Upstream stator

Deflector ring

Figure 12.1. Conventional turbine meter

Turbine Meters

September 2002

12.5

BP Pipelines


Helical Turbine Meters The helical turbine meter (Figure 12.2) is similar to the conventional turbine meter with these exceptions: 1. The rotor has only two helical-shaped blades, and they are much wider than standard blades. 2. The measuring element is mounted in a tube that can be removed from the housing. The rotor rides on a journal-bearing system. A pulse sensor located on the outer housing detects signals that indicate flow rate from small magnets embedded in the tips of the rotor blades. The rotor assembly is housed inside a separate meter body.

Pickup coil

Upstream stator

Downstream stator

Rotor

Figure 12.2. Helical turbine meter

Turbine Meters

September 2002

12.6

BP Pipelines


Design of a Turbine Meter Installation The design of a turbine meter installation (Figure 12.3) should take the following considerations into account: 1. It should be able to handle the maximum and minimum flow rates, maximum operating pressure, and the temperature range and type of liquid being measured. If necessary, it should include protective devices that keep the meter operation within design limits. 2. It should include strainers, filters, air eliminators, or other protective devices to remove solids in the flow that could cause the meter parts to wear out prematurely or to remove air/vapor that could cause measurement errors. 3. The accuracy of a turbine meter depends on both upstream and downstream flow conditions. BP Pipelines recommends that a turbine meter run have at least 20 pipe diameters of straight pipe upstream of the meter and 5 pipe diameters of straight pipe downstream of the meter. If a flow conditioner is used upstream of the meter, the upstream diameters can be reduced to 10 diameters of straight pipe (including the flow conditioner). Helical turbine meter installations require the use of a flow conditioner ahead of the meter. 4. Vibrations, piping stress, and pressure pulsations must be minimized; therefore, flow conditioning is necessary both upstream and downstream. 5. The pressure should be high enough to ensure that the crude or product will remain liquid at all temperatures. 6. It should allow meter proving under normal operating conditions. 7. It should comply with all applicable regulations and codes. API Manual of Petroleum Measurement Standards, Chapters 5.3 and 5.4, provides guidelines for choosing the appropriate accessory equipment and designing the piping configuration for a turbine meter installation.

Turbine Meters

September 2002

12.7

BP Pipelines


3-way solenoid valve

Instrument air

Regulator Mixing valve

Sample pump Balance valve

Relief valve Sample loop

Sample removal valve

Pipeline Densitometer

Flow computer

Sample vessel Densitometer proving connections

Twin seal valves

Signal preamplifier Flow conditioner Strainer

Nitrogen precharge vessel

Thermowell

Back pressure or flow control valve if required

Flow

Pressure drop indicator

Turbine meter Local totalizer

Temperature transducer Pressure gauge Detector switch

Pressure transducer

Bidirectional prover Detector switch

Connections for master meter check or recalibration of prover

4-way block & bleed valve with electric motor operator

Gating circuit to flow computer

Figure 12.3. Typical turbine meter installation for refined products

Turbine Meters

September 2002

12.8

BP Pipelines


Conventional turbine meters should be sized to operate between 50% and 100% of the manufacturer’s rated capacity. Helical turbines can be sized to operate between 30% and 100%. Operating the meters in these ranges will improve accuracy and extend meter life. Table 12.1 and Table 12.2 give examples of recommended operating ranges for both types of turbine meters used by BP Pipelines.

Table 12.1. Recommended Operating Range for Various Sizes of Conventional Turbine Meters Flow Rate (bph) Meter Size

Pulses/bbl 50%

100%

2"

160

320

7,560

3"

465

930

2,016

4"

890

1,780

3,000

6"

2,070

4,140

1,000

8"

3,710

7,420

500

10"

5,700

11,400

250

12"

8,550

17,100

200

16"

12,850

25,700

100

Note: This data will vary depending on the specific manufacturer of the meter.

Turbine Meters

September 2002

12.9

BP Pipelines


Table 12.2. Recommended Operating Range for Various Sizes of Helical Turbine Meters Flow Rate (bph) Meter Size

Pulses/bbl 30%

100%

2"

57

189

3,964.9

3"

208

692

696.7

4"

566

1,887

264

6"

1,132

3,774

113.2

8"

1,887

6,290

71.7

10"

3,774

12,580

25.8

12"

5,661

18,869

13.1

16"

7,548

25,159

7.6

Note: This data will vary depending on the specific manufacturer of the meter.

A secure and reliable pulse transmission system is also critical to a turbine meter’s accuracy. •

The transmission lines should be as short as possible.

•

Transmission lines should be routed away from sources of electrical interference.

•

Transmission lines should be continuous, if possible. If they are not, the shielding should be continuous.

•

A ground shield at the receiving end (flow computer/PLC) prevents ground-loop effects.

Turbine Meters

September 2002

12.10

BP Pipelines


Figure 12.4 and Figure 12.5 are schematics of transmission lines to turbine meters with and without preamps.

Transmission lines (max. 5,000 ft.)

3, 4, or 5/c shielded cable (external DC power supply required) Remote electronics Meter

Figure 12.4. Turbine meter with preamp

Transmission lines (max. 250 ft.)

c/c shielded cable

Remote electronics

Meter

Figure 12.5. Turbine meter without preamp

Turbine Meters

September 2002

12.11

BP Pipelines


Operation of a Turbine Meter Waxy deposits and stringy debris tend to build up on the multibladed rotor of a conventional turbine meter when measuring higher-viscosity oils. With only two blades, the helical turbine meter is much less affected by these deposits. As a result, the conventional turbine meter is generally limited to applications in which the viscosity of the oil (measured in centipoise, or cP) is no more than twice the meter size (measured in inches). For example, an 8-inch meter should be used with viscosities under 16 cP. Helical turbine meters, on the other hand, are being used increasingly in applications previously reserved for PD meters and even conventional turbine meters. Helical meters require additional electronics to perform pulse interpolation, or double chronometry, during proving since the meters generate fewer pulses per barrel. See Table 12.3 below for the effects of fluid conditions and other changes on meter accuracy.

Turbine Meters

September 2002

12.12

BP Pipelines


Table 12.3. Effect of Changes in the Conditions of the Fluid and Turbine Meter on Measurement Accuracy Factor Fluid properties

Meter conditions

Operating conditions

Turbine Meters


Result

Meter Factor Change

Entrained air in the liquid

Air or gas measured along with the hydrocarbons → overregistration

Decreases

Low lubricating properties of the liquid

Increased wear on meter parts → underregistration

Increases

Contaminants in the liquid

Possible damage to meter parts → underregistration

Increases

Upstream obstructions

Distorted velocity profile of flowing fluid → overregistration

Decreases

Cavitation due to low back-pressure

Increased velocity of fluid through meter → overregistration

Decreases

Deposits (for example, paraffin)

Reduced flow area → overregistration

Decreases

Wear

Worn bearings → underregistration

Increases

Friction

Excessive mechanical friction between meter parts → underregistration

Increases

Control valve chatter


Decreases

Use of a reciprocating pump ahead of the meter


Decreases

September 2002

12.13

BP Pipelines


Reference Documents 1. API Manual of Petroleum Measurement Standards, Chapter 5.1 “General Considerations for Measurement by Meters” 2. API Manual of Petroleum Measurement Standards, Chapter 5.3 “Measurement of Liquid Hydrocarbons by Turbine Meters” 3. API Manual of Petroleum Measurement Standards, Chapter 5.4 “Accessory Equipment for Liquid Meters” 4. BP Self-Study Guide, Field Specialist IV — Module 4 “Meters and Meter Proving” 5. Pipelines (NA) Business Unit Safety Manual

Turbine Meters

September 2002

12.14

Chapter 13

Other Meters Quick Reference Scope This chapter briefly describes the design and operation of orifice, ultrasonic, and Coriolis meters, which may be used for custody transfer of natural gas, crude oil, and liquid petroleum products.

Summary of Meter Design •

The orifice meter measures the flow rate and thus the volume by creating a pressure differential in the fluid.

•

The ultrasonic meter uses sound waves to measure flow rate and thus volume.

•

The Coriolis meter measures the mass and density of the fluid in the line, and from this measurement the volume can then be calculated.


BP Pipelines

September 2002


BP Pipelines


Introduction Meters other than PDs and turbines, such as orifice meters, are not routinely used in crude oil service. They are more commonly used to measure natural gas, LPGs, dense-phase fluids (such as ethylene), and some chemicals. Ultrasonic meters and Coriolis meters are additional types of meters that are starting to achieve recognition for both crude and products applications. These are inference meters, so called because they do not measure the liquid volume directly but infer it by measuring other properties of the liquid. See BP Measurement Manual, Part II — Natural Gas for more detailed information on orifice and ultrasonic meters, and BP Measurement Manual, Part III — Chemicals and Petrochemicals for more information on Coriolis meters.

Other Meters

September 2002

13.2

BP Pipelines


Orifice Meter The orifice meter measures the flow rate and thus the volume by creating and recording a pressure differential in the fluid.

Sensing element located behind chart

Differential pressure and static pressure recorder

Temperature recorder

LCD

219815

Computer

Pen

Gauge lines to flow recorder Pressure taps

Transducers

Chart Portable hand unit

Pressure drop

Electronic secondary element Flow Orifice flanges

Secondary element Orifice plate

Primary element Figure 13.1. Orifice meter installation The fluid passes through a plate with a small hole in it, the orifice plate (Figure 13.1), which restricts the flow and reduces the flowing pressure of the fluid. Small gauge lines in pressure taps near the orifice plate connect the fitting to a differential pressure sensor and mechanical flow recorder or to pressure transducers and a computer. The recorder or computer records the pressure drop and other variables, such as temperature and static pressure, that are necessary for calculating flow rate.

Other Meters

September 2002

13.3

BP Pipelines


Orifice plates are available in different sizes to fit different pipeline diameters. The orifice also varies in size to adjust the flow rate of the fluid. The thickness of the plate is another variable. The diameter, orifice size, and plate thickness are all important factors in designing an orifice meter installation. Orifice meters are often used for custody transfer measurement of gases and some petrochemicals, but not liquids. They are often used in refineries and chemical plants to measure both liquids and gases, but not for custody transfer.

Other Meters

September 2002

13.4

BP Pipelines


Ultrasonic Meter Ultrasonic meters are inferential meters that derive the fluid flow rate by measuring the transit times of high-frequency sound pulses. Transit times are measured for sound pulses traveling diagonally across the pipe, downstream with the flow, and also upstream against the flow. The difference in these transit times is related to the average fluid flow velocity along the acoustic paths. Numerical calculation techniques are then used to compute the average axial flow velocity and the volume flow rate at line conditions through the meter. The primary element is a tube containing at least one pair of transducers that generate and receive sound waves, and cables to connect them to an electronic processor (Figure 13.2). The processor operates the transducers, measures the travel speed of the sound waves, processes the data, and records and displays the calculated volume and other data.

Output signals Ultrasonic processor

Meter body

Transducers

Figure 13.2. Ultrasonic meter

Other Meters

September 2002

13.5

BP Pipelines


An electrical voltage vibrates the crystal or ceramic transducers, which creates sound waves in the fluid (see Figure 13.3). Each transducer can also convert sound waves to an electric signal. The processor measures the time it takes for sound to travel from one transducer to the other and back again.

Path 1 Path 2

0.5r

0.5r

View A-A

A Sonic path

A

Figure 13.3. Path of the sound waves in an ultrasonic meter

Other Meters

September 2002

13.6

BP Pipelines


Coriolis Meter Coriolis meters measure the mass, or weight, of the fluid in the line, as well as the fluid density. From these measurements the volume can then be calculated.

Drive coil

Flow

Velocity detectors

Figure 13.4. Coriolis meter The Coriolis meter has a sensor element and a transmitter (Figure 13.4). The sensor element consists of one or two flow tubes, a drive coil, and two pick-up coils (one for the left side and one for the right side). The product flows through the tube(s). The drive coil, when energized, causes the tubes to vibrate, and the flow of liquid through the tubes causes the tubes to twist (Figure 13.5 and Figure 13.6). This twisting is called the Coriolis effect. Each pick-up coil produces a sine wave that is representative of the twisting action. The phase shift between the two sine waves is directly proportional to the product’s mass flow (the greater the flow, the greater the phase shift). A temperature sensor accounts for changes in the elasticity of the tube due to temperature. As the density of the fluid increases, the frequency of tube oscillation decreases because of the dampening effect of the heavier fluid. The transmitter measures this frequency. The drive coil, pick-up coils, and the temperature sensor connect to the transmitter. The transmitter processes the signals from the sensor, determines the density and the mass and/or volumetric flow, and provides necessary inputs and outputs. Coriolis meters have been in service for measuring petrochemicals, but with the publication of two Draft API Standards in 2001, the industry is beginning use them for custody transfer measurement of crude oil and refined products.

Other Meters

September 2002

13.7

BP Pipelines


Fluid force

Vibrating frequency

Fluid force

Figure 13.5. Vibration of the flow tubes

Twist angle

Figure 13.6. Coriolis effect (twisting of the flow tubes)

Other Meters

September 2002

13.8

BP Pipelines


Reference Documents 1. BP Measurement Manual, Part II — Natural Gas 2. BP Measurement Manual, Part III — Chemicals and Petrochemicals 3. API Manual of Petroleum Measurement Standards, Chapter 14.3 “Concentric, Square-Edged Orifice Meters” 4. API Manual of Petroleum Measurement Standards, Draft Standards “Measurement of Single-Phase Intermediate and Finished Hydrocarbon Fluids by Coriolis Meters” “Measurement of Crude Oil by Coriolis Meters”

Other Meters

September 2002

13.9

Chapter 14

Proving a Meter Quick Reference Safety •

Make sure the portable prover is grounded to prevent static electricity buildup.

Summary of Measurement Procedures for Flowing Liquids

•


1. Check the operation of the LACT/ACT unit and ELM system or meter installation (Chapter 9).

Scope These procedures apply to proving meters on crude and product pipelines, using pipe provers or small-volume provers.

Summary of Procedures for LACT Units •

Prove LACT meters quarterly or every 50,000 barrels, whichever comes first unless ◊ directed otherwise by regulatory or contractual obligations, ◊ the fluid characteristics and operation require more frequent proving, ◊ the flow rate increases or decreases by 15% or more, or ◊ the gravity significantly changes.

2. Check meter operation (Chapter 11, Chapter 12, Chapter 13). 3. Mix and withdraw samples (Chapter 10). 4. Analyze the samples as required for the specific type of transaction and product (Chapter 2, Chapter 5, Chapter 6). 5. Prove the meter (Chapter 14). 6. Calibrate temperature and pressure devices (Chapter 9). 7. Verify/calibrate the densitometer, as appropriate (Chapter 9).

•

Prove after replacing or repairing the meter.

•

The meter factor is calculated from 5 consecutive runs, out of a maximum of 10 runs, that agree (highest to lowest) to within 0.05%.

•

The new meter factor must be within ±0.0025 of the previous meter factor (under the same operating conditions).

•

In most locations, apply the meter factor to the entire ticket period (often the entire month).

•

For leases under the jurisdiction of the Bureau of Land Management (BLM) or Minerals Management Service (MMS), apply the meter factor from the time of the proving forward and not retroactive to the start of the ticketing period.

BP Pipelines

September 2002

8. Record all results (Chapter 17).


BP Pipelines


Summary of Procedures for ACT Units •

Prove ACT meters at least monthly on each product, or more often if ◊

the flow rate changes by 15% or more,

◊

the temperature changes by 5°F, or

◊

the gravity changes by 5°API.

•

The meter factor is calculated from 5 consecutive runs, out of a maximum of 10 runs, that agree (highest to lowest) to within 0.05%.

•

The new meter factor must be within ±0.0015 of the previous meter factor (under the same operating conditions).

Summary of Preventive Maintenance for Provers •

•

Monthly: ◊

Verify temperature and pressure indicators and transmitters.

◊

Verify that all valves are sealing properly.

◊

For bidirectional provers, verify that the four-way valve is sealing properly.

◊

For unidirectional provers, verify that the interchange is sealing properly.

Every six months: ◊

Pull the prover sphere and inspect it for damage.

◊

Verify that the size is still the same as during the last prover calibration.

Proving a Meter

September 2002

14.2





• Stopwatch





• Sample heater








• Sample heater



• Sample(s)

• Centrifuge











BP Pipelines

September 2002


BP Pipelines


Introduction No meter can be absolutely accurate. To know the correct amount of oil being measured by a meter, it is necessary to determine how well a particular meter is performing under real operating conditions by proving it. Proving involves measuring the liquid flow through the meter and through a prover and comparing the two volumes. The two volumes are used to calculate the meter factor. All parties involved in a custody transfer use the meter factor to correct any inaccuracy in the meter’s measurements until the next scheduled proving. The type of prover used depends on the volume of liquid to be measured and the nature of the transfer.

Proving a Meter

September 2002

14.4

BP Pipelines


When to Prove a Meter In general, prove LACT meters quarterly or every 50,000 barrels, whichever comes first, unless directed otherwise by regulatory or contractual obligations. The fluid characteristics and operation may require more frequent proving; for example, if the flow rate changes by 15% or more or the gravity significantly changes. In addition, prove after replacing or repairing the meter. Prove ACT meters at least monthly or more often if the flow rate changes by 15% or more, the temperature changes by 5°F, or the gravity changes by 5°API.

Proving a Meter

September 2002

14.5

BP Pipelines


Procedures Calibrate provers regularly, normally every year to three years (see Chapter 16, “Waterdraw Calibration”). Keep provers in top mechanical condition to ensure accurate results. See “Troubleshooting”below for details about maintaining provers. During proving, the fluid properties (for example, API gravity), flow rate, pressure, and temperature should be similar to those during normal operating conditions for the meter. The specific procedure for proving a meter varies according to the type of proving device. For each proving, however, follow the same procedure under the same operating conditions for each proving run so that you can produce repeatable results. Use the meter proving tool in the SMART program to enter proving data. SMART will then calculate the new meter factor.

Preliminary Procedures for Stationary Provers Follow these procedures before beginning the first proving run. 1. If a flow computer is not used for proving, record all data on a notepad for later entry into SMART. 2. To establish flow through the prover, open the inlet and outlet block valves. 3. Make sure the block-and-bleed valve on the main line is closed and the four-way diverter valve (on bidirectional provers) is open to one side of the prover. •

Check the block-and-bleed valve for leaks. Open the bleed valve to ensure that oil is not leaking past the seals on the valve.

•

Observe the pressure indicated on the cavity gauge of the four-way valve so you will notice any rise in pressure during proving, which indicates a leak.

4. After diverting the oil into the prover, allow time for the prover temperature to stabilize. The temperature is considered to be stabilized when the prover outlet temperature is constant and agrees closely with the meter temperature. 5. To adjust the flow rate back to normal, lower the back-pressure setting on the meter. Reset the back-pressure when you are finished proving. 6. If the meter is new or has been recently repaired, verify that the number of pulses generated per barrel matches the meter manufacturer’s specifications as indicated on the Meter Proving Report. •

Reset the electronic pulse counter to zero.

•

Start the electronic pulse counter with the remote switch attached to the counter.

•

Open the flow through the meter. After 10 barrels have been registered, stop the electronic pulse counter. Read the counter.

Proving a Meter

September 2002

14.6

BP Pipelines


•

Using the following formula, calculate the pulses per barrel: total pulses ---------------------------------------------------------------------------------------------------------------- = pulses per barrel closing meter reading – opening meter reading

7. Take a sample of the flowing oil and determine its gravity using a hydrometer (see Chapter 2, “Gravity and Temperature Measurement in Tanks” and Chapter 10, “Automatic Sampling”). Record the results so you can enter them later on the Meter Proving Report. 8. Reset the electronic pulse counter to zero. 9. Set the four-way valve and launch the sphere for the first pass. 10. For a unidirectional prover, record the number of pulses at the end of the sphere (or displacer) pass. 11. For a bidirectional prover, reverse the four-way valve to allow the sphere to change directions, and record the number of pulses for the round trip. 12. Note the temperature and pressure of the prover and record the readings for this run. If both inlet and outlet thermometers are available, average the two readings. 13. For a bidirectional prover, record the meter temperature (unless temperature-compensated) and meter pressure. 14. Reset the prover counter and repeat steps 9-13 until you have accumulated data for 5 consecutive runs. •

If the results of the 5 runs meet BP Pipelines’ requirements of 0.05% repeatability (see “Repeatability Requirements”below), stop.

•

If not, continue the proving runs until you obtain 5 consecutive runs that are repeatable. If you make 10 runs without meeting the repeatability requirements, stop and determine the problem (see “Troubleshooting” below).

15. Return the flow through the LACT or ACT to normal. 16. Reset the back-pressure setting on the meter. 17. Complete the Meter Proving Report on your laptop. 18. Compare the new meter factor with the previous one. If the new meter factor varies from the previous one by more than ±0.0015 for ACTs or more than ±0.0025 for LACTs, identify the problem (see “Troubleshooting” below).

Proving a Meter

September 2002

14.7

BP Pipelines


Procedures for Proving with a Portable Prover If you are using a portable prover, follow these additional steps. 1. Ground the prover. 2. Hook up the hoses on the prover to the prover connections. •

Inspect the hoses for signs of wear or damage and make sure they have the correct pressure rating.

•

When removing the protective dust caps on the prover connections, loosen the caps slowly to allow any built-up pressure to dissipate.

•

If the prover is equipped with a vent valve, bleed the pressure before removing the caps.

3. Establish flow through the prover and check for leaks. 4. Launch the prover sphere and bleed air from the vent valves while the sphere is in motion. Be sure to bleed both prover chambers. 5. Verify that the prover counter is receiving signals from the pulse generator. Launch the sphere a few times to make sure that the detector switches are gating properly. 6. Clear the counter and then follow steps 7-16 under “Proving with Stationary Provers” above. 7. Block in and bleed pressure from the prover. 8. Disconnect the prover and reset the counter. 9. Stow all equipment and bleed pressure from the prover. 10. Clean the area. 11. Complete the Meter Proving Report on your laptop. 12. Compare the new meter factor with the previous one. If the new meter factor varies from the previous one by more than ±0.0015 for ACTs or more than ±0.0025 for LACTs, identify the problem (see “Troubleshooting” below).

Repeatability Requirements The results of a meter proving must meet specific criteria that demonstrate repeatability. These requirements are as follows: •

Calculate a meter factor using the average number of pulses from a series of 5 consecutive round trips.

•

Within the series, the total pulse counts must not vary by more than 0.05% between the highest and lowest reading.

Proving a Meter

September 2002

14.8

BP Pipelines


•

If you cannot meet the criteria for repeatability in 10 round trips, stop and determine the problem before continuing (see “Troubleshooting” below).

•

For ACT locations, the new meter factor must be within ±0.0015 of the last meter factor for this product. For LACT meters in crude oil service, the tolerance is ±0.0025. The previous meter factor is shown on the Meter Proving Report.

•

The meter factors should be trended, using the utility program in SMART, to monitor meter performance and condition.

See also Chapter 15, “Design of Prover Systems” for design considerations that affect repeatability.

Troubleshooting When results from a meter proving are unacceptable or when there is other evidence that the meter or the proving equipment is malfunctioning, you must determine the cause of the problem. This section describes some of the most common difficulties that you may encounter in the proving process and suggests ways of correcting them. Proving problems tend to fall into two broad categories: 1. The pulse counts vary by more than 0.05% between the highest and lowest reading in 5 consecutive runs (nonrepeatability). 2. The new meter factor varies from the previous meter factor by more than ±0.0025 for LACTs or more than ±0.0015 for ACTs. (These tolerances are valid only if the meter was proved under the same operating conditions.)

Nonrepeatability Nonrepeatability can have the following causes: •

Air or gas in the prover

•

Unstable temperature

•

Unstable flow rates

•

Bad detector switches

•

A nearby electrical field, two-way radios, or radio repeater stations, which can produce stray pulses

•

A defective prover sphere

•

A leaking four-way valve (bidirectional prover)

•

A leaking diverter valve (unidirectional prover)

The procedures for these checks are given below in “Procedures for Troubleshooting.”

Proving a Meter

September 2002

14.9

BP Pipelines


Changing Meter Factor A changing meter factor can often be traced to the following problems: •

Meter wear

•

Deposits in the meter

•

Flow rate of the oil

•

Viscosity of the oil

•

Temperature and pressure of the oil

•

Air and vapor in the oil

•

An overinflated or underinflated sphere

Use good judgment in evaluating widely divergent meter factors at a particular location. Repairing or replacing a meter is expensive, so evaluate the meter thoroughly and perform extensive troubleshooting procedures to prevent unnecessary costs. Table 14.1 summarizes some of the most common causes of a fluctuating meter factor.

Table 14.1. Causes of Meter Factor Fluctuation Cause

Effect

Meter Factor

Incrustation

Lower meter registration

Increases

Prover temperature too high

Higher meter registration

Decreases

Prover temperature too low


Increases

Air or gas in oil


Decreases

Leaking valve


Decreases

Piston wear


Decreases

Stray pulses to counter


Decreases

Loss of pulses to counter


Increases

Leakage around sphere


Decreases

Proving a Meter

September 2002

14.10

BP Pipelines


Procedures for Troubleshooting Check the following components and circumstances to investigate a changing meter factor or repeatability problems. 1. Liquid changes •

When there is an unacceptable discrepancy between the new meter factor and the previous one, review the characteristics of the oil. If there have been considerable changes in the liquid since the previous proving, the new meter factor may be valid. The changes may be in gravity, temperature, or type of crude/product.

2. Prover displacers •

Inspect prover displacers regularly for over- or underinflation. A deflated sphere causes liquid to leak past the sphere, and the meter factor drops. Overinflated spheres may cause the sphere to jump, which will produce uneven meter pulses. The sphere should be 2-3% oversized.

•

Overinflation causes increased wear and distortion of the sphere as well as jumping of the sphere, which produces erratic pulse counts. Underinflation causes high pulse counts and results in a meter factor that is too low.

3. Four-way diverter valve •

Check the four-way diverter valve prior to proving and then at least once during proving.

•

If the valve is sealing properly, the gauge should remain at a pressure significantly lower than the prover pressure. Any rise in pressure indicates that the valve is leaking.

•

Leakage through the four-way valve causes an increase in pulse counts and thus a lower meter factor.

4. Detector switches •

If you remove either switch on a prover, contact the Measurement Team, as the prover must be recalibrated (waterdrawn) before using it again.

•

Consult the manufacturer’s instructions before attempting any adjustments or repairs to the switches.

5. Prover isolation valve (block-and-bleed valve) •

During proving operations, check all connecting valves for leaks. Make sure the total flow from the meter (and only that flow) is flowing through the prover while you are proving the meter.

•

Any leakage causes higher pulse counts, resulting in a lower meter factor.

Proving a Meter

September 2002

14.11

BP Pipelines


6. Meter back-pressure •

API recommends that the back-pressure be no less than 2 times the pressure drop across the meter at the maximum operating flow rate plus 1.25 times the equilibrium vapor pressure at measurement temperature. For crude oil, this means that the system should be operated above 20 psi.

•

Improper back-pressure causes the liquid to separate or flash, producing cavitation in the meter. The meter will become very erratic under these conditions.

7. Check for air or vapor in the system. 8. Check pressure, temperature, and density-sensing devices for error. 9. Check all electrical equipment for any failures, including the pulse generator, counters, coil, preamplifiers, signal transmission system, power supply, and all readout devices. 10. Check for leakage from all isolation and diversion valves. 11. Check for proper gearing in the meter accessory drive.

Proving a Meter

September 2002

14.12

BP Pipelines


Preventive Maintenance for Provers Follow these procedures for maintaining a prover. At least monthly: 1. Verify temperature and pressure indicators and transmitters. 2. Verify that all valves are sealing properly by checking bleeders. •

Check the body bleed on block-and-bleed valves.

•

Check the bleeder between double block valves.

3. For bidirectional provers, verify that the four-way valve is sealing properly by checking the differential pressure or by opening the body bleeder. 4. For unidirectional provers, verify that the interchange is sealing properly by checking the differential pressure or opening the cavity bleeder. Every six months: 1. Pull the prover sphere and inspect it for damage. Replace it with a new sphere if damage is extensive. 2. Verify that the size is still the same as during the last prover calibration. •

Measure the sphere around two axes (the seam and fill ports). The two readings should agree within 1%. See Table 16.2 for the acceptable tolerance for various sizes of spheres.

•

If the sphere needs to be resized, use a 50-50 mix of water and antifreeze.

3. Reinstall provers with adjustable sphere ramps according to the manufacturer’s recommendations to prevent sphere damage.

Proving a Meter

September 2002

14.13

BP Pipelines


More About It Here you will find the following figure: •

Figure 14.1. Sample proving report

Before you prove a meter for the first time, examine a sample Meter Proving Report to familiarize yourself with the information that SMART provides on the form and the kinds of proving data that you are expected to provide.

Proving a Meter

September 2002

14.14

BP Pipelines


Figure 14.1. Sample proving report

Proving a Meter

September 2002

14.15

BP Pipelines


Reference Documents 1. API Manual of Petroleum Measurement Standards, Chapter 4 “Proving Systems” 2. BP Self-Study Guide, Field Specialist IV – Module 4 “Meters and Meter Proving” 3. BP Self-Study Guide, Field Specialist III – Module 1 “Meter Prover Calibrations” 4. Pipelines (NA) Business Unit Safety Manual

Proving a Meter

September 2002

14.16

Chapter 15

Design of Prover Systems Quick Reference Scope This chapter describes the design of meter proving systems, including bidirectional provers, unidirectional provers, and small-volume provers.

Summary of Prover System Design •

Flow rate ◊ Use a bidirectional prover when the flow rate is less than 3,000 bph (usually costs less). ◊ Use a unidirectional prover when the flow rate is more than 5,000 bph (usually costs less). ◊ Either type may be specified for flow rates between 3,000 and 5,000 bph.

•

Prover repeatability must be ±0.02%.

•

The meter must produce at least 10,000 pulses per proving pass unless double chronometry is used.

•

Recommended displacer velocity ◊ Maximum of 5 feet per second (fps) for bidirectional pipe provers ◊ Maximum of 10 fps for unidirectional pipe provers ◊ Minimum of 0.5 fps for nonlubricating fluids

•

Volume between detector switches should be at least 50 gallons.

•

Fluid velocity through the four-way valve should be a maximum of 15 fps for bidirectional provers.

•

The prerun must be designed so that before the sphere reaches the first detector switch, ◊

the four-way valve completely seats (bidirectional prover),

◊

the interchange completely seals (unidirectional prover).

BP Pipelines

September 2002



BP Pipelines


Introduction This chapter outlines the design of systems using bidirectional and unidirectional provers. Using the correct size and type of prover for the operating conditions, fluid characteristics, and repeatability requirements is crucial to accurate meter proving.

Design of Prover Systems

September 2002

15.2

BP Pipelines


Installation and Operating Requirements for Provers Many criteria affect the design of a prover/meter system. Table 15.1 below shows some of the important considerations.

Table 15.1. Effect of Various Criteria on the Design of a Prover System Design Criteria Operating conditions

Design Impact

Flow rate

Type of prover: • Use either type of prover for flow velocities up to 5 fps. • Use unidirectional provers up to 10 fps.

Operating pressure

Pipe wall and flange ratings

Ambient and operating temperature

Transducer/gauge ranges

Allowable pressure drop

As prover diameter increases, prover pressure drops.

Fluid characteristics

Lubricity

All provers should have a baked-on phenolic internal coating.

Operation

Repeatability requirements (see “Repeatability Considerations” below)

Resolution of meter pulse generator Resolution of detectors Resolution of prover counter

Installation

Size

*

Locate prover as close to meter as practical. Space limitations may affect prover diameter, distance between detectors, and prerun length. Ease in calibration

Minimum volume of 50 gallons between detectors. Larger prover volumes should be rounded up to the next 25-gallon increment, for example, 75 gal., 100 gal., 125 gal., etc.*

The minimum volume and rounding requirements do not apply to small-volume ballistic provers.


September 2002

15.3

BP Pipelines


Repeatability Considerations Prover repeatability (see Chapter 14, “Proving a Meter”) relies on these design considerations: •

Resolution of the meter pulse generator — how many pulses per unit volume are generated by the meter being proven?

•

Resolution of the detectors — within what distance can the detectors detect the presence of the prover sphere?

•

Resolution of the prover counter — electronic counters can indicate pulse intervals to within ±1 interval.

Resolution of the Meter Pulse Generator To prove a meter that has a pulsed output, a pipe prover must collect a minimum number of pulses during the proving period during each proving run. Meter gearing in LACT meters smaller than 6 inches should produce a minimum of 8,400 pulses/bbl. Some ACT meters (especially helical turbine meters) may producer fewer pulses/bbl and usually require pulse interpolation, a type of double chronometry, to be used.

Resolution of the Detectors To determine the minimum volume of liquid that passes between the detectors during proving, use this formula: N minimum volume, in barrels = ---K where N = the number of pulses per prover pass K = the number of pulses per barrel from the meter Assume the number of pulses per pass N to be at least 10,000. If the meter is a 6-inch PD meter, then the number of pulses per barrel (K) is 8,400. Using N = 10,000 and K = 8,400 in the equation gives 1.19 barrels, which equals about 50 gallons. Thus the calibrated section of the prover (volume between detector switches) should be at least 50 gallons.


September 2002

15.4

BP Pipelines


Prover Sizing The prover must be sized so that the following considerations are met. •

Prover system repeatability must be ±0.02% (see Chapter 16, “Waterdraw Calibration”).

•

The meter must produce at least 10,000 pulses per proving pass.

•

Recommended displacer velocity is ◊

a maximum of 5 feet per second (fps) for bidirectional pipe provers,

◊

a maximum of 10 fps for unidirectional pipe provers,

◊

a minimum of 0.5 fps for nonlubricating fluids.

•

Volume between detector switches is at least 50 gallons (in nominal 25-gallon increments; that is, the volume should be 50 gallons, 75 gallons, 100 gallons, etc.).

•

Fluid velocity through the four-way valve is a maximum of 15 fps for bidirectional pipe provers.

Prover Diameter The diameter of the prover for a given flow rate is also important. As the prover diameter increases, •

the displacer velocity drops,

•

the distance between detectors decreases,

•

the prerun length decreases, and

•

the size and cost of the prover increase.

The formula for estimating prover diameter based on flow rate is as follows:

d =

0.3F ----------v

where d = the estimated prover diameter in inches F = flow rate in barrels per hour v = displacer velocity in feet per second


September 2002

15.5

BP Pipelines


Minimum Distance between Detectors To find the minimum distance between detectors, determine the minimum one-way (unidirectional) or round trip (bidirectional) length using each of these equations: 4 × detector error minimum trip length, in inches = ----------------------------------------0.02% or minimum trip length, in inches = 10, 000 (minimum number of meter pulses per run) × 2 × detector error Divide the answers to each equation by 12 to get the minimum trip distance in feet for a unidirectional prover. For a bidirectional prover, divide again by 2 to get the one-way distance. After performing both calculations, consider the larger of the two results as the minimum trip length for the prover. Refer to Table 15.2 below to find the detector error for various prover sizes.

Table 15.2. Approximate Detector Error for Pipe Provers

*

Prover Pipe Size

Approximate Detector Error*

6"

0.0366

8"

0.0392

10"

0.059

12"

0.0792

16"

0.12

20"

0.168

24"

0.2208

30"

0.309

Verify approximate detector error and all prover calculations with the manufacturer.


September 2002

15.6

BP Pipelines


Minimum Prerun Length Determine the minimum prerun length using these equations: minimum prerun length, in feet = C × displacer velocity, in fps The value of C depends on whether you are using a bidirectional or unidirectional prover. For bidirectional provers, C = valve closing time, in sec + 0.5 sec (safety factor) Table 15.3 shows typical valve actuator times. This is the total time for the valve to unseat, lift, turn, and reseat. The valve closing time is equal to half of the total actuator time. For example, the valve closing time for an 8-inch valve is 2.5 sec. (5.0 sec. divided by 2), and C is 3 sec. (2.5 + 0.5).

Table 15.3. Typical Actuator Times for Four-way Valves

*

General Twin Seal 300# Four-way Valve Size

Typical Actuator Time* (seconds)

3"

2.15

4"

2.6

6"

3.55

8"

5.0

10"

5.7

12"

5.25 or 9.45

16"

8.5

Verify four-way valve closing times and all prover calculations with the manufacturer.

For unidirectional provers, C = sphere interchange seal time, in sec + 0.5 sec (safety factor) The time for a sphere interchange to seal depends on the type and manufacturer of the interchange.


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BP Pipelines


Sphere Type The sphere material used depends on the type of liquid in the pipeline. The numbers for the polyurethane spheres in Table 15.4 indicate the hardness of the material, with higher numbers being harder.

Table 15.4. Type of Sphere to Use for Various Liquids Sphere Material

Recommended Operating Temperature

Service

Neoprene (black)

-20° to 280°F

General-purpose hydrocarbons and chemicals

Polyurethane (53 yellow)

-20° to 170°F (in oil)

Special services, crude

Polyurethane (58 green)

-20° to 140°F (in water)

Special services

Polyurethane (66 red)

-20° to 170°F (in oil) -20° to 140°F (in water)

Toluene, propylene, xylene, unleaded gasolines, special services

Polyurethane (70 blue)

-20° to 225°F

MTBE, H2S


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BP Pipelines


Reference Documents 1. API Manual of Petroleum Measurement Standards, Chapter 4 “Proving Systems” 2. BP Self-Study Book, Field Specialist IV, Module 4 “Meters and Meter Proving” 3. Pipelines (NA) Business Unit Safety Manual


September 2002

15.9

Chapter 16

Waterdraw Calibration Quick Reference Safety •


Scope These procedures for calibrating provers apply to conventional unidirectional and bidirectional provers, as well as small-volume provers.

Summary of Prover Preparation •

Isolate the prover from the pipeline.

•

Verify the condition and operation of the four-way valve and prover switches.

•

Inflate a new sphere to the same size as the previous calibration or 3% over the prover’s internal diameter (ID) and lubricate it with white lithium-based grease.

•

Clean the prover and fill it with clean, deaerated water.

Safety Reminder •

The proper safe handling and disposal of the water used in prover calibrations is the responsibility of the local field personnel.

Summary of Responsibilities for Witnessing Prover Calibration •

The contractor must change the fill rate of each run (round trip or one-way trip for unidirectional provers) by at least 25%, preferably 50%, from the previous run. Normally, fill rates are alternated between fast and slow runs.

•

Three consecutive trips must agree to within 0.02% of each other.

•

Sign and verify the waterdraw calibration worksheet.

BP Pipelines

September 2002


BP Pipelines


Introduction Calibrating, or verifying, a prover’s volume at standard conditions ensures that it is measuring accurately. BP Pipelines uses the waterdraw method to calibrate pipe provers and small-volume provers (see BP Self-Study Book “Meter Prover Calibrations” for more information about the waterdraw method). BP Pipelines generally contracts with outside vendors to perform the waterdraw calibrations. BP Pipelines personnel prepare the prover for the waterdraw, witness the procedure, and must make sure that the calibrations are done properly and that the contractor meets high standards of quality and safety.

Waterdraw Calibration

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BP Pipelines


When To Calibrate a Prover Calibrate provers on the following schedules. •

Portable provers: Recalibrate once a year, or at least every 3 years.

•

Stationary pipe provers currently in use: Recalibrate every 3 years, or at least every 5 years. Calibration frequency can vary depending on the volume through the system and the frequency of provings.

•

Newly installed (or reworked) stationary provers: Calibrated by the manufacturer. Check the calibration within one year of installation. ◊

If this check agrees within 0.04% of the originally calibrated volume, use the new volume and recalibrate the prover on the regular calibration schedule.

◊

If a prover does not repeat within 0.04% of the originally calibrated volume, use the new volume as the correct volume and recalibrate the prover within a year. The two volumes determined within one year of each other must agree within 0.04%. If they do, then recalibrate on the regular calibration schedule.

•

If the prover does not meet this requirement, check it to determine why it does not meet calibration standards. It may be necessary to repair the prover equipment or revise the conditions under which the prover is calibrated. After it is repaired or after the conditions are changed, follow the policies for a newly installed stationary prover.

•

If either detector switch is removed for repair or replacement, the prover must be recalibrated before being placed back into service since this may change how the switches operate and thus affect the calibrated volume if the prover. This includes adjusting the reed switch inside the detector switch. Contact the Pipeline Measurement Team to schedule a recalibration. If it is impractical to perform the calibration at that time (for example, midwinter in cold climates), the Measurement Team may allow the prover to be placed back into service until a calibration can be scheduled. However, you must recalculate every meter ticket generated from the time the prover is repaired until the recalibration and generate correction tickets.

•

Clean the prover and fill it with clean, deaerated water.

Reminder •


If either the detector switch or one of its components is removed from the prover for repair, replacement, or adjustment, the prover must be recalibrated.

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BP Pipelines


Preparation Procedures for Waterdraw Calibration The field specialist must take all of the following steps before each waterdraw calibration.

Preparing Pipe Provers Follow these steps for preparing pipe provers. 1. Check the four-way diverter valve or interchange to make sure the seals are holding under water pressure during the flushing and recirculating process. Replace the slips or seals, if necessary. 2. Prepare the prover sphere. •

It is recommended that a new prover sphere be used for the waterdraw calibration.

•

The sphere used for the waterdraw should be the same sphere used in normal operation of the prover. (See Table 16.1 under “More About It” for the types of sphere to use for various liquids.)

•

You may use the existing sphere if it is in good condition and all witnesses agree.

•

Inspect it to make sure the sphere has no cuts, soft spots, or flat spots.

•

The sphere should be round. Determine the roundness by comparing the measurement around the seam of the sphere to the measurement around the fill valves. The two measurements should agree to within 1%. (See Table 16.2 under “More About It” for sphere roundness tolerances.)

•

After inspecting the sphere, inflate the sphere to the same size that was used at the last calibration, or to 3% over the internal diameter (ID) of the pipe, by pumping a mixture of 50% antifreeze and 50% water into the sphere. (The maximum oversizing is normally 5%, but see Table 16.3 under “More About It” for additional sphere sizing information.)

•

Lubricate the sphere with a water-soluble, lithium-based grease so that it will move smoothly through the pipe.

•

If the prover has adjustable ramps, the ramps must be reinstalled in accordance with the manufacturer’s recommended procedures to prevent sphere damage.

3. Make sure the detector switches are in perfect condition and are operating properly. The sphere must move freely and trip each detector as it passes so that the volume measured on each run is accurate. •

Remove and clean all mechanical switches and plunger parts. Lubricate them freely and work them several times to assure freedom of movement. Reinstall and adjust each part, making and breaking switch connections with an ohmmeter. Make all repairs and adjustment according to the manufacturer’s recommendations.


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16.4

BP Pipelines


4. The water inlet and outlet of the prover should have 2-inch NPT threaded connections with a male or female end. 5. Isolate the prover from the pipeline. •

Insert isolation blinds or blind flanges as close to the prover as possible.

•

Double block-and-bleed-type valves do not need to be blinded if you can verify their sealing integrity before the calibration.

6. Clean the inside of the prover. •

For a crude oil prover, flush with gasoline, solvent, or any agent that is soluble with crude. DO NOT USE SOAP TO CLEAN THE PROVER! Immediately following, flush several times with water (saltwater can be used, but fresh water is preferred). Flush the prover until no oil or film appears. ◊ During the flushing process, shift the four-way valve several times as oil may collect here and cause problems during the calibration procedure. ◊ Vent the four-way valve cavity by removing the pressure gauge if necessary. ◊ Vent all lines, if possible, to clear other points where oil or product may be trapped. ◊ Allow the prover to sit overnight with water in it. Flush again the next day until oil scum no longer appears. During this flushing, be sure to shift the four-way valve several times to run the sphere around the prover loop from side to side—left to right and right to left—to clean all foreign material from the interior of the prover. Steam cleaning a prover is a good method of flushing if steam is available.

•

For provers with finished products, flushing with water is usually adequate as they are normally clean.

7. Check the water. •

Use only clean, deaerated, potable water to calibrate the prover. The prover may be cleaned and flushed with saltwater if fresh water is not available, but the final rinse should be with fresh water.

•

The amount of water needed for flushing and calibrating will vary according to the size of the prover. For example, 1,500 gallons are needed for an eight-barrel, bidirectional prover after it has been cleaned—1,000 gallons for the reservoir in the waterdraw trailer and 500 gallons for the prover.


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BP Pipelines


Preparing Small-Volume Provers Follow these steps for preparing small-volume provers. 1. Make sure the prover has a 2-inch connection on the inlet and outlet of the prover for water. 2. If the prover is new, you may need to install the outlets. 3. Flushing procedures for a small-volume prover are basically the same as for other provers. Use the inlet and outlet hoses to flush the prover, check for leaks while flushing, and replace seals if necessary. 4. Check the switches to make sure they are functioning properly.

Other Preparations In addition to these steps, there may be procedures specific to certain brands of provers. For all types of provers, the waterdraw contractor will do the following: 1. The contractor levels the trailer containing the water reservoir and test measures and attaches it to a power supply. 2. The contractor wires the prover’s detector switches to an alarm in the trailer to indicate when the prover sphere first makes contact and when it moves past each detector switch. 3. The contractor connects the prover to the trailer with inlet and outlet hoses. A pump on the trailer withdraws water from the trailer’s reservoir and circulates it through the connecting hoses through the prover and test measures and back to the reservoir once all preparations for proving have been completed. 4. The contractor will verify the size of the prover sphere.


September 2002

16.6

BP Pipelines


Control panel

Solenoid valves (normally open)

PI

Vent

Gauge glass Test Measure #5 Test meas. #4

Test measure #3

Test measure #2

Test measure #1

Water reservoir tank Pressure gauge and temperature indicator (both sides)

Centrifugal pump

Vent Block-and-bleed valve

Four-way diverter valve Detector switches

Sphere

Figure 16.1. Waterdraw calibration unit


September 2002

16.7

BP Pipelines


Procedures for Calibrating a Pipe Prover Using the Waterdraw Method Generally, bidirectional and unidirectional provers are calibrated the same way, except there is only a single one-way trip in a unidirectional prover. 1. Before the calibration can begin, the contractor must determine the number and sizes of the test measures that will be needed to certify the volume of the prover. The contractor determines the number of times each test measure will be filled, making sure that the final fill will reach the gauge glass so that the level can be read. The liquid level must reach the scale on the final fill or it will not be possible to certify the prover volume. 2. The contractor fills the prover with clean water and makes sure all the air has been vented from the prover—before calibration begins. To make sure all air has been removed, the contractor launches the sphere and moves it through the prover, bleeding air as the sphere moves. The contractor will continue to move the sphere through the prover until all air has been removed and the prover and water temperatures are stabilized. 3. After circulating water through the test measures to make sure they are wet before the calibration begins, the contractor then drains the water from the test measures but not from the prover. Adequate time must be allowed for the test measure to drain properly. •

For NIST test measures without drain-down valves, drain-down time is 10 seconds.

•

For NIST test measures with drain-down valves, drain-down time is 30 seconds.

4. To start the calibration, the contractor cycles the four-way diverter valve on the prover and places the sphere in a launching position. 5. Next, the contractor begins drawing water through a bypass valve to bypass the test measures and deliver water directly into the reservoir. 6. The water continues to flow into the reservoir tank until the sphere makes contact with the first detector switch. At this point, the contractor stops the flow of water and reverses the four-way valve. The contractor will withdraw water to bring the sphere past the switch to a point where the switch is de-energized (the sphere has moved just off the switch). 7. The contractor then reverses the four-way valve and moves the sphere toward the switch by withdrawing water through one of the solenoid valves. As the water moves through the solenoid valve, the contractor reads and records the system pressure indicated on the pressure gauge on the waterdraw manifold. 8. When the sphere contacts the detector switch, the solenoid valve closes, which stops all flow through the prover and the test measures. At this point, the contractor closes the block valve downstream of the solenoid valve to prevent additional flow through the valve.


September 2002

16.8

BP Pipelines


9. The contractor then opens the main valve to allow water to flow into the first test measure. When the sphere moves off the switch, the solenoid valve reopens. During the withdrawal of the first one-third of the volume of the prover, the contractor reads and records the temperature at the outlet of the prover. 10. The contractor continues withdrawing water until the sphere is approximately 1 gallon short of the second detector switch. The contractor determines how close the sphere is to the switch by reading how much water has been withdrawn from the prover and delivered into the test measures. 11. At this point, the contractor will stop drawing water through the main outlet manifold valve and will continue filling the final test measure by drawing water through the solenoid valve line. 12. During this first run, the contractor will time the fill rate of one of the test measures. The contractor will determine this fill rate in gallons per minute (gpm) by taking the volume in the test measure and dividing that number by the time required to fill it. The contractor reads and records the gpm on the calibration worksheet. The contractor determines this rate to use as a point of reference. During subsequent runs, the contractor will decrease or increase the rate by at least 25% to verify that there is no leakage around the sphere. 13. The contractor also reads and records the average prover pressure during the waterdraw through the solenoid valve so that, if necessary, a correction for pressure on steel can be calculated. 14. When the sphere energizes the second switch, the run is over. The contractor has completed a one-way trip through the prover. This one-way trip may be left-to-rightor right-to-left, depending on how the contractor launched the sphere at the start of the run. 15. In a bidirectional prover, the contractor reverses the four-way valve and repeats the above operation from step 5 to step 14 in the opposite direction to complete a round trip, or run. In a unidirectional pipe prover, the run is only a one-way trip. 16. After each one-way trip, the water levels in each test measure must be read and recorded on the calibration worksheet (see Figure 16.2 under “More About It”). 17. The contractor reads the bottom of the meniscus on the scale on the test measure’s gauge glass. The contractor then drains the test measures to prepare for the next trip. While the water is draining, the contractor determines the temperature of the water draining from each test measure with a certified thermometer and records it. 18. After each run, the fill rate (gpm) should be changed (faster or slower than the previous one) by at least 25% (BP Pipelines prefers a 50% change if that is possible). •

Normally, the second run is slower than the first run. The third run is then set at the same rate as the first run, and so on. The preferred sequence of runs is “fast, slow, fast.”

•

At the discretion and concurrence of all parties, the contractor may alter the


September 2002

16.9

BP Pipelines


preferred order in which the flow rate is changed. However, the flow rate for at least one trip for a unidirectional prover and at least one round trip for a bidirectional prover must be changed by at least 25%. Note: At least one of the runs is a slow run to assure that there is no leakage around the sphere. 19. With a bidirectional prover, the contractor will continue making runs until 3 consecutive round trip volumes, corrected for temperature and pressure, agree within 0.020%. The corrected volume for consecutive passes in the same direction making up these round trips must also agree within 0.020%. The calibration passes in opposite directions do not necessarily have to agree. 20. With a unidirectional prover, the 3 consecutive one-way trips must agree within 0.020%. 21. The average of the 3 round trip corrected volumes is considered the base volume of a bidirectional prover at standard conditions. The average of the 3 consecutive one-way trips is the base volume of a unidirectional prover.

Procedures for Calibrating a Small-Volume Prover Using the Waterdraw Method The procedures to follow in calibrating small-volume provers vary with the type and manufacturer. Follow the manufacturer’s recommended procedures. However, 3 consecutive runs, with at least a 25% flow rate change between runs, are required. The runs still need to meet the same 0.020% tolerances as conventional provers.


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16.10

BP Pipelines


Calibration Calculations Almost all calibration contractors prefer to use computers to calculate waterdraw calibrations. The computer calculations can be accepted, provided the Pipeline Measurement Team verifies the computation software with periodic manual calculation checks. BP Pipelines employees who witness a calibration must sign and verify a worksheet that shows the calibration data (test measure readings, prover and test measure temperatures, pressures, etc.). This worksheet (see Figure 16.2 under “More About It”) must be completed in ink. Keep a copy of this sheet in the file along with the calculation data.


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BP Pipelines


More About It Here you will find the following figures and tables: •

Figure 16.2. Waterdraw calibration worksheet

•

Table 16.1. Type of Sphere to Use for Various Liquids

•

Table 16.2. Sphere Roundness Verification

•

Table 16.3. Minimum Inflation Percentages for Given Pipe Sizes


September 2002

16.12

BP Pipelines


Figure 16.2. Waterdraw calibration worksheet


September 2002

16.13

BP Pipelines


Sphere Type The sphere material used depends on the type of liquid in the pipeline. The numbers for the polyurethane spheres indicate the hardness of the material, with higher numbers being harder.

Table 16.1. Type of Sphere to Use for Various Liquids Sphere Material

Recommended Operating Temperature

Service

Neoprene (black)

-20 to 280°F

General-purpose hydrocarbons and chemicals

Polyurethane (53 yellow)

-20 to 170°F (in oil)

Special services, crude

Polyurethane (58 green)

-20 to 140°F (in water)

Special services

Polyurethane (66 red)

-20 to 170°F (in oil) -20 to 140°F (in water)

Toluene, propylene, xylene, unleaded gasolines, special services

Polyurethane (70 blue)

-20 to 225°F

MTBE, H2S


September 2002

16.14

BP Pipelines


Sphere Roundness Verify the roundness of the sphere by determining its circumference around two separate axes perpendicular to each other. A circumference variation in the sphere (that is, the difference in length around these two perpendicular axes) of more than 1% of the nominal circumference is considered out-of-round. Measuring the sphere, first around its equator and then around its polar axis, usually across the two valve holes, and comparing the difference between the two measurements according to Table 16.2 will verify sphere roundness.

Example According to the table below, a 6-inch sphere with a nominal circumference of 19 inches would be expected to have a circumference variation around two axes no greater than 3/16 inch to be in round. Alternatively, a 30-inch sphere with a nominal circumference of 94 inches, and with a circumference variation around two axes greater than 15/16 inch, would be considered out-of-round.

Table 16.2. Sphere Roundness Verification Sphere Size

Nominal Circumference

Recommended Tolerance (1% Deviation)

6"

19"

3/16"

8"

25"

1/4"

10"

31"

5/16"

12"

38"

3/8"

14"

44"

7/16"

16"

50"

1/2"

18"

57"

9/16"

20"

63"

5/8"

22"

69"

11/16"


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BP Pipelines


Table 16.2. Sphere Roundness Verification, continued Sphere Size

Nominal Circumference

Recommended Tolerance (1% Deviation)

24"

75"

3/4"

26"

82"

13/16"

28"

88"

7/8"

30"

94"

15/16"

36"

113"

1-1/8"

42"

132"

1-5/16"

48"

151"

1-1/2"

Sphere Sizing The sphere is oversized by inflating it during calibration to compensate for piping irregularities, such as an oval pipe cross section, coating problems, or mandrel marks in the 90° bends and in the 180° returns. However, too much oversizing may cause the sphere to chatter. Undersized or oversized spheres may cause leakage past the sphere or erratic detector switch activation. If the prover is constructed with openings in the calibrated section (such as vents, drains, detector holes, or flange separations, etc.) that are wider than the surface sealing width of the sphere, a momentary leak path can exist. For example, an 8-inch standard-wall pipe prover with a 1/2-inch vent opening will require a prover sphere oversized by approximately 4% (0.66 inch in this example) to span the opening width by a comfortable margin. Table 16.3 shows the minimum additional sealing width (sphere inflation) required to span openings in the measuring section. Other criteria for sizing the sphere must also be considered, such as pipe openings.


September 2002

16.16

BP Pipelines


Table 16.3. Minimum Inflation Percentages for Given Pipe Sizes Nominal Pipe Size

Pipe ID

% Sphere Inflation

Oversize Sealing Width

% Sphere Inflation


% Sphere Inflation


% Sphere Inflation


% Sphere Inflation


6

6.065

2%

0.25

2.5%

0.31

3%

0.37

4%

0.50

5%

0.64

8

7.981

2%

0.33

2.5%

0.41

3%

0.49

4%

0.66

5%

0.84

10

10.02

2%

0.41

2.5%

0.51

3%

0.62

4%

0.83

5%

1.05

12

12

2%

0.49

3%

0.74

4%

1.00

5%

1.26

6%

1.53

14

13.25

2%

0.54

3%

0.82

4%

1.10

5%

1.39

6%

1.69

16

15.25

2%

0.62

3%

0.94

4%

1.27

5%

1.60

6%

1.94

18

17.25

2%

0.70

3%

1.07

4%

1.44

5%

1.81

6%

2.20

20

19.25

2%

0.79

3%

1.19

4%

1.60

5%

2.02

6%

2.45

22

21.25

2%

0.87

3%

1.31

4%

1.77

5%

2.23

6%

2.71

24

23.25

2%

0.95

3%

1.44

4%

1.94

5%

2.44

6%

2.96

26

25.25

3%

1.56

4%

2.10

5%

2.65

6%

3.22

7%

3.79

28

27.25

3%

1.68

4%

2.27

5%

2.86

6%

3.47

7%

4.09

30

29.25

3%

1.81

4%

2.43

5%

3.07

6%

3.72

7%

4.39

36

35.00

3%

2.16

4%

2.91

5%

3.68

65

4.46

7%

5.25

42

41.00

3%

2.53

4%

3.41

5%

4.31

6%

5.22

7%

6.15

48

47.00

3%

2.91

4%

3.91

5%

4.94

6%

5.99

7%

7.05

Note: All dimensions are in inches.


September 2002

16.17

BP Pipelines


Reference Documents 1. API Manual of Petroleum Measurement Standards, Chapter 4.2 “Conventional Pipe Provers” 2. API Manual of Petroleum Measurement Standards, Chapter 4.3 “Small-Volume Provers” 3. API Manual of Petroleum Measurement Standards, Chapter 4.9, Part 1 “Determination of the Volume of Displacement and Tank Provers by the Waterdraw Method of Calibration” 4. BP Self-Study Guide, Field Specialist III – Module 1 “Meter Prover Calibrations” 5. Pipelines (NA) Business Unit Safety Manual


September 2002

16.18

Chapter 17

Claims and Adjustments, Using SMART Quick Reference Security •

Do not reveal your SMART password to anyone.

Scope This chapter tells you when and how to make claims and adjustments and how to use SMART (software you will use to create measurement tickets and reports). This chapter applies to custody transfer of all types of petroleum liquids in tanks and pipelines.

Claims and Adjustments Reasons for claims or adjustments: •

A tank burns or fails while on line.

•

The producer removes hydrocarbons from a tank while on line.

•

Security seals are broken while a tank is on line.

•

The tank stop valve is mistakenly sealed open.

•

The LACT/ACT measurement equipment malfunctions.

Procedure for making claims or adjustments: •

Provide full details of the claim and recommendation for fair settlement on a claim memorandum.

•

The lease producer must provide a notarized affidavit when filing a claim.

•

After investigating and verifying the claim, retain all original paperwork in the field office.

BP Pipelines

September 2002


BP Pipelines


Ticketing Software Capabilities Field specialists use measurement software for these tasks: •

Downloading the latest data about tank or meter locations

•

Updating or creating new tank or meter records

•

Creating tickets and reports

•

Determining meter factor trends

Ticket Distribution and Storage •

Print out at least two copies of each ticket or report.

•

Obtain the signature of the witness on the paper copies.

•

Keep a signed paper copy and all supporting documents (such as records of calibration checks) in the field office.

•

Give a paper copy to the witness.

•

Retain copies of all tickets for 5 years.

Claims and Adjustments, Using SMART

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17.2

BP Pipelines


Introduction An adjustment is a correction to a measured volume in a custody transfer. An adjustment may be necessary due to a security breach, equipment failure, or human error. A claim is a demand for compensation in the event of such a problem. Any involved party may make a claim and the parties may agree to make an adjustment to settle the claim. Report writing and record keeping are important aspects of your job. Collecting accurate data and entering the data correctly will help ensure measurement integrity and aid in the settlement of claims or making of adjustments. Reports and records also provide a valuable source of information about the specifications and performance history of pipeline equipment. BP Pipelines’ SMART software generates and stores most of the reports and tickets that the company has developed to meet industry requirements for reporting and record keeping. In addition, the SMART system is a repository of meter and tank records that you can consult as a reference.

What You Will Need •

Laptop computer

•

Printer


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BP Pipelines


Procedures for Making Claims and Adjustments Table 17.1 shows what actions to take when a claim or adjustment is necessary.

Table 17.1. When to File a Claim or Adjustment Problem

*

Action

• Tank burns or fails on line or • Producer removes hydrocarbon from an on-line tank or • Seal is broken while tank is on line

• Seal tank stop valve closed with a regular seal. • Record second gauge, gravity, and temperature readings on a claim memorandum and attach it to the run ticket. Do not record the second readings on the run ticket. • Report in writing all known details of the tank failure or burning to your supervisor.

• Tank stop valve is sealed open

• Seal tank stop valve closed with a seal. • Report in writing all known details to your supervisor. • Obtain a notarized affidavit from the producer stating the estimated amount of hydrocarbon in question.* • Record both the regular seal of the first run and a special seal as the “off seal” number on the next run ticket.

• Hydrocarbon run into an on-line tank

• Seal tank stop valve closed with a seal. • Record second gauge, gravity, and temperature readings on the run ticket. • Report in writing all known details to your supervisor. • Producer must submit a notarized affidavit stating the estimated amount of hydrocarbon in question.*

• LACT or ACT measurement equipment malfunctions (meter, S&W monitor, diverter valve, etc.)

• Shut the unit down. • Report in writing all known details to your supervisor. • Close the current ticket.

When a lease producer files a claim, a notarized affidavit is required to satisfy royalty and various government agency regulations. An affidavit is not normally required from other pipeline companies or refineries filing claims.


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BP Pipelines


Claims Procedures for filing a claim: 1. Fully investigate all aspects of the claim in cooperation with the producer or other involved parties. 2. Record the details of your investigation. 3. Obtain a notarized affidavit from the producer, if required (see Table 17.1 above). 4. Submit the memorandum, affidavit, and run ticket to your supervisor for review. Keep the originals of these documents in the local field office. A claim must include the following information: •

Full details of the claim, including but not limited to the gross barrels, temperature, S&W, API gravity, meter factor, and tank number. ◊

•

Include the API gravity and agreed net barrels when the exact temperature and S&W are not available.

A recommendation for fair settlement of the claim.

Figure 17.1 under “More About It” at the end of this chapter shows a sample claim.

Adjustments A notarized affidavit from the producer to BP Pipelines must include the following: •

Full details of the claim, including but not limited to the gross barrels, temperature, S&W, API gravity, meter factor, and tank number. ◊ The API gravity and agreed net barrels when the exact temperature and S&W are not available must be included.

Send copies of all documentation supporting claims to the Manager of Oil Movements for reconciliation in SMART. Figure 17.2 under “More About It” at the end of this chapter shows a sample affidavit.


September 2002

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Procedures for Using the SMART Measurement Software for Ticketing and Reports You will use the SMART measurement software for these four tasks: •

Downloading the latest data about the locations you are responsible for

•

Updating or creating new tank or meter records

•

Creating tickets and reports

•

Determining meter factor trends

See the BP Self-Study Book “Ticket Writing (SMART)” for more detailed instructions than are provided in this manual.

Creating Tickets and Reports The types of tickets and reports the software will generate are these: •

Tank custody transfer tickets

•

Meter custody transfer tickets

•

Tank inventory tickets (station tanks)

•

Meter proving reports

•

Meter factor records

Corrections to Tickets To correct the information on a custody transfer ticket, open the original ticket and make the change to the necessary fields. After making these changes, SMART will prompt you to give a reason for the change. This explanation will then be printed on the ticket. To correct a ticket for the current month or the past two months, use the SMART Mobile Module. To correct a ticket from an earlier cycle, you must use the Operations Module.


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Distribution of Tickets and Reports After you have finished entering all the information, follow these steps. •

Check each ticket or report after entering data. ◊

Review it to make sure that you have provided all the required information and that it is correct.

◊

Be sure you have typed the name of the witness in the Witness field.

•

When you print out copies of the document, make at least two copies — one for the field office and one for the witness. Some field specialists also like to make a third copy for their own records.

•

Obtain the signature of the witness on the paper copies.

•

Turn in a signed paper copy and all supporting documents (such as records of calibration checks) to the field office.

The electronic version of all tickets and reports is stored in SMART’s Operations Module for the life of the system. A paper copy of each ticket and report must stay on file at the designated field office for at least 5 years. Supporting documents must be filed with the tickets and also kept for at least 5 years.


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More About It Here you will find the following figures: •

Figure 17.1. Example of a claim letter

•

Figure 17.2. Example of a notarized affidavit

•

Figure 17.3. Example of a SMART tank custody transfer ticket

•

Figure 17.4. Example of a SMART meter ticket for a lease meter


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Manager Revenue Accounting BP Pipelines Supply & Logistics P.O. Box 00000 Houston, TX 77000

September 29, 2001

Dear Sir: Enclosed is a letter from Jack Producer, District Manager of XYZ Company at Lovington, NM regarding unregistered oil delivered to BP Pipelines from 7:00 a.m. September 19, 2001 to 9:00 p.m. September 20, 2001. The meter involved was No. 95545, LACT No. 4 at Painter Reservoir. The malfunction was caused by a set screw, located above the meter failure transmission switch, coming loose and letting a gear fall off, which caused the meter counter to stop turning. The figures presented to us by Mr. Producer have been checked with the Field Specialist in Lovington and we are in agreement that the 10,566 net barrels is a fair adjustment. Please issue a ticket for this amount to the XYZ Company account for September.

_________________________

______________________

Joe Supervisor

Jim Honcho

Core Team Leader

District Manager

BP Pipelines

BP Pipelines

Lovington, NM

Midland, TX

Figure 17.1. Example of a claim letter


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BP Pipelines P.O. Box 000 Lovington, NM Attn.: Joe Supervisor

September 28, 2001

Volume Adjustment, Painter Reservoir Lease #xxxx, Meter Serial #xxxxx On September 19, 2001, XYZ Company experienced a gear failure above the meter failure transmission switch, resulting in 500 barrels of merchantable oil being shipped that were not recorded on LACT #4. The volume of oil run through the meter but not registered by the LACT unit was verified by use of BP Pipelines’ telemetry totalizer. Calculations used to determine the unmetered oil loss were as follows: BP Pipelines meter reading at 7:00 a.m. 19 September 2001 = 236,059 BP Pipelines meter reading at 9:00 p.m. 20 September 2001 = 254,124 Difference = 18,605 Oil metered by the LACT unit from 5:00 a.m. 19 September 2001 to 9:00 p.m. 20 September 2001 was 8,387 gross bbl. Rate at which LACT meter was proved = 496 bph 496 bph × 2 hours = 992 bbl shipped from 5:00 a.m. to 7:00 a.m. 19 September 2001 8,397 − 992 = 7,392 bbl metered on the LACT unit from 7:00 a.m. 19 September 2001 to 9:00 p.m. 20 September 2001 BP Pipelines metered gross bbl = 18,065 LACT unit metered bbl = − 7,395 Unmetered gross bbl = 10,670 Meter factor established 15 September 2001 = 1.0031 Meter factor 1.0031 × 10,670 = 10,703.077 corrected bbl The API gravity @ 60°F was 50.3 at last proving on 15 September 2001. The average temperature of this oil was 82°F, based on the average temperature of crude shipped through other LACTs at this facility, resulting in a temperature correction factor of 0.9872. 0.9872 × 10,705.077 = 10,566 bbl corrected volume


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The cause of the aforementioned unregistered run was due to a malfunction in the lease automatic custody transfer meter. The stated quantity of oil run was calculated as accurately as possible with the information available. XYZ Company requests credit for the net volume of 10,566 barrels, figured at API gravity @ 60°F of 50.3.

__________________________ Jim Honcho District Manager

STATE OF NEW MEXICO COUNTY OF LEA On this 28th day of Sept. 2001, before me the undersigned Notary Public in and for said County and State, personally appeared Jim Honcho whose name is subscribed to the foregoing instrument and acknowledged that he executed the same as a free and voluntary act and deed for the purposes and considerations therein mentioned and set forth. Witness my hand and official seal on the 28th day of Sept. 2001. My commission expires: June 10, 2002

______________________ John Smith, Notary Public

Date

Figure 17.2. Example of a notarized affidavit


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Figure 17.3. Example of a SMART tank custody transfer ticket


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Figure 17.4. Example of a SMART meter ticket for a lease meter


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Reference Documents 1. BP Self-Study Book, Field Specialist IV, Module 4 “Ticket Writing (SMART)” 2. Pipelines (NA) Business Unit Safety Manual


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Abbreviations ACT—automatic custody transfer ANSI—American National Standards Institute API—American Petroleum Institute ASTM—American Society for Testing and Materials ATC—automatic temperature compensator BPV—base prover volume bbl—barrel(s) bph—barrels per hour CPL—correction factor for the effects of pressure on a liquid CPS—correction factor for the effects of pressure on steel CPU—central processing unit CTL—correction factor for the effects of temperature on a liquid. CTS—correction factor for the effects of temperature on steel. ELM —electronic liquid measurement GOV—gross observed volume GSV—gross standard volume IDLH—immediate danger to life and health IP—Institute of Petroleum. ISO—International Organization of Standardization. LACT—lease automatic custody transfer. MF—meter factor MPMS—Manual of Petroleum Measurement Standards NIST—National Institute for Standards and Technology

Glossary

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NSV—net standard volume OSHA—Occupational Safety and Health Administration PD meter—positive displacement meter PLC— programmable logic controller psia—pounds per square inch absolute psig—pounds per square inch gauge psi—pounds per square inch RTD—resistance temperature detector RVP—Reid vapor pressure S&W—sediment and water SCADA—Supervisory Control and Data Acquisitions SI—International System of Units (metric system) TCC—Tulsa Control Center TOV—total observed volume VCF—volume correction factor

Glossary

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Glossary A absolute pressure (psia)—a measure of pressure that includes atmospheric pressure. For example, if a pressure gauge on a tank shows a reading of 4.0 psi, the absolute pressure at that point would be 18.7 psia (4.0 psi + 14.7 psia = 18.7 psia).

accuracy—The ability of a measuring instrument to indicate values closely approximating the true value of the quantity measured.

ACT—see automatic custody transfer. adjustment—a correction to a measured volume in a custody transfer. An adjustment may be necessary due to a security breach, equipment failure, or human error.

affidavit—a sworn statement in writing. algorithm—a formula or set of steps for solving a particular problem. An algorithm always has a set of unambiguous rules and a clear stopping point.

all-levels sample—a sample obtained by submerging a weighted, stoppered bottle to a point as near as possible to the draw-off level, then opening the bottle and raising it at a rate such that it is about three-fourths full as it emerges from the liquid. Because of the difficulty of obtaining a representative sample using this method, it is usually used with products which are more homogenous than crude oil.

ambient air—the air we breathe. American National Standards Institute (ANSI) —a group of organizations and agencies that provides information about and approval for American National Standards for industry, engineering, safety, design, and other applications. Many of these standards have been adopted as OSHA standards.

analog signal—the representation of the magnitude of a variable in the form of measurable physical quantity that varies smoothly rather than in discrete steps.

analog—of or pertaining to an instrument that measures a continuous variable that is proportional to another variable over a given range. Temperature and pressure are examples of variables that can be measured as continuous variables.

API gravity—an arbitrary (U.S.) scale that measures the gravity or density of liquid petroleum products (that is, weight per unit volume). API gravity is expressed in degrees. The lower the number, the denser the oil. See also relative density.

Glossary

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API—American Petroleum Institute. The leading standardization organization for oilfield drilling and producing equipment.

application—software that performs a specific set of tasks. ASTM—American Society for Testing and Materials. An organization that sets guidelines for testing and use of materials.

automatic custody transfer (ACT)—a system for automatically sampling and measuring crude oil at a point of receipt or delivery.

automatic line sample—a sample withdrawn automatically from oil flowing in a pipeline which is representative of the total batch passed through the line. If the rate the sample is taken is proportional to the rate of flow it is called a flow-proportional sample.

automatic sampler—a device used to extract a representative sample from the liquid flowing in a pipe. The automatic sampler generally consists of a probe, a sample extractor, an associated controller, and a sample receiver.

automatic sampling system—a system consisting of flowing stream conditioning equipment, an automatic sampler, and sample receiver.

B back-pressure valve—a valve that automatically regulates pressure on its inlet side to a preset value.

back-pressure—the pressure maintained on equipment or systems through which a fluid flows to prevent the fluid from vaporizing.

barrel—the common unit of volume measurement in the oil field. A barrel of oil is equivalent to 42 gallons of oil.

base prover volume (BPV)—the calibrated volume of a prover’s proving section corrected to standard conditions (0 psi and 60°F). The base volume is indicated on the prover’s calibration certificate. Water is often used in calibrating provers because of its universal availability and its well-known properties.

batch—the total volume of oil shipped in a single custody transfer. Also called a parcel. bbl—barrel(s) bidirectional—referring to flow that may be in either direction; for example, a bidirectional pipe prover or meter.

Glossary

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block-and-bleed valve—a high-integrity valve with double seals and with a bleeder valve for determining if either seal leaks.

bottom sample—a sample obtained from the material on the bottom surface (or as close to the bottom as possible) of the tank or container. Also called outlet sample or clearance sample.

boxcar seal—a numbered, metal sealing device for detecting tampering on a tank or metering system. Compare wire seal.

BP Amoco Lease Number—the company’s internal number for a lease. BP Pipelines (North America), Inc.—a common carrier pipeline, subject to the rules and regulations of the Federal Energy Regulatory Commission or an applicable state commission, in the business of transporting liquid hydrocarbons for hire, without discrimination or preference, to the extent of available facilities, for anyone who requests such services and meets tariff requirements.

bph—barrels per hour

C calibration certificate—a certificate issued by a standardization laboratory expressing the relationship between the reading indicated by an instrument and the true value. Knowing this relationship allows the instrument reading to be adjusted to give a closer approximation to the true value. The determination of the true value must be traceable to a national standard. See NIST-certified.

calibration—the adjustment or standardizing of a measuring instrument or a standard capacity measure, tank prover, or pipe prover.

capacity table—see tank calibration table. central processing unit (CPU)—a device made up of one or more microprocessors and associated components. The CPU controls certain system activities including interpreting and executing specific programs. The CPU uses arithmetic logic units (ALU), timing and control circuitry, an accumulator, a program counter, and other components to control certain processes within a closed system.

centrifuge—a device used to spin samples of crude oil to determine the oil’s suspended sediment and water (S&W) content.

certified instrument—an instrument, such as a thermometer, which has been calibrated by a standardization laboratory and is accompanied by a calibration certificate.

claim letter—a letter from a field representative to his or her supervisor reporting the investigation of a claim and recommending a fair settlement.

Glossary

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claim—a demand for compensation in the event of a problem requiring an adjustment of a measured volume in a custody transfer.

clearance sample—a spot sample taken 4 inches below the level of the tank outlet. Also called bottom sample or outlet sample.

closing gauge—the measurements taken (oil height, temperature, and bottom S&W level) on a manually gauged tank to determine the oil quantity and quality after transferring the tank’s oil into the pipeline system. Also called closing a tank.

cloud point—the temperature at which a waxy solid material appears as a diesel fuel is cooled. composite spot sample—a blend of spot samples mixed in proportion to the volume of material from which the spot samples were obtained.

connection height—the point near the base of the tank shell where liquid exits the tank and enters the pipeline

Coriolis meter—a meter that measures the mass flow of a fluid and its density. The volume can be calculated from these measurements. Previously used only for measuring petrochemicals, the industry is beginning use them for custody transfer measurement of crude oil and refined products.

CPL—correction factor for the effects of pressure (compressibility) on a liquid; used in calculations for determining net standard volume in a tank.

CPS—correction factor for the effects of pressure on steel; used in calculations for determining net standard volume in a tank.

CPU—see central processing unit. critical zone—the vertical range in which the level of the stored oil is high enough to lift a tank’s floating roof off the tank floor but too low to make the entire roof float freely in a level position. Gauging measurements taken while the oil is within this zone will not be accurate because the height of the oil conforms to the slant of the floating roof.

CTL—correction factor for the effects of temperature on a liquid; used in calculations for determining net standard volume in a tank.

CTS—correction factor for the effects of temperature on steel; used in calculations for determining net standard volume in a tank.

Glossary

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custody transfer— a change in ownership or responsibility for a quantity of crude oil or other pipeline commodity. At a lease site, custody transfer takes place between the lease operator and the pipeline company. A custody transfer facility is responsible for measuring the commodity and accounting for charges to the buyer.

D datum plate—a level metal plate attached to the tank shell or bottom. It is located directly below the gauge hatch and is used as a fixed reference point for all measurements of oil height made in the tank. The tip, or end, of the plumb bob will just make contact with the gauge plate during hand gauging procedures. Also called gauge plate or striking plate.

deadweight tester—An apparatus, hydraulically operated, for calibrating pressure gauges. The required pressures are obtained using accurate weights.

deadwood—any obstruction inside a tank that would decrease the tank’s liquid volume. demulsifier solution—a liquid that destroys, or breaks, an unwanted emulsion; added to samples that are being tested for suspended S&W.

densitometer—a device on a pipeline that continuously measures density or API gravity of a fluid.

density—the mass (weight in a vacuum) of liquid per unit volume. See relative density, API gravity.

differential pressure—the pressure drop across a device, such as an orifice plate/filter, in a flowing stream. The amount of this pressure drop varies with flow rate. digital signal—the representation of the magnitude of a variable in the form of discrete values or pulses of a measurable physical quantity. digital—of or pertaining to data in the form of digits, especially electronic data stored in the form of a binary code.

displacer—a spherical or cylindrical object that moves inside the prover pipe and displaces a known volume of fluid. dissolved water—water that is in solution in the oil at a defined temperature and pressure. distillation analysis—a method of obtaining data on the boiling point range of a crude oil. It determines the percentages or yields of crude fractions over their typical boiling point ranges.

distillation—a method used to determine the water content of oil. In this method, a sample of oil is mixed with a solvent until it boils. The water and solvent vapors condense and continuously

Glossary

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separate with the water falling into a trap with graduated sections and the solvent returning to a flask. The amount of water can be read from the graduations on the trap.

diverter valve—on a LACT unit, a valve that diverts a liquid back to the tank or storage unit rather than shipping it downstream, due to an unacceptable level of S&W.

double chronometry— draw-off level—the level of liquid in a tank where the water draw-off valve is located. drift—an observed change, usually uncontrollable, in meter performance, meter factor, etc. over time.

E electronic liquid measurement (ELM)—a metering system using electronic calculation equipment with API liquid measurement algorithms and security/auditing features, on-line temperature and pressure inputs, and linear meter pulse inputs. ELM provides real-time, on-line measurement.

emulsion—an oil and water mixture that does not readily separate.

F flash point—the temperature at which a liquid will give off enough flammable vapor to ignite or flash in the presence of a flame.

flashing—a process where highly volatile components come out of solution, usually due to a reduction in pressure.

floating roof—a tank roof which floats freely on the surface of the liquid contents except at low levels, when it is partially or wholly supported by legs. This is not the same as the lightweight floating cover frequently installed in fixed-roof product tanks to minimize evaporation loss. flow straightener—a length of straight pipe containing straightening vanes or the equivalent, which is installed at the inlet of a flow meter to eliminate swirl in the liquid, thereby reducing measurement errors.

flow-proportional sample—a sample of liquid taken from a flowing stream during the entire custody transfer. The rate of sample collection is proportional to the flow of the liquid in the pipe over a given time period.

fluid—a substance that flows; liquids and gases are fluids. four-way valve—a flow-reversing valve used with bidirectional provers.

Glossary

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free water—the measured volume of water present in a container of liquid hydrocarbons; free water is not in suspension in the hydrocarbons at the observed temperature. Compare suspended water.

G gasoline-indicating paste—a paste applied to a gauge tape that changes color when it comes into contact with gasoline.

gate valve—a full-bore valve with a sliding (gate-type) closure. gathering system—a pipeline, usually of small diameter, that brings oil, gas, or both from a group of leases (i.e., wells in a field) to a point for delivery to the main pipeline or other transport system. In SMART, a gathering system consists of facilities between a connection point and a base system.

gauge tube—a pipe (usually slotted) that extends down from the gauge hatch in a floating-roof tank to allow measurement through the roof of a floating roof tank.

gauge—to manually determine the quantity of a liquid in a tank. gauging height—the distance from the datum plate at the tank bottom (or, with lease tanks, from a striking point on the tank floor) to a designated reference point at the top of the tank.

grade—the type of crude oil based on its quality and composition. Grade is an important factor in commodity pricing. The higher the sulfur content, the lower the quality of the crude. Crude oil is generally classified as sweet (containing little or no sulfur), intermediate, or sour (containing hydrogen sulfide or another acid gas). Light crudes (those with relatively high API gravity and therefore low density) command a higher price than heavy crudes.

grindout—the process of spinning an oil sample in a centrifuge to determine the suspended S&W content. Also called shakeout.

gross observed volume (GOV)—a volume of oil, including dissolved water, suspended water, and suspended sediment but excluding free water and bottom sediment, measured at the prevailing oil temperature and pressure. Compare total observed volume.

gross standard volume (GSV)—a volume of oil, including dissolved water, suspended water, and suspended sediment but excluding free water and bottom sediment, calculated at standard conditions. This may be either the volume in a tank or the difference between the volume before and after a transfer. Compare net standard volume.

Glossary

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H hand gauging—manually measuring the quantity and quality of the liquid contents of an upright cylindrical storage tank.

handline gauging—hand gauging. hand-run tank—a tank whose oil content is transferred to a pipeline using manual measurement methods.

haze—a cloudy appearance in a transparent liquid or solid; an indication of contamination. high bottom—a level of S&W that is higher than 4" below the pipeline connection. hydrocarbons—a term that describes a wide range of hydrogen and carbon molecules. On the light end, the hydrocarbon methane, a natural gas component, consists of one carbon and four hydrogen atoms. On the heavier end, some crude oils are made up of many carbon and hydrogen atoms. hydrogen sulfide (H2S)—a poisonous gas which can evolve from crude oil. Higher H2S levels are generally found in the heavy sour crude oils. Respiratory protection is required when levels in the air reach 10 ppm. The IDLH (immediate danger to life and health) level is 300 ppm.

hydrostatic pressure—the pressure that a stationary column of fluid, such as oil or water, exerts on its container in proportion to the height of the liquid. In a full tank, the hydrostatic pressure is greatest at the tank bottom and decreases uniformly to the top of the liquid level.

I innage—the preferred method of gauging a tank. IP—Institute of Petroleum. ISO—International Organization of Standardization. An organization that sets standards in many businesses and technologies.

K Karl Fischer titration—a method of determining the water content of an oil sample, sometimes referred to as water content by titration.

K factor—denotes the number of pulses emitted by a meter while a certain volume of fluid flows through it; usually expressed in pulses per barrel. See pulses per unit volume.

Glossary

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L LACT—see lease automatic custody transfer. lease automatic custody transfer (LACT)—a system for automatically sampling, measuring, and transferring crude oil from a lease to a connected pipeline.

light ends—gaseous light hydrocarbons in crude oil: ethane (C2); propane (C3); isobutane and normal butane (C4); and isopentane and normal pentane (C5). Light ends may easily be lost by evaporation.

lower sample—a spot sample obtained at the midpoint of the lower third of the tank contents in a large tank, or just above the suction line in a lease tank.

M mass flow—the measure of flow in mass (for example, pounds) per unit of time (for example, hour). Coriolis meters measure the mass flow of a liquid.

mass—the mass of a substance is the quantity of matter it contains. It is, therefore, independent of external conditions such as the buoyancy of the atmosphere. In oil measurement, mass is frequently referred to as the weight-in-vacuo (weight in a vacuum).

measurement ticket—an official document that records any quantity of crude oil received into or delivered out of the pipeline system. A measurement ticket is the “bill of sale” for this type of transaction. Also called run ticket or custody transfer ticket.

meniscus correction—the correction that must be applied to a hydrometer reading on opaque oils to allow for the meniscus.

meniscus—the curved upper surface of the oil that adheres to the stem of the hydrometer due to surface tension forces in the oil. The curvature can be either concave or convex.

mercaptans—naturally occurring sulfur compounds. metals content—heavy metals in crude oil such as arsenic (As), iron (Fe), vanadium (V), and nickel (Ni).

meter factor (MF)—a number used to correct a meter’s inaccuracy. The factor is derived in the proving process by dividing the gross standard volume of oil flowing through the prover by the gross standard volume registered by the meter.

meter prover—a vessel of known volume that is used as a volumetric reference standard for checking the accuracy of pipeline meters.

Glossary

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meter proving—the procedure that determines the relationship between the volume of oil indicated by the meter and the true volume being measured under the same set of conditions.

meter pulse—an electronically generated signal. The number of pulses is proportional to the volume being measured; the frequency of pulses is proportional to the flow rate.

meter—a device for measuring volumes, quantities, or flow rates of the liquid flowing through the meter.

middle sample—a spot sample obtained from the middle of the tank contents (a point halfway between the upper and lower sample points).

MPMS—Manual of Petroleum Measurement Standards; published by API. multiple tank composite sample—a mixture of individual samples from several compartments (on ships, barges, and so forth), each of which contains the same grade of petroleum material. The mixture is blended in proportion to the volume of material in each compartment. Compare single tank composite sample.

N net standard volume (NSV)—a volume of oil, excluding total water and total sediment, calculated at standard conditions. Compare gross standard volume.

neutralization number—an indication of the amount of acidic components present in the crude oil. Also referred to as total acid number.

NIST-certified—refers to a measurement device whose accuracy has been tested by procedures specified by the National Institute for Standards and Technology (NIST) and is accompanied by calibration certificate.

NIST-traceable—refers to a measurement device that can be traced or referenced to a reference measurement standard at the National Institute for Standards and Technology (NIST).

nitrogen—in crude, the amount of “organic” nitrogen which is bound (attached) to hydrocarbon molecules.

O observed gravity—the API gravity of the product not temperature-corrected to 60°F. off seal—the seal removed from the tank stop valve prior to opening the valve to transfer the product into the pipeline.

Glossary

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opening gauge—the measurements taken (oil height, temperature, gravity, suspended S&W content, and bottom S&W level) on a hand-run tank to determine the oil quantity and quality prior to transferring the tank’s oil into the pipeline system. Also called opening a tank.

organic chlorides—in crude, primarily chlorinated hydrocarbons that remain in the hydrocarbon phase and are not removed in the refinery desalting process.

orifice meter—a meter that measures the velocity of the fluid (flow rate) by creating and recording a pressure differential in the fluid and then uses that rate to calculate the volume.

outlet sample—a spot sample taken at the level of the bottom of the tank outlet (either fixed or swing pipe) but not higher than three feet above the bottom of the tank. Also called bottom sample or clearance sample.

oxygenate—a compound containing oxygen, such as MTBE or ethanol, added to a gasoline to improve combustion efficiency and reduce carbon monoxide emissions.

P parcel—see batch pipeline—a system of connected lengths of pipe, usually buried in the earth or laid on the seafloor.

PLC— programmable logic controller. A microprocessor-based device used to control, among other operations, the flow of liquids through a pipeline from the gathering lines to the refinery by controlling the operation of valves and pumps along the pipeline. A PLC controls operations by continuously gathering information from the field (in the form of electronic analog or discrete signals), making decisions based on that information, and taking action based on those decisions. It can be used alone or in conjunction with a SCADA or other system.

positive displacement meter—a meter that breaks up a flow into portions of a known volume by filling and emptying chambers and counts those portions.

pour point—the lowest temperature at which a liquid will flow when its container is inverted. powered mixer—a type of mixer that uses an external source of power (usually electricity) to drive a motor and pump to mix the oil.

prerun—the piping on a bidirectional prover between the launch chamber and the first detector switch. The prerun length must be long enough to allow the four-way valve to be fully seated before the displacer (sphere) reaches the first detector switch.

pressure—force per unit area measured in pounds per square inch (psi).

Glossary

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probe—a small device that extends into a section of pipe. The probe contains an opening through which small discrete units of liquid are pulled and diverted to a sample storage container. See sample extractor.

production tank—a tank used in the field to receive crude oil as it comes from the well. Also called a flow tank or lease tank.

prover isolation valve—a valve in line with the meter that diverts flow through the prover when closed.

prover pass—a single movement of the displacer between the detector switches. prover round trip—a complete forward and reverse trip of the displacer in a bidirectional prover.

prover—see meter prover. proving run—a single pass of the displacer in a unidirectional prover; a single round trip in a bidirectional prover.

proving section—the calibrated area of a prover, located between the detector switches, where actual measurement takes place. Also called the measuring section.

psia—pounds per square inch absolute; that is, pressure measured in a vacuum. It equals the sum of gauge pressure (psig) and atmospheric pressure.

psig—pounds per square inch gauge; that is, pressure recorded by a gauge and measured with respect to that of the atmosphere. It refers to the amount of pressure a fluid exerts on the inside walls of a vessel containing the fluid.

psi—pounds per square inch; a measure of pressure. pulsating flow—flow with periodic pressure fluctuations. pulse generator—an accessory device on a meter that produces a series of repeating electrical signals (pulses). The number of pulses is proportional to the volume measured, and their frequency is proportional to the flow rate. pulse interpolation—a technique for counting the whole number of pulses between two events (such as the activation of detector switches) and then calculating any remaining fraction of a pulse.

pulses per round trip—the number of pulses or counts generated by a meter during a proving run. With a properly designed conventional pipe prover, the meter will generate at least 10,000 pulses between detector switches.

Glossary

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pulses per unit volume—the number of pulses for a given unit (barrels, gallons) that the meter will produce. This number, also known as the K factor, is provided by the meter manufacturer and depends on meter gearing, size, and construction.

R reagent—a substance used in a chemical reaction to detect, measure, examine, or analyze another substance; for example, in Karl Fischer titration to determine the water content in oil samples.

reference point—a point near the gauge hatch used during hand gauging. This point is marked, and the distance between it and the gauge plate is normally written nearby on the side of the tank.

Reid vapor pressure (RVP)—the vapor pressure of a liquid at 100°F as determined by ASTM D323. See also vapor pressure.

relative density—The ratio of the weight of a given volume of a substance at a given temperature to the weight of the same volume of water at the same temperature. API gravity is derived from relative density. Formerly called specific gravity.

remote—a term used to refer to devices that are not part of or located near the main computer. repeatability—the closeness of successive measurement results for the same quantity under the same conditions and with the same equipment and methodology.

representative sample—a small portion extracted from the total parcel or batch that contains the same proportion of flowing components as the total parcel being transferred. The precision of extraction must be equal to, or better than, the method used to analyze the sample. reproducibility—the closeness of the agreement between the results of measurements of the same quantity, where the individual measurements are made by different operators using different equipment at different locations.

resistance temperature detector (RTD)—a sensing element with an electrical resistance that is a function of temperature.

roof correction—in gauging a tank, the number that corrects for the oil displaced by the floating roof.

RTD—see resistance temperature detector. run a tank—to transfer oil from an upright cylindrical lease tank to a pipeline. run ticket—see measurement ticket.

Glossary

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running sample—a sample obtained by lowering an unstoppered bottle at a uniform rate of speed from the top of the oil to the level of the bottom of the outlet connection or swing line and returning it to the top of the oil at the same rate, such that the bottle is about three-fourths full when it is withdrawn from the oil. Because of the difficulty of obtaining a representative sample using this method, it is usually used with products which are more homogenous than crude oil.

RVP—see Reid vapor pressure.

S S&W—sediment and water; that portion of the crude oil that is unmerchantable. salt—in crude, a contaminant resulting principally from either production practice in the oil fields or handling in tankers transporting the crude.

sample conditioning—the process of mixing a sample to prepare it for analysis. sample container—a can, bottle, or thief containing a liquid sample for testing. sample controller—the device in an automatic sampler that governs the operation of the extractor either in proportion to time or to the flow rate.

sample extractor—in an automatic sampler, the device used to pull small discrete units of liquid, called sample grabs, from the flowing stream (through the probe). The extractor diverts these units of liquid to a nearby storage container.

sample grab—the volume of liquid extracted from the pipeline by a single actuation of the sample extractor. The sum of all grabs results in a sample.

sample handling—the process of extracting, conditioning, transferring, and transporting a representative sample from a sample container to analytical glassware or centrifuge tubes.

sample pot—see sample receiver. sample proving—a technique used to validate an automatic sampling system. An acceptable validation can be made by injecting a known quantity of water ahead of the sampling system, taking samples, analyzing the samples for sediment and water content, and comparing those results with the known water injection. sample receiver—a container on an automatic sampler in which all sample grabs are collected. A receiver may be fixed (stationary) or portable.

sample—a small quantity of liquid obtained from a tank or pipeline for analysis. See representative sample.

Glossary

September 2002

G.16

BP Pipelines


SCADA—Supervisory Control and Data Acquisitions. A software system that monitors and controls pipeline or refinery status and provides logging capabilities. SCADA systems are highly configurable and usually interface to a facility via PLCs.

sediment and water (S&W)—materials coexisting with, yet foreign to, petroleum liquid that require separate measurement for sales, accounting, and other reasons. These foreign materials include free water and sediment, and emulsified or suspended water and sediment.

sediment—any foreign substance of no value in the oil that will not dissolve and remains suspended, such as fine grains of rock, clay, metal, etc. shakeout—see grindout. shell height—the distance between the bottom of the bottom angle of the tank and the top of the top angle.

SI—International System of Units (metric system). sideline gauging—automatic gauging of a tank. single tank composite sample—a blend of the upper, middle, and lower samples taken from a single tank. For a tank of uniform cross sections, such as upright cylindrical tanks, the blend consists of an equal part of the three samples. For other types, the blend may require different proportions from each sample. Compare multiple tank composite sample.

sludge solvent—a solvent, like Stoddard solvent, used to remove sludge from sample containers, bottles, thiefs, test tubes, or other vessels.

sludge—a mixture of sediment, dense hydrocarbons and water which can settle out on the bottom of a tank or vessel containing a sample.

SMART—BP Pipelines’ software for creating measurement tickets and reports. spot sample—a sample taken at a specific location in a tank or from a pipe at a specific time during a pumping operation.

standard conditions—the standard pressure and temperature to which fluid measurements are corrected. These are 14.73 lb/in2 and 60°F in the U. S. system.

standardization laboratory—a laboratory accredited by national or international authorities to calibrate instruments or equipment to traceable measurement standards.

static measurement—the measurement of a hydrocarbon that is not flowing; for example, oil in a tank.

Glossary

September 2002

G.17

BP Pipelines


static mixer—a mixer with no moving parts. The kinetic energy of the moving fluid provides the power required for mixing (e.g., fixed objects in a conduit that uses the kinetic energy of the moving fluid to mix the hydrocarbons). Compare powered mixer.

Stoddard solvent—a solvent used to clean sludge from sample containers, bottles, thiefs, test tubes, or other vessels; may also used to dilute samples in S&W testing.

storage tank—a tank in which a hydrocarbon is stored pending transfer by pipeline, truck, or other means to a point where it is ultimately sold.

strainer—a device placed upstream of a meter to remove from the stream foreign material which is likely to damage the meter or interfere with its operation. The strainer element is generally coarser than that of a filter designed to remove solid contaminants.

strapping—see tank strapping. stream conditioning—the mixing of the pipeline contents, upstream of the sampling location, which is necessary for delivery of a representative sample.

subsample—a sample of a sample. sulfur— in crude oil, a contaminant primarily present as organic sulfur (attached to hydrocarbon molecules) or as hydrogen sulfide, mercaptans (see mercaptans), and inorganic salts (sulfates).

suspended water—small droplets of water that do not quickly separate from the oil due to the forces of gravity. Compare free water.

T tank calibration table—a table that tells the quantity of liquid contained in a tank at any given level. Also called tank table.

tank stop valve—a valve that controls the flow of oil into or out of a tank. The term specifically applies to valves connected to lease tanks.

tank strapping—the process of measuring the external circumference of a cylindrical tank by stretching a steel tape around each course of the tank’s plates and recording the measurements. The term is often used for the process of taking the full set of measurements required in generating a tank table.

tank table—see tank calibration table. tap—a pipe welded to the shell of a tank that serves as a conduit or port to the inside of the tank. Also known as a nozzle.

Glossary

September 2002

G.18

BP Pipelines


tape cut—the level at which the oil level in the tank crosses the gauge tape when the plumb bob is properly resting on the datum plate.

temperature compensator—a device on a meter that automatically converts the registered volume flowing through the meter to a standard volume at 60°F. Also known as an automatic temperature compensator (ATC).

test measure—in a waterdraw calibration unit, a vessel of known volume calibrated by NIST. thermowell—a metal protective pocket installed in the pipe wall into which the sensing element (bulb) of a thermometer is inserted.

time-proportional sample—a sample composed of equal sample grabs taken from a pipeline at uniform time intervals during the entire transfer.

titration—a process of chemical analysis by which drops of a standard solution (Karl Fischer reagent, in the testing for water in oil by titration) are added to another solution (the oil sample) to obtain a desired response.

top sample—see upper sample. total observed volume (TOV)—a volume of oil, including total water and total sediment, measured at the prevailing oil temperature and pressure. Compare gross observed volume.

total water—the sum of the dissolved, entrained, and free water in the cargo or batch of oil. traceability—the relation of a prover or a transducer calibration, through a step-by-step process, to the fundamental standards of mass, length and time, certified and maintained by national or international standardization laboratories. See also NIST-traceable.

transducer—a device that is actuated by power from one system and supplies a different form of power to another system For example, the transducers in an ultrasonic meter receive electrical power, which causes them to vibrate (mechanical power), and in turn they convert received sound waves back into an electrical signal.

trend—to chart meter factors from one meter over time to monitor the meter’s performance and condition. SMART includes a utility program for this purpose. turbine meter—a flow meter with a bladed rotor that turns at a speed approximately proportional to the mean velocity of the flowing liquid and therefore to the volume rate of flow.

Glossary

September 2002

G.19

BP Pipelines


U ultrasonic meter—an inferential meter that derives the velocity of the fluid (flow rate) by measuring the transit times of high-frequency sound pulses; the flow rate is then used to calculate volume.

unidirectional—referring to flow in one direction only; for example, a unidirectional pipe prover or meter.

upper sample—a spot sample taken at the midpoint of the upper third of the tank contents in a large tank, or just below the surface of the liquid in a lease tank.

V vapor pressure—the pressure in an enclosed space that is due to the vapor of the substance occupying that space. Since liquid evaporates more quickly as temperature rises, vapor pressure increases as the temperature of the liquid increases. Thus, vapor pressure is a measure of the tendency of the substance to evaporate.

Varsol—the brand name for a solvent that may be used in the centrifuge test, also referred to as Stoddard solvent.

viscosity—a measurement of a fluid’s resistance to flow. Various units of viscosity measurement include centipoise, centistokes, and Saybolt Second Universal (SSU).

volatility—the tendency of a liquid to vaporize. volume correction factor (VCF)—the product of the temperature (CTL) and pressure (CPL) factors for a liquid; used in calculations for determining net standard volume in a tank.

volume-weighted average temperature— the average temperature determined electronically from the mean value of the measured temperature over a specified period of actual flow.

W water cut of dip—(1) the depth of free water lying on the bottom of a tank.; (2) the line of demarcation of the oil/water interface. waterdraw calibration—a method of certifying the volume of a prover. water-indicating paste—a paste applied to a gauge tape that changes color when it comes into contact with water.

water-saturated toluene—a solvent used in S&W testing.

Glossary

September 2002

G.20

BP Pipelines


wire seal—a metal sealing device used to replace a boxcar seal that is defective or shows signs of tampering. Compare boxcar seal.

witness—a person who observes the measurements of a meter or tank custody transfer or meter proving and verifies the measurement activities by signing the accompanying ticket or proving report. This person must be a representative of the connecting carrier or shipper and should be knowledgeable about the information contained in the ticket or proving report.

Glossary

September 2002

G.21

BP Pipelines


Index Page numbers in italics refer to figures.

A ACT unit see LACT/ACT units adjustments procedure for filing, 17.5 sample affidavit, 17.11 when to file, 17.4 API gravity determination equipment list, 2.4 sample to use in lease tanks,

1.7, 3.5 API gravity determination in tanks hydrometer method, 2.6–2.8 thermohydrometer method,

2.5–2.6 automatic sampling see also sample receivers equipment list, 10.4 labeling sample container,

10.6 mixing samples, 10.12 procedures handling portable receivers, 10.5 handling samples, 10.4,

10.5, 10.6 maintaining receivers,

10.5 automatic sampling system see also sample receivers design, 10.8–10.11 testing receivers, 10.7 total system, 10.7

C calculations average tank temperature, 2.8 detector resolution, 15.4 distance between prover detectors, 15.6 ELM system functions, 9.11

Index

flow computer functions,

11.7 flow rate in LACT unit, 9.7 meter factor, 14.1, 14.4, 14.6 net standard volume, 3.13,

4.16 prover diameter, 15.5 prover prerun length, 15.7 pulses per barrel, 14.7 sample grabs per transfer, 9.8 tank volume, 7.3 waterdraw, 16.11 calibration PET, 2.12 pressure transducers, 9.10 prover, see waterdraw calibration strapping tape, 7.5 capacity table see tank capacity table centrifuge tube cleaning, 5.5 types, 5.7, 5.11 claims procedure for filing, 17.5 sample letter, 17.9 when to file, 17.4 cleaning pipe prover, 16.5 sample bottle, 1.9 sample receiver, 10.6 tape, 2.9 thermometer, 2.9, 2.11 thief, 1.6 closing gauge large tank, 4.11 lease tank, 3.11–3.12 cloud point testing, 6.13–6.14 compositing samples, 1.7, 1.10 connection height see tank strapping Coriolis meter design, 13.7–13.8

September 2002

uses, 13.7 crude oil manual sampling mixing tank contents, 1.4 number of samples from tanks, 1.14 reasons for sampling, 1.3 temperature determination mixing tank contents, 2.5 tests distillation, 6.10–6.11 hydrogen sulfide, 6.8–6.9 light ends, 6.7–6.8 mercaptans, 6.4 metals, 6.6–6.7 neutralization number,

6.11 nitrogen, 6.11–6.12 organic chlorides, 6.5 Reid vapor pressure,

6.5–6.6 sulfur, 6.3–6.4 viscosity and pour point,

6.9 water content, 5.12–5.14 cupcase thermometer accuracy limits, 2.2 cleaning, 2.11 immersion time, 2.15 use of, 2.2

D demulsifier, 5.4 detectors calibration, 14.11 distance between, 15.6 maintenance, 16.4 role in nonrepeatability, 14.9 role in prover calibration,

16.3 role in prover sizing, 15.5 role in prover system design,

15.3

I.1

BP Pipelines


role in sphere sizing, distillation in crude oil,

6.10–6.11 E effective inside tank height see tank strapping ELM system described, 9.11 flow computer live input, 9.12 manual input, 9.11 ticket output, 9.12–9.13 security, 8.7

differences between lease tank and large tank, 3.5 innage, 3.5 opening gauge, 3.6–3.11 gauging height see tank strapping

H haze testing, 6.15–6.16 hydrogen sulfide testing, 6.8–6.9

I inferential meter see turbine meter, ultrasonic meter, Coriolis meter

F field centrifuge testing see suspended S&W testing flash point testing, 6.14–6.15 forms LACT/ACT inspection blank, 9.15 sample, 9.14 proving report, 14.15 sample adjustment affidavit, 17.11 sample claim letter, 17.9 sample lease meter ticket, 17.13 sample tank ticket, 17.12 strapping report, 7.13 waterdraw calibration worksheet, 16.13

G gauging calculations, 3.13, 4.16 equipment list, 3.4, 4.4 for inventory annually, 4.13–4.15 monthly, 4.12–4.13 procedures, large tank closing gauge, 4.11 differences between lease tank and large tank, 4.5 external floating roof, 4.5 innage, 4.8 internal floating roof, 4.7 opening gauge, 4.8–4.11 procedures, lease tank closing gauge, 3.11–3.12

Index

K Karl Fischer titration see suspended S&W testing

L labeling automatic samples, 10.6 demulsifier bottle, 5.5 sample container, 1.6, 1.7,

10.2 laboratory testing see suspended S&W testing LACT/ACT units checking calibrating pressure transducers, 9.10 calibrating temperature devices, 9.10 checkout list, 9.5 equipment list, 9.4 procedures, 9.6–9.9 programming run time,

9.5 inspection form blank, 9.15 sample, 9.14 meter proving, 14.5 reporting malfunctions, 17.1 where to seal, 8.5 light ends testing, 6.7–6.8

M manual samples clearance, 1.7, 3.8, 3.9 labeling sample container, 1.7 lower

September 2002

large tank, 4.5 lease tank, 3.5 middle large tank, 3.5, 4.5 lease tank, 1.7, 3.5 number to take large tank, 1.14 small tank, 1.14 types listed, 1.4 upper large tank, 4.5 lease tank, 3.5 manual sampling see also API gravity determination, suspended S&W testing, settled S&W determination, manual samples compositing, 1.7, 1.10 equipment list, 1.3 mixing samples, 1.16 mixing tank contents, 1.4 number of samples to take crude tank, 1.14 product tank, 1.15 procedures all-levels, 1.10 bottle, 1.9–1.11 running, 1.11 spot with bottle, 1.9–1.10 spot with thief, 1.5–1.8 summary of, 1.13 where to sample large tank, 4.5 lease tank, 3.5 mercaptans testing, 6.4 metals testing, 6.6–6.7 meter factor accuracy limits, 11.4–11.5,

14.7 calculating, 14.1, 14.2, 14.4,

14.6, 14.8 causes of fluctuations, 14.10 effect of operating conditions,

11.11 trending, 11.5 troubleshooting,

14.11–14.12 meter prover calibration schedule, 14.6 calibration, see waterdraw

I.2

BP Pipelines


calibration cleaning 16.5 maintenance, 14.13 meter proving procedures general, 14.6 portable prover, 14.8 stationary prover,

14.6–14.7 proving report, 14.15 proving schedule, 14.5 repeatability requirements,

14.8

11.11–11.12 operating ranges of meter,

11.10

troubleshooting meter factor, 14.10 nonrepeatability, 14.9 procedures, 14.11–14.12 meter proving system design criteria, 15.3–15.4 detector resolution, 15.4 prover sizing diameter, 15.5 distance between detectors, 15.6 prerun length, 15.7 valve actuator time, 15.7 prover sphere type, 15.8 pulse generator, 15.4 mixing samples, 1.16, 10.6 tank contents, 1.4

N neutralization number, 6.11 nitrogen testing, 6.11–6.12

O opening gauge large tank, 4.8–4.11 lease tank, 3.6–3.11 organic chlorides testing, 6.5 orifice meter design, 13.3 orifice plates, 13.4 uses, 13.4 oxygenate content, 6.16

P PD meter design, 11.6 equipment for checking, 11.3

Index

inspection procedures auxiliary equipment, 11.5 meter, 11.4–11.5 troubleshooting, 11.5 inspection schedule, 11.3 maintenance, 11.3 PD meter installation design, 11.7–11.10 equipment, 11.7–11.8 factors affecting accuracy,

specifications, 11.8–11.10 PET accuracy limits, 2.2 immersion time, 2.15 keeping in motion, 2.2, 2.15 petroleum products manual sampling mixing, 1.4 number of samples, 1.15 reasons for sampling, 1.3 summary of procedures,

1.13 tests flash point, 6.14–6.15 oxygenate content, 6.16 Reid vapor pressure, 6.13 viscosity, pour point, cloud point, 6.13–6.14 water content and haze,

6.15–6.16 pour point testing in crude oil, 6.9 in products, 6.13–6.14 prover see meter prover prover sphere inflation, 16.16–16.17 preparing for calibration,

16.4 role in changing meter factor,

14.10, 14.11 role in nonrepeatability, 14.9 roundness tolerances,

16.15–16.16 types, 15.8, 16.14 when to check, 14.13

September 2002

proving see meter proving proving system see meter proving system

R reference height see tank strapping Reid vapor pressure testing in crude oil, 6.5–6.6 in products, 6.13 repeatability and detectors, 15.4 and pulse generator, 15.4 causes of nonrepeatability,

14.9 requirements, 14.8 troubleshooting,

14.11–14.12 reports distributing, 17.7 types, 17.6 using SMART to create, 17.6

S S&W see settled S&W determination, suspended S&W testing sample bottle cleaning, 1.9 sample container labeling, 1.7 sample pots see sample receivers sample receivers cleaning, 10.6 maintaining, 10.5 portable described, 10.10 handling, 10.5 mixing equipment, 10.12 sizes, 10.13 stationary described, 10.9 mixing equipment, 10.11 samples, see manual samples, automatic sampling sampling, see manual sampling,

I.3

BP Pipelines


automatic sampling seals see also security boxcar seal, 8.8 broken, 8.6 during closing gauge, 3.11,

3.12 during opening gauge, 3.6 equipment for working with,

8.3 how to use, 8.4 signs of tampering, 8.6 when and where to use on tanks, 8.4–8.5 where to use on LACT/ACT units, 8.5–8.6 security see also seals on ELM systems, 8.7 on LACT/ACT units, 8.5–8.6 on tanks, 8.7 settled S&W determination procedure, 1.7–1.8, 3.9, 3.12 rejecting tank for, 3.1 SMART for meter factor trending,

14.9 for proving report, 14.6 for reports, 17.6 for settled S&W determination, 4.13, 4.14 for tickets, 4.12, 4.13, 17.6 sample lease meter ticket, 17.13 sample tank ticket, 17.12 sphere see prover sphere strapping see tank strapping sulfur testing, 6.3–6.4 suspended S&W testing equipment list, 5.3 field centrifuge method large tanks and automatic samplers, 5.8–5.10 lease tanks, 5.7–5.8 sediment only, 5.11 Karl Fischer titration, 5.12 laboratory method,

5.11–5.12 Index

maximum allowable, 5.1 number of samples to take large tank, 1.14 small tank, 1.14 preparing demulsifier, 5.4 preparing samples, 5.5 preparing water-saturated toluene, 5.4 water content by volume,

5.12–5.14 T tank calibration table see tank capacity table tank capacity table development, 7.3, 7.9 use, 2.4, 3.13, 4.16 tank strapping calibration of tape, 7.5 equipment list, 7.3 fill condition, 7.12 procedures checks before strapping,

7.4 circumference, 7.5–7.7 connection height, 7.10 deadwood measurement,

7.11 effective inside tank height, 7.9–7.10 height measurements, 7.7 manhole dimensions, 7.11 overflow line, 7.10 plate thickness, 7.4 reference height, 7.9 shell height and tilt,

7.8–7.9 strapping report, 7.13 when to strap, 7.3 temperature determination in tanks cupcase thermometer procedures, 2.10–2.11 for custody transfer, 2.10 for inventory, 2.10 immersion times, 2.15 mixing tank contents, 2.5 PET procedures, 2.9–2.10 where to measure, 2.8, 2.8,

tests for crude oil, see crude oil, tests for products, see petroleum products, tests thermometers verifying glass thermometer,

2.12–2.13 verifying PET, 2.11–2.12 thief, 1.5 cleaning, 1.6 cord, 1.5 procedures for lowering, 1.6 tickets correcting, 17.6 distributing, 17.7 output from ELM system,

9.12–9.13 sample lease meter, 17.13 sample tank, 17.12 types, 17.6 using SMART to create, 17.6 turbine meter design conventional, 12.5 helical, 12.6 inspection procedures auxiliary equipment, 12.4 meter, 12.4 maintenance, 12.3 operation, 12.5, 12.12 turbine meter installation design, 12.7–12.11 factors affecting accuracy,

12.13 operating range conventional meter, 12.9 helical meter, 12.10 pulse transmission accuracy,

12.10–12.11 U ultrasonic meter, 13.5–13.6

V viscosity testing in crude oil, 6.9 in products 6.13–6.14

2.14

September 2002

I.4

BP Pipelines


W water content testing in crude oil, 5.12–5.14 in products, 6.15–6.16 waterdraw calibration accuracy limits, 16.10 calculations, 16.11 calibration schedule, 16.3 procedures general, 16.6 pipe prover, 16.4–16.5,

16.8–16.10 small-volume prover,

16.6, 16.10 prover sphere types, 16.14 sphere inflation, 16.16–16.17 roundness, 16.15–16.16 worksheet, 16.13 water-saturated toluene, 5.4

Index

September 2002

I.5

BP_Measurement Manual PART1

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