1.SCOPE

Engineering StandardsStandard0115

Page

ENRON

2 of 1

GAS PIPELINECORROSIVE GAS DEFINITIONIssue Date

GROUPFOR GAS PIPELINE FACILITIES

02/88

Rev. No.2

Date05/91

1.SCOPE

This standard defines the characteristics of gas for use in determining when internal corrosion prevention measures should be instituted in the design, construction and/or operation of gas pipeline facilities.

2.CODES AND STANDARDS

49 CFR Part 192, 192.475 and 192.477.

Operating Procedure 40.104, Internal Corrosion, Non-Jurisdictional Gathering Facilities.

Operating Procedure 40.105, Internal Corrosion, DOT Jurisdictional Facilities.

3.DEFINITION

3.1Gas containing water in liquid phase and at least one of the following components is considered to be potentially corrosive. A combination of two or more components with water in liquid phase may be potentially corrosive at lower concentrations. The concentrations above which corrosion will occur will be higher in dry gas (gas having water vapor below the point of saturation).

*3.1.1H2S concentration greater than 1.0 grain per 100 SCF (16 ppm or 0.0016% by volume).

3.1.2CO2 concentration greater than 12 psia partial pressure regardless of total pressure at operating temperatures up to 60F. The limit should be lower at higher operating temperatures and should be evaluated on a case-by-case basis.

CO2 concentration expressed as mole percent is the partial pressure of CO2 as a percentage of total pressure of the gas mixture (e.g., for a gas pipeline at 500 psia, 12 psia/500 psia = 0.024 mole fraction or 2.4 percent).

3.1.3O2 concentration greater than 50 ppm.

3.1.4Aqueous solution containing chlorides in concentrations greater that 500 ppm.

3.1.5Liquids or materials having a pH less than 6.0.

3.2Produced liquids containing sulfate reducing or acid producing micro biological colonies with culture test indicating over ten (10) colonies per milliliter are considered to be potentially corrosive.

4.GENERAL REQUIREMENTS

4.1Corrosive gas shall not be transported in DOT jurisdictional pipelines unless the corrosive effect of the gas has been investigated and measures have been taken to eliminate or minimize internal corrosion.

4.2When it is determined that corrosive or potentially corrosive gas will exist in new or existing operating pipelines, the requirements of Operating Procedures 40.104 or 40.105 shall apply.

4.3When it is determined that corrosive gas will exist in pipelines to be constructed, the provisions for corrosive or sour gas service contained in Engineering Standards for the components and materials used in the design will be considered. Typical design measures to eliminate or minimize internal corrosion follow.

4.3.1Blending of corrosive gas stream with non-corrosive gas stream.

4.3.2Corrosion resistant materials and/or internal coating for pipe and piping components. See Engineering Standards 4701 and 4905 for pipe and piping materials selection and 6600 series for pipe coating materials.

4.3.3Pigging facilities and corrosion inhibitor injection. See Engineering Standards 0075 and 0100 for pipeline design philosophy.

4.3.4Gas treatment to remove water or acid producing components. See Engineering Standard 0050 for treating plant design philosophy.

* Indicates revised paragraph, this Rev. No.