Mahboobul Mannan, Dwight B. Pfenning, C. Dale Zinn
Jones & Neuse Inc.
Austin, Tex.
Conducting risk analysis and safety-engineering studies before construction of a sour-gas pipeline system will build redundancies into the system and ensure safe operation and maintenance.
A recent analysis of a sour gas pipeline built in Texas provides an example of procedures for safety engineering and risk assessment.
This first of two articles presents the risk-analysis methodology and minimum safety systems required by governmental regulations, a prioritized list of credible release scenarios, and hazard-zone calculations for each release scenario.
The concluding article will examine the hazard zones for the effects of postulated hazards on operating personnel, equipment, third parties, and the environment.
DOT, TEXAS REGULATIONS
Significant reserves of sour natural gas must be sweetened before delivery to gas transmission lines. In order to transport the sour gas to the processing plant, however, large gathering systems consisting of several miles of pipelines quite frequently must be constructed.
Given the severe impact of an accident and release from a sour-gas pipeline, it is very important that all safety procedures and governmental regulations be properly followed in design, construction, operation, and maintenance of sour-gas pipelines.
Texas' natural-gas transmission pipelines are required to comply with the design, construction, operation, inspection, and maintenance criteria in U.S. Department of Transportation (DOT) 49 Code of Federal Regulations (CFR) Parts 191 and 192 and in Title 16, Texas Administrative Code, Sections 7.707.72.
Additionally, all facilities which use, process, or distribute natural gas with an H2S content greater than 100 ppm are subject to Rule 36 of the Texas Railroad Commission (TRC). 1 2
The federal regulations went into effect in 1970 and, about the same time, federal regulations were also adopted requiring gas-transmission line operators to file reports with the U.S. government on "reportable service incidents" involving all gas transmission pipelines, regardless of when the lines were built.
Over the years, the data have been analyzed and published by several organizations.
SAFETY SYSTEMS
It is common practice to utilize a multiple-layer safety program for sour-gas pipelines. This approach assists in addressing safety considerations at each stage of project development.
An overview of the various safety programs follows.
PIPE, MATERIAL DESIGN
Sour-gas pipelines should be designed, constructed, inspected, and tested in accordance with the requirements of 49 CFR 192 and Title 16, Texas Administrative Code, Sections 7.70-7.72. From a safety point of view, 49 CFR 192 delineates stringent requirements for pipelines, resulting in a high level of builtin pipeline safety.
The Charpy V-notch specification is not required by any of these standards but should be included in the sour-gas pipeline design to ensure high resistance to fracture (fracture toughness) of the pipe.
Where pipe and components are specified with fracture toughness, the probability of a fracture occurring is reduced, the pipe is more tolerant to defects, and the potential for a fracture to propagate is reduced.
Pipe damage in the form of denting reduces the ability of the pipe to tolerate defects. Pipe with fracture toughness, however, can accommodate quite large dents without significant reduction in pipe integrity.
WELDS, VALVES
All welds on sour-gas pipelines should be radiographically tested. This procedure significantly exceeds 49 CFR 192 requirements which call for testing of at least 15% of each day's welds. In addition, all welds on sour-gas pipelines should be stress relieved to reduce the possibility of sulfide stress cracking (SSC).
Sectionalizing valves should be located strategically and as required by 49 CFR 192. Provision should be made for automatic closure of the pipeline by high or low-pressure detectors and by H2S gas detectors.
Should heaters be required to keep the gas temperature greater than the dew point temperature, the heat-transfer media preclude direct contact between the tubes carrying the gas to be heated and the direct energy source.
The heaters should be designed to shut down under abnormal operating conditions.
TESTING, CORROSION PROTECTION
Before being placed in service, the completed sour-gas pipeline should be hydrostatically pressure tested to 90% of its yield strength. This test procedure exceeds the hydrostatic test requirements of 49 CFR 192.
The maximum allowable operating pressure (MAOP) should be established in accordance with the hydrostatic test results and 49 CFR 192.619. These tests and requirements reduce the potential for a pipeline failure due to an undetected defect during the construction phase of the project.
Hydrostatic pressure tests should also be conducted during service to reduce the potential for pipeline failure due to corrosion effects.
Sour-gas pipelines should be constructed with pig launchers and receivers to accommodate inspection of the pipeline with an instrumented inspection tool, a "smart pig."
The pig launcher and receiver system should be arranged so that liquid slugs that may be received at the pig receiving trap can be safely separated from the gas being directed to the flare for disposal. The use of modern corrosion-protection technology reduces the potential for a corrosion-caused pipeline failure.
The steel to be used for the pipeline should pass the National Association of Corrosion Engineers (NACE) corrosion test (TM-02-84) for hydrogen-induced cracking. Additionally, the steel should meet NACE requirement MR-01-75 to resist SSC.
As additional corrosion protection, the pipe should be externally coated with a corrosion-resistant film. The entire pipeline should be protected from general galvanic corrosion by a state-of-the-art cathodic-protection system.
Internal corrosion should be monitored by corrosion probes and controlled by corrosion-inhibitor injections.
OPERATIONS, MAINTENANCE
As part of its responsibilities, the operator of the pipeline should incorporate and expand programs for the safe and reliable operation of the pipeline. Some of these programs should include:
- A written operating manual which contains procedures for normal operations, maintenance, abnormal conditions, repair, emergency situations, and accident investigation
- Training programs for operating, maintenance, and pipeline-inspection personnel in accordance with TRC Rule 36 and other governmental regulations
- An active pipeline-damage contact program. This program includes direct contact with landowners and tenants along the pipeline right-of-way, direct contact with excavating contractors who commonly work in areas near the right-of-way, pipeline marking programs, and "call before you dig" programs.
- A program for monitoring and maintaining pipeline integrity. This program includes regular transmission-line patrols and leakage surveys.
Inspections and maintenance of the pipeline should be performed in accordance with a detailed operating and maintenance plan. TRC Rule 36 is administered by TRC's oil and gas division and requires the following:
- Buried pipelines should be marked with sufficient information to establish the ownership and existence of the line, and the marker signs shall use the words "Poison Gas" and "Danger."
- Metals used in construction must be resistant to SSC and satisfy the requirements of the latest editions of NACE standard MR-01-75 and API RP-14E, Sections 1.7(c), 2.1(c), and 4.7.
- Control and safety equipment must be provided or safety procedures designed to prevent the undetected continuing escape of H2S.
- A written contingency plan must be developed to provide an organized plan of action for alerting and protecting the public within a specified radius of exposure (ROE) following an accidental release of a potentially hazardous volume of H2S.
The ROE should be calculated with the Pasquill-Gifford equation.
- Pipeline personnel (operators, supervisors, maintenance) must be trained in H2S safety.
EMERGENCY PLANS
Emergency plans for the sour-gas pipeline should be developed in accordance with applicable governmental and operating-company requirements.
Written emergency responses, accident investigations, and repair procedures should be prepared, and the appropriate operating personnel should be trained in their proper use. Results of risk-assessment studies and hazard-zone calculations should be used in formulation of the emergency-response actions contained in the emergency plans.
PUBLIC RISK
The presence of all the safety systems discussed in the previous section and the utmost care in operation of the facility do not preclude the possibility of a rupture in the pipeline and release of sour natural gas.
In order to define the public risk, hazard zones must be calculated for postulated releases. After computation of the hazard zones, the probability of the postulated releases and the probability of weather conditions that would cause vapor-cloud travel are estimated.
The public risk is then calculated as a probability of exposure of the public as a function of distance from the pipeline.
RELEASE SCENARIOS
Examination of the design and operation of the sour-gas pipeline suggests several release scenarios.
For each, the potential severity and probability of occurrence has been subjectively estimated. The information has been placed in a risk matrix to establish the priority for detailed examination of the different releases.
The 4 x 4 risk matrix used is shown in Fig. 1. It is based on four severity categories and four probability-of-occurrence categories.
A release with a risk index of 1 or 2 is considered to be a high-risk hazard that requires action. Releases with risk indices of 3, 4, and 5 are moderate risks. Low-risk hazards have risk indices of 6, 7, 8, and 9 and may be investigated as resources permit to lower the residual risk on a cost-benefit basis.
For the sour-gas pipeline in this study, four scenarios were based on two types of release causes--corrosion and outside-force damage. For each type of release, two different hole sizes were selected to represent extremes within each category.
Table 1 shows the postulated hole sizes for the two rupture categories.
HAZARD-ZONE CALCULATIONS
The eight types of calculations for hazard zones are:
- Flow rates vs. time for the hole sizes. With the operating condition of the pipeline and under the assumption that ruptures occur at a distance half the pipeline length from the compressor, gas release rates were calculated with pipe-break models.
The models calculate the flow out of the break by pressure balance. Maximum and steady-state flow rates are calculated for each of the hole sizes.
- Bleed-down time for the section of pipeline between sectionalizing emergency-shutdown valves (ESD) for the four hole sizes.
After a rupture is detected, a possible response could include isolation of the leaking section by closing the sectionalizing valves. The gas mixture in that leaking section will continue to leak until the leaking section is completely purged.
For the sour-gas pipeline analyzed in this study, four different rupture sizes were considered and the flow rates were plotted against the bleed-down time. Plots for two different hole sizes are shown in Fig. 2.
Fig. 2a represents a catastrophic failure of the pipeline, and Fig. 2b represents a pinhole break. This information can be used to formulate emergency response plans and mitigation measures.
- Vapor dispersion for each of the hole sizes and for two weather conditions (wind speed and atmospheric stability) for clouds released in the vertical direction.
For the sour-gas pipeline analyzed in this study, vapor dispersion calculations were made for each release rate at the two weather conditions.
The two conditions selected represented prevailing conditions and worst-case conditions. Worst-case conditions are defined as those that yield maximum downwind cloud travel.
The dispersion methodology used is a turbulent jet release model. 3 When the turbulent jet portion of the release dissipates, the model couples to a Gaussian-type dispersion using dispersion methodology and coefficients specified in Texas Air Control Board's Episodic Model. 4
The clouds rise and bend over because of the wind after they lose upward momentum. In some cases the plume may extend to the ground, while in other cases the plume may not touch the ground at all.
This study assumed, however, that the plumes touched the ground in all cases. We have taken this very conservative approach (worst-dispersion *contact area) to account for weather conditions where the plume is trapped between the ground surface and a stable layer aloft. The H2S concentrations of interest were chosen as 100, 300, 500, and 1,000 ppm. H2S is both an irritant and an asphyxiant.
Low concentrations of approximately 100 ppm irritate eyes; slightly higher concentrations may irritate the upper respiratory tract. If exposure is prolonged, pulmonary edema may result. 5
The irritation action has been explained on the basis that H2S combines with the alkali present in moist surface tissues to form sodium sulfide, a caustic.
With higher concentrations, the action of the gas on the nervous system becomes more prominent, and a 30-min exposure to 500 ppm results in headache, dizziness, excitement, staggering gait, diarrhea, and dysuria, followed sometimes by bronchitis and bronchopneumonia.
The action on the nervous system is, with small amounts, one of depression. In larger amounts, it stimulates, and with very high amounts the respiratory center is paralyzed. Exposures of 800-1,000 ppm may be fatal in 30 min, and high concentrations are instantly fatal.
H2S does not combine with hemoglobin of the blood; its asphyxiant action results from paralysis of the respiratory center. The "immediately dangerous to life or health" (IDLH) level (as defined by the Standards Completion Program of the National Institute for Occupational Safety and Health 6 for the purpose of respirator selection) represents a maximum concentration.
In the event of respirator failure, one could escape from this concentration within 30 min without experiencing any escape-impairing or irreversible health effects.
Distances to IDLH concentrations and other concentrations of interest (100, 500, and 1,000 ppm) are given in Table 2.
- Vapor dispersion for the flow from craters up to 6.0 ft in diameter.
Calculations were made for dispersion from craters formed by ruptures of the sour-gas pipeline analyzed by the authors.
The pressure of the release and the shearing action caused by the momentum of the release create craters in the overburden of the rupture area. For a pipeline rupture, the expanded gas impinges on the crater walls and loses some of its momentum through drag forces.
The mass rate (F) is known and therefore the velocity from the crater is calculated by the following:
Vc = F/(PgAc)
where:
Vc = The velocity leaving the crater
Ac = The crater area
Pg = The density of the gas at atmospheric pressure
For the sour-gas pipeline analyzed, calculations were made for the largest flow rate and for crater diameters of up to 6 ft. The downwind distances of cloud travel and maximum cloud width were found to be within 20% of the results from the calculations for no crater formation.
- The vertical and horizontal extent of the flammable zone for the largest release.
Because H2S is a toxic gas, one of the strategies for eliminating H2S concern is to ignite the release. To enable evaluation of the size of the area potentially affected in an induced ignition, the flammable extent of a cloud from the maximum flow rate (steadystate flow) is calculated.
For the gas mixture studied, the lower flammable limit is 2.35 mole %. The plume shape of the lower flammable limit concentration extends 189 ft downwind and 314 ft high with a maximum diameter of 18 ft.
- Fire radiation for torch fires for the steady state flow rates. In instances of outside intervention causing ruptures, most of the ruptures are ignited either by the actual contact, the implement causing the rupture, or surrounding ignition sources.
Also, in the event a vapor cloud is intentionally ignited, it is necessary to estimate the distances from a torch fire that various fire-radiation hazard zones could extend.
Usually selected as radiation levels of interest are the following:
- 10,000 BTU/hr-sq ft = Approximate heat load necessary to cause structural failure of steel materials
- 4,300 BTU/hr-sq ft = Minimum radiation level necessary to damage wooden structures, and the maximum permitted at the knuckle joint of low-pressure storage tanks
- 1,600 BTU/hr-sq ft = Potential hazard to personnel not using protective clothing
- 500 BTU/hr-sq ft = Permissible continuous exposure limit for personnel.
The largest distance a particular zone could extend depends on the wind direction and orientation of release. A horizontal release downwind yields the largest distance.
For this worst case, the distances to the four radiation levels are shown in Table 3. The attenuated distances account for the scattering and absorption of the energy by the water vapor in the air. The distance that individuals could approach this type of fire is 40-50 yd.
- Composition and flame temperature of the products of combustion of the flowing gas stream.
For the flowing gas stream, the products of combustion and flame temperature were calculated to determine the amount Of SO2 in the burned gas stream.
The calculations are made under the assumption of no excess air for the combustion process. This yields the largest SO2 concentration and the highest flame temperature. The effect of increasing excess air would be to lower the SO2 concentration and the flame temperature.
The two conditions offset one another in the dispersion calculation in that the higher temperature causes the cloud to have more buoyancy and rise faster, and the lower initial concentration causes the cloud to dilute faster to less than concentrations of concern.
- Dispersion of the products of combustion (SO2, the gas of primary interest).
SO2 is so irritating that it provides its own warning of toxic concentrations. Concentrations of 400-500 ppm are immediately dangerous to life, and 50-100 ppm is considered to be the maximum permissible concentration for exposures of 30-60 min. 5 Excessive exposures to high concentrations of this material can be fatal. Its toxicity is comparable to that of hydrogen chloride. However, less-than-fatal concentrations can be tolerated for moderate periods of time with no apparently permanent damage.
In order to determine the dispersion distances to SO2 concentrations of concern" the calculations are made based on the flame size and shape of a horizontal release.
Due to the buoyancy of the gas plume created by the high flame temperature, the cloud rises rapidly and dilutes to less than 100 PPM SO2 concentration levels before the vertical momentum is dissipated.
For the sour-gas pipeline analyzed by the authors, the burned-gas stream which contains the SO2 moves 2,936 ft downwind, has a height of 715 ft, and a maximum width of 104 ft.
REFERENCES
- Railroad Commission of Texas, "Rules and Regulations for the Transportation of Natural and Other Gas by Pipeline," Transportation/Gas Utilities Division, Pipeline Safety Section, TRC, February 1990.
- Railroad Commission of Texas, "Statewide Rule 36 Hydrogen Sulfide Safety," Oil and Gas Division, TRC, 1990.
- Ooms, G., "A New Method for Calculation of the Plume Path of Gases Emitted by a Stack," Atmospheric Environment, Vol. 6, 1972.
- Texas Air Control Board, "Users' Guide to the Texas Episodic Model," Permits Section, October 1979.
- Sax, N.I., Dangerous Properties of Industrial Materials, Van Nostrand Reinhold Co., New York, 1984.
- National Institute of Occupational and Safety Hazards, Pocket Guide to Chemical Hazards, U.S. Government Printing Office, Washington, 1985.
Copyright 1991 Oil & Gas Journal. All Rights Reserved.
