West Texas Gas
Gas Distribution Pipeline Integrity Management
Program
June 22, 2012
Revision 1
WEST TEXAS GAS
GAS DISTRIBUTION PIPELINE INTEGRITY MANAGEMENT PROGRAM
TABLE OF CONTENTS
1 - SECTION 1 - REVISION LOG .................................................................................................................... 4
2 - SECTION 2 - INTRODUCTION .................................................................................................................... 5
2.1. The Federal Integrity Management Rule ....................................................................................... 5
2.2. Pipelines Operated by West Texas Gas ....................................................................................... 5
2.3. Terms as Used In the IMP ............................................................................................................. 5
3 - SECTION 3 - W EST TEXAS GAS’ DISTRIBUTION PIPELINE INTEGRITY MANAGEMENT PROGRAM ................... 6
3.1. Overview of West Texas Gas’ Program ........................................................................................ 6
4 - SECTION 4 - KNOWLEDGE ....................................................................................................................... 7
4.1. Regulation ..................................................................................................................................... 7
4.2. System Knowledge ........................................................................................................................ 7
4.3. Updates ......................................................................................................................................... 7
4.4. DOT Annual Report ....................................................................................................................... 8
4.5. Annual Review ............................................................................................................................... 8
5 - SECTION 5 - THREAT IDENTIFICATION PLAN ............................................................................................. 9
5.1. Regulation ..................................................................................................................................... 9
5.2. Threat Factors ............................................................................................................................... 9
5.3. Threat Factor Information .............................................................................................................. 9
5.4. Threat Identification by System ..................................................................................................... 9
6 - SECTION 6 - RISK ANALYSIS PROCESS AND RISK FACTORS .................................................................... 10
6.1. Regulation ................................................................................................................................... 10
6.2. Process ........................................................................................................................................ 10
6.3. Risk Determination ...................................................................................................................... 12
6.4. Regions ....................................................................................................................................... 12
6.5. Validation of Results .................................................................................................................... 12
6.6. Pipeline Threats with Associated Threat Factors ........................................................................ 13
6.7. Consequence Factors ................................................................................................................. 16
7 - SECTION 7 - ADDITIONAL AND ACCELERATED ACTIONS .......................................................................... 17
7.1. Regulation ................................................................................................................................... 17
7.2. Process for the Identification and Evaluation of New Measures for Line Pipe ............................ 17
7.3. Leak Management Program ........................................................................................................ 20
7.4. West Texas Gas Distribution Pipelines Located in Texas ........................................................... 20
7.5. Mechanical Fitting Failure Regulation ......................................................................................... 21
8 - SECTION 8 - PERFORMANCE PLAN ........................................................................................................ 22
8.1. Regulation ................................................................................................................................... 22
8.2. Introduction .................................................................................................................................. 22
8.3. System Specific ........................................................................................................................... 22
9 - SECTION 9 - PERIODIC EVALUATION AND IMPROVEMENT......................................................................... 23
9.1. Regulation ................................................................................................................................... 23
9.2. Audits ........................................................................................................................................... 23
2
9.3. Improvements .............................................................................................................................. 23
9.4. Metrics Review ............................................................................................................................ 24
9.5. Communication of Results .......................................................................................................... 24
10 - SECTION 10 - RESULTS REPORTING .................................................................................................... 25
10.1. Regulation ................................................................................................................................. 25
10.2. Review Process for Plan Effectiveness ..................................................................................... 25
10.3. Performance Measures Submittal to PHMSA and appropriate State Regulatory Agency ........ 25
11 - SECTION 11 - COMMUNICATIONS PLAN ................................................................................................ 26
11.1. External Communications ......................................................................................................... 26
11.2. Safety Concerns ........................................................................................................................ 26
11.3. Internal Communications ........................................................................................................... 26
11.4. External Communications ......................................................................................................... 26
12 - APPENDIX A - PIPELINE INFORMATION ................................................................................................. 27
13 - APPENDIX B - SUMMARY AND RISK ANALYSES ..................................................................................... 28
14 - APPENDIX C - INFORMATION GATHERING FORM ................................................................................... 29
15 - APPENDIX D - PERFORMANCE METRIC INFORMATION GATHERING FORM............................................... 30
16 - APPENDIX E - EVALUATION OF A/A ACTIONS ....................................................................................... 35
17 - APPENDIX F - STEEL SERVICE LINE REPLACEMENT .............................................................................. 41
18 - APPENDIX G - MAINLINE STEEL REPLACEMENT .................................................................................... 43
3
WEST TEXAS GAS
GAS DISTRIBUTION PIPELINE INTEGRITY MANAGEMENT PROGRAM
1 - Section 1 - Revision Log
REVISION
NUMBER
REVISION
DATE
REVISION SUMMARY
0
July 14, 2011
New Gas Distribution Pipeline Integrity Management Program
1
June 22, 2012
Minor revisions to 4.3 Updates, 6.2.1.1 Records Retention, 9.4 Metrics Review
and Appendix E – Evaluation of A/A Actions
4
2 - Section 2 - Introduction
2.1.
The Federal Integrity Management Rule
The Department of Transportation/Pipeline and Hazardous Materials Safety Administration
(DOT/PHMSA) issued a new Subpart P to §192 titled Gas Distribution Pipeline Integrity Management
(DIMP) on December 4, 2009. The latest amended version of Subpart P was issued on February 1, 2011.
The Rule specifies regulations for identifying threats, evaluating risk, implementing measures to address
risk, measure performance, monitor results, and evaluate effectiveness.
Operators are required to develop and implement a gas distribution integrity management plan no later
than August 2, 2011.
2.2.
Pipelines Operated by West Texas Gas
West Texas Gas (WTG) operates approximately 485 gas distribution systems in Texas and Oklahoma
totaling over 5000 miles. The systems consist of steel and plastic (ABS, PVC, and PE) and range in size
from less than 2” to 22”.
2.3.
Terms as Used In the IMP
Terms as used in West Texas Gas’ Integrity Management Program, e.g. Hazardous Leak, are as defined
or described in §192, the Texas Administrative Code, and the West Texas Gas Operations and
Maintenance Manual.
The Integrity Management Department consists of the Director of Integrity Management and the Pipeline
Integrity Specialist.
5
3 - Section 3 - West Texas Gas’ Distribution Pipeline Integrity Management Program
3.1.
Overview of West Texas Gas’ Program
WTG is preparing its Program based on the requirements described in Subpart P. As such, it contains the
following sections:
Distribution
Integrity
Management
Program Elements
Task
Knowledge
Knowledge
Section 4
Appendix A
Pipeline
Information
Appendix B
Summary and Risk
Analyses
Appendix C
Information
Gathering Form
Task
Additional or
Accelerated Actions
Additional and
Accelerated Actions
Section 7
Threat Identification
Plan
Section 5
Risk Analysis
Process and Risk
Factors
Section 6
Task
Administration
Revision Log
Section 1
Performance Plan
Section 8
Appendix E
Evaluation of A/A
Actions
Appendix F
Steel Service Line
Replacement
Appendix G
Mainline Steel
Replacement
6
Periodic Evaluation
and Improvement
Section 9
Results Reporting
Section 10
Communications
Plan
Section 10
Appendix D
Performance Metric
Information
Gathering Form
4 - Section 4 - Knowledge
4.1.
Regulation
49 CFR §192.1007(a)
(a) Knowledge. An operator must demonstrate an understanding of its gas distribution system
developed from reasonably available information.
1) Identify the characteristics of the pipeline's design and operations and the environmental
factors that are necessary to assess the applicable threats and risks to its gas distribution
pipeline.
2) Consider the information gained from past design, operations, and maintenance.
3) Identify additional information needed and provide a plan for gaining that information over
time through normal activities conducted on the pipeline (for example, design, construction,
operations or maintenance activities).
4) Develop and implement a process by which the IM program will be reviewed periodically and
refined and improved as needed.
5) Provide for the capture and retention of data on any new pipeline installed. The data must
include, at a minimum, the location where the new pipeline is installed and the material of
which it is constructed.
4.2.
System Knowledge
Knowledge of a distribution system can be defined as information, such as the materials and type of
construction, the operating conditions of the pipe or facility, and other relevant factors within the
surroundings in which the system operates. This knowledge of the system will help identify the threats to
the system and establish which systems or segments should be subject to a risk evaluation.
4.2.1. Data Gathering
In order to develop an accurate risk assessment of each system, WTG collects data from the following
types of sources:
1.
2.
3.
4.
Paper records.
Electronic records.
Interviews with field personnel.
Field observations and research.
Data from the above sources are compiled into a master spreadsheet which serves as the reference for
risk assessment and segment performance assessments.
4.2.2. Missing Data
Where paper or electronic records are not available, WTG shall make use of Subject Matter Experts
(SMEs) or reasonable and carefully considered deductions. These deductions will become part of the
system knowledge until better information may be obtained through design, construction, operations or
maintenance activities.
4.3.
Updates
During the course of operating or maintaining a distribution system, additional information will become
available, including pipe and risk factor data. Field personnel should be trained to recognize potentially
useful pipe or risk data during their daily activities. This data shall be reported to the Integrity
Management Department for inclusion in the plan and related risk assessments. The minimum
information that should be recorded each time a segment is serviced or repaired is as follows:
7
1. Location.
2. Pipe type.
3. Pipe size.
Data discovered in the field may become part of a leak report or other maintenance work order. In this
case, notification shall be made to the Integrity Management Department of the additional system
knowledge. Field personnel should carefully complete the necessary forms and documentation for the
work being performed. Updates to system knowledge may be made from the collected data.
Each time a pipeline is exposed, WTG Form 1100 should be filled out to document the condition of the
pipe. A check box is included in this form to verify if the DIMP data currently being used is correct. If the
DIMP data is incorrect, the form will be sent to the Integrity Management Department with the corrected
data in order to update the DIMP risk model and associated databases.
Each time a new pipe line is installed, the Project Report Form WTG-1400 will be filled out to document
pipe material, size, manufacturer, year manufactured, grade, material designation code, pipe category,
wall thickness and test pressure. WTG-1400 along with shape files showing the exact location will be
submitted to the Integrity Management Department for processing and installation into GIS mapping.
4.4.
DOT Annual Report
PHMSA Form 7100.1-1, Gas Distribution System Annual Report, contains the basis of WTG’s system
knowledge. Form 7100.1-1 is also a source of historical system information. Before data from the annual
report is used as system knowledge, it must be verified as current and accurate by the Integrity
Management Department.
PHMSA Form 7100.1-1 may also be used as a source of information for past design, operations and
maintenance decisions. The Integrity Management Department shall review historical filings for trends
relating to segment risk and incorporate this information into the body of system knowledge.
4.5.
Annual Review
At least once per calendar year, at intervals not to exceed 15 months, the Integrity Management
Department shall review this program for consistency with 49 CFR §192 Subpart P and for necessary
updates to system and threat information. The program review shall be documented and retained
according to 49 CFR §192.1011. The annual program review shall include interviews with field personnel
and other SMEs to verify the completeness of data derived from operations and maintenance reports.
Section 10.2 further details the requirements of this report.
8
5 - Section 5 - Threat Identification Plan
5.1.
Regulation
49 CFR §192.1007(b)
(b) Identify threats. The operator must consider the following categories of threats to each gas
distribution pipeline: corrosion, natural forces, excavation damage, other outside force damage,
material or welds, equipment failure, incorrect operations, and other concerns that could threaten
the integrity of its pipeline. An operator must consider reasonably available information to identify
existing and potential threats. Sources of data may include, but are not limited to, incident and
leak history, corrosion control records, continuing surveillance records, patrolling records,
maintenance history, and excavation damage experience.
5.2.
Threat Factors
Threat factors used in the Risk Analysis are listed in Section 6.6.
5.3.
Threat Factor Information
The specific threat factor information used in the Threat Identification process is located in Appendix A.
The Integrity Management Department reviews and updates this information annually per Section 6.2.5.
If sufficient information is unavailable or is considered unreliable by the Integrity Management Department
for a particular threat factor, the Integrity Management Department with assistance from the SME of that
specific discipline will either identify that particular threat factor as “unknown” which scores at the highest
possible value or make a conservative, but realistic, estimate for that information element. The Integrity
Management Department will document the use of all estimated information elements in the Risk Analysis
for that particular segment.
For potential for frost action and corrosive properties of soil data, WTG utilizes information published on
the USDA’s National Resources Conservation Services website.
Earthquake faults and acceleration data is obtained from the USGS.
5.4.
Threat Identification by System
5.4.1. Process
The Integrity Management Department uses the process contained in Section 6 and the risk model
contained in Appendix B to determine the risk score for each system and the associated Threat Severity
Index.
9
6 - Section 6 - Risk Analysis Process and Risk Factors
6.1.
Regulation
49 CFR §192.1007(c)
(c) Evaluate and rank risk. An operator must evaluate the risks associated with its distribution
pipeline. In this evaluation, the operator must determine the relative importance of each threat
and estimate and rank the risks posed to its pipeline. This evaluation must consider each
applicable current and potential threat, the likelihood of failure associated with each threat, and
the potential consequences of such a failure. An operator may subdivide its pipeline into regions
with similar characteristics (e.g., contiguous areas within a distribution pipeline consisting of
mains, services and other appurtenances; areas with common materials or environmental
factors), and for which similar actions likely would be effective in reducing risk.
6.2.
Process
This Section describes the use of the relative risk model to evaluate the relative risk posed by each
System, in order to determine the highest priority pipeline segments for use in the Additional and
Accelerated Actions evaluation. Risk is defined as the: Likelihood of Failure times the Consequences of
Failure.
6.2.1. Information Sources
The Integrity Management Department utilized sources such as leak history, corrosion records,
continuing surveillance records, patrolling records, maintenance history, excavation damage experience,
and SME knowledge for initial gathering of threat and consequence related information. The current
information is found in Appendix A and is updated annually per Section 6.2.5.
6.2.1.1. Records Retention
All WTG records that pertain to DIMP will be maintained as required by §192 and the West Texas Gas
O&M Manual. In addition, all DIMP related records must be maintained for at least ten years even if §192
or the West Texas Gas O&M Manual requires less. This will include any superseded revision to this plan.
The Integrity Management Department will be contacted prior to the purging process of all DIMP related
records.
6.2.2. Threats
Probability of Failure is a function of the Threats to a pipeline’s integrity. Threats to a pipeline’s integrity
are listed in eight categories. WTG may add additional threat categories in the ‘Other’ category if
conditions warrant such an addition.
1.
2.
3.
4.
5.
6.
7.
8.
Corrosion.
Natural forces.
Excavation Damage.
Other outside force damage.
Material of weld failure.
Equipment failure.
Incorrect operation.
Other.
10
6.2.3. Threat Severity Index
Each Threat category has numerous factors with which to evaluate the particular pipeline/segment’s
threat level. The factors are evaluated using a scoring system 1 and the ratings are then summed for each
category to arrive at a raw Threat number. This raw number is normalized by dividing the sum of the
threat scores by the maximum possible threat scores. This number is called the Threat Severity Index.
The Threat Severity Index is established based on guidance found in Criteria and Risk Assessment
sections of ASME B31.8S-2010 Appendix A.
6.2.4. Significant Threats
If the Threat Severity Index is > 67%, that particular threat is deemed to be a Significant Threat and A/A
actions will be considered for that segment.
The Threat Severity Index (TSI) is calculated with the following formula.
TSI = [total risk score points from risk model minus number of risk factors]/[4*number of risk factors]
This methodology is explained as follows.
1. Each threat factor can be scored with a range from a minimum value of 1 to a maximum value of
5. Consequently, there is a scoring range of 4 for each threat factor.
2. Each threat factor is scored appropriately and the individual threat factor scores are summed to
determine the total threat score.
3. Similarly for each threat, e.g. corrosion, the maximum number of points that can possibly be
scored is 4 (range from 1 to 5) times the number of threat factors.
4. For example, if there are fourteen threats in a threat category and total points scored for that
threat is 52, the TSI is 68% by the following calculation; [52-14]/[4*14].
6.2.5. Threat Weighting
The threat sum score is then divided by the number of criteria in each Threat category. This normalized
number is then multiplied by a rating factor for that particular Threat. This yields a series of weighted
Threat category numbers that are summed to determine the Likelihood of Failure for a particular System.
Systems with multiple pipe material types, sizes, or other factors are ranked by their individual Segments
and then averaged to get a System total.
The SME Team meets annually to update the risk analysis using sources of information listed in Section
6.2.1 and establish the weighting factors for the risk model. The SME Team includes the Integrity
Management Department, field personnel, and other SMEs as needed. The SME Team uses historical
failure records, operating experience and available design information to define the relative risk hierarchy
and weighting factors.
The following table shows the threat weighting results for 2011.
2011 THREAT WEIGHTING
THREAT
THREAT WEIGHTING FOR STEEL
SYSTEMS
THREAT WEIGHTING FOR NONMETALLIC SYSTEMS
Corrosion
20%
0%
___________________________
1
1 being the least threatening condition and 5 being the most threatening condition.
11
2011 THREAT WEIGHTING
THREAT
THREAT WEIGHTING FOR STEEL
SYSTEMS
THREAT WEIGHTING FOR NONMETALLIC SYSTEMS
Natural Forces
10%
15%
Excavation Damage
25%
30%
Other Outside Forces
20%
25%
Material or Weld
10%
15%
Equipment
6%
6%
Incorrect Operations
6%
6%
Other
3%
3%
6.2.6. Consequence of Failure
Consequence of Failure is a function of the severity of a release. In this case, ten factors found in the
Consequences section of the Risk Analysis are evaluated to determine the consequence of a release
from any West Texas Gas distribution segment.
6.3.
Risk Determination
The Risk for each Covered Segment is determined by multiplying the Likelihood of Failure by the
Consequences of Failure. These numbers for each segment are found in Appendix B.
6.4.
Regions
Regions can be defined as a method of subdividing pipeline Systems into areas with similar
characteristics (e.g., contiguous areas within a distribution pipeline consisting of mains, services, and
other appurtenances; areas with common material or environmental factors), and for which similar A/A
actions likely would be effective in reducing risk. The WTG risk results can be subdivided in a multitude of
ways. First, risk is looked at on a System basis. This can be narrowed down to an individual Segment risk
within each System to further identify what is driving the risk. Each System can also be narrowed down by
material type, size, or other similar characteristic to further define the region if needed.
6.5.
Validation of Results
The information used to fill out each individual threat factor is obtained from electronic records, paper
records, SMEs, or a combination of these as described in Section 4.2.1 and Section 4.2.2. The
information source for each threat factor is identified in the risk model. Upon completion of a new Risk
Analysis, the results shall be validated by a person or persons qualified to validate the results. The
validation process will focus mainly on information from SMEs. Information from paper and electronic
sources are checked for accuracy and completeness before being input into the risk model. The
individuals validating the results must have the following minimum qualifications.
1. Minimum two years engineering, operating or maintenance experience with WTG.
2. Minimum five years experience in pipeline engineering, operating or maintenance.
3. Thorough knowledge of §192 with particular emphasis on Subpart P.
12
4.
5.
6.
7.
6.6.
Detailed knowledge of the WTG DIMP Program.
Thorough knowledge of the principles of risk management.
Detailed knowledge of the WTG risk model and ability to interpret results produced by the model.
Ability to communicate results shown by the risk model to other WTG personnel including
management.
Pipeline Threats with Associated Threat Factors
CORROSION
Coating
Liquids on the system
Number of Mainline CP readings not within spec
Percentage of Grade 1 Corrosion Leaks
Percentage of Grade 2 Corrosion Leaks
Percentage of Grade 3 Corrosion Leaks
Corrosion A/A Actions
NATURAL FORCES
River or Stream Crossing
Frost Heave Susceptibility
Earthquake Fault Zone
Soil Type
Percentage of Grade 1 Natural Force Leaks
Percentage of Grade 2 Natural Force Leaks
Percentage of Grade 3 Natural Force Leaks
Natural Force A/A Actions
EXCAVATION DAMAGE
One Call Activity
Number of 1st Party Damage that did not result in a leak
Number of 2nd Party Damage that did not result in a leak
13
Number of 3rd Party Damage that did not result in a leak
Number of 1st Party Damage that resulted in a leak
Number of 2nd Party Damage that resulted in a leak
Number of 3rd Party Damage that resulted in a leak
Mapping Quality
Percentage of non-metallic system with tracer wire
Percentage of Grade 1 Excavation Damage Leaks
Percentage of Grade 2 Excavation Damage Leaks
Percentage of Grade 3 Excavation Damage Leaks
Excavation Damage A/A Actions
OTHER OUTSIDE FORCES
Number of shallow sections excluding identified patrol points
Percentage of Grade 1 Other Outside Force Leaks
Percentage of Grade 2 Other Outside Force Leaks
Percentage of Grade 3 Other Outside Force Leaks
Other Outside Force A/A Actions
MATERIAL OR WELD FAILURE
Pipe material
Pipe size for main lines
Decade Installed
Manufacturing defects
Mechanical damage failures
Percentage of Grade 1 Material or Weld Leaks
Percentage of Grade 2 Material or Weld Leaks
Percentage of Grade 3 Material or Weld Leaks
14
Material or Weld A/A Actions
EQUIPMENT MALFUNCTION
PCV Failures
PRV Failures
Odorant Failures
Percentage of Grade 1 Equipment Malfunction Leaks
Percentage of Grade 2 Equipment Malfunction Leaks
Percentage of Grade 3 Equipment Malfunction Leaks
Equipment Malfunction A/A Actions
INCORRECT OPERATION
Incorrect operations or inadequate procedure failures
Percentage of Grade 1 Incorrect Operation Leaks
Percentage of Grade 2 Incorrect Operation Leaks
Percentage of Grade 3 Incorrect Operation Leaks
Incorrect Operation A/A Actions
OTHER
Other Failures
Line loss percentage for previous 12 months
Percentage of Grade 1 Other Leaks
Percentage of Grade 2 Other Leaks
Percentage of Grade 3 Other Leaks
Other A/A Actions
15
6.7.
Consequence Factors
CONSEQUENCES
Business District
Residential Area
Number of Irrigation Services
Number of City Commercial and Public Authority Services
Number of Rural Commercial and Public Authority Services
Number of Rural Domestic Services
Number of City (Municipal) Services
Significant Services Affected (facilities that would be difficult to evacuate, e.g. hospital, day care, etc.)
Home or Business Dwellings Intended for Human Occupancy
Operating Pressure
16
7 - Section 7 - Additional and Accelerated Actions
7.1.
Regulation
49 CFR §192.1007(d)
(d) Identify and implement measures to address risks. Determine and implement measures designed
to reduce the risks from failure of its gas distribution pipeline. These measures must include an
effective leak management program (unless all leaks are repaired when found).
7.2.
Process for the Identification and Evaluation of New Measures for Line Pipe
The Integrity Management Department will evaluate each System within twelve months of completing a
risk evaluation for the possible implementation of Additional and Accelerated (A/A) actions.
The Integrity Management Department will use the form in Appendix E to facilitate the evaluation of new
A/A actions.
The Integrity Management Department will review the individual Threat and Consequence scores for
each System. Within each System, the Integrity Management Department will identify each threat factor
having the maximum score of five and each System having an individual Threat Severity Index2 score ≥
67%.
The Integrity Management Department will then review those Systems for possible application of A/A
actions in order to reduce the individual threat factor scores and the Threat Severity Index score.
The Integrity Management Department will develop a specific A/A action plan for the system/segment that
requires A/A actions. This plan will include A/A actions, implementation dates, responsibilities, expected
outcome, measurement and management approval. Management approval will consist of VP, Operations
Manager, District Manager and Integrity Management Department.
The following table provides examples of A/A action to be considered. WTG may implement one or more
of these examples in order to address the threats to each System. The examples given are not intended
to rule out any other reasonable action that WTG may select to reduce the risk of a System.
THREATS
EXAMPLES OF POSSIBLE A/A ACTIONS
PRIMARY
SUBCATEGORY






External corrosion
Bare steel pipe (CP)
Bare steel pipe (No CP)
Wrapped steel pipe (CP)
Wrapped steel pipe (No CP)
CI pipe (Graphitization)
CORROSION








Internal corrosion

___________________________
2
See Sections 6.2.3. and 6.2.4.
17
Increase frequency of leak surveys.
Replace, insert or rehab.
Provide hot spot protection (e.g., install
anodes at anodic locations).
Correct cathodic protection
deficiencies.
Increase frequency of leak surveys.
Install drips.
Install pipe liner.
Install moisture removal or control
equipment.
Evaluate gas supply inputs and take
corrective action with supplier.
THREATS
EXAMPLES OF POSSIBLE A/A ACTIONS
PRIMARY
SUBCATEGORY
Atmospheric corrosion
NATURAL
FORCES
Outside force/weather:
(e.g., earth movement,
lightning, heavy
rains/floods, temperature
extremes, high winds)
 Steel pipe
 Plastic pipe
 Cast iron pipe




Coat (paint) the exposed piping.
Increase survey frequency.
Replace or rehab.
Relocate.



Relocate pipe from high risk locations.
Replace pipe in high risk locations.
Install slip or expansion joints for earth
movement.
Install strain gages on pipe.
Install automatic shut-offs.
Expand the use of excess flow valves.
Conduct leak survey after significant
earthquake or other event.






Conduct
enhanced
awareness
education.
Request regulatory intervention.
Inspect targeted excavation and
backfill activities.
Inspect for facility support.
Improve accuracy of line locating.
Participate
in
pre-construction
meetings with project engineers and
contractors in high-risk areas.
Use warning tape.
Expand the use of excess flow valves.
Improve system map accuracy and
availability.
Recruit support of public safety officials
(e.g., fire department).
Install additional line markers.




Provide first responder training.
Install curb valves.
Improve response capability.
Expand the use of excess flow valves.


Expand policy on when and how to
install protection.
Increase
frequency
of
patrols/inspections
of
high-risk
facilities.
Evaluate the need to relocate hard-toprotect facilities.
Expand the use of excess flow valves.


Inspect exposed pipe prior to backfill.
Increase frequency of leak surveys.


EXCAVATION
DAMAGE





Third-party damage
Operator damage




Fire/explosion (primary
OTHER OUTSIDE
FORCE DAMAGE

Vehicular

Leakage (previous damage)
18
THREATS
EXAMPLES OF POSSIBLE A/A ACTIONS
PRIMARY
SUBCATEGORY
Vandalism



Install or improve fences/enclosures.
Increased surveillance.
Relocate hard-to-protect or critical
facilities.


Perform leak survey after blasting.
Relocate away from frequent blast
areas (e.g., mines).
Replace with more ductile pipe
material.
Blasting



MATERIAL OR
WELD FAILURE

Manufacturing defects
Construction/workmanship
defects
Mechanical damage:
o Steel pipe
o Plastic pipe
o Pipe components







EQUIPMENT
MALFUNCTION
Malfunction of system equipment



INCORRECT
OPERATION



Inadequate procedures
Inadequate safety practices
Failure to follow procedures








OTHER
Replace or repair.
Increase frequency of inspection and
monitoring.
Investigate if a type of joint or
equipment
is
being
used
in
inappropriate situations or locations.
Improve installation procedure.
Trend equipment failure.
Replace or repair.
Increase frequency of inspection and
monitoring.
Investigate if a type of joint or
equipment
is
being
used
in
inappropriate situations or locations.
Improve installation procedure.
Trend equipment failure.
Improve procedures.
Improve training.
Evaluate locations where inadequate
practices may have been used.
Perform internal audits or inspections.
Increase frequency of leakage survey.
Increase odorant level.
Increase frequency of odorant testing.
Improve choices of odorant testing
locations.
The Integrity Management Department will identify the benefit of implementing additional actions and
make a decision for implementing A/A actions. The Integrity Management Department will utilize
reasonable technical and financial judgment in evaluating recommended actions for implementation.
If approved, the Integrity Management Department will be responsible for implementing the approved
actions within the time frame specified for the approved actions.
19
7.3.
Leak Management Program
WTG has implemented an electronic Leak Tracking System (LTS) which stores all leak data. The LTS is
used as a scheduler for upcoming leak surveys, repairs to non-hazard leaks, and re-probes for any open
leaks. The LTS also houses the data used to trend all leaks within WTG.
7.4.
West Texas Gas Distribution Pipelines Located in Texas
7.4.1. Service Line Removal or Replacement (TAC §8.209)
WTG owns and operates 424 distribution systems within the state of Texas. These 424 systems have a
total of 269 TRRC system identification numbers. The following is WTG’s risk-based program to meet
TAC rule §8.209 for Distribution Facilities Replacement.
TAC rule §8.209 requires each operator to determine what the greatest risk to public safety is for each
system. The process that WTG uses to determine this risk is determined by calculating the number of
leaks for steel service lines and comparing this to the number of leaks on main lines for an equal period of
time. This information will determine if the system’s greatest risk is either steel service lines or main lines.
The data used for this comparison is made using the number of leaks reported by WTG on the PS95
filings. The initial determination was made using data from 2009 and 2010. Going forward three years of
data will be used. The following procedure will be followed after the above mentioned determination is
made. The initial scheduling for replacement of any facilities will begin on January 1, 2012.
7.4.1.1. Systems that fall into the Steel Service Lines category:
Each system will have an annualized steel service line leak rate calculated using the following formula:
1. Number of below grade leaks repaired on steel service lines (excluding third party damage leaks
and leaks on steel service lines that have been removed or replaced by this regulation) divided by
the number of steel service lines reported to PHMSA on form F 7100.1-1. Beginning in 2012 three
years (3) of data will be used for this calculation, however for initial implementation only two (2)
years of data is being considered.
Based on the results of the leak rate calculation, the following schedule will be used for replacement:
1. Any system with an annualized steel service line leak rate of 7.5% or greater will be considered
Priority 1 and removed or replaced by June 30, 2013.
2. Any system with an annualized steel service line leak rate greater than 5% but less than 7.5% will
be considered Priority 2 and no less than 10% of the original inventory in service at the beginning
of the year must be removed from service or replaced.
3. Any system with an annualized steel service line leak rate of less than 5% will be considered
Priority 3 and removal or replacement is not required; however upon discovery of any new service
line leak, the service line must be removed or replaced rather than repaired.
The results of the initial data have determined that 12 WTG systems have steel service lines as the
greatest risk to public safety. These systems can be found in Appendix F.
7.4.1.2. Systems that fall into the Main Lines Steel category:
Each system will be prioritized using WTG’s DIMP risk model. This risk model takes into consideration
pipe location, proximity to buildings and other structures, the type and use of the buildings, concentration
of the public, composition and nature of the system, age of the pipe, pipe material, type of pipeline facility,
operating pressure, leak history records, prior leak grade repairs, corrosion history, environmental
conditions, and additional factors.
Any system with a total risk score in the DIMP risk model of greater than 4.99 will have at least 5% of the
total system length replaced and/or removed on an annual basis, with the following exception:
1. Poly Pipe segments.
20
2. Coated steel segments with document history of effective corrosion protection (exposed pipe
reports & pipe to soil readings).
3. Pipeline segments greater than 500 foot from a building intended for human occupancy or a welldefined outside public gathering area.
For each system/segment that meets this DIMP risk score greater than 4.99, the Integrity Management
Department will develop a system specific written plan for replacement and/or removal. Specific written
plans will not be developed for systems that require less than 100 foot of replacement and/or removal.
Required replacement and/or removal footage will be completed under normal routine maintenance
activities. The system specific written plans will be included on the annual report submitted to the TRRC
on or prior to March 15th of each year.
If greater than 5% of a system’s mainline footage is replaced and/or removed in a calendar year, this
excess footage will be credited to the following year’s replacement schedule.
Any system with a total risk score in the DIMP risk model of less than 5.0 will not be included in the
mandatory replacement program.
The results of the initial data have determined that 412 WTG systems have main lines as the greatest risk
to public safety. Of the 412 systems, 30 systems have a DIMP risk score greater than 4.99. These
systems can be found in Appendix G.
7.4.1.3. Reporting Requirements:
On or prior to March 15th of each year, WTG will develop and submit to the TRRC an annual report which
will include the following:
1. A list of steel service lines or other distribution facilities (by system ID number) replaced during
the prior calendar year.
2. Revisions to WTG’s risk-based replacement program.
3. Proposed specific work plan (by system ID) for the current year.
7.5.
Mechanical Fitting Failure Regulation
49 CFR § 192.1009 What must an operator report when a mechanical fitting fails?
(a) Except as provided in paragraph (b) of this section, each operator of a distribution pipeline system
must submit a report on each mechanical fitting failure, excluding any failure that results only in a
nonhazardous leak, on a Department of Transportation Form PHMSA F–7100.1–2. The report(s)
must be submitted in accordance with §191.12.
(b) The mechanical fitting failure reporting requirements in paragraph (a) of this section do not apply
to the following:
(1) Master meter operators;
(2) Small LPG operator as defined in §192.1001; or
(3) LNG facilities.
7.5.1. Mechanical Fitting Failure Process
WTG is tracking all mechanical fitting failures on a distribution system. The Leak Tracking System (LTS)
will flag any mechanical fitting failure and notify the Integrity Management Department. The Integrity
Management Department will contact the district and gather required data to submit Department of
Transportation Form PHMSA F-7100.1-2.
21
8 - Section 8 - Performance Plan
8.1.
Regulation
49 CFR §192.1007(e)
(e) Measure performance, monitor results, and evaluate effectiveness.
(1) Develop and monitor performance measures from an established baseline to evaluate the
effectiveness of its IM program. An operator must consider the results of its performance
monitoring in periodically re-evaluating the threats and risks. These performance measures must
include the following:
(i) Number of hazardous leaks either eliminated or repaired as required by §192.703(c) of this
subchapter (or total number of leaks if all leaks are repaired when found), categorized by cause;
(ii) Number of excavation damages;
(iii) Number of excavation tickets (receipt of information by the underground facility operator from
the notification center);
(iv) Total number of leaks either eliminated or repaired, categorized by cause;
(v) Number of hazardous leaks either eliminated or repaired as required by §192.703(c) (or total
number of leaks if all leaks are repaired when found), categorized by material; and
(vi) Any additional measures the operator determines are needed to evaluate the effectiveness of
the operator's IM program in controlling each identified threat.
8.2.
Introduction
The Integrity Management Department utilizes this Performance Plan to determine if the West Texas Gas
Distribution program is effective in assessing and evaluating the integrity of distribution systems. The
Performance Plan includes internal evaluation of the Program’s performance, internal and external audits,
and reporting of performance results.
8.3.
System Specific
The Integrity Management Department will annually, by January 31 for the previous year’s data, collect
the following performance metrics data for each System as listed below. The form used to document this
information can be found in Appendix D or may utilize an alternative form to document this information.
PERFORMANCE MEASURE
EXPECTED PERFORMANCE
Number of hazardous leaks either eliminated or repaired
as required by §192.703(c), categorized by cause
Number of excavation damages
Number of excavation tickets
Total number of leaks either eliminated or repaired,
categorized by cause
Number of hazardous leaks either eliminated or repaired
as required by §192.703(c), categorized by material
WTG specific measures
22
9 - Section 9 - Periodic Evaluation and Improvement
9.1.
Regulation
49 CFR §192.1007(f)
(f) Periodic Evaluation and Improvement. An operator must re-evaluate threats and risks on its
entire pipeline and consider the relevance of threats in one location to other areas. Each operator
must determine the appropriate period for conducting complete program evaluations based on
the complexity of its system and changes in factors affecting the risk of failure. An operator must
conduct a complete program re-evaluation at least every five years. The operator must consider
the results of the performance monitoring in these evaluations.
9.2.
Audits
The Integrity Management Department should determine if an audit is warranted after the annual review
of the Annual Integrity Management Report found in Section 10.2. Events that would indicate the need
for an audit include the following.
1. Failure to meet expected performance for System Specific performance measures as identified in
Section 8.3.
2. Notice from PHMSA or a state regulatory agency of a pending formal inspection.
The audit may include consideration of the entire Program or only specified sections as determined by the
Integrity Management Department.
The Integrity Management Department may choose to schedule an audit at other times if circumstances
warrant.
After determining that an audit is necessary, the Integrity Management Department should determine if an
internal or an external audit shall be performed.
9.2.1. Internal Audits
The Internal Audit team shall be composed of personnel both with and without direct responsibility for any
distribution integrity management work. This team is constituted by the Integrity Management Department
and reports directly to that position. The audit team will forward its audit results to the Integrity
Management Department within thirty days of completing the audit.
The Integrity Management Department will determine which issues are to be addressed in the audit.
9.2.2. External Audits
When appropriate, the Integrity Management Department will commission an external audit team to
review the overall functioning of the West Texas Gas Distribution Integrity Management Program. The
audit team will forward its audit results to the Integrity Management Department within thirty days of
completing its audit work.
The Integrity Management Department will determine which issues are to be addressed in the audit.
9.2.3. Audit Results
The Vice President of Operations will review audit results for information and for consideration of
implementation.
9.3.
Improvements
The Integrity Management Department will be primarily responsible for recommending improvement to
the Program after an annual review of the Performance Plan results.
23
Improvements may also be proposed by any West Texas employee. These improvements may be the
result of exceptional performance achieved at a particular time for one or more metrics or unsatisfactory
performance on a similar scale. The improvements will be documented in the Annual Integrity
Management Report that is described in Section 10.2.
9.4.
Metrics Review
The Integrity Management Department will annually review and update, if necessary, the currently
effective system specific metrics based on regulatory changes to current metrics or for other reasons
deemed appropriate.
Within 90 days of a significant revision to this plan, the Integrity Management Department will forward a
revised copy to PHMSA and appropriate state agencies.
9.5.
Communication of Results
The Director of Integrity Management will distribute performance results and audit results in accordance
with Section 11.3.
24
10 - Section 10 - Results Reporting
10.1.
Regulation
49 CFR §192.1007(e)
(g) Report results. Report, on an annual basis, the four measures listed in paragraphs (e)(1)(i)
through (e)(1)(iv) of this section, as part of the annual report required by §191.11. An operator
also must report the four measures to the state pipeline safety authority if a state exercises
jurisdiction over the operator's pipeline.
10.2.
Review Process for Plan Effectiveness
The Integrity Management Department will prepare an Annual Integrity Management Report by April 30th
each year beginning with year 2012 that includes the following:
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
Overall assessment of the Program’s effectiveness.
List of A/A actions completed and results obtained.
Process improvements identified and implemented.
Performance against the previous year’s Program Performance Parameters and any identified
trends.
Any other Distribution Integrity Management Activities carried out in the previous year.
Determination if an audit is required in the forthcoming twelve months.
Identification of any Distribution Integrity Management work scheduled in the previous year but
not completed.
A Recovery Plan for work scheduled but not completed.
A review of the overall contents within the DIMP to ensure compliance with §192 Subpart P.
An Integrity Management Department and SME review of the current pipeline data used in the
risk assessment to ensure that the most up-to-date information is being used.
The Annual Integrity Management Report will be reviewed and approved by the Vice President of
Operations.
10.3.
Performance Measures Submittal to PHMSA and appropriate State Regulatory Agency
The Integrity Management Department will submit a West Texas Gas Performance Report including the
four measures listed in §192.1007(e)(1)(i) through §192.1007(e)(1)(iv) to PHMSA and the appropriate
state regulatory agency as part of the Annual Report required by §191.11. The Annual Report is required
to be submitted by March 15 for the proceeding calendar year. The annual report requirement does not
apply to a master meter system or to a petroleum gas system that serves fewer than 100 customers from
a single source
25
11 - Section 11 - Communications Plan
11.1.
External Communications
11.1.1. Public Awareness Program
WTG will cover external communications for the general public, local officials and emergency responders
through the West Texas Public Awareness Program.
11.2.
Safety Concerns
11.2.1. DOT/PHMSA
The Integrity Management Department will continually monitor the DOT/PHMSA website for rule changes,
advisory bulletins, new information and recommended practices. An electronic log sheet will be kept to
detail and describe all visits to the PHMSA website. Any changes or notices that would affect the DIMP
will be documented on the log sheet.
11.3.
Internal Communications
Internal communications are made per the following table.
DOCUMENT
ORIGINATOR
DOCUMENT
RECIPIENT
ACTION REQUIRED
Annual DIMP Update
Integrity Management
Department
Vice President of Gas
Pipeline Operations,
Pipeline Operations and
Maintenance
Review and approval by
Vice President of Gas
Pipeline Operations
Annual Distribution Integrity
Management Report
Integrity Management
Department
Integrity Management
Department
Review, approval and
distribution within WTG
Annual Risk Analysis Update
Integrity Management
Department
Vice President of Gas
Pipeline Operations
Include in DIMP update
including consideration of
A/A actions
External and Internal Audit
Findings
Integrity Management
Department via Audit Team
Vice President of Gas
Pipeline Operations
Update DIMP as
appropriate
Abnormal Operating Condition
Report
Field Operations
Integrity Management
Department
Update DIMP as
appropriate
Completed Projects Form
Field Operations
Integrity Management
Department
Update DIMP as
appropriate
Leak Tracking Form
Field Operations
Integrity Management
Department
Update DIMP as
appropriate
Leak Survey Form
Field Operations
Integrity Management
Department
Update DIMP as
appropriate
11.4.
External Communications
The Integrity Management Department will communicate any significant changes within the WTG DIMP to
PHMSA and the appropriate state authority in a timely manner as soon as these updates are made.
26
12 - Appendix A - Pipeline Information
The Pipeline Information spreadsheet is too large to fit into a Word® table. The most current version of the
Pipeline Information spreadsheet can be found on the WTG internal employee website under the Integrity
Management Department section.
27
13 - Appendix B - Summary and Risk Analyses
The Risk Analysis spreadsheet is too large to fit into a Word® table. The most current version of the Risk
Analysis spreadsheet can be found on the WTG internal employee website under the Integrity
Management Department section.
28
14 - Appendix C - Information Gathering Form
The Pipeline Information Gathering spreadsheet is too large to fit into a Word® table. The most current
version of the Pipeline Information Gathering spreadsheet can be found on the WTG internal employee
website under the Integrity Management Department section.
29
15 - Appendix D - Performance Metric Information Gathering Form
30
West Texas Gas
Information from January 1, _____ to December 31, _____
Date: ___________________________________________________________
Distribution Gas Pipeline Performance Information
Gas Pipeline/Segment Name: _______________________________________
PERFORMANCE METRIC
SPECIFIC METRIC
Corrosion
Number of hazardous
leaks either eliminated or
repaired as required by
§192.703(c), categorized
by cause
Corrosion
Total number of leaks
either eliminated or
repaired, categorized by
cause
Corrosion
Number of hazardous
leaks either eliminated or
repaired as required by
§192.703(c), categorized
by material
Corrosion
WTG specific measures
Natural Forces
Number of hazardous
leaks either eliminated or
repaired as required by
§192.703(c), categorized
by cause
Natural Forces
Total number of leaks
either eliminated or
repaired, categorized by
cause
Natural Forces
Number of hazardous
leaks either eliminated or
repaired as required by
§192.703(c), categorized
by material
Natural Forces
WTG specific measures
Excavation Damage
Number of hazardous
leaks either eliminated or
repaired as required by
§192.703(c), categorized
by cause
METRIC RESULT
ACHIEVED
31
COMMENTS
PERFORMANCE METRIC
SPECIFIC METRIC
Excavation Damage
Number of excavation
damages
Excavation Damage
Number of excavation
tickets
Excavation Damage
Total number of leaks
either eliminated or
repaired, categorized by
cause
Excavation Damage
Number of hazardous
leaks either eliminated or
repaired as required by
§192.703(c), categorized
by material
Excavation Damage
WTG specific measures
Other Outside Force
Damage
Number of hazardous
leaks either eliminated or
repaired as required by
§192.703(c), categorized
by cause
Other Outside Force
Damage
Total number of leaks
either eliminated or
repaired, categorized by
cause
Other Outside Force
Damage
Number of hazardous
leaks either eliminated or
repaired as required by
§192.703(c), categorized
by material
Other Outside Force
Damage
WTG specific measures
Material, Weld or Joint
Failure
Number of hazardous
leaks either eliminated or
repaired as required by
§192.703(c), categorized
by cause
Material, Weld or Joint
Failure
Total number of leaks
either eliminated or
repaired, categorized by
cause
METRIC RESULT
ACHIEVED
32
COMMENTS
PERFORMANCE METRIC
SPECIFIC METRIC
Material, Weld or Joint
Failure
Number of hazardous
leaks either eliminated or
repaired as required by
§192.703(c), categorized
by material
Material, Weld or Joint
Failure
WTG specific measures
Equipment Failure
Number of hazardous
leaks either eliminated or
repaired as required by
§192.703(c), categorized
by cause
Equipment Failure
Total number of leaks
either eliminated or
repaired, categorized by
cause
Equipment Failure
Number of hazardous
leaks either eliminated or
repaired as required by
§192.703(c), categorized
by material
Equipment Failure
WTG specific measures
Incorrect Operation
Number of hazardous
leaks either eliminated or
repaired as required by
§192.703(c), categorized
by cause
Incorrect Operation
Total number of leaks
either eliminated or
repaired, categorized by
cause
Incorrect Operation
Number of hazardous
leaks either eliminated or
repaired as required by
§192.703(c), categorized
by material
Incorrect Operation
WTG specific measures
Other
Number of hazardous
leaks either eliminated or
repaired as required by
§192.703(c), categorized
by cause
METRIC RESULT
ACHIEVED
33
COMMENTS
PERFORMANCE METRIC
SPECIFIC METRIC
Other
Total number of leaks
either eliminated or
repaired, categorized by
cause
Other
Number of hazardous
leaks either eliminated or
repaired as required by
§192.703(c), categorized
by material
Other
WTG specific measures
METRIC RESULT
ACHIEVED
COMMENTS
Comments:
Prepared by: _________________________ Date: _____________________________
34
16 - Appendix E - Evaluation of A/A Actions
35
West Texas Gas
A/A Actions
Date:
____________________
INSTRUCTIONS:
1. The Integrity Management Department completes Part 1 Segment Identification on the form.
2. The Integrity Management Department reviews the individual Threat scores and the individual
Consequence of Failure scores for each segment from the latest risk analysis and completes Part
2: Threat and Consequence Hazard Identification.
3. The Integrity Management Department completes the Part 3: Possible A/A Actions section of the
form.
4. The Integrity Management Department completes the Part 4: Evaluation of Possible A/A Actions
section of the form by performing an evaluation of each possible measure which includes, at a
minimum, pros/cons, cost/benefit, technical analysis, and all assumptions.
5. The Integrity Management Department determines if the identified action is to be implement and
checks the appropriate box in Part 4.
6. The Integrity Management Department retains this form for the service life of the pipeline.
Part 1: System Identification:
System Name: __________________________________________________________
Pipeline System Identification: ______________________________________________
Calendar Year: __________________________________________________________
State: __________________________________________________________________
System’s DIMP Risk Score: _________________________________________________
TAC 8.209 Category: ______________________________________________________
Service Line Priority: ______________________________________________________
36
Part 2: Threat and Consequence Hazard Identification:
Pipeline Segment Threat Scores:
Threat Factors with Risk Analysis Score of 5 or Threat categories with TSI > 67%:
T 1. _____________________________________________________________________
T 2. _____________________________________________________________________
T 3. _____________________________________________________________________
T 4. _____________________________________________________________________
T 5. _____________________________________________________________________
Threat Factors with Possible A/A Actions:
T 1. _____________________________________________________________________
T 2. _____________________________________________________________________
T 3. _____________________________________________________________________
T 4. _____________________________________________________________________
T 5. _____________________________________________________________________
Pipeline Segment Consequence Scores:
Consequence Factors with Risk analysis Score of 5:
C 1. ____________________________________________________________________
C 2. ____________________________________________________________________
C 3. ____________________________________________________________________
C 4. ____________________________________________________________________
C 5. ____________________________________________________________________
37
Part 3: Possible A/A Actions: (reference §192.1007(d)):
List all of the possible A/A Actions that could lower the individual threat or consequence factor risk.
T 1. _____________________________________________________________________
T 2. _____________________________________________________________________
T 3. _____________________________________________________________________
T 4. _____________________________________________________________________
T 5. _____________________________________________________________________
38
Part 4: Evaluation of A/A Actions:
Add additional sections if necessary.
1. A/A Action from Part 3:
Threat to be addressed: ____________________________________________________
Specific Action to be implemented: ___________________________________________
Analysis of Action (pros/cons, cost/benefit, technical analysis, all assumptions, and give details of outside
technical review if appropriate):
1. _________________________________________________________________
2. _________________________________________________________________
3. _________________________________________________________________
Implement Identified Measure: Yes
No
Location Affected: _______________________________________________________
Time Frame for Completion: _______________________________________________
Specific Responsibilities for Implementation: ____________________________________
________________________________________________________________________
2. A/A Action from Part 3:
Threat to be addressed: ____________________________________________________
Specific Action to be implemented: ____________________________________________
Analysis of Action (pros/cons, cost/benefit, technical analysis, all assumptions, and give details of outside
technical review if appropriate):
1. _________________________________________________________________
2. _________________________________________________________________
3. _________________________________________________________________
Implement Identified Action: Yes
No
Location Affected: _______________________________________________________
Time Frame for Completion: _______________________________________________
Specific Responsibilities for Implementation: ____________________________________
___________________________________________________________________________
39
3. A/A Action from Part 3:
Threat to be addressed: ____________________________________________________
Specific Action to be implemented: ____________________________________________
Analysis of Action (pros/cons, cost/benefit, technical analysis, all assumptions, and give details of outside
technical review if appropriate):
1. _________________________________________________________________
2. _________________________________________________________________
3. _________________________________________________________________
Implement Identified Action: Yes
No
Location Affected: _______________________________________________________
Time Frame for Completion: _______________________________________________
Specific Responsibilities for Implementation: ____________________________________
________________________________________________________________________
Prepared by: ____________________________________________________________
Date: __________________________________________________________________
Approved by: District Manager: _____________________________________________
Date: ______________________________________________________
Operations Manager: __________________________________________
Date: ______________________________________________________
Vice President: ______________________________________________
Date: ______________________________________________________
40
17 - Appendix F - Steel Service Line Replacement
41
WTG DIMP Risk Scores TAC §8.209 Service Line
SYSTEM NAME
SYSTEM TRC ID #
RISK
SCORE
Miami
JUNCTION
Devine
Christoval
Higgins
110356
211162
710231
211087
110240
6.578
6.528
6.220
5.654
5.271
# OF STEEL
SERVICE LINE
LEAKS IN 2009 AND
2010
# OF SYSTEM
STEEL SERVICE
LINES
ANNUALIZED STEEL
SERVICE LINE LEAK
RATE
PRIORITY
2
2
2
2
3
216
511
2
95
240
0.005
0.002
0.500
0.011
0.006
3
3
1
3
3
BALMORHEA
210022
4.654
1
0
0.000
Leak was on a
steel riser,
service line is
poly
Waka
Morton System
95
110597
4.290
4
31
0.065
2
110675
3.876
1
4
0.125
1
Groom Mainline
110455
3.657
1
24
0.021
3
Lelia Lake Rural
110819
2.989
1
0
0.000
Leak was on a
steel riser,
service line is
poly
Poor Boy
110002
Regan Lateral
960478
2.685
2.496
1
1
8
5
0.063
0.100
2
1
42
18 - Appendix G - Mainline Steel Replacement
43
WTG DIMP Risk Scores TAC §8.209 (Scores > 4.99)
DISTRICT
SYSTEM NAME
TRC ID #
RISK
SCORE
Amarillo
Pearsall
Kermit
Canadian
Junction
Shamrock
Farwell
Amarillo
Pearsall
Canadian
Stratford
Shamrock
Stratford
Junction
Canadian
Junction
Dalhart
Shamrock
Junction
Pearsall
Shamrock
Claude Residential
Somerset
Kermit
Canadian
SONORA
Wheeler
Farwell
Groom
Natalia
Follett
Dumas
Shamrock
Stratford
MENARD
Darrouzett
Eden
Texline
Briscoe
Paint Rock
Jungman
New Mobeetie
110108
411170
210347
110085
211140
110616
110182
110213
411372
110185
110161
110516
110545
211161
110144
211094
110575
110063
211122
411373
110362
8.915
8.912
8.770
8.695
7.563
7.470
7.420
7.280
7.196
7.086
7.000
6.908
6.867
6.626
6.616
6.404
6.313
6.194
6.163
6.042
6.034
THREAT
SCORE
CONSEQUENCE
SCORE
TOTAL SYSTEM
LENGTH (FEET)
SYSTEM
LENGTH
LESS POLY
& COATED
STEEL
SYSTEM
LENGTH LESS
POLY & COATED
STEEL X 5%
1.748
1.564
1.512
1.705
1.483
1.437
1.400
1.427
1.384
1.363
1.429
1.354
1.461
1.380
1.408
1.455
1.315
1.347
1.340
1.343
1.284
5.100
5.700
5.800
5.100
5.100
5.200
5.300
5.100
5.200
5.200
4.900
5.100
4.700
4.800
4.700
4.400
4.800
4.600
4.600
4.500
4.700
126959
370775
351054
119679
176641
117650
73863
55578
151789
53204
39600
189211
66665
110168
39793
83450
19825
14251
22000
59922
21439
79341
253757
176913
114869
114468
27250
62084
39072
146299
46179
19800
0
64434
60203
34993
12160
1214
614
1525
34789
479
3967
12688
8846
5743
5723
1363
3104
1954
7315
2309
990
0
3222
3010
1750
608
61
31
76
1739
24
44
WTG DIMP Risk Scores TAC §8.209 (Scores > 4.99)
DISTRICT
SYSTEM NAME
TRC ID #
RISK
SCORE
THREAT
SCORE
CONSEQUENCE
SCORE
TOTAL SYSTEM
LENGTH (FEET)
SYSTEM
LENGTH
LESS POLY
& COATED
STEEL
Shamrock
Pearsall
Shamrock
Shamrock
Pearsall
Ft.
Stockton
Stratford
Dalhart
Amarillo
Wheeler Mainline
LaPryor
Old Mobeetie
Allison
East Central
110617
710495
110363
110016
411375
5.998
5.778
5.670
5.652
5.612
1.304
1.481
1.319
1.285
1.369
4.600
3.900
4.300
4.400
4.100
188139
55956
32400
8704
34320
59604
13599
22307
1564
31152
2980
680
1115
78
1558
IMPERIAL
210327
5.467
1.367
4.000
83424
57024
2851
Etter
NORTEX
Goodnight
110176
110392
110209
5.344
5.203
5.015
1.406
1.334
1.433
3.800
3.900
3.500
20095
658705
88980
8710
0
79426
436
0
3971
45
SYSTEM
LENGTH LESS
POLY & COATED
STEEL X 5%