A Failure in Construction Procedures Incur Additional Cost in Direct Examinations and Maintenance of Gas Piping

Gas Utility CompaniesWith many natural gas utility companies in the seventh year reassessment phase of their Transmission Integrity Management Plan, BGL felt it necessary to express concern for those continual findings which depict past construction procedural shortfalls.  These past shortfalls are increasing the current cost associated with Direct Examinations on pipelines and pipeline maintenance.

Pipeline construction managers, inspectors, and operators are aware of the pre, during, and post inspections that are to take place during new construction of gas pipelines. Article 49, Part 192.319 clearly states that when placing pipe in a ditch the coating and the pipe should be protected from equipment and backfill material. However, many of the direct examinations performed over the past few years have found coating defects and corrosion that has been caused by materials and large rocks left lying in the trench and on the pipe during the back-filling process.

Proper cathodic protection of the pipe can ensure longevity of the pipelines remaining life.  However, rocks and materials left in the ditch can have a drastic effect on the remaining life and replacement costs associated with these foreign materials.  Recently, there has been a greater push for third-party inspectors.  Such third-party inspectors do not work directly for the utility company or the construction contractor.  Adherence to the engineering guidelines and procedural process are their number one priority.

If your company is in need of assistance, BGL offers on-site inspectors that can ensure traceable, verifiable, and complete third-party record keeping to ensure future cost of maintenance is kept to a minimum.

By: William Luttrell

Rehabilitation Considerations for Pipelines Attached to Bridges

For several years, BGL Asset Services has been rehabilitating pipelines attached to bridges. Such an undertaking requires several key considerations to ensure the owner is getting the greatest return out of that investment.

1. What type of coating should be applied? The coating needs to be appropriate for the conditions it is exposed to. Some things to consider are: UV resistance, pedestrian traffic, mechanical damage, vibration, application issues, environmental concerns, etc.
2. What is the current condition of the pipe under the existing coating? It may look presentable, but are there issues that are causing severe damage to the pipe.

Bridge Pipeline Corroded Pipeline Bridge Pipe Pipeline Attached to Bridge

3. What type of hangers should be used? Is the weight of the pipe evenly distributed throughout the crossing? Are the anchors points secure? Is the pipeline electrically isolated from the structure? Are the supports causing any metal to metal contact, vibration issues, damage to the coating, longitudinal or circumferential stress, etc.?

hanger1 hanger2 hanger3 hanger4

4. Is the pipe protected using the appropriate application of Fiberglass Reinforced Plastic (FRP) shields, and are they the appropriate length? Note how the lack of shield protection has shifted due to pipe movement.

FRP1 FRP2 FRP3 FRP4

5. What equipment is needed to safely complete the project? It is not enough to inspect from the edge of the crossing. A hands’ on 360 degree visual inspection is recommended to truly assess the current condition of the pipeline for corrosion, pipeline wall thickness, coating adhesion, supports, transition, etc.

pipeline equipment1 pipeline equipment2 pipeline equipment3 pipeline equipment4 pipeline equipment5

These are but a few of the issues that should be considered when inspecting and remediating piping attached to bridges. In doing so, a company should fulfill all essential attributes to ensure compliance with PHMSA regulations, maintain the integrity of the pipeline and prolong the life of the company’s existing aging assets.

   Let us serve you…BGL Asset Services

By: William Luttrell

Correlation Between Defensive Driving and Working with Natural Gas

Driving in SnowThroughout this past winter, most of us have had to endure extremely cold weather and hazardous driving conditions. How many of you noticed those drivers who were more offensive in their driving techniques rather than defensive? You know, the person who sped by at sixty or seventy miles an hour when everyone else was doing twenty. Most of us probably witnessed those same drivers sitting alongside the roads or ditches waiting for the tow truck to help them out.

If you think about it, working with natural gas is very similar. Just as those drivers become impervious to road conditions, many technicians become too secure when working with natural gas. Unfortunately, it is this sense of experience or routine that often leads to mishaps or unacceptable short cuts.Working with Natural Gas

Many of the tasks that we perform are routine. However, our goal should always be sure to never let that sense of routine mind-set carry over into a situation that could be dangerous. Just because it did not happen before does not mean that it won’t happen the next time. Just as you didn’t skid out of control today doesn’t mean you won’t tomorrow. Two questions we should always ask ourselves, “At what point are we willing to sacrifice our own life or that of others, and, Can you live with the consequences of your actions or decisions?”

So as the snow melts and Spring brings about many new tasks in the gas industry, ask whether or not this particular moment, situation, or incident is worthy of an offensive mind-set or a defensive mind-set. A defensive mind-set that is cautious, respectful of the hazards, and methodic in the approach to bring about a safe resolution to a dangerous situation.

By: William Luttrell

In Search of the Perfect Operator Qualification Program

When it comes to Operator Qualification (OQ), it seems that finding that perfect mix of written testing, on-the-job training, and field evaluations still eludes many professionals in the natural gas industry. How can Part 192, Subpart N, and Part 195, Subpart G, in all its simplicity, become so convoluted across individual utility systems? Why is one OQ test or field evaluation recognized by some utilities and not others? In many cases they are identical tests.

natural gas technicianHow can operators maintain a sense of uniform consistency to ensure all natural gas personnel receive the best training possible? There is a solution, but that solution requires operators to come together and establish an industry standard which will be the basis for all training. To many, such a statement sends up so many red flags that it is hard to imagine that there could be one uniformed training program that fits all natural gas utilities or systems. However, it is possible.

Let’s take a moment and consider our military training programs. How do you think they are able to fulfill global training of their personnel with such uniformed precision yet maintain flexibility? They do not attain professional knowledge just from basic or technical training. Training continues throughout their career; as they transfer from one station to another, that baseline training follows. The difference is that a military person receives supplemental training based on regional or command differences. Thus, each installation, career field, or command center does not have to duplicate their efforts by reinventing a whole new training program for each task. They only have to introduce the supplemental changes in their training program based on how the baseline qualifications are performed for that given region or command.

Currently, if an employee leaves one utility for another, that person must retake many of the same OQ tests and evaluations that they were already qualified to perform. Additionally, many contractors must re-qualify every time they are contracted to fulfill projects for a different utility system. Such duplication of effort only undermines the quality of training that we could accomplish. Shouldn’t our professional individuals receive baseline training which includes set guidelines for recurring training after a certain number of years? Then, during those years that they are baseline qualified, they would only have to fulfill those supplemental training tasks required by given regions or companies. Further, what if a region or company does not require supplemental training? That individual would only have to address those new qualifications required to perform their duties.

It is time we streamline our operator qualification process. We as industry leaders need to put together a committee to determine the knowledge and baseline procedures that should be expected of all technicians across all company and regional boundaries. Just as operators can only expand on the requirements of 192 and 195, so too can utilities only expand on the baseline qualifications for the sake of regional and company differences. This will allow everyone in the industry to maintain uniformity in baseline knowledge.

In order to manage such an undertaking, we as an industry can form a committee of experienced operators, including both managers and technicians, to perform yearly audits to ensure the baseline training system remains intact across all boundaries. Further, this committee can review the supplemental training programs to ensure they do not compromise the integrity of the baseline program.

As we imagine the possibilities of such a program, we immediately see a reduction in duplication of effort from all personnel within the industry. This would be a streamlined process that allows for a more cohesive training program, yet it is not restrictive in nature and allows each utility system the ability to maintain the flexibility necessary to fulfill their corporate and regional qualification requirements. Let us step back and consider the possibilities of such a streamlined program including: financial savings, structured progression of operator qualifications, alleviation of redundancy, and a uniform, highly skilled workforce. Is that not what our industry strives to achieve?

By: William Luttrell

Happy New Year to All

The holiday season is often a time of reflection for all those precious memories of holidays past.  It is also a reflection on the future.  What can we give up?  What can we change?  How can we do better?

For all of us in the natural gas industry there is much to reflect on and there is a great deal we can do to make our systems better and safer.  This is true whether we are updating systems or implementing new technology to increase our awareness and decrease our risk.  As PHMSA initiates new policy for the natural gas industry, we in the industry must take ownership for the roles we play to improve our systems and ensure such safety.

Each of us has a greater responsibility than that of a “job”.  Our decisions affect more than the company’s output or bottom dollar.  We affect the livelihood of millions of people.  What may be a simple over- sight could turn into a catastrophic incident!  Such an incident comes with life-long consequences which can never be undone.

So this season reflect on the following report as we renew our commitment to improve our knowledge, our procedures, and our performance to ensure 2014 and beyond will be some of the safest years in the gas industry.

May your holidays be filled with joy!

 

BGL Asset Services employees

 

National Gas Transmission: Serious Incidents: 1993-2012

Year

Number

Fatalities

Injuries

Property Damage (B) (C)

1993

10

1

16

$40,000

1994

10

0

22

$27,300,647

1995

8

2

7

$50,000

1996

6

1

5

$4,306,000

1997

4

1

5

$1,110,000

1998

11

1

11

$19,533,000

1999

5

2

8

$195,184

2000

7

15

16

$1,846,096

2001

4

2

5

$0

2002

4

1

4

$219,949

2003

8

1

8

$2,141,135

2004

2

0

2

$71,400

2005

5

0

5

$602,730

2006

6

3

3

$3,172,500

2007

8

2

7

$4,596,283

2008

5

0

5

$228,252

2009

6

0

11

$1,818,179

2010

6

10

61

$376,452,115

2011

1

0

1

$1,413,979

2012

3

0

7

$780,403

Totals

119

42

209

$445,877,852

2013 YTD

1

0

2

$354,000

3 Year Average (2010-2012)

3

3

23

$126,215,499

5 Year Average (2008-2012)

4

2

17

$76,138,586

10 Year Average (2003-2012)

5

2

11

$39,127,698

20 Year Average (1993-2012)

6

2

10

$22,293,893

 

National Gas Distribution: Serious Incidents: 1993-2012

Year

Number (A)

Fatalities

Injuries

Property Damage (B) (C)

1993

51

16

84

$3,905,500

1994

60

21

91

$7,927,150

1995

43

16

43

$1,493,902

1996

47

47

109

$8,050,352

1997

41

9

67

$1,681,750

1998

54

18

64

$9,968,086

1999

52

16

80

$3,746,000

2000

51

22

59

$4,313,695

2001

30

5

46

$855,663

2002

30

10

44

$4,472,979

2003

51

11

58

$7,547,565

2004

38

18

37

$6,116,239

2005

29

11

38

$8,170,960

2006

24

16

28

$4,145,979

2007

30

9

30

$4,925,469

2008

29

6

48

$6,052,576

2009

37

9

47

$11,111,119

2010

25

8

39

$4,105,990

2011

30

11

49

$5,506,863

2012

24

7

44

$7,137,916

Totals

776

286

1,105

$111,235,753

2013 YTD

20

7

38

$3,102,778

3 Year Average (2010-2012)

26

9

44

$5,583,590

5 Year Average (2008-2012)

29

8

45

$6,782,893

10 Year Average (2003-2012)

32

11

42

$6,482,068

20 Year Average (1993-2012)

39

14

55

$5,561,788

Statistical data taken from:  http://primis.phmsa.dot.gov/comm/reports/safety/SerPSI.html?nocache=702

By William Luttrell

Coordination Through Cooperation And Communication

Pipline SafetyPipeline Damage Prevention

During a recent ECDA of a gas pipeline it was determined that the loss of integrity was due to another utility’s attempt to directionally bore an expansion of their infrastructure. As one looks at the above photos, several questions come to mind. Were proper locates called in to the (811) one-call center? Did the existing pipeline company have an inspector on site to ensure proper distance was maintained between their facilities? Why did the operator not stop the boring procedure to investigate what they were bumping against underground? Did the contractor attempt to spot all existing utilities within their proposed construction zone before initiating the directional boring process? We will never know the answers to these questions, but one thing is certain, the cost of repairing the damage and the potential hazards from a pipline failure could have been catastrophic.

Over the past few years, pipeline safety has focused a great deal on public awareness (Title 49, Part 192.616) and damage prevention (Title 49, Part 192.614) regulations to help alleviate excavation mishaps. However, these regulations along with State 811 (Call Before You Dig) one-call centers cannot be stand-alone programs. Some states and regional areas have already recognized that there is still more that can be done. Many have initiated utility committees for the sole purpose of “Coordination through Cooperation and Communication”.

In short, all utilities and excavation contractors need to come together as one cohesive information network allowing for the sharing of readily available contact information and infrastructure records. Such genuine respect for each party’s infrastructures will enable every utility and contractor to complete their underground excavation in a manner that considers facility integrity and public safety as its number one priority. Additionally, such coordinated efforts should minimize construction cost brought about due to construction delays, lost labor hours and unwanted facility damages.

These proactive programs should be commended; however they do not come without their own set of problems. Although most utilities and large contractors are on board, how do you get the small one or two person general excavators to conform to the ideology? Further, it is hard enough to maintain records and receive quality locates on active lines but what about all those abandoned inactive lines that are still in the ground? Ask an excavation crew how often they have to stop work due to the uncovering or damage of an unmarked and unknown underground line. So how will antiquated abandoned lines be addressed? Finally, as our population grows, pipeline upgrade programs continue, and building construction expands into new territories we can expect our easements to become cluttered by both active and inactive systems.

Only the future will tell whether we succeed at “Coordination through Cooperation and Communication.”

By William Luttrell

BGL Creates the Distribution Services Department

In speaking with Brian Horanoff and Greg Gillespie, owners of BGL Asset Services, expanding their operations to include other vital areas of gas distribution services was truly a matter of mind set rather than a change in current business practices.

Timing is right for BGL to move in this direction. Recent changes in Federal guidelines and rulemaking requires utilities to institute a greater sustained effort in the integrity management of their distribution systems. A majority of this focus has been on the prioritization of operational processes and how process data is captured in the field as a means to measure a system’s risk and the consequences associated with those risks.

Another key area of interest by governmental officials has centered on routine maintenance standards and the miles of antiquated distribution lines that are still in use throughout the United States. Currently there is a push to update or replace much of these existing systems. It is these two areas of the gas distribution system driving the need for better reporting methods and risk assessments. Many of the past records and reports have been misplaced, destroyed by fire or flood, or just faded away due to the quality of print some 40 years ago.

As a result, there is a renewed call for action in the industry and BGL is in a position to assist natural gas distribution clients. Currently, BGL has on staff over 50 years of distribution operations experience. Such expertise includes: directional boring; design and construction of steel and polyethylene natural gas distribution mains and services; installation, repair and recoating of regulator stations and large commercial and industrial meter sets; leak and atmospheric corrosion surveying; management oversight of Federal and State regulatory compliance; and business process improvement consulting.

BGL has assessed the expertise of their staff and we expect to play a vital role in our client’s current and future business plans as they work diligently to fulfill these newly established requirements. We are certain BGL’s past experience and demand for high quality workmanship will be exactly what our clients will expect and receive.

If you are interested in discussing how BGL can assist in the completion of those construction and maintenance requirements as outlined in Title 49, Part 192, please contact us today.

BGL Goes The Extra Mile To Fulfill The Service Needs Of Their Clients — Even By Kayak!

KayakCombine

Caption: Expected completion time September 30. The actual completion time was September 13 using the RMLD methane detector and accessing natural gas mains under bridges via kayak on the Chattahoochee River.

Recently a client asked BGL if they could assist them in leak surveying their non-accessible natural gas pipeline crossings.  This challenge included approximately 165 creeks, 60 canals, 12 lakes, 154 major highways, 27 railroad overpasses, 70 rivers, and 3 large commercial rooftop systems.

At first, this did not seem like a lot to ask of BGL.  However, there was one caveat. Could it be done in one month?  BGL had all of the equipment necessary to perform the survey in the traditional way using Combustible Gas Indicators and Flame Ionization units.  Just two small hurdles to overcome; getting all the proper permitting and lost labor hours due to setting up traffic control on most of the overpasses.

BGL is always committed to servicing their client’s needs, and no matter how challenging a project might be, BGL typically finds a plausible solution.  As the discussion unfolded it was clear.  The thing to do was to purchase three Remote Methane Leak Detectors (RMLD).  They were meant for a scenario such as this one.

Within five days BGL had purchased and received three RMLD units, three kayaks, and spent the next three days completing all operator qualification requirements necessary to be considered proficient in the use of the RMLD.  BGL technicians even went so far as to complete kayak training in the field at one of the local rivers.

The great thing about the RMLD is their ability to use infrared to detect leaking methane from as far away as 100 feet.  Using the RMLD eliminates the need for permits or major traffic control scenarios.

In the end BGL was able to beat the deadline. Thanks to some of the latest technology on the market and the perseverance of every employee involved; the quality of the survey upheld all guidelines set forth by the client.

If you are interested in discussing pipeline leak detection, please contact BGL today.

We’re honored to be one of the Michigan 50 Companies to Watch!

Choice1logoWe’re honored to be one of the Michigan 50 Companies to Watch! Find out more about our exciting award: www.MichiganCelebrates.biz

For more information please see this press release