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2 | EXECUTIVE OUTLOOKLocalization: The Winning Strategy
4 | GLOBAL PERSPECTIVEIndustry Commentary from Around the World
6 | TECHNOLOGY FOCUS Tap into Efficiency: Bypass Pipeline Maintenance Costs
8 | SAFETY MATTERSExtraordinary Safety Measures for an Everyday Task
10 | FUTURE THINKINGArctic Adventure: A Long-term Proposition
12 | MARKET REPORT Analyzing and Predicting Potential Failure
20 | TOUCHPOINTSPipeline Events, Papers and Conferences
28 | BY THE NUMBERSFive Steps to Non-Intrusive Isolation
14 | The Economics of Efficiency Technology advancements provide efficiencies in exploration, production and transportation, ultimately providing stability – and even profits – in an era of low prices.
22 | It’s All About the DataPipeline integrity management systems yield business- critical information and enable operators to make better-informed decisions.
D E P A R T M E N T S
EDITOR-IN-CHIEF Jim Myers MorganMANAGING EDITOR Waylon SummersART DIRECTOR Joe AntonacciDESIGN PRODUCTION Kat Eaton, Mullerhaus.netDIGITAL PRODUCTION Jim Greenway, Ward MankinPHOTOGRAPHY Robert D. Flaherty, Ezequiel Scagnetti
T.D. WilliamsonNorth and South America +1 918 447 5000Europe/Africa/Middle East +32 67 28 3611Asia Pacific +65 6364 8520Offshore Services +47 5144 3240www.tdwilliamson.com
Want to share your perspective on anything in our magazine?Send us an e-mail: [email protected]
V O L . V I I , N O . 2 • 2 0 1 5
Innovations™ Magazine is a quarterly publication produced by T.D. Williamson.
®Registered trademark of T.D. Williamson, Inc. in the United States and other countries. ™ Trademark of T.D. Williamson, Inc. in the United States and other countries.© Copyright 2015. All rights reserved by T.D. Williamson, Inc. Reproduction in whole or in part without permission is prohibited. Printed in the United States of America.
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Set Double Block and Monitor Tool at location
BY THE NUMBERS
Five Non-Intrusive Isolationsteps to a
Set Plug Module #1 – 100% Isolation Pressure
Bleed Down LP Side to 50% of HP Side
Set Plug Module #2 – 50% Isolation Pressure
Bleed Down LP Side to Ambient Pressure
Offshore pipeline maintenance typically falls into one of four categories: valve replacement, tie-in, riser repair, or heavy lift protection. During these types of maintenance, operators rely on non-intrusive inline isolation methods to protect their people, achieve compliance, and mitigate reductions to production. The most common isolation is the DNV-certified double block and monitor method, as seen here.
DNV-Certified Double Block and Monitor Isolation Method
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1
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LOWLINE PRESSURE
HIGHLINE PRESSURE
ANNULUS PRESSURE
Monitoring andTracking Module
DP*
Mon
itore
dD
P* M
onito
red
DP*
Mon
itore
d
*Direct Pressure
PlugModule #1
PlugModule #2
ControlModule
Annulus pressure monitored for verification of both seals 50% LINE PRESSURE
DNV Recommended Practice for Pipeline Subsea Repair Criteria (DNV-RP-F113/3): . Each barrier must be able to retain full line pressure. Independent locking system. Seal must be independently tested. Ability to monitor line integrity. Seals must be independent from
the other
Through the use of independently operated isolation barriers, the isolation system allows high-pressure pipeline operators to carry out remedial pipeline work in a safe, controlled, and monitored
environment.
GENERAL INFORMATIONDebbie [email protected] 202-824-7338
More than 100 presentations by industry experts will address relevant and timely topics, including:
• best practices implementation • case studies (operations related)• construction and maintenance • corrosion control • damage prevention• emergency response• engineering• environmental issues (PCBs,
air emissions, storm water)• excess flow valves • gas control • gas operations technologies• gas quality• GIS/GPS applications• integrity management –
distribution & transmission• LNG • MAOP verifications
• measurement – distribution & transmission
• odorization issues• operations planning & support• pipeline safety• pipeline system planning
& design• plastic materials • public awareness programs• purging operations• regulatory compliance• safety management• technical training & knowledge
transfer• underground gas storage • utility & customer field services • work management systems …and much more!
Conference attendees are eligible for Professional Development Hours.
OPERATIONS CONFERENCE & BIENNIAL EXHIBITION
A M E R I C A N G A S A S S O C I A T I O N
Safety & Operational Excellence – Across the Globe!
MAY 19-22, 2015 GAYLORD TEXAN HOTEL & CONVENTION CENTER GRAPEVINE, TEXAS
Attention, Equipment & Service Providers!The conference also features the renowned AGA biennial exhibition of products and services related to the operating functions of natural gas utility and transmission companies.
Don’t miss your chance to reach the natural gas industry’s leading operations management of local, national and international gas utility and transmission companies who attend this event. The exhibition happens once every two years; make 2015 count!
To Reserve Exhibit SpaceAGA Show Managementc/o Exhibit Promotions Plus [email protected] 410-997-0763 or 301-596-3028
SPONSORSHIP OPPORTUNITIES Annemarie O’Donoghue [email protected] 202-824-7032
Look for the conference program and registration details atwww.aga.org/OpsConf2015.
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Working in oil and gas means we can make a claim most industries can’t: We have the power to move the world. I don’t mean just in the sense of fueling transportation, even though 60 percent of the oil produced globally is, in fact, used to transit people and products from point A to B.
What I’m referring to in this case is how our industry has become a driving force for local economic development on every continent. This is especially true as international oil companies (IOCs) continue to partner with and support national oil companies (NOCs) in emerging markets.
A few years ago, the global consulting firm Accenture suggested that localization initiatives – developing local economies, stimulating industrial development, increasing local capability, building a skilled workforce, and creating a competitive supplier base – would become the minimum requirements for doing business with NOCs. In other words, IOCs would have to look beyond the deal and do things that are good for the country.
As part of this ongoing push toward localization, IOCs are guiding NOCs – who command nearly 80 percent of the world’s remaining oil reserves – to expand homegrown competencies and technological expertise. As a result, developing countries are better equipped to use their oil and gas resources to promote economic and social progress.
Take a look at Norway’s Statoil, for example, a product of the Norwegian government’s ambition to utilize its North Shore and continental shelf resources. During Statoil’s early years, the government built a local energy industry by giving first consideration on contracts to Norwegian bidders who were competitive on key attributes like price and quality. As foreign operators began to enter the Norwegian energy industry, they were encouraged to partner with local companies on research and development.
Today, Norway is among the top energy exporters in the world. And Statoil is sharing its wealth globally. The company supports training and competence building in Brazil, Canada, Russia and Nigeria. Nigeria, in fact, is the site of another compelling example of the benefits of localization.
The Nigerian National Petroleum Corporation (NNPC) is dedicated to leveraging the country's energy resources to help the nation advance technically and economically. With the help of Shell – who provided knowledge transfer, training, and preferential bidding to Nigerian suppliers – NNPC was able to develop its oil industry capabilities.
Obviously, localization isn’t a one-way street. By working with NOCs, IOCs gain access to oilfields that might otherwise have been off limits. They expand their global footprint while reducing risk and improving ROI.
In my own experience, recruiting and training a knowledgeable local workforce has enabled T.D. Williamson to meet global customer demands with uniform quality. Which means localization is a winning strategy, all-around.
BY JOHAN DESAEGHERVICE PRESIDENT
EUROPE/AFRICA/MIDDLE EAST T.D. WILLIAMSON
E X E C U T I V E O U T L O O K
Localization: The Winning Strategy
“…IOCs are guiding NOCs to expand homegrown competencies and technological
expertise. As a result, developing countries are better equipped to use their oil and gas resources
to promote economic and social progress.”
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TU TRANOPERATION RESEARCH ANALYST, ENERGY INFORMATION ADMINISTRATION
Northeast, the industry plans to expand existing systems and build new systems to transport natural gas produced in the Northeast to consuming markets outside the region.
Flows on ANR Pipeline, Texas Eastern Transmission, Transcontinental Pipeline, Iroquois Gas Pipeline, Rockies Express Pipeline, and Tennessee Gas Pipeline accounted for 60 percent of flows to the Northeast in 2013. Flows on these pipelines in 2013 were between 21 percent and 84 percent below 2008 levels, with the largest percentage decline occurring on the Tennessee Gas Pipeline. As a result, these pipeline companies have announced plans to modify their systems to allow for bidirectional flow, adding the ability to send natural gas out of the Northeast region. In 2014, the Tennessee Gas Pipeline and the Texas Eastern Transmission began flowing gas both ways between states along the Northeast and Southeast region borders. Even though the Northeast has seen increased natural gas production and new infrastructure, consumers in New England continue to pay high natural gas prices during peak demand days because of pipeline constraints and lower supplies from Eastern Canada and liquefied natural gas (LNG) imports.
GROUNDBREAKING REPORT ON CORROSION
NACE International is compiling the International Measures of Prevention, Application and Economics of Corrosion Technologies (IMPACT) study, a groundbreaking report on the costs of corrosion for many industries and nations worldwide. With 16 research partners in nine countries, this study will provide the most comprehensive data ever recorded on the financial impact of corrosion on the world’s largest economies, to include economic models and templates.
In the early part of 2015, participating research partners began the data collection process. Once all data is submitted to NACE International, it will be combined and analyzed to provide a global view of the costs of – and solutions to – the threats of corrosion.
The last time this kind of research was done (2002), it was commissioned by the U.S. Congress and assigned to the Federal Highways Administration (FHWA). For the past decade it has served as a valuable resource; however, it only focuses on U.S. assets and didn’t address indirect costs. The IMPACT study will include global data and examine indirect costs.
Each year, there are increasing reports on the rising challenges of aging, poorly maintained infrastructure. For example, in the United States, hundreds of billions of dollars are spent annually on mitigating corrosion of infrastructure, such as gas and liquid pipelines, railroads, and hazardous materials storage. In addition, corrosion has a high cost in production and manufacturing sectors, such as oil and gas exploration and production, petroleum refining, and petrochemicals.
The FHWA study indicated that a savings of as much as 30 percent is possible through the use of corrosion control technology that was available even 10 years ago, but the study was unable to specifically identify the cost differences between prevention, repair, and replacement of assets. The IMPACT study will be the first study to provide that data. It will demonstrate the usefulness of corrosion control methods and the long- and short-term affordability of those methods. And it will go beyond just the costs associated with corrosion in a collection of case histories and industry best practices.
Research partners for this study include: Chinese Academy of Sciences, Japanese Society of Corrosion Engineers, Australasian Corrosion Association (ACA), Saudi Aramco, American Water Works Association (AWWA), Federation of Indian Chambers of Commerce and Industry (FICCI), DECHEMA Institute, U.S. Department of Defense, International Union of Painters and Allied Trades (IUPAT), U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration (PHMSA), U.S. Environmental Protection Agency (EPA), U.S. Federal Highways Administration (FHWA), Petronas, Exova, Association of State and Territorial Solid Waste Management Officials (ASTSWMO), and Northern Area NACE International representing Canada.
Bob Chalker CHIEF EXECUTIVE OFFICER, NACE INTERNATIONAL
MAKING NATURAL GAS EVEN SAFER
The domestic abundance of natural gas in the United States continues to offer tremendous opportunities for the nation’s economy, environment and energy security. Local natural gas utilities provide the critical final link between natural gas production, pipelines and people, and we are constantly striving to enhance our operations to continue to deliver safe, reliable and affordable energy to homes and businesses.
As part of this ongoing focus on safety, the American Gas Association and its members have embarked on a groundbreaking voluntary effort to elevate the safety of natural gas delivery by drawing on the combined expertise of natural gas utilities nationwide.
Launched in 2015, the AGA Peer Review Program is a national voluntary peer-to-peer safety and operational practices review program that will allow natural gas utilities to observe their peers, share leading practices and identify opportunities to better serve customers and communities. While other industries have implemented peer safety reviews, this is the first national program of its kind for the U.S. natural gas utility sector.
Throughout 2015 and beyond, companies from the more than 200 local U.S. natural gas utilities that make up AGA’s membership will volunteer to team up in peer groups of 3-4 companies to visit one another’s facilities and conduct detailed reviews focusing on key aspects of pipeline and employee safety. These face-to-face discussions between experienced, knowledgeable and dedicated natural gas utility professionals will help each company, and the industry as a whole, strengthen its practices and processes and ultimately lead to an even safer natural gas industry.
Christina SamesVP, OPERATIONS & ENGINEERING, AMERICAN GAS ASSOCIATION
GlobalPerspective Industry Commentary from Around the World
PAGE 14: Read more on oil production from the Energy Information Administration (EIA)
THE STATE OF BIDIRECTIONAL NATURAL GAS PIPELINE CAPACITY
32 Percent Of Natural Gas Pipeline Capacity Into The Northeast Could Be Bidirectional By 2017 — Spurred by growing natural gas production in Pennsylvania, West Virginia, and Ohio, the U.S. natural gas pipeline industry is planning to modify its systems to allow bidirectional flow to move up to 8.3 billion cubic feet per day (Bcf/d) out of the Northeast. As of 2014, the industry had the capacity to transport 25 Bcf/d of natural gas from Canada, the Midwest, and the Southeast into the Northeast. In addition to these bidirectional projects in the
Source: U.S. Energy Information Administration estimates based on Ventyx's data
Note: In this context, the Northeast includes the Northeast Census region as well as Delaware, Maryland, Ohio, and West Virginia.
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T E C H N O L O G Y F O C U S
Tap into Efficiency: Bypass Pipeline Maintenance Costs
Utilizing the isolation system housing
to create bypass, operators achieve major
efficiency gains.
6
By eliminating the need to bypass flow through a separate set of taps, the total number of fittings is reduced and the HT&P process is enhanced. It’s not news that pipelines are a high-maintenance asset.
And for most operators who need to perform maintenance, shutting their pipeline down simply isn’t an option. Regardless of whether the product in the line is worth US$100 a barrel or US$40 a barrel, if flow gets interrupted for any period of time, it’s going to show up on the P&L statement.
For decades, hot tapping and plugging (HT&P) has been the preferred method of performing both planned and emergency maintenance on pipelines. Operators often use HT&P to isolate and bypass small lengths of pipe so that repairs, modifications, or tie-ins can be made without having to stop flow and drain or flare product. This means that, by including a bypass as part of an isolation, operators can significantly improve their ability to safely perform maintenance and avoid the financial pitfalls that accompany shutting down a line.
However, like any technology or methodology, there’s always opportunity to realize additional savings by making the process more efficient. And one way to achieve greater efficiency is by bypassing flow directly through the housing of the plugging machine.
Fewer Fittings Mean Lower CostsTypically, the biggest determinant of cost when it comes to an HT&P project is how many taps an operator needs to make in order to isolate the pipe, bypass flow, and create a safe work environment for their technicians to perform maintenance.
More taps means more fittings, more welds, more potential leak paths, more inspections, and ultimately, more
money. But by eliminating the need to bypass flow through a separate set of taps, the total number of fittings is reduced and the HT&P process is enhanced.
Take for instance a double isolation bypass procedure, which is a common method for isolating a section of pipe by sealing it off both upstream and downstream of the area that requires work. This procedure normally requires two hot taps and two fittings on each side of the isolation zone (four fittings total). One fitting on each side is used to install the bypass pipe and the other is used for insertion of the plugging head(s).
Although operators are always looking to increase the efficiency of their processes, the current low oil price environment has provided the industry with renewed determination. This is where advances in HT&P technology come in. One such advancement is increased capability
with the patented STOPPLE® Train plugging system, developed by T.D. Williamson (TDW).
Always supported by specialized applications engineering, this unique approach to line isolation halves the number of hot taps and fittings by inserting two independent seals through a single entry point, instead of requiring a tap for each seal. This isolation method allows for product bypass directly through the housing of the plugging machine.
The STOPPLE Train system’s two
independent seals, which establish double block and bleed capability, also provide an extra layer
of safety for the technicians working on the pipeline and increase the likelihood of achieving an acceptable seal on the first attempt.
“Being able to perform a double isolation and bypass through the housing of the plugging system reduces the need for additional fittings, and as any operator who has ever had to perform an HT&P job knows, this means significant cost savings,” explains David Turner, Director of Hot
Tapping and Plugging Technology at TDW. “Beyond reducing cost, fewer fittings mean minimized risk of third-party damage, which is fairly common. This approach also improves safety and reduces the size of the excavation required to get at the pipe, again resulting in lower equipment costs and less risk for operators,” says Turner.
Simplification Boosts Savings, TooSimplified field operations are another tangible benefit of bypassing through the plugging machine housing. Fewer welds mean reduced manpower requirements and less time needed to complete the HT&P operation.
“Any time you can streamline field-related operations, you’re going to see additional savings,” says Grant Cooper, Manager of Commercialization, HT&P Technology for TDW. “So now, not only have you reduced your number of fittings by half (i.e., cost and risk), you’ve gained efficiencies in manpower and time, which translate into increased safety.”
Finding ways to hedge against fluctuating energy prices will always be a valuable pursuit for operators. But in today’s climate, being able to help stabilize cash flow through more efficient applications of existing HT&P technology can help yield an even greater return.
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Extraordinary Safety Measures for an Everyday Task
On a January day in 1992, residents about 96 kilometers (60 miles) north of Calgary, Alberta, were forced into the cold, along with about 600 workers at a gas plant construction camp site. A pipeline about 800 meters (0.5 miles) a compressor station ruptured on both sides of a hot tap tee. The natural gas escaping from the rupture caught fire at three different places along the 373 meters (quarter mile) of damaged pipe. Fortunately, no one was injured. As reported by the Oil and Gas Journal, the primary cause of the accident was “the noncompliant procedure used to weld the 24- in. stub to the 36-in. carrier pipe.” More specifically, it was faulty welding that created a hydrogen crack, which, ultimately, couldn’t handle the stresses from the pipeline.
The accident happened over 20 years ago, but it is still a powerful illustration of how even everyday procedures like welding require stringent safety measures and highly specialized professionals to keep dangerous accidents from occurring on a pipeline.
The Risks of Keeping the Product FlowingHydrogen cracking is one of the greatest concerns of pipeline owners. If hydrogen atoms pool within the steel’s grain boundaries – forming hydrogen gas – pressure can build and cause cracking. Although the cracking often becomes apparent just one or two days after welding, the pipeline can also take up to 10 or more years to show signs. That’s why hydrogen cracking is often called “delayed cracking.”
Besides hydrogen cracking, the other major danger in pipeline welding is “burn-through,” which can cause the product inside the pipeline to leak or even ignite. Burn-through is of significant concern as almost all pipeline welding is “live welding,” which means that it’s performed when a pipeline has liquid or gas inside.
Live welding, also known as “in-service welding,” is the first step in the process for hot tapping and plugging,” says Chris Vrolyk, a welding engineer manager for T.D. Williamson. This means live welding is integral to the safe repair and maintenance of pipelines – such as for tie-ins, defect removal, or making a line piggable. “In fact, it’s used in most of our services, so we deal with it on a daily basis,” adds Vrolyk.
Although service companies are well acquainted with the process, live welding still involves applying concentrated heat on a pipeline
carrying flammable product. Welding engineers and associated workers must make safety the first priority.
Planning for Safe ExecutionEach live welding case can be different, so planning a site-specific approach is key. First, welding engineers perform a risk analysis to determine the best approach, assess all possible scenarios, and create a backup plan. After successful execution of a weld, more testing follows – technicians trained in advanced non-destructive evaluation (NDE) return to the site a minimum of two days after completion to ensure that there are no signs of hydrogen cracking.
“To plan the project, we need to know about the customer’s pipeline condition – the thickness and operating pressure, for example,” explains Vrolyk.
“We need to figure out what size and type of fitting to use and where it will be placed. We do a pre-weld examination with ultrasonic testing to tell how thick the wall is and make sure it’s clean. We need to assess the hardness of the material to make sure we use the right procedure.”
Trained to Combat Delayed CrackingOf course, safety regulations often include certifications and training standards for the engineers and other workers performing the welding procedures. “We’re continually training in both the classroom and field to avoid burn-through and hydrogen cracking,” states Vrolyk.
“We conduct special engineering software simulations and mockups in the shop before projects to ensure that everyone is well prepared.”
Although live welding is used for most pipeline procedures, it’s difficult for pipeline companies to carry the expertise in-house. Most operators rely on specialized providers to perform the service because they know how to work within government safety regulations and have the extensive training and special equipment required for success.
More than hydrogen cracking caused the 1992 Calgary incident, but it serves as an example that even everyday tasks like welding deserve special attention to safety.
S A F E T Y M AT T E R S
Mitigating the risks of live welding through
ongoing training.
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Looking beyond the current price of oil,
the industry prepares for unique Arctic
pipeline challenges.
A Long-term Proposition
A Challenging Environment
According to the U.S. Geological Survey, the Arctic may hold 90 billion barrels of undiscovered oil, more than 28 trillion cubic meters of natural gas, and 44 billion barrels of natural gas liquids. All of which makes developing untapped Arctic hydrocarbon resources an attractive commercial opportunity.
At the same time, of course, the Arctic’s severe physical environment presents immense and costly challenges for both energy exploration and ecological preservation.
According to George Lim, industry veteran and offshore expert for global pipeline services provider T.D. Williamson (TDW), it will take new technologies to overcome the complexities that could limit
development in this forbidding region and to mitigate risks to personnel, equipment, and the natural environment.
Finding Solid Ground
One of the first difficulties to conquer relates to the construction of essential infrastructure.
For onshore projects, for example, the frozen layer of soil that sits about two meters down (also known as “permafrost”) has been considered suitable for the construction of oil and gas infrastructure. But with the permafrost thawing, it might be harder than expected to find solid ground for new infrastructure.
“Building on permafrost that is in a thawing cycle is a complex challenge,” Lim says. “There is no reliable long-term solution for that, yet.”
Construction can also be done on the soft, slightly thawed soil that sits above the permafrost. However, this option is even more costly because it requires piles to be driven down more deeply to solid ground beneath.
Given the complexity of onshore drilling in the Arctic, it may seem somewhat reassuring that the majority of the region’s oil and gas – about 84 percent of it – is accessible via offshore drilling. But offshore drilling is not without its own unique challenges. One of the biggest challenges? Price. Burying pipelines in the seabed is extremely expensive. And because shifting icebergs can cause gouges in the seabed soil, pipelines need to be buried down to 10 meters deep, a distance that requires innovative technologies to achieve. Another challenge is day-to-day operations: Once in place, buried pipelines need to be inspected, monitored, and repaired like any other lines.
Can these difficulties be whittled down to size? Lim thinks so.
“Being able to create new technologies to overcome Arctic limitations, while promoting environmental stewardship, can be cost-prohibitive,” says Lim. “So prospective companies that cannot afford deep development spending will have to join efforts in Joint Industry Projects.”
Protecting the Arctic, Defining the Future
External inspection and monitoring of these deeply buried lines are impossible using current technologies. And traditional support vessels, with diver-based or remotely operated equipment, are unable to access potential repair sites when the sea is ice-covered – nine months of the year. So the only way to stop loss of containment, and the consequent environmental impact, is to completely shut down the operation during this period, which is rarely desirable from a business standpoint.
“Before we ever get to the Arctic, the industry will need to find a solution to temporarily stem a leak until the sea is ice-free,” Lim says. Repair vessels and equipment could then be deployed to carry out a permanent repair by cut and spool replacement. Developing such a comprehensive and failsafe approach to leak detection, assessment, and repair will require a great degree of expertise and cross-industry collaboration.
Thanks to ongoing investments in such sophisticated technology and shared interests among E&P companies and service providers, many potentially catastrophic risks – for the environment and for investors – can be eliminated. And although some Arctic opportunities are still out of reach, it’s only a matter of time before technology catches up.
As Lim points out, the Arctic is the last pristine surface frontier. We all carry responsibility to maintain that for future generations. And new pipeline technologies will play no small part in helping to strike the right balance between development and preservation that will define the future of the Arctic.
F U T U R E T H I N K I N G
With the break-even point for arctic operations at about twice the recent price of crude oil, now may not be the best time for the industry to embark upon drilling in the steel-snapping, oil-thickening cold.
But if Arctic drilling and production are to become a viable and sustainable reality, planning for the future starts today. In fact, the complexities of the Arctic environment require it.
44
28
90 BILLION bblOil
According to the U.S. Geological Survey, the Arctic may hold:
28 TRILLION m3
Natural Gas
44 BILLION bblNatural Gas Liquids
90
ARCTIC ADVENTURE:
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Benefiting from advances in leak
detection, gas utilities invest in data.
is the easy part; gathering the volumes of requisite pipeline data, well … that could take decades.
Digging Up DetailsIn order for predictive software to deliver on its promise, it requires a lot of data: pipeline diameters, age, pressure, temperatures, geology, proximity to roadways, ground depth, previous incidents, etc. – multiplied by the kilometers of pipe in the ground. The more data these systems receive and analyze, the better they can project pipeline failures and proactively recommend remediation, repairs, replacements, and relocations.
For utilities, capturing this data is not as easy as one might think. “Today, when you need to operate on a pipe, you may not know exactly where it’s located or what it’s made of,” says Philippe Simon, a gas utility and distribution expert with T.D. Williamson (TDW). “Often, operators can’t formally acquire this information until a line is excavated for maintenance or relocation.”
This isn’t to say that some pipe data doesn’t exist. In fact, about 20 years ago, utilities started more consistently compiling data, but most of that information was logged on paper and filed away in metal cabinets. In other words, it doesn’t exist in a neatly structured, easy to access data warehouse with a smooth graphic user interface and smart query function.
Step By StepUtilities continue to embrace modeling software, which evolves on an almost monthly basis. And with each day there is an opportunity to capture and store even more data about their lines.
Gaz de France, which owns several hundred thousand kilometers of distribution pipelines across the globe, is leading the industry in its commitment to data capture and input. “With so many kilometers of existing pipe, to say nothing of the thousands of kilometers being laid every year, it’s safe to say that Gaz de France’s data input is perpetual,” explains Simon. “And Gaz de France, and its customers, will reap the benefits of such a significant investment.”
From here, the industry expects to see a new
level of pipeline technology that does more than analyze input and project potential failures: it’s looking forward to solutions that also allow utilities to monitor their pipe systems in real time. This kind of technology could work hand in hand with existing solutions, meaning utility companies would continue to rely on predictive software to help prevent leaks, and they would leverage new technology to alert them, in real time, to leaks as they occur.
Tremendous OpportunitiesAlthough integrated, real-time leak detection will be a reality one day, gas utilities must meet customer expectations today: increased safety and reliability. And they will continue to depend on trusted leak detection technologies from companies like GAZOMAT™, a subsidiary of TDW, whose offerings help utilities detect and characterize leaks, and determine the appropriate level of response.
“Through recent advances in leak detection technology, like the portable Catex™ 3-IR Analyzer, operators can gather and correlate a wealth of leak information,” says Simon. “They can also more accurately assess the risk of a leak or accident. And since the software prioritizes attention and investment based on risk severity, the utility’s efficiency is significantly increased.”
It’s a powerful affirmation of the industry’s commitment to progress, that – even after more than 100 years
– leak projection and detection technologies are still improving, and faster than ever before.
M A R K E T R E P O R T
Analyzing and Predicting Potential Failure
For more than 100 years, utility companies have been relying on pipelines to transport natural gas to customers. And for more than 100 years, customers have expected those lines to be 100 percent safe and reliable.
Pipe materials and production methods have changed a bit over this period, but customers’ expectations have not. Fortunately, pipeline inspection and leak detection methods have greatly evolved to help utilities meet those customer needs. And as gas utilities are particularly devoted to their end users, most any development that delivers greater safety and reliability is swiftly adopted. So it’s no surprise that when predictive modeling software for pipeline integrity was introduced about 15 years ago, the industry took note.
This relatively recent evolution has proven quite valuable to gas utilities, helping them promote safe operations by identifying risks for pipeline leaks, as well as recommending repairs and replacement. However, although these software offerings have helped the industry better serve its customers, the evolution is not without some unique challenges.
To realize the full value of predictive software, utility companies must gather and input extensive pipeline data – as is required by the software – to most effectively predict failures. Adopting the software
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If the rig count were the only gauge used to measure the health of oil and gas activity in Texas’s Eagle Ford shale, some observers might conclude that the patient’s typically “stable” condition could reasonably be escalated to “serious.”
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The Economics of Efficiency
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• A Stutter Step in Rig Count Doesn’t Mean the End is Nigh
• Condensates on the Move: Incentives for Removing Wet Gas Liquids
• Automation is Part of the Profit Equation
• Are Lower Prices the New Norm?
How Technology Provides Stability — and Even Profits — in the Era of Low Prices
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After all, as crude oil prices have fallen, so have the number of active Eagle Ford rigs. In just the three months since November 2014, the total dropped about 27 percent, from 264 to 192, according to Energy Information Administration (EIA) data published in March 2015. And in light of continuing weak global energy demand, the prospects for a quick rig count turnaround seem unlikely.
But don’t cue the dirge quite yet. A decline in rigs isn’t necessarily a predictor of falling production. In fact, during the natural gas price plunge of 2008, output actually increased, even as rigs came offline.
In short, rig counts can be misleading. At least that’s the view of Citigroup commodity strategist Anthony Yuen, co-author of a Citigroup research note comparing the events of 2008 to today’s drop in U.S. crude oil prices, which have fallen more than 50 percent since the summer of 2014.
Yuen points out that the total number of U.S. natural gas rigs peaked at about 1,600 in 2008 before falling to 672 by July 2009.
Today, the number of natural gas rigs is less
than half that, closer to 300. Yet the data indicates that production is up 50 percent from when the rig count was at its highest point.
Credit drilling and operating efficiencies for the boost, says Citigroup.
Can boosting efficiency have the same effect in the Eagle Ford? Can technology – automation in particular – mitigate the drop in crude prices by
reducing operating costs, increasing product flow, and helping to capture marketable NGLs and condensates?
There’s ample evidence those types of improvements are already in play. And they’re having a big impact on operators’ P&L statements.
A Stutter Step in Rig Count Doesn’t Mean the End is NighBefore 2008, the Eagle Ford shale formation – a narrow, roughly crescent-shaped band sweeping 650 kilometers (400 miles) across Texas – hadn’t caught the eye of many oil and gas companies. Although the area was known to contain hydrocarbons, the rock unit’s permeability was exceptionally low. It was doubtful that oil and gas could flow through to a production well.
Until, of course, it did. The Eagle Ford success story is the
stuff of legends: 5-year-old independent energy company Petrohawk combines two proven technologies and cracks a formerly unyielding energy deposit, demonstrating the area’s viability with a well that comes in with an initial flow rate of 7.6 million cubic feet of natural gas per day. By September 2014, the Eagle Ford roll call includes industry luminaries and lesser-knowns alike, who, all together, are pumping out more than 1.5 million barrels per day of crude oil and light condensate. Late in 2014, the Eagle Ford hits the 1 billion barrel mark, outpacing its North Dakota rival, the Bakken. And projections for future growth are impressive, with suggestions that the region will produce 1.8 million barrels per day of
oil equivalent in 2015. Adding to the Eagle Ford’s accolades is the
fact that the area produces the bulk of America’s condensate, which grew from 178 million barrels in 2009 to 274 million barrels just three years later. And with minimally processed condensate given the nod for export by the U.S. Commerce Department’s Bureau of Industry and Security (BIS), the sky seems to be the limit. But then, the price of crude oil falls. Again and again and again.
Yes, the drop has caused a stutter in the Eagle Ford rig count. However, the consensus among international analysts is that not only can the Eagle Ford weather a prolonged period of lower prices, it can prosper.
For example, in December, when oil was trading in the US$60s, global energy researcher Wood Mackenzie said production would remain profitable even if prices dropped to around US$49 per barrel.
Analysts at ITG Investment Research Inc. were even more optimistic, saying that in some areas of the Bakken, Permian and Eagle Ford, explorers can drill new wells profitably, even if crude falls to US$25 a barrel.
So far, the production numbers justify such rosy outlooks. Oil output across the United States
has continued to rise despite the national rig count sagging. During the first full week of January, the EIA reported, production rose by an additional 60,000 barrels per day.
“These increases have occurred despite the (Eagle Ford) region’s relatively high well decline rates,” an EIA briefing said. “However, by offsetting the natural declines through the use of new recovery techniques, further production increases are possible.”
As the EIA suggests, the Eagle Ford has moved from being capital intensive and price-driven to technology intensive and innovation-driven. As such, operators have been able to squeeze more product from those intransigent formations, and save money in the process. Among the improvements, better completion techniques have boosted initial production rates. Tighter well spacing has helped maximize production and increase reserves, and altering variables like the frac fluid and proppant is further building output. Integrated electrical and control systems have decreased energy consumption, while computerized monitoring oversees key process data, including flow rates, pressures, and leak detection – really, anything that could stop or slow production. In short, automation is helping both
$14M
$12M
$10M
$8M
9/10 9/11 9/12 9/13
“By offsetting the natural declines through the use of new recovery techniques, further production increases are possible. . ."
The Eagle Ford has moved from being capital intensive and price-driven to technology intensive and innovation-driven.
Eagle Ford Well Costs
P RO J E C T S TA R T DAT E
WE
LL C
OS
T
Sept. 2010
Sept. 2013
8M
6M
4M
2M
2007 2008 2009 2010 2011 2012 2013 2014
300
200
100
0
Eagle Ford Production vs Rig Count
Production Rig Count
Rig Count
Natural Gas Productionin mcf/dOil Productionin bbl/d
Source: Energy Information Administration
Source: Energy Information Administration
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an economic incentive for removing the liquids from Eagle Ford production and selling them at a premium. And innovation (read: Automation) can be used to get more liquids out easier and faster. Which is particularly important in light of two projections: The Energy Policy Research Foundation’s forecast that by 2017, 19 percent of all NGLs produced in the United States will come from the Eagle Ford, and Citigroup’s prediction that exports of light and ultralight crude from the United States could reach 1 million barrels a day by the end of 2015.
Mexico, for one, would like to get its hands on some of that – a tenth of the total, to be exact.
Following the BIS decision to allow the export of ultralight oil, Petroleos Mexicanos (PEMEX) petitioned the U.S. Commerce Department to
import 100,000 barrels of light crude per day. If approved, it would allow Mexico to increase gasoline production and improve refining. In exchange,
PEMEX would send its heavy oil to refineries on the United States Gulf Coast that are configured for processing it.
Automation is Part of the Profit EquationIn a low price environment, pushing more product is a sensible option. But it’s not the only one. Reducing costs and eliminating inefficiencies are equally valid choices.
The removal of wet gas liquids fulfills all of those goals. In addition to providing marketable products, it aids in pipeline maintenance. Liquids in the line reduce the optimum flow of natural gas and drastically increase fuel and power consumption. Capturing them avoids those issues.
“One of the major line items in the operation
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400
201420132012201120102009
300
200
100
6 12 18 24 30 36 42
2009
2010
2011
2012
2013
-70%
-68%
-68%
-64%
-69%
-30%
-39%
-47%
-48%
-20%
-28%
-27%
-20%
-42%
Average Oil Production Per WellDuring the First 48 Months of Operation
Year-Over-Year Decline in Production in Wells Drilled in the Eagle Ford Region from 2009-2013
M O N T H S O F O P E R AT I O N
B B L / D
First Full Monthof Production
YEAR 1 YEAR 2 YEAR 3 YEAR 4
Increased Initial Production from~ 25 bbl/d in 2009
to~ 375 bbl/d in 2014
Source: Energy Information Administration
CONTINUED ON PAGE 27
EOG Resources Maximizing Net Present Value (NPV)
of the Eagle Ford
WELLS PER SECTION 10 WELLS 16 WELLS DIFFERENCE
Reserves/Well 450 MMBoe 400 MMBoe
Reserves/640 Acres 4.5 MMBoe 6.4 MMBoe +1.9 MMBoe
Recovery Factor = 6% = 8% + 2% Recovery
CWC/Well $6 MM $6 MM
Direct ATOR/Well 130% 100%
NPV10/640 Acres $69 MM $98 MM +$29 MM NVP
Source: EOG Resources / March 2013 Investor Presentation
PREVIOUS 640 ACRES10 WELLS PER SECTION
(65 AC./WELL)
CURRENT 640 ACRES16 WELLS PER SECTION
(40 AC./WELL)
personnel safety and pipeline integrity, which can be particularly troublesome given the high paraffin content of Eagle Ford crude.
But even despite today’s lower oil prices, Zellou sees new opportunity emerging in the Eagle Ford. That’s especially so, he says, because current drilling economics favor wet gas.
As he explains, in the past, on an energy content basis, natural gas and crude oil were priced at parity.
“Now, even with the drop in crude oil prices to around US$50 per barrel and natural gas at around US$3 per million BTU, natural gas is priced at about half of crude oil on an energy content basis,” he says. In other words, for the equivalent amount of energy, natural gas priced at US$3 per MMBTU is equal to about US$17 to US$20 per barrel of oil. Granted, that’s considerably less than the US$50 or so that oil was trading at in January, but the gap is certainly smaller than when oil was US$100 per barrel.
What this means, Zellou says, is that there’s
product and cash flow in the Eagle Ford.Still, Eagle Ford operators admit that because
the region is highly variable, with wells in the same field performing differently, it can be difficult to generalize break-even costs. And no one seems comfortable betting on how low oil prices would have to fall before production starts to level off, or even decline.
Condensates on the Move: Incentives for Removing Wet Gas LiquidsAbdel Zellou, Ph.D., a U.S. midstream and gathering market expert with global pipeline services provider T.D. Williamson (TDW), has spent considerable time over the past several years examining productivity nuances in the Eagle Ford region. As such, he understands the pressures that operators there are dealing with. Chief among them, he feels, are low recovery and high decline rates compared to conventional wells and the need to control operating expenses, while still assuring
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TDW experts deliver — providing technical presentations and hands-on demonstrations throughout the world. To learn more: [email protected].
TDW Events, Papers & Conferences
TouchPointsOil Sands15-16 SEPTEMBER | Fort McMurray, AB | Canada
S E P T E M B E R 2 0 1 5
AUG 31 - 2 SEPT NACE Central Area Conference St. Louis, MO
15-16 Oil Sands Fort McMurray, AB
19-22 Arkansas Gas Association 2015 Hot Springs, AR
21-23 North American Pipelines Congress Chicago, IL
22-24 Rio Pipeline Rio de Janeiro, BR
Rio Pipeline22-24 SEPTEMBER | Rio de Janeiro | Brazil
DUG East23-25 JUNE | Pittsburgh, PA | USA
MEA Gas Operations Technical & Leadership Summit11-13 AUGUST | Rochester, MN | USA
The Pipeline & Energy Expo25-26 AUGUST | Tulsa, OK | USA
NACE Central Area Conference31 AUGUST - 2 SEPTEMBER | St. Louis, MO | USA
Arkansas Gas Association 19-22 SEPTEMBER | Hot Springs, AR | USA
North American Pipelines Congress21-23 SEPTEMBER | Chicago, IL | USA
Don't miss the white paper presentation by hot tapping and plugging technology experts Frank Dum and Niyaz Garaev at RIO PIPELINE.
Quantifying and Improving Seal Efficiency: Double Block and Bleed Pipeline Isolation
Often driven by a demanding market and relentless shareholder expectations, operators work smart and hard to achieve 100 percent success in the field. This is particularly applicable to pipeline isolation and operational safety. This paper will demonstrate how the trend toward field-proven Double Block and Bleed isolation is maximizing project efficiencies and providing pipeline operators with significantly reduced costs and greatly increased safety.
As isolations are a routine aspect of pressurized pipeline maintenance, the Double Block and Bleed methodology was developed to help operators, across geographies and industries, approach 100 percent success in achieving line isolations with no detectable seepage, and without shutting down their production.
Booth D6 T.D. Williamson Sept 22-24, 2015
J U N E 2 0 1 5
1-5 World Gas Conference Paris, France
2-5 Oil & Gas Asia Kuala Lumpur, Malaysia
23-25 DUG East Pittsburgh, PA
A U G U S T 2 0 1 5
11-13 MEA Gas Operations Technical & Leadership Summit
Rochester, MN
25-26 The Pipeline & Energy Expo Tulsa, OK
Oil & Gas Asia2-5 JUNE | Kuala Lumpur | Malaysia
World Gas Conference1-5 JUNE | Paris | France
Indicates TDW will present a white paper at this event
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• PIMS, PIMSS, and IMPS: The Foundations of Pipeline Integrity
• A Constantly Evolving Technology
• Accurate and Aligned: Getting the Whole Picture
• Recognizing Value
Proper pipeline integrity management yields critical information, enabling smart decisions.
Ask pipeline operators what their priorities are, and keeping their pipeline systems running optimally will consistently rank high on the list. They are always looking for innovative ways to fine-tune their operations to benefit their customers and the public. They’re even willing to share best practices to strengthen the industry as a whole. This creative, cooperative approach to optimizing pipeline operations takes on even greater importance when the price of oil is low and controlling costs becomes critical.
It’s All About the
Data
One of the most powerful means of creating or driving efficiencies is right at the operators' fingertips: By analyzing the wealth of information collected through pipeline integrity management systems, operators can better project the need for repairs, as well as control costs.
It’s true that protecting pipeline integrity is often a government-mandated, standard part of the job for operators. But the process of detecting, correcting, and preventing pipeline leaks and failures is much more than a simple set of to-do items on operators’ checklists.
Done properly, pipeline integrity management is a tremendous opportunity for companies to
cultivate critical data –
accurate, aligned data that will allow
them to make the best decisions possible to safeguard the public,
protect their assets, and control costs. And thanks to recent developments with the tongue-twisting acronyms of PIMS,
PIMSS, and IMPS, there are more tools and resources available to operators than ever before.
PIMS, PIMSS, and IMPS: The Foundations of Pipeline IntegrityEven experienced operators tend to get confused about the difference between programs for keeping pipelines running optimally – pipeline
integrity management systems (PIMS) – and thesimilar-sounding pipeline integrity management system software (PIMSS) that is available to augment the PIMS process.
“The PIMS management system is a process, and it is performed by actual people – operators, or employees, or individuals – working to make sure a pipeline system is able to perform its intended function for its design or useful life,” says Mike Kirkwood, Ph.D., a transmission market expert for global pipeline services provider T.D. Williamson (TDW).
“PIMSS is a software program that supports PIMS; it is really a digitization of the pipeline integrity management process, and it helps operators maintain compliance with that process,” he adds.
But Kirkwood is quick to point out that pipeline integrity management system software depends entirely on the implementation of a thorough, well-planned pipeline integrity management system. You simply can’t have PIMSS without PIMS.
So what does a thorough PIMS look like? In the United States, PIMS often takes the form
of what operators call an integrity management plan (IMP). The process of developing an IMP begins with gathering all available pipeline system information: Materials, diameters, inline inspection run records, active corrosion prevention measures, and more. After the operator has collected and entered all of the data, the information can be used to help predict potential problems.
Done properly, pipeline integrity management is a tremendous opportunity for companies to cultivate critical data – accurate, aligned data that will allow them to make the best decisions possible to
safeguard the public, protect their assets, and control costs.
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First, operators use the data to identify high consequence areas (HCAs) along the pipeline’s path. The criteria for HCAs differs between natural gas and hazardous liquid lines due to the severity of the potential consequences. HCAs for natural gas transmission pipelines focus solely on populated areas – environmental and ecological consequences are usually minimal for releases involving natural gas. For hazardous liquid pipelines, HCA identification focuses on populated
areas, drinking water sources, and unusually sensitive ecological resources.
With these tasks completed, the operator moves on to integrity
assessment. This could involve hydrostatic
testing, inline inspection, or non-destructive evaluation (NDE), all processes that reveal the current condition of the pipeline system. Once the operator knows the condition of the pipeline, it is possible to make decisions about what should be done – and when – to restore and maintain the pipeline’s integrity.
From there, the operator develops its management of change and quality control processes. All of this information helps the operator decide if changes to the PIMS – things like additional training or different ways of
performing inspections – are needed to better protect the pipeline and promote optimal function.
The remaining processes comprise communicating any changes the operator implements both within the company and among community members, and establishing some kind of performance measurement system. The final step usually involves setting reassessment intervals and establishing preventive and mitigation measures, such as reducing corrosion to achieve zero failures.
It’s a complicated, multistep process, and Kirkwood admits that it can be a bit daunting for operators, but the payoffs in terms of safety, efficiency, and financial return are well worth the learning curve.
A Constantly Evolving TechnologyRather than focusing on the complexities of PIMS, it can be helpful for operators
to look at it as an ongoing process of collecting as much relevant information as possible about their pipelines, sharing that information with stakeholders – such as employees and the communities – and using it to guide their decisions about pipeline maintenance and repairs.
“It’s all about gathering data, storing data, and managing information within an architecture which is easy to use, easy to access, and available to those who need it,” Kirkwood says.
That architecture should ideally take the form of a software system, which not only makes the
PIMS processes easily accessible to everyone concerned, but also helps with the tremendously important process of analyzing and fully leveraging the information that you gather.
Does one area of pipeline require more repairs than others? Has one section of pipeline been more prone to corrosion? PIMSS can help you recognize these trends and map out a plan for addressing them.
And PIMSS technology is continuously growing and evolving, so even more valuable options have been recently introduced and more are on the way. One recent development is the arrival of cloud-based data storage, which provides another convenient option for accessing and backing up pipeline data. Another new trend: Mobile options that allow operators to carry out PIMS-related tasks from their hand-held devices. The technology is similar to consumer products that allow people to start their car from inside their home on a cold day. A mobile-based PIMSS program might even allow you to ask the system to evaluate a new data set while you’re on the way to the office.
But Kirkwood cautions users not to get too dazzled by PIMSS technology too quickly.
Before purchasing a system, it’s critical to understand exactly what you’re buying, and what it is and isn’t capable of doing. PIMSS, for instance, provides helpful “snapshots” of the
condition of your pipelines, but the current technology does not harness the concepts of “big data” that can be analyzed to identify greater patterns or trends.
Accurate and Aligned: Getting the Whole Picture
To get the most out of PIMSS technology, and PIMS management in general, operators should not only be collecting data, but also taking steps to ensure they’re getting accurate, aligned data. In other words, all of the pieces of the puzzle should make sense when put together, showing exactly what is happening within the pipeline system.
In most cases, alignment requires extra effort, because the information operators gather about their pipeline systems is typically pulled from multiple sources. Putting everything together for a big-picture look at the pipeline, its risks, and the best measures for managing it can get a bit tricky. And whenever companies need assistance in this area, specialized service providers, like T.D. Williamson, are available to guide them.
“Imagine having two pieces of see-through paper,” Kirkwood says. “On one piece, I’ve got
the pipeline, and on the other piece of paper, I’ve got the defects. I’m putting one on top of the other, and I’m trying to overlay where all of the defects are on my pipeline. However, the problem is the pieces of paper are two different sizes, so the
A mobile-based PIMSS program might even allow you to ask the system
to evaluate a new data set while you’re
on the way to the office.
It’s a complicated, multistep process, and it can be a bit daunting for operators,
but the payoffs in terms of safety, efficiency, & financial return are well worth the learning curve.
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pipeline doesn’t fit on the defects, or the defects don’t fit on the pipeline.”
There are, however, technologies like the Multiple Dataset (MDS) inline inspection platform that simultaneously collect multiple sets of pipeline integrity data from a single source
– including critical information on corrosion, dents, manufacturing defects, material changes, and so on.
“With platforms like these, you get absolute alignment because it all comes
from the same tool at the same time,” says Kirkwood.
Recognizing ValueAn exciting trend in PIMS is in the area of regulation, particularly in Europe, where governments are giving operators a greater role in deciding
how to go about protecting pipeline integrity. Instead of presenting operators with a lengthy list of “do’s and don’ts” to prevent pipeline failure, more governments are asking, “Show me what you’re doing to protect your pipelines’ integrity.” The result has been greater levels of innovation and growing appreciation for the many benefits of PIMS.
This trend is encouraging. The practice of
well-crafted PIMS processes – with the assistance of carefully chosen software solutions – is proving to be an added-value proposition for pipeline operators. Every bit of accurate, aligned data that operators cull from their PIMS processes equips them to make better choices, choices that ultimately help them achieve their mission-critical goals of greater pipeline safety and increased efficiency.
Populated areas include both high population areas (called “urbanized areas” by the U.S. Census Bureau) and other populated areas – referred to by the Census Bureau as a “designated place.”
Drinking water sources include those areas supplied by surface water or wells, and where a secondary source of water supply is not available. The land area in which spilled hazardous liquid could affect the water supply is also treated as an HCA.
Unusually sensitive ecological areas include locations where critically imperiled species can be found; areas where multiple examples of federally listed, threatened and endangered species are found; and areas where migratory water birds concentrate.
HCAs for Natural Gas Transmission Pipelines An equation has been developed based on research and experience that estimates the distance from a potential explosion at which death, injury or significant property damage could occur. This distance is known as the “potential impact radius” (PIR), and is used to depict potential impact circles.
Operators must calculate the potential impact radius for all points along their pipelines and evaluate corresponding impact circles to identify what population is contained within each circle.
Potential impact circles that contain 20 or more structures intended for human occupancy; buildings that house populations of limited mobility; buildings that would be hard to evacuate (e.g., nursing homes, schools); or buildings and outside areas occupied by more than 20 persons on a specified minimum number of days each year, are all defined as HCAs.
of midstream and gathering lines is the fuel cost to gather, dehydrate, and compress the gas,” Zellou explains. “Not only does efficient liquids removal create a revenue opportunity, it also helps the operator minimize costs.
“Operators already know this simple equation: profit equals revenue minus cost,” he adds. “Using technology to generate additional revenue and control costs makes shale development less sensitive to price swings and increases profitability.”
So, where, exactly, does automation figure into the calculation? For Zellou, it fits into both the health and wealth of a pipeline. And the potential impact is enormous.
Although he’s still working to put hard numbers to the benefits Eagle Ford operators might accrue by, for example, switching to automated pig launching – using equipment that can be remotely programmed to deploy multiple spheres or pigs on a regular schedule – the preliminary figures suggest savings in the hundreds of thousands of dollars.
And here’s how that adds up: Not only can automated systems more efficiently launch spheres to capture valuable NGLs and optimize product flow (that’s the wealth part Zellou mentioned), they can dispatch cleaning pigs to eliminate paraffin, the wax that creates an environment where corrosion-causing, deadly H2S-breeding microbes thrive (which is the health part).
Automation can also reduce the blowdown
associated with opening and closing the doors during a normal pigging operation by up to 90 percent. And it increases the life of the valves used in the system because they’re operated less.
But beyond those benefits, automated, unmanned operation reduces work hours and helps protect personnel safety. And in the Eagle Ford, the well-being of the workforce has become a significant challenge.
That’s because as the region has boomed, travel along the Eagle Ford’s remote, narrow roads has become more treacherous. Crews who need to load and retrieve pigs or spheres from a non-automated pigging system may face daily trips to those lines, easily driving as much as seven hours. But with auto-launching, field personnel are on-site only twice during an entire cycle of a week or more, significantly reducing personnel travel time.
Are Lower Prices the New Norm?It could be said that for oil and gas operators, there’s no such thing as living in the present. Even the commodity pricing structure is built on futures.
So, what do the years ahead hold for the Eagle Ford? What will the new normal be? Given the complexity of the global energy market, the impulses of OPEC, and the continuing ban on American crude exports, it’s not easy to predict with complete certainty.
But what we do know is this: Automation is continuing to breathe new life, health, and wealth into the region.
HCA Definitions The Economics of EfficiencyCONTINUED FROM COVER STORY PAGE 19
28 29
Set Double Block and Monitor Tool at location
BY THE NUMBERS
Five Non-Intrusive Isolationsteps to a
Set Plug Module #1 – 100% Line Pressure
Bleed Down LP Side to 50% of HP Side
Set Plug Module #2 – 50% Line Pressure
Bleed Down LP Side to Ambient Pressure
Offshore pipeline maintenance typically falls into one of four categories: valve replacement, tie-in, riser repair, or heavy lift protection. During these types of maintenance, operators rely on non-intrusive inline isolation methods to protect their people, achieve compliance, and mitigate reductions to production. The most common isolation is the DNV-certified double block and monitor method, as seen here.
DNV-Certified Double Block and Monitor Isolation Method
28
1
2
3
4
5
LOWLINE PRESSURE
HIGHLINE PRESSURE
ANNULUS PRESSURE
Monitoring andTracking Module
DP*
Mon
itore
dD
P* M
onito
red
DP*
Mon
itore
d
*Differential Pressure
PlugModule #1
PlugModule #2
ControlModule
Annulus pressure monitored for verification of both seals 50% LINE PRESSURE
DNV Recommended Practice for Pipeline Subsea Repair Criteria (DNV-RP-F113/3): . Each barrier must be able to retain full line pressure. Independent locking system. Seal must be independently tested. Ability to monitor line integrity. Seals must be independent
from each other
Through the use of independently operated isolation barriers and continuous monitoring,
the system allows high-pressure pipeline operators to carry out remedial pipeline work in a safe, controlled, and
monitored environment.
What You Can’t Afford to Miss.
IVP.
TDW-IVP.com
DOWNLOAD THIS E-BOOK TO FIND OUT.
8
According to PHMSA, that amounts to
76,000 MILESof gas transmission pipeline.
The new regulations apply to all steel gas transmission lines — Class 3; Class 4; all high consequence areas (HCAs); and Class 1 and 2 pipe in higher risk locations, also known as moderate consequence areas (MCAs).
Eventually, these regulations will also apply to hazardous liquids pipelines.
Are your pipelines included?
PHMSA defines ‘Moderate consequence’ as “an onshore area that is within a potential impact circle, containing one or more buildings intended for human occupancy, an occupied site, or a designated Federal interstate, expressway, or 4-lane highway right-of-way, and does not meet the definition of high consequence area.”
HCA MCA
CLASS 1 1,660 (est.) 24,177
CLASS 2 1,412 (est.) 14,750
CLASS 3 15,854 (est.) 17,097
CLASS 4 752 (est.) 210
TOTAL 19,768 (est.) 56,234
HCAs and Est. MCA Mileage
Total Estimated HCA + MCA Mileage = ~ 76,000 miles
Scope of Proposed IVP Process Estimated to Apply to Approximately 76,000 miles of GT Pipeline
