Issue 2 // 2014
A publication of Chesapeake Energy Corporation
Play
The
A New Day Collaborative solutions drive top-quartile performance. //
page 10
Issue 2 // 2014 Like never before, it is a new day at Chesapeake. Our employees have driven billions of dollars in value into our company this year, creating a healthy, stable, growth-oriented business with operational performance that rivals our competitors. From drilling and completing wells more efficiently while driving down costs to capturing the most value from production operations, employees have shown us just what the new Chesapeake looks like. Fiercely competitive. Always improving. Never settling. And 2014 is just the start. This issue reflects a sliver of the many innovations and shared best practices that make Chesapeake a great business, a great
2 Focused on a Million-Barrel Future With growing production and operating efficiencies on the rise in 2014, Chesapeake aims to reach a rare production milestone within five years.
investment and a great place to work. Sarah Piowaty // Editor
On the cover Daybreak meets a Chesapeake production
Drilling All-Star Wells in the Sooner State
site on the plains of eastern Wyoming. The company is laying a solid foundation in this
Blending innovation with collaboration, Chesapeake is drilling faster wells and saving millions of dollars in the Mid-Continent South.
quickly growing operating area as it increases returns while cutting capital costs.
Contact us Email: communications@chk.com Mail: P.O. Box 18128 Oklahoma City, OK 73154-0128
Designers Amy Neal Ginny Bourke Joel Uber Contributing writer Lindsay McIntyre
PLAY The active leasing and exploration for oil or natural gas in an area; wildcatting in or on a geological trend. The Play is designed and published twice a year by Chesapeake’s Communications Department and can be viewed online at chk.com under Media. This publication includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forwardlooking statements are statements other than those of historical fact that give our current expectations or forecasts of future events. They include estimated natural gas and liquids proved reserves, production forecasts, estimated operating costs, assumptions regarding future natural gas and liquids prices, effects of anticipated asset sales, planned drilling activity and drilling and completion capital expenditures (including the use of joint venture drilling carries), and other anticipated cash outflows, as well as projected cash flow and liquidity, effects of planned debt reduction, business strategy and other plans and objectives for future operations.
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Haynesville Team Proves Time is Money From moving to 24-hour completions to cutting costs by more than 35%, the Haynesville Shale completions team takes competitive drive to a new level.
10 The Next big thing A team of employees turn a subpar operating area into a high-return, production-growing operation in Wyoming’s Powder River Basin.
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Executive SPOTLIGHT EHS Vice President Brittany Benko instills a culture of safety at Chesapeake through a heightened focus on protecting the environment, respecting owners and responsibly producing energy.
14 getting Ahead of the Curve Geophysicist Dan Shearer elevates a time- and moneysaving solution to a 3-D seismic challenge.
Inside Chesapeake Solid financial discipline and transparency with our stakeholders reinforce our commitment to being a partner of choice.
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TOP-QUARTILE PERFORMANCE CHK
CASH FLOW GROWTH CORE EXPANSION COMPLEXITY REDUCTION CAPITAL EFFICIENCY
ISSUE 2 2014 //
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Report Sarah Piowaty
focused on
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// the play
This year Chesapeake began a focused climb to reach a production milestone of 1 million barrels of oil equivalent (boe) a day in the next five years. Capitalizing on the strength of its people, healthy financials and continually improving operational performance, Chesapeake has laid a solid foundation to reach this goal with the assets it holds today.
ISSUE 2 2014 //
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Delivering Oil More Efficiently Combining field knowledge with innovation, Chesapeake’s production field teams work with the Operations Support Center to transport and sell each load of oil (180 barrels) as soon as it‘s ready for market, giving Chesapeake a competitive edge among its peers. Not only does this generate faster sales, it minimizes the risk for spills and other safety hazards.
50%+ Faster Completions in the Eagle Ford Shale Field teams dramatically improved completions cycle times in several ways, including increased multiwell padsites, shortened equipment-move times and simultaneous fracturing, when crews fracture one well while perforating another on the same pad — all leading to higher production in 2014.
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ueled with world-class assets, value-generating operations and a healthy balance sheet, Chesapeake is perfectly positioned to reach its goal of 1 million boe in daily production by 2019. While the goal requires tremendous efforts from the entire company, employees have made big gains this year to lay a solid foundation, finishing the third quarter with an average daily production of 726,000 boe. Operations in South Texas and Ohio’s Utica Shale are a microcosm of the entire company’s commitment to grow production through continuous improvement and value creation.
Careful Planning Paying Off in the Utica While Chesapeake’s Utica production was substantial in 2013, bringing new infrastructure online in 2014 and decreasing downtime has contributed to expected year-over-year 300% growth in natural gas, natural gas liquids (NGL) and oil production for the region. To produce and deliver large amounts of natural gas and NGL, infrastructure that requires years of planning, design and construction must be in place, including gathering, compression and processing
Pumping Up in South Texas
facilities. Chesapeake’s marketing division nego-
South Texas net production grew nearly 15% between year-end
tiates contracts with midstream companies that
2013 and September of this year, primarily due to improvements
build the infrastructure, which requires 18 to 24
in artificial lift installations, cycle times and controllable downtime. The results not only generated faster production from new wells, they significantly improved the base production of older wells. Artificial lift helps improve production while overcoming the natural pressure decline in wells — pressure that brings the oil or natural gas to the surface but decreases as hydrocarbons leave the reservoir. A well’s
months of planning for multiple facilities. Opening a new gathering facility can only benefit production when compression and processing capacity increase as well. “In the last two years we’ve worked closely with
production rate may drop by half after one year, and after several years pressure may be depleted enough
the Utica’s operations teams to plan and develop
to prevent flow to the surface. Artificial lift equipment helps the remaining pressure bring hydrocarbons
the infrastructure needed to support the forecast-
to the surface. This year South Texas teams committed to increasing their artificial lift installations while
ed gas and NGL production,” said Sylvain Riba of
keeping expenses in check.
Chesapeake’s Commercial Services Department.
South Texas net production increased % through Q3
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“Through constant collaboration between
“So far this year, the new facilities have increased
teams in the field and in Oklahoma City, we now
our daily processing capacity by 200,000 cubic feet
average 10 installations per week, up from just
and compression capacity by 335,000 cubic feet.
four earlier this year,” said Geno Hill, Operations
With additional capacity coming later this year, we’ll
Manager – South Texas. “And once a well’s arti-
have another 150,000 in processing and 110,000
ficial lift is installed, production technicians and
in compression each day.”
operations engineers continue evaluating and mak-
As in South Texas and other Chesapeake
ing adjustments to ensure each one is as efficient
operating areas, reducing downtime in the Utica
as possible.” As a result, each well’s daily average
also leads to faster sales. By the end of the third
rose 40 boe per day. Even more impressive, while the number of installations increased, their costs did not
quarter Utica field teams surpassed the number of
— the teams are under budget by 22%.
wells turned to sales in all of 2013, with an expect-
The region also reduced cycle times, contributing to higher production — the less time spent drilling, the faster a well begins producing. In the last year South Texas cut drilling cycle times by 11%, in part by
ed year-end improvement of more than 25%. “We’ve right-sized our production facilities and
implementing a spudder rig program, where a smaller, specialized rig sets the surface sections instead of a
optimized our scheduling to maximize pad produc-
conventional big rig. While the spudder rig prepares surfaces, the big rig travels from well to well, drilling the
tion and bring wells to sales faster. Also, our lease
production section and moving wells to production sooner.
operators continue to improve downtime, which this
“We’re drilling more wells with the same number of big rigs by cutting two to four days off cycle times when we use spudder rigs,” said Jason Stidham, Manager – Drilling, South Texas. “Currently we use spudder rigs on about half of our new wells, and we intend to ramp that up to 100% in 2015.” Finally, South Texas teams implemented several
Downtime in the Utica dropped to from
36 12 %
initiatives to reduce controllable, equipment-related
%
year we’ve cut from 36% to 12% between the first and third quarters,” said Matt Rucker, Production Superintendent. “Everyone’s perseverance and teamwork has been
downtime. Through collaborative efforts field and technical teams continue to identify trends and execute
amazing, from managing the long-term planning to
solutions to optimize production, which has contributed to decreasing controllable downtime from 25%
how well our field teams have optimized our oper-
to 10% since January. The teams also added new night lease operators to bring producing wells back
ations. Going forward, we’re focused on continuing
online quickly should one go down overnight. In the past, overnight production interruptions could not be
to capture the most value from our assets and
corrected until daylight.
facilities to keep growing this strong company.”
ISSUE 2 2014 //
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// the play
Report Sarah Piowaty // Photography Megan McAtee
hile the shortest distance between two points may very well be a straight line, when time is money and your goal is reaching your destination as quickly and safely as possible, you want to make sure you know everything about that road — where you should downshift, where the road is rough and when you can let cruise control take over. At Chesapeake, a group of drilling engineers and the company’s Operations Support Center (OSC) work together to provide teams in Oklahoma’s Mid-Continent South district with an ideal drilling road map for each new well in the district — the result of modeling previous wells successfully drilled in the same area. They are one of many Chesapeake teams elevating innovative ideas and driving top operating performance. Since work began in the second quarter of 2014 with wells in the Colony Wash area, the teams have cut average drilling days by 24% compared to 2013, saving more than $1 million per well. The OSC opened in 2011, when its drilling analysts began gathering real-time drilling data while monitoring a small number of Chesapeake wells 24 hours a day. Its capacity grew, and in 2012 the OSC began monitoring Mid-Continent South wells, capturing drilling data nearly every second. OSC teams now work closely with Mid-Continent South drilling engineers, who are responsible for designing every well. The OSC introduced the engineering team to its new offset analysis tool, designed to capture more value from historical drilling data. Brainstorming ensued, and together they created a pilot program for step-by-step optimized drilling. “It truly is a combined group effort,” said Jake Waddle, Engineering Analyst II and the OSC’s project lead for the program. “Knowing the next well to be drilled, the drilling engineers select up to five previously drilled wells in the same area, known as offset wells. The tool takes the real-time historical data of the offset wells and creates ideal parameters for drilling.” OSC drilling analysts use the tool to determine each offset well’s rate of penetration (ROP), or drilling speed, through each section. For example, if between 5,000 and 5,200 feet “Well A” drilled the fastest, its operating measures at that depth — such as weight on the drillbit and the drillbit’s revolutions per minute — become the model for the new well at the same depth. The district’s drilling engineers help finalize the parameters for each section of the new well, including a target ROP with top and bottom thresholds. The information is then communicated to the drilling superintendents and company men in the field. “Colony Wash wells are very similar in structure throughout the formation, so it was an ideal area to
Colony Wash Performance
test this new process,” said Nathan Bland, Drilling
average depth of wells: 17,200 feet
Engineer II in the district, who credits collaboration
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among the OSC, drilling superintendents, company men and drilling contractors in the field with the fast results. drilling section in each of the first two wells we drilled.” While planning is critical, evaluating and tracking progress is at the heart of Chesapeake’s commitment to continuous improvement. During drilling the OSC’s drilling analysts overlay each well’s road map with the real-time drilling data coming from the rig. It’s one large moving graph that shows, among other elements, the
Average Drilling Days
“The field team cut about two days off of just one
2013 average
days
35
2014 Q3/Q4 average
days
30 days
record WELL Rig Release: 8-23-14 Goeringer 33-11-16 1H
current ROP in relation to the target and established thresholds. A hit to any threshold triggers an alert to the drilling engineers and field drilling teams, who also receive hourly updates. If the ROP isn’t where it should be, Bland and the drilling superintendent or on-site company man can discuss solutions, try a new parameter and, through the OSC’s monitoring, quickly see whether it helps. At other times, the company man knows immediately what adjustments need to take place. Drilling superintendents such as William Daniel rely on their richly experienced teams to effectively combine their drilling expertise with the benefits of this new technology. “I have quite a set of guys who just love what they do and are amazing at drilling great wells. While they closely watch the parameters, they also have vast drilling knowledge, and that combination is why we’re drilling such fast wells,” said Daniel. Every morning Daniel sends drilling reports to his district field teams, who see every rig’s progress — a point that he says sparks competitiveness and The road ahead — Inside Chesapeake’s Operations Support Center, teams watch and
pride every day.
evaluate real-time drilling progress overlaid on the model road map. Drilling Engineer Nathan Bland (standing) along with Engineering Analyst Jake Waddle.
ISSUE 2 2014 //
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t’s 2 a.m., and through an opening in the thick Louisiana
in these wells while fracturing and in doing so they set the standard for improved
forest you can see the Chesapeake drilling and completions
and safe SIMOPS practices. Modifying SIMOPS practices also allowed teams to
teams out in full force, working side by side, a constant whir
fracture wells while drilling other wells on the same pad, creating the “superpad.”
of pipe moving, trucks hauling and fluids pumping. Drilling teams have always worked around the clock, but
“We worked with several teams to optimize 24-hour operations and SIMOPS,” explained Carl Meyer, Completions Superintendent. “It was exciting to
for completions teams it’s sometimes new territory. And Ches-
hear everyone’s ideas during those discussions and explore the ways we could
apeake’s Haynesville Shale completions team knows what it
significantly improve our operations.”
means to be efficient and be in line with the company’s goal to be a competitive low-cost provider in the area, providing maximum shareholder return. Committed to generating the most value from their operations while maintaining production quality and safety, they
The process of cost leadership and elevating efficiency didn’t stop there. “Everyone started looking at each stage of our operations differently, determined to identify ways to keep progressing,” said Finney. They evaluated the amount of chemicals needed during stimulations and cut out unnecessary agents while main-
implemented a 24-hour operations cycle and cut costs.
taining high production performance, saving an additional
Wells that cost $3.9 million to complete in Q3 2013 now
$300,000 per well.
come in closer to $2.8 million. “With a goal of reducing cycle times and costs, and constant contact between the field and technical employees, we seized the opportunity to collectively find ways to improve the entire completions process,” said Patrick Finney, Manager – Completions, Barnett & Haynesville. It began in October 2013, when teams mapped out each stage of the drilling, completions and production processes. They found ways to modify
The efficiencies in the Haynesville have increased production and decreased downtime all without sacrificing the environment or safety of Chesapeake’s employees and contractors. “We strive to protect our people and our environment while delivering our company goals. We work side by side, maintaining the focus of another workday in the oilfield,” said Finney. And the Haynesville team continues to find ways to keep the environment
simultaneous operations (SIMOPS) and implemented 24-hour operations,
and safety in the forefront while increasing efficiency and cutting costs.
leading to a 64% reduction in cycle times from Q4 2013 to Q1 2014 and
“When we see results that maximize the return for our share-
savings of $100,000. SIMOPS (temporarily shutting in one well to drill or complete another well on the same pad) halts production on the shut-in well. The team aimed to not shut
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holders, we’re driven to generate more value from everything we do. We want to keep improving. It all comes down to teamwork — finding better ways to do things.”
Report Erica Smith
Driving down costs and returning the best value meant looking at new concepts. One is the use of ball seat subs, eliminating the need for cleanouts or drilling out plugs. This comes at a cost savings of $200,000 per well and gets wells completed up to six days faster. This process shows that through basic engineering design, the team was able to generate huge savings.
Another game-changer for the completions team has been the use of two coiled tubing units (CTUs) simultaneously on the same pad. On a four-well pad, two CTUs are rigged up, keeping rental costs the same as using one CTU at a time, but cutting cycle time in half. Instead of two days completion time per well spent on coiled tubing jobs, it’s now two days per two wells. Outside costs are the same, but the job is done twice as fast.
The sun is rising on Chesapeake’s Wyoming operations. Miles below the rolling hills of sagebrush and honey-colored cheatgrass, there is a complex geologic formation that Chesapeake is beginning to unlock, and after five years is reaping major results. The efficiencies seen in the oil-rich Powder River Basin are one of the company’s many success stories from 2014, going from $12 million in costs per well (spud to completion) down to nearly $9 million while increasing production.
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Report Emma Flinton
ISSUE 2 2014 //
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C
hesapeake entered the Powder River Basin in 2008. While the
drilling problems. The first major change came when geology and drilling worked
play looked promising initially, in 2012 the company was drilling
to move the target window 15 – 30 feet above the original zone, the Niobrara.
subeconomic wells with marginal returns. In late 2013, with a
“The Niobrara was the source rock we cracked first, and that petroleum
new competitive capital allocation program — where operating
system feeds the many stacked plays above it, which includes the Teapot, Park-
areas within Chesapeake vie for capital — the competition
man, Sussex, Shannon and others,” explained Rockies Geoscience Manager
was just too stiff as other areas were showing greater returns.
Ken Rechlin. “It’s a legacy basin, so we already know where the oil is. It’s just
Powder River Basin operations went from 11 rigs down to three,
a matter of producing it economically.”
and the future of the play was uncertain. “In the past, significantly cutting the rig count of an area would have led
Adjusting the target not only reduced drilling days and costs, it also gave the teams the opportunity to test a revised well design. The drilling group was able
to low morale,” said Jim Govenlock, Vice President – Rockies Business Unit.
to downsize their casing strings — multiple layers of heavy steel casing and
“However, this team understood that slowing down gave them the opportunity
cement that provide a protective barrier between production and the shallow
to re-evaluate what was best for the play.”
formations — to a slim well design that saved nearly $500,000 per well with-
Rockies Drilling Manager Darrel Overgaard agrees. “We were running very fast and in many directions. Although a busy district is a great opportunity, we knew slowing down would be an even greater opportunity to learn from the past, focus on the problems, implement changes and prove our value to the company,” he said. They did indeed. In addition to bringing down the cost per well, spud-to-spud cycle times
out compromising wellbore integrity. While these changes were great for the drilling engineers, it gave the completions team a few challenges. None they weren’t willing and ready to tackle. “Not only did we go to a harder-to-treat rock, but we were also limited in the amount of pressure we could use. We have taken those challenges in stride and continue to work on the overall design,” explained Julian Carrillo, Rockies
dropped from 45 days down to less than 30 days with longer laterals, contribut-
Completions Manager. “Communication between the teams has been huge in
ing to average well costs decreasing by more than 30%.
understanding each other’s needs, challenges and sometimes even sacrifices.”
These efficiencies began with Chesapeake’s transformation in 2013. The
The completions team continues to find creative ways to optimize their
company moved to a business unit structure where geology, drilling, comple-
fracture design to place higher sand volumes at lower pressure. Even though
tions, production and engineering work together in one asset with a common
the team was no longer exclusively targeting the highly fractured interval of the
goal of driving financial discipline and finding new growth opportunities. Across
Niobrara, fracturing from directly above still provided access to the sweet spot of
the company teams were starting to work smarter and more efficiently. And the
cost and production they needed to make it competitive for capital.
Rockies team was no exception. Every piece of the well life cycle was reviewed and evaluated, from design to pad layouts to production facility design; nothing was off limits. The Rockies
“The progression from novel idea to value-adding solution could not have occurred without a collaborative effort,” said Casey Miller, Rockies Supervisor – Planning and Logistics.
team first went back to the geology to reimagine what this play could be. Geologists had identified the best rock in the formation, but the target zone was naturally fractured, resulting in millions of dollars of mud losses and other
Collaboration Solidifies a Second Chance The future is bright for the Powder River Basin. So bright that the company recently made a large capital investment through a deal with RKI Exploration and Production.
While well costs have decreased by 25%, production is on the rise
Since 2010, Chesapeake and RKI jointly owned and operated acreage in the Powder River Basin, splitting the area into northern and southern portions. While Chesapeake operated in the south and RKI operated in the north, each company had a working interest — a share of the revenue — in both portions.
— the company expects to recover more than 2 billion barrels of oil in the region.
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Powder River Basin Geologists Rachel Keng and Brian Varacchi work to unlock the area’s value at Chesapeake’s Oklahoma City headquarters.
Lease Operator Peter Curry and Production Technician Jolene Cotton discuss production numbers in Converse County, Wyoming.
Chesapeake recently ended that arrangement, giving RKI its acreage and
Sustainable Infrastructure
working interest in the north, along with $450 million. In exchange, Chesapeake
43% of Chesapeake’s current Powder River Basin production is oil,
received RKI’s acreage and working interest in the south, which more than dou-
40% is dry gas and 17% is natural gas liquids. The only current option
bles its current interest. The area includes the Niobrara and five additional forma-
for gas takeaway is through one gas processing plant in Douglas,
tions, many of which are on track to produce more than 40% rates of return.
Wyoming. While the facility does not have the capacity for all of Ches-
“This deal was a terrific endorsement to us up here and gave us confidence
apeake’s production, the pressure will soon be alleviated. A new plant
in our rate of return and our area as a whole,” said Wyoming resident and Pro-
will give Chesapeake a capacity of 120 mmcf per day, more than three
duction Superintendent Brandon VanderVoort. “We now know we have what it
times its current takeaway capacity. The new infrastructure will provide
takes to deliver and be a key asset for the company, and that is very exciting.”
for more takeaway than Chesapeake has ever had in the area, further
Employees in this asset are prepared and ready for increased activity. A focus
fueling the Powder River Basin’s profitable and efficient growth.
on continuous improvement coupled with Chesapeake’s financial commitment to the Powder River Basin further cements Chesapeake’s place in Wyoming. “2015 will be our year to demonstrate all we can do as an asset. It’s our time to execute and show that when all of the teams work together for a development, this is what can happen,” said Sheldon Burleson, Manager – Production, Rockies. Chesapeake now expects to recover more than 2 billion barrels of oil in the region.
A new gas processing plant will soon give Chesapeake more than
3X
its current takeaway capacity.
ISSUE 2 2014 //
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Ahead Curve Seismic data licensed from GPI/GOK
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Report Erica Smith // Photography Megan McAtee
N
ot long ago, a typical exchange between a Chesapeake
minutes. It was released to the market in 2012 and now takes only 30 seconds
geologist and geophysicist would go something like this:
to convert time to depth for a 25-square-mile area around a single well. It has
Geologist: How deep is the Marcellus Shale?
been extremely successful.
Geophysicist: 0.791 seconds
“The business unit has cut drilling time in half, with no geologic sidetracks
While the geophysicist is correct, it doesn’t help the
since 2012. We now know what’s happening thousands of feet ahead of the bit,”
geologist, who refers to the depth in feet. The time, 0.791
said Shearer. “Chesapeake is changing the industry because of how we look
seconds, is the time that it takes for a sound wave to travel from
at steering wells through shales. This is truly game-changing. It allows effective
the surface down to the formation and back to the surface. But
multidisciplinary collaboration in a common language — depth. With this soft-
the rest of the industry talks in depth — measured in feet. The drilling team and
ware solution, we can, in minutes instead of hours, compute the localized depth
geoscientists could see the Marcellus on seismic in time, but without accurate
conversion and very accurately predict the geology ahead of the bit.”
depth conversion along the horizontal part of the well, there was less certainty in placing the bit and planning the lateral.
The margin of error has dropped from hundreds of feet to tens of feet, and rig line geologists now spend considerably less time geosteering their wells,
To get everyone talking in the same language, Senior Geophysics Advisor Dan Shearer created an industry-changing 3-D depth conversion procedure for
while still placing the bit in the best rock. Chesapeake, along with the rest of the industry, now uses this method in several other operating areas.
horizontal wells that reduces drilling times while increasing production from the Marcellus. But getting there wasn’t easy.
“We’re able to drill more structurally complex horizontal wells faster and cheaper. We can map out the subsurface and plan much more effectively,”
Prior to 2009, time-to-depth conversion along a horizontal well was an
said Shearer.
arduous and time-consuming process. Teams would drill down until they found the formation, sometimes sidetrack (where a second hole would have
“Dan saw a problem and elevated a solution,” said Northern Division Senior Vice President Chris Doyle. “That solution was so innovative that it
to be drilled to bypass a problem area in the first
immediately enhanced communication
hole) and then drill the well where it belonged.
and drove significant improvement in
Sometimes the drillers had to back up and try again multiple times. This was very expensive, requiring a great deal of manpower and time. While the first time-to-depth conversion application was
Software provides: > Better predictive model > More accurate predrill plans
targeting, ultimately having a direct impact on Chesapeake’s capital efficiency. This is a prime example of what we are encouraging our employees
developed in 2010, multiple sidetracks and other
> Ability to refine the model while drilling
to do in line with our core values —
costly issues still remained.
> Greater percentage of wellbore in the zone
pursuing continuous improvement and
By early 2011, Chesapeake was operating
always seeking to deliver more than
24 rigs in northeastern Pennsylvania, part of the
Below: Geophysicist Dan Shearer’s 3-D depth
what is expected. And that is exactly
Marcellus North region. Geosteering was extreme-
conversion procedure reduces drilling time while
what Dan did.”
ly difficult. The area was structurally complex
increasing production.
with hundreds of faults, had rapid structural dip changes, large salt features and limited 3-D seismic data. Sudden and unanticipated structural changes slowed drilling and resulted in multiple sidetracks. Shearer created an initial solution, but it involved complex calculations that required keeping track of every step and file name, taking a full day and night of intense concentration. If a simple typo in a file name or other mistake was made, he would have to start again. The procedure worked, but with 24 rigs operating at the time, it was inefficient and hard to manage. Shearer worked with a seismic interpretation software company to develop an automated module that generates the conversion in just seven to 10
ISSUE 2 2014 //
15
Inside
A closer look at our people and progress
EXECUTIVE spotlight: Creating a Culture of Safe and Responsible Operations
S
afety is personal to EHS Vice President Brittany Benko. In 2010 she
“I can’t give good EHS advice until I understand our business, and our business
worked in environment, health and safety (EHS) for BP; the same year
happens out in the field,” she added. “By gaining more field knowledge, our EHS
as the Deepwater Horizon oil spill, the largest oil spill in U.S. history and
team members are becoming trusted advisors to our operations employees. This
one that claimed 11 lives.
partnership will enable us to operate even more responsibly.”
“My most poignant moment after the spill was when we called off the search for
Among Chesapeake’s core values, Benko relates most closely to respect and
our missing co-workers. In that moment we were admitting that 11 men had lost their
change leadership, as they directly impact continuous improvement throughout
lives. That’s why safety is so personal to me — you don’t get lives back,” she said.
Chesapeake. She views EHS as having a key role in supporting the company’s production growth goals starting by
Benko, a third-generation oil and gas industry veteran, spent a year
decreasing incident rates and the
working on BP’s spill response team,
number of spills. One way the EHS team is working
including meeting with Gulf Coast
to reduce incidents is by instilling
state leadership and community members directly impacted by the
a safety culture at Chesapeake. In
blowout and spill. This experience
2014 the company’s safety experts
might have disillusioned most, but for
launched a yearlong campaign to
Benko it helped shape her commit-
raise awareness among employees
ment to EHS.
about potential workplace hazards. From January through October 2014
“Because of the energy we discover and produce, people can enjoy a high
the company reduced its total record-
quality of life,” said Benko. “I’m proud
able incident rate by 29% compared
of what we do, but I am also acutely
to the same period in 2013. “A safety culture means that
aware that we can impact people, the environment and the communities
everyone understands that every
where we live. We can produce energy
day they make decisions that impact
in a way that is respectful, and EHS is a part of how we do it.” A scientist with undergraduate and graduate degrees in zoology, chemistry and biology, Benko’s career at BP spanned 12 years. As BP’s strategy shift-
EHS Vice President Brittany Benko joins CEO Doug Lawler in a commitment to responsibly producing oil and natural gas while protecting the environment, the public and employees.
“If you’re a safety and environmental person, onshore is the most interesting
co-workers. It means that every day our employees are able to go home to their families because they have made safe decisions at work,” she explained. “We are committed to
ed to more offshore activities, Benko turned her attention to Chesapeake as a leader in domestic onshore energy production.
the safety of themselves and their
compliance, but what we’re really striving for is a culture. We want a belief system built on safety, responsibility and respect that centers us as a company.”
and challenging,” she said. “With onshore development you interact more with
Benko’s optimism and professionalism serve as the foundation for the EHS
people and work to find mutually beneficial solutions that respect our owners,
team’s mission to keep employees safe and focus on Chesapeake’s environmental
protect the environment and allow for responsible energy production.”
compliance.
Benko has challenged her department to improve their technical skills and
“We have already seen a significant improvement in our incident rates, but we
better understand Chesapeake’s operations by spending time outside of the com-
must do better. We can always be better,” Benko said. “When we honor our core value
pany’s Oklahoma City headquarters. She often refers to her choice to train in the
of respect, when we make responsible decisions and when we challenge ourselves to
field as one of her best professional decisions.
improve, we will be at the forefront of the country’s most influential industry.”
16
// the play
The New CHK.com Visit chk.com today, recently redesigned to improve the experience for our
2013 Corporate Responsibility Report
stakeholders with easy-to-find content, including owner resources, investor
Chesapeake’s commitment to
information and overviews of each operating area. The site is also optimized
becoming a partner of choice includes
for mobile devices, making it easy to navigate on any platform.
being transparent about our operations
LEADING A RESPONSIBLE
Energy Future 2 0 1 3 C O R P O R AT E R E S P O N S I B I L I T Y R E P O R T
and clear in our business strategies. Our Corporate Responsibility Report highlights our 2013 activities and addresses issues important to us and our stakeholders, including corporate governance, environmental, health and safety and community and employee engagement. Read the report at chk.com/responsibility.
Focused on Financial Discipline Chesapeake continued growing production while reducing capital expenditures and cash costs during the third quarter of 2014, further demonstrating its commitment to creating value for its stakeholders while building a sustainable, growth-oriented company. Additional progress includes:
•
The sale of southern Marcellus and eastern Utica assets for $5 billion
•
Two-notch upgrades this summer from Moody’s and S&P
•
Removing $6 billion in leverage from its balance sheet in the last two years
For the sixth year in a row, thousands of employees made a difference in their communities this summer through Operation Blue, the company’s annual volunteer campaign.
ISSUE 2 2014 //
17
Chesapeake Energy Corporation P.O. Box 18128 Oklahoma City, OK 73154-0128
PRESORT STANDARD U.S. POSTAGE PAID Oklahoma City, OK Permit No. 605
Strong. Dedicated. Focused.
Integrity, trust and respect are the foundation for every decision we make. This year we have driven billions of dollars in value into our company — something that could only happen with a workforce of outstanding employees committed to continuous improvement, creating value for our stakeholders and building a business positioned for long-term growth. We are Chesapeake, and we are leading a responsible energy future.