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The Play: Haynesville Shale

Rigging up the Haynesville
By Cheryl Hudak

Rigging up day is an exciting event at every drillsite. Crews are alert as the massive derrick swings up from the ground, critical connections are made and checked, and a giant crane lifts the bright yellow top drive to its final working position on the mast. There is an almost electric atmosphere that says this is the moment when the action really begins.

That atmosphere pervades the entire area known as the Haynesville Shale. Here, where piney woods obscure the border between Louisiana and Texas, there is a sense that the action is just beginning. 

Nomac #18 rigs up.

Chesapeake is rigging up another well in the Haynesville Shale. The company’s first Haynesville Shale well was drilled three years ago. But the feeling is strong that 2010 is only the beginning for development of this vast natural gas field. With estimated ultimate reserve recoveries of up to 300 trillion cubic feet of natural gas, it’s clear that Chesapeake has only reached the early stages of development in the Haynesville.

“At the current U.S. rate of consumption, the Haynesville Shale alone could fuel the entire nation for more than 10 years,” said Haynesville Production Superintendent John Cogar.

Chesapeake is the largest leasehold owner in the 3.5 million acre play. In three action-packed years, the company has become the largest driller in the Haynesville with 35 rigs currently working. It has 107 drilled and completed wells producing 535 million gross cubic feet per day (mmcf/d) of natural gas. And it has increased proved reserves from 135 to 715 billion cubic feet of equivalent (bcfe) as of September 30, 2009.

Geologically, the Haynesville Shale has some unique characteristics. According to John Sharp, Chesapeake’s Haynesville Geoscience Manager, the play is a young one, as far as shale rocks go.

The proud crew, dubbed the “Fastest Crew
in the Haynesville Shale,” shaving 10 days
off the average drilling time of 45 days.

“The Haynesville is a Jurassic-aged play, about half as old as the Paleozoic Era Barnett Shale in North Texas, the Fayetteville Shale in Arkansas and the Marcellus Shale in Appalachia.” Sharp explained. “The Haynesville rock has a high clay content, and it is deeper and higher pressured than many other shale plays. That high pressurization began about 150 million years ago when organic matter within the shale began to break down and create gas.  Because the shale and surrounding rock were so impenetrable, the gas couldn’t rise up and seep into what we call ‘conventional reservoirs.’ It was trapped in the source rock for millions of years, ballooning up with pressure. That abnormally high pressure makes the Haynesville Shale a wonderful natural gas play economically because it means high production wells.”

But high pressure also presents drilling and production challenges. 

“Historically, our Louisiana operations were primarily lower pressured, so we are bringing local vendors up to the standards necessary for high-pressure well drilling,” said Chuck Duginski, District Manager, Haynesville East. “We brought a number of people with high-pressure development experience from Oklahoma, Texas and other areas where we operate.”

The excitement of the Haynesville is compounded by the fact that the massive play was a Chesapeake discovery.  Sharp credits this success to the company’s emphasis on knowledge sharing among its geoscientific teams.

Double the fun! Nomac rigs #22 and #18 drill opposing horizontal laterals
simultaneously on one Haynesville Shale superpad, creating efficiencies while
reducing the environmental footprint.

“The geological side of our business is all about new ideas, and sharing the knowledge among the people in our Big 4 shale plays (the Barnett, Fayetteville, Haynesville and Marcellus shales) really does make a difference.  We are always brainstorming, discussing concepts, ideas and interesting ways to go about getting gas into the pipelines.”

“We were the Haynesville’s first movers geologically and in leasing,” said Sharp. “That makes this play even more special to us.  There really is no history in the Haynesville Shale. We’re writing it now.”

Making that history is a thrill to men like Sharp. “I’ve spent 26 years in this industry, always looking for that next 50 bcfe opportunity.  In the Haynesville Shale, we have hundreds of sections in a row, EACH containing 50 bcfe!  I have never seen anything like this.”

Dave Wittman, District Manager - Haynesville West, noted the company’s position of leadership. “We’re still very early in this play. Chesapeake is still leading the way. We’ve evolved and our completion techniques are getting better on these very high-pressured wells.  Everything here is more intense.”

Another unique aspect of the Haynesville is the fact it had gathering infrastructure in place when the play was discovered. “We really thought all along that the Haynesville would be big,” Wittman said, “but I don’t know if we thought the wells would be quite as strong as they are.  Our biggest challenge last year was getting wells tied into the pipeline. Now, it’s just having enough pipeline!”

Pipeline crews work to accommodate rapidly increasing production.

The existing system was not equipped to accommodate the field’s immense production.  As a result, pipeline construction caused some involuntary production curtailment in the Haynesville in October 2009.  Today a new processing/sales point is being constructed in DeSoto Parish by Chesapeake Midstream Partners, capable of running 1.0 bcf per day into the Tiger and Centerpoint interstate pipelines.

The play’s sprawling boundaries have also expanded beyond its original gathering systems.  “We’re building an entire transportation system – more than 400 miles of pipeline here,” said Duginski.  “We’re about halfway there.”

Extensive activity in the play has necessitated the division of the Haynesville into West and East districts.  The West side encompasses most of Caddo, Bossier and parts of DeSoto parishes, as well as the Texas portion of the play.  Haynesville East includes most of DeSoto Parish and Sabine, Red River and parts of Caddo parishes.  Plans were recently announced for the construction of a new field office near the town of Mansfield in DeSoto Parish to support activities of the Haynesville East operations.  The Haynesville West office is housed in the Bossier Parish town of Sligo, Louisiana, just southeast of Shreveport.

Flow testing on a new well

This growth is good news for Chesapeake. It is also good news for the people who live in the geographic region.

“The impact on local residents is huge,” said Cogar.  “People are really happy to enjoy the royalties paid for minerals.  There are new jobs here, and local businesses are prospering.  Also, increasing tax revenues are allowing communities to prosper.  That’s a wonderful thing.”

Duginski shares that enthusiasm. “We’ve made a very active effort to be the leader. I think the Haynesville is sort of a Chesapeake flagship.  It was our discovery and our decision to put our company’s name in front of municipalities and regulators here in Louisiana.  We are being challenged to live up to our standards of being good partners – showing that we can be good neighbors, protecting the environment while developing resources.  That’s an amazing part of the Chesapeake ride, isn’t it?  We’re very proud of that.”

Another layer of opportunity in Louisiana

Nomac rig #55 drills in a hay field.

The future of northwestern Louisiana looks even brighter with the announced development of another natural gas source, the Bossier Shale, a second shale formation that overlaps a core area of the Haynesville.  Imagine one gas field located on top of another: the Bossier lying about 500 feet above the 10,000 to 13,500-foot-deep Haynesville.

Chesapeake’s 175,000 net acres of Bossier Shale leasehold may hold risked, unproved reserves of around 2.3 trillion cubic feet of natural gas and unrisked, unproved reserves of around 9 trillion cubic feet.

The company drilled an initial  Bossier Shale test well, the Blackstone 26 H-1 in DeSoto Parish, in August 2009, which averaged 8.1 mmcfe/d of production for its first 30 days.  Chesapeake is currently drilling a second Bossier well and plans to have wells producing both the Bossier and Haynesville shales simultaneously – from shared “superpads.”

“The better parts of the Bossier are as good as typical Haynesville,” said Duginski.  “And our lease terms generally give us mineral rights through the deeper Haynesville, so we’ve already got rights to the Bossier.”

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The Technology: The Engineering Technology Group

Ahead of The Curve
by Laura Bauer

Sharing information from play to play improves efficiencies, saves money

“We have story after story of how our ability to share information across departmental and district lines has saved Chesapeake valuable time and money.”

To be competitive in the natural gas and oil industry, it’s critical to stay one step ahead of the curve. Chesapeake stays ahead of the competition by sharing information across the company from one district to another. In fact, the company has a team of more than 20 employees dedicated to accomplishing just that.

Chesapeake’s Engineering Technology and Special Projects Group works across all areas of the company to evaluate technology, ensure best practices are being implemented, and help share information from one play to the next.

“Most organizations don’t have a ‘company centered’ group that works with all plays to leverage information and reduce learning curves,” explained Keith Yankowsky – Manager of Engineering Technology & Special Projects. “Our group is responsible for making sure that what was learned in one play is applied to the next.”

Alan Byrnes, Senior Petrophysicist; Jennifer
White, Petrophysicist; and Tim Beard, Asset
Manager, collaborate on the company’s future
drilling activities.

For example, in the Barnett Shale Play of North Texas it took more than 10 years to perfect the completion process. This process was applied from the outset in the Marcellus Play in the northeastern part of the United States, greatly reducing the learning curve and expediting operations. 

“With the Engineering Technology Group working closely with our Unconventional, Petrophysical, Reservoir Technology Center  and Asset teams, we started high on the learning curve in the Marcellus Shale, and as a result, have been very efficient,” said Yankowsky. “By leveraging our experience and knowledge, we were able to apply our latest technology and designs to the play optimizing well performance at an early stage of the development. We continue to fine tune our approach – always striving to improve.”

How do they do it? The Engineering Technology Group has a company-wide focus that extends across all of its plays.

“We look at everything that’s working and find ways to implement new ideas to save time and money,” explained Yankowsky. “We work jointly with our Unconventional Group, Petrophysics and the Reservoir Technology Center to see how all the components fit together. A large part of our job is making sure everyone has support to complete their projects.”

Yankowsky’s group meets daily with different districts so they are always in the loop when it comes to new challenges and triumphs.

“We see ourselves as a service department – providing consultation and solutions for any number of departments,” he explained. “Every day, we get calls from various districts asking us to research possible scenarios so we can approach operations in the smartest way possible.”

No area is excluded from the Engineering Technology Group’s watchful and helpful eye.

A frac job in the Barnett Shale, this photo, paved the way for
fracing efficiencies in the Marcellus Shale.

They continually examine longer-producing plays to determine if there is any new information that will improve efficiencies. The group has had success in the Barnett Shale by working with the Asset and Reservoir teams implementing ideas from recently discovered plays and successfully reapplying them in the Barnett.

“We implemented some new design parameters from the Eastern Division to make our Barnett wells more productive,” said Yankowsky. “This has enabled us to optimize existing core assets by simply sharing and applying information.”

The information-sharing process also extends to Chesapeake’s commitment to protecting water resources, a significant part of the drilling and completion process. The group is constantly looking at new methods of water conservation and reclamation, the process by which produced brine is cleaned using mechanical or thermal processes. Reclamation allows water to be returned to the environment safely or reused in operations, reducing the requirement of freshwater for future wells.

The unique urban environment and frequent drought conditions of the Barnett Shale have put this play at the forefront of Chesapeake’s water reclamation evaluation efforts, explained Rick McCurdy, Advisor - Chemicals and Water Reclamation. “Lessons learned in the Barnett have allowed Chesapeake to more rapidly address produced water issues in the Marcellus Shale.”

Chesapeake also recently developed a process in the Marcellus where produced brine from the initial flowback process is cleaned and reused for the completion of subsequent wells. This process not only conserves freshwater, but has resulted in an operational cost savings of more than $6 million per year. Based on this success, Chesapeake is now looking at brine reuse opportunities in all of our major shale plays.

The team doesn’t just focus on operations; they also look at financial and cost aspects to ensure Chesapeake is getting the best prices by leveraging bidding from play to play.

According to Operations Accounting Supervisor Tim Haladay, his team examines service costs from similar companies across the company’s operating areas to guarantee Chesapeake is getting the best deal and is being charged appropriately.

“Our group looks for trends in billing practices and pricing agreements from various districts,” he explained. “And we share this with production foremen, superintendents and others so they know what to watch out for in terms of incorrect billing.” 

This practice has saved Chesapeake tens of millions of dollars according to Haladay.

“We have story after story of how our ability to share information across departmental and district lines has saved Chesapeake valuable time and money,” said Yankowsky.

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The Play:

Texas Panhandle Granite Wash
by Cheryl Hudak

Q: What is better than a natural gas well with estimated ultimate recovery of 4 billion cubic feet?

A: A natural gas well with estimated ultimate recovery of 4 billion cubic feet PLUS 180 thousand barrels of oil!

In these days of $75/barrel oil, it’s the PLUS that brings smiles to companies like Chesapeake who are exploring and producing in the Texas Panhandle Granite Wash.  Attractive finding costs of approximately $1.50 per million cubic feet, compared to $2.50 costs in some fields, make the play even more attractive.

The Texas Panhandle Granite Wash is not a shale, although it requires similar horizontal drilling and hydraulic fracture stimulation techniques.  It is one of several granite wash plays that lie below much of the Anadarko Basin.  The eastern edge of the Greater Granite Wash extends across six western Oklahoma counties where it is known as the Colony Granite Wash.  Farther west, the formation regroups and is known as the Texas Panhandle Granite Wash as it begins in Roger Mills County, Oklahoma and crosses the state line into Wheeler, Hemphill and Roberts counties of Texas. 

Cumulatively, these various granite washes have the potential to be the largest non-shale resource play in the Mid-Continent and a very important asset for Chesapeake.

With about 350 wells in the Texas Granite Wash area, the region is a familiar location for exploration and production.  Chesapeake began operations in the Texas Panhandle Granite Wash with the Bravo acquisition in 2004.  “Bravo was drilling vertical wells and slickwater fracing them in the Stiles Ranch area,” said Michael Park, District Manager – Anadarko Basin. “In February 2007 Chesapeake decided to try a horizontal, and it was successful.”

Future opportunities in the play include horizontal drilling in
the Atoka formation, which could pave the way for significant
production reserve potential.

At the time, Chesapeake was one of the first companies to realize the benefits of developing the various Anadarko Granite Wash plays with horizontal drilling.  Since then, the company has stayed at the forefront of technology throughout the play.  Today Chesapeake is the most active driller in both the Colony and Texas Panhandle Granite Washes, with a total of 12 rigs projected in both for 2010.

The company is one of the largest leaseholders in the Texas Panhandle Granite Wash, holding approximately 40,000 acres on which it currently produces approximately 75 million cubic feet of equivalent per day (mmcfe/d) net. The company anticipates that number to reach 80 mmcfe at year-end 2010 and 85 mmcfe at year-end 2011.

“We have some good wells in the area,” Park said.  “The Zybach 15-2H in Wheeler County is one of the deeper wells in the Texas Granite Wash at 16,000 feet. It is also bringing up more than 4 mmcf/d along with 300 barrels of oil.  The Miller 26-6H also had initial production exceeding 4 mmcf/d plus more than 500 barrels of oil per day.”

Those 500 barrels of oil are a tremendous bonus, assuming flat NYMEX oil prices of $75 per barrel.

One of the differences between the Texas Panhandle Granite Wash and the Oklahoma Colony Granite Wash is depth.  Both are Des Moines age plays, but the Texas Panhandle Granite Wash in Roberts County is a bit shallower, while in Hemphill and Wheeler counties the formation is approximately the same depth as the Colony Granite Wash play. 

The Texas Panhandle Granite Wash is on
the western edge of a geologic feature
called the Amarillo Uplift in the prolific
Anadarko Basin.

The Panhandle Granite Wash reservoirs also have more fluid production variation, according to Park:  “Oil and water are inconsistent from well to well and zone to zone within the overall Granite Wash interval.  The Texas Panhandle Granite Wash is also more normally pressured as compared to the over-pressured Colony Granite Wash.”

While the Texas Panhandle Granite Wash play has its own unique challenges, its increased rate of penetration, as compared to the Colony Granite Wash, is this play’s greatest drilling asset, according to J.D. Hertweck, Manager of Drilling Engineering – Northern Division.

“A typical Texas Panhandle Granite Wash well will reach an average total depth of 16,800 feet measured depth in 33 days, as compared to 42 days for the same well in the Colony Wash,” said Hertweck.  “This translates to 27% less rig time spent on the well, which reduces drilling costs and brings the well on production that much sooner.”

Future opportunities in the play include horizontal drilling in the Atoka formation, which could pave the way for significant production reserve potential.  Competitive bidding opportunities also have allowed the company to lock in attractive drilling and completion service agreements which will support its efforts to keep finding costs low.

The Texas Panhandle Granite Wash is a valuable asset for Chesapeake, with attractive finding costs, high initial production rates, a functional infrastructure in place and attractive leasing opportunities.  And – oh, yes – there is that $75-per-barrel oil.

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The Environment: Reducing Emissions

Breathe Easy
by Brandi Wessel

EPA recognizes Chesapeake for significant reductions in methane gas emissions

At Chesapeake, efficiency is more than just a good business practice, it’s an important part of the company’s commitment to the environment. Implementing and enhancing numerous Environmental Protection Agency (EPA) Gas STAR Best Management Practices (BMPs) and technologies, is making the company even more efficient by significantly reducing methane emissions, thus reducing its environmental footprint and increasing revenue through additional natural gas sales.

In recognition of these efforts, Chesapeake was recently named the EPA Natural Gas STAR Program’s Production Partner of the Year, and the company’s Andrew McCalmont, Coordinator – Gas STAR Program and Special Projects, was named Implementation Manager of the Year.

Kade Kusik, EH&S Field Representative, uses a
high-tech infrared FLIR camera to scan wellsites
and equipment for natural gas leaks.

“Since joining in 2007, Chesapeake has reported significant methane emissions reduction totals to the EPA through the implementation of a broad range of voluntary cost-effective technologies and practices resulting in increased revenue and reductions of methane emissions to the atmosphere,” said Suzie Waltzer, EPA Natural Gas STAR Program Coordinator.

A significant portion of these cost-efficient technologies include reduced emissions completions, commonly referred to as green completions. A technique long employed by Chesapeake, green completions are the recovery and sale of natural gas produced during a well completion flowback or workover. This procedure helps reduce venting and flaring at the wellsite, while allowing the industry to recover an EPA-estimated 25.2 billion cubic feet (Bcf) of natural gas annually – gas that may have otherwise been released into the atmosphere.

Along with practices and technologies to reduce methane emissions, a key component of the Natural Gas STAR Program is the tracking and reporting of methane emissions reductions. To accomplish this goal, Chesapeake has employed the use of STARtracker, a web-based software program to record and manage data. The company’s Natural Gas STAR team completed an extensive research effort and uploaded all emissions reduction efforts since 2001 into the program. The database allows the team to focus on relevant, ongoing practices and document past reductions, as well as to help create awareness and identify additional emissions reduction opportunities.

Seth Unruh, EH&S Field Representative,
retrofits a Mizer Pilot Valve to an existing
wellsite.

One discovered opportunity involves the retrofitting of process controllers. A common industry practice, the valves are designed to continuously vent a small amount of natural gas. Mizer Pilot Valves were researched, piloted and installed at a number of facilities throughout the company’s operations. This retrofit captures previously vented natural gas and allows it to be sold into the market. Several thousand retrofits have been completed, and have added double value by reducing methane emissions and generating additional sales volume. 

While technologies such as this have been a large part of Chesapeake’s emissions reduction efforts, McCalmont also attributes the company’s success to teamwork and education.

“We formed an implementation team in September 2007, and one of our primary goals has been to develop a company-wide understanding and awareness of our partnership with the Natural Gas STAR Program” said McCalmont. “It’s important for our employees to understand the benefits of the program’s initiatives and their role
in the process.”

Mizer Pilot Valve

Chesapeake also hosted a Producers Technology Transfer Workshop at its corporate headquarters in Oklahoma City in May 2009.  The conference drew more than 130 industry participants from across the country and featured a variety of presentations and exhibits concerning methane emissions reduction technologies and practices.

“The Natural Gas STAR Program is only successful because of the strong support of our partner companies such as Chesapeake, who are willing to implement methane emissions reduction activities and share their successes with the program,” said Waltzer.

 

A Clean Energy Solution

Natural gas is primarily methane (CH4). Methane is a nonreactive hydrocarbon, which means its emissions do not react with sunlight to create smog. As a result, natural gas is by far the cleanest-burning hydrocarbon on the planet, with much lower CO2 emissions and fewer pollutants than coal or oil when burned – approximately 30% less than oil and 50% less than coal. Natural gas is even cleaner when other air pollutants are considered. Emissions of carbon monoxide, nitrogen oxides, sulfur dioxide, particulates and mercury are all dramatically lower with natural gas.

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Inside CHK

A closer look at Chesapeake's people and progress.

Chesapeake United Way campaign

Chesapeake opened its campus to the
community for Fall Fest where hundreds of
adults and children celebrated the season
with games, rides, food and live music.

While fall means football, falling leaves and cooler weather to most, it also marks a special time at Chesapeake – the annual Chesapeake United Way campaign. This company-wide fundraising effort is one of Chesapeake’s most celebrated community traditions. With a variety of activities and a company dollar-for-dollar match of employee contributions, Chesapeake’s United Way campaign helps to fund long-lasting community change.

This year employees banded together to raise a record-setting amount of more than $3.6 million for local United Way organizations throughout its local operating areas.

Through the company's many events,
more than $3.6 million was raised for
United Way.

With silent auctions, raffles, Halloween parties and a duck derby, the events continued to grow with the introduction of a family-friendly Fall Fest celebration. Located on the company’s Oklahoma City corporate campus, this event was open to the public with all proceeds going to United Way. Fall Fest featured live music, food, rides, carnival games, pumpkin decorating, face painting and a hay maze in the shape of the Chesapeake flame. In addition, every attendee received a pumpkin from Oklahoma’s own McClemore Pumpkin Farm.

“We are committed to the communities in which we operate,” said CEO Aubrey McClendon. “By supporting and contributing to organizations like United Way, we hope to help support successful kids, strong families, healthy citizens, independent living and community preparedness.”

Original CHK Buildings to live on through donation of parts for reuse

6100 is the sole survivor of the original 12
Three Chopt Square buildings and is the
future home of Chesapeake’s history center.

In the center of Chesapeake’s Oklahoma City campus was a cluster of 12 small buildings, which has served as the centerpiece of the company’s campus for the past 20 years. Over the decades, as the company has dramatically grown, so has its corporate campus. With more than 3,000 employees officing in Oklahoma City, Chesapeake’s newer buildings were built to accommodate the company’s work force with many features and amenities that support a rapidly growing, high-tech business. After much consideration, the company decided to demolish 11 of the two-story buildings known as Three Chopt Square. In its place will be Chesapeake’s “Central Park,” an underground parking garage with a greenbelt on the surface to be used as an athletic field.

Shutters are being donated to nonprofit
building groups to use on future projects.

However, before a wrecking ball arrived on campus, Chesapeake arranged for more than 3,900 building parts to be donated to local nonprofit groups such as Habitat for Humanity and Rebuilding Together. Everything from doors, toilets, cabinets and windows to sinks, blinds and refrigerators were removed for use by these local organizations in future building projects and renovations.

“We are grateful Chesapeake recognizes the great value we place on reusable materials and fixtures. We will use the donated materials to help low-income seniors make their homes safer, warmer and dryer,” said Valerie Aubert, Executive Director of Rebuilding Together Oklahoma City. “We are most appreciative.”

The approximate value of items donated is $350,000.