When one thinks of water shortages, the mind naturally goes to the southwestern states where there are few lakes and the rivers become dry arroyos in summer. But the Appalachian region, despite its hundreds of rivers and thousands of lakes, has water issues too. Water rights are but one of the many challenges facing operators in the promising Marcellus Shale play. In fact, as soon as it became known that the vast Marcellus Shale formation was loaded with trillions of cubic feet of natural gas, prospective operators started securing water rights to supply the anticipated hydraulic fracturing treatments required to open reservoirs for production.

They faced tough, deeply entrenched competition from farmers, coal companies, and heavy industry, not to mention recreational users and environmentalists. Speaking at Hart Energy Publishing’s Developing Unconventional Gas Conference, Roger Pinkerton, chief executive officer of Range Resources, one of the more prominent Marcellus players, remarked, “Even if Marcellus activity reaches Barnett Shale levels — about 30 times current levels — water used will be only half as much as area recreational activities, including golf courses.” Nevertheless, area residents, farms, and businesses have voiced concerns.

A watershed solution

Into the gap stepped General Electric’s Water & Process Technologies Group and STW Resources Inc. The companies have announced that they have formed a collaboration that will drastically reduce the amount of freshwater lost to the environment due to hydraulic fracturing.

Their plan is to remediate the billions of gallons of oilfield brine produced as fracturing wastewater. Typically, the brine is disposed of by pumping it downhole into deep saltwater aquifers, way below the freshwater table. However, using a cost-effective patented process developed by GE Thermal Evaporation Technologies, it is estimated that producers will recover up to 70% of their hydraulic fracturing wastewater. Essentially, the process separates wastewater into two volumes: a relatively small volume of highly concentrated brine solution that may be disposed of conventionally, and a larger volume of reclaimed water that can be reused in subsequent treatments. The good news is that the process has applications everywhere, not just Appalachia, solving a perennial problem that has plagued producers from coast to coast. The really good news is that STW Resources believes it can use the process to effectively treat wastewater from other industrial sources, making the water suitable for agricultural irrigation and human use.

The water remediation program complements the current oil and gas industry situation nicely, since in the shale plays there has been a trend toward slickwater fracs, which are generally more economical than crosslinked polymers, but require large amounts of water. With suppressed commodity prices and the general malaise of the economy, any solution that helps the industry continue to use its cost-effective slickwater treatments will be welcomed.

Knowledge is power

The Marcellus theme has a familiar ring, although it’s the reverse of the old patronistic truism, “It’s not who you know, but what you know,” at least in the shale plays. Operators and their service company partners are scrambling to acquire geochemical and geomechanical knowledge of the Marcellus formation they can use to develop appropriate drilling, formation treatment, and completion programs. Even so, early indications are that there will be no blanket “Marcellus solution.” The formation is so vast, and contains enough heterogeneity, that a common prescription detailing well construction approaches is unlikely.

Besides its vast 75-mile-by-450-mile area that extends north from Virginia to New York and east from Ohio to New Jersey, the Devonian-age formation varies in thickness from 50 ft in the West to as much as 500 ft in the East. In the West is fine-grained organically rich black shale interbedded with organically lean gray shale; in the East one finds a mixture of sandstone, siltstone, and shale. The formation has undergone considerable post-depositional uplift that has created major fractures and folds, as well as swarms of microfractures. BJ Services, which advertises its “Understand the Reservoir First” process as essential to optimal treatment design, admits that in the Marcellus case there may be several reservoirs it needs to understand. “There is no universal solution,” said Chad Perkins, BJ Services Northeast region engineer. As a result, the company is securing core and log data from across the play and performing detailed geochemical and geomechanical analyses on it.

In general, operators know that the more advance information they can share with drillers, stimulation companies, and completion specialists, the more likely their projects will be successful. In the scramble for knowledge, a data market has emerged. Larry Galloway, of Geophysical Pursuit Inc. in Houston, claims to have the largest library of Marcellus play seismic data. Other troves of diverse data exist too, some dating back almost to the Drake discovery. However, it should be noted that for the first 150 years following Drake’s 1857 well, the emphasis was on acquiring data on potential oil reservoirs, and shale was seen as an impediment standing in the way of the oil-seekers. One exception was a pioneering venture in New York’s Naples Field that produced gas from the Marcellus in 1880, finally abandoning its 12 wells after producing 32 MMcf. Parsing through all the existing data, much of which is in analog form, could be a monumental task.

In the mid-1970s, the US Department of Energy funded the Eastern Gas Shales Project to develop new technology to advance the commercial development of Devonian shale gas. This was before shale gas became so popular, and abysmal commodity prices deterred all but the most avid supporters. Through a series of logged test wells and hydrofracs, the project concluded that the Marcellus could not be treated as a single unit, and success could only be expected by targeting specific formations and locations. A consensus held that the most successful plan would be one involving interception of the natural fracture network with hydraulic fractures to maximize reservoir contact and conductivity. To provide perspective, it is interesting to note that even after almost 40 years of testing and analysis by scores of learned and experienced geoscientists and engineers, estimates of the Marcellus’ potential range from 50 Tcf to more than 363 Tcf (one recent estimate reckons the top end might reach as high as 516 Tcf). Further perspective is added by noting that 363 Tcf will supply the entire nation’s gas needs for 15 years, fueling the current widespread interest in the region. Which estimate will ultimately prove to be correct remains to be seen.

The development of shale gas plays is difficult and costly. As a result, activity is held hostage by cyclic commodity prices. Today’s price is sufficient to sustain investment in some areas, but not others. However, it appears to be a practical fact that most shale plays share a common decline progression — they produce at a high rate initially, then rates quickly drop by 50% or more over the next 12 to 18 months. But then, and this is a key point, they produce with little decline for the next 20 to 30 years. Companies with patience, who are willing to bet on the long-term benefits of their acreage rather than initial production, may be the ultimate winners in the Marcellus.

Challenges persist

Most agree that two major challenges characterize Marcellus Shale development: the sheer size of the play (almost 34,000 sq. miles), and the difficult terrain. Where large multi-well drilling pads are common in the western US and Canada, they are quite rare in the Northeast. A Horn River pad may accommodate 28 wells, whereas a “big” Marcellus pad may contain four to six wells (Figure 1).

Although it’s true that the oil business got its start in the Northeast, and pipelines exist that connect to a number of gas storage fields and subsequently to various city-gates, there are few lines capable of accommodating the gas volume producers anticipate producing from the “New Marcellus.” A careful examination of the infrastructure must be made now, to identify and mitigate its weaknesses before some of these high-volume fields come online, or the Marcellus will pop like a birthday balloon.

The road network and seasonal issues pose problems for equipment mobility (Figure 2). And the densely populated areas create traffic tie ups. Anyone who has followed a loaded West Virginia coal truck along a hilly two-lane road in low-low-gear knows the problem. Where Westerners typically estimate travel time at a mile-a-minute; in Appalachia, the formula is a quarter of that. Operators and service companies acknowledge the difficulties and are trying to mitigate their effects by developing operational efficiencies such as batch completions.

Discovering Marcellus magic

It’s still early, but the service industry is rising to the challenge of developing a magic formula for drilling and completing Marcellus Shale wells. Following on the need to develop a clear comprehension of the formations and the reservoir, Halliburton strongly recommends investment in upfront well evaluation services. Many operators agree, and to date the Marcellus development has progressed using the conservative approach of drilling, evaluating, and oftentimes stimulating and completing vertical wells before attempting more costly horizontal producers. Even though it’s a well-established fact that horizontal wells often outperform their vertical neighbors on a cost per unit-of-production basis, vertical pilot wells provide the opportunity to perform the upfront science that will help optimize the drilling and completion practices of future development wells. Operators don’t want to take on the expense and risk of drilling a horizontal well until they know more about the target’s properties and potential. In addition, many key factors affecting stimulation design can be determined from analyzing vertical pilot holes.

Halliburton’s Northeast Technical Manager, Matt McKeon, described the systematic approach his company recommends. “We use our ShaleEval process to assess reservoir potential,” he said. “The first part involves core testing to reveal total organic carbon content, kerogen typing, thermal maturity, gas content, and analysis, sorption isotherms, mineralogy, rock properties, and lithological description.” McKeon went on to describe the ideal logging program for the Marcellus. “At a minimum, we recommend running a triple combo log with full-wave sonic on pilot wells and having the results analyzed using a shale-specific process like our ShaleLog service,” he said.

Halliburton also favors running shale-focused mineralogical and elemental analysis logs, such as the elemental analysis GEM tool, and high-resolution imaging logs to detect and characterize natural fracture swarms. Once favorable formation intervals are determined, they can be tested to provide pore pressure, fracture pressure, closure stress, and qualitative permeability estimates to aid stimulation design. “After running these logs and tests on a few representative pilot wells in an area, it is possible to apply the findings to other development wells in the same locale,” McKeon said. He cautioned that even though a great deal of useful information can be obtained from vertical pilot wells, it is still beneficial to log future horizontal wells to more specifically identify and optimize stimulation points.

An additional useful complement to horizontal drilling is the company’s LaserStrat Chemostratigraphy service. Using continuous geomechanical analysis of returned cuttings while drilling, a well can be chemically steered to stay within the most productive parts of the shale (Figure 3).

McKeon also recommended the use of microseismic monitoring of hydraulic fracture stimulations in pilot and development wells. “Pinnacle, a Halliburton service, can map fracture propagation patterns. We develop insights we can use to modify frac designs to maximize reservoir exploitation,” he said. Microseismic mapping of fracs in pilot holes can be used to fine-tune subsequent horizontal well drilling designs by helping to align the wellbore azimuth perpendicular to induced fracture planes, determine the desired wellbore landing point, estimate frac stage interval proximity, and provide an indication of nearby geological anomalies.

Asked if Halliburton had discovered a “magic potion” for unlocking Marcellus’ secrets, McKeon said, “One thing that seems to be providing improved success rates is integrating our discrete services into packaged solutions.” He explained that real synergies can be achieved when multiple product service lines (PSLs) can partner together to develop solutions as a team. Enhanced communication and information sharing among its drilling fluids, drill bit products, directional drilling, wireline logging and perforating, cementing, stimulation, and fracture diagnostics PSLs can maximize efficiencies, increase production potential, and offer cost savings for operators. While each discrete service can provide an effective solution that offers individual advantages in its own right, collaborative integration allows the team to focus on a larger, common goal, incorporating processes that benefit the group as a whole. Examples include the continuous reduction in time and cost required to drill horizontal wellbores from kick off point to target depth when fluids, drilling, and drill bits services work together on the well. Along with the savings of time and money, the well bores are drilled more in-gauge, cleaner, and closer to the drilling plan than typically seen. That being said, service companies have found individual products and services that repeatedly provide successful results in the Marcellus. Halliburton mentioned its AquaStim frac fluid system, “Drill By Design” customized bit optimization process, and Baroid’s Boremax mud system with DFG hydraulics modeling to name a few.

Most Marcellus wells are air-drilled vertically to the kick-off point. Then, operators typically switch to an inhibited water-based mud to drill to target depth. Lately, a few have tried using mineral oil-based muds instead of inhibited water-based mud for its compatibility with the shale and potential for enhanced penetration rates. While oil-based mud has some drawbacks, some operators have reported experiencing shorter overall drilling times in early trials.

The most common completion method used in Marcellus horizontal wells is the “plug ‘n perf” technique with cemented production casing, whereby each zone is isolated, perforated, and fractured in sequence. A variety of horizontal completion styles have been tried and some alternatives are being employed regularly today by operators. One such technique is mechanical packer isolation of openhole well bores used in conjunction with frac stimulation initiation sleeves. Microseismic fracture monitoring and tracers have been helpful in gauging the isolation effectiveness of different completion methods. With a significant portion of the total well cost being invested in fracture stimulation, operators want to be assured that stage isolation integrity is maintained and the frac treatments are propagating efficiently along the length of the horizontal well bore.

In stimulation, fortunately the Marcellus offers a shallow target, so standard Ottawa sand proppants and moderate pump horsepower can be used effectively. The trick is getting the frac in the right place, and for this, microseismic fracture mapping service is one key technology used to drive and verify this outcome. Combining fracture mapping with data gathered through the ShaleEval process, the fracture stimulation, and production analysis and monitoring can permit the development of localized reservoir and fracture simulation models. These models can be used to increase exploitation efficiency and production potential at the field level.

McKeon sees growing operator interest in applying some technologies in the Marcellus that have been proven successful elsewhere, and he offers a few examples. One such process is Halliburton’s pinpoint stimulation technique. Using its highly efficient CobraMax H and Surgifrac coiled tubing fracturing process, area operators hope to be able to effectively stimulate more intervals of a horizontal well bore than currently possible in a timely, cost-efficient manner. Production and stimulation monitoring services can help to determine the contribution of each interval to the total production of the well or gauge the flow paths of stimulation treatments.

“When it comes to shales, rarely is there a “silver bullet,” McKeon said. “Improvements in technologies and services are evolving all the time.” McKeon pointed out that each shale formation is unique with notable variations, so standard services must be customized to each particular play and even to specific wells. “Even when common practices, such as a stimulation frac design, are employed in different shale reservoirs, modifications are required to address the individual characteristics of each distinct formation in order to economically optimize production,” he said.

Building better boreholes

Baker Hughes believes that gamma-ray imaging is an effective way to geosteer in the Marcellus. Scott Frank, account manager at the company’s new Canonsburg, Pa., facility said, “Azimuthal gamma-ray imaging allows the client to see if they’re staying within the zone of interest in real time without the need to stop and orient the gamma ray. Navigating through stable zones is important to avoid stuck pipe situations,” he said.

“Annular pressure while drilling the build and lateral sections provides real-time equivalent circulating density [ECD] to ensure proper borehole cleaning.”

Frank pointed out that ECD monitoring is commonly used offshore but rarely on land wells. Although it is not a new technology, it is important in areas where sufficient mud flowrates may not be achieved in the laterals. Frank explained that knowing the hole is being properly cleaned of cuttings and debris may allow operators to increase penetration rates and reduce wiper trips. According to Baker Hughes, because of the possibility of borehole instability in the Marcellus, ECD monitoring should become commonplace.

Baker Hughes recommends its StarTrak logging-while-drilling (LWD) resistivity imaging tool (Figure 4). The tool’s high resolution images will help identify fracture orientation, formation dip, and, on the drilling side, borehole breakout.
“We believe that the imaging data, used in conjunction with microseismic monitoring, will allow operators to better understand the role of natural fractures in well production,” Frank said. “High-definition resistivity images may eventually lead to optimizing the number of stages treated in frac jobs and their placement in the laterals.”

Local experience valued

BJ Services believes that overcoming logistical challenges will go a long way toward the effective development of Marcellus play wells. The company sends an experienced treatment specialist to each location to plan how pump floats and frac tanks will be staged on the cramped pads. It’s sort of like watching an expert deck hand direct the loading of a busy car ferry without a scratch. “We are committed to using local staff wherever possible,” said BJ’s Chad Perkins. “Their knowledge and experience on narrow mountainous roads in all kinds of weather pays off.” The company uses the local expertise approach in its cementing and stimulation design as well. “The same two experienced people look at every single design before it is presented to the client,” Perkins said. “This ensures design consistency and provides cross-checking to avoid human-error.”

Because the Marcellus play is simply too vast, too heterogeneous, and too different from other shale plays around the country to yield an overall Marcellus solution, BJ Services is committed to finding the best solution for specific areas by careful examination of logs and cores as well as drilling and stimulation records. Already, the company’s trademarked “Understand the Reservoir First” process is paying off in better frac designs. Because some areas of the play are experiencing proppant flowback issues, the company recommends its FlexSand mixture run as a 15% add on the final proppant mix before it’s fed to the screws. So far, the best fluid seems to be slick water, although data are still being gathered on each job in the event conditions point to an advantage from using a cross-linked fluid. “Before the Marcellus interest developed, most of the shale fracturing in the Northeast used nitrogen-based equipment designed for small single-well pads and hilly terrain,” said John Gottschling, region technical manager. “The productive intervals in the shale were widely scattered and many operators used a shotgun perforating technique followed by nitrogen foam and sand or 100% nitrogen gas stimulation treatments. The advent of Marcellus exploitation has brought a much more scientific approach to perforating and stimulation treatment design,” he said.

Different operators prefer different techniques in the Marcellus, attesting to its regional heterogeneity. For example, several operators are using BJ Services’ DirectStim openhole completion process in their wells, where completion stages are isolated by inflatable packers and zonal access is via a ball-actuated sliding sleeve (Figure 5). Other operators prefer the plug ‘n perf sequential technique, usually in conjunction with real-time microseismic monitoring. Where originally most fracs used sand proppant, today’s operators are experiencing the benefits of such techniques as mixing FlexSand in the final mix or tailing-in with BJ Services’ LiteProp ultra-lightweight proppant to ensure fractures are propped open all the way to the top of the wing. The FlexSand technology uses irregularly shaped grains with dimples in their surfaces that lock-in with adjacent grains for a pack that will not wash out during clean-up operations.

At the moment, most Marcellus wells are fairly shallow. However, there are areas where the Marcellus lies 8,000-ft deep or more. These areas may require BJ Services to go back into its repertoire of techniques and switch to more sophisticated fluids and pumping or zonal isolation technologies. A valuable source of knowledge has come from the numerous vertical completions in the Marcellus. Operators have good geological and petrophysical information and many have attempted fracture completions in the vertical sections. This provides excellent geomechanical data that can be used to site and drill better laterals as well as design better completions in those laterals. The numerous vertical boreholes provide a natural conduit for microseismic arrays to monitor fracture treatments in nearby laterals.

Logistical issues are changing too with the establishment of more multiwell pads and 24-hour operation. This allows more efficient and cost-effective use of equipment and crews. It also has allowed the introduction of a popular technique called “zipper-frac” whereby adjacent wells are fraced in an alternating pattern back and forth, stage-by-stage. The technique, first pioneered in the Arkoma Basin, helps prevent fracs from adjacent wells from intersecting one another, and maximizes reservoir contact.

Mastering the Marcellus

Schlumberger is pulling on its long experience in the Northeast to give it an advantage as it develops its integrated approach. “We’re leveraging the experience of our local personnel by equipping them with the latest drilling, logging, and completion technology. With shale permeability measured in nano-Darcies, we have a ‘Do it Right the First Time’ approach,” said Paul Lundy, Pittsburgh Northeast operations manager, Schlumberger Data & Consulting Services. Lundy explained that incorporating technologies such as Sonic Scanner acoustic scanning platform, ECS elemental capture spectroscopy sonde, and FMI full-bore formation microimager will give the operators a clear understanding of the lithology of the rock.

“Running both the FMI and Sonic Scanner in the horizontal section allows visualization of actual fractures, both natural and drilling induced, and a clear understanding of the stress variation along the borehole. This allows a far more rigorous approach to selecting perforation locations and stimulation design,” Lundy said.

“If it were my well, I would also involve TerraTek – validating core analysis through log measurements by way of ECS and Sonic Scanner. Once I understand where my productive zones are most likely to be and have identified the preferential landing zones, I would optimize the stimulation utilizing Planar3D for modeling fracture height based on input from the Sonic Scanner information taken along the well path,” Lundy continued.

“With this, I’d incorporate StimMAP Live microseismic fracture monitoring to track the fracture’s propagation as it occurs, allowing real-time adjustments to be made while pumping into the fracture,” he said. “The key to a successful shale well is understanding the marriage between the rock and the completion. Schlumberger Data & Consulting Services offers a complete package of reservoir characterization and earth modeling, and we work very closely with all of our technology segments to help deliver the maximum value to our clients.”

Lundy went on to explain, “We use TerraTek to analyze cores to estimate well productivity and provide geomechanical data. The logs tell us total organic content and permeability, which yields a productivity estimate. Then we design the lateral drilling and completion program to achieve it.”

With “ground truth” from cores, every aspect of the subsequent work can be customized to each well.
The company recommends running its geoVISION microscanner resistivity LWD tool behind its PowerDrive rotary steerable systems to drill and evaluate the laterals.

Asked to name the No. 1 challenge facing Marcellus players today, Robert Wolfsberger, Northeast basin vice president, sales and marketing, said unequivocally, “It’s the water issue. Schlumberger Water Services Group is a solution to our clients’ needs.” According to Wolfsberger, Schlumberger's Water Services specializes in assessing, developing, and managing the world's groundwater resources using the most powerful and cost-effective technologies available today. Its approach to the Marcellus as well as similar plays is to optimize all aspects of the water system thereby reducing water costs for the oil and gas operator.

Universal problems

Each operator and service provider is challenged by the vastness and complexity of the Marcellus Shale. Water is scarce, and water rights are jealously guarded. Obtaining drilling and stimulation permits can be challenging and time-consuming when dealing with the various laws of the several states overlying the Marcellus trend. Even economic analysis suffers when one considers the wide range of reserves estimates. How much recoverable gas is actually there? And a paradox not well understood by the general public may delay development. That is, the currently depressed commodity price makes some plays only marginally profitable, whereas others are still going strong. Just a few dollars’ uptick and a measure of price stability could turn the Marcellus play into the find of the century. So rising gas prices could actually benefit consumers by enabling access to huge reserves right in their backyard.