The Arkoma Basin of southeastern Oklahoma and north central Arkansas is home to three prolific shale plays — the Woodford, the Caney, and the Fayetteville. Although there are some similarities, most players agree that each should be studied in its own right to determine the possible effect of the differences between them. There is no “Arkoma Solution.”

However, experience has led to the development of some trends that seem to prevail in most Arkoma wells. In a recent report, Constellation Energy recognized the dramatic growth of horizontal drilling as applied to natural gas wells. It cites several sources that support this contention. For example, compared to a total rig count growth of 70% since 2000, the number of horizontal rigs has grown by 377% during the same period. Another source says that horizontal well drilling is growing 96% year-on-year. And it’s a good thing. According to Simmons & Company, absent the development of applicable technology, overall gas production would have declined 40% to 50%, but instead it remained essentially flat.

Notwithstanding the positive effect of new technology development on gas well drilling and production, Wood Mackenzie warns that operators should not expect overnight results in their unconventional gas plays. There is no panacea or magic elixir that works on all shale gas wells. Each must be treated according to the challenges it presents — on a reservoir-by-reservoir basis or even on a well-by-well.

Measure before cutting

The ancient carpenter’s rule applies. Experienced service providers are unanimous in this regard. Knowledge is the key to the development of effective solutions. BJ Services has gone so far as to trademark its “Understand the Reservoir First” philosophy, demonstrating to all its commitment to excellence through the development of local knowledge along with the capture and application of learnings from each project to guide future recommendations to its customers.

Operators too, have recognized the benefit of superior measurements to guide strategic and operational decision-making. In its Fayetteville play, Southwestern Energy (SEECO) has taken a high-tech approach to get the best well placement and maximum reservoir contact. The company uses state-of-the-art formation evaluation and completion technology to maximize its reservoir knowledge before undertaking a project. The result is that it can produce more gas from fewer, but better, wells.

If there is a consensus among Arkoma operators, it is to achieve maximum effective reservoir contact with the objective of achieving the lowest cost per Mcf while getting the gas to market as quickly as possible. There are two ways to achieve this objective: possess a good deal of blind luck, or take the time to develop the reservoir understanding necessary to make the right decisions. In short, measure before cutting.

Successful technology applications

Much of the success in drilling and completing the Arkoma Shales is the result of good hard work in applying proven drilling and completion techniques. There are many ways to drill and complete a well, and with foreknowledge, operators and their service providers can usually find the best technique for the well under consideration. A few stand out as being particularly useful. In the realm of formation evaluation, microresistivity imaging, acoustic imaging, elemental capture spectroscopy and nuclear magnetic resonance are mentioned most frequently. It’s useful to take a closer look at each.

Microresistivity imaging provides a 360-degree image of the borehole wall in such detail as to allow users to identify, measure, and determine the orientation of microfractures intersected by the borehole. Lithological texture can be observed, as well as formation dip, and fracture apertures can be quantified. One microresistivity imaging device that is available in logging-while-drilling (LWD) tools is the Schlumberger geoVISION service. Some prefer to drill and log vertical pilot holes to get the information, while others use LWD, drillpipe-conveyed wireline techniques, or tractors to log horizontal sections. Another limitation is oil-based mud, which is used to drill most Woodford wells. While several providers offer oil-based mud microresistivity imagers, often they are unable to provide the fine detail of the water-based mud versions.

Microresistivity imaging is used primarily to detect and discriminate drilling-induced fractures from natural fractures, detect lithology changes, identify geologic features such as sub-seismic faults, and evaluate qualitative stress variations along lateral sections.

Acoustic logs enable resolution of another piece of the formation evaluation puzzle. This is the ability to perform geomechanical analyses and 3-D anisotropy determinations including the magnitude of hydraulic fracture closure stress and orientation of the prevailing stress profile. An advanced tool, the Sonic Scanner service from Schlumberger gives compressional, shear, and Stoneley velocities, along with the orientation of maximum horizontal shear velocity. The accuracy of stress profile calculations is enhanced by taking both horizontal and vertical measurements in complex, highly laminated rocks such as gas saturated shales. The equipment can be run in both cased and openhole.

When run in cased holes, an added benefit of the tool is provision of a high-quality cement bond log. The primary benefit of these measurements is the ability to make recommendations for landing and orienting laterals for maximum effective reservoir contact as well as guiding the engineers responsible for hydraulic fracture design.

Elemental capture spectroscopy logging provides detailed understanding of shale mineralogy as well as total organic carbon content, and volume of adsorbed and free gas in place. It can help identify reservoir “sweet spots” and can be used to “chemically steer” the well into the best reservoir zones.

Nuclear magnetic resonance imaging has been characterized as the only direct logging measurement of permeability. It yields lithology-independent measurements of effective porosity, free fluid porosity, clay-bound water, and capillary-bound water. Advanced versions, such as the XMRI tool from Halliburton, help to discriminate open fractures that can actually flow gas from drilling induced fractures that pose leak-off problems.

Breakthrough technology

Recommended by all hydraulic fracturing providers, the use of microseismic imaging to track fracture propagation represents technology that is making a major difference in the Arkoma as well as in other shale plays. Generally, the technique involves hanging an array of geophones in a nearby well to monitor the progression of the microseisms that occur as a hydraulic fracture propagates through the rock. Previously, the seismic arrays were placed in the vertical sections of offset wells, but recently, tractors have been used to place the arrays in lateral sections, paralleling the well being treated. For its dramatic effect on hydraulic fracture quality and placement, microseismic imaging is recognized as today’s hot new technology. In some cases, results are made available at the well site in real time, and can be used to guide the fracturing job, helping to prevent a fracture from propagating into an aquifer or communicating with offset producing wells. Perhaps the biggest benefit of real-time fracture monitoring is the ability to make on-the-fly changes to plans for subsequent stages of multistage fracture programs based on observations from the stage being treated.

Barry Dean of Schlumberger provided insight into the value of StimMAP Live, the company’s real-time microseismic log presentation. “We are able to map the propagation of the fractures we make using StimMAP Live,” he said. “This prevents treating sections of lateral that have already been effectively treated, or helps identify sections not taking treatment in time to take remedial action. There are isolation issues, and without StimMAP you might be treating a section of a horizontal well and find that all the treatment is going into the same reservoir volume as treated in the previous stage. You should not assume that the entire horizontal lateral is being treated based on the location of isolation plugs and perforations.

“We use the Plug n’ Perf technique most of the time,” Dean said. “This system gives us the flexibility we need.” According to Dean, while other multistage techniques may be more efficient, it is important to know in advance exactly where you want to treat, and it is much preferable to get many fractures distributed along the lateral. “I would rather have dozens of 500-ft- to 800-ft-long closely spaced transverse fractures than five widely spaced 2,000-ft-long fractures,” he said.

Learnings from the application of microseismic technology have led to a new technique called “Simul-Frac.” Particularly appropriate in the Arkoma, where it’s desirable to produce multiple closely spaced fractures to maximize recovery rates and ultimate recovery factors, the technique has been pioneered by Continental Resources on its Woodford Shale acreage in eastern Oklahoma. Basically, geophone arrays were deployed in vertical and/or horizontal sections of offset wells then multistage hydraulic fracturing was conducted in two or more wells simultaneously with excellent results. Overall reservoir volume treated was improved along with well productivity.

Sequential fracturing of adjacent well bores often resulted in fracture stimulation treatment fluids, moving along the path of least resistance, to intersect producing well fracture networks. This flooded producing well fracture networks, interrupting production, and reduced the efficiency of fracture treatments on the new wells. In collaboration with Schlumberger, Continental Resources engineers determined that fracture propagation from a well was dependent on the local stress fields that it encountered as it radiated out from the well being treated. As induced fractures neared previously fractured reservoir it communicated with that drainage volume due to the lower post-frac stress level. Why not avoid this communication by pre-stressing the earlier-treated wells?

At first, they tried pumping adjacent stages on parallel wells simultaneously. Results were encouraging. Another technique used a batch process where adjacent stages were left pressured-up until treatment of the nearby wells were completed, then all wells were allowed to flow back and clean up at once. By leaving a stage under pressure, higher reservoir stress was created that would, in some cases verified by StimMAP Live, divert fracture propagation away from the pressured region to untreated parts of the reservoir.

Further experimentation resulted in a number of variations of the Simul-Frac technique with similar results: Vertical staggering takes advantage of the tensile region surrounding the tops and bottoms of fractures to allow close spacing of fractures;

More than two laterals can be stimulated at once — in some cases up to four laterals were simultaneously pumped; and In shales, since there is essentially no leak-off, the fractures remain pressured up until they flow back during the cleanup phase. Accordingly, treatments can be sequential as long as the wells are left pressured up until the conclusion of all treatments.

With the Zipper-Frac technique, adjacent stages are treated sequentially without pressure bleed-off. After treating the toe of the first well, the frac crew moves to the adjacent well. While the frac crew is treating the toe of the second well, the plugging and perforating crew is setting the frac plug and perforating the next stage of the original well. The crews swap back and forth between wells until all stages have been treated. The plugs hold pressure on previously treated zones while adjacent stages are being treated.

If fewer crews are available than wells, a system is designed whereby perimeter wells are treated first, then held under pressure while the inner wells are treated. This prevents fractures from the inner wells from communicating with the fractures from the perimeter wells. This allows a more dense fracture pattern to be created. The combinations are endless, and they are a function of the actual well spacing, the structural geology, logistics, and the desire for fracture density over fracture length. The multiwell technique is very efficient when all wells share a single drilling pad. However, efficiencies may still be realized even if crews have to move between adjacent locations.

Another benefit, and perhaps the most important, is you only load the wells once with fluid when simultaneously completing closely spaced horizontal wells. You avoid the costs associated with having to workover wells or install artificial lift due to fracturing into producing well fracture systems from new well stimulations.

In preparing for the simultaneous stimulation technique, the appropriate logs were run to gain as much reservoir and geomechanical foreknowledge as possible. The Sonic Scanner service was run in cased hole to ascertain that a good cement bond existed and hydraulic isolation of the annulus was assured. The service helped estimate stress variation along the laterals and pick optimum perforation points.

In a test series, three Simul-Frac projects were run by Continental Resources. Several valuable conclusions were reached. There was a clear potential to increase production rates. Two of the projects resulted in increased rates, and a third, which did not, was constrained by pipeline capacity. Subsequently, three additional projects have been completed. Early data indicates that the production rate improvement will last. Frequency of workover and intervention of producing wells is reduced.

Building better fracs

Armed with reservoir understanding obtained from logs, cores, and offset well data, BJ Services’ engineers have designed ways to improve productivity from the multistage fracs they make in shale gas plays. Simply fracturing the rock was not enough. They wanted to ensure their client got the maximum gas flowrate from the resulting fracture. To do that, they had to ensure that the entire frac was propped from top to bottom. To overcome the tendency for sand proppant to slump to the bottom of the frac due to the effects of gravity, BJ Services introduced its LiteProp technology, an ultra-lightweight proppant bead that is almost perfectly spherical and light enough to float in most carrier fluids, even those used in slickwater fracs.

“We use 40/100 mesh LiteProp 108 ULWP to fill in the tops of the fracture wings,” said Scott Nelson of BJ Services’ Oklahoma City region. Rocky Freeman, also of the Oklahoma City region, added, “The LiteProp proppant is added late in the pumping schedule, and we have evidence that not only does it help prop the entire fracture open, but it is actually creating new fractures due to diversion, so it’s improving reservoir contact too.”

The technique follows the philosophy of partial monolayers, which is particularly effective in low-permeability reservoirs. Essentially, the idea is to improve fracture length more than width. In low-permeability reservoirs, a single proppant layer may be enough to sustain the fracture. By removing proppant, less horsepower is required to create and propagate the fracture to achieve the desired conductivity. The lightweight proppant floats to the fracture tip instead of slumping to the bottom of the wing. At the same time, the new proppant has a high compressive strength and heat resistance. But the biggest advantage is its weight-to-volume ratio.

For example, LiteProp 108 ULWP occupies a 250% greater volume than an equivalent weight of Ottawa sand (Figure 1). Tony Martin, BJ Services’ international stimulation development manager, said, “The concept of near-buoyant proppant can revolutionize the industry.”

BJ Services also likes having the ability to use microseismic monitoring to aid in making both on-location treatment decisions and to improve treatment designs in future wells. To take advantage of this information, the company performs mostly Plug n’ Perf type multistage fracs. “The advantage of the flexible Plug n’ Perf technique is that you’re not locked in to a predetermined perforating interval,” said BJ Services’ Mike Stockard. Terry Hardwick added, “We watch the pumping pressures from our frac van and make decisions on-the-fly to get the best results. We also like to pump all the specified fluid even if we get a screenout on the sand. We think that getting all the fluid pumped is important in extending the frac to its limit,” he concluded.

The company averages five to 10 stages per well, spaced out along the horizontal lateral. Each stage may contain several perforated zones, so more than one frac can be created per stage.

Giving a plug to the cementers, BJ Services’ Curtis Huff said, “It should be noted that the key to a successful frac job is a successful cement job. We’ve found that the natural fractures tend to take drilling mud and cement. The result is that you lose all the conductivity the natural fractures provided.”

To combat this problem, the company has developed special cement blends such as foamed cement, acid soluble cement, and foamed acid-soluble cement to provide good hydraulic isolation without damaging potential pay zones. “Later we can dissolve the cement using acid,” Huff explained. “Or in the case of foamed cement, we can usually get the fractures to propagate out through any cement that may be present. We’ve had near 100% success since we started engineering our cement jobs according to log and well parameters, and completing the job using foamed and acid-soluble systems.”

Foamed cement is key in the Woodford

According to Halliburton, operators completing wells in the Woodford Shale had cemented 116 horizontal production strings using conventional cement before switching over to lightweight foamed cement. As of early 2008, 229 lateral production strings had been isolated using cement foamed with nitrogen. Results were dramatic, and fell into at least one of three categories:
Improved gas production;
Improved fracture stage stimulation; and
More complete hydraulic isolation.

Most importantly, operators released production data on almost half the wells stimulated using foamed cement. On average, the 30-day gas production from those wells averaged 28.1% better gas volumes than wells cemented conventionally.

In the case of stimulation design improvement, Halliburton statistics show improved fracture initiation and placement on 96.4% of the wells isolated using foamed cement compared to 79.9% success on conventionally cemented wells.

A major contributor to problems cementing long lateral sections is uniform cement distribution around the pipe. Azimuthal bond logs showed that conventionally cemented wells often had an uncemented channel running along the top of the casing. This was caused by heavy slurry cement slumping to the low side of the hole leaving a fluid-filled gap at the top. When stimulation commenced, the channel robbed frac fluid and pressure from the treatment zone, resulting in sub-optimal performance. On the other hand, the nature of foamed cement is to completely fill the annulus, leaving no channels due to gravity slumping. According to Halliburton, cement compressive strength is secondary in importance to complete hydraulic isolation. The cement sheath should exhibit both ductile and elastic characteristics along with increased tensile strength.

The desired characteristics are achieved by designing a cement slurry that is fully engineered to meet each well’s requirements. The generalized objectives include 360-degree uniform coverage around the casing; an expandable sheath that achieves 100% cement-to-formation bond as well as cement-to-casing bond; a life-of-the-well solution that will provide complete hydraulic isolation for both the stimulation and completion phases as well as the subsequent production phase; maintaining positive hydrostatic pressure during the entire cementing operation to prevent borehole wall caving; and providing a positive mud-cleaning displacement action to optimize the hole to accept the cement.

Newfield Exploration benefited from the use of foamed cement in several of its Woodford Shale wells. Typically, the company has been drilling 8 3?4-in. diameter laterals using 8.5 lb/gal to 10.0 lb/gal oil-based mud. Production casing was centralized 5 ½-in. diameter pipe. Borehole stability and hole quality have been good, and, as a result, there have been few problems getting casing set to total depth. Completions are multistage, high-volume slickwater fracs. Treatments are generally pumped at 80 bbl/min to 100 bbl/min, and wellhead treatment pressures range from 5,000 psi to 9,000 psi. The favored technique is Plug n’ Perf. It has been hypothesized that the application of pressure cycles as each stage is broken down and treated may have overstressed the cement sheath in the past. This is one key reason that ductile foamed cement is ideal for multistage shale play fracturing. Halliburton engineers developed a generalized technique for application of foamed cement, then customized the mixture to optimize it to each well’s parameters and the planned fracturing schedule before pumping it. To help it reach the desired level of design optimization, the company uses proprietary software like its ShaleEval program to match the proposed completion design to the geological and geomechanical conditions of the formation to be treated. It employs its ShaleStim technology that is specifically designed to optimize stimulation treatments from pre-job evaluation and planning through clean-up and recovery.

Shale drilling can be tricky. As a result, Halliburton’s Security DBS Division has addressed the technology of purpose-built drillbit design with its QuadPack drill bits
These roller cone tungsten carbide insert bits were specifically designed for shales like the Woodford, and they deliver increased penetration rates through long intermediate sections and subsequent laterals. Key features of the bits include larger, tougher bearings, improved bearing seal capabilities, and better bit hydraulics and steerability.

Location, location, location

As the saying goes, the top three reasons given for the success or failure of a business are location, location, and location. This is true in drilling the nation’s shale plays as well. While the maps imply broad swaths of shale crossing the country from sea to sea and from north to south, bringing in a commercially viable producer is not a slam dunk.

The Arkoma Basin in particular has seen its share of successes and also-rans. According to a report published by PetroQuest Energy in January 2009, in addition to itself, the most successful players in the Woodford appear to be Newfield Exploration, Devon Energy, XTO, Continental Resources, and St. Mary Land & Exploration, with a total of 575,000 acres leased. To the east in the Fayetteville trend, the players include SEECO, Chesapeake, XTO, and PetroHawk Energy in addition to PetroQuest. Between them, they have 1.83 million acres under lease.

For every successful venture in the Arkoma, the news is full of less impressive performances. Obviously, location plays a major role in the success of a project, but it’s possible that overlooking successful technology could play an equally important role. If you listen to the major service providers, simply drilling a well in the right place is no assurance that it will produce high volumes of gas at commercially viable rates. There is a lot of technology between simply fracturing the rock and producing successful fractures that maximize reservoir contact, conductivity, and longevity. Famous oilman George H. Mitchell has been honored as the “Father of the Barnett,” testifying to his dogged persistence of two decades that finally resulted in a “solution” for making profitable wells in the famous north Texas play. The gas was always there, and George Mitchell knew it, but it took years for technology to catch up to his dreams. Now the technology is available, and successful players are using it to their everlasting advantage.