Successes Notched in a Tough Play

Stretching from the northeastern Panhandle counties of Texas into western Oklahoma, the Granite Wash play covers almost 500 sq miles. Its very structure is an enigma, with the entire wash package ranging from as thin as 10 ft to as massive as 4,000 ft. In some places the bit bites into the wash at 300 ft. In other places, you might not hit the play till you’ve drilled through 19,000 ft of rock.

The entire play is characterized as extremely complex, heterogeneous rock, with a wide variety of mineralogy. The condition is mainly attributed to the fact that the play was deposited over several geologic ages and evolved from numerous source terrains. Some drillers strike highly porous and permeable reservoirs and produce large volumes of oil. But by far, the majority of the Granite Wash play contains unconventional gas, with poor reservoir characteristics but high producible amounts of hydrocarbon.

Figure 1. Q406FHX six-bladed PDC bit with 1/2-in. cutters shows little wear after successfully drilling an extremely abrasive section of the Granite Wash (Photo courtesy of Baker Hughes)

Even with the potential of striking a rich prize, Granite Wash operators are focused on cost control. There are numerous unknowns between drilling into a pay zone and ultimately producing it at commercially viable rates long enough to recoup the investment.

After probing the play extensively using vertical wells, many companies are trying to improve their position by drilling horizontally through the pay zones. At first, results were mixed, but recently, many excellent horizontal producers have been completed. A common problem has been the lack of extensive high-quality seismic over the area. There are fairly decent geological maps that have been enhanced and updated over the years by well-to-well correlation as each new penetration is drilled and logged, but because of the play’s geologic complexity, knowing what’s in two adjacent wells doesn’t guarantee that you know what’s in between them.

Even if a company drills a vertical pilot hole and then tries to sidetrack it laterally to exploit a pay zone it has discovered, it may drill out of the zone in the first hundred feet. According to one operator, drilling conditions are not difficult; it’s finding conditions that are challenging. A few operators are clinging to the position that vertical wells make the most economic sense in a complex, heterogeneous area, and they could be right, because they have been successful at finding and developing acreage at very low cost per thousand cubic feet. However, others believe that until a reservoir’s true production potential is known, or at least can be estimated with reasonable accuracy, drilling and completing wells without knowing what lies between them is risky business. You can be lucky and strike the mother lode, but you can more likely miss a huge opportunity.

Focusing on cost control is leading many operators to consider drilling efficiency techniques that have been proven elsewhere, such as an adaptation of Encana’s quad-drilling technique where four wells are drilled and completed in batch fashion from a single large drill site. Multistage stimulation techniques are applied on most completions in an attempt to contact as much reservoir rock as possible from each well bore. Operators are trending to the use of better rigs and more scientific drill bit selection.

Service Companies Attack the Unknowns

Leading service providers are addressing the challenges of the Granite Wash and recommending the best services to their clients.

One of the major drilling challenges in the Granite Wash is that the formations are extremely abrasive. To overcome this challenge, polycrystalline diamond compact (PDC) bits with abrasion resistant cutters and having an excellent control on the tool face are used. Baker Hughes recommends the 6 1/8-in. Q406FHX bit be used to effectively drill these abrasive formations with excellent control of the tool face. This is a six-bladed PDC bit with ½-in. cutters.

Figure 2. Experienced frac crews know that before pouring on the horsepower they need as much reservoir knowledge as they can get. (Photo courtesy of BJ Services)

Not surprisingly, BJ Services pointed out that knowledge is the most effective tool to unlock the secrets of the play. To emphasize its commitment to understanding a reservoir’s challenges and characteristics before recommending a fit-for-purpose solution, the company has trademarked its Understand the Reservoir First process, and applies this principle to all its projects.

Echoing these sentiments, Halliburton is concerned that stimulation economics are often based on little quantifiable information. Historically, most vertical well completions in the Texas Panhandle expose up to 10 different intervals that are potential producers. These intervals, including and surrounding the Granite Wash, have numerous mineralogies, pore pressures, and hydrocarbon types that make standard wireline log interpretation alone extremely unreliable in terms of production potential. This, in turn, has made stimulation design and job size optimization difficult with the offset production statistics being the best available guide for the designer. The increasing trend toward horizontal drilling in certain horizons of the Granite Wash further complicates any effort to track the Granite Wash’s development from a holistic reservoir standpoint.

According to Halliburton, a qualitative analysis of pay potential can be made from traditional triple-combo log suites. This suite typically includes readings for gamma ray, bulk density, photoelectric factor, neutron porosity, and formation resistivity. However, high uranium content in pay zones, varying grain density, varying mineralogy, and even highly varying formation water resistivity make quantitative, multi-zone analysis ambiguous. More advanced logging measurements available from Halliburton are required to clear the fog surrounding Granite Wash petrophysics. The MRIL tool (magnetic resonance imaging log) has long been a valuable resource as it can see fluid types and fluid filled poor space, giving a very accurate measurement of effective water saturation and effective porosity. The CSNG tool (compensated spectral natural gamma) can differentiate between radioactive isotopes in the formation and help determine pay intervals.

These new tools in combination with standard logging tools can give an extremely accurate and predictive picture of the formations tested. Post-frac production logging can then be used to calibrate productive potential even further on future wells.

3-D seismic visualization calibrated with vertical well logs helps determine play trends and new wellbore paths, but microseismic fracture monitoring service provided through Pinnacle – a Halliburton service – can actually show where and how fractures propagate from both vertical and horizontal wells. As the Granite Wash depletes, well spacing goes down, and economic drives become stricter, it becomes imperative to have a tool that can visually link what’s known and key you into an optimized reservoir development plan.

Schlumberger has been working the wash for several years. Chris Shade, vice president sales for the Midcontinent area, observed that operators have realized that they will get better results with horizontal wells than with vertical wells. The economics indicate that horizontal wells deliver better returns than vertical wells – much higher production and reserves with a relatively small incremental cost. However, the challenge remains as to where to land the lateral – given multiple vertical targets – and how to stay in good reservoir rock. Asked if his company was using its high specification geosteering logging-while-drilling (LWD) tools to steer the well bore through high-quality reservoir sections, Shade said, “At the moment, many are trying to geosteer with the gamma ray. We believe this is a challenge because they cannot geosteer very effectively with only a gamma ray. Geosteering with the right tool combination may be the best way to approach the Granite Wash. At a minimum, measurements beyond the gamma ray only need to be made in the lateral section to better define reservoir quality along the lateral.”

Because Schlumberger uses the Elemental Capture Spectroscopy (ECS) service to measure mineralogy, they believe they have a better chance of identifying porosity. The company also uses the Sonic Scanner acoustic scanning platform to make geomechanical measurements to get local stress orientation. These measurements have been very important in the shale plays and Schlumberger believes they will be important in the Granite Wash too. “We use our ECS log to help identify mineralogy and by using this we do a better job of picking up the porous and permeable areas. Then we use the stress information from the Sonic Scanner to help land the well properly, design the lateral well trajectory, pick perforations, and design the frac,” concluded Rick Lewis, technical projects leader at Schlumberger.

Figure 3. The Schlumberger Sonic Scanner tool provides the benefits of axial, azimuthal and radial information from both the monopole and dipole measurements for near-wellbore and far-field slowness. (Photo courtesy of Schlumberger)

Shade explained that laterally, given the geological nature of this reservoir, Schlumberger aims to implement an engineered completion, compared to doing a geometric completion where perforation clusters are simply spaced out evenly. The objective is to direct the fracture energy in the best direction and at the best locations. For this job, along with the Sonic Scanner or LWD sonicVISION services, the company recommends its Azimuthal Density tool. “The key is to acquire data along the lateral in order to optimize the completion,” said Shade. “The Granite Wash play is a three-dimensional challenge. There may be from six to 13 potential pay zones, and they vary both vertically and horizontally. Through pre-drill modeling, we can simulate the well trajectory in advance to determine its potential.”

Lewis said, “Pilot holes tell you what is in the well, but not what is between the wells. The sand quality varies laterally as well.” When a pilot hole is in the plan, Schlumberger recommends its Platform Express integrated wireline logging tool augmented by the ECS log and the Sonic Scanner. This combination tells how much water is bound up in the clay, as well as anisotropy within the sands and shales. “We can take into account the laminations and determine that some shales are much greater barriers than others,” Lewis concluded. “Ideally, we would like to run all of these services in the lateral with LWD.”

Cementing Can Be Critical

The principle of planning before acting can be found in specific solutions BJ Services recommends and implements for its Granite Wash customers. Scott Nelson, region technical manager, said, “Each stage of constructing a well affects each subsequent stage, so we plan and execute our services with that in mind.” For example, a properly designed Granite Wash deviated wellbore cement program will provide formation isolation that facilitates future stage fracturing operations. Successful cement jobs can eliminate the communication of fluid and/or pressures along the well bore during the placement of multiple hydraulic fracturing stages. The use of foamed cements is well suited to this application due to their expansive nature with zero free water and low fluid loss properties.

The large extent of the multiple Granite Wash pays can require some 3,000 ft of vertical cement coverage. Due to the low frac gradient and subsequent formation breakdown pressures, cement designs often incorporate nitrified mud spacers ahead of cement systems to prevent the loss of circulation as the cement is lifted up the annulus.

Microseismic hydraulic fracture monitoring jobs on horizontal wells often reveal that there is overlap of frac stages attributable to inadequate cement isolation behind casing. In a play with such high variation in depth, pressure, temperature, and permeability, Schlumberger recommends a tailored approach to every production casing cement job unique to formation and well conditions. Using CemCADE cementing design and evaluation software for a thorough cement job design is critical for maximizing reservoir contact, completion efficiency and wellbore integrity. It incorporates wellbore hydraulics, slurry design, fluid compatibilities, and mud removal with special emphasis on slurry stability, so that a solid isolation between multiple frac stages can be assured.

Figure 4. Fortunately, most hydraulic fracturing in the Granite Wash is fairly straightforward with a traditional mix of water, a friction reducer, and frac sand — either plain or resin-coated to reduce flowback. (Photo courtesy of BJ Services)

Halliburton cited lost circulation and hole stability issues during drilling and completion as major challenges. Even today, serious problems arise when drilling, casing, and cementing Granite Wash wells. The Brown Dolomite is a well-known lost circulation zone that must be dealt with. In addition, the high inconsistency in rock strength, pore pressure and just general poor hole quality make drilling and completing the Granite Wash a significant challenge. Shale creep, whole mud loss, stuck casing, and poor cement bond are just a few of the effects of these issues. These are compounded when drilling a horizontal well bore in a formation with varying characteristics; many times based on extrapolated offset well-depth correlations and gamma ray.

A comprehensive approach at the drilling program is required to overcome the problems associated with poor hole stability. Recent Halliburton advancements in this arena include the following:

• The Geo-Pilot rotary steerable system has a perfect application in the Granite Wash’s complex lithology and geology. Coupled with ever-advancing bit designs, time in-hole has been greatly reduced which reduces risk and improves hole quality.
• The DFG software maintains tight control over the hydraulics associated with drilling, tripping and circulating the well bore. Twenty-four-hour mud condition monitoring services have become common.
• WellSET service treatments have had good success in controlling existing and potential lost circulation problems, which again lowers risk, time in-hole and poor hole quality.
• The ZoneSeal process is a proven solution to help control lost circulation problems while cementing and achieve excellent cement bond for life-of-the-well zonal isolation. Lower circulating density, better sweep efficiency, and a more elastic bond ensure the best possible zonal isolation across long intervals covering multiple pay zones.

According to the company, these technologies, coupled with a sensible drilling and casing program, will give the best chance of a completion, either vertical or horizontal, with no nasty surprises down the road.

Drilling Complexity Explained

Baker Hughes provided an example of the Granite Wash directional drilling challenges. Because formations change significantly laterally, the company recommends its real-time reservoir navigation system (RNS) to stay in the zone. First, pre-well models are derived from the pilot hole. Guided by the models, it was suggested that the client hold a tangent around 70° in order to reach the target top and then keep building inclination to the landing point. The resistivity response from the RNS tool was essential to follow the real- time correlation once it approached the target zone. However, the gamma ray response at this point indicated an evident lateral variation without correlation. On the lateral section, the resistivity curves couldn’t be associated with specific gas shows, minimizing the tool’s usefulness on this complex reservoir, and influencing the client decision to run the RNS tool without Multiple Propagation Resistivity (MPR) service.

From 13,747 ft measured depth (MD), interpretation was only accomplished through the apparent Gamma Ray and the Azimuthal Gamma Ray image response, determining the relative stratigraphic position and providing timely advice when the borehole was moving up or down through the target zone. The initial correlation showed the well was landed in the lower section of Granite Wash B in search of the best gas zone according to the Neutron/Density response in the pilot hole. However, after navigating into an inter-bedded shale with no significant gas show, the inclination was increased to around 95° to place the borehole in the upper section of Granite Wash B where it was kept with further inclination adjustments during the lateral by correlating with a nearby offset well.

Baker Hughes was able to navigate laterally approximately 4,500 ft. MD in the 68-ft- thick target zone, keeping 100% within the lateral section. This was accomplished by communication between the reservoir navigation engineers and geologist, using responses from the RNS tool. RNS resistivity and Azimuthal Gamma Ray played an important part in navigation through the target zone, providing confirmation of moving up or down section and warning of approaching the top or bottom of the zone. In future wells, it may be useful to rely on real-time resistivity as complementary information to achieve a better interpretation where the gamma ray lost continuity and correlation. To navigate through those important intervals, the required changes in inclination should be done smoothly, considering that the thickness of the sandstones bodies associated with the gas shows are about 1 to 3 ft. The upper Granite Wash B turned out to be the best zone for geosteering due to its high gas unit values. Once the density porosity log from wireline was integrated with the RNS model, it appeared the good porosity zones were related mainly to the best average rate of penetration performance as well as to resistivities below 25 Ohm-m.

Stimulation Issues Abound

Rocky Freeman, region engineer for BJ Services in Oklahoma City, commented on the challenges facing frac designers. He explained that multiple porosity layers are found within the Granite Wash. Each distinct layer is named alphabetically from top to bottom as Granite Wash A, B, C, D, E, etc. The total vertical extent can cover as much as 3,000 ft, with each Granite Wash pay separated by shale.

Figure 5. Chemists at Halliburton’s Duncan, Okla., laboratory solve complex problems associated with the heterogeneous mineralogy of the Granite Wash. (Photo courtesy of Halliburton)

An effective wellbore plan kicks off at the top of the Granite Wash then deviates downward and intersects all of the Granite Wash from top to bottom. Staged hydraulic fracturing treatments begin from the toe of the well bore and work up through the Granite Wash. The typical method of fracturing is pumping slickwater with sand or resin-coated sand, but the challenge with this treatment comes from the fact that proppant settling in non-viscosified water is severe and limits overall proppant pack length and coverage within the formation. This generates a sand bank, which only provides conductivity to the well bore from beneath the lateral. BJ Services is utilizing LiteProp ultra-lightweight proppant technology to pump nearly buoyant proppants that add conductivity from the upper portions of the created fracture geometry that remain untouched by sand. The ability to prop the open fracture from above and below the well bore has been performed with success in the Granite Wash.

Field studies on the production of offsetting wells have yielded significant differences in gas and condensate production rates. The difference in production relates to wells treated with polyacrylamide friction reducer slickwater with and without the addition of a breaker system. According to Freeman, as much as a 50% increase in production has been confirmed in Granite Wash wells treated with friction reducer breaker versus wells treated without the breaker.

Lack of frac water is a big headache according to Halliburton. Since the migration from traditional gel-based and foam fluid systems to treated fresh water, job sizes and the number of stages performed per well have only increased. Recent drought conditions in western Oklahoma and the Texas Panhandle have highlighted this challenge. But there is a solution. The reasons for using freshwater as the base fluid for water frac treatments are many, but the main four are 1) additive sensitivity to mixing water chemistry, 2) fluid impurities, 3) brine-water scaling tendency, and 4) the need for bacterial control. Use of recycled stimulation fluids and/or produced formation water, especially in combination, poses significant problems for all of these. Halliburton has developed several technologies to address water-related challenges:

• a new friction reducer FR-66 agent that greatly increases tolerance to dissolved solids in the mixing water;
• BE-9 agent is a new biocide that can be run on the fly;
• CleanStream service uses ultraviolet light to control bacteria and minimizes or even eliminates the need for chemicals to control bacteria; and
• effective and economical stimulation water treatment technologies are being developed.

While poor and varying water chemistry is having less effect on stimulation efficiency, Halliburton’s Duncan Technology Center in Oklahoma is studying the effects this complex chemistry may have on formation productivity.

Schlumberger sees the major challenge as ensuring the fracture is in the right place and that it propagates in the direction and to the extent specified in the stimulation design. For this, the company relies on its FracHite* rock stress analysis answer product log to predict where the fracture will propagate during the design stage. Where necessary, the company counteracts proppant settling using its FiberFRAC* fiber-based fracturing fluid technology, creating a network of fibers within the fracturing fluid to provide an efficient mechanical means to transport, suspend, and place the proppant. In addition to fracture height containment, the retained proppant pack permeability can be significantly increased because of the lower polymer loading required. When fewer polymers are used, more of the propped fracture contributes to production, yielding a longer effective fracture half-length. The fibers degrade, so permeability is restored across the entire treatment.

StimMORE effective diversion technology combines fluid-based, tool-free fracture diversion technology with StimMAP LIVE real-time microseismic monitoring. Microseismic data delivered while the fracture treatment is pumped allows

Figure 6. The Schlumberger StimMAP Live microseismic fracture monitoring service provides accurate answers in real time. (Photo courtesy of Schlumberger)

real-time optimization of fracture treatments, each fracturing stage can now be monitored and subsequent stages altered if necessary to provide optimum reservoir contact. Because it is fluid-based, the diversion slurries can be pumped on the fly as part of the main treating fluid, diverting the fracture as needed. By using a multi-component blend of degradable materials, StimMORE slurries temporarily block fractures, diverting fluid flow and inducing the creation of additional fractures along the well bore. The slurries degrade completely after the fracturing treatment has been completed and leave no residual formation damage. In re-fracturing treatments, where wells have existing perforations in place, effective diversion technology provides an innovative solution for fracture diversion when traditional methods such as bridge plug placement are no longer possible.

Double-Duty Wells Pay Off

Baker Hughes successfully applied a high-tech completion with excellent results. Multilateral completions have strong economic potential in the Granite Wash. Operators can save capital investment by accessing production from two laterals while drilling a single vertical well bore. Greater drainage access across a section is also possible by using this technology.

As operators continue to strive for greater lateral drainage per well bore, multilaterals are expected to play a growing role in the Granite Wash field development. The technical limits of drilling one long lateral can be overcome by drilling two shorter opposed laterals that yield the same reservoir drainage. Parallel and stacked laterals may provide greater connectivity to the reservoir after fracture treatment as well.

The technical challenge of such a project in the Granite Wash is to provide a seal across the junction to selectively fracture both laterals, which requires a TAML level 4 junction. The commercial challenge is to provide this technology and install it so that economic benefits exceed those of drilling two separate well bores.

There are three overriding criteria that the success of such a project will be determined by:

1. Can a multilateral system be drilled and installed at a cost less than drilling two single lateral wells?
2. Will the multilateral system deliver all the design criteria needed to properly complete these wells?
3. Will production results match or exceed expected rates from two separate single lateral wells?

Two multilateral wells have been drilled and completed in the Granite Wash to date. The multilateral installations were determined to have been a success. An average of 13% cost savings over drilling and completing two separate wells was achieved. Initial production appears to indicate that rates and drainage equivalent to two separate wells was realized as well.

Unaddressed Challenges Demand Solutions

Hart asked industry experts to elaborate on unaddressed challenges facing Granite Wash players. One suggestion is to improve the cost effectiveness of drilling and completing multiple laterals from a single mother bore.

According to Halliburton, one challenge the industry has not been able to solve yet is how to lower the risk and cost of drilling multiple laterals from a single vertical well to an acceptable level. Most horizontal well bores drilled in the various horizons of Granite Wash have, to date, been very successful producers. Horizontal well bores, however, reach only a small fraction of the overall height of the Granite Wash and its surrounding formations, even with large stimulation treatments. The quick, trendy and – you would suppose – obvious answer would be to simply drill a lateral in each successive lens of productive rock. In reality, if the lateral is not openhole, big challenges arise with lateral isolation, casing, kickoff, leakoff control, perforating and stimulating. Completion technology does exist to construct a multilateral with junction integrity and isolation, and stimulation technology does exist for the treatment of multiple intervals in those laterals; however, it still entails a much lower risk and cost to drill independent, single-lateral wells.

It is frustrating indeed to know that the capability exists to solve this problem, but at present the solution is cost-prohibitive. It could be simply a matter of more operators getting accustomed to drilling and completing horizontal wells in the Granite Wash, then the step to an optimum completion may not seem so large. The same could be said for obtaining better formation data upon which to make better decisions. Two choices seem to be to wait until the service industry comes up with slimmer LWD strings, or bite the bullet and drill larger well bores that can accept the existing equipment. It would seem that the latter choice could be made easily and would require a fairly modest incremental investment, compared to the potential value the logs could provide. All service companies agreed that the biggest challenge facing Granite Wash players is lack of knowledge, and by drilling and thoroughly logging a few strategically placed wells many of the Granite Wash mysteries might be revealed. Heterogeneity is only a problem if you don’t know where it is. Even the most complex formations can be adequately mapped if they can be penetrated by a well bore, and a horizontal well bore offers an even better chance to understand the reservoir.

The Prize Awaits

Almost daily, one hears of yet another Granite Wash success. Horizontal wells seem to be catching on with the operators, who are bringing in high-rate wells that produce large volumes of condensate and natural gas liquids. According to Chesapeake, the economics are very strong. Forest Oil brought in its first Granite Wash horizontal at 17 MMcfg/d. In January 2010, the company announced successful results from its third and fourth horizontal wells testing 15.1 MMcfg/d and 16.0 MMcfg/d respectively. The company expects to keep four rigs running continuously in the Texas Panhandle area this year. Newfield announced five of the seven horizontal wells it brought in tested more than 20 MMcfg/d. Results like these are encouraging and Granite Wash activity levels bode well for the immediate future, if not longer.