Making hydrocarbon production from shales a profitable venture requires a process for driving down overall costs. It is clear from experience in these tight, widely varying resource plays that companies achieve an advantage through many efficiencies reached during the entire exploration and development process.
The starting point is critical to the success of this process. Because shale varies greatly, what works in one reservoir or well probably will not be as effective in the next. Failure to understand the difference leads to expensive miscalculations and prolonged well development.
Each shale well and reservoir requires a high degree of understanding to reach its full economic potential. This is especially important when exploring new shale formations for which knowledge is a key factor in the speed and efficiency of bringing on production.
Lessens learned in exploiting the Barnett shale in north-central Texas, have helped form processes for evaluating and developing the Haynesville shale to the east of the Barnett and the emerging Eagle Pass shale south of the Barnett.
Need to know
The need to know cannot be emphasized strongly enough. Reservoir knowledge guides a multitude of choices that can make or break a shale well, including critical steps in designing optimal fracture treatments.
Understanding the reservoir in these complex unconventional resources entails a rigorous grasp of rock properties, fracture geometry, fluid interactions, evaluation processes, microseismic surveys, tracers, and production logs. It also requires sharing this information across disciplines so that insights are leveraged as effectively as possible.
Collaboration among geoscientists and engineers is central to improving shale exploitation. Having a single strategy for the entire well rather than a series of discrete operations enables everyone on the asset team to make decisions with full knowledge of how actions affect total well objectives.
Specialized processes for shale analysis and stimulation design facilitate this effort. For instance, Halliburton's ShaleEval shale formation evaluation service forms expert shale teams that integrate geology and engineering in a process that examines fluids, the fracture treatment, formation evaluations, and candidate selection.
The process also uses shale-specific systems to identify mineralogy and integrate wireline log data and laboratory core analysis to help define shale characteristics. The information guides fracture treatment design by helping identify targets, which is critical to well performance in shale reservoirs. These systems are components of a life-cycle-based approach to developing shale reserves that Halliburton uses to integrate asset management from the first look at reservoir potential through development stages and decline.
Ultimately, this knowledge sharing facilitates a holistic view of the reservoir throughout its development, which brings with it the various insights needed to create shared efficiencies and synergies.
Formation description
Companies can acquire reservoir information with basic logging suites. Their primary purpose is exploration and calculation of reservoir fluids. But new analysis and presentation techniques provide a comprehensive formation description that is routinely verified and calibrated with core analysis.
A variety of logs provides highly practical information about shale. For example, formation lithology is identified with natural gamma ray tools to measure elevated uranium signals that are common indicators of shales rich in organic matter and total organic carbon (TOC). When they also exhibit sufficient porosity, these shales typically are productive.
Information also comes from resistivity measurements that indicate fluid saturation and permeability in the shale. Low permeability and high clay content can be an early indictor that the shale may not respond well to treatment.
Density logs and dual count neutron logs indicate shale porosity and the associated reservoir capacity for storing fluids. Acoustic logs, which record the velocity of compressional and shear waves through the formation, are used to generate stress data, which help predict the behavior of hydraulic fracturing treatments that are critical to shale production.
Images of the formation acquired with electrical borehole imaging tools provide views of the sedimentary sequences in the wellbore. This information is used to plan optimal horizontal well trajectories in shales, guide sidewall-coring points and identify pressure dependent leak-off points from small fractures.
Magnetic resonance logging provides data on the fluids in the pore spaces as well as other formation parameters such as pore size, calculated permeability and presence of clays. In shale wells, these data cover the long, continuous intervals at reservoir conditions with less expense than conventional core data.
Building on the Barnett
Much of what is known about the mysteries of shale rests on lessons learned in developing commercial production out of the Barnett shale in north-central Texas. In pioneering this resource play, companies have applied innovative new technologies and methods subjected to almost daily changes.
But successful techniques hammered out in the Barnett are not easily transferred to new and emerging shale plays. Experience proves that methodology is the most important constant in shale development, not discrete techniques. Using a process that starts with reservoir knowledge is key for selecting the most appropriate techniques and achieving the highest efficiencies.
To the east of the Barnett, the Haynesville shale straddles the borders between Texas, Louisiana, and Arkansas in one of the oldest productive regions in the US.
While the Haynesville is also a tight-gas shale, the comparison of its relatively ductile rock with the Barnett shale is one of peanut butter to peanut brittle. Understandably, wells in these two shales are not completed in the same way. Fig. 1 shows various shale samples.
First drilled in 2005, the reservoir is deep at about 10,500-14,000 ft and hot with bottomhole temperatures as high as 380° F. Bottomhole pressures can exceed 12,000 psi and treating pressures climb to 15,000 psi. Its laminated shales include soft ductile intervals that can cause proppant embedment and fines problems.
There is vigorous discussion about how best to produce this resource and a correspondingly diverse set of production successes and failures. That has resulted in a competitive learning curve in this promising play as operators seek to exploit it economically.
Haynesville treatments
Reservoir knowledge is proving to be the best starting point for unraveling the Haynesville shale. A Halliburton study of modeled stimulations to test various treatment strategies has further defined fundamental differences in rock character and reservoir conditions compared with the Barnett shale.
The study reviews the design processes and technologies recommended to achieve the best production results.1 Its results are not indicative of any one particular well or set of reservoir characteristics.
Simulations conducted in the study indicate that formation brittleness is a valuable guide to identifying fracture initiation points. Perforating and fracturing from these intervals are critical to successful stimulation.
The study also shows that low-viscosity fluid systems do not provide adequate proppant transport and suspension to achieve long-term productivity in this formation. The Haynesville, however has successful simulations with crosslinked gel fracture treatments containing high-conductivity proppants.
The successes were attributed to better wellbore-to-fracture communication established by proppant distribution throughout the created fracture height and length.
Fluid systems
In simulating a variety of treatment designs, the Haynesville shale study model consisted of a typical 4,000-ft lateral section broken into stages of about 300-400 ft. Within the stages were 3-4 perforation sets of 2-4 ft in length with a perforation density of 6 shots/ft.
To simplify the simulation, the study evaluated a single fracture created in a horizontal wellbore. It selected fluid systems based on rock properties.
The Haynesville shale is a generally ductile formation with relatively low Young's modulus and Poisson's ratio. Identification of brittle areas is important because these are the best targets for fracture initiation. But there are concerns too. These areas have significant lime content that can cause fines problems if acid is applied.
Clays are also present and can result in fines and swelling damage in response to water-based fluids.
The study also simulated multiple treatment designs to address treatments in the Haynesville shale that vary from high-rate, treated-water fractures, hybrids of treated water and linear gel, and hybrids of linear gel to crosslinked gels.
Water fractures with low proppant concentrations and large water volumes provide minimal conductivity damage and low costs. Linear-gel systems have good friction-reduction properties, similar to the water fractures with friction reducer.
Crosslinked-gel fracturing fluid systems allow treatment at lower pump rates, with smaller fluid volumes and provide the ability to place high-conductivity proppants. Placing high-conductivity proppants is not attempted with low-viscosity fluids because of the poor proppant transport and narrow fracture widths.
The fluid efficiency and excellent proppant transport of crosslinked systems can maximize formation surface-area contact and communication with the wellbore to achieve the benefits of the long, horizontal sections with spaced fractures communicating with the wellbore.
High-viscosity fluids help establish a dominant fracture to accept larger high-strength proppants (20/40 mesh). In addition, more effective proppant transport provides a longer effective fracture with direct communication at the wellbore.
Fig. 2 shows a typical fracturing spread on a Haynesville well.
Proppant options
High temperatures and pressures make proppant selection in the Haynesville important for short and long-term production. Cleanup and early production following fracturing are the immediate issues. But over time as reservoir pressure depletes, the increasingly stressful environment becomes the greater consideration.
Fracture conductivity may be the most important parameter for long-term production of the Haynesville shale. Initial closure stress on the proppant in the fracture may start at more than 6,000 psi. As production continues, the stress increases and can exceed 12,000 psi.
For water-frac treatments, conductivity issues include initial conductivity, two-phase flow (gas and water), proppant crushing and fines, and proppant embedment in the fracture face.
For linear-gel treatments, conductivity concerns include the same list, with the addition of a polymer filter cake. Crosslinked-gel treatments add concerns about the yield stress of residual polymer in the fracture. Gel breakers can address both the polymer filter cake and residual-gel issues.
Embedment is another issue. Proppants embedded into the ductile shale by formation pressure leads to decreased fracture width and the resulting lower conductivity. Brinell hardness numbers (BHN) can be used to infer embedment. Table 1 from a Halliburton internal report shows BHNs for different formations, including several shale plays.
Shale formations have a great amount of variation. The Barnett is very hard with a BHN of 80, while the Marcellus BHN is a much softer 32. The Haynesville shale, with a BHN of 18, has one of the lowest values seen for low-permeability stimulation targets, indicating the most potential embedment.
These extreme variations from hard to very ductile formations are a strong indicator of the pronounced differences between shales and the scope of techniques that might be applied. What works in one play may not work as well in another and not at all in a third.
The study considered proppant conductivity for proppants for Haynesville shale stimulation treatments at simulated reservoir conditions of temperature and stress and proppant concentration of 1 lb/sq ft. Results of the simulations clearly show that man-made proppants are the most appropriate proppant based on conductivity. While this does not consider effects that reduce the conductivity of all proppants, it does show the relative performance of the proppants to guide selection.
The study shows the practical importance of petrophysical information in designing effective fracture stimulations of the Haynesville formation. Organic content, ductility and brittleness, clay content, and a host of other characteristics are fundamental to targeting the treatment and to the design of fluid and proppant systems.
A typical Haynesville well, designed to produce at high rates and low cost, maximizes reservoir exposure while eliminating communication between fractures with a reliable annular seal (Fig. 3).
Eagle Ford
South of the Barnett in the emerging Eagle Ford shale. Early operators are in the process of understanding a formation that recently was an obstacle rather than an objective.
Stretching across a broad swath of Texas from northeast to southwest, its potential is equally huge. But the play is very young and largely confined to three southwest counties: McMullen, LaSalle, and DeWitt. In these counties it lies at depths to about 12,000 ft.
The likely source rock for the Austin chalk formation above it, the Eagle Ford shale exhibits an altogether new range and different scope of shale characteristics, and challenges from the Barnett and Haynesville shales.
One of the most topical issues at this stage in the Eagle Ford is drilling through the depleted zones above it. Companies are drilling mile-long multilaterals in it, but the temperatures and pressures do not appear to be too demanding.
Still, the differences are being carefully considered, from variations in fluid compatibilities to changes in drilling and completion strategies. And within the Eagle Ford, operators are quietly noting the variations that exist within its boundaries, where shale depth, thickness and mineralogy can change dramatically over short distances.
As the resource play picks up momentum, the knowledge that is being collected now will be a major factor in how efficiently it is developed. The ability of early operators to achieve the efficiencies and effectiveness of an integrated process driven by this reservoir knowledge will determine the pace and the success of the Eagle Ford resource play.
Start at the beginning
The effort under way to understand the Eagle Ford is the hallmark of success in gas shales. Clearly, this emerging play varies from the Haynesville shale, which is markedly different from the Barnett and other shales around the world.
The only way to approach economic development of these resources is by first understanding their unique characteristics. That knowledge guides a holistic approach that builds efficiencies during the life of the asset.
Reference
- Parker, M., "Haynesville Shale: Hydraulic Fracture Stimulation Approach," Paper No. 0913, International Coalbed and Shale Gas Symposium, Tuscaloosa, Ala., May 20-21, 2009.
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