Frac advances key to unconventional gas supply growth

Sept. 22, 2008
Advances in production stimulation technologies have been critical to the meteoric growth in unconventional gas supply.

Advances in production stimulation technologies have been critical to the meteoric growth in unconventional gas supply.

The unconventional gas share of US natural gas supply has surged to more than 40% today from less than 7% in the late 1970s, when government-sponsored research into unconventional gas technologies got underway. Some have predicted that the unconventional gas market share could top 50% in 2025–30.

Today, improvements in well fracturing technology have been instrumental in gas shales emerging as the hottest hydrocarbon play in North America. Advanced fracturing techniques are also playing a key role in recovery of natural gas from tight sands and coalbed methane (CBM) as well.

Gas shales

It is well known that hydraulic fracturing is the major enabler to convert nano-darcy reservoirs into profitable plays, notes Don Conkle, Schlumberger vice-president, stimulation services.

“As more shale reservoirs are exploited and discovered, proper reservoir characterization (geological and petrophysical models) will dictate the ways to optimally complete and stimulate wells,” he points out. “Along those lines, technologies that will decipher stress anisotropy (e.g., the Sonic Scanner) and its effects on fracturing placement will be key for better reservoir management.

“Also, technologies that will allow operators to control fracturing geometry will be on top of the game-changer technologies; in today’s environment, hydraulic fracturing monitoring by microseismic is a quite powerful tool to determine where the fracture goes. However, having the opportunity to control fracturing placement by using diverters poses a great challenge for operators and service companies and could be definitively a game-changer in the way that well cost can be reduced by completing horizontal wells in an open hole environment with the capability to control treatment diversion in real time.”

In environmentally sensitive areas, such as those where the Barnett shale is being exploited, another concept that could be a game changer would be to find the ways to create the same fracture geometries by using less materials (water and sand), Conkle says.

“Water supply these days might not be an issue for some operators, but certainly in years with severe drought, water may become a scarce resource, so techniques that will improve the fracturing placement in the areas where reservoir engineers want it will have the potential to reduce treatment sizes significantly.”

The biggest production driver for shale formations is the completion, according to Bill Grieser, Halliburton’s Oklahoma City-based technical analyst.

“This requires a reverse engineering approach,” he notes. “The final well operation — the completion — must be the initial consideration in order to design all of the other components involved in producing the resource.”

Grieser notes that it is difficult to achieve commercial production from nano-Darcy rock without the substantial increase in surface area that can be generated by complex hydraulic fractures.

This is why industry seeks brittle shale rather than ductile shale as potential producers, he adds: “Calculations indicate it takes 1 to 2 million sq ft of surface area to generate the >1 MMcfd gas rates.”

The biggest production driver for shale formations is the completion: “This requires a reverse engineering approach. The final well operation — the completion — must be the initial consideration in order to design all of the other components involved in producing the resource.”— Bill Grieser, Halliburton

Multistage mechanical bottomhole assemblies are being used to reduce cycle time and complete wells faster, Grieser points out: “Laterals are getting longer. Frac stages are increasing in number. Stimulation span is getting shorter, and more perforation clusters are being used. Proppant amounts continue to increase. More hybrid-style fracs are being used to reduce damage and place more proppant. Production and proppant trends seem to indicate conductivity is important.”

Conductivity enhancement is critical for high-rate waterfrac treatments, concurs Barry B. Ekstrand, vice-president, reservoir stimulation, Weatherford International.

“Sand sizes have gotten progressively smaller in high rate waterfracs, as water in absence of a viscosifying agent is a poor and inefficient sand transport medium,” he says. “Smaller sand is more readily accepted into the created fracture, but it still settles quickly to form a bed at the bottom of the fracture. This leaves a potentially significant amount of created fracture without any sand in suspension across it to prop it open at the end of the treatment—and thus unconnected to the conduit from the reservoir into the wellbore.”

Conductivity enhancement is achieved with specialized chemistry that coats the sand grains and causes rearrangement such that bed porosity and permeability increases, according to Ekstrand.

“The distribution of sand is increased in height, and the proportion of the created fracture area that is propped open at the end of the treatment is increased,” he notes. “The result is a more efficient production conduit into the reservoir and increased longevity of fracture conductivity for a given job size.”

Another advance in fracturing technology involves simultaneous fracturing, or simulfracing, multiple wells.

“The benefits [of simulfracing] to the reservoir are the higher hydraulic horsepower delivered per volume of rock, resulting in a larger, more complex fracture network,” Grieser says. “The benefit to the operator is completion of two wells in a shorter period of time.

“The drawback is the extra effort required from both the operator and service company to mobilize two to three times the equipment, manpower, and materials and orchestrate a continuous operation without delays or breakdowns.”

Early production analysis of more than 100 simulfraced wells has shown, on average, a production increase vs. conventional, single-well treatments, he cites. Late-time production is not yet available to determine the effects of linked fracture networks.

Among the new techniques and new technologies being brought to bear on the challenges posed by gas shales is that of fiber optic cable being used to provide a real-time temperature profile during the fracturing treatment to determine frac position and placement efficiency along the horizontal wellbore, says Grieser: “Fiber optic cable can also be used during production to determine areas of high productivity and areas that need restimulation.”

The Halliburton analyst also foresees increased use of salt-tolerant fracturing chemicals that allow the reuse of returned frac water and the implementation of mechanical, chemical, and operational diversion techniques to refrac horizontal wellbores that drive creation of new fracture paths.

In addition, operators are looking at the “shale oil window” as potential shale targets that previously have been avoided in favor of dry gas, Grieser notes.

Just as important are industry’s improvements in the environmental footprint of fracturing operations.

Drilling pads containing multiple extended-reach wellbores drilled and completed from the same location help reduce that footprint, according to Grieser.

“Smaller location size may drive the industry to compact completion/drilling equipment, including coiled tubing and skid-based fracturing equipment,” he says. “This will force the hydraulic horsepower, water, and proppant to be delivered to the formation in a focused manner, normally called pinpoint stimulation.”

Water management is also a crucial environmental issue, as this natural resource becomes increasingly scarce and and more costly each year.

“Water storage and disposal cost has gone from $1.00/bbl to $6.00/bbl in the past 8 years,” Grieser points out. “It now competes with drilling and completion costs as one of the major cost items. The industry is under pressure to recycle, reclaim, and reuse this valuable resource.”

Tight sands gas

Although exploitation of tight sands gas has taken a back seat to the hot shale gas plays, tight sands gas nevertheless accounts for one-third of US gas production and reserves.

Ekstrand contends that the game-changing production stimulation technique for tight sands gas “will center on eliminating damage of the fracture wall with viscosifier technologies that dramatically increase viscosity yield of materials, so significantly smaller amounts of foreign material are injected into the reservoir.”

Such systems will have a much higher viscosity-to-polymer weight ratio and flatter viscosity profile, meaning longer life of the viscosity, he adds.

“Similarly, improvements in filter cake degradation/removal technologies will improve productivity by minimizing skin effects of the filter cake on the fracture wall for increased productivity and longevity.”

Coalbed methane

Two Denver-based Halliburton experts—Mike Mullen, principal technical professional, and Kumar Ramurthy, technical professional-team lead—advocate a “holistic” approach to understanding and effectively stimulating CBM reservoirs.

Such an approach has five main components, they say:

“The first step begins with understanding the rock stresses in and around the coalbeds. This is a critical step in understanding how the hydraulic frac treatment will interact with the reservoir.

“The second step is to understand the gas stored in the system, in the coals, shales, and the sands that may be interbedded with the coals and shale. This petrophysical analysis can be accomplished using Halliburton’s StimLOG software to provide a total system resource assessment that captures the gas in place of the sand, coal, and shale in one evaluation.

“The third step is to understand system permeability. This is essential for the proper design and placement of the frac treatment, as well as for reservoir modeling to understand reservoir performance.

“The fourth step is to take all this information into the fracture design process. There is no ‘one frac design made to fit all coals’: While there will be some trial and improvement to the frac design, frac modeling has proved to be a very useful tool not only for the design of a CBM frac but also in the post-job analysis to help diagnose and understand the stimulation issues specific to that particular coal.

“The fifth step is to review the post-stimulation well performance. Is it producing as expected? Are coal fines or frac sand being produced? If so, a number of remedial treatments could be applied during the stimulation treatment to address these issues before they happen.”

Ekstrand also thinks it’s important to address the issue of coal fines being released during fracturing, which results in plugging and a loss of fracture conductivity.

“Coal fines agglomeration technologies that chemically bind together the coal fines provide stabilization of the coal fines and inhibit or stop migration of any that are released as they bind to become larger particles that no longer can enter the fracture,” he says. “The result is higher fracture conductivity and longevity.”

Horizontal wells completed with discrete fracturing ports that can be ball- or dart-activated for precise fracturing initiation are bringing a different life to CBM plays, according to Conkle: “With more horizontal wells completed in CBM, some of the technologies currently used and that will be used in shale plays will definitively impact the development of CBM plays—for instance, hydraulic fracturing monitoring, nondamaging fluids, and low-temperature diverters, among others.”

Controlling diagenesis

Fracture diagenesis may be the most important and exciting area of research aimed at maintaining fracture conductivity, contends Matt Oehler, Halliburton fracturing product manager in Houston.

“Successful prevention could lead to substantial production uplifts without the need to refracture wells experiencing production decline,” he says. The discovery and definition of rapid-onset diagenesis and the development of a service that helps prevent it is expected to have a profound effect on well completions throughout the industry, Oehler adds.

The diagenesis process is assumed to normally require millions of years, but in the case of hydraulic fracturing, it can occur within a few months. Prevention of the early onset of proppant diagenesis contributes significantly to the productive life of hydrocarbon wells.

Diagenesis-type reactions can occur between proppant and freshly fractured rock surfaces via generation of crystalline and amorphous, porosity-filling minerals within the proppant pack. Although rapid loss of fracture conductivity after hydraulic fracture stimulation is often assumed to be the result of migration of formation fines or the generation of fines derived from proppant crushing, Oehler cites recent laboratory work that points to diagenic reactions because of chemical compositional differences between the proppant and the formation, and compaction of the proppant bed due to proppant pressure solution reactions.

“This damage mechanism applies to propped, fracture-stimulated wells; however, it is more significant in high-temperature and high-stress wells,” he says. “Diagenesis might explain the difference often observed between reservoir simulation of production after fracturing and actual production, including the decline rate.

“The rate of production loss is directly related to the diminishing rate of fracture conductivity that results from narrowing of propped fracture width and infill of proppant pack porosity. As pressure dissolution takes place, propped fracture width reduces under stress; but as precipitation (or recrystallization) occurs, precipitant fills in the pore spaces between proppant grains. As little as 25% of the initial proppant-pack porosity may remain after only 40 days at 300° and 6,000 psi closure stress.”

To control proppant diagenesis, Halliburton applies a hydrophobic, dielectric material to fracture proppant before the proppant is pumped downhole as part of a hydraulic fracture stimulation treatment. The service helps prevent the early onset of diagenesis.

“The rate of porosity loss can be reduced by treating the proppant with a dielectric coating that makes the proppant surface hydrophobic (water-hating) and insulated (inhibiting water-based chemical reaction),” Oehler says.

“A survey of wells fractured or refractured using proppants coated with a dielectric, hydrophobic material showed very stable production over time. Wells in the same area that were completed using uncoated proppants generally demonstrated steeper declines and less-sustained production.”

Hydraulic fracturing, produced water

One of the dilemmas for production stimulation experts is how to deal with the huge volumes of produced water and consequently the use of that produced water in hydraulic fracturing efforts.

Water costs, which can account for 30–50% of total well completion costs, is a necessity for all phases of drilling, completion, and stimulation activity. Being able to cost-effectively source, handle, treat, and dispose of water is a critical concern in production stimulation efforts. And it is becoming increasingly important, especially in the US Lower 48 Western states, to better utilize produced water and minimize use of fresh water supplies.

Leonard Case, stimulation product manager-equipment systems for Halliburton in Duncan, Okla., contends that the handling of produced water is transitioning from a liability to an asset, becoming a significant part of the value chain in the monetization of oil and gas assets.

Produced water has been used in production stimulation to varying degrees over the years, he notes: “The most common approach is to either use the produced water as is, modifying the final stimulation fluid system to give acceptable performance, or diluting the produced water with fresh water to bring the mixture to some minimum acceptable state and then modifying the frac fluid system.

“These are very unique solutions and only good for similar produced waters. With these solutions, there is always a tradeoff between fluid performance and economics.”

To overcome the variability of the source water, some producers have incorporated a treating processes such as evaporator distillers or reverse osmosis, Case points out.

“Both of these processes produce water that is either drinking quality or very near drinking quality. which removes all variability from the produced water. The limitations of both of these processes is that they are very capital-intensive, have relatively low throughput volumes, and will not handle all produced and flowback water without some type of pretreatment being performed.”

What the industry needs is a process tailored to typical oil field conditions, adds Case, “where job rates can vary from 10 bpm (barrels per minute) to >160 bpm, with total job volumes ranging from 60,000 gal to more than 3,000,000 gal and where the produced water quality can vary from 1,000 ppm to 300,000 ppm total dissolved solids.

“Now in field testing, Halliburton has addressed this challenge by developing the technology to selectively remove the ions that hamper our ability to use the produced water as a base fluid from which to create a fracturing fluid. Most produced waters contain different levels of sodium, potassium, magnesium, calcium, strontium, barium, iron, boron, chlorides, residual oil, and a host of production chemicals.

“With our ‘selective ion removal’ process, we can selectively remove the harmful ions such as calcium, magnesium, barium, iron, and boron, as well as the residual oil and various production chemicals.

“What we are left with is what we refer to as a ‘treating brine’ containing sodium, potassium, and chlorides. Not only can we effectively remove the targeted ions, we can vary the amount removed; therefore, we create a ‘standard’ treating brine that will give the same performance from a wide variety of produced water. This newly created treating brine is ideal for use in lower-rate water frac applications as well as linear fluids or borate cross-linked treating systems.”

To that end, Halliburton has developed a new biopolymer-based, linear—no crosslink required—frac fluid system that can use produced water and eliminates the need for hydrocarbon-based concentrates.

“Because the system does not require potable mixing water or crosslinkers, the fluid is both practical and economical for use in a variety of produced waters,” claims Oehler. “Eliminating the need for purchase and transportation of potable water for fracture stimulation reduces cost, reduces demand on potable water supplies, and contributes to the sustainability of favorable health, safety, and environment conditions.”

The new fracturing fluid is mixed from a dry polymer, reducing its potential environmental impact in that no hydrocarbons are needed. The fluid can be mixed into tanks or on-the-fly with a new dry polymer blender. In typical water temperatures, 80% hydration can be achieved in under 5 min. Because there is no crosslinker, there are no additional liquid additive pumps, nor are crosslink quality-control tests needed.

“The new fluid outperforms traditional crosslinked gels and offers an economical, superior alternative to surfactant-gel technology for fracturing low-permeability, medium-temperature (150–250 °F) formations with permeability below 10 md,” Oehler says. “In the resulting fracture, the retained conductivity of the proppant pack is often greater than 80%, and the system breaks and cleans up effectively.

“The low pipe friction generated by linear fluid makes it ideal for pumping down tubing and coiled tubing for multistage, pinpoint stimulation, and applications in unconventional reservoirs where high pressures are required at the fracture face.”

Oehler thinks that the new fracturing fluid will have a “profound” influence on the way the industry does business: “It has the capability to perform without crosslinking and without liquid concentrates that require BTEX [benzene, toluene, ethylbenzene, and xylenes] to function. Further, it does not require transporting and consuming ever more scarce potable water.”

Equipment innovations

Key areas of fracturing equipment innovation have focused on improving efficiency, reducing emissions, and increasing reliability, according to Chad Joost, sales manager, well stimulation products, Stewart & Stevenson.

“The improvements in efficiency have been achieved through the development of our distributed control and data acquisition system (AccuFrac and the Intelligent Pump Control), providing unit control and visibility to all recorded parameters from inside the Data Acquisition and Control Unit (commonly referred to as the Data Van),” he says. “This system allows the key wellsite personnel to control all aspects of the job and reduces the personnel demands on the wellsite—also providing some relief to the service companies’ hiring requirements in a very tight labor market and allowing equipment operators to rest between unit mobilization.”

With the US Environmental Protection Agency’s off-highway emissions requirements now at Tier 2 levels for engines at or above 750 bhp, Stewart & Stevenson has developed fracturing equipment meeting those requirements with emissions-compliant engines and cooling systems.

“These emissions-compliant units have been well received in the US market as a result of our industry’s drive toward reducing our environmental impact,” Joost notes.“We expect to see even greater emphasis on reducing emissions in markets outside of the US.”

In addition, fracturing equipment reliability has improved significantly by integrating real-time diagnostics with the pump control system (Intelligent Pump Control), says Joost.

“This functionality informs the equipment operator of any faults during the job and takes the appropriate action (alarm only, unit rampdown, or unit shutdown),” he says. “In cases of unit alarms, the fault is logged and addressed after the job or during the next maintenance event. In the case of faults of greater importance, the control system takes the appropriate action to avoid further damaging the equipment.

“Other advances that have improved equipment reliability include preventative maintenance programs that are controlled through databases with operating fluid analysis, improvement in equipment design with high-strength materials and advanced designs, and operator training through the OEM.” ]