Many oil companies are trying to develop low-permeability tight gas reservoirs to meet specific industry challenges. This unconventional energy source is a fast-growing market; however, effective development of low-permeability tight gas reservoir resources requires operational efficiency to improve performance. Schlumberger increased investment in research and development will assist the industry with the specific challenges ahead.
Fiber-based fracturing fluid technology
Proppant settling occurs during hydraulic fracturing operations when the fluid viscosity falls below the critical threshold required to suspend proppant. The settling can reduce the deliverability of the fracture, negatively impacting productivity.
In slickwater applications, the viscosity of the base fluid is inadequate to provide proppant transport. In tight gas applications with conventional crosslinked fluids, the fracturing fluid is designed to break shortly after pumping. The fracture remains open for hours, and a low-viscosity fluid remains that is unable to suspend the proppant.
Tailored, fiber-based fracturing fluid
FiberFRAC fiber-based fracturing fluid technology decouples proppant transport from fluid viscosity. The technology creates a fiber-based network within the fracturing fluid, providing a mechanical means to transport, suspend, and place the proppant. Because the proppant transport then no longer relies on fracturing fluid viscosities, it can be tailored to reservoir conditions to optimize fracture geometry. If fracture height growth is a concern, a low-viscosity fluid can be used, even at high temperatures, while still maintaining good proppant transport.
In addition to fracture height containment, the retained proppant-pack permeability can be significantly increased because of the lower polymer loading required. Laboratory testing has shown that decreasing the polymer loading by 40% can increase retained permeability by 24%. When less polymer is used, more of the propped fracture contributes to production, yielding a longer effective fracture half-length.
Expanded temperature range
FiberFRAC technology can be applied in wells with 140 to 345 degF temperatures—a range that accounts for more than 80% of the tight gas wells in North America. Proven in both the laboratory and the field, the FiberFRAC technology enhances proppant distribution in hydraulically fractured wells for increased stimulation effectiveness and improved subsequent production.
Field tests have demonstrated that the fibers do not adversely affect retained proppant-pack permeability and hence fracture conductivity. Recent extensive field testing of fiber-based fracturing treatments in tight gas wells in North America has shown significant production improvements compared with production increases seen after conventional treatments in offset wells.
Applications
Hydraulic fracturing operations on tight gas wells
Low-permeability environments with extended fracture closure times
Temperature ranges between 140 and 345 degF
Slickwater fracturing fluid treatments
Crosslinked polymer fracturing treatments
Benefits
Improved production rates
Greater reservoir drainage efficiency for lenticular reservoirs
Increased retained proppant-pack permeability
Optimal dimensionless fracture conductivity
Less fracture height growth
Features
Proppant transport decoupled from fluid viscosity
Enhanced proppant distribution fibers that degrade over time
Lower-viscosity fracturing fluid extended temperature range
Lower polymer loadings
FiberFRAC Specifications
1.Temperature range：
-Low-temperature fiber 140 to 200 degF 140 to 200 degF
-High-temperature fiber 200 to 345 degF 200 to 345 degF
2.Fracturing fluid compatibility
-Low-temperature fiber Borate cross-linked fluids, ClearFRAC* family of polymer-free fracturing fluids, and zirconate cross-linked fluids
-High-temperature fiber Borate cross-linked fluids, ClearFRAC fluids, and zirconate cross-linked fluids
3.Proppant compatibility
-All mesh sizes: sand, precured resin-coated proppant, intermediate-strength proppant, bauxite
4.Energized compatibility
-Nitrogen in all cases; CO2 based on fluid compatibility
5.Connate water conditions
-Max. total water hardness 20,000 mg/L
-Max. magnesium 8,000 mg/L
Other Technologies of Schlumberger
HiWAY Flow-Channel Fracturing Technique
The HiWAY flow-channel fracturing technique significantly increases fracture conductivity while reducing water and proppant consumption. This means higher short- and long-term production, simpler logistics, and a smaller operational footprint.
Multistage Fracturing Services
Our fracturing and completion services maximize reservoir contact by offering the most efficient and effective reservoir stimulation service for each well.
Fracturing with Coiled Tubing: Perforate, stimulate, and fracture multiple zones in single field operations, and shock coalbed mehtane formations to produce longer, cleaner perforations.
Multistage Stimulation Systems: Minimize installation time, risks, and costs and bring wells onto production faster and more efficiently than with conventional plug-and-perf techniques.
PerfFRAC Shale Gas Dynamic Fluid Diversion Service: Maximize reservoir potential through high-rate fracture stimulation treatments down the casing with a perforating gun assembly in the wellbore.
ThermaFOAM High Temperature CO2 Fracturing Fluid
ThermaFOAM high temperature CO2 fracturing fluid is a unique chemical system specifically designed for fracture applications in wells with bottomhole static temperatures (BHSTs) between 200 and 300 degF [93 and 149 degC]. ThermaFOAM fracturing fluid is a CO2-compatible product that uses the CO2-polymer interaction to create stable and robust foam systems that allow polymer-loading reductions of up to 50%.
The reduction in polymer loading, combined with improved well performance and the elimination of the need for a crosslinking gel, has resulted in a fluid system that maximizes cleanup of the proppant pack within the fracture.
Significant reductions in time to sales can typically be expected for wells fractured using ThermaFOAM high temperature CO2 fracturing fluid, compared with wells stimulated using conventional fracturing technology.
UltraMARINE Seawater-Base Fracturing Fluid
The use of UltraMARINE seawater-base fracturing fluid simplifies offshore fracturing operations with unlimited availability and similar composition around the world with only small variations. Furthermore, UltraMARINE fluid can be used with brackish water for onshore operation in areas where freshwater availability is limited.
UltraMARINE fluid is engineered to provide optimized viscosity at bottomhole conditions to improve fluid performance during fracturing operations. The fluid is designed for enhanced thermal stability and has a bottomhole temperature range of 175 to 325 degF.
As an effective temporary scale inhibition for application in reservoirs with scaling tendency waters, UltraMARINE fluid mitigates the risk of scale precipitating from the seawater by controlling the pH. UltraMARINE fluid has a high tolerance to salt content and has been tested in waters with total dissolved solids (TDS) in excess of 100,000 ppm.
Microseismic Services
StimMAP hydraulic fracture mapping service for monitoring treatments records microseismic activity in real time during the fracturing process. A full range of software provides modeling, survey design, microseismic detection and location, uncertainty analysis, data integration, and visualization for interpretation, wherever and whenever decisions must be made. Computer imagery is used to monitor the activity in 3D space relative to the location of the fracturing treatment. Then, the monitored activities are animated to show progressive fracture growth and the subsurface response to pumping variations.
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