Case Study of a Novel Hydraulic Fracturing Method That Maximizes Effective Hydraulic Fracture Length
- Eric Hughson Tudor (BJ Services Co. Canada) | Grant Walter Nevison (Gasfrac Energy Service) | Sean Allen (Gasfrac EEnergy Services Inc) | Blaine Pike (Paramount Resources)
- Document ID
- Society of Petroleum Engineers
- SPE Annual Technical Conference and Exhibition, 4-7 October, New Orleans, Louisiana
- Publication Date
- Document Type
- Conference Paper
- 2009. Society of Petroleum Engineers
- 5.6.3 Pressure Transient Testing, 5.6.4 Drillstem/Well Testing, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 4.2 Pipelines, Flowlines and Risers, 6.6.2 Environmental and Social Impact Assessments, 2.5.2 Fracturing Materials (Fluids, Proppant), 2.5.1 Fracture design and containment, 5.1 Reservoir Characterisation, 1.10 Drilling Equipment, 4.6 Natural Gas, 5.5.8 History Matching, 2.4.3 Sand/Solids Control, 4.1.5 Processing Equipment, 1.8.5 Phase Trapping, 4.1.2 Separation and Treating, 5.6.9 Production Forecasting
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Effective fracture lengths are frequently observed to be much less than antcipated fracture lengths. This is seen in lower than expected production or evidenced in pressure transient analysis results. A precursor to the poor fracture performance is poor recovery of the fracturing fluid; often less than 50% is recovered during clean-up. In many reservoirs this unrecovered fracturing fluid remains immobile within the formation creating an obstruction to flow. This significantly compromises effective frac length and results in decreased production.
During the fracturing process and subsequent closure of the fracture, the bulk of the fracturing fluid invades the reservoir matrix along the fracture face, referred to as the "invaded zone??. This fluid is forced into the reservoir by the significant pressure differential between fracturing pressure and reservoir pressure. Once in the matrix, removal of fluid from the invaded zone can be very difficult as it is held by relative permeability, irreducible saturation, and/or capillary pressure effects.
A novel hydraulic fracturing process using 100% liquefied petroleum gas (LPG) has demonstrated quick and complete fracture fluid recovery, significant production improvements and dramatically longer effective fracture lengths. The process gels the LPG for efficient fracture creation and proppant transport. With that there is no compromise in the fracture treatment placed when compared to conventional treatments. However, once the fracture treatment is complete and the viscosity of the gelled LPG is broken, the unique properties of LPG create an ideal fluid for complete cleanup. Removal of this fluid from the invaded zone is easily achieved; relative permeability effects, irreducible saturation behaviour and capillary pressure demands are eliminated. Complete recovery of the LPG is consistently demonstrated.
Fracturing with 100% gelled LPG was first completed in January 2008. By June 2009 over 210 fracture treatments had been completed. This new process has been applied to a wide range of formations from depths of 750 ft through to 11,500 ft. In this paper, short term technical evaluations, such as post fracture pressure transient analysis, are used to demonstrate the rapid cleanup and effective fracture lengths that approach anticipated fracture lengths. Long term actual production comparisons will be a focus on future papers as results become available.
The science of hydraulic fracturing has predominately been focussed on fracture geometry and proppant placement to maximize production rates and cumulative production. Current technology for hydraulically fracturing tight reservoirs, including shales, often focuses on complex fracture volumes rather than bi-wing geometry to create and maximize the formation stimulated area. This in turn results in optimized commercial production rates. Within the conventional bi-wing hydraulic fracturing theory it is well understood that the optimized fracture length is inversely proportional to reservoir permeability. Similarly, the created fracture volume model used on shales tends to follow the same theory that optimized created volume is inversely proportional to the reservoir permeability.
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