This February 2011 study compares the production and cost impacts of using energized and non-energized fracturing fluids on unconventional gas wells in the Montney formation. Analysis of roughly 24 to 36 months of gas production show significant benefit can be achieved from energized fracturing fluids and that their use warrants investigation in other unconventional oil and gas plays. There is illustrated potential for significant gas recovery improvement. There is also opportunity to reduce fracturing resources; the most significant of which is water and proppant consumption; there is also opportunity to reduce pumping rate and pressure in some instances. The potential environmental benefit of considerably lowering water consumption is attractive and may, in itself, justify their use. Energized fracturing treatments can cost more; however, the benefits are shown to far outweigh the incremental costs. The opportunity exists to improve unconventional well fracturing effectiveness and to reduce the resources used in those treatments by including nitrogen or carbon dioxide in the fracturing fluid. Based on the comparative assessment completed on the subject Montney wells in the Dawson Area of N.E. British Columbia, the use of energized fluids is shown to generate significantly improved well performance over those wells fractured with non-energized fluids. On average each well stimulated with energized fluids is forecast to potentially recover between 1.1 to 2.2 times as much gas as non-energized fracturing treatments the Study Areas 1 and 3 respectively. Area 1 Study compared the performance of Slick Water against Nitrified Slick Water and CO2 Foam fracturing treatments. The production analysis predicts an 11% incremental recovery improvement of 0.29 Bcf by using energized fluids. Though the treatment costs for the energized fracture treatments were seen to be higher, the value of this incremental recovery outweighs the additional cost with no incremental risk. Of note was the opportunity to reduce the fracturing fluid liquid volumes by over half with using CO2 Foam treatments rather than Slick Water. This shows the opportunity to improve production while also minimizing environmental impact. At marginal gas prices of $4.00/Mcf, the value of this incremental recovery approaches $1.4 MM from an incremental fracture cost investment of $500,000. Area 3 Study compared the performance of Gelled Frac Oil against CO2 Foam fracturing treatments. The production analysis showed a 124% incremental recovery improvement of 3.75 Bcf by using energized fluid fracturing treatments. At marginal gas prices of $4.00/Mcf, the value of this incremental recovery approaches $14.8 MM, from an incremental fracture cost investment of $400,000.
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. Following conventional hydraulic fracture treatments, 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. 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. Introduction 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. Both conventional bi-wing and the created volume fracturing theories require that the fracture matrix be a substantial distance from the wellbore. Both theories require a conductive path from the fracture network to the wellbore. The fracture length or volume needs to fully contribute to achieve maximum production.
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. IntroductionThe 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
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