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.
Flow Control Devices (FCDs) in SAGD applications have succeeded and failed to varying degrees and their use has not been overly pervasive or fully accepted yet. However, recently it has been publicized that FCD technology has achieved upwards of 100% improvement in SAGD oil production and potential improvements in steam oil ratios (SOR), which has continued to spark interest in its application. SAGD reservoirs are inherently heterogeneous and this presents distinct operational complexities when attempting to expedite the production of the oil while attempting to avoid steam breakthrough. Producing the steam reduces the thermal efficiency of the project which results in an increased SOR while also creating a high potential of compromising the mechanical integrity of the production liner. FCDs can mitigate the operational negatives and enhance the operational positives, however, they are not a ‘silver bullet’ for all ailments and their implementation needs to be carefully planned. This paper reviews FCD implementation workflows and highlights recent downhole instrumentation technology advancements that enhance FCD performance analysis and supports better deployment designs that should improve the economic viability of existing and upcoming SAGD projects.
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThis paper reviews the history of the world's largest running blowout as well as the integrated engineering based approach taken to define the blow-out mechanism and to ultimately kill and abandon the wells.During 1916 cable tool drilling operations, Peace River Oils No.1 encountered an uncontrolled flow of salt water and gas at 345 m depth. The flow was estimated at over 30,000 bbls/d, ultimately the rig collapsed into the sinkhole and temporarily killed the surface flow. The rig was rebuilt in 1917, recovered the production casing, but again a blow-out could not be controlled and the well was left to flow 30,000 bbls/day of salt water into the Peace River. At the time of the project initiation, there was one relief well (1955), one attempted relief well (1982) and a lost well (1916).The defacto well operator, the Alberta Energy and Utilities Board contracted an integrated team of professionals including well control engineers; geologists, drilling and completion engineers, geomechanics specialists and well operations specialists to evaluate the potential of effecting a permanent kill solution. This led to a primary recommendation to re-enter the 1916 wellbore via a flowing well operation to reach total depth and conduct a well kill.
A review of laboratory and field testing of a new flow control device is presented in this paper. The device is designed specifically to limit steam breakthrough in thermal operations. For the past few years, four companies operating Steam Assisted Gravity Drainage (SAGD) facilities in Alberta's oil sands have come together to study downhole Flow Control Devices (FCDs) in a laboratory setting and to share field data of the application of such devices. Within this collaboration, a new device was designed to address the challenge specific to thermal operations, namely limiting steam breakthrough into production wells. Laboratory tests were undertaken to define the steam-limiting characteristics of this device under field representative SAGD conditions at full scale rates, temperatures and pressures. Tests were performed with oil to gauge viscosity sensitivity, as well as with water and steam at various inflow rates, temperatures and steam qualities. Testing was also performed with Non-Condensable Gas (NCG) to help assess how methane production may affect performance under both low and high Gas Volume Fraction (GVF) conditions. Finally, three-phase erosion testing was performed using water, quartz and air, allowing a realistic, scalable assessment of the device's long-term reliability. Highlights from these tests are reported and compared to results from testing of conventional, commercially available devices. The new device has shown superior performance relative to other devices designed for non-thermal applications. Thus, it inhibits the influx of steam while allowing the flow of emulsion into a production well. Based on the results of laboratory testing, the device is currently being tested in field operations. Early indications are that the device is performing as expected. Preliminary field data are presented. Laboratory testing of thermal flow control devices is especially challenging and unique when compared with similar testing for conventional flow control devices. This becomes more evident when testing devices designed specifically to limit steam breakthrough. Furthermore, in thermal operations, the phase change potential that is inherent when operating near the saturation point of water opens new possibilities in the design of flow control devices. A successful, practical implementation of this phase change characteristic was achieved in a collaborative environment.
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