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Early stimulation work in Peat Field of Queensland, Australia involved application of cavity completion techniques to produce methane gas at commercial rates in the first wells completed in the reservoir gas cap. Early in the project life, cavity completion treatments resulted in promising and acceptable gas flow rates. However, excessive cost associated with this technique led to consideration of alternate stimulation approaches by the design team. The main objective was to achieve similar or better gas rates at the lowest cost. Multi-seam nitrogen-foam stimulation was conducted in several wells of the Peat field to assess the effectiveness of this technique in terms of:production enhancement and cost reduction;location of the coal-seam intervals in the gas cap (i..e. gas-saturated coals) and;improved completion efficiency. To minimise the effects of tortuosity and multiple far-field fractures in addition to ensuring that each coal-seam interval received adequate treatment, a staged stimulation approach in combination with other remedies such as sand slugs and high injection rates was adopted and successfully applied. Zonal Isolation was achieved through the use of the newly developed, easily drillable composite plugs that allow staged treatment with flowback capabilities. Field data of representative Peat wells will be used to demonstrate the successful application of the hydraulic fracturing approach that resulted in methane gas rates that more than compete with the early cavity completion techniques either from a cost or production improvement point of view. The following specifics are addressed in the paper:A novel fracture design approach and modeling of fracturing treatments that can be of value to a broad audience of operators and design engineers.Real-time fracture stimulation methodology, analysis, and execution.Remedies to minimize the near-wellbore tortuosity and multiple far field fractures to avoid premature "screenout" and carry the fracture treatment to completion.Chemical optimization of fracture fluid designed based on coal characteristics.Use of newly developed composite epoxy-glass fracture and bridge plugs that provide a more efficient and cost effective way to carry out staged stimulation treatments.Post-fracture production tests to estimate the nitrogen-foam fracture treatment effectiveness in multi-seam CBM wells. Introduction The Peat field1 is located on the eastern edge of the Bowen Basin about 20 km east of the town of Wandoan (Fig. 1). The field is approximately 8 km wide and 26 km long and comprises Late Permian Baralaba Coal Measures overlying the Burunga Anticline, the largest anticlinal feature in the Bowen Basin. Aggregate net coal thicknesses range from about 7.1 m to 22.7 m over an interval of between 100 m to 140 m. Individual seam thicknesses range up to 13.7 m. Coal depths range from 600 m below ground and are currently being investigated to as deep as 1200 m. Within 15 km to the west coal depths reach over 2000 m.
Early stimulation work in Peat Field of Queensland, Australia involved application of cavity completion techniques to produce methane gas at commercial rates in the first wells completed in the reservoir gas cap. Early in the project life, cavity completion treatments resulted in promising and acceptable gas flow rates. However, excessive cost associated with this technique led to consideration of alternate stimulation approaches by the design team. The main objective was to achieve similar or better gas rates at the lowest cost. Multi-seam nitrogen-foam stimulation was conducted in several wells of the Peat field to assess the effectiveness of this technique in terms of:production enhancement and cost reduction;location of the coal-seam intervals in the gas cap (i..e. gas-saturated coals) and;improved completion efficiency. To minimise the effects of tortuosity and multiple far-field fractures in addition to ensuring that each coal-seam interval received adequate treatment, a staged stimulation approach in combination with other remedies such as sand slugs and high injection rates was adopted and successfully applied. Zonal Isolation was achieved through the use of the newly developed, easily drillable composite plugs that allow staged treatment with flowback capabilities. Field data of representative Peat wells will be used to demonstrate the successful application of the hydraulic fracturing approach that resulted in methane gas rates that more than compete with the early cavity completion techniques either from a cost or production improvement point of view. The following specifics are addressed in the paper:A novel fracture design approach and modeling of fracturing treatments that can be of value to a broad audience of operators and design engineers.Real-time fracture stimulation methodology, analysis, and execution.Remedies to minimize the near-wellbore tortuosity and multiple far field fractures to avoid premature "screenout" and carry the fracture treatment to completion.Chemical optimization of fracture fluid designed based on coal characteristics.Use of newly developed composite epoxy-glass fracture and bridge plugs that provide a more efficient and cost effective way to carry out staged stimulation treatments.Post-fracture production tests to estimate the nitrogen-foam fracture treatment effectiveness in multi-seam CBM wells. Introduction The Peat field1 is located on the eastern edge of the Bowen Basin about 20 km east of the town of Wandoan (Fig. 1). The field is approximately 8 km wide and 26 km long and comprises Late Permian Baralaba Coal Measures overlying the Burunga Anticline, the largest anticlinal feature in the Bowen Basin. Aggregate net coal thicknesses range from about 7.1 m to 22.7 m over an interval of between 100 m to 140 m. Individual seam thicknesses range up to 13.7 m. Coal depths range from 600 m below ground and are currently being investigated to as deep as 1200 m. Within 15 km to the west coal depths reach over 2000 m.
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractHydraulic fracturing injection experiments were performed in unconsolidated sand under stress to delineate the mechanisms controlling fracture propagation and to determine the effect of these mechanisms on potential formation damage. The tests included injection of cross-linked guar and visco-elastic surfactant into 3-Darcy sand samples subjected to different overburden stresses. The following observations were made:• The experimental data indicate that fracture propagation in unconsolidated sand is primarily a result of fluid invasion and shear failure in a process zone ahead of the fracture tip. The shear failure is caused by large tip stresses or by pore pressure increase within the process zone.• Three different invasion/damage zones were observed, including the external filtercake, the gel-invaded zone (or the internal filtercake), and the filtrate-invaded zone.• Sub-parallel "micro fracturing" and complex fracture geometry was encountered. The sub-parallel fractures may be initiated at the tip or at the fracture wall due to shear failure and is dependent on the fluid efficiency and the type of leakoff, i.e., wall building or viscous.• Field consequences of micro fracturing during stimulation may include early screenout, short fracture length and extensive formation damage as the fracturing fluid invades the sheared interfaces.• Typically, lower efficiency fluids were associated with increased net propagation pressure and higher density of micro fracturing.These findings suggest that injection of low efficiency fluids in weak, poorly consolidated formations results in a different type of formation damage, namely creation of sub-parallel micro fractures enveloping the main propped fracture, that could severely undermine post-stimulation productivity.
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThis paper presents a case study of a successful hydraulic fracturing campaign in the Arman field in western Kazakhstan: the first large scale campaign ever performed by a western service company in Kazakhstan. The Arman field is a mature field, originally delineated in Soviet times, and currently producing from four of the original vertical wells, and from newly drilled deviated (30 to 60 degree) wells. The field is currently under waterflood in three of the producing zones, but formation water is also being produced from wet zones. There is significant gas production, since the wells are all producing below the bubble point, either with ESP's or rod pumps.We believed that hydraulic fracturing had good potential for stimulation in this field since most of the wells were producing with a positive skin. In addition to the positive skin, the reservoir was normally pressured, and also depleted in some zones, limiting the amount of drawdown to about 1000 psi. The wells were also producing water and gas in addition to oil, which further reduced the oil production (by a variety of mechanisms).In this paper, we first describe the hydraulic fracturing operations, and the specific actions taken to deal with difficult features of this reservoir. We then examine the production mechanisms in the reservoir and compare the pre and postfracture production data.Finally, we evaluate the effectiveness of hydraulic fracture stimulation as a method for improving oil recovery in this type of moderate permeability reservoir under waterflood.
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