Summary Ultralow-permeability shale reservoirs require a large fracture network to maximize well performance. Microseismic fracture mapping has shown that large fracture networks can be generated in many shale reservoirs. In conventional reservoirs and tight gas sands, single-plane-fracture half-length and conductivity are the key drivers for stimulation performance. In shale reservoirs, where complex network structures in multiple planes are created, the concepts of single-fracture half-length and conductivity are insufficient to describe stimulation performance. This is the reason for the concept of using stimulated reservoir volume (SRV) as a correlation parameter for well performance. The size of the created fracture network can be approximated as the 3D volume (stimulated reservoir volume) of the microseismic-event cloud. This paper briefly illustrates how the SRV can be estimated from microseismic-mapping data and is then related to total injected-fluid volume and well performance. While the effectively producing network could be smaller by some proportion, it is assumed that the created and the effective network are directly related. However, SRV is not the only driver of well performance. Fracture spacing and conductivity within a given SRV are just as important, and this paper illustrates how both SRV and fracture spacing for a given conductivity can affect production acceleration and ultimate recovery. The effect of fracture conductivity is discussed separately in a series of companion papers. Simulated-production data are then compared with actual field results to demonstrate variability in well performance and how this concept can be used to improve completion design, well spacing, and placement strategies.

Ultra-low permeability shale reservoirs require a large fracture network to maximize well performance. Microseismic fracture mapping has shown that large fracture networks can be generated in many shale reservoirs. In conventional reservoirs and tight gas sands, single-plane fracture half-length and conductivity are the key drivers for stimulation performance. In shale reservoirs, where complex network structures in multiple planes are created, the concept of a single fracture half-length and conductivity are insufficient to describe stimulation performance. This is the reason for the concept of using stimulated reservoir volume as a correlation parameter for well performance. The size of the created fracture network can be approximated as the 3-D volume (Stimulated Reservoir Volume or SRV) of the microseismic event cloud. This paper briefly illustrates how the Stimulated Reservoir Volume (SRV) can be estimated from microseismic mapping data and is then related to total injected fluid volume and well performance. While the effectively producing network could be smaller by some proportion, it is assumed that created and effective network are directly related. However, SRV is not the only driver of well performance. Fracture spacing and conductivity within a given SRV are just as important and this paper illustrates how both SRV and fracture spacing for a given conductivity can affect production acceleration and ultimate recovery. The effect of fracture conductivity is discussed separately in a series of companion papers. Simulated production data is then compared with actual field results to demonstrate variability in well performance and how this concept can be used to improve completion design, and well spacing and placement strategies. Introduction Fisher et al. (2002), Maxwell et al. (2002), and Fischer et al. (2004) were the first papers to discuss the creation of large fracture networks in the Barnett shale and show initial relationships between treatment size, network size and shape, and production response. Microseismic fracture mapping results indicated that the fracture network size was related to the stimulation treatment volume. Figure 1 shows the relationship between treatment volume and fracture network size for five vertical Barnett wells, showing that large treatment sizes resulted in larger fracture networks. It was observed that as fracture network size and complexity increase, the volume of reservoir stimulated also increases. Fisher et al. (2004) detailed microseismic fracture mapping results for horizontal wells in the Barnett shale. This work illustrated that production is directly related to the reservoir volume stimulated during the fracture treatments. In vertical wells, larger treatments are the primary way to increase fracture network size and complexity. Horizontal well geometry provides other optimization opportunities. Longer laterals and more stimulation stages can also be used to increase fracture network size and stimulated reservoir volume. Mayerhofer et al. (2006) performed numerical reservoir simulations to understand the impact of fracture network properties such as SRV on well performance. The paper also showed that well performance can be related to very long effective fractures forming a network inside a very tight shale matrix of 100 nano-darcies or less.

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Effects of proppant selection on well productivity are demonstrated in a large sample case study covering 2,300 square miles [6,000 square kilometerskm2] in Alberta, Canada.In 80% of cases studied, wells fractured with ceramic proppant provided significantly higher gas production rates compared to wells propped with sand or other materials.The most frequently stimulated formation in the Western Canadian Sedimentary Basin (WCSB) is the Cardium formation of the Late Cretaceous period.This formation is also known to contain natural fractures resulting from location-dependent tectonic strain.Records indicate that across the basin the Cardium formation has received over 12,500 fracture stimulations during the last 50 years.About 4,000 detailed fracturing treatments were reviewed to define the smaller focus area. This This study includes a review of 1,600 well boress in an area operated by 96 companies.On average, 156 new wells have been drilled annually since 2000.Record numbers of new wells were completed in 2004, and the number of Cardium wells completed in the last four years exceeds the total from the preceding two decades.A detailed database containing available fracture treatment and production data was compiled from government records and service industry sources.This paper summarizes a study of over 750 well stimulations. Drilling activity peeked at 163 wells in 2003 and has averaged 140 wells per year since 2000.Drilling in the previous decade averaged 28 wells per year.This paper reports on analyses derived from a database containing 680 records representing all available fracturing data.These records were compiled from governmental, service industry, and operating company sources. Various stimulation strategies have been employed in the Cardium development.This paper will examines productivity of hydraulic fractures propped with various materials and placed with a variety of fluid systems.Wells in this study were stimulated with as low as 2,200 lbm [1 tonne] to nearly 407,000 lbm 200 tonnes [185 tonne440,000 lbm] of proppant per well in one to five stages. Analyses suggest that significantly greater economic return has been achieved when fracture designs are optimized.In this study, the most common design was 132,000 lbm [60 tonne] of proppant placed with a hydrocarbon-based fluid.For this treatment design, the average first year production for wells receiving 132,000 lbm [60 tonne] of sand was 302 MMscf [8.5 x 10[6] m[3]] of gas.Wells stimulated with 132,000 lbm [60 tonne] of ceramic proppant averaged 420 MMscf [11.9 x 10[6] m[3]] production during the first year.30Benefits vary with job size, fluid type, and other factors.TThe incremental cost of manufactured ceramic proppants is usually recovered within 30 days, generating a significant increase in profitability.At current gas prices, average return on investment achieved by optimizing proppant selection greatly exceeds 100%. Production from Cardium oil wells was also found to increase with proppant concentration and with proppant size.A preliminary review suggests that oil production has been significantly improved with higher conductivity fractures. While a full statistical review remains underway, the initial comparisons suggest that further increases in proppant conductivity should be considered.Additional information is provided to assist fracture optimization strategy for both oil and gas wells in the Cardium formation. Introduction Hydraulic fracturing is required to achieve economic production rates from most Cardium gas wells.In fact, records indicate over 12,500 stimulation treatments have been performed within this formation throughout the WCSB.Despite this extensive experience, no clear consensus has emerged from the various operators on fracture design optimization.The purpose of this paper is to survey and evaluate the productivity achieved with various treatments.A detailed database was compiled from government and service industry records. Stimulation treatments are classified by fracturing fluid type, proppant type, and proppant quantity placed in each well.

Effects of proppant selection on well productivity are demonstrated in a large case study covering 6,000 square kilometers (2,300 square miles) in Alberta, Canada. In 9 of 11 cases studied, wells fractured with ceramic proppant provided significantly higher gas production rates compared to wells propped with sand or other materials. The most frequently stimulated formation in the Western Canadian Sedimentary Basin is the Cardium formation of the Late Cretaceous period. Records indicate that across the basin the Cardium formation has received over 12,500 fracture stimulations during the last 50 years. This study includes a review of 1,600 wells currently operated by 96 companies. On average, 156 new wells have been drilled annually since 2000. Record numbers of new wells were completed in 2004, and the number of Cardium wells completed in the last four years exceeds the total from the preceding two decades. A detailed database containing available fracture treatment and production data was compiled from government records and service industry sources. This paper summarizes a study of over 750 well stimulations. Various stimulation strategies have been employed in the Cardium development. This paper examines productivity of hydraulic fractures propped with various materials and placed with a variety of fluid systems. Wells in this study were stimulated with as low as one tonne (2,200 lb m ) to nearly 185 tonnes (407,000 lb m ) of proppant per well in one to five stages.Analyses suggest that significantly greater economic return can be achieved when fracture designs are optimized. In this study, the most common design was 60 tonnes (132,000 lb m ) of proppant placed with a hydrocarbon-based fluid. For this treatment design, the average first year production for wells receiving 60 tonnes of sand was 8.5(10 6 ) m 3 (302 MMscf) of gas. Wells stimulated with 60 tonnes of ceramic proppant averaged 11.9(10 6 ) m 3 (420 MMscf) production during the first year. Benefits vary with job size, fluid type, and other factors. The incremental cost of ceramic proppant is usually recovered within 30 days, generating a significant increase in profitability. At current gas prices, average return on investment achieved by optimizing proppant selection greatly exceeds 100%. Additional information is provided to assist fracture optimization strategy in the Cardium development.