The application of horizontal wellbore drilling and multistage fracturing technology has been playing a pivotal role in unlocking shale-gas reserves globally. More recently, the same technology has been applied to both new and mature oil fields. A key question for economic optimization of these assets is what fracture spacing to use along a horizontal wellbore. Of equal importance is what spacing to use for multilaterals and the wellbores themselves to achieve optimal drainage of the reservoir. In addition, the design of the fracturing treatments must be optimized. To address these questions, a combination of reservoir and fracturing simulation has been applied. The required input data are provided through a combination of advanced log and core analyses, diagnostic fracture injection testing (DFIT), rate transient analysis (RTA), and characterization of fracture geometry through microseismic monitoring. Fluid rheology is characterized using pressurized rheometers and flow loops. This paper presents results of this work using examples of current Canadian oil and shale-gas reservoirs and a methodology to improve the economic return of different completion and production scenarios.

The Montney gas reservoir presents exciting potential and is likely to become a critically important component of future gas supply. However, the Montney often presents variable and unique stimulation challenges. Unlike reservoirs like the US Barnett shale but possibly like the Muskwa in the northeast B.C. Horn River basin, recovery of water-based fluids can be a key issue to achieving economic production rates in the Montney.Choice of fracturing fluid must be carefully determined for each area of the Montney, balancing economics with production response. One must always keep in mind that key reservoir properties can vary dramatically in the Montney, both as a function of geographic location and depth.A presentation entitled "Montney Fracturing Fluid Considerations" was given at the 2009 CSUG conference, which summarized results of regained methane permeability vs. drawdown pressure and contact time with Montney core under representative reservoir conditions. Water-, foamed water-, and hydrocarbon-based fracturing-fluid systems were studied. Implications of the results as to choice of optimum fluid were discussed. This paper presents field-production results of the trials conducted with fluid systems resulting in conjunction with the above study. The concepts and reasoning used to arrive at final fluid choices for field trials are discussed, as well as a theoretical interpretation of the field-production results. BackgoundThe Montney reservoir spans approximately 2961 km 2 and has original gas in place (OGIP) estimates of between 35 and 250 Tcf. The industry accelerated the development of this resource using horizontal wells with fracture stimulations in 2005. As an industry, various gelled, slickwater, and oil-based fracturing fluids have been trialed. To evaluate the effectiveness of these systems, Montney fluids were tested against Montney core in 2009 (Taylor et al. 2009).To follow up on the theoretical core work, various fracture-stimulation methodologies were attempted in the Trident Montney field during 2009 and 2010. The stimulations evolved from CO 2 foam to ultrahigh-quality biopolymer foam with sand and lightweight proppant (LWP), finally settling on slickwater limited-entry fracs. During the evolution of stimulations, there were lessons learned on cement selection, reservoir heterogeneities, and multilaterals and wellbore design.The purpose of this paper is to detail all of the various fracture stimulations trialed in the field and present the results/lessons learned.