Analyses of an Elmworth Hydraulic Fracture in Alberta

Abstract

Summary A tight gas sand with 1-µd permeability was produced, after a large hydraulic foam fracture, at rates close to predicted values. The rates of about 300 Mcf/D (8495m3/d) after 23 days would not bear the cost of development at 1979 Canadian prices. However, it is estimated that, with higher netbacks and longer fractures, commercial development would be feasible. Introduction The Elmworth gas field is located within the Deep basin near Grande Prairie, Alberta (Fig. 1). The Deep basin covers about 26,000 sq miles and appears to contain an enormous amount of gas in different-quality rocks. Masters1 has estimated the Deep basin could contain more than 400 Tcf of gas, recoverable at various levels of price and technology. Canadian Hunter visualizes the gas distribution in the Deep basin as a resource triangle. In such a distribution, the sands and conglomerates of highest porosity and permeability are at the very top of the triangle. As reservoir quality decreases, the resource triangle indicates larger and larger quantities of gas in lower-porosity and lower-permeability rocks. Near the bottom of the triangle are sands approaching 7% porosity and 1 µd in-situ permeability. Within these lower porosity rocks (7 to 11%) resides a huge ultimate potential. Detailed analyses were made of logs, cores, and tests of about 20 zones from 57 wells in a 60-township area around the Elmworth field. This study indicated that, with sufficient but reasonable economic incentives, it would be possible to recover more than 200 Tcf from the lower-quality rocks within the Deep basin.2 To obtain more information on the technology and economics required to recover this gas, Canadian Hunter performed a large hydraulic fracture over the Cretaceous Falher Zones A and B in the Canhunter Texcan Elmworth Well 11–12–71–13W6. This paper presents a description and analysis of the fracture. Petrophysical Properties The Falher Zones A and B were cored completely, and a full suite of openhole logs was run. This suite included the induction-electrical, acoustic with variable density display, compensated neutron-density, and microlog. Selected logs and the core analysis (made at atmospheric conditions) are shown in Fig. 2. Although the entire cross section of 164 ft is considered gas-bearing, less than one-half of the section is estimated to be net pay, based on analysis of logs, cores, and pressure buildups. Sixty-six feet of this section have measured core porosities equal to or above 7%; this is shown by the shaded area on the porosity curve in Fig. 2. Permeabilities above 0.1 md also are shaded. Sonic log and pressure buildup analysis indicate a net pay closer to 45 ft. The relation between fractional core porosities (f) measured at 200 psi and sonic travel time (?t) in µs/ft is described byf=0.0054?t-0.2865.

Effect of Mud Filtrate Invasion on Apparent Productivity in Drillstem Tests in Low-Permeability Gas Formations

“…6,500(1981) The input data for the DST simulations (Table 1) were based on properties of the Falher sandstone formation in western Canada. Wyman et al 2 presented a description of this formation. Other important reservoir properties used in the study included relative permeabilities and capillary pressures.…”

First Field Application in Canada of Carbon Dioxide Separation for Hydraulic Fracture Flow Back Operations

“…Foamed fracturing fluid systems (both N 2 and CO 2 ) have been used for many years throughout the Deep Basin area of Alberta and British Columbia (Wyman 1980). Figure 1 shows a location map of the Deep Basin area.…”