Completion Operations in Low Permeability Deep Basin Gas Reservoirs: To Use or Not to Use Aqueous Fluids, That is the Question

Abstract

Many tight gas formations are water-wet and undersaturated where the initial water saturation in the reservoir is less than the capillary equilibrium irreducible water saturation. Using aqueous-based stimulation and workover fluids causes water to be trapped in the near wellbore region, thereby significantly impairing the ability of gas to flow. Therefore, hydrocarbon fluids are better suited for completion operations in such reservoirs. Laboratory data revealing the sensitivity of one such formation to aqueous fluid invasion are discussed and actual field examples are provided in three different formations. Introduction As the oil and gas industry matures and known reserves continue to be depleted, the focus moves towards more challenging environments. One such environment is the Deep Basin area of West Central Alberta where vast reserves of natural gas and associated liquids are present in a number of low permeability reservoirs(1). Similar areas also exist in the U.S., such as the Powder River Basin, Permian Basin, and the Green River Basin. In situ effective gas permeabilities in such reservoirs are in the 0.1 mD range or less. It should be noted that while routine core measurements in the laboratory may indicate permeabilities of up to 1 mD for such reservoirs, the effective gas permeability in the reservoir will be significantly less(2, 3). Although horizontal wells are being used with increasing frequency in exploiting such reservoirs, the vast majority of the wells drilled are vertical wells in the Deep Basin. This is mainly due to the differences in the cost of drilling. A typical horizontal well can be as much as two to four times more expensive than a vertical well for such deep targets. Also, because most horizontal wells are completed barefoot in tight gas reservoirs, the drilling induced damage becomes quite important for the performance of these wells. Therefore, it is critical that a suitable drilling fluid be used in drilling horizontal wells. This was discussed in an earlier article(4). The gas flow rate from a vertical well can be maximized by stimulation. Vertical wells in tight gas formations are usually stimulated by hydraulic fracturing after drilling. Hydraulic fracturing is accomplished by pumping a large volume of fluid mixed with additives and a solid proppant (usually sand) into the formation at high injection rates, cracking the reservoir rock. The fluid is used as a carrier so the proppant can be pumped, and once the proppant has been placed in the fracture, the well is usually flowed back to a tank to recover the carrier fluid. The permeability of the proppant is very high. However, some of the carrier fluid will be imbibed into the freshly exposed matrix rock and remain in place. Depending on the characteristics of the fluid, the permeability of the fracture face may be impaired. The same can also be said for fluids used in workover operations as well. In many low permeability gas reservoirs aqueous fracturing fluids are used due to their cost advantage and safety considerations(5, 6).

The Application of Ultra-Lightweight Proppants to Cryogenic Liquid Nitrogen as a Fracturing Fluid: A Research Protocol

“…Traditional proppants are too dense to be carried by pure nitrogen-based fluids, thus creating demand for ultra-lightweight proppants (ULWPs) that minimize density while maintaining the ability to withstand the high pressures within the wellbore. Nitrogen mist technology has already been improved with the addition of ULWPs, but its application remains restricted to shallow shale formations [10]. Cryogenic liquid nitrogen (LN2) is a novel alternative that has yet to be tested in conjunction with ULWPs.…”

Waterless fracturing technologies for unconventional reservoirs-opportunities for liquid nitrogen

“…Although self-propping by rubblizing fracture surfaces is considered as a contribution for fracture opening at shallow depths, this possibility is minimized for deep formations having tight cementation. However, with the recent development of ultralight weight proppants (Rickards et al 2006;Gu et al 2015), hundreds of gas fracturing jobs pumping 100% nitrogen were successfully performed in shallow shale and siltstone gas plays in Canada during 2006(Canyon, 2016.…”

Numerical investigation of fluid-loss mechanisms during hydraulic fracturing flow-back operations in tight reservoirs

“…A number of reasons including compaction, dehydration, disconnection of oil reservoir from free water level and diagenesis have been cited (Bennion et al, 2002;Gupta, 2009). Generally speaking, as the wettability to water increases, initial water saturation increases; however, desiccated reservoir can also be water wet, and the Cardium formation is an example of a desiccated water-wet reservoir, as evidenced by its low initial water saturation and oil relative permeability end point being higher than its corresponding water relative permeability end point (Purvis and Bober, 1979;Coskuner, 2006). Experimental study of Coskuner (2006) also confirms that water-based fracturing fluid may cause water blockage near hydraulic fracture in desiccated tight reservoir and hamper oil/gas production.…”

“…Generally speaking, as the wettability to water increases, initial water saturation increases; however, desiccated reservoir can also be water wet, and the Cardium formation is an example of a desiccated water-wet reservoir, as evidenced by its low initial water saturation and oil relative permeability end point being higher than its corresponding water relative permeability end point (Purvis and Bober, 1979;Coskuner, 2006). Experimental study of Coskuner (2006) also confirms that water-based fracturing fluid may cause water blockage near hydraulic fracture in desiccated tight reservoir and hamper oil/gas production. Similar observations are obtained from the numerical study of Assiri and Miskimins (2014), although their model did not include a fracture system.…”