The Mitigation of Formation Damage and the Application of a New Scale Squeeze Inhibitor

Abstract

In certain North Sea fields, barium levels of 250 ppm in formation water can lead to downhole sulphate scale deposition. Conventional treatment involved a squeeze inhibitor deployed through an aqueous phase. However, a squeeze treatment of low water-cut wells in water-sensitive formations and/or those with poor well lifting ability may result in negative wettability effects, formation damage by water blocking, and temporary process upsets. This paper describes the development of a new chemistry designed into an optimized squeeze package that has successfully mitigated formation damage and provided extended squeeze life time in the field. Significant permeability reductions were observed for both the Clashach formation and the reservoir during core flood tests when this new chemistry was applied in an aqueous package. The authors will discuss and identify the mechanisms of formation damage and its mitigation. Reformulation of the squeeze package focuses on the most cost-effective solution. A final reservoir core flood was conducted using a partially non-aqueous package consisting of a mutual solvent pre-flush stage prior to the injection of the main pill and aqueous overflush. The outcome of this treatment was very promising, as no permeability reduction was observed following the treatment and modeling of the squeeze life time yielded impressive predictions. A squeeze treatment using this optimized package was deployed successfully in the field, where no process upset was observed and no emulsion breaker was required during start up. Increased oil production was noted after the treatment and extended squeeze life time (>180 days) was obtained with in excess of 650,000 m3 of water protected. The inhibitor return was still over the MIC (Minimum Inhibitor Concentration) when the well was re-squeezed using the same package. The authors discuss performance of the field trial and compare it with previous treatments. Introduction Appropriate squeeze chemical inhibitors typically are required to manage the potential of a downhole scale problem, in particular the risk and uncertainty of barium sulphate scale during seawater breakthrough. However, the injected chemicals may react physically or chemically react with both the formation and reservoir fluids, thus generating unfavourable wetting alteration and/or formation damage (Jordan et al. 1998; Graham et al. 1999, 2002a; Guan et al. 2003). The risks of formation damage following aqueous scale inhibitor squeeze treatments is a major concern in many reservoirs displaying some degree of water sensitivity (Wat et al, 1999; Collins et al, 1998 & 2000; Mackay et al, 2000). Formation damage normally is manifested by a decline in production following an aqueous-based treatment. Wettability changes and water blocking can worsen the situation dramatically, with formation damage caused by brine and/or chemicals preventing the oil from re-establishing continuity from the pore space to the wellbore. In addition, if new water pathways are established, an increase in postapplication water production may be observed. Moreover, in conventional aqueous squeeze treatments, if the treatment design has not been optimized up to 40% of the injected chemical can be returned during initial well flow back and clean up (Collins 1997a). Non-aqueous scale inhibitor packages are considered to have the capacity to overcome these issues by allowing oil continuity during treatment, while reportedly minimizing relative permeability changes that occur when conventional aqueous fluids are injected into the near-wellbore area (Guan et al. 2004a, 2004b, 2006; Shields et al. 2006, 2008; Graham et al, 2003). Similar to conventional aqueous scale inhibitor squeeze packages, the use of a non-aqueous product is not recognized as equating to a wholly non-damaging treatment (Graham et al. 2002b, 2002c; Jordan et al. 2002). Damage mechanisms, such as in-situ precipitation, mineral damage, fine migration and pore throat blockage, that can arise from the aqueous treatment still exist. Another disadvantage of using hydrocarbon solvents is their heat capacity that tends to be lower than that of water, thereby reducing the near-well cooling effect that benefits inhibitor propagation and perhaps shortening squeeze life. Therefore, it is important to carefully evaluate the non-aqueous packages prior to any field application.

Acid/Scale Inhibitor Stimulation Treatment for High-Temperature CHFP Subsea Wells: Fluid Qualification and Formation Damage Assessment

“…A similar approach has been recently implemented in a squeeze treatment in the Clashach formation in the North Sea Basin. Increased oil production was noted after the treatment, and extended squeeze life time (>180 days) was obtained with in excess of 650,000 m 3 of produced water (Guan et al, 2009). …”

The Development of a Water-Free and Light Oil-Soluble Scale Squeeze Inhibitor Meeting Environmental Requirements

“…The causes for reduction can come from wetting alteration/water blocking at water sensitive reservoirs (Jordan et al 1998;Graham et al 1999;Poynton et al 2000;Guan et al 2003) and/or poor well cleanup for wells with poor lifting (Ravenscroft et al 1996;Collins 1997;Graham et al 2002;Wat et al 2001;Guan and Rohde 2009). The application of nonaqueous scale inhibitors has been proposed to address some of these concerns, many types have been reported ranging from invert emulsion-type technologies (Lawless and Smith 1999;Collins et al 2000;Smith et al 2000), microemulsions (Miles et al 2003), encapsulated products Collins 1997) amphiphilic solvent systems, (Collins et al 1998;Guan et al 2006;) and oil-miscible materials (Wat et al 1999;Wat et al 1998a;Wat et al 1998b).…”