Impact of Mutual Solvent Preflush on Scale Squeeze Treatments: Extended Squeeze Lifetime and Improved Well Clean-up Time

Abstract

The most common method for preventing scale formation is by applying a scale inhibitor squeeze treatment. In this process, a scale inhibitor solution is injected down a producer well into the near wellbore formation. Commonly, scale treatments comprise the following stages: preflush, main scale inhibitor pill, overflush tubing displacement and shut-in, followed by back-production of the well. For some years the industry has applied mutual solvent chemicals in the preflush stage of such treatments to (i) avoid emulsion formation or water blocking, thus avoiding slow well clean-up, and also (ii) for enhancing adsorption of the scale inhibitor onto the formation rock. This paper discusses the effect of a mutual solvent preflush on scale inhibitor squeeze lifetime and also on well clean up time. It builds on a previous publication that introduced a recent model to simulate the impact of a surfactant on improved inhibitor retention, which used data derived from laboratory experiments. The focus of this paper will be to consider the impact of the mutual solvent on well clean up time and the model is used to demonstrate the effect of a mutual solvent in quickly bringing wells back to full oil production. A field example is presented for a deepwater field in West Africa where intervention costs are high and any negative impact of squeeze treatments can have a significant associated deferred oil cost. A scale inhibitor squeeze design in which a mutual solvent is deployed in the preflush should account for the following phenomena: mutual solvent propagation, diminishing mutual solvent efficiency due to interaction with the fluid phases, impact of the mutual solvent on scale inhibitor retention due to increased rock surface area available for adsorption, and impact of mutual solvent on saturation dependent relative permeability functions and phase mobilities. These aspects are discussed in the paper, and the model is used to demonstrate their impact on a squeeze treatment. Particular attention is paid to the reservoir wettability, and the importance of the shape of the relative permeability curves in determining the clean up time for a well, and the benefit that a mutual solvent may bring in overcoming slow clean up times. The model is then used to demonstrate how the preflush stage of given specific field squeeze designs may be adapted to ensure optimum efficiency in terms of chemical usage, minimised deferred oil production and extended squeeze life. Introduction Precipitation of inorganic mineral scale in producing wells is one of the biggest production challenges of the oil and gas industry as oil reservoirs are becoming more mature and watercuts are increasing. The most common scales are carbonates, caused mainly by CaCO3 precipitation (due to reservoir pressure depletion), and sulphate scales, created by the incompatible mixing of reservoir brine and injected water (normally seawater). Scaling is present in all the producing areas of the world; however, the severity of the scaling tendency varies from field to field, as does the degree of difficulty managing the problem from relatively simple low temperature low pressure vertical platforms wells to high temperature and pressure, where compatibility and thermal stability are major concerns1–3, carbonate reservoirs where the precipitation of pseudo scales may cause formation damage4 and complex deep seawater completions5,6.

Preflush Design for Oil-Wet Carbonate Formations: Key To Enhance Scale-Inhibitor-Squeeze Lifetime

“…To find the answer, significant amount of studies are necessary because the effect of the surfactant or surfactant/alkali combination on a reservoir formation varies considerably owing to their distinct chemical nature as well as the chemistry of rock and native fluids. Fortunately, considerable amount of works have been reported in relation to altering wettability of oil-wet rocks and reducing oil-water IFT by use (Wu et al 2008).…”

“…In laboratory coreflood experiments, up to 88% recovery is achieved by use of environmentally friendly surfactants such as C 10 -amine and alkylpolyglucosides (APG) in oil-wet carbonate cores (Standnes and Austad 2003;Zhang et al 2006;Ghosh and Obassi 2013). The works of Wu et al (2008), Standnes et al (2002), and Xie et al (2005) are helpful in understanding the surfactant type and ionicity that is suitable for minimizing residual oil and reducing capillary-trapping forces.…”