Scale Inhibitor Application in Injection Wells to Protect Against Damage to Production Wells: When Does It Work? (2005)

Scale Inhibitor Application in Injection Wells to Protect Against Damage to Production Wells: When does it Work? Eric James Mackay Eric James Mackay Heriot Watt University Search for other works by this author on: This Site Google Scholar Paper presented at the SPE European Formation Damage Conference, Sheveningen, The Netherlands, May 2005. Paper Number: SPE-95022-MS https://doi.org/10.2118/95022-MS Published: May 25 2005 Cite View This Citation Add to Citation Manager Share Icon Share Twitter LinkedIn Get Permissions Search Site Citation Mackay, Eric James. "Scale Inhibitor Application in Injection Wells to Protect Against Damage to Production Wells: When does it Work?." Paper presented at the SPE European Formation Damage Conference, Sheveningen, The Netherlands, May 2005. doi: https://doi.org/10.2118/95022-MS Download citation file: Ris (Zotero) Reference Manager EasyBib Bookends Mendeley Papers EndNote RefWorks BibTex Search nav search search input Search input auto suggest search filter All ContentAll ProceedingsSociety of Petroleum Engineers (SPE)SPE European Formation Damage Conference and Exhibition Search Advanced Search AbstractPrevention of inorganic scale damage in the formation around production wells is usually achieved by batch squeezing the productions wells at risk.However, in Western Siberia protection of production wells is sometimes achieved by application of scale inhibitors in the supporting water injection wells.This technique relies on the effective displacement of the inhibitor across the reservoir from injector to producer.This is not generally considered a viable scale management option due to the extent of chemical retardation that is a necessary result of inhibitor retention on the rock matrix.However, for short inter-well distances, such as may occur in onshore developments, and where fracture conductivity is high enough that inhibitor contact with the matrix rock is minimal, then this technique can provide adequate protection against scale induced formation damage in production wells.This paper explores the range of reservoir scenarios under which this technique may be applicable, considering inter-well distances, the extent of fracture vs matrix flow, and the potential range of inhibitor retention on various rock substrates that may be encountered in fractured reservoirs.The approach is to use numerical modelling techniques to investigate the range of conditions under which this scale management approach may be applicable.This data may then be used identify when scale control may be adequately achieved using this technique, thereby reducing the need to shut in production wells for treatments, and when this approach would not provide adequate protection in actual field systems.Comparison is made of the potential for performing batch treatments in the injections wells, compared to continuous injection of scale inhibitor in these wells.IntroductionAfter a brief overview of the causes of oilfield scale and how it may be managed, this paper discusses the issue of where scale forms in the reservoir system, and the possibilities for treating injection water to protect production wells.Calculations are presented that illustrate when this may be an option, concentrating on dual porosity systems where natural fractures provide an effective conductivity between injectors and producers while minimising the surface area of rock that the injected chemicals will encounter on their journey as they are displaced from injection to production wells.Oilfield ScaleOilfield scales are inorganic crystalline deposits that form as a result of the precipitation of solids from brines present in the reservoir and production flow system.The precipitation of these solids occurs as the result of changes in the ionic composition, pH, pressure and temperature of the brine.There are three principal mechanisms by which scales form in both offshore and onshore oilfield systems:Decrease in pressure and/or increase in temperature of a brine, leading to a reduction in the solubility of the salt (most commonly these lead to precipitation of carbonate scales, such as CaCO[3]);Mixing of two incompatible brines (most commonly formation water rich in cations such as barium, calcium and/or strontium, mixing with sulphate rich seawater, leading to the precipitation of sulphate scales, such as BaSO[4]);Brine evaporation, resulting in the salt concentration increasing above the solubility limit and leading to salt precipitation (as may occur in HP/HT gas wells where a dry gas stream may mix with a low rate brine stream resulting in dehydration and most commonly the precipitation of NaCl). Keywords: hydrate inhibition, symposium, injection water, injection, fracture, scale inhibitor, wax inhibition, upstream oil & gas, calculation, water breakthrough Subjects: Production Chemistry, Metallurgy and Biology, Improved and Enhanced Recovery, Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene This content is only available via PDF. 2005. Society of Petroleum Engineers You can access this article if you purchase or spend a download.