Scale Formation During Alkaline Flooding
- P.H. Krumrine (The PQ Corp.) | E.H. Mayer (THUMS Long Reach Co.) | G.F. Brock (Sooner Chemical Specialties Inc.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- August 1985
- Document Type
- Journal Paper
- 1,466 - 1,474
- 1985. Society of Petroleum Engineers
- 4.2 Pipelines, Flowlines and Risers, 1.14 Casing and Cementing, 4.3.1 Hydrates, 3.2.4 Acidising, 5.3.2 Multiphase Flow, 2.4.5 Gravel pack design & evaluation, 1.2.3 Rock properties, 4.1.2 Separation and Treating, 5.1.1 Exploration, Development, Structural Geology, 4.2.3 Materials and Corrosion, 2.4.3 Sand/Solids Control, 1.6.9 Coring, Fishing, 5.4.1 Waterflooding, 5.4.7 Chemical Flooding Methods (e.g., Polymer, Solvent, Nitrogen, Immiscible CO2, Surfactant, Vapex), 4.3.4 Scale, 2.5.2 Fracturing Materials (Fluids, Proppant)
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Alkaline chemicals in enhanced recovery operations are used (1) as preflush agents, (2) with polymers and surfactants, and (3) as a principal recovery agent. In these chemical flooding techniques, the precipitation reactions of multivalent hardness ions with alkalis are of particular concern. These reactions may be prevented at the injection wells through adequate preflushing and/or the use of good-quality softened water; filtration can remove any precipitates that form at the surface. In the formation, precipitates that form at the surface. In the formation, many reactions occur that alter the injected slug significantly. Those include dissolution, mixing, neutralization, and ion exchange. Such reactions may lead to beneficial fluid diversion as precipitates form and block high-flow channels. At the producing wells, however, precipitation and deposition phenomena are undesirable because scales may form that restrict production and foul well equipment. With the current higher production and foul well equipment. With the current higher concentrations of alkali being used in the field, the development of well scaling has become noticeable and difficult to control by previously accepted practices.
This paper describes the progress and experience gained at the Long Beach Unit, Wilmington, CA, alkaline pilot dealing with scales formed in producing wells. These scales have been made up variously of calcium carbonate, magnesium silicate, and amorphous silica. In particular, the reservoir characteristics and chemical conditions leading to the scale formation are discussed in detail, showing what, how, and why the scale forms. For the Wilmington alkaline pilot, the cause appears to be the mixing of very hard waters from one subzone with moderately alkaline water from other subzones. This mixing and the dissolution of formation solids by the alkali have led to scale formation in the producers closest to the injectors. producers closest to the injectors. A few general scale inhibitor formulations, useful for both formation squeeze treatments and continuous sidestream annular injection, have been effective in controlling the carbonate scale under laboratory and field conditions. However, the physical environment and mechanical limitations in the field have resulted in a new deposit, consisting mainly of amorphous silica, against which the current inhibitor systems am ineffective. We suggest field procedures for dealing with such a situation. It is anticipated that the use of appropriate chemicals and methods can lead to cost-effective scale control.
Them is a large body of literature on alkaline flooding and its variations. However, few authors consider associated scale phenomena at the production wells or in laboratory studies, although it is well known that alkaline chemicals react with reservoir rock and fluids to produce precipitates. Mungan mentions briefly that produce precipitates. Mungan mentions briefly that plugging and scaling were noted in some field-test plugging and scaling were noted in some field-test production wells but gives no details. Raimondi et al. production wells but gives no details. Raimondi et al. describing a sodium hydroxide pilot in the North Ward-Estes field, observed increased gypsum scale formation in producers. This reservoir has a high gypsum content. However, no treatment was discussed. The authors also noted an increase in silica content at the producers but did not detect an accompanying increase in pH value or decrease in hardness levels in the produced fluids. The alkaline slug was believed to have been completely consumed by inaction with gypsum. In a field test at the Trekhozernoye deposit in Russia, fluid-flow diversion was reported because of swelling and migrating clays and precipitation of calcium and magnesium carbonates. The produced fluids showed a decrease in Ca++ ion with subsequent increases in HCO3 - ion.
In laboratory tests evaluating alkaline flooding for an Alberta reservoir, Novosad and McCaffrey reported a white precipitate in the coreflood effluents that added to the alkali consumption. They also noted that silicates are more effective at precipitation divalent metal ions. Sydansk observed the formation of new, highly hydrated alumina-silicate precipitates in alkaline com tests; these have lower silica/alumina ratios than the original formation clays. Carbonate minerals in the core dissolved first, leading to accelerated alkaline consumption. Significant amounts of silica were dissolved from the rock matrix at elevated temperatures.
A number of other studies show that alkalis react strongly with the various reservoir-rock constituents. These inactions can produce very complex ionic effluents downstream in both laboratory com tests and field production wells. Ehrlich and Wygal studied the caustic consumption of a number of clays and minerals in an attempt to quantify the contribution of each to the overall consumption. More recently, this quantification has been extended by Mohnot et al. Holm and Robertson studied the effect of various preflush agents, including alkaline silicates on divalent ion exchange in surfactant flooding.
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