1. Field of the Invention
Embodiments disclosed herein relate generally to wellbore fluids that may include silicate-based additives for stabilizing an unconsolidated formation.
2. Background Art
Hydrocarbon fluids, such as oil and natural gas, and other desirable formation fluids are obtained from a subterranean geologic formation, i.e., a reservoir, by drilling a well that penetrates the formation zone that contains the desired fluid. Once a wellbore has been drilled, the well must be completed. A well “completion” involves the design, selection, and installation of equipment and materials in or around the wellbore for conveying, pumping, or controlling the production or injection of fluids. After the well has been completed, production of the formation fluids can begin.
When the subterranean formation is “soft” or poorly consolidated, small particulates (typically sand) present in the formation may dislodge and travel along with the produced fluid to the wellbore. Production of sand is highly undesirable as it tends to cause erosion of surface and subterranean equipment, and therefore, it must be removed from the produced fluids before they can be processed. In addition, the migrating sand can plug the flow channels in the formation, thereby necessitating other stimulation techniques, such as acid stimulation, to restore the well's performance.
Various types of unconsolidated formations include dune sands, alluvial deposits of sand and gravel, and unconsolidated marine deposits. The challenges in drilling and completing wells in these types of formations are to keep the borehole open and prevent caving, and to avoid reducing the hydraulic conductivity of the near-well formation by introducing irrecoverable mud or smearing clay at the well/aquifer interface during the drilling process. Drilling fluids for unconsolidated formations are typically water-based and generally include clean fresh water, water with clay additives, water with polymeric additives and water with a mixture of clay and polymeric additives.
One method of controlling loose sands in unconsolidated formations involves placing a filtration bed of gravel near the wellbore in order to present a physical barrier to the transport of unconsolidated formation fines with the production of hydrocarbons. Typically, such so-called “gravel packing operations” involve the pumping and placement of a quantity of a desired particulate into the unconsolidated formation adjacent the wellbore. Such packs are time consuming and expensive to install.
Another method used to control loose sands in unconsolidated formations involves consolidating or stabilizing the unconsolidated subterranean producing zones into hard permeable masses by pre-flushing the formation, applying a hardenable resin composition, applying a spacer fluid, applying an external catalyst to cause the resin to set, and applying an afterflush fluid to remove excess resin from the pore spaces of the zones. Such multiple-component applications, however, often result in uncertainty and create a risk for undesirable results. For example, when an insufficient amount of spacer fluid is used between the application of the hardenable resin and the application of the external catalyst the resin may come into contact with the external catalyst in the wellbore itself rather than in the unconsolidated subterranean producing zone. When resin is contacted with an external catalyst an exothermic reaction occurs that may result in rapid polymerization. The polymerization may damage the formation by plugging the pore channels, may halt pumping when the wellbore is plugged with solid material, or may even result in a downhole explosion as a result of the heat of polymerization. Also, using these conventional processes to treat long intervals of unconsolidated regions is not practical due to the difficulty in determining if the entire interval that has been treated with both the resin and the activation agent.
These techniques typically involve the injection of a consolidating fluid, such as a resin-based consolidating fluid, through the wellbore and into the formation surrounding the interval of interest. Resin-based consolidating fluids generally include an organic resin, a curing agent, a catalyst and an oil wetting agent. The resin system hardens in the formation, thereby consolidating it. Examples of such resin-based consolidating fluids and methods for using them are described in, for example, U.S. Pat. Nos. 4,291,766; 4,427,069; 4,669,543; 5,199,492; and 5,806,593. Resin-based consolidation systems may be complicated to apply, especially those involving multiple treatment stages, and the treatment results may be erratic. When the individual components of the consolidating fluid are pumped at different stages into the formation they may or may not come together in the right order, or in the right amounts, or they may not even come together at all. And, even when they do come together, good mixing of the components is not assured, helping to explain the erratic and unreliable results that operators have experienced using such multi-stage consolidating fluids.
In an effort to improve performance, other well treatments have been proposed which use inorganic systems, specifically the use of components which form silica gels, to modify the formation and thereby reduce the production of formation fines. For example, U.S. Pat. No. 3,593,796 describes a multi-stage process in which the following components are injected sequentially into the formation: (1) an aqueous solution containing a silicate adapted to wet the fine sand grain particles, (2) an aqueous solution of a silicate-precipitating agent capable of reacting with the silicate in solution (1) so as to form a solidifying material and therein to bind the fine sand grain particles, and (3) a solution containing an oil-wetting agent. This treatment is designed to immobilize the fine particles in the formation and prevent their migration when subjected to subsequent fluid flow. The patent states that aqueous solutions of alkaline earth metal salts (e.g., calcium chloride), acidic iron salts, and certain other metal salts can be used as the silicate-precipitating agent.
In another instance, U.S. Pat. No. 3,741,308 describes a method of converting an unconsolidated sand formation into a consolidated, permeable formation by flowing volumes of aqueous calcium hydroxide (or compounds which hydrolyze or react with each other to form calcium hydroxide) through the pores of the unconsolidated formation. The patent states that the calcium hydroxide solution could be formed by adding sodium hydroxide to a solution of calcium chloride. The patent also states that during the practice of the process the sand particles in the formation become coated with calcium silicates of unknown or indefinite composition, and proposes that the coating cements the individual grains together and increases the structural strength of the sand assemblage.
Yet another approach has been described in two companion cases (U.S. Pat. Nos. 5,088,555 and 5,101,901). In U.S. Pat. No. 5,088,555, a sand consolidation method was described involving sequential injections of (a) an aqueous solution of an alkali metal silicate and (b) certain organic solutions of a calcium salt (e.g., calcium chloride hydrate or chelated calcium) through perforations in the casing of a borehole. The components of these two solutions are said to react to form a calcium silicate cement with permeability retention characteristics in the formation interval being treated that prevents sand from being produced during the production of hydrocarbon fluids from the well.
However, the use of a silicate-precipitating agent that is in solution may give rise to short gellation times upon contact silicates. Accordingly, there exists a need for consolidation or stabilization methods which allow for longer and/or controllable gellation times.