Soluble Fluid-Loss Additives Can Reduce Well Productivities and Prevent Complete Gravel Placement

Abstract

Summary Fluid-loss additives are frequently used in completion fluids and pills to reduce fluid costs and formation damage, but many of these additives create more damage than they prevent. Common recommendations are to use fluid-loss additives that will be dissolved by the produced fluids, acid, or water so that they may be readily removed after a job. Typical additives are oil-soluble resins, calcium carbonate particles, and salt suspensions. It is particularly important that soluble additives be used for wells that are to be gravel packed because the gravel will trap insoluble solids in the well. Evidence indicates, however, that even these soluble products remain in perforation tunnels and impair productivities of wells. Examples of wells indicating this effect during post-gravel-pack acid treatments are discussed. The theory of why this occurs and calculations of pressure drops through perforations filled with fluid-loss additives are presented. It has also been found that excess fluid-loss additives prevent complete coverage of a zone with gravel, because of either inadequate leakoff to the formation or partial plugging of the screen. Therefore, it is imperative that these additives be removed by acid, water, or solvents preceding the gravel slurry; however, if their removal causes loss of circulation, the results may be equally bad. The most practical solution to this problem is to use a combination of gravel and viscous fluids as a diverting system for the fluids that will remove the additives without creating additional formation damage. When this system is used just ahead of a gravel slurry, it not only helps remove the fluid-loss additives, but also helps prevent excessive fluid losses and partially prepacks the formation with gravel. Introduction Controlling the fluid-loss rate before, during, and after placement of a gravel pack is extremely important. Excessive fluid-loss rates are common in weak or unconsolidated sandstones because these formations are often very permeable, but fluids lost to the formation cause formation damage, increase the costs of completions, hinder complete zone coverage by gravel packs, and may lead to blowouts. The use of high-viscosity-gel pills to reduce fluid-loss rates should cause only minor formation damage, but in many wells these pills are ineffective and soluble fluid-loss additives must be added to them. The combination of solids and gelled fluids will effectively control fluid loss in most wells. Soluble fluid-loss additives may be grouped into three categories: oil soluble (resins and waxes), acid soluble (calcium carbonate and iron carbonate), and water soluble (salts). The most commonly used fluid-loss additives are calcium carbonate particles that are soluble in acid, and oil-soluble resin dispersions that are soluble in most crude oils. A dispersion of salt in saturated brine that can be removed by undersaturated brine or water is also used. These soluble fluid-loss additives have been shown to be effective in the laboratory and the field; some laboratory tests indicate, however, that they all result in residual formation damage.1,2 In laboratory tests by King and Hollingsworth,1 the fluid-loss additives invaded the sandpacks enough to cause residual reduction of permeabilities ranging from 8 to 26%, even after the filter cake and the first 0.25 in. [0.635 cm] of the sandpacks were removed. If gravel had been packed in these test cells, some of the filter cake and most of the additives in the first 0.25 in. [0.635 cm] of the sandpacks would have been trapped in place, thus causing more severe formation damage. The following discussions will concentrate on calcium carbonate, but it should be recognized that similar problems are associated with all soluble fluid-loss additives used in gravel-packed wells. Productivity Problems Created by Incomplete Removal of Fluid-Loss Additives Calcium carbonate controls fluid loss by three mechanisms:invasion of formation pores,bridging at the entrance to the formation to form a filter cake, andfilling of perforation tunnels. Fine grinds (5 and 50 µm) are very effective because they invade into the pores of a wide variety of permeable formations and cause "in-depth" plugging. They also form very-low-permeability filter cakes at the face of the formation and very-low-permeability packs as they fill perforation tunnels. Larger grinds (150 and 600 µm) do not readily invade into the pores of most sandstones but form filter cakes with relatively high permeabilities. Thus, the smaller grinds should control fluid loss more effectively than the larger grinds but potentially cause more formation damage because they will be more difficult to remove. The importance of using the proper particle-size distribution of calcium carbonate has been discussed previously.3,4 Generally, a wide distribution of particles is required to form bridges on the various pore sizes encountered in typical wells; however, larger grinds are needed for formations with larger pores (higher-permeability sands), and smaller grinds for formations with smaller pores (lower-permeability sands). Typical particle-size distributions of common commercial calcium carbonate additives3 are shown in Figs. 1 through 4. Theoretically, if this 5-µm grind is used for a formation that has an average pore size of 50 µm or more, most of the calcium carbonate particles will invade into this formation and will not effectively reduce the fluid-loss rate unless a high concentration or large volume of particles is used. The 50-µm grind has adequate particle-size distribution to bridge near the entrance to this formation sand and to fill the perforation tunnels to restrict fluid loss effectively. If the 150- or 600-µm grinds are used, few of the particles can invade into this formation, but the higher-permeability filter cake formed by these larger particles will be less effective in reducing fluid losses. Field experience indicates that the 5-µm grind effectively controls fluid loss in formations with measured average pore sizes greater than 100 µm. This may occur because the formation was damaged by the drilling operations or muds that reduce the average pore sizes of the formation. Current completion practices of underbalanced perforating, or perforation surging, should remove some of this damage, thus increasing the pore sizes exposed to the calcium carbonate particles and the invasion of particles from pills used after perforating.

Fluid-Loss Control Using Crosslinkable HEC in High-Permeability Offshore Flexure Trend Completions

“…Other fluid loss control systems used in Flexure trend completions exhibit specific problems which can be attributed to (1) physical properties of the particular material, and (2) the method of application.…”