Penberthy Jr., W.L., SPE-AIME, Penberthy Jr., W.L., SPE-AIME, Exxon Production Research Co. Shaughnessy, C.M., SPE-AIME, Exxon Production Research Co. Gruesbeck, C., SPE-AIME, Exxon Production Research Co. Salathiel, W.M., SPE-AIME, Exxon Production Research Co. For effective sand consolidation, resin must wet the surface of sand grains. When plastic resins do not have this ability, preflushing is essential. Model studies demonstrated that preflushing effectiveness depended on preflush volume, viscosity, and sand permeability. Results indicated that an optimum volume of 100 gal/ft was required for an effective preflush. Introduction Experience with sand consolidation for the past 30 years has shown that candidate wells should have relatively thin, clean, homogeneous, undamaged sand zones. Proper preflushing also is essential for effective sand Proper preflushing also is essential for effective sand consolidation. A variety of aqueous and organic preflushes have been used to remove formation fluids ahead preflushes have been used to remove formation fluids ahead of sand consolidation resins. Proper preflushing can contribute significantly to the strength of the consolidated sand by improving the adhesion between the resin and sand matrix. Because of increased emphasis on sand consolidation performance and lifetime, a considerable incentive exists for improving preflush selection and volume. To be effective, a sand consolidation resin first must wet and then must adhere to the surface of the sand grains. Because the sand grains in most reservoirs are water wet originally, it is critical for the resin to replace water on the surface of the grains. Fig. 1 shows the effect of residual water saturation on the strength of sand consolidated with an epoxy resin. As water saturation increases, compressive strength decreases. At 6-percent water saturation, resin is prevented from wetting the sand matrix and consolidation has little compressive strength. While studying all available sand consolidation processes, laboratory tests showed that some resins were processes, laboratory tests showed that some resins were able to displace water by themselves. Others depended heavily on preflushing for water removal. Although oil removal appears desirable, most sand-consolidation resins exhibit good sand-grain wetting in the presence of oil. Consequently, mutual solvents that preferentially remove water are more desirable for sand consolidation preflushing, particularly where epoxy resins are preflushing, particularly where epoxy resins are concerned. Preflush Study Preflush Study A series of tests identified solvents that preferentially remove water in the presence of oil. Solvents were characterized on the basis of their phase behavior with brine and oil. Fig. 2 illustrates four possible types of phase behavior for the preflush-brine-oil system. Dashed phase behavior for the preflush-brine-oil system. Dashed lines represent tie lines connecting equilibrium phases in the two-phase region. Of the four types of phase behavior, Type 2 solvent is the most desirable because it preferentially removes water and also removes oil. Type preferentially removes water and also removes oil. Type 1 solvent results in a residual oil saturation, Type 3 solvent preferentially removes oil, and Type 4 solvent has no water miscibility. Most tests were conducted with 6-percent NaCl brine and diesel oil. Promising candidates were studied further using combinations of twine, 15-percent HC1, spent mud acid, and diesel and crude oil. Tests were conducted on three classes of compounds - alcohols, glycol ethers, and glycol ether acetates. Results showed that, of the alcohols, only isopropyl alcohol demonstrated mutual miscibility for brine and oil. The glycol ether acetates were all oil miscible. Many glycol ethers, however, were mutually miscible with brine and diesel. JPT P. 845

A design criterion based on type and depth of damage is proposed to replace laboratory design curves that may have been distorted by CO 2 evolution. Furthermore, sandstone acidizing experiments have provided evidence that reprecipitation of dissolved silica from spent HF can be a real limitation to acidizing success if operational precautions are not taken. Finally, the potential for iron precipitation from spent HCI acidizing solutions is seen to be dependent on certain conditions such as iron oxidation state and the presence of carbonates.

Fonnation damage has been observed in some wells of the Prudhoe Bay field. Laboratory and field testing confinned that the primary cause of damage was the buildup of calcium carbonate scale either in the perforation tunnels or in the fonnation sandstone near the wellbore. Conventional acid treatments could dissolve this scale, but scale reprecipitation from the spent acid caused rapid productivity decline. A scale-removal treatment with Na2H2 ethylenediaminetetraacetic acid (EDTA) has been developed that can effectively dissolve scale and chelate the dissolved metal ions. Chelation of the dissolved scale prevents scale reprecipitation. Of the 25 Prudhoe Bay wells acidized with EDT A through June 1982, 19 responded with significant productivity increases. In 17 of these wells, productivity has been sustained after treatment.

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This paper describes the development and field testing of a new, low-viscosity, sand-consolidation system. During experimental investigation, several new concepts were developed that are not available elsewhere, including the use of a bisphenol F epoxy resin, an extractable two-part diluent (acetone plus cyclohexane), and an improved placement procedure. Introduction Plastic consolidation continues to be an important Plastic consolidation continues to be an important technique for controlling sand during oil and gas production. New resin systems for sand consolidation have developed consistently for the past 20 years, which, in turn, have improved field performance. Epoxy resins long have been known to have properties desirable for sand consolidation - excellent adhesion to silica surfaces and good resistance to deterioration. Several commercial consolidation processes have been based on epoxy resins, but until now, none have achieved the desirable combination of being externally catalyzed and having low viscosity. All previous low-viscosity epoxy formulations have been catalyzed internally, that is, the curing agent was added to the resin just before it was pumped into the well. Major drawbacks of this technique arelimited pumping time before the resin hardens andthe need to blend chemicals at the wellsite. While externally catalyzed resins can eliminate pumping time and blending considerations, ail previous pumping time and blending considerations, ail previous externally catalyzed epoxy processes used resins with viscosities of more than 80 cp. The high viscosity of the resin caused high pumping pressures and increased the risk of forming a channel through an unconsolidated sand. Our experience has shown that a resin with viscosity of less than 30 cp (preferably less than 20 cp) is most desirable. A new process has been developed that has low viscosity and also eliminates blending at the wellsite. With a viscosity of 16 cp, the resin solution can be pumped readily through tubular goods and into the reservoir sand. All process components are premixed before their arrival at the wellsite. The elimination of field blending simplifies the procedure to an ordinary pumping operation. The shelf life of the premixed components is longer than 1 year, which can be important when operating in remote locations. Process Description, Process Description, The basic consolidation process requires that four fluids be injected sequentially through the sand:an organic preflush to remove water from the sand surface,an preflush to remove water from the sand surface, (2) an epoxy resin diluted to 16 cp,a spacer oil to flush excess resin from the pore space, andan oil containing a catalyst to harden the resin coating around each sand grain. The key to developing a successful externally catalyzed consolidation process is to harden the desired quantity of resin on the surface of the sand grain. Laboratory studies have shown that the optimal residual cured-resin saturation is 35% of the original pore volume. Values higher than this lower the permeability of the sand after consolidation, without substantially improving compressive strength. Saturations of less than 35% contain too little resin to coat effectively or to bond together all sand grains. Consequently, design criteria for the new process were to obtain a 35% residual resin saturation and process were to obtain a 35% residual resin saturation and then to pump enough oil with catalyst to harden all the resin. JPT P. 1805