Injectrol and PermSeal Sealants Repair Leaks, Restore Integrity to Casings By Prentice Creel and Ronald J. Crook, Halliburton Energy Services, Inc. Whenever leakage downhole occurs because of pinhole-sized breaks in the casing caused by pitting or corrosion, repairs are vital. Such repairs are necessary on injection wells to satisfy regulatory requirements, and on producing wells to halt unwanted water production. Leaks can occur in designated freshwater zones, across intervals with poor primary cement jobs, or in regions characterized by a high influx of water. Leaks in injection wells that are unsuccessfully squeezed, and therefore fail regulatory testing, may result in substantial economic losses in the form of imposed fines and the eventual plugging and abandonment of the wells in question. In producing wells, the undesirable migration of water can cause formation damage, a loss of production, and an increase in the corrosion of tubulars and surface equipment. Finding a remedy to the leakage problem helps avoid subsequent costs associated with drillouts, repeated cement squeezes, and workovers. Limitations of Ultrafine and Conventional Cements Conventional cements and slurries containing ultrafine particulates are sometimes used to repair casing leaks, but at best, these solutions are limited. Ultrafine Cements The particles in ultrafine cements average 5 microns in diameter, in comparison to the 50- micron particles in Portland cement. Fine-grind cement jobs can restore integrity to the casing if the pinholes are large enough to allow a sufficient volume of slurry to enter the annulus. If the cracks are small, however, the cement is not protected from dissolution and deterioration caused by the influx of water. In fact, if the breaks in the casing are too minute, the placement of small-particle cement outside the casing is often ineffective altogether; in such situations, this type of slurry cannot serve as a barrier to the inflow of water or help provide zonal isolation.
Moreover, the presence of small pressure drops (± 50 to 150 psi/hr) presents additional difficulties in placing finely textured cements. Filtrate from these slurries is squeezed through the leaks, depositing nodules of cement particles on the casing face at the leak sites. Upon drillout, pressure tests may fail and seepage may recur. Conventional Slurries Conventional cement slurries have proven less than 10% effective in squeezing pinhole leaks; moreover, they typically require perforation of the casing to facilitate the entry of the slurry. 1 The potential for success is directly related to the severity of the leak, as indicated by pressure leakoff rates and the maximum injection rate possible below maximum pressure restrictions. Halliburton's Alternative Solutions If the remedy is outside the capabilities of either conventional or ultrafine cement, other methods are necessary to squeeze off the leaks. The application of Injectrol sealant, a sodium silicate gel system, and the use of PermSeal sealant, a monomer solution that undergoes polymerization in situ, have been successful in almost 100% of the cases in which they have been used to repair pinhole casing leaks. Furthermore, these systems, Halliburton's alternatives to small-particle cement squeeze jobs, can be used in both producing and injection wells. Injectrol Sealant In a solution, sodium silicate gels form particulate solids whenever they come into contact with such divalent ions as those found in calcium chloride or cement. 2 As the water phase is squeezed into the solution, these particulate solids accumulate to form a paste-like material that continues to grow during the squeeze process until it becomes a permanent solid. The strength of this new solid is equivalent to the final squeeze pressure applied. Sodium silicate systems have been useful in the petroleum industry for more than 30 years in various near-wellbore and deep-formation treatments designed to modify well profiles, curtail water coning, and effect other necessary changes downhole. 3 Such treatments are now considered a productive means for repairing casing leaks ranging from 15 to 500 psi/hr. Because of an insufficient pump-in rate, particulate material cannot be placed in such leaks. However, in squeeze operations, sodium silicate particulates accumulate when the material enters a reactive medium (Figure 1).
Figure 1: An example of an External Injectrol Sealant Placement and Squeeze. Since pressure-leakoff rates can be too high in sodium silicate solutions, some state regulatory agencies demand that only a cement product be used across certain depths for mending casing leaks. Particular wells, however, offer only a marginal possibility of success in the repair of leaks with cement slurries. Therefore, only wells with a low possibility of success using a cement squeeze are candidates for sodium silicate treatments. An internal activator is added to Injectrol sealant's formula when the solution is injected into a leak in which no external reactions will occur naturally. This internal initiator causes the solution to form a particulate at the designed set time. When external reactions do occur naturally, they induce the automatic formation of particulates by the sodium silicates. The Injectrol system loses its water phase during the squeezing process, thereby forming a paste in the restricted leaking channels (Figure 2). When the squeeze occurs in a confined area, the sodium silicate component can exhibit an uncommonly high resistance to extrusion pressures. 4 Figure 2: An Internal Injectrol Sealant Placement and Squeeze.
Injectrol sealant logged a 90% first-attempt success rate for the initial squeeze jobs in which it played a role. Furthermore, high leakoff rates contributed to positive secondattempt results on the 10% of the wells not treated successfully on the first try. The sodium silicate squeezes maintained pressure from 500 to 2,500 psi on all jobs. Well temperatures ranged from 85 to 190 F, with depths from 1,300 to 12,900 ft. The pressure falloff of the leaks spanned 15 to 500 psi/hr. The Halliburton service crew first spotted the target intervals with 250 to 500 gal of Injectrol sealant. Based on placement-time parameters, Halliburton engineers determined the solution's internal set times to be from 2 to 4 hours. Each of the treatments used between 250 and 1,000 gal of squeeze material, with 1 / 4 to 5 bbl of solution typically placed outside the casing in each job.halliburton performed the following procedures in applying Injectrol sealant to repair the casing leaks: 1. Determine the severity of the casing leak by analyzing the pressure leakoff rate or the maximum rate achievable below the maximum pressure restriction. 2. Mix and pump the required amount of Injectrol sealant to spot across the leak interval with excess in the casing or the tubing above. 3. Displace the Injectrol sealant to a balanced spot with fresh water if necessary. 4. Pick up the tubing to a point above the top of the solution and reverse-out the casing if necessary. 5. If a packer is used, set and squeeze to the required pressure in multiple steps until the pressure is holding at the required value. Do not use a packer if the interval to
be squeezed is at a shallow depth. 6. Squeeze the Injectrol solution into the leak with a hesitation method that causes the water phase to be extruded, leaving the solution's base material. 7. Squeeze the material into a paste and eventually into a body of solid material with a strength equal to the pressure applied to it. The material is permanently placed; it is also resistant to acid, corrosion, bacteria, and time/temperature degradation. 8. Use tubing to circulate and clean out the wells through the squeezed interval, and pressure-test the injector to meet regulatory requirements. Help ensure that the injector has been swabbed or pressure-tested to determine if water entry has been shut off. Injection-Well Repair In one of the workovers using Injectrol sealant in an injection well, three conventional cementing squeezes had failed to seal a leak in a critical zone. Environmental mandates required that the leak be stopped within its critical interval, which was believed to be a freshwater zone extending from 400 ft to 800 ft into the wellbore. Follow-up drillouts of the cementing squeezes had resulted in the same pressure leak although the cement had been squeezed up to 1,000 psi. A state regulatory agency authorized a single Injectrol sealant squeeze on the well because the plan called for permanent placement. The area was specified as a freshwater zone from ground level to 1,250 ft, and the pressure falloff rate of 450 psi/hr from a starting pressure of 500 psi indicated a leak. Regulations stipulated that a pressure test be performed in 12 months, again in 2 years if the first were successful, and every 3 years thereafter. Earlier attempts to seal the leak with fine-grind cement had failed, and because of the potential costs associated with further failure, the operator turned to Injectrol sealant. The Halliburton service team based the volume of solution for each squeeze on the capacity of the casing 800 to 50 ft from the surface. Because of a rapid pressure drop, the squeeze was performed in two attempts using 750 gal for each. The first try caused the pressure to fall from 450 to 150 psi/hr, and the well pressure would not drop below 350 psi. A 1,000-psi squeeze was achieved on the second attempt with a holding pressure of 600 psi-a level exceeding the 500 psi demanded by the 12-hr regulatory test. The 600-psi pressure level was maintained by the Injectrol sealant because of the compressive strength of the formation surrounding the well at 400 ft. Table 1 includes a typical well
profile for the jobs performed using Injectrol sealant. Table 1: Sodium Silicate Solution Jobs. Production Casing Leaks For economic reasons, or because of such practical considerations as hydrostatic limitations, many producing wells feature exposed intervals above the top of the primary cement. In these unprotected zones, the condition of the casing is generally poor because of exposure to such forces as ionic changes that cause pitting. If a casing leak develops in these wells, production levels usually decrease and problems like water invasion of the producing interval occur. The earlier practice was to identify the location of the leaks, set retrievable bridge plugs to protect the production zones, and cement-squeeze the leak using retainers. Whenever possible, cement was circulated to the surface to help eliminate further problems. However, this method tended to impair casing integrity, damage sections of the annulus, and impose hydrostatic restrictions on the exposed formations. These problems are typically associated with wells with water crossflow from a more shallow zone that migrates down the annulus into a porous interval. Because the hydrostatic pressure in this interval exceeds the reservoir pressure, the porous zone accepts the fluid. The placement of Injectrol sealant into the annulus is easily achieved even when it is difficult to inject into the leaking intervals. The Halliburton service crew based the solution volume on pressure restrictions. The gelled consistency of the Injectrol solution not only
seals the casing leaks-it also serves as an economical alternative to conventional squeeze methods. Sodium silicate squeeze jobs do not normally require squeeze packers or retainers if the casing integrity above the leak is satisfactory. This helps avoid the potential for retainer slippage that can create holes in old casings. After the Injectrol sealant is placed and a squeeze is attempted, any solution remaining inside the casing is circulated out with the tubing used to spot it. This procedure helps to avoid the drillouts associated with cementing and thereby to help prevent damage to older casings with a drill bit. Since most of the casings in the subject wells were old, damage during drillouts or tool settings was a possibility. However, Injectrol sealant not only stopped the leaks, but it also helped eliminate the need for costly drillouts. Silicate Flour Solutions containing either fine or coarse sodium silicate flour can also halt casing leaks in which a greater pressure drop vs. time is encountered. Statistics are being gathered that should allow Halliburton engineers to gauge the pressure-drop ranges for a given application. With this information, they will be able to adapt the Injectrol treatment to those ranges through the selection of the amount of silica flour and particulate size (fine vs. coarse) best suited to achieve the desired slurry density and texture. Since silica flour is not a factor in set-time development, it helps provide additional leakoff blockage by furnishing a surface area on which the squeezed particulate can develop. PermSeal Sealant Another alternative solution to pinhole casing leaks is the application of PermSeal sealant, a monomer solution that polymerizes in situ and demonstrates a unique capacity for repairing such leaks. When injected, these monomers are transformed into right-angle-set polymers that allow the solution to generate an extremely resilient material resistant to high extrusion pressures (Figure 3). Figure 3: In PermSeal Sealant, Monomers are Transformed into Right-Angle-Set Polymers that Allow the Solution to Generate an Extremely Resilient Material Resistant to High- Pressure Extrusion.
In fact, this tendency of the monomers to crosslink into polymers was a critical factor in the development of PermSeal sealant. Because of the crosslinking process, engineers were encountering very low injectivity when using formation-sweep modification materials. They also noted a substantial resistance to the extrusion of the set polymers and a failure to clear the tubulars of the material plug. The principal components of the PermSeal system are a low-toxicity acrylate monomer and a thermally controlled azo activator. Potassium chloride (KCl); fresh, potable water; and a ph adjuster are incorporated into the formula to furnish a standardized ionic concentration and the ideal ph ambience for activation of the in-situ polymerization process that transforms the monomer into a polymer. The additional components also help to render PermSeal sealant compatible with most formation conditions. 5 This environmentally friendly system is also user-friendly in that it can be customized to address a particular conformance problem through adjustments in the mix concentration. The chosen formula combinations help establish the ultimate viscosity, solubility, and strength that PermSeal sealant will exhibit downhole, and in so doing, help determine the final nature of the sealant, which can vary from a strongly crosslinked, "ringing" gel to a viscous polymer slug. 5-7 The PermSeal activator is an azo compound that undergoes thermal degradation (a process that forms a free radical). The activator initiates the polymerization of the monomer in situ. Since premature gelation can occur with monomer solutions in the simultaneous presence of transition metals and a free radical, temperature is used to
delay the formation of the free radical with the PermSeal system and thereby avoid this occurrence. The specific activator chosen for the fluid system is dictated by design temperature, which, in turn, is dependent on well conditions. Through the azo-initiator selection process, gel times may extend from 1 to 20 hours at temperatures ranging from 70 to 150 F (21.1 to 65.5 C). 5 In one application, multiple attempts had been made to repair casing leaks in a CO 2- flooded field. Normally, the successful completion of a pressure test required as many as six attempts. In one well, the casing still yielded a trace of leakoff (25 psi/hr). PermSeal sealant was selected for the treatment primarily for two reasons: 1. Its resistance to CO 2, bacterial growth, and acid 2. Its record of achievement and reliability Following is a detailed list of the procedures that can be used to repair the casing leaks using PermSeal sealant: 1. Determine the severity of the casing leak by analyzing the pressure leakoff rate or the maximum rate achievable below the maximum pressure restriction. 2. Mix and pump the required amount of PermSeal solution to spot across the leak interval with excess solution in the casing or tubing above. 3. Displace the PermSeal solution to a balanced spot with fresh water if necessary. 4. Pick up the tubing to a point above the top of the solution and reverse-out the casing if necessary. 5. Set the packer and squeeze to the required pressure in multiple steps until the pressure is holding at the required psi. 6. Squeeze the PermSeal solution into the leak by using a hesitation method until the top pressure is encountered and will hold without leaking off. The set time is designed to take place during the squeeze operation. 7. Circulate and clean out the wells through the squeezed interval with tubing. 8. Pressure-test the well with an injector or swab to help determine if the leaks have been shut off. 9. If necessary, remove the material later by using a polymer-breaking solution. PermSeal sealant was designed with an internal activator that initiates a reaction based
on thermally timed conditions. After a portion of the material was squeezed into the fissures, the well was pressure-tested and squeezed to a holding pressure satisfactory to the operator. Pressure applied to tubulars with as little as 30 ft of polymer remaining withstood a pressure drop of 6,000 psi without causing polymer extrusion. Injecting monomers into the channels, fissures, or other elements contributing to the pressure reduction ultimately leaves a material capable of withstanding internal and external highpressure drops (Figure 4). Figure 4: An Example of an Internal in-situ Polymerizing Monomer (PermSeal Sealant) Placement and Squeeze. The dependability and high-performance capabilities that PermSeal sealant has demonstrated in a number of operations has resulted in an almost-100% success rate. Table 2 includes a typical well profile of the jobs performed with PermSeal sealant. Approximately 5 to 25 bbl of PermSeal solution are typically placed outside the casing. The volume used on the jobs is determined by the length of the target interval, the casing size, the severity of the leak, and the need for the PermSeal sealant to enter the adjacent formation. Table 2: In-Situ Polymerizing Monomer Jobs.
Conclusions Injectrol sealant, a sodium silicate solution, and PermSeal sealant, an in situ-generated polymer, have proven successful in the repair of pinhole casing leaks in almost 100% of the treatments in which they have been used. The use of Injectrol and PermSeal sealants to seal casing and halt leaks can eliminate the need for expensive drillouts and repetitive cement squeezes, and the reduction in workover time when using these products can reduce expenditures for casing repairs. Injectrol and PermSeal sealants can successfully repair casing leaks in areas where conventional cements, including ultrafine blends, fail. References 1. Shryock, S.H., and Slagle, K.A.: "Problems Related to Squeeze Cementing," JPT, (Aug. 1968) 801-07. 2. Cole, C. and Lindstrom, K.: "Well Integrity Maintenance Using Pumpable Sealants," paper presented at Underground Injection Practices Council International Symposium, New Orleans, May 1987. 3. Dalrymple, D., Sutton, D., and Creel, P.G.: "Conformance Control in Oil Recovery," Southwestern Petroleum Short Course, Lubbock, Texas, April 24-25, 1985. 4. Smith, C.W., Pugh, T.D., and Mody, B.: "A Special Sealant Process for Subsurface Water," Southwestern Petroleum Short Course, Lubbock, Texas, April 20-21, 1978. 5. Dalrymple, D., Tarkington, J.T., and Hallock, J.: "A Gelation System for Conformance Technology," paper SPE 28503 presented at the 1994 SPE Annual
Technical Conference and Exhibition, New Orleans, LA, Sept. 25-28. 6. McLaughlin, H.C., Diller, J., and Ayers, H.J.: "Treatment of Injection and Producing Wells with Monomer Solution," paper SPE 5364 presented at the 1975 SPE Regional Meeting, Oklahoma City, March 24-25. 7. Sinclair, B.C. and Ott, W.K.: "Polymer Reduces Channeling, Ups Waterflood Oil Recovery," World Oil (Dec. 1978) 187, No. 7, 101-104. The Authors Prentice Creel is a senior global advisor for Halliburton Energy Services, Inc.'s, Permian Basin development group and technical team in Odessa, Texas. He has been with Halliburton for 16 years in various operational and technical engineering positions. Creel holds a BS in engineering from New Mexico State University. He is currently a director for the Trans-Pecos Section of SPE. Ronald J. Crook is a senior global advisor technologist III in the zonal isolation cementing group at Halliburton's Duncan Technology center. He coordinates requests for joint research projects and acts as a point of contact for technology exchange between various organizations. Crook holds a BS in chemical engineering from Oklahoma State University. www.halliburton.com Send questions or comments about this site to Halliburton Service Center or call U.S. (877) 263-6071 or outside U.S. (281) 983-4900. Copyright 2008 Halliburton. All Rights Reserved. Terms and Conditions Privacy