Solids-Free, High-Density Brines for Packer-Fluid Applications
- A.M. Ezzat (NL Baroid/NL Industries Inc.) | J.J. Augsburger (NL Baroid/NL Industries Inc.) | W.J. Tillis (NL Treating Chemicals/NL Industries Inc.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- April 1988
- Document Type
- Journal Paper
- 491 - 498
- 1988. Society of Petroleum Engineers
- 1.8 Formation Damage, 3 Production and Well Operations, 1.11 Drilling Fluids and Materials, 4.1.2 Separation and Treating, 4.2.3 Materials and Corrosion, 4.3.4 Scale, 2.2.2 Perforating, 2.7.1 Completion Fluids
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Summary. High-density water- or oil-based muds are not stable suspensions. Laboratory corrosion data and field observations suggest that solids-free, inhibited high-density brines could be ideal packer fluids for deep, hot wells. Expensive washover and fishing operations required for recovery of tubing stuck in settled mud solid could be eliminated.
A worldwide review of workover operations indicated extremely high costs associated with recovery of tubing stuck in settled mud solids. High-density water- or oil-based muds are not stable suspensions when left static in a well for a long time. High temperatures and/or contamination of these muds with the produced gas and oil destroys the initial suspension properties and allows mud solids and weighting materials to settle on top of the packer and around the tubing. Expensive washover and fishing operations are then performed. During the washover, more costly complications, such as twist-off or stuck washover pipes, casing leaks, blowouts, and formation damage, could develop. When such complications occur, many wells have to be plugged and abandoned. Most of these problems could be eliminated by using solids-free packer fluids. Single-salt brines and blends of high-density brines have been tested to determine their corrosive nature. An inorganic corrosion inhibitor was developed and field tested. In the last few years, many deep, high-temperature, high-pressure wells in the Gulf of Mexico have been successfully completed with inhibited high-density brines, which were also left as packer fluids. Some of these wells were worked over, tubing and packers were retrieved easily, and no significant corrosion was observed.
Packer fluids are placed in the casing/tubing annulus to provide a hydrostatic head necessary to control the well in case of packer failure or leaks, and to reduce the pressure differential between the inside of the tubing and the annulus, the outside of the casing and the annulus, and the perforated interval below the packer and the annulus. Packer fluids should protect tubing and casing metal surfaces from corrosion and enhance retrievability of tubing and packers.
Important Fluid Characteristics
1. Packer fluids must be chemically and mechanically stable under downhole conditions; i.e., there must be no settling of suspended solids and no chemical precipitates if mixed with produced fluids or gases, Also, the fluid components must not degrade with time or temperature. 2. Fluids must not deteriorate packer elastomers. 3. Fluids must remain pumpable during the life of the well; i.e., no high gelation or solidification may develop over time. 4. Fluids must not cause corrosion (inside casing or outside tubing). 5. The fluids must not damage the producing formation because they may contact these producing zones during completion or workover operations. Water-based drilling-mud organic additives degrade upon prolonged exposure to high temperatures and sometimes generate corrosive gases, such as CO2 and H2S. Bacterial activity could also break down organic materials and/or produce corrosive elements. Lignosulfonate solutions can react electrochemically at metal surfaces to form sulfides, even at moderate temperatures. Properly formulated oil-based muds are nonconductive and should not cause corrosion. In case of packer failure or leaks, however, produced oil or gas dissolves in oil mud and destroys the suspension properties, allowing the weighting material (barite) to settle on top of the packer and to cause stuck packer and tubing.
Laboratory Testing Procedures
Laboratory corrosion testing procedures (Appendices A and B) and equipment were developed. Data obtained explained the corrosive nature of these brines under static conditions, simulating packer-fluid applications.
Uninhibited Single-Salt Brines and High-Density-Brine Blends
Corrosion tests were performed to determine corrosion rates for seven commercial available, single-salt, saturated brines (NaCl, KCl, KBr, NaBr, CaCl2, CaBr2, and ZnBr2) without inhibitors. Test periods were 1 to 180 days at temperatures of 250, 300, 350, and 400 degrees F [121, 149, 177, and 204 degrees C]. Initial tests were conducted on No. 1010 carbon steel coupons. An average rate for duplicate samples was calculated for each test period (Table 1). The highest corrosion rates for all brines were with the 1-day test and much lower rates were observed in longer test periods. As the temperature increased, the 1-day test corrosion rates increased significantly. For example, CaCl2 at 250 degrees F [121 degrees C) showed 5.3 mils/yr [0.135 mm/a] and at 400 degrees F [204 degrees C] showed 54.7 mils/yr [1.39 mm/a]. ZnBr2/CaBr2 at 250 degrees F [121 degrees C] showed 10.2 mils/yr [0.259 mm/a] and at 350 degrees F [177 degrees C] showed 140 mils/yr [3.56 mm/a]. These relatively high rates decreased tremendously, however, with longer exposure times of 7 and 30 days. This phenomenon indicated that the active corroding elements in the brine were being consumed and/or that the reaction produced a protective coating on the metal surface. That is, the worst corrosion reaction is during the initial contact of brines with steel, and the longer brines are left static in a well, the less corrosive they become. CaCl2/CaBr2/ZnBr2 blends with densities of 15.5, 16, 16.5, 17.5, and 18 lbm/gal [1857, 1917, 1977, 2097, and 2157 kg/m3) were tested at 250, 300, 350, and 400 degrees F [121, 149, 177, and 204 degrees C). As with the single-salt brines, the 1 day test corrosion rates were relatively higher than the 7-, 30-, and 90-day tests. These brine blends demonstrated much higher rates than the single-salt brines, especially at and above 300 degrees F [149 degrees C] (Table 2). In addition to the temperature effect on the corrosion rates, higher blend densities produced higher corrosion rates, which are attributed to the higher acidic ZnBr2 content required at the higher blend densities. Summer blends (higher crystallization temperatures) in the same density range formulated with smaller amounts of the acidic ZnBr2, showed lower corrosion rates than the winter blends (lower crystallization temperatures). In the tables and figures, LCD is last crystal to dissolve method.
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