Workover Fluid

Key Takeaways

• Workover fluid density selection is governed by the kill weight calculation: the minimum workover fluid density required to control the well is equal to the formation pore pressure divided by the true vertical depth (TVD) of the perforations, converted to consistent units; for a well with a formation pore pressure of 4,000 psi at a TVD of 8,000 feet, the minimum kill weight is 4,000 / (0.433 * 8,000) = 1.155 SG (9.65 lb/gal), which would be achieved using a sodium chloride brine at approximately 50,000 ppm NaCl or a light calcium chloride brine at approximately 5 to 6 percent CaCl2 by weight; for higher-pressure formations (pore pressure gradient greater than 0.52 psi/ft or 11.8 kPa/m), calcium bromide or zinc bromide brines (which can be formulated to densities of 1.8 to 2.3 SG, or 15 to 19 lb/gal) are required; the workover fluid density typically includes a 10 to 15 percent safety factor above the minimum kill weight to account for formation pressure uncertainty, partial liquid loss into the formation, and temperature effects on brine density (brines expand with temperature, reducing their density, which must be corrected for deep hot wells); the safety factor is specified in the workover program and confirmed by the operator and company man before the workover begins.
• Formation compatibility testing is performed on candidate workover fluids before field deployment to confirm that the fluid will not damage the formation permeability when it contacts the productive interval during the workover: core flow tests (flowing the workover fluid through core plugs from the reservoir interval at the expected workover conditions of temperature, pressure, and flow rate, then measuring the permeability before and after fluid contact) quantify the extent of permeability damage from clay swelling, fines migration, emulsion blockage, or scale precipitation; return permeability (the ratio of post-treatment permeability to pre-treatment permeability, ideally greater than 0.9 or 90 percent) is the key performance metric for workover fluid compatibility, with lower return permeabilities indicating that the workover fluid will cause significant formation damage that reduces post-workover production; clays that are particularly sensitive to freshwater workover fluids include smectite (which swells when contacted by water with lower salinity than the native formation water, blocking pore throats) and kaolinite (which migrates as fines when disturbed by the velocity and shear stress of the workover fluid flow, plugging pore throats); KCl (potassium chloride) brines at 2 to 3 percent concentration are commonly used in sandstone formations with potassium-stabilized clays because the K+ ion prevents smectite swelling more effectively than NaCl at equivalent salinity.
• Calcium chloride (CaCl2) brines are the most widely used workover fluid base in the petroleum industry because they provide a density range of 1.0 to 1.4 SG (8.3 to 11.7 lb/gal) that covers the majority of onshore and shallow offshore workover pressure requirements, are readily available from industrial supply sources, are relatively inexpensive compared to bromide brines, and have good compatibility with most formation types when properly inhibited with clay stabilizers and corrosion inhibitors; calcium chloride brine densities above 1.4 SG are prepared by adding calcium bromide (CaBr2) to the calcium chloride solution (CaCl2/CaBr2 mixed brine), extending the density range to 1.7 SG (14.2 lb/gal) without the crystallization temperature problems that would occur at equivalent NaCl or KCl concentrations; calcium chloride brines are incompatible with formation waters containing sulfate ions (SO4^2-) because the combination of Ca^2+ from the brine and SO4^2- from the formation water exceeds the solubility product of calcium sulfate (CaSO4, anhydrite), precipitating scale in the formation and wellbore that requires acid or chelant treatment to dissolve; compatibility testing with the expected formation water is mandatory before specifying a calcium chloride workover fluid for wells where the formation water has significant sulfate content.
• Zinc bromide (ZnBr2) brines and zinc chloride/calcium bromide/zinc bromide mixed brines provide the highest-density clear brine workover fluids, with densities of 2.0 to 2.3 SG (16.7 to 19.2 lb/gal) required for ultra-high-pressure HPHT workover operations in deep formations with pressure gradients approaching or exceeding 0.65 psi/ft (14.7 kPa/m); zinc bromide brines are significantly more expensive than calcium chloride or calcium bromide brines (by a factor of 5 to 20) due to the cost of bromine and zinc as raw materials, and they are regulated as toxic substances in many jurisdictions (zinc is acutely toxic to aquatic organisms at concentrations as low as 0.1 mg/L, far below the concentrations used in workover brine) that require contained containment systems with secondary containment and zero-discharge requirements for offshore use; the handling and storage of zinc bromide workover brines require specialized equipment (all-fiberglass or stainless steel tanks and piping to prevent zinc corrosion of steel), personnel protection (zinc dust and zinc bromide are irritants requiring PPE), and disposal infrastructure (the brine must be reclaimed and recycled rather than discharged overboard in offshore operations).
• Workover fluid loss control (preventing the workover fluid from being lost into the formation during the workover) is important both for well control (loss of fluid into the formation reduces the hydrostatic head and may cause the well to start flowing) and for formation protection (excess workover fluid in the formation reduces permeability and must be cleaned up before the well can produce at its potential productivity); fluid loss control in workover operations is typically achieved by ensuring that the workover fluid density provides sufficient overbalance to prevent the formation pressure from driving formation fluid into the wellbore (which would allow loss of hydrostatic head by the gas-cut mud mechanism), by filtering the workover fluid to remove suspended solids that could plug the formation face and cause permanent permeability damage, and by adding a sized particle bridging agent (CaCO3 calcium carbonate, at a particle size distribution matched to the median pore throat diameter of the formation) that forms a temporary filter cake at the perforations and prevents fluid loss without the permanent damage that conventional filtration control agents (bentonite, drill solids) would cause; the calcium carbonate bridging agent is designed to dissolve in the HCl or acetic acid overflush that follows the workover, removing the temporary bridge and restoring the permeability to near the pre-workover level.