Plate Out

Key Takeaways

• Tracer plate-out affects the quantitative interpretation of interwell tracer tests (IWT), which are used in waterflood and EOR projects to map flow paths, estimate swept volumes, and identify high-permeability channels (thief zones) between injection and production wells: an ideal tracer would travel with exactly the same velocity as the injected water (no retardation), adsorb irreversibly on no pore surfaces (complete recovery), and not partition into any other phase (non-partitioning); real tracers including fluorescent dyes (fluorescein, rhodamine WT), radioactive tracers (tritiated water, I-131), and chemical tracers (thiocyanate, nitrate) experience varying degrees of adsorption on clay minerals, organic matter, and sandstone surfaces, causing the tracer to travel more slowly than the water (retardation factor R greater than 1) and to be recovered at lower concentrations than injected (incomplete tracer mass recovery); bead tracer plate-out is a specific form of irreversible adsorption where the bead's surface charge or surface chemistry causes it to bond to the formation mineral surface, removing the bead from the flowing fluid and preventing it from reporting to the producing well; the distinction between plate-out (surface adsorption) and size exclusion (the bead is physically too large to enter the pore throat or fracture aperture) requires laboratory core flow tests at representative flow rates and bead concentrations to quantify the relative contribution of each mechanism to bead loss.
• Scale plate-out in production systems is governed by the thermodynamic stability of the mineral phase at local temperature and pressure conditions: calcium carbonate (CaCO3, calcite) precipitates when the carbon dioxide partial pressure decreases as produced water moves from high-pressure reservoir conditions to lower-pressure wellbore and surface conditions, because the CO2-bicarbonate equilibrium shifts toward precipitation as CO2 is released from solution (analogous to the carbonation process that causes calcium carbonate scale to form in kettle descalers and hot water systems); the saturation index (SI = log10(IP/Ksp), where IP is the ion product of calcium and carbonate concentrations and Ksp is the solubility product constant) quantifies how far the produced water is from equilibrium, with SI greater than 0 indicating supersaturation and scale precipitation potential; barium sulfate (BaSO4, barite) scale precipitates when barium-rich formation water from a producing reservoir comingles with sulfate-rich seawater injected for pressure maintenance, because barium and sulfate have extremely low mutual solubility (Ksp of barium sulfate at reservoir conditions is approximately 10^-10 molar squared); barium sulfate scale plate-out is particularly problematic because it is extremely difficult to dissolve chemically (its low solubility means that acids that dissolve calcium carbonate are ineffective against barium sulfate, requiring chelating agents such as DTPA or EDTA at high concentrations) and its crystal habit produces hard, dense deposits that resist mechanical removal.
• Scale inhibitor squeeze treatments are designed to prevent scale plate-out by adsorbing phosphonate or polycarboxylate inhibitor compounds onto the formation mineral surfaces near the wellbore during the squeeze injection, where the inhibitor slowly desorbs (plates off) back into the produced water during subsequent production, maintaining inhibitor concentrations in the produced water above the minimum inhibitory concentration (MIC) needed to prevent scale nucleation; the squeeze lifetime (the duration of inhibitor release from the formation before the produced inhibitor concentration drops below the MIC) depends on the inhibitor adsorption isotherm (the relationship between the inhibitor concentration on the rock surface and the concentration in the surrounding water), the produced water flow rate through the treated rock volume, and the MIC for the specific scale chemistry; phosphonate scale inhibitors (diethylenetriamine pentamethylene phosphonic acid, DTPMPA; nitrilotrimethylene phosphonic acid, NTMP) adsorb strongly on carbonate and calcite surfaces and provide squeeze lifetimes of 6 to 24 months at typical North Sea produced water rates, while phosphonate inhibitors adsorb poorly on clean quartz sandstone (requiring a pre-flush of calcium chloride solution to pre-coat the quartz with calcium ions that provide adsorption sites for the phosphonate), with squeeze lifetimes of only 1 to 3 months in clean sandstone formations.
• Asphaltene plate-out in production tubing occurs when crude oils with high asphaltene content (typically greater than 5 percent by weight) experience the pressure reduction associated with flowing from the reservoir through the perforations and into the tubing, passing below the asphaltene onset pressure (AOP) where the asphaltene aggregate structure destabilizes and the asphaltene molecules begin to flocculate and deposit on the pipe wall; asphaltene deposits build up progressively on the tubing wall, reducing the effective tubing bore diameter and increasing the frictional pressure drop, until the tubing becomes partially or fully blocked and production stops; the time from first asphaltene plate-out to complete tubing blockage depends on the crude oil asphaltene content, the flow rate, the temperature profile, and the tubing metallurgy (rough surfaces promote nucleation more than smooth surfaces), and can range from weeks in high-asphaltene crudes to years in marginal asphaltene stability crudes; asphaltene removal from tubed wells requires either hot oiling (circulating heated crude oil or diesel down the tubing to re-dissolve the asphaltene deposits at elevated temperature), chemical solvents (aromatic solvents including xylene, toluene, and proprietary asphaltene dispersants injected by coiled tubing), or mechanical pigging (using solid scrapers conveyed by coiled tubing or jarred by slickline impact jars to physically break up and displace the deposit).
• Wax plate-out (paraffin deposition) in production tubing occurs when the flowing crude oil cools below its wax appearance temperature (WAT, also called the cloud point, the temperature at which the first solid paraffin crystals nucleate from the oil), causing waxy components (predominantly C20 to C40 normal alkanes) to crystallize and deposit on the cooler tubing wall in a gel-like structure that grows inward from the wall and progressively restricts the flow bore; wax plate-out is most severe in the upper tubing sections near the wellhead (where the flowing temperature has been reduced by heat exchange with the cooler surrounding formation or the ambient environment) and in subsea flowlines (where seawater temperatures of 3 to 7 degrees Celsius cool the produced fluid well below the WAT of most medium and heavy crude oils); wax prevention strategies include thermal insulation of the tubing and flowline (using syntactic foam or vacuum-insulated tubing to maintain the flowing temperature above the WAT), chemical inhibition (adding wax crystal modifiers that disrupt paraffin crystal growth and keep the wax in a pumpable suspension), and periodic pigging (mechanically removing accumulated wax deposits from pipelines using foam or steel pigs driven by the production pressure or pumped behind a water slug).