Injection Mandrel

Key Takeaways

• Chemical injection through a mandrel provides several critical advantages over surface injection (injecting chemicals at the wellhead or downstream of the wellhead choke): by injecting at depth, the chemical is introduced into the produced fluid stream at the point where the treatment is needed (for example, injecting methanol at the tubing shoe in a high-pressure gas well treats the low-temperature, high-pressure region where hydrates form rather than treating already-formed hydrates after they have partially plugged the flow path); the concentration of chemical in the wellbore fluid at the treatment point is higher than would be achieved with surface injection (because the chemical has not been diluted by the full column of produced fluid above the injection point); and pressure-sensitive treatment chemicals (such as corrosion inhibitors that adsorb onto steel surfaces more effectively under higher pressure) are more effective when applied at wellbore pressure (2,000 to 10,000 psi) than at surface conditions (200 to 500 psi after choke pressure reduction); the chemical injection rate required to achieve target concentration at the treatment point is determined by the produced fluid rate, the desired chemical concentration (typically 10 to 100 ppm for corrosion inhibitors, 100 to 3,000 ppm for hydrate inhibitors such as monoethylene glycol, and 1 to 10 ppm for scale inhibitors), and the distance from the injection point to the zone of concern, with higher injection rates needed when the treatment point is far below the zone of concern to ensure adequate chemical concentration is maintained throughout the flow path.
• Side-pocket mandrel design for chemical injection (pioneered by Camco and now manufactured by Baker Hughes, Weatherford, and Schlumberger/SLB) uses a bypass bore that is offset from the main tubing axis by several centimeters, with the side pocket accommodating a wireline-retrievable check valve or injection valve that can be pulled and replaced using a kickover tool run on slickline without disturbing the production tubing string; the kickover tool is a wireline tool that aligns itself with the side-pocket opening using an orienting sleeve and then bends the tool string into the side pocket to engage and retrieve the valve, or to install a new valve after retrieving the old one; the wireline-retrievable design allows operators to change the check valve's cracking pressure (the minimum differential pressure required to open the check valve and allow injection), replace a failed check valve that is allowing production fluid to back-flow up the injection line and contaminate the chemical injection pump, or upgrade from a simple check valve to a more sophisticated chemical injection valve that meters the injection rate as a function of annular pressure; this serviceability without a tubing pull is the primary commercial justification for the more expensive side-pocket mandrel over a simpler inline injection port, as a single tubing pull in a deep well costs $100,000 to $1,000,000 versus a slickline intervention cost of $5,000 to $30,000.
• Injection mandrel placement depth in the tubing string is determined by the wellbore flow assurance analysis that identifies the critical points in the flow system where treatment is most needed: for hydrate control in deepwater gas wells (where the subsea wellhead and shallow tubing are in the cold deepwater temperature environment and at high pressure, creating conditions ideal for hydrate formation in the tubing), the injection mandrel is placed as deep as possible in the completion (often at the tubing shoe near the perforations) so that thermodynamic inhibitor (methanol or MEG) is present throughout the cold temperature zone from the wellbore entry to the mudline; for corrosion inhibitor injection in CO2- or H2S-bearing wells (where acid gas corrosion of the production tubing is most severe in the liquid-dominated lower tubing sections where dissolved CO2 or H2S concentrations are highest), the mandrel is placed near the tubing shoe or below the gas lift injection point to treat the most corrosive segment of the flow path; for scale inhibitor injection (preventing calcium carbonate or barium sulfate scale deposition in the perforations or near-wellbore tubing), the mandrel is placed above the perforations to treat the produced water before scale nucleation and growth can occur in the restricted flow path of the perforation tunnels or the tubing joint above the perforations.
• Multiple injection mandrels stacked at different depths in the same tubing string (a multi-point injection completion) allow different chemicals to be injected at their respective optimal locations: a typical deepwater gas well completion might include a deep mandrel for MEG hydrate inhibitor injection at the tubing shoe, a mid-string mandrel for corrosion inhibitor injection in the liquid accumulation zone, and a shallow mandrel for a second MEG injection point near the subsea tree to treat the production wing valve and flowline; each mandrel has its own dedicated control line that runs from the wellhead to the surface chemical injection skid, where individual pumps (typically low-rate, high-pressure positive displacement pumps) dose each chemical at the design concentration; the control lines are typically 3/8-inch or 1/2-inch OD stainless steel or inconel tubing rated to 15,000 psi, bundled with the production control and gas lift lines in a composite umbilical that connects the subsea wellhead to the surface or FPSO chemical injection system; the umbilical design and chemical injection system sizing are critical long-lead items in deepwater project development, as the number and location of injection mandrels determines the number of umbilical tubes required, which directly affects the umbilical diameter, cost, and installation vessel requirements.
• Gas lift mandrels are a distinct but related category of completion component that use the same side-pocket mandrel body as chemical injection mandrels but are equipped with gas lift valves (bellows-actuated or orifice valves) rather than simple check valves; the gas lift mandrel receives compressed gas injected down the casing-tubing annulus and routes it into the production tubing through the gas lift valve at the design operating pressure, with multiple gas lift mandrels stacked at different depths allowing staged gas lift that can be optimized as the reservoir pressure declines and the continuous injection depth changes; many injection mandrel strings combine gas lift mandrels (for artificial lift) with chemical injection mandrels (for flow assurance) in a single completion tubing string, using both the side annulus (for gas lift gas) and dedicated small-bore control lines (for chemical injection) to supply different fluids at different depths through the same mandrel body configuration.