Production String

Key Takeaways

• Tubing size selection for the production string is one of the most consequential decisions in well completion design because it cannot be reversed without a full workover once the well is producing — the production engineer constructs tubing performance curves (TPC) for candidate tubing sizes and overlays them with the inflow performance relationship (IPR) to find the tubing size whose intersection with the IPR gives the maximum production rate over the well's producing life; for a high-rate oil well producing 2,000 barrels per day, the difference between 2-7/8 inch and 3-1/2 inch tubing may be 200-400 psi in flowing bottomhole pressure requirement at the same rate, translating directly to more drawdown available from the reservoir and higher production; for a gas well approaching liquid loading, the tubing size determines the critical gas velocity at which liquid loading begins — too large and the gas velocity is insufficient to carry liquids at low rates late in the well's life; for an artificial lift well, the tubing must be compatible with the pump size (for ESP or rod pump) or the gas lift mandrel spacing (for gas lift); getting the tubing size wrong means living with the consequence for the well's entire producing life, typically 10-30 years.
• Production string metallurgy is determined by the corrosive environment of the produced fluids, with sour service (H2S-containing) and high-CO2 wells requiring special alloys that can cost 3-10 times more than standard carbon steel tubing — standard API carbon steel tubing (grades J-55, K-55, N-80, P-110) is adequate for sweet (low H2S, low CO2) service at moderate temperatures and pressures; when H2S partial pressure exceeds 0.05 psia (the NACE threshold for sour service), standard carbon steel becomes susceptible to sulfide stress cracking (SSC), a form of hydrogen embrittlement that causes sudden brittle fracture under tensile load without warning; NACE-compliant sour service tubing uses specific heat treatment conditions and hardness limits to resist SSC; when CO2 partial pressure is high (typically above 30 psia), carbon steel corrodes rapidly through carbonic acid attack on the pipe wall, reducing wall thickness and eventually causing perforation and tubing failure; high-CO2 wells use 13% chromium (13Cr) stainless steel tubing or duplex stainless steel (22Cr, 25Cr) for more severe environments; the corrosion allowance, inhibitor injection strategy, and tubing material grade are calculated together as part of the completion design to achieve the required service life at the lowest total cost.
• The packer that isolates the production string from the casing annulus is as important as the tubing itself, because without packer integrity the entire production string design fails — a production packer is a downhole elastomeric and mechanical seal that expands against the production casing wall and holds the bottom of the tubing string in compression or tension; the packer isolates the annulus above the perforated interval so that produced reservoir fluid must enter the tubing through the packer bore and flow to surface, rather than flowing up the annulus where it would expose the production casing to reservoir pressure and corrosive fluids; permanent packers (set mechanically or hydraulically and not retrievable without milling) are used in high-rate or high-pressure wells where long-term annular isolation is critical; retrievable packers allow the tubing string to be pulled for workover without milling the packer, at the cost of somewhat lower pressure ratings and seal integrity; packer failure (elastomer degradation from high temperature, metallic seal damage from pressure cycling, or improper setting) allows reservoir fluid to enter the annulus, which can corrode the production casing (a very expensive failure to remediate, often requiring a patch or sidetrack), pressurize the surface equipment to unsafe levels, or allow gas to migrate into the annular space where it cannot be controlled.
• The subsurface safety valve (SSSV) installed in the production string near the top of the well is a regulatory and safety requirement in most jurisdictions that permanently shuts the well in the event of loss of surface control — a surface-controlled subsurface safety valve (SCSSV) is a flapper valve installed in the tubing 100-500 feet below the mudline (offshore) or below the surface casing shoe (onshore), held open by hydraulic control line pressure from the surface; if the control line is damaged (from a platform incident, a blowout at the wellhead, or intentional emergency shutdown), pressure is lost, a spring closes the flapper against the tubing bore, and the well shuts in automatically without requiring any surface intervention; the SSSV is the last line of defense when the Christmas tree or surface wellhead is compromised; offshore regulatory agencies (BSEE in the US, NSTA in the UK, PTTEPA in Thailand) require SSSVs at specified depths in all offshore production wells, and onshore wells in high-consequence areas (near population centers, sensitive environments) may also require them; the SSSV is tested periodically (annually in most jurisdictions) by closing it under controlled conditions and verifying the pressure seal holds — a SSSV that fails its test must be pulled and replaced before the well is returned to production.
• Tubing integrity management over the producing life of the well requires periodic inspection, pressure testing, and corrosion monitoring to catch failures before they become expensive blowouts or environmental incidents — production tubing strings are subject to continuous loading from internal pressure (reservoir pressure transmitted through the fluid column), external pressure (annular fluid pressure), temperature cycling (which induces thermal expansion and contraction stresses), corrosion (from produced water, H2S, CO2, and bacteria), erosion (from sand production or proppant flowback), and mechanical cycling from production rate changes and workover operations; tubing condition monitoring uses caliper logs (to detect wall thinning from corrosion or erosion), electromagnetic thickness tools (to measure average wall thickness around the circumference without pulling the tubing), corrosion coupons in the annular fluid (to measure corrosion rates), and periodic wellhead pressure testing of the tubing-packer assembly; when inspection reveals tubing with wall thinning below the minimum thickness required for the service pressure, or when a leak is detected (annular pressure building when the annulus valve is closed), the tubing must be pulled and replaced — a workover operation that typically costs $500,000-$3 million depending on well depth and location.