chrome tubing

Chrome tubing in oilfield production engineering refers to corrosion-resistant alloy (CRA) tubulars containing chromium as the primary alloying element, principally 13 percent chromium martensitic stainless steel (13Cr, UNS S41000) and its enhanced variants Super 13Cr (modified martensitic with 13 to 15 percent Cr, higher nickel, and lower carbon), used as production tubing and casing in wells producing corrosive fluids including carbon dioxide (CO2), hydrogen sulfide (H2S), and chloride-containing brines that would rapidly corrode standard carbon steel (L80, J55, N80) tubulars within months to years at reservoir conditions; in Western Canada Sedimentary Basin production operations, chrome tubing is specified for WCSB CO2 injection and production wells in the Weyburn and Midale enhanced oil recovery projects in southeastern Saskatchewan, for WCSB sour gas wells with moderate H2S and CO2 partial pressures in the Devonian Nisku, Leduc, and Beaverhill Lake formations of central Alberta, and for WCSB natural gas wells producing wet gas with CO2 concentrations above 3 percent and chloride-laden formation water that cause internal corrosion rates of 1 to 10 mm/year in carbon steel tubing without CRA protection. The corrosion resistance of 13Cr steel in CO2-containing environments derives from the passive chromium oxide (Cr2O3) film 2 to 5 nanometres thick that forms spontaneously on the alloy surface in the presence of oxygen or oxidizing conditions; this passive film is stable in CO2 brines at temperatures up to 120 degrees Celsius and chloride concentrations up to 50,000 mg/L, reducing CO2 corrosion rates in 13Cr tubing from 1 to 5 mm/year (carbon steel in the same environment) to below 0.025 mm/year (the API threshold for acceptable corrosion in production tubing), making 13Cr economically competitive with carbon steel plus chemical inhibitor programs when the CO2 partial pressure exceeds 0.2 MPa and the well is expected to produce for more than 5 to 10 years.

• 13Cr and Super 13Cr tubing specifications and WCSB CO2 service application limits: Standard 13Cr (API 5CT Grade L80 Type 13Cr) contains 12 to 14 percent Cr, 0.15 to 0.22 percent C, and less than 0.5 percent Ni, with yield strength of 552 to 655 MPa (80,000 to 95,000 psi) and wall thickness from 5.5 to 12.7 mm for common WCSB tubing sizes (60.3 mm to 114.3 mm OD). Super 13Cr (proprietary alloys including TenarisHydril Wedge 13Cr, Vallourec VM13Cr, and others) reduces carbon to below 0.05 percent and adds 4 to 6 percent Ni and 1 to 2 percent Mo, improving pitting corrosion resistance in chloride brines above 50,000 mg/L and extending the temperature service limit from 120 degrees Celsius (standard 13Cr) to 150 degrees Celsius. In the WCSB Weyburn Midale CO2 EOR project where 5 to 10 MPa CO2 is injected into the Midale beds at 1,500 m depth (CO2 partial pressure 3 to 7 MPa in the injection tubing, far above the 0.2 MPa threshold for aggressive CO2 corrosion), 13Cr tubing is used in all CO2 injection strings because the economics of replacing carbon steel tubing every 1 to 3 years (estimated cost $80,000 to $150,000 per tubing workover) exceed the premium cost of 13Cr tubing installation ($40,000 to $80,000 per string, 3 to 5 times the cost of L80 carbon steel) within the first 5 years of operation.
• H2S limits for chrome tubing in WCSB sour service and NACE MR0175 material selection: The resistance of 13Cr and Super 13Cr to sulfide stress cracking (SSC) differs fundamentally from their CO2 corrosion resistance: 13Cr is susceptible to SSC in H2S-containing environments because the martensitic microstructure has limited resistance to hydrogen embrittlement, and NACE MR0175/ISO 15156 restricts 13Cr use to H2S partial pressures below 0.003 MPa (3 kPa, equivalent to about 30 ppm H2S in 10 MPa total pressure gas) and temperatures above 60 degrees Celsius (below 60 degrees Celsius, the SSC risk increases and NACE limits 13Cr to even lower H2S partial pressures). Super 13Cr alloys with reduced carbon and higher nickel have improved SSC resistance and are qualified by NACE MR0175 for H2S partial pressures up to 0.01 MPa at temperatures above 60 degrees Celsius, extending the application range to WCSB low-sour gas wells with less than 0.1 percent H2S in a 10 MPa reservoir. For WCSB Devonian sour gas wells with H2S above 0.1 percent, duplex stainless steel (22Cr, UNS S31803) or 25Cr super duplex (UNS S32750) tubing provides both CO2 and H2S corrosion resistance, qualified under NACE MR0175 for H2S partial pressures up to 0.02 MPa at all temperatures relevant to WCSB Devonian production.
• Chrome tubing connection requirements and premium thread specifications for WCSB CRA applications: Standard API 8-round and buttress threads are not recommended for 13Cr and Super 13Cr tubing in WCSB high-pressure CO2 service because the thread form does not provide gas-tight metal-to-metal sealing, relying on thread compound to prevent gas leakage through the helical leak path, and thread compound can be washed out by the produced CO2 stream over time, creating external corrosion at the threaded connection. Premium connections with metal-to-metal seals (TenarisHydril Wedge 521, Vallourec VAM TOP, NOV XT39) are specified for WCSB 13Cr CO2 tubing to provide gas-tight sealing independent of thread compound, with the metal-to-metal seal creating a physical barrier between the internally produced fluid and the external annulus. Premium connection make-up torque for WCSB 13Cr tubing (5,000 to 12,000 Nm depending on tubing size and connection design) must be applied using a calibrated power tong with real-time torque-turn monitoring and recorded on the make-up chart for each joint, confirming the connection reaches the target final makeup torque without over-torque that could damage the seal surface or under-torque that leaves the metal-to-metal seal unseated.
• Chrome tubing cost-benefit analysis for WCSB CO2 and sour gas well economics: The economic justification for chrome tubing versus carbon steel plus corrosion inhibitor programs in WCSB CO2 and H2S service compares the capital premium for CRA tubing against the avoided workover costs and production deferral from carbon steel tubing failures over the well's economic life. For a WCSB Weyburn CO2 injection well with 2,500 m of 73 mm OD tubing, 13Cr tubing costs approximately $120,000 to $160,000 installed (3.5 to 5 times the $35,000 to $45,000 cost of L80 carbon steel), but avoids 1 to 2 tubing failures per 5-year period that would each cost $80,000 to $150,000 to remediate (workover rig, new tubing string, production deferral); the NPV break-even point in a typical WCSB CO2 EOR well at $50/bbl oil is 4 to 7 years, well within the 15 to 25 year expected Weyburn field production life. Carbon steel with corrosion inhibitor injection (continuous filming inhibitor at 50 to 200 mg/L) costs $30,000 to $80,000 per year in chemical cost plus monitoring, comparing unfavorably with 13Cr's essentially zero corrosion maintenance cost after installation for CO2-dominant service without H2S.
• Chrome tubing inspection and handling requirements for WCSB CRA tubular programs: Chrome tubing is more susceptible than carbon steel to surface damage, pitting, and stress concentration from mechanical impact, improper handling, and contamination by carbon steel contact during storage and running; pits or gouges in 13Cr tubing deeper than 12.5 percent of wall thickness are rejectable under API 5CT inspection criteria, and any carbon steel contamination (contact with carbon steel tongs, elevators, or pipe racks without stainless steel inserts) can deposit iron particles that initiate crevice corrosion in the CO2 environment at the contamination site. WCSB 13Cr tubing handling protocols require: dedicated non-marking slips and elevators with stainless steel inserts, fiberglass or rubber pipe racks on the rig floor with no carbon steel contact, visual inspection of each joint for mechanical damage before running, and drifting with a non-metallic drift (nylon or aluminum) to verify bore is free of deformation. Dope selection for WCSB 13Cr API connections (if premium threads are not used) requires API-modified thread compound compatible with 13Cr metallurgy; standard copper-based API modified thread compound is acceptable, but zinc-based dopes are prohibited because zinc can cause liquid metal embrittlement of 13Cr under temperature cycling conditions in WCSB CO2 injection wells where temperature swings from 5 to 60 degrees Celsius occur during injection and shut-in cycles.

13Cr Tubing Selection for WCSB Weyburn CO2 EOR Injection Well Avoiding Repeated Carbon Steel Failures

A Weyburn Unit CO2 injection well with 2,400 m of 73 mm OD L80 carbon steel tubing experienced two tubing failures in 4 years at CO2 partial pressure of 5.5 MPa and 45 degrees Celsius bottomhole temperature, each requiring a $95,000 workover for replacement and causing 18 to 22 days of injection deferral. Total failure cost was $210,000 over 4 years. Continuous filming inhibitor was injected at 80 mg/L but film formation was incomplete at the injection temperatures and flow velocities, leaving uninhibited areas that corroded at 2.8 mm/year measured by corrosion coupon at the tubing anchor. The operator replaced the L80 string with 13Cr L80 tubing at an installed cost of $138,000; corrosion coupon monitoring over the subsequent 36 months showed a corrosion rate below 0.02 mm/year (98 percent reduction). No failures occurred over the 36-month monitoring period; NPV analysis at $50/bbl and 10 percent discount rate showed the 13Cr investment paid back in 3.2 years versus the continue-with-carbon-steel base case.

Related Terms

Corrosion resistant alloy (CRA) is the material category encompassing chrome tubing; 13Cr, Super 13Cr, duplex 22Cr, and 25Cr super duplex represent increasing chromium content and corrosion resistance for progressively more aggressive WCSB CO2 and H2S service conditions. CO2 corrosion (sweet corrosion) is the primary degradation mechanism chrome tubing prevents; CO2 partial pressure above 0.2 MPa in WCSB Weyburn and Midale injection wells drives carbonic acid attack on carbon steel at 1-5 mm/year that 13Cr passive film reduces below 0.025 mm/year. Sulfide stress cracking (SSC) limits 13Cr applicability in WCSB sour service; NACE MR0175 H2S partial pressure limit of 0.003 MPa for standard 13Cr and 0.01 MPa for Super 13Cr governs material selection for WCSB wells producing mixed CO2-H2S. Weyburn CO2 EOR project in southeastern Saskatchewan is the primary WCSB application for 13Cr chrome tubing in injection strings; 5-10 MPa CO2 partial pressure in injection tubing makes CRA mandatory for economic operation over the 15-25 year project life. Premium connection with metal-to-metal seal is required for WCSB 13Cr CO2 service tubing; API threaded connections without gas-tight seals allow CO2 bypass through the thread helix, creating external corrosion and connection leak paths over time.