chemical injection

Chemical injection in oil and gas production is the continuous or batch delivery of production chemicals through dedicated injection systems to specific points in the wellbore or surface facility where the chemicals are needed to prevent or remediate flow assurance problems including corrosion, scale deposition, hydrate formation, wax and asphaltene deposition, emulsion formation, and microbial activity, with the chemical injected through a capillary tubing string clamped to the outside of the production tubing string (for downhole injection at the pump intake, the packer assembly, or the perforations), through an injection quill or nozzle assembly at the wellhead or subsea tree (for wellhead injection), or through a chemical injection point in the surface flowline or process piping (for surface facility chemical treatment). In Western Canada Sedimentary Basin oil and gas production operations, chemical injection is a core production chemistry function at virtually every producing well and facility because the combination of WCSB produced water chemistry (high bicarbonate, calcium, barium, and chloride concentrations in formation water from Cretaceous and Devonian reservoirs), WCSB gas composition (CO2 at 0.5 to 5 percent in Cardium and Viking gas, H2S at 0.1 to 15 percent in Devonian sour wells), and WCSB surface operating temperatures (minus 30 to plus 35 degrees Celsius seasonal range) creates flow assurance challenges that cannot be managed by well design or reservoir engineering alone and require continuous chemical treatment to sustain commercial production rates throughout the producing life of the well. A WCSB Cardium oil well with 5 percent water cut and 0.8 percent CO2 in solution gas, operating at minus 20 degrees Celsius ambient temperature in January, may require simultaneous injection of corrosion inhibitor (to protect the carbon steel production tubing from CO2 corrosion at the gas-water interface), scale inhibitor (to prevent calcite deposition in the tubing as pressure drops and CO2 evolves from solution, raising produced water pH above the calcite saturation point), and methanol (to prevent hydrate formation in the well casing-tubing annulus during shut-in periods when gas cools to below the hydrate equilibrium temperature); managing all three injection systems simultaneously from a single chemical injection skid is standard practice at WCSB multi-well pad facilities served by a common chemical storage and distribution system. WCSB chemical injection program effectiveness is measured by corrosion coupon weight loss rates, scale caliper log accumulation intervals, and hydrate event frequency per winter season.

• Downhole chemical injection system design: capillary tubing sizing, check valve placement, and injection point selection for WCSB wells: Downhole chemical injection delivers the production chemical to the desired point in the wellbore through a small-diameter stainless steel or Hastelloy C276 capillary tube (3.18 to 6.35 mm OD, wall thickness 0.71 to 1.24 mm) clamped to the outside of the production tubing string at 3 to 5 m intervals with tubing bands; the injection point at the bottom of the capillary terminates in a check valve assembly that prevents wellbore fluid from backflowing into the capillary between injection pulses. In WCSB ESP-lifted Cardium wells, the downhole chemical injection point is placed at the ESP pump intake (typically 1,100 to 1,500 m TVD) to deliver scale inhibitor and corrosion inhibitor at the point of maximum turbulence and CO2 release as fluid transitions from reservoir to wellbore conditions; injecting the chemical at the pump intake rather than at surface ensures the chemical reaches the critical near-pump zone before scale nucleation or corrosion can occur in the high-flow-velocity pump stages. Capillary tube hydraulics for WCSB downhole injection are designed to deliver the required chemical injection rate (typically 5 to 50 mL/min) against the sum of the hydrostatic pressure of the chemical column in the capillary (typically 8 to 15 MPa for 1,000 to 1,500 m depth), the wellhead back-pressure, and the frictional pressure drop in the capillary tube (0.5 to 3 MPa at design injection rate); the surface injection pump must exceed this total backpressure to maintain the design injection rate.
• Scale inhibitor injection programs for WCSB Cardium and Devonian produced water systems: Scale inhibitor chemical injection in WCSB oil and gas wells targets calcite (CaCO3), barite (BaSO4), and iron carbonate (FeCO3) scale that deposits in production tubing, wellhead valves, subsurface safety valves, and surface flow lines as produced water undergoes pressure reduction and temperature change from reservoir to surface conditions. Phosphonate scale inhibitors (HEDP, DTPMP, BHPMP) and polycarboxylate scale inhibitors (polyacrylic acid, polymaleic acid) are injected continuously at 5 to 30 mg/L in the produced water stream for WCSB produced water with calcium above 500 mg/L and bicarbonate above 1,000 mg/L; at these inhibitor concentrations the Langelier Saturation Index of the treated produced water remains below zero (undersaturated with respect to calcite) throughout the pressure and temperature traverse from reservoir to separator, preventing scale nucleation even at the gas-liquid interface where CO2 release would otherwise drive pH above the calcite saturation threshold. Scale inhibitor squeeze workover treatments (injecting a slug of concentrated inhibitor solution into the near-wellbore formation for adsorption on reservoir rock, providing a slow-release inhibitor source as produced fluid flows back) are used in WCSB wells that cannot support continuous downhole injection due to completion geometry or completion type constraints.
• Corrosion inhibitor injection for CO2 and H2S corrosion control in WCSB gas and sour oil wells: Corrosion inhibitor chemical injection in WCSB CO2 and H2S service wells delivers filming amine or quaternary ammonium compound inhibitors to the gas-liquid interface in the production tubing where CO2 and H2S dissolved in produced water form carbonic acid (pH 4.5 to 6.5) and bisulfide that attack the carbon steel tubing surface at rates of 2 to 12 mm per year at uninhibited conditions. Imidazoline-based filming amines at 20 to 100 mg/L in the produced water phase are the standard WCSB corrosion inhibitor for CO2 service (less than 0.5 percent H2S) in Cardium and Viking oil wells; for WCSB Devonian sour gas wells (H2S above 1 percent), high-H2S-tolerant inhibitor formulations using quaternary ammonium salts or phosphate ester chemistries are specified because standard imidazoline inhibitors lose film persistence in the presence of high H2S concentrations. Corrosion inhibitor effectiveness in WCSB wells is monitored by carbon steel corrosion coupons installed in the surface flowline and retrieved quarterly; target corrosion rates of less than 0.1 mm per year (equivalent to less than 0.5 mg/cm2/day on a corrosion coupon) indicate adequate inhibitor film coverage at the recommended injection dose, while rates above 0.25 mm per year trigger inhibitor type change or dose increase.
• Methanol and glycol injection for hydrate and freeze prevention in WCSB gas wells and gathering systems: Methanol chemical injection in WCSB gas wells and gathering systems prevents natural gas hydrate formation (clathrate ice-like solids that block pipelines and wellbore tubulars at temperatures below the hydrate equilibrium temperature at the prevailing gas pressure) and prevents water freeze-up in surface flowlines and valves during WCSB winter operating temperatures of minus 20 to minus 40 degrees Celsius. Methanol is injected at the wellhead or at the Christmas tree at rates of 5 to 30 litres per million standard cubic feet of gas for WCSB shallow gas wells (well head pressures of 2 to 10 MPa) with water content of 0.5 to 5 g/GJ; at these injection rates, the methanol concentration in the free water phase at the coldest point in the system is maintained above 25 to 35 percent by weight, depressing the hydrate equilibrium temperature by 8 to 15 degrees Celsius below the uninhibited hydrate formation temperature and providing a safety margin above the lowest ambient temperature at the WCSB surface location. Monoethylene glycol (MEG) is used instead of methanol in WCSB gathering systems where methanol vapor loss to the gas phase is an HSE concern (methanol is toxic at low concentrations) or where glycol recovery and recirculation is economically viable at high gas volumes; MEG recovery units operating at WCSB gas processing plants recycle 95 to 99 percent of injected MEG, reducing glycol chemical cost to $0.10 to $0.50 per GJ of gas throughput compared to $0.30 to $1.20 per GJ for methanol that cannot be recovered.
• Chemical injection system monitoring, pump performance, and AER Directive 017 reporting for WCSB production facilities: Chemical injection system performance in WCSB production facilities is monitored by daily injection rate verification (flow meter or stroke counter on positive displacement injection pump), monthly chemical inventory reconciliation against theoretical injection volumes, and quarterly sampling of produced fluid for chemical tracer concentration that confirms the chemical is reaching the injection point and distributing through the production stream at the design concentration. AER Directive 017 (Measurement Requirements for Oil and Gas Operations) requires that WCSB operators maintain records of all chemicals injected into producing wells and report chemical injection volumes annually in the facility chemical use report; chemicals classified as environmentally sensitive under AER Chemical Disclosure Requirements must be reported on the Canadian Chemical Disclosure Registry with product identity, injection rate, and disposal pathway documented. Chemical injection pump failures are among the most common causes of unplanned flow assurance events in WCSB operations; pump redundancy and remote injection rate monitoring via SCADA at multi-well pads reduces uninhibited exposure time from days (discovered at weekly site visit) to 2 to 4 hours (SCADA alarm response).

Downhole Chemical Injection Preventing Scale Shutdown in WCSB Cardium ESP Producer

A west-central Alberta Cardium oil well operating an ESP at 1,240 m depth experienced three ESP shutdowns in 18 months due to scale-induced pump intake blockage, with each event requiring a well service rig to pull and clean the pump assembly at a cost of $45,000 to $65,000 per event. Produced water analysis showed calcium of 2,400 mg/L, bicarbonate of 1,800 mg/L, and a Langelier Saturation Index of plus 2.1 at pump intake conditions (52 degrees Celsius, 4.2 MPa), indicating severe calcite scaling tendency. A downhole capillary injection system was installed during the third pump pull: a 4.76 mm OD 316L stainless steel capillary tube was run alongside the 2 7/8 in production tubing to the pump intake, with a 70 MPa-rated check valve at the injection point. Surface injection of HEDP phosphonate scale inhibitor at 18 mL/min (equivalent to 22 mg/L in the 47 m3/d produced water rate) was initiated from a 200-litre drum via a 7-bar positive displacement injection pump. Produced water sampled quarterly confirmed HEDP concentration of 15 to 24 mg/L at surface; no pump intake scale blockage events occurred in the 24-month monitoring period, compared to three events in the prior 18 months, saving an estimated $165,000 in avoided workover costs against a $28,000 system installation cost.

Related Terms

Scale deposition in WCSB production tubing and wellhead equipment is the primary target of scale inhibitor chemical injection; phosphonate and polycarboxylate inhibitors at 5-30 mg/L prevent calcite and barite nucleation in Cardium and Devonian produced water systems. Corrosion of WCSB carbon steel production tubing by CO2 and H2S is controlled by filming amine corrosion inhibitor injection; target corrosion rates below 0.1 mm/yr are verified by quarterly corrosion coupon retrieval. Hydrate formation in WCSB gas wells is prevented by methanol or MEG injection at the wellhead; inhibitor dose maintains 25-35% concentration in the free water phase at the coldest system point. Check valve is the critical downhole component at the injection point; it prevents produced fluid from backflowing into the capillary tube between injection pump strokes, protecting the capillary from plugging. Capillary tubing is the delivery conduit for downhole chemical injection in WCSB ESP and rod pump wells; 3-6 mm OD stainless steel or Hastelloy C276 capillary is clamped to the production tubing and run to the required injection depth.