Nova Chemicals

Severe corrosion in the carbon steel tubing led to fluid leakage and reduced output in an ultra-deep gas well. Analysis using microscopy, XRD, and corrosion testing showed that while materials met API 5CT J55 standards, large-scale wall thinning reduced the tubing’s pressure tolerance below service conditions. Corrosion products included FeCO₃ and Fe₃O₄, with protective scaling layers of CaCO₃ and crude oil residues. Once disrupted at depth-specific pH and hydrodynamic conditions, the corrosion of the tubing accelerated. Simulations of the localized corrosion rate showed peaks in the first 30 days due to high CO₂, low pH, and increased flow-induced shear stress.

Reinforced thermoplastic pipes (RTPs) have attracted considerable attention lately in the oil and gas sector as potential alternative to carbon steel pipes. However, some RTP systems have been experiencing failures as a result of deficient design and inadequate operation practices. This study presents a comprehensive assessment of the failure of a steel-reinforced flexible thermoplastic composite layered pipe in a sour environment characterized by hydrogen sulfide (H2S) exposure. Utilizing scanning electron microscopy (SEM) and electron dispersive spectroscopy (EDS), the investigation conclusively attributes the failure of the RTP to hydrogen embrittlement of the carbon steel cords and wires in the reinforcement layer. Finite element models at both meso-scale and full RTP scale were developed, incorporating a novel damage initiation and propagation criterion for failure prediction of embrittled and non-embrittled (e.g. ductile) reinforcement steel cords. The numerical models consistently predicted a reduced burst pressures of the hydrogen embrittled case of the RTP, with a close match with field observations. They also predicted failure modes that closely matched the SEM findings, hence highlighting the unsuitability of the existing steel cords in RTPs for use in sour service environments. Additionally, the presence of moisture in the annular space was identified as an exacerbating factor. This investigation provides important insights for the future design and operation of RTPs susceptible to hydrogen embrittlement, paving the way for improved structural integrity and safety measures. Further research avenues may involve modeling hydrogen diffusion in the thermoplastic layers, simulating the movement of moisture in the annulus through the capillary effect, and incorporating fracture toughness degradation for a more thorough understanding of the interplay between mechanical and environmental factors in the hydrogen embrittlement of steel-reinforced RTP composite pipes.

Several carbon steel tubing suffered severe corrosion in service which resulted in the leakage of production fluids from tubing string and, consequently, a decrease of well productivity. Optical metallographic microscopy, X-ray diffraction (XRD), combined with weight loss and characterization methods were used to determine the most probable causes of the failure. The results showed that the composition and structure of the tubing joints and couplings were in accordance with the parameter requirements of API 5CT for grade J55. Upon visual inspection, the corroded pipe exhibited significant thickness reduction in multiple locations, which justifies utilizing the triaxial yield of pipe body formula, assuming the minimum measured thickness as the nominal thickness of the pipe. When compared to the upper bound internal pressure requirements in API 5CT, the equivalent stress calculation showed significantly lower failure pressure levels, which provide strong evidence that the pipe could not withstand actual service conditions. The composition of corrosion products was mainly FeCO3 and Fe3O4, and scaling layer were composed of the heavy components of the crude oil, CaCO3 and corrosion products. The scaling layer was protecting the steel surface from corrosion and reducing the corrosion rate. Once the scaling layer was broken, the corrosion rates increased. Also, pitting corrosion rates simulations were conducted at locations with the highest corrosion risk. Results show that at the first 30 days, pitting corrosion rates are the highest at these locations due to many factors including high CO2 partial pressures, acidic pH at these locations, and larger production volumes resulting in an increase of wall shear stresses and higher velocities.

This study investigates the corrosion kinetics and crack propagation in buried transmission pipelines made of high-strength low alloy steel API X100. Despite its cost-effectiveness and ability to withstand high operating conditions without increasing pipe wall thickness, the corrosion kinetics in near-neutral pH environments for this steel grade is not fully understood. To address this gap, two numerical models were developed. The first model, using COMSOL Multiphysics v5.6, showed higher electrolyte potential at the corrosion defect center due to stress-induced defect growth, increasing corrosion susceptibility. The second model, employing the XFEM approach, evaluated crack initiation, propagation, and von Mises stress distribution along the crack path. This research contributes to a better understanding of corrosion and crack behavior in corroded pipelines, aiding in their performance improvement in near-neutral pH soil environments.

Inline vertical separators are commonly employed in natural gas transmission facilities (e.g., receipt stations) to filter liquid contaminants such as compressor oil, glycol, and free water from the gas stream. Manufacturers of these separators have claimed liquid removal efficiencies of 98-99% for droplet sizes >= 8 mu m. However, these contaminants have been found invariably in piping systems downstream of these separators, suggesting inadequate separator performance. Currently, there is a lack of ability to verify manufacturer claims due to difficulties in quantifying liquid contaminants and droplet characteristics. The potential consequences of having such contaminants include lower gas quality, impaired gas metering accuracy, corrosion and damage to equipment/instrumentation, and adverse impacts on industrial and residential end users. This paper presents performance testing of a mesh-vane-type vertical separator conducted on high pressure, pipeline quality, natural gas in the range of 4-5 MPa and flow velocity in the range of 1.3-13 m/s in the DN150 separator inlet (hence turndown ratio of 10:1). Four different spray nozzles were used to inject and atomize industrial compressor oil with a liquid-to-gas mass loading ratio of 0.06-1.8%. Test results revealed that the average bulk efficiency separation performance for this separator is approximately 90.34%. This was found to be independent of the liquid-to-gas mass loading ratio. The effective Souders-Brown K-factor was found to be 0.15 m/s. This is below literature published data in the range of 0.27-0.3 m/s for horizontal flow, vane-pack-type separators. Liquid separation tests were also conducted following the injection of solid glass beads. Liquid separation efficiency decreased by approximately 9%, following the injection of 7 kg of industrial glass beads over a period of approximately 4 h. This was attributed to accumulation of solids in the vane pack.