Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
Results
The Selection of Corrosion Inhibitors under Oil/Water/Gas Flow Conditions in Deep Offshore Catenary Risers
Kang, Cheolho (Det Norske Veritas USA, Incorporated) | Tummala, Kavitha (Det Norske Veritas USA, Incorporated) | Rhodes, Jesse (Det Norske Veritas USA, Incorporated) | Magalhae, Alvaro Augusto Oliveira (Petrobras)
ABSTRACT Multiphase flow characteristics can be altered with the change of pipeline topography in deep offshore oil and gas production. The increase of corrosion rate and decrease of inhibitor performance in the risers can occur due to the change of multiphase flow characteristics (e.g. severe slugging). For the simulation of offshore flow lines and risers, the experiments were carried out in a 44 m long industrial scale multiphase flow loop equipped with three different pipeline inclinations of 0, 3 and 45 degrees. The effectiveness of three commercial corrosion inhibitors were analyzed using 25 cP oil at 20% water cut with three different gas velocities (0.7 m/s, 3 m/s, and 6 m/s). All tests were carried out at a liquid velocity of 1.5 m/s, a system pressure of 6 bar (76 psig) using carbon dioxide gas as the gas phase, and a temperature of 50°C. Also, the effect of inclination on the flow characteristics (e.g. flow pattern) and their subsequent effect on corrosion rates are described. The results indicated that severe pitting corrosion was noticed in the 3 and 45° weight loss coupons for baseline testing. Severe slugging and high slug frequency were seen in 45 degree upward flowing conditions. The tests differentiated between three corrosion inhibitors. In most of testing conditions, high inhibitor concentration was required to achieve the target corrosion rate.
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)
CFD Based Analysis of Multiphase Flows in Bends of Large Diameter Pipelines
Khaksarfard, Reza (Concordia University) | Paraschivoiu, Marius (Concordia University) | Zhu, Zhenjin (Broadsword Corrosion Engineering Limited) | Tajallipour, Nima (Broadsword Corrosion Engineering Limited) | Teevens, Patrick J. (Broadsword Corrosion Engineering Limited)
ABSTRACT This paper describes a computational fluid dynamics (CFD) analysis performed to predict the characteristics of the dominant multiphase flow regime in over-bends and under-bends of a typical large-diameter heavy crude oil pipeline. It was noticed in field indirect inspections and also studied in the literature that pipelines downstream of the over-bends are usually prone to localized pitting corrosion but the root-cause of this phenomenon is not fully understood and therefore further investigation is still required. In this study the effect of crude API density, water to oil flow-rate ratio (water-cut) as well as pipeline internal diameter, inclination angle and total flow rate on the water-wetted surface area for a stratified multi-phase flow regime is investigated using a 3D numerical simulation technique. The water-oil interface inside the pipeline and the effect of the pipeline inclination angle on the shape of this interface for different sets of operational conditions is studied. The paper shows that the secondary flow, the Dean flow, due to a change of orientation of the pipe spreads the water on the wall of the pipe for a positive slope and accumulates the water in the center for a negative slope.
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Multiphase flow (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
- (2 more...)
ABSTRACT A widely used method to control corrosion in oil and gas pipelines is the use of corrosion inhibitors. However, their performance can be affected by their chemical composition, concentration, flow pattern, and flow regime. This investigation presents the comparison of two types of a water-soluble and an oilbased inhibitor, at concentrations of 0 ppm, 20 ppm, 40 ppm and 80 ppm, mixed in a 5% NaCl solution (electrolyte) at different electrolyte-to-oil ratios (2:8, 2:3, 8:2). A carbon steel rotating cylinder electrode was used to assess the inhibitors under different flow regimes with fluid velocities of: 0.32, 0.64, 0.97 and 1.29 m/s (1.05, 2.1, 3.18, and 4.23 ft/s). The water-based inhibitor presented the best performance, with efficiencies of up to 80%. INTRODUCTION In the oil and gas industry corrosion represents a major issue since a quarter of the failures are due to corrosion.[1]In
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)
Internal Corrosion Direct Assessment of a High-Pressure Wet-Gas Pipeline Using NACE SP0110
Teevens, Patrick J. (Broadsword Corrosion Engineering, Limited) | Zhu, Zhenjin (Broadsword Corrosion Engineering, Limited) | Khera, Ashish (Allied Engineers) | Al-Sulaiman, Saleh (Kuwait Oil Company) | AL-Jasmi, Ahmad (Kuwait Oil Company) | Prakash, Surya (Kuwait Oil Company)
ABSTRACT This paper describes the first implementation of a complete four-step wet gas internal corrosion direct assessment (WG-ICDA) for a high-pressure natural gas transmission pipeline in Kuwait in compliance with NACE SP0110. The preassessment step collected physical and production data, assessed WG-ICDA feasibility and identified pipeline regions. During the indirect inspection step, multiphase flow modeling was performed using in-house proprietary software to determine flow regime, pressure profile, temperature drop, water content, liquid holdup, solids settling velocity and general corrosion rate along the entire pipeline. Based on the developed dynamic pitting factors, historically cumulative wall losses of the pipeline to date were predicted, and locations with the greatest likelihood of internal corrosion were identified. During the in-the-ditch detailed examination step, remaining wall thicknesses at recommended excavation sites were measured. In the postassessment step, a comparison between the predicted and measured wall losses demonstrates that the conducted WG-ICDA for the subject wet-gas pipeline is successful and effective. The conducted root-cause analysis of metal degradation assists the pipeline operator to ascertain the overall integrity of this asset through optimizing corrosion mitigation strategies and operating conditions.
- North America > Canada (0.68)
- Asia > Middle East > Kuwait (0.34)
- North America > United States > Texas > Harris County > Houston (0.16)
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)
Corrosion Mechanism in a Three-Phase North Slope Pipeline
Singh, P. (ConocoPhillips) | Frenier, H.N. (ConocoPhillips) | Goldmann, E.R. (ConocoPhillips) | Murali, J.J. (ConocoPhillips) | Watkins, R.J. (ConocoPhillips) | Young, K.M. (ConocoPhillips) | Achour, M.H. (ConocoPhillips) | Dash, L.C. (ConocoPhillips) | Lee, H.S. (ConocoPhillips)
ABSTRACT A North Slope of Alaska facility separates three-phase flow (produced water, oil, and natural gas) from four drill sites. Each of the drill sites has a three-phase production line that flows to the central facility. One of the three-phase pipelines was inspected by a magnetic flux leakage (MFL) in-line inspection (ILI) tool in 2008. The inspection showed significant internal corrosion with features measured up to 37% of wall thickness loss primarily in first 1 mile from the drill site. Most of the significantly corroded features are located between 3-4 o’clock and 8-9 o’clock positions. The results of the 2008 MFL ILI, corrosion inhibitor partitioning tests, corrosion modeling, and multiphase flow simulations were used to determine the potential corrosion mechanism in the line and to recommend corrosion control measures. The mechanism was determined to be a special case of "top of the line corrosion".
- North America > United States > Alaska (0.24)
- North America > United States > Texas (0.18)
Application of Plastic Strain Damage Models to Characterize Dent with Crack
Arumugam, Udayasankar (Blade Energy Partners) | Gao, Ming (Blade Energy Partners) | Krishnamurthy, Ravi (Blade Energy Partners) | Katz, David C. (Williams - Northwest Pipeline) | Wang, Rick (TransCanada Pipeline Limited) | Kania, Richard (TransCanada Pipeline Limited)
ABSTRACT Currently, the allowable strain limit for a plain dent is 6 percent as per ASME B31.8 for gas pipelines. Field experience has shown that the 6% strain limit for plain dents could be overly conservative, which can result in unnecessary excavations and repairs. Recently, efforts to develop an alternative strain limit have been proposed. In this paper, two plastic damage-based models, namely, ductile failure damage and strain limit damage, and one minimum elongation-based criterion are reviewed. Attempts have been made to use these models to characterize rock dents associated with cracks in terms of a plastic damage severity factor and its susceptibility to crack initiation. Field excavations and finite element analysis are utilized to validate these models using two real pipeline dents from two different pipeline operators, operating in USA and Canada. The results have shown that the internal cracks were formed at the time of the initial indentation and can be predicted by the plastic strain damage based ductile failure models. On the basis of this, a newly developed approach that combines in-line inspection (ILI) technologies (caliper and magnetic flux leakage [MFL]) is introduced and utilized to discriminate between dent with corrosion and dent with crack, and identify critical dents in the pipelines.
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean (0.24)
- North America > United States > Texas (0.19)
ABSTRACT Internal pipeline corrosion is a serious concern for transportation pipelines in the oil and gas industry. Water wetting is an important aspect of internal corrosion of mild steel pipelines, since the steel will not corrode unless the water is in direct contact with it. A water wetting model considering oil and water properties, flow rates, water cut, etc., has been proposed previously. This model showed good agreement between experimental results and the water wetting predictions for a water-paraffinic model oil system. However, for crude oil systems, this model over-predicted water wetting leading to overestimation of corrosion in realistic flow system. Here, a new, improved water wetting prediction model is proposed. The new model includes the effect of the steel surface-fluid interactions in order to calculate the transition between oil and water wetting in oil-water two-phase flow, in addition to considering the interaction between the bulk turbulence and the surface tension, as was done in the original model. The new model significantly improves the prediction of the critical oil phase velocity required for full water entrainment of water, when compared to the original model. The new model has been verified with results from large scale (0.1 m ID) multiphase flow loop experiments as well as with results obtained using a doughnut cell – which is a benchtop multiphase flow apparatus. The verification included data obtained with different crude oils as well as with a model oil containing different surface active chemical.