Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
Enbridge Pipelines
ABSTRACT This paper presents new applications of Volatile Corrosion Inhibitors (VCI) inside new and/or existing out-of-service pipelines. The system utilizes a combination of soluble and volatile corrosion inhibitors that are directly applied into the pipeline. In some cases, the decrease in the corrosiveness of environment is done by increasing the pH. Different approaches are discussed depending on pipeline design and operating considerations of the owner. A recurring issue during the construction and commissioning, and sometimes operation, of facility pipe (pump station and terminal) assets is the creation of internal corrosion threats due to leftover hydrotest water or product. Available methods for removing the water or product entirely, or applying inhibitor chemicals to the hydrotest medium or product, are time-consuming and expensive. In 2015, 2016, and 2017 VCI chemicals were applied to various facility piping systems in lieu of other methods which would mitigate internal corrosion threats. This method, while not a best-practice in the oil and gas industry at the time, was shown through laboratory testing to be effective at mitigating both biological and generalized internal corrosion. The application of VCI was also proven to be safe for the personnel involved, which was one of the original objections of the operator, and the application process resulted in significant cost savings at the time of commissioning. This paper details a single preservation project as an example. INTRODUCTION Internal corrosion in metal pipelines is one of the greatest time-dependent threats affecting newly constructed, deactivated, or idled assets. New construction presents additional variables, such as leftover uninhibited hydrotest water, that increase the risks associated with internal corrosion. In mainline pipe that can be cleaned, inhibited, and inspected with inline tools and devices launched from traps, there are a multitude of ways to mitigate the risks presented by internal corrosion. However, with facility pipe, internal corrosion threats - especially from leftover hydrotest water where the pipe was not internally lined - are compounded by configurations that make owners unable to clean, inhibit, or inspect with inline tools (in most cases). In the case of buried facility pipe, external direct inspection is not possible to prevent leaks or ruptures, the consequence of which could be worsened by an inability for local staff to inspect visually, and the lack of leak detection equipment that would otherwise be present for a mainline system and thoroughfare facility pipe.
- Energy > Oil & Gas (1.00)
- Water & Waste Management > Water Management > Water & Sanitation Products (0.81)
- Materials > Chemicals > Specialty Chemicals (0.81)
Summary The problem of solids cleanout in horizontal wellbores was studied experimentally. The special case of drilling-fluid circulation with no inner-pipe rotation was considered. This case is similar to coiled tubing (CT) drilling in which frequent hole cleanout must be performed. Sand-sized cuttings (ranging from 260 to 1240 µm) were used. Critical velocity and wall shear stress required for starting bed erosion were measured. Water and viscous-polymer base fluids with three different polymer concentrations were used. Results have shown that water always starts cuttings movement at lower flow rates than polymer solutions. Fluids with higher polymer concentration (and higher viscosity) required higher flow rates to start eroding the bed. Critical wall shear stress was also determined from pressure-loss measurements. Analyzing the data revealed that water starts cuttings removal at lower pressure loss than more-viscous fluids. Higher-viscosity fluids always showed higher pressure loss at the start of bed erosion. For the range of cuttings size studied, results show that an intermediate cuttings size was slightly easier to remove. However, the impact of cuttings size was far less than that of fluid rheology. Overall cuttings size was found to have a small impact on hole cleaning. Dimensionless analysis of parameters relevant to the process of cuttings movement was performed. It was shown that dimensionless wall shear stress (in the forms of Shields’ stress and also ratio of shear velocity to settling velocity) at the onset of bed erosion correlated well with particle Reynolds number. On the basis of this finding, two correlations were developed to predict critical wall shear stress. A procedure was developed to calculate critical flow rate as well. Friction-factor data for the flow through the annulus with a stationary cuttings bed are also reported.
- North America > United States (1.00)
- Asia (0.68)
- South America (0.67)
- North America > Canada > Alberta (0.47)
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (0.88)
- Well Drilling > Well Planning > Trajectory design (1.00)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
INTRODUCTION ABSTRACT Pipelines carrying heavy crude oil from oil sand developments may be subject to corrosion caused by deposition of oil sand sediments, a sludge containing oil, water, and bacteria in a particulate matrix. A test methodology to determine the corrosive nature of the sludge and evaluate inhibitor performance is explored, consisting of exposure testing and electrochemical measurements of corrosion potential and linear polarization resistance (LPR) measurements. The corrosive nature of the sludge was demonstrated and differences in the corrosivity of various sludges were observed. Inhibitor performance was evaluated, where inhibitor was mixed with the sludge, or added to the bulk environment. The electrochemical measurements provided mechanistic data and information on the characteristics of the sludge that may be important in selecting an effective inhibitor. Corrosion has been observed at locations where sand and solids settle in oil transmission pipelines carrying heavy oil from oil sand developments. Whereas crude oil is generally expected to be naturally inhibitive, the sediments contain small quantities of water and bacteria, which enable corrosion to take place in those areas where the solids accumulate. Sedimentation processes are poorly documented and it is difficult to predict where deposition/accumulation will occur in some pipelines. With less than 0.5% sediment and water, accumulation of solids can occur as a result of gravitational settling coupled with fluid dynamic effects. The occurrence of underdeposit corrosion often does not coincide with the occurrence of corrosion caused by water accumulation. In large pipelines, inertial effects resulting from changes in pipe direction lead to underdeposit corrosion at unexpected locations. The underlying mechanisms of sediment deposition appear different for large (>20”) and small (<10”) pipelines. Enbridge has used internal corrosion mitigation programs including pigging and chemical treatment since the mid 1990's. To further increase the effectiveness of their mitigation program, a research program was initiated with the intent to understand and mitigate the corrosive influence of sediment in heavy crude oils. Five chemical inhibitor vendors were approached and encouraged to develop chemical treatments specifically aimed at reducing underdeposit corrosion. BACKGROUND Producing (upstream) pipelines typically contain a high percentage of corrosive formation water and acid gases that can cause pipeline failure within weeks or months. As a consequence of this potential for rapid corrosion, the upstream pipeline industry has developed a superb understanding of internal corrosion mitigation under water wet (high water percentage) pipeline conditions. Chemical treatment technologies have been improved and evolved over several decades and are well understood. In contrast, transmission pipelines have enjoyed a long history without significant levels of internal corrosion due to the use of sediment and water tariff limits that render the bulk fluid non-corrosive. As the potential for internal corrosion in low water cut pipelines began to manifest after decades of problem free operation, the transmission pipeline sector looked to the chemical inhibitor suppliers that serviced the upstream pipeline industry so successfully. Not surprisingly, the cleaning and batch chemical treatment programs proposed for transmission pipelines are based on experience gained on upstream pipelines with little regard.
ABSTRACT ABSTRACT A proposed method for Liquid Petroleum Pipeline Internal Corrosion Direct Assessment (LP-ICDA) has been developed that is consistent with the general principles of other Direct Assessment (DA) methods. The scope of LP-ICDA complements those of dry gas ICDA (DG-ICDA) and wet gas ICDA (WGICDA). LP-ICDA (as with other DA methods) is intended to serve as an integrity verification tool, playing the same role within pipeline integrity management as in-line inspection (ILI) and hydrotesting (either as a replacement or as a complement). The method relies on 1) identifying a mechanism for corrosion susceptibility, 2) detecting a property associated with this mechanism through an indirect measurement, 3) performing a direct observation of the pipe (e.g., by excavation), and 4) correcting for any discrepancies between the predictions and observations. The underlying basis of the proposed approach is simple; corrosion in liquid petroleum pipelines is most likely where water and/or solids accumulate. Secondary factors affecting the distribution of corrosion between locations of water and solids accumulation are also considered. INTRODUCTION Liquid product transmission pipelines are defined as pipelines that are fully packed with a liquid phase (i.e., no significant gas phase). Water content in crude oil is typically specified by "basic (or bottom) sediment and water" (BS&W) of less than 1% (sometimes 0.5 or 0.35%), and refined product or hydrocarbon condensate specifications are typically more stringent. Direct assessment methodology (DA) has been developed for the purpose of performing pipeline integrity verifications, especially for pipelines that are not able to accept inline-inspection (ILI) tools. DA development was initially driven by a need to meet pending changes to U.S. natural gas transmission pipeline regulations. DA also has applicability to the pipelines carrying other products. External corrosion DA (ECDA) and Stress corrosion cracking DA (SCCDA) have been developed for the buried pipelines. The prediction applicability of ECDA and SCCDA does not depend upon the product being transported, except that pressure fluctuations can differ between liquid and gas systems, and SCC susceptibility can be affected. The basis of DA is that 1) a mechanism for susceptibility is identified (i.e., preassessment), 2) a property associated with this mechanism is used as a basis for detecting susceptibility (indirect inspections), 3) direct observations are made to verify the correlation between the property and mechanism (direct examinations), and 4) corrections are made for any discrepancies (i.e., postassessment). Internal Corrosion Direct Assessment (ICDA) is a process that can be used to assess pipeline integrity, based on identifying areas along the pipeline where internal corrosion is most likely to exist. The process identifies the potential for internal corrosion caused by microorganisms, fluid with CO2, O2, H2S or other contaminants present in the carrying fluid. The ICDA methodology is a four-step process requiring integration of pre-assessment and indirect inspection data, with detailed examinations of the internal pipeline surface. A method to assess internal corrosion in normally dry natural gas systems has been developed and termed Dry Gas Internal Corrosion Direct Assessment (DG-ICDA).
Workshop: Data Model Standards For Pipeline Simulation
Bachman, Susie (Intergen) | Chmilar, Bill (TransCanada Pipeline Ltd) | Ellul, Ivor (Knowledge Reservoir Inc.) | Goodman, Mike (El Paso Corporation) | Goodreau, Mary (Stoner Associates Inc.) | Nicholas, Ed (Nicholas Simulation Services) | Pietsch, Ulli (Enbridge Pipelines)
Workshop Outline Vision Deliverables–Data structure –Data interchange format Prototype definition Prototype demonstration Near term priorities Discussion Vision To develop a recommended data structure and an associated data exchange format to enable consistent input and output interface with pipeline simulation models Data Structure Vendor data and format review complete Common areas Differences Result:–Draft data structure of 1999 Data Interchange Format What is XML? What is XSLT? XML and Databases Prototype Definition Description Models used–ESI –Stoner –Gregg Prototype Results Results–Using XML for Input Configuration Files –Using XML for Output Data Comments Near Term Priorities Solicit and formalize user requirements of data models Solicit vendor input Continue development of data transfer protocol Conceptualize output data model
- Data Science & Engineering Analytics > Information Management and Systems (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Piping design and simulation (0.66)
- Facilities Design, Construction and Operation > Measurement and Control > Pipeline leak detection (0.66)