Monday, October 30
Upstream pipeline operations (multiphase flow lines) are susceptible for internal corrosion attacks due to several reasons such as solids deposition, water accumulation, bacterial activities and improper operational practices, flow regime and flow related corrosion. To enhance integrity assessment for these lines, NACE International has published Standard Practices for the Internal Corrosion Direct Assessment (ICDA) protocols for predicting time-dependent internal corrosion threats for multiphase and wet gas lines. The non-intrusive technique of ICDA is applicable for piggable/non-piggable, offshore/ onshore and sweet/ sour service pipelines. This session would focus on:
- How ICDA has been used as an integrity validation technique
- Mandatory requirement of ICDA for providing the root cause and a go forward plan
- Effectiveness criteria for proving the prediction modeling
- Why ICDA would be complimentary to ILI
- Key ingredients for a “successful” ICDA program
The threat to corrosion integrity rises without the proper understanding of the wells behavior especially when dealing with high contaminants (e.g.: CO2, H2S, O2, Sand)/reservoir souring as a consequence of untreated water injection fluids affecting both producers and injectors. As the technology evolves, from the application of normal water injection to various type of Enhanced Oil Recovery (EOR) and Carbon Capture Sequestration (CCS), increasing challenges are anticipated in ensuring the integrity, visibility and efficiency of the well life. This session will focus on the well corrosion assessment methodologies and experiences in corrosion prediction and mitigation during production stage. In increasing the confidence level for corrosion assessment, the advancement of reliable prediction methods and mitigation are important to enhance the life of the asset and the decision making for future cost effective investment.
Corrosion monitoring is a key element assessing the internal corrosion severity, evaluating and optimizing corrosion inhibition (chemicals) programs. The industry has a wide range of technologies and tools that are widely used to achieve representative monitoring. The existing tools, however, have their own strengths and limitations. This session is dedicated to share experiences and enlighten participants with:
- Novel corrosion monitoring technologies.
- Where to monitor? What is the importance of data generated?
- Experiences in monitoring sour production streams. Overcoming current safety challenges and technology limitations.
- Digital data management.
- Automating monitoring to drive productivity and lower production cost.
This is an open session that includes a panel of Subject Matter Experts that will be available to answer questions from the day’s topics.
Tuesday, October 31
Most project managers and corrosion professionals are aware that very few flowlines and transfer pipelines are operating in identical environments. However, we often use a standard checklist and approved coatings system expecting that it will all “be fine”. There is definitely a gap between everybody’s understanding of “being fine”. This ranges from some construction personnel having a cosmetic view and saying it’s all good to competent QA inspectors undertaking all the appropriate tests fully supported by the project manager. There is also a considerable knowledge gap as to how the product really performed over years of service. The paint companies and contractors are inherently unlikely to publicize bad news. This session is about how a new build project (no name) undertakes all the right perceived processes and still has a monumental failure which was only picked up by someone asking the right questions. Time permitting we will also discuss flow assurance coatings, their original design criteria and expectations that many companies have for these coatings. Needless to say, there are some considerable gaps:
- Well tubing
- Flow lines
- Gathering lines
- Innovative coating systems for internal coating of well tubing, flowlines and gathering lines
- Advanced techniques for internal coating inspection
- Lessons learned for application of internal coating for corrosion control of well tubing, flowlines and gathering lines
This section covers the application of various grades of corrosion resistance alloys (CRA’s) used for wells completion and flowlines and gathering lines and the challenges of selection and use of engineering CRAs to ensure long-term asset integrity. Corrosion management by using CRAs is defined during the design stage and thus affects CAPEX. Every CRA has a specific Integrity Operating Window (IOW) within which they perform very well against the hardships of corrosion. However, when CRAs are not properly specified or operated outside IOW they susceptible to degradation mechanisms that are non-age related and the failures can be rapid. Therefore this session is intended to address field experiences, lesson learnt and advances in the application of CRA to meet the objective of long term asset integrity including the following:
- Role of design input/uncertainties/assumptions - boundary conditions for the selection of cost-effective CDAs.
- Material selection/standards - extension of CRAs application limits and requirements. Fit for purpose selection of CRAs.
- Key role of quality and fabrication.
- Current limit/experiences of using 13Cr, Super13CR, 17CR, 22Cr-25CR Duplex, Ni-based alloys.
- Variation/severity of testing methods for CRA Material Qualification (C-Ring, 4 Point Bent Beam, NACE Method A and etc.).
This session covers the use of the various grades of carbon and alloy steel tubing and casing, their characteristics and history in oil and gas production. This will include a review of the various grades in use both seamless and electric resistance welded (ERW) types, their properties, performance in corrosive environments in CO2 and/or H2S and the effect of operating condition such as gas rate, water cut, type of production, etc. Chemical composition, metallurgical condition and manufacturing process play a role in the performance of the tubing and casing. Including:
- Tubing and casing grades evolution and where they have been used
- Effect of corrosion and factors that contribute to increase in corrosion tendency
- Common mitigation measures
- Material selection of tubing and casing and the factors that impact their selection
- Development in casing and tubing materials
- Case histories and past performance of the various grades
Chemical corrosion inhibitors have been used extensively in the oil and gas production industry. At the current oil and gas market downturn, the industry is seeing serious needs in reducing CAPEX investments and improve in measures to allow the use of more cost-effective materials and also extending the facilities’ lives. The use of effective corrosion inhibitors has been identified as one of the areas where OCTG materials could be used and asset's lives could be extended while the integrity is being maintained. The session is intended to:
- Share experiences and lessons learned in the use of special corrosion inhibitors for single and/or multiphase flow tubing/pipelines/gathering lines
- Share recent or current development works on improvement of corrosion inhibition effectiveness for upstream assets
- Share with the participants the existing methods of laboratory tests to screen corrosion inhibitors and experiences on their representativeness
- Discuss flow line top of line corrosion and the laboratory testing method to effectively determine suitable corrosion inhibitors
This section describes the processes and practices relating to prevention of integrity failure (loss on containment, loss of design purpose). Process and practices include activities related to the asset itself (hard activities) such as inspections, monitoring, design practices, etc. and to the organization (soft activities) such as roles, responsibilities, corrosion/integrity awareness, training, etc. Methodologies for development, implementation and evaluation of such processes and practices are presented in this session.