Material Integrity Assessment of Onshore Assets
Onshore oil and gas assets are vast and usually cover a large area. These can refer to all upstream facilities i.e. facilities used for production and stabilisation of crude, or downstream facilities i.e., refining facilities. Upstream facilities can be divided into off-plot facilities e.g., wellheads, wellhead piping, flowlines, remote manifolds, trunklines/pipelines,
and on-plot facilities e.g., stabilisation systems, separation/dehydrations systems, flare systems, produced water systems, utilities systems,
storage facilities etc.
Typically, these assets are designed for a minimum of 25 years but in the real sense they are used for a longer period i.e., until total reservoir depletion or a halt in production due to global oil and gas economics. Thus, these assets need to be maintained consistently and occasionally optimised to aid production.
A Materials Integrity Assessment (MIA) is a multi-disciplinary review of materials and integrity of an operational asset with a view to mitigate failure or optimise production. This short article outlines the process for undertaking a MIA of an upstream facility.
A MIA can either be proactive or reactive in nature. These objectives are broadly categorised into the following:
- To assess suitability of materials when a proposed brown field modification will introduce new production fluids/operating parameters to an existing facility.
- To assess the material/integrity threats due to a change in the current operating conditions that can lead to a failure or loss of containment e.g., unexpected reservoir souring, sand production, oxygen ingress, build-up of microbial activity etc.
- To proactively ensure the assets are operating within defined limits.
- To proactively apply learnings from other facilities and global best practice.
The scope of an assessment can be the whole upstream facilities. or sections of the facility. This needs to be determined by the Client with the above objectives in mind. The scope will determine the duration of the project (from weeks to months) and the number of disciplines involved e.g., where only an on-plot scope is envisaged, there will be no requirement for a pipeline integrity engineer etc.
MIA Methodology
The methodology, and steps of the assessment are shown in figure1 below:
The scope/objective is defined by the Client in conjunction with the MIA Lead. The corresponding disciplines are defined, and personnel nominated. It is advisable to have a core team and an ad-hoc team on an on-call basis, a typical team comprises the disciplines shown below:
The ICP (Independent Competent Person) should be an experienced professional with no interest in the asset/facility who will be responsible to vet the assessment and to provide guidance where required. Individual and group roles and responsibilities are then defined with the expected time frame by the MIA Lead. It is critical to note the assumptions and exclusions at this stage of the project. Where there are known integrity concerns, these needs to be highlighted on a draft heat map displayed on a base PFS/PEFS drawings. The heat map tends to zero in on the areas that need special attention especially when undertaking a review of a very big asset. It also easily shows areas with similar integrity issues or failure patterns that will help with the assessment.
Data gathering and review is the most critical phase of a MIA. The data to be reviewed includes. but not limited to, the Facility Design Basis, Plant Operating Manual, Material Selection Reports, Corrosion Management Manuals, Inspection/Monitoring Data, CP Monitoring Data, Failure/Leak registers, Maintenance Plans/Reports, Trending Reservoir Data etc. Some well-organised and maintained facilities/assets will have this information readily available while others may have insufficient information.
Where the available data is insufficient, then several assumptions will need to be made. As an example, in a particular project where there was no baseline inspection data or any subsequent data after seven years of operation, the integrity assessment was then based on a greenfield (new) corrosion modelling. After going through the material selection process, this was then compared with what was physically on the ground and an evaluation made as to whether the right material selection had been made, and the expected remaining design life based on the existing process parameters. This comparison formed the basis of the subsequent recommendations.
A site/field visit is essential as it gives the team the opportunity to visually inspect piping, flowlines and equipment. It also serves as a verification process of the data provided or any of the identified integrity issues.
The visit should also include interviews with key operation and inspection personnel who will be able to give their observations of any changes in the field and more clarity on the plant operations. Pre-prepared questionnaires are recommended for these interviews.
Interdisciplinary Peer Review Workshop
After the site/field visit, the team write up their findings based on the areas of responsibility allotted to each person. The whole write up is then discussed as a team to fine tune and align the findings. On completion of the interdisciplinary review, it is sent to the ICP who will then have a peer review with the whole team. This serves as a form of technical challenge
of the whole exercise and the conclusions/ recommendations.
The report presentation should include a high-level summary using the traffic light system showing the overall status of the asset with the corresponding updated heat map. This high-level summary is based on a more detailed report of the individual areas. This report needs to include a full explanation i.e., scope/objective, overview/history of the asset, findings, where possible photographic evidence and recommendations. This should also be presented visually in a table. An example is shown (top of page 21) based on the earlier heat map.
Recommendations/Conclusions
The recommendations should list out action points to be carried out by the Client in order to verify the integrity of the onshore asset. These recommendations generally fall into the two categories outlined below:
Short term (less than 6 months) – These require urgent remedial actions/mitigation to avoid loss of containment of hydrocarbon inventory.
Long term (more than 6 months) – These require non urgent remedial actions to be undertaken over a course of time. Advisably between 6 months to 3 years depending on operational constraints.
The completion of the MIA is the presentation of the report (including a power point) to the Client. Any grey areas need to be clarified to the Client so the recommendations can be addressed within the given time frame.
A Corrosion Management Program (CMP) manual will include the process design and operating conditions, basis of materials selection, corrosion mitigation, inspection strategy as well as corrosion monitoring methodology. The manual needs also to include the risk assessment of critical assets to determine risk severity, monitoring techniques to ensure that the assets can be operated in a safe and reliable manner and the appropriate inspection methods to manage identified risks to maintain the integrity of the critical upstream surface facilities assets. It should also highlight the critical integrity operating window (IOW) parameters and IOW limits to be maintained during service. An IOW programme, its importance, and how to establish
IOW to enhance asset integrity is discussed in detail in reference 2.
The CMP manual needs to be revised at regular intervals to highlight recent inspection results, risk assessment data as well as changes in process conditions and additional monitoring requirements.
Corrosion monitoring as documented in a CMP manual can be conducted using a number of direct and indirect monitoring techniques, and the merits and limitations of each monitoring technique need to be considered. For effective corrosion monitoring multiple monitoring strategies need to be used and the collected data needs to be analysed along with appropriate process data. Details of various corrosion monitoring techniques for field applications can be found in the recently revised NACE publication (3). Installing coupons and corrosion monitoring probes can be useful tools for internal corrosion monitoring. These are considered intrusive monitoring types as they are exposed to pipeline interiors through appropriate access fittings. Proper safety precautions, following the work permit procedures, along with the deployment of suitably trained personnel are necessary for safe removal and installation of coupons from the pipelines during service. The NACE document “Preparation, Installation, Analysis and Interpretation of coupon data in oil field operations” serves as a useful guideline (4). Corrosion coupons are usually removed at 60-90 day intervals in order to establish long term corrosion rate trends, while the probes are useful to monitor the corrosion rates in real time. Suitable display of the probe’s output in the facility control room will enable the continuous monitoring of corrosion rates, and to alert the operating personnel in the event of higher corrosion rates in order for the required corrective action to be taken. Both wired and wireless configurations are available. The economics need to be taken into account before selecting suitable corrosion monitoring solutions. For pipelines requiring corrosion inhibitor injection, it is essential to have the probes/coupons installed upstream and downstream of the corrosion inhibitor injection point to monitor the performance of corrosion inhibitors. For reliable field corrosion data, it is essential to install the coupons at locations where corrosion is occurring, or most likely to occur, such as high velocity zones, water accumulation spots, etc. Careful location selection is vital since installing the monitoring devices at incorrect locations could obscure the data obtained and its analysis. Linear polarisation probes and electrical resistance probes are used for routine field corrosion intrusive monitoring of the process piping. Linear polarisation probes are commonly used in water systems, while electrical resistance probes can be used in higher resistivity environments. Formation of scales such as sulphide scale, sand erosion, oily/wax deposits at the sensor elements, can affect the accuracy of collected data. As a result, the collected data needs to be analysed carefully to establish a reliable base line reference for meaningful intrusive internal corrosion monitoring data.
In case of nonintrusive monitoring, probes such as thickness measuring sensors using ultrasonic principles can be installed at plant piping exteriors where continuous piping wall thickness monitoring due to corrosion/erosion is warranted, and a number of such systems are commercially available. These sensors can be installed at multiple locations and the wall thickness data, sensor battery life, and the temperature data, can be communicated in real time to the operating facility control room. The main advantage of nonintrusive monitoring is that the monitoring can be conducted when the plant is in service. In addition, critical piping at higher operating temperatures, and at elevated and inaccessible locations can be monitored. This approach offers cost-savings by eliminating the scaffolding requirements especially for elevated plant piping sections as well as avoiding the costs associated with the operating facility downtime to conduct the conventional thickness monitoring which would otherwise be required. By analysing the collected data, proactive corrective measures to mitigate piping corrosion along with scheduling the piping replacement in advance with the maintenance and operations team can be carried out. This approach enables the monitoring of the critical piping wall thickness condition to prevent the loss of containment due to internal corrosion thus facilitating the operation of the plant assets with highest safety and integrity, as well as to minimise HSE related events. As well as ultrasonic sensors, other methods such as eddy current testing, electromagnetic field mapping and battery free ultrasonic sensors are also considered nonintrusive monitoring types.
To manage critical upstream assets, microbiologically induced corrosion (MIC) also needs to be monitored and managed whenever applicable. Periodic process water sampling to monitor the planktonic bacterial counts, dissolved oxygen content, biocide residuals can be carried out. In oil and gas systems bio-film monitoring probes, samples from removed pipe sections, debris collected during pipelines scraping to monitor the sessile bacteria present in the system along with water quality parameters, provide good information (5). A number of test kits are commercially available to quickly monitor the biocide residual in the field and to initiate the required corrective actions. It is equally important to document the results and the implemented corrective actions to establish sound historical records.
To mitigate external corrosion threats, parameters such as periodic cathodic protection (CP) potential, current flowing in the structure, CP rectifier potential/current output levels, anode bed condition of underground assets, need to be monitored and managed within acceptable limits. Most of the underground carbon steel piping systems are usually protected by suitable protective coating systems supplemented by properly designed cathodic protection systems. Periodic visual monitoring needs to be carried out at excavated sections of pipelines to inspect the coating condition and to mitigate any external corrosion threats, and the monitored data along with inspection results should be documented.
When selecting the optimum corrosion monitoring solution from the wide range of available options for external and internal corrosion monitoring, the engineering and operational requirements and monitoring objectives, need to be considered, and thus by implementing a robust corrosion monitoring system combined with an effective data analysis, inspection and maintenance strategy, timely remedial measures, the critical upstream oil/gas assets’ integrity can
be managed in an efficient and sustainable manner.
Dr. H.S. Srinivasan, Saudi Aramco
References:
(1) API RP 571-2020 Damage Mechanisms Affecting the Fixed Equipment in the Refining Industry.
(2) API RP 584-2014 Integrity Operating Windows.
(3) NACE TR3T199-2020 Techniques for Monitoring and Measuring Corrosion and Related Parameters in Field Applications,
Houston, TX.
(4) NACE SP0775-2018 Preparation, Installation, Analysis and Interpretation of Corrosion Coupons in Oil field Operations, Houston TX.
(5) TM0194-2014-SG, Field Monitoring of Bacterial Growth in Oil and Gas Systems.
