Subsea Equipment Risk Based Inspection
- Which subsea systems to inspect;
- What degradation modes to inspect for;
- How to inspect;
- When to inspect;
- How to report inspection results;
- Directions for actions if defects are found or not found.
RBI planning is a “living process.” It is essential for the analyses to utilize the most recent information about subsea systems in terms of design, construction, inspection, and maintenance of subsea systems in order to optimize future inspections. From the inspection results, new and better knowledge of operational conditions provides a basis for an updating of the structural reliability and further a correction of the time to next inspection.
A subsea equipment RBI can be analyzed in twoways. One way is to use a pipeline RBI by assuming that the subsea equipment, such as a manifold or jumper, is a pipeline. (PaRIS software, developed by OPR, is able to do a subsea equipment RBI.). The other way is to use the mechanical RBI involved in the failure of component parts. In a mechanical RBI, the efforts focus mainly on the component degradation mechanisms of the subsea equipment, after which the equipment failure conditions can be determined based on these components.
Contents
Subsea RBI Inspection Management
Subsea equipment RBI planning, execution, and evaluation should not be a one-time activity, but a continuous process in which information and data from the process and the inspection/maintenance/operation activities are fed back to the planning process.
Risk Acceptance Criteria
Risk acceptance criteria are the limits above which an operator will not tolerate risk on the installation. These criteria must be defined for each type of risk to be assessed. Similar to the traditional pipeline RBI, the subsea equipment RBI quantifies risk from the aspects of Safety, environment, and economy. Most importantly, the safety level depends on product, manned condition, and location class. If the product is toxic or the location is in a sensitive area, then the safety class should be considered to be high.
The risk acceptance criteria are used to derive the time of inspection, which is carried out prior to the acceptance limit being breached. This would allow either the reassessment of the risk level based on better information, a detailed evaluation of any damage, or the timely repair or replacement of the degraded component.
The acceptance criteria are defined for each of the different consequence categories. Acceptance criteria may be based on previous experience, design code requirements, national legislation, or risk analysis. The acceptance criteria for a function may be “broken down” into acceptance criteria for the performance of the individual items comprising the function.
Generally, due to the quick reaction ability of extensive valves and sensors, the main risk is the economic loss of the subsea tree or manifold. For a pipeline and riser, however, safety, environmental, and economic risks should be considered.
Subsea RBI Workflow
RBI workflow, which consists of the following items:
- Data gathering;
- Initial assessment;
- Detailed assessment;
- Inspection reference plan (IRP) and maintenance reference plan (MRP).
Collection of information is a fundamental task at the start of any RBI study. The information that is actually required depends on the level of detailed RBI assessment. For screening, only some basic information is required.With an increased level of assessment, more documentation is required.
Typical data required for an RBI analysismay include, but are not limited to:
- Type of equipment;
- Materials of construction;
- Inspection, repair, and replacement records;
- Process fluid compositions;
- Inventory of fluids;
- Operating conditions;
- Safety systems;
- Detection systems;
- Deterioration mechanisms, rates, and severity;
- Personnel densities;
- Coating, cladding, and insulation data;
- Business interruption costs;
- Equipment replacement costs;
- Environmental remediation costs.
The initial assessment is intended to be an efficient initial qualitative assessment not requiring a detailed description of the system. In many cases this level can be the most appropriate approach for the inspection planning if detailed information or models are not available, or the benefit of a more costly assessment is marginal. The RBI initial assessment is mainly based on sound engineering judgment.
The detailed assessment is performed on a component level, defining the different sections of the subsea equipment and analyzing the reason for each individual degradation mechanism to provide results that can guide the development of an optimized inspection plan. This is different from the initial assessment, which considers the individual subsea equipment as one component. The detailed assessment is carried out for different detail levels with advanced and accurate prediction models. The detailed assessment incorporates both deterministic and probabilistic assessment of the probability of failure.
The MRPencompasses the action plan for “high-risk” items in the RBI detailed assessment. The MRP outlines the method of mitigation inclusive of remedial action to extend the remaining life of the components and to reduce the risk. The IRP is a document that describes how the RBI initial assessment will be implemented. Following the IRP will ensure that the failures occurring in the pipeline systems are managed in a cost-effective manner and kept within the acceptable limits of safety and economic risk.
Subsea Equipment Risk Determination
Subsea Equipment PoF Identification
The offshore reliability data (OREDA) database can be used as the starting point to calculate the failure rate of subsea equipment and the process can be summarized as follows:
- Failure database from OREDA;
- Equipment operation condition evaluation;
- Failure database modification;
- Subsea equipment component probability of failure (PoF) identification;
- Subsea equipment PoF calculation.
The U.K. PARLOC database can also be used to predict pipeline failure rates based on the following two assumptions:
- The development of failure rates is coherent with the historical statistical results in the PARLOC database;
- The PARLOC database from the North Sea is applicable to pipeline maritime space analyses.
It is reasonable to use the PARLOC database as a starting point for pipeline hazard identification, leaking hole size predictions, and PoF calculations. Before calculating the failure rate of the subsea equipment, the operational conditions, including the corrosion rate, erosion rate, flow assurance problem and the properties and characteristics of the equipment, should be evaluated in order to modify the failure data recorded in the OREDA.
The CO2 corrosion rate calculation module in the Norsok code M-506 is used to calculate the corrosion rate:
- Water cut;
- Pressure;
- CO2 concentration;
- pH;
- Temperature;
- Oxygen concentration;
- Inhibitor efficiency;
- Flow regime;
- Biological activity;
- Etc.
The erosion rate can also be determined by the equation below based on the following items and can be monitored continuously:
- Fluid density and viscosity;
- Sand size and concentration;
- Sand shape and hardness;
- Flow rate of fluid and sand;
- Pipe diameter;
- Flow regime;
- Geometry;
- Etc.
Flow assurance analyzes the formation of wax, asphalting, hydrate, scale, etc. The prediction of the choke operation is based on the knowledge of flow assurance. In the analysis, the following items should be considered:
- Wax appearance temperature;
- Pour point temperature;
- Hydrate formation curve.
Subsea Equipment CoF Identification
The failure of subsea equipment is unlikely to cause a large quantity of leakage. Leakage is limited by the quick reaction of extensive valves and sensors, so the main consequence is the economic loss due to the delays caused by needed repairs and the repair costs. But sometimes subsea equipment failure will also cause significant leakage, for instance the 2010 GOM incident is environment disaster due to the failure of BOP system.
The economic consequences of failure (CoF) of the subsea equipment can be analyzed on the base of:
- Product type;
- Flow rate;
- Delay time of production.
Also the repair time of subsea equipment components can be gained from the OREDA database. Relative to overall field production throughput (%) can be used to determine the CoF.
Subsea Equipment Risk Identification
Risk is calculated by the equation risk ¼ PoF CoF. Risk criteria for subsea equipment should be much stricter than that for export pipelines, and the risk can be qualitative or quantitative.
Inspection Plan
The result from the subsea RBI assessment defines a proposed inspection plan for the subsea equipment system. In this phase proposed inspection plans for all items are collected and grouped into suitable inspection intervals. Deliverables from this activity are handbooks giving recommendations for inspection scheduling. These handbooks describe the following for each of the considered pipelines systems:
- When to inspect (inspection time);
- Where to inspect (which items to be inspected);
- How to inspect (inspection methods, or level of inspection accuracy).
Offshore Equipment Reliability Data
The OREDA project was established in 1981 in cooperation with the Norwegian Petroleum Directorate . The initial objective of OREDA was to collect reliability data for safety equipment, and the main objective of OREDA now is to contribute to improved safety and cost effectiveness in the design and operation of oil and gas exploration and production facilities. The scope of OREDA was extended to cover reliability data from a wide range of equipment used in oil and gas exploration and production.
The OREDA database can be divided into four levels:
- Field/installation: This is an identifier for the subsea field and its installation(s). For each field several installations may be included.
- Equipment unit: This refers to an equipment unit on the highest equipment level used in OREDA, which typically includes a unit with one main function, for example, a Christmas tree or control system.
- Subunit: An equipment unit is subdivided in several subunits, each of which performs function(s) that are required by the equipment unit to perform its main function. Typical subunits include umbilicals and the HTP. The subunits may be redundant, for example, there may be two independent HPUs.
- Components: These are subsets of each subunit and will typically consist of the lowest level items that are being required or replaced as a whole (e.g., valve, sensor).
For each topside equipment unit and subsea equipment unit, the following information is presented:
- A drawing illustrating the boundary of the equipment unit, that is, a specification of subunits and components that are part of the equipment unit;
- A listing of all components;
- The observed number of failures for each component;
- The aggregated observed time in service for the equipment unit, classified as calendar time;
- An estimate of the failure rate for each component with associated uncertainty limits;
- A repair time estimate, that is, the elapsed time in number of hours required to repair the failure and restore functioning. This time is the active repair time, that is, the time when actual repair work was done;
- Supportive information, for example, the number of items and installations;
- A cross-tabulation of component versus failure mode, of subunit versus failure mode, of equipment unit versus failure mode, and of failure descriptor versus failure mode.
References
[1] M. Humphreys, Subsea Reliability Study into Subsea Isolation System, HSE, London, United Kingdom, 1997.
[2] Det NorskeVeritas, OREDA Offshore Reliability Data Handbook, fourth ed., Det Norske Veritas Industri Norge as DNV Technica, Norway, 2002.
[3] Mott MacDonald Ltd, PARLOC 2001, The Update of the Loss of Containment Data for Offshore Pipelines, fifth ed., HSE, London, United Kingdom, 2003.
[4] Norwegian Technology Standards Institution, CO2 Corrosion Rate Calculation Model, NORSOK Standard No. M-506, (2005).
[5] M.H. Stein, A.A. Chitale, G. Asher, H. Vaziri, Y. Sun, J.R. Collbert, Integrated Sand and Erosion Alarming on NaKika, Deepwater Gulf of Mexico, SPE 95516, 2005, SPE Annual Technical Conference and Exhibition, Dallas, Texas, 2005.
[6] O.H. Bjornoy, C. Jahre-Nilsen, O. Eriksen, K. Mork, RBI Planning for Pipelines Description of Approach, OMAE2001/PIPE-4008, OMAE 2001, Rio de Janeiro, Brazil, 2001.
[7] American Society of Mechanical Engineers, Manual for Determining the Remaining Strength of Corroded Pipelines, ASME B31G-1991, New York, 1991.
[8] Det Norske Veritas, Corroded Pipelines, DNV-RP-F101, 2004.
