Pipeline subsea

Oil and gas exploration and production in the Gulf of Mexico (3,200 platforms, 75 MODUs, 33,000 miles of pipeline, subsea production systems, wide range of support equipment), offshore California (23 production platforms,... 

Marine Structures (0951-8339). This journal aims to provide a medium for presentation and discussion of the latest developments in research, design, fabrication, and in-service experience relating to marine structures, i.e., all structures of steel, concrete, light alloy or composite construction having an interface with the sea, including ships, fixed and mobile offshore platforms, snhmarine and submersibles, pipelines, subsea systans for shallow and deep ocean operations, and coastal structures such as piers. 

Subsea production systems are an alternative development option for an offshore field. They are often a very cost effective means of exploiting small fields which are situated close to existing infrastructure, such as production platforms and pipelines. They may also be used in combination with floating production systems. 

The most basic subsea satellite is a single Subsea Wellhead with Subsea Tree, connected to a production facility by a series of pipelines and umbilicals. A control module, usually situated on the subsea tree, allows the production platform to remotely operate the subsea facility (i.e. valves, chokes). 

All pipelines will be circulated clean and those that are buried, or on the seabed, left filled with water or cement. Surface piping will normally be cut up and removed. Flexible subsea pipelines may be reeled-in onto a lay barge and disposed of onshore. 

It should be noted that there are still many deficiencies in the science and technology of corrosion monitoring, mainly in the areas of localised corrosion (pitting) and the inability to monitor at inaccessible sites such as downhole (oil and gas wells) and subsea installations (satellite wells and pipelines). 

Pipelines Pipelines carrying wet gas and crude oil present a corrosion hazard and are protected accordingly by coatings and/or inhibitors. Limitations of corrosion monitoring arise from sampling, in relation to the sampling and interval, and access problems for subsea pipelines (major trunk lines). 

Subsea pipeline emergency isolation valves for offshore facilities are provided where a risk analysis indicated topside isolation may be considered vulnerable. They should be protected from ship impacts, anchor dragging, flammable liquid spills and heavy objects that may be dropped from the offshore facility. 

Isolation - It has been shown that the addition of isolation valves at periodic intervals is not as cost effective as prevention measures such as thickness inspections or tests. However all pipelines should be provided with a means for emergency isolation at it entry or exit from a facility. Offshore facilities may be particularly vulnerable to pipeline incidents as the Piper Alpha disaster has shown. In that accident a contributing factor to the destruction was the backfeed of the contents of the gas pipeline to platform once the topside isolation valve or piping lost its integrity. Further isolation means (i.e., a subsea isolation valve SSIV) were not available. 

FRED—Shell Research has developed FRED (Fire Release Explosion Dispersion) as a PC based model for accidental release of gas or liquid. Areas of application include fire, dispersion, and explosion. Shell also has produced SEAFIRE, a consequence model for fires from subsea pipelines. 

Kobayashi and coworkers (Sloan et al., 1976 Song and Kobayashi, 1982, 1984) and workers in the CSM laboratory (Sloan et al., 1986, 1987) have measured concentrations of water in hydrate-forming fluid phases in equilibrium with hydrates (when there is no free-water phase present) for application in single phase pipelines in cold regions, such as the North Slope or subsea. The trend in deepwater pipelines appears to be toward multiphase transmission (Shoup and Shoham, 1990) and their inhibition. 

The concepts are similar for both onshore and subsea pipelines. In the above conceptual picture, it is assumed that the pipeline wall temperature is constant at 39°F. If a line is insulated, hydrate dissociation becomes much more difficult because the insulation that prevented heat loss from the pipe in normal operation will prevent heat influx to the pipe for hydrate dissociation. Alternatively, if the pipe is buried, the pipe wall temperature will be greater than 39°F and the system may be insulated by the ground. 

State estimation has been proposed as a way to improve our ability to predict hydrate formation in subsea pipelines. PF and MHE, state-of-the-art state estimation methods, have been reviewed and tested with a simple example case study with satisfactory results. Strategies based on both MHE and PF are being tested at present. The ultimate aim is to develop an efficient observer by relying on the robustness and the optimisation-based approach of MHE to provide initial guesses on the one hand, and the speed of PF on the other hand to solve the state and parameter estimation problem. 

Accident rate For most modes of transport the accident rate is reported in accidents per mile of transit (i.e., truck, rail, marine, air). For a pipeline, the accident rate is dependent on the size, material of construction, and the location of the pipeline (above or below ground, subsea), as well as other factors such as maintenance and external impacts (e.g., digging). 

It is usefiil to consider the case of an installation of a subsea gathering system for a natural gas production field. The pipeline design for a new gas production facility consisted of 20 cm diameter subsea gathering lines (flow lines) emptying into a 19 km, 50 cm diameter subsea transmission gas pipeline. The pipeline was to bring wet gas from an offshore producing area to a dehydration facility on shore. The internal corrosion was estimated to be 300-400 mpy. The corrosion mitigation options considered were (i) carbon steel treated with a corrosion inhibitor (ii) internally coated carbon steel with a supplemental corrosion inhibitor (iii) 22% Cr duplex stainless steel (iv) 625 corrosion-resistant alloy (CRA). The chance for success was estimated from known field histories of each technique, as well as the analysis of the corrosivity of the system and the level of sophistication required for successful implementation (Table 4.42). 

Subsea Oil and Gas Pipeline Integrity Management under Aging Considerations.6... 

SUBSEA OIL AND GAS PIPELINE INTEGRITY MANAGEMENT UNDER AGING CONSIDERATIONS... 

A description is presented in Figure 1.3, where the limits of the pipeline can be seen in relation to the pipeline riser and subsea isolation valve (SSIV) an assumption may be made that this condition is replicated at each pipeline end. 

All of the above risks can be multiplied as the subsea pipeline networks increase in size, complexity, and number of stakeholders involved. 

It is quite possible that any analysis required to be carried out on an aging pipeline, in order to demonstrate fitness for purpose, will suffer from a lack of data. This point is supported by the work of Stacy et al. (2008). Clear parallels can be drawn between the assessments undertaken for both offshore structures and subsea pipelines, and the paper does conclude, Data on the original design criteria, material properties, fabrication quality and installation performance are also required but may not be necessarily available. In this context, the overall assessment model will need to be able to account for this lack of knowledge. 

Regulation 11 in the Pipelines Safety Regulations (1996) requires that the operator shall ensure that no fluid is conveyed in a pipeline unless the safe operating limits of the pipeline have been established. In order to meet this requirement, inspections will be carried out and analyses undertaken in order to determine the maximum allowable operating pressure (MAOP) for the subsea pipeline. Typically, the process for such an assessment will be undertaken in a manner as described by Hopkins et al. (2001) and shown in a flowchart in Figure 1.4. This process shows the progressive... 

It is also possible to carry out a probabilistic analysis for subsea pipelines in relation to the requirements of fitness for service or life extension. This approach is supported by Hopkins et al. (2001) where the uncertainty values in relation to the inspection data, material strength, and so forth are accounted for The statistics of the input parameters and the engineering models then determine, by probabilistic analysis, the failure probability for each failure mode or mechanism and the variation of the failure probability over time. Once the uncertainty of each input value has been described statistically, a Monte Carlo simulation can be used to predict the growth rate of known defects over time. 

It would appear that the question of uncertainty is a reoccurring theme in this instance. The subsea pipeline assets will display a high degree of uncertainty in relation to their current condition, approach to be adopted to allow for accurate inspection, which in itself will be subject to a level of uncertainty in terms of accuracy and reliability of measurements, as well as the levels of uncertainty inherent to the scheduling process. A question presents itself as to what is the best way to address these areas of uncertainty. One way to approach it is nicely put by De Neveville (2003) Understand that uncertainty is not always a risk to be avoided but also presents valuable opportunities that can be exploited. The case in point can be seen from the potential cost saving to be made in terms of being able to effectively extend the operational life of a subsea pipeline asset. 

Moreover, in 1989, Elf Congo experienced corrosion of the first 5 km of a 23-km main subsea pipeline that transported sour oil. The corroded part was replaced but corroded again the next year. 

The de Waard-Milliams model is a well-known modeH - used in industry (such as subsea pipeline corrosion) to predict corrosion, and it is the cornerstone of commercially available corrosion prediction software packages such as Cassandra. Despite its applicability in industry, a significant disadvantage of this model is that it does not consider MIC. In 2002, a NACE paper was published in which the described models were related to various mechanisms from sweet corrosion, sour corrosion, and organic acid corrosion to oxygen corrosion and MIC. Obviously, it is the model describing MIC that concerns us here. 

Corrosion in oil and gas service can be classified into two categories internal corrosion and external corrosion. Internal corrosion is primarily due to the corrosive components present in the fluids handled by the particular oil and gas asset. External corrosion, on the other hand, occurs when the asset interacts with its surrounding environment. For example, in a subsea pipeline, internal corrosion is attributed to the corrosive fluids transported by the pipeline, whereas external corrosion occurs when the pipeline is attacked by the surrounding seawater. The nature and extent of damage caused by internal and external factors are highly dependent upon the chemical and physical attributes of the operating conditions. Chemical attributes are described by the various contaminants in the... 

---