The field-tested CT Scan is an innovative alternative technique being successfully used by operators to non-intrusively check their pipelines located in ultra-deepwater subsea. Pipe-in-pipe (PIP), piggable, coated pipelines, and non-piggable pipelines, are some examples of the many kinds of pipelines that may be precisely measured by the inspection application for both durability and flow security concerns.
The field-tested CT Scan technology delivers high-resolution wall integrity data as well as the quantitative identification of asphaltene, hydrates, scale, wax, and other accumulations for flow assurance reasons while the pipeline is still in use.
The assessment is done from the surroundings of the pipeline using equipment that is ROV-deployed. This is the sole non-invasive method that can check coatings on coated pipes that are not piggable or are difficult to pig without removing and replacing the coating. By shortening the duration of an inspection campaign, saves operators money. It also lessens the chance that a line may be damaged during coating removal or replacement.
Additionally, the technology enables the examination of PIP systems with precision and near-millimeter-level anomaly identification on both interior and exterior walls. It offers 360-degree, elevated-resolution images in real-time, enabling quick evaluation of the pipeline’s health. This has not been feasible up to this point without eliminating the covering layer.
The objective here is to discuss a novel technology that is intended to assist the industry in addressing difficult issues with subsea pipeline durability and flow control and to provide some instances of recent field project outcomes.
Figure 1 Pipeline Under the sea
In order to check subsea pipes from the outside without removing the protective covering, the evaluation system employs computed tomography (CT) technology. The device was developed to assist professionals in subsea pipeline flow security and stability in obtaining high-resolution photographs of the pipeline materials and pipe thickness, allowing for the exact visualization of flow assurance conditions and weaknesses in pipeline integrity. The accompanying technology makes it possible to assess the efficacy of corrective measures.
The technology, which can scan subsea pipes at a depth of 10,000 feet (3,048 meters), is controlled by an ROV. It may be installed online on both piggable and non-piggable pipelines without affecting production or requiring pipeline changes.
The device has been tested in the field and was just used to scan a pipeline system that cannot be pigged in the Gulf of Mexico. With regard to pipeline durability and flow guarantee at specified points, it was utilized to assess the state of the pipes at each scan location. The pipelines were made up of pipe-in-pipe flowlines with varying diameters and coated single-wall jumpers. The Discovery system was placed in the ocean at more than 200 places, at depths from 2,900 to 4,400 feet (884 and 1,341 meters), as part of the study.
2 Advantages of CT
The only non-invasive method that can check coated subsea pipes without removing coatings or marine growth is computed tomography (CT). Specialists in flow assurance can accurately characterize pipeline deposits using CT imaging and determine what they are, such as hydrate, wax, asphaltene, and scale. Additionally, it gives integrity engineers a way to deploy a technique from outside to precisely measure flaws and the thickness of any pipeline’s remaining walls.
2.1 For subsea pipes, CT technology has the following advantages:
Operators can accurately determine the asset’s surviving life or effectively plan remediation campaigns to remove restrictions the first time with the assistance of high-quality tomographic photographs of the pipeline materials and wall width at 1 mm resolution.
Normal operations can proceed unaffected, which prevents production targets from being further postponed and ensures that the inspection campaign has no effect on ongoing revenues.
Figure 2 Pipeline CT Scanner
Because the coating doesn’t need to be eliminated, operators can reduce vessel time and the danger of harming the asset when removing the coating.
It is Suitable for multi-phase, gas, or liquid flow.
It is able to inspect the entire pipe structure for the first time; suitable for flexible and rigid lines, such as pipe bundles and pipe-in-pipe.
The ability to evaluate pipeline environments instantly through real-time communications enables prompt rehabilitative action options to be made, minimizing lost production and restoring the asset to complete production as rapidly as feasible.
It ensures verification of the efficacy of corrective measures to guarantee the efficacy of the activities conducted.
It ensures verification of the efficacy of corrective measures to guarantee the efficacy of the activities conducted.
3 Simulations of Pipelines
Before being put into use, the technology is evaluated with a variety of materials to simulate the densities of the anticipated flowline contents and with a range of combinations to ensure that the system is able of evaluating the wall width for pipeline stability and materials for flow certainty.
Although surface processes like corrosion and oxidizing are difficult to perceive, failing to comprehend them may have serious repercussions, including economic damage and even fatalities. The accuracy of in situ ultrasonic monitoring of thickness of wall may reach the order of tens of nm in a very highly controlled laboratory setting. However, when the temperature variety and transient heat flow increase, its accuracy quickly deteriorates. The goal of the study is to enhance the accuracy and durability of the ultrasonic wall thickness monitoring system by first examining advanced temperature compensation mechanisms.
Additionally, according to recent research, certain oxidation and rust products have the ability to control corrosion and may one day be utilized in place of synthetic corrosion inhibitors. If the width of the coating layer can be monitored in situ, our understanding of their creative processes and their ability to suppress corrosion would be substantially improved. Ultrasonic waves may be used to monitor the deposition of materials because they are responsive to changes in the acoustic characteristics of materials. The next phase of this development in this field will investigate the usage of ultrasonic transducers to observe intricate surface chemical interactions when concurrent layer formation and wall-thinning corrosion happen.
Figure 3 Pipeline Simulation
3.1 The following may also be included in flow assurance evaluations:
Tests to find tiny gas channel holes in obstructed pipes in order to evaluate the likelihood of gas transmission between various sections.
Tests to measure gas interactions (maximum and minimum pressure) between pipeline segments by detecting changes in gas pressure in closed pipeline channels.
The technology is designed to scan a sample pipeline with six holes to replicate channels of gas in a pipeline clogged with asphaltene or any relevant material in order to find minor openings of the channel of gas in blocked pipes. The sizes of the holes for the Mexican Gulf deployment varied from 0.25 to 2.2 inches. Maps of the density were created after two and ten rotations. All of the channels of gas were readily visible after ten rotations.
4 Integrity Management
The equipment’s or asset’s capacity to carry out its intended task securely and dependably under challenging circumstances is crucial for subsea applications. For each platform, operation, and component of the equipment, integrity management programs start with carefully considered tactics, risk assessments, and assumption alignment. Before implementing a program, several elements must be taken into account, including duration of service, dangers related to the environment, and, if appropriate, prior IMR efforts. Based on these considerations, a risk assessment needs to be made. The intervals, kinds, and contingency planning of inspections are determined by the findings of an assessment. In addition, care should be given to scheduling, logistics, lead times for replacing equipment, and assumption baselining.
An integrity management program is made up of several different components.
4.1 COLLECTION OF DATA
For an engineering evaluation of overall integrity, design and operational data should be gathered. The original design files, papers, plans, requirements, and survey records produced throughout manufacture, installation, and operation must be kept. The operator must make sure that all presumptions are reasonable and that all data collected is accurate and reflective of the situation as it was at the time of the evaluation. Reassessment or an alternative baseline evaluation and survey are to be done if the details cannot be given.
The following reports and design elements, among others, should be examined:
Reports on the initial design, building, and installation
Maintenance and alteration reports, in which any modifications to the design baseline caused by component replacements, substitutions, or modification are documented; surveillance and inspection reports collected during operation; and
It is probable that the subsea equipment’s status will have to be deduced from data that can be checked by different methods because to the restricted access to it. Because corrosion of subsea apparatus cannot be easily measured, more care may be needed. For instance, failures of subsea sensors, chemical injection failures, or predicted vs. actual output discrepancies may arise if problems with surface equipment occur. Any of these secondary components that have problems might point up problem areas and prompt IMR action.
Figure 4 Data From CT Scanner
Figure 4 Data From CT Scanner
4.2 BASELINE RESEARCH
To comprehend the initial state of any system, the baseline status evaluation and study should be conducted. The evaluation of the baseline condition should be conducted using the following procedure:
Assess the thoroughness and scope of the initial design analyses and decide if further analyses are necessary.
List the different dangers and related processes of deterioration
Describe the mitigation scheme and make a strategy for upcoming surveillance and assessment tasks. Regular updates should be made to the baseline condition assessment after inspections, occurrences, or changes in condition.
The extra precise inspections that need to be carried out to help in providing correct data are identified by the baseline assessment. The following actions will be part of the baseline survey:
Review of prior repair and examination reports; creation of an inspection system; thorough inspection to ensure that the condition evaluation is correct.
4.3 RISK ANALYSIS
Risk analysis should be used by operators to design their initiatives. The core of the whole subsea IMR strategy is a risk assessment.
The process of identifying whether undesired outcomes are possible, their chance of occurring, and the intensity of their impacts is referred to as risk assessment. It offers the foundation for risk assessment, risk management, and risk reduction. Risk levels are determined systematically via the risk assessment process.
Risk analyses for subsea elements will include every potential form of failure. To produce a risk assessment, a number of techniques may be used. Commonly, all techniques assess the likelihood and impact of various failure scenarios. Different failure types may be classified according on whether the damage is age-related or not. External pressures like collision and inadvertent damage often lead to age-related failures, whereas corrosion and erosion frequently cause age-unrelated failures. The examination of design, production, installation, and operation is the basis for probabilities. Implications are based on reputation, cost, safety, and the environment. The sum of these yields a risk score for each piece of machinery and system.
There are several failure types that may affect subsea machinery and systems.
Internal corrosion, exterior wear and tear, and unintentional damage are the most frequent problems that impact static equipment, such as trunks, drilling rigs, valves, pipes, and jumpers. Extreme natural occurrences, fallen items, and pulled lines brought on by fishing apparatus, mooring machinery, and anchors may also have an effect on them.
As a consequence, equipment that contains hydrocarbons may distort, collapse, or break. Equipment that experiences cyclic thermal stress, slugging, rotational components, dynamic loading (related with vessel movement both long-term and event-specific), and dynamic loading are also susceptible to failure.
Figure 5 Analyzing Risks
4.4 CATEGORIZATION OF RISK/RISK CRITERIA
The classification of risk is an alternate approach. In this situation, the analyst should specify the probability and consequence groups to be used in assessing each scenario, and specify the degree of risk connected with each likelihood category combination. Both qualitative and quantitative methods may be used to generate frequency and consequence categories. In order to categorize an event consistently, qualitative classifications, usually include qualitative criteria and instances of each category. To handle safety, ecological, functionality, and other sorts of repercussions, several consequence categorization criteria may be needed.
A risk matrix may be used as a system for allocating risk utilizing a risk categorization technique after effects and likelihoods have been assigned. The industry norm is to divide qualitative risk into a minimum of three tiers. ach matrix cell may be given a risk category that corresponds to a particular set of probabilities and consequences. A company must decide which categories it will use to rank risks and, more crucially, how it will prioritize and handle the different risk levels connected to the matrix’s cells.
The use of subsea CT scanning to evaluate pipeline corrosion is spreading around the world. Planning for and keeping up with the lifetime of buildings, machinery, and systems is crucial. In addition to the increasing activity, many existing assets are nearing the end of their useful lives. Integrity management services like damage assessments and life extension assessments might be helpful for these assets.
Both new and old subsea assets are very interested in underwater CT scanning. The greater use of Subsea CT scanning in project planning and the rising knowledge of the factors affecting the residual life of current facilities and services are both results of the expanded awareness of subsea CT scanning. Subsea CT scanning may evaluate related risks for new projects, specify inspection and service periods and restoration estimates, and reduce the likelihood of failures and downtime. Workers, producers, and regulators gain from subsea CT scanning because it boosts confidence that the machinery will work as intended and be installed and operated safely. A subsea CT scanning may help with existing assets by evaluating the state and creating a baseline to go ahead for checks, upkeep, and replacement via fitness for service evaluations. Through a life extension evaluation, a subsea CT scan may also help extend the original design life.
Where a pricey replacement was previously necessary, they have proven very helpful to operators.
For a number of reasons, keeping the integrity of subsea pipelines is crucial for all oil and gas producers. This includes, but is not restricted to, protecting the environment, adhering to regulatory requirements, maximizing output via operating efficiency, and prolonging asset life.
Subsea inspection is still crucially important despite the current economic crisis in the oil and gas sector. Regular inspection campaigns are driven by regulatory requirements and the ensuing need to demonstrate the condition of a pipeline or facility.
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