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Preventing Internal Corrosion in Oil and Gas Field Pipelines

The integrity of a pipeline directly affects crude oil and natural gas production.

Oil and gas field pipelines typically fall into two categories: one is used for transportation of untreated well head fluid, and the other is used for transportation of treated fluid. Pipelines are used for transportation of single-phase or multiphase fluids. In oil and gas exploration and production operations, these pipelines are used to connect crude oil and natural gas wells to process facilities, transport processed fluids from offshore platforms to shore, and then on to processing, transport of treated water for injection applications, or for custody transfer. Failure of pipelines can hamper the operations of an entire oil and gas asset because nothing can be transported. Even if offshore and onshore facilities are well-operated and managed, failure of pipelines may bring all operations to a stop because of connectivity failure.

Design and Construction Constraints

These pipelines are designed based on initial operational requirements. The material of construction is selected per those requirements. Often, the designed pipeline cannot withstand conditions other than those of its originally designed purpose. For example, if a pipeline is designed for treated natural gas, it may have corrosion problems if switched to carry untreated natural gas. Laying subsea pipelines takes considerably more time and money than laying comparable onshore pipelines because of underwater work and seasonal sea conditions. Accordingly, the operator engaged in exploration and production of oil and natural gas lays subsea pipelines as per the requirement only, and there may not be any standby pipeline in case of failure. This too is the case of onshore pipelines and process equipment. So clearly, the integrity of a pipeline directly affects crude oil and natural gas production. Figure 1 shows the pertinent categories of pipeline services and related actions.

FIGURE 1 Categories of pipeline services, corrosion monitoring, and action for corrosion prevention.

Operational Precautions

Before putting crude oil, condensate, or natural gas into a pipeline, the operations team should ensure that the material being carried meets the pipeline design parameters. If there are any temporary operational disturbances; for example, one that can cause the natural gas to have excessive moisture, the moist gas should be diverted, say to a flare, rather than putting the wet gas into the pipeline. The operations team should monitor the operational parameters continuously. If parameters are varying from design ranges, the team must initiate action. In the case of a treated crude oil and condensate-carrying pipeline, free water and emulsified water should be removed completely before the product is put into the pipeline.

Internal Corrosion Monitoring

Pipelines should be pigged as per their schedule for inspection, cleaning, and to remove settled fluids from the pipeline. Internal corrosion monitoring data from probes and coupons should be collected and data should be analyzed. Fluid entering and leaving the pipeline should be checked to ensure that it meets design parameters. If these parameters are nearing the limits, then the corrosion monitoring team should be vigilant and ensure that the operations team takes immediate action to correct the problem. Dissolved gases, including oxygen, carbon dioxide (CO2), hydrogen sulfide (H2S), and iron counts of the fluids at starting and end points should be checked in a periodic manner. Measuring the corrosion inhibitor residual at the end of a pipeline will give an idea about the availability of chemicals throughout the line. This can indicate whether the corrosion inhibitor is working at current levels or if it is necessary to increase the dosage rate for better corrosion inhibition. In the case of a pipeline transporting dehydrated natural gas, the water dew point should be checked, and this water dew point temperature should be lower than the pipeline temperature. Otherwise, water condensation may take place in subsea/subsurface/regional temperature and pressure conditions. This condensation can cause top-of-line corrosion in the pipeline’s 12:00 position.

Corrosion monitoring should be implemented for getting real-time, continuous, and periodic data.

Online Monitoring

Testing the corrosivity of water with online equipment and following techniques like linear polarization resistance or electrochemical impedance spectroscopy arh3 required. Normally more than one technique will be helpful to obtain realistic data. This will give real-time data and gives an indication about the corrosion at that moment.

Continuous Monitoring

Collection of data over a period of time is essential to know the corrosion protection level of a pipeline for that designated interval. This gives an overview about the failures of corrosion prevention programs over a particular period. For example, one day a chemical pump does not inject a corrosion inhibitor. This treatment interruption can be identified and the effect(s) of missing that inhibitor injection can also be identified. Data loggers and many recently available instruments and probes will be helpful for this.

Periodic Monitoring

Although the above techniques will help to identify the corrosion rate, this periodic monitoring (coupons, IP data, etc.) will give the cumulative corrosion rate over a period of time. For example, microbiologically influenced corrosion (MIC) cannot be identified with online monitoring. Coupons, intelligent pigging, and other recently introduced techniques can be implemented during periodic monitoring.

Chemical Treatment

Chemical treatment is the main solution for many internal pipeline corrosion problems. Corrosion inhibitors can be tailored to address internal corrosion environments including fluid phases, operating conditions, expected flow rates, and product chemical variations. Inhibitor injection systems should be carefully monitored and maintained to optimize the chemical treatment program. This system should be capable of reliably injecting accurate dosages all the time and every time.

FIGURE 2 Function to be executed for corrosion prevention.

Pipelines in water injection service are to be treated with oxygen scavengers to remove oxygen, scale inhibitors for preventing scale formation, and continuous injection of water corrosion inhibitor to prevent internal corrosion. The inhibitor residuals at the pipeline end should also be checked to confirm the corrosion inhibition rates are adequate. Certain organisms form slime-like biofilms that can protect underlying MIC-causing microbes. When slime is present, the biocide may not reach underlying organisms in direct contact with the pipeline wall. Continuous injection of a primary biocide, like sodium hypochlorite (NaOOCl), may be required to avoid slime formation. Intermittent biocide dosing may allow slime formation that subsequent biocide applications may not be able to penetrate, and then the slime layer can only be removed by pigging.

Sometimes, periodic shock dosing of two types of biocides is necessary to prevent MIC. Shock dosing is to be carried out only after removing existing slime by pigging. Biocides are used to eradicate microorganisms in pipelines. At least two biocides may be used alternately for better results and to reduce the bacteria developing immunity to the agents. Biocides can be injected in a batch process depending on the requirements. The effectiveness of the biocide can be tested in a laboratory using a timed killing test.

For example, if a pipeline is giving high bacterial counts, then the source of bacteria should be identified. If bacteria generation is occurring in the line, then treatment with biocide(s) in batch processes can solve the problem. If the generation is in the feedstock, some upstream equipment, like a tank, is the source of generation of bacteria and then some other strategy is required to mitigate the problem.

Pipelines for transportation of treated fluids and not typically chemically treated may not require any chemical treatment if the above-mentioned operational precautions are followed. Suggesting chemical treatment to a treated fluids line is an additional cost and needs to be justified to management.

Figure 2 shows corrosion prevention functions.

Conclusions

Preventing the internal corrosion of crude oil, natural gas, and water injection pipelines involves all the above steps, which the operator should follow to ensure the integrity of oil and gas field pipelines that are essential for uninterrupted oil and gas production.

Bibliography

A.W. Peabody’s Control of Pipeline Corrosion. 2nd ed. R.L. Bianchetti, ed. Houston, TX: NACE International, 2001.

Munger, C.G. Corrosion Prevention by Protective Coatings. 3rd ed. L.D. Vincent, ed. Houston, TX: NACE, 2014.

Murthy, T.L.N. “A Systematic Approach to Prevent Internal Corrosion of Pipelines.” MP 46, 12 (2007).

Murthy, T.L.N. “Corrosion Monitoring to Prevent Corrosion Problems.” Coating and Corrosion J. Quarter 4 (2007).

Murthy, T.L.N. “Monitoring of Chemical Treatment Is Essential to Prevent Internal Corrosion.” MP 53, 9 (2014).

Murthy, T.L.N. “Practical Challenges in Monitoring and Preventing Microbiologically Influenced Corrosion.” MP 55, 12 (2016).

Murthy, Tata. L.N. “Preventing Internal Corrosion in Subsea Pipelines.” Petroleum Africa (Nov.-Dec. 2017).

Murthy, Tata L.N, “Preventing Mistakes in Corrosion Monitoring and Chemical Treatment at Oil and Gas Recovery and Processing Facilities.” Institute of Corrosion, U.K. Corrosion Management (Nov.-Dec. 2016).

Murthy, T.L.N. “Corrosion Prevention Using Real-Time Data in Oil Fields.” MP 57, 2 (2018).

Roberge, P. Corrosion Basics: An Introduction. Houston, TX: NACE, 2006.

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