Corrosion of pipeline components

In the UK Sector of the North Sea there are many operating companies who have been producing oil and gas for the last four decades. During this period of time there have been many advances in materials technology which has been used in what has been considered as one of the most aggressive environments for oil and gas production.

During this period most operating companies have experienced problems with corrosion; the latest survey has shown that 60% of all maintenance cost are directly related to corrosion. In my experience the opex or operational cost are quite often given little thought by the operating companies, but on the other hand capex or capital expenditure costs come under close scrutiny, and often material selection which will deliver performance, and higher profitability are ignored.

Although some of the facilities in the North Sea operators are more aware of corrosion costs, there are many who don’t and wait to components fail rather than take preventative measures. This cost is hidden amongst all of the other maintenance costs and accounted for as being an opex cost. But what are the real costs, in terms of shutdown, loss of production, etc.
One experience I had with one operating company was fairly typical of where operating costs are ignored. This operator had a continual problem with a pump shaft which was chromium plated. To repair this pump it had to be taken out of service and stripped down to remove the shaft for re plating. I suggested it would be better to consider a more advanced coating such as would be done with High Velocity Oxy Fuel Coating. No the coating suppliers warranty on the part is one year and it costs us nothing to have it redone as the coating breaks down within the year. When I asked who strips the pump down, he replied our maintenance crew, but these guys are paid for anyway. After several discussions Proclad was given the opportunity to coat this shaft with chromium carbide; the pump has run for the past thirty months with no deterioration of the coating.

Materials technology has proven to provide equipment reliability solutions and has assisted operators in improving profitability. Every capex made to improve equipment reliability by improved materials technology has proven to reduce costs. Another example of this is where one North Sea operator who had a particular problem with corrosion and erosion of their choke valves, where the corrosion was so aggressive the valves had to be changed out after only a few weeks of operation. Proclad were contracted to apply an Alloy UNS 06625 to the valve internals and finish machine all wetted areas. The first valves have been in operation for several years. The cost saving from this technology is not the only factor to be considered, safety is the other consideration as leakage could have caused loss of life, and may have had a severe environmental impact.

The most important consideration in designing a pipeline is the design life of the field; in conjunction with the design there has to be a lifecycle study to determine levels of corrosion and its possible negative effects. Some of the examples given are definite cost savings. It must be recognised that the use of CRA as a corrosion barrier offers the best solution in terms of maintaining pipeline integrity. It is a fact that the materials and corrosion control technologies have not seen any significant change since the 1970s.  It is also recognised that the materials used in the more difficult locations have been more reliable due to the excessive replacement costs. If a lifecycle study is carried out on a case by case basis, and operators are made more aware of the benefits of using clad equipment to protect their assets, more of this technology would be used today. It must be recognised that internal corrosion costs the oil and gas industry $1.5 billion, not considering lost production which may well double this figure. An example of which is the Alaskan pipeline failure (Prudhoe Bay) which effected US production figures by 8%.

As an example Proclad recently carried out a case study for Middle East operating company looking at carbon steel against a clad material. The pipeline in question is 14 inch diameter with an anticipated design life of 17 years. If corrosion inhibitor were used, assuming 90% efficiency the predicted corrosion rate is 0.3mm year at 70 Deg F, and 0.4mm year at 110 Deg F. A summary of both Capex and Opex cost a listed below.

Carbon Steel. $
Engineering qualification costs. 300,000
Pipeline study. 100,000
Carbon Steel materials. 3,120,000
Coating costs. 400,000
Cathodic protection. 400,000
Inhibitor facilities cost. 300,000
Total = $4,620,000

Operating costs
Corrosion inhibitor
Continuous injection rate @ 6ppm. 57,000
Batch injection rate @ 30ppm. 20,000
Biocide
Continuous injection rate @ 8ppm. 174,000
Batch injection rate @200ppm.  310,000
Calculated using a base flow rate of 75,000 BLPSD
Total = $608,000 per year

In consideration of the above the OPEX costs for the anticipated life cycle of seventeen years would be $10,336,000. Adding the capex costs would bring the total to $14,956,000.

Carbon steel, clad pipeline
Engineering qualification costs. Nil
Pipeline study.  100,000
Carbon steel materials.  2,195,856
UNS 8904 CRA materials.  5,851,200
Jointing CRA. 250,000
Coating costs.  400,000
Cathodic protection. 400,000
Total = 9,197,056   

Operating Costs
Monitoring/ pigging costs. 47,000 per year
For this case study the monitoring/pigging costs have been estimated equal. In practice the monitoring/pigging costs of the CRA Linepipe may be less expensive.

Summary

This study has shown that over the seventeen year design life of this pipeline there are significant savings. These figures clearly show the need for considering a clad material against using corrosion inhibitors.

Total Capex/Opex costs for a carbon steel pipeline = $14,956,000
Total Capex/Opex costs for a carbon steel clad pipeline = $9,996,057

It must be recognised that a large percentage of new oil and gas developments will come from remote regions such as deepwater offshore etc. Operating companies have a completely different strategy in selecting materials for these regions as corrosion failures will be much more costly to repair. It is also evident that operators are aware that many problems could be solved if they had better awareness of technologies such as cladding, and what materials are available. It is not always necessary to pick the noblest material to protect pipeline internals, but a selection suited to the service conditions is the correct way forward. It has been proven that cladding greatly enhances the lifecycle of oil and gas pipelines and the associated equipment. The challenges faced by Proclad is to convince operating companies to carry out an in depth life cycle study before selecting materials for specific applications.

The areas of major corrosion related problems for oil field environments are almost universal. CO2 and H2S gases in combination with water are responsible for most of the corrosion problems associated with processing oil and gas. The internals of a pipeline become complicated when CO2 acts in conjunction with H2S, deposited solids, and other environments. Oxygen is generally not found in oil reservoirs; however in some cases a few ppm of oxygen will enter the pipeline, and will greatly exacerbate any corrosion problems.

For example, in August of 2006 BP were forced to shut down production for a period of weeks following the worst spill on Alaska’s North Slope due to unexpected severe corrosion. This shutdown accounted for the loss of around 8% of the nation’s domestic oil production for a period of weeks. The root cause being “unexpectedly severe corrosion” which resulted in a hole in the pipeline. It must be recognised that the pipeline is in poor condition, and even with the most up to date inspection techniques the hole in the pipeline was undetected. Questions must be asked when and where will the next leak take place and what will be the resultant cost be to the economy and the environment. The oil analyst for Oppenheimer & Co Fadel Gheit was quoted as saying it should come as no surprise that there are problems with this pipeline system as it is well known that oil companies are not doing enough regular maintenance on their assets.

The pipeline in question had been in operation for thirty years, corrosion has to happen. However, does the oil spills in Alaska mean oil operators will have a different approach in materials selection to protect their assets; I believe this will not be the case. The same common approach of evaluating materials will prevail, and the more cost effective options will always be given the most consideration. In August 2007 oil was nearing $95 per barrel, for every day that field was shutdown the costs from lost production were close to $400m per day notwithstanding the additional 5 Cents per gallon it cost the consumer at the petrol pumps. If proper materials planning were taken into consideration and a clad material selected which suited to the service conditions in which it was operating, this event would have never taken place.

This is an example of how an asset can realise its lifetime potential, maximizing production without the need for corrosion inhibition or in fact maintenance. If the pipeline system is clad with a material suited to combat the predicted service conditions, it can be installed with the confidence that it will operate for the design life of the field. If we consider it cost the operator $260m to replace the effected lines including $20m of fines to the state of Alaska, environmental research costs, lost production costs etc the use of a clad pipeline would have saved a considerable amount of money. Finance raised for corrosion monitoring systems after the event is meaningless. If materials planning were taken into consideration and a clad material suited to the service conditions in which it was operating this event would have never taken place. Operators, governments, environmentalists, materials and corrosion engineers should be involved in the materials selection process particularly with an asset as valuable to the economy, and being located in an environmentally sensitive region as Alaska.

Proclad can offer such a service to operating companies as their experience is all around providing a protective barrier from corrosion. This engineering solution is in use in many areas of the world that are processing Hydrocarbons. Operators are realizing the low maintenance benefits of running their assets safely and without fear of environmental impacts of leaks.