Pipeline rehab vs. replacement depends on condition, service

Sept. 22, 1997
Research that compared rehabilitating an existing pipeline with replacing it with new line has been conducted by Abu Dhabi National Oil Co. In addition to obvious capital costs of rehabilitation vs. new construction, the company found that such a comparison must also quantify hidden costs of using older pipelines, primarily costs due to higher leak risk, extra inspection, and higher maintenance. Among other results, the study found the following: Before rehabilitation of a pipeline, its
Kamal Morsi, Hesham Bayoumi, David Robson
Abu Dhabi National Oil Co. U.A.E.
Research that compared rehabilitating an existing pipeline with replacing it with new line has been conducted by Abu Dhabi National Oil Co.

In addition to obvious capital costs of rehabilitation vs. new construction, the company found that such a comparison must also quantify hidden costs of using older pipelines, primarily costs due to higher leak risk, extra inspection, and higher maintenance.

Among other results, the study found the following:

  • Before rehabilitation of a pipeline, its condition must be assessed by intelligent pigging, cathodic-protection surveys, and coating surveys.
  • Pipeline rehabilitation is normally more cost-effective than replacement if most of the work consists of recoating.
  • For recoating costs of more than $200,000/km, it is probably not worth rehabilitating typical pipelines smaller than 18-in. OD if more than 70% of the pipeline length requires recoating.
  • If safety concerns require pipeline shutdown for rehabilitation, the resulting production losses, if crude- transfer rates are high, will often make this approach uneconomic.

Two studies

Pipeline rehabilitation is carried out to increase pipeline lifetimes or revitalize redundant lines for alternative service.

Different techniques are used for rehabilitating internal and external deterioration. External coating breakdown and corrosion are very common with land-based pipelines and are generally solved by in situ recoating.

On the other hand, internal corrosion is somewhat more difficult to deal with and may require cutting out and replacing entire sections of pipeline. Other methods of internal rehabilitation include pulled liners and epoxy flood coating.

Because some of these other methods for dealing with internal corrosion are addressed elsewhere, only external rehabilitation will be dealt with here.

Two case studies are used to illustrate the factors involved, including a quantitative assessment of leak risks under required service conditions.

The cost effectiveness of rehabilitation compared to new construction will depend on several factors. These include length of pipeline requiring replacement, length of pipeline requiring recoating, rehabilitation coating specification, feasibility of carrying out rehabilitation on "live" lines, and production losses during rehabilitation.

In addition to the simple comparison of rehabilitation costs vs. new construction, hidden costs must also be taken into account. These include potential losses from the increased leak risk of older pipeline, shorter coating lifetimes of in situ coatings, and production losses if external rehabilitation cannot be done on in-service lines.

Each case must therefore be treated separately and all the relevant data collected to obtain an accurate view of all costs associated with rehabilitation.

Presented here are two typical cases which illustrate the technical and cost aspects involved in comparisons of rehabilitation vs. replacement.

The first deals with converting a redundant oil line to condensate service; the second looks at main oil line replacement.

In the first case, the costs of laying a new condensate line are compared with the costs of rehabilitating and converting redundant main oil lines to condensate service. The comparison also takes into account the potential leak losses associated with using older pipelines.

In the second case, the costs of rehabilitating a major main-oil-line system are considered within the overall context of operational constraints and pipeline criticality.

Conversion project

Fig. 1 [20,318 bytes] shows the redundant main oil lines in a project to transfer condensate from an interior gas-processing plant to a coastal refinery and export terminal. Also shown is the proposed new 18-in. condensate line.

Production scenarios

As a result of the imminent completion of the new 36-in. main oil line No. 4, simulations of various production scenarios were conducted to determine the best way of operating the system.

These showed that only three of the four main oil lines would be required for favorable flow rates and optimized operations.

A cross-functional team identified the criteria for determining which lines should be taken out of service. These criteria included the number of sleeves and clamps, internal metal-loss defects of more than 40% of pipe-wall thickness, and modifications required to allow regular pigging

The 24-in. main oil line No. 2 and one section of main oil line No. 3 conformed to these criteria and were deemed to be redundant.

Feasibility studies were then conducted to determine whether these redundant main oil lines could be used for transporting condensate from the gas-processing plant to the refinery. It was found that main oil line No. 2 and the redundant section of main oil line No. 3 could indeed be utilized, albeit at some cost.

The rehabilitation and conversion costs together with reliability and risk involved had then to be quantified with respect to the condensate-transport requirements.

The feasibility study covered the following information on both the existing main-oil-line system and the proposed condensate transport system:

  • Leak and repair history
  • Intelligent-pigging survey results and actions taken to date on the basis of these results such as corrosion mitigation and repairs
  • Current condition of the lines
  • Operation and maintenance philosophy
  • Quantitative risk-assessment survey report
  • Design basis of condensate pipeline, including hydraulic optimization and surge analysis
  • Condensate-production profile over the next 15 years. Review of this information led to analysis of the following aspects to arrive at appropriate conclusions and recommendations:
  • Pipeline data for both the old main oil lines and the new 18-in. condensate line
  • Current status and future plans of main-oil-line system
  • Operating and capital costs of a new line vs. rehabilitation of main oil lines
  • The Net Present Value (NPV) of potential condensate-production losses as a result of leaks in the older main oil lines if these were converted to condensate service. These hypothetical losses were based on a previous quantitative risk assessment carried out on the lines of interest.1
  • Various options for utilizing main oil line No. 2 and the redundant section of main oil line No. 3 and integrating these with the condensate-transport system
  • Cost savings from converting the redundant main oil lines to condensate service.

Study results

These assessments established several facts.

First of all, based on a 1994 high-resolution intelligent-pigging survey, rehabilitation programs had been drawn up for all main oil lines covering coating repairs, cathodic-protection system upgrades, and enhanced corrosion control.

Additionally, pipe-section replacement costs for main oil line Nos. 2 and 3 for internal corrosion of more than 40% of pipewall thickness were estimated at $7 million.

Also, rehabilitation would ensure pipeline integrity for more than 30 years at a maximum allowable operating pressure (MAOP) of about 800 psi.

And, because main oil line Nos. 2 and 3 have larger diameters than the proposed new condensate line, their reuse would reduce pumping costs (capital and operating expenses).

Finally, the MAOP of 800 psi is higher than needed for transporting condensate.

A comparison of the two options in Table 1 [10,880 bytes] shows that the large savings in pumping costs make reuse of the redundant oil lines much more cost effective than installation of a new line. Table 1 also shows that reuse of the old main oil lines would still be cheaper even without the savings in pumping costs.

Despite these clear indications of potential savings, it was thought that the increased leak risk associated with using older lines would destroy any savings that might be realized.

U.S. Department of Transportation (DOT) figures for average leak rates, however, and a quantitative risk assessment conducted on these same lines showed that potential leak losses would be financially tolerable.2 3

Table 2 [54,420 bytes] compares the new-vs.-rehabilitation options with the inclusion of potential leak losses for the scenarios indicated.

Other factors were also considered:

  • Low flowrates in the larger main oil lines. The larger diameters of the older main oil lines could lead to low flowrates and an increased internal-corrosion risk. To minimize this risk, condensate dryness was deemed to be essential. Assessment of the condensate production, storage, and pumping systems showed that dry condensate in the pipelines was virtually guaranteed. This would reduce the internal-corrosion-risk created by low flowrates, dryness being thought to have more influence on corrosivity than flow regime.
  • Higher external corrosion risk. Rehabilitated pipelines are considered to have a higher risk of external corrosion because of coating breakdown. Frequent intelligent-pigging surveys and aggressive coating repairs were deemed essential for such lines.
As can be seen in Table 2 when Case No. 2 is compared to Case No. 3 as worst cases, even if pumping costs are the same for both the new and rehabilitated lines, the economic benefit from rehabilitation is greater than 20% even when potential leak losses are taken into account.

A more realistic approach (best-case comparison, Case No. 1 vs. Case No. 4) is to assume a reduction in pumping costs if the larger diameter main oil lines are used and to attribute some leak rate to the new line after 15 years of service.

This gives an NPV of $70 million for a new line compared with $41 million for rehabilitating the redundant main oil lines.

Rehabilitation vs. replacement

The second example compares the cost of a new 36-in. main oil line with rehabilitating the old main oil lines. A comparison of the two options is shown in Table 3 [6,748 bytes].

As can be seen, rehabilitation is very cost effective compared with installation of a new pipeline.

In this particular case, however, off-line rehabilitation of the main oil lines was deemed essential because of the criticality of these lines. This made it completely uneconomic to rehabilitate the main oil lines because the system is transporting several hundred thousand barrels per day of crude oil to the export terminal.

A decision was therefore made to install a new 36-in. main oil line capable of handling almost the full capacity of two of the existing main oil lines.

Once installed, the new 36-in. pipeline would give the operator the flexibility to shut down sections of the old main-oil-line system for comprehensive, off-line rehabilitation.

The new 36-in. main oil line inevitably rendered some sections of the old main oil lines redundant; these were later considered for conversion to condensate service, as described in the first case history.

Why a new line

Here is a summary of the reasons for a new 36-in. main oil line:

  1. The risks of rehabilitating in-service lines require either complete shutdown of the pipeline or use of hot taps and stopples. This measure is costly and time consuming and creates numerous dead-leg branches with higher leak risks.
  2. More than 700 clamps and sleeves could not be reliably inspected by intelligent pigging tools.
  3. There was a high risk of leaks from these old clamps and sleeves.
  4. Rehabilitation of the main oil lines would have taken a long time because of the needed excavation of giant sand dunes over much of their length.
  5. The coating durability would have been compromised by the bad weather (wind, dust, and humidity) under which it would have been applied.
  6. During the extended time required for rehabilitation, the main oil lines could have suffered further leaks. These would have further degraded existing coatings and rendered cathodic protection ineffective and thus caused further deterioration.
  7. Any leak pollutes the environment and is unacceptable under U.A.E. laws.
  8. Installation of a new, larger-diameter main oil line yields greater operational flexibility.
It was concluded that the old main oil lines could only be rehabilitated in a reasonable time by large-scale shutdowns of long sections. A new main oil line was therefore required to maintain peak production during the shutdown rehabilitation work on the other main oil lines.

Rehabilitation economics

Rehabilitation will not always be more economic than replacement if potential leak losses are high or where a high percentage of pipeline length must be recoated.

For such pipelines, the break-even point between replacement and rehabilitation must be established. Fig. 2 [21,150 bytes]shows how the costs of a new 18-in. pipeline compare with rehabilitation and leak costs. The graph shows that a new pipeline will sometimes be cheaper if recoating lengths and potential leak losses are high.

For Fig. 2, a leak rate of 0.0008 leaks/km/year is assumed for a pipeline carrying 150,000 b/d of crude oil.

For typical recoating costs of $200,000/km, Fig. 3 [19,870 bytes] shows that it is more economic to install a new pipeline if more than 70% of the pipeline length requires recoating.

For most cases, however, in which pipeline recoating lengths are less than 50% of the overall pipeline length and sleeving repairs are not extensive, it is more cost effective to rehabilitate a pipeline than to replace it.

This is well illustrated by Fig. 4 [30,240 bytes] which shows that the construction cost of a new 36-in. pipeline of 113 km is far higher than the NPV of a 30-year recoating program on 300 km of 24-36 in. pipeline.

This is the case even where recoat lifetimes are less than 5 years.

It should be noted, however, that these economics only apply to coating breakdown over discrete lengths of pipeline. (That is, the percentage of coating breakdown refers to the percentage of pipeline length requiring recoating.)


The authors would like to thank Abu Dhabi National Oil Co. (Adnoc) for authorizing the publication of this work and Abu Dhabi Co. for Onshore Oil Operations (ADCO) for providing much of the data on leak rates and rehabilitation costs.


  1. "Quantitative Risk Assessment of main oil line System." EQE ISS Ltd., Report No 174-01-R-02, Oct. 21, 1994.
  2. U.S. Department of Transportation statistics, 1970-80.
  3. Morgan, B., "The Risk Assessment of High Pressure Gas Pipelines," Risk and Reliability and Limit States in Pipeline Design & Operations, Aberdeen, May 14-15, 1996.

The Authors

Kamal Morsi is superintendent of the production engineering department at Abu Dhabi National Oil Co. (Adnoc). He worked previously for the Abu Dhabi Co. for Onshore Oil Operations (ADCO) and the Western Desert Petroleum Co. (Wepco) in Egypt. Morsi holds a BS in petroleum engineering from Cairo University and is a member of SPE.
Hesham Bayoumi is senior planning engineer at Adnoc. He worked previously for Gulf of Suez Petroleum Co. and Wepco in Egypt. Bayoumi holds a BS in mechanical engineering from Alexandria University and began his career in the refinery business.
David Robson is senior corrosion engineer at Adnoc. He worked previously for Britoil and Petroleum Development Oman. Robson holds a BS in chemical engineering from University of Manchester Institute of Science & Technology and is a chartered engineer and member of Institute of Chemical Engineers.

Copyright 1997 Oil & Gas Journal. All Rights Reserved.