2 Major Factors for Keeping Your Pipelines Healthy during the Current Oil Downturn

Operating companies have been using industry recommended practices, accumulated experience, and RBIM (risk based integrity management) to manage pipeline (flowlines, oil, gas and product pipelines) network integrity. However, they may be not sufficient to effectively address multiphase flow related problems:

  • stagnant water, solids and sludge accumulation
  • pitting (localized) internal corrosion
  • under deposit corrosion
  • bio-corrosion induced by SRB (sulfate reducing bacteria)
  • steel fatigue produced by flow induced vibrations
  • increased backpressure on wells caused by the liquid holdup 
  • process upsets in downstream facilities
  • low efficiency and shutdowns of artificial lift systems

The solutions to said issues are resource intensive. Implementation is further complicated by the fact that the operation and maintenance budget has to be allocated considering:

  • rapidly changing federal and state regulations,
  • replacement or reconditioning of aging hardware (vessels, accessories, compression equipment), and
  • reduced revenue due to current low commodities price.

The limited amount of time for project implementation and the complexity of the physics behind the problems reduce the number of viable solutions that take into account the simultaneous effect of all flow parameters that contribute to:

  • formation of favorable conditions for localized corrosion initiation, and
  • other conditions related to system integrity (e.g. flow induced vibrations, buckling, erosion caused by flow pattern transitions).

This has forced operators to rely on trial and error procedures in the selection of specific preventive or remedial actions. Such an approach is resource-intensive and time-consuming, according to the experience of international and national oil companies (e.g. BP Prudhoe Bay, Alyeska TAPS).

The attempts to solve the problem using non-metallic pipes have revealed many limitations of this technology such as upheaval buckling, degradation due to UV radiation exposure, and the risk of a catastrophic failure when operating pressure varies.

Internal corrosion is one of the main causes of pipeline failures (e.g. Alberta Energy and Utilities Board, 2007 ). While risk based inspection and management methods (RBI & RBM) have been used for many years in the industry to successfully address issues related to external corrosion or pipeline failures not associated to corrosion, they had limited success in addressing internal corrosion.

Based on our experience from completed projects, we have observed that the RBI models significantly underestimated the risk of failure due to internal corrosion in more than 300 pipelines, in which the flow was dominated by gravity. Most of these pipelines suffered from chronic and serious integrity problems (leaks, oil spills, corrosion rates > 4 mm/y, vibrations, etc.) despite the fact that:

  • the calculated probability of failure was below the target probability of failure (0.0001 per km per yr),
  • the pipelines were periodically pigged, and
  • continuous corrosion inhibitor injection was used.

The main reason of failure was pitting corrosion caused by SRB, low efficiency of corrosion inhibitor in stagnant water/gas, and solids/sludge accumulation resulting in under-deposit corrosion (Figs. 1 and 2).

 

Figure 1 - Stagnant Water in an Oil Pipeline. At low flow velocity, free water can separate from oil and accumulate at the bottom of the pipeline, which may result in severe pipe corrosion.

 
 

Figure 2 - Sludge Accumulation in an Oil Pipeline. Localized corrosion caused by sludge (a mixture of heavy hydrocarbon fractions, water and solids) accumulation in flowlines, oil pipelines and gas pipelines downstream of the field processing facilities can result in pipeline failure or extensive operational remedial costs.

 

Currently, pipeline integrity management systems assess internal corrosion risk based on:

  • Relationships (De Waard-Milliams, NORSOK, etc.) for estimating general sweet corrosion
  • Historical measurement data in few locations in the system (typically, inlet and outlet)

However, gas-oil-water-solids/sludge flow is a complex, highly non-linear phenomenon and said methods of risk assessment do not provide specific procedures to implement remedial actions for a specific combination of all the parameters that contribute to favorable conditions for corrosion initiation:

 
  • Flow rate
  • Water cut
  • GOR
  • Diameter
  • Length
  • Elevation profile
  • Pressure
  • Oil density and viscosity
  • Water salinity
  • Solids particle size and density
  • Sludge properties
 

Figure 3 - Gas-Oil-Water-Sludge Flow.

 

These parameters are different in different pipelines and change in time as production declines and water cut increases. Existing standards and guidelines also provide little information to select appropriate procedures required for a specific pipeline and operating condition from all the available remedial methods:

1. Chemical inhibition

  • Continuous inhibitor injection
  • Batch treatment
  • Optimum treatment (batch and continuous injection)
  • Biocide treatment

 2. Pigging

  • To deploy chemicals
  • To mix chemicals in water
  • To displace periodically stagnant water slugs
  • To remove solids and acid sludge
  • To avoid free span formation (in large diameter flowlines or transfer gas lines)

3. HDPE (high density polyurethane) Liners

All the above mentioned remedial actions are resource intensive and may be ineffective if used inappropriately or incorrectly, as shown for example in  Fig. 4.

 

Figure 4 - Inadequate o’clock position of the injection quill. The effectiveness of continuous corrosion inhibitor injection is very low at certain flow conditions. Furthermore, it is difficult to monitor the corrosion rate by coupons because corrosion rate and location may be non-uniform.

 

In conclusion, there are two key conditions to ensure cost effective integrity management at all stages of field development:

  1. Distributions of all parameters affecting internal corrosion over the length of the system are known.
  2. Preventive and corrective actions are selected based on the knowledge of said distributions and cost of selected methods.

Operating conditions have a strong effect on the flow parameters controlling the internal corrosion rate in pipelines. Timely preventive maintenance and preservation activities are necessary to avoid production losses caused by pipeline failures. Existing standards and guidelines indicate what measures should be taken to minimize the corrosion risk, but provide limited methods for determining the optimum pipeline operating conditions. At the same time, the pipeline operator monitors the information measured at the pipeline inlet and outlet, but cannot not see what is going on inside of the pipeline. 

When the budget and the time to implement a solution are restricted, two major factors that can help companies reduce operational costs and extend pipeline life are:

  1. Timely identification of the problems in pipelines caused by changes in their operating conditions, and
  2. Development of preventive operation & maintenance programs based on the knowledge of said problems.

In the following posts, we will discuss specific problems, methods for detecting them, and solution approaches using four-phase flow simulation.