Pipeline Geotechnics: Flow Assurance

Flow Assurance

For typical oil and gas pipelines, the fluid transported will be a mixture of hydrocarbon gases and liquids that will remain stable within a given pressure and temperature regime. For the purposes of our fictitious pipeline, we shall consider an inlet temperature of 100 degree Celsius and a well-head flowing pressure of 350 Bar.

It would be quite reasonable to expect that were the fluid temperature to fall below a critical value, then certain components of the bore fluid might change phase from gas to liquid and liquid to solid. This is in fact the case, and we shall take the critical wax deposition temperature to be below 40 degrees, at this temperature, a proportion of our bore fluid will change to solid phase and take the form of waxy deposits. The formation of such solid deposits can represent a threat to the efficiency or serviceability of the pipeline and in the extreme case, could render the pipeline permanently inoperable – should significant lengths of the pipeline become plugged and so “unpiggable”.

Defining Operational Constraints

Under normal operating conditions there will be a degree of heat loss as the bore fluid is transmitted along the pipeline, the rate at which heat is lost is a function of the thermal properties of the pipeline and the surrounding seabed soil and seawater. We shall assume that the bore fluid progresses along the flowline at such a rate that it will arrive at the host facility with a temperature of 90 degrees. The formation of waxy deposits in our pipeline is therefore not a critical consideration so long as the pipeline is in normal operation.

If we reduce the rate of flow and in an extreme case, cease flow entirely, the fluid in the pipeline can be expected to have an arrival temperature below the 90 deg temperature associated with steady flow. The critical considerations then become:

  1. How much we may reduce the flow rate (turn-down) below the design flow rate and
  2. How long the pipeline can remain in a “shut-in” condition with no flow before the critical temperature of 40 degrees is experienced.

To illustrate the first point, Figure 1 below presents the temperature profile along our fictitious pipeline route calculated for three flow rates (20%, 30% and 50% of design flow) and a reduced inlet temperature of 90 deg Celsius. The calculations were performed using two different methods, these don’t particularly interest us at the present time other than to note the agreement in results. From this figure, we can clearly see the influence of flow rate on arrival temperature, however, for even 20% of peak flow the arrival temperature is above the critical wax formation temperature of 40 deg. We might be content with this conclusion, until we recall the second point above.

Figure 1: Temperature profile for various turn-down rates Temperature profile of a pipeline for flow assurance cases

For transient flow conditions, in which the pipeline is shut-in for a period of time, one significant consideration is the rate at which heat dissipates from the bore fluid through the wall of the pipeline and insulation into the surrounding environment. If we take an edge case for illustration, with a low flow rate and temperature as our initial condition, we can see in Figure 2, that the decay in temperature from the initial condition (0 hr) over a period of 1 hour, 2 hours, 3 hours and 4 hours is rather significant. In fact, the critical wax formation temperature (40 deg) is reached at the cold end of the pipeline just 1 hour after shut-in and 4 hours after shut-in at the hot end.

Figure 2: Pipeline temperature profile for 1hr, 2hr, 3hr and 4hr shut-down periods Graph showing pipeline temperature profile for 1hr, 2hr, 3hr and 4hr shut-down periods

Clearly, a 1 hour shut-in period is too short to allow maintenance work to be performed on the host facility or for work-over of the well / well head. In order to extend the allowable shut-in period we must consider alternatives to leaving our pipeline as-installed on the seabed.

Implications for Design

Owners of pipeline systems normally have a good understanding of how they intend to operate a pipeline, and how long the system will remain in a shut-in condition. The required shut down period becomes a key input when searching for the optimal pipeline design concept for a given application.

There have been a number of innovations in pipeline design concepts over the last 15 years (pipe-in-pipe systems, direct electrical heating and pipeline bundles) that seek to minimise system heat loss compared to traditional passively insulated systems. The cost vs benefit assessment of such technologically advanced systems is clearly advantageous in some cases, otherwise such concepts would never have been developed. There is still a requirement however, for passively insulated pipelines and in such cases the thickness of the insulation material is often a critical factor:

Insulation material is normally buoyant or neutrally buoyant and beyond a given thickness will result in a pipeline that is insufficiently heavy to remain stable on the seabed following lay operations or during trenching. In some cases this will result in additional steel being required in the pipeline wall to create a heavier pipe.

Seabed Soil as Insulation

At this point, we may pause to consider the potentially beneficial effects that burying a pipeline can have on the system thermal performance. In Figure 3 below, we can see that if we take our inlet temperature as 90 deg C, the arrival temperature for our pipeline in the surface laid condition is 55 deg C. If we can lower our pipeline a distance of 1.0m below mean seabed level and provide backfill on top of the pipeline, then the arrival temperature will be closer to 65 deg C. This is for a pipeline of 6000m in length, for longer pipelines, the effect of burial would be more apparent.

Figure 3: Effect of pipeline burial depth on arrival temperature

Graph showing the effect of pipeline burial depth on arrival temperature a positive improvement for flow assurance

From Figure 3, we can conclude that pipeline burial can offer a benefit in providing a degree of insulation in addition to passive insulation installed on the pipeline. We would need to consider the costs associated with burial of the pipeline vs additional insulation to reach an optimal system design. We also need to satisfy ourselves that we can define the transfer of heat through our backfill material with sufficient confidence to achieve a robust design.

I’ll move onto measuring thermal properties of soil and how “right” we get this in the next post.