Abstract

Modeling of gas gathering systems is often complicated by the presence of localized pressure losses that are not easily explained using steady-state two-phase correlation packages. This often leads to inappropriate manipulation of base input parameters such as over use of tuning factors, or reduced pipeline diameter or even increase pipeline length to get a satisfactory pressure match. A more appropriate approach includes a review of the model inputs which typically includes rechecking the measurement of the key inputs, increasing the complexity of the model (inclusion of all fluid volumes, fluid property changes, elevation profiles) and confirmation of the appropriateness of the selected pressure loss correlation. This detailed review will often resolve the issue but a significant factor is sometimes overlooked.

It has been the authors experience that these unusual pressure losses often occur at pipeline river crossings and other depressions in the terrain. In situations where superficial gas velocities are high, two-phase correlations tend to work well, but where superficial gas velocities are low, liquids can stop flowing and become trapped even though gas continues to flow.

The goal of this paper will be to present case studies where liquids accumulate and where they continue to flow in a pipeline. The differences between the two situations will be highlighted and a procedure will be presented for correctly identifying when and where liquids are accumulating. These liquid accumulations, sometimes called Stagnant Liquid Columns, can significantly increase wellhead backpressures and adversely impact well productivity.

Introduction

The maturation of the natural gas production systems throughout North America has resulted in the majority of systems being operated well below their original design conditions. Consequently, it is not uncommon to identify excessive pressure losses when comparing calculated pressures with field measured pressure data. The reasons for excessive pressure loss are varied and most often relate to measurement issues, poor understanding of the pipeline and facility connections, and sometimes non-moving liquid accumulations called "Stagnant Liquid Columns". Liquid accumulations are a concern because they increase backpressure for all upstream wells, which reduces well deliverability, and can result in localized pipeline corrosion.

One would think that the two-phase pressure loss equations should be capable of predicting when, where, and how much liquid accumulates while also predicting pressure loss.

The two-phase correlations do calculate liquid holdup but only in a steady-state sense. Simply stated, any liquid introduced into a pipeline must by definition be produced out the other end of the conduit. If the liquid enters the conduit and stays while the gas continues through, we no longer have steady-state flow and so the correlations will break down.

This leads to the question, how do we reliably identify stagnant liquid columns and how should they be modeled? To answer this question, a discussion of recommended modeling procedures is required.

Discussion
Friction versus Hydrostatic

Since total pressure loss is the sum of the friction and hydrostatic pressure loss, it is recommended that modelers always classify every scenario as either friction-dominated flow or hydrostatic-dominated flow.

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