Analysis and prediction of hydrocarbon dew points and liquids in gas transmission lines
The occurrence of liquid hydrocarbons in natural gas transmission lines has increased in recent years as a result of the shrinking price spread between natural gas and natural gas liquids (NGLs).
Todd Dustman & Jeff Drenker, Questar Pipeline Company
David F Bergman, BP America
Jerry A Bullin, Bryan Research & Engineering
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Consequently, there is increasing interest among many pipeline companies in monitoring hydrocarbon dew point (HCDP) and liquids in the transmission lines to ensure the safety and reliability of the system. This paper examines the methods available for determining the HCDP of natural gases and their implementation in transmission systems. A case study is presented on Questar Pipeline Company’s management and control of HCDP issues in their interstate gas transmission system in Utah, Wyoming and Colorado.
In recent years, there has been increasing interest in liquid hydrocarbon formation in gas transmission lines. Some pipeline companies have attempted to address the problem through a HCDP tariff specification. In any event, many pipeline companies are interested in monitoring HCDP and liquids in the transmission lines to ensure the safety and reliability of the system. Hydrocarbon liquids in distribution systems can be carried from main transmission lines or can result from retrograde condensation downstream of the pressure-regulating station and the corresponding Joule Thomson (JT) cooling effect. Liquids can cause problems such as flame extinguishing or overfiring in furnaces or damage to gas turbines. In addition to safety considerations, liquids in transmission lines lead to higher pipeline pressure drops, higher compressor energy consumption, and reduced line capacity.
The occurrence of liquid hydrocarbons in transmission lines has become much more prevalent in recent years due to rising natural gas prices relative to NGLs. Historically, the markets for both natural gas and NGLs have been quite volatile. There have been several periods over the past five years where the price spread between natural gas and NGLs on a thermal basis has shrunk to the point where producers and processors have reduced or even stopped processing to remove NGLs. This action has resulted in the introduction of additional heavier hydrocarbons into downstream pipelines. As a consequence, both pipelines and downstream customers on pipelines have been experiencing free hydrocarbon liquid formation in their facilities.
The analysis and prediction of HCDP and liquids in transmission lines has been discussed in the literature for several decades.1,2,3,4,5,6 The concept of HCDP, retrograde condensation and formation of liquid is most easily understood by referring to a typical phase diagram, as shown in Figure 1. The theoretical HCDP is any point along the dew point line in Figure 1 when moving from the gas phase to the first small drop of liquid. The cricondentherm is the maximum temperature at which hydrocarbon liquids could occur (maximum HCDP). Also shown in Figure 1, retrograde condensation can occur when the dew point line is encountered between the critical point and the cricondentherm.
In this paper, the question of “How much liquid is too much?” is addressed. In addition, methods used to determine the HCDP are presented and discussed. Also presented in this paper is a description of how Questar Pipeline Company uses HCDP determination to manage liquid fallout on its system as well as to deliver “spec” gas to downstream pipelines. Included as part of the case study is an evaluation of HCDP using the chilled mirror method compared to compositional analysis by gas chromatograph combined with an equation of state (EOS). Two compositional analyses were obtained using a C9+ analysis and an extended analysis. Also, a third composition, modified C6+ characterisation, was obtained by redistributing the data from the C9+ analysis. The HCDP evaluation is based on field-derived gas samples from actual producing sources.
How much is too much?
As discussed by Warner, et al,2 NGC-GPA White Paper3 and Voulgaris, et al,7 the concept of a practical HCDP is needed and the question then becomes “How much liquid is too much?” Due to the types of facilities generally available, this question needs to be addressed separately for transmission lines and distribution lines.
Since most transmission lines have at least moderate separation capabilities, the primary impact of liquids is increased pressure drops, increased compression costs, more frequent pigging and decreased throughput. As a practical matter, most pipelines will usually have a small amount of hydrocarbon liquids from compressor oils. Additional liquids would be formed by retrograde condensation any time the HCDP is reached through cooling or dropping pressure. The volume of additional liquids depends on the amount and composition of the C6+. The impact of the C6+ content on the HCDP is shown in Figure 2 for a typical lean gas, assuming that all of the C6+ is a single compound ranging from C6 to C12. For example, a gas could have a very small amount of C6+ that was primarily a C12 yielding a high HCDP with very little liquids. The most convenient way of getting a feel for the amount of liquid that might condense is to look at the quality lines on a phase diagram. An example of this is shown in Figures 3a and 3b for two gases with essentially the same dew point line but with quite different amounts of liquids condensing upon further cooling beyond the HCDP. Thus, one would expect more problems with the gas that dumped larger amounts of liquids.
The most convenient method of determining the impact of liquids in transmission lines is to set up a simulation of each line. For a given set of conditions, the simulation will calculate the liquid holdup, pressure drop and compressor horsepower. From this information, decisions can be made on the best course of action, including (1) determining pigging frequency to reduce the compression cost and increase throughput and (2) more closely monitoring the quality of the incoming gas and working with the suppliers to reduce the amount of liquids in the line.
A case study of the impact of liquids in pipelines was made on a 50-mile section of a 36 inch operating pipeline with an elevation profile, as shown in Figure 4. The steepest slopes in the pipeline were about 3o. Using Bryan Research & Engineering’s ProMax8 process simulator, the line was simulated with varying amounts of liquid for gas throughputs of 100, 300 and 450 MMSCFD with an inlet pressure of 670 psia.
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