Low Pressure Versus High Pressure Dense Phase Natural Gas Pipeline Transportation

Dense phase is a favorable condition for transporting carbon dioxide (CO₂) and natural gas as well as carbon dioxide injection into crude oil reservoir for enhanced oil recovery. Pipelines have been built to transport CO₂ and natural gas [1] in the dense phase region due to its higher density, and this also provides the added benefit of no liquids formation in the pipeline.

Recently (January through April 2012 TOTMs) we discussed several aspects of transportation of carbon dioxide (CO₂) in the dense phase. We illustrated how thermophysical properties change in the dense phase and their impacts on pressure drop calculations. The pressure drop calculation utilizing the liquid phase and vapor phase equations were compared. In the August 2012 Tip of The Month (TOTM) [2], we studied transportation of rich natural gas in the dense phase region and compared the results with the case of transporting the same gas using a two phase (gas-liquid) option. Our study highlighted the pros and cons of dense phase transportation.

In this TOTM, we will study the low pressure versus high pressure (dense phase) pipeline transportation of a lean natural gas. The application of dense phase in the oil and gas industry will be discussed briefly.

Case Study:

For the purpose of illustration, we will consider transporting a natural gas mixture with composition and conditions presented in Table 1. For simplicity, the calculations and subsequent discussion will be done on the dry basis. The feed gas dew point was reduced to -40 ˚F (-40 ˚C) by passing it through a mechanical refrigeration dew point control plant. Figure 1 presents the phase envelopes for the feed and lean (pipeline) gases. The composition and conditions of the lean gas are also presented in Table 1. The 1000 miles (1609 km) long pipeline with a  diameters of 42 inches (1067 mm) has been considered. A simplistic Process Flow Diagram (PFD) is shown in Figure 2. The following assumptions and correlations are/used:

1. Dry basis, ignoring water.
2. C₇₊ considered as nC₈.
3. Steady state
4. Delivery pressure is 615 Psia (4.24 MPa).
5. Pressure drop in each heat exchanger is 5 psi (0.035 MPa).
6. No pressure drop in scrubbers and separators.
7. Horizontal pipeline, no elevation change.
8. Inside surface absolute roughness is 0.0018 in (0.046 mm).
9. Single Phase Friction Factor: Colebrook
10. For calculation purpose, each line segment was divided into 10 sub segments.
11. Overall Heat Transfer Coefficient: 0.25 Btu/hr-ft²-˚F (1.42 W/m²-˚C).
12. Simulation software: ProMax [3]
13. Equation of State: Soave-Redlich-Kwong (SRK).

Table 1. Composition and conditions of the feed gas and lean gas

Figure 1. Phase envelopes for the feed (rich) and pipeline (lean) gas

Three cases for transportation of this natural gas are considered and each is explained briefly in the proceeding section. Figure 2 presents the PFDs for Cases A and B. Case C PFD is similar to Case B with 2 more pipeline segments, compressors and coolers. Figure 3 illustrates the pipeline systems in a block diagram.  The number of pipeline segments, segment length, and inlet pressure of each segment for the three cases are presented in Table 2 in the field (FPS, foot, pound and second) and SI (System International) sets of units.

Figure 2. Process flow diagrams (PFD) for Cases A and B (Case C is similar to Case B)

Figure 3. Pipeline Block Diagrams for Cases A, B, and C

Table 2. Pipeline specifications for the three cases

Case A: High Pressure (Dense Phase)

After passing through the first stage scrubber, the lean gas enters the first stage of compressor where its pressure is raised to 1407 psia (9.703 MPa), then it is cooled to 100 ˚F (37.8 ˚C) and compressed further in the second stage to 3220 Psia (22.2 MPa). The high pressure compressed gas is cooled back to 100 ˚F (37.8 ˚C) and then passed through a separator before entering the long pipeline (See Case A in Figure 2).

Case B: Intermediate Pressure

The process flow diagram (PFD) for this case is also shown in Figure 2. In this case, the pipeline is divided into three 333.3-mile (536.2 km) pipelines with one lead compressor station and two intermediate compressor stations. In each station, the pressure is raised from 615 Psia to 1966 Psia (4.24 to 13.56 MPa) in one stage and then cooled to 100 ˚F (37.8 ˚C), passed through a separator before entering the downstream pipeline segment.

Case C: Low Pressure

This case is similar to Case B except the pipeline is divided into five 200-mile (322 km) pipeline segments with one lead compressor station and 4 intermediate compressor stations. In each station, the pressure is raised from 615 Psia to 1600 Psia (4.24 to 11.03 MPa) in one stage and then cooled to 100 ˚F (37.8 ˚C), passed through a separator before entering the downstream pipeline segment.

Simulation Results and Discussions:

The PFDs for the three cases are simulated using ProMax [3]. To improve the accuracy and to take care of variations of physical properties of gas, each pipeline segment length was divided into 10 sub segments. For Case A in which pipeline segment was considerably longer, we tried 50 and 100 sub segments and no change in the outlet pressure and temperature was observed. Table 3 presents a summary of simulation results for the three cases in the field and SI system of units. As can be seen in this table, Case A requires the least total compression power and heat duty requirements. The power reduction for Case A is about 51%  compare to Case B and 63% compare to Case C. These reductions in power and heat duty requirements are considerable.  Similarly, the heat duty reduction for Case A is about 39% compared to Case B and 50 % compare to Case C, respectively.

Table 3. Summary of computer simulation results for the three cases.

Figure 4 presents the phase envelope, the required compression and cooling stages and pipeline pressure-temperature profile for Case A. This figure shows that the pipeline outlet condition ends up to the right of the dew point curve with the gas remaining as single phase.

Figure 4. Phase envelope, compression and cooling stages and pipeline pressure-temperature profile (ID=42 in = 1067 mm)

Pipeline wall thickness is an important economic factor. The wall thickness, t, for the three cases was calculated by:

Where,

P is maximum allowable operating pressure, here set to 1.1 times the inlet pressure,

OD is outside diameter,

E is joint efficiency (assumed to be 1),

f₁ is wall thickness tolerance (assumed to be 1.0),

f₂ is design factor, 0.4 to 0.72  and here set  to be 0.72 for remote area),

σ is the pipe material yield stress (assumed pipe material grade X65 to be 65,000 psi or

448.2 MPa), and

CA is the corrosion allowance (assumed to be 0 in or 0 mm, for dry gas).

Figure 5 presents the calculated wall thickness as a function of the inlet pressure (for the three cases). Notice Case A requires the largest and Case C requires the smallest wall thickness.

Variation of density, viscosity, velocity, pressure, and temperature along the pipeline are shown in Figures 6 through 10 for Cases A and B.

Conclusions:

We have studied transportation of natural gas in the dense phase region (high pressure) and compared the results with the cases of transporting the same gas using intermediate and low pressures. Our study highlights the following features:

1. If the gas at the source is not at high enough pressure, considerable compression power and cooling duty may be required if the decision is to use the dense phase.
2. For the dense phase – Case A, (high pressure), higher wall thickness is required.
3. For the dense phase – Case A, lower compressor power and heat duty are required.
4. For the dense phase – Case A, the friction pressure drop / mile is lower .
5. For the dense phase – Case A and the same diameter, on the average the velocity is lower compared to lower pressure gas transportation.

Other logical results can be stated as well including:

1. Composition of the gas plays an important role.
2. Pipeline elevation profile and distance may be  important factors at the higher operating pressures.
3. A detailed economic analysis in terms of CAPEX and OPEX should be made for a sound comparison.

In a future Tip of the Month, we will consider the design and order of magnitude costs impacts when constructing each of these three cases, first onshore then offshore.

To learn more about similar cases and how to minimize operational problems, we suggest attending our G40 (Process/Facility Fundamentals), G4 (Gas Conditioning and Processing), G5 (Gas Conditioning and Processing-Special), P81 (CO₂ Surface Facilities), PF4 (Oil Production and Processing Facilities), and PL 4 (Fundamentals of Onshore and Offshore Pipeline Systems) courses.

John M. Campbell Consulting (JMCC) offers consulting expertise on this subject and many others. For more information about the services JMCC provides, visit our website at www.jmcampbellconsulting.com, or email your consulting needs to consulting@jmcampbell.com.

By: Mahmood Moshfeghian and David Hairston

References:

1. Beaubouef, B., “Nord stream completes the world’s longest subsea pipeline,” Offshore, P30, December 2011.
2. http://www.jmcampbell.com/tip-of-the-month/
3. ProMax 3.2, Bryan Research and Engineering, Inc., Bryan, Texas, 2012.

Figure 5. Variation of wall thickness with pipeline inlet pressure

Figure 6. Variation of gas density in the pipeline (Cases A and B)

Figure 7. Variation of gas viscosity in the pipeline (Cases A and B)

Figure 8. Variation of gas velocity in the pipeline (Cases A and B)

Figure 9. Variation of pressure in the pipeline (Cases A and B)

Figure 10. Variation of temperature in the pipeline (Cases A and B)