Low Pressure Vs High Pressure Dense Phase Natural Gas Pipeline Transportation

Capital Cost (CAPEX) Comparisons

High pressure (or dense phase) is increasingly used for transporting large volumes of carbon dioxide (CO₂) and natural gas over long distances. In this month’s – Tip of the Month (TOTM), we continue to explore key aspects of dense phase transportation in pipelines. This month’s focus is on the estimation of capital costs as a tool to compare then select the operating pressures and associated facilities for a long distance – high volume flow gas transmission pipeline.

In recent TOTMs (January through April 2012 and again in August and September 2012), we discussed several aspects of the physical behavior and transportation of carbon dioxide (CO₂) and natural gas 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  (TOTM), 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 September 2012 (TOTM), we analyzed pipeline transportation of a lean natural gas at a wide range of operating pressures from the relatively low pressure typical in many gas transmission pipelines to much higher pressures well into the dense phase region.

Case Study:

We will continue to use the same case study basis as used in the September 2012 TOTM. The gas composition and conditions are 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. The resulting composition and conditions of the lean gas are also presented in Table 1. The lean gas has a Gross Heating Value of 1082 BTU/scf (40.33 MJ/Sm³), which is in the range typically seen for contract quality natural gas in North America. The pipeline parameters are:

• Length is 1000 miles (1609 km) long
• Pipeline outside diameter is 42 inches (1067 mm). Initial inside diameters for the hydraulics analyses are: Case A = 39.0 (991 mm) inches, Case B = 40.0 inches (1016 mm), and Case C = 40.5 inches (1029 mm)
• Steady state conditions are assumed.
• Pressure at delivery point and suction at each compressor station is 615 Psia (4.24 MPa)
• This is a horizontal pipeline with no elevation change.
• Overall Heat Transfer Coefficient: 0.25 Btu/hr-ft²-˚F (1.42 W/m²-˚C).
• Simulation software: ProMax and using Equation of State from Soave-Redlich-Kwong (SRK).

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

Table 2. Pipeline specifications for the three casesThree cases for transportation of this natural gas are considered and each is explained briefly below.  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.

Table 2. Pipeline specifications for the three cases

Hydraulics Simulation Results and Discussions:

The three cases are simulated using ProMax [3] to determine the pressure and temperature profiles, the compression horsepower, and the after cooler duties. Table 3 presents a summary of simulation results for the three cases in FPS and SI systems of units.

Case A: High Pressure (Dense Phase)

This pipeline is a single compressor station configuration. The pipeline inlet pressure is in the dense phase zone. After processing and passing through the first stage scrubber, the lean gas  pressure is raised to 1496 psia (10.32 MPa), then cooled to 100 ˚F (37.8 ˚C). The gas is compressed further in the second stage to 3659 Psia (25.22 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.

Case B: Intermediate Pressure

This pipeline has three compressor stations each equally spaced at 333 miles. The pipeline inlet pressure is near the dense phase zone.  In each station, the pressure is raised from 615 Psia to 2071 Psia (4.24 to 14.28 MPa) in one stage, then cooled to 100 ˚F (37.8 ˚C), and finally passed through a separator before entering each pipeline segment.

Case C: Low Pressure

This pipeline has five compressor stations equally spaced in 200-mile (322 km)  segments. The pipeline inlet pressure is well below that for dense phase. In each station, the pressure is raised from 615 Psia to 1637 Psia (4.24 to 11.28 MPa) in one stage, then cooled to 100 ˚F (37.8 ˚C), and finally passed through a separator before entering each pipeline segment.

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

As can be seen in this table, Case A with a single compressor station requires the least total compression power and lowest heat duty requirements. The power reduction for Case A is about 51%  compared to Case B (with three compressor stations) and 63% compared to Case C (with 5 compressor stations). These reductions in power and heat duty requirements are significant.  Similarly, the heat duty reduction for Case A is about 39% compared to Case B and 50 % compare to Case C, respectively.

Variation of gas velocity, pressures, and temperature are shown on Figures 1 through 3 for Cases A and B. As discussed in the previous TOTM, when the phase diagram and the pressure profiles are cross plotted using the pressure and temperature profiles the pipeline outlet condition remains  to the right of the dew point curve with the gas remaining as single phase.

Figure 1. Variation of gas velocity in the pipeline (Cases A and B)

Mechanical Design (Wall Thickness and Grade)

Pipeline wall thickness is an important economic factor. Pipeline materials typically represent approximately 40% of the Capital Expense (CAPEX) of a pipeline. Construction will account for approximately 40% of the CAPEX as well. The estimation of the CAPEX is developed later in this TOTM. Once the wall thickness is determined, then the total weight (tonnage) of the pipeline can be calculated as well as costs for the pipeline steel.

The wall thickness, t, for the three cases is calculated from a variation of the Barlow Equation found in the ASME B31.8 Standard for Gas Transmission Pipelines:

                                                                                                                     (1)

Where,

• P is maximum allowable operating  pressure, here set to 1.05 times the inlet pressure,
• OD is outside diameter,
• E is joint efficiency (assumed to be 1) since the pipeline will be joined with through thickness butt welds and 100% inspected,
• F is design factor,(ranges from 0.4 to 0.72) and here set  to be 0.72 (for remote area),
• T is the temperature derating factor and is also 1.0 with the inlet temperatures no more than 100 ˚F (37.8 ˚C).
• σ is the pipe material yield stress (Grade X70 = 70,000 psi or 448.2 MPa), and
• CA is the corrosion allowance (assumed to be 0 in or 0 mm, for this dry gas).

After calculating the wall thickness, the diameter to wall thickness ratio (D/t) is checked against these rules of thumb:

• Onshore pipelines will have a maximum D/t of 72.
• Offshore pipelines will have a maximum D/t of 42.

If the D/t calculated is too high, the wall thickness will be increased to yield the maximum allowed D/t.

Figure 2. Variation of pressure in the pipeline (Cases A and B)

Figure 3. Variation of temperature in the pipeline (Cases A and B)

Using the calculated pipeline inlet pressures from the hydraulics as the starting point, the MAOP then the wall thickness can be calculated. The calculated wall thickness is then checked against the maximum D/t criteria. Table 4 summarizes these calculations for the three cases for both onshore and offshore locations.

Knowing the wall thickness and diameter allows the weight per lineal length (foot or meter) to be calculated. The total weight of the steel for the 1000 mile (1609 km) long can then be calculated as well. The unit weight is given in lbm/ft (kg/m) and the total weight in short tons (2000 pounds) and metric tonnes (1000 kg). The results of these weight calculations are in Table 5.

Some observations from these calculations that can be made are:

• Increasing the steel grade (SMYS – Specified Minimum Yield Stress) from X-70 to X-80 would decrease the steel tonnage approximately 14%. As the cost calculations will show, this reduction would lower the cost significantly. However, the use of X-80 steels is still not widely accepted in the pipeline industry.
• The volume of steel combined with the diameter and wall thicknesses will require a major portion of pipe manufacturing capacity. If this were a sanctioned project, pipe steel procurement would need to bid well in advance of the planned construction.
• Wall thicknesses are NOT raised to next standard API thicknesses. The large quantity of steel needed allows the buyer to dictate a non-standard thickness. The pipe mills will be glad to accommodate such a requirement.

Table 4: Pressures and Wall Thickness Selections

Table 5: Pipeline Wall Thickness Selections and Total Steel Weight

Estimated Capital Costs

The capital costs (CAPEX) for these estimates are based on two key variables: pipeline wall thickness and the compression power required. Both are dependent of the pipeline pressure profile which is dictated by the number of compressor stations. The estimated cost will be calculated from the following assumptions:

• Line pipe is priced at US$ 1200 per short ton with a 15% adder for coatings.
• Pipeline total installed cost is 2.5 times the pipe steel plus coatings cost. This factor is surprising consistent for both onshore and offshore long distance and larger diameter pipelines. Project specific factors such as mountainous terrain for an onshore pipelines, or the requirement to trench an offshore pipeline can impact this cost multiplier.
• No additional cost difference is taken into account for this estimate between onshore and offshore construction. In reality there is a difference that can be significant. These differences are largely dependent on the project location with factors that could include weather and seasonal challenges, water depth for offshore projects, terrain for onshore projects, available infrastructure and its impact on logistics, and availability of construction equipment and labor.
• Compressors and associated equipment (drivers, coolers, and ancillaries) are priced at US$ 1500 per demand horsepower.
• Onshore compressor stations are priced at US$ 25 million each for site works, buildings and equipment not directly related to gas compression.
• Offshore compressor stations are priced at US$250 million each for the fixed structure, topsides not directly related to gas compression, and a quarters complex. This assumption is sensitive to project location, whether the structure is stand-alone or in a group of structures, water depth, and met-ocean conditions.
• The offshore pipeline cases originate ONSHORE with the lead compressor station.

With these cost assumptions, an order of magnitude estimate (OME) for the total installed cost (TIC) is developed for the pipeline, then the compressor stations, and finally combined for the total pipeline system in Table 6 – Pipeline Estimate, Table 7 – Compressor Station Estimate, and Table 8 – Total System OME.

Table 6: Pipeline Total Installed Cost

Our estimating assumptions can lead to costs that are the same whether for onshore or offshore pipelines. This is where knowledge of the project becomes vital in adjusting the estimate to account for conditions that can affect the assumptions.

Table 7: Compressor Stations Total Installed Cost

The most sensitive variable for the compressor stations calculations is the location of any offshore facilities. Location, water depth and met-ocean conditions can and will impact the estimated cost significantly.

Table 8: Total System OME

The total installed costs for an ONSHORE system decline with decreasing operating pressure (MAOP), although the rate of decline is also decreasing as more compressor stations are needed. For the onshore systems, the operating cost, particularly fuel costs, can impact the operating pressure / number of compressor stations decision. It is common for total life cycle costs (OPEX plus CAPEX) to begin rising at some point as the number of compressor stations and total horsepower increases with decreasing operating pressure.

For an OFFSHORE system, show the lowest total installed cost is with a three compressor station configuration. This “optimum” CAPEX solution will be sensitive to project location as discussed above as well as operating costs. Often, with the operating costs included the “optimum” configuration favors higher operating pressures and fewer compressor stations. The cost adjustments for project location on both CAPEX and OPEX can move to “optimum” configuration either way.

Final Comments:

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. As the MAOP increases, the required power and associated cooling duty can significantly increase.
2. The decreased costs for compression are offset by increasing pipeline costs. The key is by how much.
3. Project location can have significant impact on the costs, hence the key decisions are on operating pressures, onshore versus offshore routing (where possible), and the number and power levels at the compressor stations.
4. With the high power demands of large diameter – high capacity pipelines, the operating costs for fuel can be a key factor in the configuration selection. 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.

In future Tip of the Months, we will consider the effect of project location and operating costs on the life cycle costs and the configuration selection.

To learn more, we suggest attending our G40 (Process/Facility Fundamentals), G4 (Gas Conditioning and Processing), G5 (Gas Conditioning and Processing-Special), PF81 (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 us at consulting@jmcampbell.com. 

By: David Hairston and Mahmood Moshfeghian

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.