The following specifications/assumptions for the case study are considered:

Contactor Column

► Feed sour LPG is saturated with water

► Number of theoretical stages = 4

► Pressure drop = 20 kPa (3 psi)

► Lean amine solution temperature = Sour LPG feed temperature plus 2.8 °C (5 °F)

Regenerator/Stripper Column

► Number of theoretical stages = 10 (excluding condenser and reboiler)

► Feed rich solution pressure = 414 kPag (60 psig); typically stream 8 has a letdown valve to reduce pressure to the stripper column pressure.

► Feed rich solution temperature = 98.9 ℃  (210 ℉ ); this is conservative and could be 107 ^°C at 414 kPag (225 °F at 60 psig)

► Condenser temperature = 48.9 ℃  (120 ℉ ); this reflects warm climate with aerial cooler

► Pressure drop = 21 kPa (3 psi)

► Bottom pressure and temperature = 110 kPag (16 psig), about 126 °C (259 °F)

Reboiler Duty

► Steam rate = 132 kg of steam/m³ of amine solution (1.1 lb_m/gallon) times amine circulation rate

► Saturated steam pressure = 348 kPag (50 psig) at 147.7 °C (297.7 °F)

Heat Exchangers

► Lean amine cooler pressure drop = 35 kPa (5 psi)

► Rich side pressure drop = 35 kPa (5 psi)

► Lean side pressure drop = 35 kPa (5 psi)

Main Pump

► Discharge Pressure = Feed sour gas pressure + 35 kPa (5 psi)

► Efficiency = 65 %

Reflux Pump

► Discharge Pressure = 350 kPa (50 psi)

► Efficiency = 65 %

Lean Amine Concentration and Circulation Rate

MDEA concentration in lean amine = 25 and 50 weight %

► Lean amine circulation rate was adjusted (by solver tool) to reach a specified rich loading (0.15, 0.2, 0.3, or 0.4 mol acid gases/mol MDEA) while reducing the H₂S CO₂ concentration in sweet LPG to less than 4 ppmw

► Total acid gas loadings in lean solution in the range of ~0.002 to 0.006 mol acid gases/mol of MDEA

Rich Solution Expansion Valve

Outlet pressure = 448 kPa (65 psia)

RESULTS AND DISCUSSIONS

For the above specifications, ProMax [5] is used to simulate the process flow diagram in Figure 1. The objective was to produce a sweet LPG with less than 4 ppmw H₂S and CO₂. In order to meet these specifications, the required lean MDEA solution volumetric rate was determined by the solver tool and then the calculated operation parameters were recorded.

Three feed gas pressures and for each pressure 5 temperatures were simulated. For clarity and to avoid crowded curves on the diagrams, only the results for the lowest and the highest pressures are presented.

The variation of MDEA solubility loss to sweet LPG as a function of pressure, MDEA wt. %, rich solution loading and temperature are presented in the following section. In all cases the sweet LPG pressure was 21 kPa (3 psi) lower than the feed LPG pressure.

Figure 2 presents the phase behavior for sour LPG (Table1). To avoid vaporization, throughout of the sweetening process the LPG stream should remain in the liquid region (to the left of bubblepoint curve).

Figure 2. Sour LPG phase behavior

Effect of Pressure:

For rich solution loading of 0.4 mol acid gases per mol MDEA and 50 wt. % MDEA concentration, Figure 3 presents the solubility of MDEA in the sweet LPG in terms of ppmw (the top two curves) and ppmv (the lower two curves) as a function of temperature. The two pressures are 1379 kPag and 2069 kPag (200 psig and 300 psig). Note the MDEA solubility in the sweet LPG is not affected by pressure but increases with temperature increase.

Effect of Loading:

For 50 wt. % MDEA solution and pressure of 2069 kPag (300 psig), Figure 4 presents the solubility of MDEA in the sweet LPG in terms of ppmw (the top two curves) and ppmv (the lower two curves) as a function of temperature. The two rich solution loadings are 0.2 and 0.4 mol acid gases per mol of MDEA. Note the MDEA solubility in the sweet LPG increases with increase in rich solution loading and temperature.

Figure 3. Variation of MDEA solubility in the sweet LPG with temperature and pressure (50 wt.% MDEA, 0.4 mol acid gases/mol MDEA, and no water wash)

Figure 4. Variation of MDEA solubility in the sweet LPG with temperature and rich solution loading (50 wt. % MDEA, 2069 kPag (300 psig), and no water wash)

MINIMIZING MDEA SOLUBILITY IN LPG 

Amine in LPG can result in quality issues for the LPG and may cause problems particularly in butane streams that might be used in gasoline blending. Amine can damage the fuel gauge sensing units.

An important piece of equipment for minimizing MDEA in liquid treaters is an internal and/or external water-wash system to recover any dissolved MDEA. While some solubility losses will occur in all systems; a water wash system provides an efficient recovery method to minimize these losses and remove MDEA from the treated LPG [3, 6].

Figure 5 presents a segment of the process flow diagram in Figure 1 with the internal and external water wash. Streams “In Water” and “Ext Water” are the internal and external water wash, respectively. Note stream “In Wash” enters the contactor at tray 1 and the lean MDEA stream enters at tray 2.

Stream 17 (continuous phase) is the treated LPG and stream 18 (disperse phase) is the effluent washed water. The “In Water” wash flow rate was about 0.035 % of the sour LPG volume rate, very close to the makeup water rate needed to maintain MDEA concentration.  The “Ext Water” wash flow rate was about 0.1% of the sour LPG volume rate.

Figure 5. Schematic of the internal (In Water) and external (Ext Water) wash system

Figure 6 shows that solubility of MDEA in the sweet LPG with no water wash increased rapidly when operating above a 40 – wt. % MDEA concentration. This is in agreement with the chart in reference [3] for pure liquid hydrocarbon. For this reason, operating liquid treaters with an MDEA concentration greater than 40 wt. % is not recommended [3, 6]. In general, when rich loading and treating requirements are not a concern, reducing concentration can help reduce solubility losses in liquid treaters [3,6]. Figure 6 also shows the impact of water wash on the MDEA solubility loss for the internal water wash only, the external water wash only, and the internal plus external water wash.

Figure 6. Variation of the MDEA solubility loss in the sweet LPG with the MDEA concentration at 43.3 °C (110 °F), 2069 kPag (300 psig) and rich loading of 0.4 mol acid gases per mol MDEA.

For rich solution loadings of 0.2 and 0.4 mol acid gases per mol MDEA and 50 wt. % MDEA, Figure 7 presents the solubility of MDEA in the sweet LPG as a function of temperature at 2069 kPag (300 psig). The curves show results for no water wash (top two), with internal water wash (middle two), and internal plus external water wash (lower two curves). Figure 8 is like Figure 7 with the exception that MDEA concentration is 25 wt. %.

Figure 7. Solubility of MDEA in the sweet LPG with no water wash, with internal water wash, and internal plus external water wash as a function of temperature for 0.2 and 0.4 rich solution loading and 50 wt. % MDEA at 2069 kPag (300 psig).

Figure 8. Solubility of MDEA in the sweet LPG with no water wash, with internal water wash, and internal plus external water wash as a function of temperature for 0.2 and 0.4 rich solution loading and 25 wt. % MDEA at 2069 kPag (300 psig).

Like Figure 6, Figures 7 and 8 indicate that the water washing reduces the MDEA solubility loss and the losses for 25 – wt. % MDEA are much lower than the loss for 50 – wt. % MDEA.

Figure 9 shows pressure-temperature profile from the inlet of contactor and through four trays from bottom to the top of contactor for feed pressures 1379 KPag and 2069 kPag (200 psig and 300 psig) and the LPG bubblepoint curve. This figure indicates the LPG remains as liquid during treating process.

Figure 9. Pressure-Temperature profile through treating process

CONCLUSIONS

Based on the results obtained for the considered case study, this TOTM presents the following conclusions:

► Throughout the column and water washing process the operating temperature should be lower than the bubblepoint temperature to avoid LPG vaporization (Figs 2,9).

► As the feed LPG temperature to the contactor column increases, the MDEA solubility loss to LPG increases whereas pressure effect is negligible (Fig 3).

► As the rich solution loading increases, MDEA solubility loss increases (Figs. 4,6,7).

► As the MDEA wt. % increases, the MDEA solubility loss to LPG increases (Figs. 5,6,7). To minimize MDEA solubility loss operate with MDEA concentration less than 40 wt. %. Internal and/or external water wash reduce the MDEA solubility loss.

► Even though not studied in this TOTM, mechanical and entrainment losses from the contactor top and regenerator top as well as losses due to filter change are also sources of loss and are much higher than the solubility losses presented here.

To learn more about similar cases and how to minimize operational troubles, we suggest attending our G6 (Gas Treating and Sulfur Recovery), G4 (Gas Conditioning and Processing), G5 (Advanced Applications in Gas Processing),PF4 (Oil Production and Processing Facilities), PF49 (Troubleshooting Oil and Gas Processing Facilities) courses.

Written By: Mahmood Moshfeghian, PhD

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References

1. Maddox, R.N., and Morgan, D.J., Gas Conditioning and Processing, Volume 4: Gas treating and sulfur Recovery, Campbell Petroleum Series, Norman, Oklahoma, 1998.

2. Nielsen, R.B., Rogers, J., Bullin, J.A., Duewall, K.J/; “Design Considerations for Sweetening LPGs with Amines”, Proceedings of 74^th Annual GPA Convention, San Antonio, TX, March 1995.

3. Teletzke, E.  and Madhyani, B., “Minimize amine losses in gas and liquid Sweetening”, Laurance Reid Gas Conditioning Conference, Norman, Oklahoma February 26 – March 21, 2017.

4. Moshfeghian, M., “MDEA Vaporization Loss in Gas Sweetening Process.” July 2018 tip of the month,  PetroSkills – John M. Campbell, 2018.

5. ProMax 5.0, Build 5.0.20034.0, Bryan Research and Engineering, Inc., Bryan, Texas, 2020.

6. Stewart, E.J. and Lanning, R.A., “Reduce Amine Plant Solvent Losses”, Hydrocarbon Processing, June, pp. 51-54, 1994.

Click to enlarge

Case Study:

Let’s consider the same case presented in June 2019 TOTM [3] for a rich gas with the compositions and conditions presented in Table 1 [3]. Based on the reported molecular weight and relative density for the C7+ fraction, Table 2 presents the estimated normal boiling point (NBP), critical properties and acentric factor which, are needed by the equation of state. The objective is to meet a hydrocarbon dew point specification at the cricondentherm of  -19.5 °C (-3 °F) at about 4708 kPa (682 psia) for the sales gas by removing heat in the “Gas/Gas” heat exchanger (HX) with a hot end temperature approach (TA) of 3°C (5.4°F)  and in a propane chiller with TA of 5 °C (9 °F). The heat will be rejected to the environment by a propane condenser AC-100 at 37.8°C (100°F). Pure propane is used as the working fluid in the simulation. The pressure drops in the “Gas/Gas” HX and on the process side of the propane chiller are assumed to be 34.5 kPa (5 psi). The tip will investigate the impact of inlet pressure from 2000 to 7837 kPa (290 – 1136 psia) on the performance of mechanical refrigeration presented in Figure 1.

Table 1. Rich feed gas compositions and conditions

Table 2. Estimated C7+ properties [4]

The phase envelope for the feed gas and the desired sales gas specification with a cricondentherm of -19.5 °C (-3 °F) at about 4700 kPa (682 psia) are presented in Figure 2. In addition, Table 3 presents the inlet pressure range, cold separator pressure and the corresponding cold separator temperature to meet the sales gas specifications. The process gas temperatures at the outlet of Gas/Gas HX (Stream 5) are also presented.

Figure 2. Feed gas and sales gas-phase envelopes

Table 3. Inlet pressure, cold separator pressure, the required cold separator temperature and stream 5 temperature to meet sales gas specification

 Cricondentherm Pressure      and **   Cricondenbar Pressure

The feed gas is flashed in the “Inlet Separator” at 30 °C (86 °F) and the process gas inlet pressure to remove any condensate. The “Inlet Separator” vapor (stream 2) is saturated with water by the “Saturate -100” to form stream “2 Wet” upstream of mixing with MEG hydrate inhibitor, stream “EG1” and the recycle stream “18A” from the deethanizer overhead vapor (located at the right-hand side of Figure 1).

The hydrate formation temperature (HFT) of streams 5 and 7 are estimated. The hydrate inhibitor is injected at the inlet of “Gas/Gas” HX by stream “EG1” and at the inlet of the “Chiller” by stream “EG2”. Streams “5” and “7” cool down below their respective HFTs. The injection rates of streams “EG1” and “EG2” for 80-weight % lean MEG and water solution are estimated manually or by the Adjust tool of UniSim. A design margin of 1 °C (1.8 °F) HFT below the cold temperature for streams “5” and “7” were assumed.

Assuming a TA of 5°C (9°F) and a 6.9 kPa (1 psi) pressure drop in the propane “Chiller” shell side, the pressure of saturated propane vapor leaving the chiller depends on process gas pressure and is in the range of 117 to 200 kPa (17 to 29 psia). Assuming no frictional losses in the suction line to the propane compressor “K-101”, the resulting suction pressure is 117 to 200 kPa (17 to 29 psia).

The condensing propane pressure at the specified condenser temperature of 37.8 °C (100 °F) is 1303 kPa (189 psi). The condenser “AC-100” frictional losses, plus the frictional losses in the piping from the compressor discharge to the condenser were assumed to be 34.5 kPa (5 psi); therefore, the discharge pressure of compressor “K-102” is 1338 kPa (194 psia). The compressors inter stage pressure was determined by equalizing the power for “K-101” and “K-102”. The compressors adiabatic efficiency was assumed to be 75%.

The cold Stream 7 is flashed in the 3-phase separator “V-102” at the separator pressure and corresponding temperature (see Table 3). Assuming this cold separator has no liquid carry over, the vapor stream “4” from this cold separator is used to cool down the incoming warm feed gas in the “Gas/Gas” HX. The heavy liquid stream “8B” (rich MEG solution) from the cold separator is regenerated in the regeneration unit (not shown in Fig. 1) and the lean 80 weight % MEG is recycled and used in streams “EG1” and “EG2”. The cold NGL stream “8” (light liquid phase) from the cold separator, “V-102”, is combined with the plant “Inlet Separator” condensate (stream “3”) in the mixer “Mix-101” to form stream “9”. To prepare the liquid to be fed to the deethanizer, the process specification is to raise the cold temperature of the NGL product stream “9A” to 20 °C (68 °F) and 1500 kPa (217.6 psia) in “E-102” HX, regardless of plant inlet pressure. The process duty and the temperature of the NGL product stream is set by the deethanizer process requirements. The pressure drops in “E-102” HX is 35 kPa (5 psi). Sometimes the heat duty of “E-102” is used as a cooling medium for the deethanizer overhead condenser.

Deethanizer Specifications and Performance:

Like the June 2019 TOTM [3], regardless of inlet pressure, the deethanizer specifications are:

►To recover 90 mole percent of propane of the feed in the bottom product and

►Ethane to propane mole ratio equal to 5 % in the bottom’s product

►Feed pressure 1500 kPa (217.6 psia) and temperature of 20 °C (68 °F)

►Top and bottom pressures are 1450 and 1500 kPa (210.3 and 217.6 psia); respectively

►Number of theoretical stages 12 plus the condenser and reboiler (determined by the material balance and column shortcut calculations)

►Feed tray from top is 4

The deethanizer simulation results for feed gas inlet pressure 4700 kPa (682 psia) are summarized in Table 4.

Table 4. Deethanizer key design parameters for feed gas inlet pressure of 4700 kPa (682 psia)

Impact of Inlet Feed Gas Pressure:

The Gas/Gas HX utilizes the cold temperature of stream 4 to cool down stream 2A and reduce the chiller duty. The specified temperature approach (TA) 3 °C (5.4 °F) sets the sales gas temperature to 30 – 3 = 27 °C (86 – 5.4 = 80.6 °F). Table 3 indicates that increasing the inlet pressure, up to the cricondentherm pressure of about 4708 kPa (682 psia), increases the required cold separator temperature then the cold separator temperature decreases to a minimum at -32.4 °C (-26.3 °F) at sales gas cricondenbar pressure. The “Gas/Gas” HX duty is a function of stream 4 rate and temperature (cold separator temperature). Note that the colder separator temperature results in more liquid drop out and less vapor (stream 4) rate. This may result in lower “Gas/Gas” HX duty and higher stream 5 temperature. The cold separator temperature has a big impact on “Gas/Gas” HX duty and stream 5 temperature. Therefore, streams 5 (Gas/Gas HX outlet) and 7 (Chiller outlet) temperature and their HFT (less the margin) determine the MEG injection rate.

Figure 3 presents the impact of inlet pressure (and the corresponding cold separator temperature) on the MEG injection rate of streams “EG1” and “EG2” upstream of “Gas/Gas” HX and the Chiller, respectively. As the inlet pressure increases, stream 7 temperature initially increases and then decrease. The required MEG injection rate of stream “EG1” remain relatively constant but reduces at the maximum pressure (minimum cold separator temperature) at which stream 5 temperature is 2.7 °C (37 °F). Stream “EG2” rate initially decreases and then increases at higher pressure. The total MEG injection (EG1 + EG2) rate stays the same. The calculated “EG1” and “EG2” were summed up and presented in Figure 3.

Figure 3. Impact of the inlet feed gas pressure on the MEG injection rate upstream of “Gas/Gas” HX (EG1) and Chiller (EG2) (See an alternative figure in the Appendix)

“Gas/Gas” HX cools stream 2A temperature to stream 5 and reduces the required chiller duty. Except for high inlet pressure, typically the “Gas/Gas” HX removes about 70% of the total required cooling duty to meet the specified sales gas dewpoint temperature. Therefore, the chiller duty decreases resulting in lower compressor power, decreased propane refrigerant circulation rate, and reduced propane refrigerant condenser duty requirements.

Both Chiller and “Gas/Gas” HX duties depend on the cold separator temperature. The “Gas/Gas” HX duty also depends on vapor stream 4 rate which decreases with the cold separator temperature. The net effect is an increase in the Chiller and “Gas/Gas” HX duties with the inlet pressure increase. As the chiller duty increases, the compressor power and condenser duty increase, too. Figures 4 A and B illustrate the impact of inlet pressure on the compressor power (K-101 and K-102), “Gas/Gas” HX, Chiller, and condenser (AC-100) duties in SI and FPS system of units, respectively.

Figure 4A. Impact of the inlet feed gas pressure on the Gas/Gas HX, chiller and condenser duty, and compressor power (See an alternative figure in the Appendix)

Figure 4B. Impact of the inlet pressure on the Gas/Gas HX, chiller and condenser duty, and compressor power (See an alternative figure in the Appendix)

To meet pipeline inlet specifications, the sales gas was compressed to 10,000 kPa (1450 psia) in K-103 and cooled to 40 °C (104 °F) in E-100 (located at the lower left corner of Figure 1). Similarly, the deethanizer overhead gas was compressed in K-100 and cooled in E-101 (located at the top of Figure 1) to the stream “2 Wet” pressure and temperature. Figure 5 A (SI) and B (FPS) present the impact of inlet pressure on the required pipeline and recycle compressors powers and the cooler duties for the recycle and pipeline gases.

Figure 5A. Impact of the inlet pressure on the pipeline and recycle gas compressors powers and coolers duties

Figure 5B. Impact of the inlet pressure on the pipeline and recycle gas compressors powers and coolers duties.

Figure 6 presents the impact of inlet pressure on the liquid propane and total liquid rate from deethanizer bottom. Figure 7 presents the impact of inlet pressure on the liquid propane percent recovery (ratio of propane rate in deethanizer bottom to total propane rate in the plant inlet feed gas). It looks like one would want to operate below about 7000 kPa (1015 psia), which is about 10% less than the cricondenbar.

Figure 6. Impact of the inlet pressure on the liquid propane total liquid rate from deethanizer bottom

Figure 7. Impact of the inlet pressure on the liquid propane percent recovery (rate of liquid propane/rate of propane in inlet gas)

Summary:

This tip demonstrated the impact of inlet pressure on the performance of mechanical refrigeration for a HCDP control plant and the following observations were made.

►The cold separator temperature (chilling temperature) is the key design variable and has a significant impact on the performance of mechanical refrigeration.

►The relation between the inlet pressure and the required cold separator temperature to meet the required sales gas specification is nonlinear and complex; therefore, the knowledge of sales gas phase envelope is essential (see Figure 2 and Table 3).

►To minimize the cost, typically the optimum inlet pressure for a mechanical refrigeration process is close to the cricondentherm pressure of sales gas. However, the sales gas pressure and the recycled deethanizer overhead gas compression should be considered.

►The inlet pressure to the HCDP facility cannot exceed the cricondenbar of the sales gas phase envelope.

►Above 7837 kPa [1136 psia] this gas could not be processed in a mechanical refrigeration plant to meet the HCDP specification. This is because at higher pressures you cannot condense enough liquid to meet the specification. One may want to operate below about 7000 kPa (1015 psia), which is about 10% less than the cricondenbar.

To learn more about similar cases and how to minimize operational problems, we suggest attending our G4 (Gas Conditioning and Processing), G5 (Practical Computer Simulation, and Applications in Gas Processing) courses.

By: Mahmood Moshfeghian, Ph.D.

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References

1. Campbell, J.M., “Gas Conditioning and Processing, Volume 2: The Equipment Modules,” 9^th Edition, 3^rd Printing, Editors Hubbard, R. and Snow–McGregor, K., Campbell Petroleum Series, Norman, Oklahoma, PetroSkills 2018.

2. Campbell, J.M., “Gas Conditioning and Processing, Volume 1: The Fundamentals,” 9^th Edition, 3^rd Printing, Editors Hubbard, R. and Snow–McGregor, K., Campbell Petroleum

3. Moshfeghian, M.,http://www.jmcampbell.com/tip-of-the-month/2019/06/impact-of-temperature-approach-of-the-heat-exchangers-on-the-capex-and-opex-of-a-mechanical-refrigeration-plant-with-meg-injection/, PetroSkills -John M. Campbell Tip of the Month, April 2019.

4. UniSim Design R443, Build 19153, Honeywell International Inc., 2017.

Appendix

Figure 3. Impact of the inlet feed gas pressure on the MEG injection rate upstream of “Gas/Gas” HX (EG1) and Chiller (EG2)

Figure 4A. Impact of the inlet feed gas pressure on the Gas/Gas HX, chiller and condenser duty, and compressor power

Figure 4B. Impact of the inlet feed gas pressure on the Gas/Gas HX, chiller and condenser duty, and compressor power

Part 3 – Planes, Trains and Automobiles

Introduction: What are the “Other” Options for Transportation fuels

Part 2 of this Tip of the Month examined what are possible options to renewable energy for power generation that could result in meeting the Paris Accord and maintain the standard of living that industrialized nations have come to enjoy.  This tip, Part 3, will focus on what are possible options for transportation fuels, and how do they compare overall in terms of reliability/cost and carbon footprint.

Technical solutions for alternative fuels for transportation are available, but the question becomes are they economic, available in the supply required, and do they actually result in a “net” reduction in carbon emissions.  This tip of the month will review and compare the options available to date.

The Biggest Challenge: Flight

Airplanes are by far the most challenging in terms of finding adequate energy density alternative fuels.  Electric power for commercial aircraft is impossible with today’s’ battery technology.  It will likely remain so for many years unless there is some disruptive technology breakthrough that greatly increases the energy density of batteries to allow them to support flight.  The only alternative that may be a replacement is bio-fuels.

Lufthansa has been researching and testing alternative fuels for flight since 2011 with Neste. Bio-fuels have been tested on 1,187 Lufthansa flights between Frankfurt and Hamburg in recent years.  In October of 2019, Lufthansa committed to using the Neste MY Renewable Jet Fuel^TM on flights departing Frankfurt International airport [1].  The renewable jet fuel is made from wastes such as used cooking oil and requires that it be blended with conventional fossil fuels for flight.  Neste’s estimated renewable jet fuel capacity is 100 000 tons annually. A reduction in CO₂ emissions of roughly 80% is achieved using the bio-fuel as compared to traditional hydrocarbons [2].

In January of 2020, JetBlue announced that it would become the first U.S. airline to offset emissions from all of its domestic flights, aiming to be carbon neutral by July 2020 [3].  However, their primary approach is investing in projects that offset their CO₂ emissions from their operations. The company will earn carbon credits by investing in solar and wind farm projects, landfill methane capture projects, as well as opportunities that protect forests from destruction.  To achieve their offset goals, they will be working with sustainability consultants EcoAct and South Pose, as well as Carbonfund.org Foundation.  JetBlue may also purchase Neste MY Renewable Jet Fuel^TM mixing between 25 – 40% with conventional fuel for their flights from San Francisco [3].

Alternative biofuels have been technically demonstrated, but they are unlikely to meet the emission reduction goals as outlined in CORSIA (Carbon Offsetting and Reduction Scheme for International Aviation).  CORSIA aims for the airline industry to cap carbon output to 2020 levels and to cut emissions to half of those in 2005 by 2050.  There is limited production capability of alternative fuels, and it is unlikely that production capacity and feedstock limitations could be resolved as quickly as global demand is increasing.

The U.S. Energy Information Administration’s, International Energy Outlook 2019, is projecting massive growth in global demand for jet fuel, with the demand steadily increasing through 2050.  Jet-fuel consumption rate is projected to grow faster in countries that are not members of the Organization for Economic Cooperation and Development (OECD), primarily in China and other Asian non-OECD countries as is shown in Figure 1 [4].  This will be driven by greater demand for passenger air travel and freight air transport.  Jet fuel consumption is being projected to increase at a faster rate than any other liquid transportation fuel through 2050 [4].

Figure 1. Global Jet Fuel Projections to 2019 [4]

Locomotives… I think I can…I think I can…

Alternative fuel solutions for trains (locomotives), are either LNG or electric. In 2018, Reganosa provided the LNG for Europe’s first LNG-fueled pilot locomotive test.  The pilot test ran on a 20 km (12.4 mi) section from the Feve diesel train depot to Figaredo, in Asturias [5].

In 2015, the Florida East Coast (FEC) Railway began testing operations on LNG-fueled locomotives.  In 2017, FEC Railway converted its entire line-haul locomotive fleet to run on LNG fuel.  The new 24-unit fleet consists of 12 pairs of back-to-back GE ES44ACs with a purpose-built Chart Industries fuel tender in-between [6].

For electric-powered locomotives, the reduction in CO₂ emissions is predicated on WHERE the batteries are manufactured, AND the power generation type used to charge the batteries.  Unless the trains are in Norway (primarily hydro-electric), or possibly France (largely nuclear power), that is not a winning CO₂ reduction solution for Europe or the United States at this time over 75% and 85% respectively of the energy is derived from hydrocarbons.

Automobiles… beware of false profits

Electric vehicles (EVs) are currently being promoted as being the end-all solution to the current “Green” energy economy globally.  Granted, they might be at the cusp of competing with internal combustion engines (ICEs) in terms of cost (Figure 2) [7].  The reduction in pollution emissions where the car is being driven is significant (reduction in not only CO₂, but NO_x and SO_x), but it does not take into account the entire vehicle life-cycle CO₂ emissions.  The net CO₂ footprint depends upon where the car was manufactured (and what type of power generation that country utilizes) and the type of power generation used to charge said vehicle.  Most batteries come from China, Thailand, Germany, and Poland that rely on non-renewable energy sources like coal for electricity.  It is very difficult to compare all vehicles by the tailpipe CO₂ emissions on a consistent basis.  One must consider the cradle-to-grave emissions of the vehicle, from manufacture to disposal to estimate the true carbon footprint.  As discussed in the December 2019 TOTM [8,9], making a 500 kg (1100 lbm) battery for a sport utility vehicle will emit 74% more CO₂ than making a car with internal combustion [9].  The majority of countries around the world still depend upon coal-fired power generation, as a result, with the exception of very few countries (France – Nuclear Power, and Norway – Hydroelectric Power), electric vehicles do not result in a net CO₂ reduction in emissions.

Figure 2. Cost of EVs and Hybrid Vehicles compared to ICE vehicles [7,8]

Another rarely discussed problem with EVs is cobalt, a needed element for current battery technology.  There is a significant human cost for today’s batteries, from iPhones, iPads, EVs, and renewable energy back-up.  Unfortunately, most people are not interested in how the products that they use are made, but just want to enjoy the benefits the technology provides to their immediate environment.

Over 50% of the worlds’ cobalt is mined in the Democratic Republic of the Congo (DRC), one of the worlds’ poorest nations.  Much of this mining is done by children “artisanal” miners, which use no pneumatic tools or diesel draglines.  A typical EV battery requires between 4.5 – 9 kg (10 – 20 lbm) of cobalt.  The demand for cobalt is forecasted to triple by 2025.  In 2016, corporate concerns increased after a report from Amnesty International identified two dozen electronics and car companies that had failed to do enough to ensure that their supply chain did not include cobalt produced from child labor [10].  The problem is complex, as the DRC is economically dependent upon mining, and companies choosing not to do business there will likely make the populations living situation worse.  But faced with severe corruption problems, it remains to be seen how the DRC can implement the required changes to mitigate the child labor issues.

The Natural & bio Gas Vehicle Association (NGVA Europe) is promoting Natural Gas Vehicles (NGV) and have been making significant strides towards their goal of using 20% alternative fuels by 2020 (CNG) and LNG. This organization started with the LNG Blue Corridors beginning with 50 LNG stations when launched.  Today there are 155 LNG stations, 51 000 passenger vehicles, 8 100 light commercial vehicles, 159 CNG trucks, and 1 642 LNG vehicle registrations.   The goals for the natural gas fleet development are shown in Figure 3 [11].

Figure 3. NGVA Europe – Goals for Natural Gas Vehicle Fleet in Europe [11]

In the U.S., NGV America estimates that there are 175 000 NGVs, and more than 23 million worldwide.  In the states, there are roughly 1600 CNG and 140 LNG fueling stations, as well as over 50 different vehicle manufacturers that can produce 100 different models of light, medium and heavy natural gas vehicles.  It is estimated that heavy and medium duty vehicles are the number one source of smog.  Heavy-duty vehicles (short-haul / long-haul / refuse trucks, school/transit buses) produce nearly 50 percent of all smog-precursor emissions and 20 percent of all transportation greenhouse gases [12].  Table 1 provides an estimate on the lbs of NOx reduced for heavy duty vehicles as reported by NGVA, and calculated by Argonne National Laboratory Heavy-Duty Emissions Calculator [13].

Table 1. Pounds of NO_x Reduction Comparison for HDVs versus Standard Diesel Engine [13]

The big story with NGVs is the energy value or price differential of the fuel as compared to gasoline or diesel.  Granted, new NGVs are more expensive (including engine conversions) than traditional vehicles, but the cost is offset by the price of the fuel.  Figure 4 provides a fuel cost comparison for Europe [11], while Table 2 provides cost comparison data for the United States.

Figure 4. Energy value / costs of different transportation fuels [11]

Table 2. U.S. Clean Cities Alternative Fuel Comparison [14]

The energy content of liquid fuels differ from one another, thus the price paid per gallon is not consistent for easy comparisons.  Table 2 provides liquid fuel prices normalized to an energy-equivalent basis for easy comparison.  From July 2019 to October 2019 in the U.S., CNG national average cost was roughly $0.48 less than gasoline, and $0.59 less than diesel. The LNG national average was $0.39 less than diesel [14].

Maritime Fuels

Marine transport has been a significant focus for LNG use as a fuel due to the establishment of marine Emission Control Areas (ECA), where the level of particulate emissions and SOx and NOx are strictly controlled.  Well established ECAs are on the coasts in the Baltic and northern European waters and the USA east and west coast.  Very soon the Mediterranean Sea will be similarly controlled.

In addition, January 1, 2020, the sulfur limit applicable to all marine fuels used across the world (excepting those ships using exhaust gas cleaning equipment or alternative fuels) was reduced from 3.5% to 0.5%.  As a result, in recent years there has been a significant increase in LNG-powered ship operation, as well as new ships ordered.

In 2019, there were roughly 143 LNG-powered vessels as compared to approximately 120 vessels in 2017.  An additional 135 LNG powered vessels were placed on order, and there were an additional 135 LNG-ready ships either in operation or on order [15].

The types of ships which are considered candidates for using LNG as a fuel include:

►Tugs and supply boats which operate from a base and can be easily refueled each day from tanker trucks.

►Container and cruise ships that call at ports within ECAs. These ships require more fuel, as much as 500-1000 tons of LNG, making refueling from tanker trucks virtually impossible resulting in the development of LNG bunker ships.

►Offshore service ships and boats for Oil and Gas production platforms

With that said, LNG bunkering for maritime ships is positioned to become big business.  The projection from Shell LNG 2019 is that in 2030, the demand for Marine LNG will be 20 mtpa.

Summary

This tip of the month summarized some of the alternative fuel options for transportation.  Bio-diesel and bio-natural gas are great alternatives, however, there is insufficient supply to provide the world’s transportation fuel demands.  Out of all of the technically feasible options proven today, natural gas provides the cleanest alternative in comparison to current liquid fuel usage for nearly all types of transportation, with the exception of flight.  Clearly bio-jet fuel is a great solution, however, significantly more production must be developed quickly.  Given the projections in the increase of jet-fuel demand it will be unlikely to be resolved with bio-jet fuel alone.  The next, and final tip of the month in this series will be focused on our dependence on the petrochemical industry, which is the most challenging issue of all with going net zero by 2050.

To learn more about the global natural gas economy, we suggest attending our G2 (Overview of Gas Processing).

By: Kindra Snow-McGregor, P.E.

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References

1. Lufthansa to use Neste sustainable aviation fuel in Frankfurt, Flight Global, 2 October 2019.

2. https://www.neste.com/companies/products/renewable-fuels/neste-my-renewable-jet-fuel

3. JetBlue moves to use renewable fuel and become first carbon-neutral U.S. airline, Los Angeles Times, 06 January 2020.

4. International Energy Outlook 2019, U.S. Energy Information Reganosa provides fuel for first European LNG-fueled locomotive, LNG World, 4 January 2018.

5. https://fecrwy.com/news/blog-lng-operations/

6. U.S. Energy Information Administration, McKinsey analysis

7. Lithium Batteries’ Dirty Secret: Manufacturing Them Leaves Massive Carbon Footprint, Niclas Rolander, Jesper Starn, and Elisabeth Behrmann, Bloomberg, 16 October 2018.Hyne, Norman, Ph.D. Nontechnical Guide to Petroleum Geology, Exploration, and Production, Pennwell, 1995.

8. Natural Gas and Renewables Part 1, December 2019 Tip of the Month, McGregor.

10. Blood, Sweat and Batteries, Walt V. and Meyer, S., Fortune, 23 August 2018.

11. NGVA Report of Activities 2017 – 2018

12. Game Changer Technical White Paper, Gladstein, Neandross and Associates, May 2016.

13. https://www.ngvamerica.org/environment/

14. Clean Cities Alternative Fuel Price Report, October 2019

15. 2019 will be the year of acceleration for LNG as a Marine Fuel, Keller, P., The Maritime Executive, 2 February 2019.

Part 2 – If Renewables Can’t Get Us There, What Will? 

INTRODUCTION: What are the “Other” Options for Power Generation and Heat?

Part 1 of this Tip of the Month examined how much energy equivalence that the U.S. is currently consuming in the form of hydrocarbons, and applied an energy parity analysis to investigate how renewables compare to the energy density of hydrocarbons. Other challenges of renewable wind and solar energy were reviewed, including negative energy pricing when there is too much wind, the limitation on battery storage for base-load supply, as well as the other “hidden” costs associated with local grids that generate a significant amount of their electricity via renewable resources.

An update to Part 1, is an extreme example of the negative pricing problem that hit European markets in December of last year.  According to Cornwall Insight, a period of high wind generation and low demand led to a negative day-ahead price for power in the UK for the first time on December 9, 2019. The prices for delivery from 03:00 – 04:00 local time on the hourly day-ahead auction dropped to minus £2.84 (-$3.34)/MWh [1].

At the time of negative day-ahead delivery prices, Great Britain was receiving 1.1 GW of power through two interconnectors from the Netherlands and exporting 1.4 GW through another interconnector to France. The negative value of electricity was also experienced that day in the German, Dutch and Belgian day-ahead power markets.  German prices reached a low of -€16.09/MWh (-$18.90/MWh) from 02:00 – 03:00 local time [1].  For power generators/suppliers, this is a serious concern as they are financially at risk due to loss of revenue.  This is a much larger scale example of the oversupply / negative value pricing issue than the examples highlighted in Part 1.

Clearly, with the limitations of wind and solar due to intermittency among others, we need other viable alternatives. This Tip will focus on the following options:

1. Hydrogenation of the gas grid

2. CCS (Carbon Capture and Storage)

3. Gas displacing coal and oil (power generation)

4. New Technology and Other Options?  What do those options look like?

Part 3 of this tip will cover alternative fuels for transportation and heavy industry, and Part 4 will address the elephant in the closet, and perhaps the greatest challenge to modern society: how to attain net zero emissions.

Hydrogenation of the Gas Grid – “Blue” or “Green” Hydrogen?

The biggest question is if hydrogen is viable.  “Blue” hydrogen refers to H₂ that is produced via steam methane reforming using natural gas as the units feed stream.  It certainly has positive attributes.  When combusted, hydrogen simply produces water.  The current natural gas infrastructure could be used, there are plenty of depleted reservoirs around the world available for CO₂ Sequestration, and H₂ has a Wobbe index that is within 10% of natural gas.  Steam methane reforming (SMR) is a well understood and commonly applied technology for the manufacture of chemicals (ammonia and methanol), and for refinery operations.

The uncertainties in the viability of “Blue Hydrogen” lie in the fact that SMR has a relatively low conversion efficiency to create hydrogen (65 – 70%).  These numbers do not reflect the energy requirements for the pre-combustion carbon capture, nor the energy required to compress and inject the CO₂ into storage reservoirs.

Other challenges include leakage of the hydrogen (H₂ is more likely to leak in current infrastructure), lower energy density (1 kWh requires 0.282 std m³ of hydrogen vs. 0.091 std m³ natural gas).  One can think of this decrease in energy density as a decrease in pipeline transport capacity of hydrogen by roughly 25% as compared to natural gas.  In addition, there may be a risk of possible hydrogen embrittlement for high pressure gas distribution systems.  The technical and engineering issues require additional evaluation.

Two hydrogen projects are being conducted in the UK.  The H₂₁ project started in 2016, by Northern Gas Networks, the gas distributer for the North of England. Based on a blueprint of the city of Leeds, Northern Gas Networks concluded it was technically possible and economically viable to decarbonise the UK’s gas distribution networks by converting them from natural gas to 100% hydrogen, from “blue” hydrogen combined with CCS.  The project has been ongoing and in 2020 with additional funding and other industry partners, they will complete background testing at the Health and Safety Laboratories, Buxton. These tests will be completed on a large variety of network assets including pipes, valves and joints and  will confirm potential changes in background H₂ leakage levels. They also aim to complete consequence testing in 2020 at the DNV-GL facility at RAF Spadeadam in Cumbria. This study will involve tests to confirm any changes to safety risk under background conditions, failure and operational repair on a hydrogen gas network. Once the field trials have proven that it is safe to move forward, they are planning to hold a live trial on the gas network in 2021/2022 [2].

The other project in the UK is HyNet, also located in Northern England [3].  The project is focused on enriching their natural gas network with up to 20% H₂ for use in homes. They are studying SMR for H₂ production coupled with Carbon Capture, Usage and Storage at Merseyside. They are also investigating hydrogen transportation opportunities. They are forecasting that the full engineering design work is to kick off in early 2020. The group estimates that the widespread use of a blend of hydrogen with natural gas could save around 6 million tonnes of CO₂ emissions every year, which is the equivalent of taking 2.5 million cars off the road.

It should be noted that hydrogen generation via electrolysis of water with wind energy is possible. In some circles, this is referred to as “Green” hydrogen. This technology would fit for small hydrogen demands, but it is not cost effective nor competitive as a technology for use in generation to supply the national grids.

Carbon Capture (Usage) and Storage?

Carbon capture and storage has been practiced in a number of forms in the Oil and Gas Industry for many years.  The first application of this technology is better known as CO₂ Enhanced Oil Recovery, which started in 1972 in the Kelly-Snyder oil field in Texas [4].  Figure 1 provides a schematic of CO₂ EOR. Historically the CO₂ supply originated in naturally occurring CO₂ reservoirs.  Now, new projects are increasingly utilizing the CO₂ captured from other industrial activities.  The CO₂ is injected, dissolves into the oil and carries oil to surface.  The CO₂ that is co-produced with the oil is separated and re-injected in a continuous loop.  At the end of the CO₂-EOR project, the reservoir becomes a CO₂ storage site.

Figure 1. Schematic of CO2 EOR

In addition, the technology of acid gas injection, as pioneered by our friends in Canada has also been in practice for many years.  The first acid gas injection project was completed by Chevron near Edmonton, Canada started up in 1989 [5].  The technology started out on small volumes, but with today’s technology, very large gas rates with high downhole pressures can be achieved.  The acid gas (H₂S and CO₂) are removed from the produced natural gas using an amine contactor, and are collected at the amine regenerator near atmospheric pressure. A schematic of Acid Gas Injection (AGI) is provided in Figure 2. For oil and gas production facilities, this technology has been well established.

Figure 2. Acid Gas Injection Schematic

The world’s first large-scale carbon storage project was developed in 1996 by Statoil off the Norwegian coast, injecting nearly 50 MMscfd into the North Sea from their Sleipner gas field production [5].

The technology for CCS on industrial facilities, however, is still a relatively “new” industry and has been slow in market uptake due to the capital and operating costs associated with it.  Amine technology to remove acid gases from produced natural gas is well established.  Amine technology to remove CO₂ from combustion off-gas has a number of challenges due to the presence of oxygen (degrades solvent), SOx, and NOx.  There are only two power plants in the world that utilize CCS.

The Boundary Dam Power Station Unit 3 is the world’s first operating coal-fired power plant to implement a full-scale post-combustion carbon capture and storage system started up in 2015 [6].  In the U.S., the Petra Nova facility, a coal-fired power plant located near Houston, Texas, the largest carbon capture and storage (CCS) in the world.  The post-combustion carbon capture process started up in 2017.  The CO₂ that is removed from the power plants flue gas is then used for enhanced oil recovery [7].

The Netherlands is undergoing a major project to collect and capture the CO₂ from three of the largest industrial ports in Europe; Rotterdam, Antwerp and Ghent. This is the first project of this type in the world and represents a major investment in CCS. The project’s plan is to construct the CO₂ pipeline network in the port of Rotterdam by 2026.  Once that is completed, they are planning on constructing a cross-border pipeline to Antwerp and the North Sea port by Ghent. The CO₂ will be injected into two depleted gas fields in the North Sea [8]. This will be a project to keep an eye on in terms of progress and success.

The biggest challenge facing CCS is the costs associated with the carbon capture, and the compression, in particular, if the process is post-combustion due to the low operating pressures.

Gas displacing coal and oil (power generation)?

Natural gas is now becoming recognized as the best transition fuel whilst the necessary technologies and concepts for renewable or other technologies improve and mature.  Secondly, gas in the form of LNG is developing a strong position in marine and transportation fuels, and this will impact on oil consumption.  Natural gas in the form of CNG or LNG as a transportation fuel will be addressed in a separate Tip of the Month later in 2020.

For power generation, natural gas or LNG replacing coal can result in 50% less GHG emissions.  But recognize that if one is using LNG, then 8% of the inlet gas must be combusted to liquefy LNG  Natural gas provides roughly 80% of the world’s heat demands.  If not planned for properly, that is not a number that will be easily or quickly replaced without severe standard of living consequences.

New Technology and Other Options: What do these look like?

Biofuels and Nuclear

There are other options for power generation. Nuclear is an obvious choice, in that it is arguably cheaper than renewable options.  It is more expensive than gas or coal, but it eliminates the concerns over CO₂ emissions.  The capital costs of the projects are high, and there is uncertainty around permitting and decommissioning.  Germany has made the decision to opt-out of nuclear energy, France currently derives roughly 75% of its electricity from nuclear, but is planning to scale that back to 50% by 2035.  The Middle East are considering nuclear options, with United Arab Emirates implementing the GCC’s (Gulf Cooperation Countries) first nuclear plant.  A recent study conducted by Lazard [10], in the U.S., concluded the following range in costs levelized cost of energy (LCOE) for different energy alternatives presented in Table 1.

It should be noted that the costs in Table 1 are for generation only. It excludes the cost of integration and any costs associated for intermittent technologies.   It also does not take into account reliability or intermittency-related considerations (transmission and back-up generation costs associated with wind and solar).  The assumption for the Solar Thermal Tower with Storage includes a battery with only 10 hours of storage.  The Solar PV (photovoltaic) Utility-Scale cost options assume a 30 MW system with no storage capacity.

Biofuels could be an option as well, but the supply of biofuels is insufficient to meet baseload energy demands.  It can fit in the appropriate locality, but it is not a slam dunk alternative to natural gas.

Table 1. LCOE ($/MWh) for Alternative and Convention Power Production Options [10]

New Technology and Other Options: What do these look like?

Pyrolysis, Carbon Hub and NetPower

Scientists of Karlsruhe Institute of Technology (KIT) and the Institute for Advanced Sustainability Studies (IASS) in Potsdam have succeeded in using natural gas in a climate-neutral way. Their process is based on methane splitting, “pyrolysis”, using a liquid metal tin catalyst. Methane is continuously fed from below into a column of liquid tin kept at very high temperatures, up to 1200 °C [~2200 °F].  Pyrolysis is the thermal cracking of methane to produce hydrogen and solid carbon, effectively eliminating the need for CCS. This represents significant cost savings and makes hydrogen generation possible in locations, such as Spain, that do not have access to depleted gas reservoirs. Pyrolysis technology has been known for years, but with the older technologies, the reactors would plug with the produced carbon fines making the technology impractical for commercial applications. The new process developed by KIT does not plug and provides a carbon by-product that is valuable which can be re-used and repurposed [11]. In December of 2019, KIT announced that it is partnering with Wintershall Dea to further develop this process to an industrial scale, with the goal of having this work completed within the next three years [12].

Solid carbon or natural graphite is on the EU’s critical raw materials list and has been since the list’s creation in 2011. Europe imports nearly all of its graphite. China is the worlds’ largest supplier of graphite. Primary purposes are for steel making, but it also feeds into high-tech industries such as Li-ion battery production. In addition, graphene is becoming of great interest to many countries. Graphene s a two-dimensional atomic crystal made up of carbon atoms arranged in a hexagonal lattice. It can be thought of as a giant molecule that can be chemically modified, with potential for a wide variety of applications, ranging from electronics to composite materials. The Graphene Flagship project, worth €1bn ($1.12bn) in the EU is the largest research and development initiative to date [12].

Rice University has launched Carbon Hub, which was inaugurated by Shell with a $10 million dollar commitment. Carbon Hub will fund $100 million on research to efficiently deploy energy technologies that result in zero-emissions. The research team includes more than 70 researchers from 20 universities, national laboratories and research institutes. The research is focused on splitting hydrocarbons to produce hydrogen fuel, and solid carbon materials that can be used as building materials, components for cars, clothing, and more [14]. This research sounds very much like the work being conducted by KIT and Wintershall Dea. These two organizations will be ones to watch in the future, as this technology appears to be very competitive and can supply not only clean energy, but also a source for petrochemical feed stocks that the modern world has grown dependent upon.

The last new technology that I would like to review is NetPower. The process uses the Allam cycle, named after the technology’s lead inventor, Rodney Allam. The process flow sheet is shown in Figure 3. Natural gas is combusted with pure oxygen, and uses super-critical CO₂ as a working fluid in a semi-closed loop to drive a combustion turbine. Its byproducts are liquid water, pipeline-ready CO₂, and argon and nitrogen, which could also be sold as commodities [14].

Figure 3. Net Power Schematic, Courtesy of Net Power

In 2018, the company has a started up a pilot plant near Houston, which can generate 50 MW of electricity.  They have plans to scale this facility up to commercial power plant capacity of 300 MW as soon as 2021.  This is another alternative technology that has significant potential in terms of the equivalent energy density of hydrocarbons and eliminating CO₂ emissions [14].

SUMMARY

This tip of the month explored some of the current options being investigated to provide a clean energy solution in light of the global concerns over climate warming. It focused only on the aspects for heating and power generation. Two additional tips will be forthcoming that will review alternative solutions for transportation, and what can be done to improve our dependence on the Petrochemical industry.

To learn more about the global natural gas economy, we suggest attending our G2 (Overview of Gas Processing).

By: Kindra Snow-McGregor, P.E.

References

1. Negative Auction Prices Hit European Generators, Natural Gas News, 18 December 2019.

2. www.H21.green

3. https://hynet.co.uk/

4. Hyne, Norman, Ph.D. Nontechnical Guide to Petroleum Geology, Exploration, and Production, Pennwell, 1995.

5. Acid Gas Injection – The Next Generation, John J. Carrol, Gas Liquids Engineering, Ltd., Calgary, Alberta Canada.

6. The Pursuit and Advancement of Carbon Capture and Storage, J. Romeo, Power, 3 March 2019

7. Petra Nova is one of two carbon capture and sequestration power plants in the world, EIA, 31 Oct 2017

8. Empty North Sea gas fields to be used to bury 10m tonnes of CO₂, D. Boffey, The Guardian, 9 May 2019

9. BP Statistical Review of World Energy 2019, 68^th Edition

10. Lazard’s Levelized Cost of Energy Analysis – Version 11.0, https://www.lazard.com/media/450337/lazard-levelized-cost-of-energy-version-110.pdf

11, Pyrolysis lifts prospects for hydrogen from natural gas [Brussels Conversation], Natural Gas News, 27 June 2019.

12. KIT and Wintershall Dea collaborating to develop industrial-scale methane pyrolysis for CO2-free production of hydrogen, Green Car Congress, 05 December 2019.

13. Shell and Rice University partner on hydrocarbon-based zero-emissions technologies, World Oil, 11 December 2019.

14. https://www.netpower.com/technology/.

Part 1 – The United States Today & the Energy Parity of Renewables

Where is the United States Today?

In response to the Paris Climate Change Accord, many countries in the European Union are enacting climate policies to meet the agreements in the Paris Accord and mitigate and reduce GHG (Green House Gas) emissions.  The overall goal is to achieve net-zero GHG emissions by 2050. To many, this is interpreted as moving towards a hydrocarbon free economy. For example, Italy just imposed an offshore exploration moratorium for oil and gas permits to focus on renewables instead [1]. The Netherlands is “Going off gas”, with Groningen being completely closed by 2030[2], and the country to be completely gas free by 2050.

In the United States, a group of 24 U.S. state governors has decided to require their states to adopt policies in an effort to meet the same goals, despite the United States pulling out of the Paris Climate Accord agreement. In becoming an Alliance member, states commit to [3]:

► Implement policies that advance the goals of the Paris Agreement, aiming to reduce GHG emissions by at least 26-28 percent below 2005 levels by 2025.

► Track and report the states’ progress to the global community in appropriate settings, including when the world convenes to take stock of the Paris Agreement.

► Accelerate new and existing policies to reduce carbon pollution and promote clean energy at the state and federal level.

This is in direct opposition to the current President’s position. Additionally, in opposition to the fact that the United States has become the world leader in energy production [4].

The question becomes, are these goals consistent with the environmental objectives, and the quality of life that major populations have come to enjoy and expect?

Today’s reality: hydrocarbons (oil, coal and natural gas) supply 85% of the global energy demand. Refer to Figure 1 – Energy Use by Source.

Twenty years ago, hydrocarbons provided roughly 87% of the global energy demand. During that time period, the world’s energy use increased by 50%.  This is roughly equivalent to adding all of the 2017 OECD countries over that time period. (Organization for Economic Co-operation and Development, and includes the US, EU, and Japan). In 2018, wind and solar PV (Photovolatic) provided only 4% of the world’s total energy demands.  Primary energy consumption grew at a rate of 2.9% – nearly doubled it’s 10-year average. This was the fastest growth since 2010.

2018 fuel consumption growth driven by natural gas which contributed 40% of the increase – all fuels grew faster than their 10-year average, apart from renewables, but they accounted for the second largest increment to energy growth

China, the US, and India accounted for more than two-thirds of the global increase in energy demand – with the US consumption expanding at its fastest rate in 30 years.  Renewables grew by 14.5% slightly below their historical average.

Figure 1. 2018 Energy Use by Source

Given the current Paris Accord goals some are trying to meet by 2050, it is highly unlikely that those goals will be achieved due to the current technology capabilities that we have. In fact, between population growth and per-capita energy demand CO₂ emissions actually increased last year in most nations. This was largely a result of the increase in energy consumption. See Figures 2 and 3.

Figure 2. CO₂ Emissions are growing                

Figure 3. CO₂ Emissions by Country

The European Union is close to achieving its targets through policy. However, there has been a price to pay as a result in terms of consumer cost. Their emissions remained flat for 2018. The U.S. emissions have largely been going down, but that is largely attributed to natural gas replacing coal. Despite many countries’ best efforts to reduce their carbon emissions, these reductions cannot counteract the amount of CO₂ emissions that are greatly increasing from China and India as their economies modernize. Refer to Figures 3 and 4.

In terms of global CO₂ emissions, in 2018, China alone represented 33% of the total, which is roughly equivalent to the combined emissions from the United States and Europe.

Figure 4. Largest CO₂ Emission Locations 2018 [4]

Forgotten History in the United States

The U.S. first started producing oil in 1859 in Titusville, Pennsylvania.  The demand for oil in the U.S. outpaced what local supply could deliver, and thus the U.S. became dependent upon imports from the Middle East. After WWII, in 1948 the allied powers carved out land in the British territory of Palestine to create the state of Israel to serve as a homeland for disenfranchised Jews. Many Middle Eastern countries were not happy with the agreement, which is still a source of much tension today.

The Yom Kipper War in 1973 Egypt and Syria attacked Israel. Russia started sending arms to Egypt and in response, U.S. President Nixon started supplying arms to Israel. Due to Nixon’s military support to Israel, OPEC (Organization of Petroleum Exporting Countries) reduced production and proclaimed an oil embargo of the United States. The oil embargo created a significant energy crisis in the U.S. This had a lasting impact – various acts of legislation during the 1970s sought to redefine America’s relationship to fossil fuels and other sources of energy.

As part of the movement toward energy reform, efforts were made to stimulate domestic oil production as well as to reduce American dependence on fossil fuels and find alternative sources of power, including renewable energy sources such as solar or wind power, as well as nuclear power.

The Carter Administration funded the Eastern Gas Shales Project (EGSP) which was aimed at increasing oil production out of Appalachian and Michigan basins using fracking technology. The Appalachian basin was one of the first shale plays to be targeted for fracking experiments. Current fracking technology would not be where it is today without the research funding of the Carter administration. This is likely one of the few success stories of government funded research. The funding of the EGSP continued through 1992.

It may be useful to consider what the energy embargo did to the U.S. economy and quality of living back in the 1970s. I personally remember the gasoline lines at the gas station and my family having to limit driving as a result of the embargos. Oil prices jumped by 350%, and the higher costs quickly rippled through the economy. Business and government asked consumers to help by conserving energy, the government was working on solutions but the economic crises worsened. As a result of the high cost of energy, the cost of living increased significantly. This resulted in massive lay-offs of workers and inflation became problematic. During that time, it appeared that perhaps the American dream was dead.

Fortunately, the fracking research that was initiated during the energy crises is the foundation of the shale gas boom that the US started experiencing in roughly 2010. As a result, today the United States is the world’s largest oil and gas producer.

Figure 5. U.S. becomes largest global oil producer [5]

In addition, in 2018 the U.S. became the worlds’ fourth largest LNG exporter [4]. This is a starkly different outlook than reality in the U.S. energy supply 48 years ago. The U.S. Climate Alliance would like to see the energy mix be supplied with alternate resources. Is this a realistic expectation?

What are the Goal Posts & How Big is BIG? 

In 2018, 85% of the energy consumed in the U.S. was hydrocarbon based.  Roughly 1939 million tonnes of oil equivalent of US energy demand is hydrocarbon based – it should be noted that a tonne of oil is roughly equivalent to 6.84 barrels of oil. Thus, the hydrocarbon energy consumed is equivalent to 13,270 million barrels of oil.

So what does this mean? If you were to put this amount of oil in actual barrels and laid them end to end on the ground they would wrap the circumference of the earth 282 times!

It is a significant number. The U.S. electrical power generation in 2018 was roughly 4,460 terawatt hours [4]. This energy value converted into million barrels oil equivalent, is 2,490 million barrels of oil, or roughly 18% of the total 2018 U.S. energy consumption⁴. Thus, converting all electrical power generation to renewable energy would not be sufficient to achieve the stated green house emission goals. Further cuts would be required in energy consumption.

The question becomes if not hydrocarbons, then what else? Is renewable energy a realistic alternative?

The Elephant in the Room – How Will We Get There?

It is interesting that the European Union and the U.S. are taking two different approaches in attempting to solve the carbon crisis. In Europe, they are investing in research looking at what the alternatives are and developing new technologies. In addition, they are attempting to assess the various energy economy change cost implications [6, 7]. In the U.S., individual states are attempting to implement their own regulations. This Tip of the Month is only going to focus on the Renewable electric power generation options. Part 2 will focus on the other topics listed below.

The possible options are listed below:

► Increase in renewables

► Hydrogenation of the gas grid

► CCS (Carbon Capture and Sequestration)

► Gas displacing coal and oil (power gen and transportation)

► New technology???  What are those options?

Increase in Renewables – How Do They Stack Up? Energy Parity with Oil

There has been a significant push in the U.S. to invest in renewables, and many Americans have the misconception that our energy needs with our current living standards can be meet with wind turbines and solar.

Onshore Wind Turbines

Assuming a typical onshore wind turbine with a 3 MegaWatt (MW) capacity and 40% efficiency (on the high end), that turbine would produce a net equivalent of 17 barrels of oil per day. Note the Betz Limit is the physics boundary for a wind turbine, the maximum efficiency a turbine could capture is roughly 60% of the kinetic energy from wind) [8]. This calculation assumes 1 bbl of oil is equivalent to 1.7 MW of energy, which is a typical value for a 22 API crude.  Assuming the wind blew 24 hours a day (overly optimistic), said wind turbine would produce 17 bbls oil per day. See conversion and Figure 6 below.

Figure 6. Onshore Wind Turbine Energy Parity Comparison – Production Per Day

Considering a rough installed cost of $1.3 million dollars.  Some say that averaged over a years period solar and wind only provide energy 25 – 30% of the time.  In todays dollars, the maximum net revenue produced by the wind turbine would be 17 bbl x $58 per bbl x 0.30 availability ~ $300 per day energy equivalent generation to crude oil.  In comparison, the cost to drill a single shale well, that could produce 10 bbls of oil per hour, averaged over a decade, there is no comparison between the energy density between  the two options. The differences in the rate of return and energy production is significant.

Offshore Wind Turbines

Offshore wind turbines are incredibly expensive given the technology and the investment to build them and bring the high power transmission lines via sub-sea. Assuming a typical offshore wind turbine with a 8 MW capacity, a 40% efficiency, and that the wind blew 24 hours a day, that turbine would produce a net equivalent of 45 barrels of oil per day. Wind turbines do not have 100% availability factors.  See conversion below and Figure 7 below.

In 2014 offshore wind turbine cost have been estimated to be in the range of $2.8 million dollars per MW [9]. We can use this number as a rough example.  For an 8 MW turbine, the installed costs would be $19 million dollars. Again, assuming 30% availability, the equivalent energy produced for that investment would be in the range of $780 per day. That investment would never payout unless the cost of the energy were to increase significantly.

Figure 7. Offshore Wind Turbine Energy Parity Comparison – Production Per Day

Solar

Solar power is hard to give a definitive energy parity conversion to, as it is strongly dependent upon where the panels are installed and what the average radiation levels are at that location. Assuming a square meter panel has a 1000 kWh/year generation per square meter and a 26% efficiency (typical), it will generate roughly 710 Wh per day [10]. It should be noted that the physical limit of PV efficiency is the Shockley Queisser Limit which is 34% [8]. See conversion below:

Solar is by far the least cost effective nor efficient way to generate baseload energy requirements. It would take 10 000 square meters, 107,640 ft² of solar panels to produce the energy equivalency of 4.2 bbls of oil per day. Note that surface area required is equivalent to roughly 2.5 football fields. See Figure 8 and conversion below:

Figure 8.  Energy parity of solar to crude oil

Given these parity values, it should be very clear that there is a limit to which renewables can displace hydrocarbons out of energy use alone.

For example, if one were to invest in $1 million dollars of each technology would produce the following kWh over a 30-year operating period [11].

Table 1. Hydrocarbon versus Renewable Investment Comparison [11]

The shale well produces roughly 600% more electricity for the same capital spent. The huge disparity is a direct result in the differences in energy density of the technologies.

LCOE Comparisons – Beware of False Prophets

There have been a number of studies that show the cost of renewable energy is falling rapidly. The levelized cost of energy (LCOE) is an economic assessment of the average total cost to build and operate a power-generating asset over its lifetime divided by the total energy output of the asset over that lifetime. One can think of this as the average minimum price at which electricity must be sold in order to break even over the lifetime of the project. These cost comparisons due not include the cost of transmission system modifications, battery power back up or peak shaving gas engine generators to supply the grid during periods of intermittency.

The current prices of solar and PV appear to be approaching grid parity, i.e., they appear to be approaching the same costs as a natural gas turbine co-gen power facility. Refer to Figure 9.

Figure 9. LCOE of Renewables [12]

U.S. Energy Information Agency (EIA) notes that the LCOE calculations are not applicable at renewable market penetration much above 15%. Why not? When the sun shines, power is available in surplus. It often has a negative value. This has already been experienced in two states, California and Texas.

California for example, is heavily invested in solar power. The grid operator increasingly must pay neighboring states to take the state’s excess solar electricity at a loss, and cut off power coming from solar farms, on sunny, low-demand days [13]. Despite too much installed capacity, the local building code requires all new residential construction to include solar panels, thus added an unnecessary $15 000 – $25 000 dollars to the cost of each home in an area where housing prices are already relatively high. In addition, California’s electricity prices between 2011 – 2018 increased 7 times more than the rest of the U.S..

Georgetown, Texas is a small municipality of 71,000 people, just north of Austin, Texas. In 2017 the mayor and town council decided to implement a “100% renewable” energy policy. Unfortunately, the residents of Georgetown are required to use Georgetown Utility Systems providing electricity, water, sewer, and garbage services. There are no other local alternatives. As a result, the cost of these services is not solely based on supply and demand, but are a strong function of the public policy.

To go “100% renewable”, the utility went into a 20 year, 144 MW-h supply contract with a wind turbine farm, and a 25 year, 150 MW-h contract with a solar plant. The contracted costs were higher than the average conventional generation electrical price. As a result, when the contracted power supply was in peak production, with excess capacity, the utility had to sell the excess energy production into the grid at reduced prices.

As a result, in 2018 their municipal utility was facing roughly $6.8 million shortfall from selling their excess contracted energy at a loss (energy prices are currently much lower than their 20 – 25 year term contracts). This money has to be made up by the city residents through higher electricity costs [14].  There are a number of lessons learned in the realities of the LCOE of renewables in both of these examples.

The “MYTH” of Battery Storage

Battery costs have been decreasing, but the technology is not cost effective in providing sufficient storage for large base-load demands. Wind and solar power generation cannot be dispatched when there is no wind, nor sunlight.  Averaged over a year’s period, they can provide energy 25 – 30% of the time, and often less [15]. 

For example, let’s consider Tesla, the world’s most well-known battery manufacturer. To store the energy equivalent of energy of 1 barrel of oil in Tesla batteries would require $200 000 US in batteries, which will collectively weigh 20 000 lbs [4.5 tonnes] [8]. So, despite the fact that battery prices have fallen significantly, this technology is currently not practical nor affordable for baseload storage requirements. Even a 200% improvement in battery economics will not get us to parity in terms of oil storage energy equivalence. One barrel of 22 API oil would weigh roughly 322 lbm [146 kg] and can be stored in a $20 US tank [8].

The other dirty secret of batteries is that their production leaves a massive carbon footprint where they are produced. Most batteries come from China, Thailand, Germany, and Poland that rely on non-renewable energy sources like coal for electricity.  To put this into perspective, making a 500 kg battery for a sport utility vehicle will emit 74% more CO2 than making a car with internal combustion. The average German car owner could drive a gasoline vehicle for three and a half years before a Nissan Leaf with a 30 kWh battery would beat it on carbon emissions [16]. This doesn’t include the energy it took to mine the lithium, the environmental damage from the mines themselves or the battery disposal issues.

The Other “Hidden Costs”

Changing the role of the grids existing coal fired power plants or gas turbine combined cycle plants with very high availability when operating on full load from primary to backup for wind/solar have other costs that emerge due to physical realities.

You cannot quickly turn off and on coal power gen or GTCC plants – capital costs increase efficiency decreases, in addition, cycling the plants increase wear and tear and increase maintenance costs.

In locations with a large portion of the local power supply generated from renewable energy will require flexible power generation to provide for the demand when it is inadequate or zero electricity being supplied from the renewable sources.

Now the U.S. grid has over $4 billion dollars of investment in utility scale engine drive gas generators, technology similar to those used to propel cruise ships. Most of these installations are natural gas driven, but some are fired on oil[8]. Reciprocating gas engine generators are much more flexible and have faster startup and shutdown times as compared to traditional power plant technology. For utility electricity power peaking applications, they are generally in the 20-300 MW output range[17]. These “hidden” costs are not accounted for in the LCOE energy comparisons as presented in numerous studies, again giving a false perception that renewables can replace hydrocarbons easily.

Are There Any Other Alternatives?

This Tip of the Month focused on renewables and how they may or may not fit in the U.S. power generation market. Part 2 of this Tip of the Month will focus on other technologies that may help the world achieve net greenhouse reductions while still maintaining the quality of life that we have come to expect.

To learn more about the global natural gas economy, we suggest attending our G2 (Overview of Gas Processing).

By: Kindra Snow-McGregor

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References

1. Italy imposes offshore exploration moratorium, Petroleum Economist, 26 March 2019.

2. Why the Dutch lost their faith in natural gas – and what that means for the rest of the world, Gas Transitions, 13 February 2019.

3. United States Climate Alliance, 2018 Strategy

4. BP Statistical Review of World Energy 2019, 68^th Edition

5. U.S. Energy Information Agency, Short Term Energy Outlook 2018

6. Why the Dutch lost their faith in natural gas – and what that means for the rest of the world, Gas Transitions, 13 February 2019.

7. Electrons or Molecules? We need shared parenting, Gas Transitions, 20 February 2019.

8. The New Energy Economy: An Exercise in Magical Thinking, Manhattan Institute, Report March 2019.

9. Offshore Wind Project Cost Outlook 2014, Clean Energy Pipeline

10. https://www.linkedin.com/pulse/my-17-quadrillion-plan-replace-oil-solar-power-allan-chatenay/

11. Lazard, “Lazard’s Levelized Cost of Energy Analysis, 2018, Gulfport Energy Credit Suisse Energy Summit, 2019, Cabot Oil & Gas, Heikkihen Energy Conference, Aug 15 2018.

12. Battery Power’s Latest Plunge in Costs Threatens Coal, Gas, March 26 2019, BloombergNEF

13. Why Renewables Can’t Save the Climate, M. Shellenberger, Forbers, Sept 9, 2019.

14. Texas Tax Payers Pay for Political Virtue Signaling with Costly Renewable Energy, C. Devore, Forbes, Dec 17, 2019.

15. Landon Stevens, The Footprint of Energy: Land Use of U.S. Electricity Production, Strata, June 2017.

16. Lithium Batteries’ Dirty Secret: Manufacturing Them Leaves Massive Carbon Footprint, Niclas Rolander, Jesper Starn, and Elisabeth Behrmann, Bloomberg, 16 October 2018.

17. Reciprocating Engine Generator Technology, Issue 6 Vol 121, June 9, 2017.

In 2017, approximately 31% of all the gas consumed worldwide was transported internationally. About 65% of this gas was transported via pipeline (21% of the total) and approximately 35% was transported as liquified natural gas (LNG) (10% of the total) [1].

Most of the gas transported internationally by pipeline was from Russia and Norway to Western Europe and from Canada to the US. The largest LNG importing region was in the Pacific Basin, mainly Japan and South Korea. Most of this LNG was supplied from the Middle East, Australia, Indonesia and Malaysia.

As shown in Figure 1, LNG is often the first choice for large volumes of natural gas transportation when the distances are large and when the supplier and buyer are separated by an ocean.

Figure 1. Natural gas transportation options

Figure 2 shows the overall transportation efficiency for natural gas [2].  Notice, LNG efficiency is roughly 90%. This is related to about 10 % fuel consumption for liquefaction and transportation. Notice the steep curve of the pipeline systems going from 100% efficiency at 0 distances to roughly 65% efficiency at 8000 km (4971 mile).  This is essentially the fuel gas requirements for the compression along the length of the pipeline.

Figure 2. Nominal natural gas transportation efficiency [2]

The LNG is typically stored in insulated tanks to keep it in a liquid state for longer periods. As a result of heat transfer from surroundings to the storage tank, a portion of the LNG may evaporate which is known as boil-off gas (BOG). In addition to the heat transfer, reference [3] discusses other sources or mechanisms of BOG like:

►The sloshing of cargo: Liquid Motion

►The cooling of tanks

►LNG loading and unloading conditions

►Cargo tanks pressure decrease

If the BOG is not removed from the storage tank, the tank pressure increases. The tank is designed, however, to withstand higher pressure; typical design pressure is 29 kPag (4.2 psig) and design temperature of -170 °C (-274 °F). reference [4] purposes the following alternatives for handling offshore pressure build up in the LNG tanks:

►Adequate tank design pressure

►Re-liquefaction

►Thermal oxidation i.e. combustion of the BOG gas via a burner system

►Compression

►Fuel sharing i.e. diesel + BOG combusted in a dual-fuel burner system

The descriptions of the above alternatives are presented in reference [4]. As an example, the description of fuel sharing is extracted and presented here.

“In order to match BOG generation with engine consumption for a desired load, fuel sharing can be utilized. Dual-fuel engines are capable of running on both diesel and gas, which can be used to even-out variations in gas supply or quality. With normal gas operation, around 1—5% of the pilot fuel is needed to ignite the gas. With fuel sharing, the amount of gas can be varied between around 15% and 85%, with the rest being diesel [4].”

As shown in Figure 3, reference [4] also presents a simplified system layout for BOG handling, when using two-stroke main engines and four-stroke auxiliary engines. The ideal consumption should match boil off rate (BOR), resulting in a BOG balance of zero. This is similar to a vapor recovery unit (VRU) used for hydrocarbon condensate and crude oil storage tanks.

Figure 3. Block diagram for BOG handling on an LNG carrier ship [4]

In continuing the August and October 2019 tips-of-the-month (TOTMs) [5, 6], this study was undertaken to investigate the composition and Wobbe Index (WI) of the BOG in an LNG carrier ship. The BOG composition and its WI are useful for fuel sharing. A daily BOR of 0.15 % of total LNG storage volume for an example lean/light LNG mixture containing nitrogen (1%), methane (96%), ethane (2%), and propane (1%), on the mole basis was considered. The compositions of each component in the LNG and the BOG were determined by performing two series of bubblepoint calculations: one at a specified pressure of 108 kPa (15.7 psia), another at the specified temperature of -162 °C (-259.6 °F) and the resulting BOG and LNG composition in the storage tank. The calculations involved the vapor-liquid equilibria (VLE) and the component material balances. The UniSim Design program [7] and its Peng-Robinson equation of state option for the thermodynamic package were used to perform the bubblepoint calculations.

Method 1: BOG at Constant Pressure 108 kPa (15.7 psia)

Based on the following specified data and assumptions, a detailed step-by-step VLE and material balance calculations were performed over a 10-day period.

• Step-time, one day

• LNG storage capacity, 170,000 m³ (6,004,372 ft³)

• Insulated LNG storage tank

• BOR, 0.15 vol % per day based on the total initial LNG volume

• LNG density during a step-time is constant

• BOG composition during a step-time is constant

• Initial LNG composition, mole %: N₂=1; C₁ =96; C₂ =2; C₃ =1

The mole fractions of each component in the BOG and remaining in the storage LNG tank, bubblepoint temperature, and the BOG WI were calculated and are presented graphically in the following sections.

Figures 4 and 5 present the mole fractions of CH₄ and N₂ in the BOG and in the remaining LNG as a function of the voyage days. Notice the N₂ mole fraction in BOG varies from about 0.22 to 0.167 and is considerable; typically, the upper limit is 0.20.

Figure 4. Variation of CH₄ mole fraction in the LNG and BOG with the voyage days

Figure 5. Variation of N₂ mole fraction in the LNG and BOG with the voyage days

Figure 6 presents the WI of the BOG as a function of the voyage days. The WI typical values are 45 to 52 MJ/std m³ (1200 to 1400 Btu/scf). Therefore, this BOG may be blended with a higher energy content fuel to meet the required WI specifications. More detail can be found in reference [4].

Figure 6. Variation of the WI of BOG with the voyage days

The variation of bubblepoint temperature of the storage tank LNG at a constant pressure of 108 kPa (15.7 psia) as a function of the voyage days is shown in Figure 7. Notice the bubblepoint temperature increases by about 0.8 °C (1.5 °F). Bubblepoint temperature is influenced by the light component concentration. As BOG production continues the mole fraction of N₂ in the LNG decreases from 0.01 to 0.007 which makes the bubblepoint temperature increase slightly.

Figure 8 also presents the mole fractions of N₂ and CH₄ in the storage LNG and the BOG.

Figure 7. Variation of the storage tank temperature with the voyage days

Figure 8. Variation of N₂ and CH₄ mole fractions in the LNG and BOG with the voyage days

Method 2: BOG at Constant Temperature -162 °C (-259.6 °F)

Based on the specified data and assumptions similar to the method 1, the VLE and material balance calculations were performed for the first 10-days of ship voyage. The simulation results include: the mole fractions and the amounts of each component in the BOG and in the remaining LNG, bubblepoint pressure, and the BOG WI. The results are presented graphically in Figures A1 through A5 of Appendix A.

Figure A4 in Appendix A indicates that at constant temperature, after 10 days of voyage the bubblepoint pressure reduces slightly by about 7 kPa, from 118.5 to 111.6 kPa (1 psia, from 17.2 to 16.2 psia). Over the full 10 days, the mole fraction of N₂ in the LNG decreases from 0.01 to 0.007 which makes the bubblepoint pressure decrease slightly.

Figure 9 shows N₂ mole % variation in the LNG and BOG when studied using the constant pressure and the constant temperature methods. The difference between the LNG N₂ mole % using either method is small and the maximum difference between BOG N₂ mole % is about 1 mole %.

Figure 9. Variation of N₂ mole % in the LNG and BOG; constant pressure BOG vs constant temperature BOG

Method 3: BOG at Constant Temperature -162 °C (-259.6 °F) for 1-Day Voyage (Validation)

To check the validity and accuracy of the step-time of one day, the step-time was reduced to 2.4 hours and calculations were completed for one day (10 step-time) of voyage. Based on the specified data and the other assumptions similar to the Case 2, the VLE and material balance calculations were performed for the 1-day of ship voyage. The simulation results including the mole fractions of each component in the BOG and in the remaining LNG, bubblepoint pressure and the BOG WI and are presented graphically in Figures B1 through B5 of Appendix B. Good agreements were obtained between the first day of 10-day voyage and step-time one day with the results of 1-day voyage and step-time of 2.4 hours. This confirms that the step-time of one day for these types of calculations is adequate and acceptable.

Summary

The BOG on an LNG carrier ship can be used to run the ship’s engines, auxiliary engines or to generate steam.  However, a good estimate of composition and the WI are needed for fuel sharing and to provide suitable engine fuel. Based on the work done in this TOTM, the following can be concluded:

1. Depending on the N₂ content in the LNG the WI of BOG-alone may not meet the requirements for the ship engines or the auxiliary engines. For the ten days voyage, WI varied from about 36.5 to 39.8 MJ/std m³ (979 to 1069 Btu/scf), see Figures 6 and B3. BOG may be blended with a higher energy content fuel to meet the required WI specifications.

2. Under the ideal conditions of the two BOG methods at constant pressure or constant temperature,

►the variation of cargo bubblepoint temperature/pressure was about 0.8 °C (1.5 °F) or about 7 kPa (1 psi), (Figures 7, B4 and C4).

►the difference between the LNG N₂ mole % in both methods is small and the maximum difference between BOG N₂ mole % in the two methods is about 1 mole % (Figure 9).

►BOG properties varied linearly as a function of the voyage days.

►the step-time of one day is adequate for performing VLE and material balances.

Modern membrane LNG carriers such as Q-flex (210,000 m³ LNG) and Q-max (266,000 m³ LNG) are designed for BOG recovery systems, using Hammworthy nitrogen-cycle re-liquefaction process. These modern carriers use MAN B&W 7S70 ME-C two-stroke low-speed diesel burning heavy fuel oil that is electronically controlled. This configuration avoids BOG losses in these modern carriers.

To learn more about similar cases and how to minimize operational problems, we suggest attending our G4 (Gas Conditioning and Processing), G5 (Practical Computer Simulation Applications in Gas Processing),  G29 LNG (Short Course : Technology and the LNG Chain) and G4 LNG (Gas Conditioning and Processing-LNG Emphasis) courses.

By: Mahmood Moshfeghian, Ph.D.

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References

1. BP Statistical Review of World Energy 2018

2. AA Amos, Special Report International Gas Trade: Drive to Lower Transportation Costs.” Oil and Gas Journal Volume 98, Issue 20, Pages 62-67, 15 May 2000

3. GTT (Gas Transportation Technigaz), Boil-off Clarifications, https://www.gtt.fr/en/media-center/gtt-inside/boil-off-clarifications, Jun 2019

4. B. Nygard, “Boil-Off Gas handling onboard LNG fueled ships,” https://www.wartsila.com/twentyfour7/in-detail/boil-off-gas-handling-onboard-lng-fuelled-ships, June 2019

5. KS McGregor and FE Ashford, “https://www.petroskills.com/blog/entry/00_totm/aug19-fac-a-primer-on-lng#.XWSVruNKjcc,” PetroSkills tip of the month, Aug 2019

6. KS McGregor and FE Ashford, “https://www.petroskills.com/blog/entry/00_totm/oct19-fac-useful-lng-conversions#.XacteJJKjcc /,” PetroSkills tip of the month, Oct 2019

7. UniSim Design R443, Build 19153, Honeywell International Inc., 2017

Appendix A

Method 2: BOG at Constant Temperature -162 °C (-259.6 °F)

• Step-time, one day

• LNG storage capacity, 170,000 m³ (6,004,372 ft³)

• Insulated LNG storage tank

• BOR, 0.15 Vol % per day based on the total initial LNG volume

• LNG density during a step-time is constant

• BOG composition during a step-time is constant

• Initial LNG composition, mole %: N₂=1; C₁ =96; C₂ =2; C₃ =1

Figure A1. Variation of CH₄ mole fraction in the LNG and BOG with the voyage days

Figure A2. Variation of N₂ mole fraction in the LNG and BOG with the voyage days

Figure A3. Variation of WI of BOG with the voyage days

Figure A4. Variation of the storage tank pressure with the voyage days

Figure A5. Variation of N₂ and CH₄ mole fractions in the LNG and BOG with the voyage days

Appendix B

Method 2: BOG at Constant Temperature -162 °C (-259.6 °F)

• Step-time, 2.4 hour

• LNG storage capacity, 170,000 m³ (6,004,372 ft³)

• Insulated LNG storage tank

• BOR, 0.15 Vol % per day based on the total initial LNG volume

• LNG density during a step-time is constant

• BOG composition during a step-time is constant

• Initial LNG composition, mole %: N₂=1; C₁ =96; C₂ =2; C₃ =1

Figure B1. Variation of CH₄ mole fractions in the LNG and BOG with the voyage hr; step-time of 24 hr vs step-time of 2.4 hr

Figure B2. Variation of N₂ mole fractions in the LNG and BOG with the voyage hr; step-time of 24 hr vs step-time of 2.4 hr

Figure B3. Variation of WI of BOG with the voyage hr; step-time of 24 hr vs step-time of 2.4 hr

Figure B4. Variation of the storage tank pressure with the voyage hr; step-time of 24 hr vs step-time of 2.4 hr

Figure B5. Variation of N₂ and CH₄ mole fractions in the LNG and BOG with the voyage hr; step-time of 24 hr vs step-time of 2.4 hr

The August 2019 Tip of The Month, “A Primer on LNG – What is it, Where does it fit, and The New Kid on the Block “[1] provided a high level summary of the history of LNG, from the maiden voyage of the Methane Pioneer, to the current world trade statistics for 2017 [2]. BP recently published the international LNG trade statistics for 2018 in their Statistical Review of World Energy 2019. In 2018, the international LNG trade was reported to be 431 billion cubic meters per year (BCM/yr), roughly 15.2 trillion cubic feet per year, which converts to 319 mtpa (million tonnes LNG per annum) [3]. In 2018, 20 Nations provided LNG for Export, with 42 Nations receiving the LNG at their Import Terminals [4]. The 2018 exports from the USA totaled some 28.4 BCM/yr (1 trillion cubic feet/yr) corresponding to roughly 21 mtpa [3]. This tonnage related to an average daily natural gas liquefaction rate of approximately 2.75 billion cubic feet per day (Bcfd) produced from three (3) plants, namely Sabine Pass, Corpus Christi, and Cove Point LNG. The location of these facilities are shown in Figure 1 [5]. It should be noted that the Kenai, Alaska LNG facility was not operational during this period.

As a result of the increased US LNG production, the USA rose to the fourth-largest LNG exporter in the world, following Qatar (1), Australia (2), and Malaysia (3). [3]. Only three years prior, in 2015, the U.S. did not rank as an LNG exporter (0.7 mtpa) to put the rapid growth in U.S. liquefaction capacity into perspective.

There are many published “approximate” conversions of natural gas to LNG, where simplifying assumptions that can be made to estimate “rough” numbers as presented above. These conversions are based on the approximate conversion factors as published by BP. These conversion factors are summarized in Table 1 [3].

Table 1

Approximate Natural Gas and LNG Conversions [3]

If one requires a firm understanding of their specific LNG plant operations, more detailed calculations are required for accurate results. A brief review of these common conversions and their consequences will be discussed.

Figure 1. Existing USA LNG Export Facilities [5]

Summary of Common Natural Gas to LNG Conversions   

A commonly accepted and referenced value of the decrease in volume of natural gas to LNG is roughly 600:1. This could be in the units of std m³ natural gas / m³ or conversely, scf natural gas to ft³ LNG. In reality, this conversion ratio is a function of two important variables:

 1) Natural Gas Molecular weight (MW) in kg/kmol [lbm/lbmol]

 2) Cryogenic LNG density at – 160 ºC (-260 ºF) and 101 kPa (14.7 psia) in kg/m³ [lbm/ft³]

Let’s review the calculations in detail to understand how the gas MW in kg/kmol [lbm/lbmol] and LNG liquid density change the calculated volume ratio for an operating LNG facility. The base conversions are shown below:

SI Solution:

FPS Solution:

As an example, consider a natural gas (LNG) stream with MW = 17.4 kg/kmol (lb/lbmol). Assume the LNG relative density has been determined as 0.453. The relative density of a liquid is defined as the density of the liquid relative to water at standard conditions:

The LNG cryogenic liquid density is then equivalent to 453 kg/m³ (28.27 lbm/ft³).  The conversions provided above then result in:

SI Solution:

FPS Solution:

For these types of conversions to be accurate, the cryogenic LNG density must be known. A proper Equation of State (EOS) that is designed to incorporate the non-ideal behavior of hydrocarbon liquids at cryogenic conditions must be used. As shown by Figure 2, the conversion of a typical candidate LNG feed stream, yields values in m³ std/tonne (scf/tonne) as a function solely of the feed gas MW.

It should be noted that the natural gas must be the actual “process gas” stream to the liquefaction facility and not the inlet gas to the plant, which goes through pre-conditioning to remove contaminants and heavier hydrocarbons.  Figure 3 presents the values for a typical LNG cryogenic density (-160 °C / -260 °F) and atmospheric pressure [6].   Notice that this density is by no means the reported “specific gravity” in many engineering data reference manuals for methane at standard conditions which is 300 kg/m³ (18.72 lb/ft³) [7]. This value reflects the partial density of methane in a liquid state at standard conditions when in the presence of other liquefiable hydrocarbon components, with compositions ranging from rich to lean as discussed in the July 2019 TOTM [1]. Figure 4, provides a graphical solution to determine feed gas at standard conditions std m³ (scf) to the corresponding standard LNG liquid in m³ (ft³).

Figure 2. Natural Gas to LNG Conversions as a function of MW  

Figure 3. LNG Cryogenic Density: (calculated from PS/JMC GCAP -SRK EOS )  [5] 

Figure 4. Natural Gas Standard Condition Volume to LNG Volume  

The Impact of Conversion Procedures for Natural Gas Standard Volumes to LNG Volumes  

As can be observed, there is a difference based on the actual natural gas to LNG “Standard Volume to LNG Volume” based on the gas and LNG physical properties. The plant operator/engineer, should be aware of these subtle differences. For example, if some 10 000 tonnes/d of a natural gas process stream were to be converted to LNG with properties shown above applying 600 std m³ gas /m³ LNG versus the actual 615 std m³/m³ the liquid LNG results daily yield would be: (note: tonne = 2200 lb)

Any contractual commitment based on a global relationship of gas standard volume to LNG volume should be verified by actual in-plant analysis for proper management of the sale of equivalent LNG “Energy”.  Note, a 3% difference between the two may seem insignificant, but when you consider the volumes the facilities are liquefying, 3% on say 2.75 billion standard cubic feet per day, is roughly 82 MMscfd.  For detailed engineering work, and custody transfer allocations round off errors cannot be tolerated.

LNG Parity to Crude Oil

Another interesting concept for LNG processing and subsequent export is the computation of the actual sale value of the product relative to other commonly traded fuels. Natural gas and LNG are generally traded in terms of $/MMBtu or $/TJ.  Considering that LNG is sold on an “energy” basis value, one can determine an “EQUIVALENT LNG“ sales price based on the on the variable price for a bbl of crude oil.

The average closing prices for crude oil in 2018 was $65/bbl [8]. A reasonable heating value for most hydrocarbons (either gas or liquid) can be assumed to be approximately 45 MJ/kg (19,500 BTU/lbm). If we assume a 300 lbm/STB (API = 33.6) oil sample with a specific gravity = 0.857, then the value of a bbl of oil in $/MMBTU is shown below:

Figure 5 [9], provides the market price of LNG quoted in  $/MMBTU for the Japan Cleared Customs (JCC), Korea LNG< and Japan Korea Marker (JKM) from 2013 – 2019.  Historically the Japanese and Korean LNG supply contracts have been based on a “crude oil” cocktail pricing method – i.e., the price of LNG is indexed to the value of crude oil.  The “average” JCC price for LNG in 2018 was roughly $10/MMBTU [10].  The JKM reflects pricing for “spot” trades, and as can be seen in the figure, is significantly more volatile than the long-term contract pricing.  Figure 6 [11] shows multiple deliveries of LNG throughout the world within 73% of the value of crude oil during the majority of this timeframe.  This figure represents the “spot” trading price of LNG, not the negotiated long-term contracts between individual suppliers and consumers. For 2018, assuming an average value of $10/MMBTU, the value of LNG per tonne is calculated as follows:

What Is the Cargo Value of a Typical LNG Carrier??

If a typical LNG MOSS type carrier is assumed to be loaded at port for export with some 65,000 tons, or approximately 140,000 m³ capacity the average 2018 value on board was:

The above analysis implies the MOSS LNG carrier is transporting roughly 88.4 million std m³ (3.1 Bcf), or approximately 3.1 trillion BTUs. A typical LNG MEMBRANE type carrier will accommodate some 170,000 m³, or approximately 21 % additional cargo and value.

Figure 5. Asian Import Prices for LNG 2013 – 2019 [9]

Figure 6. Global Spot LNG Market Prices $/MMBTU: Through May, 2018 [11]

“Parity Pricing” Divergence Between Crude Oil and LNG in 2019

The very unfortunate state of LNG worldwide affairs beginning in late 2018 has been a noted downturn in the “Parity Pricing” of LNG vis a vis Crude Oil prices. In 2019, the crude oil market is maintaining prices in the ranges of 60-75 $/Bbl, refer to Figure 7 [12].  World LNG sales during this time reflected a parity closer to a 50 $/Bbl crude.  Figure 8 [13] shows the integrated “Parity Pricing” of LNG vs. Crude Oil for this period. A useful parity index is the UK NBP (National Balancing Point Price) pricing index that equates energy sales based on the world’s major currencies, as shown by Figure 8.  As can be observed by the existing LNG NBP for January 2019 was fixed at some 7.50 $ /MMBTU with the Crude Oil Parity just under 11 $/MMBTU.

At the end of January 2019, however, and with less than one year’s difference, the landed value of spot market trade LNG is at an average of just above 4 $/MMBTU as shown by Figure 9 [14]. This Figure shows an extension of Figure 6, marking the further decrease in LNG prices from 6.50 $/MMBTU from the beginning of 2019. The spot market sales scenario has diminished significantly since 2018!! The situation is rather troublesome for any and all world exporters of the LNG energy commodity relying their trade on the spot market, and only time will tell if and/or when the imbalanced situation will stabilize.

The Henry HUB (Gulf Coast US) Natural Gas sales index has also fallen to some 2.37 $/MMBTU as of July 2019 [14].  It seems the balance of 2019 for all world LNG exporters as well as importers could be a very unpredictable and perhaps unstable period for this sector of the world energy commerce if they are depending upon the spot market for their sales.

The August TOTM [1] cited this delicate situation when an “oversupply” of even such an important commodity as energy laden LNG is subject to the indissoluble framework of “Supply and Demand” in the world market.  As such, with the U.S. entering the international LNG trade, new contract structures and business models are coming about, some of which are indexed to the Henry HUB pricing rather than the price of crude oil.  As can be seen by the current sport market LNG prices, we are in a situation of oversupply, however, for importing countries with extra storage capacity, this represents a huge buyers opportunity.

Figure 7: Brent and WTI Oil Spot Price through mid-2019 [12]    

Figure 8. Global LNG Market Price Compared with Oil Parity and NBP Pricing

Figure 9. Global LNG Market Prices: Through June, 2019 [14]

Conclusions:

► A brief review of the USA’s LNG Export position for the years 2017-2018 were reviewed, showing that during 2017 the US exported some 16.4 BCM/yr (0.58 tcf/yr) or roughly 12.5 mtpa [2]. The 2018 Exports from the USA totaled 28.4 BCM/yr (1 tcf/yr) corresponding to 21 mtpa  The US was the world’s 6^th largest LNG exporter during 2017, and rose to number four, following Qatar, Australia, and Malaysia during 2018.

► A numerical analysis was presented to show that the actual Natural Gas to LNG std m³/m³ (scf/ft³) is not a universal constant generally accepted as 600. The term was shown to evolve from first converting the natural gas in std m³/tonne (scf/tonne) as a function of the molecular weight of the gas, and then converting the mass to liquid applying the LNG cryogenic density. Conversions were presented graphically, and the final gas to liquid LNG ratios were shown to vary discreetly between some 15 – 20 % below and above the 600 value.

► A discussion summarizing parity of energy calculations for LNG to crude oil values was provided.  As can be seen, in 2019 there has been a divergence between the parity values of LNG to crude oil, largely attributed to oversupply in the market.

To learn more about LNG, we suggest attending our G2 (Overview of Gas Processing),  G29 LNG (Short Course: Technology and the LNG Chain) and G4 LNG (Gas Conditioning and Processing-LNG Emphasis) courses.

By: Kindra Snow-McGregor & Dr. Frank E. Ashford

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References:

1. K. Snow-McGregor , F. E. Ashford Tip of The Month, “A Primer on LNG – What is it, Where does it fit, and The New Kid on the Block,“ PS/JMC August – 2019

2. BP – Statistical Review of World Energy , 2018 ( for 2017)

3. BP – Statistical Review of World Energy , 2019 ( for 2018)

4. GIIGNL Annual Report 2019

5. https://ferc.gov/industries/gas/indus-act/lng/lng-existing-export.pdf

6. GCAP (Gas Conditioning and Processing) Computer Program – Version 9.3.2, PS/JMC – 2019

7. GPSA Engineering Data Book : 14^th Edition – 2017

8. https://www.eia.gov/todayinenergy/detail.php?id=37852

9. https://www.csis.org/blogs/energy-headlines-versus-trendlines/oil-still-drives-asian-lng-prices

10. https://ycharts.com/indicators/japan_liquefied_natural_gas_import_price

11. Federal Energy Regulatory Commission (FERC) – 2018 (Waterborne Energy, Inc. Data supplied by HIS Global Inc.)

12. https://www.eia.gov/todayinenergy/detail.php?id=37852

13. REFINITIV EIKON LNG Prices – 2019

14. Energy Information Administration (EIA) – August 2019

The main issue for cryogenic processing and transporting of a gas stream containing carbon dioxide is its frost formation. Solid carbon dioxide (dry ice) may form at low pressures when the temperature of a gas stream containing CO₂ drops below the triple point temperature of CO₂.  The triple point temperature and pressure of CO₂ are -56.57 °C (-69.83 °F) and 518 kPa (75.12 psia) respectively. Its critical temperature and pressure are 31.10 °C (87.98 °F) and 7386 kPa (1,071 psia). Frost point occurs along the solid-vapor equilibria (SVE) curve.  In addition, CO₂ is corrosive in water wet systems and it reduces the gas heating value and Wobbe Index (number). There are limits on CO₂ concentration in the sales gas and liquid products as a result. The sales-gas/transportation by pipeline specification limits the CO₂ concentration to 1 – 3 mole %. To avoid frost formation in cryogenic gas processing, removal of CO₂ is often required to meet the downstream processing requirements. Types of processing include:

► Deep NGL extraction plants: typically, less than 0.5 to 1.0 mole % depending on the process used

► LNG liquefaction plants: less than 50 ppmv

► N₂ rejection, He recovery: less than LNG feed

Therefore, it is important to estimate accurately the temperature where carbon dioxide solidifies. The solid – vapor equilibria (SVE) of natural gas systems containing carbon dioxide may be predicted accurately using simulation programs.

In continuing the April 2012 and April 2018 tip of the months (TOTMs) [1, 2], this study was undertaken to prepare simple charts for estimation of CO₂ frost temperature or pressure of binary and ternary systems containing CH₄, C₂H₆, and N₂, and CO₂. The charts present frost temperature (or pressure) of CO₂ + light hydrocarbons and nitrogen mixtures as a function of pressure (or temperature) and CO₂ concentration for a wide range of temperature from -80 °C to -120 °C (-112 °F to -184 °F). The pressure range was from about 100 kPa to 3500 kPa (14.5 psia to 508 psia) and the CO₂ concentration range was from about 0.1 to 55 mole %. For each case, the accuracy of charts will be compared with experimental data.

Figure 1 [3] presents the phase diagram for pure CO₂. Regions S, L, and V denote the Solid, Liquid, and Vapor phase, respectively. Point C is the critical point and point T is the triple point where the three phases of solid-liquid-vapor coexist. Figure 1A (FPS) is presented in Appendix A. The symbols represent experimental [4] data and the solid curves were predicted by the Nasrifar – Bolland equation of state [5].

Figure 1. Experimental [4] and predicted pure carbon dioxide coexistence curves [5]

Validation of Thermodynamic Package

To validate the accuracy of the ProMax [6] simulation program, its Peng – Robinson equation of state and Freeze Analysis Tool were utilized to predict the solid formation temperature of binary mixtures of CO₂ + CH₄ as a function of pressure and CO₂ composition. The predicted frost temperatures were compared with the experimental data. Figures 1 and 2 present the frost point temperature as a function of pressure and composition for two sets of experimental data [7, 8] and the ProMax predicted values [6].

Figure 2. Experimental [7] and predicted carbon dioxide frost points (CO₂ mole % < 11) 

Figure 3. Experimental [8] and predicted carbon dioxide frost points (10<CO₂ mole %<55)

The average absolute relative error (AARE) % for 42 frost temperatures (in K or °R) of Figure 2 predicted by ProMax compared to the corresponding experimental values [7] is 1.27%. Similarly, the AARE % for 17 frost temperatures (in K or °R) of Figure 3 predicted by ProMax compared to the corresponding experimental values [8] is 0.27%. Tables 1A and 2A in Appendix A present the point-by-point comparisons. The error analysis of Figures 2 and 3 indicates that the predicted frost temperatures by ProMax is accurate for facilities equipment design and troubleshooting.

The frost pressure for the binary system of CO₂ + CH₄ as a function of CO₂ mole fraction at a specified temperature was estimated by adjusting the pressure using the solver tool of ProMax to match the experimental frost temperature. The estimated frost pressures for six isotherms are compared with the corresponding experimental values [9] in Figure 4.

Figure 4. Frost point pressures of CO₂ + CH₄ as a function of CO₂ content at different isotherms. Experimental data are from Ref. [9].

Similarly, Figures 5 and 6 present the experimental [9] and ProMax estimated frost pressure of the ternary system of CO₂ + CH₄ + N₂ as a function of CO₂ mole fraction and five isotherms for 3 mole % and 5 mole % N₂, respectively. These two figures and Figure 6A (in Appendix A) indicate that the frost pressure is the same at a given CO₂ content and an isotherm for nitrogen content of 3 mole % and 5 mole %.

Figure 5. Frost point pressures of CO₂ + CH₄ + 3 mole % N₂ as a function of CO₂ content at different isotherms. Experimental data are from Ref. [9].

Figure 6. Frost point pressures of CO₂ + CH₄ + 5 mole % N₂ as a function of CO₂ content at different isotherms. Experimental data are from Ref. [9].

Similarly, Figures 7 and 8 present the experimental [9] and estimated frost pressure of the ternary system of CO₂ + CH₄ + C₂H₆ as a function of CO₂ mole fraction and five isotherms for 3 mole % and 5 mole % C₂H₆, respectively. These two figures and Figure 8A (in Appendix A) indicate that the frost pressure is the same at a given CO₂ content and an isotherm for ethane content of 3 mole % and 5 mole %.

Figure 7. Frost point pressures of CO₂ + CH₄ + 3 mole % C₂H₆ as a function of CO₂ content at different isotherms. Experimental data are from Ref. [9].

Figure 8. Frost point pressures of CO₂ + CH₄ + 5 mole % C₂H₆ as a function of CO₂ content at different isotherms. Experimental data are from Ref. [9].

Summary

Based on the work done in this tip, the following can be concluded:

1. For pure CO₂, as pressure increases, the frost temperature increases (Figure 1)

2. CO₂ concentration has a great impact on the mixture frost point pressure and temperature.

a. At constant pressure, as CO₂ concentration increases the mixture frost temperature increases (Figures 2 – 3).

b. At constant temperature, as CO₂ concentration increases the mixture frost pressure decreases (Figures 4 – 8).

3. At constant temperature, concentration of 3 and 5 mole % N₂ or C₂H₆ has little or no effect on the frost pressure of gas mixtures containing CO₂ + CH₄ (Figures 5, 6, 6A, 7, 8, and 8A).

4. ProMax is relatively accurate for frost point estimation for gas mixtures of light hydrocarbons and CO₂ (Tables 1A and 2A and Figures 4 – 8).

5. Simple charts are presented for accurate estimation of frost point for gas mixtures of light hydrocarbons, nitrogen and CO₂ as a function of pressure (or temperature) and CO₂ concentration (Figures 2 – 8). These charts are composition specific, similar charts should be developed for different compositions. In a future TOTM, similar charts will be presented for typical natural gas mixtures.

6. Knowledge of phase boundaries and behavior is essential for frost point calculation.

To learn more about similar cases and how to minimize operational problems, we suggest attending our G4 (Gas Conditioning and Processing), G5 (Practical Computer Simulation Applications in Gas Processing) and G6 (Gas Treating and Sulfur Recovery) courses.

Written By: Mahmood Moshfeghian, Ph.D.

References

1. M. Moshfeghian, “http://www.jmcampbell.com/tip-of-the-month/2012/04/natural-gas-with-dry-ice-phase-behavior/,” PetroSkills tip of the month, Apr 2012

2. M. Moshfeghian, “http://www.jmcampbell.com/tip-of-the-month/2018/04/impact-of-co2-on-natural-gas-density/,” PetroSkills tip of the month, Apr 2018

3. Kh. Nasrifar and M. Moshfeghian, “Prediction of carbon dioxide frost point for natural gas model systems,” Submitted for publications, May 2019

4. NIST Chemistry WebBook; http://webbook.nist.gov/chemistry/ [Cited 26 April 2019]

5. K. Nasrifar, O. Bolland, Prediction of thermodynamic properties of natural gas mixtures using ten equations of state including a new cubic two-constant equation of state, J. Pet. Sci. Eng. 51 (2006) 253-266.

6. ProMax 5.0, Build 5.0.19050.0, Bryan Research and Engineering, Inc., Bryan, Texas, 2019.

7. G.M. Agrawal, R.J. Laverman, Phase behavior of the methane carbon dioxide system in the solid-vapor region, Adv. Cryog Eng. 19 (1974) 317-338.

8. L. Zhang, R. Burgass, A. Chapoy, B. Tohidi, E. Solbraa, Measurement and modeling of CO₂ frost points in the CO₂ – methane systems, J. Chem. Eng. Data 56 (2011) 2971-2975.

9. X. Xiong, W. Lin, R. Jia, Y. Song, A. Gu, Measurement and calculation of CO₂ frost points in CH₄ + CO₂/CH₄ + CO₂ + N₂/CH₄ + CO₂ + C₂H₆ mixtures at low temperatures, J. Chem. Eng. Data 60 (2015) 3077-3086.

Cal Temp = Calculated frost temperature, K (°R)

Exp Temp = Experimental frost temperature, K (°R)

n               = Number of data points, 42

Table 2A. Comparison of ProMax predicted frost temperature with the experimental values [8]

The Average Absolute Relative Error % (AARE%) is calculated by the following equation.

Where:

Cal Temp = Calculated frost temperature, K (°R)

Exp Temp = Experimental frost temperature, K (°R)

n               = Number of data points, 17

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From Humble Unknowing Beginnings…                                    

The fabrication of a U. S. Government Cargo Ship named the Marlene Hitch, delivered during July 1945 in Duluth MN, unknowingly issued in the groundwork for the world-changing commercial activities of exporting Liquefied Natural GAS (LNG) as a viable energy source. The vessel later renamed the Methane Pioneer, shown in Figure 1, was refitted for LNG transport, and designed to carry 5000 m³ (31,450 Bbls) of LNG equivalent to some 2,335 tonnes (110 MMscf).

Her maiden voyage was from Constock’s LNG production facility on the Calcasieu River in Louisiana, carrying the world’s first ocean cargo of LNG. It left port on 25 January 1959 and reached its destination at Canvey Island in England on 20 February, taking 27 days to cross the Atlantic Ocean.

Figure 1. Methane Pioneer [1]

Since that time, the worldwide LNG Export/Import evolution has risen from an initial 10-50 million tonnes per annum (mtpa) during the 1970 – 1990 era to 100 mtpa by 2000 and doubling again by 2010 to 201 mtpa.  By 2017 the worlds Energy demand for LNG had risen to some 400 billion cubic meters (14 130 billion cubic ft) equivalent to some 291 mtpa [2]. To put this into perspective, just 1 mtpa can provide roughly 7.2 billion kWh of energy (assuming a power plant conversion efficiency of 50%).  That amount of energy could provide nearly 700 000 homes in the US their annual power requirements, assuming an average demand of 10 400 kWh [3].

Now, multiply those values by 291 to estimate the energy that was traded via LNG in 2017. LNG is a significant contributor in meeting the worlds energy needs.  This is often referred to as the LNG Value Chain and is shown schematically in Figure 2.  At the most basic level, base-load LNG is a transport business that allows natural gas to be sold from suppliers that have excess reserves/capacity to consumers that are lacking adequate natural gas resources to meet their energy needs.

Figure 2. The LNG Value Chain [4]

This industry is forecasted to continue to grow for likely the foreseeable future. A forecast from Shell to 2035 is provided in Figure 3.  Note CAGR in Figure 3 is compound annual growth rate.

Figure 3. Global gas supply by source [5] 

The future of LNG appears very promising; however, many limiting criteria are present including global energy prices, contractual structures, supply and demand issues. There is a changing landscape of new LNG gas sources, including the major capital investment decisions for new base-load liquefaction facilities that will be made likely in the next few years.

What is LNG???

LNG is natural gas that has had all contaminants (primarily H₂O, H₂S, CO₂ and mercury, as well as heavy hydrocarbons) removed to allow for liquefaction at cryogenic temperatures. The LNG is stored and transported at roughly -160 ºC (-260 ºF) and atmospheric pressure.  Depending upon the inlet gas composition to the liquefaction facility, and LNG supply contracts, the produced LNG will have a range of compositions and physical properties, from rich to lean as shown in Table 1.

Table 1. Example LNG Properties

Typical LNG composition is primarily lower molecular weight Paraffins, (C₁ – C₄), with small amounts of N₂, and possibly C₅ in some instances.  The LNG composition that a country, for example, Japan, may prefer to purchase depends primarily on the local infrastructure requirements (power plants, residential, industrial needs, etc..). The composition of natural gas in utility grids around the world might range from lean to rich depending upon how the infrastructure was originally developed.  In the United States, the natural gas industry started extracting liquids (NGLs) around 1910, thus the infrastructure has been developed to burn very lean gas as most of the liquids are removed to sell in the hydrocarbon liquids commodity market.  In other locations, there is a limited demand for the liquid hydrocarbons, so in these instances, the gas in the national grid tends to be richer in heavier hydrocarbons.  Some example of global specifications for LNG import is shown in Figure 4.  If the composition of the contracted LNG supply does not meet the countries heating value requirement, the regasified LNG can be blended with heavier hydrocarbons or nitrogen at the receiving terminal.

Figure 4. Example LNG Heating Value Specifications [6]

International Natural Gas Trade and LNG – how are they related?

LNG is an integral component of the worldwide natural gas trade.  In 2017, roughly 30% of the worlds’ natural gas consumption (3 680 x 10⁹ std m³/year (355 Bscfd)) was traded internationally (via pipeline or LNG), and 35% of the international trade was by LNG (393.4 x 10⁹ std m³/year (37.9 Bscfd)).  Therefore, it is reasonable to review in some detail the status of the regional Natural Gas Reserves, Production, and Consumption on this cited world basis.

Figure 5 [1] indicates the evolution of natural gas worldwide reserves from 1997 to 2017. Notice that the decade increases remains rather steady, and the total reserves as of 2017 is approximated to be some 193.5 trillion cubic meters (TCM) (6 832 trillion cubic feet, TCF). The Middle East is a leader in reserve figures as documented, with the US only accounting for some 8 737 billion cubic meters (308.5 trillion cubic feet).

Figure 5. Distribution of proved reserves from 1997 – 2017 [1]

There is considerable disagreement with this figure amongst experts, with some arguments that there may be discord by a factor of at least tenfold more gas within the US than reported.

Considering the surging access shale gas plays, as well as unconventional (tight) gas reserves and potential coal bed methane (CBM), coal seam gas (CSG), the actual amount of natural gas in the U.S. may be difficult to accurately account for. This is an important subject to consider; however, for the U.S. Natural Gas Reserves and Supply are perhaps understated in these figures.

A key indicator of natural gas energy usage efficiency is to follow a region (Countries) Reserves-to-Production Ratio. This will provide an indication on the ultimate longevity of sustainable gas production.  The higher the Reserves-to-Production ratio, the longer sustained production can be supported.

Notice that Figure 6 indicates a vastly different position of the North American Continent in terms of Reserves-to-Production Ratios as compared to Russia or the Middle East.  The Middle East reaches an admirable ratio of some 120, whereas N. America is below 10.  Canada’s reserves amount to some 66 – 67 TCF (1.87 – 1.90 TCM), so their position essentially coincides with the U.S. status. These Natural Gas Reserve figures have not differed greatly over the last 5 years, indicating that U.S. continental Gas “finds” have equaled a production withdrawal comparable to some 708 – 736 BCM (25-26 TCF) per year.

Figure 6. Global Reserves-to-Production Ratios [1]

A countries production and consumption of natural gas can highlight the impact that natural gas plays in providing sustainable energy for the population.  U.S. natural gas statistics is provided in Table 2. The U.S. is the world’s largest producer and consumer of natural gas.  The U.S. consumes approximately 20 % of the natural gas produced worldwide, while the North American energy source (RESERVES) is quoted as less than 5 % of the World. This data begs the question, is the North American reserves a valid estimate? Only time and exploration/production criteria and data will resolve this question.

Table 2. U.S. Natural Gas Statistics [1]

Another way to look at the natural gas trade is shown in Figure 7. Gas exporting countries are represented by red dots if they export via LNG, blue dots if they export via pipeline and yellow dots for countries that export via LNG and pipeline.  If you draw a diagonal line from the upper left-hand corner to the lower right-hand corner, you will note that the gas exporting countries are generally in the upper right-hand area of the graph and gas importing countries are in the lower left-hand portion.  The x-axis shows the size of the resource in each country and the y-axis shows the availability of that resource for export.

Figure 7. Natural Gas Reserves/Consumption vs Reserves Globally 2016 [1]

In summary, Figures 5 through 7 show the comparison of the global production/consumption and gas reserves.  Table 3 provides the 20 largest natural gas consuming and producing countries in 2017.

Table 3. Top 20 Natural Gas Producing and Consuming Countries 2017 [1]

How does this statistical data relate to the world market for LNG?  In short, it provides the global landscape of natural gas-rich countries that export vs. those which are dependent upon natural gas imports.  It also gives insight into the drivers for the U.S. to enter into the LNG international business.

The U.S. shale revolution resulting in very low local natural gas prices (excess supply), and restricted, or non-existent pipeline capacity access to energy-lacking markets, made investing in U.S. LNG export facilities a serious investment consideration! Historically LNG has been sold worldwide on an equivalent energy basis cost with the sale of crude oil, often referred to as the Japanese Crude Cocktail (JCC). However, with the emergence of the U.S. as a major LNG supplier, new, creative commercial agreements are coming into play. Regardless, the value of natural gas in Germany, UK and Japan (importing countries) is significantly greater than the current value of natural gas in the U.S., thus a significant uplift in value can be recognized in exporting LNG.

Figure 8. Historical Trend for Natural Gas Prices Based on Energy $/MMBtu ~ $/Mscf [1]

As shown by Figure 8, the 2017 cost of natural gas in Japan was in the 7.50 – 8.00 $/MMBtu range; the similar cost also for other major importers such as China, and South Korea. The import price to Europe was roughly 5.80 $/MMBtu. In that period. Crude oil prices were in the 45 – 55 $/Bbl range. The value of natural gas in the U.S., based on Henry Hub (Gulf of Mexico) pricing index, remains less than 3 $/MMBtu.

With that said, there has been significant and continuing investment in U.S. LNG export facilities.

The New Kid on the Block – U.S.A.

There are 21 export facilities for LNG throughout the world. The LNG production by country is provided in Figure 9. Qatar is the leading nation with some 103.5 BCM (76.6 mtpa), assuming a conversion of 1350 std m³ /tonne. The seven leading nations (Qatar, Australia, Malaysia, Nigeria, Indonesia and the U.S.) dominate exports with some 298.9 BCM, or 221 mtpa.  The U.S. has reached an important international role as number six in the leading group with 17.4 BCM of equivalent gas exports, or approximately 12.5 mtpa in LNG.

Figure 9. LNG Production by Country [1]

The decision by the U.S. to aggressively enter the LNG export market has been phenomenal. Assuming that the natural gas supply in the U.S. will continue to grow, thus maintaining a 3 $/MMBtu local price, the value added to the Natural Gas is spectacular when sold overseas. For example, consider the U.S. production to produce the cited 12.5 mtpa is approximately 600 billion cubic feet (BCF) per year or 1.64 BCF/d. This is only a minor fraction of the U.S. production/consumption of some 71 BCF/d. Making the simplifying assumption that U.S. LNG has a heating value of 1000 Btu/scf, one can quickly estimate the uplift of selling the gas as LNG.  The net value “added”, to the sale of 1,640,000 thousand cubic feet (MCF)/d at a net differential of say 5.5 $/MCF ($8.50 avg. worldwide vs. 3.0 $/MCF Henry Hub) generates 9 million dollars per day by the three existing export facilities. The added benefit seems well justified!  However, it should be noted that quoted value does not include CAPEX, operating costs, and shipping fees, yet highlights the significant potential for profit for these facilities.

Some 24 Countries around the world are net importers of LNG. In 2017, the major consumers were Japan with 113.9 BCM (84 mtpa), followed by China at 52.6 BCM (39 mtpa), South Korea at 51.3 BCM (38 mtpa), and India at 25.7 BCM (19 mtpa). The summary of LNG importers is provided in Figure 10. The LNG market is significant, and estimates for continued growth, while viewed with caution by some experts, is still considered very positive for the future.

Figure 10. Global LNG Imports [1]

A Review of Existing, and Proposed Import/Export Terminal Facilities in the Continental US

As shown by Figure 11, as of 2018 there are 12 existing import terminals within the Continental U.S.. During 2018, there were two operational export terminals that include Cove Point. MD, and Sabine Pass, LA. The net capacity of these facilities amounts to some 3.8 BCF/d. However, only 1.56 BCF/d were processed to yield the 2017 export level of 12.5 mtpa. There is an obvious additional net processing ability in these facilities, and projections for these could reach almost 4 BCF/d. As shown by the Figure 11, the US is in an extremely unique position to greatly increase its LNG export position in the world. There are 9 additional facilities approved for export modifications to convert the import terminals to exporting facilities.  The amount of time and expense it takes to modify an existing import facility to an export facility is significantly lower compared to a greenfield LNG project.

Figure 11. LNG Terminals in N. America [7]

Figure 12 provides the anticipated U.S. LNG export capacity from the Energy Information Administration (EIA).  To compare fast growth of US LNG export capacity with others, for example, Australia, let’s take a look at the projected growth of Chenier’s Sabine Pass Facility.  Train 6 of Sabine Pass just cleared the FID (Final Investment Decision) decision earlier this year.  Once completed, each of the 6 trains has 4.5 mtpa capacity, resulting in 27 mtpa net exporting capacity of LNG for Sabine Pass alone.  The North West Shelf of Australia (one of the largest and older LNG export facilities in Australia), produces 16.3 mtpa of LNG.  The Sabine Pass Facility will dwarf the production of the North West Shelf when completed and running at full capacity.  As can be seen in Figure 12., the U.S. is forecasted to expand LNG export capacity rapidly and could likely become the 3^rd largest LNG producer in the world by 2021.  One has to ask, is this a wise move at this time in the historical world trade of Oil, Gas, NGL, and LNG trade? These decisions include many “unseen” factors that consider critical economic/political/industrial relations between the U.S. and other countries seeking the same leader position in LNG trade.

The LNG worldwide trade is very complex.  Nevertheless, the U.S. has a unique position of flexibility. Many decisions must be made, but the unique industrial capacity is present.  In many ways, the U.S. has become the sleeping giant of LNG that has yet to recognize its full potential.

Figure 12. U.S. LNG Capacity, Company Investors Presentation [8]

To learn more about LNG, we suggest attending our G2 (Overview of Gas Processing),  G29 LNG (Short Course: Technology and the LNG Chain), and G4 LNG (Gas Conditioning and Processing-LNG Emphasis) courses.

Written By: Dr. Frank E. Ashford

                        Kindra Snow-McGregor

References

1. Reprinted with permission, American Oil and Gas Historical Society

2. BP – Statistical Review of World Energy, 2018 (for 2017)

3. US Energy Information Administration, Frequently Asked Questions

4. Short Course: Optimising Terminal and Ship Operations, John A Sheffield, 2018.

5. Shell LNG Outlook 2019

6. Coyle, D., de la Vega, F., Durr, C., “Natural Gas Specification Challenges in the LNG Industry”, KBR, Paper PS-47.

7. FERC, https://ferc.gov/industries/gas/indus-act/lng/LNG-existing.pdf

8. U.S. Energy Information Administration, company investor presentations, Dec. 2018.

9. Statista Research Department, 2019.

10. G-29 “LNG Short Course: Technology and the LNG Value Chain”, ©PetroSkills | John M Campbell, 2019.

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