FT-GTL UNLOCKS VALUE FROM NATURAL GAS Doug Miller Michael Goff Black & Veatch Corporation Ken Agee Emerging Fuels Technology April 2017 Introduction An estimated 147 billion cubic meters of gas was flared worldwide in 2015. This figure corresponds to approximately $30 billion to $35 billion per year in lost value. In addition, flaring emits approximately 350 million tons of carbon dioxide (CO 2) into the atmosphere each year. This emissions rate is equivalent to the emissions rate of approximately 125 coal-fired power plants. Environmental regulations on continuous flares are increasing, and demand to monetize this lost resource is growing. Increased flaring is a result of increased oil production, new oil producing countries and associated gas from oil shale production. The volume of gas produced from these wells is relatively small; flaring the gas is, therefore, cheaper than building infrastructure to capture it. The purpose of a well is to produce crude oil. Small-scale processes for capturing natural gas not only allow this gas to be monetized but can also allow the oil field to be developed. In addition to the gas lost through flaring, a large amount of stranded gas cannot economically be brought to market. It is estimated that about one-third of gas reserves are considered stranded. Gas is flared more for economics than for technical reasons. Technical solutions are available to monetize gas that is currently flared, but there are numerous economic reasons that flaring is prevalent. The most common problem is the lack of market access. Either the gas must somehow be captured and transported to where it is needed, or it must be converted into a more valuable product at the flare site and then transported to market. The goal of converting the gas into another form at the well site is to turn the gas into a more easily transportable form. This could be accomplished by physically or chemically converting it to a liquid, increasing the density of the gas or converting the gas to electricity and connecting to the power grid. All of these options are technically feasible. Specific-site conditions will vary; what is a good option for one location may not be the best option for all sites. Challenges to monetizing stranded and associated gas are as follows: Distance to market. Lack of local infrastructure. Black & Veatch 1 April 2017
Small gas volumes and stability in steady-state supply volumes. Changing gas composition. Availability of capital. Price distortion due to local fuel subsidies. Need to deploy technology quickly and to be operational as soon as the well becomes operational. Solutions to monetizing stranded and associated gas include the following: Convert gas to a product that can be utilized close to the source. Create local infrastructure or convert gas into a form that can be integrated with local infrastructure. Develop modular, skid-mounted processes that can be rapidly deployed at the gas source. Small-scale facilities can be easier to fund and can be executed more quickly. This paper explores options for monetizing natural gas using technologies that are commercially proven and provides a technical and commercial evaluation of the following options: Liquefied natural gas (LNG). Compressed natural gas (CNG). Power generation. Gas-to-liquids (GTL) using Fischer-Tropsch (FT) technology. Methanol production. The technologies evaluated all compete with different existing markets. CNG and LNG compete primarily with oil and coal for power generation and domestic heating. GTL competes directly with transportation fuels. Methanol competes in the traditional methanol market and is produced predominantly from natural gas and coal feedstocks. Associated gas and stranded gas are not to pipeline specifications, and the composition of associated gas and stranded gas will, therefore, vary from location to location as well as over the life of the well. It is important to understand these variations and the gas composition when evaluating gas monetization technologies. Some processes are better than others at handling various compositions. Black & Veatch 2 April 2017
Liquefied Natural Gas LNG predominantly serves the power generation and industrial fuel markets, which are subject to seasonal price variations. LNG is a viable solution when transportation over long distances is required or when local infrastructure is available for transporting and regasifying the LNG. Use of LNG as a transportation fuel is also possible, and LNG is gaining in popularity as a low sulfur alternative for locomotives and ships. LNG typically requires long-term sales and purchase agreements, which can create another obstacle. LNG is also unique because the price of LNG is usually linked to the price of oil. Although an LNG plant can in theory use any feedstock containing methane, LNG is made from relatively pure methane. Thus, any components commonly present in natural gas such as CO 2, sulfur, and C2+ hydrocarbons must be removed. Removal of these components adds to the capital and operating costs of an LNG plant. LNG production as a solution for flared or stranded gas is, therefore, economically viable only with a relatively clean natural gas that is free of sulfur and heavier components. Compressed Natural Gas CNG can be transported over relatively short distances and carried by an existing pipeline. This option may be attractive for smaller gas volumes or as a temporary solution until another solution can be implemented. CNG also can be used as a transportation fuel in fleet vehicles. This use would have the most merit for a local fleet of vehicles that already runs on natural gas and does not have to travel long distances from refueling stations. Conversion of natural gas to LNG or CNG does not increase the value of the gas, but it does allow the gas to be moved from an area where the gas has no value to an area where the gas has some value. The feed for CNG must be cleaned of sulfur compounds, and C2+ hydrocarbons must be removed to a point where these components will not condense at the pressure of CNG at ambient temperatures. CNG is normally compressed to about 245 bar. Typically, the gas must meet pipeline specifications before it can be used as CNG. Power Generation Using natural gas to produce power in a gas turbine is an option for small volumes of gas or where existing infrastructure is available for transmitting the electricity to where it is needed. A small amount of gas will meet the electric demands of the well site. Larger gas volumes will require transmission lines to get the electricity to the grid. The primary obstacles to selling electricity to the grid are potential regulations on electricity transmission and the need to work out an agreement with the local electrical utilities. Producing power from stranded gas or associated gas allows for more variation in composition, as long as the composition does not change significantly. Sulfur must be removed from the gas to meet emissions requirements. Heavier hydrocarbons only need to be removed so that no liquids are present. The gas turbine can be designed to handle various heating value gases, but changes in the Wobbe Index will cause the gas turbine to not perform as expected. Black & Veatch 3 April 2017
Gas-to-Liquids Natural gas can also be converted into transportation fuels using the FT process. Natural gas is first converted to synthesis gas (syngas [a mixture of hydrogen and carbon monoxide]), cleaned up to remove any FT catalyst poisons, such as sulfur compounds, and then converted to hydrocarbons of various chain lengths. The hydrocarbons leaving the FT reactor vary in carbon chain length from 1 to 100+ carbon molecules. The lower carbon number products can be used as fuel, condensed and sold as liquefied petroleum gas (LPG) or recycled back to the front end and converted into syngas again. The heavier hydrocarbons can be cracked to increase liquid fuel yield. Larger GTL plants would likely produce a few different products, because economies of scale allow for more product upgrading. Products that can be produced by refining FT liquids, include naphtha, jet fuel, diesel fuel, waxes and lube oils. For smaller GTL plants, producing a synthetic pumpable crude oil without additional product upgrading may make the most sense. The benefits of this approach are that capital cost and complexity are reduced. In the case of associated natural gas, synthetic crude oil (syncrude) can be blended with petroleum crude oil and refined with the petroleum crude oil. This approach is used by Black & Veatch and Emerging Fuels Technology s Flare Buster process. Flare Buster is a modular designed, fully selfsufficient plant capable of converting gas to a pumpable syncrude. The benefit of producing syncrude via the FT process from associated gas is that it can be blended with crude oil. New offtake agreements are easier to obtain or are not required because the producer is already in the oil market. If desired, diesel fuel can be produced with some mild hydrocracking and distillation. FT diesel fuel makes an excellent blendstock with crude oil diesel because of its zero sulfur species and its high cetane number. GTL and methanol production are the most flexible with regard to feedstock composition. Sulfur needs to be removed from the natural gas because it is a poison to downstream catalysts. After the sulfur is removed, practically any gas containing hydrocarbons can be converted to syngas using commercially demonstrated processes. CO 2 in the gas is not a concern for either process and, in the case of GTL, can actually be a benefit. If enough CO 2 is present, a steam methane reformer can be used to produce syngas with the correct hydrogen to carbon monoxide ratio. The benefit of a steam methane reformer over a partial oxidizer or autothermal reformer is that the steam methane reformer does not require an enriched oxygen supply. Methanol Production Methanol is commonly produced from natural gas and is used as a feedstock in the production of a large number of other chemicals. Two new markets for methanol are its use as a petrochemical feedstock (methanol to olefins/propylene) and as a liquid fuel. Methanol can be used as a blendstock in gasoline or be converted to dimethyl ether and blended into diesel. Methanol can also be used as a fuel in cars, trucks, locomotives and ships and has advantages over LNG because of its high density and liquid state at atmospheric conditions. Comparison Because the price of LNG is usually indexed to oil prices, a rise in oil prices also increases the price of LNG; therefore, the economics of LNG and GTL move in tandem even though the Black & Veatch 4 April 2017
end products are in different markets. A decoupling of LNG prices from crude oil prices could increase the attractiveness of GTL in a low natural gas price, high oil price environment. GTL could have an advantage over LNG if the gas is available in a landlocked area where getting the LNG to a port is uneconomical. GTL is the simplest product to make if the overall project is considered because it does not require entry into a new market. For associated gas that is a byproduct of crude oil production, producing more salable liquid products improves the overall economics of the well. If regulations do not allow the flaring of natural gas, converting the gas to a higher value product will allow the well to remain in operation to recover the costs associated with exploration and drilling. Table 1 provides estimated capital costs, production rates and efficiency numbers for the processes discussed and compared. All of the numbers are based on 5,000 normal cubic meters per hour (Nm 3 /h) natural gas feed, which is the assumed feed rate for a plant processing stranded gas or associated gas. Not included in the cost estimate and analysis of CNG is the transportation of the CNG to market. Similarly for power generation, no costs were included for connecting to the existing power infrastructure. All costs were calculated at the plant gate. Table 1. Estimated Capital Costs, Production Rates and Efficiency Numbers Capital Cost, million US$ Production Rate Thermal Efficiency, % Carbon Efficiency, % Simple Payback, years LNG 45 82 MTPD 85 85 8.3 CNG 16 50.8 MW 92.3 92 5.3 Power Generation 25 19.4 MW 35 0 7.7 GTL 55 450 bbl/day 53 62 6.3 Methanol 55 124 MTPD 58 72 4.6 MW megawatts MTPD metric tons per day bbl/day barrels per day Assumptions used in simple payback calculations: Gas pressure to process is 20 bar. No product transportation costs are included. Assumes infrastructure is in place for products. LNG price is $6 per million British thermal units (MMBtu). Crude oil price (GTL) is $55 per barrel. Methanol price is $300 per metric ton. Power is $20 per MW. Black & Veatch 5 April 2017