Comparison of Various Offshore Industrial Gas Technologies
You have access to this full article to experience the outstanding content available to SPE members and JPT subscribers.
Offshore oil-exploration drilling and testing are key for the production of oil; however, a number of associated challenges, particularly the handling of associated gas, must be overcome. This paper discusses the alternatives for processing the associated gas and transporting it to markets. The technologies described in this paper are applicable to nonassociated-gas projects as well. Fig. 1 provides a description of gas-handling value chains for some of the alternatives.
Floating Liquefied Natural Gas (FLNG)
Liquefied natural gas (LNG) is natural gas that has been converted to liquid form for ease of storage or transport. It is a gas cooled to −162°C and has a volume that is 1/600 that of the gas at room temperature. The gas has to be processed at both ends of the shipping chain in order for LNG to be produced and used. It can be transported by specially designed cryogenic sea-going vessels (LNG carriers). At the destination, the LNG is offloaded to a receiving terminal that stores it and revaporizes it into a pipeline that takes the natural-gas product to the end users.
Floating Compressed Natural Gas (FCNG)
Compressed natural gas (CNG) is a concept for gas transport over intermediate distances. The FCNG technology involves storing natural gas at high pressure in a carrier ship to transport it from an offshore location to a typically onshore location. The high pressure and possibly reduced temperature increase the density of the gas, making it more economical to transport.
CNG is stored and distributed in cylindrical or spherical vessels at pressures up to 275 bar and at ambient or subambient temperatures. Higher pressures and lower temperatures allow more gas to be contained per unit volume. The typical volume reduction is 1/300.
An FCNG production vessel is a traditional gas floating production and operation unit (FPO) with a high-pressure gas-transfer system, instead of a subsea pipeline, to load CNG shuttle ships. The CNG is transferred at near-ambient temperatures, so the hoses and transfer systems are the same high-pressure hoses and systems used to transfer high-pressure gas and well fluids onto an FPO. The CNG shuttle carriers provide both storage and transport, thus avoiding the necessity for storage on board the FCNG vessel.
Any CNG-delivery-system technology should offer a continuous-flow process without interruption or discontinuity (like a pipeline). Gas should flow continuously with high reliability through the CNG shuttle ships. Major buoy-system suppliers have reviewed CNG transfer and found that their systems can be adapted to CNG transfer without developing new technology.
CNG appears to be a potentially suitable and promising technology for deployment despite not having been deployed commercially to date. It has no technical barriers. The principal commercial barrier stems from CNG being a solution that lies between a pipeline for shorter distances and LNG for longer distances.
FCNG technology has existed in a design state for several years, with numerous studies having been conducted; however, no facilities have been built yet.
Gas to Hydrate (GTH)
A mixture of water and gas under low-to-moderate temperature and pressure forms solid compounds called hydrates. These ice-like structures trap gas, typically methane, ethane, hydrogen sulfide, and carbon dioxide, as molecules hosted within a lattice of water molecules.
A gas volume of between 150 and 180 std m3 may be contained in 1 m3 of hydrate. In addition, hydrate remains stable at atmospheric pressure when stored at temperatures below the freezing point of water. The combination of these properties makes hydrates a potentially useful means of transporting natural gas.
GTH systems are well-suited for offshore fields. The principal difficulty in using GTH, as with CNG, might be the ability to maintain consistent gas production.
The space requirement for GTH technology is comparatively smaller than that for the LNG process. GTH technology requires moderate storage conditions on the vessel and is safer than CNG.
According to the literature and results from a pilot-scale plant currently in operation, significant issues remain to be resolved before the first hydrate-production chain will be seen commercially. The GTH process is technically immature, which presents a significant risk for use in the medium term.
Gas to LNG, Compressed-Gas Liquids (CGLs)
CGL technology consists of a combination of natural gas and natural-gas liquids (NGLs) for easier transport. Produced light hydrocarbons are processed and conditioned after the natural gas has been separated and cleaned. The remaining products, NGLs and CGLs, are mixed, forming a solvated solution, where gas and NGLs are combined at a moderate temperature of −40°F and a moderate pressure of 1,400 psig. The combined solvated product is CGL. The process uses standard gas-plant technology, resulting in operating costs and energy consumption lower than those of more-costly LNG and gas-to-liquids (GTL) technologies.
The space requirement for CGL technology is comparatively smaller than that for typical LNG liquefaction processes. CGL requires moderate storage conditions on the vessel and would be safer offshore than CNG and GTL.
GTL involves converting the feed gas into liquid products through a series of reactions. From a broad perspective, the primary benefit of this approach is that the liquid products are much more transportable. The downside is that GTL processes tend to be very complex and expensive and operational experience onshore needs to mature before it can be applied offshore.
Onshore GTL plants tend to be massive facilities, in part because of the large amount of equipment involved. For an offshore installation, the throughput capacity might be much less but the equipment count will be the same, except for some new processes. This makes it difficult to achieve the compact design required to meet the space limitations of an offshore facility. Therefore, one of the objectives should be to obtain an intermediate liquid syncrude/raw-liquid product before distillation for separation into different marketable products. Eliminating the distillation phases offshore considerably reduces the amount of equipment and the footprint, as well as the operational difficulties.
Currently, no process suitable for gas production greater than 10 MMscf/D exists on a floating vessel, and large-scale onshore GTL is still in its infancy.
Gas to Methanol, Dimethyl Ether, or Ammonia (GMDA)
GMDA is an expansion of GTL such that the syncrude is refined to a petroleum product—methanol, dimethyl ether, or ammonia. The overall process includes separation and treatment of produced gas into dry process feed-quality gas on the main host. A processing unit mounted on an existing main host or on a vessel is then needed for size considerations, and the oil and produced liquids are transported by vessel to shore. This topic has been studied for years, with the first offshore methanol plants considered in the 1970s.
The solutions discussed in this section relate to the production of a liquid product.
Floating GTL (gasoline, diesel) production, floating methanol production, floating dimethyl ether production, and floating ammonia production all require gasification of the natural gas to obtain syngas, which is then processed further to produce liquid products.
An offshore gasification process would consist of multistage compression to feed-treatment conditions. The gas then will be pretreated and fed to the syngas-generation unit, after which it will be cooled and treated to achieve the required syngas quality before being sent for the liquids-production process, preferably onshore.
Gasification technology has never been used offshore for a commercial project. As such, a gasification process represents significant technological, scheduling, and funding risks.
Gas to Wire (GTW)
This option uses the associated gas as fuel for gas-turbine generators (GTGs) to create electric power to export to shore or to other facilities offshore. Studies have shown that, because of the size of the power-generation and -transmission equipment and the sensitivity of the power cable to motion in deep water, the technology is best mounted on a semisubmersible platform close to a floating production, storage, and offloading (FPSO) vessel.
The process will require a single- or multistage compression train to take the associated gas from inlet pressure conditions of 10 to 70 bar to the required inlet pressure for the gas turbines. The compression itself might provide enough heating that further superheating would not be required. The fuel gas is then fed to the GTG with air for combustion. The combusted gas moves the turbine to generate electrical power. The electric power generated would then be transmitted to shore for sale.
Recent design work has considered the combination of FLNG and GTW. These floating power-generation facilities would integrate storage of LNG, regasification, and power generation in a single unit.
Compared with land-based solutions, advantages of the floating power supply include fast-track implementation and attractive pricing with flexibility because construction work completed in fabrication yards normally results in efficiency and cost reduction. It is also an investment-friendly solution because it minimizes the land-acquisition process and requires fewer civil works. Therefore, FLNG power-generation solutions are now being considered in many places around the world.
GTH technologies are far from being ready for deployment, whereas LNG has already been implemented and is awaiting green initiation of operations. GMDA technologies are available but have limited to no application. A GTH-transportation solution is not technically feasible because of the immaturity of the technology and the large scaleup factors that are required to achieve a commercial process offshore. No clear indication exists as to when the technology will be commercially available at a scale suitable to commercial gas rates. Floating GTW is mature and established, but it is limited in the distance to market.
Comparison of Various Offshore Industrial Gas Technologies
01 April 2018
Natural Gas Processing and Handling
Despite a dip earlier in the year, natural-gas prices remained steady over 2017, averaging $2.99/million Btu. … Early 2018 has been a different story, however, with natural-gas prices already hitting a couple of peaks (of greater than $5/million Btu according to the Henry Hub Spot Price history).
Total Boosts LNG Business With Purchase of Engie Assets
Total is making an LNG push by spending up to $2 billion for assets belonging to fellow French firm Engie.
What’s the Future for LNG?
LNG as a fuel source has been an energy staple for many Asia-Pacific countries for decades, and is increasing in importance in other regions as countries look to diversify their energy mix.
Don't miss out on the latest technology delivered to your email weekly. Sign up for the JPT newsletter. If you are not logged in, you will receive a confirmation email that you will need to click on to confirm you want to receive the newsletter.
16 April 2018