written by Stephanie Ng & Himadri Singh
In the first article on gas disposition , we looked at the challenges of the disposition of gas co-produced from stranded oil and small marginal pools. In this article, we address the technology required; the external economic challenges; and non-technical factors affecting gas monetisation.
With respect to gas disposition, it is io’s belief that the gas disposal issue, and its impact on development economics for marginal or small pools (or even more major developments), should be considered much earlier in the commerciality assessments. In the past owners/operators may have prioritised fields with low Gas to oil Ratios (GORs), in the range of 50 to 150 scf/bbl as these developments will have a greater chance of success with limited gas to ‘deal’ with. For gas discoveries or oil discoveries with high GORs gas monetisation is more likely to be part of the development solution and will be addressed herein.
evaluate your assets
In the context of both offshore and onshore projects: field analysis; the quantity and quality of the gas; and the location of the asset with respect to the distance to market are all paramount to unlocking the potential in gas monetisation. Within the operator’s portfolio, projects can be mapped out using the following nomograph (Figure A) to help to prioritise their projects based on the range of products against two parameters: product volume and distance to market. Of course, there are non-technical factors which ultimately govern the selected solution. Geopolitical constraints, such as what additional resources are required to produce these products; would the facility be competing for a precious resource, such as water, against the country’s demands; and what is the ruling government’s appetite to export a by-product to the global market compared to supplying power to their domestic market.
Fig A. The hypothetical project portfolio
know your market
For each possible product, analysis of current supply and demand against future supply and demand projections will identify possible target markets. Any delay in first gas for the project highlights the potential risk in revenue lost in export to other markets due to the growth in domestic demand. This is illustrated in Figure B.
Fig B. A hypothetical market projection of supply and demand
The likely product price in these target markets; the location of the market and their respective transportation routes and related costs (tariffs, tax etc.); electricity import/export tariffs; product losses through transportation and other risks and issues will provide the netback price. Netback price is defined as a pricing assessment or formula based on the effective price to the producer/seller at a specific location or defined point. For example, liquefied natural gas (LNG) netback prices may be determined by the market natural gas price at market destinations less the cost of the pipeline transportation, regasification, shipping and liquefaction.
There may be opportunities for synergies with third party existing or planned infrastructure; transportation routes; other operator pipelines at negotiated attractive rates. From these non-technical and economic aspects, combined with the technical feasibility discussed below, a strategy of the best product mix may be formulated to achieve the optimal revenue.
In the first article  we discussed the ways the facility could consume gas. Now we will discuss the ways in which the excess gas may be used or monetised. The economic viability of these is a balance between the distance to market; the volumes produced; the CAPEX of the facilities and infrastructure (including export) and the prices, which may be distorted by domestic fuel subsidies.
Close proximity to existing gas/gas product export routes (e.g. pipelines, railways, trucking) or export hubs (e.g. offloading port, floating storage unit) are normally part of the most logistically convenient and lowest cost gas monetisation option. While project economics need to include the associated costs of pipeline tariffs, rail tariffs, storage tariffs etc., this can often present a more attractive economic model and can far outweigh the up-front CAPEX of having to build from new, along with the required associated infrastructure.
Alternatively, Gas to Power (GTP) may be considered, which is when excess power is sold to a Third Party. This can allow low stranded gas reserves to be commercialised and reduce flaring.
However, it can be a challenge with respect to the electricity demand of the facilities. As illustrated in the first article, a typical profile may result in an early period of gas excess (excess power) and in later years, gas deficiency (deficient in power). Fortunately, electrical power contracts do not need to be long term unlike natural gas sales contracts. However, the Third-Party agreement must be cognisant of events which lead to the unavailability of power, for example, during shutdown and/or maintenance periods which may not be coincident with Third Party requirements. This would require an “interruptible electricity supply contract”  under which the consumer agrees to temporarily reduce its electricity usage when the utility so requests. In return, the consumer is charged a reduced electricity rate. A situation where an interruptible supply may be acceptable would be to supply power to a non-electrified rural area, however power consumption would be expected to be relatively low. There is also a technical limit for electricity transmission in terms of power, cable length and voltage rating and is dependent on technology selection such as HVAC and HVDC.
Compressed Natural Gas (CNG) is methane stored at high pressure, and is a substitute for gasoline. However, the high pressure it is stored at makes it intrinsically less safe than LNG, which is stored to near ambient pressure. As the application is an alternative vehicle fuel, refuelling stations and vehicles need to be specialised/modified and is therefore markets will be local. This would incur additional transportation costs for the product if the target market does not have an established infrastructure and logistics network for this new product.
Liquefied Natural Gas (LNG) is a far safer and more cost-efficient means to transport gas by liquefaction. This product is mainly methane chilled to -196°C and stored at near ambient pressure. This allows a significant reduction in volume and the LNG can be transported long distances by carrier ship where pipelines are neither installed nor practical. However, liquefaction plants are highly CAPEX intensive and are only justifiable on a large scale. Low oil prices; high cost estimates; partner commitment; uncertain demand requirements are some of the reasons why many liquefaction projects have been pushed back by several years.
Liquefied Petroleum Gas (LPG) is a highly valuable product comprising propane and butane and is often a product to lessen the NGLs (Natural Gas Liquids) in a plant. There is a LPG market for domestic cooking applications especially in the Asia Pacific. However, the LPG process requires complex processing and is energy intensive.
Gas to Liquids (GTLs) are a synthetic fuel created from associated gas which might otherwise be flared or vented. There are several technologies which convert to hydrocarbon GTLs: coal to liquid, biomass to liquid, gas to liquids (synfuels). ,  Synfuels were first developed by the Fischer-
Tropsch process using coal as feedstock. This process is known for being costly and produces many by-products. However, thanks to the development of new catalysts, the cost and the number of by-products are reducing. GTL plants are typically on the large scale, requiring large gas rates and/or GORs, with the Shell Pearl GTL plant being the world’s largest GTL plant ever commissioned. These projects are known to be highly CAPEX intensive and more recently verging on the cost prohibitive as demonstrated by Sasol’s appetite in Louisiana . This is because this product is competing against the current over supply of crude oil in the market, making this type of project far less economically competitive. The technology for smaller/ mini-GTL plants, in the order of 1 MMscfd, is still in development; one example of this is from INFRA where their demonstration GTL plant in Texas processes 1 MMscfd of natural gas to produce 100 bbl/day of synfuel.
Gas to chemicals (GTC) provide high value products such as olefins, DME, acetic acid, formic acid and fertilisers. This is new and developing technology requiring high investment. This lends itself to a diverse range of products and multiple markets.
The economics of each of the gas monetisation options depends on supply vs demand and the price that can be achieved for the final produced product, which in some countries is regulated by the government. The desire to access international markets tends to lean projects towards LNG due to the increasing liquidity of the market and relative ease of transportation. CNG is a growing market but is mainly dependent on reasonably local demand due to a restricted transportation range of up to 100 km. Sale of natural gas is highly dependent on the pipeline infrastructure and access to market. Gas to Power is highly dependent on the local electricity demand, restrictions in place from the government and availability of the transmission lines.
For the possible economic value, each monetisation method (and in each region) carries a different risk profile with degrees of technical, commercial and geo political risks. Ultimately the ideal solution will depend on the value drivers which will seek to balance competing drivers: risk appetite, ability to source capital investment, early revenue, etc.
For example, an integrated new build gas-to-power value chain is likely to have the highest unit technical cost, however the technology is mature. The fluctuations in electricity prices may mean it carries higher credit risk. Power has highest unit technical cost due to large upfront CAPEX, higher OPEX and loss during the transmission process. On the other hand, a simple pipeline delivering gas to an established grid has the least unit technical cost combined with the most established and mature technology, but tends to access lower gas prices. This is likely to have the lowest upfront CAPEX with low OPEX and negligible transmission loss.
Figure C. Technical Cost versus Technical Maturity
In the first instance, io assesses field development economics from a top down or ‘what can the development afford?’ view point. We term this reverse economics and at the early conceptual stage this allows a rapid assessment of the range of CAPEX that may be able to be spent and still produce an economically attractive investment for the owner, given the fiscal regime. This is illustrated in Figure D. In a simpler oil development, this can easily be assessed at a range of market outcome oil prices. With gas projects, a little more care may be needed to understand the sales price; the point of transfer (to end user or aggregator) and the level of costs that may be incurred between the extraction and sale. This process enables a rapid assessment of gas monetisation options and ultimately reduces the cycle time to progress the project to the next phase of development.
Figure D. What can the development afford?
It is clear there is no one size fits all approach to solving the gas monetisation and gas disposition challenges in the upstream development space, but through project experience there is a common set of factors which tend to be considered. The true key to success is the integration of these factors with each one and other. At io our holistic team includes technical experts and economists, who apply systems thinking to understand the interdependencies of these factors and reverse economics to rapidly assess what the development can afford to provide the optimal solution for each bespoke situation.
To find out how io can help optimise the monetisation of your gas, contact us at email@example.com