WSS Energy were recently invited to present at a Finding Petroleum (https://www.findingpetroleum.com) focus event on flaring reduction.
This insights article shares the slides and a synopsis of our opinions on the challenges and options facing operators investigating routine flaring minimisation, whether through gas-to-power or through other routes for flaring valorisation.
Routine flaring reduction faces five separate challenges which often result in flaring minimisation solutions being uneconomical or impractical. Whilst there are no routine flares which cannot theoretically be minimised through using technology, the need for a positive business case results in only “simple” flares – containing almost pure methane at high flow rates and pressures – being the main ones being valorised.
Without regulatory regimes which place an incurred dollar cost on the CO2, CO2e and particulates emitted by flares, routine flaring minimisation will remain focused on straightforward sites where the business case is clear and low-risk.
The first challenge is volume – how much flare gas is emitted over time. Gas appraisal wells are an example where significant volumes (in the region of 1,000,000 SCM over a three-day period) are emitted. The temporary infrastructure required to store, export or treat such high volumes is often not feasible from an engineering perspective or economically viable. A highly prolific gas well may produce only around $80,000 of gas (at Henry Hub prices) during the well test period, hence economics for temporary infrastructure tend to be strongly negative.
At low volumes, gas-to-power through gas generators is a mature technology option, with 90SCM/hr capable of generating approximately 200kW of electricity. The economics depend heavily on the gas composition, as pre-treatment costs to reduce H2S to 200ppm (the limit for gas engines without pre-treatment, but with using a SOx scrubber) are prohibitive. Below 90SCM/hr there are gas-to-power options, however the amount of electricity generated tends to be insignificant when considering remote site operations – and the operations and maintenance cost tends to be prohibitive.
These example gas compositions, anonymised from a recent project, show how flare gas contaminants can make up a sizeable percentage of ultimate flared volumes.
“Bad” contaminants – H2S, CO2, Nitrogen, water – all have pre-treatment costs and reduce the calorific value of the flared stream. H2S is particularly challenging given its toxicity and the impact it has on compressors, pipelines and other infrastructure. Removing H2S reliably in a remote location becomes significantly more difficult as percentages increase.
“Good” contaminants – Natural Gas Liquids (NGLs) can be valuable on their own, if removed using technology such as NGL strippers or vapour recovery units, this does however depend on having an export market to achieve valorisation.
In real-world conditions, gaining a recoverable stream of high flow and pure methane very seldom occurs in sites where routine flaring is taking place – otherwise the stream would already have been utilised.
Flare duration is another factor which has already been touched on when discussing the gas appraisal well challenge. Duration can be measured in days, months and years, and in most cases when considering flare recovery a steady stream is required for at least five years to make investment likely to gain an acceptable return.
Accurate forecasting of future flaring volumes is rare, and operators tend to look at what is being flared currently and then apply an estimated decline curve in line with the current field. This often does not include the potential for future development campaigns or additional wells, so tends to under-estimate future flaring volumes. This creates an overly pessimistic picture of the future value of any flare minimisation initiatives. Accurate forecasting, and accurate measurement of actual flaring volumes, should be an essential first step when considering flare valorisation.
Access to infrastructure is often a considerable challenge. Infrastructure can include pipelines, utilities and storage facilities. Gas is often flared because there is no economic route to taking the raw gas to a central gas processing facility, where economies of scale are considerable. Trying to replicate a gas processing facility in a remote location is certainly technically feasible, but prohibitively expensive and complex to operate successfully.
In the exploration and appraisal environment temporary pipelines can be considered for either centralisation of wellhead gas processing or to temporarily connect to an existing pipeline system. The economics and practicality of temporary pipelines will depend heavily on the flare location and the distance / topography to the desired central processing facility or existing wellhead gas pipeline.
Vendors are responding to the need for flare gas valorisation and capture, and there is an active developer landscape for either standalone gas conditioning systems, or modular systems producing LNG, CNG, NGLs or gas-to-power solutions.
It has to be stated that vendor solutions are very dependent on the flare gas composition, and screening studies based on a good understanding of gas composition and flow rates is essential to avoid pursuing solutions which are not likely to be successful.
Vendors have adopted a more realistic approach to marketing their technology solutions having previously been willing to explore all potential applications. To assist vendors, operators should ensure that their flare composition and volumetric data is accurate to allow an efficient preliminary screening process.
Technology transfer from the biogas and mining industries is emerging, as both these industries have been successful in monetising marginal gas streams, generally for gas-to-power applications. Whilst the mining industry tends to have relatively low-volume but pure streams, the biogas industry has successfully managed to monetise higher-volume streams with both liquid and gaseous contaminants – including hydrogen sulphide (H2S). The main difference between biogas and oil and gas streams is the presence of NGLs in the O&G industry – hence any solutions being transferred from the biogas industry should expect to have vapour recovery as a pre-treatment step.
Although successful flare gas recovery creates potentially valuable hydrocarbons, finding an economically attractive local market or an export market can be challenging. CNG markets tend to be local and a response to insufficient gas distribution infrastructure, and require consumers and businesses to commit to switching from diesel, kerosene of other fuel sources. NGLs are potentially very valuable, but oil producing countries are often net importers rather than exporters, and require the marketing capability to invest in developing new markets.
This requires cross functional working – flare recovery cannot just be viewed as an asset responsibility, otherwise sub-optimal economic outcomes are to be expected as asset staff are not incentivised to create new hydrocarbon value chains. This requires joined-up working at the front-end of any flare gas recovery project to ensure that valorisation options are realistic, resourced and the NPV and environmental objectives are linked to corporate, rather than asset, objectives.
Cultural and business change is often required to move flare gas recovery from the “too hard” or “not valuable enough” list of options. New business models, as seen with Basrah Gas, show that associated gas recovery is possible and can be profitable.
It could be argued that similar business models to US shale water treatment need to be developed – where commercial third parties are rewarded for reducing flaring volumes and take the upside from any valorisation option – whether gas-to-power, NGLs, CNG or LNG.
As a first step operators should accurately measure their flare inventory in terms of composition and volume, and then make an accurate forecast over a 20-year period based on a realistic vision for the future of the assets. This will allow efficient conversations with technology vendors to take place, and avoid chasing inappropriate solutions which are unlikely to work.
Finally, flare gas should be viewed as part of an energy system. Combusting gas in a generator rather than flaring it still produces the same amount of atmospheric CO2, hence the CO2 reduction business case should be linked to a reduction in power demand from other generating assets. Similarly, gas-to-power systems generate a considerable amount of heat, which can be used by local industries or for oilfield processes. Only by taking a systems engineering approach can a full picture of the value potential for flare reduction be found.