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Solving the deepwater to downstream hydrate inhibitor dilemma

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Oilfield Technology,

Duncan Baillie, Business Development Manager for OMMICA, Lux Assure, shows how there is mounting evidence that, in line with the improving fortunes of the upstream oil and gas industry, deepwater fields are back in play on the global stage, and more competitive than ever.

With a number of deals in this resource class already approved in 2017, including BP's Mad Dog 2 in the Gulf of Mexico, and Statoil and Total's recent deals in Brazil, deepwater projects look set to feature large in boardroom investment decisions over the next few years.

In February, at a floater conference in Norway, oil and gas consulting services and business intelligence firm Rystad Energy suggested structural cost cutting in the deepwater market was set to make offshore projects competitive with US shale.

The firm said cost reductions and refinements in deepwater developments offshore have brought break-even prices down to between US$56 and US$58/bbl in Europe and the Americas. According to Rystad partner Lars Eirik Nicolaisen, a continuation of the reduction in shale’s break-even operating costs of more than 50% over the past two years was “unsustainable” – with costs set to rise as the industry recovers.

So with these trends likely to continue, together with the steady decline in easily extractable hydrocarbons, it seems inevitable that operators will increasingly look to target resources from deeper, more remote offshore plays, characterised by their complexity, higher risk, and often challenging reservoir fluids.

And it follows that operators will need to address the issues made ever-more problematic in these higher stake finds.

High risk finds

Developing deepwater fields is a costly and complex process. Taking into account transportation, manpower, qualifications and infrastructure costs, CAPEX has historically been much higher than onshore developments.

At the site itself, appraising and producing new hydrocarbon reserves means contending with increasingly harsh downhole conditions. Designing and operating equipment that can withstand these hostile environments is difficult. What’s more, in deepwater plays where operators are dealing with colder temperatures, higher pressures and longer tiebacks, specific flow assurance challenges that negatively impact production are particularly pronounced.

Simply put, keeping produced hydrocarbons flowing through the lines is much more complex.

Hydrate production

Among the industry’s costliest and hardest-to-remediate flow assurance issues are hydrate formation, as well as paraffin and asphaltene wax deposition.

Presenting a high risk to production, gas hydrates are ice-like structures comprising water and gas. In a relatively short period of time, hydrates can plug up lines and disrupt production, causing a potentially hazardous pressure build up.

They are particularly problematic in deepwater regions such as Brazil, Angola and the Gulf of Mexico, where pressure gradients and low fluid temperatures promote formation. It’s also a major issue in remote frontier developments where pipelines are routed along the seabed over long distances.

Yet the temperature does not have to be below freezing for hydrates to occur: they have been found offshore Western Australian, and in the Arabian Gulf.

And remediating hydrate formation when it occurs is even more problematic considering deepwater wellbores and flowlines are harder and more expensive to access.

Upstream inhibitor benefits versus downstream challenges

A common approach to suppress hydrate growth is to inject thermodynamic inhibitors, such as mono-ethylene glycol (MEG) or methanol. Methanol is batch dosed, while MEG is usually injected continually into pipeline fluids.

Timely, accurate analysis of the concentration of these inhibitors is essential, particularly for remote, deepwater developments where the infrastructure is large and complex – and even the smallest issues, if not addressed, can have devastating consequences.

Specifically, the benefits of being able to analyse concentrations quicker onsite include avoiding costly chemical wastage; optimising start up procedures by monitoring methanol transition times from tiebacks; while –for MEG – giving visibility of whether reclamation and regeneration units are performing as they should.

Yet gas chromatography (GC) equipment — traditionally used for testing — is often not available onsite. This means samples must be flown increasingly long distances for testing and analysis onshore: an expensive option where results are not available for days, even weeks.

Yet, the presence of methanol and MEG reduces the quality and value of produced fluids, and can cause problems further downstream during process and refining. Separation difficulties, poisoning catalysts, and poisoning molecular sieve beds are just a few.

As such, to protect from lost time and income due to damages, refineries and terminals often impose limits on the acceptable level of hydrate inhibitor: exceeding these mean huge fines for operators.

And, aside from financial implications, analysing the concentration of methanol and MEG in produced water is vital for ensuring compliance with environmental regulations.

Turning MEG and methanol analysis on its head

LUX Assure’s OMMICA™ provides fast, precise methanol and MEG analysis onsite, regardless of geography and complexity.

As a cost-effective CAPEX alternative, which offers results as accurate as GC in as little as an hour, OMMICA is a low-risk, simple, colourimetric onsite (offshore and onshore) chemical testing kit.

The technology is often used to complement GC which, as a traditional technique, has its drawbacks, including maintenance issues, especially when these sensitive instruments are used offshore. In contrast, OMMICA, which analyses residual methanol or MEG concentrations in produced water, crude oil and condensate, has many advantages over GC, including simplicity and robustness.

Specifically in deepwater or remote regions, the technology saves operators significant time and money by replacing expensive sample testing, as well as consequential lengthy turnaround times, with onsite capability to make near real time decisions.

Furthermore, in terms of operational cost efficiency, the easy-to-use technology provides simple set-up and user independence, meaning existing personnel can use it offshore without the need for specialist operators.

In short, it has the potential to deliver a transformative effect on the economics of deepwater fields.

The efficacy of the portable technology, which has already been proven at Statoil’s Mongstad refinery, is often used to correlate GC results elsewhere. It works by using reagents that only react with the chemical it is designed to assess, and is added directly to samples without the need for a manual water separation step: saving time, and preserving the testing integrity.

Meeting the challenge

As the stirrings of an industry on its way back intensify, how operators seek to successfully address the specific challenges these frontier projects present will be fascinating.

Key to boardroom discussions that drive investment decisions will be the impact innovations and technological developments have on transforming upstream and downstream risk; safety and economics: even in complex reservoirs and remote discoveries.

Against this backdrop, and as the sector continues to adjust to US$50 - 60/bbl oil, OMMICA technology is a rare example of a win-win solution: one that is both more cost effective than the current industry standard, while providing an as-accurate and quicker result.

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