Shale mates: UK fracking future

Keen to allay public jitters about shale gas extraction, industry body UK Onshore Oil and Gas (UKOOG) stresses that onshore production in Britain actually dates right back to the 1850s.

Around 2,000 wells were active at some point during that time and around 10% of those were hydraulically fractured (fracked).

The industry has learnt a lot over the past five or six years. It used to be a question of ‘brute force and ignorance’ but now much more technical data is available so pumping equipment is not overstretched

Weir Group’s Keith Peach

What’s changing today is that the industry now looks poised for a rapid expansion over the coming decade compared with the modest 20,000 plus barrels of oil equivalent (boe) a day that’s produced onshore already.

The development of horizontal drilling in the 1990s, recent resource estimates putting the potential of shale gas in central England at well over 1,300 trillion cubic feet and a supportive government greasing the wheels of the planning process, all point to an industry on the verge of a boom.

While there is noisy opposition from some sections of the public and onshore shale gas extraction has yet to make much practical progress in the UK, companies are bracing for an expansion in the industry to mirror that already experienced in the US.

This could lead to growing demand for equipment that already enjoys a proven track record in the established unconventional gas industry overseas.

Lost in translation?

So how much transatlantic experience can be applied directly to any future onshore industry on this side of the pond?

The main difference is in the scale of the geography involved and the UK’s relatively high population density, with the Bowland Basin, which stretches from Cheshire to Yorkshire, and Fylde Coast in Lancashire having little in common with North Dakota or West Texas in the US.

“From Lincoln to Blackpool is very densely populated, so in the UK the industry is likely to move to a process called pad drilling, where you can have up to 40 wells coming off one pad,” says Keith Peach, regional managing director, EMEA, for Weir Group’s oil and gas business, which includes well-known brands within unconventional oil and gas, such as Weir SPM (pumps), and Weir Seaboard (frack trees), among others.

Pad drilling should mean a lot less disruption to communities on the surface.

In fact, once the wells are up and running, most people could drive right past them and be unaware of their existence, with little on show apart from the stump of distribution and safety valves at the well-head, also known as a Christmas tree.

In contrast, the drilling and fracking phases are when the most activity is visible and that typically lasts between seven and 15 weeks.

This is also when some of the most spectacular pumping feats are achieved, typically using truck-mounted rigs.

During the drilling phase, mud is pumped down the well to cool the drill bit and line the walls of the shaft. It also carries rock cuttings back to the surface.

This is followed by the pumping of a cement liner, which forms another protective layer between the well and the surrounding rock.

Both applications are dominated by positive displacement pumps (either rotary types such as progressive cavity pumps or piston types), thanks to these pumps’ ability to handle varying viscosities and suspended solids.

What’s more, their ability to generate flow that is directly proportional to the pump speed ensures that hard-to-handle rock cuttings are sent at the optimal rate to separation and processing equipment without the need for flow meters, which can be prone to clogging.

Cracking under pressure Once drilling is complete, the fracking operation forces a mixture of water, a proppant such as sand and some additives into the rock at heroic pressures that sometime reach 15,000psi, although a more usual pressure in most plays is below 10,000psi.

In US operations it’s not unusual to find up to 40 highpressure pump trucks working together on a single site, Peach suggests.

While centrifugal pumps can be used to transport the mixed fracking fluid around at the surface, it’s only positive displacements pumps that can generate the bruising high pressures needed to inject the fluid into the well with sufficient force to fracture rocks.

All these applications are demanding, but Peach says that pumping technology and the understanding of the underlying processes have come on leaps and bounds in recent years.

“The industry has learnt a lot over the past five or six years. It used to be a question of ‘brute force and ignorance’ but now much more technical data is available so pumping equipment is not overstretched. In 2010 you could expect the fluid end of a pump to last 300 or 500 hours. Now it’s more like 3,000 hours,” he says.

Transporting the contaminated water produced by fracking is another tricky pumping application, because operators want to avoid using high-shear pumping equipment that could emulsify any oil droplets that may be present, otherwise it becomes more difficult to separate during water treatment.

Again, it’s pumps with a low-shear action such as progressive cavity pumps that score well here.

Under control

When it comes to valves and their associated controls, most of the wellhead technology needed for UK shale should be pretty standard, complying with the US industry’s API6A or international equivalent ISO10423:2009.

“The requirement for the UK shale industry will be dependent on the specific geology of the fields in question. However, in practice, most installations are made up of the same key components - wellhead, separators, injectors and storage all of which have different control valve and actuator requirements,” says Derek Olson, business development director with Rotork.

The requirements for the UK shale industry will be dependent on the specific geology of the fields in question

Rotork’s Derek Olson

“The specific actuators used on the wellhead will be determined by the control torque requirement - the larger the down hole pressure the larger the actuator will need to be. From Rotork’s perspective, this could range from our CMA through CVA and up to IQTF.”

In the US, spring diaphragm actuators powered by the produced gas have traditionally been used, but the US Environmental Protection Agency has recently mandated using a different approach in order to limit fugitive emissions caused by bleed gas.

Fugitive emissions are a hot topic in shale gas, because they have the potential to negate the environmental benefits of gas as a cleaner-burning fuel than coal or oil.

Published estimates of how much shale gas escapes during production and distribution vary widely, from less than 1% of production to over 9%.

When a shale gas company in Louisiana, US was looking for an affordable replacement for its existing actuation equipment in line with the latest EPA requirements, Rotork’s local agent Setpoint Integrated Solutions engineered an interface to enable CML-250 actuators to be easily fitted to installed valves and improve the level of control without venting gas.

The actuators were also designed to use solar power because the site was remote.

Pumps and valves are also among the pieces of kit most likely to contribute to fugitive emissions via their seals. Valves in particular are thought to contribute between 50 and 60% of the fugitive emissions from industrial pipes and fittings, according to the European Sealing Association (ESA).

But ESA also says that not all valves are equally suspect, with rising stem valves, such as gate valves and globe valves, more likely to leak than quarter-turn valves such as ball and plug valves.

The two major standards to watch out for are ISO15848-1 and API622. ISO15848-1 classifies valves into three tightness classes (A, B, C), with class A valves having the lowest leak rate, while the API622 standard classifies the packing arrangements used in the valve.

Safety first

While fugitive emissions are undoubtedly important, ensuring that any shale gas wells dotting the densely populated British landscape in the coming decade are safe will be the top priority.

In this case, the emergency shutdown (ESD) technologies developed for the US and other more-established markets should be pretty much ‘drag and drop’-compatible in the UK, according to suppliers.

The scale of the operation may be different in the USA and UK, but the emergency shutdown requirements for functional safety for shale gas remain the same

Emerson’s Riyaz Ali

Riyaz Ali of Emerson Process Systems explains: “Each regulatory body worldwide drives guidelines for safe and healthy working but risk reduction methods remain the same. It is mandatory to comply with IEC61511 for functional safety in certain countries and others consider it as good engineering practice. The size of the installation may vary and so the number of safety instrumented function loops but the risk reduction objectives remain the same: to protect personnel, the environment and the asset from any occurrences of hazardous events.

“The shale gas industry has been growing and experience is being accumulated over time. The scale of the operation may be different in the USA and UK, but the emergency shutdown requirements for functional safety for shale gas remain the same wherever it is.”

Most well pads will be unmanned in the UK, as they are in the US.

The only real difference from an ESD perspective is that UK pads will not be as remote so a reliable power supply is unlikely to be as much of an issue.

According to Emerson, one shale site that uses its PressureGuard Wellhead Protection system in western Utah, US is so cut-off that it takes technicians a full day to get there if there’s any troubleshooting to be done.

While nowhere on the small island of mainland Britain is quite that inaccessible, it will still be essential for safety systems to provide immediate safe shutdown when needed, without requiring onsite intervention.

Where power supplies are unavailable, US sites often use a manual hydraulic pump to set the ESD actuator initially (as is the case with the Emerson PressureGuard Wellhead Protection system previously mentioned) so it can then respond to any problem without the need for external power.

However, typical UK sites will be able to access other power options for valve controls, such as automated pneumatic, hydraulic or electric systems.

With opposition to shale gas remaining in some quarters, we’ll have to wait and see whether the nascent boom in UK production materialises.

But the government’s Task Force on Shale Gas launched its third report last month, finding that “shale gas has a role to play as an interim baseload energy source in the UK energy mix over the medium term”, apparently bringing it just a little bit closer.