Not all fields are created equal
Good morning everyone.
I’m pleased to join this executive session on the global gas challenge, because Shell sees natural gas as increasingly crucial to meeting the world's energy needs.
We also believe it is imperative to make the most of all the gas resources available, both conventional and unconventional.
Today I want to touch on some of the inherent challenges of developing unconventional gas resources: first, in terms of geological factors; then non-geological factors. Along the way, I will highlight how unconventional resources differ from conventional ones – especially in terms of the predictability of their production potential and ultimate recovery.
That difference is crucial. It explains why, when you’re considering the development of shale gas resources, a lot more information and a more flexible mindset is needed.
Geological variability & uncertainty
First, a word about terminology. I’m using the term “tight gas fields” to refer to fields that produce natural gas from formations consisting of ultra-tight sandstones, carbonates, shales and coals, and where the gas is not confined by a conventional trap of a structural or stratigraphic nature.
Having cleared that up, let’s now consider what’s so special about them.
The first geological factor to consider with tight gas fields is their lithology. These fields vary widely in their rock properties – much more so than conventional fields.
Some rock formations are clayey and thus, at certain temperatures, ductile. Others are brittle, making them easier to crack. Some have no pre-existing fractures, but some do. And these pre-existing cracks can contribute to well productivity…unless they don’t.
There’s no way of knowing what type of rock formation you’re dealing with until you actually drill and production-test the formation.
These lithological properties – and their implications for well completions – are difficult to predict at the exploration stage, but they can drastically affect field development plans. And what’s more: they can vary even from one well to the next in the same formation!
A second important factor is the geomechanics of these formations. There is a lot of uncertainty about the magnitude and orientation of principal in-situ stress axes around a well. This can make it difficult to get hydraulic fractures to grow in exactly the way you want.
Conversely, the more you understand the geomechanical stresses, the better you can get them to work in your favour – perhaps even reducing the needed scale of hydraulic fracturing.
Gathering & assessing facts
All this variability and uncertainty means that, before one can decide whether a shale play is worth developing or not, one needs to collect and analyse a lot of appraisal data. Usually, a few good 2D seismic lines are required to understand the basic tectonic framework and layout, perhaps with a few limited 3D seismic surveys where more complicated structures are expected.
Then a dozen or so wells need to be drilled, logged and tested. And it's not just a short production test as it generally is for conventional gas plays.
Longer production tests are necessary, because unconventionals are exactly that: unconventional. The traditional approach won’t do; they need a more in-depth approach for an operator to get a good idea of the ultimate recovery per well and the likely production profile. Both data are crucial since they determine the economic viability of these challenging plays.
So it’s quite crucial to ensure geoscientists and petroleum engineers have enough time to take a good, thorough look at the situation under the ground.
This can try the patience of people who want immediate yes/no answers: the investors who are putting their money on the line, for example…or the communities who feel that their way of life may be threatened. But there’s no other way to avoid false expectation other than through a thorough exploration and appraisal campaign.
That’s why I don’t like all the hype about the potential – good or bad – of untested tight gas plays. We first need to collect all the facts and soberly assess them before we can reasonably talk about their commercial potential.
If you don’t succeed…
Yes, there have been some great success stories in producing gas from shale formations, with some big ones such as the Bakken, the Barnett, the Eagle Ford, the Bossier-Haynesville in the US or the Montney in Canada.
But let’s not forget that there have been a fair number of disappointments too. We don’t hear much about them.
In the US states of Wyoming and Utah, for instance, the industry could not get the Green River basin to really work. And I’m afraid that some countries may be setting themselves up for dashed expectations. Take Poland, for instance, where a number of operators have announced that they're pulling out.
Getting definitive results requires tenacity, but tenacity driven by a good understanding of the petroleum geology. Only production geologists can know where the rocks are favourable and therefore where persistence is warranted.
The geological factors I’ve mentioned make tight gas plays quite different from traditional gas fields. But there are several non-geological factors that also call for an approach to field development that’s different from what we’re used to in conventional fields.
For Shell, a tight field development is largely about safe manufacturing techniques with mass-production-like drivers: speed, cost control, streamlining. But unlike product manufacturing, where feedstocks are quality controlled for uniformity, we have to deal with what Mother Nature gives us – and she can surprise us.
Nor should we dismiss the possible impacts such developments have on local land, water and air. Or the dust, noise and road accidents that heavy-goods traffic can cause.
Clearly, it will take a bigger technological tool box to enable operators to deal with both geological and non-geological factors. But before I describe some tools that can help, I’d like to stress again what these factors lead to in practice: unpredictability – much more so than in conventional developments.
So it’s very difficult to say with certainty how – or even if – an undeveloped shale gas play can realistically be successfully developed.
And that’s why it’s so important that high expectations be kept in check.
A recent report by the Institute of Directors called UK shale gas a 'new North Sea'. But this is premature: the geology still needs to be investigated.
Let me remind you that the Alum shale in Sweden was described as 'one of the thickest and richest marine source rocks in onshore northern Europe'. Yet Shell’s exploration wells revealed it to have only low gas saturation.
Equally, a blanket moratorium on exploration seems rash if the underlying geology has not been investigated – as, for example, in Romania, France and elsewhere.
Hence my underlying point: the need for greater flexibility to assess the geology properly, to avoid both overblown optimism and ungrounded pessimism.
That’s why I was gladdened by EU Commissioner Günther Oettinger’s recent statement. He wants Germany not to completely reject hydraulic fracturing, but instead create an appropriate regulatory structure – one that will enable the country at least to allow exploratory drilling. Subsequent decisions will then be “smarter” and based on a better understanding of the costs – and benefits – of a field development.
Greater flexibility in planning and execution is also needed – particularly where production-sharing contracts apply. A development plan for an unconventional field needs to give the operator the opportunity to adapt the plan according to the geological realities as and when they become apparent. The production-sharing contractor must be able to adapt a field development plan on the fly. Regulations need to allow this.
A key ratio
Where greater flexibility in exploration and development has been achieved, there are several tools that can help to deliver good outcomes. From an operator’s point of view, the outcomes can be measured in terms of a key ratio: productivity over cost.
One way to increase well productivity without appreciably increasing costs is to make sure that the hydraulic fractures work as intended. We’ve discovered that about a quarter of ours are ineffective: they don’t really contribute to a well’s production.
By modelling fracture mechanics better, we can understand how multiple hydraulically induced fractures will grow and interact with one other in heterogeneous formations. Shell has been studying this using advanced numerical models. The model is able to capture the influence of key parameters such as fluid-injection rate, fracture spacing and formation properties. We’re currently working to extend the model to gain insight into the interaction between hydraulic fractures and natural fractures.
And that leads me to another productivity-enhancing technique: what we call “domain stimulation”.
It turns out that the prevailing stress field occasionally enables one to enlist the help of pre-existing fractures. These natural fractures are normally shut tight, but the ones near a wellbore can – under the right in-situ stress and injection conditions – be forced open during hydraulic stimulation operations.
In such a case, the planes on either side of the fracture shift ever so slightly with respect to each other. When the hydraulic pressure is relieved, the planes no longer fit together perfectly. The result is a flow path for gas. In Canada, we’ve used domain stimulation in openhole completions to successfully increase well productivity.
Automation & standardisation
Now let’s look at the denominator in our key ratio. How can we decrease the cost per well?
Tight and shale gas fields require hundreds or even thousands of wells to extract the gas. Our industry simply doesn't have the manpower to handle that increase in activity. So we need more automation in drilling, completing and operating wells.
That’s why Shell developed the SCADAdrill autonomous control system, for instance. It connects to the existing instruments and controls of a drilling rig, operating the rig machinery and monitoring all aspects of the well-making process. Letting a machine handle the mechanical and hydraulic drudgery means that the driller can focus on things that require more thought and care – safety, for one.
The driller at the rig site is always in control, though. And he can intevene at any time if necessary.
SCADAdrill also enables expert directional drillers and well engineers at a real-time operating centre to monitor the rig remotely. They can adjust the control settings as required. Using such real-time operating centres, one directional driller can monitor several wells at once rather than just one at a time.
More standardisation is also needed in drilling and completing wells – the kind of approach that Shell is pursuing in a well-manufacturing joint venture with the China National Petroleum Corporation. We’re pursuing a 'conveyor belt' approach in which standard pieces of equipment carry out different stages in the drilling and completion process. In this way several wells can be worked on in parallel, rather than having one customised drilling rig working on one well at a time.
Finally, both productivity and cost can be optimised with better well monitoring – which Shell is addressing by integrating fibre optics with existing monitoring equipment.
An optic fibre can act as one continuous thermometer capable of measuring temperature anywhere along its length. Such distributed temperature sensing – or DTS – has become a well-established technique for monitoring wellbore activity, such as hydraulic fracturing. To this end, a fibre-optic cable is clamped on the outside of the production casing, and data are recorded and visualised as the treatment is carried out.
Recently, we’ve begun to deploy cables containing two optic fibres – one for thermal sensing and one for acoustic sensing, to pick up the sounds of fluids flowing. With this arrangement, we get immediate readings of how the treatment is progressing and can derive a better description of the actual result.
Tools for non-technical challenges
Shell is working just as hard on solutions to the non-technical challenges. One of these is reducing the environmental footprint of tight-gas activities.
Advanced water management practices are making a significant difference here. Through reuse and disposal practices, we’re able to reduce water consumption in drilling. At the Groundbirch gas field in Canada and the Pinedale gas field in the US we reuse gas-processing water for hydraulic fracturing. This reduces our freshwater requirements significantly – by as much as 50% or more.
And wherever possible, we use non-potable water for drilling and completion fluids. At Groundbirch, we’re using sewage water – treated, of course – from the neighbouring city of Dawson Creek. In fact, the combination of reusing frack water and topping up with treated waste water means that we won’t need any fresh water at all in our operations there.
A while ago, we published the Shell Operating Principles for tight sand and shale oil and gas operations. This is not so much a tool as it is a handbook, but we nonetheless keep it in our field-development toolbox.
The principles are specifically designed to protect water, land, air and communities. For us, adhering to them is an important part of building trust locally, nationally and internationally.
And we’re constantly looking for other opportunities to raise the standards for the industry. The Marcellus play is a good example. We’ve formed a coalition there with several operators who are willing to give audit rights to an independent third party. We hope to see more initiatives like this. They might set the bar high enough to meet the public’s and government’s expectations and to weed out irresponsible operators.
To wrap up…
Let me end by emphasising three points:
First, natural gas is at the heart of a sustainable energy future, and we need to make responsible use of all possible sources, conventional and unconventional.
Second, with unconventional plays, it is not possible to know the cost and benefits of a field development without due diligence – and that requires exploration and appraisal wells. If the results are favourable, then flexibility for planning and execution is also required in production-sharing contracts and regulatory regimes.
Third, innovation – in both technical and non-technical areas – holds the key to lowering costs and increasing benefits. I’ve mentioned a few new technologies today, but there are many more that should be developed.
The good news is: the current pace and quality of innovation make me optimistic that natural gas from unconventional sources can help to keep the lights on and people and goods on the move – and to do it ever more sustainably.