As the PETGAS JIP moves into its third phase, Professor Quentin Fisher explains the aims and technology behind a comprehensive database focused on characterising the world’s tight gas reservoirs
In Europe at least, tight gas has been something of a footnote in the wider unconventionals boom. Despite significant resources, much attention has moved towards shale gas. For Professor Quentin Fisher, this is a missed opportunity. “I often come across logs from tight gas sandstone reservoirs where the gas-filled porosity and permeability are much higher than for shale plays – I don’t understand why we’ve gone straight to shale gas when there are a lot of tight gas reservoirs,” he tells InnovOil, speaking by phone from his office at the University of Leeds. This reluctance is perhaps partly because the physical properties of these reservoirs remain something of a mystery to much of the industry. Until a few years ago, very little was understood about the multiphase flow properties of these tight gas sandstones. Moreover, even when they could be characterised, profitability might be marginal. But the resources are there. In October, the Oil and Gas Authority’s Southern North Sea area manager, Eric Marston, noted: “We estimate another 3.7 trillion cubic feet [105 bcm] of gas remains from current assets and, potentially, another 5 tcf [142 bcm] combined from further drilling in current fields and discovered undeveloped new fields.” With the correct identification, characterisation and equipment, the development of tight gas could be transformative in the North Sea and further afield. Around 2005, Fisher set up a lab at the University’s University of Leeds’ Centre for Integrated Petroleum Geoscience (CiPEG) to measure and understand the relative permeability and capillary pressures of fault rocks that can result in reservoir compartmentalisation. However, only a few of the major firms were using this data. “We were studying the multiphase flow properties of faults for 2-3 years but found that the industry wasn’t really using the results. Only one or two of the biggest companies really had the in-house capability to use the data,” he explains. “It coincided with a trip I had to Oman about 8 years ago to present some results on a consultancy project I was doing on fault seal but while there it became pretty obvious that we didn’t really have any really good petrophysical property data from tight gas sands.” His observation coincided with a call for proposals for the study of tight gas sands, put out by the UK’s Industry Technology Facilitator (ITF). Fisher’s idea was to develop a detailed database of the petrophysical properties of these gas-bearing sandstones, which could be used to improve wire-line log data interpretations and enable faster characterisation of these reservoirs. This so-called “Atlas of the Petrophysical Properties of Tight Gas Sands” would include detailed descriptions of the properties of individual samples, covering everything from porosity and mercury-injection characteristics to diagenetic history. Having secured the support of 6 major sponsors – including BP, BG Group, San Leon and Wintershall – in 2008 the proposal was formalised as the Petrophysics of Tight Gas Sandstone Reservoirs – or PETGAS joint industry project (JIP).
Heads in the sand Phase I of the JIP saw the team collect 25 tight gas reservoir samples from each of the sponsors and set to work. The result was, as Fisher describes, “a pretty comprehensive database” in which every sample was subjected to detailed analysis. “We measured porosity, permeability as a function of stress, NMR T2, electrical resistivity, ultrasonic velocities, mercury injection capillary pressure, BET, and then integrated these results with microstructural data collected using a scanning electron microscope,” he adds. Around 50% of these samples were from the Rotliegend of Europe (UK, Netherlands and Poland), with the remainder spread across Jurassic, Triassic and Carboniferous reservoirs from Europe, Argentina, Oman, North America and Ukraine. For around 50 samples, the team conducted even more detailed special core analysis (SCAL), delving into their capillary pressures, electrical resistivity as a function of brine saturation, gas relative permeability, and more. Over the next four years Fisher and his researchers assembled these results into a functional database, using it to inform more fundamental understandings of some of the key properties – for instance, what controlled the relationships between porosity and permeability. In 2012 the JIP moved on to its second phase, and did so with largely the same sponsors. This enabled the database to continue to grow and to become more sophisticated. As it did, more data and supporting information was able to be added, including more wireline log data and core photographs. The database became too big to handle using existing software tools, so Fisher’s group developed an in-house data visualisation tool, known as PETMiner. As a repository for all of the assembled data – wirelines logs, image data spreadsheets and more – Fisher says that the software is already being used by several companies but that the group intends to add a lot more functionality before releasing a fully commercial version next year, via a spin-off company from the University of Leeds. A key aim will be to add data-mining capabilities to help identify analogues on the database from easy-to-obtain information, such as the microstructure of cuttings. He added that: “We have already demonstrated that we can provide good estimates of reservoir quality based on the microstructural analysis of cuttings even from very old wells. This provides unique data to allow operators to cheaply reappraise prospects that have been abandoned for being too tight. Our aim is not to develop functionality within PETminer that would allow the non-expert to complete such analysis.” Although assembly of the system has been long, in practice these tools have significant advantages for the industry. “It’s really obvious when people drilled wells, even if they took core and tested them, that it is really difficult to interpret without a good knowledge of the rock properties, and some of these laboratory tests take so long that you couldn’t get that knowledge within one or two years,” Fisher says. “What we wanted to do was to provide it much quicker, and while it wouldn’t have the same accuracy as really detailed tests, it could give them a good ballpark idea.” “If we can get even a small sample we can put it under the electron microscope, compare it to everything else in the database, identify analogues and that allows us to provide companies with broad estimates of their reservoir properties really, really quickly – within a less than a week of getting a sample – and a lot more cheaply,” he says. Even with cuttings, the information already on file can help users estimate porosity and permeability relationships. When used alongside wireline log data, these can be used to infer potential flow rates. If this is useful for reservoirs which obey general rules, it is even more valuable for the exceptions. “It allows you to explain really unusual reservoir behaviour,” he notes. “For instance: If you drill and frack a well and you get lots of water and no gas, you can use the dataset to try and understand why that it is. You can then make decisions as to whether you should walk away or try to sidetrack the well.”
Mercurial strategy One of the most interesting innovations to come from the second phase of project is a very high-spec piece of equipment for conducting mercury injection capillary porosimetry (MICP) analysis. MICP – or Hg-injection – testing is routinely used for determining capillary pressure and may also be used to estimate permeability. The capillary data enables operators to predict gas saturation as a function of the height of above the free-water level. Yet accurate prediction using these measurements can be problematic. Fisher explains: “If you measure sample permeability under ambient stress conditions – that’s what the industry would call routine core analysis – the permeability can be two orders of magnitude higher than measured under in-situ stress conditions, just because samples get damaged when you bring to the surface, they cool and they get microcracks; it seemed very likely the same would be true for mercury injection analysis.” The only response, of course, was to design a new instrument which could perform the test at in-situ conditions. The high interfacial tension of mercury means that it is often injected into rocks at 60,000 psi, meaning the apparatus has to confine samples at even higher pressures – up to 100,000 psi. This required some substantial engineering. However, when the firm contracted to build the components went into administration, much of the build and testing was left up to the University itself with a state-of-the-art control system for the instrument, designed and written by Adam Schiffer of infologic. Nevertheless, the finished equipment has produced some excellent results – and which are often “radically different” to the assumptions made with previous MICP tests. “We can put samples under confining pressures up to 100,000 psi and inject mercury at up to 64,000 psi, and the results from that are looking really interesting.” In this regard, the PETGAS project has managed something fairly unique. “Various other core analysis companies have said that they were going try to build something similar but none of them seem to have done so as far as I can tell, especially under those pressures,” Fisher adds. This increased accuracy could have profound effects in terms of how the industry approaches and estimates tight gas development. Fisher explains: “In some places, such as in Oman, [we found] MICP tests are very good at predicting capillary pressure, but in other places the results can be totally misleading. If you applied them to try to work out the saturation of gas in a reservoir containing large concentrations of delicate clays such as illite, you’d really overestimate the gas in place [GIP], and that would affect economic decisions.”
Triple threat With the conclusion of PETGAS II in July 2016, the team wasted little time before the launch of PETGAS III this autumn. Sponsors Energie Beheer Nederland (EBN) and PDO are already on board, allowing the team to extend the database by a further 15 samples per sponsor, and continue SCAL test work on a further seven samples per sponsor. (For any latecomers, the JIP is still open to new entrants too). The goal, as with Phase 2, is also to improve the information and detail available through PETMiner. “A really big push we’ve had is to integrate all the measurements we make with wireline log data to improve the interpretation of those logs,” Fisher says. In the current database, more than half the wireline logs also have corresponding production rate data, adding further weight to the database’s predictive power. “We think that we can interpret the wireline logs and then estimate the production far better now, thanks to this project.” That is a vital step forward, given the uncertain economic returns of many tight gas developments. “We have to get away from traditional ways of trying to predict reservoir quality. With conventional reservoirs, you tend to pay particular attention to calculating the hydrocarbons in place and less attention to estimating flow rates because they are clearly going to be high. But when you get to unconventionals you really have to think about production rates because they can be so slow that the prospect is uneconomic to produce,” Fisher explains. Doing so will be key to projects in areas like Oman, which in addition to being an “EOR playground”, as Fisher says, have ambitious long-term strategies for tight gas development across some challenging formations. Closer to home, the involvement of EBN in particular signals interest in the potential of North Sea tight gas, and the UK’s Oil and Gas Authority is making similar noise. Although full development could be some years away, Fisher is optimistic about its prospects. “There’s a lot offshore, and if you can get the costs down, there are no [land conflicts] to speak of… With a lot of fracking-capable vessels we might be able to really hammer down the costs, and really open things up.” That precedent has already propelled the sector to dizzying heights in the US. With the right support, tight gas could see a similar transformation. “It’s always been a mantra in unconventionals to sort of ‘learn to lean’ – putting loads of technology research at the front-end so you can cut costs when you get to the production phase,” Fisher opines. Whatever the eventual outcome, the information gleaned by the PETGAS project is sure to be an invaluable tool for decades to come.