technology to get at it? Now that's a different storyBy Peter McKenzie-Brown
Photo: Rig for coil tubing. This article appears in the June Unconventional Gas Guide
In a recent presentation to the Petroleum History Society, Dave Russum – geosciences vice-president for AJM Petroleum Consulting – recounted the development of unconventional gas in Western Canada. According to Russum, evolving technology is making unconventional gas – what he says should correctly be called “conventional gas from unconventional reservoirs” – a commercially viable commodity. Despite the lower-price environment for natural gas, rapid innovation in down-hole technologies has made shale reservoirs viable sources of gas production.
The most important of these is horizontal drilling. Since the technology became widespread in the late 1980s, horizontal drilling has been enhanced by increased drilling efficiency. Much longer horizontal legs are now possible: many are two and three kilometres in length. This is possible because of improvements in bit design, the increasingly effective use of coil tubing and better down-hole motors.
Geo-steering is another increasingly critical down-hole technology. In recent years it has been given a lift by high-impact measurement-while-drilling (MWD) tools and techniques.
Another contributor to the shale-gas revolution is multi-lateral horizontal drilling – the ability to drill several laterals from a single well. As one example, last year Trident Exploration drilled a 2,400-metre vertical well into the Montney formation near Dawson Creek. At depth, the company drilled two 1,000-metre horizontal laterals. This achievement illustrates the revolution taking place in horizontal drilling – although 1,000-metre laterals are puny by the standards of some drilling programs.
Two other technologies are more directly related to reservoir production. The industry can now isolate many completion zones in horizontal wellbores. This makes reservoir fracturing possible over long distances. What’s more, microseismic technologies now enable geo-engineers to improve reservoir development and productivity by monitoring fracture efficiency within reservoirs.
Although these technologies are increasing in sophistication and declining in relative cost, they have led to a fundamental change in gas-field economics. The petroleum sector’s spending patterns are shifting, with a much bigger portion of the development pie now being invested underground. For the first time, the industry is investing more down-hole than in gathering lines and other surface facilities.
Microseismic has made great strides in the last decade. One of the leaders in this area is Houston-based Microseismic Inc. The company was founded in 2006 by Peter Duncan, who originally hales from New Brunswick, got his Ph. D. in geophysics from the University of Toronto, and cut his teeth in resource development in Alberta and offshore Nova Scotia working for Shell Canada. He stresses that the technology in itself is not new. It is well established academically and within government organizations – for use in earthquake location, for example. Applying the technology to producing reservoirs, however, is a new and rapidly developing field.
Duncan explains microseismic with vivid analogies. “Regular oil and gas seismic is like an X-ray,” he says. “Microseismic is more like a stethoscope. You can ‘hear’ the sound of fluids underground.” This is an area of rapid technological growth.
According to Duncan, “We can cement geophones on the surface and underground to enable people to better produce these gas shales, and monitor production for the life of the field. With the developments we are making today, these arrays are like a big-dish microphone. (Using a computer) you can essentially beam-steer that array around the reservoir to find out what’s going on where. The cost-effective way to do this is to set up a permanent array of phones to monitor the fraccing of every well during the development of the field.” For shale gas production, a key feature of this technology is that it can tell you where well fraccing has been effective, and where it hasn’t.
“With this system, you can monitor other subsurface phenomena – for example, the injection of water or other production fluids into the reservoir. An important application has been the use of these systems to monitor cyclic steam injection in the oilsands.” Both Shell and Esso have been doing this, although using different microseismic suppliers.
What’s the cost? Microseismic is more expensive in the Montney formation than it is in the Barnett shales of northern Texas, for example. However, a technical paper from EnCana has suggested that the incremental cost of monitoring a frac stage with one of these permanent arrays is relatively small – fully amortized, about $10,000 per frac stage. If that monitoring enables geo-engineers to increase ultimate gas production by correcting fracturing inefficiencies, it’s a small price to pay for what could be much greater cash flow.
The workhorse of underground technologies is coil (“coiled”) tubing – a tool that began to make big inroads into industry operations around 1990, and has since transformed many aspects of underground drilling and workover operations. It refers to metal piping spooled on a large reel and used for interventions in wells and sometimes as production tubing in depleted gas wells. Coiled tubing is often used to carry out operations previously done by wirelining. The main benefit of coil tubing over wireline is that you can pump chemicals through the coil. With coil tubing you are able to push tools and chemicals into the hole; wirelining relies on gravity.
The tool string at the bottom of the coil can range from something as simple as a jetting nozzle, for jobs involving pumping chemicals or cement through the coil, to a larger string of logging tools, depending on the operations. Coil tubing is also used for relatively inexpensive work-over operations. It is used to perform open-hole drilling operations.
Of particular importance in the context of shale gas production, coil tubing can be used to fracture the well – a process where fluid is pressurized to thousands of psi on a specific point in a well. This blasts the rock into rubble, thereby permitting the flow of hydrocarbons to the well-bore.
The move to more intensive down-hole spending is shifting the industry away from its traditional ways of doing business, and even the seasonal patterns it follows. Consider fraccing.
Fraccing is a stimulation technique which improves production from geological formations where natural flow is restricted. Hydraulic fracturing pumps a mix of water, sand and some soluble chemicals into the well at high pressure, thus fracturing the formation and holding the fractures open so hydrocarbons can flow more freely into the wellbore.
Dave Russum takes the story from this simple explanation to the use of multi-stage fracturing techniques on horizontal wells. “Between the heel and the toe of a horizontal well,” he says, “you isolate an interval close to the toe and frac that region. Then you move back towards the heel, isolate another interval and do another frac. This breaks up a lot of rock, making a lot more gas available. These new technologies are enabling us to access a whole lot more low-permeability rock than you would ever be able to reach with a vertical well.”
In the days of vertical drilling, producers generally fracced just one or two zones per well. With today’s technology, it is possible to frac a single well up to 17 times – although a well that required so much work would likely have a horizontal reach of 3,000 metres or more.
To fracture just one of EnCana’s Horn River shale gas wells in north-eastern BC, you need a fracturing crew equipped with perhaps 45,000 horsepower of compression. To put that in perspective, in Western Canada perhaps 800,000 horsepower is available.
“We do not believe that there will be sufficient capacity to perform all of the jobs necessary, should (BC’s Horn River and Montney shale gas) plays grow,” said Kevin Lo of FirstEnergy Capital in a research note. He also worried about the logistics of bringing in enough propping agent: fracturing a single horizontal well in these reservoirs can require up to two thousand tonnes of sand.
Dale Dusterhoft, a senior vice president at Trican Well Service, paints an even grimmer picture. “Some of the Horn River wells require up to 45,000 horsepower of compression,” he says, “and with 10 holes per pad you may have 40,000 horsepower tied up for 10 weeks.” He adds, “There will be shortages of equipment when we get up to full development of the shales” – a plus for service companies like his own, which will then charge premium day rates, but a worry for the big players in the region.
Although environmentalists have voiced concern that fraccing chemicals may contaminate groundwater, Dusterhoft argues that before wells are fracced the formations are securely sealed away from potential fresh-water reservoirs. And anyway, he says, in the unconventional wells in north-eastern BC “we only use a polymer as a friction reducer, and maybe something to stabilize the clays. Mostly we just run water and sand.” When fraccing is completely successful, he says, “All the fractures connect up with each other, so we can get maximum production. We like to say we can ‘farm’ the reservoir.”
Huge fraccing jobs like those in north-eastern BC require a great deal of logistical support. Each hole can require 2,000 to 3,000 tonnes of fine-grained sand as a propping agent. Imagine the parade of trucks bringing such a harvest of ancient beach sand up the road to north-eastern BC – often from quarries in Saskatchewan. To take on such a project may require a 40-member crew and 20 or more hydraulic compression systems mounted on huge fraccing trucks.
Because so much water is required, a typical job requires a large water storage pit in addition to a string of high-volume steel tanks. The amount of water being used in these jobs has actually led to a seasonal shift in the fraccing business. According to Dusterhoft, “Now (the industry is) drilling during winter freeze-up, as we always have, but fraccing in the summer. All the bigger operators are trending in that direction.” The reason is that the water is easier to deal with in warmer weather. In the longer term this will require upgrading to all weather-roads to Horn River and Montney. Until those upgrades are completed, service companies are leaving equipment in the area during freeze-up.
The shift to unconventional gas production occurred much more quickly than anyone expected, Dusterhoft said, and it has important implications. For one thing, it is contributing directly to the reduced number of wells being drilled in Western Canada. There are now about as many horizontal wells being drilled as those being directionally drilled.
To put that in perspective, drilling costs at Horn River are in the $5-7 million range per well, while they are maybe $4-5 million each at Montney. Add to that the cost of fraccing – say, $2-3 million per well – and it’s clear that the industry is putting a lot of money in the ground. But the production profiles for these wells make it worth the cost. These wells may produce 7.5 million cubic feet of gas per day for the first year. Production declines rapidly in the early stages but the optimists believe they may level off at, say, 2 million cubic feet per day and maintain those production levels for years.
Challenging to Extract
AJM’s Russum disputes this. “Each reservoir is different,” he says. “We don’t fully understand the science of shale gas reservoirs. I certainly don’t think we can apply a one-size-fits-all model to their production profiles. Some wells may simply stop producing in only a year or two.”
In wrapping up this commentary, it may be useful to return to Dave Russum’s assertion that there is no unconventional gas – only “conventional gas from unconventional reservoirs.” Russum stressed that shale gas plays are only one part of this important new resource, and that they have all benefitted from advancing technology. He defined this commodity as “any methane not trapped in a porous, permeable, buoyancy-driven system.”
What are the characteristics of these unconventional reservoirs? They are extremely variable. The methane within them is not freely dispersed and they have low or heterogeneous permeability. The source rock and the reservoir are closely related, and these resources represent large but low-concentration resources. They have unusual pressure regimes, and in many cases they represent a lower-quality version of conventional reservoirs. In short, they are more challenging to extract – a state of affairs that can best be resolved with evolving technology, as the story of shale gas amply illustrates.