Some 25 trillion cubic feet (Tcf) of natural gas was produced in the U.S. and Canada in 2002, and unconventional reservoirs contributed 20% of that supply. In its 2003 Natural Gas Study, the National Petroleum Council estimates that total gas production from the U.S. and Canada, excluding the Arctic regions, will struggle to remain at the 25-Tcf level in the future, and that unconventional gas will be essential to the supply mix. By 2025, the NPC expects unconventional gas will account for 10 Tcf, or 40% of the gas flowing from the non-Arctic regions of North America. The definition of unconventional gas resources varies, but most industry participants and observers include gas occurring in tight sands and carbonates, coal seams and fractured shales. According to the U.S. Geological Survey, conventional fields are discrete geographic entities with well-delineated hydrocarbon/water contacts. Their reservoirs generally exhibit high matrix permeabilities and obvious seals and traps. The recovery of gas-in-place resources is high. Unconventional resources are quite different. They are diffuse deposits, without clear boundaries, and the reservoirs have low matrix permeabilities. The seals, traps and hydrocarbon/water contacts are not apparent. Most significantly, the recovery of gas-in-place resources is very low. Exactly how much gas is available from unconventional resources is an open question. "There is tremendous uncertainty about how large that resource base actually is," says Vello Kuuskraa, president of Arlington, Virginia-based Advanced Resources International Inc. "There is so much we don't know yet about the quality of these resources." Huge numbers are assigned to in-place unconventional resources, based on assumptions that vast portions of many sedimentary basins are gas-saturated and likely to be naturally fractured. Estimates of the recoverable unconventional resources-which considerably discount the in-place numbers-usually range in the hundreds of Tcfs for the Lower 48. There are unconventional oil resources as well. California hosts the greatest concentration of heavy-oil resources in the U.S. And, western Canada's heavy oil sands comprise an eye-popping resource, underlying 54,000 square miles in northern Alberta. Bringing unconventional resources on production is not an easy task, and the learning curve is steep. By their very definition, unconventional reservoirs do not follow the classic concepts that are dear to the hearts of many industry professionals. The exploration strategies, drilling techniques, completion programs and even production protocols have to be re-invented or adjusted. Questions are abundant: where and why does water production occur, can certain reservoirs be dewatered, where are the fracture systems, what is the nature of the rock properties, when should horizontal wells be used and where should they be placed? "The development of the knowledge base is the key challenge," says Kuuskraa. "The industry has to develop a fundamental knowledge about unconventional reservoirs, how they behave and what their characteristics are." Technology is an essential part of this growing knowledge base, and it is quickly evolving to fill the needs of operators. Low-perm gas reservoirs Tight-gas sands produce far and away the greatest volumes of unconventional gas, totaling nearly 3 Tcf in 2002, says the NPC. Other estimates put the total even higher, at 4.3 Tcf, or nearly 12 billion cubic feet (Bcf) per day. Tight reservoirs occur throughout the continent, ranging from Upper Cretaceous Lance and Mesaverde sandstones in Wyoming's Green River Basin, to West Texas plays in the Pennsylvanian Canyon, to East Texas sands in the Upper Jurassic Cotton Valley and Bossier. Fractured shales are another notable source of unconventional gas. These targets are both source and reservoir in one package, and much of the gas is entrained in the formation. Currently, fractured shales produce about 500 Bcf per year in the U.S. The Mississippian Barnett Shale in the Fort Worth Basin of North Texas is far and away the leading fractured-shale play in North America. (For more on this, see "The Barnett Barrels Along," Oil and Gas Investor, December 2003.) "For all low-permeability reservoirs, the biggest development expense is drilling," says Steve Holditch, Schlumberger fellow. "Anything that you can do to reduce drilling costs is good." Tools that help locate the prime places to drill are also naturally of high interest to players in the unconventional arena. The Gas Technology Institute has been working on a technology that can identify a play's sweet spots, according to Ed Smalley, GTI business development director. Smalley spoke on unconventional gas at a recent conference in Denver, hosted by the Independent Petroleum Association of Mountain States (IPAMS). Instantaneous spectral analysis is a seismic processing technique that uses tuning frequency anomalies, low-frequency shadows and anomalous attenuation of seismic signals to reveal information about the presence of hydrocarbons, rock properties and stratigraphic features. Being able to properly identify the pay zones in low-permeability reservoirs is another fundamental need. Tight gas sands can cover thousands of feet in a well, and operators must be able to select the parts of the reservoirs that will be the most productive. Logging suites have to be specifically geared to this need. Nuclear magnetic resonance imaging aids with permeability measurements, and spectroscopy tools that identify elements improve the evaluation of porosity. Some of the image logs illuminate natural fractures and stratification. "All of these logs have been developed in the last five to 10 years," says Holditch. Improving the effectiveness of hydraulic fracture treatments is another crucial factor. Several new fracturing and acidizing fluids, using visco-elastic surfactants, appear to be delivering good stimulation results. Oriented perforating is an emerging technology that can benefit operators as well. This wireline technology perforates the casing in the preferred direction of fracture growth, which corresponds to the natural fracture systems. Oriented perfs allow a treatment to be pumped at lower injection pressures, with fewer problems, and deliver superior results. "This is one the best technologies developed in a long time. It's really made a difference in the success ratio and economics of hydraulic fracturing, especially in hard formations such as tight-gas reservoirs." Other technologies that are shaping unconventional gas development include stimulation isolation, water fracs and refracture treatments, says David Craig, Halliburton. Research efforts are directed at improving frac results in the multi-layered reservoirs that are characteristic of tight-gas sands. "It's not unusual for a tight-gas well in the Rocky Mountain region to have 20 or more intervals that require stimulation," he says. The completion efficiency-the percentage of targeted sands that are producing after completion-is not impressive in tight-gas plays in the western U.S. "In the Piceance Basin, the completion efficiency is about 70%; in the Greater Green River Basin's Jonah Field it is about 60%." The causes are bypassed zones and poor fluid recovery, Craig says. One solution is to isolate the frac stages through such equipment as flow-through composite bridge plugs. Pinpoint stimulation with an isolation packer can also help overcome the problem that occurs when the stimulation treatment goes into certain zones and bypasses others. Water fracs have revolutionized development of tight-sand reservoirs such as the Bossier in East Texas. These fracs, which use very little proppant, are much cheaper than the previous method of fracture treatment. However, it is important for operators to track results of such stimulation treatments to help in determining if the frac was actually completed as designed, he adds. "You have to look at what happens one year, two years and three years after a fracture treatment to really know if it was done correctly." Analyses of pressure build-up tests and production data can show if the desired frac lengths were achieved; if not, the treatment program needs to be redesigned. That's what has happened in the Bossier play, where post-frac studies indicated that the half-lengths of the water-frac treatments were not nearly as long as desired. The typical Bossier stimulation has now evolved to a hybrid frac, which is a slick-water treatment that adds back in some cross-linked fluid and up to 250,000 pounds of proppant. "Water fracs can be beneficial in low-permeability plays, but proppant and gel may not be bad. You have to do a systematic evaluation of the results." Refracs are another technique that is popular in several plays, notably the Barnett Shale in North Texas and the Codell in eastern Colorado. Refracs have been very successful in blanket zones and generally unsuccessful in lenticular formations. A cost-effective test is now being developed to identify candidates for refracs, based on a target zone's response to a small pump test, says Craig. Coalbed-methane reservoirs Coalbed-methane (CBM) production has grown the fastest of all the unconventional gas categories, and in 2002 it contributed 1.6 Tcf to total U.S. gas production. Instead of being tight, CBM reservoirs have a dual porosity system. Gas flows from both tiny pores in the coal matrix and from the cleat system. The gas adsorbed in the coal has to be produced at very low pressures. The permeability of CBM reservoirs can vary widely. If permeability is very low, the flow rates are not economic. But if the coals are too permeable, they are difficult to dewater. "There's an optimum permeability, somewhere in the 20- to 100-millidarcy range, where it's easier to dewater the coal but there is still enough permeability to flow a lot of gas," says Holditch. As in tight reservoirs, the challenges for CBM development are also related to drilling and stimulation. At times, horizontal or multilateral wells are better solutions than vertical wells because the coal seams can be thin and naturally fractured. CDX Gas LLC, a private Dallas-based company, has developed a horizontal drilling technique that has delivered excellent results in horizontal drilling in coal seams in West Virginia. The company has drilled 120 of its dual wells to date. Its system uses a vertical well coupled with a second horizontal or service well that can include many lateral branches. Recoveries are quick: CDX says that its system can recover 85% of the gas in place in 36 months. As a comparison, a vertical well drilled on 75-acre spacing might cost a CBM operator $145,000, while a CDX horizontal well would cost $1.4 million and drain 1,200 acres. "The horizontal CBM wells are very promising," says Scott Stevens, Advanced Resources International vice president. "The footprint is smaller and fewer wellsites and roads are needed. It can be a huge advantage." Also, many vertical CBM pilots do not dewater an area effectively, as it can take years with just a handful of wells. "With horizontal wells, you can get an answer about whether an area is good much faster." Other concerns with CBM are that wells must be produced at very low pressure to obtain the best gas recovery. Excellent pumping systems are needed to produce the water and reduce the bottomhole pressure, says Holditch. Finally, low-cost and efficient methods for water handling and disposal are critical. Heavy oil California enjoys abundant heavy-oil deposits in the San Joaquin Basin that are produced by various thermal methods. Production is fairly steady at between 400,000 and 500,000 barrels per day, and looks to continue in the future at that level, says Kuuskraa. Canada's immense deposits of oil sands are of lower quality, but they are the backbone of its production future. The Alberta Department of Energy says oil-sands production currently comprises 35% of Canada's total crude output, and by 2005 will account for half of the country's oil production and 10% of all production in North America. The oil sands, mixtures of unconsolidated sand, clay, water and bitumen, occur in three main areas-shallow deposits in Athabasca, near Fort McMurray, that can be recovered by surface mining, and deeper bitumen deposits in the Cold Lake and Peace River regions that must be recovered in place by thermal or cold heavy-oil production with sand (CHOPS) methods. The Alberta Energy and Utilities Board estimates the province's in-place oil-sands reserves at 1.6 trillion barrels, of which about 7% is mineable. The portion of that resource that can be counted as proved reserves is open to debate, but the EUB places it at 174 billion barrels. More than 80% of those proved reserves will have to be recovered by such in situ methods as steam assisted gravity drainage (SAGD). In 2002, Alberta produced 823,000 barrels of crude bitumen per day-540,000 barrels from mining projects and 292,000 barrels from in situ operations. By 2010, the EUB forecasts Alberta will produce 1.55 million barrels of mined crude bitumen and 773,000 barrels of in situ crude bitumen per day. Calgary-based Suncor Energy Inc. has been working in the oil sands since 1967, when the original upgrader was built. In third-quarter 2003, the firm was producing 231,500 barrels of oil equivalent per day from its oil-sands operations at its Millenium and Steepbank mining projects. Now it is adding another page to its production portfolio. "We've just started steaming the first phase of our in situ operation," says Brad Bellows, media relations. "We'll begin commercial production from Firebag in early 2004, and move up to full capacity at the end of 2004 and beginning of 2005." Currently, Suncor has four phases of Firebag approved, each of which will produce 35,000 barrels of bitumen per day, and it is looking at future phases beyond those. In situ projects begin with core-hole drilling to delineate the resource, then proceed to construction of pads. At Suncor, each pad contains about 20 well pairs consisting of stacked horizontal wells about a half-mile in length. The top bore is the steamer, and the bottom well is the producer. As the bitumen is heated, it flows into the producing wellbore and is pumped to the surface. Suncor is also upgrading its facilities that convert bitumen to synthetic crude. In 2005, the company is targeting production from oil sands of 260,000 barrels per day, and it plans to raise output to more than 500,000 barrels per day by 2012. Suncor has a lot of company these days in oil-sands development. Syncrude, a joint venture of Imperial Oil, Petro-Canada, ConocoPhillips, Nexen, Murphy, Mocal and Canadian Oil Sands Trust, runs another major mining project. That venture currently produces some 250,000 barrels per day, and plans to be making in excess of 550,000 per day by 2012. Recently in production is the Athabasca oil-sands project, a joint venture of Shell Canada, Western Oil Sands Inc. and Chevron Canada. As of July 2003, the project's Muskeg River mine was producing 120,000 barrels of bitumen per day. This year it will reach 155,000 per day, and is forecast to hit 180,000 per day by 2005. The same partners are also under way with another mine project, slated to produce in 2010. The Jackpine Mine will produce 200,000 barrels per day from its first phase and an additional 100,000 per day from its second phase. Also, Canadian Natural Resources Ltd. has its Horizon oil-sands project in the works. It forecasts production of 110,000 barrels per day of synthetic light crude by the first half of 2008. Production will eventually jump to 233,000 per day in 2012. Finally, Imperial Oil is proceeding with plans for its Kearl project. The first phase is sized at 100,000 barrels per day; full development would result in 200,000 barrels of bitumen per day. First production could begin by mid-2009. Alberta's in situ bitumen production will show equally impressive growth. Imperial's Cold Lake project is currently producing 120,000 barrels of bitumen per day via a cyclic steam-injection process, and it plans to add another 30,000 barrels per day from a new area called Nabiye. The company forecasts its Cold Lake production will reach 180,000 barrels per day by 2010. Other operators with in situ projects include Canadian Natural Resources, EnCana Corp., Petro-Canada, Devon Energy, and Nexen and Opti Canada Inc. On the technical front, heavy-oil operators are looking for better ways to heat the reservoir to reduce the oil viscosity, as well as improvements in processing technology to up the value of the product, says Holditch. Low-pressure operations and the injection of gas or solvent along with the steam could improve SAGD performance, for instance. An unconventional future Clearly, unconventional resources figure large in the future supply picture. Nonetheless, they are very sensitive to commodity prices, says Kuuskraa. At the same time, conventional resources are more costly to develop because today's wells are not as prolific as those drilled in the past. The gap between the finding, development and production costs of unconventional and conventional resources has been steadily narrowing. Most unconventional gas production is economic at $3.50 per thousand cubic feet, and most heavy oil is economic at $25 per barrel, estimates Holditch. "As commodity prices increase, these resources become even more attractive and it is possible to produce resources of even lower quality." A note of caution: overall, unconventional reservoirs take far more engineering and geological time and effort than do conventional reservoirs. "The hard part about conventional reservoirs is finding them," he says. "With unconventional reservoirs, you know where they are but the hard part is making money."
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