Suncor’s oil sands project in northeastern Alberta uses a fit-for-purpose rig and specialized equipment to drill scores of tightly spaced, large-diameter horizontal wells with very high build rates, all from a single pad.
Brett Regier, Suncor Energy; and Joe Bruce, Nabors Drilling
Tapping the massive oil sands reserves at Suncor’s Firebag property in northeastern Alberta, Canada, requires the drilling of many pairs of wells, spaced close together, for steam-assisted gravity drainage (SAGD). This in situ production meth od requires precise placement of the producing well’s horizontal section directly below that of the steam injection well. Because the oil sands deposits are relatively close to surface, these well pairs have shallow vertical depths and long horizontal sections, requiring very high build rates. To make matters more difficult, SAGD operations require some of the largest horizontal boreholes of any E&P application. To overcome these challenges and enable batch drilling of many SAGD well pairs to maximize production, the Firebag project employs a specialized rig design and a unique set of downhole and surface tools.
DRILLING WELL PAIRS
The Athabasca oil sands are large deposits of bitumen mixed with sand or clay located in northeastern Alberta. About 80% of the Athabasca oil sands is too deep to be extracted by traditional mining methods, so it must be accessed through in situ production technologies that heat the viscous bitumen so it can flow through production wells to surface—the most widely used of these technologies being SAGD.
Devonian limestone is the underlying rock beneath the oil sands of the McMurray Formation. The caprock consists mainly of silts, shales and clays. The Firebag area is fortunate to have thick (up to 160 ft), clean pay in the producing McMurray Formation, which starts at about 1,000 ft below the surface.
SAGD drilling operations at Firebag use a central pad to drill multiple wells from one location, Fig. 1. The concept involves two horizontal wells drilled in the oil sands with a production well at the bottom of the formation and an injection well about 16–20 ft directly above it, requiring precise directional control of the injection well placement. The two wells, referred to as a SAGD well pair, are relatively shallow, with TVDs of roughly 1,000 ft, but possess long-reach horizontal sections of up to 3,300 ft. In each well pair, steam is introduced into the reservoir through the injector. The heat reduces the bitumen’s viscosity, which allows it to flow downward into the producer. A downhole high-temperature electric submersible pump (ESP) in the producer then lifts the liquefied bitumen to surface. The producer is drilled as close to the underlying Devonian limestone as possible.
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Fig. 1. Nabors Rig 102 batch drills SAGD well pairs at Suncor’s Firebag property.
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At Firebag, many SAGD well pairs are batch drilled, starting with the drilling of all vertical surface holes, then the producer intermediates (build sections) and producer mains (horizontal sections), followed by injector intermediates and injector mains. Surface locations typically alternate between producer and injector with about 30 ft between surface locations. Downhole, there is about 300 ft of lateral spacing between well pairs. This batch drilling process could result in the drilling rig moving up to 100 times, depending on the number of SAGD well pairs on a pad.
For both producers and injectors, the 26-in. surface hole is drilled vertically to roughly 280 ft, after which 18⅝-in. casing is run and cemented in place. Both producer and injector intermediate holes begin with directionally drilled 12¼-in. pilot holes that are subsequently opened up to 17½-in. sections of about 1,900 ft MD, after which 13⅜-in. casing is run and cemented in place.
The 12¼-in. horizontal openhole section for the producer is about 2,600–3,300 ft long. A 9⅝-in. slotted liner is hung just inside the intermediate casing and extends to the toe of the well. The slot size and density are critical to maximize production without allowing sand influx. The horizontal section of the injector is first drilled with a uniform 12¼-in. diameter, and then the 820 ft closest to the heel of the well is opened up to 15 in. The slotted liner inserted into the injector is tapered in order to distribute the steam across the entire length of the horizontal section; the first 820 ft of liner is 10¾ in. and the remaining 1,800–2,500 ft is 9⅝ in.
The large diameters are required to produce the average 6,300 bpd of total fluid that flows from each well pair. This average daily volume is made up of about 4,725 bpd of water and 1,575 bpd of bitumen. As of June 2010, Firebag was producing about 60,000 bpd of bitumen from 41 well pairs, and 80 million bbl of bitumen had been produced cumulatively out of a total 9 billion bbl of recoverable reserves.
The producer surface hole is drilled vertically, then the producer intermediate section is kicked off after drilling out the surface casing shoe at roughly 280 ft. The directional driller continues to build angle at a high build rate of about 9°/100 ft through loose, unconsolidated formations until the well is at 90° near the bottom of the McMurray Formation. The producer intermediate section is then held at 90° for about 200 ft in the tangent section for the downhole ESP, which is installed during the well completion. The producer main is then drilled horizontally along the base of the McMurray Formation for about 3,300 ft on average. The producer wells are drilled with traditional MWD tools and a positive displacement motor with a bent housing.
The injector surface holes are also drilled vertically, and the well is kicked off just outside of the surface casing shoe. Before directionally drilling the intermediate section of the injector, a magnetic guidance tool (MGT) is placed inside the producer well for directional ranging. This tool is deployed into the well by tractor and moves from heel to toe of the producer’s horizontal section slightly ahead of the BHA drilling the injector. It transmits an electromagnetic field that is picked up by tools in the injection well BHA to aid in maintaining an accurate 16- to 20-ft separation between the producer and injector while drilling the injector.
The tight well spacing at surface presents a challenge for using the MGT, because the tool requires additional equipment at surface to perform the ranging operation. Software automatically accounts for the effects of the Earth’s magnetic field, formation influences and casing effects to provide a correct distance reading, with the directional drilling team providing an accuracy check on the inputs to the ranging tool.
HIGH-DENSITY PAD DRILLING
One of the challenges with batch drilling large numbers of wells from a single pad is the directional planning. Since the wells are about 30 ft apart on surface and about 300 ft apart downhole, the wells have large swings from the fixed surface location that make drilling and casing running difficult. In order to capture the optimal amount of pay, some of the pads have complicated interfingering, or directional wells of various geometries in close proximity to each other. In addition, the need to capture stranded reserves underneath the pad means that one or more wells will have to double back after having been drilled to a considerable horizontal distance from the pad in order to build the necessary angle. All of these factors contribute to a high risk of collision. In some cases, the intermediate sections of two wells will come within a few feet of each other. However, these risks can be managed properly with detailed engineering and planning.
To aid the batch drilling process at Firebag, Suncor worked collaboratively with Nabors Drilling to design a fit-for-purpose rig equipped with a walking system that nearly eliminates the need for cranes and trucks during rig moves on the pad. The walking system allows the 4 million-lb rig to move the 30–70 ft between two wellheads in the batch drilling process in only 20 min. with the water tanks and mud tanks full of fluid (about 1,600 bbl) and pipe in the derrick, while providing a smaller footprint than conventional rigs. The rig has the capability of turning 360° on its axis and can move at 4 ft per minute on the pad. These capabilities have resulted in a reduction of up to 23% in average well times at Firebag, leading to significant cost savings per well.
All suitcases—the packages of movable modules that carry the electrical cabling and plumbing among the power package, mud tank, pumps and drilling structure—are self-contained on the rig. This allows the rig substructure to be moved without separately transferring the pumps, tanks, engine house and power distribution packages, which increases fuel efficiency, eliminates the need for an umbilical system and transfer pumps, and reduces the risk of environmental spills. The packages are generally composed of five sections, each 25 ft long.
The derrick has a mast with a bootstrap design intended for applications with limited space. The mast is assembled vertically on the rig floor, with each section being raised either by the drawworks or by hydraulic power. Once the boot section (bottom) and the top section are in place, the remaining mast sections are inserted into the mast base and telescoped sequentially, allowing for a safe and efficient mast erection.
The rig is equipped with four shale shakers and three centrifuges to handle the copious amount of cuttings that comes to surface while drilling the large-diameter SAGD wells. Other specialized rig equipment includes a mud cooler to maintain the drilling fluid temperature at 54–61°F, which aids drilling of the horizontal section by preventing the bitumen from liquefying prematurely. Specialized drilling fluid was developed to handle the large amount of sand and bitumen produced while drilling the horizontal sections. This mud prevents bitumen accretion to metal surfaces such as tubulars and solids-control equipment. The fit-for-purpose rig design and other surface equipment have been instrumental in keeping the pad drilling costs relatively constant during the past several years despite high inflation rates. 
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THE AUTHORS
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Brett A. Regier is Suncor Energy’s Director of In Situ Drilling and Completions in Calgary, Alberta. He joined the company in 2002 and has worked in various disciplines, including drilling of SAGD, observation and disposal wells. For the last eight years, Mr. Regier has managed all drilling and completions operations and engineering for the Firebag project. He has more than 30 years’ experience in the industry.
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Joe Bruce is President and CEO of Nabors Canada with overall responsibility for 85 drilling rigs, 154 service rigs, abandonment and reclamation operations, and Nabors Blue Sky, which owns and operates a fleet of helicopters and heliportable well servicing equipment. His experience with Nabors spans 40 years in the North Sea, Saudi Arabia and the Gulf of Mexico. |
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