Considering the current market conditions, maximizing production and reducing well costs will be the main focus of oil and gas companies throughout 2015. Many well-cost reductions have focused on optimizing the fracturing phase of the completion stage; however, wells ultimately have to be drilled first.

Typically the manufactured well model for the shale plays is a driver in lowering costs as wells are drilled sequentially on a pad, leading to a short rig-release-to-spud interval.

As E&P companies continue to look for cost savings, there are a few other avenues to explore that complement the shale drilling model. Ensuring proper equipment and vendor selection will keep the drillbit turning to the right and will lead to reduced drilling cost that in return will lower costs to the overall well program.

One such piece of equipment—the top drive—is an integral component of the Tier I drilling rigs that are in demand in areas with unconventional plays. Technical advancements for these plays generally fall under two categories: making the horizontal section longer and improving the fracturing operation.

A top drive that is capable of drilling longer wells at a greater or more aggressive trajectory will help differentiate a rig’s offering, especially in a downturn/competitive market.

Selecting a top drive capable of drilling a certain depth may be a fundamental component during rig design, but there are several other areas to consider. Before making the decision to go with a selected top drive model, operators should consider whether they are purchasing the right equipment for today’s well requirements and tomorrow’s technical advancements and ensure the equipment is fully supported after the sale to keep the top drive turning.

Specifications for horizontals

Rig inventories for the shale plays include state-of-the-art technologies such as walking systems, alternating current drives, top drives and robust mud pumps, making it necessary to secure a long-term contract. All equipment is specified to meet the drilling programs of the term contracts. If the well program calls for a depth rating, the top drive needs to be selected so that the specification rating will not be exceeded.

Traditionally, when selecting a top drive, two main specifications are called into question: torque rating and load rating. The load rating will be a factor in determining what the rig is able to trip in and out of the hole. The top drive torque rating will determine the horsepower of the rig in its ability to rotate the driveline or drillstring from surface to bit.

Hart Energy’s Market Intelligence program noted that, “the greatest demand is for units in the 400-ton to 600-ton category, with 500 tons being the most requested model as the contract drilling industry expresses preference for 1,500-hp rigs.”

The 500-tonnage top drives allow the drilling contractor versatility in depth of the well. But a top drive with a smaller tonnage rating may still drill the wells within a certain play and give the rig the mobility of a smaller top drive needed for quick pad spud times. Such top drives fall into the 400-tonnage capacity.

The same considerations should be made for the top drive’s torque capabilities. Equipping the rig with a top drive powerful enough to drill tomorrow’s wells can be a competitive advantage. If compactness is the advantage, a top drive with a smaller motor offering may be the better choice.

Horizontal drilling rigs are seeing higher horsepower mud pumps added to the inventory. The water course diameter/fluid path diameter of the top drive is now a key specification in top drive selection.

Vince Fortier, global products commercial manager for Tesco Corp., expanded on horizontal specifications. “Continuous drilling torque fluid path diameters provide important specifications that tie directly into the rig’s focus on making hole rather than tripping capabilities,” he said. “Furthermore, top drive control software can provide an advantage over equipment specification alone through intelligent drillstring manipulation (stick/slip mitigation and drillpipe oscillation.)”

Top drives for tomorrow’s market today

It is incumbent that the top drive or any equipment selected during the procurement phase meets the requirements for the job that it needs to perform today. Typically, today’s newbuilds are constructed under the impetus of a two- to three-year contract.

Take into consideration the life cycle of a top drive. API 8C calls for the fatigue analysis of the load-bearing components to be done for a 20-year scenario. Other components will need to be replaced throughout the life of the asset; the asset itself will be operational for the long haul.

Properly maintained and used within suggested operational limits, the top drive can have a successful asset life for 15 to 20 years. This asset life makes clear the need for adaptability in tomorrow’s market.

Tesco’s Permian Basin operations manager Juan Hernandez is typically seeing horizontals with depths of 5,182 m (17,000 ft), “but they can reach up to 20,000 feet [6,096 m],” he said. Pushing the well to these limits requires today’s state-of-the-art technology, but the limits of the wells five years from now will require planning strategically for capital equipment that can last 15 years.

Akita Drilling Ltd., a drilling contractor in Canada, has already installed a 750-ton top drive on a land rig for the Montney Shale formation. A larger tonnage top drive like the 750 may become more common in the U.S. shale plays as depth targets become longer.

Equipment upkeep for shale drilling

Since the top drive can have such a long asset life, the second factor comes to light as well. Operators should make sure that the top drive they have selected can have convenient and responsive serviceability. This may be original equipment manufacturer-supported or by a third-party company.

Many top drive manufacturers are also equipping the top drive with equipment health monitoring (EHM) systems, providing the drilling contractor a higher degree of asset integrity management.

Short drilling breaks between end-of-well and the spud of a new well in shale plays allow less time for the driller to provide equipment maintenance.

Roy McNiven, vice president of After Market Sales & Service, Tesco, explained, “One of the major effects we see related to pad drilling is the lack of time afforded for maintenance due to the lack of conventional rig moves. Minor maintenance is accounted for on a daily basis; however, equipment is operating on a continuous basis and, over time, normal wear and tear results in repairs that go beyond what can be accomplished in a typical 30-minute interval per day.”

Incorporating an EHM solution to the rig allows flexibility to maintain equipment when necessary and warns the driller of pushing the equipment into inordinate limits. An EHM system will give the drilling contractor the needed diagnostics to effectively manage an asset while operational in the field. Standard maintenance practices, including recertification, still need to be considered.

Adding in a proper inspection and recertification schedule will ensure the top drive sees its 15-year lifecycle.

Diversify assets, drill ahead

As the industry looks for ways to optimize production while simultaneously reducing costs in the North American shale plays, looking at all areas of the value chain rather than one component will be the differentiator for oil and gas operators. By planning for tomorrow’s wells and investing in quality equipment and providers, operators will reduce costs and maintenance issues over an extended period of time, satisfying market demands and shareholders.