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Application of Top Drive Drilling To Horizontal Wells

Colin B. Murch, Tesco Drilling Technology

This paper was selected for presentation by an SPE Program Committee following review of
information contained in an abstract submitted by the author(s). Contents of the paper, as
presented, have not been reviewed by the Society of Petroleum Engineers and are subject to
correction by the author(s). The material, as presented, does not necessarily reflect any
position of the Society of Petroleum Engineers, its officers, or members. Papers presented at
SPE meetings are subject to publication review by Editorial Committees of the Society of
Petroleum Engineers. Permission to copy is restricted to an abstract of not more than 300
words. Illustrations may not be copied. The abstract should contain conspicuous
acknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O.
Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-214-952-9435.

Drilling horizontal wells requires the application of a variety of new technologies, most of which are associated with downhole tools and equipment. Surface drilling equipment can be overlooked when planning horizontal wells. Top drives are a key component of modern drilling equipment and have been used in offshore applications since the early-1980’s. Recently smaller, more portable top drives have made this technology available to most land drilling rigs, and even large workover rigs, without the need for expensive modifications to their derricks. In addition, the practice of renting top drives has provided the contractual flexibility needed by both operators and drilling contractors in order to
provide top drives for single wells, or even critical portions of one well.

Top drives were originally designed for, and installed on, large offshore rigs. The first installation was in 1982. The ability to drill with stands, eliminating the time needed to lay down pipe and pick it up as singles to drill the next well, was a major advantage where the rig could be floated to the next
location with pipe racked in the derrick. The drilling time savings associated with the use of top drives offered significant advantages in the high daily cost environment of offshore operations. The long term contracts used in offshore work provided for the payout time needed by contractors in
order to justify the capital costs of top drive equipment and the necessary derrick modifications. The large 160 foot derricks used in offshore operations were sizable enough to permit the installation of the large, DC-traction motor top drives of that period. Portable top drives were introduced into land drilling rigs in 1992. Small, lightweight, hydraulically-powered top drives were developed in order to ensure the fit into the smaller derricks used in land operations without the need for costly derrick modifications. A separate power unit provided the additional power needed for a top drive and provided top drive capability to mechanical rigs and small electric rigs. A rental concept was also introduced in order to better match the shorter term contractual arrangements typical of land
drilling. With their increasing use, it was soon learned that top drives provided significant operational advantages. These advantages centred around the ability to concurrently rotate,
circulate and hoist. For reaming and backreaming operations this proved invaluable. This capability reduced the risks of getting stuck in the hole and potentially losing part, or all, of the bottomhole assembly, drill string, or even the well. Appropriately configured top drives also automate a
number of rig floor functions. This not only increases the efficiency of operations but reduces the likelihood of personnel strains and injuries.

With the advent of horizontal drilling, the complexity of many drilling operations has been increased and several new problem mechanisms have been introduced. Top drive drilling provides the means of mechanically dealing with many of these problem mechanisms. The advantages of using a top drive for horizontal well drilling can be grouped into the following general categories:
· Efficiency Improvements. Daily costs of horizontal drilling operations are generally two to three times higher than routine vertical drilling. This increase is associated with the number of additional tools and services required, including rental drill strings; MWD tools and directional drilling services; mud motors; logging while drilling tools, and in many cases, underbalanced drilling equipment. The
economic advantages of reducing drilling times through the use of top drives becomes far greater in these high daily cost applications.

· Risk Reduction. With the more complex and expensive bottom hole assemblies associated with horizontal drilling, the capabilities of top drive drilling greatly reduces the risk of losing these assemblies or even the well itself. An important advantage, this benefit is difficult to quantify and is generally assessed as an insurance benefit based on similar drilling in the area.
· Mechanical Advantages. Top drives give the driller the capability to physically deal with many of the mechanical problems introduced in horizontal drilling. The precise torque control of most top drives and the ability to hoist, rotate and circulate provide a significant advantage. These problems, which will be elaborated on further in the paper, include running casing and liners, keyseating, differential sticking and increased drag. For the oil company, top drives can provide the flexibility to use a smaller rig potentially increasing rig availability and reducing rig move costs and lease size. . In many cases the alternatives considered to deal with horizontal well problems include expensive and
environmentally-sensitive mud additives
· Safety and Well Control. These advantages are similar for vertical and horizontal drilling and will not be elaborated on further in this paper. The improvement in safety associated with top drive relates to the pipehandling features included with most top drives. This pipehandling reduces the risk of handling stands of drill collars as well as bottomhole assemblies. Well control is improved as a result of the capability of the top drive to make up to the drill pipe at any point in the derrick in order to re-establish circulation or, using a remotely-actuated valve, to shut in the drill pipe.

EFFICIENCY IMPROVEMENTS Top drives increase drilling efficiencies by reducing the time spent on non-productive operations. This reduction in time not only reduces overall well costs but it also reduces risk through limiting exposure to problem mechanisms. This second aspect is of particular advantage while drilling long horizontal sections where it is important to limit the time not
spent rotating and circulating.

Top drive efficiencies result from the following capabilities:
· Drilling With Stands. Where stands can be made up ahead of time or, on pad or template wells where the rig can be skidded with pipe stood in the derrick, the time spent on connections can be reduced from 50% to 67%.

· Reaming. When running into the hole, the ability to quickly lower the top drive onto the box connection of the stand at any point in the derrick, make up the connection and quickly ream back to bottom can save substantial rig time. No time is spent laying down singles and picking up the

· Bit Orientation and Survey Times. With the ability to make connections on bottom and by drilling with stands, the need to re-orient the bit and to survey are reduced, again by 50% to 67%. Making connections on bottom also allow circulation to be established from the bottom up.
· Drilling with Air. While drilling with stands, the number of connections is reduced. With air, this allows drilling to proceed faster, reducing the time for water influx. Air drilling can then reach greater depths than with kelly drilling, where the increased connection time allows increased water influx such that air drilling cannot proceed.

· Underbalanced Operations. For underbalanced operations, the time spent waiting on drill pipe
depressurization is reduced since connections are made less often. Nitrogen costs can also reduced due to the lower number of connections.

· Laying Down and Picking Up Pipe. The time spent on this operation can be eliminated during pad work where the rig can be skidded with pipe in the derrick. In addition, considerable tool joint damage can be avoided. Tool joint damage is a major cause of drill pipe washouts.
· Pilot Hole and Hole Opening Operations. The ability to drill with stands simplifies the process of drilling a vertical pilot hole to first confirm the depth of the target zone. With the pilot hole plugged back and a whipstock set, drilling operations can resume without having to lay down pipe and
pick up singles. Time spent for hole opening operations is similarly reduced.

The primary advantage in this area is the ability to backream. For horizontal wells, often with long, unstable horizontal sections, this capability is critical. The ability to rotate and circulate while pulling out of the hole can significantly reduce the risk of sticking the drill pipe and possibly losing expensive downhole tool assemblies. In many cases, companies carry expensive downhole tool loss insurance with high deductibles and restrictive maximum losses per incident. Top drives provide the capability of mechanically mitigating these risks while at the same time offering a variety of other advantages.

Horizontal wells present a number of unique problem mechanisms which can be effectively dealt with through the use of a top drive. Following are the most common problems and the reasons why a top drive is the preferred solution to address them:

· Unconsolidated Formations. Horizontal sections of up to 2,000 metres in unconsolidated channel sand formations have been drilled with the use of a top drive. With a top drive, the reduced wellbore exposure time associated with drilling with stands, connections on bottom and reduced
survey requirements are vitally important. The ability to readily circulate and the ease of hole conditioning also reduce the difficulties associated with these formations. Where required, backreaming proves very useful in these areas.

· Cuttings Beds. In horizontal wellbores the tendency to build up cuttings beds and stick the pipe is significant. Hole conditioning wiper trips with complete stands is very effective in dealing with these problems.
· Differential Sticking. The ability to apply torque while squatting down with the top drive or by jarring down can be accomplished readily with a top drive. Rotating and hoisting can be effective in dealing with these problems. Reduced connection time minimizes the time dependency of
this type of occurrence.
· Ledges. Concurrently hoisting and rotating are effective means of pulling out of hole sections containing ledges.
· Keyseating. Rotating the drillpipe while running in or tripping out of the hole will reduce the incidence of getting stuck in keyseats.
· Increased Drag. The ability to readily rotate out of the hole when tripping reduces the pull required as a result of keeping the pipe from pulling tight across the high side of the build radius. Rotating the pipe also reduces the drag effects of the pipe laying on the bottom of the horizontal section.
· Bridging. The ability to ream through, or backream out of, sections of formation instability is readily available when using a top drive.
· Hole Conditioning. The ease of making full-stand wiper trips and conditioning the hole can greatly reduce the risks of sticking the pipe.
· Running Casing and Liners. The ability to reciprocate and circulate casing while running in will result in a much higher degree of success. The top drive, because of the stability afforded by the torque track, yields accurate stabbing of casing joints, generally eliminating the use of a stabbing
board. With the appropriate crossover subs and the precise torque control afforded by top drives, casing can be rotated and circulated into the hole. The ability to apply the weight of the top drive and the overhead equipment to the casing can further reduce the incidence of stuck casing.
· Rig Availability . With the reduced pull required as a result of being able to readily rotate out of the hole, more choice is available when selecting the drilling rig to be used. In many cases, a smaller rig can selected, resulting in lower daily costs, mobilization costs and reduced lease size requirements.
· Doglegs and Micro-Doglegs. By readily backreaming through these sections, the difficulties with them can be eliminated.
· Slide Drilling. While drilling with motors, an appropriately designed top drive can be used to “ rock the pipe’ thus reducing the friction of running through the well control equipment and the drag associated with the pipe laying on the bottom of the horizontal section. Much longer horizontal sections can be achieved through this method.

In Canada, horizontal drilling is widely used in drilling shallow heavy oil deposits in Eastern Alberta and South Eastern Saskatchewan. Many of these wells are placed on primary production using progressive cavity pumps (screw pumps). Increasing use is being made of Steam Assisted Gravity
Drainage (SAG-D) production techniques. This technique is applied in a number of ways including parallel horizontal wellbores, one of which is used for low pressure steam injection in order to saturate the producing formation. Other methods involve horizontal producers with steam injection
done through vertical wells at the toe of the producing wellbores.
Wells of this nature are generally drilled from pads with the number of wells per pad ranging from two or three up to eight. As indicated earlier, pad drilling using a top drive can have the added advantage of eliminating the time spent laying down and subsequently picking up drill pipe since the rig can often be skidded with pipe stood in the derrick..
Following is a summary of an eleven well horizontal program drilled by Strike Energy Inc.. in the Bolney formation in the Paradise Hill area of Saskatchewan (Twp 52, Rge 23, W3M) between November, 1994 and September, 1995. Strike Energy has now merged with Tarragon Oil and
Gas Ltd. The first four wells of this program were drilled without a top drive and the last seven wells were drilled with a rental, hydraulic, portable top drive. Formation. The Bolney formation consists of virtually 100% unconsolidated sand with no shales or cementation. It is at or above the maximum theoretical porosity.
Drilling Program. Wells were drilled using the following typical program.
· Surface Casing. 339.7 mm landed at 110 metres
· Kick-off Point. 285 metres
· Intermediate Hole. Pilot with 222 mm; hole opener to 311 mm.
· Intermediate Casing. 244 mm landed at 570 metres MD
· Horizontal Section. 222 mm hole, 450 metre section; 177.8 mm slotted liner landed at 1100 metres MD. Problem Mechanisms. In drilling the Bolney wells the problem mechanisms experienced were stuck pipe due to differential sticking; rotational keyseating; tight hole; hole collapse and overshooting. Attempted Solutions. Nitrogen and back-off and jarring were unproductive. Washover was considered too risky. Results. Following is a summary of the results for the program separated into those wells drilled with a top drive and those wells drilled without a top drive.
· Wells 1 through 4 (drilled without top drive). Total drilling time - 61 days; Total metres drilled - 2050 metres; Total cost - $Cdn 3.43 million (including three lost tool strings); Cost per metre drilled - $Cdn 1,670.00 per metre.
· Wells 5 to 11 (drilled with a rental, hydraulic portable top drive). Total drilling time - 70 days; Total metres drilled - 3,040 metres; Total Cost - $Cdn 3.27 million; Cost per metre drilled - $Cdn 1,080.00 per metre. Recommended Drilling Practices. Strike Energy Inc. recommended the following drilling practices for these type of wells:
· Good low fluid loss mud
· Ability to rotate and “squat” (i.e. apply the weight of the top drive and overhead equipment to the drill string)
· Ability to circulate while tripping
· Limit time exposed while in the open hole section
· Use a top drive.

Top drive drilling will improve the ability to drill successful, economic, horizontal wells. The increased degree of control afforded by top drive drilling will result in less difficulties and greater predictability of results and ultimately lower costs and reduced drilling times. To utilize top drives on these wells, the top drive must be appropriately sized to fit into the rigs which do this work. Their load rating and torque/rpm capacities must fit the characteristics of the wells to be drilled. Either the rig must

have the additional power available for the top drive or a separate power unit must be supplied. Finally the contractual terms necessary to obtain the top drive must match the business needs of the end user.

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