CTD can be very cost-effective in developing mature fields. Through
careful planning, the benefits of underbalanced drilling—and the increased
production it delivers—can be achieved for less than the cost of sidetracking
existing wells, using a conventional drilling rig.
ADAM MISZEWSKI, AnTech
Directional coiled tubing drilling is an established technique for
revitalizing mature oil and gas fields. The technique has been used
successfully in fields across the U.S., including Alaska, Texas, California,
Kansas and Michigan, amongst others, Fig. 1. In particular, there has
been high growth in deployment across the Middle East, with a doubling of the
CTD rig count over the last few years and further growth expected in the coming
WHY USE CTD
The reasons for using CTD vary,
depending on the application. The main reasons are thru-tubing or slimhole
sidetracks; underbalanced drilling; high-pressure wells, which require
specialist MPD/UBD; and remote operations.
The most commonly used BHA diameter
for CTD is 3⅛ in., with
larger tools available with 5-in. OD and smaller tools available with 2⅜-in. OD, Fig.
2. The BHA sizes are limited to 5 in. or below, due to the practical limits
on the size of coiled tubing. The technique is most suited to smaller hole
sizes, such as 8½ in. or below, with most wells drilled with a hole size less
than 4¼ in. Therefore, the benefits usually stem from re-entry drilling of
shallow gas or oil wells. An alternative way to think about CTD is that it is a
reservoir drilling technology, so the closer to the reservoir, the more
advantageous CTD will be.
Coiled tubing is designed for
underbalanced operations and continuous circulation, as is standard. Therefore,
mature fields with low pressure can be drilled, underbalanced, safely and
efficiently, with the reservoir rock protected from damage—critical when there
is little pressure to drive production. Although underbalance can be achieved
with a single-phase fluid in high-pressure reservoirs, this is particularly relevant
to fields requiring a two-phase drilling fluid, such as water and nitrogen, as
a stable circulating regime can be maintained at all times. Also, some fields
are not able to use EM telemetry, and, therefore, wired CTD tools are the only
option in two-phase systems.
Coiled tubing also has significant
advantages for drilling high-pressure wells, either using managed pressure or
underbalanced drilling techniques. This is due to continuous circulation and high-pressure
control equipment, as is standard. The continuous circulation allows for better
control of downhole pressure through adjustable pumping rates, in addition to
drilling fluid weight and choke pressure. Pressure control equipment of up to
15,000 psi is also relatively standard.
Coiled tubing drilling is also advantageous
in offshore projects, in terms of slot recovery, equipment footprint and cost
reduction. CTD operations can be carried out through tubing, which removes a
significant amount of the slot recovery operations. Due to the size of the
equipment, CTD can fit on most platforms and does not require the use of a jackup
rig, thereby reducing the cost of new wellbores and minimizing the crew numbers
required to do the work. This is in addition to the advantages of MPD on coiled
The smaller, more mobile coiled tubing equipment gives an advantage over
conventional rigs in remote locations: for example, North Western Australia. This
can be critical to the commercial success of small projects. However, a
combined approach with a conventional rig can, instead, be the optimum solution.
For example, utilizing a conventional drilling rig to drill the well down to
the reservoir and then using the CTD package to drill the reservoir, ideally
underbalanced, optimizes the benefit of each technology. In addition, it also means
more wells can be drilled in a set period of time than with a single rig, or
for lower cost than mobilizing two drilling rigs. This is before the
improvements to production are factored in from drilling underbalanced.
However, there are situations where CTD is not suitable. The largest
hole size ever drilled directionally with CTD is 8½ in., and currently the
technology is unable to drill larger diameters. CTD has been used successfully
to drill new wells from surface; however, this requires specialist, hybrid
coiled tubing units, which can be difficult to source. When a hybrid unit is
available, they are usually depth-limited and, therefore, only suited to
shallow wells. Consequently, operations requiring large hole sizes and casing
running operations are unlikely to be suitable for CTD.
Another limitation of CTD packages is in cementing. Due to the wireline
inside the coil required to operate the BHA, any cementing operations become
very time-consuming, due to the resultant slack management, or expensive, due
to having a second standard coiled tubing string available for that operation.
A coiled tubing drilling package requires the same fundamental equipment
as a conventional drilling package—a “rig,” a fluids and solids control package
and a set of downhole drilling tools. All coiled tubing units can be used for
CTD re-entry operations within the limits of their capacity. However, CTD
requires coiled tubing with wireline inside, commonly referred to as e-coil.
Consequently, a collector bulkhead and a slip-ring collector need to be
installed, to allow an electrical connection from outside the reel to the
wireline inside the coil and to the BHA.
The fluids and solids control equipment utilized will be heavily
dependent on whether or not the well is going to be drilled underbalanced and
whether single- or two-phase fluid systems are going to be used. Something that
often surprises people unfamiliar with CTD operations is how fine the cuttings
are. This can cause challenges with solids control—especially when drilling
underbalanced—and must be taken into consideration when planning a CTD
Ideally, the formations drilled with coiled tubing can be left with a
barefoot completion. Completion options are relatively limited when using a
coiled tubing unit alone, unless using a hybrid unit. On land, it is usually
simpler and more cost-effective to bring in a workover unit to run pipe. The
challenge with underbalanced operations is to ensure that any completion run is
installed, while maintaining the underbalanced condition at all times.
PLANNING PROCESS FOR
ONSHORE MATURE FIELD
The following is an example planning process, based on an onshore mature
field where the original reservoir has been depleted. The operator may choose
to sidetrack to access areas of virgin pressure away from the existing wellbores
or can access other productive formations which are behind pipe. Whatever the
target, certain aspects need to be understood, which will be familiar to drilling
The formations between the casing exit and the reservoir need to be well-understood.
If there are particular zones that are troublesome, then now is the time to
assess whether the kickoff point can be lowered to avoid the zone, or if operational
controls will need to be in place in the drilling program. The expected
drilling fluids system should also be assessed at this stage, as it defines the
equipment requirements and has a significant impact on the well budget. This is
also the time to evaluate the completion requirements with a particular focus
on zonal isolation. For example, are there zones above that need to be isolated
from the reservoir and, if so, can they be isolated with a swellable packer, or
is cementing required? Each consideration has a domino effect on the
suitability of using CTD, in either a managed pressure or underbalanced set-up.
Assuming the subsurface objectives are broadly understood, the next step
is to assess the existing well stock, to see which wells are suitable for
sidetracking. These wells need to be screened for well integrity, current oil
and gas production, location, casing/tubing size and ability to reach
directional targets. Once the initial list of wells has been created, then the
available logs for each of the potential donor wells should be reviewed. The
most critical logs are cement evaluation logs. Some older wells can be located
on very small pads, so the pad size for each well should also be considered and
permission to extend sought, if required. A minimum pad size of 200 ft x 300 ft
is desirable, but there is some flexibility, depending on the equipment to be
used. In some cases, it may simply be that the pad has not been maintained to its
boundaries, but the rights are in place and, therefore, the pad just needs to
be prepared for the operation.
The casing and cement integrity are both critical for successful
operations. If a cement evaluation log is not available, then it should be
planned to be carried out, well before the CTD spread is to be mobilized, so
that remedial cement jobs can be carried out if required. Ideally, casing
pressure tests should also be carried out at this time, to verify the integrity
of the casing where the exit will be. Once the donor wells have been selected,
the trajectories can be finalized, and the wells can be permitted.
Prior to the mobilization of the coiled tubing unit, certain preparatory
actions should be carried out in the yard. Firstly, the slip-ring collector and
collector bulkhead should be installed. If the unit has not been used for
e-coil in the past, then a mounting bracket will need to be made to fit the
specific unit. The collector bulkhead should be placed on a y-piece or lateral,
with one leg for drilling fluid and the other for the wireline to the bulkhead.
Once these are installed, then ideally the e-coil is pressure-tested, and the
wireline is checked for continuity and insulation, while the water is still in
the coil. If it is not possible to pressure test, due to limitations of the
yard, then at a minimum, the wireline should be electrically checked after the
bulkhead is installed.
In a mature, onshore field in the U.S., it is usually most cost-effective
to utilize a workover unit to carry out the casing exit, or, at a minimum, set
the whipstock and run any completions required. The casing exits can be carried
out in a batch. Once a suitable number of casing exits have been completed, which
are unlikely to clash if one of the windows takes longer than expected, then
the CTD package can be mobilized, and new laterals can be drilled on each well.
If timed right, then there will be very little time lag between drilling the
new sidetrack and running the completion equipment. This will minimize the time
when production is offline.
In conclusion, CTD can be a very cost-effective solution to develop mature
fields either onshore or offshore. Through careful planning, the benefits of
underbalanced drilling—and the increased production it delivers—can be achieved
for less than the cost of sidetracking existing wells using a conventional drilling
Lead Photo: AnTech's crew preparing the COLT BHA for drilling operations. Image: AnTech
ADAM MISZEWSKI is global operations manager at
AnTech. Accordingly, his role is to deliver the firm’s services safely and
efficiently, and he is committed to working with customers and service partners
to ensure the promised value is realized. Before joining AnTech, Mr. Miszewski
worked as a drilling engineer for BP in Aberdeen, UK. He is chairman of SPE’s
Dorset Section. Prior to that, he worked for a short period with Halliburton. Mr.
Miszewski graduated from Imperial College, London, with a First Class master’s
degree in mechanical engineering.