Directional Coiled Tubing Drilling (CTD) has been used successfully in fields across the USA including: Alaska, Texas, California, Kansas, and Michigan amongst others (Figure 2). The established technique revitalizes mature oil and gas fields and, 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 years.
Why use Coiled Tubing Drilling
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 Managed Pressure Drilling/Underbalanced Drilling (MPD/UBD) and remote operations.
The most commonly used BHA diameter for CTD is 3-1/8” with larger tools available with 5” OD and smaller tools available with 2-3/8” OD (Figure 3). The BHA sizes are limited to 5” or below due to the practical limits on the size of coiled tubing. The technique is most suited to smaller hole sizes such as 8-1/2” or below, with most wells drilled with a hole size less than 4-1/4”. Therefore, the benefits usually stem from re-entry drilling or 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.
Drilling safely and efficiently
Coiled tubing is designed for underbalanced operations and continuous circulation as 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.
Drilling high-pressure wells
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 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 15,000psi is also relatively standard.
Drilling offshore
Coiled tubing drilling is also advantageous in offshore projects in terms of the type 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 jack-up rig and thereby reduces the cost of the new wellbores and minimise the crew numbers required to do the work. This is in addition to the advantages of MPD on coiled tubing.
Drilling in remote locations
The smaller, more mobile coiled tubing equipment gives an advantage over conventional rigs in remote locations, for example, Northwestern 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.
When not to use CTD
There are situations where CTD is not suitable. The largest hole size ever drilled directionally with CTD is 8-1/2” 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 the expense of needing a second standard coiled tubing string available for that operation.
Equipment requirements
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 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 slipring 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 is underbalanced, and must be taken into consideration when planning a CTD campaign.
Completion equipment
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 whilst maintaining the underbalanced condition at all times
Example planning process for an 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 teams everywhere.
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 knock-on impact into the suitability of using CTD in either a managed pressure or underbalanced set up.
Screening donor wells
Assuming the subsurface objectives are broadly understood, the next step is to assess the existing well stock to see the wells that 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 200ft x 300ft 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, it 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 mobilised, 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 finalised and the wells permitted.
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