Coiled Tubing Technology: How to plan a Coiled Tubing Drilling campaign
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 years.
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 type, 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 tubing.
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.
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 campaign.
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.
“Controlling downhole-pressure fluctuations while drilling underbalanced reduces formation damage, avoids lost circulation, and minimizes differential sticking.”
- Oil & Gas Journal: Underbalanced drilling requires downhole pressure management
EXAMPLE 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 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 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 rig.
Lead photo: AnTech's crew preparing the COLT BHA for drilling operations. Image: AnTech
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