It is well documented that incremental improvements in athletic performance can be accumulated to create a winning team. Oilfield operations are no exception and it is important to take advantage of this potential to eliminate unnecessary intervention costs. Regardless of oil prices, as an industry we face economic and social pressures to be as efficient as possible.
In the current environment, extracting the last barrel of oil from existing assets by re-introducing and drilling branches in existing wells is a smart and cost-effective strategy – provided it can be done cost-effectively. Coiled tubing drilling (CT) is an underused technology that improves efficiency in many areas compared to conventional drilling. This article describes how operators can take advantage of the efficiency gains that CTD can provide to reduce costs.
successful entry. To date, coiled tubing (CTD) drilling technology has found two successful but distinct niches in Alaska and the Middle East, fig. 1. In North America, this technology is not yet widely used. Also known as drillless drilling, describes how CTD technology can be used to extract bypass reserves behind a pipeline at low cost; in some cases, the payback period of a new branch can be measured in months. Not only can CTD be used in low cost applications, but the inherent advantage of CT for underbalanced operations can provide operational flexibility that can greatly increase the success rate for each wellbore in a depleted field.
CTD has been used in underbalanced drilling to increase production in depleted conventional oil and gas fields. This application of the technology has been very successfully applied to low permeability declining reservoirs in the Middle East, where the number of CTD rigs has slowly increased over the past few years. When underbalanced CTD is used, it can be reintroduced through new wells or existing wells. Another major successful multi-year application of CTD is on the North Slope of Alaska, where CTD provides a low-cost method to re-commission old wells and increase production. The technology in this application greatly increases the number of margin barrels available to North Slope producers.
Increased efficiency leads to lower costs. CTD can be more cost effective than conventional drilling for two reasons. First, we see this in the total cost per barrel, less re-entry through CTD than through new infill wells. Secondly, we see it in the reduction of well cost variability due to coiled tubing adaptability. Here are the various efficiencies and benefits:
sequence of operations. Drilling without a rig, CTD for all operations, or a combination of workover rigs and coiled tubing is possible. The decision on how to build the project depends on the availability and economics of service providers in the area. Depending on the situation, the use of workover rigs, wireline rigs and coiled tubing can provide many benefits in terms of uptime and costs. General steps include:
Steps 3, 4 and 5 can be done using the CTD package. The remaining stages must be carried out by the overhaul team. In cases where workover rigs are less expensive, casing exits can be performed before the CTD package is installed. This ensures that the CTD package is only paid when the maximum value is provided.
The best solution in North America is usually to perform steps 1, 2 and 3 on several wells with workover rigs prior to implementing the CTD package. CTD operations can last as little as two to four days, depending on target formation. Thus, the overhaul block can follow the CTD operation, and then the CTD package and the overhaul package are executed in full tandem.
Optimizing the equipment used and the sequence of operations can have a significant impact on the overall cost of operations. Where to find cost savings depends on the location of the operation. Somewhere drillingless work with workover units is recommended, in other cases the use of coiled tubing units to perform all the work may be the best solution.
In some locations, it will be cost effective to have two fluid return systems and install the second when the first well is drilled. The fluid package from the first well is then transferred to the second well, i. by drilling package. This minimizes drilling time per well and reduces costs. The flexibility of flexible pipes allows for optimized planning to maximize uptime and minimize costs.
Unparalleled pressure control capabilities. The most obvious capability of CTD is the precise control of wellbore pressure. Coiled tubing units are designed for underbalanced operation, and both underbalanced and underbalanced drilling can use BHP chokes as standard.
As mentioned earlier, it is also possible to quickly switch from drilling operations to controlled pressure overbalance operations to underbalanced operations. In the past, CTDs were considered limited in the lateral length that could be drilled. Currently, restrictions have increased significantly, as evidenced by the recent project on the North Slope of Alaska, which is more than 7,000 feet in the transverse direction. This can be achieved by using continuously rotating guides, larger diameter coils and longer reach tools in the BHA.
Equipment required for CTD packaging. The equipment required for a CTD package depends on the reservoir and whether drawdown selection is required. Changes occur mainly on the return side of the fluid. A simple nitrogen injection connection can easily be placed inside the pump, ready to switch to two-stage drilling if necessary, fig. 3. Nitrogen pumps are easy to mobilize in most locations in the United States. If there is a need to switch to underbalanced drilling operations, more thoughtful engineering is required on the back side to provide operational flexibility and reduce costs.
The first component downstream of the blowout preventer stack is the throttle manifold. This is the standard for all CT drilling operations used to control bottom hole pressure. The next device is a splitter. When working on overbalance, if drawdown is not foreseen, then this can be a simple drilling gas separator, which can be bypassed if the well control situation is not resolved. If drawdown is expected, either 3-phase or 4-phase separators can be built from the start, or drilling can be stopped and a full separator installed. The divider must be connected to signal flares located at a safe distance.
After the separator there will be tanks used as pits. If possible, these can be simple open-top fracturing tanks or production tank farms. Due to the small amount of sludge when re-inserting the CTD, there is no need for a shaker. The sludge will settle in the separator or in one of the hydraulic fracturing tanks. If a separator is not being used, install baffles in the tank to help separate the separator weir grooves. The next step is to turn on the centrifuge connected to the last stage to remove the remaining solids before recirculation. If desired, a mixing tank may be included in the tank/pit system to mix a simple solids-free drilling fluid system, or in some cases, pre-mixed drilling fluid may be purchased. After the first well, it should be possible to move the mixed mud between wells and use the mud system to drill multiple wells, so the mixing tank only needs to be installed once.
Precautions for drilling fluids. There are several options for drilling fluids suitable for CTD. The bottom line is to use simple liquids that do not contain solid particles. Inhibited brines with polymers are standard for positive or controlled pressure applications. This drilling fluid must cost significantly less than the drilling fluid used on conventional drilling rigs. This not only reduces operating costs, but also minimizes any additional loss-related costs in the event of a loss.
When drilling underbalanced, this can be either a two-phase drilling fluid or a single-phase drilling fluid. This will be determined by reservoir pressure and well design. The single phase fluid used for underbalanced drilling is typically water, brine, oil or diesel. Each of them can be further reduced in weight by simultaneously injecting nitrogen.
Underbalanced drilling can significantly improve system economics by minimizing surface layer damage/fouling. Drilling with single-phase drilling fluids often seems less costly at first, but operators can greatly improve their economics by minimizing surface damage and eliminating costly stimulation, which will ultimately increase production.
Notes on BHA. When choosing a bottom hole assembly (BHA) for a CTD, there are two important factors to consider. As mentioned earlier, build and deployment times are especially important. Therefore, the first factor to consider is the overall length of the BHA, fig. 4. The BHA should be short enough to swing fully over the main valve and still secure the ejector from the valve.
The deployment sequence is to place the BHA in the hole, place the injector and lubricator over the hole, assemble the BHA on the surface cable head, retract the BHA into the lubricator, move the injector and lubricator back into the hole, and build the connection. to BOP. This approach means no turret or pressure deployment is required, making deployment quick and safe.
The second consideration is the type of formation being drilled. In CTD, the face orientation of the directional drilling tool is determined by the guiding module, which is part of the drilling BHA. The orienteer must be able to navigate continuously, i.e. rotate clockwise or counterclockwise without stopping, unless required by the directional drilling rig. This allows you to drill a perfectly straight hole while maximizing WOB and lateral reach. Increased WOB makes it easier to drill long or short sides at high ROP.
South Texas example. More than 20,000 horizontal wells have been drilled in the Eagle Ford shale fields. The play has been active for over a decade, and the number of marginal wells that will require P&A is increasing. The play has been active for over a decade, and the number of marginal wells that will require P&A is increasing. Месторождение активно действует уже более десяти лет, и количество малорентабельных скважин, требующих P&A, увеличивается. The field has been active for more than a decade and the number of marginal wells requiring P&A is increasing.该戏剧已经活跃了十多年，需要P&A 的边缘井数量正在增加。 P&A 的边缘井数量正在增加。 Месторождение активно действует уже более десяти лет, и количество краевых скважин, требующих P&A, увеличивается. The field has been active for more than a decade and the number of lateral wells requiring P&A is increasing. All wells destined to produce the Eagle Ford Shale will pass through the Austin Chalk, a well-known reservoir that has produced commercial quantities of hydrocarbons for many years. An infrastructure has been put in place to take advantage of any additional barrels that can be put on the market.
Chalk drilling in Austin has a lot to do with wastage. Carboniferous formations are fractured, and significant losses are possible when crossing large fractures. Oil-based mud is typically used for drilling, so the cost of lost buckets of oil-based mud can be a significant portion of the cost of a well. The problem is not only the cost of lost drilling fluid, but also changes in well costs, which also need to be taken into account when preparing annual budgets; by reducing the variability in drilling fluid costs, operators can use their capital more efficiently.
The drilling fluid that can be used is a simple solids-free brine that can control downhole pressure with chokes. For example, a 4% KCL brine solution containing xanthan gum as tackifier and starch to control filtration would be suitable. The weight of the fluid is about 8.6-9.0 pounds per gallon and any additional pressure required to overpressure the formation will be applied to the choke valve.
If a loss occurs, drilling may be continued, if the loss is acceptable, the choke may be opened to bring the circulating pressure closer to reservoir pressure, or the choke may even be closed for a period of time until the loss is corrected. In terms of pressure control, the flexibility and adaptability of coiled tubing is much better than conventional drilling rigs.
Another strategy that can also be considered when drilling with coiled tubing is to switch to underbalanced drilling as soon as a high-permeability fracture is crossed, which solves the problem of leakage and maintains the fracture productivity. This means that if the fractures do not intersect, the well can be completed normally at low cost. However, if fractures are crossed, the formation is protected from damage and production can be maximized by underbalanced drilling. With the right equipment and trajectory design, over 7,000 feet can be traveled at Austin Chalka.
generalize. This article describes the concepts and considerations when planning low cost re-drilling campaigns using CT drilling. Each application will be slightly different, and this article covers the main considerations. CTD technology has matured, but applications have been reserved for two specific areas that supported the technology in its early years. CTD technology can now be used without the financial commitment of a long-term activity.
value potential. There are hundreds of thousands of producing wells that will eventually have to shut down, but there are still commercial volumes of oil and gas behind the pipeline. CTD provides a way to defer releases and secure bypass reserves with minimal capital outlay. Drums can also be brought to market at very short notice, allowing operators to take advantage of high prices in weeks rather than months, and without the need for long-term contracts.
Efficiency improvements benefit the entire industry, whether it be digitalisation, environmental improvements or operational improvements. Coiled tubing has played its part in driving down costs in certain parts of the world, and now that the industry is changing, it can deliver the same benefits on a larger scale.