Rethinking Well Construction by Use of Drilling With Casing
Advances in drilling and reaming with casing or liners (DwC, DwL, RwC, and RwL) are yielding unprecedented capabilities in well design and construction. These innovations reflect the continued evolution of a versatile system of technologies that has grown in two decades from a tool to improve efficiency and mitigate drilling hazards to a system enabling advanced wellbore construction.
Advancing the Technology
Modern DwC involves a suite of capabilities for drilling and reaming with either the primary string or liner. The concept has a long history. In the 1950s, the production sections of wells were drilled using tubing that was ultimately cemented in the hole without recovering the bit. Slimhole coring technology from the mining industry was tried in the 1990s in an effort to improve exploration efficiency.
Over the next decade, DwC technology and versatility grew. In addition to eliminating nonproductive time (NPT) tripping drillpipe out of the hole and the associated wellbore problems, DwC emerged as an effective means of proactively mitigating wellbore instability, lost circulation, and pressure transition issues.
The introduction of an integrated casing drive system in the early 2000s enabled the safe and efficient rotation, reciprocation, and circulation of the casing, which led to other benefits such as ensuring high-integrity cementing and zonal isolation. Advances in casing bit design began to resolve the inherent challenge of durability vs. subsequent drillout.
With growing wellbore complexity and challenges, DwC technology evolved from discrete hazard mitigation to a larger capability well plan optimization. Greater capability advanced the end objective from solving an immediate problem to constructing a high-integrity wellbore—as designed and to the total depth (TD). The latest innovations continue this wellbore construction advance on multiple fronts.
Strengthening the Wellbore
Plastering has been one of the more intriguing and elusive benefits of DwC techniques. The so-called smear effect crushes cuttings against the formation to form a barrier to circulation losses and enhance wellbore stability. But achieving it on a regular, predictable basis has been difficult. Plastering occurs in some wells but not in others.
A greater understanding of this process is providing the means to produce and accelerate wellbore plastering reliably, thus substantially strengthening the wellbore. The first field application of the process is planned. Research has shown that the key to plastering is the concurrence of the formation’s permeability and fracture matrix with a wide range of particle sizes in the annulus. If these factors do not correspond, plastering does not occur.
The main variables are the range of particle sizes and the speed of achieving an optimal size distribution. While grinding in the casing wellbore annulus can reduce cuttings to a wide range of size over time, the delay in achieving the appropriate distribution allows time for problems to develop. Early achievement of the optimal particle distribution is critical to success.
In addition, and critical to the calculation, this optimal size distribution may never occur if left to natural processes. There are many factors that influence plaster formation, and they create a complex equation for success. Mud type—water, oil, or synthetic—along with rock type and bit selection can all affect particle formation and distribution. The size of the annulus between the hole and the casing contributes many variables to the equation, including annular velocity and the time that cuttings are exposed to annular grinding.
Achieving a much higher probability of plastering and accelerating the process have been essential to establishing an effective plastering capability. Based on research into particle size, creation, and distribution, proprietary software has been developed to create an optimal blend of application-specific wellbore strengthening materials (Fig. 1). The blend of materials is added to the drilling fluid before penetrating the lost circulation zone.
The theoretical strengthening mechanism has three levels. First, the casing rotation on the wellbore wall repairs the imperfections of the borehole such as microcracks and small fissures, therefore helping restore the original integrity. This process is thought to be responsible for the strengthening benefits observed while drilling impermeable shales, in which conventional wellbore strengthening methods are not applicable. Second, in lost circulation scenarios caused by fracture propagation, the available particle size distribution from the added blend and ground cuttings are plastered into the induced fractures, helping to isolate the pressure to the tip and arrest the fracture growth. The propped fractures increase the tangential stress around the wellbore wall. Third, continuous rotation of the casing heals the fractures, and the plastered filter cake reduces the permeability at the compacted near-wellbore zone, providing an effective stress in the wellbore vicinity.
Wellbore strengthening increases the fracture gradient, enabling a wider mud weight window to reduce the loss of circulation and the potential for well control events, and can eliminate the need for a contingency string to mitigate a problem zone.
Advances in DwL wellbore construction include its integration with managed pressure drilling (MPD) capabilities for wellbore pressure management. The union is another reminder that complex well construction challenges require more than a simple technology fix.
MPD controls wellbore pressure through management of annular backpressure in a closed loop drilling system. The effect is dynamic control of equivalent circulating density (ECD) in contrast to conventional systems that depend on changes in mud weight.
MPD is commonly performed with drillpipe. This necessitates tripping the pipe and running casing, which can result in surge and swab pressures and prolonged wellbore exposure. DwL provides the solution to tripping, and when combined with MPD provides a highly effective means of drilling and casing problem wells. Lower density fluids can be used with MPD, allowing the ECD to maintain sufficient overbalance to contain pressured reservoirs while mitigating wellbore instability in unstable shale formations. Furthermore, MPD allows the application of surface backpressure while making connections, which compensates for the loss of annular friction pressure during drilling.
In slot recovery operations offshore South America, the use of the integrated capabilities is planned for drilling and running casing through weaker sand and shale sequences at hole angles requiring mud weights exceeding the anticipated fracture gradient. Impetus for the program came from sidetrack problems with the original wells that resulted in 281 days of NPT.
A collaborative engineering process using the operator’s basis of design led to the combination of MPD and RwL to drill and case the difficult 12½-in. and 9½-in. hole sections. Once drilled, the application of surface backpressure during liner-running operations is planned for maintaining wellbore stability and safely reaming the 9⅝-in. and 7⅝-in. drilling liners to TD.
Solving the Bit Conundrum
Drilling with casing bits continues to be a key enabling technology for DwC applications. The bit challenge is inherent because the bit must be tough enough to drill the rock and yet be drilled out with the same type of bit that drills the next section, without the process damaging the new bit. Risk of damaging the drillout polycrystalline diamond compact (PDC) bit has been a primary constraint in increasing the durability of drillable bits.
Recent design innovations are achieving much faster drillout times with PDC casing bits designed for drilling in medium to medium-hard formations with unconfined compressive strengths of up to 15,000 psi. The new bits have an average drillout time of less than 20 minutes, compared with steel alloy casing bit drillout times of 125 minutes.
The Weatherford Defyer DPA casing bit provides a cutting structure comparable to conventional PDC bits with an average of 80% less steel in the drillout path, compared with full steel alloy casing bits. As a result, drillout times are significantly reduced. In a study of multiple bit runs, the casing bit was drilled and the hole section reached TD in a single run. Cutters on the PDC drillout bits remained in good condition.
In the Asia Pacific region, the new bit design was a key to drilling a well with 13⅜-in. casing that is the world’s deepest DwC application. The benefits included high rates of penetration and fast drillout time, while meeting the operator’s directional objective. The bit drilled a total 593 m of medium soft claystone interbedded with sandstone at 43 m/h to 46 m/h. A zone of about 45 m of hard limestone stringers was drilled at a rate of 6 m/h to 36 m/h.
The section’s TD was reached in 16 hours with a hole inclination of 0.24°. Drillout of the DPA bit took approximately 8 minutes using a 12¼-in., 6-blade, 19-mm cutter steel-bodied PDC bit (Fig. 2). The bit was later graded at 2-3-BT-A-X-3-WT-TD after drilling 1188 m to TD.
In deepwater applications, DwC technology developed specifically for NPT reduction, reduced mud costs, and hazard mitigation is in the final design stages following successful testing. The technology features a retractable shoe joint that allows the high-pressure wellhead housing to be landed safely once the surface section is drilled.
Drilling with casing on wells with surface blowout preventers requires drilling the section to TD with the casing and casing hanger separate. Once on the bottom, the string is pulled back and a joint or two of pipe is laid down. Then a joint with the casing hanger is picked up, made up to the string, run, and cemented. In a subsea application, this would require the casing string to be tripped back to the surface to install the high-pressure wellhead housing, which would negate a key reason for DwC.
The SeaLance DwC system provides a means of drilling to TD, telescoping the string to land the high-pressure wellhead housing, and cementing in a single trip. The system eliminates tripping of the conventional bottomhole assembly and the requirement to pump weighted mud after drilling the hole section. The reduced annulus allows much lower flow rates for transporting cuttings and a significant reduction in mud volumes required to drill the hole section. DwC hazard mitigation benefits address problems including collapsed holes, fluid losses, shallow gas, and rubble zones. In addition, the system facilitates batch setting of wells using a less expensive multipurpose vessel or smaller rig, with a larger rig following to drill each well to TD.
Continued advances across a full scope of DwC, DwL, RwC, and RwL technologies are answering complex wellbore challenges with new methods focused on the larger objectives of wellbore construction. Integrated in the well’s basis of design, these systems provide game-changing options for how wells are planned and constructed.
Mechanical Extrusion Offers Advantages Over Ball Activation for Downhole Tools
One of the most innovative recent advances in downhole drilling tool activation has been the introduction of mechanical extrusion technology, incorporating the use of rigid metal darts to improve the cycling and control of a variety of processes and devices. Increasingly, operators are recognizing mechanical extrusion by means of dart activation as a time-, cost-, and labor-saving alternative to traditional ball activation methods.
For example, conventional cycling of drilling bypass valves has used a polymer extrusion process that relies on balls as the activation device. However, Churchill Drilling Tools has developed an effective and accurate mechanical extrusion method that uses a dart-based valve. The system can perform activations up to five times faster than polymer methods.
The company’s MX (mechanical extrusion) system allows the use of rigid Smart Darts for multicycle control and exploits their robustness and resilience at high pressures and temperatures (up to 660°F) to deliver greater operating speed, reliability, and performance. The system’s unique feature is its two configurable shearing modes, which solves reliability and power delivery problems. It requires a radius as small as 0.0075 in. for power transmission, thereby making implementation extremely compact.
With the ability to control and power three or more tools independently, users eliminate the conventional inner diameter (ID) and obstruction conflicts between different tools in a string. This has implications for mono-cycling ball and shear systems, which commonly obstruct the bore after use. These can be turned into multicycling, nonobstructive, and multitool systems. The system can also enhance multicycling ball-activated tools that are based on polymer extrusion by improving performance and delivering greater multitool compatibility and interoperability.
The system allows the mechanical extrusion to be delivered in a range of settings to suit the specific cycle application. With a variety of latching, sealing, and flow path geometries, as well as the adjustable shear mode ratings, this element of the system provides a tangible change in string design and program implementation. For example, in bypass valve implementation, users can cover multiple flow path contingencies with a single valve in hole and choose from the range of darts to establish the optimal setting for the situation encountered.
The system advances the capability of simple hydromechanical control and its power and reliability benefits into areas that previously needed more complex electronic systems. Being mechanical, it is not subject to the same high pressure and high temperature limits that affect electronics and electrical components.
Smart Darts enable a multicycle circulating sub (circ sub) tool to deliver a reliable and versatile bypass on demand. Whatever the drilling application, whether planned or a contingency, the system enables a rapid and reliable switching to the optimal flow path configuration.
The correct flow path mode is vital for a given application. There is no need to set up a Dart Activated Valve MX configuration in advance, as one tool in hole will do everything. Each bypass application has its own dart to “quick set” the valve into the right mode. Functions such as spotting lost circulation material (LCM), split-flow hole cleaning, and dry tripping can operate on a “plug and play” basis.
The closing cycle is likewise easy by using a rapidly deployed universal closing dart to allow drilling to resume quickly without loss of hydraulic performance. Multiple dart cycles can be performed in any sequence.
When curing losses, boosting hole cleaning, or performing other circulation applications, conventional bottomhole assembly (BHA) bypass relies on balls landing on seats. Landing seats are sized to withstand a pressure-up activation cycle and then succumb to a blowthrough shear-out sequence to regain circulation to the bit. The emergence of the mechanically extruding dart technology, as an alternative to polymer extrusion, has presented tool designers with an opportunity to push some of the performance boundaries of conventional valves.
The goal for any tool is to maximize performance and value while being as simple, reliable, and flexible to use as possible. For drilling bypass valves, a specific analysis to assess the current conventional limits follows.
Activation Speed and Ball Displacement Algorithms: With heavy losses, fast activation is critical to stem mud loss to the formation. Overzealous activator displacement, which fails to take into account the depth, angle, and mud density parameters, creates a risk of blowthrough misfire. Conservative displacement can increase delays and may make activation pressure more difficult to detect from the surface. Therefore, polymer extrusion systems can lead to comparatively slow activation sequences, as time is taken for displacement calculations and detection of the activation point before curing can begin. In contrast, darts eliminate the calculation element and activate at high pump rates. And with a positive opening stroke clearly indicated by a pressure drop, losses can be treated more quickly.
Cycling Reliability: The properties of the extrusion determine the performance window of the cycle. Using polymer extrusion, the designer has to create interference between the ball and the seat that can withstand the landing shock and allow the ball to overcome the inertia of the piston/mandrel in the valve before it reaches its extrusion threshold. In single-cycle circ subs, this interference can be overengineered to guarantee opening. But for multicycling, the shear-out point needs to be in pump range so that circulation can be regained by extruding the ball. For valve closing by polymer extrusion to be possible, it must also remain possible for the ball to misfire by definition. By creating a dual shear point characteristic (), mechanical extrusion simultaneously addresses reliability and the activation speed.
Multimodal/Application Flexibility: When selecting a valve, it is prudent to perform a weighted risk assessment to identify the circulating contingencies that are most likely for a given well. For example, while hole cleaning might be a major issue, contingency for heavy losses might be prioritized on the basis of well control. The operator then selects a tool based on these priorities.
In polymer extrusion systems, tool choice is an important consideration because of the multiple configuration permutations during bypass. The introduction of an activation ball sets the polymer extrusion tool in primary bypass mode. However, this may not be the optimal setting, meaning that performance is either limited or delayed while smaller secondary setting balls are pumped to secondary seats to create application specific flow paths. By contrast, dart-based mechanical extrusion can optimize bypass for almost any application in a single step, thereby simplifying the tool selection and application.
Genuine BHA Isolation: Using polymer extrusion, contamination of the BHA during pill spotting can occur even when 100% bypass has been configured. A ball on a seat seals in just one direction. Once the pumps are switched off, U-tubing and buoyancy forces will determine whether the ball stays on its seat or floats or rolls away to allow curing fluids to make their way into the BHA. Dart latching through mechanical extrusion ensures isolation.
Simplicity of Operation and Design: Complexity downhole invariably adds risk and decreases reliability. While the permutations of polymer extrusion methods allow the skilled user to activate and configure for almost any application, the need for skill and expertise adds risk for the operator. Multisized operating balls and complicated displacement procedures for activation can increase the risk of error and nonproductive time. Furthermore, caution about trying unfamiliar or complex procedures could lead to suboptimal use and diminished return on investment in the tool.
For the mechanical extrusion system, a simple port and piston assembly housing a low-profile ceramic “socket” to catch the darts is all that is required. The darts themselves determine performance. Individually sealed, the dart is kept isolated from the downhole environment until the last minute and is used once. The dart’s robustness allows deployment and landing at speeds up to 2,000 ft/min, five times faster than polymer extrusion methods. This can save more than an hour of waiting time and provides positive opening indications to reduce uncertainty.
In more than 120 applications through 2012, the system has achieved a 100% reliability record. For example, a European land operator used a single dart cycle to set hole cleaning and tripping dry modes simultaneously, saving time and improving rig floor safety to a level previously unattainable.
In another instance, a North Sea operator planned for hole cleaning and jetting, but when unexpected losses occurred, it was able to switch strategies in a timely manner and select a dart that would deliver LCM into the formation and protect the BHA from contamination.
The system has been used successfully in bypass valves for more than 80 wells since January 2011, including in the Gulf of Mexico.
In December 2011, mechanical extrusion was applied to a fourth dart in a new tool for string integrity testing. The Pressure Testing Sub MX system provides a simple, accurate way to test a drillstring up to a specific preset pressure with the capability to regain circulation between each test. This allows users to perform multiple tests at various pressures in a single run. The system can be run in any length of pipe, at any angle or temperature, and with any type of circulation fluid.
The subs have fully tapered internals, provide unrestricted circulation and have a full through-bore before the first cycle. The dart is dropped and pumped into place with the load transmitted through pins in the dart into the sub. The pins determine the shear-out pressure. Pressure can be held at the required test level for as long as necessary. When testing is complete, a small increase in pressure is used to shear out the dart into the catcher below (Fig. 2). The benefits of the system are that multiple test cycles can be performed, full circulation can be regained between each test, and that the shear-out point can be accurately modified by altering the dart’s pins before it is dropped.
The system was first successfully used in Norway by a major pipe manufacturer in 2011 with shearing accuracy results of 99.6%. Subsequently, a full program of further drillstring development applications with the system has been scheduled. The system is also being used in the United Kingdom Continental Shelf for leak detection in operational drillstrings in pre-emptive integrity tests before ultracritical high-pressure phases.
Choosing the Right Tool for the Job
The Smart Dart can easily be integrated into existing tool designs by replacement of the landing seat and does not require a redesign of their ball activated systems. The dart is available in a range of sizes with easily adjustable shearing points. Whereas a typical ball system requires about 13.4% of the bore ID for use in power delivery, the MX system requires less than 1% of the bore ID for that purpose. This compactness aids tool implementation and flexibility for multitool compatibility and interoperability.
The system enables the improvement of BHA design through the reduction of ID restrictions and an increase in operational performance windows. To achieve this, ball seats within a series of conflicting tools can be replaced with dart seats that catch only the darts intended for that tool. This simplifies the process for the user, as more options are available for operating the BHA.
Smart Darts can provide an unlimited combination of geometries, latches, seals, and chokes that can be rapidly deployed to set the tool into its optimal configuration.
Mechanical extrusion by means of dart use is helping to make existing processes faster, simpler, and more cost-effective. This merits an evaluation of mechanical extrusion for its potential to become the conventional system for a range of downhole deployments.