Emerging Coiled Tubing Drilling Technology (2)
Emerging Coiled Tubing Drilling Technology (2)
口 Sun Zhenchun/China National Petroleum Corporation Consulting Center Senior Expert, Professor-level Senior Engineer
He Lixin / Oran (Beijing) Petroleum Technology Company
The previous article introduced the development and application of coiled tubing drilling technology. From this issue, it will focus on some important equipment of this technology.
Basic Equipment for Coiled Tubing Drilling
The basic coiled tubing equipment used by most coiled tubing drilling operators is very similar to workover services (Picture 1). In some cases, individual equipment may need to be modified or replaced to suit specific applications. The trend towards the use of larger diameter coiled tubing in coiled tubing drilling has resulted in very different sizes of drilling equipment and workover equipment. The main basic equipment is introduced as follows.
Coiled Tubing Drum The primary function of the coiled tubing drum is to safely protect and store the coiled tubing (Picture 2). This is achieved by avoiding excessive damage from fatigue (bending) of the pipe string or mechanical damage. A flexible elbow is usually attached to the drum so that the drum can pump fluid through the coiled tubing during rotation. For 1000 CTD operations, coiled tubing, take-over plate and collector assemblies with cables inside are required so that the cables in the coiled tubing string are connected to the ground through rotating drums (cable elbows/collectors). In addition to the hydraulic fittings that operate the drive motors, brakes, and guides (pipe runners) systems that wind the pipes, the drums used for CTD operations are often equipped with detection equipment and connectors (such as pressure detection sensors for MWD mud pulse technology, or continuous Tubing string testing equipment such as diameter and ovality testing devices).
The theoretical capacity of continuous oil management of the drum (Picture 3). It can be calculated by the following formula. The assumption is that the tube wraps well over the entire drum. It is practically difficult to achieve this level and a margin must be left in order to keep the capacity of the drum within practical limits.
In the formula, L-pipe capacity (feet); A-pipe stacking height (inch); B-width between flanges at both ends of the drum (inch); C-roller mandrel diameter (inch); K-different pipe sizes K value (ft/in3).
K values for different tube sizes (see Table 1).
The coiled tubing can be properly arranged on the drum by the use of the drive motor and the pipe racker. Using a roller with a larger radius can significantly increase the life of the coiled tubing. Recommended roll mandrel radii are shown in Table 2.
Coiled Tubing Even basic CTD operations require high performance coiled tubing strings. For example, if the drilling operation requires multiple trips and trips of the coiled tubing string in the same wellbore, the fatigue of the coiled tubing string will build up rapidly. In addition, the likelihood of stuck tubing during CTD operations is higher than that of most conventional workover operations. bigger. Not only does this mean that the coiled tubing string must perform optimally, but the operator must know the operating conditions limits of the drilling coiled tubing string at all times. There is always a desire to improve the yield stress of the coiled tubing and possibly the use of novel materials such as titanium alloys, composite materials and ceramics, etc., in order to broaden the drilling depth limit and better monitor and understand the coiled tubing at different pressures and temperatures. Fatigue life with cyclic use. Computer models have been used to analyze pipe fatigue life and as a coiled tubing monitoring system in drilling.
Drilling new and directional wells typically uses 2-3/8" or 2-7/8" coiled tubing. In recent years, most vertical wells have been drilled with 2" coiled tubing, and most vertical new wells have been drilled with 2-7/8" coiled tubing. Coiled tubing used in drilling operations has a maximum OD of 3-1/2", and newer hybrid drilling systems use 3-1/4" OD coiled tubing as standard.
For almost all drilling operations, it is recommended that the tubing string be at least 0.156" thick and be constructed of material with a yield strength of 70,000 psi or 80,000 psi. However, for drilling deeper vertical wells or extending longer horizontal wells, a 100,000 psi yield strength may be required. Or 110,000 psi material. For some wells, tapered tubing with wall thickness tapering from 0.190" to 0.125" may be required.
Typically, for a given drilling operation, coiled tubing is sized between tube life (smaller size tubing has longer cycle life, but lower strength and limited flow) and flow cross section (larger size tubing A compromise between higher strength and larger flow cross section, but shorter cycle life). As a result, CTDs typically use 2-3/8" or 2-7/8" coiled tubing. Also, consider the amount of coiled tubing that can be wound on a given drum to the desired depth or the maximum weight the crane can support.
During the drilling design phase, the optimal size, wall thickness and yield strength of the coiled tubing are determined using coiled tubing simulation software and well data relative to the well intended to be drilled.
If the coiled tubing parameters cannot be determined by computer model selection, the following recommended parameters can be considered:
1. Internal pressure limit: the maximum pump pressure during the operation of the coiled tubing is 4000psi; the maximum pump pressure when the coiled tubing is stationary is 5000psi. 2. The maximum breaking pressure difference is 1500psi. 3. The maximum recommended wellhead pressure is 1500psi. 4. The maximum tensile limit of coiled tubing is 80% of the yield strength published by the manufacturer. 5. Diameter and ovality of coiled tubing: the maximum outer diameter is 106% of the nominal diameter of the coiled tubing; the minimum outer diameter is 96% of the nominal diameter of the coiled tubing.
The industry has invested a lot of time and effort into studying the lateral length limit of coiled tubing drilling horizontal wells. The primary factor controlling the length of wellbore that can be drilled by coiled tubing is coiled tubing bending. A slender pipe in a highly deviated wellbore or a horizontal wellbore will become sinusoidally bent under a certain sinusoidal force:
Fcrs = 2 x ( E x I x W ) 1/2
Fcrs = 2 x ( E x I x W ) 1/2
In the formula, Fcrs is the critical force (lbf); E is Young's modulus, 30 x 106 (psi); I is the moment of inertia (in4); W is the weight of the tubing in the mud (lb/ft); Dh-Dp is the radial clearance (in).
式中，Fcrs为临界力(lbf)；E为扬氏模数，30 x 106 (psi)；I为惯性矩(in4)；W为油管在泥浆中的重量(lb/ft)；Dh-Dp为径向间隙(in)。
In the case of sinusoidal bending, only a small amount of weight is transferred to the drill. When the axial force reaches a second, larger critical value, Fcriu (approximately 1.4 times larger than Fcrs), helical bending occurs. In the final stage, helical locking occurs and no force can be transmitted to the bit, at which point the coiled tubing is no longer advancing along the horizontal wellbore.
In order to maximize the horizontal wellbore drilled by the coiled tubing, every effort should be made to: keep the wellbore clean and free of cuttings deposits; maximize the density of the drilling fluid; and minimize dogleg severity (wellbore curvature).
The second factor controlling the length of the horizontal section is the inability to install weighted tubing (drill collars/weighted drill pipe) above the build-up point in coiled tubing drilling. One option to overcome these limitations is to use a tapered coiled tubing string.
Injector Head The injector head (Picture 5) provides the power and traction required to raise and lower coiled tubing in the wellbore. The injection head has two traction chains running in opposite directions and is hydraulically driven. Clamp blocks are installed on the drag chain for running coiled tubing into and out of the well. When the coiled tubing is in the well, the injection head supports the full weight of the coiled tubing.
The CTU operator needs to have complete control over the movement of the coiled tubing string using several hydraulic systems—an important feature because drilling loads must be carefully controlled during CTD.
The pulling force of the injection head for drilling is at least 60,000 lbs. The main technical performance parameters of the commonly used Hydra Rig injectors are listed in Table 3.
The radius of the gooseneck has a great influence on the life of the coiled tubing. About 75% of coiled tubing fatigue and deformation are related to goosenecks. The large radius of the gooseneck is beneficial to prolong the life of the coiled tubing. Recommended gooseneck radii are listed in Table 2.
Power Unit The function of the power unit is to provide power to operate the CTU and primary/secondary pressure control systems such as blowout boxes and BOP systems. In addition to providing hydraulic power when the equipment is running, the power unit is equipped with an energy storage device, which can operate the pressure control device within a certain limit after the engine is stopped. During drilling, if non-standard equipment or auxiliary equipment is to be powered by the CTD power unit, it should be confirmed that the power unit output is appropriate and that the pressure and flow rates are matched.
Most CTD operations are long-running and therefore require proper inspection and maintenance of the power plant during drilling, such as adding fuel oil, checking lubrication, etc.
All CTD operations on cranes require some equipment to lift, move and place the drilling tool (BHA). Local conditions and equipment configuration will determine the size (height) and lifting capacity of the crane. A crane is often used to place the injector on top of the BOP and then hang the injector in place. The boom should be long enough to bury a 40-foot BHA (drilling a vertical hole/milling casing) or a 65-foot BHA (drilling a directional hole) above the support.
Pedestals For a specific drilling project, the CTD engineer must determine if a plinth is required and its size and type. The base (Figure 5) is used to increase the stability of the wellhead equipment. Its main features are:
1. Raise the work above the wellhead equipment for easy access to the wellhead; 2. Use to support the injection head without a crane, raise/lower the injection head position for easy installation. 3. When installing the BHA, allow the injection head to translate away/return to the wellhead; 4. Provide a safe working platform for the operator when hoisting the injection head or BHA; 5. Support the BHA/pipe during installation operations.
The support should be designed so that its height can be adjusted within certain limits to suit the particular wellhead and surrounding conditions. Usually, the legs of the stand are fixed after they are adjusted to the proper height.
One of the more complex CTD mounts is the hybrid device, or jack mount. Its structure is that there is a platform on the base that is raised/lowered by a hydraulic cylinder. The feature of this type of base is that the height of the table can be adjusted freely and can be used to raise and lower pipes, reducing the reliance on heavy-duty cranes or derricks.
Ensure safe pipe loading and unloading equipment
Pipe loading and unloading equipment is used to help ensure safe and proper loading and unloading of pipe and tools such as drill collars, tubing, couplings, casing couplings, and the like. For CTD operations, the pipe loading and unloading equipment used in conventional drilling needs to be modified or reduced in size in order to operate efficiently.
Blowout Preventer (BOP) System for Well Control
The configuration of the BOP equipment required for CTD operations depends largely on the type of operation and the "worst-case" conditions that the operation is expected to encounter. There are several BOP systems with very different combinations. One or more of the following scenarios are encountered in most CTD operations:
1. Low pressure diverter system---used when drilling new wellbore in shallow layers containing harmful gas. 2. The drill bit is smaller than the inner diameter of the CT four-ram BOP---the drill can pass through the four-ram BOP. When drilling deviated wells, the curved shell motor can further limit the outside diameter of the drill bit. Under normal circumstances, the maximum outer diameter of the drill bit for drilling directional wells is 3-7/8". 3. The drill bit is larger than the inner diameter of the CT four-ram BOP---the bit cannot pass through the four-ram BOP. 4. Hybrid tripping/running pipe Operation --- Requires BOP to fit the size of tubing/casing to be operated. 5. Operating BHA under underbalanced conditions --- Requires specially constructed BOP to accommodate gas well conditions and to control wellbore pressure.
Requirements for basic well control equipment are as follows: suppress wellbore pressure and fluids, such as providing primary containment (blowout preventer box); be able to circulate under controlled conditions, such as through drilling strings or choke manifolds; return fluids from the wellbore Or the separated product is diverted to a safe area for processing or storage; continuous monitoring of drilling fluid performance, flow rate and pressure.
For most CTD jobs, a BOP pressure rating of 5000 psi is suitable. However, the operating pressure rating must exceed the expected bottom hole pressure. The BOP size (or diameter) depends on the size of the wellbore or planned completion. The commonly used coiled tubing BOP system is a 4" (inner diameter) four ram structure. Larger BOP sizes (eg 5" to 7-1/16 ”) is not commonly used; if used, BOPs of single or double ram construction are usually used. In most cases, at least a semi-closed ram and a shear/full-closed ram BOP are required, and often include an annular BOP to Provides applicability to a variety of jobs. The annular BOP can seal any diameter of pipe or tool, from fully closed to fully open.
The well control equipment used in most CTD operations is very similar to that used in workover operations. In some cases, individual components can be modified or replaced to suit specific applications, but often devices for different applications can be used interchangeably. The main components of the BOP are as follows:
BOP The side door BOP is the most commonly used BOP for CTD operations. It has good sealing performance, and its seals can be easily replaced during coiled tubing operations.
The standard quadruple BOP (Figure 6) provides suitable functionality and is easy to install and operate if the inside diameter is suitable. Larger boreholes typically require a 7-1/16" BOP.
Single Ram/Double Ram BOP When drilling operations require a diameter larger than 5-1/8", the BOP group can be assembled by 5-1/8" or 7-1/16" single or double rams made.
Ring BOP Ring BOP is extremely adaptable and can accommodate a wide range of tool sizes.
Other BOP Equipment Other BOP equipment used to connect, monitor or operate pressure control equipment groups include: Kill Manifolds, Choke Manifolds, Reverse Circulation Manifolds, BOP Controllers and Instruments, Mud Crosses/Risers.
The coiled tubing is sealed by a blowout preventer box located on top of the blowout preventer as it travels in the well. The blowout preventer keeps the annular space sealed during the drilling process and during the tripping of the string in the wellbore. In order to facilitate the use of the bottom hole tool combination, it is necessary to install the blowout preventer and the riser between the blowout preventer and the injection head.
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Coiled tubing drilling auxiliary equipment, testing equipment, bottom hole assembly (BHA)
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Coiled Tubing Drilling, Coiled Tubing Rollers, Coiled Tubing Theoretical Capacity, Internal Pressure Limits, Sinusoidal Bending, Injection Heads, Power Units, Pressure and Flow Rates, Bearings, Hybrid Units, Pipe Loading and Unloading Equipment, Blowout Preventer (BOP) Systems , Blowout preventer, four-stage BOP, single ram/double ram BOP, annular BOP, other BOP equipment, suppress wellbore pressure.
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