This application relates to the disclosures of U.S. Pat. No. 7,210,710, issued on May 1, 2007, the entire contents of which are incorporated herein by reference.
The present invention relates to a drill pipe, a tubular drill string component for unconventional oil and gas drilling with 6⅛″ to 6¾″ production hole sizes. Unconventional oil and gas drilling is commonly referred to as shale drilling.
Shale drilling is becoming increasingly developed as hydraulic fracturing, or fracking, continues to make unconventional recoveries more efficient and economical. Shale drilling typically requires the drilled hole to include a vertical profile followed by a horizontal profile such that the well trajectory maximizes exposure to the production zone. A typical Bakken well profile would have a kick-off point between the vertical and horizontal profiles located at about 10,000 feet Measured Depth (MD) followed by another 10,000 feet MD of horizontal section. Typical build rates from vertical to horizontal are about 10 degrees dogleg or higher, increasing the well tortuosity and hence the cyclical stresses on the drill pipe.
Issues associated with conventional drilling are exacerbated in the case of shale drilling. Drilling horizontal wells is more challenging as the drilled lengths increase, both vertically and horizontally. Challenges include managing ECD (Equivalent Circulating Density), providing directional control towards the trailing end of horizontal section, efficient hole cleaning, and dealing with inefficiencies due to drill string buckling and increased tubular wear.
Horizontal drilling with a longer horizontal section tends to increase hole cleaning challenges, and can cause the drill string to get stuck if drilling parameters and mud properties are not closely monitored and adjusted in real time.
Difficult drilling conditions lead drill pipes used for unconventional drilling to have a shorter drilling tubular life than drill pipes used for conventional drilling. A typical shale well horizontal section is drilled with the drill string in compression, increasing contact between the pipe and the formation or casing, especially in curved portions, leading to wear. The life span of drill pipes used on shale wells is significantly reduced by 1-2 years from the typical 4-5 year life span of drill pipes used for conventional drilling. Drill pipes in shale wells thus require more frequent repairs, and more frequent replacement than conventionally used drill pipes, hence also driving the costs higher.
Currently used drill pipes typically have a 4″ outside diameter (OD), following standards described in the API SPEC 5DP: Specification for Drill Pipe, the entire content of which is incorporated herein by reference. Buckling and mid-section wear are two main issues associated with existing drill pipes, which are related to drill pipe diameter selection.
A drill pipe for unconventional oil and gas drilling is disclosed herein and an exemplary embodiment comprises first and second tool joints, with the first and second tool joint having identical outside and inside diameters, a main portion between the first and second tool joints, with upsets adjacent to the first and second tool joints, and a central section between the upsets. An outer diameter of the central section of the main portion is less than an outer diameter of the main portion upsets, and the ratio of the outer diameter of the central section of the main portion to the outer diameter of the main portion upsets is selected for a range of given hole sections from 6⅛″ to 6¾″.
The characteristics and advantages of an exemplary embodiment are set out in more detail in the following description, made with reference to the accompanying drawings.
It is an object and feature of an exemplary embodiment described herein to provide a shale drill pipe with an optimum outer diameter to minimize buckling and mid-section wear, and optimize drilling efficiencies. An exemplary embodiment increases drill string buckling resistance and allows higher flow rates. An exemplary drill pipe may in addition have a zone to increase shale drill pipe life expectancy.
One advantage of an exemplary shale drill pipe described herein is the ability to apply more weight on bit, which yields a greater rate of penetration, without experiencing pipe buckling. Another advantage of the exemplary shale drill pipe described herein is an improvement in hole cleaning efficiency by decreasing bottoms up time as well as number of bottoms-up cycles to clean the well. The exemplary drill pipe can be handled with standard handling equipment (elevator). These and other objects, advantages, and features of the exemplary shale drill pipe described herein will be apparent to one skilled in the art from a consideration of this specification, including the attached drawings.
Referring to
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Tool joints used (2) have double shoulder connections such as VAM® Express connections, which offers a higher torque and a longer service life with a slimmer profile than other tool joints. Tool joint outer and inner diameters vary based on the application and connection used. Connections may have different sizes to ensure compatibility with different tube combinations of outside and inside diameters. For instance, there are several sizes of VAM® Express connections, such as VAM® Express VX39 and VAM® Express VX40 which are compatible with different tubes combinations of outside diameters and inside diameters.
The drill pipe main section and tool joints are manufactured separately. Tool joints are forged then welded onto the main section using friction welding. Upsets are required to be forged on the main section to achieve a thickness which ensures the same strength between the tube and the weld zone. A minimum upset outer diameter (OD) is thus based on the yield strength of the weld, such that the total tensile strength of the weld zone is at least greater than the total tensile strength of the tube body. A maximum upset OD is determined such that the upset zone is compatible with handling equipment.
In an exemplary embodiment of the present invention the drill pipe length may be Range 2 or Range 3, corresponding to 31.5 feet nominal length or 45 feet nominal length, respectively.
In an exemplary embodiment of the present invention an acceptable range for tube wall thickness is 0.26-0.43″.
In an exemplary embodiment of the present invention the outer diameter of the pipe main section is greater than 4″ and smaller than 4½″, while the inner diameter of the pipe central section is between 3.826″ to 3.240″.
In an exemplary embodiment of the present invention the outer diameter of the upsets is greater than or equal to the tube main section OD, and is smaller than the tool joint OD. Thus, the outer diameter of the upsets (1b) is greater than 4″ and smaller than 5″.
In an exemplary embodiment of the present invention for a drill pipe element with a main section outer diameter such that 4″<OD<4½″, the ratio R of the outer diameter of the central section of the main portion (1a) to the outer diameter of the upsets of the main portion (1b) is such that 0.9<=R<=0.99.
In a preferred embodiment the tube main section wall thickness is 0.330″, based on market needs.
In a preferred embodiment which uses a double shoulder connection such as a VAM® Express VX 39 connection the outer diameter of the tool joints is 4⅞″ and the inner diameter of the tool joints is 3″. In a preferred embodiment which uses a double shoulder connection such as a VAM® Express VX 40 connection the outer diameter of the tool joints is 5¼″ and the inner diameter of the tool joints is 3″.
It is beneficial to increase equipment flow limits since this provides better drilling efficiency, and better hole cleaning efficiency. Referring to
However, referring to
Data presented in
In a preferred embodiment, the outer diameter of the central section is 4¼″ with a central section inner diameter of 3.590″.
In a preferred embodiment, the outer diameter of the upsets is 4½″ with an upset inner diameter the same as the tool joint inner diameter.
In a preferred embodiment R=0.944 to within standard engineering tolerances in the field, which corresponds to the preferred 4¼″ main section tube OD and a 4½″ main section upset OD.
In a preferred embodiment, the drill pipe provides the tensile capacity to safely perform drilling and tripping operations. In a preferred embodiment the drill pipe is manufactured with S-135 grade steel (with a yield strength of 135 ksi), as determined by tensile load requirements.
To improve pipe resistance to buckling, an increase in stiffness can be obtained by increasing the pipe OD. By increasing the shale drill pipe OD from 4″ to 4¼″ the pipe stiffness increases and the SDP can handle up to 18% more weight on bit (WOB) than a standard 4″ pipe, without buckling during rotary drilling operations. A higher WOB yields a greater rate of penetration, and overall more efficient drilling operations. When tripping or drilling, buckling is likely to occur as a result of compressive axial loading, which can further increase torque and drag. Buckled pipe may create a lock up in severe cases, thus making it very difficult to transfer mechanical energy to the drill bit. While increasing pipe OD is beneficial for buckling and wear, increasing pipe ID is also beneficial to increase the flow rate, reduce hydraulic pressure losses, and increase hole cleaning and drilling efficiency. For each hole size there is a drill pipe size that gives the lowest hydraulic pressure loss. For a 6¾″ hole size with an exemplary embodiment of the shale drill pipe described herein, using a 4¼″ OD and a central section ID of 3.590″ a 150 psi improvement in stand pipe pressure is obtained, with a 12.5% increase in flow rate, compared to a currently used 4″ OD pipe, with standpipe pressure defined as the sum of all pressure drops throughout the drill string and between the drill string and the hole. Drill pipe elements with larger inner diameters yield smaller hydraulic pressure losses. Although increasing tool joint ID would have some effect on the pressure loss, the overall benefit is insignificant and hard to quantify.
Despite changes in OD and ID for a given production size hole, all holes must be cleaned to the same standard, which requires optimizing drill pipe design such that cleaning flow rate is at least as large as required to meet the standard.
For a given flow rate, a drill pipe with a larger OD will be more efficient with respect to hole cleaning, since the annular velocity of fluids traveling uphole between the drill pipe and the bore hole wall will increase. The increase in annular velocity improves cleaning efficiency by up to 20% in terms of number of bottoms up and time to clean the well (a bottom up is achieved when materials from the bottom of the drill hole reach the surface) as well as circulating hours for each bottom up, such that the desired level of cleaning is reached. Mathematical modeling shows the number of bottoms up decreases from 6.3 to 5.4 to clean a hole, and circulating hours decrease from 6.7-10 hrs to 5.8-8 hrs, depending on flow rates. Flow rates can be selected to obtain a constant annular velocity and the same level of hole cleaning for all holes, without pushing the equivalent circulating density beyond safe working limits.
Referring to
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In an exemplary embodiment, a central section of the drill pipe main portion has special metal thermal spray metallic coating wearbands, such as WearSox—trade mark of WearSox, which are more resistant to friction wear than the pipe body material. In a preferred embodiment, WearSox is applied over an area 8 feet in length located at the pipe mid-section, with a 1/16″ to ⅛″ thickness. Use of such a central wearband can increase tube service life by 200% or more in typical shale formations.
In an exemplary embodiment, hardbanding is used on the tool joints. In contrast with hardbanding on the pipe midsection, tool joint hardbanding is a hot welding process which protects casing and tool joint from wear. Standard hardbanding for tool joints is typically 3″ long and can be applied to the tool joint OD or in a groove. In an exemplary embodiment at least one tool joint has a hardbanding section with an outer diameter greater than or equal to an outer diameter of a tool joint by 3/16″.
In another embodiment, an internal plastic coating (IPC) is applied on the drill pipe interior to protect against corrosion, pitting, and corrosion fatigue. IPC can improve hydraulic efficiency. IPC may be liquid, solid, or an epoxy.
Because many possible embodiments may be made of the invention without departing from the scope thereof, it is to be understood that all matter herein set forth or shown in the accompanying drawings is to be interpreted as illustrative and not in a limiting sense.
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Number | Date | Country | |
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20140209394 A1 | Jul 2014 | US |