Showing papers in "Spe Drilling & Completion in 2008"

Tubing Buckling--The State of the Art

Abstract: Almost unique in engineering analysis is the problem of tubing buckling in wellbores. In general, structures loaded above their critical load fail catastrophically. Yet, both tubing and drillstrings are commonly operated above the critical load. These tubing strings do not fail because the wellbore provides the necessary support for “post-buckling” equilibrium. The two fundamental questions about tubing buckling are • What is the critical load? • What is the post-buckled configuration? The critical load tells us if the tubing will buckle. Euler solved the problem for “short” columns, but these results rarely have application in a wellbore because the pipes in a wellbore are usually very long (Timoshenko and Gere 1961). The first stability criterion that considered the stabilizing effect of weight on long pipes in inclined wellbores was developed by Dawson and Paslay (1984). The post-buckled configuration tells us about tubing movement, bending stresses, contact forces, and axial-load distributions. The original buckling analysis by Lubinski et al. (1962) proposed a helical configuration in a vertical wellbore and used the method of virtual work to determine a specific constant pitch for that helix as a function of the axial force and bending stiffness. These two works set the following themes for further analysis of tubing buckling: • What is the critical buckling load in curved, 3D wellbores? • How does torque affect the critical buckling load? • How do tapered strings affect the critical buckling load? • What is the buckling configuration in inclined wellbores? • How do the boundary conditions affect the configuration? • How do tapered strings buckle? • How does torque affect the buckling configuration? • What effect does friction play in tubing buckling? Many of these questions have been, at least, partly answered in the past three decades. This paper will examine the technical fundamentals of the tubing-buckling problem; summarize the most useful, new results from these papers, and discuss the remaining challenges in tubing-buckling analysis.

State-of-the-Art in Coalbed Methane Drilling Fluids

Abstract: The production of methane from wet coalbeds is often associated with the production of significant amounts of water. While producing water is necessary to desorb the methane from the coal, the damage from the drilling fluids used is difficult to assess, because the gas production follows weeks to months after the well is drilled. Commonly asked questions include the following: What are the important parameters for drilling an organic reservoir rock that is both the source and the trap for the methane? Has the drilling fluid affected the gas production? Are the cleats plugged? Does the 'filtercake' have an impact on the flow of water and gas? Are stimulation techniques compatible with the drilling fluids used? This paper describes the development of a unique drilling fluid to drill coalbed methane wells with a special emphasis on horizontal applications. The fluid design incorporates products to match the delicate surface chemistry on the coal, a matting system to provide both borehole stability and minimize fluid losses to the cleats, and a breaker method of removing the matting system once drilling is completed. This paper also discusses how coal geology impacts drilling planning, drilling practices, the choice of drilling fluid, and completion/stimulation techniquesmore » for Upper Cretaceous Mannville-type coals drilled within the Western Canadian Sedimentary Basin. A focus on horizontal coalbed methane (CBM) wells is presented. Field results from three horizontal wells are discussed, two of which were drilled with the new drilling fluid system. The wells demonstrated exceptional stability in coal for lengths to 1000 m, controlled drilling rates and ease of running slotted liners. Methods for, and results of, placing the breaker in the horizontal wells are covered in depth.« less

Wellbore-Stability Study for the SAFOD Borehole Through the San Andreas Fault

Abstract: This paper presents a wellbore-stability study of the San Andreas Fault Observatory at Depth (SAFOD) research borehole located near Parkfield, California, USA. In the summer of 2005, the SAFOD borehole was drilled successfully through the active trace of the San Andreas Fault (SAF) in an area characterized by fault creep and frequent microearthquakes. In this study, we report how the analysis of wellbore failures in the upper part of the hole, geophysical logs, and a model for stress gradients in the vicinity of the fault were used to estimate the mud weights required to drill through the fault successfully. Because logging-while-drilling (LWD) acoustic caliper data and real-time hole-volume calculations both showed that relatively little failure occurred while drilling through the SAF, the predicted mud weight was successful in drilling a stable borehole. However, a six-arm caliper log, run after drilling was completed, indicates that there was deterioration of the borehole with time, which appears to be caused by fluid penetration around the borehole. The LWD-resistivity measurements show that essentially no fluid penetration occurred as the hole was being drilled. Because of this, the mud weight used was capable of maintaining a stable wellbore. However, the resistivity data obtained after drilling show appreciable fluid penetration with time, thus negating the effectiveness of the mud weight and leading to time-dependent wellbore failure. Using finite-element modeling (FEM), we show that mud penetration into the fractured medium around the borehole causes failure with time.

Polymer Reduction Leads to Increased Success: A Comparative Study

Abstract: Recent advances in guar and crosslinker technologies have resulted in the development of high-viscosity crosslinked borate-fracturing fluids without increasing polymer loadings. These low polymer (LP) borate fracturing fluids are being used successfully in various formations previously believed to be too hot and or too deep for LP fracturing fluids. Historically, polymer loadings of 3.6 to 4.2 kg/m3 (30 to 35 lbm/1,000 gal) were commonly pumped in the Western Canadian Sedimentary basin (WCSB) for formations deeper than 2500 m and bottomhole temperatures greater than 80°C. These same formations are now fracture stimulated using the LP fluids with loadings as low as 1.8 kg/m3 (15 lbm/1,000 gal) with exceptional results. This paper demonstrates that LP fracture fluids can be used in place of fluids requiring higher polymer loadings with minimal changes to the overall design of the fracture treatment. The new fluid can be pumped on-the-fly at conventional pump rates and proppant concentrations because of the fluid’s improved shear and temperature stability. The advantages of using a reduced-polymer fracturing fluid include increased production, lower treatment costs, and lower frictional pressure loss. This paper illustrates these advantages as it compares the LP fracture fluid with HP fracture fluids in more than 200 wells in the WCSB. The formations where LP fluids were used have depths of up to 3250 m and reservoir temperatures reaching over 100°C. To order the full paper, visit http://www.onepetro.org/mslib/servlet/onepetropreview?id=SPE-100467-PA