When drill string in a gradual dog leg is subjected to either tensile or compressive axial loads, the maximum curvature of the drill pipe body exceeds that of the hole axis curvature. Lubinski recognized this fact and published an analysis in 1961 for the tensile case. His results are given in the API RP7G manual. Contemporary technology uses compressive axial loads in some extended reach and horizontal drilling applications. In addition, when casing is set, it is common to have the casing in a dog leg under compression. An analysis for compressive loads, analogous to Lubinski's analysis, is required to evaluate the bending stresses in these situations accurately. This work presents the analytical solution for maximum drill pipe curvature when an axial compressive load, in the practical range, is applied to the drill string. Similar to the tensile case, contact (point and wrap) between the drill pipe and the hole wall as well as tool joint contact load must be taken into account. Dimensionless curves are presented for bending stress calculation for both tensile and compressive axial loads. The curves allow easy evaluation of the bending stress magnification (BSM). The results show it is important to take the bending stress and the BSM into account in practical design particularly because of coupling with axial tension and compression loads. The results given in this paper complement calculations based on torque and drag models of drill strings. The results also complement and build on the earlier work of Lubinski. The results are extended to burst and collapse analysis in casing and to fatigue analysis in drill pipe. The important influences of BSM are made clear in design curves for these applications.
Depletion of unconsolidated sand reservoirs can cause compaction of the reservoir sand. This strain transfers load to the casing. and this can kink and crush the casing, preventing workovers and requiring redrilling wells (Figure 1). Early redrilling can have significant negative impact on project earning power, so it is necessary to design casing to withstand compaction loading. This paper explains Shell Oil's new compaction design philosophy for casing to be run in some highly compactive Gulf of Mexico reservoirs. The paper explains the technical tools used to quantify compaction loading; the relative importance of different casing damage mechanisms; and Shell's approach to designing casing to mitigate the influence of compaction. Shell's approach to compaction emphasizes minimizing column buckling under axial compaction loads and collapse under transverse compaction loads. The approach to buckling is based on a model that quantifies the ability to work through buckled casing. The approach to collapse is based on a model linking depletion to the load transferred between the sand, cement, and casing. The compaction solution is specialized to Gulf of Mexico sand and reservoir characteristics. Casing design is only one aspect of the multidisciplinary solution to the compaction problem. Compaction-tolerant sand control must be included in the completion design, and advanced core testing must be used to link the casing design to the stress-strain behavior of unconsolidated sands. Where historical damage exists, downhole casing logging has been used to guide and validate the solution. These other facets of compaction technology go beyond the scope of this paper but have been addressed by Shell Oil's integrated approach to the compaction problem. Introduction to the Compaction Problem Depletion of the reservoir pressure increases the effective stress acting on the reservoir sand. For an unconsolidated sand, the increase in stress causes large compaction strain (several percent). This strain in the sand can cause corresponding severe deformation in the casing (Figure 1). The deformation does not breach the casing, but it prevents workovers and recompletions through the casing and requires costly redrilling of the well. For deep offshore wells, early casing damage at relatively low compaction strain can significantly decrease project earning power, so there is incentive to take early design steps to mitigate compaction-driven casing damage. The solution to this problem is to design casing, cement support, and sand control that are compaction resistant to a reasonable and practical degree. Doing this requires quantitative understanding of the damage mechanisms and the way that a specific amount of depletion strains the sand and deforms the casing. The solution also requires quantitative understanding of the parameters that affect the ability of the casing to resist compaction loading. Blind overdesign of the casing is not a viable solution. Overdesign is ineffective if a critical damage mechanism is overlooked. Overdesign also can have unacceptable economic cost (how much collapse strength is enough?) and unacceptable increased risk to the completion design, the well inflow, or the clearances between tight strings run inside one another. In order to develop a guideline for design of casing in compacting reservoirs, Shell used a combination of finite element analysis and analytical modeling to quantify and rank damage mechanisms as functions of depletion, sand compaction tendency. cement placement, well angle, and casing D/T ratio and grade. Compaction is not new, and much work has been done on this topic. Much work has dealt with shallow reservoirs where compaction leads to surface subsidence. This is an ancient problem (e.g., aquifer depletion). and References 2–11 are only a few examples of work in this area. P. 731
TX 75083-3836, U.S.A., fax 01-972-952-9435.z` AbstractThe oil and gas industry is heading toward development of Extreme-HPHT wells which can expose low alloy, carbon steel production casing to shut-in pressures over 18,000 psi, 50-450°F changing temperatures, and a sour environment containing H 2 S, CO 2 , and water. These conditions represent a step increase in the severity of the service conditions acting on well casing. The completion of such wells requires a new, comprehensive understanding of the relationship between three dimensional service stresses (caused by load and pressure) and the capability of the pipe material to resist crack initiation. This step in understanding is aided by an evolution from the one-dimensional, pass/fail, NACE-A tensile test to an environmental test of a hollow pipe specimen loaded with a three dimensional stress state. The same type of test is able to calibrate the accuracy of a formula for pipe performance based on fracture propagation in a sour environment. This paper reports development of a compact (less than 2 ft x 1 ft), inexpensive test frame and hollow specimen geometry to address this testing need; and the paper reports initial results from such testing. Combined-load testing specimens in this frame provides a means to quantitatively determine the way that principal stresses in the well combine to cause (1) crack initiation and (2) crack propagation in low alloy carbon steel pipe in a sour environment. The testing is able to simulate the pipe combined loading which can occur in the well.Part I of the paper explains the key features for the new test frame and specimens. The paper is intended to help enable the reader to build similar frames and specimens. The frame is able to passively apply axial tension or compression combined with internal pressure; internal H 2 S environment; and/or external H 2 S environment. The low cost and passive mechanism enable several frames to be run at the same time. The mini-pipe specimens are cut from the wall of coupling stock or heavy walled casing. The paper explains the specimen geometry, threading, end caps, H 2 S containment, and surface finish; the methodology for controlling loading of the coupon; and the low stiffness designed into the frame Part II of the paper provides preliminary results of seventeen tests with combinations of tension, compression, and internal pressure; and internal/external H 2 S exposure. Additional tests are planned for 2005. The tests are intended to determine a critical combination of combined axial-pressure loading stresses, H 2 S corrosion exposure, and pipe material toughness which leads to crack initiation and failure in pressurized pipes. The role of the initiation failure formula is shown to be separate from a different formula for pipe failure due to crack propagation.
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