The analysis described here, based on Santa Barbara Channel field experience, shows that increasing water depth reduces the overburden stress gradient, substantially influencing the apparent fracture gradient, particularly at shallow penetrations. Two methods of correlating fracture particularly at shallow penetrations. Two methods of correlating fracture gradient are presented in the analysis. Introduction The consideration of formation fracture gradients in selecting casing setting depths is fundamental to the preparation of an acceptable drilling program. When preparation of an acceptable drilling program. When Exxon Co. U.S.A. undertook the deepwater challenges of the Santa Barbara Channel, a project was initiated to develop a fracture-gradient prediction technique that would assess the impact of water depth. Development of the Technique Onshore Fracture Gradients As frequently referenced, Hubbert and Willis, established a theoretical basis for subsequent work in the development of actual fracture-gradient prediction techniques. Later theoretical studies of porous bodies have concluded that the most important factors affecting fracture initiation pressure are the overburden stress, the formation fluid pressure, and the horizontal-to-vertical stress ratio, whereas rock compressibilities and Poisson's ratio have relatively little influence. Matthews and Kelly, in a technique presented in 1967, correctly indicated that the stress ratio, F sigma, was the most significant and yet elusive variable. The following relation was presented for the fracture gradient: ..........................................(1) By assuming a total overburden gradient of 1.0 psi/ ft, we can estimate the effective vertical stress as follows: ..........................................(2) For normally pressured formations, the stress ratio, F sigma, is empirically correlated, on the basis of field data, for a given area as a function of depth. The onshore aspect of the technique that was developed for the Santa Barbara Channel area incorporates these stress-ratio concepts with a method to estimate the actual overburden gradient rather than using the assumed value of 1.0 psi/ft. Since the overburden stress at any depth should be the cumulative weight of the formations above that depth, well data that are indicative of formation density can be used to estimate overburden. Techniques have been published that are based on velocity data from seismic published that are based on velocity data from seismic surveys and sonic logs or that utilize formation bulk density logs directly. We selected the latter method and estimated overburden with Eq. 3: ..........................................(3) where 0.4335 is the constant used to convert units of gm/cc to psi/ft. In practice, of course, a simple arithmetic average of the bulk densities of the overlaying formations, pb, will suffice: ..........................................(4) The final form of the fracture-gradient prediction formula used in the Channel is given as Eq. 5: ..........................................(5) JPT P. 910
A mathematical model of a buttress-threaded connection was developed to compute the strain limit of casing. The model results are compared with full-scale test results and predictions are made of the casing strain when the connection fails for various conditions of temperature, pressure, and connection assembly. Introduction Usually, well casing is designed so that the applied axial forces are not sufficient to cause yielding. However, for limited strain problems it is possible to load certain casing types beyond the yield point without causing a failure. Two examples of limited strain problems are soil subsidence and thermal expansion and contraction. For these types of problems, a displacement load is imposed and the stress is determined by the material properties. Permafrost soil subsidence caused by thawing induces a displacement-type load. To design for such loads, Atlantic Richfield Co. and Exxon Co., U.S.A.. have performed tests and calculations to determine the strain limit performed tests and calculations to determine the strain limit of 13 3/8-in., 72-lb/ft, N-80 buttress casing, which is used as surface casing in many Prudhoe Bay wells. Although full-scale casing connection tests have been conducted, the experimental measurements provide information for only a few special loading conditions. To investigate the effects of changes in loads, geometry, or material properties, the ability to calculate stresses and strains in the casing connection is needed. A computer model has been developed to perform a stress analysis of the threaded connection. Test data and model calculations establish the criteria for strain limit design of a 13 3/8-in., N-80 buttress casing. Model Description The problem of concern is diagrammed in Fig. 1. Since the geometry and loading are axisymmetric, an axial cross-section of the pipe may be analyzed as a twodimensional problem, with circumferential effects accounted for in the calculations. Moreover, a plane of symmetry exists at the center line of the collar. Therefore, it is possible to hold the center-line position rigid and apply the axial deflection across the end of the pipe section. pipe section.The mathematical model used to perform the stress analysis of the threaded connection was developed by Prototype Development Associates. The computer code Prototype Development Associates. The computer code uses the finite-element method to calculate stresses and strains for a given load system. Several features made the code adaptable to a threaded connection analysis. Mechanical properties may be approximated by a bilinear constitutive relation that accounts for yielding in the threads during deformation. The particular stress-strain relation selected for calculation is described in another section. Another nonlinearity is introduced by modeling the interface between mating teeth. This surface is capable of carrying a considerable compressive load, but the thread surfaces must separate without resistance under a tensile load. A special interfice element accounts for this nonlinearity and allows for resistance to shear motion, which is used to approximate frictional resistance to radial thread separation. This friction is most important near a failure condition where deformation is significant. The effects of connection assembly loads are modeled by specification of initial displacements that describe the appropriate interference fit between pipe and coupling. For the 13 3/8-in. buttress-connection analysis, approximately 2,000 finite elements and 2,200 nodes are used. JPT P. 355
American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc. Abstract A technique is developed to analyze the buckling stability of multiple, concentric pipes If the system is unstable and buckles against a lateral support such as an irregular open hole, an estimate is made of the elastic stresses and pipe curvature. Example applications are pipe curvature. Example applications are presented in offshore platform wells, in floating presented in offshore platform wells, in floating drilling, and for partially cemented surface casings. Introduction In the design of oil and gas wells, it is often necessary to consider the stability (tendency to buckle) of casing and tubing. Previous literature has shown methods to Previous literature has shown methods to determine the stability of a single pipe under complex loadings, and methods are available to determine the resulting geometry and stresses of a pipe which has elastically buckled into a helix inside of a uniform outer pipe. The technique in this paper describes the behavior of a system of concentric pipes. It further provides an approximate calculation methods of the system geometry after helical buckling has occurred against a lateral restraint of non-uniform diameter. Three example applications of the concepts are given:The effect of drill pipe tension on the stability of a marine riser in floating drilling,the required spacing of lateral supports for oil-well conductors on an offshore platform, andbuckling of an oil-well casing nest against a partially uncemented open hole. Stability of Concentric Pipes The following derivation shows how the tensions and compressions of the individual pipes contribute to the overall stability of a multiple pipe system. Specifically, the stability load pipe system. Specifically, the stability load of the system is shown to be the arithemetic sum of the individual loads (Eq.1), and the total system stiffness is the sum of the individual moments of inertia (eq. 2).
A compact five-spot well pattern was completed through permafrost at Prudhoe Bay and circulated with hot fluid, creating thaw zones. Compaction Prudhoe Bay and circulated with hot fluid, creating thaw zones. Compaction and deformation of soil in these zones led to casing strain. Analysis determined that casing strains were caused by large differences in compactibility of soil types. Introduction The development of petroleum reserves in the arctic region of Alaska requires new petroleum engineering technology to deal with permafrost problems. A conventional well drilled through permafrost is subjected to the hazards of external freezeback pressures, internal freezeback pressures, and thaw consolidation (compaction). These three major concerns have been studied extensively by operators in the Alaskan arctic. Solutions to the problems associated with the freezeback of shut-in wells have been published in the past four years. Thawing of permafrost around a wellbore also can lead to casing damage. When ice melts, it is reduced approximately 9 percent in volume. Stresses carried through the ice phase of in-situ permafrost tend to transfer to the soil matrix as the ice melts and the pore pressure diminishes because of this reduction. The soil tends to compact when subjected to a higher stress level. The degree of compaction depends on the type of soil, the stress state in the frozen permafrost, the pore pressure after thaw, and the size of the thawed region. Although most compaction is accounted for by lateral movement of the surrounding frozen permafrost, some vertical consolidation or subsidence also can be expected. This vertical consolidation or movement can damage the casing strings throughout the permafrost section. The original field rules for Prudhoe Bay development required that a producing well be protected from subsidence damage by refrigeration, insulation, or other means. To understand thaw consolidation in the thick permafrost at Prudhoe Bay, BP Alaska Inc. conducted a permafrost at Prudhoe Bay, BP Alaska Inc. conducted a field test to thaw a limited region surrounding a well. The amount of thaw in this field test was equivalent to that created around a heavily insulated producing well. Both casing strain and formation movement were detected with a moderate degree of uncertainty in the field data. One solution to the internal freezeback problem is to replace water-base mud with a gelled, weighted oil-base fluid. The thermal-insulating properties of this fluid are quite good. However, a producing well insulated in this manner would develop a larger thaw radius during its operating life than was created in the BP Alaska field test. Petroleum engineers designing casing programs for field Petroleum engineers designing casing programs for field development were uncertain of the effect of this large thaw zone on casing integrity in a producing well. To assess the significance of the consolidation process for a gelled-oil-insulated completion, a major field test at Prudhoe Bay was conducted. The test site was located in Prudhoe Bay was conducted. The test site was located in Section 11, T10N, R15E, in the center of the Prudhoe Bay field and adjacent to a BP Alaska well where numerous cores were taken in the permafrost. Core analysis provided a complete lithology of the permafrost. The provided a complete lithology of the permafrost. The goal of the field test was to observe casing integrity and to measure the strain of a casing string surrounded by a thaw zone equivalent in size to a zone created by a well after 20 year's production. This paper describes the field test, operational aspects, and results. JPT P. 468
Introduction In typical oilfield casing design work, engineers specify the force that a casing must withstand. For example, it is generally necessary for each section of a casing string to support the weight of all the pipe that is suspended below. The force and stress are known quantities, and the resulting pipe deformation, called strain, can be calculated using the physical properties of the casing steel. However, there are situations where the casing loading is of a displacement type, for which the deformation is specified. In this case, the stress is unknown. An example is surface casing subjected to soil subsidence. In soil subsidence, the compacting soils will tend to strain the adjacent casing, and the amount of resulting pipe strain can be essentially independent of the casing properties. As a part of the Prudhoe Bay permafrost-thaw subsidence studies, Exxon Co., U.S.A., and Atlantic Richfield Co. conducted a testing program to determine the amount of casing strain that would cause failure. The casing tested, 13 3/8-in., N-80, 72-lb/ft buttress, is used as surface casing in many Prudhoe wells. Testing Procedure Three tension tests and three compression tests were made with strain gauges installed as shown in Fig. 1. The compression specimens were of relatively short length (2 1/2 ft) to prevent Euler buckling. (Actual surface casing will not column buckle if it is laterally supported by cement and the formation.) The tension specimens used welded end fixtures to provide a means of attachment to the test machine. The casing tested was 13 3/8-in.-OD, controlled yield N-80 (normalized), 72-lb/ft buttress, selected from mill runs for Prudhoe Bay. Both mill- and field-end connections were constructed by the torque-turn method, which specifies both minimum turns and minimum torque required for a satisfactory connection. Mill ends were made at the mill with an epoxy thread-lock compound, while the field ends used a teflon thread compound. Based on metallurgical test coupons, the API yield strength (0.5-percent strain) of this casing ranged from 83 to 92 ksi. The ultimate strengths ranged from 110 to 122 ksi and occurred at strains of 12 to 16 percent. Elongation (maximum strain) was 25 to 35 percent, indicating good ductility. The post-yield behavior was uniform, with plastic moduli of 550,000 to 850,000 psi. Wall plastic moduli of 550,000 to 850,000 psi. Wall thicknesses were uniform, and averaged 0.495 in. (API minimum/nominal is 0.450/0.512 in.2) The samples were tested at the U. of California Field Research Facility at Richmond. Load increments of 50,000 to 200,000 lb were spaced 5 to 30 minutes apart. Tension Test Results Fig. 2 shows the tension axial-strain readings for the D locations, which are located on the pipe 7 in. from the buttress collar. There were three tests, and the mill-end and the field-end gauges provided six sets of data. Test 1 was terminated without failing the casing at a load of 2,250,000 lb and with pipe strains of 3.6 percent (mill end) and 3.7 percent (field end). Tests 2 and 3 experienced fractures near the last perfect thread of the mill end at loads of 2,350,000 and 2,250,000 lb, respectively. The mill-end strains were 3.6 to 4.2 percent. Fig. 3 shows a comparison of strain data taken at various locations on the casing. JPT P. 1301
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