Hoover-Diana is a deepwater Gulf of Mexico oil and gas development. The reservoir development plan is a hybrid drilling and completion program encompassing remote subsea wells (Diana) connected by flowlines to a host DDCV (deep draft caisson vessel) and platform-type wells (Hoover) on the DDCV with surface trees connected to the seafloor by production risers.The Diana subsea wells were batch drilled with a dynamically-positioned drillship and then completed with a new-build, moored semisubmersible. These subsea wells were designed as horizontal open-hole gravel packs to deplete a relatively thin oil rim that lies between an aquifer and a large gas cap. The horizontal sections of each well were drilled and completed with the subsea tree in place, and all wells were flowed back to the drilling rig for clean-up and hydrate prevention prior to installation of the DDCV and flowlines. At the time, these were the deepest water-depth horizontal wells in the world. Numerous challenges were encountered in the design and construction of these wells, including the scheduling aspects associated with the two deepwater drilling rigs and pipeline installation vessels.The Hoover drilling program required significant upgrades of an existing API-type platform rig combined with unique modifications to accommodate DDCV motions and riser systems. The Hoover drilling and completion program is a mixture of cased-hole frac pack wells and open-hole, horizontal gravel pack wells. Furthermore, it marks the first time a drilling rig would set subsea wellheads from a caisson vessel and perform all of the drilling and completion operations including the riserless operations.
Summary. Thaw subsidence during the production life of wells drilled through the permafrost can transfer very high axial compressive loads to the surface casing. Improved techniques were required to define the compressive strain capacity of surface casing for North Slope operations. These techniques were used to identify cost-effective surface-casing designs capable of withstanding the axial compressive strains imposed by permafrost thaw. Plans to drill North Slope development wells on closer surface spacing resulted in predicted permafrost thaw loads on the surface casing that exceed current operating practices. In addition, development of lower-productivity wells has resulted in completions with smaller-diameter tubulars. Both of these considerations have led to a reassessment of the surface-casing programs for these new wells. The results presented are based on two parallel and complementary investigations: full-scale physical testing and nonlinear finite- clement analysis. The physical tests provided information about the performance of the casing and connections under high compressive loads. Data were used to verify the accuracy of corresponding finite-element models with three different criteria: strain-gauge data from the coupling and pin surfaces, failure mode comparison, and failure load comparison. An excellent match was achieved between the strain-gauge data and the analytical strain results, the actual vs. modeled failure mode (i.e., compressive bulging in the pipe body), and the actual vs. modeled failure load. Once verified, the models were used to investigate the effects of field-related parameters that were not tested. These included variations in makeup condition, pipe-wall thickness, thread taper angle, and casing length. Finally, these results enabled the selection of suitable surface-casing materials and connections for arctic operations. Introduction Surface casing is set through the permafrost for Alaskan North Slope wells (as deep as 2,000 ft [610 m] in some areas) to establish an adequate "foundation" for the wellhead and tree assembly, to provide backup pressure containment, and to isolate the inner strings from permafrost loads. Permafrost thawing caused by the long-term production of high-rate oil wells can lead to pore-pressure reduction, resulting in sediment compaction. The magnitude of strain that these effects induce on the surface casing depends on several factors, including the mechanical properties and lithology of the permafrost and the proximity of nearby wellbores that contribute to the overall thaw area. The incentives to reduce the wellhead spacings of arctic wells include limiting gravel requirements for both offshore islands and onshore well pads on the tundra and reducing the length of pipe- line required to manifold the wells. Proposed wellhead spacings (as close as 15 ft [4.6 m] for offshore islands) were expected to produce higher soil strains than those predicted for original Prudhoe Bay wells spaced roughly 120 ft [37 m] apart. Therefore, a full performance study was conducted to quantify the axial strain limits of 13 3/8-in. [34-cm] -diameter, 72-lbm/ft [107-kg/m], L-80 butress-threaded casing (common surface casing in North Slope use). The performance was compared with that predicted for normalized N-80 grade casing used on some early Prudhoe Bay wells. Description of Analysis Methods The casing performance was analyzed with the finite-element method and verified by well-instrumented, full-scale testing. Non- linear finite-element analysis techniques have been developed for the analysis of threaded connections with a development version of the ABAQUS general-purpose finite-element program. Additionally, processing hardware and software were used to allow efficient analysis of large finite-element models on the Cray X/MP supercomputer. This processing and analysis system allows efficient and accurate creation of large finite-element models and aids greatly in the interpretation of the results. Finite-Element-Model Generation. Three initial assumptions used in creating the models wereaxisymmetry,symmetry about the plane through the center of the coupling, anddisplacement-controlled axial loading at the ends only. The two symmetry assumptions greatly reduce the size of the model and the associated computing cost. The third assumption allows no shear loading on the outside of the casing, only displacement-controlled end loading. This loading constraint corresponded to the physical test con-ditions. Permafrost thaw subsidence causes displacement-controlle loading on the casing in the field, although the loading is applied by shear forces on the outside of the casing. Several finite-element meshes were created and tested during the course of the casing analysis. First, test meshes were developed for the buttress threadform itself. Next, test meshes were developed for the pipe and coupling walls. For a given model, or model subset, a finer mesh with smaller elements will give a more accurate solution. Computer costs associated with a given model increase approximately with the square of the number of elements in the model. The final finite-element mesh selection is a tradeoff between cost and accuracy that was resolved by examining strain jump and radial stress contour plots and considering the need to retain fidelity in the threadform geometry. A typical finite-element mesh for the buttress connection is shown in Fig. 1. This mesh contains about 4,500 nodes and 2,500 quadrilateral constitutive elements (both second-order, reduced-integration and first-order, full-integration). Nonlinear Analysis Techniques. Three major areas of nonlinear behavior must be modeled accurately to analyze the performance of the casing with buttress-threaded connections:material properties,deformation geometry, andsurface interaction between the pipe and coupling in the thread region. These nonlinearities must be handled with an iterative solution procedure. For a solution to satisfy the convergence criterion. equilibrium must be satisfied within a specified tolerance at every degree of freedom. To model the history dependence of the final solution accurately, equilibrium convergence must be achieved for each incremental solution during loading. This process required more than 500 iterations for each model. SPEDE P. 289^
Summary This paper discusses methods and test procedures for conducting field evaluations to determine the effectiveness of oilfield tubular-inspection equipment and personnel. Specific requirements and equations are proposed for qualifying magnetic particle, ultrasonic, eddy current, radiographic, optical, and mechanical nondestructive test equipment. The design and use of pip standards to check automated pipe-inspection systems are also described. By incorporation of the methods pipe-inspection systems are also described. By incorporation of the methods developed in this paper, nondestructive inspection services can be qualified with respect to the pipe diameter, weight, grade, or critical application of the tubular. Introduction In drilling for oil and gas, we are encountering ever-increasing challenges in the form of more hostile environments. Higher pressures. greater temperatures, corrosive gases, and deeper, deviated wellbores present new problems. Because of these challenges, the quality of problems. Because of these challenges, the quality of tubulars that are used to complete the well becomes even more critical. The oil industry currently ensures the quality of new tubulars placed downhole through nondestructive inspections conducted in the field or at the pipeyard. The inspection equipment typically is designed to locate seams, laps, pill, slugs and thin-wall areas that result from the manufacturing process, as well as mechanical damage from handling. Oilfield tubulars are one of the most important factors that affect the production and safety of any oil or gas well. In particular, tubing and casing are subjected to high tension loads from the weight of the string, burst loads from internal production pressures, collapse loads from external formation pressures, bending loads from wellbore deviations, and other severe conditions, such as sour-gas environments. And finally, these tubulars may remain in production for as long as 20 years with corrosion taking production for as long as 20 years with corrosion taking its toll. The majority of today's oilfield tubulars are made of carbon or alloy steels and are manufactured by the seamless piercing and rolling process. The cost of these tubulars often represents 20 to 40% of the drilling program cost. but the cost of a tubular failure can be even more dramatic. Pipeyard inspection reports for new tubing and casing indicate that about 20% of domestic tubulars are rejected when held to API specifications. Therefore, the pipeyard inspection is critical in maintaining the quality pipeyard inspection is critical in maintaining the quality of the wellbore. Service companies provide tubular inspections for most oil companies. The quality of these inspections varies significantly from region to region. One of the principal reasons for this variation is a lack of specifications for the nondestructive testing (NDT) of oilfield tubulars. Once a specification has been established, the next step is to evaluate and to qualify the inspection company during field evaluations in that region. Existing NDT specifications, such as the American Soc. of Nondestructive Testing (ASNT), the American Soc. for Testing and Materials (ASTM), or API Specifications, are neither detailed enough nor directed specifically enough to the oil field to allow the inspection equipment to be evaluated and qualified to a particular level. The final step in among quality inspections is through adequate supervision and periodic audits of equipment and personnel. periodic audits of equipment and personnel. This paper addresses the specific performance levels for NDT equipment and personnel for oilfield tubular inspections. The requirements developed at Exxon Production Research Co. involve theoretical calculations, review Production Research Co. involve theoretical calculations, review of the existing inspection methodology, and experimental testing in electromagnetics, ultrasonics, and radiography. Then these requirements were incorporated into a procedure for conducting field evaluations to determine and to maintain the quality of oilfield tubular inspections. Field Evaluations of Oilfield Inspection Operations Field evaluations of an oilfield inspection operation consists of testing and documenting information in three principal areas: (1) automated pipe-body inspections, principal areas:automated pipe-body inspections,special end-area and prove-up inspections, andpersonnel certification and reference documents. These areas are discussed individually and described in more detail to pert-nit field evaluations to be conducted. Performance specifications that serve as a basis for evaluating the quality of the inspections are described. When field evaluations are made, all pertinent information that describes the inspection equipment, personnel, and procedures should be recorded. Identification numbers should be assigned to the inspection equipment when no other identifiable markings exist to allow easy identification at a later date. This also serves as a list that describes the equipment available at the particular inspection site. Automated Pipe-Body Inspections The geometrically uniform section of the pipe (all but the last few feet from either end) typically is inspected by an automated inspection system capable of scanning pipe at about 1 ft/sec [0.3 m/s]. JPT p. 88
The Hadrian-5 prospect in the United States (US) Gulf of Mexico’s Keathley Canyon 919 block was drilled by the operator in ~7000-ft water depth as one of the first Gulf of Mexico wells drilled after the deepwater moratorium. This exploration well was permitted under the new regulatory requirements of the US Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE). These new requirements included additional blowout preventer (BOP) certification and testing, incorporation of selected API recommended practices, and certification of the well design by a registered professional engineer. In addition to the well design regulations, BOEMRE required operators to calculate a worst-case discharge scenario and develop plans to contain that scenario. Well containment plans were developed that included the newly-formed Marine Well Containment Company’s (MWCC) response capabilities. The well was drilled between March and August of 2011 to a total depth (TD) of 19,631 ft and encountered several hydrocarbon intervals that were safely managed. The rig selected for this well was the dynamically-positioned (DP), Maersk Developer semisubmersible. This paper describes the planning, permitting, and execution of this challenging well. Topics covered include: New permitting requirements for federal waters in the US Worst-case discharge scenario and impact on casing design Elimination of trapped annular pressure via well design Minimizing vibrations in the tuff formation of the Hadrian mini-basin Managing the uncertainties associated with sub-salt formation pore pressures Drilling and casing mobile tar zones The well was drilled and evaluated in a safe manner with no significant incidents even though the geologic formations encountered were different than predicted.
This paper presents a procedure on the finite element method for analyzing a bolted flange connector and compares this method with three traditional approaches. The finite element method considers such effects as flange interface separation, nonlinear and nonconstant flange stiffness, and bolt bending. A comparison of the finite element model with the three traditional methods (each employs a formula for flange stiffness) shows a fairly close correlation for total bolt force versus applied load, but a wide discrepancy for maximum bolt stress versus applied load. The discrepancy between the finite element model analysis and the three other methods (empirical by Weiss and Wallner, truncated conical area by Roetscher, and the classical hollow cylinder approach) can be attributed to the change in flange stiffness during separation and the occurrence of bolt bending. The selected method of analysis was shown to significantly affect the results of a bolt fatigue analysis, but was shown to have little effect on a static analysis. In offshore applications, the environment creates dynamic stresses which make a fatigue analysis essential for long-term safety.
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