Within the context of broad industry recognition of two drilling technologies, Underbalanced Drilling predates Managed Pressure Drilling (MPD) by at least a decade. While there are some similarities in some of the equipment and possibly in some of the techniques, the applications are different in their intent. This paper will discuss methodologies comparing Conventional, Underbalanced, and Managed Pressure Drilling Operations with respect to objectives, planning, drilling equipment and operations, and well control. The application of Managed Pressure Drilling was specifically created to give it an identity apart from Conventional Drilling and apart from Underbalanced Drilling. There appears to be some confusion with respect to methodology for Managed Pressure Drilling. What constitutes a Managed Pressure Drilling Operation? What constitutes an Underbalanced Drilling Operation? Are they actually the same? Does it matter? Figure 1 illustrates the general domains of Conventional Drilling Operations, Managed Pressure Drilling Operations, and Underbalanced Drilling Operations. Conventional Drilling Operations Conventional drilling by most accounts had its beginnings at Spindletop, near Beaumont Texas in 1900. Three key technologies contributed to the success of the well and later the drilling industry. They were rotary drive, roller cone bits, and drilling mud. There have been some improvements over the years. Today, the conventional drilling circulation flow path begins in the mud pit, drilling fluid (mud) is pumped downhole through the drill string, through the drill bit, up the annulus, exits the top of the wellbore open to the atmosphere via a bell nipple, then through a flowline to mud-gas separation and solids control equipment, then back to the mud pit. All this is done in an open vessel (wellbore and mud pit) that is open to the atmosphere. Drilling in an open vessel presents a number of difficulties that frustrate every drilling engineer. Conventional wells are most often drilled overbalanced. We can define overbalanced as the condition where the pressure exerted in the wellbore is greater than the pore pressure in any part of the exposed formations. Annular pressure management is primarily controlled by mud density and mud pump flowrates. In the static condition, bottomhole pressure (PBH) is a function of the hydrostatic column's pressure (PHyd) (Figure 2), where… PHyd = PBH In the dynamic condition, when the mud pumps are circulating the hole, PBH is a function of PHyd and annular friction pressure (PAF) (Figure 2), where… PBH = PHyd + PAF In an open-vessel environment, drilling operations are often subjected to kick-stuck-kick-stuck scenarios that significantly contribute to Non-Productive Time (NPT), adding expense for many drilling AFEs. Because the vessel is open, increased flow, not pressure, from the wellbore is often an indicator of an imminent well control incident. Often, the inner bushings are pulled to check for flow. In that short span of time, a tiny influx has the potential to grow into a large volume kick. Pressures cannot be adequately monitored until the well is shut-in and becomes a closed vessel.
A purpose-built finite-element model (FEM) is applied to simulate radial displacement of a casing string constrained within an outer wellbore. The FEM represents a fully stiff-string model wherein the casing is approximated by general-beam elements with six degrees of freedom at each node to account for all possible physical displacements and rotations. Results predicted include deflection of the casing centerline from the wellbore centerline, effective dogleg curvature, bending deformation, wall-contact forces, and bendingstress magnification. These results will provide for a more-accurate assessment of well integrity in terms of casing-stress safety factors and centralization before cementing, as well as more accurate prediction of running loads during the drilling phase.In critical-well-casing design, accurate assumptions regarding bending stiffness may be necessary to avoid overly conservative as well as nonconservative analysis. Challenging finite high-pressure/ high-temperature (HP/HT) and extreme-temperature wells are opportunities for increased design efficiency by avoiding overly conservative and costly designs, which can be crucial. Alternatively, design for extreme loads such as overpull loads in long deviated wells may be nonconservative if severe bending stresses are not considered.A realistic case study is presented that demonstrates the possibility to achieve cost efficiency by means of optimized casing design. A case study also is presented in which a nonconservative design may result if severe bending loads are not modeled. The purpose-built FEM code is in many ways preferable to the use of commercial finite-element-analysis (FEA) packages because of the time-consuming effort required to build up the detailed model.In typical casing and tubular-stress design, a soft-string model assumes casing strings are coincident with the wellbore centerline. The known or assumed wellbore curvature is applied directly to the casing string. Any effect of casing-string stiffness and allowable radial displacement within the outer wellbore is ignored. In many cases, this results in an overly conservative analysis. Likewise, the impact of bending-stress magnification is typically ignored, along with the effects of centralizer placement. This may also be nonconservative for critical overpull situations, such as in extended-reach-drilling (ERD) and horizontal wells.
A purpose-built finite-element model (FEM) is applied to simulate radial displacement of a casing string constrained within an outer wellbore. The FEM represents a fully stiff-string model wherein the casing is approximated by general beam elements with 6 degrees of freedom at each node to account for all possible physical displacements and rotations. Results predicted include deflection of the casing centerline from the wellbore centerline, effective dogleg curvature, bending deformation, wall contact forces, and bending stress magnification. In critical well casing design, accurate assumptions regarding bending stiffness may be necessary to avoid overly-conservative as well as non-conservative analysis. Challenging HPHT and extreme temperature wells are opportunities where increased design efficiency can be crucial. Alternatively, design for extreme loads such as overpull loads in long deviated wells may be non-conservative if severe bending stresses are not considered. A realistic case study is presented which demonstrates the possibility to achieve cost efficiency by means of optimized casing design. Also a case study is presented where a non-conservative design may result if severe bending loads are not modeled. The purpose-built FEM code is in many ways preferable to use of commercial FEA packages because of the timeconsuming effort required to build up the detailed model. In typical casing and tubular stress design, a "soft-string" model assumes casing strings are coincident with the wellbore centerline. The known or assumed wellbore curvature is applied directly to the casing string. Any effect of casing string stiffness and allowable radial displacement within the outer wellbore is ignored. In many cases this results in an overlyconservative analysis. Likewise the impact of bending stress magnification is typically ignored along with the effects of centralizer placement. This may also be non-conservative for critical overpull situations such as in ERD and horizontal wells.
ConocoPhillips' Magnolia project will utilize a Tension Leg Platform (TLP) in a record water depth of 4674 feet (1425 m) in Garden Banks block 783 in the Gulf of Mexico. The wells will be predrilled and then completed with a platform rig. Production is expected from unconsolidated, fine grained and over-pressured Pleistocene and Pliocene formations. Reservoir compaction was identified as a drive mechanism for the field. Rock mechanics studies indicated that reservoir depletion in the low-strength and high-porosity reservoir rocks could result in significant reservoir compaction due to initial shear failure followed by pore collapse. This paper will describe our analysis of such rock failure mechanisms and projected strains, which served as the basis for deriving estimates for reservoir compaction and stretch of overlying strata. The team faced a unique challenge to develop a casing design that would address reservoir compaction concerns. By itself, casing design was only one part to a solution that involved developing a comprehensive well construction and completion strategy that could deal with the reservoir compaction problems. The cost of casing failure would have significant negative impact on project economics. A concerted effort was undertaken to study the geology and the rock characteristics of the formations in this field. The resulting casing design strategy conforms with, and in some aspects improves upon, ConocoPhillips' current casing design philosophy. This paper discusses two of the major design factors:the effect of tension on the casing in the overburden above the reservoir andthe effect of compression on casing in the reservoir. Specific design criteria were developed for each of these factors. The field was sub-divided into different reservoir compartments, then the maximum stretch and compressive strain that is expected in each compartment was calculated for the reservoir and overburden zones. The selected design strategy was applied to the casing design with a view to optimizing wellbore life and project economics of each well. The result is a unified approach to compaction that begins in geomechanical analysis and ends with the financial decision process. Introduction The approach undertaken in engineering the Magnolia casing design for compaction has been to design each wellbore from the bottom to the top. The design work commenced with developing key design inputs to the project such as the production tubing size, the perforation requirements, and the sand control system that would be installed in each of the wells. Certain inflow performance is required from each wellbore from the reservoir to meet project economic goals. The reservoir and the geologic models also took this into account in determining the number of wells to be drilled and their placements in the reservoir. The formation stresses at Magnolia were characterized using well logs, leak-off test (LOT) data, core test data, drilling reports, and geological reports from previously drilled wells. Stress-gradients derived from these data were used to estimate in-situ stresses at reservoir depth and the anticipated abandonment reservoir pressure. A formation failure analysis for the field was conducted. The result of this analysis focused on predicting the rock mechanics and field sand production events. The reservoir flow data for the field, which included fluid data and reservoir permeability data, were also analyzed. This information was used to determine pressures through the reservoir/wellbore system and predict stress changes due to fluid flow. Information gathered from offset wells in the Gulf of Mexico with analogous sand properties indicated serious casing failure problems that were associated with compaction. A closer look indicated that most of the casing, cementing, and sand control assumptions made in those wells did not resolve the issues with compaction.
A method is presented to predict wellbore and formation temperatures for a template of closely spaced wells. Multiwell thermal interaction will alter the wellbore temperatures as well as formation temperatures in the interwell zones and also farther out from the well template. The change in temperature profile relative to a single well can be significant. For producing wells in close proximity, wellbore and formation temperatures will converge to a significantly hotter condition than in the isolated-single-well case.The modeling of wellbore and formation temperatures for closely spaced wells has not been widely examined to date. This problem has been approached only by using theoretical formulations based on simplified assumptions. The current work presents for the first time a methodology based on standard industry tools and models that yield results consistent with field experience. The method employs standard industry thermal/hydraulic-modeling software and a finite-element model (FEM) in a loosely coupled, iterative analysis that assumes steady-state conditions. Other numerical approaches including finite-difference (FD) and boundary-element-method (BEM) techniques are also considered. The far-field thermal-flux behavior of a single well is also considered as an important baseline for comparison.The effect of multiwell thermal interaction is important for closely spaced wells such as offshore platforms or subsea and Arctic developments. A case study is presented for a high-pressure/high-temperature offshore field development. The multiwell disturbance on formation and wellbore temperatures affects well design, facilities planning, and operations. Annular-pressure buildup, wellhead movement, tubular-stress design, cement-slurry design, subsidence/compaction effects, and facilities health and safety issues can all be affected. In some cases, unexpectedly high wellbore temperatures can be catastrophic.If multiwell thermal interaction is not taken into account, then load events such as annular-pressure buildup, wellhead movement, and thermal-induced stresses may be underestimated. For high-rate production wells, the increase in produced-fluid temperatures may be small, but even a small change may be critical. In all cases, the effect on outer wellbore strings/annuli and on the formation is significant. This also impacts the planning of offshore fields to be developed in phases with batch drilling.
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