A two-dimensional computer model is developed to determine the radiative heat flux distributions within the vapor formed above a metal target irradiated by a laser beam. An axisymmetric cylindrical enclosure containing a radiatively participating medium is considered. Scattering is assumed to be isotropic and allowances are made for variation of the radiative properties of the medium and boundaries. The P-1 and P-3 spherical harmonics approximations are used to solve the integro-differential radiative transfer equation. The resulting equations are then solved for the radial and axial heat fluxes using a finite-difference algorithm. The most significant factors affecting the results obtained from both the P-1 and P-3 approximations were the optical thickness of the medium and the type of laser profile incident upon the medium. Using different wall reflectivities and scattering albedos had a smaller effect. Changing the medium temperature had an insignificant effect as long as medium temperatures were below 20,000 K.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractDeepwater high pressure, high temperature (HPHT) drilling environments present difficult challenges to well engineers. Typical deepwater pore pressure and fracture gradient profiles result in a narrow drilling window that can lead to seven to nine casing points. The high cost of these wells demands a high rate completion for economic payback, which defines the size of the production casing and liners. Drilling casings are restricted by the standardized 18-3/4" through bore diameter dictated by high pressure wellhead housings, blowout preventers, and riser systems. Furthermore, high pressures require thick wall casing, especially if sour service materials are specified. Satisfying all of these pressure and geometrical constraints requires some unconventional practices.Current and emerging technologies offer several ways to address this design dilemma. Riser-less drilling can be an effective way to delay running the high pressure wellhead, allowing for additional large diameter casing seats. Dual gradient drilling is a concept that can decrease the number of required casing points. Solid expandable liners provide a way to add or push casing points without the geometry impact of a conventional string. Managed pressure drilling may also show promise for eliminating a seat. However, heavy reliance on these new technologies may run counter to the guiding principle of keeping HPHT wells as simple and reliable as possible.This paper presents the concept of using conventional oil country tubular goods (OCTG) in unconventional sizes to increase the number of available casing points in deepwater wells. The method has several advantages in the areas of performance and reliability compared with the previously listed technologies. The decades of industry experience with conventional OCTG make the technology especially appropriate for containing high pressures and sealing off trouble formations.Related issues such as manufacturing lead time, costs, connections, and hangers are discussed. Several HPHT examples are included to illustrate the trade-offs with other design options.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractDeepwater high pressure, high temperature (HPHT) drilling environments present difficult challenges to well engineers. Typical deepwater pore pressure and fracture gradient profiles result in a narrow drilling window that can lead to seven to nine casing points. The high cost of these wells demands a high rate completion for economic payback, which defines the size of the production casing and liners. Drilling casings are restricted by the standardized 18-3/4" through bore diameter dictated by high pressure wellhead housings, blowout preventers, and riser systems. Furthermore, high pressures require thick wall casing, especially if sour service materials are specified. Satisfying all of these pressure and geometrical constraints requires some unconventional practices.Current and emerging technologies offer several ways to address this design dilemma. Riser-less drilling can be an effective way to delay running the high pressure wellhead, allowing for additional large diameter casing seats. Dual gradient drilling is a concept that can decrease the number of required casing points. Solid expandable liners provide a way to add or push casing points without the geometry impact of a conventional string. Managed pressure drilling may also show promise for eliminating a seat. However, heavy reliance on these new technologies may run counter to the guiding principle of keeping HPHT wells as simple and reliable as possible.This paper presents the concept of using conventional oil country tubular goods (OCTG) in unconventional sizes to increase the number of available casing points in deepwater wells. The method has several advantages in the areas of performance and reliability compared with the previously listed technologies. The decades of industry experience with conventional OCTG make the technology especially appropriate for containing high pressures and sealing off trouble formations.Related issues such as manufacturing lead time, costs, connections, and hangers are discussed. Several HPHT examples are included to illustrate the trade-offs with other design options.

Optimization of offshore production facilities requires the placement of several wellbores in close proximity of each other. If the wells are spaced sufficiently close, diffusion of thermal energy between the wellbores has a pronounced effect on the undisturbed geothermal gradient of the formation. Such variations of the geothermal gradient have been observed while drilling new wells in mature offshore fields with wells that have been in production for six months or longer. When a new well is drilled in this section of the formation, higher geothermal temperatures are encountered at shallower depths. This can seriously impact the drilling, mud, cementing and casing programs. Previous research concerning the heat transfer analysis of injection, production, and circulation is based on the thermal interaction of a single wellbore with the formation. These works typically use axisymmetric finite difference formulations of the wellbore heat transfer equations. Unfortunately, this approach is not adequate to analyze the effects of multiple wellbores. This paper bridges this gap with a technique to evaluate the thermal proximity effects of multiple wellbores. The method is based on the integral formulation of the heat conduction equation and it demonstrates the alteration of the undisturbed formation temperature profile. The results suggest that local geothermal temperatures in the vicinity of a producing field can be increased by several tens of degrees Fahrenheit. Introduction In a producing well, the bottom-hole energy of the formation fluids is transported up-hole. In this process, a part of the fluid enthalpy is lost to the formation due to heat transfer from the fluid to the wellbore and surrounding formation. When steady state conditions of production are established (typically, in a few months), there is a change in the formation temperature, especially between the mudline and the kick off point, where the vertical wellbores are in close proximity. Since optimization of offshore production facilities requires placement of several wellbores in close proximity of each other, diffusion of thermal energy between the wellbores can have a pronounced effect on the "near-wellbore undisturbed geothermal temperature" of the formation, especially at shallow depths. Such variations in the geothermal temperature have been observed while drilling new wells in mature offshore fields with wells that have been producing for six months or longer. When a new well is drilled in this section of the formation, higher geothermal temperatures are encountered at shallower depths. This seriously impacts the drilling, mud, cementing and casing programs. For example, MWD equipment, motors, and drilling fluids used to drill the upper hole sections may not be rated to perform at these higher temperatures. Furthermore, since cooling (or heating) of the rock formation induces contraction (or expansion) and creates tangential compressive (or tensile) stresses around the wellbore, the altered temperatures will affect mud density, kick tolerance (or potential for lost circulation due to excessive cooling along the wellbore perimeter) and influence ECD considerations1.

A finite difference model was developed and used to simulate transient heat transfer in wells undergoing injection and production processes. The tubing temperature profiles from these simulations were then reduced to a set of algebraic equations to provide simple and effective temperature versus depth and temperature versus time estimates. Results from field tests are also presented and compared in order to validate the finite difference model. INTRODUCTION Accurate temperature prediction for dowuhole tubulars has become increasingly important due to the potential cost savings associated with more preeise optimization of string design. Much of the attention in the literature has focused on accurate cementing temperature modeIs, while very little mention has been given to fracture stimulation or production temperature predictions. In an effort to predict tubing temperature profiles during injection and production, an axisymmetric finite difference model was developed. The model was developed following standard finite difference practices and provides the ability to accurately simulate virtually any well configuration under any sequence of flowing or static conditions. However, numerical simulation requires substantial input, and accuracy can only be assured if all input parameters are known. In certain situations, though, an engineer may find that a usable finite difference code or accurate well thermal properties are unavailable. In these eases, good correlations can provide similar results at substantial cost and time savings. In other situations, an engineer may need to predict the temperatures resulting from an increase in flow rate, or perhaps predict the temperatures for a fracture stimulation on a well for which production data is already available. The equations presented here can be used to accurately predict the temperatures resulting from such operations. PROCEDURE In order to develop a method to quickly estimate tubing temperatures during injection and production, it was necessary to identify the most sensitive input variables so that an appropriate correlation could be formulated. Using the finite difference model, the significant variables were found to ix the volumetric flow rate, depth, time, undisturbed static temperature profile, well geometry, flowing fluid properties, and formation thermal properties. Results from field tests were also compared in order to validate the finite difference model. Table-1 Comparison of FD Model With Field Tests(Available in full paper) A modified version of the injection model proposed by Ramcyl was used as the basis for providing the tubing temperature profiles. The model was modified by replacing the analytical time function with a function predicted by the finite difference simulations. The model was further simplified by allowing the overall heat transfer coefficient to be infinite (see Appendix), thus allowing the wellbore thermal effects to be included in the time function. An equivalent model for production was also developed (see Appendix) and shares the same time function as the injection model.