The detailed interactions between the reservoir and the wellbore are especially important in thermal processes such as steam flooding and in situ upgrading. These linkages must therefore be captured in thermal simulations. Although fully-coupled thermal wellbore-reservoir flow simulators have been developed, the implementation of the thermal well model is somewhat complicated and the simulations are computationally demanding. In this paper, we present a semianalytical treatment that enables a fairly straightforward extension of existing isothermal wellbore flow models to the nonisothermal case. The procedure entails the use of analytical solutions for wellbore temperature applied in conjunction with numerical solutions of the reservoir mass and energy balance equations coupled with wellbore mass and momentum balance equations. The approach thus enables a degree of decoupling between the wellbore flow and energy problems. We proceed by first presenting analytical solutions for wellbore temperature, developed under various assumptions (some of these solutions have been obtained previously). We then describe the use of one of these solutions, which allows for general variation of in situ phase fraction and other properties along the wellbore, within the semianalytical context. The implementation of the overall method into a general purpose research simulator is also described. Results are presented for several cases involving multiphase flow in monobore and multilateral wells. Close agreement with reference solutions, obtained from a fully-coupled thermal wellbore-reservoir model, is demonstrated for all of the examples. The semianalytical treatment is additionally shown to provide comparable or improved computational efficiency relative to the fully-coupled model. The overall procedure is therefore very well suited for use in general thermal reservoir simulation. Introduction Thermal recovery processes such as steam flooding and downhole heating are essential for the production of heavy oil and oil sands. Downhole heating is also under investigation for the recovery of oil from oil shales. For any of these processes, accurate and efficient simulation is essential for reservoir management and process optimization. The wellbore model is particularly important as the detailed interaction between the reservoir and wells can substantially impact reservoir performance. In recent work (Livescu et al., 2008), we developed a fully-coupled, thermal wellbore-reservoir simulator. Detailed coupling is essential because flow from the reservoir into the wellbore (in the case of a production well) provides the source terms for the wellbore flow model, and these source terms depend strongly on reservoir variables. The formulation was implemented into Stanford's General Purpose Research Simulator (GPRS). The general simulator is described in detail by Cao (2002) and Jiang (2007). Within the thermal black-oil context, the wellbore flow model entails the one-dimensional (axial) time-dependent solution of mass conservation equations for oil, water and gas, a momentum balance (or pressure drop) equation, and an energy equation. A drift-flux representation is applied to account for slip between phases (Holmes et al., 1998). The detailed parameters appearing in the drift-flux model were determined from large-scale two and three-phase flow experiments performed over a range of flow rates and pipe inclinations (Oddie et al., 2003; Shi et al., 2005a,b). The thermal wellbore flow model also accounts for heat transfer between the well and the reservoir, temperature-dependent property variation, and transient effects.
Thermal recovery processes are widely applied for the production of heavy oil and oil sands. Thermal reservoir simulation models, however, often lack a comprehensive well modeling capability. Such a capability is required to capture the detailed thermal effects that occur in the wellbore. These effects can be important as they impact wellbore pressure and temperature and thus production and injection. We recently developed a fully-coupled black-oil thermal multiphase wellbore flow model and implemented it into Stanford's General Purpose Research Simulator (GPRS). The model computes pressure, temperature, and oil, water and gas phase fractions along the wellbore as a function of time and includes treatments for slip between fluid phases, heat losses to the reservoir, and general variations of fluid properties with temperature and pressure. The purpose of this paper is to validate and test the coupled wellbore-reservoir model for challenging and realistic cases. The thermal wellbore model is first validated through comparison to field data for three-phase flow in a long well with both vertical and inclined sections. Close agreement between the model and field data is obtained. Complex wells containing multiple branches are then simulated, including a steam-water case with vaporization and condensation. The general conclusion from this work is that the new model is capable of simulating a wide variety of complex coupled reservoir-wellbore phenomena. Introduction Thermal recovery processes such as steam flooding, steam assisted gravity drainage (SAGD), and downhole electrical heating are essential for the production of heavy oil and oil sands, and they are also under investigation for the in situ upgrading of oil shales. Under any of these recovery processes, a key to efficient reservoir management and process optimization is the ability to perform accurate reservoir simulations. Although the current generation of flow simulators is able to model thermal effects within the reservoir, the wellbore flow models linked with these simulators often lack comprehensive thermal capabilities. This may limit simulation accuracy for many cases. Thus, there is a need for the development, validation and testing of comprehensive thermal wellbore flow models that are coupled to reservoir simulators. This is the overall goal of the work described in this paper. Over the last few decades, there have been many analytical and numerical models presented for nonisothermal wellbore flow. This literature is reviewed in detail by Livescu et al. (2008) so our discussion here will be brief. The analytical models include, among others, those of Ramey (1962), Satter (1965), Hasan and Kabir (1994, 1999, 2002, 2007) and Livescu et al. (2008). These models are useful in many contexts though they typically include many simplifications, such as assuming steady state flow or neglecting spatially varying inflow, which render them unsuitable for use in general simulators. Numerical models are much more general as they potentially allow for transient effects, spatial variability, slip between phases, general property variation, etc. Such models have been developed by Farouq Ali (1981), Farouq Ali and Abou-Kassem (1989), Stone et al. (1989, 2002), Holmes et al. (1998), Pourafshary et al. (2007) and Livescu et al. (2008). These models entail one-dimensional (axial) representations of the wellbore and include coupled conservation equations for multiple components (e.g., oil, water and gas), an energy equation, and a pressure drop relationship. Flow from the reservoir into the wellbore (in the case of a production well) provides source terms for the wellbore flow model. Previous formulations have been developed for both black-oil models (Stone et al., 1989; Livescu et al., 2008) and fully compositional models (Stone, 2002; Pourafshary et al., 2007).
A recently developed 2 ⅛-in. intelligent coiled tubing (ICT) system combines real-time downhole data monitoring with the capability to simultaneously provide downhole power, significantly improving operational efficiency and accelerating well recovery in all types of CT operations. From milling, stimulation, and well cleanouts to gas lifting, camera services, logging and perforating operations, this novel system can provide accurate, real-time downhole monitoring of high-resolution depth correlation, differential pressure, and temperature data. The novel real-time downhole communication system consists of a non-intrusive electrical conductor wire, surface hardware and software, and a versatile 2 ⅛-in. bottomhole assembly (BHA) that incorporates the conductor release assembly, casing collar locator (CCL), pressure, and temperature sensor package, and BHA release function. Switching between different applications is as simple as changing out the BHA, which reduces the need to rig-up and rig-down and leads to operational time and cost savings. The main advantage of this system is that it eliminates the downhole uncertainties. For instance, using the real-time downhole depth, pressure, and temperature data, the CT field crew can react to changing conditions, make decisions based on dynamic downhole events, and eliminate missed or wasted runs. Several case studies are presented in this paper. First, an ICT conveyed camera operation was effectively performed in an onshore lateral well in North America to locate the damaged casing. Previously, several unsuccessful attempts with a wireline, camera, and tractor system resulted in 50 hours of total lost time to the operator. Second, a complex cement milling, cleanout, and perforating operation was performed to kick off an onshore well in Netherlands. The real-time CT communication system was used to perforate the well and to have control over its bottomhole pressure, especially during the kick off stage. Third, an ICT system was used in a mature offshore well in Brazil with increasing water cut to run inflatable plugs to isolate the water zone. Fourth, a complex drifting, logging, jetting, zonal isolation, and scale removal operation was performed in a mature offshore well in Brazil to decrease its water cut. Fifth, a matrix acidizing operation was performed in a deepwater cased well in Brazil. The logging profiles showed that the well had low well productivity. Using the ICT system, the perforations were accurately located due to the CCL data and the acid treatment was enhanced due to the downhole pressure and temperature data. Placing the acid at the right spot significantly increased the well productivity. The paper describes the novel real-time data monitoring system and discusses the data acquired during these field operations. The system performance and benefits confirmed during the five operations are presented. These findings outline the versatility of the 2 ⅛-in. ICT system, the predictability of successful operations resulting from using this system, and the cost and time savings for operators.
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