This paperde'scribes a fully implicit, three dimensional thermal numerical model for simulating flow through a porous media and through a wellbore. Darcy's law is used together with conservation of energy and mass to model flow in the porous media. The wellbore simulator is a time dependent, thermal, three-phase, one dimensional model which conserves energy, momentum of all phases and mass. Wellbore grid blocks are embedded in reservoir grid blocks. Variables in the reservoir and wellbore are solved for simultaneously. Many options are included in the wellbore simulator including the ability to model parallel flow in inner tubing and outer annuli and specification of slant angles or other parameters per wellbore grid block.This coupled model is targeted mainly at horizontal well or other applications in which a high degree of dynamic interaction occurs between the wellbore and reservoir.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractOil recovery operations are seeing increased use of integrated geomechanical and reservoir engineering to help manage fields.This trend is partly a result of newer, more sophisticated measurements that are demonstrating that variations in reservoir deliverability are related to interactions between changing fluid pressures, rock stresses and flow parameters such as permeability. Several recent studies, for example, have used finite-element models of the rock stress to complement the standard reservoir simulation.We discuss current work on fully coupling the geomechanical elastic/plastic rock stress equations to a commercial reservoir simulator.This finite difference simulator has black-oil, compositional and thermal modes and all of these are available with the geomechanics option. In this paper, the focus is on the implementation of the stress equations into the code. Some work on benchmarking against an industry standard stress code is also shown as well as an example of the coupled stress/fluid flow. Our goal in developing this technology within the simulator is to provide a stable, comprehensive geomechanical option that is practical for large-scale reservoir simulation.

A high-pressure steam-CO2 co-injection experiment, carried out in a 1.5 m diameter physical simulator packed with Athabasca oil sand, is described. The experimental run lasted/or 113 hours and consisted of two injection-drawdown cycles. During the run, 1454 kg of steam and 75.3 kg of carbon dioxide were injected (equivalent to 2.1 mole % CO2 in the mixture). This resulted in the recovery of 12.5% o/the initial bitumen in the oil sand. The experimental data obtained was compared to the results of a numerical modelling study. Good agreement was obtained. Differences between the numerical simulation and experiment are discussed. Results from steam-only predictions are used to discuss the merits of the steam-CO2 injection process relative to steam injection alone. Introduction Many experiments have been carried out at Alberta Research Council (ARC) in the last five years to test the effectiveness of additives on recovery of Athabasca bitumen. An adequate numerical simulation capability is useful in analyzing these runs. This capability also serves as a design aid for further experiments as well as serving a need for idealized studies. The experiment that was simulated for this report (hereafter denoted "Run 15006") was the first run in the 150 cm pressure vessel in which stearn and CO2 were simultaneously injected into an oil sand pack of this physical size. The primary objective was to study recovery benefits from addition of CO2 to the injection stream. Other objectives were to study the rate of advance of temperature profiles in the bed during the run and to provide data to test a numerical simulation of the steam-C02 process. A three component model developed at ARC was used to simulate the above process. The model is a fully implicit thermal numerical simulator with the capability of handling a single additive. Objectives of the numerical simulation were principally to test the numerical model, and hence all its property data for a CO2/water/bitumen system. Description of Experiment The 150cm diameter simulator system (Fig. 1) consists of a large pressure vessel (150 cm ID by 270 cm high) designed to allow steam and gas to be injected simultaneously into the test bed under controlled flow rates. Oil sand is packed into this vessel and maintained at field overburden conditions by introducing a nitrogen blanket at the top of the cell. Feed streams were injected to the centre of the test bed via an injection well. The three main systems are schematically illustrated in Figure 1. These are the injection system, test cell and production system. The steam portion of the injection system consists of a high pressure steam generator followed by a superheater. Flow turbines measure flow rate after the superheater and are marked "F" in Figure 1. Thermocouples and pressure, gauges are also in place, marked "T" and "P" in Figure 1. The steam generator operates at a constant flow rate. Pressure to the system is regulated by a control valve upstream of the superheater.

Summary The extension of a previously reported well model to compositional and thermal applications is discussed. This multisegment, multibranching wellbore model has been fully coupled to a commercial reservoir simulator that can operate in black-oil, compositional, or thermal modes. In this paper, the discussion will focus on thermal, heavy-oil applications in which simulation requires a better representation of the wellbore geometry and the physics of fluid flow and heat transfer. Introduction Gravity-drainage processes with possible steam (SAGD) or gas vapor (VAPEX) assistance and other recovery technologies often require the use of long horizontal wells with flow in an inner tubing and outer annulus.1–3 Thermal studies that simulate horizontal wells have been discussed by many authors. Recovery techniques include cyclicsteam projects,4–10 dual-well SAGD,11 and single-well SAGD.12 In these studies, the oils are heavy (970 to 1014 kg/m3; 14 to 8°API), with viscosities ranging from 2,000 cp at 32°C in California fields up to 1,000,000 cp at 12°C for oils found at the UTF project13 in the Athabasca tar sands deposit. These studies have, for the most part, used the conventional wellbore line source/sink model available in any thermal simulator. Simulation technology for horizontal wells has improved dramatically since the late 1980s. At this time, Stone et al.14 described a horizontal well model that featured a mechanistic multiphase fluid-flow model in the wellbore and allowed flow simultaneously in an inner tubing and outer annulus. This was designed to handle simulations in the near-wellbore region of a dual-well SAGD process and, because of the more detailed flow regime map, could not handle larger-scale simulations for stability reasons. Also during this time period, Long et al.15 carried out the Seventh SPE Comparative Solution Project concerning the modeling of horizontal wells in reservoir simulation. A variety of methods was used by the participants to model the inflow into the horizontal well model. These included the use of an inflow performance relationship (IPR) with a separate well model or direct coupling by modeling the well as part of the grid. Similarly, there were various wellbore hydraulics models ranging from a constant-pressure line sink to friction pressure-drop relations or simple functional fits of published holdup correlations. All of these horizontal well models were designed to run robustly and stably in large-scale field simulations. However, some were limited in their ability to calculate a multiphase pressure drop, others in not allowing the wellbore model geometry to correspond to the engineering design of the well rather than to the simulation grid. Some methods allowed multiphase pressure drops with explicit updates or other approximations. Recently, Tan et al.16 have described a fully coupled discretized thermal wellbore model with the ability to simulate flow in casing/annulus wellbore cells. Estimates of the relative flow rates are made based on phase saturations and straight-line relative permeability curves. These estimates are passed to a subroutine that calculates flow rates from the correlated Beggs et al.17 measurements. Wellbore cells are connected to reservoir cells. A multisegment well model that can simulate flow in advanced wells was discussed by Holmes et al.18,19 This model, implemented in a commercial black-oil simulator, is able to determine the local flowing conditions (the flow rate and pressure of each fluid) throughout the well. It allows for pressure losses along the wellbore and across any flow-control devices. In addition to being fully implicitly coupled, with crossflow modeling and the standard group control facilities, horizontal wells, multilateral wells, and "smart" wells containing flow-control devices can also be modeled. The trajectory is not constrained by the simulation grid. For example, the wellbore may run outside the grid or across layers. Properties and geometry can be updated at any time in the simulation. In this paper, we first describe the implementation and enhancements to the implicit multisegment well model discussed in Ref. 18 that allow this model to run in compositional and thermal modes. In these modes, the equation of state (EOS) or thermal K-value treatment of the fluid pressure/volume/temperature (PVT) is extended to the wellbore flow. Phase volumes are computed in each segment and are then used to calculate the multiphase pressure drop. In thermal mode, an enhancement allows the definition of heat transfer coefficients, which permit heat loss to the reservoir, to another segment, or to the overburden. Another enhancement allows individual segments to inject or produce fluids, which permits the direct modeling of gas lift, downhole water pumps, or circulating wells, available in any mode. It is important in compositional, and especially thermal, wellbore simulations to provide an accurate initial estimate of the well solution; otherwise, there can be convergence problems. A method for predicting the initial state within the well is also shown later. We then present four case studies. Each case study has been set up from published engineering analyses of fields in western Canada and California, U.S.A. The well model used in these studies is considerably more detailed than that in the original published simulation work. Not only are the wellbore hydraulics more accurately modeled with multiphase flow models, but the geometry of the wells is also specified in more detail. Wellbore geometry includes the ability to run the well outside the simulation grid, allowing the modeling of heat loss from a steam-injection well to the formation, between the surface and the simulation grid. Also, an undulating well trajectory can be specified and is demonstrated in one of the studies. Fluid flow down an inner tubing and back along an outer completed annulus is demonstrated in three of the studies, in which heat transfer occurs between the inner tubing and the outer annulus and between the annulus and the formation. Two of these studies contain a segment at the heel of a horizontal annulus that removes fluids to an external sink, allowing part of the circulating fluids to return to the surface while the remainder are injected, produced, or stored in the wellbore. Where possible, differences are shown between the multisegment model and a standard line source/sink model that demonstrate the effects of modeling the improved wellbore physics. Description of the Multisegment Well Model The multisegment well model reported by Holmes et al.18 was originally implemented in a black-oil simulator. It uses four main variables: a total fluid-flow rate through the segment, weighted fractional flows of both water and gas, and pressure in the segment.

Canine rabies causes an estimated 60,000 human deaths per year, but these deaths are preventable through post-exposure prophylaxis of people and vaccination of domestic dogs. Dog vaccination campaigns targeting 70% of the population are effective at interrupting transmission. Here, we report on lessons learned during pilot dog vaccination campaigns in the Moramanga District of Madagascar. We compare two different vaccination strategies: a volunteer-driven effort to vaccinate dogs in two communes using static point vaccination and continuous vaccination as part of routine veterinary services. We used dog age data from the campaigns to estimate key demographic parameters and to simulate different vaccination strategies. Overall, we found that dog vaccination was feasible and that most dogs were accessible to vaccination. The static-point campaign achieved higher coverage but required more resources and had a limited geographic scope compared to the continuous delivery campaign. Our modeling results suggest that targeting puppies through community-based vaccination efforts could improve coverage. We found that mass dog vaccination is feasible and can achieve high coverage in Madagascar; however, context-specific strategies and an investment in dog vaccination as a public good will be required to move the country towards elimination.