Summary Experiments on initial stages of the steam-assisted gravity drainage (SAGD) process were carried out, using two-dimensional (2D) scaled reservoir models, to investigate production process and performance. Expansion of the initial steam chamber, its shape and area, and its temperature distributions were visualized with video and thermal-video pictures. The relationship between isotherms and steam-chamber interface was investigated to study the drainage mechanism. Temperature at the expanding steam-chamber interface was observed to remain nearly constant at close to 80°C. The effect of vertical spacing between the two horizontal wells on oil recovery was also investigated. For the Conventional SAGD case, oil production rate increased with increasing vertical spacing between the wells; however, the lead time for the gravity drainage to initiate oil production became longer. The results suggest that vertical spacing between the wells can be used as a governing factor to evaluate production rate and lead time in the initial stage of the SAGD process. Based on these experimental results, the SAGD process was modified; the lower production well was intermittently stimulated by steam injection, in conjunction with continuous steam injection in the upper horizontal injector. With the modified process (named SAGD-ISSLW), the time to generate near-breakthrough conditions between two wells was shortened, and oil production was enhanced at the rising chamber stage compared with that of the Conventional SAGD process. Introduction The SAGD process was developed by Butler and his coworkers.1,2 In Canada, the SAGD process has proven successful for recovery of bitumen, as demonstrated in the reports on the UTF projects (Phases A and B).3,4 Chung5 and Chung and Butler6,7 reported experimental results for the SAGD process with scaled and visual reservoir models. Furthermore, Chow and Butler8 reported numerical simulation results matching Chung's experimental results5 using Computer Modelling Group Ltd.'s STARS™ simulator. Recently, Mukherjee et al.9 successfully forecasted the performance for Phase B of the UTF project. Butler10 gave a review of the SAGD process. An operational problem of the SAGD process for oil sands reservoirs is the lead time required to generate a steam chamber in near-breakthrough conditions between the two horizontal wells before the production stage. In this study, we first examined characteristics of the Conventional SAGD process, especially the expansion rate of the steam chamber by gravity drainage and the effects of well spacing. It was found that by using smaller vertical spacing between the two horizontal wells, the lead time was reduced, while production rate after breakthrough became lower. As shown in this paper, results from our investigation demonstrated that a more economical SAGD operation could be achieved by a simple modification involving selective intermittent stimulation of the lower horizontal producer by steam injection. For this process, called the SAGD-ISSLW process, the lower horizontal well was modified to enable intermittent stimulation by steam injection along the well design reported by Liderth.11 As such, this well served two functions: selective intermittent steam injection, and continuous fluid production. Steam from this lower well was injected intermittently to prevent steam breakthrough. The experiments using this process were compared to those using the Conventional SAGD process. The results showed that the SAGD-ISSLW process was successful in reducing the lead time to generate the steam chamber in the initial stage. The quick generation of the steam chamber plus the intermittent steam injection provided the advantage of allowing larger vertical spacing to be set between the two horizontal wells. Intermittent steam injection also led to another advantage of enhancing the instability of the steam-chamber interface near the ceiling, and thus it could be used to control the expanding steam chamber more effectively. Experimental Apparatus and Procedures Many experiments were performed in scaled 2D reservoir models with porous packing materials to investigate steam-chamber behavior and oil-production mechanisms, with respect to heat and mass-transfer phenomena. To compare process performance, steam-injection and fluid-production rates were measured. The experimental apparatus was designed and dimensions were determined according to the scaling criteria given in Refs. 5 and 6. Major experimental conditions and the purposes for the four phases of experiments are listed in Table 1. One difference between our experiments and those of Chung and Butler6 is the process used to preheat the reservoir by circulating steam through two wells before injecting it into the reservoir. We did not use preheating in our experiments, as we believed that it would interact with the well structure and materials, and as a result, heat not only the reservoir but also both side plates of the 2D models. Fig. 1 shows a schematic of the experimental apparatus, including the reservoir model. The apparatus consisted of a water pump, steam generator, steam accumulator, 2D scaled reservoir model, production-control mechanism, visualization system, and the data-acquisition system. All components, except the data-acquisition and video-camera systems (DAS), were mounted on a flat steel table designed and built in-house. Scaled Reservoir Model. The 2D scaled reservoir models (Fig. 2) were designed to represent a vertical segment of an oil sands reservoir. The models were made from smooth and transparent acrylic-resin plates 20 mm in thickness. The transparent side plates allowed visualization of the displacement of the oil in the steam chamber. Glass beads (diameter: 0.18 to 0.25 mm, average 0.21 mm) and heavy oil were packed between the two side plates. Motor oil (COSMO #1000, molecular weight=490 g/gmol, ?=998 kg/m3) served as the heavy oil in the experiments. Viscosity of the COSMO #1000 oil and Athabasca bitumen (extracted by Suncor Inc.) was measured as a function of temperature with a rheometer (Shimadzu, RM-1), as shown in Fig. 3. Viscosity of this oil was 93 000 mPa's (or 93 Pa's) at an initial temperature of 20 to 25°C, and 120 mPa's at a steam temperature of 106°C. Thus, the viscosity of the heavy oil used in the present experiments is roughly one-fifth that of the bitumen.
EnCana Corporation's Christina Lake Thermal Pilot Project, 170 km south of Fort McMurray, Alberta, Canada, uses steam-assisted gravity drainage (SAGD) technology to recover bitumen from the Lower Cretaceous McMurray formation. This paper presents an analysis of time-lapse and crosswell seismic data, as part of an overall study integrating different disciplines and technologies, to understand the effects of geology on SAGD-process performance in the pilot area.A 3D baseline survey was conducted at the start of the pilot in 2001, and two follow up surveys were conducted in 2004 and 2005. In addition, six crosswell seismic profiles were acquired by placing both sources and receivers in the vertical wellbores. The goal of the seismic surveys was to better understand steamchamber growth and reservoir architecture by detecting lithology changes, including the occurrence and distribution of mudstone stringers. Data from the surveys, especially from the crosswell profiles, indicated significant reservoir heterogeneity, and helped to characterize reservoir architecture in the pilot area more accurately.Analysis of seismic data (both 4D and crosswell) showed steam-chamber growth and oil recovery to be influenced strongly by reservoir geology. Steam-chamber growth is especially affected by the presence of low-permeability facies in the vicinity of the SAGD well pairs. Our analysis indicates that these reservoir heterogeneities have contributed to the creation of areas within the reservoir that have been unaffected by steaming operations to date. These findings are in agreement with flow-simulation results and collectively contribute significantly to the planning of future developments.
This paper presents results of phase behaviour calculations and compositional simulation of asphaltene precipitation in reservoirs. For phase behaviour calculations, the precipitated asphaltene is represented by a pure solid while the oil and gas phases are modelled with an Equation of State (EOS). Compositional simulation of the dynamics of asphaltene precipitation in porous media includes the flow of suspended solid in the oil phase, deposition of solid through adsorption and entrapment, and plugging. Calculations of asphaltene precipitation for a North Sea oil with hydrocarbon gas, for a Canadian crude with CO2, and for a heavy oil with propane are described. The results are in agreement with laboratory experiments and field observations. Introduction Asphaltene precipitation from reservoir fluids during oil production is a serious problem because it can result in plugging of the formation, wellbore and production facilities. Asphaltene precipitation can occur during primary depletion of highly undersaturated reservoirs or during hydrocarbon gas or CO2 injection for improved oil recovery (IOR). The injection of hydrocarbon gases or CO2 for IOR promotes asphaltene precipitation. Numerous field reports and laboratory studies on this aspect have been published1–8. Precipitation can occur anywhere in the reservoir, although it manifests itself frequently at the production wellbore at solvent breakthrough. Asphaltene precipitation may also occur during solvent injection into heavy oil reservoirs9. Butler and Mokrys10,11 proposed an in situ solvent extraction process for heavy oils and tar sands called VAPEX. This process uses two horizontal wells (one injector and one producer). The injection of solvent (e.g. propane) creates a solvent chamber where oil is mobilized and drained toward the producer. In addition to the mobilization process, the solvent may also induce asphaltene precipitation, which provides an in situ upgrading of the oil. The Asphaltene Precipitation Envelope (APE) bounds the region where precipitation occurs12,13. In Refs. 12 and 13, the APE's are referred to as Asphaltene Deposition Envelopes (ADE). In this paper, the term "precipitation" refers to the formation of the asphaltene precipitate as a result of thermodynamic equilibrium, and "deposition" refers to the settling of the precipitated asphaltene onto the rock surface in a porous medium. The onset conditions correspond to points on the APE. Within the APE, the amount of precipitated asphaltene increases as pressure decreases from the upper onset pressure to the saturation pressure of the oil. The precipitation reaches a maximum value at the saturation pressure, and decreases as pressure decreases below the saturation pressure. Inside the reservoir, after precipitation has occurred, the asphaltene precipitate can remain in suspension and flow within the oil phase, or can deposit onto the rock surface. The main deposition mechanisms are adsorption and mechanical entrapment. The deposited asphaltene may cause plugging of the formation and alteration of rock wettability (from water-wet to oil-wet). Many thermodynamic models that describe the phase behaviour of asphaltene precipitation have been reported in the literature. These include the use of a liquid solubility model2, a thermodynamic colloidal model14, a thermodynamic micellization model15, a colloidal activity coefficient model16, a variation of a model for wax17,18, or a pure solid model19–21. Nghiem et al.20,21 also describe the incorporation of the pure solid model into an EOS compositional simulator. This paper focusses on the phase behaviour modelling and compositional simulation of asphaltene precipitation in gas injection process for IOR using a solid model for the asphaltene precipitate. Calculations are performed for three typical IOR process: a North Sea oil with hydrocarbon gas injection, the Weyburn oil with CO2 injection, and the Lindbergh heavy oil with propane injection. These represent examples of the three main solvent IOR processes where asphaltene precipitation normally occurs.
Underbalanced drilling (UBD) holds several important advantages over conventional drilling technology. These include minimization of formation damage, faster penetration rate, and ability for evaluation of reservoir productivity during the drilling process. As UBD technology matures, it has also been used more and more in different applications. However, many aspects of UBD technology remain poorly understood. The model presented in this paper seeks to understand the mechanisms involved in the transport of cuttings in UBD.The model simulates the transport of drill cuttings in an annulus of arbitrary eccentricity and includes a wide range of transport phenomena, including cuttings deposition and resuspension, formation, and movement of cuttings bed. The model consists of conservation equations for the fluid and cuttings components in the suspension and the cuttings deposit bed. Interaction between the suspension and the cuttings deposit bed, and between the fluid and cuttings components in the suspension, are incorporated. Solution of the model determines the distribution of fluid and cuttings concentration, velocity, fluid pressure, and velocity profile of cuttings deposit bed at different times.The model is used to determine the critical transport velocity for different hydrodynamic conditions. Results from the model agree quite closely, qualitatively, with experimental data obtained from a cuttings transport flow loop at the Technology Research Center of the Japan Natl. Oil Corp. (TRC/JNOC)'s Kashiwazaki Test Field in Japan. These results show the importance of slippage in the formation of the cuttings deposit bed. The model is useful in evaluating the minimum flow rate for effective cuttings removal in UBD.
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