Some of the advantages of the simultaneous use of surfactants and nanoparticles in enhanced oil recovery (EOR) processes are the increase in the efficiency of injection fluid for sweeping, the reduction of adsorption of the surfactant onto the reservoir rock, the alteration of wettability, and the reduction of water/crude oil interfacial tension (IFT). However, a large amount of nanoparticles required in chemical EOR processes might limit their application. Therefore, the main objective of this work is to synthesize, characterize, and evaluate magnetic iron core–carbon shell nanoparticles that can be recovered and to study their impact on the reduction of surfactant adsorption on the porous media and oil recovery at reservoir conditions. The additional benefit of the proposed method is that these nanoparticles can be recovered and reused after the application because of their magnetic properties. The magnetic iron core–carbon shell nanoparticles were obtained following a new one-pot hydrothermal procedure and were carbonized at 900 °C using a teflon-lined autoclave. The core–shell nanoparticles were characterized using scanning electron microscopy, dynamic light scattering, N2 physisorption at −196 °C, X-ray diffraction, X-ray photoelectron spectroscopy (XPS), and magnetometry measurements. The magnetic iron core–carbon shell nanoparticles with an average particle size of 60 nm were obtained. The XPS spectrum corroborated that magnetic Fe(0) of the core was adequately coated with a carbon shell. The IFT was measured using a spinning drop tensiometer for a medium viscosity crude oil and a surfactant mixture. The minimum IFT reached was approximately 1 × 10–4 mN m–1 at a nanoparticle concentration of 100 mg L–1. At this concentration, the dynamic adsorption tests demonstrated that the nanoparticles reduce 33% the adsorption of the surfactant mixture in the porous media. The simultaneous effect of core–shell nanoparticles and the surfactant mixture was evaluated in a displacement test at reservoir conditions obtaining a final oil recovery of 98%.

The rise of the SAGD (steam-assisted gravity drainage) technology over the last ten years as the leading technology to develop oil sands in-situ is unquestionable. This despite the youth and questions that still surround this technology. Therefore, a review of most of the existing operations in Canada has been undertaken (32 pads in 8 different operations), which includes an analysis of their current performance and particularities, trying to understand what makes a SAGD project successful, and what determines its performance. Moreover, SAGD's performance has been compared with the performance of CSS (cyclic steam stimulation), the other leading in-situ technology for oil sands. The main finding of this work is that geology and reservoir properties are by far the most dominant features for a successful SAGD operation. SAGD targets must be reservoir areas with average thickness above 15 m, good vertical communication and no thief zones. Moreover, if the geological conditions are known, the SAGD process has to be operated properly as lack of operational excellence can be detrimental to the performance of any SAGD project. SAGD operations are badly compromised by lack of steam mainly, but also by long boiler shutdowns, and by losing confined injectors early on in the process, which lead to splitting big pads into smaller ones. Finally, as long as the steam chamber can grow, the ultimate recovery of a SAGD operation can be expected to be in the order of 60 to 70%. The cOSR (cumulative Oil-Steam- Ratio) can fluctuate between 0.30 and 0.50, with the higher end values associated with high quality reservoirs (mainly oil content), excellent operations, and large pads; while operations at the lower end values have usually a combination of operational issues, smaller oil content and shale baffles (poor vertical connectivity). Introduction From 1985 to 1987 the government of Alberta, represented by AOSTRA, built the Underground Test Facility (UTF), whose purpose was to prove the SAGD concept. The first SAGD pilot was run from 1987 to 1990 under the name of Phase A. This 'proof of concept' pilot consisted of three short well pairs closely spaced (50 m in horizontal length and 25 m apart). The success of this pilot led to a joint venture between AOSTRA and industry. This resulted in the first commercial pilot built from 1990 to 1992 in the same facility called Phase B. This pilot had three wells pairs as well, which were 70 m apart and had lengths of 500 m. This pilot was operated until June 2004, with an ultimate recovery in excess of 65% and an Oil-Steam- Ratio (OSR) of 0.42. Since then, more than 10 commercial SAGD projects have been operating in Canada, mainly in the Athabasca area, while CSS is used only by three operators (Imperial Oil, Shell and CNRL) in the two other Alberta oil sands areas. Therefore, over the last decade SAGD has become the preferred in-situ technology for developing oil sand leases, mainly in the Athabasca area. Presently, the biggest in-situ operation in Canada, Imperial Oil at Cold Lake, uses CSS, with a production of ~140 kbpd. Similarly, CSS is currently the technology used at Shell's Peace River as SAGD has not shown its promise there. Consequently, the rise of SAGD, a fairly young technology compared to CSS, has raised a lot of questions such as what is its efficiency, its ultimate recovery, how sound is it, what type of reservoirs are better suited for SAGD? Therefore, an analysis of the performance of the current operations must address whether SAGD is the preferred in-situ technology to develop oil sands, and under which geological conditions. The present document reviews a large database of SAGD operations in Canada (8 operations and 32 pads) and tries to address some of the questions mentioned hitherto.

No abstract

In the challenging context of heavy to extra heavy oil production, polymer flood technology appears to be a promising solution to enhance ultimate recovery of reservoirs. Several field applications have already shown the efficiency of such technologies, although the final incremental recovery and mechanisms involved are still poorly understood. Indeed, the characteristics of the viscous fingering effects that certainly play a role are rarely captured at the field scale or at the core scale. This work aims at comparing the results of two core experiments with polymer flood in secondary and tertiary mode, in reservoir conditions, in term of recovery as well as in terms of relative permeabilities. In both cases, experiments were carried out on reconstituted reservoir cores, with restored wettability, initially saturated with live oil partially degassed in a PVT cell to the expected pressure and viscosity at the start of the field test. Saturation profiles were measured with X-Ray scans; effluents were collected in test-tubes and analyzed by UV measurements. Additional follow-up with tracers was tested in order to better assess the breakthrough of different fluids as well as the polymer adsorption during the experiment. Although the viscosity ratio was still highly unfavorable, with a polymer bulk viscosity around 70 cP at 10s-1 and an oil viscosity estimated at 5500 cP, polymer floods exhibit an excellent recovery factor.

No abstract