Field-Scale Simulation of Cyclic Solvent Injection (CSI). Cold heavy-oil production with sand (CHOPS) has been a popular and profitable means for primary recovery of heavy oil, up to approximately 10 Pa∙s viscosity, from unconsolidated sands. It presents an interesting secondary enhanced-oil-recovery (EOR) target, not only because 90% or more of the oil in place (OIP) is usually available, but also because of the presence of the wormhole network remaining post-CHOPS. The latter should provide for extensive penetration of and reservoir contact with solvent injectants—hence, the method discussed here of cyclic solvent injection (CSI). It seems clear that cycles of solvent slugs and production periods is a technically promising concept; but it is one of those for which quantitative simulation is rendered especially difficult: first by the low diffusivity of solvents, which allows large concentration differentials to persist at small scales; and second in this case by the similarly small scale, localized, but dominant nature of the wormholes themselves. Much of this paper is concerned with comparison of various approaches to this problem. Some of these may have inspiration for researchers dealing with similar issues in vapour-assisted petroleum extraction (VAPEX) and related processes.
This paper is also an example of using simulation as an adjunct to basic physical investigations. That is, you may not know the physics at all, just some data and a few hypotheses. Science is required, at which point the suggestion of using simulation can seem strange, to put it politely, to many people. But the way to look at it is to remember what a simulator is—a solution to a boundary-value problem. In science, hypotheses are converted to equations and the equations are solved to see if they usefully predict reality. A simulator in this context is simply a tool to solve a much more complicated and rigorous set of equations, than would otherwise be possible.
Design of Caprock Integrity in Thermal Stimulation of Shallow Oil-Sands Reservoirs. This is a topic of considerable importance, given the quantity of McMurray oil-sands resource that lies close enough to the surface, that the maximum safe operating pressure may be less than otherwise desirable for economical recovery. In such cases, caprock integrity is a material consideration to both project feasibility and safe operation. In turn, the difficulty and uncertainties of the problem requires a balanced mix of science, engineering judgement, and practical wisdom to maintain reasonable but not excessive safety factors.
This paper does an admirable job of bridging the gap between the science and the practical (read: regulatory) application of geomechanics to thermal caprock integrity. It presents an accessible picture of the state of the art, mixed with past experience, and is a good introduction to the field for nonexperts as well.
Propagation of Nanocatalyst Particles Through Athabasca Sands. Transport diluent is one of the major operating costs for any bitumen producer. The sensitivity of this cost to oil properties increases as the oil becomes heavier. Thus, in the case of bitumen (<~10°API), almost any amount of upgrading is useful, if (as always) the cost is proportionate to the quality uplift. That is challenging if any surface “pots and pans” are required.
Some previous work has indicated that a useful degree of in-situ upgrading may be possible, if a suitable catalyst is present. Thus, the question of catalyst transport, in any form, forms one of the key challenges of making this idea concrete. This paper contributes to that effort by presenting data collected on the transport/retention properties of a nanocatalyst, from experiments using McMurray sand.
Experimental Investigation of Bitumen Recovery From Fractured Carbonates Using Hot Solvents. The potential benefits of thermal solvent processes apply especially to carbonate rocks. This is partly because of their lower porosity compared with typical clastics, which makes the steam-oil recovery benefits more valuable. In addition, solvent swelling, generated by thermally enhanced diffusion, is one practical method (among others) by which bitumen can be moved from the finest matrix pores into the secondary porosity system.
Solvent applications are almost infinitely variable in design—even considering a single reservoir model—therefore, there can be no shortage of experimental data for comparison against current and future theories of production. There is certainly no excess of data for the emerging Grosmont play. This paper begins to fill that gap, with a study of recovery from preserved Grosmont core, using propane and bitumen at elevated temperature. Recovery of 58% OIP is reported in one case.
Straightline Analysis of Flow Rate vs. Cumulative-Production Data for the Explicit Determination of Gas Reserves. In a previous work, the authors of this paper described the adaptation of a long-standing solution for bondary-dominated incompressible flow at constant wellbore pressure to gas well testing. This was accomplished with transformations that involve only known quantities, as opposed to the standard psuedotime and pressure transformations. The latter involve the answer, requiring iterative calculations.
Here, the authors extend this methodology provides for a simple determination of gas reserves based on an identifiable window of straight line hyperbolic behaviour. They show that the slope (and duration) of this line are functions only of measurable properties, and the rate of depletion, relative to open flow.
Tight-Gas-Sand Permeability Estimation From Nuclear-Magnetic-Resonance (NMR) Logs Based on the Hydraulic-Flow-Unit (HFU) Approach. As with bitumen before it, one of the major milestones on the transition of shale gas to conventional status is the practical and reasonably established methodology for property evaluation and delineation. This paper contributes by describing an improvement of NMR techniques for the estimation of shale permeability. The study is based on 54 core samples from the Xujiahe formation in the central Sichuan basin.
Neil Edmunds is Vice President Enhanced Oil Recovery for Laricina Energy Limited in Calgary and Adjunct Associate Professor of Petroleum Engineering at the Schulich School of Engineering at the University of Calgary. He has more than 30 years of experience in thermal recovery of bitumen and the related development of reservoir-simulation software. Before joining Laricina, Edmunds was a reservoir-engineering specialist with EnCana Corporation, where he provided direction for the Foster Creek steam-assisted-gravity-drainage (SAGD) and VAPEX pilots, researched new recovery technologies, and gave expert testimony before regulatory hearings. Previously, he contributed to two pioneering SAGD projects: the AOSTRA Underground Test Facility and CS Resources’ East Senlac. Edmunds holds a BSc degree in mechanical engineering from the University of Alberta. He is a member of the Canadian Heavy Oil Association, SPE, and the Association of Professional Engineers and Geoscientists of Alberta.
Field-Scale Simulation of Cyclic Solvent Injection (CSI) describes post-CHOPS field-scale simulations of CSI performed with a comprehensive numerical model that uses mass-transfer rate equations to represent nonequilibrium solvent solubility behaviour (i.e., there is a delay before the solvent reaches its equilibrium solubility in oil). The model contains mechanisms to simulate foaming or no-foaming during CSI, depending on the field behaviour. It has been used to match laboratory experiments, design CSI operating strategies, and to interpret CSI field pilot results.
Caprock integrity in SAGD is concerned with both hydraulic integrity and mechanical integrity of caprock during the SAGD operation. Design of Caprock Integrity in Thermal Stimulation of Shallow Oil-Sands Reservoirs describes an integrated approach in analyzing the caprock integrity problem in a shallow SAGD project. Minifrac tests were used for in-situ stress characterization, and laboratory triaxial tests were used for measure the caprock shale’s compressive strength, thermal expansion, and temperature effects on the mechanical strength. On the basis of the minifrac tests and laboratory triaxial tests, numerical simulations were conducted to design a maximum operating pressure.
Propagation of Nanocatalyst Particles Through Athabasca Sands discusses results of an experimental study that examined the flow of nanocatalyst particles dispersed in viscous oil through sandpacks prepared with Athabasca reservoir sand, and operated at the reservoir conditions. The experiments procedure including sandpack preparation, measurement and monitoring of flow, particles, and medium properties are explained. The results of two experiments conducted with Athabasca sand are compared with the results of a previous study conducted with clean silica (Ottawa) sand. The analysis of morphology, size, and elemental composition of the deposited particles on sand grain surfaces measured by an environmental scanning electron microscope of the extracted samples from the sandpack are discussed.
A hot solvent injection option was evaluated for the bitumen containing carbonates samples obtained from the Grosmont unit in Canada. In the paper Experimental Investigation of Bitumen Recovery From Fractured Carbonates Using Hot Solvents, propane and butane were tested as solvent at the temperature values just above the saturation point at the reservoir pressure of this formation keeping the solvent in the gas phase. It was observed that the dilution achieved by butane was significantly greater than the dilution achieved by propane. As a result of this, butane yielded 58% bitumen recovery with significantly lower asphaltene content compared with propane that gave only 21% recovery at their saturation temperatures (115°C and 55°C, respectively).
Straightline Analysis of Flow Rate vs. Cumulative-Production Data for the Explicit Determination of Gas Reserves demonstrates that constant bottomhome pressure gas-well decline-curve analysis can be successfully undertaken on the basis of a straightline analysis technique that circumvents iterations, pseudopressure, pseudotime calculations, and uses flow rate vs. cumulative production data. The technique yields explicit predictions of original gas in place and removes the empiricism found traditionally in the calculation of hyperbolic decline exponents (b) for gas wells in boundary-dominated flow.
Tight-Gas-Sand Permeability Estimation From Nuclear-Magnetic-Resonance (NMR) Logs Based on the Hydraulic-Flow-Unit (HFU) Approach discusses a technique of estimating flow-zone indicator (FZI) from NMR logs. The difficulty of tight gas sands permeability estimation by using conventional methods is first described. The HFU approach is introduced to classify the Xujiahe formations into five types, and the corresponding relationships between core-derived porosity and permeability are established. A novel technique, which enables that FZI can be calculated effectively from NMR logs is highlighted, and then, the reliability of FZI calculation technique is verified. Accuracy and wide applicability of the proposed technique are finally discussed and several field examples are displayed.