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Summary The Grosmont formation, a carbonate reservoir in Alberta, Canada, has 400 billion bbl of bitumen resource, which is currently not commercially exploited. The carbonate reservoir is karstified by groundwater and tectonically fractured, resulting in three classes of porosity: matrix, vugs, and fractures. The viscosity of bitumen is lowered by four to six orders of magnitude when heated by steam. Since December 2010, the Saleski pilot project evaluated steam-injection-recovery processes by use of four well pairs, two each in the Grosmont C and Grosmont D units. For the first year of the pilot, two well pairs were operated with continuous injection and production similar to successful steam-assisted-gravity drainage(SAGD) projects in Alberta oil sands. Reservoir observations of steam/oil ratio (SOR) and calendar-day oil rate (CDOR) indicate recovery by gravity drainage is viable, although operating practices from conventional SAGD must be modified for the Grosmont formation. The decision to evaluate cyclic injection and production from single wells was made in early 2012, although it was recognized that cyclic operations created new challenges for the facility (which was built for SAGD operations) and artificial lift. The pilot data indicate that the drilling conditions (balanced vs. overbalanced), completions (openhole vs. slotted liner), and acid treatments of the wells have a significant impact on the individual-well performance. Injectivity into the Grosmont reservoir is high, even into a cold reservoir, because of the existing fracture system. Injection pressures stayed less than 40% of the estimated pore pressure required to lift the overburden. 4D-seismic results indicate that the injection conformance along the well axis is close to 100% and that the heated area is laterally contained around the well. Productivity is comparable to oil-sands project performance. The decline of oil rate is not only dependent on pressure but also on temperature. For cyclic operations, a CDOR of 43 m3/d (for a 450-m-long well) and an SOR of 3.4 were achieved, demonstrating that with sufficient scale, a commercial project can be established successfully. The pilot has satisfactorily derisked the Grosmont reservoir at Saleski. While cyclic operations have demonstrated economic performance, continuous injection and production similar to SAGD remains an alternative recovery strategy beyond startup in the later depletion stage. Successful future developments will advance the optimization of drilling, completion, artificial-lift, and plant capacity issues, while the reservoir itself has demonstrated its production capacity.

Bitumen production from the Grosmont formation is enabled by bitumen-viscosity reduction caused by heating with steam, and is driven by three processes: thermal expansion, gravity drainage, and spontaneous imbibition. Gravity drainage is the dominant recovery mechanism. Maintaining a balance of injected and produced fluid is indicative of good performance. The projected steam/oil ratio (SOR) for the carbonate Grosmont formation is comparable to that of the clastic Clearwater formation; the impact of lower porosity is compensated by lower water saturation.On the basis of the experience from the pilot project, a followup development of the Grosmont formation relies on cyclic operation of injection and production. Saleski Phase 1, approved by the Alberta Energy Regulator, is designed for 1700-m 3 /d oil capacity from the Grosmont formation. For the first time, probable undeveloped reserves have been assigned to a fractured-carbonate bitumen reservoir. The cyclic-to-continuous steam-assisted-gravity-drainage drainage (C2C-SAGD) concept, where initial cyclic operation of individual wells is converted into continuous injection and production with well pairs as the reservoir depletion matures, intends to maximize recovery in future exploitation projects.Spontaneous Imbibition. In general, fractured carbonate reservoirs are initially oil-wet (Al-Hadhrami and Blunt 2001). Specific to the Saleski Grosmont, laboratory experiments are currently being executed to confirm the wettability. Assuming bitumen is the wetting phase (Fig. 2, left), capillary pressure in the matrix is low at high bitumen saturations. Fluid movements into or from

Data pads in unconventional plays have shown significant value when they are carefully designed to tackle specific problems or concerns. This includes the use of diagnostics to cross-validate development concepts such as stimulation design, well architecture, frac and well spacing, and numerous other variables. In this paper, it is demonstrated how various diagnostics technologies together with subsurface data can be used to calibrate a frac model. The model can then be coupled with a reservoir simulator to accelerate completions concept select decisions in unconventional plays. This process (a) eliminates multiple field trial costs, (b) tests different completions and stimulation designs, and (c) assists in de-risking various field development planning scenarios. This paper focuses on a real-life case-study where integrated diagnostics and modeling were applied to de-risk multiple completions scenarios. An intermediate planar frac model was calibrated and used to lower the uncertainty of key frac parameters including frac geometry and conductivity. In addition, subsurface parameters such as in-situ stresses and rock properties were tuned. The results from the integrated modeling effort were used to propose future development options for the play.

Conventional displacement methods such as water flooding do not work effectively in densely fractured reservoirs: due to the high fracture permeability it is not possible to establish significant pressure differentials across oil bearing matrix blocks to drive oil from matrix rock towards producers. In such reservoirs one has to rely on natural mechanisms like capillary imbibition or gravity to recover oil from the matrix reservoir rock. In Middle-East fractured carbonates, the matrix rock is commonly oil-wet or mixed wet and only gravity drainage remains a feasible process. However, permeabilities are usually low, <10 mDarcy, resulting in low gravity drainage production rates with high remaining oil saturation and/or capillary holdup. EOR techniques such as steam injection and miscible gas injection have the potential to improve GOGD rates and recoveries:In shallow fractured reservoirs it is possible to inject steam in the fracture system. Steam will condense as long as it contacts cooler matrix rock, resulting in a steam front that develops in a stable way through the fracture system. Heating of the matrix will result in oil expansion, reduction of viscosity, gas drive and stripping effects.In deeper reservoirs GOGD under miscible conditions becomes an option. Injection gas that is miscible with the oil will result in swelling and viscosity reduction, both increasing oil mobility and therefore improving the GOGD rates. Miscibility further adds the advantages of single-phase flow at high effective relative permeability and reduced interfacial tension, thereby reducing re-imbibition effects and increasing ultimate recovery from inhomogeneous reservoirs. To assess the benefit of these EOR methods, simulation techniques should be capable of modelling the impact of these processes on GOGD. We present in this paper a general dual permeability method that can handle GOGD as well as different, mutually interacting, processes expected to occur when EOR techniques are applied to fractured reservoirs. 1. Introduction The connected fracture network in densely fractured reservoirs has a strong impact on reservoir displacement mechanisms. Conventional displacement methods such as water flooding do not work effectively: due to the high fracture permeability it is not possible to establish significant pressure differentials across oil bearing matrix blocks to drive oil from matrix rock into the fracture system. In densely fractured reservoirs one relies on mechanisms like capillary imbibition or gravity to recover oil from the matrix reservoir rock. In the Middle East fractured carbonates are commonly oil wet or mixed wet, and the main production mechanism is gravity. Once a gas cap is established in the fracture system, the oil will drain down the matrix rock driven by gravity and into the fracture system at flow barriers. In the fracture system the oil forms a (thin) rim that can be produced. Production rates achieved with this GOGD (Gas Oil Gravity Drainage) process are often low due to low matrix rock permeabilities, capillary hold-up and re-imbibition effects. Capillary hold-up also negatively impacts ultimate recovery.