The focus of this paper is innovation in oil sands recovery technology. Canada hosts the third largest reserves of petroleum in the world, mostly in heavy oil/oil sands reservoirs. The two commercial in situ recovery technologies, Cyclic Steam Stimulation and Steam-Assisted Gravity Drainage, were both invented >30 years ago; both use large amounts of water and emit carbon dioxide. Industry is facing a critical point where it is imperative to find new technologies. It has been a significant challenge to find new processes with large reductions of water and carbon dioxide emissions. Another critical issue is adoption time scale - in the past, new technologies have taken 10-20 years to become commercial - this pace must be accelerated. The oil sands industry needs to improve the innovation cycle of oil sands extraction technologies. The objective here is to understand how to do this, to describe factors that encourage and discourage innovation, and to recommend strategies to enable and stimulate non-incremental innovation. It is interesting to note that despite only a few oil companies still having research laboratories and permanent research staff, abundant potentially inventive scientific, engineering, and management staff exist in oil companies. So the question becomes: what is preventing them from developing a plethora of inventions and bringing creativity to issues confronted by the oil sands industry? It does not appear to be only a technical issue but also a social one. Market, resource, and social issues lead to this result: most petroleum funding directed at near market iterations, short term incentives (increasing shareholder value), government funding matched to current industry activity and thus linked to market forces, low funding levels, culture of risk adversity and fear of risk, innovation curbed by regulatory factors or internal work overload, and high costs due to investment, variable resource quality, high capital costs, and oil price volatility.
Given its water consumption and greenhouse gas emissions to the atmosphere, it is critical to optimize the steam injection strategy and steam conformance in steam-based oil sands recovery processes such as cyclic steam stimulation and steam-assisted gravity drainage to minimize the steam-to-oil ratio and maximize the cumulative oil volume produced. Given the heterogeneity of oil sands reservoirs, robust adaptive oil sands processes which respond to the system to continuously shift the operation towards desired operational objectives are desired. This kind of adaptive control can be achieved by proportional-integral-derivative (PID) control. PID automated control is a relatively simple method to control well operations in thermal processes by using observed data already measured in existing steam-based recovery processes. Here, a vertical-horizontal hybrid well configuration within an oil sands reservoir, with reservoir properties previously tuned by a history-match to field data, is operated under PID control to demonstrate that automated control can yield improvements of recovery process performance. Here, the well configuration consists of multiple vertical injectors and a few horizontal producers - early in the process, cyclic steam stimulation is initially done in the vertical wells to establish thermal communication within the reservoir. After sufficient communication is accomplished, the steam is injected into the vertical wells and fluids are produced through the horizontal wells in a steam-assisted gravity drainage mode. Automated control must accomplish thermal communication between the vertical and horizontal wells and thereafter the steam must be controlled to minimize the steam-to-oil ratio and maximize the oil rate. The results demonstrate that PID control can be used to improve the cSOR and volume of oil produced.
It has been shown that the performance of a Steam-Assisted Gravity Drainage (SAGD) well pair is affected by its orientation and position within a point bar. In typical commercial operations, multiple wellpairs, usually arranged parallel to each other, are arranged in pads within oil sands reservoirs. Thus, the overall performance of the recovery process in a point bar is not that of a single well pair but reflected by oil accumulation differences, interactions between well pairs (pressure and fluid flow), and how the well pairs interact with the structure and geometry of the point bar including the arrangement of inclined heterolithic strata relative to the SAGD well pairs. This research describes how the point bar structure impacts the performance of a pad of SAGD wellpairs and the impact of pad orientation on performance of the pad. The results show that the performance of well pairs in a SAGD pad are affected by the orientation of the pad within the point bar. Also, the results show that the variability of the performance of the well pairs within the pad is large and thus, single well pair models do not provide sufficient analysis of process performance due to the heterogeneity of the point bar. In other words, pad-scale models are required for recovery process evaluation and design.
The Steam Assisted Gravity Drainage (SAGD) process is widely used in the Athabasca oil sands deposit to recover bitumen. Since the viscosity of bitumen is high at original reservoir conditions, heat is required to lower its viscosity to the point it becomes mobile enough to be recovered under gravity drainage. To heat the reservoir, steam is injected into the formation and thus SAGD is energy intense - on average, the steam-to-oil ratio (SOR) is equal to about 3.5 m3 (expressed as cold water equivalent) of steam injected per m3 of bitumen produced. Given that the fuel used to generate steam is the largest operating cost, the SOR is a key parameter for evaluating the economics of any SAGD project. The target for many SAGD operations is a SOR lower than 2.5 m3/m3. Here, we explore the use of dynamic distributed steam injection within a pad of SAGD wellpairs controlled via a Proportional-Integral-Derivative (PID) feedback controller, a concept we refer to as Smart Pad. The Smart Pad Reservoir Production Machine is designed to dynamically distribute steam injection along multiple well pairs so that over a period of operation, the pad-scale cSOR is dynamically improved as the process evolves. First, a method to condition the PID control gains is described and second, the controller is applied to a multiple well pair SAGD pad in an oil sands reservoir with a top water zone. The results demonstrate that automated control can lead to improvements of the SOR over that of constant pressure. The results show that automated PID control is able to detect the "sweet spots?? (oil zones with better geological properties) in the reservoir and dynamically deliver more steam to that region. Meanwhile, it reduces the steam injection towards relatively worse reservoir quality zones, i.e. shale barriers, high permeability channel to the top water zone, to lower the local SOR. In this manner, the PID feedback controller provides an efficient method to recovery bitumen in SAGD operation, especially during the first 7-10 years' operation, where it helps to achieve a relatively low cSOR and maintain a normal level of oil recovery. Also, the PID controller reduces the degree of dependence of SAGD operation on the geological conditions of the reservoir. The algorithm described could be applied to any operating or new SAGD pad.
Carbonates contain more than 50% of the world's known hydrocarbon resources. Although natural fractures are a common feature in carbonates and they can improve primary production from tight matrix carbonates, they pose a unique challenge for enhanced oil recovery (EOR) from heavy oil and bitumen (HOB) carbonates. The current focus on 'energy mix' to sustain the world energy demand has once again put HOB carbonates in global spotlight. Among the known HOB carbonate reservoirs globally, the Grosmont carbonate in Northern Alberta contains the largest original in-place HOB (~406.5 billion barrels). However, the Grosmont carbonate poses the greatest development challenge of all other known HOB carbonates due to its petrophysical complexity. We recently published our progress towards developing a methodology for characterizing the Grosmont carbonate that is suitable for direct reservoir simulation. The objective of the current paper is to assess the performances of different steam-based EOR recovery technologies using multiobject reservoir models of the Grosmont. Our results show that simulations on appropriate reservoir models representative of the most hydraulically active objects produce a good account of heat and fluid flow in complex carbonates. Cyclic steam stimulation (CSS) in this paper describes steam injection below fracture pressure and can therefore be related to what has recently been presented in the literature as cyclic single well steam-assisted gravity drainage.
Cold Heavy Oil Production with Sand (CHOPS) is a non-thermal heavy oil recovery technique used primarily in the heavy oil belt in western Alberta and eastern Saskatchewan. Under CHOPS, typical recovery factors are between 5 and 15% with average ~10%. This leaves ~90% of the oil in the ground after the process becomes uneconomic. CHOPS exhibits an enhancement in production rates compared to conventional primary production, which is explained by formation of high permeability channels known as wormholes. The formation of wormholes has been demonstrated to occur in both laboratory experiments and field tracer studies. The ability to model growth of wormholes does not currently exist in commercial reservoir simulators. Here, wormholes are modelled as multi-lateral wells, which grow dynamically in the reservoir, using existing wellbore features. A module was coupled to CMG STARSTM to dynamically grow wormholes in the reservoir taking foamy oil flow, sand failure, and sand production into account. Here, we present on the results of history matches against field data to tune model parameters. The history-matched model reasonably predicts production trends of field CHOPS operations. The results provide a methodology to model CHOPS and predict under uncertainty where the wormholes will tend to grow into the reservoir. This provides a tool for placing new wells in the reservoir that will most likely not be in direct contact with existing wormholes. Multiple realizations of the reservoir can be used to mark the region of the reservoir that undergoes wormhole formation. The model can then be used for follow-up EOR processes such as cycle solvent injection as well as field scale optimization.
The Steam and Gas Push (SAGP) process was developed to improve the thermal efficiency of SAGD process. In SAGP, non-condensable gas is co-injected with steam into the reservoir. Ideally, the non-condensable gas accumulates at the top of the reservoir and provides insulation which reduces heat losses to the overburden. This means that lower SOR can be achieved at the same recovery factor. It remains unclear how energy is distributed and transformed within the chamber and its edges when non-condensable gas is added to the injected steam. In this work, we compare conduction and convection at edge of the steam chamber during SAGD and SAGP. The results show that both oil production rate and cumulative oil are reduced in SAGP compared to SAGD when 0.8 mole% NCG is co-injected with steam. This is because the injected NCG accumulates at the upper part of the leading edge of the steam chamber and slows down the growth of the steam chamber in that area, which results in lower cSOR but with a reduction of recovery factor. If 0.8 mole% NCG is co-injected at later periods of the operation, lower cSOR results without a significant reduction of oil production rates and cumulative oil production. In this case, the injected NCG migrates directly to the upper part of the reservoir and accumulates at the side edge of the steam chamber, since the steam chamber had already grown to the top of the reservoir. The added gas slows down lateral growth of the steam chamber in the upper part of the reservoir and forces steam chamber growth in the downward direction. From an analysis of energy transport in SAGP and SAGD operations, the results reveal the optimal timing for the onset of NCG co-injection with steam.
Expanding Solvent-Steam Assisted Gravity Drainage (ES-SAGD) was invented to enhance SAGD performance by reducing energy use while increasing oil production rates and recovery factor. ES-SAGD involves co-injection of solvent and steam. The majority of energy losses occur between the steam generator and sandface and at the top of the depletion chamber (to the overburden). ES-SAGD performance improvement is traditionally ascribed to oil phase dilution which in turn leads to oil phase viscosity reduction. However, the amounts of solvent added to the process are typically very small (< 5-6% by volume) thus it remains unclear how the solvent can lead to significant lowering of the steam-to-oil ratio (~25-50%) and large enhancements of the oil rate (~25 to 100%). Here, we report on how SAGD and ES-SAGD (hexane, heptane and octane solvents) can potentially perform in the presence of in-situ emulsification at steam chamber edge. We present a numerical approach which allows incorporation of emulsion modeling into SAGD and ES-SAGD simulations with commercial reservoir simulators via a two-stage pseudo chemical reaction. Numerical simulation results show excellent agreement with experimental data for low-pressure SAGD and ES-SAGD. Accounting for viscosity alteration, multiphase effect and enthalpy of emulsification appear sufficient for effective representation of in-situ emulsion physics during SAGD and ES-SAGD in very high permeability systems. Results also show that, in-situ emulsification may play a vital role within the reservoir during SAGD; increasing bitumen mobility thereby decreasing cSOR. It was concluded that traditional approach to numerical ES-SAGD simulation can significantly over-predict incremental oil recovery. Results from this work extend understanding of ES-SAGD by examining its performance improvement over traditional SAGD in terms of multiphase behavior at the edge of the chamber, thermal efficiency and incremental recovery. Results reveal that dynamics at the edge of the chamber is more complex than simple solvent dilution model.
Carbonate-cemented concretions in Grand Rapids oil sand reservoirs are common with length scales up to several meters wide and high. The concretions can be found embedded in unconsolidated oil sands distributed irregularly within the formation. From a Steam-Assisted Gravity Drainage (SAGD) recovery process point of view, calcite concretions are non-productive rock which can interfere with the growth of steam chambers. However, depending on the length scales of the spatial distribution, sizes, and shapes of the concretions, thermal dispersion can occur which can potentially enhance heat transfer within the oil sands formation. Thus, although calcite concretions are heat sinks that reduce the oil in place, they could potentially aid in steam chamber conformance. Heterogeneity of the SAGD steam chamber depends on the heterogeneity of the underlying geology. Here, the impact of spatial distributions and size of concretions on the performance of SAGD is examined. The temperature distribution (chamber growth) and steam chamber height and shape are examined. The results reveal that steam chamber growth and conformance is impacted by the presence of calcite concretions. Concretion nearer the SAGD wellpair have the largest impact since they interfere with steam chamber growth from the earliest stages of the process and the impact grows throughout the process yielding cold spots along the wellpair. This provides a means to decide length scales for placement of wellpairs to optimize chamber conformance and SAGD performance.
The creation and evolution of point bar systems is well understood in meandering river deposits. A large fraction of Athabasca oil sands deposits are ancient point bar systems characterized by bedded, sandstone-dominated strata with interbedded siltstone layers. The recovery process of choice for these deposits is the Steam-Assisted Gravity Drainage (SAGD) process due to the high viscosity of the oil, low solution-gas ratio, and often caps rock not sufficient to with stand injection pressures of Cyclic Steam Stimulation. However, because of the presence of siltstone interbeds, these reservoirs commonly have lateral and vertical lithological heterogeneity which interfere with the formation of uniform steam chambers along SAGD wellpairs. Other units in point bar deposits that impact SAGD chamber development within the formation include remnant channel succession and channel lag. The objective of this research is to construct a detailed three-dimensional point bar model to determine how its heterogeneity impacts SAGD performance. Here, the point bar model is based on the Lower Cretaceous Middle McMurray Formation in the Athabasca oil sands deposit in Alberta, Canada. Single SAGD wellpair submodels at different locations and orientations were extracted from the point bar model. The results of the reservoir models simulation suggest that attention must be paid to SAGD wellpair placement in point bar systems.