ABSTRACT: The main goal of this research was to investigate the risk of caprock failure due to the SAGDOX process, a hybrid steam and in-situ combustion recovery process for oil sands. A temperature dependency extension to the linear and non-linear constitutive models was developed and implemented in the GEOSIM software. The analysis has shown that there is no increased risk of caprock failure for SAGDOX process compared to SAGD. The study has shown that the overlying Wabiskaw formation experiences shear failure during both SAGD and SAGDOX due to its low initial cohesion, friction angle and proximity to pressure and temperature front, although the failure was mainly driven by pressure propagation. However, Clearwater shale above Wabiskaw can still provide proper zonal isolation to the steam/combustion chamber under SAGDOX operating conditions. Uncertainty in the analysis is due mainly to the sparse nature of geomechanical properties data for the oil sand reservoir and the caprock formations, especially at temperatures over 200 C.
1.1 The SAGDOX process
Nexen Energy ULC (Nexen) has been evaluating SAGDOX - a post SAGD oxidation process (Kerr, 2012; Jonasson and Kerr 2013) - to improve the recovery and project economics of its Long Lake SAGD operation. SAGDOX is meant to be used after several years of SAGD operations when the bitumen between two SAGD well-pairs is mobile. In SAGDOX process (applied to a row of parallel well pairs) oxygen is coinjected with steam in every other SAGD injector well and starts an oxidation process by reacting with residual oil around the injection well. At this point the SAGD production well below the oxygen-steam injector is shut in and steam along with oxygen and combustion gasses fill the steam chamber voidage and push hot bitumen towards the neighbouring SAGD well-pair. The neighbour injection well is also shut-in and could be converted to a producer if need be. Various other well arrangements have been considered including those with vertical injection wells and infill horizontal production wells. Since oxygen is co-injected with steam, very high oxidation temperature of a pure combustion process are not generated as steam carries a large portion of the heat of combustion away from reaction front and temperatures are thereby moderated. Nonetheless, temperatures in the range of 400-600 deg C are expected in the oil sand zone. The high temperature combustion front where the oxidation reactions are active moves away from the oxygen injection wells as the residual oil left behind after steam displacement is consumed. The high temperature reaction zone has a tendency to move upward towards the cap rock under the influence of gravitational forces.
Flow assurance is a critical problem in the oil and gas industry, as an increasing number of wells are drilled in deep water and ultra-deep water environments. High pressures and temperatures as low as 2° C in these environments hinder flow of hydrocarbon-based fluids by formation of methane hydrate and wax. Commonly used methods for flow assurance in flowlines are chemical injection and direct electric heating which face several limitations. In this paper, an application to use superparamagnetic nanoparticle-based heating for flow assurance, in the form of a magnetic nanopaint is presented. Superparamagnetic nanoparticle-based heating has been extensively researched in the biomedical industry for cancer treatment by hyperthermia. Superparamagnetic nanoparticles in dispersions generate heat by application of an oscillating magnetic field as explained by Neel’s relaxation theory. In our application, superparamagnetic Fe3O4 nanoparticles are embedded in a thin layer of cured epoxy termed ‘nanopaint’. This nanopaint coating on the internal surface of subsea flowlines could generate heat and thus prevent formation of methane hydrates and wax.
In this paper, parameters affecting heating performance of superparamagnetic nanoparticles such as particle size, and magnetic field and frequency are discussed. Rigorous characterization of nanoparticles and nanopaint performed using VSM, TEM etc., is used to quantify heating performance and optimize it. Heating performance of two samples of Fe3O4 nanoparticles varying in size distribution is evaluated in batch experiments and compared to Neel’s relaxation theory. Performance of nanopaint to heat static/batch fluids and flowing fluids is evaluated. Heating performance of superparamagnetic nanoparticles in dispersions and in nanopaint is found to be similar and so it is concluded that Neel’s relaxation theory is applicable to nanopaint. Heating performance of nanopaint is flow experiment is found to be better than in batch experiments by a factor greater than 5.
Flow assurance is the ability to transport hydrocarbon-based fluids economically and safely from the reservoir to production facilities, over the life of the field. With increasing oil and gas production from deep-water and ultra-deep water wells, flow assurance has become a critical problem for the oil and gas industry. Subsea wells are at greater risk of deposit formation due to low temperatures and high pressures in deep water environments. Methane hydrate formation and wax deposition severely limit production rates, pose safety concerns and may also result in the shutdown of the well. Hence various methods are employed for remediation and prevention of flow assurance problems, primarily relying on the principles of temperature increase, pressure reduction or mechanical removal. These methods include use of pigging solutions, chemical additive injection, SGN (nitrogen steam generation) process, direct electric heating, heated pipe-in-pipe (Hpip) solutions and have been previously summarized in . Commonly used methods in the industry are chemical injection and direct electric heating. In chemical injection, a glycol usually methanol is injected into the pipeline to lower the hydrate formation temperature. However, high costs and concentration limits imposed by quality control limit their usage. In direct electric heating, electricity is forced through tracer cables laid along the length of the flowline. Temperature can be controlled by varying the power input to the system and variable heating rates can be obtained. However, there is risk of electricity leakage and component failure due to excessive heating. In this paper, we use superparamagnetic nanoparticle-based heating to address the issue of flow assurance.
A continued increase in energy demand has amplified the significance of commercial heavy oil and bitumen recovery from complex carbonates formations such as the Grosmont Formation (OOIP ~ 406.5 billion barrels) in Alberta, Canada. To facilitate commercial development of bitumen carbonates, we have designed reservoir simulation models of complex carbonate reservoirs based on the concept of multiple interacting objects. Spatial distribution of different objects including fractures, vugs, breccia, and matrix are constructed by using stochastic methods with intensity functions derived from cores, logs, drilling and geologic data. Thermal reservoir simulations are conducted directly on realizations of these 'objects network' reservoir models. Although data from the highly fractured, karstified and vuggy bitumen-rich Grosmont Formation is used in this paper, this methodology is generic and applicable to other complex carbonate reservoirs. Results suggest that continuous type steam-based enhanced oil recovery (EOR) such as steam-assisted gravity drainage (SAGD) may not be best suited for bitumen recovery from complex carbonates.
The ultimate aim of reservoir characterization is to construct a representative spatial quantification of storativity (porosity), hydraulic conductivity (permeability), and fluid phase saturations. In highly complex carbonates where fractures, vugs, matrices, and karsts contribute to recovery performances, reservoir models must sufficiently represent the heterogeneity in hydraulic corridors (described here as object clusters) to accurately predict fluid breakthrough and ultimate recovery for different EOR technologies. Unfortunately, the 'forward modeling' approach (which focuses on understanding drivers that generated fractures by analyzing parameters such as stress distribution, fracture height, fracture spacing) often used by geoscientists for characterizing naturally fractured reservoirs (NFR) of sandstone matrix is seldom sufficient for carbonates. This is primarily due to the complex process of diagenesis inherent in carbonates. As a result, a systematic combination of the 'forward modeling' approach to the 'inverse modeling' approach (this approach focuses on understanding the responses created by fractures such as productivity heterogeneity, breakthrough, and channelized flow) is favored for the Grosmont carbonate reservoir. There are seldom sufficient data for complex carbonates, especially because of the difficulty to obtain consolidated sample representative of the tremendous heterogeneity. Although the emergence of tools such as the Formation Microimager (FMI), Computed Tomography (CT) scans, Scanning Electron Microscopy (SEM) and the improvements in traditional formation evaluation methods have contributed to increasing data availability, effective integration of data at different scales is extremely important to derive value from these measurements. Although statistics derived from wellbore (typically from vertical wells) measurements provide insight into the vertical distribution of properties such as fracture geometry, fracture length, fracture orientation, vugs, karsts; spatial distribution of these properties can be constrained by the knowledge of larger (km) scale correlations. As an example, previous studies suggest that a good large (km) scale lateral continuity of facies exist for the Grosmont Formation (Edmunds et al., 2009). Geologic studies have also described the predominant location of large karsts (nearer the sub cretaceous unconformity), (Hans et al., 2012). Therefore, in addition to well data, larger scale seismic and geologic data offer increased data control points thereby reducing the uncertainty in the developed model. Analysis of early pilot tests (Ezeuko et al., 2013) indicates a reasonable-to-high injectivity, suggesting a high degree of communication between high conductivity (mostly fractures, vugs, and karst) object clusters.
Stochastic optimization based on a simulated annealing method were carried out to determine the optimum steam and steam-solvent flooding strategies in thin (4 m) heavy oil reservoir both in the absence and presence of a bottom water zone. The steam injection pressure optimization case determined a technically feasible operating strategy. However, the cumulative energy to produced oil ratio (cEOR) realized from the optimized process is high. In comparison, the solvent-aided steam optimization case achieved an operating stratety that obtains a much lower cEOR and cumulative water-to-oil ratio (cWOR) than those in the optimized injection pressure-only strategy. We observed that a solvent channel forms at the top of the reservoir after breakthrough of solvent to the production well. The formation of the solvent channel led to oil-solvent mixing at the periphery of the channel as well as heat transfer to oil beyond the channel, which leads to better recovery performance. In the the presence of a bottom water zone, the optimized steam injection pressure optimization strategy was found to perform poorly. However, the optimized solvent-aided strategy achieved superior economics. With solvent injection, the presence of the bottom water zone enhanced mixing of solvent and oil yielding better oil recovery performance.
In Western Canada, about 80% of heavy oil resources are found in reservoirs less than 5 m thick (Adams 1982). Although currently commercial thermal-based techniques such as Steam-Assisted Gravity Drainage (SAGD) and Cyclic Steam Stimulation (CSS) are highly successful for recovering bitumen and heavy oil from thick pay zone (> 15 m), their application in thin heavy oil (<6 m) reservoirs are generally not thought to be economically viable. This is due to the high steam-to-oil ratio (SOR) which caused by significant heat losses to the overburden relative the amount of heat delivered to the oil which renders the processes uneconomic. Cold production (CP) employs small energy input. However, the average recovery factor is typically low, usually, between 3 to 8% of the Original Oil In Place (OOIP) (Adams 1982). By employing so called Cold Heavy Oil Production with Sand (CHOPS) technique, the recovery factor can reach as high as 15% (Pan et al. 2010). However, the formation of wormholes during CHOPS operation creates new challenges for applying follow-up processes to recover additional oil beyond CHOPS.
Bachman, Robert Clayton (Taurus Reservoir Solutions Ltd) | Walters, Dale A. (Taurus Reservoir Solutions Ltd) | Hawkes, Robert (Pure Energy Services) | Toussaint, Fabrice Luc (Dinova Petroleum) | Settari, Tony (U. of Calgary)
Industry is currently using mini-frac analysis for the determination of fracture closure stress and after-closure reservoir properties. The foundation of all mini-frac analysis is the one dimensional Carter leak-off model, which leads directly to the concept of G Time. For 30+ years, G Time (or the G function) has played the dominant role for the determination of closure stress. The current norm uses combination G function and combination square root Dt plots for closure pressure determination. Each combination plot has three plotting functions associated with it. These combination plots also allow the identification of non-ideal behavior. Additionally, various log-log derivative techniques based on pressure transient analysis concepts have been developed to act as a guide for determining flow regimes and closure pressure. These PTA based techniques also allow the determination of after-closure flow regimes and properties. Concurrently, various specialized after-closure plotting techniques have been developed for fracture/reservoir property determination.
Despite all these techniques, there remains ambiguity in performing mini-frac analysis. Part of the problem is that the recommended plots do not rigorously identify the various flow regimes that occur during a mini-frac fall-off. Mini-frac analysis requires a general theory that accounts for all of the actual observed flow regimes. A systematic approach based on pressure transient analysis (PTA) concepts has been developed to identify the various flow regimes (Carter leak-off being only one of them). The starting point is the Bourdet log-log derivative plot, accompanied by the primary pressure derivative (PPD) function. It will be shown that the PPD on its own has independent flow regime identification capabilities. Once specific flow regimes have been identified, specialized log-log plots can be constructed for further flow regime verification. New combination plots are then developed for each flow regime to further assist in closure pressure determination. The theory will first be developed and illustrated with various example problems.
Nolte (1979) introduced the first rigorous technique for determining closure pressure using the Carter leak-off assumption coupled with material balance within the fracture. This led to a special time function called G Time. Nolte (1986) further extended this work to account for different fracture geometries. These analysis techniques were the beginning of what is now referred to as before-closure analysis. Closure pressure was determined by linear plots of p versus G. Deviation from straight line behavior indicated the closure pressure. Practical difficulties of where to draw the straight line often occurred. This is the analogous situation that occurred in welltest PTA for determining the correct straight line on the Horner plot. For PTA the situation was resolved by Bourdet et al. (1983) with the Bourdet log-log pressure derivative plot. This plot allowed for flow regime identification, reservoir properties determination and defining the time range over which straight lines could be drawn on other specialized plots to complete the analysis.
A discussion of the paper is included in the pdf file, and is available as a separate supplementary document. The discussion is authored by D.P. Craig, Halliburton, R.D. Barree, Barree & Associates, and M. Ramurthy, Halliburton.
4D seismic imaging requires extensive time to setup, implement, and process to provide information on the progress of recovery efforts such as estimates of the size and shape of reservoirs and their internal artifacts. Conventional seismic imaging results in a resolution on the order of tens of meters. As an alternative, white noise reflection processes use sub-noise signals to image reservoirs and can potentially do this at scales below 1 meter.
Both simulations and lab experiments show that reflections from white noise processes can be used advantageously to localize discontinuities and track their movement through media. For example, for steam-based oil sands recovery processes, it is critical to have an understanding of the steam conformance to improve the efficiency of the recovery process. White noise signaling technologies can be used to monitor the spatial distribution of fluids e.g. a steam chamber interface, and objects e.g. shale layers and concretions, at higher frequencies resulting in finer resolution in real-time compared to conventional methods.
The results demonstrate that acquisition and ranging of discontinuities in the laboratory can be achieved at the centimeter scale. The methods are extended to concurrent use of multiple transducers to improve directionality and triangulation of discontinuities.
Among of the new inventions on thermal recovery, Fast-SAGD was introduced as the next generation of SAGD with greater amounts of bitumen and lower injected steam. However, there are still many suspicions about the successful of this technology such as the incremental bitumen recovery of Fast-SAGD is from the SAGD production well or combined with the offset well? It is very difficult to conclude that Fast-SAGD is better than conventional SAGD when numerical simulation of two processes was conducted in different well pattern as well the amount of operated well.
This paper presented a comparative evaluation between conventional SAGD and Fast-SAGD in three typical formations (McMurray, Clearwater, and Bluesky) of Alberta's Oil Sand. Three reservoir models with over one hundred numerical simulations under various operation conditions were developed to achieve the most unprejudiced comparison between two recovery processes. The simulation results proved that significantly recoverable bitumen was originally produced from offset well in Fast-SAGD system and leads to higher recovery factor. But, there is only slight increase in cumulative oil recovery when two processes were performed in same pattern with similar number of production wells. The result also indicated that the difference of 10kPa between steam injection pressure and reservoir pressure in literature is not enough for both SAGD and Fast-SAGD operations. And then, this study presented a numerical investigation for evaluating the potential applicability of Fast-SAGD recovery process under complex reservoir conditions such as shale barriers, thief zones with bottom and/or top water layers, overlying gas cap and fracture systems in Clearwater formation.
Cold heavy oil production with sand (CHOPS) is widely used as primary recovery method for heavy oil in western Canada. This process involves sand production in massive amounts. Sand production creates high permeability zones (wormholes) which extend the drainage radius. Typically 5-10% of the OOIP is recovered by this process. Therefore, the need to find a follow-up process is paramount.
The objective of this work was to experimentally evaluate the potential of using cyclic CO2 injection for recovering additional oil from depleted foamy oil reservoirs. A total of five depletion tests were conducted in a two meters long sand-pack kept in a vertical orientation. The primary depletions at different depletion rates were followed by one or two huff-n-puff cycles of CO2 injection.
The total recovery factor after cyclic CO2 injection reached 30% indicating the potential of solvent injection as a secondary oil recovery method. Interestingly, the recovery after the cyclic CO2 injection was more or less independent of depletion rate used in the primary production. It was found that the cyclic CO2 injection was more efficient when the primary depletion was at slow rate and resulted in lower primary depletion recovery.
The results of this study show that it may be possible to re-energize the depleted heavy oil reservoirs by injecting CO2, especially those that did not give high recovery factors during the primary depletion.
The unusually high primary recovery factors observed in many heavy oil reservoirs are often attributed to foamy oil flow, i.e. the non-Darcy flow involving formation and flow of gas-in-oil dispersion. It occurs when the wells are produced aggressively at high drawdown pressures that lead to conditions in which the viscous forces become strong enough to overcome the capillary forces in pushing dispersed bubbles through pore throats. The role of gravitational forces in generating such dispersed flow has not been adequately studied. This work was aimed at evaluating the contribution of gravitational forces in primary depletion of heavy oil formations under foamy flow conditions.
Primary depletion tests were conducted in a 200 cm long sand-pack that was held in either horizontal or vertical orientation. The results of horizontal depletion tests were compared with the depletion tests conducted with the sand-pack in vertical direction. Vertical depletions showed better recoveries at slower depletion rates compared to horizontal depletions.
The recovery factors of both horizontal and vertical depletions were correlated against the average drawdown pressure available to move the oil. It was found that the recovery factor show a strong dependence on the average drawdown pressure. It was also found that the curve of recovery factor versus average drawdown pressure moves slightly towards higher recoveries in the presence of an added foaming agent which increases the oil foaminess.
In western Canada, there have been more than 300 heavy oil waterflooding projects. Most of these projects displayed good economical and efficient variability even though they were operated in marginal pools. Although waterflooding of heavy oil has almost 50 years history, its mechanisms, especially in the situation of high oil water viscosity ratio, are still not well understood. In the situation of high viscosity ratio, fractional flow theory does not work because of severe water fingering and other mechanisms that are different from conventional waterfloods. The operation strategies of heavy oil waterflooding, such as water injection rate, injection pressure and VRR, are still under controversy.
In a water-wet environment, waterflooding (water displacing oil) represents a process of water imbibition. In this paper, the water imbibition mechanisms and their effects on the heavy oil recovery are studied using a water-wet micromodel. The effects of time, viscosity ratio and water injection rate on the imbibition rate are also studied. The imbibition rate of water was found to be proportional to the reciprocal of the square root of time, and inversely related to oil viscosity. The effects of injection rate on imbibition rate are complicated. At low injection rates, waterflooding becomes more efficient, and significant volume of oil is produced discontinuously. Images of the imbibition process were recorded and analyzed from visual micromodel studies. Water broke through quickly because of water fingering, and a considerable portion of recovery comes from post-breakthrough production of oil, under high water cuts. In the cases of low rate water injection, water imbibed into the original oil region perpendicularly to the water channel. In this stage, capillary imbibition was a key factor. Water film thickening and snap-off were the two main mechanisms that made water imbibition work. Emulsification was also another important mechanism observed, with W/O emulsions primarily being formed.