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Results
Characterizing Unconsolidated Heavy Oil Sands Using Cryogenic MicroCT - A Pilot Study from Kuwait
Ahmed, K.. (Kuwait Oil Company) | Ferdous, H.. (Kuwait Oil Company) | Jain, A. K. (Kuwait Oil Company) | Ahmad, F.. (Kuwait Oil Company) | Golab, A.. (FEI Oil and Gas) | Deakin, L.. (FEI Oil and Gas) | Young, B.. (FEI Oil and Gas) | Mascini, A.. (FEI Oil and Gas)
Abstract Conventional analysis on core plugs from unconsolidated heavy oil sands is challenging to perform. Sometimes doubts exist about whether the results are representative of the in-situ rock fabric. A digital rock pilot study was designed to provide unique data to understand the rock and allow independent verification of laboratory data, such as calculated petrophysical properties, characterization of damage associated with coring and preservation, direct imaging of oil distribution and pore-wall wettability, and characterization of pore types, clays, grains and grain contacts. The pilot study presents successful cryogenic helical X-ray micro-computed tomography (microCT) of preserved plugs maintained in the frozen state throughout the imaging process. Those 3D images were processed to calculate porosity and absolute permeability. Direct imaging of oil distribution by 3D microCT, with X-ray contrasting agents to highlight the oil with complementary characterization of pore-wall wettability by secondary electron Field Emission Scanning Electron Microscopy (FESEM) is presented to confirm observations from the 3D microCT imaging. Finally, Back scattered SEM (BSEM) imaging and automated, quantified mineral mapping are presented. The 3D tomograms from cryogenic microCT imaging were analysed based on morphological characteristics to identify damaged zones, representing >30% of the volume. The calculated absolute permeability of those 3D tomograms ranged from 8.50D to 24.8D across the plug. The undamaged region had distinctly lower kabs (average = 9.71D) than the most damaged region (average = 21.6D), compared to measurements by a traditional laboratory on adjacent screened and cleaned plugs reported as >20D. The oil saturation from direct microCT imaging was 76.3%, compared to conventional core analysis of oil saturation on a sister plug (62.1%). The 3D images show oil filling most of the open pores and the pore-filling and porous minerals. Furthermore, the oil appears to be in direct contact with the mineral grains, indicating that oil is the wetting phase. Wettability imaging by FESEM confirmed that the majority of the mineral surfaces are oil-wet but the layers of asphaltenes are thin. The mineral composition is dominated by quartz (81%) and feldspar (16%) with some minor clay (1.7%) and carbonate (0.3%). The mineralogy indicates that the sample is likely to be unreactive to steam and/or chemical stimulants.
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Mineral > Silicate (1.00)
Abstract Solvent injection alone, or in combination with steam, is currently receiving considerable attention as an emerging in-situ oil sands technology in Alberta. The goal of solvent and steam assisted recovery processes is to reduce energy consumption and greenhouse gas emissions over the use of steam alone. Pilot studies in the field indicate a significant difference between reservoir simulation predictions, and field performance and previous studies have demonstrated that the assumption of instantaneous equilibrium is not valid for solvent-bitumen interactions and can introduce significant inaccuracies to the modelling results. In addition to assuming non-equilibrium, this study seeks to determine the mechanism of solvent dissolution in bitumen and the expected improvement in oil recovery, if any, when a solvent is injected with steam. The unique aspect of this work is that instantaneous phase equilibrium is not assumed, as is typical of numerical simulations for solvent-steam applications. Partial equilibrium was not based on an empirical factor or concept. Rather, this study bases phase equilibrium on an analytical model of the dissolution and mobilization of a drop of bitumen inside a pore, by solvent and heat. The analytical solution indicates that the time required for a drop of bitumen to mobilize towards the production well is at least three times greater for solvent via diffusion and dispersion than by heat conduction. The analytical solution was developed for solvent injection, heat injection, and co-injection for several boundary conditions. The single drop model is built into a new thermal compositional simulator developed for this study. Thermal solvent injection processes were investigated for non-equilibrium phase behaviour. The results were compared with the case of instantaneous equilibrium, showing the reason for the previous lack of accurate predictions for solvent injection in oil sands reservoirs. The results and extensions of this work will be of interest in heavy oil production because they serve to explain the unexpected performance and frequent lack of success of these processes. This model is capable of precisely predicting solvent injection concentration, flow rate, and recovery at the field scale, making it possible to determine whether or not solvent injection is appropriate in any given situation.
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Facilities Design, Construction and Operation > Unconventional Production Facilities > Oil sand/shale/bitumen (1.00)
Successful 1st Eocene Carbonate Reservoir Steamflood Pilot Mitigates Key Technical Uncertainties for Full Field Development of Wafra Field, PZ Kingdom of Saudi Arabia & Kuwait: Part 2 Simulation Model Validation
Kumar, Raushan (Chevron Corp) | Brown, Joel (Chevron Corp) | Lolley, Chris (Chevron Corp) | Barge, David (Chevron Corp) | Bartlema, Ruurd (Chevron Corp)
Abstract This paper describes the key learnings from detailed data analysis and the application of a probabilistic workflow to achieve a validated dynamic simulation model of the large scale pilot (LSP) that was successfully completed in the 1st Eocene reservoir in the Wafra field, PZ. The development of the validated dynamic simulation model was a key success measure identified for the pilot to assist in the broader Wafra full field steamflood development decision making process. The pilot consisted of sixteen 2.5 acre inverted 5 spot patterns (16 injectors and 25 producers) with associated steamflood and production facilities. In the execution of this work, detailed analysis of production, pressure, temperature, oil viscosity and geochemical data was conducted to develop key insights into the pilot behavior. A 1 Eocene LSP steamflood model was successfully validated with production and injection data through the primary and steamflood periods. The validation method took into account uncertainties in static and dynamic properties. A probabilistic methodology using design of experiments on uncertainty parameters, combined with error-filters on multiple responses of rates, pressure and temperature was used in the study. The confidence in the final validated model was high with excellent agreement achieved between pilot and model data. The validated model also captured regional behaviors observed in the production data analysis. The validated model captured both pre-steam and post-steam behavior in the pilot. The successful execution of this work has resulted in an estimate of carbonate steamflood recovery possible in the 1st Eocene reservoir in Wafra.
- Geology > Geological Subdiscipline > Stratigraphy (0.69)
- Geology > Geological Subdiscipline > Geochemistry (0.68)
- Geology > Rock Type > Sedimentary Rock (0.68)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.48)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.67)
- Asia > Middle East > Saudi Arabia > Saudi Arabia - Kuwait Neutral Zone ("Partitioned Zone") > Arabian Basin > Widyan Basin > Wafra Joint Operations Block > Wafra Field (0.99)
- Asia > Middle East > Qatar > Arabian Gulf > Rub' al Khali Basin > Umm Er Radhuma Formation (0.99)
- Asia > Middle East > Kuwait > Saudi Arabia - Kuwait Neutral Zone ("Partitioned Zone") > Arabian Basin > Widyan Basin > Wafra Joint Operations Block > Wafra Field (0.99)
Abstract Outflow Control Devices (OCDs) are commonly used in SAGD horizontal injection wells to enhance steam distribution in the well and facilitate uniform heating of the reservoir. Multiple devices are positioned in the tubing string across the horizontal portion of the well to create the desired steam distribution. Most OCD designs incorporate a sliding sleeve which is run in the closed position to allow steam to be circulated through the well. Circulation continues until sufficient injectivity can be achieved, allowing for bullhead steam injection. Post circulation, the sliding sleeves require coiled-tubing intervention to shift the sleeves open, activating the OCD. The subject method applies existing technology from horizontal multistage ball-activated completions to tubing deployed SAGD OCDs to eliminate the requirements for the initial coiled-tubing well intervention. The ball-activated OCDs are activated by pumping degradable balls from surface to land in the OCD. Once landed, the tubing is pressured up to the predetermined shifting pressure, the sliding sleeve shifts open, and the ball disengages from the seat and continues to the end of the tubing string. This process is repeated with progressively larger balls for all the installed OCDs. Product qualification has been completed to ensure SAGD service requirements are achieved. This includes ball degradation tests in boiler feed water, flow loop ball shift testing at ambient and elevated temperature, and mechanical tool shifting tests. The results of this testing are shared. Through the elimination of the coiled-tubing intervention, significant operational efficiencies and cost savings are anticipated. In addition, the expected efficiency gain will minimize well down-time, resulting in less reservoir cooling and impact to production.
- North America > United States (0.28)
- Asia > Middle East (0.28)
- North America > Canada > Alberta (0.15)
Abstract A solvent enhanced steam drive pilot in the Peace River area in Canada was executed over a period of two years on an inverted 5-spot pattern to evaluate bitumen uplift and solvent recovery. Data quality and uncertainty management were used to assure conclusive results for the pilot; in particular, this paper focuses on how sampling played a key role in providing conclusive results. Especial focus is provided to the design, performance, execution, and learnings from the use of the automatic proportional samplers which was particularly challenging, considering their novel use on heavy oil production containing abrasive material such as sand and H2S. Moreover, to determine solvent production, several newly developed algorithms were tested to split the solvent and bitumen compositions, since they overlap over a wide range of components. Results from the pilot show that significant errors and misinterpretations can occur while evaluating solvent recovery whenever the assumptions under the solvent-bitumen split algorithms are not checked against frequent sampling data. The pilot also provided best practices for the utilization of proportional auto samplers in heavy oil production in the presence of abrasive material inherent to in-situ production, and the sampling of gas streams with heavy condensate for the accounting of solvent production through casing vent gas.
- Asia (0.93)
- North America > Canada > Alberta (0.47)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Facilities Design, Construction and Operation > Unconventional Production Facilities > Oil sand/shale/bitumen (1.00)
Abstract Steam assisted gravity drainage (SAGD) is recognized as a profitable and stable approach to address the exploitation of heavy oil and oil sand resources. However, the efficiency of SAGD, a close relative of a sufficiently-expanded and uniformly-developed steam chamber, tends to be deteriorated by quick steam movement and high heterogeneity. Chemical additives and foam assisted SAGD (CAFA-SAGD) is a strategy proposed on this account. This study aims to analyze the mechanisms and phenomena involved. The injection of chemical additives to promote in-situ foam generation reduces gas relative permeability by slow-moving and stagnant bubbles trapping. Also, lamella resists bubbles flow and increases apparent gas viscosity. The restriction of steam mobility thus favors a sufficiently-expanded steam chamber and the nitrogen co-injected to stabilize bubbles works as a separator between steam and overburden to reduce heat loss. Simultaneously, the interfacial tension reduction due to surfactants injection at a water/oil interface may influence phase behavior, which further leads to the solubilisation of residual oil. CAFA-SAGD is thus likely to increase heat efficiency and add oil output. A homogeneous model is built to analyze CAFA-SAGD considering foam generation by snap-off and leave-behind, foam trapping in a porous medium and foam coalescence due to both the lack of surfactants and capillary suction. Besides, with the analysis of foam wall slip phenomena, a comprehensive foam property model is coupled to analyze shear thinning rheology and calculate lamella viscosity as a function of gas saturation and gas velocity. In addition, the influences generated by surfactant injection should be added. This study also develops an analytical FA-SAGD model based on Butler's finger rising model (1987) to show foam's effects on a steam chamber growth rate and shape. We derive the FA-SAGD model accounting for the retarded steam movement with higher steam viscosity and lower gas relative permeability. The foam viscosity is calculated as a function of gas saturation and a gas rate, and the modification of gas relative permeability is reflected with a higher gas residual saturation according to Bertin et al.'s foam property model (1998). After comparing, validating, and discussing the developed model against the SAGD model, we find that foam injection contributes to high production efficiency with less steam consumption. A lower steam mobility generated by stronger foam is more likely to have a lower SOR (steam-oil ratio). The results agree well with the published high-temperature steam foam experiments and pilot tests. Strong bubbles accumulate along the boundary of a steam chamber to restrict steam movement, while weak foam fills inside the chamber to enhance steam trap, contributing to a higher oil recovery factor and lower SOR.
- North America > United States (0.68)
- North America > Canada > Alberta (0.47)
- North America > United States > California > San Joaquin Basin > Kern River Field (0.99)
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin > McMurray Formation (0.99)
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin > Firebag Oil Sands Project > Wabiskaw-McMurray Formation (0.99)
Numerical Prediction of H2S Production in SAGD: Compositional Thermal-Reactive Reservoir Simulations
Ayache, Simon V. (IFP Energies Nouvelles) | Preux, Christophe (IFP Energies Nouvelles) | Younes, Nizar (IFP Energies Nouvelles) | Michel, Pauline (IFP Energies Nouvelles) | Lamoureux-Var, Violaine (IFP Energies Nouvelles)
Abstract Nowadays EOR methods such as thermal techniques are widely used to recover the viscous hydrocarbons from heavy oils and bitumen reservoirs. One of the thermal methods is the Steam-Assisted Gravity Drainage (also called SAGD), which consists in injecting steam into the reservoir to melt the viscous oil and allow its mobility. The melted oil falls by gravity to the production well. The injected hot steam, once it reaches the heavy oils/bitumen, induces chemical reactions called aquathermolysis. These reactions generate gases such as hydrogen sulfide (H2S) or carbon dioxide (CO2). The H2S is known to be highly toxic and corrosive. Hence it needs to be given a particular attention when it is produced at the surface. Reservoir models have been built to simulate thermal effects during a SAGD process but only few publications in the literature deal with the aquathermolysis reactions occurring in reservoirs where steam is injected. This paper focuses on building a reservoir simulation model to forecast the H2S production. The example of the Hangingstone heavy oil field in Canada has been chosen. This simulation model is based on a compositional PVT description for heavy oil/bitumen and on a recently developed sulfur-based compositional kinetic model to describe the aquathermolysis reactions. The description of the heaviest components found in heavy oils/bitumen is made through a SARA decomposition. The reactive model that describes the aquathermolysis reactions is firstly presented. Then a section of this paper is dedicated to the building of a PVT model for heavy oil. Another chapter presents the 2D heterogeneous reservoir models used for the simulations. Finally the simulations results are presented. A sensitivity analysis has been performed to investigate the effect of the rock conductivity and the pressure/temperature of the injected steam on the H2S production. The different simulations have given consistent results with production data in terms of H2S production at surface. This shows that both the fluid description and the aquathermolysis kinetic model used in the study are relevant for the prediction of H2S production in the context of steam injection.
Abstract This paper presents the results of an experimental investigation to determine the mechanisms of pore plugging and permeability reduction near SAGD screen liners. The aim is to arrive at a liner design that maximizes wellbore productivity without compromising the sand control function of the liner. We set up a large-scale Sand Retention Testing (SRT) facility that accommodates a multi-slot liner coupon at the base of a sand-pack with representative grain shape and particle size distribution (PSD) of typical oil sands. Brine is injected at different flow rates and pressure differences across the coupon and the sand-pack as well as the mass and PSD of the produced sand and fines are measured during the test. Further, the PSD and concentration of migrated fines (<44 microns) along the sand-pack are determined in a post-mortem analysis. The testing results are used to assess the effect of slot size and slot density on the sand control performance as well as pore-plugging and permeability alterations near the sand-control liner. We observed that the slot size, slot density and flow rate highly affect the concentration and PSD of produced fines as well as accumulated fines (pore clogging) above the screen. For the same flow rates and total injected pore volume, wider screen aperture and higher slot density result in lower fines accumulation above the screen but more sanding. Further, the variation of slot density alters the flow convergence behind the slots, hence, the size and concentration of mobilized fines. Results indicate that higher fines concentration near the screen reduces the retained permeability, hence, lowers the wellbore productivity. This paper provides a new insight into pore plugging and fines migration adjacent the sand control liner. It also introduces a new testing method to optimize the design of sand control liners for minimum productivity impairment in SAGD projects.
- North America > United States (1.00)
- North America > Canada > Alberta (0.70)
- Geology > Mineral > Silicate > Phyllosilicate (0.47)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.36)
- North America > United States > Colorado > Spindle Field (0.99)
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin > McMurray Formation (0.99)
- Well Completion > Sand Control (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Thermal methods (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
Abstract Surface movement of a field under cyclic steam stimulation (CSS) is induced by the thermal processes used to extract bitumen from the reservoir. The ground movement can be related to reservoir dilation and compaction and provides a record of the effect of injection and production. Accurate monitoring of the ground deformation that occurs at a CSS field can be used to calibrate predictive models, show the effectiveness of steam injection, and demonstrate the impact of the recovery operation on the surface elevation. Accurate monitoring, however, requires the ability to consistently measure large non-linear changes in the surface height over relatively small areas. CSS sites can experience 20+ cm of surface heave in one month. The spatial extent of the ground movement is related to the well layout. Along short distances, 10s of metres, the ground movement (heave and subsidence) may be more than 2 cm. Interferometric Synthetic Aperture Radar (InSAR) uses radar returns from the ground to calculate very precise estimates of the ground change. In arid regions, InSAR can be used to capture a very high density of ground movement points. In this case, measurements with a density of approximately every 3 m are possible with the RADARSAT-2 satellite. The ground conditions in arid regions are ideal for radar observation. The ground conditions in the region of the Alberta oil sands are not ideal for InSAR monitoring. The amount of ground water, variations due to seasonal change, and the sparsity of effective radar reflectors led to the development of InSAR methods that employ installed targets (or corner reflectors). This methodology works very well to capture the relatively slow ground change associated with steam assisted gravity drainage (SAGD) operations. The same measurement process at a CSS operation would require an extreme density of corner reflectors. It would not be environmentally or economically feasible to install corner reflectors at a spacing of 75 m across a CSS operation. To improve the accuracy of InSAR surface elevation monitoring, we have created a new way of extracting deformation information from radar imagery. This has worked particularly well for the CSS process at the Primrose field. The methodology extracts the signal in high-noise conditions and dramatically increases the effectiveness of InSAR observations over a CSS field. The new InSAR methodology exploits the spatial and temporal characteristics of the radar images to produce a more robust estimate of the ground movement than had been possible previously. The wide-area InSAR measurements are compared to measurements from Global Positioning System (GPS) and to the net over injection (NOI) metric, which describes the amount of steam going into the reservoir less the amount of produced fluids. The GPS time series and the InSAR measurements show excellent agreement. The point source nature of the GPS data, however, restricts the spatial comparison that is possible. In this case, the NOI data shows the progression of injection / production spatially and temporally. The ground movement patterns from the NOI and the InSAR data are very similar. Increases in NOI are very highly correlated with surface heave. Subsidence seems to lag decreases in NOI slightly but is still clearly positively correlated.
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
Effects of Concentration-Dependent Diffusion on Mass Transfer and Frontal Instability in Solvent-Based Processes
Yuan, Qingwang (University of Regina) | Zhou, Xiang (University of Regina) | Zeng, Fanhua (University of Regina) | Knorr, Kelvin D. (Saskatchewan Research Council) | Imran, Muhammad (Saskatchewan Research Council)
Abstract Mass transfer plays a key role in affecting the efficiency of solvent-based processes in enhanced oil recovery. The mass transfer is usually very slow because of the pure molecular diffusion. However, it can be greatly enhanced by frontal instability when solvent is injected to displace oil. Under unfavorable mobility contrast, the interface between two fluids may become very convoluted as displacements continue. This therefore increases the contact area and leads to more efficient mixing. It is necessary to accurately simulate the detailed frontal instability and its propagation with time in order to investigate its effect on the mass transfer. Most of previous numerical simulations assumed a constant diffusion coefficient (CDC) in solvent-based processes. However, experimental studies on the mixing between two miscible fluids indicated that the diffusion coefficients actually vary with concentration or viscosity. Moreover, some numerical simulations with commercial simulators also showed that using the CDC may result in very high and unrealistic values when matching the oil production rate. In present study, a concentration-dependent diffusion coefficient (CDDC) is considered in which the diffusion coefficient is exponentially proportional to concentration. Highly accurate nonlinear numerical simulations are conducted to simulate the frontal instability under unfavorable mobility ratio between solvent and oil. The effect of injection rate and mobility contrast on frontal instability and mass transfer is examined, and the breakthrough time for the CDDC case is discussed. For better comparisons, the CDC case is presented to more clearly show the effects of CDDC.
- North America > Canada (0.48)
- North America > United States (0.46)
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.34)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (0.71)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (0.69)
- Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (0.48)