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Collaborating Authors
SPE Heavy Oil Conference Canada
Abstract Steam Assisted Gravity Drainage (SAGD) production is a challenging environment where the economics are driven by optimization of the steam injection and oil production. An accurate metering system coupled with downhole pump information is required as is the reduction in physical intervention and operating expenditures. Suncor’s Firebag team engaged themselves in this challenging endeavor over the last 4 years to build a strategy using multiphase flowmeter (MPFM) to (1) provide a compact and versatile solution for new wells, (2) comply with regulations, and (3) validate the metering performances of the MPFM against the conventional separator. The goal of this paper is to address the learnings and challenges faced in the MPFM deployment under these high temperature and harsh line conditions. This knowledge sharing is expected to serve as a guideline for future users of this MPFM technology in SAGD applications particularly with Cold Weather Operations, Multiphase Sampling and High H2S environment, also considering Pressure-Volume-Temperature (PVT) Modeling. From a practical point of view, the qualification, application and benefits of MPFMs in field conditions will be highlighted versus the conventional solution. A particular focus will be placed on the production optimization and reservoir management. Additionally, the synergy between the downhole pump information and instantaneous MPFM flow rate measurements will be reviewed along with the positive impact on the production optimization. The benefit of the MPFM accuracy and continuous measurement is expected to improve the allocation factors applied to all wells and pads.
Abstract Production of heavy oil from Alberta’s vast reserves continues to be a costly and capital intensive endeavor. To date considerable research has been focused on mining, SAGD, in-situ combustion, and vapor extraction. A new chemical dispersant technology has been introduced in the past year that reduces the apparent viscosity of the produced fluids from wells in the heavy oil fields around Lloydminster, Alberta, reducing the power required to drive the downhole progressive cavity pumps (PCPs), allowing pumping rates to increase, and increasing daily oil production by up to 300%. The primary benefit is removing the obstacle of pump speed limitation due to high oil viscosity. CHOPS production suffers from many challenges. Principally, the cold heavy oil exhibits high viscosities, in some cases in excess of 100,000 centipoises (cPs). Over the past two decades, technological advances in downhole PCPs, rod strings, well heads, and power units have improved the ability to produce heavy oils. However, when viscosities approach or exceed 100,000 cPs these advances do not overcome the excessive drag created by the heavy oils as they travel up the production tubing. The newly developed chemistry creates a dispersion of oil in water with a much reduced overall viscosity and increased mobility. The result: more oil loading into the pump, less drag along the rod string and production tubing, lower power requirements, the ability to increase the pump RPMs and, therefore, increased oil production. This technology was developed in Western Canada and has proven itself to be successful at increasing oil production, improving on-time, and reducing servicing on Canadian heavy oil wells produced by way of cold recovery methods. This technique could be utilized in other heavy oil fields throughout the world where production rates are limited by the issues created by extreme oil viscosities.
- North America > Canada > Saskatchewan > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > Canada > Northwest Territories > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > Canada > Manitoba > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- (2 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Cold heavy oil production (1.00)
- Production and Well Operations > Artificial Lift Systems > Progressing cavity pumps (1.00)
Abstract The use of polymer floods to efficiently displace heavy oils with viscosities up to 10,000 mPa.s has be tested successfully in laboratory scale evaluations; commercial success on the field scale has been achieved with oil viscosities up to 2000 mPa.s in Western Canada1 and other parts of the world1. Since it has been established that the polymer flood technology can be successful at displacing heavy oils on a field scale, it is timely to improve the efficiency of this technology. Researchers have shown that heterogeneities are more detrimental when waterflooding heavy oils than experience obtained from conventional waterfloods3, 4. Hence, it is essential to understand the polymer flood displacement of heavy oil in the presence of heterogeneities. In addition, it was beneficial to conform the impact of large scale heterogeneities with judicious use of associative polymers. Building a high and low permeability layer into a cylindrical sandpack allowed for demonstrating the impact of heterogeneities on a waterflood and polymer flood displacing heavy oils; the high permeability layer had a permeability 10 times greater than the low permeability layer. The reduced oil recovery in the heterogeneous, dual permeability core can be modeled correctly using a reservoir simulator if a capillary pressure difference curve is introduced during the simulations. The capillary pressure difference curve controls the degree of cross-flow from the high permeability layer to the low permeability layer and corrects the sweep efficiency. Salinity and hardness tolerant associative polymers suitable for injection into reservoir core have been screened and developed for heavy oil displacement processes. These specialty polymers generate a higher in situ apparent viscosity by forming large hydrodynamic radii through association between polymer molecules. In reservoir applications, these associative polymers may generate tremendous resistance factors in high permeability streaks. The dual permeability corefloods demonstrated that associative polymers outperformed the regular partially hydrolyzed polyacrylamides in two aspects: (1) the associating polymer generated incremental oil recovery after HPAM recovery and (2) the mobility reduction (or resistance factor) of the associative polymers was significantly higher than HPAM. Hence associative polymers can be used for blocking and diverting purposes in high permeability layers where regular polymers may not be as effective.
- Europe (0.68)
- Asia (0.68)
- North America > Canada (0.47)
Abstract Current technologies for in-situ heavy oil recovery involve either heating the reservoirs to liquefy the hydrocarbons or attacking the deposits with solvents. This is usually accomplished by providing a source of external energy such as using natural gas to heat the oil or subjecting it to mechanical stimulation. However, a challenging case is in ultra-shallow reservoirs where the recovery is limited only to matrix oil drainage by gravity. In these cases, many heavy oil reservoirs are too thin to use thermal processes for enhanced heavy oil recovery due to the heat losses to overburden and underburden. In this paper, a study to develop a new technology to increase heavy oil recovery using alkali, surfactant and polymer is presented. It has been found that novel surfactants can create a stable emulsion for heavy oil and formation brine, by which viscosity of heavy oil can be reduced significantly. At 25 °C, the viscosity of heavy oil is 15,785 cP. But when the heavy oil and synthetic brine are emulsified with some new surfactants, the viscosity reduces about 2.88 to 3.46 cP. Therefore, the mobility of heavy oil is improved significantly. In order to analyze the contribution of the various components to viscosity, a heavy oil sample was separated with a silica gel column. It was found that asphaltenes and resins, the two heaviest and most polar components in the heavy oil, exert the largest influence on the viscosity of heavy oils. Viscosity decreases as temperature increases, which is leveraged by thermal technology for heavy oil recovery. The decrease in viscosity is most pronounced, however, at temperatures below 60 °C. The high viscosity of heavy oil can be dramatically reduced further by emulsification with proper surfactants and alkali, which is the principle behind non-thermal technology for heavy oil recovery. In this research, emulsions created by the surfactants B and E are stable at 25 °C, and their performance in non-thermal heavy oil recovery was evaluated using sand pack flooding test. 23% of heavy oil recovery was achieved by injection of surfactant B and polymer Superfloc A-110 HMW. It has also been found that injection of 1.0 PV of surfactant solution followed by injection of 1.0 PV of polymer solution to be the optimum methods for both surfactants B and E. In most cases, Superfloc A-110 HMW polymer seems to be slightly better than Superfloc A-120 V for enhanced heavy oil recovery.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.36)
Caprock Integrity Case Study for Non-thermal Polymer Flooding Project Using 4D Reservoir Coupled Geomechanical Simulation
Ansari, S.. (1Data and Consulting Services, Schlumberger Canada.) | Haigh, R.. (2Canadian Natural Resources Ltd.) | Khosravi, N.. (1Data and Consulting Services, Schlumberger Canada.) | Khan, S.. (1Data and Consulting Services, Schlumberger Canada.) | Han, H.. (1Data and Consulting Services, Schlumberger Canada.) | Vishteh, M.. (1Data and Consulting Services, Schlumberger Canada.)
Abstract Maintaining an effective caprock seal is of prime importance in any enhanced oil recovery (EOR) stimulation involving subsurface injection of fluid. Hydraulic or mechanical breaching of the caprock may entail leakage of injected fluids and/or hydrocarbons into shallower formations, or even to the surface, with the potential for adverse environmental impact. Determining a safe optimal injection pressure which minimizes the likelihood of such an occurrence is a challenging problem. For example, assessing caprock integrity with the static stress measurement alone at the virgin state of reservoir without considering dynamic stress changes is likely to be both unreliable and inadequate. In this paper, we present a case study of hydraulic and mechanical integrity of Wabiskaw caprock at multiple injection scenarios under dynamic conditions. In this study a multi-disciplinary approach was used which integrates geology, petrophysics, reservoir engineering and geomechanics followed by a finite element coupled reservoir-geomechanics simulation. A 3-D mechanical earth model (MEM) was constructed utilizing advanced azimuthal shear anisotropic sonic log and core based mechanical properties. All the available LOT mini-frac as well as MDT micro-frac tests data were assessed and used to calibrate the anisotropic stresses at initialization step in addition to assessing the lateral variability of the vertical stress. Several tight streaks expected to provide additional abutment to the primary caprock were honored in the model. The 3-D MEM was extended to the surface and embedded with the sideburden and underburden layers incorporating adjacent injectors and producers to minimize the boundary effects. This study evaluated tensile and shear failures within the reservoir and the caprock at several injection scenarios for a period of 30yrs with injection bottomhole pressures of 116 and 155bar at the rate of 150 m/day. No shear failure or tensile failures were predicted by the coupled geomechanical simulator in the caprock for all the injection scenarios. This model also predicted the vertical displacement within the reservoir, caprock and at the surface. The amount of heave at the ground surface was negligible.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.96)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.46)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.32)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Clearwater Formation (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 > Pelican Lake Field (Wabasca Field) > Wabiskaw Sandstone Formation (0.96)
- (4 more...)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Thermal methods (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Abstract The Aera Energy LLC (Aera) Development Team has drilled and completed, each year since 2000, about 1,000 oil producers and water/steam injectors, and constructed the associated surface facilities. Such a high activity level, which involves some 800 contractors and hundreds of pieces of mobile oilfield equipment, leads to unsurpassed congestion and logistical complexity, requiring a different approach from traditional planning and execution methodologies. In 2001, Aera turned to the manufacturing industry for ideas. The company realized that drilling and constructing a well is not just a step in delivering a commodity; it is manufacturing a new well. The decision was made to implement Lean principles in the development process. Some of the Lean principles that were adopted were: moving from large batches of wells to near single-piece flow; just-in-time execution of planning and implementation activities; relentless focus on continuous improvement through mapping of work processes and eliminating the identified waste; designing and constructing oilfield equipment that is right-sized for the application needed; and creation of a very transparent system of visual tools that shows the status of key indicators at any point in time. The transition to Lean has paid off. The desired high release rate of wells has been maintained despite significant oil price volatility. The safety performance of the Aera Development Team and its contractors improved continuously and the injury frequency was reduced by a factor of 10. The drilling and completion cost (on a per-foot basis) for the most common well type was held flat in nominal terms between 1997 and 2011, while industry costs more than doubled over the same period. In 2011, Aera was the first oil company to receive the Manufacturing Excellence Award from the Association for Manufacturing Excellence. The award recognizes "demonstrated excellence in their operations" and has a primary focus "to acknowledge continuous improvement, best practices, creativity, and innovation." This paper describes the Lean journey including the culture change that was needed, the obstacles that had to be overcome, examples of Lean implementation (e.g., tools, processes, results), and the critical success factors to successfully implement Lean in new well construction.
- North America > United States > California > San Joaquin Basin > Kern River Field (0.99)
- South America > Brazil > Parnaiba Basin > Block PN-T-68 > California Field (0.97)
- North America > United States > California > San Joaquin Basin > Yowlumne Field (0.97)
- (2 more...)
Abstract Foamy oils, generated during cold production, have also been detected in solvent based recovery processes. Understanding the foamy oil mechanism is key to determining how oil is produced in processes such as Cyclic Solvent Injection (CSI). Visual observations of solvent exsolving from solution during depressurization were performed to gain a better understanding of these processes. Heavy oil saturated with CO2, CH4, C3H8 and a combination of CO2 and C3H8 are examined in an etched glass micromodel. Three different expansion rates are examined. The results indicate that CO2 and CH4 show an extreme supersaturation. CO2 saturated oil produces more nucleation sites than CH4, C3H8 and a mixture of CO2 and C3H8. Approximately 8 times more nucleation sites were produced with CO2 than with CH4. With more nucleation sites, there is a greater potential for oil recovery with solution gas drive. The experiments conducted here provide a qualitative understanding of the foamy oil process and aid in the understanding of solvent based enhanced oil recovery mechanisms such as Cyclic Solvent Injection (CSI).
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Experimental Evaluation of Dispersion and Diffusion in a UTF BItumen/n-Butane System
Frauenfeld, Ted (Alberta Innovates - Technology Futures (AITF)) | Jossy, Chris (Alberta Innovates - Technology Futures (AITF)) | Jossy, Eddie (Alberta Innovates - Technology Futures (AITF)) | Wasylyk, Brad (Alberta Innovates - Technology Futures (AITF)) | Diaz, Brigida Meza (Alberta Innovates - Technology Futures (AITF))
Abstract Laboratory experiments at Alberta Research Council (now Alberta Innovates Technology Futures) have indicated the potential for improving the recovery of bitumen and heavy oil, and a substantial reduction of SOR relative to SAGD, by the addition of substantial volumes of light hydrocarbon to steam as an enhancement of SAGD. Many scaled lab model experiments have been completed, some of which have identified solvent/steam ratios that outperformed low pressure SAGD. In order to more reliably scale the results of these experiments, it was desired to measure the rate of oil production and hence solvent front advance rate in field permeability sand. The experiments were isothermal to simplify the numerical simulations. Three experiments were completed, one at 68°C one at 80°C and one at 100°C. The respective butane pressures were 700 kPa, 1020 kPa and 1450 kPa. The respective oil rates were 52.5 g/h, 62.3 g/h and 63.2 g/h. Solvent front advance rates were 7.81 cm/d, 9.0 cm/d and 9.42 cm/d. These rates translate into SAGD-like rates when extrapolated to a field size project.
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (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)
- (2 more...)
Abstract The steam-assisted gravity drainage (SAGD) process is currently the widely used one among the in-situ recovery methods to produce bitumen from Alberta oil sands in Western Canada. A thermal process requires very small grid size to provide the better description in the reservoir simulation model than the coarse grid; however the simulation runtime will take longer. The relationship between the number of grids and runtime is not linear but exponential. It is important to design the proper grid size giving reasonable results with shorter runtime. In this study, the optimal grid system design has been investigated through numerical simulation sensitivity studies for the SAGD process. A 1×25×1 m (i, j, k direction; j is wellbore direction) grid size is accepted as a standard size for the SAGD simulation. Grid size sensitivity study has been conducted to determine the maximum grid size that shows a closer result to the 1×1 m case and also the impact of grid size in j-direction as well as the i/k ratio in SAGD simulation. The simulation results shown an i/k ratio is more important than a grid size itself. Based on the CSOR and oil production as well as steam chamber shape, the 2×2 m grid case is closer to the 1×1m case results than 3×1 m case. For the grid size optimization in the wellbore direction (j direction), the grid size of over 25 m cases are no big difference in both production and steam chamber shape for a homogeneous model, and there is no steam chamber propagation to the j-direction. The maximum grid size in j-direction to see the wellbore end effect is 10 m in this study. Considering the reservoir heterogeneity, if shale barriers exist, the impact of grid size in j direction is more important and the smaller grid size is required for the proper numerical simulations to describe steam chamber development in field scale SAGD project. For j-direction grid design, a hybrid type of grid system, a fine grid size in wellbore end zone and regular grid size in wellbore zone, may help to see the steam chamber development with saving a degree of simulation runtime.
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.36)
Abstract Thermodynamic steam trap, or sub-cool control, in a typical SAGD production is essential to the stability and longevity of the operation. It is commonly achieved through the control of fluid production. The goal of such control is to maintain a steady and healthy liquid production without allowing bypassing of steam from the injector to the producer. Therefore, it is effectively a control of the liquid level above the producer. Unfortunately, it is not practical to monitor this liquid level. A rule of thumb sub-cool estimation of 10°C/m of liquid level is popularized in the industry, however, does not prove to hold in many situations. This paper presents a study of the dynamics of SAGD production control with a resulting algebraic equation that relates sub-cool, fluid productivity and wellbore draw down to the liquid level above a producer. The main conclusions of this study include: There is no minimum sub-cool value for a pure gravity drainage scenario; however, as the wellbore draw down is considered there is minimum sub-cool value in order to maintain the stability of fluid flow. For a given productivity, the liquid level increases as sub-cool increases or as wellbore draw down decreases. For each set of parameters, there exists a minimum productivity below which SAGD operation would halt. Before the steam chamber reaches the top of the reservoir, the production rate is limited by the vertical distance between the injector and the producer, the larger the distance the higher the production rate can be. A verification of this analysis was conducted via a series of numerical reservoir simulations. Although limited to 2D, we believe this analysis captures the main physics amid the dynamic complexity of SAGD production control. The resulting algebraic equation can be used for better understanding the dynamics of sub-cool control and determining operation strategies.