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.
Thermal recovery methods, in particular technology based on steam injection, are used extensively around the world for heavy oil and bitumen production. Because of the unconsolidated nature of the majority of such deposits, sand control is required. Design effectiveness of sand control depends on the reservoir type, production technology and operational practices. The industry is facing many challenges such as low oil prices, tight environmental regulations, the need to lower risks while assuring well integrity and longevity and project economics. All of that requires special technical solutions for thermal well design, including sand control.
The paper provides an overview of sand control for thermal heavy oil and bitumen production operations, factors affecting sand control design for thermal projects, sand control devices and industry trends. Laboratory observations and field data are discussed. The impact of steam on different quality heavy oil and bitumen deposits in relation to sand control is discussed in detail. Efficient sand control design for thermal production operations requires a multidisciplinary approach and is an integral part of the well longevity and project economics. Better understanding of the impact of reservoir quality, thermal formation damage and operational practices on well performance is required to assure success of a thermal project.
When compared with steam-assisted gravity drainage (SAGD) operations in the McMurray Formation, Athabasca Oil Sands, SAGD projects in the Clearwater Formation at Cold Lake did not perform as expected, likely because of reservoir properties. This paper will use the Orion SAGD case study to: (1) investigate the impacts of reservoir properties on the SAGD thermal efficiency by field evidences; (2) identify key geological parameters influencing each well pad; and (3) summarize major geological challenges for Orion SAGD expansion.
Wireline log data were interpreted to characterize reservoir properties, which were used to build 3D models. 3D visualizations and 2D cross sections of the reservoir revealed spatial distribution and heterogeneity of each property. SAGD production performance was analyzed using: (1) temperature profiles that monitored the growth of the steam chamber; (2) cumulative steam-oil ratios (CSORs); and (3) oil production rates (OPRates), which are direct indicators of thermal efficiency.
Results show that impermeable barriers and low-permeability zones were detrimental to steam injectivity and steam chamber growth, as observation wells in Pilot Pads 1 and 3 did not detect any steam saturation. High-permeability zones favored high steam injectivity and mobility, especially in Pad 105. Steam chambers were irregularly shaped by high shale-content zones, as two sharp spikes displayed on the temperature profile in Pad 103. Low oil-saturation zones and thin net-pays increased the CSORs, as seen in Pads 106 and 104. Impermeable barriers are almost horizontal, making no difference on well pad orientation by their dip angles. Lack of porosity variation made it difficult to identify the impact of porosity on each well pad.
The relatively extensive distribution of impermeable barriers between and above well pairs, as well as the relatively large area of low oil saturation and thin net-pay, were identified as major geological challenges.
Producing from bitumen reservoirs overlain by gas caps can be a challenging task. The gas cap acts as a thief zone to the injected steam used during oil-recovery operations and hinders the effectiveness of processes such as steam-assisted gravity drainage (SAGD). Moreover, gas production from the gas cap can accentuate the problem even more by further depressurization of the gas zone.
Following a September 2003 ruling by the Alberta Energy Regulator (AER), the oil and gas industry in the province of Alberta, Canada, had approximately 130 million scf/D of sweet gas shut-in to maintain pressure in gas zones in communication with bitumen reservoirs. This decision led to the development of EnCAID (Cenovus' air-injection and -displacement process), a process in which air is injected into a gas-over-bitumen (GOB) zone, and combustion gases are used to displace the remaining formation gas while maintaining the required formation pressure.
An EnCAID pilot was started in June 2006, and preliminary results were reported in 2008. After 8 years of operations, the EnCAID project has not only proved to be effective at recovering natural gas and maintaining reservoir pressure, it has also shown it can heat up the bitumen zone and make the oil more mobile and amenable for production. This led to the development of the air-injection and -displacement for recovery with oil horizontal (AIDROH) process.
The AIDROH process is the second of two distinct stages. First, an air-injection well is drilled and perforated in the gas cap. The well is ignited and air injection is performed to sustain in-situ combustion in the gas zone. This phase is characterized by a radially expanding combustion front, accompanied by conduction heating into the bitumen below. The second stage begins when horizontal wells are drilled in the bitumen zone. The pressure sink caused by drawing down the wells alters the dynamics of the process and creates a pressure drive for the combustion front to push toward the producers in a top-down fashion, taking advantage of the combustion-front displacement and gravity drainage.
In light of the temperature increases observed in the bitumen overlain by the EnCAID project, a horizontal production well was drilled in late 2011 and commenced producing in early 2012. This paper provides an update of the EnCAID pilot results and presents a summary of the technical aspects of the AIDROH project, pilot results, and interpretation of the data gathered to date, such as observation-well temperatures, pre- and post-burn cores, and temperatures along the horizontal producer.
Results indicate that the AIDROH process has the potential to maximize oil production from GOB reservoirs, and efforts continue to be made to optimize its design and operation.
Mahmoudi, Mahdi (University of Alberta) | Fattahpour, Vahidoddin (University of Alberta) | Nouri, Alireza (University of Alberta) | Yao, Ting (University of Hong Kong) | Baudet, Beatrice Anne (University of Hong Kong) | Leitch, Michael (RGL Reservoir Management Inc.)
Oil sand characterization tests are essential for the selection and evaluation of sand control devices. Current approaches for screen selection and evaluation usually rely on Particle Size Distribution (PSD) and neglect the effect of important parameters such as porosity, grain shape and frictional properties. One aim of this study is to characterize oil sand's mechanical, geometrical and size characteristics that should be considered in the completion design. Another objective is to determine if natural mixture of oil sand could be reasonably replicated with commercial sands for large-scale sand control evaluation tests.
In this paper we present the results of a comprehensive image analysis and laser sieve analysis on oil sand samples from the McMurray Formation to quantify geometrical grain characteristics (sphericity, aspect ratio, convexity and angularity) of the sand grains and establish the PSD of the samples. Direct shear tests were performed to assess the frictional characteristics of different oil sands around the liner under variable stress conditions during the SAGD well lifecycle.
Image analysis, PSD, and direct shear tests showed that natural mixture of oil sand could be successfully simulated with commercial sands in terms of size and shape of grains and mechanical properties. This conclusion is significant to those performing large-scale sand control evaluation tests that usually require large quantities of sands that are not readily available and require significant preparation.
This paper provides the first comprehensive investigation of the granular, and geomechanical characteristics of oil sand from the McMurray Formation. The paper discusses the missing parameters in the design of sand control device, and evaluates test methods that measure those parameters. The proposed testing program could be used as a benchmark for oil sand characterization in relation to the design and evaluation of sand control device.
Heterogeneity in the Athabasca oil sands can impede the growth of SAGD steam chambers. Here, we show how controlled-source electromagnetic (EM) methods can be used to detect growth-impeded regions and monitor changes in steam chamber growth. Our achievements are two-fold. We first generate a background resistivity model based on well logging at a field site in the Athabasca oil sands and then estimate the resistivity of the steam chambers using an empirical formulation that incorporates the effects of temperature on the surrounding rocks. Using the resulting 3D model, electromagnetic responses for any EM survey can be computed. The second, and more important, achievement illustrates that imaging SAGD chambers, as they grow in time, may be possible with cost-effective surveys. Our example uses a single transmitter loop with receivers in observation wells. In the wells, only the vertical component of the electric field is measured. Even with this limited data set, the images obtained through 3D cascaded time-lapse inversion identifies the location and extent of an impeded steam chamber. The proposed EM survey acquisition time and processing should be relatively fast and cost effective, and are expected to yield sufficient information to help make informed decisions regarding SAGD operations.
Steam Assisted Gravity Drainage (SAGD) is an in-situ recovery process used to extract bitumen from the Athabasca oil sands in northeast Alberta. In SAGD, two horizontal wells are drilled at the bottom of the reservoir (Dembicki, 2001). Steam is injected into the top well and produces a steam chamber that grows upwards and outwards. At the edge of the chamber, the heated, fluid oil and condensed water flow through the formation and are collected by the underlying horizontal production well. The chamber expands further into the bitumen reservoir as the oil drains (Butler, 1994).
The success of this technique is dependent upon steam propagation throughout the bitumen reservoir. However, reservoir heterogeneity, such as clay beds and mudstone laminations, can cause low-permeability zones that can impact the growth of the steam chambers (Strobl et al., 2013; Zhang et al., 2007). This affects the amount of produced oil and exemplifies the importance of monitoring the steam chamber growth. Successful monitoring can aid in optimizing production efforts by increasing understanding of the reservoir, decreasing the steam-to-oil ratio, locating missed pay, identifying thief zones, and more efficiently using resources (Singhai and Card, 1988).
Because the electrical conductivity of a lithologic unit is affected by steaming, electric and electromagnetic methods are promising tools to detect and image SAGD steam chambers. Additionally, these types of surveys can be much more cost-effective than seismic methods (Engelmark, 2007; Unsworth, 2005). Electric and electromagnetic surveys can also be readily installed as permanent installations. Tøndel et al. (2014) used a permanent electrical resistivity tomography (ERT) installation in the Athabasca oil sands to monitor SAGD steam chamber growth over time. From their study, electrodes can stand up to the high-temperature environment in boreholes surrounding the steam chambers while geophones can break down over time. Devriese and Oldenburg (2015) showed how the method can be extended to frequency- and time-domain EM. Permanent installations can also provide multiple data sets per year, without being limited by access to the area in wintertime only.
Connacher's first oil sands project, the Pod One facility at Great Divide, has been operational since 2007. The successful SAGD project has produced approximately 7 million barrels of bitumen. During the past three and a half years, the impacts of certain predicted reservoir challenges and opportunities have become apparent.
While the quality of the oil sands in this first phase of Pod One is generally good, Pad 101 South in particular has geological zones that affect SAGD operation. This includes a bitumen lean zone, and a gas cap overlying the main bitumen channel/s. Early field results matched with detailed simulations have shown positive results in maximizing well pair production. For the purposes of this paper a lean bitumen zone differs from an aquifer in two ways. The lean zone is not charged, and is limited in size. The operation is also complicated by the fact the gas bearing zone has been depleted through earlier production.
Connacher's operating practice at Great Divide attempts to achieve a pressure balance between the 3 zones (rich oil sands, lean zone, gas cap) to reduce steam loss and maximize production rates. Reducing the pressure encourages steam chamber development growth horizontally and ensures that steam contacts the highly saturated bitumen areas. How this is achieved with the highest positive impact on well productivity is illustrated with operational data and analysis including the results of simulations that recommended the optimum operating strategies.
Bao, Xia (U. of Calgary) | Chen, Zhangxin John (University of Calgary) | Wei, Yizheng (University of Calgary) | Dong, Chao Charlie (U. of Calgary) | Sun, Jian (U. of Calgary) | Deng, Hui (U. of Calgary) | Yu, Song (University of Calgary)
Optimization of Steam Assisted Gravity Drainage (SAGD) remains a major concern in Surmont leases (an Athabasca oil sands deposit located in northeastern Alberta, Canada) due to the extensive presence of top gas and top water zones over the bitumen. Observation well data has detected the pressure communication between the SAGD steam chamber and overlying thief zones. Maintaining the steam chamber pressure is very difficult due to these thief zone interactions.
Previous numerical simulations, laboratory experiments and field production data have demonstrated that the overlying top water and gas thief zones have a detrimental effect on the SAGD process. Oil production and steam oil ratios tend to decrease as the depletion of top gas continues. Also, the heat loss to the overlying thief zone will be more significant when the top water zones are present. However, an optimal operating strategy for the full field scale SAGD process with both top gas and top water remains uncertain. In addition, a detailed investigation of the impact of top gas and water thief zones on SAGD performance provides the basis in calibration of geostatistical and flow models for commercial phase planning and forecasting.
The objective of this paper is to construct numerical flow simulation of a Surmont pilot using a well-defined 3D geostatistical model to determine the impact of the top thief zones on bitumen recovery. The focus of the study will be on three horizontal well pairs plus 15 vertical observation wells at the McMurray formation. The stochastic geostatistical model is to build a representation of the McMurray geology that honors the deposition structure, facies proportions, reservoir characteristics and petrophysical properties. Structural tops are interpreted from well logs and porosity-permeability relationships established from quantitative log analysis and core-log calibration. The facies-based log-derived porosity, permeability, shale volume and water saturation are populated into a grid block by Sequential Gaussian Simulation (SGS) in the petrophysical modeling process. Then a static model is upscaled to coarse simulation grids, and a submodel for each single well pair is extracted for the purpose of history match in STARSTM simulator. Reasonable history match of oil and water rates has been achieved by calibrating this static model with the field production data. The steam chamber pressure and temperature profile from the numerical model has been conformed to the field data from the observation wells. Optimization of cumulative steam oil ratios (cSOR) by varying injection pressure and the steam trap control with the top thief zones has been investigated in great detail.
In conclusion, SAGD performance is dominantly controlled by geological heterogeneity, completion and operation constrains, and steam chamber pressure variations. Finally, integrated optimization strategies have been developed and tested on a full field-based heterogeneous simulation model.
Bitumen is too viscous to be produced by conventional recovery methods and significant amounts are too deep to be recovered by mining, necessitating enhanced in-situ oil recovery techniques. The majority of operating and planned in-situ bitumen projects employ thermal techniques to lower the bitumen's viscosity, allowing it to be produced. The viscosity characteristics of the bitumen consequently have a significant effect on production rates and recovery. Bitumen viscosity and chemical composition variation with depth within a single reservoir column has been reported for many heavy oil and oil sand reservoirs in the Western Canadian Sedimentary Basin and elsewhere in the world.
This study investigates, through reservoir simulation, the effects of viscosity variation with depth on the SAGD process and the resulting produced oil characteristics. Oil characteristics, including chemical component and viscosity profiles were built into a variety of reservoir simulation models. The simulation results indicate that the produced oil viscosity and component concentration vary as the steam chamber develops. The trend of the produced oil characteristics is related to the original in-situ profiles of and the reservoir flow barriers. In conjunction with oil rate, surface heave, or other available data, the produced oil characteristics may be used to suggest steam chamber development and the presence of barriers or baffles. The presented approach has potential to become a useful technique for SAGD steam chamber growth monitoring and production optimization.
Oil viscosity and compositional gradients, both areal and vertical have been observed in various fields worldwide1. Differences in physical properties and chemical composition of oil are more significant in heavy oil and oil sands reservoirs2. Recently, more attentions has been paid to heavy oil and oil sands reservoirs in the Western Canadian Sedimentary Basin, where 172.7 billion barrels of bitumen and heavy oil are to be recovered3, mostly through thermal processes, such as CSS (cyclic steam stimulation) and SAGD (steam assisted gravity drainage). Erno et al. found that the viscosity increases towards the bottom of the reservoir for Clearwater B, McMurray, and Wabiskaw formations at Caribou Lake, and Waseca formation at Pikes Peak with up to an order of magnitude difference in the Clearwater B formation. It was suggested that the viscosity variation may affect the performance of CSS, the proposed recovery process for those reservoirs, and should be considered in reservoir characterization and modeling4. Chan et al.5 reported vertical variations of certain chemical compounds in a McMurray Formation corehole in the Athabasca area (re-plotted in Figure 1). They showed that the ratio of diasterane to regular sterane increases from the top to the bottom of the reservoir. Based on the observed baseline of chemical compound distribution, a field application was demonstrated that used the chemical compound concentration from the produced sample to diagnose the CSS performance5.