Steam-assisted gravity drainage (SAGD) has been extensively applied in thermal recovery from oil sands reservoirs in the Athabasca region of Northern Alberta, Canada. As the steam chambers associated with SAGD well pairs become mature, a form of abandonment is often applied that may include pressure maintenance in the depleted zone. Quantification of potential surface subsidence associated with SAGD abandonment becomes critical especially when the mature wells are in proximity to future developments. In addition,induced shear stresses should be estimated to fulfill well-integrity requirements. In the context of this case study, first, the development of a static geomechanical model (SGM) derived from a fine-tuned geomodel realization is discussed, which forms the basis for the iteratively coupled simulation model. The calibration work flow of the coupled reservoir/geomechanical simulation model to historical heave data is then reviewed and the effects of different parameters on calibration quality are investigated. Finally, the estimation of subsidence and the induced shear stresses in the nearby wells are discussed, and the magnitude of residual heave is quantified. The results of this study show that only a fraction (up to 38%) of surface heave is reversible (in form of subsidence) during the abandonment phase. Therefore, the magnitude of the surface subsidence and the associated shear stresses are small. The modeling study has also shown that a small magnitude of subsidence may be recorded even 10 years after abandonment. However, more than 50% of the surface subsidence is observed in the first 2 years after abandonment. Other important findings of this study include documenting the effects of thief-zone interaction and pseudoundrained loading as they relate to irreversibility of surface heave; documenting the effects of various geomechanical parameters on the quality of calibration against the historical heave data; observation of the relative effects of the isotropic unloading, thermal expansion, and shear dilatancy on the magnitude of heave; and quantification of incremental, yet small, shear stresses along the nearby horizontal wells.
As a critical input in determining the maximum steam injection pressure, caprock integrity assessment in thermal operations has become increasingly important because of the potential severe consequences of a caprock integrity breach on the environment, safety and project economics. Because of the complex thermo-poro-mechanical coupling of the thermal stimulation process, numerical simulation is required in evaluating caprock integrity.
Thermal stimulation of heavy oil reservoirs significantly alters the pore pressure and in-situ stresses not only in the reservoir, but also in the caprock. Rock mechanical properties also change with temperature, pore pressure, stresses and rock deformation. Accurate characterization of reservoir and caprock mechanical properties and constitutive behavior is critically important in caprock integrity analysis. Through geomechanical and fluid flow coupled simulation of a steam-assisted gravity drainage (SAGD) case using commercially available reservoir simulator and finite element geomechanical simulator, this paper discusses the physical processes that occur in thermal operations, including stress and strain change, rock volume change, and rock failure, in both the reservoir and the caprock. The effects of rock elastic and strength properties, constitutive model, coefficient of thermal expansion, thermally induced pore pressure, and steam injection pressure on reservoir deformation and caprock integrity will be explained through simulation cases.
Schedule Session Details Expand All Collapse All Filter By Date All Dates Tuesday, February 14 Wednesday, February 15 Thursday, February 16 Filter By Session Type All Sessions General Activities Social and Networking Events Technical Sessions Panel, Plenary, and Special Sessions YP events Training Course/Seminar Tuesday, February 14 08:30 - 17:00 In-Situ Recovery Methods and SAGD Instructor(s) K.C. Yeung This course will provide a general overview of current and emerging heavy oil recovery methods with emphasis on field experiences in Alberta and steam assisted gravity drainage (SAGD). Participants will learn about the concepts, field development, reservoir performances, applicability, challenges, and issues of the various in-situ recovery methods. Learn More 08:30 - 17:00 Overview of SAGD Analytical Models and Their Assumptions and Limitations Instructor(s) Mazda Irani Learn More Wednesday, February 15 07:30 - 17:00 Conference Registration 07:30 - 08:30 Breakfast and Exhibits 08:30 - 12:00 01 HO - Carbonate Recovery Processes Palomino A-C Session Chairpersons Japan J Trivedi - University of Alberta, Jian-yang Yuan - Osum Oil Sands Corp Discussions in this session focus on carbonate reservoir recovery processes and mechanisms, from field experiences to laboratory observations. Topics include thermal casing and cement, Sand control, well intervention, and wellbore simulations. Soliman, University of Houston; M. Shahri, T.W. Cavender, Halliburton Energy Services Group 08:30 - 12:00 03 HO - Hybrid or Solvent Based Processes I Mustang Room Session Chairpersons Ronald A Behrens - Chevron ETC, John Joseph Ivory - InnoTech Alberta This session addresses the fundamentals and tools for predicting benefits of and usage of solvent for enhanced recovery.Â Topics include both water-soluble solvents and the more traditional hydrocarbon solventsâ€™ viscosity, relative permeability, heat and mass transfer, sampling, and reservoir performance prediction.
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.
Tuesday, April 18 Hot Breakfast Sponsored by: Halliburton and Precise Downhole Services Session 1: Looking Back - Moving Forward Session Chairpersons Jarrett Dragani, Cenovus; Janelle Watson, Shell Canada Opening Keynote: Historical Perspectives on Older Steam Drive Technology for In-Situ Thermal Recovery - Applying Lessons Learned to Meeting New Challenges Rudy Strobl, EnerFox Enterprises and Milovan Fustic, University of Calgary Canada's Oil Sands – Challenges Met, Challenges Coming Morning Coffee Break Sponsored by: KADE Technologies Inc. and Westwood Electric Morning Coffee Break Sponsored by: Session 2: Meeting Today's Challenges with Innovation Sponsored by: Spartan Controls Session Chairpersons Glenn Thoben, Spartan Controls; Chris Wong, GE Power Learning's from the Grand Rapids Field Trial of Tubing-Deployed Inflow Control Devices for SAGD Application Keynote Lunch Keynote Speaker: Lessons Learned and Near Term Priorities for In Situ Authorizations at the AER Session 3: Project Updates Sponsored by: HIVE innovations Session Chairpersons Jian-Yan Yuan, Osum Oil Sands; K.C. Yeung, K C Yeung Canadian Enterprise Inc. ConocoPhillips Surmont Overview – A look at the largest single phase SAGD project Session 4: What's Next for Tech Session Chairpersons Heath Williamson, Black Pearl Resources Inc.; Richard Chan, Suncor Energy; Carmen Lee, Husky Energy The Future of Canadian Oil and Gas: The Challenge of Staying Competitive in a Changing World.
Particle-size distribution (PSD) is a list of values that defines the relative amount of particles present according to the size in a sample. The PSD of the McMurray Formation sediments characterizes rock granulometry and is a fundamental indicator of the nature of the sediment. The size distribution of the component solid particles in the McMurray Formation sediments relates to their porosity; volume of water and bitumen contained within the pore space; and the depositional environment, including lithological association, stratigraphy, areal distribution, and associated physical processes. PSD is known to be a significant factor for evaluating bitumen recovery from an oil-sand mine. This is because presence of fines (evaluated by PSD analysis) affects the hot-water-separation process and processing-plant recovery prediction and provides grade control. Presence of more fines translates into lower recovery from commercial oil-sand processing. In this study, we investigate whether the PSD should be also considered a critical parameter for evaluation and estimation of permeability of an oil-sand reservoir. We show, by use of the data from Cenovus Energy’s Telephone Lake lease, that there is a strong relationship between permeability and PSD data. We also show that the information provided by the PSDs for permeability prediction is more significant than that inferred from a simple porosity/permeability relationship. Subsequently, we comment on permeability modeling by use of PSD data and list the techniques available for cleaning and modeling of multivariate PSDs. We document a methodology for modeling of PSDs and provide a work flow for incorporating these data in improved understanding and modeling of permeability and its distribution.
Over the last 30 years, laboratory testing has been conducted to investigate the geotechnical properties of Clearwater clay shales from the Clearwater formation in northeast Alberta, Canada. These properties are important for characterization of the overburden zones above in-situ oil-sands mines and for assessment of caprock integrity in steam-assisted-gravity-drainage (SAGD) projects. In general, caprock-integrity assessments include caprock geological studies, in-situ stress determination, constitutive-property characterization, and numerical simulations, which allow operators to ensure that steam-injection pressure does not cause any risk to the confinement of steam chambers. The aim of this study is to identify and provide the representative parameters that can enhance understanding of the geotechnical behaviour of the Alberta Clearwater formation clay shale. Moreover, it illustrates how the results can be used to extract constitutive model parameters for modelling the behaviour of this class of material. The parameters are also used for complex reservoir-geomechanical simulation for caprock integrity. These parameters are also compared with other Cretaceous clay-shale counterparts in North America.
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.
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.
The Athabasca oil sands deposit is the largest oil sands deposit in Alberta-Canada which contains about 1.7 trillion barrels (270×109 m3) of bitumen in-place. In the Athabasca oil sand, most of the bitumen deposits are found within a single contiguous reservoir, the lower cretaceous McMurray Formation.
Since mid 1980's, SAGD process feasibility has been field tested in many successful pilots and subsequently through several commercial projects in Athabasca-McMurray Formation. However, SAGD remains very energy intensive, extremely sensitive to geological and operational conditions, and an expensive oil recovery mechanism. Over the 20 years of SAGD experience in Athabasca, the only well configuration that has been field tested is the standard 1:1 configuration which has a horizontal injector lying approximately 5 meters above a horizontal producer.
This study examines the impact of using several modified well configurations for SAGD in the McMurray Formation in Athabasca in order to improve process performance. The technical feasibility of applying each arrangement was evaluated through sensitivity analysis. Numerical modeling was carried out using a commercial fully implicit thermal reservoir simulator; Computer Modeling Group (CMG) STARS 2009.13. The wellbore modeling was utilized to account for frictional pressure drop and heat losses along the wellbore. The reservoir properties were selected in order to accurately represent of the McMurray Formation in Athabasca.
The new well configurations provide operational and economical enhancement to the SAGD process over the standard well configuration in Athabasca area. The SAGD process response to different reservoir parameters of the McMurray Formation, such as mobile water saturation and reservoir heterogeneity in the form of bioturbated shale, has been investigated for the most promising of the new well configurations.