Multicomponent joint inversion is an important technique for reservoir prediction using PP and PS seismic data. The addition of PS data is helpful to solve the problem of multiplicity and increase the precision of reservoir prediction. Based on 3D multicomponent seismic data of M area in Canada, the logging response characteristics of the reservoir are analyzed and the sensitive parameters are optimized. The PP and PS joint inversion, characteristic curve inversion and lithofacies probability simulation are integrated to increase the precision of reservoir prediction gradually. The application results show that, due to the reservoir prediction based on joint inversion, the top and bottom interface of oil sands reservoir and the distribution of interbed are described in detail. And important geophysical prospecting results are provided for oil sands development in this area.
Presentation Date: Monday, October 15, 2018
Start Time: 1:50:00 PM
Location: 213A (Anaheim Convention Center)
Presentation Type: Oral
Polymer flooding is an Enhanced Oil Recovery process usually employed in tertiary mode, after a waterflood. However, in heavy oil reservoirs the process is also commonly employed either in primary or secondary conditions because waterflooding is not considered to be economic. For new projects the question often arises as to whether it is better to start by injecting water or to go straight to polymer injection. Injecting water first provides a baseline for comparison with the polymer flood and in some cases allows an earlier start-up of the project due to the construction and commissioning of polymer mixing facilities. On the other hand, the risk is that water channeling could occur and could be irreversible, thus reducing the potential recovery during polymer injection.
Some authors have reported laboratory studies comparing the different methods but so far there has been no field results published that could be used for validation or guidance. Although several polymer flood projects in heavy oil have been reported in the past few years they are still relatively few and no detailed field results have been reported to date on that issue.
The largest polymer flood in heavy oil is currently being implemented in the Pelican Lake field in Canada, with several hundreds of horizontal wells injecting polymer. All the methods - primary, secondary and tertiary - have been tested and as a result the field provides a large database that allows to compare recovery and other parameters for each method.
Although such a comparison is mostly focused on a single field and is thus inherently biased, it should provide useful guidelines for companies looking to start new pilots or field projects. Relevant literature on this topic will also be reviewed to present a complete review of the issue.
This paper presents a numerical assessment for the Maximum Operating Pressure (MOP) of a Steam Assisted Gravity Drainage (SAGD) project considering the effect of the Natural Fractures (NFs) and intrinsic anisotropy of the cap shale. Current numerical and heuristic assessments usually ignore the effect of the intrinsic and structural anisotropy of the cap shale in the caprock integrity studies.
A coupled Hydro-Thermo-Mechanical (HTM) model was developed to assess the MOP. The coupled model employed a novel constitutive model which was developed to investigate the effect of NFs and intrinsic anisotropy in the cap shale. The coupled model was validated against surface heave measurements, and later utilized in a sensitivity study to assess the MOP for cases with different number of NF sets, fracture density and fracture dip angle.
Results indicate that the MOP is highly sensitive to the fracture density and dip angle. According to the results, vertical fractures have minor effect on the MOP while oblique fractures with the dip angle between 25° to 65° significantly affect the MOP. Neglecting the NFs can lead to significant overestimation of the MOP. This highlights the necessity to include the NFs in the caprock integrity assessments.
The numerical model presented in this paper considers the intrinsic anisotropy and the presence of NFs in the cap shale, while existing mathematical tools for caprock integrity studies have not incorporated the intrinsic and structural anisotropy. Ignoring the anisotropy in caprock can potentially cause a considerable overestimation of the MOP.
The Pelican Lake field in northern Alberta (Canada) is home to the first successful commercial application of polymer flooding in higher viscosity oils (i.e. greater than 1,000 cp), which has opened up new opportunities for the development of heavy oil resources.
The field produces from the Wabiskaw "A" reservoir which has thin pay (2 to 6 meters) and exhibits a significant viscosity gradient across the field, with oil viscosities as low as 600 cp in the existing waterflood and polymer flood area to over 200,000 cp in the current undeveloped "immobile" area. This unique geological feature limits the application of chemical injection to the less viscous areas of the field and calls for different methods for the heavier accumulations.
As a first step to develop alternate technologies capable of recovering oil from heavier areas of the field not ideal for polymer flooding, a hot water injection pilot was designed and implemented in June 2011. The hot water injection scheme was applied to a transition area where dead oil viscosity ranges from 3,000 cp to approximately 15,000 cp. It consists of one horizontal producer supported by two horizontal hot water injectors, with an injector-producer distance of 50 meters for both injectors, and 3 vertical observation wells equipped to monitor pressure and temperature between one injector and the producer.
The pilot was operated in three phases. The first phase consisted of 6 months of primary production period to obtain a baseline of the pilot performance prior to hot water injection. The second phase began in June 2011 and consisted of hot water injection through the edge injectors. The third phase was started in March 2012 and consists of hot water edge injection accompanied by hot water circulation in the production well as a means to stimulate oil production. One of the features of this stage is the use of an insulated coil tubing, which continuously delivers hot water to the toe of the producer and allows continuous stimulation and uninterrupted oil production.
This paper describes the mechanical components of the pilot and discusses the results obtained with an emphasis on the hot water circulation stage which has proven to be very effective. Oil production increased from approximately 6 m3/d during the flood stage, to more than 25 m3/d during the hot water circulation stage and has held relatively steady for more than 2 years.
The data captured has been reconciled with analytical and reservoir simulation models, and results suggest that the technology could help unlock some of the heavier oil accumulations in the field.
This paper investigates the effect of anisotropic behavior of caprock shales on the caprock failure pressure in SAGD projects. Shales and mudstones exhibit strong anisotropy at the micro and macro scales. However, the anisotropic behavior has been neglected in the existing published works on this subject.
In this research project, a coupled hydro-thermo-mechanical model was developed for the assessment of caprock integrity in thermal operations. A transversely isotropic constitutive model in the elastic range was combined with an anisotropic failure criterion to capture the intrinsic anisotropy of the cap shale. The coupled tool was validated against field data and employed in a study to determine the effect of shale anisotropic behavior on the pressure associated with caprock breach.
Results display the effect of shale anisotropy on caprock response in terms of deformations, stresses and failure pressure. The assumption of isotropic shale behavior in caprock integrity assessment for a case study resulted in the overestimation of the failure pressure by about 10%.
Existing numerical models for evaluating the integrity of caprocks during thermal operations employ isotropic constitutive laws. These models are believed to be deficient in capturing strongly anisotropic response of shales and mudstones. The research described in this paper incorporated elasto-plastic shale anisotropy in the caprock failure analysis model for the first time. The paper demonstrates the importance of capturing shale anisotropy in the accurate prediction of caprock breach pressure in SAGD projects.
Romanova, U. G. (Weatherford Laboratories Canada) | Ma, T. (Weatherford Laboratories Canada) | Piwowar, M. (Weatherford Laboratories Canada) | Strom, R. (Calgary Rock and Materials Services Inc.) | Stepic, J. (JMS Geological Consultants)
Canada ranks third in the world in terms of oil reserves which are primarily heavy oil and oil sands. In situ production of heavy oil and bitumen by thermal methods based on steam injection is a commercial technology. However, as the availability of better quality deposits is declining, the industry is moving towards development of lower quality oil sands. Lower quality oil sands are typically finer, have lower initial oil saturation and a more complex mineralogy.
Thermal formation damage associated with steam injection is discussed in the paper in regards to oil sands located in the Lower Cretaceous formations in Western Canada. The focus of the paper is the McMurray, Clearwater and Grand Rapids oil deposits. Petrographic data (thin section analysis, X-ray diffraction and scanning electron miscroscopy) and physical rock properties are used to compare three oil sand formations. Results of laboratory experiments to obtain relative permeability data and evaluate thermal formation damage are discussed. Examples of the high temperature-high pressure water-oil relative permeability and steamflood data for three formations are presented. The paper shows that thermal formation damage is reservoir specific.
A multidisciplinary approach is needed to obtain a good understanding of oil sand deposits, in particular lowerquality reservoirs. Laboratory testing to evaluate formation damage effects and obtain relative permeability data is essential for reservoir simulation and feasibility studies for a specific project.
Steam-assisted gravity drainage (SAGD) is one successful thermal-recovery technique applied in Alberta oil-sand reservoirs. When considering in-situ production from bitumen reservoirs, one must reduce viscosity for the bitumen to flow toward the production well. Steam injection is currently the most promising thermal-recovery method. Although steamflooding has proved to be a commercially viable way to extract bitumen from bitumen reservoirs, caprock integrity and the risk of losing steam containment can be challenging operational problems. Because permeability is low in Albertan thermal-project caprock formations, heating greatly increases the pressure on any water trapped in pores as a result of water thermal expansion. This water also sees a great increase in volume as it flashes to steam, causing a large effective-stress reduction. After this condition is established, pore-pressure increases can lead to caprock shear failure or tensile fracturing, and to subsequent caprock-integrity failure or potential casing failure. It is typically believed that low-permeability caprocks impede the transmission of pore pressure from reservoirs, making them more resistant to shear failure (Collins 2005, 2007). In considering the "thermo-hydromechanical pressurization" physics, low-permeability caprocks are not always more resistant. As the steam chamber rises into the caprock, the heated pore fluids may flash to steam. Consequently, there is a vapor region between the steam-chamber interface penetrated into the caprock and the water region within the caprock which is still at a subcritical state. This study develops equations for fluid mass and thermal-energy conservation, evaluating the thermo-hydromechanical pressurization in low-permeability caprocks and the flow of steam and water after steam starts to be injected as part of the SAGD process. Calculations are made for both short-term and long-term responses, and evaluated thermal pressurization is compared for caprocks with different stiffness states and with different permeabilities. One can conclude that the stiffer and less permeable the caprock, the greater the thermo-hydromechanical pressurization; and that the application of SAGD can lead to high pore pressure and potentially to caprock shear, and to subsequent steam release to the surface or potential casing failure.
Matt Abram and Graham Cain, Devon Canada Summary The unconsolidated sands of the Lower Cretaceous McMurray formation are the primary host of the Athabasca oil-sands deposit in Alberta, Canada. Alberta has one of the world's largest nonconventional hydrocarbon resources with an estimated 1.8 trillion bbl of heavy oil (ERCB ST98-2013). The Pike 1 Project is a jointventure between Devon Canada Corporation (operator) and BP Canada Energy Group ULC. The Pike 1 Project is currently under a multiyear appraisal program to evaluate the McMurray bitumen resources that are amenable to steam-assisted gravity drainage (SAGD). In the Pike 1 Project area, the particle-size distribution (PSD) of the middle McMurray reservoir sands is highly variable because of the complex nature of the depositional environment. In order to understand the McMurray reservoir sands, Devon has exercised rigorous laboratory sampling and quality-control procedures to confirm the comprehensiveness of the PSD data set. By use of an unsupervised hierarchical classification technique, a dynamically growing self-organizing tree algorithm was used to cluster all of the PSD histograms from within the bitumen net-pay zone into one of four sand classes on the basis of similarity. Each sand class has a distinct PSD and permeability range. Using the sand classes, Devon extracted select intervals of core that closely matched the PSD histogram of each class to provide physical samples, termed "sandprints," to fulfill sand-control-testing objectives. Further work included integrating the sand classes within the Pike 1 geological model, 3D permeability mapping, and upscaled sand-class volumes for SAGD well-pad optimization. This paper describes the process by which Devon has evaluated and classified the Pike 1 PSD data set into distinct sand classes within the unconsolidated middle McMurray reservoir. Devon's methodology of acquiring these sands, necessary for sand-control testing, is also discussed in detail, emphasizing the overall effectiveness of the process. By use of this innovative PSD classification process as a supporting tool to reservoir characterization, Devon intends to realize the following benefits: - SAGD horizontal-well-pair placement optimization - A more methodical approach to laboratory testing of horizontal-liner technology for SAGD producers and injectors - Improved reservoir management Introduction Pike is a multistage, joint-venture project, owned 50% each by Devon Canada (operator) and BP Canada Energy Group ULC (Figure 1). The first commercial scheme applied for on the Pike lease is the Pike 1 Project, and it is currently under review by the Alberta Energy Regulator and Alberta Environment.
The Pelican Lake heavy-oil field in northern Alberta (Canada) has had a remarkable history since its discovery in the early 1970s. Initial production by use of vertical wells was poor because of the thin (less than 5 m) reservoir formation and high oil viscosity (800–80,000-plus cp). The field began to reach its full potential with the introduction of horizontal drilling and was one of the first fields worldwide to be developed with horizontal wells. However, with primary recovery at less than 10% and 6.4 billion bbl of oil in place (OIP), the prize for enhanced oil recovery (EOR) is large. Initially, polymer flooding had not been considered as a viable EOR technology for Pelican Lake because of the high viscosity of the oil, until the idea came of combining it with horizontal wells.A first - unsuccessful - pilot was implemented in 1997, but the lessons drawn from that failure were learned and a second pilot was met with success in 2006. The response to polymer injection in this pilot was excellent, with oil rate increasing from 43 BOPD to more than 700 BOPD and remaining high for more than 6 years; the water cut has generally remained at less than 60%. Incremental recovery over primary production is variable but can reach as high as 25% of oil originally in place (OOIP) in places. This paper presents the history of the field and then focuses on the polymer-flooding aspects. It describes the preparation and results of the two polymer-flood pilots, as well as the extension of the flood to the rest of the field (currently in progress). Polymer flooding has generally been applied in light- or medium- gravity oil, and even currently, standard industry-screening criteria limit its use to viscosities up to 150 cp only. Pelican Lake is the first successful application of polymer flooding in much higher-viscosity oil (more than 1,200 cp), and as such, it opens a new avenue for the development of heavy-oil resources that are not accessible by thermal methods.