The integrity of a geological formation is a primary concern in any underground fluid injection project. Hydraulic pressurization due to injection may reduce fault strength, trigger fault slippage, and cause fault reactivation. The reactivated fault affects the fluid migration and loss from the injection zone, which might undermine the efficiency and safety of the project. Hence, a reliable modeling of fault reactivation is critical.
In this work, we propose a new approach to modeling fault reactivation. Faults are complex structures and generally consist of core and damage zones with macroscopic fracture networks. The embedded discrete fracture model (EDFM) is an effective method for simulating complex geometries such as fracture networks and nonplanar hydraulic fractures. We used the EDFM in conjunction with a compositional reservoir simulator to model fault reactivation under hydraulic pressurization. The phase behavior and fluid flow are accurately modeled using the equation of state (EOS) compositional simulation.
The activation of fault occurs at a threshold pressure, which depends on the chemo-mechanical properties of the formation rock. The threshold pressure can be estimated using analytical, numerical, or laboratory methods. In this study, we provided an analytical calculation of the threshold pressure. Moreover, we used a refined, multiphase, compositional, and geomechanical reservoir simulator to predict the threshold pressure. The coupled geomechanical reservoir simulation is computationally expensive; therefore, we suggest using this approach, in the absence of laboratory measurements, to simulate only a few regions of the formation with distinctive rock types. The estimated values of threshold pressures for different geomechanical rock types can be used in our simulations.
We performed large-scale reservoir simulations using the EDFM to investigate the storage capacity of carbon depositional formations representative of the Gulf of Mexico and monitor CO2 migration paths before and after fault reactivation. The results of this study are helpful to evaluate the capacity and integrity of carbon storage sites. Our methodology gives promising results for the prediction of fault reactivation and CO2 migration within a formation.
The proposed approach accurately models faults and their reactivation. It does not require refinement and geomechanical calculation for each gridblock in the domain, which reduces the computational time by at least five times. The significance of this approach becomes more pronounced in large formations with multiple rock types and faults. Although we used our approach for the study of carbon storage, the same methodology can be used for other types of fluid injection, such as water disposal.
A comprehensive analytical model of the Steam-Assisted Gravity Drainage (SAGD) process is developed, encompassing steam chamber rise, sideways expansion, and the confinement phases. Results are validated using experimental and field data.
A new analytical model for predicting steam chamber rise velocity and oil production rate during this period is developed. In this theory, by combining volumetric oil displacement with Darcy oil rate considering the indirect frontal instability effect, the rise velocity, and the steam chamber height are calculated. The model is extended to predict oil production, heat or steam injection rate, heat consumption and Cumulative Steam-Oil Ratio (CSOR) during this phase. The model results show the CSOR decreases, with an increasing oil production rate. The rise velocity increases with an increase in permeability and temperature. Results are validated with experimental and field data.
The sideways steam chamber expansion is treated by a new analytical approach which is called Constant Volumetric Displacement (CVD) where injection rate must be increased continuously for a constant oil rate. At the final stage, adjacent chambers interfere, reducing the effective head for gravity drainage and the heat requirement in this system. For a small well spacing, confinement occurs earlier, heat loss starts decreasing sooner, resulting in a lower CSOR, than for a large spacing.
The above analytical SAGD models including rise, lateral spreading, and confinement phases are combined to obtain the Comprehensive Constant Volumetric Displacement (CCVD) model. The results are validated against experimental and field data. Excellent agreement was obtained with laboratory and field results.
Hadavand, Mostafa (University of Alberta) | Carmichael, Paul (ConocoPhillips Canada) | Dalir, Ali (ConocoPhillips Canada) | Rodriguez, Maximo (ConocoPhillips Canada) | Silva, Diogo F. S. (University of Alberta) | Deutsch, Clayton Vernon (University of Alberta)
4D seismic is one of the main sources of dynamic data for heavy-oil-reservoir monitoring and management. 4D seismic is significant because seismic attributes such as velocity and impedance depend on variations in reservoir-fluid content, temperature, and pressure distribution as a result of hydrocarbon production. Thus, the large-scale nature of fluid flow within the reservoir can be evaluated through information provided by 4D-seismic data. Such information may be described as anomalies in fluid flow that can be inferred from the unusual patterns in variations of a seismic attribute. During steam-assisted gravity drainage (SAGD), the steam-chamber propagation is fairly clear from 4D-seismic data mainly because of changes in reservoir conditions caused by steam injection and bitumen production. Anomalies in the propagation of the steam chamber reflect the quality of fluid flow within the reservoir. A practical methodology is implemented for integration of 4D seismic into SAGD reservoir characterization for the Surmont project.
Particle size, shape and mineralogy are considered as primary characteristics of sand and sandstone. Several techniques have been developed for the particle size and shape analysis of unconsolidated sands. However, few of these techniques can be used for sandstones. Most particle size measurement techniques provide a spherical equivalent of the particle size and neglect the particle shape. Although several techniques have been developed for the particle size and shape analysis of the unconsolidated sands, these techniques could not be used for the size and shape variation analysis of consolidated or semi-consolidated sandstone.
Recently, X-ray micro CT scanning technique has been used for the evaluation of petrophysical properties of sandstones. This paper presents a workflow for the measurement of particle size and shape of sandstones. This research utilized X-ray micro CT scans for 2-dimensional particle shape measurements including Sphericity, Convexity, Aspect Ratio and Feret diameters. The methodology presented in this paper is the first step toward assessing the particle shape and size variation of sandstones for use in such applications as sand control design.
Image-J, an Open-source software, was used to process and filter the X-ray raw images. A new tool was developed to measure the shape factors (i.e. Sphericity, Aspect Ratio and Convexity) and size variations. A series of images from different sandstones were analyzed and compared to their lab measurements. The image calculated porosity and permeability showed some degree of deviation from the lab measured porosity and permeabilities.
This paper presents a new workflow to measure the particle size and shape for the sand control design in sandstone reservoirs. With a larger database it is possible to develop a correlation to calculate rock properties from image size analysis technique and correct them for the shape variation. The next step will be to measure the 3D size and shape from the image analysis and compare to the shape and size analysis from dynamic image analysis.
Roostaei, M. (University of Alberta) | Guo, Y. (University of Alberta) | Velayati, A. (University of Alberta) | Nouri, A. (University of Alberta) | Fattahpour, V. (RGL Reservoir Management) | Mahmoudi, M. (RGL Reservoir Management)
ABSTRACT: Unconsolidated sand was packed on a slotted-liner coupon in large-scale sand retention tests (SRT) and was subjected to several stress conditions, corresponding to the evolving stress conditions during the life cycle of a SAGD producer. Cumulative produced sand at the end of testing was measured as the indicator for sand control performance. Retained permeability was calculated by measuring pressure drops near the liner and was considered as the quantification of the flow performance of the liner. Experimental results indicate the liner performance is significantly affected by the stress induced compaction of the oil sand. The stress results in the sand compaction, leading to a denser sand, hence, a lower porosity and permeability. The lower porosity results in a higher pore-scale flow velocity, which can trigger more fines mobilization, hence, a higher skin buildup. With respect to sanding, the higher stress can stabilize the sand bridges: Increased normal forces between near-slot sand particles result in a higher inter-particle friction, hence, more stable sand bridges and less produced sand. The lower and upper bounds of slot window are governed by plugging and sand production, respectively. Experimental results indicate an upward shift in both the lower and upper bounds at elevated stress conditions
Steam Assisted Gravity Drainage (SAGD) is a thermal recovery technology currently employed to extract heavy oil and high viscosity bitumen from Alberta oil sands.
Due to the unconsolidated nature of oil sands, SAGD wells are prone to producing sand, hence, requiring sand control devices to prevent sanding during oil production. Slotted liners are a prominent sand control technique, which have been extensively used in Alberta's SAGD wells to avoid sand production problems. The design of the slots must allow a free flow of fines and clays through the slots and the porous medium around the well, with minimal plugging.
In SAGD recovery method, a large volume of high-pressure steam is injected by the injector well to reduce the bitumen viscosity and facilitate the production. Continuous injection of the high-pressure steam leads to a complex alteration of the in-situ stresses and the associated geomechanical properties within the reservoir and even the neighboring strata. Porosity and permeability of the reservoir sand are influenced in this process.
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.
Permeability enhancement of oil sands during SAGD, a gravity drainage process, is desirable to minimize start-up time and improve overall recovery efficiency. High pressure cold water injection may be used as a stimulation process where water is injected into a SAGD well pair at high pressure and limited volume to distort the sand texture and enhance permeability or break thin impermeable interbeds impeding the hot fluid movement in long-term SAGD operation.
In this study an iteratively coupled reservoir-geomechanics simulation is used to evaluate the extent of permanently stimulated and dilated volume as well as the efficacy of rupturing the impendent impermeable barriers. The geomechanical model incorporates a non-linear elasto-plastic constitutive model calibrated with the available McMurray sand public data. Estimates of the initial oilsand permeability and porosity were calibrated using the flow and shut-in periods of existing minifrac test data. The updated coupling parameters from the stress module in any time step enables the 3D thermal multi-phase reservoir model to sensitize various water injection scenarios and optimize the permeability enhancement affecting long-run performance of the SAGD recovery. The study reveals a minimum injection pressure about 15% larger than the initial vertical stress is required for an efficient dilation operation.
Thermal recovery processes in oil sands typically rely quite heavily on gravity drainage as one of the primary drive mechanisms. Steam Assisted Gravity Drainage (SAGD) is one such process that requires gravity drainage and vertical communication between the steam injector and producer for an efficient start-up and long-term recovery. The oil sands, especially those in the Alberta are very densely packed and if they are failed in shear at low effective stress they will dilate and increase permeability. This enhancement of permeability can be used to accelerate SAGD start-up as well as increase the efficiency of long-term drainage. This paper presents a calibrated reservoir and geomechanical model illustrating the pressure requirements (or effective stress) for significant permeability increases that will positively affect SAGD performance.
A detailed study has been conducted to model oil sand dilation by means of cold water injection prior to a typical SAGD process. The goal was to demonstrate an increase in absolute and water relative permeability from a rate and volume limited cold water injection into the SAGD well pairs. An advanced coupled reservoir and geomechanical simulation technique has been implemented to conduct this study.
ABSTRACT: This paper investigates the potential of using heating or cooling to induce shear or tensile failure of the shales present in low-quality oil sands of Alberta and thus improve vertical communication and recovery. Several methods were considered and explored by conceptual simulations, in a setting representative of Nexen Energy ULC Long Lake reservoir. Various scenarios were simulated using a coupled thermal reservoir and geomechanical modeling software (GEOSIM). In order to capture the relevant physics, significant extensions to the software were required, for modeling cryogenic cooling and thermal dependencies of properties. The main findings of the study are:
- Electric heating using the SAGD injector well can induce shear failure in shales close to it. It also creates a shear failure region around the injector and it could be considered as a modification of the start-up strategy.
- Modeling of cryogenic cooling requires capturing several ice formation effects, which have a strong effect on stresses and failure. Cryogenic cooling directly in the shale predicted progressive shear failure to a considerable distance from the injector. 2-D simulations of cooling the SAGD injector show that the horizontal stresses can be considerably reduced and will favor vertical fractures
- Hydraulic fracturing after a sufficient cooling period appears to be a feasible process which can be carried out with significantly reduced injection pressures, comparable to MOP (maximum operating pressure).
As the in-situ oil sands development in Alberta matures, projects in lower quality reservoirs must be considered. Poor quality sands often contain interbedded shales with areal extent which can significantly impair vertical communication and drastically reduce recovery in conventional SAGD or related hybrid processes. Several methods have been envisioned to provide vertical communication through the shales, but none of these have been proven in the field so far. Of these, the use of multi-stage fracturing technology (Saeedi and Settari, 2016) is not always applicable because the stress regime may not favor vertical fractures. A desirable method would be one that is feasible to implement at startup time, does not require excessive pressures, does not endanger caprock integrity and provides sufficient improvement in vertical communication. In this research, we have considered and evaluated several techniques, which are based on geomechanical principles:
a) Local heating at shale locations. The idea is to create sufficient increase in horizontal stress to induce shear failure and increase in vertical permeability across the barrier. The implementation could be via induction or microwave electric heating, or one can also consider use of resistive heating elements in the wells with heat transfer into the formation mainly by conduction.
b) Local cooling (using cryogenic technology). If it is possible to selectively cool the shale, tensile fracturing could develop. This mechanism is believed to exist also on fracture face in waterflood induced fracturing and has been quantified by simulation (Tran et al., 2013).
The carbon steel lines carrying brackish water associated with a heavy oil SAGD (Steam Assisted Gravity Drainage) operation in Northern Alberta experienced severe localized corrosion attack specific to bends, welds, and other locations containing a gas phase. Pinhole leaks occurred after only seven years of service. A comprehensive study was conducted which included consideration of possible damage mechanisms based on flow regime, water chemistry, gas composition, piping elevation changes, and various corrosion product/material analysis.
This paper is a continuation of a previous study3 which was based on similar failures which occurred at similar facility. New findings are discussed regarding how the pipes are damaged. It is concluded that CO2 breakout is the major cause of severe pitting on the bends and preferential weld attack despite a low CO2 concentration of < 30 mg/L in the water. The CO2 breakout under turbulent flow and/or piping elevation changes resulted in corrosion rates up to 1.125 mm/y (45 mpy) at 10°C. In comparison, the De Waard-Milliams model predicted a corrosion rate of only 0.0425 mm/y (1.7 mpy)!
Turbulent flow (Reynolds number is 1.7 × 105) and depressurization contributed to the CO2 breakout from the water which caused severe corrosion with the protective siderite readily removed. Corrosion occurring at CO2 gas/water/metal boundaries resulted in high pitting rates and corrosion was aggravated with the increase in mass transfer when gas bubbles collapse.
Oxygen corrosion and microbial induced corrosion as secondary damage mechanisms are also discussed in this paper. The corrosion damage mechanism study provides guidance for BW piping/pipeline designs and material selection.
In SAGD facilities, brackish water (BW) containing trace amounts of free CO2 accounts for 15% of the boiler feed water used for steam generation. In 1975, De Waard and Milliams1 developed a now well-known CO2 corrosion model. This model has been widely used to predict CO2 corrosion of carbon steel (CS) in the oil and gas industry. The De Waard-Milliams model was based on tests conducted with 0.1% NaCl solution under oxygen free conditions with the liquid flowing around the electrodes at 1 m/s. The corrosion rate (CR) was determined by means of weight loss and polarization resistance measurements.
The in-situ steam based technology is still the main exploitation method for bitumen and heavy oil resources all over the world. But most of the steam-based processes (e.g., cyclic steam stimulation, steam drive and steam assisted gravity drainage) in heavy oilfields have entered into anexhaustion stage. Considering the long-lasting steam-rock interaction, how to further enhance the heavy oil recovery in the post-steam injection era is currently challenging the EOR (enhanced oil recovery) techniques. In this paper, we present a comprehensive review of the EOR processes in the post steam injection era both in experimental and field cases. Specifically, the paper presents an overview on the recovery mechanisms and field performance of thermal EOR processes by reservoir lithology (sandstone and carbonate formations) and offshore versus onshore oilfields. Typical processes include thein-situ combustion process, the thermal/-solvent process, the thermal-NCG (non-condensable gas, e.g., N2, flue gas and air) process, and the thermal-chemical (e.g., polymer, surfactant, gel and foam) process. Some new in-situ upgrading processes are also involved in this work. Furthermore, this review also presents the current operations and future trends on some heavy oil EOR projects in Canada, Venezuela, USA and China.
This review showsthat the offshore heavy oilfields will be the future exploitation focus. Moreover, currently several steam-based projects and thermal-NCG projects have been operated in Emeraude Field in Congo and Bohai Bay in China. A growing trend is also found for the in-situ combustion technique and solvent assisted process both in offshore and onshore heavy oil fields, such as the EOR projects in North America, North Sea, Bohai Bay and Xinjiang. The multicomponent thermal fluids injection process in offshore and the thermal-CO2and thermal-chemical (surfactant, foam) processes in onshore heavy oil reservoirs are some of the opportunities identified for the next decade based on preliminary evaluations and proposed or ongoing pilot projects. Furthermore, the new processes of in-situ catalytic upgrading (e.g., addition of catalyst, steam-nanoparticles), electromagnetic heating and electro-thermal dynamic stripping (ETDSP) and some improvement processes on a wellbore configuration (FCD) have also gained more and more attention. In addition, there are some newly proposed recovery techniques that are still limitedto the laboratory scale with needs for further investigations. In such a time of low oil prices, cost optimization will be the top concerns of all the oil companies in the world. This critical review will help to identify the next challenges and opportunities in the EOR potential of bitumen and heavy oil production in the post steam injection era.