Canada has the opportunity to become an energy superpower on the global stage, and it is the city of Calgary in the western province of Alberta that will lead the way. Located in the heart of the resource-rich Western Canada Sedimentary Basin--which includes the oil sands, the second-largest deposit of oil in the world--Calgary is the decision center of a young country's vast energy industry. It is vibrant and hopeful, a place driven by the western spirit of determination and innovation. Calgary sits in a rich valley at the intersection of two rivers--a spot where the Canadian prairie meets the foothills and just a bit further, the Rocky Mountains. It is a beautiful region, but historically a difficult one in which to exist.
This paper presents a new workflow for the simulation of in-situ combustion (ISC) dynamics. In the proposed method, data from kinetic cell experiments, depicting the combustion chemistry, are tabulated and graphed based on the isoconversional principle. The tables hold the reaction rates used to predict the production and consumption of chemical species during in-situ combustion.
This new method of representing kinetics without the Arrhenius method is applied on one synthetic and two real kinetic cell experiments. In each case, the new method reasonably captures the reaction pathways taken by the reacting species as the combustive process occurs. A data-density sensitivity study on the tabulated rates for the real case shows that only four experiments are required to capture adequately the kinetics of the combustion process. The results are, however, found to be sensitive to the size of the time step taken. The method predicts critical changes in the reaction rates as the experiment is exposed to different temperature conditions, thereby capturing the speed of the combustion front, temperature profile, and fluid compositions of a simulated combustion tube experiment.
The direct use of the data ensures flexibility of the reaction rates with time and temperature. In addition, the non-Arrhenius kinetics technique eliminates the need for a descriptive reaction scheme that is typically computationally demanding, and instead focuses on the overall changes in the carbon oxides, oil, water and heat occurring at any time. Significantly, less tuning of parameters is required to match laboratory experiments because laboratory observations are easier to enforce.
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.
Mahmoudi, Mahdi (RGL Reservoir Management) | Roostaei, Morteza (RGL Reservoir Management) | Fattahpour, Vahidoddin (RGL Reservoir Management) | Sutton, Colby (RGL Reservoir Management) | Fermaniuk, Brent (RGL Reservoir Management) | Zhu, Da (RGL Reservoir Management) | Jung, Heeseok (RGL Reservoir Management) | Li, Jiankuan (University of Alberta) | Sun, Chong (University of Alberta) | Gong, Lu (University of Alberta) | Shuang, Shuo (University of Alberta) | Qiu, Xiaoyong (University of Alberta) | Zeng, Hongbo (University of Alberta) | Luo, Jing-Li (University of Alberta)
Standalone screen has been widely used as sand control solution in oil industries for over a century. Screen plugging and impairments by formation fines, scaling and corrosion cost oil and gas industry significant amount of resources. This study presents a detailed study on the corrosion and plugging of slotted liner, wire wrap screen and mesh screen samples extracted from the field to better understand some of the mechanisms for these poor field performances.
Three types of standalone screen were received from operating wells to study the failure mechanism of the screen and provide recommendations for recompletion. A thorough visual inspection of all screens was performed and documented in this paper. From the results of the visual inspection a certain section of each screen was cut for further detailed microscopic study to better understand the scaling and plugging mechanism, as well as microscopic geometry of the plugged and corroded zone.
The results highlighted the importance of the corrosion in the base pipe on the observed performances. All the studies pointed toward the flow dependence corrosion behavior, and the role of the water cut on the corrosion rate. The wire wrap screens have been in service for less than a year, yet the extensive corrosion led to creation of several holes in the pipe. The study showed the corrosion initiated from inside the pipe. Similarly, the corrosion of the slotted liner samples showed a strong flow dependent corrosion rate, where the corrosion rate on the slot/formation interface was slightly higher. The mesh screen showed very high plugging percentage by formation fines, where a thick film of clay and fine sand covered the space between the mesh and the base pipe. The results indicated that an inappropriate design of the mesh and pore could cause significant plugging.
This paper provides several field examples of the corrosion and plugging of the standalone screens. The results could help engineer to better understand the risk of corrosion and plugging on the standalone screen design. This paper provides some general guidelines for assessing the scaling and corrosion potential at field condition based on the results of the screens studied in the paper.
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.
One of the key steps toward improving the predictability of air-injection-based processes relies on the development of accurate phase-behavior models of the oil.
Historically, for in-situ combustion (ISC) in heavy oils and bitumens, phase behavior was often ignored because the physical aspects of the process (e.g., distillation) were not considered to be as significant as the oxidation reactions. However, this step is important for several reasons. First, the compositional model should reflect the phase behavior of the original fluids. Second, reaction rates are dependent on the concentrations of the reactants, which in turn are affected by the volatility of the components. This is particularly important for lighter oils (but not unimportant for heavier oils), where the phase equilibrium between the liquid and vapor can have a significant effect on the flammability range for vapor-phase combustion at given temperature and pressure conditions. Finally, for the case of lighter oils, a good phase-behavior model is required to capture the compositional effects of the resulting flue-gas drive.
This study presents a practical work flow to develop a phase-behavior model in terms of saturates/aromatics/resins/asphaltenes (SARA) fractions that is aligned with the reaction-modeling approach used in most kinetic models. The methodology requires conventional-oil-characterization (i.e., dependent on distillation cuts) and conventional-phase-behavior experiments (e.g., differential liberation), as well as oil characterization in terms of SARA fractions.
The first step of the method consists of splitting the heaviest oil fraction (i.e., plus fraction), followed by lumping all of the single-carbon-number (SCN) components, in such a way that the new oil characterization honors the SARA data available, such as composition and the physical properties of each fraction (e.g., molecular weight). In addition, the gas components (e.g., methane) would be treated as additional components as necessary. The second step is to tune an equation of state (EOS), in terms of the SARA-based model, to match the relevant laboratory experiments. Finally, the tuned EOS would be used to export the equilibrium constants (K-value tables) to the thermal numerical simulator.
Different examples on the application of the phase-behavior-modeling work flow are presented and discussed in detail for heavy and light oils. This work opens up opportunities to model the ISC process for any oil (i.e., light or heavy) using the currently available kinetic models, which in turn is an important step toward improving the predictability of ISC processes using reservoir simulation.
Ouled Ameur, Zied (Cenovus Energy Inc) | Kudrashou, Viacheslau (Texas A&M Engineering) | Nasr-El-Din, Hisham A. (Texas A&M University) | Forsyth, Jeffrey (nFluids Inc) | Mahoney, John (Mahoney Geochemical Consulting) | Daigle, Barney (AkzoNobel)
The acidizing of sour, heavy-oil, weakly consolidated sandstone formations under steam injection is challenging because of fines migration, sand production, inorganic-scale formation, corrosion issues, and damage caused by asphaltene precipitation associated with these sandstone formations. These and other similar problems cause decline in the productivity of the wells, and there is a recurring need to stimulate them to restore productivity. The complexity of sandstone ormations requires a mixture of acids and several additives, especially at temperatures up to 360°F, to accomplish successful stimulation. Three treatments were tested on a horizontal well in the field: hydrochloric acid (HCl); Chelating Agent B, a high-pH chelant; and Chelating Agent A, or glutamic acid N,N-diacetic acid (GLDA). The first two treatments with 15 wt% HCl and high-pH (pH=10) Chelating Agent B produced results below expectations. The third treatment using GLDA was successful, and the well productivity increased significantly. The field treatment with GLDA included pumping the treatment fluid, which was foamed to create proper rheological characteristics and a better-controlled pumping process. The treatment fluids were displaced into the formation by pumping produced water and were allowed to soak for 6 hours. In this paper, we evaluate the field applications of GLDA using geochemical modeling, production data, and analysis of well-flowback fluids after the field treatments.
One of the unanswered issues with steam applications is the wettability state during the process. Removal of polar groups from the rock surface with increasing temperature improves water wettability; however, other factors, including phase change, play a reverse role on it. In other words, hot water or steam will show different wettability characteristics, eventually affecting the recovery. On the other hand, wettability can be altered using steam additives. The mechanism of these phenomena is not yet clear. The objective of this work is to quantitatively evaluate the steam-induced wettability alteration in different rock systems and analyze the mechanism of wettability change caused by the change of the phase of water and chemical additives.
Heavy-oil from a field in Alberta (27,780 cP at 25°C) was used in contact angle measurements conducted on mica, calcite plates, and rock pieces obtained from a bitumen containing carbonate reservoir (Grosmont). All measurements were conducted at a temperature range up to 200°C using a high-temperature high-pressure IFT device. To obtain a comprehensive understanding of this process, different factors, including the phase of water, pressure, rock-type, and contact sequence were considered and studied separately.
Initially, the contact angles between oil and water were measured at different pressures to study the effect of pressure on wettability by maintaining water in the liquid phase. Secondly, the contact angle was measured in pure steam by keeping pressure lower than the saturation pressure. The influence of contacting sequence was investigated by reversing the sequence of generating steam and introducing oil during measurement. These measurements were repeated on different substrates. Different temperature resistant chemicals (surfactants and alkalis) were added to steam during contact angle to test their wettability alteration characteristics at different temperature and pressure conditions (steam or hot-water phases). The results showed that wettability of tested substrates is not sensitive to pressure as long as the phase has not been changed. The system, however, was observed to be more oil-wet in steam than in water at the same temperature, for example, in the case of calcite.
Analysis of the degree of the wettability alteration induced by steam (or hot-water) and temperature was helpful to further understand the interfacial properties of steam/bitumen/rock system and useful in the recovery performance estimation of steam injection process in carbonate and sand reservoirs.
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.