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.
The complicated nature of combustion reactions makes the performance prediction of in-situ combustion difficult. This study proposes a solution to better understand the complex chemical reaction schemes through systematically conducted Thermogravimetric Analysis and Differential Scanning Calorimetry (TGA/DSC) experiments.
In this study, results from combustion tube experiments (CTE) are integrated with kinetic and analytical modeling. The SARA (Saturates, Aromatics, Resins, and Asphaltenes) fractions of a bitumen sample were subjected to TGA/DSC experiments under air injection at a constant heating rate. Heat flow curves (DSC curves) were used to determine kinetic parameters by using Reaction Kinetic Models (Arrhenius Model, Coats-Redfern Model, Horowitz-Metzger Model, and Ingraham-Marrier Model).
The kinetic analyses conducted on separate SARA fractions and on bulk crude oil samples provided valuable information: asphaltenes require the largest activation energy but generate the greatest amount of heat upon combustion. Saturates provide large amounts of heat, which proves their ignition feature. Aromatics and Resins play an important role on asphaltene cracking, in addition to supplying large amounts of heat to asphaltenes upon burning.
In-situ combustion is a very promising enhanced oil recovery method which can yield high oil recovery. However, the unknowns associated to chemical reactions inhibit the prediction of combustion performance. This study provides a unique solution to find the correct and simple reaction kinetics by integrating reaction kinetic experiments with several kinetic analysis methods.
In order to satisfy the increase in world energy demand, the global oil and gas industry is expected to invest US$ 25 trillion from 2015 to 2040 in development projects (
Exploratory factor analysis using SPSS software identified three success criteria groupings - (1) Project Management Success, (2) Business Success, and (3) Future Potential/Growth. For success factors the number of groupings is six. These are (1) Project Management, Leadership & Team Competence, (2) Front End Loading, (3) Project External Context and Compliance, (4) Project Impacts on External Environment, (5) Project Risk and Quality Management, and (6) Project Connectivity with Local Resources Capacity. The criteria and factors identified are directly applicable to projects and programs in other domains such as mining, large scale infrastructure development, ship building, and defense acquisition. The results of this study can be used as a starting point towards the development of a success measurement methodology for industrial megaprojects.
The emergence of hydrocarbons within shale as a major recoverable resource has sparked interest in fluid transport through these tight mudstones. Recent studies suggest the importance to recovery of microfracture networks that connect localized zones with large organic content to the inorganic matrix. The paper presents a joint modeling and experimental study to examine the onset, formation, and evolution of microfracture networks as shale matures. Both the stress field and fractures are simulated and imaged.
A novel laboratory-scale, phase-field fracture propagation model was developed to characterize the material failure mechanisms that play a significant role during the shale rock maturation process. The numerical model developed consists of coupled solid deformation, pore pressure, and fracture propagation. Benchmark tests were conducted to validate model accuracy. Laboratory-grade gelatins with varying Young’s modulus were used as scaled-rock analogs in two-dimensional Hele-Shaw cell setups. Yeast within the gelatin generates gas in a fashion analogous to hydrocarbon formation as shale matures. These setups allow study and visualization of host rock elastic-brittle fracture and fracture network propagation mechanisms. The experimental setup was fitted to utilize photoelasticity principles coupled with birefringence properties of gelatin to explore visually the stress field of the gelatin as the fracture network developed. Stress optics image analysis and Linear Elastic Fracture Mechanics (LEFM) principles for crack propagation were used to monitor fracture growth for each gelatin type.
Observed and simulated responses suggest gas diffusion within and deformation of the gelatin matrix as predominant mechanisms for energy dissipation depending on gelatin strength. LEFM, an experimental estimation of principal stress development with fracture growth, at different stages was determined for each gelatin rheology. Synergy between diffusion and deformation determines the resulting frequency and pattern of fractures. Results correlate with Young’s modulus. Experimental and computed stress fields reveal that fractures resulting from internal gas generation are similar to, but not identical to, type 1 opening mode.
The novelty of our work is that microfracture networks are imaged and modeled as they form rather than measured after the fact. Host rock elastic-brittle fracture and fracture network propagation mechanisms are triggered by internal gas generation, microfracture frequency, connectivity, and topology are linked to material properties in a direct fashion.
In the Midway Sunset Oil Field in Central California, operators inject steam into the shallow diatomite formation to enhance heavy oil recovery through imbibition, wettability alteration, and viscosity reduction, among other mechanisms. The injected steam, however, does not always remain in the reservoir or return through the wells. In two zones in the study area, the steam comes out at the surface, creating sinkholes, seeps, and steam outlets (see Figure 1b and 1c). These phenomena, called "surface expressions," pose safety and environmental hazards. This study examines attributes of the zones with surface expressions that may contribute to their occurrence. It is hypothesized that the surface expressions are caused by leakage of steam through old improperly abandoned wells, high injection pressure, structurally controlled flow patterns, high injection volumes, or flow along naturally occurring faults, among other possible factors. Spatial statistical analysis using logistic regression and classification trees is used to explore the relationship between the surface expressions and spatial attributes. The results point to a significant spatial correlation between the surface expressions and two predictors: concentration of plugged wells and geologic seal thickness. These predictors emphasize the importance of both properly abandoning retired wells and having sufficient seal between the producing zone and the surface.
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.
Seright, Randall S. (New Mexico Institute of Mining and Technology) | Wang, Dongmei (University of North Dakota) | Lerner, Nolan (Cona Resources Limited) | Nguyen, Ahn (Cona Resources Limited) | Sabid, Jason (Cona Resources Limited) | Tochor, Ron (Cona Resources Limited)
This paper examines oil displacement as a function of polymer-solution viscosity during laboratory studies in support of a polymer flood in Canada’s Cactus Lake Reservoir. When displacing 1,610-cp crude oil from field cores (at 27°C and 1 ft/D), oil-recovery efficiency increased with polymer-solution viscosity up to 25 cp (7.3 seconds-1). No significant benefit was noted from injecting polymer solutions more viscous than 25 cp. Much of this paper explores why this result occurred. Floods in field cores examined relative permeability for different saturation histories, including native state, cleaned/water-saturated first, and cleaned/oil-saturated first. In addition to the field cores and crude oil, studies were performed using hydrophobic (oil-wet) polyethylene cores and refined oils with viscosities ranging from 2.9 to 1,000 cp. In field cores, relative permeability to water (krw) remained low, less than 0.03 for most corefloods. After extended polymer flooding to water saturations up to 0.865, krw values were less than 0.04 for six of seven corefloods. Relative permeability to oil remained reasonably high (greater than 0.05) for most of the flooding process. These observations help explain why 25-cp polymer solutions were effective in recovering 1,610-cp oil. The low relative permeability to water allowed a 25-cp polymer solution to provide a nearly favorable mobility ratio. At a given water saturation, krw values for 1,000-cp crude oil were approximately 10 times lower than for 1,000-cp refined oil. In contrast to results found for the Daqing polymer flood (Wang et al. 2000, 2011), no evidence was found in our application that high-molecular-weight (MW) hydrolyzed polyacrylamide (HPAM) solutions mobilized trapped residual oil. The results are discussed in light of ideas expressed in recent publications. The relevance of the results to field applications is also examined. Although 25-cp polymer solutions were effective in displacing oil during our corefloods, the choice of polymer viscosity for a field application must consider reservoir heterogeneity and the risk of channeling in a reservoir.
Fialips, Claire I. (Total S.A.) | Labeyrie, Bernard (Total S.A.) | Burg, Valerie (Total S.A.) | Maziere, Valerie (Total S.A.) | Muneral, Yann (Total S.A.) | Haurie, Helene (Total S.A.) | Jolivet, Isabelle (Total S.A.) | Lasnel, Regis (Total S.A.) | Laurent, Jean-Paul (Total S.A.) | Lambert, Laurent (Total S.A.) | Jacquelin-Vallee, Laurence (Total S.A.)
Steam-assisted gravity drainage (SAGD) is currently the preferred thermal-recovery method used to produce bitumen from Athabasca deposits in Alberta, Canada. SAGD is, however, an energy-intensive process with large amounts of greenhouse-gas (GHG) emissions and required water treatment. One option to reduce emissions and water usage is with solvent-based techniques, such as the NsolvTM process. Suncor and Nsolv have been working together on a bitumen-extraction solvent-technology (BEST) field demonstration at Suncor’s Dover test site. The solvent-injection–produced-oil ratio (SvOR) is among the key performance indicators (KPIs) of the BEST facility. Solvent breakthrough caused by inefficiency of thermodynamic trapping, such as subcool trapping, contributes to SvOR and affects the facility’s economic and artificial-lift efficiencies. Subcool is the temperature difference between the injected butane (at saturated condition) and produced fluids (mixture of butane condensate, upgraded bitumen, and formation water). One of the unknowns in this process is the efficiency of thermodynamic trapping. On the basis of field results, it is shown that, like the SAGD process, liquid-pool depletion presents a critical control on the performance of the recovery process. Although the produced fluids are depleted from the liquid pool at the base of the chamber, because liquid-butane viscosity dependency on temperature is not strong and its viscosity changes slightly with temperature, thermodynamic trapping (or subcool trapping) is not efficient. Stability analysis of BEST data suggests that vapor breakthrough is part of the process but can be minimized by operating at temperatures greater than the second subcool limit. The second subcool limit (or Nsolv optimal reservoir subcool) will vary over time, and it is shown to occur at slightly less than 4°C after liquid-pool development.
Bao, Yu (Research Institute of Petroleum Exploration & Development, CNPC) | He, Liangchen (Liaohe Oilfield Company Ltd, Petrochina) | Lv, Xue (Sino-Pipeline International Company Ltd.) | Shen, Yang (Research Institute of Petroleum Exploration & Development, CNPC) | Li, Xingmin (Research Institute of Petroleum Exploration & Development, CNPC) | Liu, Zhangcong (Research Institute of Petroleum Exploration & Development, CNPC) | Yang, Zhaopeng (Research Institute of Petroleum Exploration & Development, CNPC)
The Orinoco heavy oil belt in Venezuela is one of the largest extra-heavy oil resources in the world. It has become a major goal for the unconventional oil exploitation in these years. Now, the most common production method is to use the horizontal well cold production without sand. It is an economic and commercial process, and with the reservoir of this area have high initial gas to oil ratio (GOR), porosity and permeability with unconsolidated sand. However, after several years' production, the oil rate draws down quickly caused by the reservoir pressure drops; the key challenge of cold production is that the recovery factor (RF) tends to be only between 8% and 12%, implying that the majority of the oil remains in the oil formation. It is necessary to develop viable recovery processes as a follow-up process for cold production. Generally, steam based recovery method was widely used as a follow-up process for cold production. In this paper, steam fracturing (dilation) Cyclic Steam Stimulation (CSS) operation and Non steam fracturing (No dilation) CSS operation by using reservoir simulator is examined for a post cold production in extra heavy oil reservoir, in order to analyze the performance of the oil rate, cumulative steam-to-oil ratio (cSOR), steam depletion zone, greenhouse gas emission and some necessary parameters.
The key component of the steam fracturing (dilation) is the ability to inject high temperature and pressure steam into the formation to fracture the reservoir rock which in turn raises the rock permeability and mobilized the oil by lowering the visocisity. To compare the results of the dilation and no dilation CSS operation, this study reveal that due to the steam is injected into the reservoir by using the same cumulative cold water equivalent (CWE), the steam condensate; pressurized by steam vapour, fracture the formation. Dilation operation achieves higher oil rate, lower cSOR. The result also show that fraturing (dilation) of the reservoir during steam injection relieves the pressure which in turn lowers the steam injection pressure below the case where No dilation operation ouccurs.