In recent years, the Cyclic Solvent Injection (CSI) process has shown to be a promising method for enhanced heavy oil recovery in Canada. CSI laboratory studies work for only 2 to 3 cycles due to low incremental oil in subsequent cycles. However, in field pilots the CSI keeps operational after many years. This study intends to capture the full production mechanisms responsible of heavy oil production in CSI to better understand the phenomena in field applications.
A physical sandpack model was used to test the CSI response. The sandpack was saturated with live heavy oil of 7900 mPa.s viscosity at 24 ° C, and primary production was run. Five CSI tests were then conducted to simulate the performance under the gravity effects. The experiments were conducted in a horizontal and vertical mode injection respectively at high and low-pressure depletion rates using 70 mol % CH4 and 30 mol % C3H8 solvent mixture. The sandpack was Computed Tomography (CT) scanned after every cycle to provide information about the gas and oil saturations evolution.
When CSI was run on the horizontal core, the incremental oil recovery was negligible for both slow and fast drawdown rates. When the sandpack was vertically flipped and rapidly produced, the three CSI cycles exhibited higher recover, and similar incremental recovery per cycle. This result indicated that even at high drawdown pressures, gravity segregation can effectively maximize the cross-flow mixing between solvent and heavy oil to penetrate the un-swept areas.
The results of this study demonstrate the importance of gravity drainage in the CSI process, and the relative significance of gravity forces on successful oil recovery rates. The results of this study illustrate the limitations of previous horizontal laboratory tests and show an improved test configuration for modeling and prediction of the improved response observed in CSI pilots.
Santamaria, Carla (Exxon Mobil Corporation) | Flood, Jim K. (ExxonMobil Development Company) | Schuberth, Paul C. (Exxon Mobil Corporation) | Morell, Jorge J. (Exxon Mobil Corporation) | Hinojosa, Jaime R. (Exxon Mobil Corporation) | Haddock, Justin (ExxonMobil Development Company) | O'Donnell, Hugh (Ingenium Training & Consulting Ltd.) | Sandelands, Eric (Ingenium Training & Consulting Ltd.) | Cowan, Mel (Ingenium Training & Consulting Ltd.) | Higgins, Alan (Ingenium Training & Consulting Ltd.)
An approach for enhancing safety performance in Energy Industry field applications by integrating decision-making science will be presented. Results – both qualitative and quantitative – will demonstrate step change potential in safety performance in pursuit of plateau breakthrough to zero high severity incidents. Safe Choice empowers and enables safe decision-making at all levels of an organization by providing new knowledge and techniques, and linking these to current behavioral based safety practices.
Emerging understanding about brain and social science, as it relates to Energy Industry safety, is provided in practical discussion centered around decision-making. Workforce members are entrusted and empowered with new knowledge, personal decision-making style survey results, and an appreciative inquiry discussion that integrates brain science concepts in a simple effective way to their existing, familiar work processes and tools for managing safety and risk in their operating, drilling, and construction field sites. Following Safe Choice, individuals have a greater understanding of their own human performance and decision-making. Focusing on individual learning and awareness is the differentiator.
The program was first developed for the ExxonMobil Hebron Project integration, hook-up and commissioning construction site in Newfoundland and Labrador, Canada during 2015-2016. Together, with other transformational safety leadership initiatives, Safe Choice contributed to best-in-class safety performance. Safe Choice was then further developed and adapted for application within operating field sites during 2017. With further success, the program is now being implemented globally with an agile, user-centered design philosophy and approach.
The small group approach to training includes each worker receiving an individual decision-making style report and creates an atmosphere of appreciative inquiry, trust and openness. Developing leadership supporting strategies that foster a continuation of this atmosphere once back in the field (and outside of the classroom) has proven effective, with use of the new language and concepts evident in regular daily meetings such as toolbox talks, shift handover and safety meetings, as well as being used between workers during conversations in the field. Many locations where Safe Choice has been implemented have excellent safety performance, and will show both qualitative and quantitative measures of success achieved.
Energy Industry Leaders, Operations, Drilling, Construction and Safety Professionals will gain new knowledge on successful next-step integration of decision-making science into safety programs for protecting their workforce. This will expand and extend earlier insights from panel discussions at SPE HSSE Meetings in New Orleans (April 2017) and Abu Dhabi (April 2018). This paper includes results of the program so far.
Unconventional completions in North America have seen a paradigm shift in volumes of proppant pumped since 2014. There is a clear noticeable trend in both oil prices and proppant volumes – thanks to low product and service costs that accompanied the oil price crash in early 2015. As the industry continues to recover, operators are reevaluating completion designs to understand if these proppant volumes are beyond what is optimal. This paper analyzes trends in completion sizes and types across all major unconventional oil and gas plays in the US since 2011 and tracks their impact on well productivity.
Completion and production data since 2011 from more than 70,000 horizontal wells in seven major basins (Gulf Coast, Permian, Appalachian, Anadarko, Haynesville, Williston and Denver Julesburg basins) and 11 major oil/gas producing formations were analyzed to examine developments in proppant and fluid volumes. Average concentration of proppant per gallon of fluid pumped was used to understand transitional trends in fracturing fluid types with time. Production performance indicators such as First month, Best 3 or Best 12 months of oil and gas production were mapped against completion volumes to evaluate if there are added economic advantages to pumping larger designs.
In general, all major basins have seen progressive improvements in average well performance since 2011, with the Permian Basin showing the highest improvement, increasing from an average first-six-months oil production of 25,000 bbl in 2011 to 75,000 bbl in 2017. The Gulf Coast basin, where the Eagle Ford formation is located, has seen a 6-fold increase in proppant volumes pumped per foot of lateral since 2011 while the Permian and Appalachian basins hit peak proppant volumes in 2015 and 2016 respectively. In Permian and Eagleford wells, higher proppant volumes in general have resulted in better production up to a certain concentration. In Williston and Denver basins, most operators are moving away from gelled fluids, and reduced average proppant concentration per fluid volume pumped shows inclination toward hybrid or slickwater designs. While some of these observations are tied to reservoir quality, proppant volumes have begun to peak as operators have either reached an optimal point or are in the process of reducing volumes.
Demand for proppant is expected to nearly double by 2020. As oil prices continue to recover, well AFEs continue to increase, despite multiple efforts to improve capital efficiency. The need for enhanced fracture conductivity and extended half-lengths on EURs are been discussed by combining actual observed production data and sensitivities using calibrated production models. The industry is moving toward large-volume slickwater fracturing operations using smaller proppants, but he operating landscape is expected to see a correction when such designs become less economical.
This paper was prepared for presentation at the Unconventional Resources Technology Conference held in Houston, Texas, USA, 23-25 July 2018. The URTeC Technical Program Committee accepted this presentation on the basis of information contained in an abstract submitted by the author(s). The contents of this paper have not been reviewed by URTeC and URTeC does not warrant the accuracy, reliability, or timeliness of any information herein. All information is the responsibility of, and, is subject to corrections by the author(s). Any person or entity that relies on any information obtained from this paper does so at their own risk.
Ghanizadeh, Amin (University of Calgary) | Clarkson, Chris R. (University of Calgary) | Song, Chengyao (University of Calgary) | Vahedian, Atena (University of Calgary) | DeBuhr, C. (University of Calgary) | Deglint, H. J. (University of Calgary) | Wood, J. M. (Encana Corporation)
A schematic of the liquid permeameter, which was designed and constructed in-house for the measurement of liquid permeability using steady-state and pulse-decay flow techniques, is provided in Figure 1. The liquid flow tests were performed under controlled axial/radial confining pressures in a biaxial core holder.
This paper was prepared for presentation at the Unconventional Resources Technology Conference held in Houston, Texas, USA, 23-25 July 2018. The contents of this paper have not been reviewed by URTeC and URTeC does not warrant the accuracy, reliability, or timeliness of any information herein. All information is the responsibility of, and, is subject to corrections by the author(s). Any person or entity that relies on any information obtained from this paper does so at their own risk. The information herein does not necessarily reflect any position of URTeC.
Zhu, Da (RGL) | Gong, Lu (University of Alberta) | Qiu, Xiaoyong (University of Alberta) | Hu, Wenjihao (University of Alberta) | Huang, Jun (University of Alberta) | Zhang, Ling (University of Alberta) | Fattahpour, Vahidoddin (RGL) | Mahmoudi, Mahdi (RGL) | Luo, Jing-Li (University of Alberta) | Zeng, Hongbo (University of Alberta)
The scaling has been found to be a major problem in thermal production, such as in the Steam-Assisted Gravity Drainage (SAGD) operation. In addition to providing a favorite environment for corrosion, scaling could result in extreme plugging in sand control devices. Therefore, any coatings for the equipment and completion in thermal production should provide significant anti-scaling surface properties. This paper presents a detailed study, including field and laboratory testing, on application of the Electroless Nickel Coating (ENcoating) in thermal production environment. Initially, ENcoated and uncoated carbon steel samples were tested in laboratory to assess the scale, hardness and adhesion of inorganic and organic materials. Successful laboratory testing lead to a field testing plan, which involves deploying the ENcoated and uncoated samples into a horizontal well for thermal production. The specimens were recovered after certain time and a comprehensive X-ray Photoelectron Spectroscopy (XPS) and Energy-Dispersive Spectroscopy (EDS) were performed to assess accumulation of fouling substances on ENcoated and uncoated carbon steel. This study suggests the application of the ENcoating technology to solve the problems caused by scale, and adhesion of organic and inorganic material in thermal production. The comprehensive laboratory testing and field data from the SAGD wells shows that ENcoating significantly improves the well integrity in the harsh thermal production environment.
ABSTRACT: The in situ stress regime is one of the most important inputs for any subsurface project in civil, mining and petroleum engineering, and combined with soil and/or rock strength generates a geomechanical model, which can be used to predict the ultimate loading that geological materials can withstand, and the required type of mechanical support needed to ensure the structural integrity of any excavation, such as tunnels, shafts, and boreholes. In this work we describe a comprehensive workflow that was carried out to constrain the in situ stress regime in the southern Saskatchewan region, Western Canada. The in situ stress regime was constrained by a geomechanical modeling approach, using acquired petrophysical wireline logging in boreholes, rock strength properties measured on core samples through triaxial tests, and micro-fracturing tests carried-out at different depths along a borehole. This complete dataset significantly contributed to the reliability of the in situ stress characterization, as the microfrac tests, mainly in shallow horizons, constrained the Minimum Horizontal Stress gradient, whilst borehole imaging showed rock failure patterns at the borehole wall (breakouts and fractures) and provided a way of constraining the Maximum Horizontal Stress by reproducing the rock failure with geomechanical modeling. The constrained stress regime exhibits a transition from shallow to deep horizons, and overall is under a strike slip faulting condition. The results of this study greatly contribute to a better understanding of present day subsurface stresses in the region.
1. INTRODUCTION AND BACKGROUND
The western Canada sedimentary basin has received some attention in the past from studies on characterizing the in situ stress regimes. Bell et al. (1994) presented a study with findings on stress regimes and stress orientation in the region, which was synthetized by Hamid (2008) as shown in Figure 1.
The map yields a good expression of the regional tectonics, with high stress concentration near the Rocky Mountains where trust faulting can be inferred, and as it moves towards the East the stress regime turns into strike slip, and eventually normal faulting. The stress direction also aligns very well with the Rocky Mountains, having the Maximum Horizontal Stress (SHmax) mostly normal to them.
In his work, Hamid (2008) compiled a very broad range of information about the subsurface stresses in the region by using petrophysical logging data and an extensive database of hydraulic fracturing in boreholes, obtaining a high confident correlation between instantaneous shut-in pressure (ISIP) and fracture closure pressure (FCP) across the region.
Fluid diffusivity inversion and injection-induced microseismicity provide useful means of evaluating unconventional reservoirs. When taking into consideration geomechanics, linear poroelasticity equations provide the key connection between diffusion and microseismicity. This work explores microseismicity generation from a probabilistic point of view, embedding uncertainty assessment in its quantification. Bayesian framework serves as the base for probabilistic analysis.
The primary objective of this work is to develop a new microseismicity probabilistic model framework that can be used for uncertainty quantification in data analysis as well as to provide forward modeling of microseismicity. Results are tested against real data of Horn Rives shales in Western Canada, and show good prediction of the number of actual microseismicity occurrences against time.
The novel probabilistic model is derived from Directed Graphic Model using a statistical learning framework. Stochastic Poisson process combined with a specific rate model is integrated to generate a likelihood function. Both, parameter inference and microseismic event forecast are assisted by Bayesian theorem. The model has an intrinsic statistical learning root, which specifically uses observed microseismic data to update model parameters and then is applied for microseismicity prediction.
The model is extended to take into account basic geomechanical principles.
The novelty of this study is the development of a probabilistic microseismic prediction model which obeys rate-and-state law based relative seismicity rate constitutive equations. The model inherently considers time dependence of nucleation and fault geomechanics. It can be used for planning purposes in the pre-hydraulic fracturing stage.
Weng, Yibin (State Key Laboratory of Petroleum Pollution Control, CNPC Research Institute of Safety and Environmental Technology) | Xue, Ming (State Key Laboratory of Petroleum Pollution Control, CNPC Research Institute of Safety and Environmental Technology) | Cui, Xiangyu (State Key Laboratory of Petroleum Pollution Control, CNPC Research Institute of Safety and Environmental Technology)
The reduction of greenhouse gas emission in oil and gas production could bring several benefits including energy conservation, cost reduction and economic returns. The direct emission measurements and reduction potential evaluation is the prerequisite to achieve an effective reduction goal on greenhouse gas emission. Based on the survey of production processes and related parameters, a series of greenhouse gas emission sources were identified and measured. The emission sources including production processes, leakage-prone facilities such as dehydrator, boilers, heaters, associated gas treatment plant, light hydrocarbon recovery unit, storage tank, and gas flaring were measured. A series of leakage detection and measurement instruments were applied as well, such as Hi-Flow™ Sampler, impeller flowmeter, Bascom-Turner gas sentry and gas flow probes, etc. Based on the measured emission data, a simulation model was then used to evaluate the specific forms, sources and the reduction potentials of the greenhouse gases. The measured greenhouse gas emissions showed that: evaporation and flashing losses from storage tanks were the largest source, accounting for 86% of the total methane emission, and 42% of the total greenhouse gas emissions. The contribution of methane emissions from heaters and boilers during incomplete combustions was less than 1% of the total methane emissions, and about 16% of the total greenhouse gas emissions. When controlling technology on storage tank losses was applied, methane emission could be reduced by 81.7%, and the greenhouse gas emissions could be reduced by 39.9%. Furthermore, such controlling technologies also presented substantial economic benefits through the recovery of fuel gas. In this study, the recovery potential of various greenhouse gas emission sources were analyzed. In addition, a preliminary cost-benefit analysis was performed per the emission categories, reduction potentials, and the feasibility of reduction technologies. Finally, the probability on the application of such reduction technologies were evaluated.