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Calgary-based Tourmaline Oil Corp. announced today that it is acquiring Black Swan Energy in an all-stock deal valued at CAD $1.1 billion. The transaction is set to boost Tourmaline's output by 50,000 BOE/D and the company expects to average around 500,000 BOE/D by mid-2022. The operator said the Black Swan acquisition is one of several it has made recently to become the largest producer in the north Montney Shale area of British Columbia. Black Swan's 231,000-acre position gives Tourmaline an estimated 1,600 horizontal drilling locations and proven and probable reserves of 491.9 million BOE. Tourmaline said in its announcement that Black Swan has not booked material reserves in other areas that it sees as having high potential and complementary to its existing footprint.
Abstract Geomechanical rock properties correlations and modeling approach for conventional reservoirs are inappropriate and unsuitable for unconventional shale gas reservoirs where the shale formation is strong and has very low porosity. These correlations are critical in the development of 1D and 3D geomechanical models which are used for various field applications including drilling optimization, hydraulic fracturing design and operation, and field management. The study investigates various geomechanical rock properties and their relationships to one another using data extracted from rock mechanics testing conducted on shale core samples. For rock elastic properties correlations, dynamic elastic properties determined from compressional sonic velocity, shear sonic velocity and density are plotted against laboratory-measured static elastic properties obtained from triaxial tests. Steps were taken to further refine the properties correlations by separating the data from vertical and horizontal core samples, using data from tests conducted at in-situ confining stress condition, and focusing on data only taken from Field A and nearby fields. Similar steps were also taken to develop the correlations for rock strength properties. Correlations for the shale anisotropic elastic properties were also developed based on ratio of horizontal and vertical elastic properties. Blind tests were conducted on three wells in Field A using the new rock properties correlations which showed good matching of the predicted geomechanical properties with the new correlations and core measured test data.
An acquisition this week making ARC Resources the biggest player in the Montney Shale draws attention to a play where profits projections are up along with gas prices, though growth is likely to remain slow and steady. The purchase of Seven Generations Energy for shares worth $2.2 billion combines two companies with combined liquids rich gas production, which will total 340 BOE/D. ARC, which is also in the Pembina Cardium play, will become the large producer of gas liquids in Canada and is third largest natural gas producer. The reasons given for the deal are in lockstep with deals among big shale producers in the US--the efficiencies of running an operation that has more than double its production is expected to save $110 million a year by 2022. That, will increase the free cash flow which will allow it to reduce debt and "deliver incremental returns to shareholders."
ConocoPhillips announced this week that it is in the late stages of buying 140,000 net acres from Canadian independent Kelt Exploration for $375 million. The all-cash deal stands out since in recent years international oil companies and some US independents have steadily divested themselves of Canadian assets. Bucking this trend, ConocoPhillips will upon closing increase its position in western Canada's liquids-rich Montney Shale to 295,000 acres and add 15,000 B/D of Kelt's production--just under half of the seller's total production from Alberta and British Columbia. In 2019, ConocoPhillips reported about 63,000 B/D from its Canadian operations. The buyer also says that it will gain 1,000 additional drilling locations with an estimated cost of supply in the mid-$30s.
Liao, Lulu (Sinopec Research Institute of Petroleum Engineering & China University of Petroleum, Beijing) | Li, Gensheng (China University of Petroleum, Beijing) | Zhang, Hongbao (Sinopec Research Institute of Petroleum Engineering) | Feng, Jiangpeng (Sinopec Middle East R&D Center) | Zeng, Yijin (Sinopec Research Institute of Petroleum Engineering) | Ke, Ke (Sinopec Middle East R&D Center) | Wang, Zhifa (Sinopec Middle East R&D Center)
With the coming of increasingly large databases, the growing amount of computational resources and latest algorithmic advancements, data driven and machine learning techniques are considered as potential game changers in traditional Oil and Gas industry. Unconventional oil and gas formations, including basin central gas/oil, shale gas/oil, tight gas/oil, and coalbed methane formations, are abundant, which have become an increasingly important part of global energy supply and attracted increasing attention from the industry. In the development of unconventional hydrocarbon exploration, the high well placement density leads to more data and provides the condition to use data-driven methods for engineering parameters on well production could not be easily considered by traditional simulation methods.
The objective of this study is to optimize of completion parameters by data mining and ensemble machine learning methodologies which are essential for the development of the Montney Formation. Firstly, all the data with more than 80 variables over Canada Wapiti-Montney Tight gas formation have been collected and used for determining the most important engineering parameters by the sensitivity test. In additional, the time series analysis is used to identify the turning time when stimulation dominated effects disappeared in the entire production period. Based on the sensitive test and data mining results, multiple key parameters have been recognized and used as independent variables for the machine learning analysis, such as liner regression, support vector machine, neural networks, Gauss regression, etc. The corresponding assumptions for each learning methods are analyzed, benchmarked and discussed in this paper. In addition, a stacking model which ensemble top 3 best accuracy Machine Learning models is carried out to enhance the accuracy of production forecast ability in Montney Shale formation. During the model training, several feature engineering methods are used to lowering the difficulty for models to obtain knowledge in big data.
Based on the sensitivity analysis results, the following matrices, Stimulated Length (SL), Total Stage Count (TSC), Pumped Proppant per Length (PPL), Pumped Fluid Per Length (PFL) and Injection Rate (IR), are recognized as the most important and sensitive independent variables for production prediction in Wapiti-Montney tight gas formation. The final ensemble model is established by stacking three best individual machine learning algorithms of this study. They are random forest, XGBoost, and Light GBM respectively. The accuracy of prediction by ensemble model could reach as high as 90%, which is much higher than predictions before stacking process.
The application results were encouraging. Three Wapiti horizontal gas well was optimized by the proposed data driven workflow and the cumulative production were improved by 20% around the turning time point. Such new quick evaluation using Ensemble Machine Learning model could optimize the accuracy of prediction and provide simple rules of engagement for Well completion Design Optimization and decision-making throughout the entire development of Montney Tight formation in Wapiti field.
Magsipoc, E. (University of Toronto) | Li, M. (University of Toronto) | Abdelaziz, A. (University of Toronto) | Ha, J. (University of Toronto) | Peterson, K. (University of Toronto) | Grasselli, G. (University of Toronto)
The serial section technique was used to construct a high-resolution and high-quality fracture network image stack of a true triaxial hydraulic fracturing experiment on a shale sample from the Montney formation. The stack was used to create a point cloud and fracture surface meshes that were used for fracture analysis. Fractures were separated by subtracting the fracture intersections from the point cloud then applying a connected components algorithm to separate them. Point clouds were generated from these fractures and were thinned to achieve a 1-voxel thickness. After thinning, they were smoothed to reduce the aliasing effect from the image stack grid structure. Fractures were identified as either a bedding or non-bedding fracture by proxy of their orientation. Then, their surfaces were analyzed using a directional roughness metric. This roughness metric was used along with information about the stress state to evaluate the peak shear strength criterion for each individual fracture. The slipping potential of these fractures under the stress state applied by the true triaxial frame was estimated by the ratio of the actual shear stress on the fracture and the peak shear strength criterion.
Hydraulic fracturing (HF) creates flow channels either by opening pre-existing planes of weakness or by creating new ones within the rock matrix. The geometries of these fractures differ depending on a variety of influencers such as bedding, rock fabric, material strength, the local stress environment, and spatial heterogeneities embedded within the rock mass. The morphologies of these fractures can provide useful information on the expected fracture geometry and production of a reservoir. This can be achieved by fracture geometry quantification with roughness metrics and aperture to gain information for estimating fluid resistance and proppant performance. However, this information is not easy to obtain from the field.
Laboratory HF experiments provide useful insights to the mechanics of hydraulic fracturing performed in the field. Because they are physically accessible, the fractures created by the experiment can be opened and examined. Tan et al. (2017) illustrates an example of an examination of the fracture networks of multiple HF experiments performed under true triaxial stress. Their experiments provided insights on the sensitivity of the fracture network geometry to fluid viscosity and injection rate. However, this required them to take apart the sample to gain access to internal fractures. While they were only interested in the general fracture structure, this action may have potentially lost information on the smaller fractures within the network.
Abstract Aimed at sharing the unconventional wisdom gained from a hydraulic fracturing monitoring case study in the Montney tight gas play, the work showcases the ability of 4D modeling of collective behaviors of microseismic events to chase the frac fluid and navigate the spatiotemporal fracture evolution. Moreover, microseismicity-derived deformation fields are integrated with volumetric estimates made by rate transient analysis to calibrate spatially-constrained SRV models. Through the case study, we give evidence of fracture containment, evaluate the role of natural fractures and the use of diverting agents, estimate cluster efficiencies, conduct analytical well spacing optimization, model productivity decline induced by communication frac-hits from offsets, and provide contributing fracture dimensions and numerical production forecasts. To support the interpretations, we supplement the work by the results of 3D physics-based analytical modeling and multi-phase numerical simulations, and the findings are then validated using two extensive datasets: production profiles acquired by fiber optic DAS, and reservoir fluid fingerprints extracted from mud logs. Besides describing the evolution of seismicity during the treatment, the applied integrated fracture mapping process gives a more reliable and unique SRV structure that streamlines forward modeling and simulations in unconventional reservoirs as well as contributes to solving inverse problems more mechanistically.
Li, Mei (University of Toronto) | Magsipoc, Earl (University of Toronto) | Abdelaziz, Aly (University of Toronto) | Ha, Johnson (University of Toronto) | Guo, Jianchun (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Peterson, Karl (University of Toronto) | Grasselli, Giovanni (University of Toronto)
ABSTRACT Hydraulic fracturing creates highly conductive flow channels by injecting fracturing fluid at high pressures. A complex fracture network is generated in shale due to the contribution of the natural fractures, bedding planes and other zones of weakness. X-ray micro-computed tomography (μCT) has been used to visualize fracture complexity. The visualization accuracy is limited to the scanning resolution and density contrast within the material. An experimental approach is presented in this paper to three-dimensionally (3D) map the fracture network at micron (μm) resolution. A 3D fracture network is reconstructed based on serial-sectioned digital images of a shale cube hydraulically fractured under true-triaxial conditions. The hydraulic fractures are identified as opened natural fractures, activated bedding planes, and newly generated hydraulic fractures. Activated bedding planes represent the majority of hydraulic fractures, which significantly contributes to the lateral growth of the fracture geometry. Rough and crooked natural fracture planes can be observed. On the contrary, the activated bedding planes are smooth and relatively straight. This fracture mapping method can also be applied to quantitatively study fracture aperture to ultimately improve the conductivity prediction of the fracture network. 1. INTRODUCTION Hydraulic fracturing creates highly conductive flow channels in low-permeability reservoirs by injecting fracturing fluid at high pressures to stimulate reservoir production. The complexity of the fracture network created by hydraulic fracturing in shale is a result of the interference between the hydraulically induced fractures and the existing weak planes, such as bedding planes and natural fractures. Increasing the stimulated reservoir volume (SRV) or enhancing the complexity of the fracture network can be beneficial to improve production. Understanding the fracturing mechanism by studying the fracture complexity is of vital importance to hydraulic fracturing design and to enhance production. A variety of destructive and non-destructive experimental methods (Ramandi et al., 2017; Tan et al., 2017) have been used for studying fracture complexity in rock mass. The non-destructive observational method μCT has advantages in mapping the fracture complexity over destructive methods. However, visualization of the fracture network in large samples can be problematic. The problem arises from the compromise between the resolution of acquired images using the μCT and capturing a representative field of view (FOV) of the sample. Capturing a large FOV means that micron-scale fractures are represented by only a few voxels in the direction normal to the fractures and in some cases they are sub-resolution. Additionally, existing weak planes that exhibit low density contrast to the rock matrix may be misconstrued as fractures during the process of image segmentation. To overcome these two limitations of relying solely on μCT to capture fracture complexity in large samples, an experimental method is proposed in this paper to three-dimensionally (3D) map the fracture network at micron (μm) resolution utilizing the idea of serial section reconstruction. The method of 3D reconstruction of serial section has been successfully used in medicine and biology for centuries since its first applications in embryology (Levinthal and Ware, 1972). To the authors knowledge, this is the first time this method is being applied to reconstruct the fracture geometry in a hydraulically fractured shale sample.
Abstract A single-point entry completion architecture has been implemented in several hydraulically stimulated resource plays across North America. The objective is to understand whether the innate properties of the rock and what we can diagnose about how it hydraulically fractures can inform the question of applicability of single-versus multi-point completion designs. Wells were treated using a single-point entry design in the Montney and the Duvernay and an assessment of well performance was carried out. Multiple diagnostic pads have been carried out over several years in both formations, including microseismic and geochemical fingerprint data allowing for a general characterization of the gross geometry and connectivity. Initial results from a fiber are available in the Montney with a single point completion design. The fracture diagnostic data was compiled and described in the context of the nine main sub-surface controls on the connectivity. In the Montney, it is relatively clear how completion intensity changes, like stage length, in single-point entry wells change the production performance outcome. In the Duvernay, there is significantly more uncertainty. This contrast contributed to the decision to treat several follow-up pads in the Montney via a single-point entry design, whereas a multi-point plug and perf completion is preferred for the Duvernay wells. Costs and stage isolation are considerations, but one other contributing explanation is that the dominantly planar fracture geometry in the Montney enables each stage to contribute proportionally, thus ensuring the stimulation distribution effectiveness from the near-to the far-field. The dry-gas area of the Montney is very stiff, with an absence of natural fractures, a paucity of faults, no containment issues and no significant frac barriers. Conversely, in the Duvernay, the inherent complexity in the fracture geometry complicates the stimulation distribution effectiveness in the far-field. Furthermore, the lower mobility of a liquids-rich hydrocarbon system probably benefits from the potentially tighter frac spacing, possible in a multi-cluster design, even with a probable increase in non-uniformity over single-point. It is hypothesized that in formations that develop complex fracture geometries, ‘putting all your eggs in one basket’ with a single-point entry design, needs to be assessed along with the other value drivers for the well architecture selection.
Abstract Today, almost half of Western Canada's natural-gas production comes from the Triassic-aged Montney formation, a six-fold increase over the last 10 years while gas production from most other plays has declined. In the last few years, demand for condensate as diluent for shipping bitumen has driven development of liquids-rich Montney natural gas leading to a surge in gas production and gas-on-gas competition in the Western Canadian Sedimentary Basin (WCSB), which has driven local natural gas prices down. This has had a material effect on the operations and finances of companies active in the Western Canada and is re-shaping the Canadian gas industry. A significant portion of this growth has taken place in NE British Columbia and with the planned electrification of the industry in British Columbia, including the nascent LNG operations, will influence tomorrow's power industry in this region. NE British Columbia is a geographically large area with sparse population and the power supply into this region has lagged behind development of oil and natural gas resources. The area was originally served from geographically closer NW Alberta. More recently, supply was established from the BC Hydro power grid with the most significant developments being Dawson Creek-Chetwynd Area Transmission (DCAT) completed in 2016 and the additional 230 kV transmission projects scheduled for completion in 2021.