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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.
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.
A challenge in microseismic monitoring is quantification of survey acquisition and processing error, and how these errors jointly effect estimated locations. Quantifying acquisition and processing error, and uncertainty has multiple benefits, such as more accurate and precise estimation of locations, anisotropy, moment tensor inversion, and, potentially, allowing for detection of 4D reservoir changes. Here we quantify uncertainty due to acquisition, receiver orientation error, and hodogram analysis. We use a probabilistic location approach to identify the optimal bottom well location based upon known source locations. Probability density functions (PDF) are utilized to quantify uncertainty and propagate it through processing, including in source location inversion to describe the 3D event location likelihood. Changes in the early processing steps have allowed for understanding of location uncertainty and improved the mapping of the microseismic events.
Presentation Date: Tuesday, October 16, 2018
Start Time: 8:30:00 AM
Location: 208A (Anaheim Convention Center)
Presentation Type: Oral
ABSTRACT: A seismic monitoring case study is documented for stimulation of multiple wells completed in the Lower Montney Shale. A network of 4 broadband stations and 1 accelerometer were deployed and recorded numerous minor seismic events with moment magnitude between 0.5 and 2.8. Sequential hydraulic fracture stages progressively activated several parallel, critically- stressed faults, resulting in induced seismicity during the injection. The case study provides key insights about the spatial and temporal characteristics of the seismogenic faults, and the relationship to fracturing operations. Source mechanisms show a predominantly strike-slip mechanism consistent with lineaments apparent from the seismic locations. The case study highlights observations during multiple fault activation with progressive fault activation and the corresponding ground motion, and provides seismic observations conducive to effective mitigation following a traffic light protocol.
Injection induced seismicity is an increasing concern throughout North America, particularly associated with salt water disposal in the U.S. Mid-continent and hydraulic fracturing in Western Canada. Hydraulic fracturing operations within localized regions of three reservoirs in Canada has documented induced seismicity with local magnitudes up to 4.6 Ml in the case of the largest event in the Montney trend. Regulators have imposed mandatory monitoring and a traffic light system where operations are modified to mitigate events where seismic magnitude exceeds a specific level.
The Montney shale is an active unconventional reservoir in Western Canada, where large scale hydraulic fracturing has been utilized to economically recover hydrocarbons. In NE British Columbia, the Montney operations occur near the Fort St. John graben structure. High volume hydraulic fracturing has resulted in felt seismicity, including some of the largest recorded induced seismicity associated with hydraulic fracturing (British Columbia Oil Gas Commission (BCOGC, 2014). In addition to the imposition of a traffic light system where operations are required to cease if magnitudes greater than 4 occur, ground motion requirements have also been introduced to understand local effects of felt activity.
In this paper, a case study is described using a local seismic array to monitor stimulation of four Lower Montney treatment wells. The resulting seismicity indicates several parallel, pre-existing faults were activated during treatment of the pad.
ABSTRACT: Hydraulic fracturing (HF) is an indispensable technique in the exploitation of the Montney formation, one of the largest shale gas plays in North America, due to its ultra-low permeability. Good understanding of the geomechanical properties is essential for reducing potential hazards and enhancing the design of the HF programs. Basic geomechanical properties of Montney shale, like Young’s modulus, Poisson’s ratio, uniaxial strength, cohesion and friction angle, have been reported by several researches. However, few results about the fracture behavior can be found in the literature. This paper presents the Mode I and Mode II fracture toughness (KIc and KIIc) of Montney shale. The material properties could be used for further analysis and numerical simulation. KIc and KIIc are measured using the semi-circular bending method (SCB) and double shear method (DS), respectively. The SCB sample is a semi-circular disk with an edge notch throughout the sample thickness while cylindrical sample with two sets of notches on the top and bottom is used in the double shear test (DS). Confining pressure up to 50 MPa is applied to the DS sample to ensure Mode II failure. The result shows KIIc increases nonlinearly with pressure up to 30 MPa until an upper limit is approached.
The Montney Formation is a Lower Triassic stratum covering approximately 130,000 km2 in British Columbia and Alberta. Its thickness typically ranges between 100 m and 300 m, increasing westerly from 0 m at the erosional margin of the basin in the east to over 300 m in the west before it outcrops in the Rocky Mountains (Alberta Energy Regulator, 2013; Rivard et al., 2014). The depth to the top of the Montney Formation also increases to the west from approximately 500 m in the east/northeast to over 4000 m in the west/southwest (Ghanizadeh et al., 2014; Rivard et al., 2014). The oil and gas exploration of the Montney’s conventional sandstone and dolostone reservoirs has started since the 1950s. However, the Montney siltstones remained undeveloped until 2005, for the reason that the permeability of the tight shale is very low (NEB, 2009). Two key technology, horizontal drilling and multi-stage hydraulic fracturing, make the develop the unconventional tight gas economically viable (Alberta Energy Regulator, 2013).
This work establishes an effective approach to predict pore pressure in theoverpressured Montney shale and overburden from sonic logs by implementingnormal-trend and explicit methods. The cause of the overpressure condition inthe Montney is also addressed. These two methods were selected on the basis ofthe study carried out by Contreras et al. (2012) that worked successfully forpore pressure prediction under subpressured conditions in parts of the westernCanada sedimentary basin (WCSB). As a second objective, the stress-faultingregime was determined in the study area by use of stress polygons and data fromdiagnostic fracture-injection-test analysis as a quantification of the minimumhorizontal stress. This is of paramount importance because there is not ageneric theory explaining the stress-faulting regime for most of the westernregion of the WCSB. The Eaton method from sonic logs (Eaton 1975) and theBowers method (Bowers 1995) were implemented in two vertical wells drilledthrough the Montney shale. The first part of the analysis considered two normalcompaction trends, but unreasonable pressure profiles were obtained andrequired a revision on the depositional environment. It was found that for thestudy area, three normal compaction trends have to be considered. The Bowersmethod was initially implemented using both loading and unloading conditions inorder to establish a safe range of pore pressure to allow successful wellplans. It is concluded that undercompaction could be masked as the onlyoverpressure mechanism in the Montney shale in the study area. The formationexperiences an inverse faulting regime that will lead to the creation ofhorizontal hydraulic fractures. The Eaton method using three normal compactiontrends and an exponent equal to 0.9 works successfully in the study area. TheBowers method uses the loading and the unloading conditions, and the specificcorrelation parameters were found to be suitable for the study area and can beextrapolated to adjacent future production and exploratory wells.
Contreras, Oscar (Schulich School of Engineering, University of Calgary) | Hareland, Geir (Schulich School of Engineering, University of Calgary) | Aguilera, Roberto (Schulich School of Engineering, University of Calgary)
Abstract This work establishes an effective approach to predict pore pressure in the overpressured Montney Shale and overburden from sonic logs by implementing normal-trend and explicit methods. The cause of the overpressure condition in the Montney is also addressed. These two methods were selected on the basis of the study carried out by Contreras et al. (2011) that worked successfully for pore pressure prediction under subpressured conditions in parts of the Western Canada Sedimentary Basin (WCSB). As a second objective, the stress faulting regime was determined in the study area by using Stress Polygons and data from diagnostic fracture injection test analysis as a quantification of the minimum horizontal stress. This is of paramount importance since there is not a generic theory about the stress faulting regime for most of the west region of the WCSB. The Eaton method from sonic logs (Eaton, 1975) and the Bowers method (Bowers, 1995) were implemented in two vertical wells drilled through the Montney shale. The first part of the analysis considered two normal compaction trends but unreasonable pressure profiles were obtained and required a revision on the depositional environment. It was found that for the study area three normal compactions trends have to be considered. The Bowers method was initially implemented using both loading and unloading conditions in order to establish a safe range of pore pressure to allow successful well plans. It is concluded that undercompaction could be masked as the only overpressure mechanism in the Montney shale in the study area. The formation experiences an inverse faulting regime that will lead to the creation of horizontal hydraulic fractures. The Eaton method using three normal compaction trends and an exponent equal to 0.9 works successfully in the study area. The Bowers method using the loading and the unloading conditions, and the specific correlation parameters were found to be suitable for the study area and can be extrapolated to adjacent future production and exploratory wells.
It is commonly assumed for the purpose of stress analysis and the interpretation of indirect tension tests that the moduli of deformation are equal in tension and in compression. This assumption has been questioned by several researchers. However, it is difficult to measure the tensile elastic modulus Et due to the fact that the direct tensile test is difficult to perform in laboratory. Hence, much attention has been placed by researchers on the tensile elastic modulus determination through the Brazilian test. A Brazilian test was conducted in this study for determining Et and Ec of the Montney shale in its foliation plane. Two pairs of strain gauges were mounted at the center of the Brazilian disc on its both side faces. In each pair, one gauge was installed along the direction of the line load P to record the compressive strain and the other one was installed in the direction perpendicular to it to record the tensile strain of the center part. The tensile elastic modulus Et as well as the compressive elastic modulus Ec then were calculated using these recorded strains through the theory of elasticity. From the test results the average compressive elastic modulus was about 40 GPa and that for the tensile modulus was about 31 GPa.
Conventional natural gas is created when methane molecules move from their original location to an area where they are trapped by a geological structure leading to a higher concentration of methane molecules. Although easier and cheaper to produce, the gas production from these conventional sources is declining. Therefore, the oil and gas industry is turning to fossil fuels that were previously thought of as not economically feasible and difficult to produce. The large volume and long-term potential, attractive gas prices and unprecedented interest in world markets, bring the unconventional gas into the forefront of our energy future.
Located in a large area spanning the British Columbia and Alberta border, the Montney Formation is one of the largest economically feasible resource plays in North America . The Montney resource play represents a complex geological sequence that varies from conventional gas (and oil) along the eastern edge of the basin, to a combination of tight gas and gas shale play in the center, and to the classical black massive gas shale along the western edge (Fig. 1) . The Montney Formation has had a long history of exploration, yet surprisingly little information is publically available about it. Many previous studies of the Montney Formation have been proprietary oil company reports. Most such reports dealt with the geology, log responses and reservoir potential, and some with core evaluation. As new exploratory drilling continues to reveal the wide range of facies in the Montney, it adds to both the complexity and potential of this relatively unique formation in western Canada . Hence, the experimentally obtained geomechanical parameters are also necessary for the Montney shale material characterization and the numerical simulations of its stimulation processes.
The tensile elastic modulus Et is an important parameter which characterizes the tensile property of the rock material.
Possibility of inducing shear fractures rather than tensile during and after the hydraulic fracturing operation is an important issue in stimulation of shale gas plays which could affect the fracturing pattern and in-situ stresses estimation. Therefore, the experimentally obtained geomechanical parameters are necessary for the shale material characterization and the numerical simulations of its stimulation processes. In this study, four double shear tests were conducted on the Montney’s samples to understand its behavior under different loading states and to measure its discontinuities strength parameters. During the experiments it was observed that samples sheared through the foliation planes as well as through the rock material. It showed that when the inclination of the discontinuity with respect to the normal stress approaches 90°, the sample would not necessarily shear along the discontinuity, but behaves like an intact material in which many factors such as stress conditions, discontinuity surface conditions, joints spacing, as well as the rock material by itself would play important roles in the final failure mode. From the results, the cohesion was found as 2 MPa and the peak friction angle was about 40°.
Shale gas is natural gas that is embedded in shale, a sedimentary rock that was originally deposited as clay and silt. Shale gas is one of a number of “unconventional” sources of natural gas, including coalbed methane tight sandstones, and methane hydrates. While the potential for Canadian shale gas production is still being evaluated, the principal Canadian shale gas plays are the Horn River Basin and Montney Shales in northeast British Columbia, the Colorado Group in Alberta and Saskatchewan, the Utica Shale in Quebec and the Horton Bluff Shale in New Brunswick and Nova Scotia. Located in a large area spanning the British Columbia and Alberta border, the Montney Formation is one of the largest economically feasible resource plays in North America (Fig. 1) . As new exploratory drilling continues to disclose the wide range of facies in the Montney, it adds to both the complexity and potential of this relatively distinctive formation in western Canada .
A tight gas reservoir is generally defined as any low permeability formation in which special well completion techniques, mostly hydraulic fracturing, are required to stimulate production. New technologies, such as multi-stage hydraulic fracturing, together with horizontal drilling, are making it easier and more reasonable to produce shale gas . Advances in logging and core evaluation techniques have improved our ability to understand the petrophysical characteristics of the complex reservoirs so far. Still, it is believed that with the addition of innovative technology based on the better understanding of geomechanical behavior of these reservoirs, the productive yield from application of hydraulic fracturing technique could be further enhanced. Predicting the geomechanical response of the shale gas material during hydraulic fracturing operation in the field needs better understanding of their geomechanical behavior under laboratory testing. Furthermore, understanding the geomechanical behavior helps optimize the planning and management of the hydraulic fracturing operation.
Possibility of inducing shear fractures rather than tensile during and after the hydraulic fracturing operation is an important issue which could affect the fracturing simulations and in-situ stresses estimation.