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Results
Evolution of Completion Techniques in the Lower Shaunavon Tight Oil Play in Southwestern Saskatchewan
Schlosser, D. J. (NCS Oilfield Services Canada Inc.) | Johe, M.. (Crescent Point Energy Corporation) | Humphreys, T.. (Crescent Point Energy Corporation) | Lundberg, C.. (Crescent Point Energy Corporation) | McNichol, J. L. (NCS Oilfield Services Canada Inc.)
Abstract The Oil and Gas industry has explored and developed the Lower Shaunavon formation through vertical drilling and completion technology. In 2006, previously uneconomic oil reserves in the Lower Shaunavon were unlocked through horizontal drilling and completions technologies. This success is similar to the developments seen in many other formations within the Williston Basin and Western Canadian Sedimentary Basin including Crescent Point Energy's Viewfield Bakken play in southeast Saskatchewan. In the Lower Shaunavon play, the horizontal multistage completion era began in 2006, with horizontal divisions of four to six completion stages per well that utilized ball-drop sleeves and open-hole packers. By 2010, the stage count capabilities of ball-drop systems had increased and liners with nine to 16 stages per well were being run. With an acquisition in 2009, Crescent Point Energy began operating in the Lower Shaunavon area. The acquisition was part of the company's strategy to acquire large oil-in-place resource plays. Recognizing the importance that technology brings to these plays, Crescent Point Energy has continuously developed and implemented new technology. In 2009, realizing the success of coiled tubing fractured cemented liners in the southeast Saskatchewan Viewfield Bakken play, Crescent Point Energy trialed their first cemented liners in the Lower Shaunavon formation. At the same time, technology progressed with advancements in completion strategies that were focused on fracture fluids, fracture stages, tool development, pump rates, hydraulic horsepower, environmental impact, water management, and production. In 2013, another step change in technology saw the implementation of coiled tubing activated fracture sleeves in cemented liner completions. Based on field trials and well results in Q4 2013, Crescent Point Energy committed to a full cemented liner program in the Lower Shaunavon. This paper presents the evolution of Crescent Point Energy's Lower Shaunavon resource play of southwest Saskatchewan. The benefits of current completion techniques are: reductions in water use, increased production, competitive well costs, and retained wellbore functionality for potential re-fracture and waterflooding programs.
- Geology > Petroleum Play Type > Unconventional Play (0.48)
- Geology > Geological Subdiscipline (0.46)
- North America > Canada > Saskatchewan > Williston Basin > Shaunavon Formation (0.99)
- North America > Canada > Saskatchewan > Williston Basin > Bakken Shale Formation (0.98)
- North America > Canada > Manitoba > Williston Basin > Bakken Shale Formation (0.98)
- (6 more...)
Abstract Water flooding is often applied to increase the recovery of oil from reservoirs. In practice, the water injectivity below the fracture propagation pressure (at so called matrix flow), is usually too low, so that the pressure is increased and the well is fractured. The fracture behavior is however different for unconsolidated sands than for consolidated rock as higher pressures relative to the minimum stress are required to obtain fracture propagation. Injecting water at higher pressure will lead to higher recovery. Our aim was to gain experimental and numerical data to establish the transition from matrix flow to fracturing. We present a series of model tests on different unconsolidated materials using large cylindrical samples with a diameter of 0.4 m. We changed the permeability of the sample and investigated the effect of cohesion by adding cement to some of the samples. It appeared that fractures obtained in material without any cohesion are really complex. On the other hand, adding some small cohesion to the sample, we observed a fracture more like โclassicalโ fractures in competent rocks. For interpreting the tests, we have developed a fully coupled numerical model taking into account the two phase flow of oil and water, and the deformation of the sample.
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.88)
- Geology > Geological Subdiscipline > Geomechanics (0.87)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.41)
Fracture Propagation, Fluid Flow, and Geomechanics of Water-Based Hydraulic Fracturing in Shale Gas Systems and Electromagnetic Geophysical Monitoring of Fluid Migration
Kim, Jihoon (Earth Sciences Division, Lawrence Berkeley National Laboratory) | Um, Evan Schankee (Earth Sciences Division, Lawrence Berkeley National Laboratory) | Moridis, George J. (Earth Sciences Division, Lawrence Berkeley National Laboratory)
Abstract We investigate fracture propagation induced by hydraulic fracturing with water-injection, using numerical simulation. For full 3D rigorous modeling, we employ a numerical method that can model failure due to tensile and shear stresses, dynamic nonlinear permeability, the dual continuum approach, leak-off in all directions, and thermo-poro-mechanical effects. From the numerical results, fracture propagation is not the same as propagation of the water front, because fracturing is governed by geomechanics, whereas water saturation is determined by fluid flow. At early times, the water saturation front is almost identical to the fracture tip, showing that the fracture is mostly filled with injected water. However, at late times, advance of the water front is retarded, compared to the fracture propagation, yielding a significant gap between the water front and the fracture top, which is filled with reservoir gas. We also find considerable leak-off of water to the reservoir. The inconsistency between the fracture volume and the volume of injected water cannot properly estimate the fracture length, when it is estimated based on the simple assumption that the fracture is fully saturated with injected water. As an example of flow-geomechanical responses, we identify pressure fluctuation under constant water injection, because hydraulic fracturing is itself a set of many failure processes, in which pressure drops every time when failure occurs. The fluctuation decreases as the fracture length grows. We also study application of electromagnetic (EM) geophysical methods, because the EM geophysical methods are highly sensitive to changes in porosity and pore-fluid properties, such as water injection into gas reservoirs. We employ a 3D finite-element EM geophysical simulator and evaluate the sensitivity of the crosswell EM method for monitoring fluid movements in shaly reservoirs. For the sensitivity evaluation, reservoir models are generated through the coupled flow-geomechanical simulator and are transformed via a rock physics model into electrical conductivity models. It is shown that anomalous conductivity distribution in the resulting models is closely related with injected water saturation but little with newly-created unsaturated fractures. The numerical modeling experiments demonstrate that the crosswell EM method can be highly sensitive to conductivity changes that directly indicate the migration pathways of the injected fluid. Accordingly, the EM method can serve as an effective monitoring tool for distribution of injected water (i.e. migration pathways) during hydraulic fracturing operations.
- North America > United States > Texas (0.68)
- Europe (0.67)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play > Shale Gas Play (0.46)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.42)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Abstract One downside of prolific oil and gas production is the often associated increase in produced water volumes. As hydrocarbon prices and production increase, so do water production and the need for efficient water disposal. This need plus increasing regulatory scrutiny and operatorsโ environmental stewardship goals have compelled the search for economic methods of safely maximizing - and maintaining - disposal well efficiency. This paper will relate case histories of several salt-water disposal wells in northwestern Louisiana, in which the conventional remediation solution, matrix acid treatments, did not effectively remove near-wellbore damage. Instead, precision bypass fracs were designed to maximize injectivity without fracturing rock beyond the narrow zonal limits set by state regulators. The strict regulations required a precise, scientific approach to stimulation design and operations, including the use of fracture modeling, on-site diagnostics and radioactive tracers. The paper will present regulatory issues, stimulation design process, operational highlights and post-stimulation results for some representative disposal wells. It will also describe improvements made at producing well locations to minimize future stimulation requirements. Finally, it will conclude with some recommended best practices for economical, safe, effective bypass frac design and operations in water disposal wells.
- North America > United States > Texas (1.00)
- North America > United States > Louisiana (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.71)
- Geology > Geological Subdiscipline > Geomechanics (0.69)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (1.00)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Abstract Horizontal wells are increasingly used worldwide and are especially desirable offshore for water-flooding and reservoir pressure maintenance as they allow more access to the reservoir with large injectivities. Fracture growth in these horizontal injectors can play an important role in determining the injection rates, reservoir sweep and oil recovery. A model is developed to estimate the growth of fractures in horizontal injectors. The model considers two orientations of fracture growth:longitudinal fractures i.e. fracture along the horizontal well and centered transverse fractures, i.e. at the center and perpendicular to the horizontal well. Fracture growth is due to:reduction of permeability around the horizontal well caused by particle deposition from injection fluids, reduction in minimum horizontal stress due to cold fluid injection, and injection of viscous polymer fluids. The model accounts for plugging of the horizontal well, the induced fracture and the formation around the fracture. It also calculates the thermal and pore pressure stresses to update the minimum horizontal stress around the fracture tip. It also allows injection of power-law fluids to model polymer injection in horizontal injectors. It is shown that the injection well pressures are controlled by the minimum horizontal stress. The injection fluid quality, injection rate, and injection fluid temperature determine the rate of fracture growth in a horizontal injector. Fracture lengths are estimated for longitudinal and transverse fracture growth orientations as the lower and upper bound values. Background: Injectivity of Horizontal Wells In offshore locations with limited reservoir access, horizontal wells are an economic alternative to increasing reservoir access and significantly increasing the rate of injection and production from the reservoir. With the increasing limitations being placed on the overboard discharge of produced water in offshore platforms, larger volumes of treated produced water are being injected back into the ground. In onshore locations, over 91% of the produced water is reinjected. More injection wells are being utilized for waterflooding and for subsurface disposal. There is a growing realization that a large proportion of injection wells are fractured at some point in their life. This implies that even wells that were not deliberately hydraulically fractured are likely to have fractures created due to the injection of water over extended periods of time. This is true of both vertical and horizontal wells. In the past, models have been presented for fracture growth in vertical injection wells (Perkins et al. 1985, Saripalli et al. 1999). Fracture growth was shown to be driven by thermal stresses and by particle plugging induced by suspended solids in the injection water. As the injection pressure exceeds the fracture pressure, a fracture begins to propagate. The rate of growth of the fracture is controlled by the water quality and by the reduction in minimum horizontal stress induced by the injection of cold water. Poor water quality usually results in longer fractures and lower injectivities (higher injection pressures).
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.68)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)