Um, Evan Schankee (Earth and Environmental Sciences, Lawrence Berkeley National Laboratory) | Kim, Jihoon (Harold Vance Department of Petroleum Engineering, Texas A&M University) | Wilt, Michael (Earth and Environmental Sciences, Lawrence Berkeley National Laboratory) | Commer, Michael (Earth and Environmental Sciences, Lawrence Berkeley National Laboratory) | Kim, Seung-Sep (Geology and Earth Environmental Sciences, Chungnam National University)
We examine the detection and imaging sensitivity of surface electric field measurements over a 3D hydraulically active fracture zone (HAFZ) at depth when one end point of a surface electric dipole source is directly connected to a wellhead. This configuration is often called the top-casing electric source method. The sensitivity also depends on conductivity structures around the well because they control a leak-off of electrical currents from the steel-cased well. Our inversion experiments show that the method can delineate a localized HAFZ in a shallow to intermediate depth (e.g. ≤2 km) and can also detect changes in its width and height. The inversion results are improved when a volume of the subsurface imaging domain is reasonably constrained from geomechanical perspectives. The primary advantage of the method is the fact that the method has both source and receivers on the surface and thus, does not require well occupancy and interruption to the normal operation of the wells. Accordingly, it has potential to serve as a cost-effective tool for monitoring hydraulic fractures.
Presentation Date: Tuesday, October 16, 2018
Start Time: 1:50:00 PM
Location: 213A (Anaheim Convention Center)
Presentation Type: Oral
Kim, Jihoon (Korea Institute of Ocean Science & Technology) | Park, Hyeju (Korea Institute of Ocean Science & Technology) | Ko, Jin Hwan (Korea Institute of Ocean Science & Technology) | Won, Bo Reum (Korea Institute of Ocean Science & Technology) | Sitorus, Patar Ebenezer (Korea Institute of Ocean Science & Technology) | Park, Jin-Soon (Korea Institute of Ocean Science & Technology) | Lee, Kwang-Soo (Korea Institute of Ocean Science & Technology) | Kang, Taesam (Konkuk University) | Park, Hoon Cheol (Konkuk University)
Up to now, a pitch controller has been used as a typical solution for adapting the variation of flow speed in horizontal axis tidal current turbines. This study was mainly about the development procedure of a pitch controller for a horizontal axis tidal current turbine throughout analyzing thrust, torque, and rotational speed which measured from multiple-step experiments. First, we conducted indoor experiments using a scale turbine model with a pitch-change module to explore the effect of pitch variation at the beginning of the development. In the next step, the different extracted powers by the pitch angle variation is measured from the indoor experiments of a scaled-up model. In the last step, a re-scaled-up turbine model with a pitch controller was fabricated based on the results of the indoor experiments and used for consecutive outdoor experiments. In a broad range of the flow speed from 1 to 4 m/s, the developed pitch controller successfully regulated the rotational speed within 80±8 rev/min; hence, the extracted power was maintained within 6.73±0.55 kW. Moreover, the thrust, which is a big burden to the tidal current turbine and its supporting structure, was stayed from 10.5 to 7.1 kN. Namely, it was recognized from the outdoor experiments that the developed pitch controller could well regulate the power as well as the thrust of the tidal turbine model in the unpredictable flow speed variation of an offshore condition. Eventually, based on the results and experiences of the three-step experiments, the pitch controller for a 200 kW tidal current turbine was designed and fabricated.
As the problems of fossil fuel, which are depletion of resource, environmental pollution, and economic damage, are rising, renewable energy has been developed to reduce fossil fuel usage. Among them, tidal energy is the most reliable and alternating energy resource from the ocean because it is predictable, regular and higher energy density. Moreover, leading countries such as the United Kingdom, Canada have vast resources of tidal energy and they then continue to do research about tidal energy extraction(Rourke, Boyle, & Reynolds, 2010) In the Republic of Korea, the studies of tidal energy extraction was actually starting with a helical-bladed Darrius turbine at the Uldolmok in Jindo, 2003.(Han, Lee, Yum, Park, & Park, 2010)
We parallelize individual non-isothermal fluid-flow and geomechanics simulators separately, and then use a sequential method for coupling between flow and geomechanics. Message Passing Interface (MPI) is employed in the distributed memory system, and Open Multi-Processing (OpenMP) is used in the shared memory system. We primarily implement MPI for matrix assembly and parallel solvers, particularly using the PETSc library codes while using OpenMP for other miscellaneous subroutines to prevent significant overheads. We also study different matrix decomposition schemes for the geomechanics linear system, which not only precondition for parallel solvers but also assign computation loads to cores involved in the cluster.
We take more than one million cells to investigate parallel performance. For both flow and geomechanics, the parallelization largely reduces the overall simulation execution time and obtains scalable speedups. Parallel-solver-only performance is tested as well. We find that solver performance achieves scalable speedups, where the optimum overall speedup for the parallel coupled simulator exceeds 14. Also, matrix decomposition methods have effects on parallelization in terms of execution time and solver performance, implying that the selection of matrix decomposition methods is important for high efficiency parallelization.
The parallel scheme in this study can straightforwardly be applied to other sequentially coupled simulators, without significant code development. When the flow and geomechanics simulators are sequentially coupled, we find that the scalability of the parallel coupled simulator can be honored. We also find that plasticity can lead to imbalance in the parallel environment. Thus, efficient parallel schemes for plasticity are required.
We numerically investigate a potential fault activation in Tarim Basin, west China, during hydraulic fracturing operations, by considering rigorous coupled flow and geomechanics. In this study, we find that the fault can be activated by water injection, when it is nearly critically stressed, being sensitive to small changes in stress. Lower cohesion, lower frictional angle, and higher injection rate can activate the fault more easily. Interestingly, the fault becomes activated away from the hydraulic fracture, before the injected water reaches the fault plane. Then, when the hydraulic fracture meets the fault plane, the injected water changes the effective stress of the fault significantly, causing large shear failure. We also calculate the magnitudes of the seismic moment, which are low, because only limited areas of the fault plane are failed. Thus, from this preliminary numerical study of Tarim Basin, we can possibly consider the fault activation as a reservoir stimulation technique for the Tarim Basin field.
We modeled microearthquakes (MEQs) for tensile failure of vertical fracture propagation by combining geophysics, flow, and geomechanics simulators while accounting for poromechanical effects. Each time fracturing occurred, we calculated the seismic moment tensor from the obtained displacement field and newly fractured area. Then, using this information, we modeled intensity, location, number of the events, and time of MEQs. We simulated various scenarios, taking single phase flow (i.e., water) in order to remove complex responses from multiphase flow. We first studied a synthetic reservoir having one single shale layer with two strong bounding layers and a horizontal well. The simulated MEQs reflected the propagation of the hydraulic fracture, where the magnitudes of most MEQs were between -1 and -3. Then, we simulated a vertical well in the more realistic geological model of the Arch Forth-Worth Basin, where the Barnett shale is located. We studied two scenarios: one in which the fluid was injected into the Lower Barnett shale and it only fractured into the injected layer, and one in which there was fluid migration from the injection point into the Upper Barnett Shale. The magnitudes of MEQ for these two scenarios were similar and mostly between -0.75 and 0.75 in strength. For all cases, the event locations of MEQs corresponded to the fracture propagation. Thus, the forward simulation of microearthquakes can be a useful to detect propagation of hydraulic fractures and stimulated reservoir volume. Additionally, we showed that under some reservoir conditions it is possible for fluid to fracture layers above the injection point without fracturing the targeted layer.
Hydraulic fracturing has revolutionized the energy industry for the last decade. This process entails pumping large amounts of sand and water down a well, where the increase in pressure creates a network of fractures that allow petroleum engineers to access trapped hydrocarbons. The operation is poorly understood, so the development of successful hydraulic fracturing methods has been too often a trial and error process. This poses monetary and environmental risks, and a general sense of mistrust towards the oil and gas industry. However, the basics of hydraulic fracturing dictates that a large planar fracture is created in a direction perpendicular to the minimum horizontal stress. In addition to this, a significant number of shear failures (micro-earthquakes) are generated in the surrounding intact reservoir rock . Furthermore, depending on the reservoir on which it is performed, hydraulic fracturing can cause fault reactivation and shear slip of existing natural fractures [2, 3].
The simultaneous combination of these phenomena makes the physics of the problem a difficult subject to study. Nevertheless, because the failure induced by perturbation of fluid pressure implies strong interaction between flow and geomechanics , we employed a coupled simulator to accurately predict and assess any risk derived from hydraulic fracturing a vertical well.
We investigated wellbore stability during hydraulic fracturing using the Mohr-Coulomb failure model and an intrinsic permeability step function for failure status. In order to assess the risk of failure, we varied the values of bottom-hole pressure, permeability multipliers for our permeability step function, and the cohesion values between the well casing and the surrounding cement to represent different quality levels of the cementing operation. Additionally, we studied shear failure for a homogeneous and a heterogeneous three shale layer reservoir. From numerical results, higher bottom-hole pressures increased the fracture propagation speed because it implied higher geomechanical loading. Furthermore, a higher permeability multiplier leads to a larger failed zone because higher permeabilities pressurize the failed zone faster. Also, simulations showed that there is very little fracturing when the cement is of high quality. On the other hand, incomplete cementing and/or weak cement can cause significant shear failure and the evolution of long fractures along the vertical well, where they become a factor for potential contamination of aquifers. Moreover, simulations of heterogeneous shale reservoir showed how mechanical properties of the reservoir rock can help resist shear failure of the wellbore. Finally, a coupling strength sensitivity analysis of the steel-cement interface layer demonstrated that higher coupling strengths induce shear failure. Thus, high-quality cement, complete cementing, strong formation rock properties along the vertical well, and low poromechanical effects between fluid and geomechanics appears to be the strongest protection against shear failure of the wellbore cement and contamination hazards to water aquifers during hydraulic fracturing.
The combination of horizontal drilling and hydraulic fracturing can extract enormous quantities of natural gas from previously thought uneconomic reservoirs , making shale gas production an important energy resource of the future [2, 3]. However, the extreme low permeability of the shale gas reservoirs requires hydraulic fracturing to enhance productivity [4, 5]. At the same time, environmental impacts induced by hydraulic fracturing have been raised, for example, contamination of ground water, unstable growth of hydraulic fractures, seismic risks, reactivation of existing faults, and soil contamination due to proppant chemicals . The potential environmental impacts have had a negative influence on public opinion, which is curbing and even halting the American shale gas revolution in its tracks.
Dusseault et al. (2001)  studied compaction-induced shear failure of vertical wells by fluid production. Shear failure is one of the typical mechanisms of well instability. Incomplete cementing between the well and reservoir formations is considered one of the highest environmental risks of ground water contamination, as well as a catalyst for wellbore failure [6, 8]. Pressurization at the bottom of the well causes high shear stress along the vertical well and can result in shear slip at the contacting area between the well casing and the cemented zone if the contacting area is poorly cemented. Cracks from shear failure along the well can be a potential pathway connecting deep shale gas reservoirs to shallow aquifers with higher permeability.
We perform coupled flow-geomechanics-electrical/electromagnetic (EM) modeling and examine the feasibility of surface-based electrical/EM methods for detecting hydraulically-active fractured zones in depth. We employ the finite element methods for geomechanics and electrical/EM modeling, while the finite volume method is used for flow modeling. After converting flow-geomechanics models to conductivity models via a rock physics relationship, we show that anomalous distribution of electrical conductivity is directly related to injected water saturation, implying that EM responses are directly sensitive to hydraulically-active fractured zones. In our modeling experiments, we inject saline water that has high concentration of NaCl, to enhance EM signals associated with the hydraulically-active fractured zones. By using a steel-cased injection well though which surface electrical sources directly charge saline-water-saturated fracture zones, we demonstrate that surface electrical/EM methods can identify the difference in the electric fields between with and without the hydraulic fracture. Thus, this measurable difference implies that the electrical and EM methods can be an important complementary tool to detect and image propagation of a large hydraulic fracture.
Micro-earthquake (MEQ) monitoring has mainly been studied for imaging fractures and fluids [1, 2]. MEQ provides general information about locations of fracturing events. However, the mapping highly depends on initial velocity models which we do not know well, leaving uncertainties in the amount of correlation with the areas that are hydraulically active . The magnitudes of MEQ are often too small to be reliably recorded in practice. More importantly, MEQ monitoring does not accurately indicate if the fluid pathways remain open after the injection stops. Electrical/electromagnetic (EM) geophysical methods have a potential to complement MEQ because they are be sensitive to fluids in pores and fractures, and have potential to provide independent information about fluid flow associated with hydraulic fracturing.
In this study, we investigate detectability of electrical/EM methods for fracture propagation induced by water-based hydraulic fracturing (HF). The goal of this study is to evaluate EM geophysical methods for detecting hydraulically-active fractured zones in HF operations. For the goal, we use the 3D finite element method (FEM) for geomechanics, taking linear elastic fracture mechanics, while the 3D finite volume method (FVM) is used for flow . We also employ 3D FEM for DC and diffusive EM modeling , which can accurately and economically handle irregular fractured zones not conforming to rectangular Cartesian grids. While fracture propagates, hydrological and petrophysical parameters (e.g. saturations of native and invaded fluids, changes in pore volume and aperture) that are computed by coupled flow-geomechanical simulation are transformed via a rock-physics model into electrical conductivity models.
We propose and investigate formulation and numerical simulation for largely deformable anisotropic reservoirs in this study. We employ the total Lagrangian method (TL) for coupled flow and geomechanics, which does not need to update the coordinate system each time step. The use of the deformation gradient as well as the first and second Piola stresses reflects the change of reservoir configuration, being mathematically equivalent to the updated Lagrangian method. To accurately model full-tensor permeability derived from the Piola transformation in permeability, we use the multi-point flux approximation (MPFA). The total Lagrangian method with MPFA can provide high accurate and rigorous modeling. We thus consider the total Lagrangian method with MPFA as the reference method in this study. Then, we compare it with two other methods: Total Lagrangian method with the two-point flux approximation (TPFA) and infinitesimal transformation assumption with TPFA. From numerical simulation, we find differences between the reference method and the other two methods. Displacement based on the assumption of the infinitesimal transformation is different from that of the total Lagrangian method. Also, we find that volumetric strain and pressure of TL-MPFA are different from those of TL-TPFA. As the anisotropy ratio of permeability increases, the errors between MPFA and TPFA increases.
Small deformation (i.e., infinitesimal transformation) is typically assumed in reservoir geomechanics [1, 2, 3, 4]. This assumption is usually valid in reservoir engineering problems associated with rock, which induce small deformation. However, the assumption might be invalid in largely deformable reservoirs, such as oceanic gas hydrate deposits and fractured/crashed salt domes [5, 6]. Anisotropic reservoirs are profoundly sensitive to substantial changes in reservoir configuration, having full-tensor permeability and elastic moduli during deformation. This causes non-orthogonal grids in flow. However, the modeling of largely deformable anisotropic reservoirs has little been investigated.
In this study, we employ the total Lagrangian method for coupled flow and geomechanics. The coordinate system remained fixed both for flow and geomechanics. Instead, the deformation gradient reflects the change of reservoir configuration, which yields mathematical equivalence to the updated Lagrangian method [7, 8, 9]. The total Lagrangian method also induces full-tensor permeability from the Piola transformation, even if the initial permeability tensor is diagonal . To accurately model full-tensor permeability, we use the multi-point flux approximation (MPFA) . Then, the total Lagrangian method with MPFA can provide high accurate and rigorous modeling, honoring the objective stress rates (i.e., Lie derivatives). We thus consider the total Lagrangian method with MPFA as the reference model in this study.
We evaluate the validity of the two assumptions on hydraulic fracture propagation. We employ the semi-analytical approach in modeling of coupled flow and geomechanics, where flow is solved numerically, whereas geomechanics is solved analytically. We first model a PKN hydraulic fracture geometry numerically and incorporate the fluid compressibility term in order to investigate the effect of the fluid compressibility in hydraulic fracture geometry evolution. The results show that as the fluid becomes compressible, the fracture propagation is delayed because it takes time for pressure to be built up to extend the fracture. In multi-phase flow system, we model a hydraulic fracturing process in a gas reservoir by solving flow numerically yet geomechanics analytically. The fracture propagates slowly when water saturation of the reservoir is low. This implies high initial gas saturation, resulting in high total compressibility of reservoir fluid. We observe the gas concentration at near fracture tip, caused by (1) the movement of initial gas within the fracture to the fracture tip and (2) the possibility of the leakage of gas from the formation to the hydraulic fracture. This existence of gas is another factor that can lead fluid flow within the hydraulic fracture to be compressible.
The scientific community has taken several assumptions in the study of hydraulic fracturing. For example, one of the assumptions is to ignore the effects of fluid compressibility by assuming the fluid to be incompressible, which is the main assumption used to derive the analytical solutions of the hydraulic fracturing problem. But, considering the stiffness of a typical rock and the stiffness of the injected fluid (e.g. water), fluid compressibility cannot be ignored. Furthermore, when the injected fluid is gas, such as nitrogen and carbon dioxide, the fluid compressibility must be considered to account for the geomechanical changes in the reservoirs. Another common assumption is to disregard the reservoir gas that is going to infiltrate the hydraulic fracture from the reservoir formation during hydraulic fracturing operations, whereas the leak-off from the fracture into the reservoir is usually considered. However, some studies have indicated that the existence of a gap between the fracture tip and the water front is possible (i.e. vacuum area ). This gap implies the possibility of the leakage of shale gas from the formation into the hydraulic fracture.
In order to investigate the importance of fluid compressibility in the hydraulic fracturing process, we first focus on modeling a Perkins-Kern-Nordgen fracture geometry which is first introduced by Perkins and Kern  and further improved by Nordgren . A PKN geometry has been considered to be physically acceptable in a sense that the fracture length is larger than its height, which is one of the primary assumptions of the geometry. We derive mass balance equations assuming the fluid is not incompressible to incorporate fluid compressibility term in the equations. We then validate our numerical modeling by comparing the numerical results with analytical solutions, taking zero compressibility.
Ko, Jin Hwan (Korea Institute of Ocean Science & Technology) | Kim, Jihoon (Korea Institute of Ocean Science & Technology) | Park, Hoon Cheol (Konkuk University) | Yoon, Jong Su (Korea Marine Equipment Research Institute) | Choo, Jin Hun (Korea Marine Equipment Research Institute) | Hwang, Tae Gyu (Korea Marine Equipment Research Institute)
Recently, tidal current turbines have gained high attention as systems extracting predictable and sustainable renewable energy, but a commercial power generation in an array form is not started yet due to technical, financial, and environmental uncertainties. In technical aspects, power efficiency and structural safety would be critical for the success in the tidal current generation. Active control is a powerful approach for achieving the high efficiency as well as the safe operation in the conditions of the variable direction and the variable speed of the tidal current even though the complexity of the turbine systems increases. This study is focused on the development of an active controller in the tidal current turbines. The new concept that we have developed is the yaw control of the turbine systems by a rudder. In order to validate our new active-control concept, we conducted the indoor experiments of a 1/15 scale turbine model including the active controller. The effect of the yaw control on the power efficiency was analyzed and minute yaw control as well as 180 degree turn by the controller was demonstrated. After the validation, the active-controller was enlarged to 1/5 scale model and was successfully demonstrated in an outdoor facility. Eventually, based on the results of this study, the full-scale model of 200kW capacity and the corresponding activecontroller will be fabricated and be validated by in-situ tests over 2 m/s at the Uldolmok strait in South Korea.