Fault slip potential induced by fluid injection in the Matouying EGS field, Tangshan seismic region, North China

The Tangshan region is one of the most seismically active areas in the North China, and the 1976 M 7.8 earthquake occurred on July 28th near the Tangshan fault zone. The Matouying Enhanced Geothermal Systems (EGS) field is located ~90 km away from Tangshan City. Since the late 2020, preliminary hydraulic stimulation tests have been conducted at depths of ~3965–4000 m. Fluid injection into geothermal reservoir facilitates heat exchanger system. However, fluid injection may also induce earthquakes. In anticipation of the EGS operation at the Matouying uplift, it is essential to assess how the fault slip potential of the nearby active and quiescent faults will change in the presence of fluid injection. In this study, we first characterize the ambient stress field in the Tangshan region by performing stress tensor inversions using 98 focal mechanism data (ML ≥ 2.5). Then, we estimate the principal stress magnitudes near the Matouying EGS field by analyzing in situ stress measurements at shallow depths (~600–1000 m). According to these data, we perform a quantitative risk assessment using the Mohr-Coulomb framework in order to evaluate how the main active faults might respond to hypothetical injected-related pore pressure increases due to the upcoming EGS production. Our results mainly show that most earthquakes in the Tangshan seismic region have occurred on the faults that have relatively high fault slip potential in the present ambient stress field. At well distances of less than 15 km, the probabilistic fault slip potential on most of the boundary faults increase with continuing fluid injection over time, especially on these faults with well distances of ~6–10 km. The probabilistic fault slip potential increases linearly with the fluid injection rate. However, the FSP values decrease exponentially with increased unit permeability. The case study of the Matouying EGS field has important implications for the deep geothermal exploitation in China, especially for Gonghe EGS (in Qinghai province) and Xiong’an New Area (in Hebei province) geothermal reservoirs that are close to the Quaternary active faults. Ongoing injection operations in the regions should be conducted with these understandings in mind.

Casing Deformation Mitigation Achieved Through Ball Activated Sliding Fracturing Sleeves – An Alternative to Plug and Perf Fracturing Operations

Casing Deformation has plagued numerous unconventional basins globally, in particular with plug-and-perforation (also known as plug-and-perf) operations. This infamous issue can greatly influence 20-30% of field productivity of horizontal wells in shale and tight oil fields (Jacobs, 2020). When a wellbore lies in a target zone and intersects many natural fractures, these fractures are perturbed by hydraulic stimulation. Therefore, rock or bedding slippage may occur, resulting in casing deformation. This phenomenon is escalated by active tectonics, high anisotropic in-situ stresses, and poor cement design. This paper evaluates the mechanisms of casing deformation. It reviews how these conditions can be evaluated in the target zone. The mitigation procedures to reduce casing deformation through either well planning or completions design are discussed. Finally, an alternative completion method to plug-and-perf allowing limited entry completion technique in restricted casing with a field case study will be discussed.

Fluid-injection-induced earthquakes characterized by hybrid-frequency waveforms manifest the transition from aseismic to seismic slip

Aseismic slip loading has recently been proposed as a complementary mechanism to induce moderate-sized earthquakes located within a few kilometers of the wellbore over the timescales of hydraulic stimulation. However, aseismic slip signals linked to injection-induced earthquakes remain largely undocumented to date. Here we report a new type of earthquake characterized by hybrid-frequency waveforms (EHWs). Distinguishing features from typical induced earthquakes include broader P and S-pulses and relatively lower-frequency coda content. Both features may be causally related to lower corner frequencies, implying longer source durations, thus, either slower rupture speeds, lower stress drop values, or a combination of both. The source characteristics of EHWs are identical to those of low-frequency earthquakes widely documented in plate boundary fault transition zones. The distribution of EHWs further suggests a possible role of aseismic slip in fault loading. EHWs could thus represent the manifestation of slow rupture transitioning from aseismic to seismic slip.

Geomechanically Driven Casing Deformation During Multistage Perf and Plug Fracturing Operations: Investigation and Mitigation

Casing Deformation has presented itself in numerous unconventional basins. Severe deformation interferes with multistage fracturing, in particular with plug-and-perforation (also known as plug-and-perf) operations, the most common stage isolation method in unconventional development. Casing Deformation can greatly impact 20-30% of field productivity of horizontal wells in certain US shale and tight oil fields (Jacobs, 2020). Reservoir accessibility and well integrity are the two separate issues when considering casing deformation. In this paper, the impact of geomechanically driven casing deformation on reservoir accessibility that in turn affects production and economics, will be discussed. Origin of casing deformation within a target zone lies in natural fractures placed in highly anisotropic stress regimes. When these fractures are perturbed by hydraulic stimulation, slow slip or dynamic failure of the rock may occur. This phenomenon is intensified by active tectonics, high anisotropic in-situ stresses, and poor completion practices, i.e., poor cement. This paper evaluates these processes by demonstrating failure conditions of wellbores in different stress states and well orientations representative of unconventional basins. It reviews how these conditions can be evaluated in the reservoir, so risk can be estimated. The mitigation procedures to reduce casing deformation impact to operations through either well planning or completions design are discussed. Finally, this paper will also review an alternative completion method to plug-and-perf that allows limited entry completion technique in restricted ID casing due to casing deformation with a field case study.

Novel chemical stimulation for geothermal reservoirs by chelating agent driven selective mineral dissolution in fractured rocks

Improving geothermal systems through hydraulic stimulation to create highly permeable fractured rocks can induce seismicity. Therefore, the technique must be applied at a moderate intensity; this has led to concerns of insufficient permeability enhancement. Adding chemical stimulation can mitigate these issues, but traditional methods using strong mineral acids have challenges in terms of achieving mineral dissolution over long distances and highly variable fluid chemistry. Here, we demonstrate a novel chemical stimulation method for improving the permeability of rock fractures using a chelating agent that substantially enhances the dissolution rate of specific minerals to create voids that are sustained under crustal stress without the challenges associated with the traditional methods. Applying this agent to fractured granite samples under confining stress at 200 °C in conjunction with 20 wt% aqueous solutions of sodium salts of environmentally friendly chelating agents (N-(2-hydroxyethyl)ethylenediamine-N, N′, N′-triacetic acid and N, N-bis(carboxymethyl)-l-glutamic acid) at pH 4 was assessed. A significant permeability enhancement of up to approximately sixfold was observed within 2 h, primarily due to the formation of voids based on the selective dissolution of biotite. These results demonstrate a new approach for chemical stimulation.

Guest Editorial: Why Multistage Stimulation Could Transform the Geothermal Industry

Geothermal energy is “having a moment.” It has been part of the global energy mix for many decades, but growth has been limited by the relatively limited number of sites with optimal geologic conditions. Technologies developed in the oil and gas sector have the potential to overcome these limitations and unlock dramatically increased geothermal production in the US and worldwide. Success is far from certain, but with the enthusiasm, ingenuity, and capital flowing toward these technologies, there is a realistic shot at breakthrough success. Geothermal energy comes in a variety of flavors, from shallow heat-pump systems used for residential heating and cooling to deep, hot wells drilled for electricity production. While opportunities exist across this spectrum, this column is specifically concerned with the drilling of deep, high-temperature wells for electricity production. Flow rate is a major challenge for geothermal. The energy content of one barrel of hot water is much lower than the energy content of one barrel of oil. Thus, to achieve profitability, geothermal wells must produce the equivalent of tens of thousands of barrels of water or steam per day. Across much of the western US, temperatures are hot enough for geothermal electricity production within reasonable drilling depth. However, in the absence of special geologic conditions from a hydrothermal system, wells usually cannot produce sufficient rate. Dating back to the 1970s, hydraulic stimulation has been tested as a way of increasing flow rate per well. Designs utilize injection and producer wells, with fluid heating up as it circulates between the wells. If engineers could use stimulation to consistently achieve high flow rates, a vast resource would be unlocked. The US Department of Energy’s (DOE) 2019 GeoVision report estimates that more than 60 GWe could be produced in the US by 2050. To date, success with hydraulic stimulation has been limited. Conventionally, geothermal wells have been drilled vertically and then stimulated by injecting only water (no proppant) into a single openhole section (without using multiple stages). Engineers have hoped that the injected water would shear-stimulate a dense network of natural fractures, with a large amount of surface area and fracture conductivity. These designs can yield modest success because geothermal wells are usually drilled in high-strength rock in the crystalline basement, and so fractures have considerable self-propping capability. However, rather than creating a dense network, flow tends to localize into a small number of dominant flowing pathways. Without a large number of flowing pathways, the reservoirs lack the ability to sustain high rate and are subject to thermal short circuiting that prematurely reduces the production temperature. Fortunately, similar problems have been encountered and solved by the shale industry. The shale revolution was unlocked by the application of multistage hydraulic fracturing along horizontal wellbores. Mechanical isolation allows sequential injection into sections of the well. Within each stage, perforation pressure drop is used to force fluid to flow into multiple pathways along the well. Perforation clusters are spaced tightly—typically from 10 to 50 ft. Recent core-through studies confirm that stimulation is creating hundreds or thousands of conductive fractures along each fractured lateral.

First Application of Rigless Electrical Submersible Pump Technology in the Gulf of Mexico

An operator planned to install ESPs to overcome high water cut and minimize the gas supply risk for a gas lift completion at a platform in the Gulf of Mexico. The platform is an oil collection point and its continuous operation is essential during any rig-assisted interventions. To maintain platform operation, three wells were selected for deployment of rigless electrical submersible pump (ESP) replacement systems to avoid the future use of a workover rig. The challenge was to allow a single-trip ESP deployment using the crane facilities with existing height limitations. A special surface connection system was designed to allow long ESP sections to connect under pressure at the wellhead. The technology is based on a propriotery system and method of connecting long strings at the surface using a surface lubricator and an adapted deployment stack. The system elements are located between the pump intake and protector seal sections of a standard ESP string that can easily and economically sourced in most locations. This new technology reduces the number of wireline/slickline runs needed, and the system features allow verification of mechanical connection integrity at the surface prior to deployment in the well. The successful deployment and commissioning of a rigless ESP replacement system in the SM 130 A-26 well in the Gulf of Mexico was completed in October 2019 without incident. Prior to the deployment of the rigless ESP replacement system, it was decided to perform hydraulic stimulation operations to improve the well productivity. This operation resulted in higher than expected well inflow with increased water cut. At the time of writing this paper, the ESP system had recently failed to start due to stuck pump (possibly scale related). Due to the ability to perform a rigless system upgrade for the unanticipated well inflow conditions, the operator is planning for the first rigless replacement of the existing ESP to achieve higher flow rate during the last quarter of 2021. The successful deployment of the alternative ESP deployment technology demonstrated the potential to improve the economics of the existing production facilities by reducing production deferment, minimizing health, safety, and environment (HSE) exposure; and improving the asset value. This paper discusses the engineered solution and application of the technology required to deploy long ESP strings, modifications required for the specific well conditions, and the lessons learned during the first successful deployment of rigless ESP technology in the Gulf of Mexico. Due to the performance and capability demonstrated in the first successful installation, Talos Energy has recently installed its second rigless ESP replacement system in a recompleted zone and is planning for installing its third system in the SM 130 field in 2022.

Redesign of stormwater collection canal based on flood exceedance probability using the ant colony optimization: study area of eastern Tehran metropolis

An increase in stormwater frequency following the rapid development of urbanization has drawn attention to the mitigating strategies in recent decades. For the first time, the present study aims to conduct a local rehabilitation in stormwater collecting systems by (i) detecting the critical nodes along with the canal network and (ii) redesigning the critical canal reaches using Ant Colony Optimization (ACO) to create maximum capacity for flood discharge with minimum reconstruction cost while considering the probability of exceedance of the flood as a constraint. Hence, using the SWMM model, the flow in the collection system was simulated, and the inundation points in the study area in the eastern Tehran metropolis were determined. After determining the critical points, the hydraulic stimulation model for the selected canal flows was developed using HEC-RAS software to accurately simulate each critical bridge's flow. Then, the optimal parameters for the canal bed width and canal depth were obtained using ACO and defining a probability objective function using the flood probability exceedance as the redesign constraint. The results from the optimizer were compared with those of the LINGO nonlinear model. Finally, the operational performance of the redesigned system was evaluated using the optimal selected parameters. The results showed that in redesigning the studied canals, the two widening and deepening options are needed to obtain a discharge with sufficient flow capacity in various return periods (RPs). The optimization results for the first to third critical sections for a design discharge with a 100-year RPs showed that the calculated cost was 19.765(*106), 13.327(*106), and 43.139(*106) IR Rials (1USD = 202000IRR), respectively. For the selected sections, the optimal bed width is 6.97, 8.97, and 10.93 meters, and the optimal depth is 3.68, 4.81, and 4.04 meters, respectively. The results indicate that the local modification in the eastern flood control canal adequately improved inundation problem reduction in various RPs – i.e., for a 10-year RP, the number of node flooding dropped from 4 to zero, the inundated area from 17 percent to zero, and the overflow volume from (10–45) to zero. It also reduced overflow volume from (30–65), (43–74), and (70–92) in the status quo to (4–12), (11–27), and (24–36) percent for precipitations with 25, 50 and 100-year RPs, respectively.