Search

Aged hydrocarbon wells, if proper care is not ensured, can crack, get corroded, and leak subsurface fluids. Permian Basin in Texas, home to thousands of such wells, has seen numerous blowouts and wastewater leaks. Our study employs surface deformation derived from satellite observations, and injection well records to investigate these events. The results reveal an over‐pressurized wastewater aquifer producing a surface uplift of 20 cm/yr, likely due to wastewater being injected tens of kilometers away. Focusing on a January 2022 blowout resulting in 3 cm subsidence in 2 weeks, our geophysical model suggests aquifer over‐pressurization as the cause. With an excess pressure of over 3 MPa in the aquifer, several more such blowouts are possible in the near future. This research highlights the urgent need to better understand the impact of subsurface fluid injection and calls for prompt action to mitigate the environmental effects of oil and gas production. Plain Language Summary: Wastewater, a byproduct during oil extraction, is generally injected back into the ground. Permian Basin has witnessed several incidents of leakage of wastewater in the last 3 years. Recently in January 2022, huge amounts of wastewater were expelled at a high pressure from an old well. We used satellite data and wastewater injection data to understand the cause of these events. We found that the wastewater injection happening nearly several kilometers away is responsible for these leakages. We also discovered a highly pressurized wastewater lake below the surface in this region using geophysical modeling. Due to high pressures, the land in this region rose by 40 cm in just 2 years. Meanwhile, a part of this region sunk by 3 cm because of the leakage in January 2022. Our findings raise concerns about the potential for more leakages in the near future if action is not taken. Key Points: We utilized satellite observations of land surface deformation to explore the subsurface anomalies in the Permian BasinWe established a significant link between wastewater injection and oil well blowouts in the Permian BasinWe discovered an over‐pressurized aquifer responsible for the reported blowouts, with a potential for more blowouts in the near future [ABSTRACT FROM AUTHOR]

The U-shaped well geothermal production system is proposed on the basis of abandoned oil wells which can achieve the non-interference conversion of "heat extraction without water". Compared with the fracturing enhanced geothermal system, the U-shaped well system is more stable and more achievable. However, there is no comprehensive parametric study of the heat extraction performance of U-shaped well geothermal production system. In this paper, the thermal-hydraulic model of U-shaped geothermal production system is established based on the abandoned oil well. The temporal and spatial evolution of temperature field is analyzed, radiation range of the temperature drop is calculated, the effects of well-layout parameters on heat extraction performance are investigated. For well-layout parameters, the optimal horizontal section length is 1500m, the optimal insulation material length is 1000m. For the engineering parameters, the optimal injection rate is 1500m3/d and the optimal injection fluid temperature is 288.15K to obtain a higher heat extraction power. The discontinuous mode can sustainably guarantee better heat extraction performance compared with continuous mode. These findings can provide some reasonable suggestions for the deep geothermal development. [Display omitted] [ABSTRACT FROM AUTHOR]

It is necessary to establish effective communication between two horizontal wells during the preheating period of steam-assisted gravity-drainage (SAGD). However, the preheating time is usually very long, which results in high steam consumption and CO2 emissions. There is little research on the effects of different wellbore fluids during the preheating period. The heat transfer and heating characteristics of different wellbore fluids–water, heat-conduction oil, and air–were explored by using physical experiments and numerical simulations. In this study, the results indicated that the heat-transfer performance of heat-conduction oil is the best. The numerical simulation's results indicated that compared with the wellbore saturated with water, the heat-conduction oil reduced the viscosity of crude oil, and energy consumption was not obvious during the preheating stage. The super-heavy oil flowed into the wellbore due to the solubility of the heat-conduction oil and its own gravity. As a result, the super-heavy oil content in the wellbore gradually accumulated, increasing the risk of coking. Those experiments showed that the use of electrical heating provides good potential to improve SAGD efficiency during the preheating period, and water is the best injection fluid for wellbores during the electrical heating process. [ABSTRACT FROM AUTHOR]

Copyright of Natural Gas Geoscience is the property of Natural Gas Geoscience and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Drilling fluid infiltration during well drilling may induce pore pressure and strain perturbations in neighbored reservoir formations. In this study, we report that such small strain changes (∼20 µε) have been in situ monitored using fiber-optic distributed strain sensing (DSS) in two observation wells with different distances (approximately 3 and 9 m) from the new drilled wellbore in a shallow water aquifer. The results show the layered pattern of the drilling-induced hydromechanical deformation. The pattern could be indicative of (1) fluid pressure diffusion through each zone with distinct permeabilities or (2) the heterogeneous formation damage caused by the mud filter cakes during the drilling. A coupled hydromechanical model is used to interpret the two possibilities. The DSS method could be deployed in similar applications such as geophysical well testing with fluid injection (or extraction) and in studying reservoir fluid flow behavior with hydromechanical responses. The DSS method would be useful for understanding reservoir pressure communication, determining the zones for fluid productions or injection (e.g., for CO2 storage), and optimizing reservoir management and utilization. [ABSTRACT FROM AUTHOR]

Drilling fluid infiltration during well drilling induces pore pressure and strain perturbations in neighboured reservoir formations. In this study, we in situ monitored such small strain changes (~20µε) using fiber-optic distributed strain sensing in two observation wells with different distances (approximately 3m and 9m) from a new drilling wellbore in a shallow water aquifer. The results suggest that the drilling induced hydromechanical deformations that occurred at depths of both wells are indicative of the impact zones of fluid invasion and reservoir permeability structure (heterogeneity). A hydraulic diffusion model is used to interpret the strain evolution. The method and data would be useful for understanding reservoir pressure communications, determining the zones for fluid productions or injections (e.g., for CO2 storage), and optimizing reservoir management and utilization. [ABSTRACT FROM AUTHOR]

• Heat extraction from abandoned oil wells using nanofluids in coaxial heat exchanger. • COP of coaxial heat exchanger with nanofluids was 1.83 times to that of water. • Cu/water nanofluid with 4% volume fraction enhanced the outlet temperature by 25%. • Cu/water nanofluid extract higher heat energy followed by Al 2 O 3 -Cu , CuO and Al 2 O 3. • Hybrid nanofluids were also a potential alternative to extract geothermal energy. The present study aims to analyze the thermal performance of the water-based nanofluids inside the wellbore heat exchangers to extract the geothermal energy from abandoned oil and gas wells (AOGW). Consequently, the study has considered Al 2 O 3 /water, Cu/water and CuO/water nanofluids as well as the Al 2 O 3 –Cu/water hybrid nanofluid with various particle volume concentrations ranging from 1% to 4% inside the coaxial wellbore heat exchanger (CWHE). For this purpose, a conjugate heat transfer module with a well-known k-epsilon (k-ε) turbulent model of COMSOL Multi-physics has been employed to simulate the fluid flow and heat transfer of the CWHE installed in AOGWs. Additionally, a sensitivity analysis has also been performed to determine the impact of individual operational parameters such as injection fluid mass flow rate and temperature on the system's thermal performance. It has been noted that the outlet fluid temperature enhanced by 25% with the addition of 4% of Cu nanoparticles to the water. Moreover, the maximum coefficient of performance of CWHE has been observed around 1.83 using Cu/water nanofluid with 4% volumetric fractions at an injection fluid temperature of 20 °C and a mass flow rate of 5 kg/s. Finally, the Cu/water nanofluid provided the best thermal performance followed by Al 2 O 3 -Cu /water, CuO/water and Al 2 O 3 /water nanofluids. It is expected that the findings of this study could motivate the researchers to work on the potential application of nanofluids/hybrid nanofluids to extract geothermal energy from AOGWs. [ABSTRACT FROM AUTHOR]

• A flow simulation model was created to investigate gas injection of a four-well pad for temporary gas storage and to assess the possibility of incremental oil production. • The effect of the injected gas on adjacent wells is an important consideration regarding regulatory and ownership constraints. The modeling results enable analysis of adjacent wells and the impact to neighboring multi-pads. • Economic evaluation to assess the feasibility of gas re-injection in the Bakken Formation. • A comprehensive study of upstream gas flaring situation in North Dakota, USA. The flaring of associated gas from oil wells and the excess gas from gas-processing units and oil refineries is one of the most prominent producers of greenhouse gas emissions and is an extraordinary waste of economic value given the huge volumes of flared gas. In light of the increasing awareness of its negative impact, the industry is investigating economical means to reduce the anthropogenic release of greenhouse gases into the atmosphere. Oil production from the Bakken and Three Forks formations has significantly increased over the last ten years without commensurate augmentation of gas capture infrastructure, which consequently resulted in increased flaring of the associated gas. The North Dakota Industrial Commission (NDIC) has set rigorous regulations to reduce flaring. However, operating companies are experiencing challenges to meet NDIC gas capturing limit of 95%, which leads to oil production being curtailed. The project's main objectives are to evaluate technically and economically the feasibility of deploying gas re-injection in the Bakken Formation as a means to increase oil recovery, reduce flaring and meet North Dakota Industrial Commission requirements. The techno-economic assessment utilizes reservoir simulation inputs and outputs such as production rate, fluid composition, injection fluid rate and composition, and bottom hole flowing pressure to provide a detailed costs and revenue estimation of injection and production. Different gas injection schemes are investigated, surface equipment and gas injection network are modeled and optimized. It is substantiated that gas re-injection can increase oil recovery by 34%. The results of this effort suggest that gas re-injection to mitigate flaring in the Bakken can be economically achievable. [ABSTRACT FROM AUTHOR]