Abstract:This study is a continuation of our previous work, which focused on a near-wellbore water blockage alleviation by applying a thermally cured silane-functionalized benzoxazine to modify rock wettability. In this new analysis, we have demonstrated that the resin can be applied in low-permeability sandstones (approximately 15 mD as opposed to 100 to 200 mD in the previous study) to change the rock surface wettability from water-wet to intermediate gas-wet. We have also demonstrated that curing temperatures as low… Show more
“…Water removal efficiency also reaches around 85%, making both viable options for blockage removal. (7) In wells with quartz-containing blockages, HCl shows lower dissolution rates, whereas mud acid is more effective, exceeding 80% dissolution. Mud acid demonstrates a significantly higher removal efficiency.…”
Section: Discussionmentioning
confidence: 99%
“…Preliminary analysis suggests that the surge in blocked wells can be attributed to two primary scenarios. First, low-producing gas wells often exhibit limited liquid carrying capacity, leading to substantial water accumulation in the wellbore, resulting in pronounced effusion and water blockage issues. , Second, low-flow-rate natural gas, containing corrosive gases such as H 2 S and CO 2 , continuously carries saturated water vapor, which increases mineralization levels at the well’s bottom, contributing to scaling and sand deposition within the wellbore. , However, a comprehensive understanding of the blockage types, mechanisms, and appropriate treatment methods remains elusive.…”
In the Changqing area, over 23.6% of gas wells produce less than 0.1 × 10 4 m 3 /d of gas daily, posing a challenge to gas field sustainability. Laboratory analysis of scale samples from three wells and formation water analysis via inductively coupled plasma revealed soluble salt as the primary well blockage, with sodium chloride and calcium chloride comprising 48.0−81.2% of total content. The G3# well blockage contains a small amount of quartz from acid-insoluble components of carbonate acidification. Formation water from all wells exhibited high salinity (up to 153 g/L) with a calcium chloride water type. Scanning electron microscopy and EDS confirmed halite and quartz features in blockage samples. Theoretical calculations show salt crystallization when tubing pressure falls below 10 MPa and daily water production is <1.0 tons/day. Lower production leads to lower tubing pressure and higher salt precipitation at the bottom of the well. For G1# and G2# blockages, HCl dissolves >90%, and water >85%, making them suitable removal agents. For 3# blockage, mud acid with >80% dissolution is recommended. Chemical methods effectively clean the wellbore and formation. Optimized blockage removal measures increase tubing pressure and daily production by 2.18 and 4.05 times, respectively. This study offers insights into addressing well blockage challenges in low-producing gas wells.
“…Water removal efficiency also reaches around 85%, making both viable options for blockage removal. (7) In wells with quartz-containing blockages, HCl shows lower dissolution rates, whereas mud acid is more effective, exceeding 80% dissolution. Mud acid demonstrates a significantly higher removal efficiency.…”
Section: Discussionmentioning
confidence: 99%
“…Preliminary analysis suggests that the surge in blocked wells can be attributed to two primary scenarios. First, low-producing gas wells often exhibit limited liquid carrying capacity, leading to substantial water accumulation in the wellbore, resulting in pronounced effusion and water blockage issues. , Second, low-flow-rate natural gas, containing corrosive gases such as H 2 S and CO 2 , continuously carries saturated water vapor, which increases mineralization levels at the well’s bottom, contributing to scaling and sand deposition within the wellbore. , However, a comprehensive understanding of the blockage types, mechanisms, and appropriate treatment methods remains elusive.…”
In the Changqing area, over 23.6% of gas wells produce less than 0.1 × 10 4 m 3 /d of gas daily, posing a challenge to gas field sustainability. Laboratory analysis of scale samples from three wells and formation water analysis via inductively coupled plasma revealed soluble salt as the primary well blockage, with sodium chloride and calcium chloride comprising 48.0−81.2% of total content. The G3# well blockage contains a small amount of quartz from acid-insoluble components of carbonate acidification. Formation water from all wells exhibited high salinity (up to 153 g/L) with a calcium chloride water type. Scanning electron microscopy and EDS confirmed halite and quartz features in blockage samples. Theoretical calculations show salt crystallization when tubing pressure falls below 10 MPa and daily water production is <1.0 tons/day. Lower production leads to lower tubing pressure and higher salt precipitation at the bottom of the well. For G1# and G2# blockages, HCl dissolves >90%, and water >85%, making them suitable removal agents. For 3# blockage, mud acid with >80% dissolution is recommended. Chemical methods effectively clean the wellbore and formation. Optimized blockage removal measures increase tubing pressure and daily production by 2.18 and 4.05 times, respectively. This study offers insights into addressing well blockage challenges in low-producing gas wells.
Deep saline aquifers are often favorable for underground CO2 sequestration due to their large capacity and relatively low likelihood for resource conflicts. However, many possible issues can arise during CO2 injection. Often these aquifers have a significant salinity level (as these often present minimal resource conflict issues) and as such salt precipitation near the injection wellbore can be problematic. Furthermore, when water blockage occurs, salt precipitation can be exacerbated since large amounts of water remain near the wellbore. Altering the rock wettability towards less water-wet can alleviate water blockage and in turn reduce the likelihood or severity of salt precipitation. Previous lab experiments have shown that supercritical CO2 (sc-CO2)-based silylation can effectively functionalize rock surfaces with hydrophobic silanes. In this study, numerical models were constructed to evaluate the combined effects of multi-phase fluid flow, water evaporation and salt precipitation assuming a change in wettability (thus impacting the relative permeability characteristics of the reservoir) resulting from the silylation process. The aim of this study is to evaluate the efficacy of this chemical treatment to address near wellbore salt precipitation induced by CO2 injection. According to the simulation results, a decrease in injectivity due to salt precipitation is more significant when water blockage is also present. Injectivity is deteriorated prominently in high salinity reservoirs with water blockage since evaporation into the injected CO2 phase will cause significant salt precipitation. In a representative formation, the injectivity decline is worse (up to 68.6% relative injectivity change (RIC)) when both salt precipitation and water blockage are considered since the latter provides more trapped brine inducing more salt accumulation around the wellbore. With hydrophobic silylation, the combined effects of salt precipitation and water blockage on RIC are decreased on an absolute basis by up to 7%. Depending on techno-economic considerations, this method is encouraged to be implemented as early as possible during a CO2 injection program to minimize salt accumulation from the outset.
Summary
To promote the effect of waterflooding of a heterogeneous low-permeability reservoir in the Ordos Basin, a microbial plugging agent is developed to plug the multiscale water channeling. Based on the characteristics of the growth of bacteria, the microbial plugging agent can plug both porous media and microfractures with different scales. The microbial plugging agent is prepared by activating the native bacteria present in low-permeability reservoirs by using the fermentation nutrients. After growing in the fermentation nutrient solution for 4 days in a beaker, the growth of microbial strains begins to stabilize. After that, the main particle size of the prepared microbial plugging agent is between 40 μm and 160 μm and the median particle size (D50) is near 90 μm. The microbial plugging agent has good shear resistance, salt resistance, and stability. At the initial state, due to good injectivity, the microbial plugging agent can smoothly enter into a low-permeability core, a heterogeneous core, and a fractured core, respectively. Thus, it can grow and reproduce in the cores. Based on the characteristics of growth, it can match with the spatial scale of pore or fracture in the cores, so that it cannot only plug the porous media water channeling with different scales but also plug the microfracture water channeling with different scales. This phenomenon has been confirmed by microscopic visualization flow experiments and core flow experiments. The developed microbial plugging agent can be applied to plug the multiscale water channeling to enhance oil recovery of low-permeability heterogeneous reservoirs.
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