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BackgroundBreast cancer (BC) exhibits a high incidence rate, imposing a substantial burden on healthcare systems. Novel drug targets are urgently needed for BC. Mendelian randomization (MR) has gained widespread application for identifying fresh therapeutic targets. Our endeavor was to pinpoint circulatory proteins causally linked to BC risk and proffer potential treatment targets for BC.MethodsThrough amalgamating protein quantitative trait loci from 2,004 circulating proteins and comprehensive genome-wide association study data from the Breast Cancer Association Consortium, we conducted MR analyses. Employing Steiger filtering, bidirectional MR, Bayesian colocalization, phenotype scanning, and replication analyses, we further solidified MR study outcomes. Additionally, protein-protein interaction (PPI) network was harnessed to unveil latent associations between proteins and prevailing breast cancer medications. The phenome-wide MR (Phe-MR) was employed to assess potential side effects and indications for the druggable proteins of BC. Finally, we further affirmed the drugability of potential drug targets through mRNA expression analysis and molecular docking.ResultsThrough comprehensive analysis, we identified five potential drug targets, comprising four (TLR1, A4GALT, SNUPN, and CTSF) for BC and one (TLR1) for BC_estrogen receptor positive. None of these five potential drug targets displayed reverse causation. Bayesian colocalization suggested that these five latent drug targets shared variability with breast cancer. All drug targets were replicated within the deCODE cohort. TLR1 exhibited PPI with current breast cancer therapeutic targets. Furthermore, Phe-MR unveiled certain adverse effects solely for TLR1 and SNUPN.ConclusionOur study uncovers five prospective drug targets for BC and its subtypes, warranting further clinical exploration.

Background and aim: Rivaroxaban is an emerging oral anticoagulant for postoperative anticoagulation after percutaneous left atrial appendage closure (LAAC). Because a once-daily dosing regimen of rivaroxaban causes fluctuations in the drug plasma concentration, we studied the feasibility and safety of twice-daily rivaroxaban as a postoperative anticoagulation regimen for patients with atrial fibrillation (AF) undergoing LAAC.Methods: This study involved patients with AF who underwent LAAC and took rivaroxaban postoperatively. A total of 326 patients who received a standard total dose (15 or 20 mg) of rivaroxaban based on their creatinine clearance rate were divided into the twice-daily (BID) rivaroxaban group (n = 208) and once-daily (QD) rivaroxaban group (n = 118) according to their anticoagulation strategy. Transesophageal echocardiography was recommended at 3–6 months postoperatively to check for device-related thrombosis (DRT). Clinical outcomes were evaluated during postoperative anticoagulation.Results: The median CHA2DS2-VASc score (4 [3, 5] vs. 4 [3, 5], p = 0.28) and HAS-BLED score (2 [2, 3] vs. 2 [2, 3], p = 0.48) were not significantly different between the groups. During the anticoagulation period (4.1 ± 0.7 vs. 4.1 ± 0.9 months, p = 0.58), 148 (71.2%) patients in the BID group and 75 (63.6%) in the QD group underwent follow-up transesophageal echocardiography. There were no statistically significant differences between the two groups in terms of DRT (1.4% vs. 2.7%, p = 0.60), minor bleeding (8.2% vs. 11.0%, p = 0.39), thromboembolic events (1.0% vs. 0.8%, p = 1.00), major bleeding (0.5% vs. 0.8%, p = 1.00), or death.Conclusion: A short course of twice-daily rivaroxaban following LAAC is a feasible alternative regimen with a low rate of major bleeding events, DRT, and thromboembolic events for patients with AF.

Sequestering CO2 in depleted oil reservoirs provides one of the most appealing measures to reduce greenhouse gases (GHG) concentration in the atmosphere. The remaining liquids after enhanced oil recovery (EOR) processes, including residual oil and remaining water, lead to the main challenges to this approach. How to effectively evacuate a depleted oil reservoir by recovering not only residual oil but also remaining water is a critical consideration for this type of CO2 sequestration. This paper presents conceptual investigations concerning the methods which effectively evacuate depleted oil reservoirs from both the displacement efficiency and the sweep efficiency points of view. To improve the displacement efficiency, surfactant slug and solvent slug injection was examined using a core scale numerical model. Investigations regarding improving sweep efficiency, such as horizontal well pattern infilling and foam injection, were carried out based on a typical row well pattern. Simulation results showed that surfactant slug which modified the relative permeability and capillary pressure remarkably reduced both residual oil saturation and remaining water saturation. A CO2 slug injected before surfactant slug can help improve the oil recovery. Solvent enriched CO2 slug also remarkably reduced the residual oil saturation to as low as 2%. Horizontal well pattern infilling had great advantage for thick or inclined reservoirs, and foam slug injection greatly improved CO2 storage capacity in thin reservoirs by improving the sweep efficiency. Maximum mobility reduction (MRF) is the most important parameter to maximize the storage capacity and the benefit. The variation of CO2 storage capacity along with CO2 slug size. Larger foam slug size will play a better storage performance. The conceptual simulation investigations confirmed that depleted oil reservoirs can be effectively evacuated for CO2 storage. Depleted oil reservoirs with maximum evacuation are the best candidates for CO2 sequestrations. [ABSTRACT FROM AUTHOR]

Shale oil resources are abundant, but reservoirs exhibit strong heterogeneity with extremely low porosity and permeability, and their development is challenging. Carbon dioxide (CO2) injection technology is crucial for efficient shale oil development. When CO2 is dissolved in reservoir formation water, it undergoes a series of physical and chemical reactions with various rock minerals present in the reservoir. These reactions not only modify the reservoir environment but also lead to precipitation that impacts the development of the oil reservoir. In this paper, the effects of water–rock interaction on core porosity and permeability during CO2 displacement are investigated by combining static and dynamic tests. The results reveal that the injection of CO2 into the core leads to reactions between CO2 and rock minerals upon dissolution in formation water. These reactions result in the formation of new minerals and the obstruction of clastic particles, thereby reducing core permeability. However, the generation of fine fractures through carbonic acid corrosion yields an increase in core permeability. The CO2–water–rock reaction is significantly influenced by the PV number, pressure, and temperature. As the injected PV number increases, the degree of pore throat plugging gradually increases. As the pressure increases, the volume of larger pore spaces gradually decreases, resulting in an increase in the degree of pore blockage. However, when the pressure exceeds 20 MPa, the degree of carbonic acid dissolution will be enhanced, resulting in the formation of small cracks and an increase in the volume of small pores. As the temperature reaches the critical point, the degree of blockage of macropores gradually increases, and the blockage of small pores also occurs, which eventually leads to a decrease in core porosity. [ABSTRACT FROM AUTHOR]

To investigate the impact of the soaking strategy on the entire shut-in, flowback, and production processes following hydraulic fracturing, we developed a core simulation system using nuclear magnetic resonance technology to track fluid migration across the entire process. This simulation system, with a specially designed core sample, enabled us to quantify the contribution of each stage to oil production and analyze the stimulation mechanism of soaking from an integrated perspective. Our results demonstrate that forced imbibition during the shut-in stage includes both countercurrent imbibition and cocurrent displacement. Increasing the pressure difference between the fracture and matrix strengthens the displacement effect and weakens the imbibition effect, leading to decreased oil recovery. In contrast, from an integrated perspective, increasing the pressure difference can enhance total oil recovery. This is because two additional stimulation mechanisms of soaking, namely, oil–water redistribution and formation pressure enhancement, can be observed only during the subsequent flowback and production stages and not during the shut-in period. As the pressure difference increases, the main stimulation mechanism of soaking changes from countercurrent imbibition to oil–water redistribution and formation pressure enhancement. Additionally, we observed that the soaking strategy can cause severe water blockage, hindering the full utilization of the formation pressure enhancement mechanism. This study reveals that the stimulation mechanisms in the shut-in stage have a wide-ranging impact that extends beyond this stage. Therefore, adopting an integrated approach is necessary to study the stimulation mechanism of soaking, breaking the traditional view of analyzing a single stage alone. [ABSTRACT FROM AUTHOR]

Reservoir heterogeneity is the main cause of high water production and low oil recovery in oilfields. Extreme heterogeneity results in a serious fingering phenomenon of the displacing fluid in high permeability channels. To enhance total oil recovery, the selective plugging of high permeability zones and the resulting improvement of sweep efficiency of the displacing fluids in low permeability areas are important. Recently, a Branched Preformed Particle Gel (B-PPG) was developed to improve reservoir heterogeneity and enhance oil recovery. In this work, conformance control performance and Enhanced Oil Recovery (EOR) ability of B-PPG in heterogeneous reservoirs were systematically investigated, using heterogeneous dual sandpack flooding experiments. The results show that B-PPG can effectively plug the high permeability sandpacks and cause displacing fluid to divert to the low permeability sandpacks. The water injection profile could be significantly improved by B-PPG treatment. B-PPG exhibits good performance in profile control when the high/low permeability ratio of the heterogeneous dual sandpacks is less than 7 and the injected B-PPG slug size is between 0.25 and 1.0 PV. The oil recovery increment enhanced by B-PPG after initial water flooding increases with the increase in temperature, sandpack heterogeneity and injected B-PPG slug size, and it decreases slightly with the increase of simulated formation brine salinity. Choosing an appropriate B-PPG concentration is important for B-PPG treatments in oilfield applications. B-PPG is an efficient flow diversion agent, it can significantly increase sweep efficiency of displacing fluid in low permeability areas, which is beneficial to enhanced oil recovery in heterogeneous reservoirs.