This paper proposes a novel method for planning active distribution networks (ADNs) with the integration of an active network management (ANM) scheme using coordinated voltage control (CVC) through on-load tap changer (OLTC) transformers. The method was formulated as a security-constrained optimal power flow (SCOPF) problem to minimize total operational costs, which maximizes the utilization of renewable distributed generators (DGs) over a planning horizon. The ANM scheme was applied using OLTC to ensure safe operation and reduce voltage violations in the network. To analyse the impact of ANM, the planning problem was examined both with and without the ANM scheme. Moreover, SCOPF, considering the N-1 line contingency analysis and multi-DG configuration, was implemented to analyse the feasibility of the proposed method and the advantages of ANM under contingency situations. The method was validated on a weakly-meshed 16-bus UK generic distribution system (UKGDS). The results showed that ANM can lower operational costs and maintain network voltage for operation in feasible conditions even in the case of a contingency. Moreover, the ANM scheme mitigated the voltage rise effect caused by DGs and maximized their utilization.
Abstract:Bamboo viscose or regenerated cellulose fibers were used to check their absorbency properties effect on the wicking and moisture management in gauzes. Bamboo viscose and cotton fibers were spun into five different yarn samples with different fiber proportion by ring spinning. Fifteen different gauze samples were made of these yarn samples. The gauze samples were subjected to wicking test to check the wicking ability. Water vapor transmission test was applied to check the vapor transmission rate. These tests were applied to measure the effectiveness of bamboo viscose, cotton and blended gauze samples in wound healing. Pure bamboo gauzes and gauzes with high content of bamboo fiber, i.e. 75B:25C and 50B:50C, shows better wicking and vapor transmission properties. It makes gauzes with high bamboo viscose suitable for wound care applications because of moisture absorbency.
Long horizontal wells in naturally fractured carbonate reservoirs often exhibit very high water-cut within months of production because of the early arrival of water from natural fractures. Passive inflow control devices (P-ICDs) have been used globally to balance influx, delay water or gas breakthrough to prolong well life. However, some wells have continued to experience high water-cut despite the control measures. Image log review has revealed the uncertainty is in the identification of fractures and its conductivity networks. Two additional zonal control technologies are presented in this paper: on/off ICDs and intelligent (IC) or smart completions in comparison. A software-based 3D reservoir model was built to represent a horizontal oil-producer in a fractured carbonate reservoir penetrating a thin oil rim. The first model simulated well production performance in a well with on/off ICD. Intervention was replicated in time (i.e., taking longer) to shut-off ICDs. The second model evaluated production forecast over the same period for the same well, this time equipped with an IC in the open hole (OH). Actions in this case were taken right away from the surface (i.e. without downhole intervention) to identify and restrict or shut-off intervals with water breakthrough. Time-lapsed 3D reservoir model calibration is possible with ICs as they provide real-time downhole pressure and temperature across each interval. The timely control of zonal valves from surface actuation reduced production of water or gas. On/off ICDs, on the other hand, necessitated scheduling a production log (PL) to confirm the interval of water or gas breakthrough and performing coiled-tubing (CT) intervention to shut-off the problematic zone. Intervention comes at cost of interrupting well production and reducing net oil recovery. A simplified cost-benefit analysis of both cases showed that despite a higher initial capital investment in ICs, well operating costs were substantially lower with higher oil recovery. In IC solution, costs for running production logs and intervention tools were eliminated and so was the risk of losing these tools in the hole and the loss in production during the intervention period. Continuous monitoring of downhole pressure data helped reservoir characterization and prediction of reservoir production behavior without compromising production on-stream time. A comparison of different reservoir flow control devices suggests that ICs are the optimal choice in some fractured carbonate reservoir conditions. They provide real-time monitoring of each producing zone and surface control of the flow control valve (FCV) settings in real-time as reservoir performance changes. They enable production testing evaluation—without production logging and interventive shifting with CT, i.e. to determine the source of water entry and optimization of multi-zone production without downhole intervention.
Analyses of dynamic data that include pressure and production history have long been recognized as a tool to evaluate the underground reservoir size, fluid volumes and future performance. This study encompasses a similar case utilizing analytical and numerical methods to interpret the dynamic data. As a result several geological features were confirmed and a few sub-seismic features were identified. The field under discussion is located in Lower Indus Basin of Pakistan and characterized by hydrocarbon accumulations in Lower-Goru Upper-Sand reservoirs. Exploratory well A-1 discovered the field by finding gas bearing Sandstone reservoir established based on formation evaluation and open-hole log profile. The structure was bounded by two major intersecting faults and one splay fault, all juxtaposed against shale barriers. Due to these structural features A-Sand was expected to exhibit depletion drive mechanism. When A-1 was put on production, it performed as a dry gas producer for brief period of time then its gas rates started declining with increasing CGR. Routine surveillance recorded depletion in reservoir pressure and the well loaded up after a year. After reviving on Gas Lift and A-1 became essentially an oil producer with a GOR of 2000 scf/stb. BHP surveys showed no further depletion than 400 psia. These facts hinted at pressure support to A Sand reservoir as opposed to originally assumed closed structure. To enhance oil production hydraulic jet pump was installed and achieved apex oil rates from the well, interestingly, without commensurate increase in water production. On Jet Pump also, well exhibited fairly constant liquid withdrawals strengthened idea of pressure recharging. To identify source of A-Sand recharging, it was decided to (1) analyse pressure-production history (2) Closely analyse interpreted analytical model built on pressure data (3) Perform numerical PTA by integrating G&G data, and (4) develop Allen diagrams to see possible juxtaposition with downthrown blocks. The study concluded that Splay fault on reservoir structure may not be completely sealing since both Analytical and Numerical Model transient models strongly suggested slightly different position of splay fault on the west of the well. Allen Diagram further showed decreasing throw of the same fault intimating possibility of juxtaposition. Hence, it was concluded that the oil source and pressure support most probably lies beyond the western fault and could be confirmed by refining subsurface structure through re-interpretation of seismic data.This way, the work emphasized the role of dynamic data in adding value to a company's knowledge of subsurface elements and hence widen the scope of field development strategy.
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