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Luu, Hong Truong, Duong, Quoc Hung, Le, Khac Quyet, Lin, Che-Wei (2022): Begonia yentuensis and B. khaucaensis (Begoniaceae), two new species from northern Vietnam. Phytotaxa 560 (2): 222-232, DOI: 10.11646/phytotaxa.560.2.5, URL: http://dx.doi.org/10.11646/phytotaxa.560.2.5

Begonia yentuensis Luu & C.W. Lin, sp. nov. (Figs. 1 & 2) Type: — VIETNAM. Bac Giang Province: Yen Tu Mountain Range, Tay Yen Tu Nature Reserve, N21°09’58” E106°46’34”, 498 m elev., 09 August 2013, Luu Hong Truong, Hoang Minh Duc, Le Khac Quyet & Duong Quoc Hung TYT22 (holotype: SGN; isotypes: SGN, PHH & TAIF). Monoecious tuberous herb. Stem tuberous at base, tubers globose up to ca. 3 cm with numerous fibrous roots, stemless or sometimes producing leafless erect stem to 3 cm long, ca. 5 mm across, crimson, glabrous. Stipules yellowish pink to red, very widely triangular, 2–3 mm long, 4–6 mm wide, herbaceous, abaxially strongly aristate-keeled near tip of the midrib up to 8 mm long, margin ciliate; stipules at erect stem red, triangular, ca. 3–4 × 3 mm, herbaceous, slightly keeled, glabrous, margin entire to ciliate, apex acute and mucronate. Leaves solitary, nearly appressed to substrate; petiole terete, yellowish pink, 1–7 cm long, 3–6 mm across, adaxially densely hirsute, subglabrous abaxially; leaf blades symmetric or subsymmetric, very widely ovate to orbicular, undivided or with irregular pointed shallowly lobes ca. 3–10 mm long, blade 9–23 cm long, 8.2–24 cm wide, basal lobes cordate, 1.5–5 cm long, apex acute, margin biserrate and ciliate; leaf thick chartaceous, succulent, adaxially olive green to dusky green, slightly bullate and puberulous between veins, giving lamina a wrinkled texture; abaxially magenta to brownish red, puberulous and hirsute on veins; venation palmate, midrib distinguishable, 6–18 cm long, ca. 2 major lateral veins on either side of midrib, other primary veins branching dichotomously, tertiary veins reticulate. Inflorescences terminal on erect stem or arising directly from tuber, bisexual, cymosely branching panicle 7–25 cm long, peduncle 4–12.5 cm long, branched 3–5 times, erect, red, glabrous; protandrous. Bracts deciduous, red, ovate-triangular to ovate, first pair 7–10 × 5–7 mm, glabrous, margin ciliate, bracts of upper inflorescence similar but smaller. Staminate flower: pedicel creamy pink to red, 1.3–2 cm long, glabrous, tepals 4, white to pink, glabrous; outer 2, orbicular to widely ovate, 11−13 mm across; inner 2, obovate, 9–12 mm long, 5–6.5 mm wide, apex rounded; androecium zygomorphic, ca. 3.5 mm across; stamens yellow, 17–25; filaments shortly fused at base; anthers oblong, ca. 1 mm long, 2-locular, apex rounded, filaments ca. 1 mm long. Pistillate flower: pedicel red, 0.7–2.5 cm long, glabrous, ovary pale creamy green, trigonous-ellipsoid, 8–10 mm long, ca. 5 mm thick (wings excluded), glabrous; 3-winged, wings unequal, triangular, 11–13 mm long, glabrous; lateral wings narrower, 2–4 mm wide, abaxial wing 5–7 mm wide, margin entire; ovary 3-locular, placenta undivided; tepals 5 (rarely 4), white to pink, glabrous, outer 2, orbicular, 8–12 mm across; inner 3, suborbicular to obovate, 6–11 mm long, 5–10 mm wide, apex rounded; styles 3, fused at base, yellow, 2–3 mm long, stigma spirally twisted. Capsule capsule body ca. 15 mm long, 7.5 mm across, glabrous; wings 3, unequal, 16–18 mm long, lateral wings to 5 mm wide, abaxial wing to 13 mm wide, rounded to truncate proximally, truncate distally, splitting between the locules and wings. Distribution and ecology:— Begonia yentuensis is endemic to Bac Giang Province, North Vietnam. It is a deciduous lithophyte growing on sandstone rock under the canopy of a secondary moist tropical evergreen forest dominated by species of the Magnoliaceae, Fagaceae and Lauraceae mixed with bamboos. Phenology:— Flowering was found in July to September and fruiting starting in August. Etymology:— The species is named after its type locality, Yen Tu Mountain Range. Conservation status:— Begonia yentuensis was found in western slopes of the Yen Tu Mountain Range and appears to be rare within Tay Yen Tu Nature Reserve and fewer than 100 mature individuals. It may be found in adjacent forests of the Yen Tu Mountain Range. Therefore, we provisionally propose its conservation status as Data Deficient until more information is recorded (IUCN Standards and Petitions Subcommittee, 2022). Notes:— Begonia yentuensis resembles B. asperifolia Irmsch. (1927: 359) (Fig. 3) in its winter dormant habit, subsymmetric, rugose foliage, 4-tepaled staminate flowers and pistillate flowers with 5 tepals, but it is different in its shorter petioles up to 7 (vs. to 28) cm long, androecium golfclub-shaped (vs. spherical), filaments fused at base (vs. fused at base into a column ca. 2 mm long), anthers less than 25 (vs. more than 50), apex rounded (vs. acute to mucronate) and placentae unilamellate (vs. bilamellate). Like B. asperifolia, according to phenotypic morphology and geographical origin, B. yentuensis is best placed within the group known as “unassigned to section with tubers” that belongs to Begonia subg. Platycentrum in Shui’s system. Molecular studies are necessary to confirm if there are trait combinations or new morphological traits suitable for creating a new section, or assigning the species to a known section. In the subsymmetric, solitary leaf and terminal inflorescence, B. yentuensis is also similar to B. labordei H. Léveillé (1904: 323) (Fig. 4), but differs in the rugose (vs. flat) foliage, cymose inflorescence (vs. racemose at base), pistillate tepals 4 or 5 (vs. 3 or 4) and actinomorphic (vs. zygomorphic), ovary glabrous (vs. often hairy) and placentae unilamellate (vs. bilamellate). A comparison of the salient characters of the three species is presented in Table 1.

Begonia khaucaensis Luu & C.W.Lin, sp. nov. (Figs. 5 & 6) Type:— VIETNAM. Ha Giang Province: Dong Van Karst Plateau - Du Gia National Park, Khau Ca Forest, 22°50’54”N 105°7’16”E, 800m elev., 22 October 2016, Luu Hong Truong & Le Khac Quyet HG 6 (holotype: SGN; isotypes: SGN, PHH & TAIF). Monoecious rhizomatous herb. Rhizome stout, creeping, crimson, ca. 1 cm thick, internodes 0.5–3 cm long, hirsute. Stipules crimson to reddish olive green, widely triangular, 1.5–2.5 cm long, 1.2–2.3 cm wide, herbaceous, keeled, abaxial midrib scattered with white hirsute, margin entire, apex aristate, arista ca. 3 mm long. Leaves alternate, petiole terete, crimson to dark brownish red, 18–30 cm long, 0.5–1 cm thick, lenticels slightly prominent, creamy white, sparsely to densely hirsute, glabrescent; leaf blade asymmetric, suborbicular to reniform, oblique, with a welldeveloped basal lobe on one side giving a cordate appearance, 17.5−27 cm long, 15–23 cm wide, broad side 9.5–16 cm wide, basal lobes cordate, 5–11 cm long, margin sparsely denticulate to subentire, apex acuminate; leaf thin coriaceous, succulent, adaxially emerald green (vermilion to greenish maroon when juvenile), sparsely bullate between veins, bulla tipped white hirsute, glabrescent; abaxially pale green, veins pale red; venation basally 7–9 palmate, midrib distinct, ca. 2 secondary veins on each side, lateral through connection between with other basal veins, minor veins reticulate. Inflorescences axillary, dichasial cymes, arising directly from rhizome, branched up to 5 times; bisexual, cymosely branching panicle 16–30 cm long, peduncle olive green to crimson, 13–25 cm long, glabrous. Bracts white to rosy red, orbicular to very widely ovate, first pair up to 2.5 cm across, glabrous, margin entire, apex retuse to rounded or apiculate; bracts of upper inflorescence similar but smaller. Staminate flower: pedicel white to pink, 0.8–2 cm long, glabrous; tepals 4, white to rosy pink, glabrous; outer 2, very widely obovate to orbicular, 12–15 mm long, 13–16 mm wide; inner 2, elliptic, ca. 7 mm long, 3 mm wide; androecium zygomorphic, ca. 5 mm across; stamens golden yellow, 40–65, filaments fused at base, anthers narrowly obovate-triangular, ca. 1.5 mm long, 2-locular, apex truncate to slightly retuse, shorter than filaments. Pistillate flower: pedicel pinkish white to rosy pink, 1.7–2 cm long, glabrous; tepals 3, rosy pink to white, glabrous; outer 2, orbicular to widely depressed ovate, 9–14 mm long, 8–15 mm wide; inner 1, elliptic, 5–8 mm long, 2–3 mm wide; ovary narrowly trigonous-ellipsoid, 6–8 mm long, ca. 3 mm thick (wings excluded), pink to white, 3-winged; wings unequal, pinkish white, 8–10 mm long, lateral wings narrower, narrowly crescent-shaped, 1.5–2.5 mm wide, abaxial wing crescent-shaped, ca. 4 mm wide, margin entire; ovary 3-locular, placenta bilamellate; styles 3, fused at base, golden yellow, ca. 3.5 mm long, stigma spirally twisted. Capsule pendent on a stalk 28–37 mm long, tepals persistent, capsule ca. 15 mm long, 1 cm thick (wings included), wings unequal, crescent-shaped, rounded to cuneate proximally, rounded distally. Distribution and ecology:— Endemic to Du Gia National Park in Ha Giang Province. The new species is an evergreen lithophyte growing on damp limestone rock under the canopy of tropical evergreen forests dominated by Burretiodendron hsienmu W.Y.Chun & F.C.How (Malvaceae) and species of the Clusiaceae, Sapindaceae, Ebenaceae, Euphorbiaceae, Aceraceae, Araliaceae and Fagaceae. Phenology:— Flowering was seen in October and November, and fruiting starting in November. Etymology:— The species is named after its type locality, Khau Ca Forest. Conservation status:— Least Concern (LC) (IUCN Standards and Petitions Subcommittee, 2022). Begonia khaucaensis appears to be abundant and well protected within the Khau Ca Forest of Dong Van Karst Plateau - Du Gia National Park. No threats to its existence were seen. Notes:— B. khaucaensis is restricted to limestone regions, and it has characters such as rhizomatous habit, axillary inflorescence and 3-tepaled pistillate flowers. These characters are shared by sect. Coelocentrum, however, it is also similar with the broad delimitation of sect. Petermannia in Shui’s system (2019) in many aspects. We are unable to appropriately allocate this new species to any section until molecular information is available. Begonia khaucaensis somewhat resembles B. jubar V.T.Pham & C.W. Lin (2021: 145) in its rhizomatous habit, 4-tepaled staminate flowers and 3-tepaled pistillate flowers with 3-locular ovaries with blamellate placentae, but it is different from B. jubar in its hairy stipules (vs. glabrous), sparsely to densely hirsute petioles (vs. glabrous), suborbicular to reniform leaves (vs. ovate to widely ovate with slightly polygonal outline), entire bract margins (vs. denticulate to serrate with very short soft hairs), zygomorphic androecium (vs. actinomorphic or nearly so) and crescent-shaped ovary wings (vs. triangular). Moreover, B. khaucaensis bears some resemblance to B. quadripetiolata Aver. & H.Q.Nguyen (2019: 135) in the rhizomatous habit, uniformly green leaves, 4-tepaled staminate flowers and the bilamellate placentae, however, the new species markedly differs in the petioles have a terete outline (vs. quadrate), leaf upperside very sparsely hirsute hairs (vs. glabrous), zygomorphic (vs. actinomorphic) androecium and 3-tepaled (vs. 5-tepaled) pistillate flowers. A detailed comparison of B. khaucaensis with these two phenetically similar species are presented in Table 2., Published as part of Luu, Hong Truong, Duong, Quoc Hung, Le, Khac Quyet & Lin, Che-Wei, 2022, Begonia yentuensis and B. khaucaensis (Begoniaceae), two new species from northern Vietnam, pp. 222-232 in Phytotaxa 560 (2) on pages 227-230, DOI: 10.11646/phytotaxa.560.2.5, http://zenodo.org/record/7040690, {"references":["Lin, C. W., Phan, L. C. S. & Nguyen, N. H. (2021) Begonia rigidifolia ssp. sonhungii (sect. Petermannia, Begoniaceae), a new subspecies from limestone hills in Central Vietnam. Phytotaxa 498 (2): 139 - 144. https: // doi. org / 10.11646 / phytotaxa. 498.2.7"]}

The Simclast model has been verified and applied effectively in simulating the delta development for some major deltas in the world. In this study, we applied the model Simclast for simulating the history of the Red river delta development in late Pleistocene-Holocene. Results of the model reveal that the mainland of study area had reduced rapidly during transgression period (10,000-8,000 BP). The morphology changed significantly in the paleo-Red and Day river systems, but slightly in the paleo Thai Binh river system. The paleo-river network had been active in upper part before 11,000 BP and then shifted seaward until 2,000 BP. The river-sea interaction causes erosion and accumulation; as a result the morphology changed remarkably. The paleo-Thai Binh river had been inactive until 5,500 BP and then it was active but the morphology had not varied remarkably. The recent coastline generated from Simclast is relatively in accordance with the present coastline.

Recent geodynamic characteristics of the Southern Central coast are analyzed on the basis of vertical and horizontal displacement velocities along active fault zones. The horizontal displacement velocity varies in magnitude from this fault system to another fault system, from 0.11–0.3 mm/year on the strike-slip - normal faults to 0–0.058 mm/year on the strike-slip faults and normal faults. The subsidence velocity changes complicatedly, different from one fault to another fault, depending on the mechanism of faults. On the continental shelf, most of the values of high subsidence’s velocity are related to the normal and strike-slip faults. Subsidence activities make the sea level increase highly, the subsidence activity makes the sea level rise at structures that fall close to the shore, reach about 0.2–0.48 mm/year in late Pleistocene - Holocene. The increase of sea level directly affects the intensity of erosion, flood, salinity and land loss events in coastal lowlands. Slippage of the seabed, earthquakes, volcanoes are geological hazards directly related to the geodynamic regime of the Southern Central coast.

The article mentions the results of the new analysis of gas-geochemical and high resolution shallow seismic data acquired by the sea surveys in 2016, which revealed a remarkable coincidence between the seabed gas anomalies at river mouth area of Gulf of Tonkin and the gas distortion/accumulation phenomena in the near-surface sediment layers, especially right above the large tectonic fault systems, such as Red river, Lo river and Chay river. The gas-geochemical analysis reveals the existences of thermogenic and metamorphic methane and carbon dioxide gases within the faults of Red river and on Cat Ba island, anomalies of helium and hydrogen as well as the “heavy” isotopic carbon signals of methane and carbon dioxide in the areas of near-surface active faults. These new results suggest the initial conclusions about the relationship between gas-geochemical field and tectonic fault activities in study area.

This study presents a methodology for reactive power compensation provided by distribution static synchronous compensators (DSTATCOMs) to mitigate the voltage fluctuation and increase the solar energy harvest via photovoltaic (PV) inverters accordingly in medium-voltage distribution systems. An approximate method that uses one power flow run with the base-case system is analytically developed to offer a fast estimation of the location and size of DSTATCOMs to enhance the local voltage controllability over sunshine hours. This study then presents daily local reactive power control, where the control signals are calculated based on instantaneous measurements of the voltage at each bus without requiring any communications. The control method involves estimating the amount of reactive power support by the installed DSTATCOMs to reduce the voltage fluctuation during daytime while PV inverters are fully used to harvest the solar energy. At night-time, the DSTATCOMs operate as a master in voltage-controlled mode with other PV inverters in load mode if required to minimise the energy loss while improving the voltage profile. The proposed method has been tested on a 69-bus distribution system with 1 min load and 1 s solar power profiles and validated using a repeated power flow-based exact solution.

This paper proposes local reactive power control to mitigate the voltage fluctuation in medium-voltage systems using DSTATCOMs and photovoltaic (PV) inverters. New expressions are developed to estimate voltage fluctuations and reactive power compensations by transforming line segment power-flow variables into nodal power injections. Using local measurements of voltages and solar powers, the method can provide a fast estimation of reactive power compensations to maintain the voltage at every bus. DSTATCOMs are also properly allocated to enhance the voltage controllability. Coordinated control of multiple reactive power resources is investigated as well. One-second solar irradiance along with one-minute home loads is used to demonstrate the effectiveness of the proposed method.

This paper reports the results of the third Russian–Vietnamese expedition (V.I. Il'ichev Pacific Oceanological Institute, Far East Branch, Russian Academy of Sciences and the Institute of Marine Geology and Geophysics, Vietnam Academy of Science and Technology) in the Gulf of Tonkin, South China Sea (April 2016). The studies revealed new specific features of the distribution and origin of gasgeochemical fields in sediments within the rift zone of the Red River along a 150-km profile. Four zones with high-amplitude anomalies of hydrocarbon gases, helium, hydrogen, carbon dioxide, and carbon monoxide were revealed. The distribution of the anomalies reflects the tectonic structure of the area and points to the presence of several lithospheric sources of gases including gases of deep origin. The studies were carried out within the scope of the Joint Vietnamese–Russian Laboratory for Marine Geoscience (V.I. Il'ichev Pacific Oceanological Institute, Far East Branch, Russian Academy of Sciences and the Institute of Marine Geology and Geophysics, Vietnam Academy of Science and Technology).

Conventional deterministic electric vehicles (EV) charging coordination is performed assuming the EV and grid loads and PV output are known advance. In contrast, conventional probabilistic EV charging coordination takes into account the uncertainties of EV and grid loads and PV output without considering their mutual correlations. The major drawbacks of these methods are that the conventional deterministic charging increases the probability of voltage and current noncompliance (PVCN), while the conventional probabilistic charging decreases the quality of service (QoS). Therefore, this paper proposes a novel correlated probabilistic model for EV charging loads in coordination with a solar photovoltaic (PV)-rich commercial grid. In this model, correlated samples are generated from uncorrelated samples, which contain various random variables associated with EVs, battery energy storage (BES) and PV. The generated samples are subsequently incorporated in the proposed coordinated EV charging method, where the power factors of BES and PV are also controlled, to maximize QoS while minimizing PVCN. The effectiveness and practicability of the developed model are validated on an IEEE 37-bus unbalanced distribution system, which is associated with the real data of vehicles and solar PV collected from a campus of the University of Queensland.

The Day river coastal zone is the place of plentiful and eventful economical activities and the natural habitat of diverse endemic species that should be preserved and developed. According to the updated geological, remote-sensing and oceanographic data sources, this study figures out the actual state, evolutional history and forecasts the development of the Day river coastal zone up to the year 2070, which could be used to improve the effectiveness of the long-term spatial coastal zone management and master planning. Major conclusions are as follows: (i) The Day river coastline has been highly modified since the last 50 years, (ii) The shoreline seaward development tends to gradually decrease in recent years, and (iii) The river-bed continues to be shifted southwestwards in the context of global climate change and sea level rise.

The scheme of the faults in South Central coastal region was established on the basis of interpreting the high resolution shallow seismic data and the deep-seismic data, in combination with the previous studies on geodynamics, tectonic evolution, geological hazards of the South Central coastal region. The fault systems were formed based on updated geophysical, geomorphological, tectonophysic and remote sensing data, including 19 faults in 3 directions: Sub-longitudinal (8 faults), NE-SW (7 faults) and NW-SE (4 faults).

The model of Late Pleistocene-Holocene sequence stratigraphy of the subaqueous Red River delta and the adjacent shelf is proposed by interpretation of high-resolution seismic documents and comparison with previous research results on Holocene sedimentary evolution on the delta plain. Four units (U1, U2, U3, and U4) and four sequence stratigraphic surfaces (SB1, TS, TRS and MFS) were determined. The formation of these units and surfaces is related to the global sea-level change in Late Pleistocene-Holocene. SB1, defined as the sequence boundary, was generated by subaerial processes during the Late Pleistocene regression and could be remolded partially or significantly by transgressive ravinement processes subsequently. 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A fundamentally new conclusion that zones of high seismic activity are controlled by electroconducting (fluid-saturated) fragments rather than by the entire deep fault is drawn. It is shown that the areal abundance of earthquake foci in geoelectric blocks of the Earth’s crust within Sakhalin and Vietnam containing electroconducting formations is mostly controlled by their roof occurring at a depth of ≤15 km.

The maximum horizontal gradient method was first proposed by Blakely and Simpson (1986) for determining the boundaries between geological bodies with different densities. The method involves the comparison of a center point with its eight nearest neighbors in four directions within each 3 × 3 calculation grid. The horizontal location and magnitude of the maximum values are found by interpolating a second-order polynomial through the trio of points provided that the magnitude of the middle point is greater than its two nearest neighbors in one direction. In theoretical models of multiple sources, however, the above condition does not allow the maximum horizontal locations to be fully located, and it could be difficult to correlate the edges of complicated sources. In this paper, the authors propose an additional condition to identify more maximum horizontal locations within the calculation grid. This additional condition will improve the method algorithm for interpreting the boundaries of magnetic and/or gravity sources. The improved algorithm was tested on gravity models and applied to gravity data for the Phu Khanh basin on the continental shelf of the East Vietnam Sea. The results show that the additional locations of the maximum horizontal gradient could be helpful for connecting the edges of complicated source bodies.

Focusing on every individual electric vehicle (EV) while optimally charging a significant number of EV units at the workplace is normally computationally burdensome. Such charging optimization requires not only a long runtime but also a large CPU memory due to numerous decision variables involved. This paper develops a new combined state of charge (SOC) based methodology to calculate day-ahead combined probabilistic charging loads for a large number of EV units. Here, several models are proposed to estimate different combined statistical parameters based on historical data. The proposed methodology determines the transition of the combined SOC distribution of EV units from one timeslot to the next using these estimated parameters. Various strategies of SOC-based charging (e.g., unfair and fair modes) are investigated to control EV loads. Numerical results show that the proposed SOC-based charging can reduce the number of decision variables significantly, and require less computational time and memory accordingly.

The electrical power sector has entered an era of decarbonizing energy generation by accommodating more Renewable Energy Sources (RES), especially solar energy in the power grid. However, high penetration of such a resource has negative impacts on the power network such as power fluctuations, reverse power flows and voltage rises. Energy Storage (ES) offers an effective solution to addressing those challenges while improving the load factor as well as the utilization of network infrastructures. This paper proposes a new framework to integrate Community Energy Storage (CES) units in an existing residential community system with rooftop solar Photovoltaic (PV) units. In this framework, three analytical approaches are respectively developed to handle three important parameters of the CES integration (i.e. locations, sizes and operational characteristics) to enhance network performances. Firstly, a simple approach is developed on the basis of a Center of Gravity (COG) theory to determine the location of CES for minimizing the annual energy loss. Secondly, a new analytical formulation based on a load following control method is presented to identify the proper rated capacity of CES and its hourly dispatch strategy for achieving a desired annual load factor. Lastly, a technique to estimate the optimal operational characteristic of CES is proposed for flattening the daily demand profile and improving the voltage profile. The proposed framework is tested on a 19-bus test system while considering the probability of PV generation along with load variations. The numerical results show that the developed framework can bring the system load factor to a maximum of 0.76, at which the penetration levels of CES and PV are at 22% and 5% respectively while reducing the energy loss by 24.21% and enhancing the voltage profile significantly. The results also indicate that 22% CES penetration can reduce the annual purchased energy cost from the grid by 11.1% and the annual energy loss cost by 36.88%, where the system accommodates respective PV penetration levels of 5% and 50%.

Single-phase solar photovoltaic (PV) injections in distribution systems can lead to voltage rise problems. This paper presents a mathematical framework to evaluate the phenomenon of rise in the voltage due to single-phase PV injections in 3-phase 4-wire distribution systems. The impacts of single-phase PV generation on neutral-point shifting and its effects on voltage unbalance criteria (e.g., NEMA standards) are thoroughly investigated. Injection of single-phase PV increases the voltage on that phase while decreasing the voltage on other phases, worsening the voltage unbalance problem. Furthermore, the influence of ZIP load models on voltage quality is investigated. This accurate load model can help reducing voltage unbalance factors for a given PV penetration level.

This paper proposes a multiobjective voltage unbalance factor to estimate single-phase photovoltaic (PV) hosting capacity in 3-phase residential networks. This factor is derived from a combination of various components, including zero and negative-sequence voltage unbalance factors associated with the inherent variability and uncertainty of both loads and PV generation. A time-varying probabilistic ZIP load model is also incorporated in the proposed factor to characterize the uncertainty of voltage-dependent loads within each hour of a day over four seasons. The location, size and phase allocation of PV units are randomly generated. Simulation results obtained on a modified IEEE 4-bus test feeder and the IEEE European low voltage test feeder show that the developed approach can provide a better response to the hourly-varying and uncertain behaviors of loads and generation.

A constant or voltage-dependent load model is usually assumed in most distributed generation (DG) planning studies. However, this paper proposes several different types of time-varying voltage-dependent load models to determine the penetration level of photovoltaic (PV) units in a distribution network. Here, a new analytical expression is first proposed to size a PV unit, which can supply active and reactive powers. This expression is based on the derivation of a multiobjective index (IMO) that is formulated as a combination of three indices, namely active power loss, reactive power loss and voltage deviation. The expression is then adapted to allocate PV units while considering the time-varying load models and probabilistic PV generation. The effectiveness of the proposed approach was validated on 69- and 33-bus test distribution systems. The results showed that PV allocation with different types of time-varying load models can produce dissimilar penetration levels.

An accurate load forecasting is always particularly important for optimal planning and energy management in smart buildings and power systems. Millions of dollars can be saved annually by increasing a small degree of improvement in prediction accuracy. However, forecasting load demand accurately is a challenging task due to multiple factors such as meteorological and exogenous variables. This paper develops a novel load forecasting model, which is based on a feed-forward artificial neural network (ANN), to predict hourly load demand for various seasons of a year. In this model, a global best particle swarm optimisation (GPSO) algorithm is applied as a new training technique to enhance the performance of ANN prediction. The fitness function is defined and a weight bias encoding/decoding scheme is presented to improve network training. Influential meteorological and exogenous variables along with correlated lagged load data are also employed as inputs in the presented model. The data of an ISO New England grid are used to validate the performance of the developed model. The results demonstrate that the proposed forecasting model can provide significantly better forecast accuracy, training performances and convergence characteristics than contemporary techniques found in the literature.

This paper proposes a strategy for optimal allocation of multiple Community Energy Storage (CES) units in a distribution system with photovoltaic (PV) generation. The main contribution of this strategy is it considers all possible benefits accrued from and costs incurred by CES deployment to a utility. The benefits are gained from energy arbitrage, peaking power generation, energy loss reduction, system upgrade deferral, emission reduction and VAr support. A cost-benefit analysis is also conducted to identify the optimal Net Present Value (NPV), Discounted Payback Period (DPP) and Benefit-Cost ratio (BCR). Moreover, an optimal power factor approach is included in the analysis to dispatch CES units to improve load factors and voltage profiles. The probabilistic distribution of solar irradiance is also incorporated in the proposed strategy to consider the uncertainty of PV generation. Several sensitivity analyses are carried out to investigate the effects of PV penetration, load models and the number of CES units deployed on the profitability of CES investment. Numerical results show that the proposed strategy enables a power utility to identify the location, size and operational characteristic of CES units for maximizing the total NPV and enhancing load factors and voltage profiles. (C) 2016 Elsevier Ltd. All rights reserved.

This paper presents a methodology for the integration of dispatchable and nondispatchable renewable distributed generation (DG) units for minimizing annual energy losses. In this methodology, analytical expressions are first proposed to identify the optimal size and power factor of DG unit simultaneously for each location for minimizing power losses. These expressions are then adapted to place renewable DG units for minimizing annual energy losses while considering the time-varying characteristics of demand and generation. A combination of dispatchable and nondispatchable DG units is also proposed in this paper. The proposed methodology has been applied to a 69-bus test distribution system with different scenarios. The results demonstrate that dispatchable DG units or a combination of dispatchable and nondispatchable DG units can lead to a substantial reduction in annual energy losses when compared to nondispatchable DG units. The results also show that a maximum annual energy loss reduction is achieved for all scenarios proposed with DG operation at optimal power factor. (C) 2013 Elsevier Ltd. All rights reserved.

The high penetration of distributed generation (DG) is a new challenge for traditional distribution systems. Power injections from DG units change network power flows, thereby influencing system losses and voltage stability. This paper presents a new multiobjective index (IMO)-based analytical approach to determine the optimal size and power factor of DG unit for reducing power losses and enhancing loadability. This index is defined as a combination of active and reactive power loss indices by optimally assigning a weight to each index such that the IMO can reach a minimum level. At this level, the optimal location and weights are identified. The proposed methodology has been tested on three typical distribution systems with different characteristics and validated using an exhaustive load flow (ELF) solution. The results show that DG operation with optimal power factor and appropriate weights for active and reactive power losses can significantly reduce power losses and enhance loadability.

This chapter presents distribution system modelling required for Distributed Generation (DG) integration studies. The model of distribution systems covers loads and generation sources. Loads modelled using time-varying voltage-dependent loads or time-varying loads associated with exponents for voltage-dependent loads are highlighted in this chapter. From the generation-side, how to model different technologies, including biomass, solar Photovoltaic (PV) and battery energy storage is clearly explained to better represent their P-Q capacity characteristics. PV output power represented by a probability density function is also thoroughly presented with mathematical expressions. Finally, three test distribution networks used in this book to verify various methodologies and showcase the benefits achieved from intelligent integration of renewable DG units are described in detail.

This chapter provides a comprehensive coverage of the intelligent integration of biomass Distributed Generation (DG) from a power and energy loss point of view. The intelligent integration that determines the optimal location, size, operating power factor and operational characteristics of DG units is presented in a step-by-step manner considering time-varying load demand. Firstly, analytical expressions are developed to calculate the optimal sizes of DG units at various locations in a distribution network to minimise the overall power and energy losses. Secondly, the optimal sizes of active and reactive power are calculated separately and then combined based on an analytical expression to specify the optimal power factor. Finally, the methodologies are developed to identify the optimal locations along with optimal sizes and power factors. The results obtained on two test distribution systems show the importance of selecting the best locations, sizes and power factors in minimizing the power and energy losses in both the test systems. The major conclusions that can be drawn from this case study are also highlighted at the end of the chapter.

Electric Vehicle (EV) charging stations are usually considered to consume active power only in most planning studies. This chapter proposes an analytical approach to adopt plug-in hybrid EV charging stations that considers reactive power support in a medium voltage commercial distribution network with Photovoltaic (PV) units. In this study, expressions are derived from the apparent power loss to size charging stations with dispatchable power factors for minimizing voltage deviations. Such stations are employed to charge aggregated EV units parked in a public area. The developed expressions are then adapted to accommodate EV charging stations while considering the time-varying voltage-dependent load models and the probability of PV generation and EV charging. The simulation results show that properly adopted charging stations with dispatchable power factors can enhance probabilistic voltage profiles.

This chapter presents new analytical expressions to efficiently capture the optimal power factor of each distributed Generation (DG) unit for reducing energy losses and enhancing voltage stability over a given planning horizon. These expressions are based on the derivation of a multiobjective index, which is formulated as a combination of active and reactive power loss indices. The decision for the optimal location, size and number of DG units is then obtained through a benefit–cost analysis. Here, the total benefit includes energy sales and additional benefits, namely energy loss reduction, network upgrade deferral and emission reduction. The total cost is a sum of capital, operation and maintenance costs. The simulation results show that the additional benefits are imperative. Inclusion of these in the analysis can yield faster DG investment recovery.

Due to low electricity rates at nighttime, home charging for electric vehicles (EVs) is conventionally favored. However, the recent tendency in support of daytime workplace charging that absorbs energy produced by solar photovoltaic (PV) panels appears to be the most promising solution to facilitating higher PV and EV penetration in the power grid. This paper studies optimal sizing of workplace charging stations considering probabilistic reactive power support for plug-in hybrid electric vehicles (PHEVs), which are powered by PV units in medium voltage (MV) commercial networks. In this study, analytical expressions are first presented to estimate the size of charging stations integrated with PV units with an objective of minimizing energy losses. These stations. are capable of providing reactive power support to the main grid in addition to charging PHEVs while considering the probability of PV generation. The study is further extended to investigate the impact of time-varying voltage-dependent charging load models on PV penetration. The simulation results obtained on an 18-bus test distribution system show that various charging load models can produce dissimilar levels of PHEV and PV penetration. Particularly, the maximum energy loss and peak load reductions are achieved at 70.17% and 42.95% respectively for the mixed charging load model, where the system accommodates respective PHEV and PV penetration levels of 9.51% and 50%. The results of probabilistic voltage distributions are also thoroughly reported in the paper. (C) 2016 Elsevier Ltd. All rights reserved.

Energy Storage (ES) has been seen as a crucial element in active distribution networks. It facilitates a high penetration level of intermittent renewable energy in power systems thus provide several technical and economic benefits to the utility and consumer. However, given a high capital cost associated with ES, it is crucial to develop an effective planning strategy to avail the maximum benefit. This paper proposes a methodology to determine the optimal location and capacity of Community Energy Storage (CES) units by considering all their possible benefits and costs. The benefits are obtained from energy arbitrage, peaking power generation, energy losses reduction, Transmission and Distribution (TD) system upgrade deferral, CO2 emission reduction and VAr support, while the costs include CES's capital, replacement and Operational and Maintenance (OM) costs. A comprehensive cost-benefit analysis is conducted to identify the optimal Net Present Value (NPV), Discounted Payback Period (DPP) and Benefit Cost ratio (BCR) of CES investment starting at current year, year 2025 and 2035. Numerical results show that the proposed strategy is able to specify the optimal location and size of CES unit for maximizing the NPV. Some interesting findings are also discussed in the paper.

This paper investigates the loss reduction potential of primary distribution systems with distributed generation (DG) units, capacitors and network reconfiguration. A methodology is proposed to combine different types of DG units and capacitors for minimising losses. A combination of reconfiguration, DG and capacitor placement to obtain high loss reduction is also presented. The results obtained on a 33-bus test distribution system with constant load condition and a 687-bus real distribution system with varying load conditions show significant loss reduction using the proposed approach. The combination of type 1 DG (i.e. DG capable of delivering real power only) and capacitor placement or reconfiguration with type 1 DG and capacitor placement can be viable for minimising losses. © 2013, © 2013 Taylor & Francis.

This paper presents three alternative analytical expressions, including two new expressions, to determine the optimum sizes and operating strategy of distributed generation (DG) units considering power loss minimization and a methodology to identify the best location. These expressions can be easily adapted to consider the renewable DG units (i.e., biomass, wind and photovoltaic) for minimizing energy losses by considering time-varying demand and possible operating conditions of DG units. The results obtained on a 69-bus distribution test system demonstrate that the proposed approaches can be adequate to determine the location, size and power factor of DG unit for minimizing energy losses. The alternative expressions can be utilized depending on availability of required data and these produce similar outcomes. Highlights A methodology for different renewable DG allocation for energy loss minimization Three alternative analytical expressions for identifying the optimum size An analytical expression for calculating the optimum power factor