Design Enhancement of Grid-Connected Residential PV Systems to Meet the Saudi Electricity Regulations

Abstract

Distributed grid-connected photovoltaic (PV) generation explores several methods that produce energy at or near the point of consumption, with the aim of reducing electricity losses among transmission networks. Consequently, home on-grid PV applications have garnered increased interest from both scientific researchers and industry professionals over the last decade. Nevertheless, the growing installation of intermittent nature residential PV systems (R-PV) in low-voltage distribution networks is leading to more cautious considerations of technology limitations and PV design challenges. This conservative perspective arises from the standpoint of grid quality and security, ultimately resulting in the revocation of PV connection authorization. Hence, the design of R-PV systems should consider not only the specifications of the PV panels and load profiles but also the characteristics and requirements of the connected power grid. This project therefore seeks to enhance the design considerations of grid-connected PV systems, in order to help the end-users meet the grid codes set out by the Saudi Electricity Regulatory Authority (SERA). Since the maximum amount of generated power is essential for PV system optimization, the ratio of grid strength to maximum transmitted power was employed to ascertain the suitable capacity of the PV system, while the assessment of PV power output was utilized to specify the system size. Furthermore, a battery energy storage system (BESS) with a small size (~10% of the PV capacity) is employed to enhance the PV power quality for a dependable grid interconnection. The BESS is equipped with a versatile power controller in order to achieve the designed objectives. The obtained results show an essential advancement in terms of power quality and reliability at the customer’s connection point. Moreover, with the design assessment process, the low-voltage ride-through (LVRT) and power factor requirements can be met, in addition to the total harmonic distortion (THD) and frequency transient limitations. The proposed solution assists end-users in efficiently designing their own R-PV systems while ensuring quality and sustainability for authorized grid interconnection.

1. Introduction

Saudi Arabia’s revenue predominantly relies on oil, as it holds 15% of the world’s oil reserves. With the introduction of Saudi Vision 2030 in 2016, the country aims to establish sustainable energy systems systematically. This involves investing in and shifting toward renewable water and energy sources, as well as other endeavors related to private and industrial business structures aimed at increasing job opportunities and attracting foreign investments [1]. To support and achieve Saudi Vision 2030, various organizations have emerged, including the King Abdullah City for Atomic and Renewable Energy (K.A.CARE) and the National Renewable Energy Program (NREP) under the Ministry of Energy (MoE). K.A.CARE and NREP oversee the development, initiation, monitoring, and phase-out of numerous renewable energy projects nationwide, with a focus on transparency, a significant increase in the renewable energy mix, project deployment, and bidding processes, and the cultivation of domestic expertise [2].

The Ministry of Energy (MOE), the Public Investment Fund (PIF), and Neom are engaged in collaborative efforts aimed at realizing the objectives outlined in Vision 2030. As depicted in Figure 1, the overarching aim is to implement 3000 projects by 2024 and 6000 projects by 2030 within photovoltaic (PV) systems, thereby enhancing the Kingdom of Saudi Arabia’s photovoltaic energy capacity to 40 gigawatts by 2030. Notably, particular emphasis is placed on the integration of small-scale systems within various sectors including residential areas, industrial zones, places of worship, and educational institutions such as mosques, schools, and universities, with a collective target of achieving a cumulative capacity of 13 gigawatts [2].

Voltage fluctuations, frequency deviations, and power quality disturbances are all aspects of power grid stability and reliability that can be impacted by the integration of residential PV systems. Voltage fluctuations refer to rapid changes in voltage levels, which can occur due to varying loads or sudden changes in generation. These fluctuations can cause issues such as equipment malfunction or damage to sensitive electronic devices. Frequency deviations occur when the frequency of the alternating current deviates from its standard value. In most power systems, the frequency is tightly regulated to ensure stable operation of electrical equipment. Deviations in frequency can disrupt the synchronization of devices connected to the grid, potentially leading to equipment damage or even system-wide blackouts. Power quality disturbances encompass a range of issues including voltage sags, swells, harmonics, and transients. These disturbances can degrade the performance of electrical equipment, leading to inefficiencies, malfunctions, or premature failure. When residential PV systems are not properly integrated and synchronized with the grid, they can exacerbate these problems by injecting variable and intermittent power into the system. This can lead to voltage and frequency fluctuations, as well as to power quality issues, which not only affect the performance of individual PV installations but also have the potential to disrupt the overall grid operation. Addressing these concerns requires stringent adherence to grid connection standards and the implementation of robust control mechanisms to ensure seamless interaction between PV systems and the grid. The complexity of electric power distribution networks is a major contributor, accounting for around 90% of reliability challenges, while transmission and generation systems contribute the remaining 10%. Hence, there is a concerted effort by electric companies and utilities to improve the reliability of distribution systems, aiming to enhance electricity supply to load points [3].

In addition to enhancing the PV output power, recent research and development efforts also focus on addressing various power quality issues and grid standards. Concerns regarding power quality encompass aspects such as grid voltage, current, frequency, and power factor, emphasizing the importance of evaluating the quality of installed renewable-energy-based distributed generators (DGs). A study highlighted in [4] elucidated different facets of power quality, while those in [5,6] explored the impact of poor power quality on the performance and efficiency of grid-connected PV-DGs. The majority of the reviewed studies advocate for improving PV power quality before integration with the power grid.

Inverter technology stands as the cornerstone for ensuring the reliable and safe integration of PV systems into the grid. It is imperative for delivering high-quality power to the AC utility system at a reasonable cost. To fulfill these criteria, cutting-edge power electronics technologies are employed in PV inverters. Through the utilization of semiconductor devices and pulse-width modulation (PWM) techniques for high-frequency switching, these inverters achieve high-efficiency conversion, along with a high-power factor and minimal harmonic distortion [7]. In addition, Ref. [8] discussed the concept of an AC/DC high-frequency isolated power converter serving as an interlink converter, subsequently integrated with the DC/DC converter of a BES to streamline system size and component count. This approach offers the potential to eliminate the need for the BES’s DC/DC converter. Additionally, it minimizes the number of power conversions between PV-AC-BES, thereby enhancing overall system efficiency. T. Masuta has used an extremely bigger PV generation system based on unit commitment (UC) and a numerical simulation to evaluate the supply and demand operation. The proposed strategy can minimize the outage and shortage of demand power [9]. W. Liang has proposed a technique for mitigating the harmonic power fluctuation of PV inverters. An impedance design method for a BES quasi-Z source based on a built model for the PV-BESS system has been proposed and analyzed [10]. D. Lamsal has proposed a discrete Kalman filter for PV generation and BESS systems to remove the bias error of PV forecasting data. The filter can create a barrier for the fluctuation of PV generation power and remove the bias error prominently [11]. O. Ungwa [12] has proposed two control systems, a distributed and a coordinated control system, for minimizing the sudden over-voltage in a photovoltaic-battery-connected low-voltage network. The proposed control strategy can stabilize the voltage within a statutory range.

This study aims to investigate the requirements set forth by the Saudi Electricity Regulatory Authority (SERA) [13], which was previously known as the Electricity and Cogeneration Regulatory Authority (ECRA), for low-voltage distribution systems (LVDS) incorporating photovoltaic (PV) installations. Also, the reformed technical standards, set out by the Saudi Electricity Company (SEC), are also considered in this study [14]. The objectives are multifaceted, aimed at enhancing the design and performance of residential PV systems within the Kingdom of Saudi Arabia. First, this study endeavors to determine the maximum PV power attainable based on the grid strength at the point of a customer’s connection. Second, it seeks to estimate solar energy production to optimize PV sizing and orientation for enhanced power quality and efficiency, where the health of the point of common coupling (PCC) power is directly related to the amount of injected PV power and the interfaced grid impedance. Third, this study proposes strategies for active and reactive power compensation, with the help of a small-rating BESS as shown in Figure 2.

Unlike the regular use of bulky and costly BESS to store a high amount of energy, an optimal size and operation functionality of the attached BESS is proposed to improve power quality parameters such as voltage stability, frequency regulation, and power factor correction. Furthermore, the utilization of a compacted 3-winding step-up transformer was chosen for the sake of reducing the DC-DC boost stage ratings and limit the possible fault currents, in addition to the necessity for electrical isolation at the PCC. Finally, the research will validate these proposed enhancements through practical implementation on actual distribution system (DS) installations and subsequent monitoring and analysis of performance metrics. The findings of this study will provide valuable insights and recommendations both to the SEC for refining their requirements and to end-users for maximizing the benefits of residential PV systems in the KSA.

In addition, the design assessment method allows for the fulfillment of the low-voltage ride-through (LVRT) and power factor criteria, as well as the adherence to total harmonic distortion (THD) and frequency transient constraints. The proposed method aims to facilitate end-users in effectively creating their own R-PV systems, while guaranteeing high standards and long-term viability for authorized grid connection.

2. The Recent SEC Requirements for Residential PV Integration

In alignment with the goals of Saudi Arabia’s Vision 2030 regarding renewable and sustainable energy, economic support, and natural resource conservation, the Saudi Electricity Company (SEC) has established regulations and requirements for connecting small-scale solar PV systems to the national distribution grid. This initiative is in response to the bylaw governing the integration of such systems, as approved by the Saudi Electricity Regulatory Authority (SERA) and the Saudi power distribution code 2020 [15].

The SEC is the government agency authorized in the Kingdom of Saudi Arabia by SERA to clarify regulations and rules, so researchers relied on these regulations in designing the proposed system. The SEC’s regulations focus on ensuring voltage stability, flicker reduction, frequency control, and improvements in power factor and quality when connecting small-scale solar PV systems (with a capacity between 1 kW and 2 MW) to the distribution network [14].

2.1. Voltage Stability Requirements

Voltage sags and swells in power systems with renewable energy sources (RESs) refer to sudden and temporary drops or increases in voltage at the connection points lasting between 10 milliseconds and 1 second [16]. These disturbances are considered significant power quality issues in the industry, with voltage sags being particularly severe and leading to grid stability challenges. Modern grid codes emphasize the importance of maintaining PV system connection during voltage sags to prevent significant loss of PV-generated power, which can disrupt grid operation and stability [17]. Therefore, compliance with low-voltage ride-through (LVRT) capability requirements, which enable PV systems to remain connected during voltage sags and support voltage recovery until the disturbance is resolved, is enforced by modern grid codes to address voltage sag and stability problems.

To provide examples, according to the German regulations, PV inverters must withstand faults for up to 0.15 s in cases of severe grid voltage drops to zero. These regulations permit PV systems to remain connected without any unnecessary disconnections if the voltage at the PCC recovers to 90% of its rated value within 1.5 s post-fault [18]. Similarly, the LVRT requirements in other countries’ grid codes (GCs) are comparable, with slight variations in timeframes and voltage thresholds. Therefore, in Japan, China, and Denmark, renewable energy plants are expected to endure faults and remain connected to the grid for a specified duration if the voltage dips to 80% below its nominal value; otherwise, immediate disconnection is necessary. Comparable mandates exist in the United Kingdom and the United States, where renewable energy plants are required to stay connected even if the PCC voltage drops to 15% of the nominal value [19].

Furthermore, in the line with GCs, the specifications outlined by the SEC regarding the voltage stability [14] mandate that small-scale solar PV systems must remain connected to the distribution network and operate steadily within a voltage range of 90 to 110% of nominal voltage, irrespective of protection system types and settings. Additionally, these systems should enhance overall power system stability by withstanding dynamic voltage variations, particularly those resulting from faults in higher-voltage-level networks. These requirements encompass all types of disturbances (single-phase, two-phase, and three-phase faults). Furthermore, solar PV systems exceeding 11 kW in capacity must remain connected to the distribution network even if the connection point voltage drops to zero for 300 ms, as illustrated in Figure 3. Adherence to this LVRT standard is mandatory for all components that could trigger the disconnection of small-scale solar PV systems, including inverters. Following fault resolution, the voltage should return to within ± 5% of the normal operating range.

The fluctuating power output of PV systems can lead to voltage flickers on distribution networks, which are caused by variations in solar irradiance. Recently, there has been a growing focus on assessing and managing flicker, with requirements imposed on power quality for distribution systems [20]. Flicker severity is measured through short- and long-term probability indices [21], as outlined in standards such as IEC [22], with measurement durations of at least 10 min and 2 h, respectively. According to IEEE [23] standards, medium-voltage distribution sources must not produce objectionable flicker levels between 0.9 and 0.7 PU for short- and long-term probability indices. In addition, most of the other standards specify that PV power plants integrated into the grid should not exceed the limits set out by IEC [22].

2.2. Voltage Flicker and Fluctuation Requirements

In addition, the voltage flicker requirements for integrating a small solar PV system into Saudi Arabia’s national distribution grid, as outlined by the SEC, stipulate that flicker severity at any connection point represented by short- and long-term probability indices shall not exceed the limits of 0.8 and 0.6, respectively [24]. Furthermore, during normal operation, the connection and functioning of a small-scale solar PV system should not cause the voltage, at its connection point, to deviate from the system’s rated voltage by more than ±5%. The voltage values should fall within the specified intervals provided in

Table 1. SEC conditions for the network operating nominal voltage.

Operating Voltage	Nominal Voltage (V)	Lowest (V)	Highest (V)
Low Voltage	220/127	209/120	231/134
	380/220	360/209	400/231
	400/230	380/218.5	420/241.5
Medium Voltage	13,800	13,100	14,500
	33,000	31,400	34,700

. Moreover, when connecting or disconnecting a small-scale solar PV system from the distribution grid, any voltage fluctuations at the connection point should not exceed 3% of the system’s rated voltage.

2.3. Harmonics Distortion Requirements

Harmonic distortion refers to the alteration of voltage and current waveforms from their normal shapes [25], which is considered a significant power quality issue. In a solar PV system, harmonics can be generated by power electronic devices such as inverters and converters. These devices introduce distortion into the system, leading to increased losses in the power grid and potential malfunctions in protection equipment [26]. To address this issue, stringent regulations are in place to limit harmonic distortion at the connection point. The THD, of the PCC injected current, is used to quantify and measure harmonic distortion levels in either voltage or current [27]. Various standards exist for harmonic distortion, with most requiring THD levels to be below 5%, except for the United Kingdom’s code (EREC G83) and Germany’s code (VDE-AR-N4105), which set a stricter threshold of less than 3% for PV integration [20].

Additionally, the SEC mandates that the harmonic and inter-harmonic voltages at the connection point of a small-scale solar PV system connected to the distribution network must not exceed the specified planning levels outlined in

Table 2. SEC conditions for the maximum continuous harmonic levels of the PCC current.

Odd Harmonics 1		Odd Harmonics 2		Even Harmonics
Order (h)	Harmonic Voltage (%)	Order (h)	Harmonic Voltage (%)	Order (h)	Harmonic Voltage (%)
3	4.0	5	5.0	2	1.8
9	1.2	7	4.0	4	1.0
15	0.3	11	3.0	6	0.5
21	0.2	13	2.5	8	0.5
21 ≤ h ≤ 45	0.2	17 ≤ h ≤ 49	1.9 × 17/h − 0.2	10 ≤ h ≤ 50	2.5/h + 0.22

¹ Multiple of 3 odd harmonics; ² not multiple of 3 odd harmonics.

. The corresponding planning level for total harmonic distortion is set at THD = 6.5% for both 13.8 kV and 33 kV voltage levels, according to SEC requirements. Furthermore, for a small-scale solar PV system connected to the LV distribution network, the requirements concerning the voltage harmonics, in Table 2, are fulfilled if the harmonic current emissions do not exceed the limits stated in the IEC standard [22].

2.4. Frequency Deviation Requirements

In recent years, there has been a growing emphasis on the compliance of PV systems with grid frequency variation standards, as frequency is a crucial factor in maintaining power system quality. Modern grid codes now often require PV systems to operate within specified frequency control parameters, maintaining a nominal frequency with a defined margin. Failure to do so may result in rapid disconnection. Each country establishes a standard nominal frequency value based on the design and operational characteristics of its power system components. For example, Europe and most Asian countries adhere to a 50 Hz nominal frequency, while many North and South American countries operate at 60 Hz. National transmission system operators (TSOs) set permissible frequency variation ranges for normal operation. For instance, countries like Great Britain, Germany, France, Belgium, and Poland allow frequencies to fluctuate between 49.5 and 50.5 Hz under normal conditions, with a critical range of 47 to 52 Hz. Other countries like Ireland, Italy, Australia, Denmark, and China have narrower frequency variation intervals [28]. Furthermore, according to SEC requirements, small-scale solar PV systems must be able to remain connected to the distribution network within specified frequency ranges for designated time periods as outlined in

Table 3. SEC conditions for the operating range of the distribution network frequency.

Below FN 1 (Hz)	Above FN 1 (Hz)	Operation Requirement
58.8–60.0	60.0–60.5	Continuous
57.5–58.7	60.6–61.5	for a period of 30 min
57.0–57.4	61.6–62.5	for a period of 30 s

¹ F_N is the network nominal frequency, which is 60 Hz for the SEC power plants.

.

2.5. Power Factor Requirements

The power factor, which measures the efficiency of electricity use on a scale from zero to one, is an important consideration in grid codes around the world. Different countries have specified specific power factor values in their grid codes, such as 0.95 lagging to 0.95 leading for Germany, China, and South Africa, 0.90 lagging to 0.90 leading for Italy and Australia, and 0.85 lagging to 0.85 leading for Spain [20]. The SEC has mandated the control of power factor (cos φ) as a function of active power for small-scale solar PV systems. A characteristic with adjustable minimum and maximum values, along with three connected lines as shown in Figure 4, must be configured within the control systems of the solar PV systems. Changes in active power output will result in a new cos φ set point based on this characteristic. The parameters A, B, and C should be field adjustable, and their settings are the responsibility of the SEC. If the SEC does not provide explicit instructions, the power factor of parameters A and B, for the active power in the range of 0 to 0.5 of the nominal active power of the solar PV unit, should be 1, while for parameter C, the power factor should be 0.95 for the full capacity of the nominal active power of the solar PV unit.

2.6. Electrical Isolation and Galvanic Isolation

Transformers play a vital role in various applications, serving essential functions such as electrical and common ground isolation, voltage regulation, noise decoupling, and enhancing power quality [29]. They offer complete electrical isolation between circuits or systems, ensuring utmost safety and reliability by delivering clean, stable power without any interference or voltage fluctuations. Also, transformers help protect against potential damage from electrical surges, reduce disruptions caused by noise, correct harmonic distortion, and prevent earthing failure. These critical benefits make transformers highly valuable in diverse settings, as they improve power quality by providing a consistent voltage output to connected devices, ensuring they receive clean and stable power without any interruptions or voltage variations. Furthermore, the presence of nonlinear loads, like electronic devices, can generate harmonics that result in issues such as voltage fluctuations, power disruptions, and decreased efficiency. Transformers play a crucial role in mitigating harmonic distortion by delivering a stable and clean voltage output devoid of any disturbances.

Moreover, transformers possess inductance due to their coil structure, which acts as a hindrance to high-frequency signals like electrical noise. This property allows transformers to effectively block out electrical noise. Also, transformers equipped with an electrostatic screen connected to the earth can further reduce various power problems. Earthing failure is a common issue in electrical systems, caused by various factors and leading to hazards like power surges, equipment failure, and fire. Transformers offer protection by isolating circuits, blocking electric currents to prevent dangers from earthing failure. Power surges, sudden increases in current, can also pose risks like fires and equipment malfunctions. Transformers safeguard against these surges by blocking any electric current from passing through the primary and secondary coils, ensuring safety and preventing damage to devices.

3. PV Power to Grid Strength Criteria

As renewable energy generation (REG) is being deployed more frequently for different power generation purposes, its design considerations are becoming increasingly important. Generally speaking, the specifications of the interconnected power grids and the required technical quality of the generated power must also be taken into consideration while designing the REG systems [30]. For instance, the performance and reliability of the integrated REGs are greatly influenced by the power grid impedance properties, as shown in Figure 5. This concept gains more importance in the context of renewable energy production, since it necessitates the use of energy conversion and filtering power electronic equipment. Hence, due to the power fluctuation and frequency stability issues, numerous studies investigated the reliability and robustness of the grid-connected PV systems [31,32,33]. Therefore, this study highlights the technical issues that challenge a qualified interconnection of on-grid residential PV systems (R-PV). In addition, this study attempts to enhance the design of R-PV systems by obtaining the optimal system capacity and operation, in order to meet the standards of the interfaced distribution networks.

To determine the PV system capacity that ensures a sustained voltage stability at the point of interconnection, the grid strength to the maximum transmitted power (GsMp) is defined. The system strength refers to the ability of the system to consistently maintain a nominal voltage at the PCC bus and bring it back within the acceptable range, both during normal operating circumstances and when disruptions occur. In short, the grid strength indicates the dynamical nature of the grid, which can be quantified by the short circuit ratio (SCR). The maximum transmitted power is then specified to maintain the stability of the grid voltage and frequency, based on the obtained grid strength. Referring to Figure 5, and from the basic definition of the grid strength criteria [31], the desired short-circuit ratio (SCR_d) can be expressed as:

$$S_{PCC,max}={\left(P_{PCC}+j{Q}_{PCC}\right)}_{max}=\frac{{SC}_{pcc}}{{SCR}_d}$$

(1)

where S_PCC,max is the maximum allowable apparent power at the PCC and SC_pcc is the apparent power at a short circuited PCC bus. P_PCC and Q_PCC are the PCC active and reactive powers, respectively. Based on an intensive analysis, the critical short-circuit ratio is 2, in order to achieve a safe and qualified grid interconnection [34]. However, to ensure stable system operation, the SCR_d was chosen to be 5 in this study. This ratio was carefully selected based on recently conducted work [30].

The PCC active and reactive power can be expressed in a function of the PV side parameters or the SEC grid characteristics, as follows:

$$P_{PCC}=\frac{V_{PCC}{V}_{inv}sin\left({\delta }_i\right)}{X_{FT}}=\frac{{E_{SEC}}^2{R}_{SEC}-E_{SEC}{V}_{PCC}{R}_{SEC}cos\left({\delta }_s\right)+E_{SEC}{V}_{PCC}{X}_{SEC}sin\left({\delta }_s\right)}{{R_{SEC}}^2+{X_{SEC}}^2}$$

(2)

$$Q_{PCC}=\frac{{-V_{PCC}}^2+V_{PCC}{V}_{inv}cos\left({\delta }_i\right)}{X_{FT}}=\frac{{E_{SEC}}^2{X}_{SEC}-E_{SEC}{V}_{PCC}{X}_{SEC}cos\left({\delta }_s\right)+E_{SEC}{V}_{PCC}{R}_{SEC}sin\left({\delta }_s\right)}{{R_{SEC}}^2+{X_{SEC}}^2}$$

(3)

where V_inv, V_PCC, and E_SEC are the voltages at the PV inverter, PCC bus, and SEC grid, respectively. The angles δ_i and δ_s are called the power angles, which represent the phase difference between the inverter to PCC voltages and the SEC grid to PCC bus voltages, respectively. X_FT is the reactance of the power transformer and filter between the PV system and the PCC bus, whereas R_SEC and X_SEC are the PCC to SEC line resistance and inductance. By substituting Equations (2) and (3) into Equation (1), along with setting the desired short-circuit ratio at 5 and short circuiting the PCC bus, we end up with:

$$S_{PCC,max}=E_{SEC}^2/\left[5{\left(R_{SEC}^2+{X_{SEC}}^2\right)}^{1/2}\right]$$

(4)

In addition, the assumption of ignoring the grid resistance is no longer satisfied, since the R-PV systems are connected to low-voltage distribution networks with short lines [31]. Hence, the short-circuit ratio with the impact of grid resistance (SCR_R) can be written as:

$${SCR}_R=\frac{{SCR}_d}{\left[\left(\left(R_{line}/X_{line}\right)/\sqrt{{\left(R_{line}/X_{line}\right)}^2+1}\right)+1\right]}$$

(5)

Since the inverter-to-PCC reactive power is controlled by an intended BESS, the capacity of the utilized inverters (S_inv) must therefore be associated with the obtained PCC complex power, neglecting the X_FT reactive power; that is:

$$S_{PCC,max}=S_{inv,max}=\sqrt{{P_{inv}}^2+{j{Q}_{\begin{array}{c}inv\\ \\ \end{array}}}^2}$$

(6)

The inverter reactive power (Q_inv) is normally generated to contribute to supporting the PCC bus voltage. However, considering the reactive power should limit the inverter active power capacity. As a result, the expected PCC injected active power would be less than the PV maximum power. Therefore, this study suggests drawing zero reactive power out of the PV inverter (Q_inv = 0). As a result, the maximum PV power can be expressed as:

$$P_{PV,max}=P_{PCC,max}=\frac{E_g^2}{SCR\sqrt{R_{line}^2+{X_{line}}^2}\left[\left(\left(R_{line}/X_{line}\right)/\sqrt{{\left(R_{line}/X_{line}\right)}^2+1}\right)+1\right]}$$

(7)

In order to clearly show the influence of the grid impedance on the PV system capacity, the PV maximum power in per unit (PU) was plotted versus the grid resistance-to-reactance (R/X) ratio and versus the line impedance magnitude, as shown in Figure 6. The figure demonstrates the resultant P_PV,max with different choices of the SCR (2, 5, 8, and 10).

It is concluded that (from 0 to 1.5) the R/X ratio has a severe impact on the PV capacity, while the magnitude of the line impedance has a continuous degradation influence up to 0.5 PU. As a result, the impedance of the line that linked the PV system with the connected grid must have a value less than 0.2 PU. The choice of the SCR is assigned through the choice of the stability level, where SCR = 2 is the lowest stability option.

4. Estimation of PV Power Based on Power Quality Consideration

Estimation of the Solar Radiation Energy

As is well known, using the concepts of semiconductors, the PV panels transform the energy from solar radiation into electricity. Thus, the first step in estimating the PV output power is the awareness of the solar energy received in a particular area. Numerous research studies have examined a number of solar energy models [35,36]. Nevertheless, the choice of model depends on the model’s accuracy, simplicity, and input data quantity. Thus, this study uses the solar radiation model introduced in [37], based on the aforementioned modeling considerations, to calculate the amount of solar energy that would be received under any potential PV system configuration.

There are distinct patterns in which solar energy reaches the planet. The energy content and atmospheric angle can be used to categorize these patterns. The majority of the radiation energy (≥96%) is carried by the basic component, which directs a beam of light onto the PV panel surface. Therefore, rather than estimating the total radiation power, the potential solar energy is collected by estimating the sun’s direct-beam energy. From [37], the cumulative daily and monthly solar energy collected by a tilted surface (D_E and M_E) may be written as:

$$M_E\left(m\right)=\sum _d^{d+30}{D}_E\left(d,m\right)=\sum _d^{d+30}\sum _{T=0}^{24}{H}_E\left(T,d,m\right)\left(\mathrm{W}\mathrm{h}/{\mathrm{m}}^2\right)$$

(8)

where H_E is the hourly solar irradiance energy, which is expressed in terms of the sunlight-to-location air mass (AM) as follows:

$$H_E\left(T,d\right)=1377\times {\left(0.7\right)}^{{AM(T,d)\times \left(T\right)}^{0.678}}\left(\mathrm{W}/{\mathrm{m}}^2\right)0\le H_E\le 1377$$

(9)

5. Structure of the Grid-Connected PV System

Incorporating essential components and formulating a control algorithm for the photovoltaic system prior to its integration into the grid as shown in Figure 2 holds the potential to bolster the involvement of photovoltaic systems as a primary contributor to energy generation within Saudi Arabia, particularly at the residential level, thereby advancing the objectives outlined in Vision 2030.

The primary objective of this paper is to enhance the power quality by addressing potential issues arising from the integration of photovoltaic systems into the grid. To mitigate these challenges, a novel system has been devised, which delineates a connection methodology drawing upon the overarching framework established by the Saudi Electricity Company [14], albeit with notable enhancements. Key among these enhancements is the incorporation of two pivotal components aimed at ameliorating power quality during integration: the utilization of a 3-winding transformer and the integration of a battery energy storage system (BESS). The 3-winding transformer assumes a critical role in attenuating the harmonics that can detrimentally impact the grid, thereby mitigating the likelihood of service provider reluctance to facilitate integration. Additionally, the inclusion of an energy storage system, sized to approximately 15% of the total system capacity, is not intended primarily for energy storage during periods of solar insufficiency but rather to bolster overall system capacity and enhance power quality. The system is engineered with two distinct configurations, enabling the utilization of the 3-winding transformer and the energy storage system (ESS) for individual end-users, as illustrated in Figure 7. Alternatively, it can be interconnected with multiple small systems to amalgamate into a larger system, subsequently interfacing with the grid via the switch and incorporating the storage system to enhance capacity, as exemplified in Figure 8. In order to conduct the proposed methodology to the closer side of the end-user, this study considers the system configuration, as in Figure 7, in the design and validation processes.

6. Control Mechanism of the PV and BESS Apparent Power

6.1. Control Methodology for the R-PV Inverter

As discussed in the previous section, the DC-AC inverter for the PV system is designed to generate only active power, at the maximum power point tracking (MPPT) level, while maintaining the reactive power at zero. This is essential to minimize the capacity of the PV system for a fixed generated AC power. The objectives of the eliminated reactive power can be reconducted using the attached BESS synchronous compensator. Hence, the controller circuit for the interfaced PV system has the following objective:

$$S_{inv}=P_{PV,MPPT}+j00\le P_{PV,MPPT}\le P_{PV,MPPT}$$

(10)

6.2. Control Methodology for the BESS Inverter

The main principle of attaching a BESS at the PCC bus is to enhance the sustainability and quality of the R-PV interconnection. Hence, the BESS inverter is considered to be a versatile power-conditioning controller to perform different operation modes by controlling the active and reactive power. Utilizing a BESS is essential to decouple the control of the inverter-generated power.

6.2.1. BESS Reactive Power Control for Voltage and Power Factor Regulation

Based on the mathematical static modeling in Equations (2) and (3), the relation between the magnitude and phase shift of the PV inverter terminal voltage to the PCC injected power can be simulated, as illustrated in Figure 9. It can be concluded from the shown figure that the reactive power has a direct relationship to the inverter voltage, while the active power relies mainly on the voltage phase angle (power angle).

The above-mentioned (V-Q) and (F-P) relationships can be quantify using the principle of the frequency–voltage droop control (FV-Control) as follows [38]:

$$\left\{\begin{array}{c}{Q}_{ref}=Q_N-Q_{PCC}=\left[\frac{Q_N-Q_{PCC}}{V_N-V_{PCC}}\right]\left(V_N-V_{PCC}\right)=K_q\left(V_N-V_{PCC}\right)\\ \\ P_{ref}=P_N-P_{PCC}=\left[\frac{P_N-P_{PCC}}{f_N-f_{PCC}}\right]\left(f_N-f_{PCC}\right)=K_d\left(f_N-f_{PCC}\right)\end{array}\right.$$

(11)

On the other hand, controlling the PCC reactive power is directly associated with the power factor (PF) of the injected power. As the power factor is one of the significant SEC regulations, as discussed in the Section 2, the BESS-based controller is also designed to maintain the level of the injected reactive power within the limits set by the power-factor constraints (Figure 4). From the ordinary definition of the power factor, which is the ratio of the active power to the total apparent power:

$${PF}_{pcc}=P_{PCC}/S_{PCC}=P_{PCC}/\sqrt{{P_{PCC}}^2+{Q_{PCC}}^2}$$

(12)

Referring to SEC regulations [14], the reactive power can be controlled to regulate the PCC power factor in four different modes, as follows:

• Zero reactive power. This mode is mandatory when the generated power is less than 0.5 PU. This operation mode is considered to conduct unity power factor during this condition of the reactive power.
• Fixed reactive power, considering the constraints of PF in Figure 4. Hence, for this case, the reference of the reactive power reactive power shall be specified accordingly.
• Fixed power factor, and this can be achieved by monitoring the PCC power factor and regulating the reactive power accordingly.
• Controlling the reactive power based on the PCC active power, in order to maintain the PF_pcc within the stated boundaries. Hence, the reactive power here can be expressed in a function of only the active power.

The selection among these different modes is totally dependent on the connected-grid criteria. The reference reactive power for the above operation modes can be obtained using the relationship in Equation (12), as follows:

$$\left\{\begin{array}{c}\begin{array}{c}\begin{array}{c}mode1:Q_{ref}=0P_{pcc}\le 0.5p.u\end{array}\\ mode1:Q_{ref}=\pm K0.5p.u\le P_{pcc}\le 1.0p.u\end{array}\\ \begin{array}{c}mode2:Q_{ref}=\pm \frac{\sqrt{{P_{PCC}}^2\left(1-{{PF}_N}^2\right)}}{{PF}_N}0.5p.u\le P_{pcc}\le 1.0p.u\\ \begin{array}{c}mode3:Q_{ref}=\pm \frac{\sqrt{{P_{PCC}}^2\left(1-{\left(-0.1P_{pcc}+1.05\right)}^2\right)}}{-0.1P_{pcc}+1.05}\end{array}0.5p.u\le P_{pcc}\le 1.0p.u\end{array}\end{array}\right.$$

(13)

The parameter Q_ref represents the reference reactive power, which is the difference between the PCC reactive power and the required compensating reactive power. Since the converter control circuits adapt and process the measured voltage and current in the d-q axis for direct quadrature-control algorithms, the reactive power can be adjusted though the q-axis current. The q-axis component of the inner-loop current controller is then responsible for generating the magnitude of the refence voltage in the d-q reference frame.

6.2.2. BESS Active Power Control for Frequency Regulations

It is important to note that when rotating-type generators are not present, there is a lack of high kinetic stored energy and, therefore, a lower moment of inertia for the power line. This inertia is crucial for maintaining stable dynamic performance. The deficit in this inertia can be filled by regulating the nominal frequency at the point of interconnection.

Relying on the fact that the active power at the PCC bus is essentially affecting the nominal frequency, the dynamics of the power lines tend to increase the operational frequency as active power increases [39,40]. As discussed in Section 6.2.1, the relationship between the active power and frequency difference can be quantified through the frequency droop control, as in Equation (11). In addition, due to the fact that the active power can be adjusted though the d-axis current, the frequency control has therefore been assigned to the d-axis component of the inner loop current controller, as in Figure 10.

6.2.3. Power Isolation and Harmonics Mitigation

Power electronic voltage source inverters (VSI) are widely acknowledged for their significant role in generating line current harmonics, primarily because of their distinctive characteristics of switching and producing square output voltage. To fulfill the criteria set out by the grid provider, it is necessary to identify and eliminate the high-frequency harmonic contents in order to lower the current harmonics. This may be achieved by introducing the inverse phase shift of these harmonics by injection. The present harmonic components may be represented by the Fourier series function using the fundamental frequency and phase shift in the following manner:

$$i_{PV}\left(t\right)=0.5I_{PV0}+\sum _{n=1}^{\infty }\left[I_{pv,an}\cos \left(n{\omega }_{0}t\right)+I_{pv,bn}\sin \left(n{\omega }_{0}t\right)\right],n=2,3,4,\dots$$

(14)

where I_PV0 is the DC component in the current, and the variable index n represents the harmonic order. I_pv,an and I_pv,bn are the corresponding constant coefficients of the nth harmonic. Figure 10 demonstrates the control method used for the cancellation of harmonics in the PV source current. This cancellation is performed in the d-q reference frame. The extraction of the harmonics of the source current may be achieved by using a band stop filter (BSF), where the fundamental system frequency is considered as the filter cut-off angular frequency (ω₀). The electric isolation solution among all power stages (PV system, BESS, and SEC grid) is achieved by utilizing a compact 3-winding power transformer as discussed in Section 2. Figure 10 shows the controllers circuit of the BESS DC-AC inverter.

The operational control strategy of the BESS converter is visually depicted in Figure 11. The PCC voltage and current feedback, in conjunction with grid regulation, are utilized to determine the factors contributing to the unlawful integration of R-PV. The control algorithm, consequently, generates the necessary bidirectional BESS power to suppress the detected technical defects. The voltage and power factor controller tasks must be individually selected to address the most severe technical issue, where the reactive power control is exclusive; only one mode can be active at a time.

7. Validation and Case Study

7.1. Configuration of the PV System and the Connected Power Network

In order to validate the estimation process of the PV output power, a 10 kW laboratory-grid-connected PV system, as in Figure 12, was investigated for this purpose. The PV system parameters and the connected LV-SEC distribution network are listed in

Table 4. Parameters for an existing laboratory PV system and the interconnected SEC network.

PV System Parameters
System capacity	~10 kW	Covered area	4.2 m × 12.6 m
PV panel type	Monocrystalline 385 W	Panels efficiency	19%
Location	Riyadh, Saudi Arabia	Location coordinators	(24.7136° N, 46.6753° E)
Tilt angle	24 degree	Azimuth angle	0 degree (south)
Number of panels	24	DC cable length	16 m
Inverter type	GROWATT On-grid 4.5 kW MPPT	Inverter DC output voltage	48 VDC
Inverter DC nominal voltage	150 VDC	Inverter AC output voltage	220 VAC (1-ph)
PV panel dimension	2.1 m × 1.05 m	Inverter efficiency	98.4%
SEC Distribution System Parameters
Estimated line resistance	0.306 Ω/km [41]	Estimated line inductance	0.9444 mH/km [41]
Grid nominal AC voltage	380 VAC (3-ph, 60 Hz)	PCC nominal AC voltage	220 VAC (3-ph, 60 Hz)
Estimated line length	1.24 km	Desired SCR	5
Rating of grid to PCC transformer	50 kVA (380Y/220D)	Impedance of grid transformer	6%

.

First, the PV output power during 5 June 2023 was acquired and compared to a calibrated estimated PV power, as shown in Figure 13. The results show that the assessment model for the solar and PV output power is reliable and can be utilized in the PV system design and analysis.

7.2. Solar Energy Estimation and PV System Capacity

Based on characteristics of the LV-SEC distribution network listed in Table 4, Equation (7), and SCR equaling 5, the maximum PV output power is 12.68 kW. Therefore, the required area of the PV system is obtained by dividing the resultant PV maximum power by the maximum solar radiation power and power efficiency of a single panel. The estimations of the average monthly energy and maximum power for solar irradiance, at the specified location, are shown in Figure 14. It is observed that the annually maximum power for the 24° tilted surface is 0.957 kW/m². Therefore, for an 18% PV system efficiency, the required covered area and number of panels are listed in

Table 5. Resultant parameters of the optimal designed PV system based on the proposed method.

Parameter	Value
PPV,max	12.68 kW 1
Required area (for 18% system efficiency 5)	~74 m2
Number of PV panels (with 2.2 m2 each)	34 panel
Recommended on-grid inverter capacity	4 kW ≤ Pinv ≤ 12.5 kW
Recommended BESS inverter capacity	0.5 kW ≤ Pinv ≤ 1.5 kW
Estimated BESS size (10% of PPV,max daytime operation) and 48 Vdc	~80 Ah ≤ BESS ≤ ~300 Ah

¹ P_PV,max obtained from Equation (7) and multiplied by (2/3) to account for two lines out of a 3-ph system. ⁵ This efficiency involves the PV panels’ and power converters’ efficiencies.

.

The estimated average monthly energy and maximum output power for the designed PV system, while considering 18% for the PV system efficiency, are shown in Figure 15. The obtained results prove the feasibility of the design process, where the maximum PV output power is kept below the maximum possible level (12.68 kW).

7.3. Capacity and Dynamic Impact Evaluation of the BESS

In order to demonstrate the dynamic impact of utilizing the BESS on the PCC power quality and security, this section shows the results of the system designed in Section 7.2. The actual SEC distribution network, along with the designed R-PV system, has been investigated through the PSCAD simulation platform. Different case scenarios were conducted to demonstrate the capability of the BESS-based synchronous compensator to follow the recent SEC regulations for PV integration. The case scenarios include the normal operation and faulted (disturbance) conditions, where the fault event is conducted at the SEC network side as shown in Figure 7.

7.3.1. PCC Bus Voltage and Power Factor during Fault Conditions and No Control

In this case scenario, the impact of a fault condition introduced into the PV system, without the integration of the BESS, is examined. The performance evaluation focuses on the behavior of PCC voltage, power, and power factor, as shown in Figure 16. A 3-phase -to-ground fault with zero ground resistance occurs at t = 10.6 s, lasting for 0.3 s as per the SEC-LVRT grid code.

Prior to the fault, the system was in a steady-state condition with PCC voltage (Vpcc) = 1 PU and ≥0.90 leading power factor. During the fault, the PCC voltage drops to 0.1 PU for 0.3 s before gradually increasing back to near 1 PU at 12.3 s. Both PCC active and reactive power levels drop to zero, which is expected since it is a 3-phase-to-ground fault with zero ground resistance. Once the fault is cleared, the PCC active power briefly drops further to −0.2 PU, then sharply rises to 0.8 PU with a large overshoot at 11.3 s before stabilizing at 0.4 PU by 11.6 s. Additionally, due to the slow response, it requires more compensation of reactive power, for voltage support at PCC, with a maximum value of −0.4 PU at 11.2 s, and then the injected reactive power reduces as the PCC voltage increases. Similarly, the impact of the introduced fault can be seen in the power factor behavior in which the PF_pcc is zero at 10.8 s when the PCC active power is zero. However, when the PCC active power becomes negative, which means that the PV system consumes power rather than generating it, the power factor becomes, again, zero at 11.10 s, then reaches 0.90 PU before decreasing at 11.5 s in line with active power changes. While the PCC voltage meets SEC-LVRT grid code requirements, PCC active/reactive power and power factor deviate from their specified limits set by the SEC.

7.3.2. Regulation of PCC Voltage during Normal and Abnormal Conditions

In this scenario, the same fault condition of the above section was conducted, but with the existence of a BESS system. Unlike the pervious case scenario during the fault event, the BESS system here contributes 0.6 PU of reactive power to support the PCC voltage, as shown in Figure 17. During the fault event, PCC voltage drops to 0.1 PU for 0.3 s before rapidly rising above 1 PU at 11.2 s and stabilizing around that value thereafter within about 500 ms from the time of fault clearance. Upon fault clearance, the PCC active power increases, reaching 0.6 PU with a slight overshoot at 11.1 s before settling back to the steady-state value at 11.8 s. The injected reactive power from the BESS system aids in improving and maintaining the PCC voltage and power factor close to their steady-state levels. Consequently, the PCC voltage complies with SEC-LVRT grid code requirements, and the specified limits for PCC active power and power factor are effectively preserved.

7.3.3. Regulation the PCC Power Factor Utilizing the Four Control Modes

The performance of the designed PV system was investigated during the activation of the power factor control (mode 1, mode 3, and mode 4) under a 3-phase-to-ground fault. Mode 2 was not performed, as it is similar to mode 1. A 10 Ω resistance was placed in the faulted-to-ground line to simulate the voltage sag event. As depicted in Figure 18, the power factor was at its unity value, while the PCC voltage was at 1.05 PU. During the fault condition, the BESS regulates the PCC reactive power to maintain the unity power factor at the PCC. The result shows a fast response and recovery during and after the fault event. However, the PCC voltage seems out of control, where it drops to 0.9 PU during the fault, but it shows a fast recovery (about 50 ms) after the fault clearance. In summary, it is clear that the reactive power and power factor are both with the boundaries provided by the SEC, whereas the PCC voltage is not regulated at the nominal value.

Figure 19 shows the system response during mode 3 of power factor control. At normal conditions, the power factor was regulating at 0.95 and it has been changed to a unity value at 10.2 s. The results show the ability of the BESS system to efficiently regulate the power factor at a desired level. During the fault condition, the system has the same performance as in mode 1, which goes along with the SEC power-factor standards.

Figure 20 shows the system response during mode 4 of power factor control. At normal conditions, the power factor was regulating based on the amount of the PCC active power, as described in Equation (13). The results show the ability of the BESS system to efficiently regulate the power factor at a desired level. During the fault condition, the system has the same performance as in mode 1, which goes along with the SEC power-factor standards.

7.3.4. Evaluating the Frequency Response without Active Power Regulation

Figure 21 shows the effect of a 3-phase-to-ground fault with a 10 Ω ground resistance, with the absence of a BESS system. In this case study, the PV power was doubled (P_PV = 2 P_PV,max) to examine the system when the injected PV power is higher than the obtained maximum possible level. As illustrated in Figure 21, under normal operating conditions, the PCC voltage, frequency, active power, and power factor are at 1 PU, 60 Hz, 1.5 PU, and 0.98, respectively. However, during the fault event, the PCC voltage experiences a drop to 0.5 PU for 0.4 s before gradually returning to 1 PU by 11.2 s. Additionally, there is a sudden spike in PCC active power at the onset of the fault, peaking at 2.2 PU before decreasing close to 0.4 PU due to the nature of the applied disturbance. Upon fault clearance, PCC active power exhibits a slight overshoot at 10.9 s before settling back to its rated value at 11.2 s. The frequency response during the fault event shows a drop to 54 Hz at the fault occurrence and a subsequent increase to 66 Hz upon fault clearance. Consequently, it can be inferred that the requirements set by the SEC for PCC frequency and power factor are violated.

7.3.5. Evaluation the Frequency Response with Active Power Regulation

In this case, the same evaluation in the previous section, with the existence of the BESS system, was conducted, as illustrated in Figure 22. During the fault event, the PCC voltage dips to 0.8 PU for 0.1 s before gradually recovering to 1 PU by 11.6 s. Furthermore, at the point of fault clearance, there is a brief spike in PCC voltage to 1.2 PU for 0.1 s before returning to its usual level. Additionally, there is a sudden increase in PCC active power at the start of the fault, reaching a peak of 1 PU for 0.05 s before dropping back to normal levels until the fault is resolved. The BESS plays a role by injecting 0.3 PU of reactive power to assist in stabilizing the PCC voltage. Consequently, PCC reactive power peaks at 0.6 during the fault event and then decreases to 0.5 PU once the fault is cleared. Additionally, at fault clearance, it increases again to 0.6 PU in response to the slight rise in PCC voltage to 1.2 PU before returning to its steady-state value at 11.2 s. By comparing the results in Figure 21 to the results in Figure 22, it is noticeable that the frequency nadir, which measures the lowest frequency dip, was reduced by 7.2%. In addition, the rate of change in frequency, which quantifies the rate of frequency change with respect to time (df/dt), was also reduced by 11.6 Hz/s. This proves that the integration of the BESS assists in keeping the frequency and power factor within the acceptable limits specified by SEC regulations, thereby ensuring adherence to regulatory requirements for frequency and power-factor constraints.

7.3.6. Injected Current Harmonics and Fault Current

Figure 23 below provides an explanation of the role that the 3-winding transformer plays in partially filtering the harmonics before they are completely filtered by BESS and injected into the grid. In the first waveform, the shape of the current wave coming out of the inverter is clearly shown, in which the harmonics are visible (these harmonics were maximized by adding a nonlinear load). After that, the second wave of the current is the wave generated by the 3-winding transformer, and it is clear that some of the harmonics have been eliminated. The most significant current harmonics, those filtered by the 3-winding transformer, are the third-multiple harmonics. After that, when it is the BESS’s turn to compensate for the current, it needs to get rid of the remaining harmonics, as shown in the third wave, before arriving at the final result, which is the closest sinusoidal shape to the one that meets the requirements of the Saudi Electricity Regulatory Authority and the SEC.

To provide a clearer picture of the development in the waveform of the current before it was connected to the grid, the THD spectrum is drawn in Figure 24. The percentage corresponding to each spectrum shows the noticeable improvement caused by the 3-winding transformer and the BESS. The THD was initially 6.44%, and it reached 1.78%, which is a value that meets the requirements of the Saudi Electricity Company.

In addition, the PCC current, during a 3-phase-to-ground fault event, was analyzed as shown in Figure 25. A 10 Ω resistor was placed on the faulted line to maintain the stability of the investigated system. Without utilizing the 3-winding power transformer and the BESS system, the fault current was high (reaching 0.65 PU) and can travel to the PV system side. This high current could harm the PV system and the power conversion equipment. Additionally, this accident can challenge the sustainability of the PV system integration, where the controller system for the DC-AC PV inverter could not handle the oscillating dq-axis currents, as shown in Figure 26. On the other hand, the results also show an essential improvement to the PCC current and the dq-axis controller current components with the utilization of the proposed BESS system. The oscillation in the dq-axis current components was due to the lack of frequency regulation, which the BESS takes care of.

In addition to achieving the grid connection requirements, the utilization of the 3-winding transformer with the small rating of a BESS and the proposed control approach contributes to enhancing the safety and security to the end-user-side equipment.

8. Economic Feasibility of the Proposed Solution

As financial implementation plays a pivotal role in determining the feasibility of any technical solution, this section therefore briefly illustrates the initial and operational costs for the proposed solution. The prices, listed in

Table 6. Cost profile for a 10 kW PV system with a 10% BESS-based synchronous compensator.

Equipment		Count	Total Cost (USD)
PV system	385 W PV panel	26	3900
	On-grid hybrid inverter (12 kW-1 ph-220 VAC)	1	2560
	Mounting structure	2	1400
	DC cable roll	4	640
	PV MC4 connectors	28	87
	DC circuit breakers	2	60
	DC and AC circuit breakers	2	46
	Installation fees	1	3210
Total			11,903
BESS system	48 V battery (100 Ah)	2	240
	Battery rack	2	60
	On-grid hybrid inverter (1.5 kW-1 ph-220 VAC)	1	310
	Installation fees	1	200
	3-winding power transformer (10 kVA)	1	450
Total			1260

, are all based on the commercially available equipment in Saudi Arabia. The size of the laboratory PV system considered in this study is used to specify the required equipment. The cost of the PV system (PV panels, DC-DC converter, AC-AC on-grid inverter, construction, and DC cables) are based on actual market prices, where it was recently installed in the research laboratory.

As observed from Table 6, the additional cost, due to the utilization on the proposed solution, is approximately 10% of the PV system total cost. This percentage of increment becomes lower as the PV system rating increases. The economic feasibility for the proposed solution is obvious, where a 10% additional cost can maintain the security and authority of the PV system integration.

9. Conclusions

This paper highlighted and addressed the recent regulatory framework for small-scale solar PV systems in the Kingdom of Saudi Arabia set forth by the Saudi Electricity Regulatory Authority (SERA) and reformed by the Saudi Electricity Company (SEC). These regulations are essential for authorized and sustainable interconnection to low-voltage distribution networks. The main objective of this study is to enhance the design considerations of grid-connected residential PV systems, in order to help the end-users meet the recent technical grid codes, while maintaining the cost and required PV system area as minimally as possible. To this aim, this study endeavored to determine the maximum PV power attainable based on the connected network characteristics at the point of a customer’s connection. The maximum PV injected power is significant to determine the interconnection quality and stability, as stated by SERA recommendations. In order to continue the process of PV system designing, this paper also sought to estimate the solar energy production for any given customer’s PV panel orientation to optimize PV size and construction. In addition, this study proposed an active and reactive power compensation strategy for enhanced quality and stability at the PV point of common coupling (PCC). The proposed control strategy is mainly dependent on the utilization of a battery energy storage system (BESS) and a versatile interface power converter. The BESS is designed only to contribute to PCC quality and stability (~10% of the PV capacity) to maintain its low cost and size. An intensive computational analysis, along with actual PV system and SEC distribution data, was conducted to validate and investigate the feasibility of the proposed solution. An intended R-PV system, located in Riyadh, Saudi Arabia, was designed in detail and investigated under normal and faulted conditions. The results showed an essential enhancement in terms of power quality and reliability. The LVRT test showed a 500 ms faulted bus voltage recovery, while the power factor could be regulated in four designed operating points. The frequency response was also enhanced with a −7.2% frequency nadir and a −11.6 Hz/s ROCOF at the time of the fault event. In addition, the PCC current was also improved with −3.04% in THD and 23.2% reduction in fault current. The utilized 3-winding power transformer showed an efficient role played toward harmonic mitigation, fault current limitation, and system isolation, in addition to the voltage stepping-up capability, which helps in reducing the DC-DC converter’s requirements. Based on this study’s outcomes, it is recommended to the Saudi electricity industry and delivery to establish a regulatory framework for an energy storage system and shunt power compensation to ensure reliable integration and safety for integrated small-scale PV systems. The cost analysis conducted in this study showed that approximately 9% of the PV system cost must be dedicated for the BESS. Since cost-effectiveness is really essential in determining the feasibility of the proposed solution, it is recommended to intensively analyze the proposed solution cost efficiency in a future work.