## 1 Introduction  
The Bredasdorp Basin is widely known as South Africa's hydrocarbon-producing basin [1]. Exploration and drilling in this basin have revealed the occurrence of active petroleum systems; specifically, the efficient reservoir sandstones, mature source rocks and traps paved the way to the commercial extraction of oil and gas in the basin's central and northern flanks [2]. Oil and gas are still being explored in this region; thus, the basin's petroleum system processes are receiving more attention to ensure its economic sustainability [3]. Pore pressure (PP) is the fluid pressure in the pore space and results in an overpressure situation when hydrostatic pressure is exceeded [4]. Reservoir pore pressure is one of the principal concerns for drillers in exploratory areas throughout the primary recovery of hydrocarbons [5]. This is because inaccurate estimation of pore pressure in any reservoir can lead to uncertainties and serious consequences, such as formation damage, wellbore instability, gas kicks, and the worst-case situation of blowouts [6; 7; 8]. Consequently, this could hinder the attempts to achieve or contribute to the 2030 United Nations' Sustainable Development Goals (SDGs), including goal numbers 14 'Life Below Water' and 15 'Life on Land,' which aim to protect the ecosystem and environment [9]. Pore pressure prediction is critical in any reservoir for evaluating and accessing fluid contacts for more efficient selection and for safety purposes [8]. In addition, it prevents the kicks and blowout circumstances often triggered by abnormally high pressure (i.e., overpressure) during well drilling activities in the petroleum industry [5; 8]. Pore pressure prediction gives drillers an early warning of potential oil and gas kicks, enabling them to adjust mud weight pre-emptively. A kick causes a delay in drilling practices, blowouts, and jeopardization of the wells [5; 9; 10; 11; 12]. A comprehensive understanding of reservoir pressure enables the effective design and implementation of casing strategies that maintain a safe and operational mud weight window between pore pressure and the fracture gradient, thereby enhancing wellbore stability and optimizing drilling economics [5; 8]. Factors such as compaction, fluid overpressure and tectonic activity can cause pore pressure to deviate significantly from the hydrostatic pressure line [13; 14]. Stress-related mechanisms, fluid volume increase mechanisms, and fluid movement mechanisms are classified as overpressure generation categories. All these mechanisms can cause overpressure in the formation if they occur at a rapid rate that exceeds the formation's ability to expel excess pressure [15]. Compaction disequilibrium is one of the main factors causing high overpressure in the tertiary sediments. Predrilling data (seismic data) and drilling data (well logging) are the most conventional pore pressure prediction and estimation approaches [16]. Wireline log, which gives extensive and continuous data, is much more affordable than measuring pore pressure directly from the wellbore [15]. Changes in pore pressure affect the type of fluids found in the reservoir. Pore pressure and fluid contacts are significant parameters when locating hydrocarbons in the reservoir. As a result, they necessitate a critical review of regulating factors that may affect both, such as the pressure gradient at which fluid contacts change, mud weight, pore shapes, permeability, pressure type, sediment compaction, overburden, and tectonic stress [8]. The pore pressure and fluid contact changes are induced by reservoir petrophysical anomalies driven by time variation [17]. Determining fluid contacts (gas-water contact--GWC, oil-water contact--OWC, and gas-oil contact--GOC) is imperative for estimating field reserves and formation evaluation [18]. Fluid contacts may differ across a reservoir due to semipermeable barriers, faults, variations in rock quality or reservoir heterogeneity, hydrocarbon filling history, and hydrodynamic processes [19; 20; 21].