Efficient separation of water from crude oil remains one of the persistent challenges in petroleum production, particularly in mature fields where the water cut (WC) increases as reservoirs age. The presence of stable water-in-oil emulsions negatively influences processing efficiency, raises operating costs, encourages corrosion, and accelerates scaling in surface facilities (Alharbi and Abdulhamid, 2023). These issues are especially critical in sub-Saharan African fields, where infrastructure constraints and reservoir heterogeneity often intensify emulsion stability and complicate dehydration operations (Sheng, 2021). Understanding the mechanisms governing water dispersion and removal is therefore essential for improving surface treatment efficiency in such environments (Peter, 2012).

The effectiveness of surface separation equipment is generally governed by multiple parameters, including separator design, emulsion rheology, chemical treatment strategy, residence time, and the physical characteristics of dispersed droplets (Lim et al., 2017). In the Badila Field, southern Chad, crude oil is processed through a sequence of separation units including electrostatic coalescers, heaters, demulsifier injection systems, heat exchangers, and decantation tanks. Despite this integrated system, field operators continue to report residual water at the outlet of the Central Processing Facility (CPF), indicating possible limitations in separator performance, electric field strength, or fluid residence time (Noïk et al., 2006). These persistent inefficiencies highlight the need for a deeper assessment of the field’s separation performance under real operational conditions.

The problem addressed in this study arises from the persistent presence of significant water volumes in the export crude from the Badila CPF despite the installation of modern dehydration units, including the V-200A/B electrostatic coalescing separators with a rated capacity of 15,000 bbl/day (Eow and Ghadiri, 2002). This issue creates operational risks by affecting pipeline specification compliance, triggering export-quality penalties, and increasing overall dehydration costs. Reported facility constraints—such as low electromagnetic field intensity and the limited height of the decantation tank—suggest potential causes of inadequate separation performance (Benyamine et al., 2024).

Consequently, the study seeks to assess how effectively the current system removes water from crude oil and how design and operational parameters shape residual water content and droplet size distribution. The central hypothesis posits that insufficient electric field strength and limited residence time restrict coalescence, allowing fine water droplets to persist at the CPF outlet. In line with the journal’s required structure, the study aims to quantify residual water content using atmospheric distillation, characterize droplet size distribution based on field measurements, evaluate design and operational constraints affecting separation efficiency, and recommend targeted strategies to improve dehydration performance. Overall, this research contributes to a better understanding of oil-water separation dynamics in an onshore Central African context, where infrastructure aging, fluid complexity, and operational variability commonly affect treatment performance. The findings can support operators in optimizing separator design, improving chemical treatment programs, and reducing water carryover in similar mature fields across the region. Beyond the Badila Field, the study has practical implications for improving energy efficiency, reducing maintenance costs, and ensuring compliance with export crude specifications in comparable production facilities.

2. Materials and Methods

2.1 Ethical approval statement

This study involved the collection and analysis of crude oil and produced water samples from industrial operations. No human or animal subjects were involved. Authorization for sampling and data collection was obtained from PetroChad Mangara Ltd. under field authorization code PCM-OPS/ENV–2023/07, in accordance with institutional operational and environmental compliance standards. Therefore, formal ethical approval was not required.

2.2 Study area and periods

The Badila oil field, located in the Nya Pendé Department of southwestern Chad, was discovered in 2002 by ExxonMobil during operations in the DOB and DOI exploration blocks and was later transferred to PetroChad Mangara in 2011 to support further development (Lirong et al., 2022). Geographically, the field lies at approximately 08°20′25.25″ N and 16°19′40.32″ E, about 430 km southwest of N’Djamena and 60 km from Moundou, the country’s principal economic center (Glencore, 2012) (Figure 1). The reservoir is part of the sedimentary sequence of the Doba Basin, known for producing medium-to-heavy crude oil with a moderate and evolving WC (Lirong et al., 2022). For this study, samples were collected between 2014 and 2023 from the inlet and outlet of five production wells (Badila-001 to Badila-005) and from all major separation units within the CPF.

2.3 Sampling and data collection

At each sampling point, temperature, pressure, WC, and water–oil ratio (WOR) were measured following procedures adapted from ASTM D95 (Sugeng et al., 2021; Margolis and Hagwood, 2003) and established field sampling protocols (Luo et al., 2025; Kang et al., 2018). Water content was quantified by atmospheric distillation using a Laboratory Distillation Apparatus (Model D95-Pro, Fisher Scientific®, USA), and the corresponding WC and WOR values were calculated using the following formulas,

Where V_water is the measured water volume, and V_sample or V_oil represent the total sample volume or oil-phase volume, respectively.

Reduction efficiency and growth rate were determined using the relations (Kang et al., 2018),

Where x_i and x_odenote inlet and outlet concentrations, and 𝑊𝑐_𝑖 and 𝑊𝑐_𝑜 represent the water cuts at the inlet and outlet of the separation units.

2.4 Measurement of droplet size

Water droplet size distribution in the crude oil samples was measured using a Coulter Counter (Model Multisizer 4e, Beckman Coulter Inc., USA), following the procedure outlined by Luo et al. (2025) and complemented by methodologies from Alharbi and Abdulhamid (2023). Prior to analysis, samples were equilibrated at 25 °C in a thermostatic bath to minimize thermal effects on droplet dynamics. Each sample was analyzed in triplicate to ensure measurement reliability. Droplet size distribution was expressed as mean diameter (µm) and standard deviation, providing a basis for assessing the effectiveness of electrostatic coalescence and gravitational settling across the CPF. These measurements were subsequently used to examine the relationship between droplet characteristics and overall separation performance.

2.5 Statistical analysis

All collected data—including WC, WOR, droplet size distribution, and separation efficiency—were analyzed using IBM SPSS Statistics 26 (IBM Corp., USA) and OriginPro 2022 (OriginLab®, USA), with descriptive statistics (mean, variance, standard deviation) calculated for all variables. Inferential analyses comprised ANOVA to compare water-cut variations across wells and CPF units, Pearson correlation to assess the relationship between droplet size and separation efficiency, and linear regression to identify key predictors of residual water content. Graphical outputs such as droplet size distribution curves and separation-efficiency plots were produced in OriginPro 2022, while tables were formatted in Microsoft Excel 2021. A map of the study area was generated using QGIS 3.22.

3. Results

3.1 Water-cut dynamics at the wellhead

The evaluation of WC at the Badila Field wellheads from 2014 to 2023 shows a clear and progressive increase in water production across all five wells, reflecting reservoir maturity and evolving flow behavior. WC values ranged from 0.10 to 0.90, with growth rates spanning 10% to over 1000% during the decade. Badila-001 initially exhibited a sharp rise (200% in 2014) before stabilizing to 50% by 2023, a trend attributed to repeated reservoir interventions and directional re-entry operations that helped delay water breakthrough. In contrast, Badila-004 and Badila-005 displayed closely aligned WC trends, indicating hydraulic continuity due to their proximity and similar reservoir properties. Mean WC values over the study period were highest in Badila-005 (1.60%), which also recorded the strongest growth rate (224.60%), reflecting elevated water influx combined with comparatively low oil output, thereby increasing treatment and handling costs. Overall, the results highlight significant variability in water encroachment behavior among wells, with implications for production planning, separation system performance, and long-term reservoir management.

3.2 Water-in-oil ratio (WOR) at the central processing facility (CPF)

The evaluation of WOR across the CPF separation units shows a progressive decrease in water content as fluids move through the treatment system. The average WOR at the inlet of V-200A was 5%, decreasing to 2.70% at the outlet, representing a 46.40% reduction. For V-200B, WOR declined from 2.70% to 2.03%, corresponding to a 27.40% reduction. The settling tanks further reduced WOR from 2.02% to 1.20% (39.10%), while the boilers achieved the highest reduction from 1.30% to 0.20% (91.40%). The heat exchangers contributed an additional decrease from 0.10% to 0.07% (54.20%). Overall, the results indicate that although each unit contributes to lowering WOR, water content remains above 2% at the CPF outlet.

3.3 Evolution of water droplet size in crude oil during processing

Water droplet size in crude oil progressively decreased through the CPF separation stages. The average droplet size reduced from 67.8 µm at the V-200A inlet to 2.1 µm at the heat exchanger outlet, representing a total reduction of 71.3% (Table 3). Stage-specific reductions were 36.6% for V-200A, 51.6% for V-200B, 53.6% for settling tanks, 54.1% for the boiler, and 71.3% for the heat exchanger, with mean droplet sizes ranging from 54.8 µm at V-200A to 4.15 µm at the heat exchanger.

3.4 Water cut, water-in-oil ratio, and water droplet size evolution

Analysis of water cut (WC) at the outlet of Badila production wells over the ten-year period (2014–2023) shows a gradual increase in annual average water content, ranging from 0.10% to 0.90% at the wellheads (Table 4). Growth rates varied between 10% and over 1000%, reflecting reservoir dynamics. The mean wellhead water cuts over the decade were 0.44–1.60%. At the CPF, the inlet water-in-oil ratio (WOR) at V-200A was 5%, reducing to 2.70% at the outlet, with reduction efficiencies for V-200B, settling tanks, boilers, and heat exchangers of 27.40%, 39.10%, 91.10%, and 54.20%, respectively. Water droplet size decreased from 67.80 µm at the V-200A inlet to 2.10 µm at the heat exchanger outlet, achieving a total reduction of 71.30%.

3.5 Influence of electric and magnetic fields on water droplet coalescence

The electromagnetic conditions applied within the V-200A/B separators influenced the behavior of dispersed water droplets (Figure 2). Under the electric field, droplets exhibited enhanced alignment and interaction, leading to increased coalescence and the formation of larger droplets. The magnetic field produced only minor changes in droplet behavior, with slight modifications in interfacial tension and hydrocarbon orientation observed under higher flux densities. Overall, the combined electric and magnetic fields increased droplet polarization and collision frequency, resulting in noticeably improved coalescence at this stage of processing.

3.6 Effect of separator height on droplet settling

The height of separators and settling tanks directly affected droplet behavior and overall separation performance. Upon entering the settling tanks, droplets exhibited initial breakup due to turbulence, followed by progressive agglomeration as residence time increased (Figure 3). Increased vertical height provided a longer settling path and extended residence time, enabling droplets to grow larger and separate more efficiently under gravity.

3.7 Effect of temperature and pressure on droplet separation

Temperature and pressure demonstrated contrasting effects on droplet behavior during oil–water separation. Increasing temperature enhanced molecular mobility and reduced viscosity, which promoted droplet coalescence and accelerated water removal. Temperatures around 130 °C were identified as optimal for desalting operations (Figure 4). Conversely, elevated pressure increased turbulence and shear forces, leading to fragmentation of larger droplets into smaller, more stable ones that were harder to separate. Higher pressure also strengthened interfacial forces, further stabilizing emulsions and delaying phase disengagement.

3.8 Environmental implications of increasing water cut, WOR, and droplet dynamics

The ten-year production data from the Badila wells show a clear upward trend in WC, leading to increased volumes of produced water requiring treatment and disposal. Wells with high WC—particularly Badila-005—generated disproportionately large amounts of water relative to oil, increasing operational load and the potential for environmental risks such as leaks, accidental releases, soil salinization, and groundwater contamination. The use of Electric Submersible Pumps (ESP) intensified emulsification, resulting in more stable oil–water mixtures that were harder to break and required more energy-intensive treatment. At the CPF, persistent water-in-oil ratios (WOR > 2%) at separator outlets indicated inefficiencies in dehydration processes. Stable emulsions, limited demulsifier effectiveness, and electrostatic separation constraints contributed to incomplete hydrocarbon removal from produced water. The presence of micro-droplets (<2 μm) in treated oil suggested inadequate separation and the potential need for additional polishing technologies. Thermal treatment improved dehydration but increased overall energy consumption. Conditions affecting droplet coalescence—such as electric/magnetic fields, separator geometry, temperature, and pressure—were also observed to influence the efficiency of water removal.

4. Discussion

The similar WC trends observed in Badila-004 and Badila-005 suggest hydraulic continuity between the wells, reflecting their spatial proximity and comparable reservoir characteristics. This pattern aligns with the understanding that water presence in multiphase fluids is often more pronounced in oil due to its relatively greater affinity for water compared to gas (Brill, 1987). As production progresses, the acceleration of multiphase fluids through ESP systems further intensifies fluid mixing, amplifying emulsification and stabilizing water and sediments within the oil phase.

The enhanced emulsification produced by ESP-driven turbulence increases interfacial tension and facilitates the retention of fine solid particles, a phenomenon consistent with observations by Zhang et al. (2022), who demonstrated that sediment settling is favored at lower flow velocities. The accumulation of solids and stabilized emulsions contributes to scale, paraffin, and crystal deposition, leading to plugging of perforations, degraded reservoir connectivity, and corrosion risks in pipelines and storage infrastructure (Duncan and Reimer, 2019). These well-level challenges propagate downstream to surface processing facilities, where the persistence of high WOR values at the CPF underscores difficulties in achieving effective dehydration.

At the CPF, the limited performance of demulsifiers in breaking stable emulsions indicates strong interfacial films formed by natural surfactants, reducing the overall efficiency of chemical treatment. Variability in electromagnetic field strength between V-200A and V-200B separators further contributes to inconsistent electro-coalescence performance, influencing the coalescence of micro-droplets of varying sizes and polarities (Wang et al.,2025). This challenge is compounded in settling tanks, where inverse emulsion behavior in low-viscosity oils and thermally induced instabilities can diminish separation performance and, in some cases, contribute to production losses (Li et al., 2023).

The reduced droplet size observed at V-200A (36.6%) compared with V-200B (51.6%) reflects differences in electric field intensity, with weaker fields limiting droplet polarization and coalescence efficiency (Eow and Ghadiri, 2002). While coalescence in settling tanks is also shaped by viscosity, surface tension, and natural emulsifiers, improvements typically require advanced demulsifiers such as Vx Champion, which can achieve up to 60% reduction (Issaka, 2015). Elevated temperatures in boiler and heat exchanger stages promote molecular mobility and enhance coalescence, facilitating separation (Zhang et al., 2025). However, the persistence of micro-droplets (<2 µm) highlights the need for more advanced coalescing technologies or bio-demulsifiers to achieve complete dehydration (Dhandhi et al., 2022). The high water–oil affinity of Badila crude (~80%) further reinforces the inherent stability of its emulsions.

The enhancement of droplet coalescence under applied electric fields corresponds with established mechanisms in which induced dipole moments increase droplet attraction, promoting rapid fusion and gravitational settling (Oommen and Kumar, 2019). Although water’s diamagnetic nature limits magnetic field influence, sufficiently strong magnetic flux densities may still induce subtle changes in interfacial behavior, contributing marginally to separation efficiency (Eow and Ghadiri, 2002). The combined electric and magnetic fields create a synergistic environment that facilitates droplet aggregation, reflecting principles used in modern electrostatic desalting systems (Tahouni et al., 2023). Complementing these effects, separator geometry—including height, flow distribution, and lamella configuration—plays a fundamental role in determining residence time and promoting gravitational settling, consistent with prior research (Olmos et al., 2001; Hafskjold, et al., 1994).

Temperature and pressure conditions further interact with separation performance, requiring careful optimization. Elevated temperatures reduce fluid viscosity and enhance coalescence, whereas excessive pressures increase turbulence, promote droplet breakup, and stabilize emulsions, hindering phase disengagement. These observations are consistent with studies affirming the need to balance heat input with controlled pressure conditions to maximize dehydration efficiency (Huang, 2025; Al-Muslim and Dincer, 2005). The interplay between thermal energy, electric fields, separator geometry, and chemical treatment ultimately dictates the system’s ability to reduce WOR and droplet size to acceptable operational limits.

These technical findings also carry broader environmental implications. Rising water cut elevates produced water volumes, thereby magnifying risks associated with handling, storage, and disposal. Improperly managed produced water contributes to soil salinization and groundwater contamination (Duncan and Reimer, 2019). Persistent emulsification and incomplete dehydration increase residual hydrocarbons and heavy metals in treated water, intensifying ecological risks (Wang et al., 2025; Li et al., 2023). The presence of micro-droplets represents a well-documented challenge in meeting regulatory standards for dispersed oil concentrations (Dhandhi et al., 2022). Suboptimal operating conditions—especially those affecting droplet coalescence—create a cascade of environmental costs through increased chemical consumption, energy usage, and waste generation. Accordingly, optimizing separation parameters, integrating advanced coalescing technologies, and refining demulsifier strategies are essential steps for reducing environmental impacts and enhancing the sustainability of oilfield operations.

5. Conclusions

This study assessed water separation efficiency at the Badila Field by examining water cut, WOR, and droplet size behavior across wells and CPF units. The findings show that water retention remains a significant challenge, particularly in mechanically pumped wells prone to emulsification. While electrostatic coalescers, gravity tanks, and thermal treatments reduce water content, their performance is constrained by equipment design, limited field strength, and operational settings, allowing micro-droplets to persist and pose risks such as corrosion and fouling. The results underscore the need for integrated process optimization, improved chemical treatment, and tighter operational control to enhance dehydration efficiency. Continued development of advanced separation technologies and real-time monitoring is recommended to further reduce residual water in mature oil fields.

Acknowledgements

The authors sincerely thank the Geosciences Laboratory of Mao and the Fine Analysis Laboratory of the University of Garoua for their valuable support and for conducting all the analytical work required for this study. We are also grateful to the Embassy of France in N’Djamena for partially funding this research through support for short-term visits to Cameroon. Special thanks are extended to Glencore, through its Chad subsidiary PetroChad, for generously providing access to field data that was essential for this work. Their contributions greatly facilitated the successful completion of this study.

Source of funding

This work was partially funded by the Government of Chad through research grants and by the Embassy of France in N’Djamena, which supported short-term scientific visits to Cameroon.

Data availability

The datasets generated and analyzed during the current study are available from the corresponding author upon reasonable request. Certain operational data were provided by PetroChad Mangara Ltd. under confidentiality agreements.

Informed consent statement

No informed consent was required to conduct the study.

Conflict of interest

The authors declare no conflict of interest.

Authors’ contribution

Conceptualization, methodology, supervision, and manuscript writing: Brahim Bakimbil; statistical analysis, visualization, and manuscript review: Blaise Niraka; data collection, laboratory analyses, and data curation: Djouldé Darman Roger. All authors read and approved the final manuscript.