An advanced model for hydrodynamic analysis and development planning of reservoirs: A case study in southwestern Iran
Effective reservoir management, aimed at maximizing oil recovery, necessitates meticulous analysis of pressure history, production data, and hydrodynamics, and comprehending underlying production mechanisms (Lu et al., 2020). This comprehensive approach is indispensable for optimizing oil production (Al-Qasim, 2020).
The primary objective is to apply these principles explicitly to investigate an oil reservoir in southwestern Iran, emphasizing global applicability. The reservoir comprises fractured carbonate formations, with production reliant on these fractures. Initially, the reservoir contained saturated oil, with a gas cap. However, as production increased, reservoir pressure declined, leading to reduced oil output. To counteract this, a gas injection project is underway to elevate reservoir pressure. The findings not only enhance reservoir understanding and management but also offer a valuable model applicable to similar reservoirs worldwide, optimizing oil production and recovery in diverse contexts.
The oil field under investigation is in the southwestern region of Iran, specifically within Khuzestan province, and is characterized by its predominant carbonate lithology, as documented in Alavi's comprehensive study of 2004 (Alavi, 2004). This particular study area holds a prominent status within the context of southwestern Iran, serving as one of the most significant oil fields in the region.
Notably, this oil field exhibits a remarkable geological structure, marked by a substantial anticline formation stretching over 41 km (25 mi) in length and spanning 9 km (5.6 mi) in width. Within this expansive geological formation, a network of 76 strategically positioned oil wells plays a pivotal role in oil extraction and exploration endeavors, Fig. 1.
In these studies, a comprehensive analysis was conducted, considering critical parameters and data sources. This involved assessing pressure changes in reservoir fluids from various wells, monitoring fluid level variations during production phases, and using well test-derived permeability parameters. The study also examined hydrodynamic gradients and pressure fluctuations in different reservoir sections.
The main goals were to assess reservoir development trends, identify hydrodynamic directions within the field, and evaluate their strengths. Additionally, the study aimed to determine the extent of impermeable surface expansion within the reservoir. These investigations were drawn from diverse reputable sources and methods to ensure analysis accuracy and comprehensiveness. The insights gained are not limited to the specific oil field but can also serve as valuable models and references for global reservoir analyses. The methodologies used have broader applications for optimized reservoir management and enhanced oil recovery worldwide.
Reservoir fluid pressure analysis is a top priority for studying reservoir changes over various time intervals (Chilingar et al., 2005). To examine reservoir pressure, we calculate the rate of pressure changes relative to production, Fig. 2a. Based on the oil pressure trend, we can classify changes into five distinct time periods.
As shown in Fig. 2b, oil pressure is affected significantly by reservoir production. During the initial period with low production, the pressure drop trend is gradual, averaging 65 feet (PSI) with an annual average of 22 pa. Minimal production stabilizes the reservoir pressure at an initial natural level of 112 pa, leading to the gas cap expanding rapidly and reducing the oil column, Fig. 2c. In the second period at peak production, the oil column thickness decreased from 815 to 512 meters (m). The oil column diminished by about 0.75 m per million barrels of production during this phase, followed by a decline of approximately 0.42 m per million barrels in subsequent periods.
High production rates in the second period caused a more pronounced oil column reduction. In the third period, pressure decreased gradually, with a 50-pm drop recorded over the years. The fourth period saw a restart of production, leading to a 130-pm pressure drop in the oil column. In the fifth period, marked by a gas injection project, the decline in tank pressure stopped, and gradual pressure increased by 40-pm. These findings highlight the direct correlation between significant pressure reduction and reservoir production.
Gas to oil ratio. Analyzing GOR fluctuations is vital for assessing oil and gas reservoirs (Aguilera, 2004). Figure 3a depicts significant GOR fluctuations over the reservoir's life, tied to reservoir oil pressure. Reduced pressure corresponds to increased GOR. High oil production leads to rapid GOR increases. Subsequent reduced production and pressure decline cause minor GOR fluctuations. Periodic misalignment between GOR and pressure contributes to high GOR in some wells (Zolalemin, 2019). This parallels slotted reservoirs (Wang et al., 2019). As tank pressure drops, soluble gas enters the gas cap through slots, reducing oil-to-gas ratios (Busahmin and Maini, 2019). Produced GOR relates to soluble GOR, anticipating a decrease.
Investigation of reservoir hydrodynamics. Water pressure assesses reservoir hydrodynamics (Sun et al., 2018). Trends mimic oil and gas pressure (Fig. 3b), suggesting no active discharge. Initial decade pressure drops approximately 970 pm (Fig. 4a), with no increase during production declines, revealing no active discharge. Vital in petroleum engineering (Kai et al., 2019), it shows water infiltrates from the periphery, increasing pressure and reducing it in the outlet region (Busahmin et al., 2021).
Measuring pressure differentials detects water infiltration (Wang and Chen, 2019; Pourmorad et al., 2021). This study examines water pressure trends (Huan et al., 2021), vital for understanding reservoir pressure stabilization (Amr et al., 2021). Sometimes, pressure stabilizes, unrelated to production and pressure (North, 1990; Dashti and Sfidari, 2016), needing an appropriate model (Guzman et al., 2021).
Gas impacts reservoir pressure (Shad et al., 2016), combining production with pressure history, predicting production behavior and pressure drop (Dickey, 1986). It separates natural from abnormal factors (Shohel et al., 2021). Figure 2 shows pressure decline and tank production pre-gas injection. Figure 2b reveals steep pressure drops during high production but no stabilization. Stabilization occurs with no or very low production, an inverse production-pressure relationship (Khojastehmehr et al., 2019).
Continuous production sans gas injection depletes pressure, halting production. Resuming, pressure drops significantly. Self-recovery begins with dissolved gas release from oil, unrelated to hydrodynamics. High production doesn't stabilize reservoir pressure (Jia et al., 2021). Pressure stabilization relies heavily on production in this reservoir, debunking the idea of inherent stabilization (Dickey, 1986). Over 13 years of oil production, lower water pressure sharply decreased, lacking compensatory mechanisms (Chilingar et al., 2005) for stability. Concurrently, oil production led to steep water pressure declines, as evidenced by well water pressure and production-reservoir pressure diagrams, Fig. 4a, (Guzman-Osorio et al., 2021).
The absence of self-compression indicates weak hydrodynamics (Yuewei et al., 2021). Figure 4b highlights the most significant difference between oil and water contact in the southeast. Well 11 in the southern region exhibits the highest water pressure, followed by the northern areas and then the western section. Geological strata slope from north to south. The decline in western water pressure, correlating with production and pressure (Fig. 2b), reveals compartmentalization, due to permeability barriers and pressure diffusion (Fig. 5a), effectively isolating the influence of water (Kai et al., 2019).
Due to elevated water pressure in the southeastern reservoir region and opposing geological strata slopes leading to lower water pressure in the northern part, in alignment with the regional slope and hydrodynamics, it's evident that hydrodynamics are absent in these areas (Shad et al., 2016). According to these findings, altering reservoir fluid contact levels is not feasible. In reservoirs with active hydrodynamics, water typically enters from regions with lower pressure and higher flow intensity and exits from areas with lower pressure and reduced flow intensity (Dickey, 1986).
This study demonstrates that in reservoirs with hydrodynamics following geological strata slopes, the pressure difference between two points remains positive. Negative values indicate deviations in reservoir fluid contact surfaces, due to static-related factors, (Shen et al., 2021). Fluid and water pressures in the northern and western regions are essentially equal, Table 1. In the southern part, there's a 30-pa pressure differential, opposing the regional strata slope. There's a significant and rapid decline in reservoir water pressure over time, reaching about 1,100 pa, Fig. 3b.
The findings suggest that water infiltration into the region with the greatest contact surface would increase oil pressure, along with gas pressure. Importantly, water pressure would rise notably in this area. Currently, oil and gas pressures in the reservoir are nearly equal, with a slight difference. Surprisingly, water pressure is higher in the southeast region (Table 2), contradicting the area's typical stratification slope and tectonic characteristics. The significant compaction of reservoir rock in this area, reducing both porosity (Fig. 5a) and permeability (Fig. 5b), combined with the proximity of contour alignment lines (Fig. 6), supports these findings.
Prominent production mechanisms include gas cap expansion, dissolved gas thrust, fluid thrust and gravity drainage (Richard, 2019; Weber, 1986). Gravity drainage is the primary production mechanism in this reservoir, due to the lack of an active discharge mechanism for replenishing reservoir pressure. The reservoir's gas cap remains unstable, due to its limited size. A gas injection project, introduced as a secondary method, aims to enhance pressure and boost production. In addition to these mechanisms, the reservoir exhibits two distinctive phenomena: diffusion and convection, specific to rift reservoirs, supported by fluid properties and pressure trends, Fig. 3a. Compressive dispersion indicates permeability barriers and reservoir discontinuities (Adesina et al., 2020).
Pressure anomalies cause significant fluctuations across segments, due to lithological and tectonic variations, forming distinct compartments within the reservoir (Chengzao et al., 2021). The western section exhibits unfavorable pressure distribution, affecting production conditions, porosity and permeability values, Fig. 4a. Permeability barriers have compartmentalized this region, reducing reservoir productivity and increasing drilling costs, Fig. 5b. Solutions involve drilling wells at closer intervals and using artificial hydraulic fractures (Khojastehmehr et al., 2019).
Studies demonstrate segments with these characteristics generally have lower regional production and permeability, Fig. 4a. Compressive dispersion relates to porosity, permeability and production, with higher dispersion associated with increased porosity and permeability but decreased production, Fig. 5b. While lithology and diagenesis affect porosity, the correlation holds for pressure, permeability and dispersion (Khojastehmehr et al., 2019). These segments, which are non-contributory to the reservoir's water supply and inaccessible to water, due to their characteristics, play a crucial role in the reservoir's hydrodynamic behavior (Zolalemin, 2019).
Reservoir segmentation. Oil reservoir segmentation, crucial for analysis (Matthews et al., 2008), divides it into north, south and west zones, Fig. 7b. Static pressure trends show remarkable consistency, Fig. 4b. West exhibits broader static pressure variations, due to prevalent evaporitic lithologies, Fig. 5b. Eastern reservoir splits into north and south, due to varied fractures; northern part has higher permeability, Fig 5b. Western reservoir has fewer fractures, due to fault activity and salt layers, Fig. 5b. Wells in this region show distinct high-rate decline characteristics, Fig. 5a.
The studied reservoir is a natural rift reservoir, evident from the correlation between GOR production and pressure, along with consistent fluid properties in different sections and depths. This reservoir is divided into three regions: north, south and west, based on production indices, pressure distribution, pressure permeability and hydrodynamic characteristics. The northern and southern sections show the most development potential. To develop the western part of the reservoir with carbonate and evaporitic rock, creating artificial fractures in the reservoir rock is essential for pressure reduction.
Given that gravity is the predominant production mechanism, raising reservoir pressure through gas injection becomes essential to optimize oil recovery from reservoir blocks. This action should ideally be initiated before the third production cycle. Due to the limited fracture system development in the western reservoir section, increasing well density and implementing hydraulic fracturing within the reservoir rock is essential for efficient gravity drainage. According to the studies, reservoir production should be conducted in a balanced manner. Excessive reservoir flowrates lead to a rapid reduction in the oil column's thickness and result in a significant volume of oil loss within the reservoir rock.
Hydrodynamic studies indicate that the tilting of the contact surface of reservoir fluids in the southeastern part of the reservoir is caused by non-hydrodynamic factors. Furthermore, there is no natural hydrodynamic influx into the reservoir, necessitating the use of gas injection to maintain constant pressure. The research conducted in this article has revealed an inverse relationship between reservoir production and the distribution of wells under compressive forces. In simpler terms, the lower this parameter is in a particular section of the reservoir, the higher the daily production and accumulation rate in that specific area.
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