Introduction

Heterogeneity plays a pivotal role in the reservoir’s management, secondary recovery processes, and performing raising afflux from the collector to the wells (Malureanu et al. 2010). It encompasses differences in permeability, porosity, grain-size, mineralogy, mechanical properties, and diagenetic attributes. According to El-Deek et al. (2017) and Adams et al. (2011) heterogeneity occurs at various scales: megascopic (basin scale), macroscopic (formation scale), mesoscopic (lithofacies variability) and microscopic scale (variation of petrophysical properties). Porosity and permeability heterogeneity as it affects flow and storage capacity of the reservoirs in the PZ-2 and PZ-4 well were investigated (Fig. 1). This is borne out of the desire and renewed commitment of the Federal Government of Nigeria for more rigorous exploration of the Niger Delta and other frontier basins. This effort will shore up the oil and gas reserves, guarantee adequate production of hydrocarbon for both local consumption and export to boost revenue generation. According to Dutton et al. (2003), geological heterogeneity serves as a major control on reservoir production, and recharge estimation (McCord et al. 1997). The PZ-2 and PZ-4 wells penetrated section of the Agbada Formation. According to Lambertx-Aikhionbare and Shaw (1982) described the Agbada Formation as a sequence of alternating sandstones and shales deposited at the interface between the lower deltaic plain and marine sediments of the continental shelf fronting the delta. The aim of this work is to determine reservoir heterogeneity originating from petrophysical and facies variations, which may lead to better understanding of the flow behavior and management of the reservoir.

Fig. 1
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Map of Niger Delta depobelts showing the location of the studied wells (Doust and Omatsola 1989)

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Geological setting

Niger Delta Basin formation was initiated during the separation of African continent from South America in the Cretaceous times. In the Late Cretaceous, a proto Niger Delta first developed but ended with a major transgression in the Paleocene (Lambert-Aikhionbare and Shaw 1982). A regression occurred during the Eocene with the deposition of a wedge-fluvio-deltaic sediments which built out into the South Atlantic as the modern Niger Delta (Short and Stauble 1967; Burke et al. 1970; Lambert-Aikhionbare and Shaw 1982). Stratigraphic framework (Fig. 3) of the Niger Delta had been investigated by numerous researchers (Reijers 2011; Doust and Omatsola 1989; Short and Stauble 1967). They claimed that eustatic sea level changes, tectonics and climatic processes were responsible for various lithofacies development. Stratigrphically, three lithostratigraphic units are recognized in the Niger Delta; Akata Formation, Agbada Formation and Benin Formation (Short and Stauble 1967). The Agbada Formation has long been the focus of investigation due to its hydrocarbon richness, and most of these works were not bound in literatures. More so, focus on the heterogeneity of Agbada Formation sandstones has remained in infancy. Therefore, understanding of the reservoir for better petroleum play will open up a new front in the exploration and exploitation of hydrocarbon in the basin.

Methods of study

Forty three sandstone samples (cores) from PZ-2 well (2240.08–2243.63 m) and PZ-4 well (2222.07–2232.30 m) in the Niger Delta Basin were interpreted sedimentologically (Figs. 2, 3) and further subjected to petrophysical analysis (Tables 1, 2) using conventional porosimeter and permeameter. Pore matrix ratio (PMR), flow zone indicator (FZI) and reservoir quality index (RQI) were calculated using Amaaefule et al. (1993) equations (FZI = RQI/PMR) and reservoir quality index = 0–0314(k/Φ)0.5, respectively. k denotes permeability and Φ represent porosity. These datasets were plotted against various petrophysical data encountered and used to define the hydraulic flow units (Figs. 6, 7). Coefficient of variation by Moissis and Wheeler (1990), Corbet and Jensen (1992) was also employed for the determination of heterogeneity.

Fig. 2
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Mechanisms and units of delta evolution (after Reijers 2011)

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Table 1 Petrophysical data of PZ-2 well, Niger Delta
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Table 2 Petrophysical data of PZ-4 well, Niger Delta
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Results

Forty three core samples collected from PZ-2 and PZ-4 well were examined in details and characterized based on texture, sedimentary structures, and other sedimentary features (Table 3; Figs. 3, 4). Petrophysical data obtained from porosimeter and permeameater analysis of the sandstones are presented in Tables 1 and 2.

Table 3 Lithofacies characterization of sediments in PZ-2 and PZ-4 wells
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Fig. 3
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Lithological log of selected cores at different depths in PZ-2 well

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Fig. 4
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Lithological log of selected cores at different depths in PZ-4 well

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Petrophysical characteristics of PZ-2 and PZ-4 well

Porosity values (Tables 1, 2) range from 17.90 to 33.40%. This indicates good to very good porosity. Permeability values range from a minimum of 1.50–377 mD and indicates fair to good permeability in the PZ-2 well and in the PZ-4 well, porosity values range from 23.70 to 35.10%, mean porosity of 29.77%. Permeability values range from 2.20 to 5080 mD and a mean value of 1046.65 mD and indicate fair to good permeability. PZ-2 well exhibit correlation coefficient of 0.7868, indicating a better correlation than PZ-4 well with a correlation coefficient of 0.5014.

Reservoir heterogeneity

Several authors have used different techniques to determine reservoir heterogeneity; multivariate regression (Chen et al. 2015; Zang et al. 2018), Lorenz coefficient (Schmalz and Rahme 1950; Zang et al. 2018), coefficient of variation (Corbet and Jensen 1992; Lake and Jensen 1991) among others. The concept of Corbet and Jensen (1992) was adopted in the determination of heterogeneity. The Coefficient of Variation (CV) for porosity in the sandstones facies in PZ-2 well and PZ-4 well were 0.12 and 0.18 respectively. These results indicate homogeneous porosity. The CV values for permeability in the sandstone facies for both the PZ-2 and PZ-4 well are 1.40 and 0.53.These values indicate greater heterogeneous (Fig. 4) and homogeneous permeability. PZ-4 well has CV values of 1.33 for permeability in the bioturbated sandstone facies and this indicates great heterogeneity (Corbet and Jensen 1992). The CV values for permeability in the sandstone facies was 0.83 m and indicates heterogeneous. Sedimentologically, the bioturbated sandstone facies has a more heterogeneous attribute than the sandstone facies and may serve as a better reservoir candidate than the sandstone facies. The most heterogeneities permeability distribution occurs in the bioturbated sandstone facies (Fig. 5) in the PZ-4 well and sandstone facies in the PZ-2 well and are homogeneous in porosity (Fig. 5).

Fig. 5
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Facies derived log showing changes of coefficient of porosity and permeability variation in PZ-2 well

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Hydraulic flow units and implication for reservoir management

The flow units in the reservoirs in PZ-2 well and PZ-4 well were delineated based on the sedimentary facies, petrophysical characteristics, pore matrix ratio, and flow zone indicator. Integration of these parameters aided in the identification of four flow units in the PZ-2 well (Fig. 6) and three flow units in PZ-4 wells (Fig. 8). From the integrated simulated Figs. 7a–e and 8a–e shows the variation of FZI with the depth interval of 2223.42 m, 2224.67 m, 2226.68 m and 2229.06 m in PZ-2 well and 2240.40 m 2241.05 m and 2242.30 m in PZ-4 well, respectively. There was a sharp peak at the depth of 2224.34 and 2224.67 m in PZ-2 well and 2242.30 in PZ-4 well. Highest FZI peak was recorded at the depth of 2242.30 m in PZ-4 well. This is attributed to lack of pore filling clay, low tortuosity, and excellent reservoir quality and macroporous pore throat size of the sandstones (Table 5; Fig. 8). This zone contains 42.5% of oil saturation and water saturation of 20%. These features indicate a better reservoir and a moderate hydrocarbon recovery is envisaged. Four flow zones (Fig. 7) were delineated in PZ-2 well; FZ-1 (2229 m), FZ-2 (2226 m), FZ-3 (2224.67 m) and FZ-4 (2223 m) and three flow zones in the PZ-4 well include FZ-3 (2240 m), FZ-2 (2241 m) and FZ-1 (2242.30 m). Low FZI values were recorded at various depths in both wells due to fine grained nature of the lithofacies, high tortuosity and probably presence of pore bridging and pore filling clay (Amaefule et al. 1993; Kassab et al. 2017; Nabikhani et al. 2012).

Fig. 6
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Facies derived log showing changes of coefficient of porosity and permeability variation in PZ-4 well

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Fig. 7
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Hydraulic flow units in the PZ-2 well

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Fig. 8
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Hydraulic flow units in the PZ-4 well

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Discussion

Facies encountered in the PZ-2 well were grouped into (1) fine grained sandstone, (2) micaceous shale intercalated with sand, (3) micaceous shale with siltstone. Similarly, PZ-4 well consists of five lithofacies; (1) bioturbated fine grained sandstone, (2) bioturbated shaly sandstone, (3) laminated shaly sandstones, (4) sandstone and (5) shale with pyrite in PZ-4 well (Tables 3, 4). The sandstones are angular to sub rounded and well sorted. The shales are dark grey, micaceous, flaggy and indicates low energy regime of paleo-deposition. Porosity (coefficient of variation) in the PZ-2 and PZ-4 well has values of 0.12 and 0.18, respectively. These values suggest homogeneous porosity distributions. Permeability (coefficient of variation) in the PZ-2 well and PZ-4 well have values of 1.43 and 1.53, respectively. These values indicate very heterogeneous permeability (Figs. 5, 6). Generally, the petrophysical and lithofacies data shows that the Agbada Formation sandstones in PZ-2 and PZ-4 well represent homogeneous porosity to very heterogeneous permeability reservoirs. El-Deek et al. (2017) and Morad et al. (2010) noted that sedimentary structures, facies distribution, geometry, reservoir structural parameters and effects of diagenesis are key factors to reservoir heterogeneity. However, based on the lithological and petrophysical analysis of the core samples in the study area, heterogeneity variations in PZ-2 and PZ-4 wells can be attributed to lithofacies architecture (Figs. 3, 4), petrophysical qualities (Tables 1, 2, 3, 4, 5) and pore size geometry (El-Deek et al. 2014, 2017). In addition, on the scale of heterogeneity, Agbada Formation in both wells occur at mesoscopic to microscopic scales due to evidence of variable paleo-depositional environments (Table 3) and textural attributes. In addition, on hydraulic flow zones, FZ-3 in PZ-2 well were characterized by high permeability (217 mD), porosity (32.30%), water saturation (47.70%), hydrocarbon saturation (31.80%) and FZ-1 in PZ-4 well which has a higher permeability (5080 mD), porosity (32.1%), water saturation (24%), and hydrocarbon saturation (42.3%), were adjudged to be the most promising flow units respectively. Generally, within the context of sequence stratigraphic framework, the bioturbated sandstones and sandstones facies in the area of study display progradational stacking pattern (Table 3) based on their stratigraphic architecture and were interpreted as a product of lower shore face environment of deposition. According to Lipus (2015) progradational pattern leads to higher vertical connectivity than a retrogradational sequence, and a better dispersed sweep efficiencies may be expected from the facies due to macroporous throat size and good reservoir quality.

Table 4 Reservoir quality index (RQI), flow zone indicator (FZI) and pore matrix ratio (PMR) of PZ-2 well, Niger Delta
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Table 5 Reservoir quality index (RQI), flow zone indicator (FZI) and pore matrix ratio (PMR) of PZ-4 well, Niger Delta
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Conclusion

Lithofacies and reservoir heterogeneity in the PZ-2 well and PZ-4 well have been explored. PZ-2 well is composed of fine grained sandstone, micaceous shale intercalated with sand and micaceous shale with siltstone facies. PZ-4 well recorded five lithofacies: bioturbated fine grained sandstone, bioturbated shaly sandstone, sandstone, laminated shaly sandstone, and shale with pyrite deposited in a lower shore face environment of paleo-deposition. The bioturbated sandstones and sandstones facies are most porous, permeable and exhibit greater heterogeneous permeability and homogeneous porosity than other lihofacies encountered in the study area. Four flow zones were identified in PZ-2 well; FZ-1 (2229 m), FZ-2 (2226 m), FZ-3 (2224.67 m) and FZ-4 (2223 m) and three flow zones in PZ-4 well; FZ-3 (2240 m), FZ-2 (2241 m) and FZ-1 (2242.30 m). These flow zones are characterised by good reservoir qualities and adjudged as a better reservoir candidates for probable prospects.