Petrophysical Characterization and Flow Models for Agbada Reservoirs, Onshore Niger Delta, Nigeria

Corresponding Author: Prince Suka Momta Department of Geology, University of Port Harcourt, Nigeria Email: princemomta@yahoo.com Abstract: Three selected reservoirs (XB, XC and XE) from three wells (A, B and C) occurring within the Agbada producing sands in part of the Greater Ughelli Depobelt of the onshore Niger Delta have been studied. The study aims at evaluating the petrophysical characteristics of the sandbodies and also identifies the various flow units present within each reservoir. Petrophysical parameters were used as input data to generate the Stratigraphic Modified Lorenzo Plots (SMLP). This model uses a graphical method to quantitatively determine flow units and to understand the flow and storage capacities of sedimentary rocks. Results of the analysis shows that average porosity and permeability range is between 7-28.8% and 1.20529 mD, indicating poor to very good reservoir quality in different parts of the field. Generally, porosity and permeability decrease with increasing depth in the field reflecting burial diagenetic porosity loss in response to increasing thermal exposure with depth. Porosity and permeability change laterally across the field from west to east. Increase in porosity and permeability towards the eastern part of the field reflects lateral change in facies. Well C has the best porosity (28%) and permeability (529 mD), lowest water saturation (0.01), hence, highest hydrocarbon prospect. The stratigraphic Modified Lorenzo Plots (SMLP) revealed a total of seventy five (75) Flow Units (FU) in the three studied reservoirs. Each reservoir displays similar flow pattern relative to others suggesting that facies (rock properties) have a strong control on flow in each reservoir. Generally, poor quality units occur towards the bottom of each reservoir in a well and good quality units towards the top. The dominant flow units in the three reservoirs fall within the high storage and flow (normal flow unit) unit category, suggesting that the dominant depositional setting (shallow marine shoreface/beach/barrier) and facies type beside diagenetic effects play significant role in fluid dynamic behaviour of any rock body. Depositional environments and subsequent diagenesis are the primary factors controlling porosity distribution, pore connectivity and fluid flow in the three studied reservoirs.


Introduction
The study area falls within the onshore portion of the Niger Delta sedimentary basin in the Greater Ughelli depobelt. The Agbada stratigraphic unit forms the hub of oil and gas accumulation in the basin. Extensive studies have been carried out that gave insight into the gross depositional setting of the foreset beds of the Agbada reservoirs (Amajor and Agbaire, 1989;Reijers, 2011;Arochukwu, 2014). In the past one decade there had been slow exploration activities in the basin. Efforts have been concentrated on developing and producing from proven reserves in the various oilfields. This provided more job opportunities for reservoir engineers, production engineers, development geologists and petrophysicists than exploration geoscientists. Modern geostatistical computer software has also improved the understanding of reservoir conditions through modeling and simulation. Petrophysical parameters serve as input data that help in building these models that have given much insight into reservoir condition and improved oil and gas production.
The concept of hydraulic flow unit and petrophysics have been well documented in recent time (Amaefule et al., 1993;Abbaszadeh et al., 1996;Gunter et al., 1997a;1997b;Porras et al., 1999;Al-Ajmi and Holditch, 2000;Yasin et al., 2001;Rushing and Newsham, 2001b;Aguilera and Aguilera, 2002;Civan, 2003;Tiab and Donaldson, 2004;Perez et al., 2005;Taslimi et al., 2008;Bhattacharya et al., 2008;Rahimpour-Bonab et al., 2012). In this study, the Stratigraphic Modified Lorenzo Plots by Gunter et al., (1997a) and adopted by Rahimpour-Bonab et al. (2014), will be adopted to identify flow units and also to understand the hydraulic behaviour of sand-bodies deposited within a specific depositional environment. Fractional flow capacity and storage capacity values are determined from inflection points on the Lorenzo plot, which correspond to changes in flow capacity or storage capacity associated with factors that affect reservoir quality. These changes are interpreted as flow units within the reservoir (Gunter et al., 1997a;Lawal and Onyekonwu, 2005;Rahimpour-Bonab et al., 2014). The Gunter et al. (1997a) model used a graphical method to quantitatively determine flow units. Petrophysical data will be used to accomplish these plots to understand the flow and storage capacities of sedimentary rocks.
Petrophysical parameters that will be generated from wireline logs (comprising of Gamma Ray, Resistivity, Neutron, Density and Sonic) include; true formation resistivity (R t ), formation water resistivity (R w ), formation factor (F), water saturation (S w ), irreducible water saturation (S wirr ), Bulk Volume Water (BVW), porosity and permeability. Deductions from the analysis and interpretation of petrophysical parameters will be useful in oil and gas production and reservoir management.

Geological Setting
The evolution of the Niger Delta sedimentary basin is controlled by pre-and synsedimentary tectonics as described by (Evamy et al., 1978;Ejedawe, 1981;Knox and Omatsola, 1989;Stacher, 1995;Reijers, 2011). The embryonic delta that developed following the subsidence that occurred down dip of the Upper Cretaceous Anambra basin during the Eocene time has continued to grow seaward from one time to the other. The growth and further development of the delta have been accentuated by high sediment supply, climatic factors and proximity of provenance areas. Initial sediment deposition during the Middle-Late Eocene time was towards the west of the inverted Cretaceous Abakaliki High and south of the Anambra Basin (Reijers, 2011). Studies by (Weber and Daukuro, 1975;Ejedawe, 1981;Ejedawe et al., 1984;Reijers, 2011), showed that the embryonic delta subsided during the Late Eocene to Middle Oligocene <700 m/Ma and prograded approximately 2 km/Ma along three depositional axes that fed irregular, early delta lobes that eventually coalesced. Recent study by Durogbitan (2014) has corroborated the fact that during the Miocene the delta was at the lowstand and experienced high fluvial incision that led to the formation of most of the channels (Opuama). He argued that the delta at that time was actually fluvial-dominated which does not actually portray the picture of the present day wavedominated delta. Adojoh et al. (2014), demonstrated from palynology point of view that hinterland pollen and very fine sand and siltstones have been deposited during dry climatic periods. Momta and Odigi (2014), described the Lowstand Systems Tracts (LST) associated with shallow marine Tortonian section of the Eastern Niger Delta, as being fluvially-induced rather than a deep sea turbidite LST. The progradation of the Niger Delta has continued from the Eocene to the present day with an advancing coastline.
Three diachronous stratigraphic units have been identified in the subsurface of the Niger Delta. The basal unit is the Akata shale of Eocene age, which is believed to be the stratigraphic equivalence of the exposed Paleocene Imo shales north of the Niger Delta, Reijers (2011) and the major source rock. The Agbada Group, Reijers (2011), which is a sequence of shale and sand in almost equal proportions overlies the Akata group, Reijers (2011) and constitutes majorly the hydrocarbon producing portion of the delta. The youngest Benin Group is the topset portion of the delta made of majorly very coarse grained loose sands with gravels, peat/wood materials and minor clay intervals. Eleven megasequences have been identified beginning from the Northern Delta Depobelt to the Coastal Swamp Depobelt based on the presence of regionally continuous transgressive shales that contain distinct biostratigraphic records. The youngest of this shale is the Bolivina 46 shale (Qua Iboe Shale) which also continued up to the shallow offshore area in the eastern part of the Niger Delta.

Materials and Methods
This study examined three selected reservoirs (XB, XC and XE) from three wells designated A, B and C. A suite of well logs consisting of Gamma Ray (GR), resistivity (ILD), Neutron, Density and Sonic were provided for this study. Petrophysical parameters were deduced from log data and used to characterize the reservoirs. Poroperm calculations were basically based on the Archie's petrophysical equations (Archie, 1950). Gamma ray log gives information on the lithology types encountered in the field. Petrophysical parameters were first generated for the three selected reservoirs using well logs. The Gunter et al. (1997a), method was adopted to subdivide the reservoirs into Flow units. Flow unit demarcation is useful in reservoir modeling and flow simulation (Amaefule et al., 1993;Bhattacharya et al., 2008;Rahimpour-Bonab et al., 2012;. Gunter et al. (1997a;1997b) presented a graphical method for quantifying the flow units according to the petrophysical rock/pore types, flow and storage capacities (Kh) and (Фh) and reservoir process speed (K/Ф). In this study, the minimum numbers of static flow units have been determined using the static reservoir rock properties such as log poroperm values. A Stratigraphic Modified Lorenz Plot (SMLP) was generated using cumulative flow capacity (Khcum) and cumulative storage capacity (Фhcum). The flow capacity (Kh) and storage capacity (Фh) are functions of permeability and porosity values considering their sampling depths (Equation 1 and 2). The values of cumulative flow and storage capacities were determined using Equation 3 and 4 (Rahimpour-Bonab et al., 2014;Gunter et al., 1997a):

Study Location
The study area is an onshore Niger Delta field, located in the Greater Ughelli Depobelt (Fig. 1). Three wells (A,B and C) ( Fig. 1) studied in the area are separated at a distance of about 8 km between A and B, B and C and about 15.2 km between A and C covering an area of approximately 18.9 Sq.km ( Fig.  1). The wells are separated by a set of minor faults and two major faults (red curved lines in Fig. 1) that appear to be regional as represented on the base map. These faults followed the growth faulting pattern of the Niger Delta as observed on seismic section.

Fig. 1. Map showing study area and well locations
The main body of the study area is dissected by several minor to intermediate faults which do not presently appear to impede fluid communication within the major reservoirs.

Reservoir Quality Assessment
Petrophysical evaluation of three reservoirs (XB, XC and XE) carried out shows average porosity and permeability range to be between 7-28.8% and permeability 1.20-529 mD (Table 1). This implies that the reservoir property ranges from poor to very good at different parts of the field. Generally, porosity and permeability decrease with increasing depth in the field. This trend reflects burial diagenetic porosity loss in response to increasing thermal exposure with depth (Ehrenberg and Nadeau, 2005). It is also observed that porosity and permeability change laterally across the field from west to east. Wells A and B have the poorest porosity and permeability. They occur towards the western part of the field. This increase in porosity and permeability towards the eastern part of the field reflects lateral change in facies. Well A occurred towards the basin-ward side of the field and may indicate that there is a shift from lower marine mud/silt dominated environment to the shoreface/coastal environment where porosity is high. Well C has the best porosity and permeability, lowest water saturation, hence, highest hydrocarbon prospect. The density-neutron crossover is also detected in well C showing the presence of a gas cap. This occurs at depth 3350 m (Table 1).

Reservoir XB
This reservoir has a funnel shaped GR log motif indicating an upward coarsening sequence of increasing grain size (Fig. 2). It occurs at a depth of about 2835 m in well A, 2760 m in B and 2680 m in well C. It has a range of porosity between 7-13% and average porosity of 9.37% (Table 1) in well A. Its permeability is between 0.4 to 3.6 mD and average permeability of 1.2 mD. Water saturation is very high, average of 88%. This reservoir has low hydrocarbon potential with its high water saturation content. In well C, there is an increase in porosity and permeability. Neutron-Density corrected porosity range is between 15-46% and average porosity is 28.8%. Permeability range is between 55-1673 mD with average value of 529 mD. Average water saturation is 1.9%. Reservoir XB in well C shows great hydrocarbon prospect with its good to very good petrophysical characteristics.

Reservoir XC
This also displays a funnel shaped GR motif. It shows a prograding stacking pattern of a sand body increasing in grain size upward. This unit is similar to XB and XE. The top of reservoir XC occurred at 3040, 2925 and 2825 m in wells A, B and C, with average thickness of 122 m. Its range of porosity and permeability in well A is between 5.6-9.2% and 0.3-0.8 mD. Average porosity and permeability is 7.8% and 0.5 mD. It has high water saturation in well A and less hydrocarbon potential. No geophysical measurement was done for this reservoir in well B. In well C, its average porosity and permeability are 24.4% and 270.7 mD. Water saturation is very low (1.1%). The depositional setting of this sand-body might be mouth bars, interdistributary beach and deltaic front facies (upper shoreface).

Reservoir XE
This reservoir also displays a coarsening upward trend. It occurs in all the wells with thicknesses of 55, 65 and 95 m in wells A, B and C. Top of this reservoir occurs at 3610, 3455 and 3245 m. The GR log motif displays a serrated funnel shape trend indicating progradation with within impacts of tidal activities. It represents deposit within the delta front environment. Porosity and permeability values in well A show an average of 11.5% and 0.57 mD. Water saturation is 86%. In well B, porosity and permeability range is between 0.7-10.3% and 0.2-8.8 mD. Average water saturation is 50% (Table 1). In well C, porosity and permeability is good with an average of 11.6% and 56.6 mD. Water saturation is very low, 0.9%. This reservoir has a tendency of producing more water than hydrocarbon in well A and B and more hydrocarbon than water in well C.

Sedimentology and Depositional Environments
The Gamma Ray log trends have been used to infer both lithology types and gross depositional environments of the three sand bodies. The general trend for the reservoirs shows a coarsening upward gamma ray log motif, indicating an increase in grain size (Fig. 2). Environments that display this attribute range from beach, barrier to upper shoreface deposits. Gamma Ray (GR) with 100°API and above contains majorly a clay/mud or shale-dominated environments. Gamma ray values below 75°API tend towards sand. Quantitatively, GR log have been used to compute values for gamma ray index and consequently for volume of shale (Vsh).

Volume of Shale (Vsh)
The plot for volume of shale shows a high percentage of shale towards the lower part of Reservoir XE in well B (Fig.  3). The observed depositional setting is the main controlling factor for Vsh distribution in this reservoir. The selected reservoirs have similar trend and may represent similar depositional setting, probably upper shoreface or regressive bars (barrier bars). The lower portion of the reservoir may represent a lower shoreface/shoreface transition environment dominated by mud/silty and very fine grained sandstones. The three reservoirs may likely exhibit similar flow behaviour due to their similarities in electrofacies trend (Fig. 2) and flow plots, though may vary in saturation types and amount. Higher flow will be experienced towards the top of the reservoirs.

Flow Unit Determination
A total of seventy five (75) Fig. 4-10); baffle units, with low flow capacity and high storage capacity; and finally, barrier units, containing impermeable units with very low flow and storage capacities. The slope of each segment is indicative of the flow performance in the reservoir (Gunter et al., 1997a). Steep slopes are indicative of permeable and high performance flow units (Rahimpour-Bonab et al., 2014) and gentle slopes or horizontal segments are representative of low permeability units or flow barriers.
The normal flow units as mentioned above have approximately equal flow and storage capacities. They are recognized with it straight or high angle gradient (about 15 or 345° from the normal) on the SMLP. This unit occurs in all the reservoirs and in all the wells (Fig.  4a-10). There are about thirty-eight (38) units that exhibit this flow and storage capacities. In well A, reservoir XB, they occur in FU1, FU2, FU3, FU4, FU7, FU8 and FU9; in reservoir XC, they occur in FU1, FU3, FU4, FU11; in reservoir XE as FU2, FU3, FU4, FU6, FU8 and FU9 (Fig. 4a-10).

Discussion
In well B (XB and XE include: FU1, FU2 FU4 and FU1 FU3, FU4, FU5, FU6, FU8) and finally, in well C, they include FU1, FU3, FU4, FU5, FU6, FU8, FU9 (Reservoir XC) and FU2, FU3, FU4, FU5, FU6 (reservoir XE), Fig. 4-10. It is obvious that the units with the highest flow and storage capacities dominate in all the reservoirs. This shows that sediments deposited within shallow marine beach, barrier and shoreface environments as indicated by the log motif (Fig. 3) have good reservoir qualities. The general trend of the speed velocity, a ratio of permeability and porosity (Table 2-7), increases towards the top of the reservoirs. The speed velocity gives information about the pore throat characteristics. This implies that megaporous units are developed towards the top of the reservoirs.
The baffle units have low flow and high storage capacities (FU10, FU12 (well A reservoir XB), FU5, FU7 (A, XC), FU1 (XE); well B contains FU5, FU7 (in XB), FU7 (in XE); well C has FU10 in XC and FU1 and FU8 in reservoir XE (Fig. 4-10). The baffle units are: FU5, FU6; FU2, FU6, FU8, FU9, FU10 in reservoirs XC and XE for well A. Well B has FU3, FU6; FU2, FU9 (for reservoirs XB and XE); FU2, FU7; FU7 for well C, reservoirs XC and XE (Fig. 4-10). This unit shows areas with very low porosities and permeabilities. This may have been caused by the presence of shale that occurred as intercalations in the reservoirs and also the lower part of the reservoirs stratigraphically fall within the lower shoreface dominated by silty/mud or shaly facies. The slope of this unit on the SMLP is very low (horizontal or almost horizontal).

Conclusion
Depositional environments and subsequent diagenesis are the primary factors controlling porosity distribution, pore connectivity and fluid flow in the three studied reservoirs. The increase in porosity and permeability towards the eastern part of the field reflects lateral change in facies. Well A occurred towards the basin-ward direction in the field and may indicate a shift from mud/silt dominated environment to shoreface/coastal environment where porosity is high. Well C has the best porosity and permeability, lowest water saturation, hence, highest hydrocarbon prospect. The density-neutron crossover is also detected in well C showing the presence of a gas cap.
The stratigraphic Modified Lorenzo Plots (SMLP) revealed a total of seventy five (75) flow units (Table 8) in the three studied reservoirs. Each reservoir displays similar flow pattern relative to others suggesting that facies (rock properties) have a strong control on flow in each reservoir. Generally, poor quality units occur towards the bottom of each reservoir in a well, whereas good quality units occur towards the top. The dominant flow units in the three reservoirs fall within the high storage and flow (normal flow unit) unit category, suggesting that the dominant depositional setting (shallow marine shoreface/beach) and facies type play significant role in fluid dynamic behaviour of sedimentary rock bodies.