**3.1 Environment of deposition**

The well log (gamma ray log) and drill-cutting samples are the major lithologic tools used to identify lithofacies in the field. Ditch cutting sample description (**Table 1**) [15] indicates that the N5.2 sand contains some glauconite pellets showing sedimentation within a marine environment. The depositional environments inferred using electrofacies and the presence of glauconite within the sample interval are; beach, barrier bar, shoreface and regressive bars [15]. The overall gamma ray trend shows an upward coarsening sequence.

**Figure 2.** *Seismic base map showing well locations and line of section.*

The log expression for the N5.2 sand exhibits blocky/cylindrical motif (**Figure 4**). It has a sharp base with a gradational top, about 70.08 m thick, excellent reservoir quality, good lateral continuity and displaying a layer-cake reservoir architecture deposited probably as barrier bar or a channel sitting on a beach-barrier system (**Figure 4**). There are particles of glauconite in the ditch cutting sample indicating that the sediments were deposited within the marine environment.

#### **3.2 Architecture and reservoir characteristics of the N5.2 sand**

#### *3.2.1 Architecture of the N5.2 reservoir*

The root-mean-square amplitude, a seismic attribute generated over the seismic volume at different timeslices is more diagnostic in facies identification. Generally, the RMS amplitude is an expression of the square root of the average of the squares of the amplitude within certain window of the analysis, and it is related to the energy within the seismic trace. The root-mean-square (RMS) are useful in differentiating between lithology types. For instance, values of the trace with high amplitudes may indicate a highly porous lithology such as porous sand, which are potential high quality hydrocarbon reservoirs. It can also serve as a direct hydrocarbon indicator. Three different color bands are used to indicate amplitude values: yellow indicates the highest amplitude (100 RMS value); light brown to red (50–68 RMS values), and the light green to blue colors represent the least to medium amplitude points (0–18, and 20–30 RMS) (**Figure 5**). The N5.2 sand falls within the Beach-Barriershoreface (BBS) RMS trend that aligned parallel to paleo-coastline direction (**Figure 5**) indicating a shallow marine depositional architecture. Depth structure map also indicated similar trend showing a four-way dip closure having two culminations and depositional axis parallel to the major structure-building fault (**Figure 6**).

#### *3.2.2 Reservoir characteristics of the N5.2 sand*

Well log attributes show that the N5.2 reservoir is a massive, clean and thick (about 70.08 m thick) barrier/shoreface shallow marine sandstone with excellent reservoir quality. Pixel-based facies modeling using sequential indicator simulation

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**Table 1.**

**Figure 3.**

(N5.2 reservoir) Well A2P2

**Reservoir Sample description**

*Ditch cutting description of the N5.2 reservoir [15].*

*Geologic Characteristics and Production Response of the N5.2 Reservoir, Shallow Offshore Niger…*

*(a) Well correlation of key reservoirs in the field and (b) well correlation of N5.2 reservoir across the field.*

Sandstone: medium to dark brown, oil saturated, clear, translucent, friable to loose quartz grains, very fine-fine grains, and predominantly very fine, sub-rounded to rounded, very well sorted, excellent porosity and permeability, contains mica with traces of glauconite, traces of carbonaceous speckles. Oil shows: medium brown oil stain, intense bright yellow fluorescence, instant blooming milky white cut fluorescence, light brown residue. Very strong hydrocarbon odor

*DOI: http://dx.doi.org/10.5772/intechopen.85517*

*Geologic Characteristics and Production Response of the N5.2 Reservoir, Shallow Offshore Niger… DOI: http://dx.doi.org/10.5772/intechopen.85517*

#### **Figure 3.**

*Sedimentary Processes - Examples from Asia, Turkey and Nigeria*

were deposited within the marine environment.

*Seismic base map showing well locations and line of section.*

*3.2.2 Reservoir characteristics of the N5.2 sand*

*3.2.1 Architecture of the N5.2 reservoir*

**Figure 2.**

**3.2 Architecture and reservoir characteristics of the N5.2 sand**

depositional axis parallel to the major structure-building fault (**Figure 6**).

Well log attributes show that the N5.2 reservoir is a massive, clean and thick (about 70.08 m thick) barrier/shoreface shallow marine sandstone with excellent reservoir quality. Pixel-based facies modeling using sequential indicator simulation

The log expression for the N5.2 sand exhibits blocky/cylindrical motif (**Figure 4**). It has a sharp base with a gradational top, about 70.08 m thick, excellent reservoir quality, good lateral continuity and displaying a layer-cake reservoir architecture deposited probably as barrier bar or a channel sitting on a beach-barrier system (**Figure 4**). There are particles of glauconite in the ditch cutting sample indicating that the sediments

The root-mean-square amplitude, a seismic attribute generated over the seismic volume at different timeslices is more diagnostic in facies identification. Generally, the RMS amplitude is an expression of the square root of the average of the squares of the amplitude within certain window of the analysis, and it is related to the energy within the seismic trace. The root-mean-square (RMS) are useful in differentiating between lithology types. For instance, values of the trace with high amplitudes may indicate a highly porous lithology such as porous sand, which are potential high quality hydrocarbon reservoirs. It can also serve as a direct hydrocarbon indicator. Three different color bands are used to indicate amplitude values: yellow indicates the highest amplitude (100 RMS value); light brown to red (50–68 RMS values), and the light green to blue colors represent the least to medium amplitude points (0–18, and 20–30 RMS) (**Figure 5**). The N5.2 sand falls within the Beach-Barriershoreface (BBS) RMS trend that aligned parallel to paleo-coastline direction (**Figure 5**) indicating a shallow marine depositional architecture. Depth structure map also indicated similar trend showing a four-way dip closure having two culminations and

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*(a) Well correlation of key reservoirs in the field and (b) well correlation of N5.2 reservoir across the field.*


**Table 1.** *Ditch cutting description of the N5.2 reservoir [15].* (SIS) algorithm for stochastic distribution of properties shows three distinct lithofacies (sand, siltstone and shale) in the reservoir across the field (**Figure 7**). These facies were defined based on log signatures, volume of shale cut-off, and

#### **Figure 4.**

*Gamma ray log motifs showing inferred depositional environments of the reservoirs.*

#### **Figure 5.**

*RMS amplitude showing facies trends and architecture. Hint: BBS indicates beach, barrier and shoreface architecture. The N5.2 sand falls within the BBS category.*

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**Figure 7.**

*Facies model showing lithofacies characteristics of N5.2 sand [25].*

**Figure 6.**

*Geologic Characteristics and Production Response of the N5.2 Reservoir, Shallow Offshore Niger…*

net-to-gross (NTG) calculations. The volume of shale (VSH), net-to-gross ratio (NTG) and total porosity (PHIT) from petrophysical evaluation were populated into the 3D grid facies model (**Figures 7** and **8**). Sand is the dominant lithofacies in

*Depth structure map for N5.2 reservoir in two structural culminations and a saddle.*

*DOI: http://dx.doi.org/10.5772/intechopen.85517*

*Geologic Characteristics and Production Response of the N5.2 Reservoir, Shallow Offshore Niger… DOI: http://dx.doi.org/10.5772/intechopen.85517*

net-to-gross (NTG) calculations. The volume of shale (VSH), net-to-gross ratio (NTG) and total porosity (PHIT) from petrophysical evaluation were populated into the 3D grid facies model (**Figures 7** and **8**). Sand is the dominant lithofacies in

#### **Figure 6.**

*Sedimentary Processes - Examples from Asia, Turkey and Nigeria*

*Gamma ray log motifs showing inferred depositional environments of the reservoirs.*

*RMS amplitude showing facies trends and architecture. Hint: BBS indicates beach, barrier and shoreface* 

*architecture. The N5.2 sand falls within the BBS category.*

(SIS) algorithm for stochastic distribution of properties shows three distinct lithofacies (sand, siltstone and shale) in the reservoir across the field (**Figure 7**). These facies were defined based on log signatures, volume of shale cut-off, and

**16**

**Figure 5.**

**Figure 4.**

*Depth structure map for N5.2 reservoir in two structural culminations and a saddle.*

**Figure 7.** *Facies model showing lithofacies characteristics of N5.2 sand [25].*

the reservoir (**Figure 5**) with over 83% NTG and negligible volume of shale (VSH) (**Figure 7**). This implies that the reservoir flow mechanism will be influenced by the properties of the sand facies.

**Figure 8.** *Porosity model for N5.2 sand.*

**19**

**Figure 11.**

**Figure 10.**

*Winland plot for the N5.2 sand.*

*Geologic Characteristics and Production Response of the N5.2 Reservoir, Shallow Offshore Niger…*

Dykstra-Parson's coefficient is an expression that measures the degree of variation and heterogeneity of a reservoir [26]. The variation in the values of the core permeability reflects the degree of heterogeneity in the reservoir. Rock samples with zero permeability values (shales) were not used since it is a logarithmic plot. The Dykstra-Parson plot performed for the core samples from the well section is shown in **Figure 9**. The Dykstra-Parson's number for the core samples is 0.30—which indicates a homogenous reservoir. Higher values of Dykstra-Parson indicate more

*RQI versus normalized porosity crossplot. Note that most of the samples have high quality index with RQI* 

*above 100. This is indicative of a high quality formation with high hydraulic potential.*

*3.2.3 Test for heterogeneity and flow unit characterization of the N5.2 sand*

*DOI: http://dx.doi.org/10.5772/intechopen.85517*

heterogeneity of which one is the maximum number.

**Figure 9.** *Dykstra-Parson plot for heterogeneity test (N5.2 VDP = 0.3).*

*Geologic Characteristics and Production Response of the N5.2 Reservoir, Shallow Offshore Niger… DOI: http://dx.doi.org/10.5772/intechopen.85517*
