Petrophysical Analysis of Reservoirs Rocks at Mchungwa Well in Block 7 Offshore, Tanzania: Geological Implication on the Reservoir Quality

The present work highlights the results of the study conducted to estimate the petrophyiscal properties of the Mchungwa well with the aim of assessing the quality of reservoirs rocks. A set of well logs data from Mchungwa well were used for the analysis that involved identification of lithology, hydrocarbon and non-hydrocarbon zones and determinations of petrophysical parameters such as shale volume, porosity, permeability, fluid saturation and net pay thickness. This study was able to mark six sandstone zones with their tops and bases. Of the six zones hydrocarbon indication was observed on four zones from which estimation of petrophysical parameters was done to assess the reservoirs quality. The petrophysical parameters across the four reservoirs yield an average shale volume ranging from 0.08 to 0.15 v/v. The porosity ranges from 7% to 23%, indicating a fair to good porosity sandstone, while permeability ranges from 0.01 to 6 mD. The porosity and permeability results suggest that the quality of the sandstone reservoirs identified at Mchungwa well is poor. Fluid types defined in the reservoirs on the basis of neutron-density log signatures and resistivity indicate a mixture of water and gas. However, high water saturation (50% 100%) indicates that the proportion of void spaces occupied by water is high, thus, indicating low hydrocarbon saturation of 2.4%, 17.9%, 19.2% and 39.3%. Generally the results show that hydrocarbon potentiality at Mchungwa well is extremely low because of small net pay thickness and very low hydrocarbon saturation. This could be attributed to the geology of the surrounding area where low hydrocarbon saturation suggest the presence of non-commercial volumes of either migrant gas or gas generated from the interbedded claystone sediments, which are dominant in the observed well.


Introduction
Tanzania deep offshore basins are part of the Tanzania coastal basin formed as a result of Gondwana break-up and drifting of Madagascar with respect to the African continental block during the Early Mesozoic time. The exploration Block 7, where Mchungwa well is located, forms part of the deep offshore basins that are known to be petroliferous for hydrocarbon exploration [1] [2]. This is evident by the presence of hydrocarbon shows both at the surface and subsurface in different parts around the surrounding area. The basins occur parallel to the coast and are joined with large, down-to-the-basin faults, which demarcate the present coastline ( Figure 1).
The basins are mainly composed of thick Mesozoic and Tertiary successions with approximately 4000 m thickness, which overlap the continent-ocean boundary [3] [4] [5]. Several Mesozoic-Tertiary potential marine organic-rich source rocks are present and four regional potential source intervals have been recognized [2] [6]. These include Cretaceous sandstone, a regional proven reservoir, and Tertiary deltaic sandstones and limestone are local proven reservoirs. Cretaceous siltstones and shale are regional seals and Jurassic evaporates provide local effective seals.
Despite the presence of hydrocarbon discoveries in various parts along the Tanzania  This study therefore uses well log data to study the petrophysical characteristics of the reservoir rocks at Mchungwa well in Block 7 in order to assess the quality of the reservoirs encountered in the well. Results from this study advance our understanding on the relationship between the petrophysical properties and hydrocarbon system of the offshore Block 7 and in other nearby blocks. Moreover, the petrophysical information obtained from Mchungwa well provides vital information on the quality of reservoirs and also a source of information to further exploration in relation to the geological processes.  [9]. The continental margins of the fragmented continents underwent gradual thermal subsidence during the Bajocian where by restricted marine syn-rift sediments were deposited into the basin, flooding the intra-continental Karoo sequence. The accumulation and preservation of marine organic matter into this restricted marine basin forms the primary source rocks for the margin [9]. The final phase of the Gondwana breakup is characterized by the termination of tectonic activity and the formation of passive margins of the Somali Basin [9].

Geology and Tectonic
Regional structural trends of Tanzania coastal and offshore basins follow the Tanga and Lindi Permo-Triassic faults, which strike in the NNE-SSW and NNW-SSE respectively, with some young onshore faults oriented along the same trends. The offshore structures are post Karoo faults whose trends have been rejuvenated from older ones. The orientation of structural features runs parallel to the present coastline [9] [11].

Local Geological Setting
Block 7 is located offshore northern Tanzania

Lithological Identification from Gama Ray (GR) Log
The gamma ray (GR) log measures the natural radioactivity of the formation in the borehole versus depth. The lithological identification was done by reading API values on the gamma ray curve. In the curve the shale free lithology like sandstone and carbonate show low gamma ray values (≤60 API) whereby shale (black shale and marine shale) exhibit relatively high GR count rates (≥60 API) ( Figure 2) due to presence of potassium ions in their lattice structure [14].

Lithological Identification from Photoelectric Factor (PEF)
The PEF log is sensitive to differences in the mean atomic number of the formation and it is insensitive to the porosity and fluid saturation of that lithology, which makes the PEF log a good indicator of lithology. The response of the tool to common rock types used in lithology identification is given in Table 1 [15].

Lithological Identification from Neutron-Density Logs
A combination of neutron and density logs were sketched together in the same track, and low values on both logs represents sandstone formation, overlap of the two log curves indicates limestone lithology and high values on both logs indicate shale lithology. In addition to using neutron-density logs separation for differentiating two lithology, in this study the logs were also used to create a neutron-density cross plot. The cross plots were obtained by plotting together neutron and density logs where sandstone, carbonate and shale lithology were displayed. Observing points falling within a lithology region and using gamma ray log scale, rock types were identified.

Reservoir Identification
Reservoir rocks, which are porous and permeable sedimentary rocks containing water, oil or gas in their pore spaces, were identified using the gamma and the porosity (neutron-density) logs. Common reservoir rocks are sandstones and carbonate. Sandstone reservoirs exhibit very low radioactivity, because of low concentrations of radioactive elements [16] [17]. Porosity tools are also important in locating reservoir zones in a sense that each porosity tool should give a reading in porous zones which, when converted to porosity as a function of lithology, will show the same porosity in reservoirs free of gas and clay effects [17].

Fluid Type Identification
Reservoirs may contain water, hydrocarbons or both and in this context it is therefore important to identify which type of fluid is contained in the reservoir.
Resistivity logs were used to distinguish between water bearing zones, and hydrocarbon bearing zones while porosity logs were used in identifying hydrocarbon interval especially gas bearing interval.
In hydrocarbon bearing formations, the resistivity log signatures show higher resistivity values than in water bearing formations. In gas zones, neutron log records lower hydrogen content, thus a higher count rate resulting in low porosity

Shale Volume Estimation
The shale volume was calculated using the Larionov [18] model (Equation (1) where SH V is the shale volume and GR I is the gamma ray index which was obtained using Equation (2).
where I GR is gamma ray index, GR log is the gamma-ray reading for each zone, GR min and GR max are the minimum and maximum gamma-ray values for clean sand and shale respectively.

Porosity Determination
In this study total and effective porosities of the selected reservoirs zones were calculated using density logs. These parameters are determined by substituting the bulk density readings obtained from the formation density log within each reservoir into Equation (3). In the equation, the formation bulk density ( b ρ ) is related to formation matrix density ( ma ρ ) and formation fluid density ( f ρ ) as follows.
where φ is total porosity, ma ρ is matrix (or grain) density for sandstone, b ρ is bulk density from log, f ρ is fluid density.

Water Saturation Determination
Determination of water saturation is the key parameter from which initial hydrocarbon in place can be estimated during formation evaluation. In this study, the Archie's and Indonesia's models were used to calculate water saturation depending on whether the reservoir is clean sand or shaly sand and their results were compared.

Archie Equation Model
This is the common model that is used to calculate water saturation in clean lithology (i.e., clean sand or carbonate). Archie's equation used for determination of water saturation is given in Equation (4) where w R is the water resistivity at formation temperature, t R is the true resistivity, m a φ is the formation factor (F) in which "a" represents constant related to texture, (assumed to be approximately 1 for sandstone), "ϕ" is the porosity, "m" is the cementation exponent and "n" is the saturation exponent.

Indonesian Model
Indonesian model introduced by Poupon and Leuveaux [20] is used to calculate the water saturation in shaly sand reservoirs. The main inputs are the effective porosity (ϕ e ), shale volume (V sh ), shale resistivity (R sh ), water resistivity (R w ) and deep resistivity (R t ). It is given in Equation (5) below.

Net Pay
A porosity cut-off of 10% as minimum value and 25% as a maximum value, along with a shale volume cut-off of 0% as minimum value and 25% as maximum value were used to define the quality of the reservoir rock. Water saturation cut-off value of 50% was used to define pay zone. The reservoirs were defined by the porosity greater than 10% and shale volume less than or equal to 25%. For the net pay, if the water saturation within the reservoir is less than 50%, the reservoir is considered to contain hydrocarbon.

Hydrocarbon Saturation (Sh)
This is the amount or percentage of hydrocarbon that occupies the pore space computed by subtracting the percentage of water occupying the pore space (water saturation) from 100% as indicated in Equation (6) below.

Permeability Estimation
The permeability of each delineated reservoir at Mchungwa well was estimated using equation below [21].
where K is the permeability in mD, φ is Effective porosity in v/v and wir S is the irreducible water saturation in v/v. In this study the permeability was estimated first by using the calculated water saturation, and then the results were compared with those estimated from Crain's method [22] using irreducible wa-

Lithology Results
Three main lithologies are identified at Mchungwa well, which include shale, sandstone and little carbonate from lithology identification logs (gamma, neutron-density combination, cross plot and photoelectric factor (PEF)). Six (6) clean sand formations marked as zones A, B, C, D, E and F with their depth range have been identified and presented in Figures 3-8 and Table 2.

Hydrocarbon and Non-Hydrocarbon Bearing Zones
Hydrocarbon zones were identified qualitatively by using neutron-density logs combination and resistivity logs. Based on visual observation from these logs, four zones marked by C, D, E and F among six selected reservoir zones were identified as gas bearing zones. These zones were identified depending on the presence of neutron-density crossovers and high resistivity values in these zones,

Quantitative Interpretation
Average petrophysical values for each reservoir are shown in Table 3    The dominant free shale lithology is sandstone, which is interbedded with shale, in some intervals, while other intervals the PEF value indicates the presence of carbonate lithology (limestone and dolomite), which probably occurs as cement in sandstone. However, core data and core cuttings are needed for final verification but these were not included in the study. Therefore, to minimize uncertainties in interpretation, lithology type has been narrowed down to sand and shale lithology.

Reservoir and Hydrocarbon Zones
The reservoir zones were identified qualitatively by marking the clean sand

Net Thickness and Hydrocarbon Potentiality
The four selected reservoirs were analyzed quantitatively to estimate the values of shale volume, porosity, and fluid content through the use of empirical equations described in the methodology section. The net thicknesses of these four reservoirs after applying shale volume and porosity cutoff value were determined and indicated that sandstone reservoir in Zone F is thicker than other three zones (Table 3). However, after applying the water saturation cutoff value of 50% in order to define the net pay thickness (the economic zone with high hydrocarbon amount) Zones C and D gave zero net pay thickness. This indicates that Zones C and D contain more than 50% water implying that they are non-economical hydrocarbon zones. These zones are also characterized by thin/small crossovers and relative low resistivity values, which could be interpreted as the presence of an extremely low amount of gas but these crossovers could also be attributed to other factors. In some cases crossovers can arise from lithological differences as scaling effect where it could be sandstone recorded on limestone scale, or limestone recorded on dolomite scale [23].

Geological Implication on the Petrophysical Properties
Petrophysical results at Mchungwa well is strongly affected by the regional and local geology of the area, so these results could be used to visualize and give broad context for the reservoirs' quality in the nearby area. High shale volume in Zone C (Maastrichtian Sandstone) was deposited during Late Cretaceous major transgression period where marine argillaceous sediments were frequently deposited with turbidity sandstones than sandstones deposited in Early Cretaceous However, a regional decrease in porosity value could be due to cementation caused by dewatering of the thick sequence of Hauterivian to Campaanian hemi-pelagic claystone, which surround porous Albian sand and underlie the Maastrichian sand. Cementation by dewatering of the hemi pelagic claystone could also be the major reason for low permeability in the well. High water saturation in the identified sandstone reservoir sections and low hydrocarbon concentrations suggest the presence of non-commercial volumes of either migrant gas or gas generated from the interbedded claystone sediments which are dominant observed in the well.

Conclusion
Qualitative and quantitative interpretations of petrophysical properties of the reservoirs from well logs analysis in this study were successfully done. Results is also observed that, the quality of the reservoirs decreases with depth, most likely due to the diagenesis and compaction associated with depth of burial of the older sediments during deposition. Generally, the field under study does not have good prospect for exploration and production because of the high level of water saturation and consequently low hydrocarbon saturations. However, the petrophysical information obtained from Mchungwa well provides vital information on regional geologic variability to enable further exploration in Northern offshore blocks in Tanzania.