RESERVOIR CHARACTERISTICS AND PALAEO-DEPOSITIONAL ENVIRONMENT OF DUSKI FIELD, ONSHORE, NIGER- DELTA, NIGERIA

The Niger Delta is a prolific hydrocarbon producing belt in the southern Nigeria sedimentary basin on the continental margin of the Gulf of Guinea. This study used well log suites to delineate the hydrocarbon reservoirs, depositional environments and lithostratigraphy of the Duski Field, Onshore Niger Delta, Nigeria. A comprehensive interpretation of the three wells revealed five (5) reservoir units with low volume of shale and thickness variations between 24m and 60.20m. The average porosity values ranged from 12% to 34%, with high hydrocarbon saturation in all the reservoir sands. Generally, porosity and permeability values decrease with depth in all the wells. Cross-plots of water saturation (Sw) and porosity ( ) (Buckles plot) revealed that some reservoirs were at irreducible water saturation; hence producing water-free hydrocarbons. Therefore the hydrocarbon accumulation of this field is commercially viable and promising. This study revealed that the reservoir sand units were deposited within marginal marine depositional environment which include fluvial channel, transgressive marine, progradational and deltaic settings.


INTRODUCTION
The Niger Delta Basin occupies the Gulf of Guinea continental margin in equatorial West Africa between Latitudes 3 0 and 6 0 N and Longitudes 5 0 and 8 0 E. It ranks among the world's most prolific petroleum producing Tertiary Deltas (Kulke, 1995). The stratigraphy, sedimentology, structural configuration and palaeoenvironment of the Niger Delta have been discussed by various workers (Short and Stauble, 1967;Weber, 1971;Weber and Daukoru, 1975;Evamy et al, 1978;Nton and Adesina, 2009) among others. Doust and Omatsola (1990) noted that from the Eocene to the present, the delta has prograded southwestwards, forming depobelts, which represents the most active portion of each stage of the development of the delta. According to Kulke (1995), the Niger Delta contains only one identified petroleum system referred to as the Tertiary Niger Delta (Akata-Agbada) petroleum system. The Niger Delta province is ranked the twelfth richest petroleum province with 2.2% of the world's discovered oil and 1.4% of world's discovered gas by the US Geological Survey's World Energy Assessment (Klett et al., 1977).
In the Niger Delta, petroleum is produced in sandstone and unconsolidated sands of the Agbada Formation. This formation is characterized by alternating sandstones and shales with rock units varying in thickness from 30m to 4600m (Short and Stauble, 1967). The sandstones in this Formation are the main hydrocarbon reservoirs with shale providing lateral and vertical seals. Petrophysical interpretation of logs plays an important role in the discovery and development of petroleum and natural gas reserves. It also helps to correlate zones, assist in structural mapping, identification of productive zones, determination of depth and thickness of zones to distinguish between oil and gas or water in a reservoir and to estimate hydrocarbon reserves (Darwin and Singer, 2008).
This study provides a better understanding of the reservoir properties (porosity, permeability) and related sedimentological features likely to impact on fluid flow. The fluid types and their contacts were determined as well as the palaeodepositional environment. Such findings will assist in future exploration and exploitation activities within the Field and can help locate new targets. The Tertiary Niger Delta is a prograding sedimentary complex, deposited under transitional marine, deltaic and continental environments since Eocene in the north to Pliocene in the south. It is located in the southern Nigeria margin of the Gulf of Guinea and consists of over 12 km thick sediments (Short and Stauble, 1967;Avbovbo, 1978;Doust and Omatsola, 1990;Kulke, 1995).
The Niger Delta sedimentary complex is characterized by coarsening upward regressive sequences. The overall regressive sequence of clastic sediments was deposited in a series of offlap cycles that were interrupted by periods of sea level changes (Etu-Efeotor, 1997;Bouvier et al, 1989).  Shannon and Naylor (1989) and Doust and Omatsola (1990).

RESERVOIR CHARACTERISTICS AND PALAEO-DEPOSITIONAL ENVIRONMENT OF DUSKI FIELD
The Niger Delta is divided into three formations (Doust and Omatsola, 1990;Fig.3), representing prograding depositional facies that are distinguished mostly on the basis of sand-shale ratios (Tuttle et al., 1999). The type sections of these formations are described in Short and Stauble (1967) and summarized in a variety of papers (Doust and Omatsola, 1990;Kulke, 1995).

DATA SET AND METHODOLOGY
The data set used in this study was provided by Addax Petroleum Development Company, Nigeria. These include Base map, showing location of three wells (A1-A3); electronic copy of composite well logs consisting of Gamma ray, Resistivity, Neutron and sonic logs present in LAS format. Density log was generated from sonic log and other relevant logs were also created as continuous logs using Petrel calculator. Relevant wireline log signatures were employed to identify hydrocarbon-bearing reservoirs and computing reservoir petrophysical parameters. Such include; gamma ray log (lithology identification), volume of shale log (porosity correction), density and neutron logs (delineating fluid contacts), resistivity and water saturation logs (identifying pore fluid type). In addition, gamma ray and resistivity logs were used in determining the reservoir zones and the presence of hydrocarbon. The gamma ray log shapes were used for characterisation of various depositional environments. The methodologies adopted in this study are summarized in Figure 4 and details are documented in Salami (2015).

Lithological Identification
A gamma ray (GR) cut-off was set to distinguish the sand and shale units by creating a facies template on Petrel software for lithofacies identification. The gamma ray (GR) log was used to delineate the different lithologies in the three wells. The GR log reflects the proportion of shale and can be used quantitatively as a shale indicator (Schlumberger, 1989). Sand bodies were identified by the

RESERVOIR CHARACTERISTICS AND PALAEO-DEPOSITIONAL ENVIRONMENT OF DUSKI FIELD
deflection to the left of the GR log due to the low concentration of radioactive minerals in sands while deflection to the right signifies shale unit, with high concentration of radioactive minerals (Schlumberger, 1989). Conventionally, GR log is set to a scale of 0-150 API unit and a central cut off point of 65 API was inferred based on the sand-shale discrimination. This implies that API value greater than 65, is interpreted as shale unit while lesser indicates sandstone (Schlumberger,1989).

Correlation
The three wells A1, A2, and A3, located within the Duski Field, were correlated using gamma ray and resistivity logs responses. According to Schlumberger, (1989), the gamma ray and resistivity logs are good correlation tools in both open and cased holes. The wells were correlated from bottom to top using lithological log responses that may be product of similar depositional processes and environment. Sand units of interest were carefully picked and correlated across the wells to give an idea of the continuity of the reservoirs at different depths across the whole Field. This is based on the concept of electric log correlation procedures and guidelines (Daniel and Richard, 2003)

Evaluation of Petrophysical Parameters
The petrophysical parameters such as permeability, porosity, effective porosity, hydrocarbon saturation, water saturation, bulk volume of water, volume of shale, netgross, formation factor, irreducible water saturation and hydrocarbon pore volume were estimated from the logs responses using Schlumberger Petrel (2009) software.

Volume of shale (Vsh)
The magnitude of the gamma ray count in a formation of interest (relative to that of nearby clean and shale zones) is related to the shale content of the formation. This relationship may be linear or non-linear. The gamma ray log was used to calculate the volume of shale by first determining the gamma ray index using the formula proposed by Asquith and Gibson, (1982): Igr = ……………………………………….. (1) Igr = Gamma ray index which describes a linear response to shaliness or clay content. GRlog = log reading at the depth of interest GRmin = Gamma Ray value in a nearby clean sand zone GRmax= Gamma Ray value in a nearby shale Using Larionov non-linear relationship for Tertiary rocks, volume of shale can therefore be calculated as: Vsh= 0.083 (2 2Igr -1)………………………………………..(2) Vsh = is the volume of shale Igr = Gamma ray index

Bulk volume of water
This is the product of water saturation and porosity corrected for shale: BVW=Sw*Фe……… (Asquith and Krygowski, 2004)…... (3) Where: BVW = bulk volume water; Sw = water saturation; Фe =effective porosity If values for bulk volume of water (BVW), calculated at several depths within a formation are consistent, then the zone is considered to be homogeneous and at irreducible water saturation. Therefore, hydrocarbon production from such zone should be water -free (Morris and Biggs, 1967).

Identification of fluid type
A general indication of fluid type was inferred from the resistivity readings. High deep resistivity readings corresponding to sand units indicated hydrocarbon bearing or freshwater zones while low deep resistivity readings, showed water bearing zones (Schlumberger, 1989).Usually, a definite identification of fluid type contained within the pore spaces of a formation is achieved by the observed relationship between the Neutron and Density logs. The presence of hydrocarbon is indicated by increased density log reading which allows for a cross-over. Gas is present if the magnitude of crossover, that is, the separation between the two curves is pronounced while oil is inferred where the magnitude of cross-over is low (Asquith and Krygowski, 2004). Hence, log responses of Density and Neutron compensated logs made the identification of fluid type in the studied wells practicable.
However, this theoretical estimate of irreducible water is useful in the estimation of relative permeability.

Identification of facies and depositional environments
A basic scheme of classifying sand bodies in the Gulf Coast area of the USA, apparently developed by Shell (Serra and Sulpice, 1975) is based on the shapes of the SP along with the resistivity logs. The principal shapes are the bell, the funnel and the cylinder (Fig.5). Since the gamma ray log measures the shaliness of a formation, it can indicate the lithofacies and depositional environment of a rock and was used as such in this study.

Bell shapes
A bell-shaped log motif in which the gamma ray value increases regularly upwards from a minimum value indicates increasing clay content. It can be serrated or smooth. It is smooth if there is homogeneity of sand unit (the sand unit might be comparatively massive without shale interbeds), or become serrated when it consist of interbedded sand and shale (Fig.5). A bell-shaped succession is usually indicative of a transgressive shelf sand, alluvial/fluvial channel, tidal channel or deep tidal channel and fluvial or deltaic channel (Nelson and James, 2000;Selly, 1998;Shell, 1982).

Funnel shapes
According to Selley (1998), funnel shape log motif is a coarsening-up succession which can be divided into three categories namely; regressive barrier bars, prograding marine shelf fans and prograding delta or crevasse splays. The crevasse splay is a deposit of deltaic sediments formed after the flooding of the bank which leads to fan-shaped sand deposit on the delta plain (HWU, 2005). Gluyas and Swarbrick (2004) classified the crevasse splay under the deltaic depositional system. Generally, a funnel shape log motif may be a deltaic progradation or a shallow marine progradation (Fig.5).
Also, shapes on the gamma ray log can be interpreted as grain-size trends and, by sedimentological association as facies successions. A decrease in gamma ray values will indicate an increase in grain size: small grain sizes will correspond to higher gamma ray values. The sedimentological implication of this relationship leads to a direct correlation between facies and log shape not just for the bell shape and funnel shape as described above, but for a whole variety of shapes.

Cylindrical shapes
This log motif shows relatively consistent gamma ray readings and indicates no systematic changes in grain RESERVOIR CHARACTERISTICS AND PALAEO-DEPOSITIONAL ENVIRONMENT OF DUSKI FIELD sizes or thickness of interbeds and abrupt upper and lower contacts. It also shows even block with sharp top and base. It is indicative of aggrading condition which may be interpreted as eolian, braided stream, distributary channelfill, submarine canyon-fill, carbonate shelf margin and evaporite fill basin.

Irregular shapes
The irregular or serrated-shaped GR log pattern is indicative of environments such as fluvial flood plain, storm dominated shelf and distal deep marine slope. According to Emery and Myers (1996), the trend has no character, representing aggradation of shales or silts. The irregular shape of gamma ray log patterns may also indicate basin plain environment (Coleman and Prior, 1980)

Lithology
The lithology of the wells comprised mainly of parallic sequence of sandstone with interbedded shale, characteristic of the Agbada Formation (Fig.6). The lower portion of this section contains thick shale unit while the upper portion is made up of more sands than shale. This corroborates the findings of Weber, (1971) ;Avbovbo, (1978); Doust and Omatsola, (1990) and Kulke, (1995) for the description of the Agbada Formation.

Well Correlation
The log responses show that the area of interest, which is Agbada Formation, is characterized by alternation of shale and sand units. The correlation panel (Fig.6) revealed that the horizons are continuous and exhibit little variation across the wells.

Petrophysical Evaluation
The results of the computed petrophysical parameters of the reservoir units across the three wells A1, A2 and A3 are shown in the Tables 1-3. The lithological sequence of each well was identified and defined using gamma ray log.

Porosity
The porosity values of the reservoir sands decrease with depth across the three wells A1, A2 and A3 (Table 1-3). In well A1, effective porosity ( e) value of 29% was estimated in reservoir sand 1, 19% in reservoir sand 2, 17% in both sands 3 and 4, while 16% was recorded for reservoir sand 5. In wells A2 and A3, similar downward trends were observed as shown in Tables 1-3. The highest porosity value was estimated for reservoir sand 1 across the three wells while lowest values were recorded for sand 4 in well 1 and well 2 and sand 5 in well 3. A lateral variation also occurred across the wells due to changing environmental conditions. Reservoir sand 1, has average porosity of 29% in well A1, 43% in well A2 and 31% in well A3. These values are consistent with results from previous studies (Adeoye andEnikanselu, 2009, Nton andOdundun, 2012).     Porosity can range from zero to over 50% and in normal reservoirs; the range is 20% -39%. Odoh et al, (2012) established that porosity values of the Amboy Field reservoirs, in Niger Delta, range from 25-29.8%, with vertical and slight lateral variations recorded across the field. This they suggested to be as a result of sedimentation processes and the age of the sediments.
The lateral variations in porosity values across the three wells of Duski field are also consistent with the report of Evamy et al (1978), Bouvier et al (1989) and Omoboriowo et al (2012). They attributed the lateral variation to changes in the depositional environment and the gradual deepening of the depth of deposition due to the retrogradation of the coastline and the shift in depobelts. According to Omoboriowo et al. (2012), the low energy environment of the lower Agbada Formation which was deposited in the open shelf or shelf slope had little or no influence on the reworking of the sands. This contrasts with the sediments of the upper Agbada unit, deposited in tidal flats and the deltaic front, where strong waves reworked the sands According to Chapellier, (1992), primary porosity, which is mainly observed in clastic rocks, generally decreases in time due to the effects of cementation and compaction. Magara (1980) and Selley (1978) used linear porosity-depth relationship to describe diagenetic changes affecting compaction.

Permeability
The reservoirs sand units in this field show very high permeability values in a decreasing trend with depth (Table 1-3), the highest being the channel sands in reservoir sand 1, with permeability of 102595mD in well A2, 34349mD in well A1 and 27850mD in well A3. The anomalously high values recorded for the channel sands may be partly due to the energy level which influenced the grain sizes and this in turn is controlled to a large extent, by the depositional environment. It is established that porosity and permeability of sandstones depend on grain size, sorting, cementation and compaction (Schlumberger, 1991, Etu-Efeotor, 1997Rider, 1986Rider, , 1996. Therefore, high permeability and porosity values computed were due to high energy environment of deposition associated with fluvial and fluvio-marine processes. According to Tyler (1988), fluvial (channel) and fluvio-marine (barrier bar) processes would generate better quality reservoirs as against marine processes which tend to decrease reservoir quality by producing less sorted heterolithic lithologies. Hence, the difference in quality of reservoir sand units in terms of porosity and permeability is, to a greater extent, related to the degree of sorting of sandstone which is fundamentally controlled by depositional environments and processes, as well as the volume of shale in each unit (Table 1-3). The reservoir sands 4 and 5, which were deposited in a low energy environment have slightly reduced porosity and permeability due to high volume of clays (shales) and silts (siltstones) often associated with such environments. This was evident in the volume of shale estimated from the reservoir sand units 4 and 5 (Table 1-3)

Reservoir fluids
The five (5) reservoir units, 1, 2, 3, 4 and 5, were found to contain gas, oil and water ( Table 4). The fluid types and their columns in each reservoir vary across the three wells A1, A2 and A3.

Hydrocarbon and Water Saturation
The reservoir sand 1 in well A1, contains 81.20% hydrocarbon saturation (Sh) and 18.80% water saturation (Sw) ( Table 1). It is saturated with oil and water, with hydrocarbon pore volume of 27.61% (HCPV) and oil down to (ODT) 1195m (Table 4) with irreducible water saturation (Swirr) of 7%. From the cross-plot of porosity vs water saturation (Fig.7), most of the points plotted along the hyperbolic curve and this implied that reservoir sand 1 in well A1 is at irreducible water saturation and the bulk volume of water (BVW) is at constant value of 6.39%; hence minimal quantity of water will be produced with hydrocarbon (Morris and Biggs, 1967). In well A3, reservoir sand 2 has 61.85% hydrocarbon saturation, 38.15% water saturation, Swirr is 7%, HCPV is about 23.50% and BVW is 14.49%. From the Buckles plot (Fig.8), it was observed that the points are rather scattered and not along the hyperbolic curve. This means that reservoir sand 2 in well A3 will produce large quantity of water with oil. This is also consistent with water saturation data. It contains only water and oil with oilwater-contact (OWC) at 1553m while oil up-to 1565m (Asquith andKrygowski, 2004 andMorris andBiggs, 1967).

Reservoir fluid and contacts
The reservoirs were interpreted for their fluid contents using appropriate logs. In estimating the fluid content and contacts in clastic reservoirs such as obtained in the Niger Delta, shaliness, water saturation, neutrondensity porosity and resistivity logs responses are parameters to be considered. These parameters are essential in the identification of the fluid types and their various contacts within the reservoirs (Table 4).
The combination of neutron-density porosity log overlay, water saturation, volume of shale and resistivity logs were used to delineate hydrocarbon and water bearing zones. The large cross-over of Neutron-Density log overlap (Fig.9) indicates the occurrence of gas reservoir (Asquith andKrygowski, 2004 andAdepelumi et al. 2011).
The utilization of petrophysics to study the lateral changes in fluid content in reservoirs can be very useful in the sense that it helps presume the lateral continuity or extent of the reservoir when seismic data is not available and thus reduces failure in oil/gas exploration (Adeoye and Enikanoselu, 2009).

Depositional Environments and Facies
Gradual changes in shaliness are associated with changes in grain size and sorting that are controlled by facies and depositional environment as well as lithology (Shell, 1982;Nton and Odundun, 2012;Emery and Myers, 1996;and Selley, 1998). Analysis of the gamma ray logs indicated that the log trends fall mostly into four categories namely; irregular, funnel, cylindrical and bell shaped successions.
The reservoir sands were deposited within the transitional environments which comprise fluvial channel, deltaic and basin floor sand bodies. The bell-shaped gamma ray log motif in the wells varies between 5m and 10m thick in places where it occurred. This was observed in the upper part of reservoir sand 3 at depth interval 2044-2104m of well A2, with a sharp break from the overlying shale (Fig.10).This was also found in the reservoir sand 4 of well A3, at depth interval 2584-2624m (Fig.10). The bell-shaped successions are usually indicative of a transgressive sand, tidal channel or deep tidal channel and fluvial or deltaic channel. As reported by Nelson and James (2000), tidal channels commonly contain glauconite and shell debris.
Bell shaped successions with carbonaceous detritus are associated with fluvial or deltaic channels (Selly, 1998); however, in this study, core samples and biostratigraphic data were not available to establish this. According to Weber (1971), most cycles of sedimentation begin with the erosion of underlying sand unit and the deposition of thin fossiliferous transgressive marine sand. The analysis revealed that the bell-shaped successions are thin, which may suggest that the sands were deposited in a transgressive marine setting.
The irregular log motifs occur in several sections of the three wells. These trends show no systematic change in gamma ray values and represent aggradation of shale or silt (Emery and Myers (1996). The trend is extensive, particularly at deeper depths of all the wells; in well A1 for instance, it occurred between the depths interval 2100-2550m (Fig.10). These log facies are interpreted as basin plain environment, which is characterized by clays and fine silts, deposited from suspension, with high lateral continuity and low lithologic variation.
The funnel shaped log motifs occurred in the lower part of sand 2 and sand 3 reservoirs of well A2 with thicknesses of 18m and 30m respectively (Fig.10). Also, this trend appeared as serrated and dominant in sand 5 unit of well A2 with thickness of 35m. The trend is usually interpreted to indicate deposition of cleaning upward sediment with an increase in the sand content of the sand bodies, as applied to a marine setting. The environment of shallowing-upward and coarsening successions is divided into three categories Selley (1998). They include: regressive barrier bars, prograding marine shelf and prograding delta or crevasse splays. The regressive barrier bars and prograding marine shelf fans environments are commonly deposited with glauconite, shell debris, carbonaceous detritus and mica (Selley, 1998). This cannot be established due to absence of core samples and biostratigraphic data. These log shapes cannot be associated with crevasse splay on the account of thicknesses (Nton and Odundun, 2012).
One of the main differences between a crevasse splay and a prograding delta is the depositional scale. According to Chow et al., (2005), the prograding delta is comparatively large. The funnel-shaped successions in well A2 which are 18 m, 30 m and 35 m, are likely to be a prograding marine shelf or a prograding delta (Rider, 1999). In non-reservoir portions of the wells, prograding sand units were also observed above sand unit 1 across the wells. It was also observed between the depths interval 1700-1750m below sand 2 and depth interval 1825-1870m in each of the three wells.
The cylindrical log shape patterns are observed in most of the sand units across the wells. This trend is very obvious in the reservoir sand 1 unit across the three wells of the field (Fig.10). This pattern is also observed in the lower part of reservoir sand 2 of well A1. This shape characterized the gamma ray logs of the upper portion of the reservoir sand 3 in well A2 and lower part of reservoir sand 3 in both well A1 and A3. It is a dominant pattern in both reservoir sand 4 and 5 of well A1.The upper and lower boundaries of reservoir sand 1 across the three wells are sharp and bounded by marine shale. The thickness of the cylindrical gamma ray log shapes of reservoir sand 1 in the wells range from 24 m to 37 m. The thickness is about 34m in reservoir sand 2 of well A1. The thicknesses of 31m and 22m were observed in reservoir sand 3 of well A1 and A2 respectively. Also in sand 4 of well A1, 41m thickness was observed.
The cylindrical-shaped gamma ray logs could indicate a slope channel and inner fan channel environments according to Shell (1982) log shape classification scheme. Reservoir sand 1 across the three wells together with sands 2, 3 and 4 of well A1, were deposited in a slope channel environment due to the irregular trends and their thicknesses. The cylindrical log shapes trends with greater range of thickness indicate turbidite sands (Emery and Myers;1996).

CONCLUSION
This study involved analyses of composite well logs for reservoir evaluations and palaeo-depositional environment interpretation in Duski Field, Onshore Niger Delta. It was observed that the five oil-bearing reservoir sand units across the field were very prolific. These units were characterized by porosity, permeability, hydrocarbon saturation, water saturation, irreducible water saturation, hydrocarbon pore volume and bulk volume of water values which compared closely with that obtained for sands of other Niger Delta producing fields.
The rock properties of the Duski Field are variable due to environmental influence and depth of burial. Sand units have good quality properties as reservoir rocks while the shale units function both as source rock and seal. The variability in the rock properties was controlled by the different environments of deposition. It was deduced that the study area is within the marginal marine depositional 66 environment and comprised fluvial channel, transgressive marine, progradational and deltaic settings.
All the reservoirs in well A1, except sands 5, reservoir sand 2 in well A2; reservoirs sands 1, 3, and 4, are at irreducible water saturation and would produce water-free hydrocarbons. Some other sand units, namely: sands 1, 3, 4, and 5 of well A2; sand 5 in well A1 and reservoir sand 2 in well A3; are not at irreducible saturation. Much water and wet hydrocarbons would be produced by wells bored through these units.
It is envisaged that with the availability of seismic, check shot and biostratigraphic data, more information could be gathered on the volumetric, depositional environments and the structural configuration of the reservoirs.