Structural Modeling of the Top Turonian Reservoir in the Northern Seme Oilfield (Benin, West-Africa)

The Sèmè oilfield is located in Benin’s offshore coastal sedimentary basin, near the Benin-Nigeria border, and contains two important oil bearing structures called “Sèmè North” and “Sèmè South”. In this coastal basin, Turonian sandstones of Abeokuta formation (Cenomanian-Turonian to Early Senonian age) form two reservoir units differentiated by two seismic horizons H6 and H6.5. The H6 seismic horizon represents the upper reservoir unit and is the main reservoir from which, more than 22 million barrels of crude oil had previously been produced in Sèmè oilfield. In order to improve knowledge of field petroleum geology, the present study presents the structural features of this upper reservoir unit. The use of Petrel software modules for the integra-tion of 15 wells data, allowed presenting a structural model and illustrative cross sections that precise the geometry and specifying the structural characteristics of this reservoir unit within Sèmè field. The displayed structural architecture shows that the upper Turonian sandstones unit is composed of 11 layers including 7 reservoir layers (A, B, C1, C2, D1, D2, E) and 4 in-tra-reservoir layers (1, 2, 3 and 4) controlled by faults systems. The model provides basic framework necessary for geological characterization of the reservoir through a static model. The results of this study can be used for petrophysical modeling, Gross Rock Volume (GRV) determination and technical redevelopment of the field.


Introduction
The Offshore Benin Basin (OBB), which includes the Sèmè oilfield, belongs to the Benin Coastal Basin, one of the coastal basins of the "Dahomey Embayment" [1]- [6]. The Dahomey Embayment (from western Nigeria to eastern Ghana), is part of the northern Gulf of Guinea a prolific petroleum province where many fields were discovered on the continental shelf or in waters less than 2000 meters deep. The Upper Cretaceous petroleum system with Turonian sandstones reservoirs is the most active over the province [7]. Within Sèmè oil field, Turonian sandstones of Abeokuta formation consist of 28% clay and 70% sand. Composed of quartz, calcite, dolomite and rutile, these sandstones have good porosity (18%) and were exploited from 1982 to 1998. During these 16 years of operation, only 22% of the estimated reserves at the time were produced. In 1998, while crude oil world prices were very low, oil production in this field was accompanied by large volumes of water. Water production from the reservoir gradually reached 90%. This situation led to the cessation of production activities and the definitive closure of the field. Nowadays, scientific and technical progresses in the oil industry allow better characterizing hydrocarbon reservoirs and revaluating the residual reserves of a field [8]. According to the significant increased interest and exploration activity in the region [9], the present study aims to define the structural features of the upper part (named H6 seismic horizon) of the sandstones units through a geological modelling using seismic sections, wells data and Petrel software. As part of an important modeling of the H6 horizon including geometrical modeling and petrophysical modeling (static model), the objective of this work is to present the first step of this modeling process based on seismic maps and fault interpretation, reservoir layering as well as correlation framework. The study results are necessary for a better understanding of the geometry of this structure and evaluation of his petrophysical characteristics and potentialities.

Study Area
The Sèmè oil field is located in the north-eastern part of the offshore sedimentary basin of Benin at bathymetries ranging from 27 to 54 m ( Figure 1). With an area of 63 km 2 , it is positioned 2500 m from the Benin-Nigeria border and has two oil structures [10].
The stratigraphic chart of the offshore Benin basin is presented in Figure 2.
The upper boundary of Abeokuta formation is materialized by the seismic marker H6 which is usually picked with the influx of immature, medium and coarse predominantly non-calcareous sandstone [11] [12]. The Maastrichtian unconformity cuts into the formation in the eastern most part of the shelf in the     [12].

Methodology of Study
The geometrical modeling workflow involved the use of seismic and well data [14] [15] [16] [17] [18]. The study brings together the H-6 reservoir geological information necessary to generate a global 3D field characterization. The study includes a new seismic interpretation and a totally re-interpreted data set made of considerable quantity of past data completed by more recent acquired geological data.

Seismic Data
Seismic sections extracted from acquired lines within the field and their interpretation provides the following data: 1) a depth map at top reservoir (H6 horizon), prepared with the most likely velocity map tied to the well tops and 2) A set of fault polygons representing the intersection of the interpreted fault plans with the H6 horizon, with their main dip angle and azimuth.

Software Utilization
The methodology consisted in a complex analysis of data relating to top reser-   2) Different small horst and grabben systems oriented mainly N-S or SW-NE, in particular in the S4 and S10 area.
3) The accident at the south of wells DO1, S3, S6 and S4, has a direction going from East west to nearly North-South with a dip to the north. It is composed of two different faults in continuity and will have a major impact on the grid construction and flow behavior of this producing zone.

Vertical Layering of the Reservoir Unit
The vertical gridding was done using the top H6 horizon and the well top markers from the correlation. Well tops and correlation were used to define the ver-  Barrier 2: This level is most of the time corresponding to a high Gamma ray interval. Its thickness is between 1 and 2.5 m. This level corresponds to a break in pressure potential between units B and C. This break shows in some cases the unit C more depleted than B (i.e. Wells S4, SC-2, SC-3), or in some other cases the unit C less depleted than B (i.e. Wells S6, S11).
Unit C1: With a global thickness from 5 to 8 m, this level is a very good massive reservoir, produced in many wells. Unit C2: Good massive reservoir around 5 m thick. C1 and C2 units limit was defined based on a small radioactive level, not always visible. There is no noticeable difference in pressure potential between these two units.
Barrier 3: This level corresponds to the limit between the C and D reservoir units. It is most of the time corresponding to a shaly interval (S4, S6, S3, S10), but with not so clear log response in some cases (S11). This level was cored in well S2, and is described as a 3 meter thick shaly interval, finely laminated. There is most of the time a pressure gradient break above and below this level, with the C level more depleted than the D.
Barrier 4: This interval is the main barrier level of the Abeokuta complex, always indicating an important pressure gradient break, between the depleted D unit above, and the non or very poorly depleted E unit bellow. It corresponds in some well with a shaly interval (S6, S7, SC-3), but has often a not clear log signature (S3, S10…). This barrier doesn't seem to be correlated with a consistent singular sedimentological event, but most probably to a relay in multiple sealing intervals. This level was cored in well S2, and probably corresponds to a half meter shaly interval (2304 -2304.5 core depth). Note that this well has no pressure data to prove the correlation of barrier 4, and a possible uncertainty on the core to well depth shift. The base of this unit was mainly defined on the presence of a shaly level, not always clear. There is no pressure break visible above and below this lower limit.
In some cases, some uncertainties remain concerning the exact location of some markers, especially when no or poor pressure points are available (well S2, DO1, DO2A), or when these pressure points were taken late after end of production (CSE1, CSW1). In those cases, the well log data were mainly used with the uncertainties discussed above.
Using Petrel software applications (Schlumberger) modules, the limits and trends of the reservoir architecture and a 100 × 100 m grid was defined. Such refinement is sufficient to take into account the observable geological heterogeneities. Thus, pillar gridding process, grid skeleton and grid segmentation allow to build the 3D grid view of H6 horizon (Figure 7). Generally, structural continuity is affected by small faults of limited throws, not accurately defined by seismic.
The H6 horizon thickness is generally less than 100 m. The 3D grid view of          [7]. According to [7] only one well (SC3) located in West Sèmè North give possibility to differentiate 11 layers with a global thickness of 220 m. From other wells the number of layers vary from one (well S7) to six (well S4). The presence of horizontal barriers raised the question of the existence of several independent reservoir units, with possibility of different contact level. It was observed that for every well, the E reservoir unit is disconnected from the upper unit. On the other hand, the reservoir units A, B, C and D constituting one reservoir tank with an original OWC at 1910 m TVD remain the most likely assumption.

Conclusion
The structural modeling of the top Abeokuta formation (H6 horizon) using Petrel exploration software has shown that the "Sèmè North" H6 horizon is formed of 11 layers (7 main reservoir layers: A, B, C1, C2, D1, D2, E) and 4 thin intra-reservoir layers. Layer A is partially absent. Thus, the study brings together the H-6 reservoir geological information. Its displays the structural architecture of the Turonian sandstones unit including reservoir layers, barriers, faults systems and provide the basic framework necessary to generate a global 3D field characterization. The seismic interpretation and time to depth conversion have been significantly improved by the addition of 3D into the seismic survey. However, critical structural uncertainties at the top H6 map still remain.