Assessment of Aquifer Performance for Oil Drainage in the Upper Pinda Reservoir of the Mibale Field

: The Mibale field in offsore of the DRC has been producing oil since 1976. This field is faced with the arrival of massive water and the depletion of its reservoir leading to the drop in its oil production, while the injection of water is effective for several decades. Understanding the behavior of the aquifer in this reservoir is a solution to the application of effective water flooding for oil drainage to this field. The objective pursued in this study is to evaluate the performance of the aquifer on the basis of the material balance equation, to understand its behavior in maintaining or not the pressure in this reservoir in order to identify the causes related to this depletion and the influx of water despite the application of water flooding techniques. To reach this goal, the data collection during the internship made it possible to analyze and process this data using professional software. The results show that the overall drainage index of the water drainage mechanism is 84% (due to 20% for the aquifer alone and 64% for the water flooding) and 10% of oil compressibility. (IDOI), 6% of dissolved gas segregation (IDS). Reserves in this reservoir are estimated at 4.5 million barrels. The aquifer is inactive, semi-radial linear with a constant (U) estimated at 595.5 barrels per psi (bbl / psi) and an initial volume (WI) of 347.1 million barrels (Mbbl). Cumulative contributions from this aquifer are estimated at 173,868,933 barrels for the last 42 years of operation. This aquifer alone has no influence on the inflow of water and the maintenance of pressure, but its influence increases with water from injection wells. In conclusion, this inactive aquifer is located in the carbonate Karst of Upper Pinda to the north of the deposit. Being inactive, this aquifer is not at the origin of breakthrough or coning water acting in this field. It is likely that this phenomenon is amplified by water flooding. Which allows us to classify water flooding technology among aquifer drainage mechanisms; since this significantly activates the behavior of the aquifer and has the same effects as the aquifer.


Introduction
In a quest to increase productivity of many of the fields' wells or enhance the recovery of the proven hydrocarbons in place within the Lower Congo coastal oil district of the DRC, this study focusses on the upper Pinda reservoir, its recovery and performance.
The upper PINDA is an oil reservoir of the MIBALE hydrocarbon field, located in the region of Banana/ Moanda in the DRC offshore (See Figure 1). With oil commercial discovery announced in 1973, it came into production of in 1976 [2,5]. The field accounts of 21 wells (producers and injectors), however it has experienced reduction in its production from year 1978 to date due to problems of water inflow, which is believed to impeding boost in oil recovery. The Mibale field is confirmed in its decline phase of production, despite its commercial oil potential which is still abundant in the reservoir. Nonetheless, the life of this field could be lengthened in exploring other mechanisms of drainages of oil in the tank and enhanced recovery.
Henceforth, this study seeks to understand the natural drainage mechanisms within the field, using field operation and production data in order to suggest better mechanism for enhance reservoir performance. As the field is produced with its reservoir depleted using active bottom water drive mechanism, we postulate that there is no acute sand control problem. In extenso, we analyse the mode of exploitation of the wells through the analysis of relevant reservoir parameters in the production history, as well the aquifer parameters to match the observed production wells respective higher water-cut (s). Figure 1 is a map of the geographical location and its various wells in activities. It is located in the Kongo Central province, the south-western part of the DRC (red dot on the country map) and very precisely in the Lower Congo Basin offshore. In the mid-1970s Mibale field had only 8 wells, which turned it as a major producing field in 1976 with an estimated oil production of 10,000 barrels per day. As per year 2017 the wells stock stood at 21 of which 15 producers and 6 water injectors ( Figure 1). By contrast, despite proven oil reserves are still significant, current field production is around 3000 barrels per day, suggesting its aquifer poor performance and poorer oil sweep with the water flooding recovery method in use. It must however be pointed out that injectors and producers can in some cases be closed temporarily if maintenance and work-over operations occur. Henceforth, Figure 1 is only a snapshot in time of the filed base management and can today (in 2021) be modified in line with field production plan.

Methods
Water influx into reservoirs (oil and gas) can be estimated via several mathematical approaches, known as models, as they proceed to simulate changes in pressure within the aquifer and between the aquifer and reservoir. The main approaches in use are related with the type of flow within the reservoir/ aquifer; either steady-state or unsteady-state.
An example of a steady-state flow model is the Schilthuis aquifer model [1,20,22]. Steady-state models assume that the rate of water influx is directly proportional to the pressure drop between the original oil-water contact (OWC) and the external aquifer boundary. For steady-state models, the pressure at the external aquifer boundary is assumed to be constant.
However, there are three other popular aquifer models which are based on unsteady state flows.
The van Everdingen and Hurst (VEH) aquifer model is an unsteady-state model, which is based on the radial diffusivity equation. The van Everdingen-Hurst aquifer model uses superposition to calculate cumulative water influx. There is in addition a pseudosteady-state flow model called the Fetkovich aquifer model. It was developed from a combination of an inflow equation and a material balance model based on the aquifer. And there is equally the Carter-Tracy aquifer model which is known as the approximate model, based on the van Everdingen-Hurst but considering unsteady-state model [1,7,15].
For all of these approaches depend primarily on the characteristics of the aquifer and the configuration of the oil field itself; production drive mechanism and data suggest the use of the equations of HURST AND VAN EVERDINGEN for the determination of the cumulative water inflows during 42 years of exploitation of the MIBALE field. In a nutshell, we adopt this approach of unsteady state flow for the Mibale field, i.e. Edge-water drive, Bottom-water drive to assessing the problem of its water influx and performance.

Materials
To complete this work, several materials and tools were used. It is mainly a laptop containing the following software: 1) Geographical Information System (GIS 10.4) software at ArcGis for the development of the various maps related to the study area; 2) Inkscape software were used to determine the isobath map and some parameters of the aquifer, 3) The Petrel software version 12 also allowed us to geologically model the PINDA reservoir in order to understand the structure of the deposit, 4) The Sufer software version 11 allowed us to establish the evolution of the water and oil contact during 42 years of operation,

Datasets
Drilling data, well logs, and the upper PINDA reservoir fluid properties (PVT) of the 12 wells of the MIBALE field collected during the offshore Mibale field development and its production at plate-form located at MOANDA city were made available by the operating company for this study. Additional confidential production documents on the methods of exploitation of this field since 1973 were also used to validate the production mechanism, oil recovery and field reservoirs base management during the years.

Area of Interest and Hydrocarbons
The Mibale deposit area consists of a faulted anticlinal structure with an area of 11Km 2 delimited by major faults caused by the diapiric lifting of salt of LOEME. It is part of the coastal basin of the DRC (Figure 2, below).
With a multitude of faults, the geology of the coastal basin is subdivided into two phases: before the salt commonly called ante-salt (also pre-salt) and After the salt (post-salt). The pre-salt is made of the following formations: the metamorphic basement of Mayombe, the sand of Lucula, the clays of Buccomazi (principal source rock of the Coastal Basin of the DRC), the Toca carbonate, the Chela sands generally considered a drain favorable to the migration of hydrocarbons from the BUCCOMAZI source rock to the Post-Salt Reservoirs, and the salt of LOEME [4,5].

Mibale Field Depositional Systems and Wells
Mibale Upper Pinda formation is a complex structural stratified multi layered system deposited during the Albian stage of the Cretaceous period and is overlain by the Cenomanian shale member of the Iabe formation. As shown on Figure 3 above. The geological model of the reservoir adopts four basic stratigraphic zones that classify the Pinda formation: Zone 1: the transitional interval between the shalyCenomanian (at the base of the Iabe formation that acts as the reservoir seal) and the limy Upper Pinda. 1) Zone 2: a slightly sandy, but mostly open-platform limestone. 2) Zone 3: the replaced open-platform vuggy dolomite.
3) Zone 4: supratidal to nearshore marine cyclic carbonate-clastic interbedded dolomites, dolomitic sandstones, and dolomitic shales. For this study, indicated reservoir zones 2 through 4which is also known as the Upper Pinda -have been subdivided into seven geologic layers ( Figure 4). The seven layers thicknesses are too variable. Some of these layers are loaf, while the others have very considerable thicknesses, and the majority of them discord (angular discrepancy) towards the Northeast of the deposit. As portrayed, all units thin towards the northwest onto the Mibale field paleo-depositional high, located in the Mibale 10 area. For instance, layers 3 and 4 are also truncated to the northwest beneath the layer 2 unconformity (Figure 4).

Petrophysical Characterization of the Upper Pinda Reservoir of the Mibale Field
Based on formation evaluation and log data analysis, the Pinda formation reservoir is modelled an heterogeneous multilayer tank as described in Figure 4. As such, it only returns variable petro-physical properties (porosity, permeability,…) which impact the flow of fluids towards producing wells.

Flow vs. Facies
The Mibale field reservoir is composed of three dominant facies (See Figure 3 Based on the layered model of Mibale Field facies and zonation, a corresponding Net-to-Gross map is presented in Figure 6 below. Meanwhile, some characterization and variation of petrophysical parameters of the upper PINDA are given in Figure 7.   Figure 8 is contour map based on eight wells of the field at reservoir depths. It portrays the spatial distribution of porosity in those wells and translates an average reservoir porosity of about 15%, which is deemed to be a good porosity. Note the porosity is variable from one area to another and it varies especially with depth [4,5,13].

Field Oil Water Contact
Another important petrophysical property or data impacted by production and water drive mechanism is the field OWC, hence water breakthrough in producing wells. For the purpose of the study, we have provided a map of isobaths of field of MIBALE Field ( Figure 9).

Reservoir Pressure During Production of the Deposit
The Upper Pinda reservoir pressure evolution over the years of production (1976 to date) is captured in data plotted in Figure  10   At the end of this figure which plots the pressure test data carried out in the different horizons of the Upper Pinda reservoir, we can see that each layer had its own pressure. The different facies of the Upper Pinda reservoir being communicating, the shape of the pressure evolution with the production is similar in all the lithofacies of the reservoir.
The Reserves of the MIBALE oil field were (re) evaluated by the company in 2015. The accumulations in place under standard conditions were as follows. The cap gas factor is evaluated by the following formula: The interpretation of this value is based on the following arguments according to other reservoir engineering researchers [6,18]: 1) When m=10, the deposit behaves like a deposit at Water Drive. The pressure is maintained. The GOR is constant, the gas cap is so important that it manages to maintain P and replace the oil produced. 2) For m=1, there is a partial pressure maintenance, the gas can neither maintain pressure nor replace all the oil produced. 3) For m=0.1, the deposit behaves like a dissolved gas deposit. No pressure maintenance and there is a GOR trigger. In the case of the species, the field of the Mibale field was naturally characterized by a segregation mechanism due to dissolved gas. It did not have a gas cap initially (absence of Gas Oil Contact: GOC).
A deposit whose natural drainage mechanism is of the segregation (dissolved gas) type is not good at injecting water during natural depletion. The consequence of injecting water into this type of deposit is that the oil will be produced with a significant amount of gas, while another quantity of the gas will escape to form a gas cap during the operation of the deposit. This will consequently lead to an increase in the viscosity of the oil, leading to the low mobility of the latter.
The oil recovery factor, R, at pressures above bubble point is given by: We can use the equation (2) to calculate the recovery factor using data from table 1. We can say, the recovery factor is: This recovery factor shows that we have not yet reached the production of even half of the oil in place (OOIP).

Hurst and Van Everdingen Equation
Water inflows over time are evaluated in this paper by using the following HURST and VAN EVERDINGEN equation [1,3,7,11,18]. These influxes of water infiltrants depend on the constant of the aquifer (U) and the pressure drop (∆P) in the reservoir as a function of the exploitation time of the deposit.
This equation is nothing other than the equation below in the simplified sense: Where = 245∅ℎ89 : isnothing other than the constant of the aquifer in cc / atm, but as we work with the units of the field, then this parameter (U) becomes: in bbl/psi [10,15] On this paper n=42 years, which practically corresponds to 2018, but we will limit ourselves to assessing these water inflows in 2017; since n-1=41 years.
hmed Tarek, 2010 shows that, the initial water volume of the aquifer can be evaluated by the following formula: At least in this article, we wanted to expand equation (4) of the aquifer constant and propose this reasoning so that at future publications we can correct these equations.
With C=0.000264 if the time (t) is in hour, C=0.00634 if the time (t) is in days C=2.309 if the time (t) is in year. This is the case in this scientific article.
For a radial aquifer, for a linear aquifer Knowing that [6,14]. The permeability (K), the porosity (Φ) and the compressibility of the water and of the formation (Cw, f) of the PINDA reservoir of the Mibale field were studied and characterized their values are presented in Table 2. The radius of the reservoir (r 0 ) and that of the aquifer (re) were found using Inkscape software after design and projection of the isobath map of the roof (Figure 9). The thickness of the aquifer is known from the logging and drilling data by positioning the Water oil Contact in all the wells in the field as shown in Figures 5 and 9. These different parameters are then presented in Table 2. Knowing the characteristics of the deposit and some parameters of the aquifer present in this deposit, let us calculate the initial volume of water in the aquifer (Wi) and the constant of this aquifer (U) using equations 5 and 6 with the data from table 2. After calculating the dimensionless water inflows from the formulas (11 and 12) established in the book by Tarek, 2010, we notice that there is no difference in results between equation (11) and (12). The proof is that if we calculate the dimensionless water inflow (WeD) whose dimensionless time is 55.6 with the two equations, we find the same answer (26.9 or 27.09).
So would we want to know at what level is the difference between these two equations illustrated by Tarek and the whole publishing house of this book [22] Is there any way to properly adjust the conditions of use of these two equations? The results from these formulas are identical to the values established in the tables, which confirms the validity of these tables.

Computation of Average Reservoir Pressure over
Period of Operation After pressure data compilation and computations using Microsoft Excel, this is the representation of the average pressure of the reservoir over period of operation. Each point indicates the corresponding pressure at the given time ( Figure 11). The point clouds in the figure above reflect the evolution of the average pressure of the Upper Pinda reservoir. This development shows us how at certain periods there was a slight increase in the pressure in the tank. We can see it from 1978 until 1980, the Average tank pressure had increased from 1752 to 2145 Psi.
As we can see again between 1994 and 1995, the pressure also increased from 1249 to 1343 Psi. Arriving in 2008 until 2011, the pressure had also increased from 628 Psi to 872 Psi. This slight increase in pressure will finally be noted also over the time interval from 2012 to 2018, with an increase in pressure from 551 Psi to around 900 Psi.
All these time intervals marked by the increase in pressure have been circled in red in the figure. We can interpret these annual increases in pressure as a phenomenon which was caused by water injections into the Upper Pinda reservoir of the Mibale field and we will see below their impact on the influx.

Computation of Pressure Drops as Observed over Time and Influx Water
We know that the inflows into the deposit are a function of the pressure drop between the reservoir and the aquifer. For our case, at Edge Water Drive, leading to instability in the production of wells with generalized coning water in all Producing wells in the field, the annual pressure drops are evaluated by the method of Hurst and Van Everdingen exposed by L. DAKE.
The pressure drops occurring at times 0, t1, t2.. The results of various pressure drop calculations are then presented in the 4th column of Table 3. The annual pressure drops were calculated using the Van Everdingen superimposition method [3,10,14] simplified by the equations presented above: simple difference in pressure from a previous year and the following year, divided by two or simply u zev /u wxv . The results obtained show that certain pressure drop values are negative (less than 0), in Table 3. This can be interpreted as the deposit had benefited from pressure gain during these periods instead of loss in pressure. These respective pressure benefits came from injection wells which during these periods significantly increased the quantities of injection water up to 25,000 barrels of water per day. Figure 11 indicates this increase in pressure (circled in red dotted lines) which justifies the negative pressure drops (∆P) in Table 3. And since the pressure drops are in negative values, this will lead to obtaining the values of the inputs water (We) negative (less than zero) during these years.
On the other hand, the Upper Pinda reservoir is a multilayer reservoir and each of its layers has a very specific pressure and is exploited separately by the wells (Figure 5). However, certain layers are exploited by producing wells, others on the contrary undergo water injections and sometimes are not exploited. All these layers are connected to each other through the fault networks that affect the Upper Pinda reservoir.
The unexploited layers contain high pressures unlike those which are exploited and can under certain conditions compensate for depletion in certain layers in operation. And we think that the increase in pressure that occurred in the years may be due not only to the injection wells but also to the pressures of unexploited layers which communicate through the faults. We can present this equation in simplified form as follows: ./ 23 (15) The overall result of these entries is represented by the figure below:

173868933
Mbbl 42 €|}:c Table 4 presents in its last column all the results of calculations on the influx of water into the reservoir of the Mibale field. We predicted this in the previous paragraphs; the overall results clearly show that the inflows are affected by the pressure drop, and that in all years when the pressure drop values are negative, the water inflows are negative; we say that there was no influx of water at those times. The aquifer present in this field is inactive or still not supplied, exerting a low pressure in the Upper Pinda reservoir of the Mibale field.
The cumulative inflows of water during 42 years of operation of this field are calculated and are around 173,868,933 Barrels of water supplied by the aquifer.
The latter are evaluated each year on the basis of equation (4), the results being presented in the last column of Table 4, we present below, the inactivity periods of the aquifer in the Upper Pinda Mibale field reservoir Figure 12. We can interpret the periods when the water inflows are negative as years during which the aquifer did not inject water into the reservoir, in other words the years when the aquifer did not exert its effects in the reservoir (inactive aquifer). And as this periodically manifests, we say that the aquifer was not supplied regularly.

Mibale Field Oil Water Contact (OWC) Variation over the Years of Production, as a Consequence of Water Influx
The reservoir oil water contact (OWC) was penetrated at 5,720 feet true vertical depth subsea (TVDSS) by exploration well in Mibale 1X in 1976 and by all wells. Currently, the known OWC is located at depth 5,500 feet true vertical depth subsea (TVDSS). There has been a net variation of 220 feet during the production years. Considering the 42 years since the first oil, this translates into the original OWC moving up an average of 5.23 feet annually.
In this table, it is a question of showing by calculation the sudden variations by the water oil contact during the 42 years of exploitation of the Mibale field. Original Oil Water Contact (OOWC) was found averagely in all wells in the field at a depth of 5,720 feet (figures 5 and 9). In 2017 the Current Water Oil Contact (CWOC) is at 5,500 feet. We proceed as follows: ∆ •F = 5,720 − 5,500 42 = 5.23 feet annually From this response, subtract from the value of the original contact water (5,720-5.23=5,714.77) to find the WOC corresponding to a given period. This is what gives the results on the table above.
The vertical cross section shows the position of the Mibale well 19 penetrating layer L2 in red color with its toe (Total Depth) above the OWC, allowing it to produce the oils contained in the L2 layer of the Upper Pinda reservoir. The other two wells (Mibale 11 and 18) already have their toes (Total Depth) below the actual Oil water contact. With this arrangement of the well, if their perforations are not checked, they are already drowned in the water part; which will lead to water production. Figure 14 however presents the well facing the mounted water oil contact (WOC), i.e. showing how this contact varies horizontally.
In this part, we show in an horizontal plane the variation of Water Oil Contact. Looking to the right of this figure, a scale indicartive of the color is mensionne; all the sides where we have the blue colors in other words 6 where the values of our curves of 5709.2 feet, up to the value of 5600 feet average, we are in areas where the increase in water is maximum (100%).
This is to say that if a well has been perforated moderately at this depth, its perforation will be in the water zones and the consequence: the enormous production of water manifested on the surface by the increase of water cut. This reasoning should be properly illuminated by means of the Mibale 11 and Mibale 18 wells. Since Mibale 19 is a directional well above water contact, it will not be able to do so because it is in the oil zone.

Determination of Mibale Field the Global Drainage
Index In most books on reservoir engineering [6,9,10,22] the General Material Balance equation is the sum of the indexes of drainage mechanisms linked to the petroleum reservoir. We determine the index of reservoir drainage mechanisms by water to assess the performance of the aquifer studied in this article.
The other drainage indexes will follow to calculate the overall drainage index of the field from their sum, and compare the results of these drainage indexes in order to deduce the most effective drainage mechanism in this field.
For the aquifer, the researchers [18,22] have shown that the drainage index of the aquifer is evaluated by: Formula 16 assesses the performance of the aquifer alone in draining oil from the reservoir.
Knowing that The oil expansion drainage index is also determined by the following formula from Tareck and the other authors: Since the Mibale field deposit does not have a gas cap, its gas is dissolved. in this case we can estimate the drainage index by segregation by the following mathematical formula: Reservoir engineering specialists [8,16,21] show that in a gas cap and influx tank, the index of drainage by water compressibility and formation is negligible. We can then calculate the sum of all these three indexes which is equal to 1. Either mathematically we write: [15,17].
The following Upper Pinda reservoir data were used to determine this drainage index. Compared to the other indices of the drainage mechanism acting in the Mibale field, we notice that drainage by water is more effective than others. But this index of drainage of hydrocarbons by water which is around 84% represents the injection water from the wells and that of the aquifer.
To evaluate the contribution of the aquifer alone in this 84%, we will use equation 16 to determine the drainage index of the aquifer alone without the contribution of the water injection wells. This will mainly take into account the influx of water from the aquifer and the water produced in this field. If we subtract in 84% of the index of drainage by water, the 20% found as the index of drainage by aquifer, and 16% found as the Oil compressibility and gas segregation Index of drainage, we realize that the injection water of the wells play a very capital role in the drainage oils in the tank of the Mibale field. Injection well water alone contributes to drainage up to 64% out of 84%.

ˆM
Knowing that the Material Balance equation in linear form is written as follows [18,19,22]: The gas cap factor being zero, the cap gas in the reservoir of the Mibale field has no effect on oil production, this results in a reduction of the previous equation to the form: Knowing that -° "°& " ±; 1.18 & 1.13 0.05 :[/² " Using equation (22), allows us to draw the graph whose equation will be presented as follows [: According to Havlena and Odeh [11,22,23] the parameters which constitute this equation (23) plotted on a two-axis Cartesian graph can better characterize the aquifer and allow to find the Original Oil in Place (N).
We use equation 22 can be used to calculate the volume of fluids supported in the Mibale field reservoir.

Mibale Field: Structure, Faces and Impact in Oil Recovery
The structure of the deposit is a faulty anticline formed after Loeme's salt tectonic. This reasoning is confirmed by the drilling data and by the work of GAFFNEY and BIMBANGA [2,5]. The reservoir of the deposit is composed of three types of dominant facies: 1) Dolomitic, 2) Limestone, 3) Sandstone of good porosity but very minor. The reservoir of the Mibale field is heterogeneous, this heterogeneity of the reservoir has a great influence on the directional permeability of the reservoir.
The correlation analysis between permeability and porosity shows that the correlation coefficient is low in the three litho facies of the Upper PINDA reservoir. The low value of this correlation can justify of low permeability on the upper Pinda reservoir.

Water Influx and Pressure Drops in the Upper Pinda Reservoir
This reservoir was operated initially with a pressure of 2600 Psi in 1976 and today (2017)  The assessment of water influx in this deposit indicates that the deposit aquiferhad a water volume of around 347,100,090 barrels. With its constancy of the aquifer (U) evaluated at the turn of 595,5 barrels per Psi, which provided a cumulative volume of water inflow (We) evaluated at 173,868,933 barrels.
Analysis of the influx of water shows that this aquifer was not active, it exerts its effects periodically and that is when there is water injection into the field. We note that the aquifer of the Mibale field is not naturally supplied. Its influence is controlled by water injector wells.
The evaluation of the drainage mechanism in the Mibale field shows us that the water from the injection wells remains the only mechanism that contributes to the drainage of hydrocarbons in this reservoir. They contribute to capacity building of the inactive aquifer by giving it a power to drain a total of 84% against 16% of the other drainage mechanisms: oil expansion and dissolved gas expansion.
The predominant drainage mechanism of the Upper Pinda reservoir and the use the linear Material Balance equation shows that since 1976 until today, a sustained volume (F) of fluids of 193,518,933 barrels of fluids has been achieved in the Upper Pinda reservoir of the Mibale field.
From this value we subtract the 123,000,000 Barrels of Oil Products (Np) in the field, we find that 70,518,933 barrels represent other fluids (water and gas) Produced for 42 years. And of these 70,518,933 barrels by subtracting 27,156,000 barrels which represent the cumulative production of water (Wp) (show table 6), we estimate gas production at 43,362,933 barrels of gas, equivalent to 155,151.49 Million Standard Cubic Feef (Mscf) produced in the Mibale field.

Recovery Factor
With a recovery factor of 31.29%, the cumulative production of oils has not yet reached half of the original oil in place (OOIP). This shows that 270 million barrels of oil are still present in the Upper Pinda reservoir. To be able to recover these oils and increase the recovery factors, it is important to think of new technologies for optimizing wells in operation. If not before the Expiration of the Exploitation contract in 2023, the PERENCO-Rep Company would leave significant quantities in this tank. This can be one of the motivating reasons for the company to renegotiate for the renewal of its contract which goes up to 2040.

Conclusions
The study on the assessment of aquifer performance for oil drainage in the Upper Pinda reservoir, aimed to determine the inflows of water supplied by the aquifer to understand the role played by this aquifer in the oil recovery and possibly determine its performance.
To reach this goal, the use of the Van Everdingen and Hurst equation coupled with the Material Balance equation, borehole geological data and reservoir data collected by the operating company were processed and analyzed to constitute these manuscripts.
From this study we say that the field has a reservoir of lithological nature carbonated, characterized by three dominant facies: 1) The dolomitic facies of good quality and especially containing important hydrocarbon reserves. This facies is met in Upper Pinda 3, 2) calcareous facies, very bad due to their high saturation in water, it is found in Upper Pinda 1 and Upper 2, 3) The very minor sandstone facies in the reservoir has a mean porosity of 22 percent (%). The aquifer is inactive, only allowing it to maintain the reservoir pressure. Its inflows of water calculated at the height of 173,868,933 barrels are not supplied regularly. This aquifer has a drainage index (Iaq) of drainage evaluated at 20%, associated with injection water from the wells, the drainage performance of this aquifer (IWDI) increases significantly up to 84% of drainage index against 16% of other mechanisms that contribute to oil drainage in the Upper Pinda reservoir. This water drainage mechanism in the Upper Pinda reservoir of the Mibale field caused a modification of water oil contact from 5720 to 5500 feet towards the top of the structure, which represents 220 feet during the 42 years of operation due 5. 23 feet per year. This allows us to categorize this aquifer as: linear and semi-radial. The graph of Alvena and Odeh shows that the Stock Tank Original Oil In place (N) is currently 4.5 million barrels with recovery factor 31%. This inactive aquifer is located in the carbonate Karst of Upper Pinda, to the north of the deposit. Being inactive, this aquifer is not at the origin of breakthrough or coning water acting in this field. It is likely that this phenomenon is amplified by water flooding. which allows us to classify water flooding technology among aquifer drainage mechanisms; since this significantly activates the behavior of the aquifer and has the same effects as the aquifer.

Funding
This research has not received any specific grant from funding organizations in the public, commercial or non-profit sectors.