Reservoir Characterization and Formation Evaluation

JOURNAL GEOLOGICAL SOCIETY OF INDIA Vol.87, May 2016, pp.591-600

Reservoir Characterization and Formation Evaluation of a “Royal Onshore Field”, Southern Niger Delta using Geophysical Well Log Data DANIEL N. OBIORA1*, DAVID GBENGA1 and GODWIN OGOBIRI2 1

Department of Physics and Astronomy, University of Nigeria, Nsukka 2 Department of Physics, Niger Delta University, Bayelsa *Email: [email protected]

Abstract: The reservoir properties of three wells in Royal Field, Niger Delta basin was characterized using fundamental formula. The distributions and thicknesses of sand bodies were determined within each of the wells in the field using geophysical modeling software. The quantitative and qualitative analyses were done for the three exploration wells with the depth ranges of 4000-9700m for Royal well 1, 1000-8805m for Royal well 2, and 4000-8000m for Royal well 3. Each well has identified sand units. Royal well 1 and Royal well 2 have 5 sand units (A, B, C, D, E) each, with respective thicknesses 422m, 110m, 92m, 142m and 350m for well 1, and 82m, 65m, 214m, 362m, and 192m for well 2. Royal well 3 has 4 sand units (A, B, C, D), with respective thicknesses 135m, 80m, 269m and 229m. Petrophysical evaluations were made from well logs. The average porosity values obtained for Royal wells 1, 2, and 3 are 0.24, 0.18 and 0.22 respectively while the corresponding average permeability values are 2789mD, 1292mD, 1643mD. Porosity values obtained from porosity logs and density log (RHOB) using porosity formula are found to be within the range of 0.070.45, while their permeabilities range from 164 to 8453 milli Darcy. The water saturation obtained for each reservoir unit in combination with the resistivity index were used to prove the presence of hydrocarbon in these sands. Royal well 2 having its sand A, 80% hydrocarbon saturated and 82m thickness is the most prolific. The results clearly indicate that the application of this technique is very effective for the interpretation of reservoir properties. Keywords: Reservoir properties, Well logs, Hydrocarbon saturation, Permeability, Porosity, Niger Delta.

INTRODUCTION

Geophysical well logging has become a standard operation in petroleum exploration. Identification of geological formations and formation fluids, correlation between holes, and evaluation of the productive capability of the reservoir formations are usually the principal objectives of well logging. Well logging involves measuring the physical properties of surrounding rocks with a sensor located in the borehole. The record of measurement as a function of depth is called a well log. The instrument itself is sometimes called a log, but it really is a logging tool. The “log” is the paper or digital recording of the measurement made by the logging tool, versus depth or time. Log is an indirect measurement of formation properties exposed by a bore well, acquired by lowering a device or a combination of devices in bore well. Borehole geophysical well logging is a procedure to collect and transmit specific information about the geologic formations penetrated by a well by raising and lowering a set of probes or sondes that are water tight instruments in the well.

Where a hole is drilled into a formation, the rock plus the fluids in it (rock-fluid system) are altered in the vicinity of the borehole. The borehole and the rock surrounding it are contaminated by the drilling mud, which affects logging measurements. This is important in maintaining the mud pressure in the borehole to be greater than the formation fluid pressure. Failure to do this may result in a blowout. The amount of contamination is a function of the mud weight (borehole pressure) and the mud water (filtrate) loss. The mud filtering into the formation leaves a mud cake on the wall of the hole. The borehole environment is divided into two zones, the invaded and the uninvaded zones. The invaded zone is an area which is invaded by mud filtrate. It consists of a flushed zone and a transition zone. The flushed zone is close to the borehole where the mud filtrate has replaced nearly all the formation fluid. The transition zone is an area between the flushed zone and the uninvaded zone. The uninvaded zone is an area beyond the invaded zone where mud filtrate is unable to contaminate formation

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fluids. Resistivity is usually high if the zone is a hydrocarbon bearing zone. A resistivity log response across a formation depends on the type of mud used, and the composition of the formation. For a hydrocarbon bearing formation, using a salt based mud filtrate, resistivity will be low in the flushed zone due to presence of mud filtrate, formation water and low amount of residual hydrocarbon. At the transition zone, resistivity tends to increase as more hydrocarbon mix with mud filtrate. Resistivity of the uninvaded zone is much greater than that of the invaded zone because hydrocarbons are fully present and are more resistant than formation water. Well bores are generally drilled by circulating a fresh-water suspension (drilling mud) down through the drill pipe and back to the surface through the annular region between the drill pipe and the rock. Occasionally, salt-water mud, oil, or air is the circulating medium. The circulating drilling fluid removes rock cutting from the bottom of the borehole. The fluids in a rock’s pore spaces (interstitial fluids) are normally under pressure. Their pressure is roughly in balance with that of the borehole fluid. If the borehole pressure were less, the differential pressure would tend to expel interstitial fluid into the borehole. Sufficient solids are added to the mud to make the pressure of the fluid column approximately equal to that of the formation fluids. Mud densities range between 1.1 and 2.0 gm/cm3. Exact balance is rarely achieved, however, and the usual tendency is for the mud to be under slightly greater pressure. This causes the borehole fluid (mud filtrate) to enter porous formations and push the indigenous fluid back from the borehole, a process called invasion. In the invasion process the mud solids plaster the borehole wall to form a mud cake whereas the fluid portion (mud filtrate) enters the formation interstices. The mud cake quickly becomes sufficiently thick (up to 2 to 3 cm) to prevent further entry of borehole fluid into the formation. However, the mechanical aspect of drilling abrades the mud sheath, which is then repeatedly renewed by additional filtrate invasion. Boreholes are ordinarily caged with steel pipe (casting) several times during drilling to provide permanent protection against collapse of the borehole or formation fluid entering the borehole. This is necessary because different formations have different interstitial fluid pressures relative to the borehole fluid pressure, so that the borehole fluid density cannot be adjusted. Open-hole logs are usually run just before setting the casing. Consequently, most well logs consist of portions run at different times. Some logs (casedhole logs) measure through casing and cement. Logging can be done while drilling or after drilling.

Geophysical well logging methods include mechanical methods, passive and a number of active electrical methods (self-potential, resistivity, induction, and induced polarization), nuclear methods (natural γ-ray detection and observations from induced nuclear reactions), acoustic logging and measurement of magnetic and thermal properties. Some researchers (Aigbedoin and Iyayi, 2007; Amigun et al., 2012; Egbai and Aigbogun, 2012) had analyzed the petrophysical parameters of some other oil fields in the Niger delta basin using geophysical well logs. Benjamin and Nwachukwu (2011) used the mode compaction equation to analyze the porosity and assess the compaction status of the hydrostatic sandstone in the Niger delta. Adaeze et al (2012) used integrated petrophysical well log and core data to analyze the reservoir characteristics of Uzek well off shore deposit of the Niger delta basin. The aim of this study is to provide a lithological interpretation, reservoir characteristics and hydrocarbon prospects using geophysical well log data in Royal field, onshore Niger delta basin. This is achieved by: (i) determining the sand units within the wells, (ii) calculating the petrophysical properties of the sands in the field (porosity, permeability, gross thickness, water saturation and hydrocarbon saturation), and (iii) evaluating the production potential of the wells. GEOLOGY OF THE A REA

The study area is the royal field located onshore within the Niger delta basin, Nigeria. The Niger delta lies between longitudes 3 – 9° E and latitudes 4 – 6° N (Fig.1). The Niger delta is a prolific hydrocarbon province and is one of the largest tertiary delta systems in the world. The Niger delta province contains only one identified petroleum system (Kulke, 1995; Ekweozor and Daukoru, 1994) referred to as the Tertiary Niger Delta (Akata –Agbada) Petroleum System. It has proven recoverable reserves of 35 billion barrels of oil, condensate and 184Tcf of gas (NNPC, 2005). The Niger delta is geologically very unique since it typifies the most classic delta. It covers an area of about 75,000sq km and is a prograding complex. The geological configuration, stratigraphy and structural formation of the Niger delta basin have been discussed extensively (Whiteman, 1982; Adejobi and Olayinka, 1997; Bilotti and Shaw, 2005; Owoyemi and Willis, 2006; Obaje, 2009). The Niger delta is a sedimentary basin, composed of numerous complex regressive offlap sequences of clastic sediments. Its thickness ranges from 9000-12000m. The digitations of a small number of different rock types pose a difficult JOUR.GEOL.SOC.INDIA, VOL.87, MAY 2016

RESERVOIR CHARACTERIZATION OF A “ROYAL ONSHORE FIELD”, SOUTHERN NIGER DELTA

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ROYAL FIELD

Fig.1. Map showing the location of the study area within Niger delta basin (Google map, www.google.com/map)

task of defining a stratigraphic nomenclature. Short and Stauble (1967), from deep wells evidence, were able to discriminate three major lithofacies based on dominant environmental differences in which a regressive sequences were clearly defined. The sedimentary environments are continental, transitional and marine. The basal unit is the massive marine shales, the intermediate unit is the interbedded shallow marine and fluvial sands, silt and clay and top unit that caps the sequence is a massive continental sands. They are readily identifiable as three regional and diachronous formations, since the delta has been prograding uninterrupted throughout the Tertiary, though, there are localized variations in lithofacies. From the bottom up, the lithofacies are known as Akata Formation, Agbada Formation and Benin Formation as shown in Fig.2. Petroleum in the Niger delta is produced from sandstone and unconsolidated sands predominantly in the Agbada Formation. Reservoir characteristics of the Agbada Formation are controlled by depositional environment and depth of burial. Most known reservoir rocks are Eocene to Pliocene in age, and are often stacked, ranging in thickness from 15 meters to 45 meters thickness. The physical and chemical properties of the oil in the Niger delta are highly variable, even down to the reservoir level. The oil within the delta has a gravity range of 16-50° API (American Petroleum Institution), with the lighter oils having a greenishbrown color. Fifty-six percent of Niger delta oils have API gravity between 30°- 40°. JOUR.GEOL.SOC.INDIA, VOL.87, MAY 2016

SOURCE OF DATA

Three geophysical well logs which was recorded in May/June, 2010 at various locations within the Royal field, Niger delta basin by AP (Nig) limited were employed in this study. The location of the wells are shown in Figs. 3.1, 3.2, and 3.3. Various sand and shale units were identified

Fig.2. Geological formations of Niger delta Area (Doust and Omatsola, 1989)

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SAND A

SAND B

SAND A

SAND B SAND C

SAND C SAND

SAND SHALE

SAND D

SAND D

SAND E

SHALE

GR- Gamma Ray log; CALI-Caliper log; NPHI-Neutron l og; RHOB- Density log; DT-Sonic log; ILD-Deep Induced log; MSFL- Micro-Spherical Focus log.

Fig. 3.1. Log suite of Royal well 1 GR- Gamma Ray log; CALI-Caliper log; NPHI-Neutron l og; RHOB- Density log; DT-Sonic log; ILD-Deep Induced log; MSFL- Micro-Spherical Focus log.

Fig.3.3. Log suite of Royal well 3

procedure was aimed at bringing out the lithology, reservoir, its size, complexity, productivity, and the type and quantity of fluid it contains. Results were used to locate and estimate the economic prospects of the wells already drilled. An analysis suitable for this case was adopted for the description of the lithologic units of interest (reservoirs) that were intersected by the respective wells.

BENIN FORMATION WHICH IS MAINLY WATER RESERVIOR

SAND A SAND B SAND

SAND C

SHALE SAND D SAND E GR- Gamma Ray log; CALI-Caliper log; NPHI-Neutron l og; RHOB- Density log; DT-Sonic log; ILD-Deep Induced log; MSFL- Micro-Spherical Focus log.

Fig.3.2. Log suite of Royal well 2.

within each of the wells as marked out in the figures. The software used in the analysis of data is Petrel. METHODOLOGY

The evaluation of formations in most cases often involves a detailed qualitative and quantitative estimation of reservoirs and the fluid in it. This helps in understanding the geologic conditions of a given area. The analytic

Qualitative Log Interpretation

Qualitative log interpretation is based on the visual observation of the logs to determine zone of interest. It is primarily concerned with shape, characteristic signature and physical model of the relevant well log. It involves the identification of permeable and impermeable beds. Also bed thickness and depth to various fluids can also be determined. The gamma ray log which measures natural radioactivity in formations, was used in the identification of sand/shale lithology. The log is represented in track 1 of Fig.3.1, 3.2, and 3.3, and is scaled from 0 to 150 API units which are increasing from left to right. As a result of the concentration of radioactive materials in shale, gamma ray response will be high, while lack of radioactive materials or its low concentration in sand formation will result in low gamma ray response. Therefore, a maximum deflection to the right of a gamma ray log is an indication of the presence of shale, JOUR.GEOL.SOC.INDIA, VOL.87, MAY 2016

RESERVOIR CHARACTERIZATION OF A “ROYAL ONSHORE FIELD”, SOUTHERN NIGER DELTA

while a minimum deflection to the left is indicative of sand lithology. The gross reservoir thickness was determined by knowing interval covering both sand and shale within the reservoir studied, using gamma ray log. Net sand thickness was determined by subtracting the interval covering the shale from gross reservoir thickness (Gross reservoir thickness interval is the interval covering shale and sand within a reservoir. Net thickness of sand is the interval covering sand only within a reservoir. It is called net productive sand). Well log data were used in this analysis to generate rock. The reservoir fluids were characterized using neutronporosity and bulk-density logs. Edited well log data were used to generate the logs with the aid of Petrel software. Petrel software was chosen to generate the logs because it is window based software for visualizing the sub-surface with a user interface based on the windows Microsoft standards. A combination of the gamma ray log and deep laterolog were used to differentiate between hydrocarbon and nonhydrocarbon bearing zones. The deep laterolog is represented in track-2 of wire line logs in Figs. 3.1, 3.2 and 3.3. The scale increases from left to right with a range of 0.2 to 2000 ohm meters. Hydrocarbons are nonconductive, and are located within porous and permeable sand. Thus, as hydrocarbon saturation pores increases, resistivity also increases. Therefore, an increase in resistivity on a resistivity log along with a corresponding minimum deflection to the left of gamma ray log indicates the presence of a hydrocarbon bearing reservoir, while a decrease in resistivity along with corresponding minimum deflection to the left of gamma ray log indicates a water bearing reservoir. The reason being that water due to its conductivity will have a corresponding low resistivity. Hydrocarbon bearing reservoirs in the three wells were located, identified, digitized and named using; (i) gamma ray log to establish reservoir boundaries, (ii) a relatively high resistivity value within an established reservoir defines a hydrocarbon bearing reservoir (Archie, 1942), (iii) the reservoirs were then identified and the depth interval subjected to detailed study, (iv) the top of the reservoirs were defined using stratigraphical approach. The reservoir fluids were characterized by using a combination of neutron porosity and bulk-density logs. The formation density compensated and neutron logs were used for the differentiation of the various fluid types. An increase in density porosity log along with a decrease in neutron porosity log in a gas-bearing zone is called gas effect. Gas effect is created by gas in the pores. Gas in the pores causes the density log to record very high porosity, (because JOUR.GEOL.SOC.INDIA, VOL.87, MAY 2016

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gas is lighter than oil or water), and causes the neutron log to record too low a porosity (because gas has a lower concentration of hydrogen atoms than oil or water) (Asquith and Gibson, 1982). Thus an increase in contrast between density porosity and neutron porosity logs is an indication of a gas zone, while a decrease in density porosity and neutron logs indicates oil or water-bearing reservoir. Therefore, the combination of neutron-density log is an effective tool used to differentiate between gas, oil and water. Quantitative Log Interpretation

This includes the use of empirical formula to estimate the reservoir parameters such as volume of shale, formation factor, porosity, water saturation, permeability, hydrocarbon saturation etc. Calculations of such reservoir parameters will help to determine if a reservoir is exploitable. The gamma ray log was used to calculate the volume of shale (Vsh) in a porous reservoir. The first step used to determine the volume of shale from a gamma ray log was to calculate the gamma ray index using (Asquith and Gibson, 1982)

I GR =

GRlog − GRmin

(1)

GRmax − GRmin

where IGR is the gamma ray index, GRlog is the gamma ray reading of the formation, GR min is the minimum gamma ray (clean sand), GRmax is the maximum gamma ray (shale). All these values were read off within a particular reservoir. Having obtained the gamma ray index, the volume of shale was then calculated using (Dresser Atlas, 1979);

(

)

V sh = 0 ⋅ 83 2 3⋅7 I GR − 1

(2)

Porosity (ϕ) is defined as the percentage of voids to the total volume of rock. The formation density log was used to determine formation porosity. The formation porosity was determined by substituting the bulk density readings obtained from the density log within each reservoir into the formula (Asquith and Gibson, 1982);

ϕ=

ρ ma − ρ b ρ ma − ρ f

3

where ϕ is the porosity, ρma = 2.65gm/cc (sandstone), ρf = 1.0gm/cc (fluid density), ρb is the formation bulk density. The formation factor (F) was determined from (Archie, 1942)

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F=

a

ϕ

4

m

where ϕ is Porosity, a is lithologic constant (0.62) and m is cementation exponent (2 for sands). Using the Archie’s equation that related the formation factor (F) to the resistivity of a formation at 100% water saturation (Ro) and the resistivity of formation water (Rw), the resistivity of the formation water was estimated using

Rw =

R0 F

F × Rw Rt

6

F=

R0 Rw

7

S w2 =

R0 Rt

8

But

Thus,

where Sw is the water saturation of the uninvaded zone, Ro is the resistivity of formation at 100% water saturation, Rt is the true formation resistivity. In flushed zone, water saturation from empirical observation is given as: SX0 = (Sw)0.2 Sxo is the water saturation of the flushed zone and Sw is the water saturation of the uninvaded zone. Irreducible water saturation (Swirr) is the water held in the pore spaces by capillary forces. When a zone is at irreducible water saturation, the water saturation in the uninvaded zone (Sw) will not move because it is held on grains by capillary pressure. For most reservoir rocks, irreducible water saturation ranges from less than 10% to more than 50% (Schlumberger, 1972). It was determined from (Asquith and Gibson, 1982)

S wirr =

F 2000

250 × ϕ 3 K= S wirr

9

Where F is the Formation factor and S wirr is the Irreducible water saturation. Permeability (K) is the property of a rock to transmit fluids. It is controlled by the size of the connecting passages (pore throats or capillaries) between pores. It is measured

10

where k is the permeability, ϕ is the porosity and Swirr is the irreducible water saturation. The product of formation water saturation (Sw) and its porosity (ϕ) is the bulk volume water (BVW), BVW = Sw x ϕ

5

Determination of the water saturation for the uninvaded zone was achieved using the Archie’s equation given as

S w2 =

in darcies or millidarcies. The permeability of each reservoir that was identified, was derived from (Tixier, 1949)

11

where BVW is the bulk volume water, Sw is the water saturation and ϕ is the Porosity If values for bulk volume water calculated at several depths in a formation are constant or very close to constant, they indicate that the zone is homogenous and at irreducible water saturation (Asquith and Krygowski, 2004). When a zone is at irreducible water saturation, water calculated at the uninvaded zone (Sw) will not move because it is held on grains by capillary pressure. Therefore, hydrocarbon production from a zone at irreducible water saturation should be water free (Morris and Biggs, 1967). Hydrocarbon saturation (Sh) is the percentage of pore volume in a formation occupied by hydrocarbons. It was obtained by subtracting the value obtained for water saturation from 100%, that is, Sh = (100 – Sw)% where Sh is the hydrocarbon saturation, and Sw is the water saturation The resistivity log was used to determine the nature of the fluid contained within the interstices of rock units. It clearly identifies zones filled with water or hydrocarbon. Then the crossplot of neutron and density logs were employed to further differentiate oil bearing zones from gas bearing zones since the fluid content also affects these porosity tools. Correlation

Correlation of equivalent strata from one well to another was one of the first uses of well logs (Schlumberger, 1972). It involves the determination of equivalence in geologic age or position of a sequence of the subsurface in two or more locations, that is, intervals of logs from different wells are matched for similarity using visual process which enables the identification of similar features at different localities. Well to well correlation studies permits accurate subsurface mapping and determination of the following: presence of faults; whether well depth has reached a new productive horizon and if not approximately how much to be drilled; JOUR.GEOL.SOC.INDIA, VOL.87, MAY 2016

RESERVOIR CHARACTERIZATION OF A “ROYAL ONSHORE FIELD”, SOUTHERN NIGER DELTA

the elevation of the formations present in the well relative to the other wells, outcrop or geophysical projection; the existence of dips, folds, unconformities (the thickening and thinning of lithological sections, or lateral changes of sedimentation). Having set up a correlation panel, the first step is to identify an event or marker that is laterally continuous and therefore present in almost, if not all the wells. Sand and carbonates are not laterally extensive owing to their mode of deposition; therefore it is normal to use shale in the first stage of correlation as these represent low energy, laterally extensive bodies. As low energy deposits, they are laid down close to the horizontal on the field. The gamma ray log and resistivity logs were used for correlation in this work. The two forms of correlation done in this work include lithology and reservoir correlations. The gamma ray log was used to identify similar features at different localities. That is, it involved the correlation of equivalent strata from one well to the next in order to determine similarity or equivalence of lithology in two or more wells. This was achieved using similarity in gamma ray log signatures in the different wells. The log measures natural radioactivity in formation. This enabled the zoning of the study area into alternating sand and shale sequence. Potential reservoirs across the three wells which correspond to equal depths were determined using the gamma ray log and resistivity logs. This is with a view to calculate reservoir parameters across wells in order to make useful quantitative deductions. RESULTS AND DISCUSSION

The quantitative and qualitative analyses were done for the three exploration wells shown in Figs. 3.1, 3.2 and 3.3 with the depth ranges of 4000-9700m for Royal well 1, 10008805m for Royal well 2, and 4000-8000m for Royal well 3. The reservoir’s petrophysical parameters have been computed and tabulated in Table 1. The logs used in this study include resistivity logs, gamma ray (GR), neutron porosity (NPHI) log, and bulk density (RHOB) log. The lithologic units within the area of interest were correlated to identify their lateral and vertical extent using a combination of gamma ray (GR) and resistivity logs respectively. Gamma ray value less than 80API indicates sand unit while values above 80API indicates shale unit. Shale bed was used as a reference datum for the correlation. The suite of borehole logs was loaded and analyzed using the Petrel Software. The various lithologies within the wells across the field were mapped first using lithologic log (gamma ray log). Lithology was identified by defining shale JOUR.GEOL.SOC.INDIA, VOL.87, MAY 2016

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baseline (SBL) using a cutoff value of 80API, which is constant line separating shale from sand. Low gamma radioactivity is an indication of sand, while high, that is, positive inflection of log curve is an indication of shalyness. Electrical logs were used to indicate the fluid type that occurred in a reservoir while porosity logs were used for porosity calculation. Petrophysical parameters such as, permeability, volume of shale, water saturation, hydrocarbon saturation, and irreducible water saturation were calculated and the results presented in Table 1. Royal Well 1

Five sand units were identified; sand A, B, C, D and E with thickness ranging from 92m-422m. Their porosity were estimated by means of density logs, and was found to be within the range of 0.09 - 0.45, with sands A, B, C, D, E having values 0.26, 0.23, 0.19, 0.09, 0.45 respectively. The porosity value decreases down the depth but increases in sand E. The high porosity value obtained in sand E is as a result of micro porosity known to occur in clay and shale materials. The presence of shale is explained by the high gamma ray average value of 77API within the sand, which is very close to the cut off value of 80 API. The permeability ranges from 225 to 8453 milli Darcy, with sand D having the lowest value of 225 milli Darcy which is a good permeable value and sand A, B, C, and E having values 2166, 1916, 1128, 8453 milli Darcy respectively, which are excellent permeable values for free flow of reservoir fluids. Comparing the value of porosity 0.45 in sand E, it is expected that the corresponding permeability should be low because pore spaces in clay materials are not connected to allow free flow of fluid. Therefore, the high value of permeability of 8453mD might be as a result of naturally fractured (or even hydraulically fractured) formation. Permeability will be higher because the isolated pores are interconnected by the fractures (Halliburton, 2001). The hydrocarbon saturation in Royal well 1 ranges from 2% to 55% while water saturation ranges from 45% to 98% showing that the well is water predominant. Sands C and D have approximate equal percentage of water and oil while sands A, B, and E are considered as water reservoirs (Fig.4a) Royal Well 2

Five sand units were also identified; sand A, B, C, D, and E with thickness ranging from 65m-362m. Their porosity was found to be within the range of 0.07- 0.25 with sand A, B, C having 0.25, 0.24, 0.24 values respectively, which is a very good porosity value while sands D and E have 0.08

598

DANIEL N. OBIORA AND OTHERS Table 1. Summary of the obtained and computed petrophysical parameters for the wells ^E hE/d^

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