Integration of Seismic and Petrophysics to Characterize Reservoirs in ‘‘ALA’’ Oil Field, Niger Delta

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Hindawi Publishing Corporation The Scientific World Journal Volume 2013, Article ID 421720, 15 pages http://dx.doi.org/10.1155/2013/421720

Research Article Integration of Seismic and Petrophysics to Characterize Reservoirs in ‘‘ALA’’ Oil Field, Niger Delta

P. A. Alao, S. O. Olabode, and S. A. Opeloye

Department of Applied Geology, Federal University of Technology Akure, P.M.B 704 Akure, Ondo State, Nigeria

Correspondence should be addressed to P. A. Alao; [email protected]

Received 9 April 2013; Accepted 25 June 2013

Academic Editors: M. Faure and G.-L. Yuan

Copyright © 2013 P. A. Alao et al. This is an open access article distributed under the Creative Commons Attribution License, which permits unrestricted use, distribution, and reproduction in any medium, provided the original work is properly cited.

In the exploration and production business, by far the largest component of geophysical spending is driven by the need to characterize (potential) reservoirs. The simple reason is that better reservoir characterization means higher success rates and fewer wells for reservoir exploitation. In this research work, seismic and well log data were integrated in characterizing the reservoirs on “ALA” field in Niger Delta. Three-dimensional seismic data was used to identify the faults and map the horizons. Petrophysical parameters and time-depth structure maps were obtained. Seismic attributes was also employed in characterizing the reservoirs. Seven hydrocarbon-bearing reservoirs with thickness ranging from 9.9 to 71.6 m were delineated. Structural maps of horizons in six wells containing hydrocarbon-bearing zones with tops and bottoms at range of −2,453 to −3,950 m were generated; this portrayed the trapping mechanism to be mainly fault-assisted anticlinal closures. The identified prospective zones have good porosity, permeability, and hydrocarbon saturation. The environments of deposition were identified from log shapes which indicate a transitional-to-deltaic depositional environment. In this research work, new prospects have been recommended for drilling and further research work. Geochemical and biostratigraphic studies should be done to better characterize the reservoirs and reliably interpret the depositional environments.

1. Introduction 2. Geologic Setting Reservoir characterization has evolved through three gener- The study area is located in the Cenozoic Niger Delta ations—based originally in petrophysics, then on geologic (Figure 1) which is situated at the intersection of the Benue analogs, and more recently on multidisciplinary integration. Trough and the South Atlantic Ocean where a triple junction The petrophysical approach begun in the 1950s, where reser- developed during the separation of the continents of South voir attributes were determined using logs, cores, and well America and Africa in the late Jurassic [2]. Subsidence of the tests. The second generation based principally on geologic African continental margin and cooling of the newly created analogs added the concept between wells. The analog tech- oceanic lithosphere followed this separation in early Creta- nique improved interwell prediction, but identifying the right ceous times. The Niger Delta started to evolve in early Tertiary analog often proved difficult, especially in structurally and times when clastic river input increased [3]. Generally, the stratigraphic complex settings. Multidisciplinary approach, delta prograded over the subsidizing continental-oceanic the third generation, attempts to integrate all available geo- lithospheric transition zone and during the Oligocene spread logic, engineering, and geophysical data along with mod- onto oceanic crust of the Gulf of Guinea [4]. The weathering ern probabilistic and risk analysis techniques to produce a flanks of outcropping continental basement sourced the better reservoir model [1]. This third generation reservoir sediments through the Benue-Niger drainage basin. The delta made significant use of 3D seismic amplitude anomalies and has since Paleocene times prograded a distance of more than other complex trace attributes to define field development 250 km from the Benin and Calabar flanks to the present programs. This multidisciplinary approach was used in this delta front [5]. Thickness of sediments in the Niger Delta 2 research work. averages 12 km covering a total area of about 140,000 km . 2 The Scientific World Journal

478400 479200 480000 480800 481600 482400 483200 484000 484800 485600

72000 72000

71200 71200

70400 70400

69600 ALA 02 69600 ALA 05 ALA 04 ALA 01 68800 68800

ALA 03ST 68000 ALA 06I 68000

67200 67200

66400 66400

65600 65600

64800 64800 Figure 1: Location of “ALA” field in the Niger Delta. 478400 479200 480000 480800 481600 482400 483200 484000 484800 485600

The stratigraphic sequence of the Niger Delta comprises three 1 : 50000 broad lithostratigraphic units: a continental shallow massive 0 500 1000 1500 2000 2500 sand sequence—Benin Formation, a coastal marine sequence (m) of alternating sands and shales—Agbada Formation, and Figure 2: Basemap showing location of the wells. a basal marine shale unit—Akata Formation. The Benin Formation is characterized by high sand percentage (70– 100%) and forms the top layer of the Niger Delta depositional sequence. The Agbada Formation consists of alternating sand and shales representing sediments of the transitional environment. The sand percentage within the Agbada For- mation varies from 30 to 70%, which results from the large number of depositional offlap cycles. The Akata Formation consists of clays and shales with minor sand intercalations. The sediments were deposited in prodelta environments. The sand percentage here is generally less than 30% [6].

3. Methodology Data set used in this study includes 3D seismic and 6 Figure 3: Synthetic seismogram of well ALA 04. well logs provided by Chevron Nigeria Limited (CNL). The structure of the field of study was interpreted using 3Dseismicdatawhichwasintegratedwithwelllogs.The This impedance was converted to reflectivity, which was then inline and crossline numbers range from 5800 to 6200 and converted from depth to time using an appropriate wavelet to from 1480 to 1700, respectively. The reflection quality of produce a synthetic seismogram for well ALA 04 (Figure 3) the data is very good; faults and stratigraphic picks for totiethewellstoseismic. horizons are easily recognizable. The wells (ALA 01, ALA Thewellsusedforthisstudywereplottedastheyappeared 02, ALA 03ST, ALA 04, ALA 05, and ALA 06I) penetrated onthebasemap(Figure 2), that is, from west to east. The depths of −13,019.00 ft (3968.19 m), −12996.00 ft (3961.18 m), plot revealed that the sands reduced in thickness going from −13000.69 ft (3962.61 m), −11,541.5 ft (3517.85 m), −11674.50 ft west to east. The direction of deposition of the sands was (3558.38 m), and −13088.50 ft− ( 3989.37 m). In order to thus inferred to go from proximal (west) to distal (east). increase the accuracy of subsurface imaging, generate maps Sand units of interest were carefully picked and correlated and well log cross-sections, geophysical softwares like SMT across the wells to give an idea of the continuity of the Kingdom Suite, Schlumberger’s Petrel, and Senergy’s Inter- reservoirs at different depths across the whole survey area. active Petrophysics were used to produce a comprehensive Petrophysical parameters obtained in the course of study geophysical and geological evaluation of the study area. The includes volume of shale, porosity (effective and total), net- acoustic velocities from the sonic logs were multiplied by to-gross ratio, water and hydrocarbon saturation (moveable density log to compute new acoustic impedance (AI) log. and residual), irreducible water saturation, bulk volume of The Scientific World Journal 3

Subaerial channel sands Delta distributary channel fill Point bars Barrier bars

Interdistributary Mature beach Abrupt Gradational beach timing timing Cylinder Bell Bell Hybrid Distributary channel Barrier foot

Barrier bar sand Tidal channel sands Transitional barrier Outer Inner bar and lagoon Barrier bar Distributary mouth bar Tidal Tidal Bar foot channel ﬂat

Flower pot Serrated Multiple bars

(a) (b)

Figure 4: Gamma ray and resistivity log shapes suggestive of depositional environment: (a) After Busch, 19757 [ ]; (b) Schlumberger, 1985 [8]. water, permeability, and fluid discrimination. The fluid types Table 1: Fault throw estimation. were discriminated using the neutron-density log. In order Fault Reservoir Throw (m) Throw (ft) to properly characterize the reservoir sands delineated and G 83.227 273.054 correlated across the studied wells, a plot of 𝑆𝑤 versus Φ (i.e., Buckles plot) was made to determine whether or not Major fault (M1) D 192.150 630.413 the sands are at irreducible water saturation. The depositional A—— environments were inferred from gamma and resistivity log G 54.731 179.564 motifs after Busch and Schlumberger models (Figures 4(a) Major fault (M2) D 58.827 193.002 and 4(b)). A—— G—— 4. Results and Discussion Minor fault (F1) D 15.961 52.365 Time structural contour maps were produced for three A 20.561 67.457 horizons defined on top of sand bodies, namely, Hor A, G 30.906 101.398 Hor D, and Hor G. The maps generated revealed two major Minor fault (F2) D 99.267 325.679 faults (M1 and M2) which are growth faults and are very A—— extensive (Figures 5 and 6). The major faults trend NE-SW and dip south terminating at the northwest flank of the field. The major faults show a subparallel relationship. The field are good hydrocarbon prospects in the Niger Delta [10]. The is dissected by several crestal synthetic and antithetic faults. wells in this field are located on the downthrown block of Most northerly minor faults are synthetic to the major fault the major fault M2 (Figures 8(a) and 8(b)), in the rollover M2; those at the central parts are antithetic. These intrafield anticlines formed against the fault. The capability of the faults small-displacement faults are of varying lengths and most to act as seals depends on the amounts of throw and the run almost parallel to the north bounding major structure volume of shale smeared along the fault planes [10]. Faults building fault. The field structure generally strikes almost couldactassealsifeitherthethrowsarelessthan150m,or perpendicular to the major structure building fault. The thevolumeofshalesmearedalongthefaultplaneismore structure climbs to the east where the highest points in most than 0.25 (25%). Cross-sections (Figure 7) were generated of the reservoirs encountered in all the wells drilled on the to further comprehend the relationship between the faults field are recorded. and the horizons. The throws of the faults were estimated Sand development in Ala field is somewhat uniform west- in this research (Table 1). Poststack seismic attributes as east across the field but better developed towards the main acoustic amplitude, RMS amplitude, maximum amplitude, structure building fault. Growth faults and anticlines are and average energy which are direct hydrocarbon indicators apparent on this field which serves as traps acting either as weregeneratedforthereservoirsmappedtoapprehendthe fault assisted as in minor fault F2 or anticline closures as in geological framework and be able to predict new prospects. faults F2 and F5 [9]. The anticlines and fault-assisted closures From the acoustic amplitude attribute map of reservoir A 4 The Scientific World Journal

478000 480000 482000 484000 486000 488000 Time Time 478000 480000 482000 484000 486000 488000 −2160 72000 72000 −2460 72000 72000 F6 −2220 F1 F5 F6 71000 F7 71000 −2520 71000 F1 71000 −2280 70000 70000 70000 F5 70000 −2580 F3 −2340 F2 M2 69000 M2 69000 69000 F2 69000 −2640 −2400 F4 68000 68000 68000 F4 68000 − M1 −2460 67000 M1 67000 2700 67000 M1 67000 −2520 66000 66000 − 66000 66000 2760 − 65000 65000 2580 65000 65000 − 2820 −2640 64000 64000 64000 64000 −2880 −2700 63000 63000 63000 63000 − − 62000 2760 62000 62000 2940 62000 61000 −2820 −3000 61000 61000 61000 − 60000 60000 2880 60000 60000 −3060 478000 480000 482000 484000 486000 488000 478000 480000 482000 484000 486000 488000 (m) (m) 0 1000 2000 3000 4000 5000 0 1000 2000 3000 4000 5000 1 : 78125 1 : 78125 (a) (b)

Figure 5: Time structure map for reservoirs A and D. (a) Time structure map for reservoir A (b) Time structure map for reservoir D.

478000 480000 482000 484000 486000 488000 Time moderate amplitude ranging from 20 to 53 while closure 2 72000 72000 −2000 has amplitude as high as 98. This fact is further buttressed on F5 −2020 71000 F6 71000 the maximum amplitude and average energy attribute map −2040 (Figure 8(c))withclosure1havingvaluesrangebetween80– 70000 70000 −2060 F3 − 100 and 1680–4030, respectively, while closure 2 has values as 69000 M2 69000 2080 F2 −2100 high as 130 and 7985. A third closure (closure 3) situated at the 68000 68000 − M1 2120 southwestern part of the map is also amplitude supported but − 67000 67000 2140 notconspicuous;thisismostlikelynothydrocarboncharged F4 −2160 66000 66000 −2180 asthehighamplitudeherecouldbeasaresultofhighnet-to- − gross ratio (thick sand deposition). 65000 65000 2200 −2220 For reservoir D, the high amplitude is evidenced on 64000 64000 −2240 − closure 1 (Figure 9), which indicates the presence of hydro- 63000 63000 2260 −2280 carbon. From the Rms amplitude (Figure 9(b)), high ampli- 62000 62000 −2300 tude was observed on closure 1, the northwestern area and − 61000 61000 2320 northeasternedgeofthemap.Thehighamplitudesobserved −2340 on the northwestern area, and northeastern edge of the 60000 60000 −2360 478000 480000 482000 484000 486000 488000 map most likely would be a result of sand deposition in the area since there is no structure which could support (m) 0 1000 2000 3000 4000 5000 hydrocarbon accumulation; this same pattern is also evident 1 : 78125 on the maximum amplitude and average energy attribute maps (Figures 9(c) and 9(d)). Interestingly, rms amplitude, Figure 6: Time structure map for reservoir G. maximum amplitude, and energy in closure 1 are as high as 120,100,and12400,respectively.Fromtheattributemaps (Figure 8(a)), two closures—the closure against the fault F2 generated for reservoir G (Figure 10), high amplitude on (closure 1) and that against F5 (closure 2)—are amplitude sup- closure 1 is not very conspicuous on all the attribute maps, but ported which serve as leads for future drilling project. These it still was fairly distinct from the surrounding environment. areas are bright spots which are indicative of hydrocarbon This sparse hydrocarbon occurrence was also observed on presence. the well logs, as only ALA 01 showed the presence of Closure 2 which is a prospect area conspicuously has hydrocarbon. Most distinct on the attribute maps is the high higher amplitude than the present area (closure 1) where all amplitudeonanisolatedgeologicfeature(whichismost the present wells are drilled (Figure 8). This trend is also likelyhydrocarboncharged)inthenorthcentralpartof noticed on all other amplitude attribute maps generated. On the maps except for the acoustic amplitude map where low the Rms amplitude attribute map (Figure 8(b)), closure 1 has amplitude was depicted. The Scientific World Journal 5

XLine 1590 XLine 1480 XLine 1647 XLine 1590 XLine 1505 IL 5925 5925 5925 5925 5925 5925 XL 1700 1660 1620 1581 1541 1501 0 −250 −500 −750 −1000 −1250 −1500 −1750 −2000 −2250 −2500 −2750 −3000 −3250 −3500 −3750 −4000 −4250 −4500 −4750 −5000 (a) (b) 1000 − 0 1000 2000 3000 4000 5000 6000 7000 8000 −1400 ALA 05 −1400 Wells −1600 −1600 −1800 −1800 −2000 −2000 Hor G − − 2200 Hor G 2200 Hor D −2400 −2400

−2600 Hor A −2600 − − 2800 Hor D 2800 −3000 −3000 −3200 −3200 −3400 −3400 0 1000 3000 4000 5000 6000 7000 8000 1000 2000 − (m) 0 500 1000 1500 2000 2500 1 : 69152 Major fault A Minor fault 2 Major fault B ALA 02 Minor fault 1 ALA 05 (c) Figure 7: (a) Cross-section path. (b) Seismic section showing the displacement of the reservoir sands. (c) Cross-section showing displacement of the three sands mapped.

Thesixwellslocatedwithinthefieldpenetratedthetwo 06I, only reservoir sand D is hydrocarbon bearing which upper lithological zones of the Niger Delta. The first zone lies is evident with the high resistivity in the sand (Figure 11). between the depth intervals of 0 ft to −7972.44 ft (−2432 m) The reservoir interval is between 10821.5 and 11467.5 ft. The and comprised mainly thick sand bodies with few very thin petrophysical parameters derived for this reservoir is shown shale interbeds. The second lithological zone extends from in Table 2. The pay interval is relatively dirty which is the depth of −7972.44 ft (−2432 m) to about −13088.50 ft noticeable on the neutron density crossplot with the data (−3989.37 m) as shown in Figure 11. points clustering around the sandstone (SS) to limestone (LS) From the well logs, eight reservoirs were delineated, three index line (Figure 12(b)). At interval 10830.50 ft, there was a of which were mapped across the seismic section. In ALA glaring change in the petrophysical parameters, the porosity 6 The Scientific World Journal

478000 480000 482000 484000 486000 488000 Seismic Surface 72000 72000 478000 480000 482000 484000 486000 488000 attribute 100 71000 71000 72000 72000 71000 71000 90 70000 70000 70000 70000 69000 69000 80 69000 69000 68000 68000 70 68000 68000 67000 67000 67000 67000 60 66000 66000 0 66000 66000 50 65000 65000 65000 65000 40 64000 64000 64000 64000 63000 63000 63000 63000 30 62000 62000 62000 62000 20 61000 61000 61000 61000 10 60000 60000 60000 60000 478000 480000 482000 484000 486000 488000 478000 480000 482000 484000 486000 488000 (m) (m) 0 1000 2000 3000 4000 5000 0 1000 2000 3000 4000 5000 1 : 78125 1 : 78125 (a) (b) Surface Surface 478000 480000 482000 484000 486000 488000 attribute 478000 480000 482000 484000 486000 488000 attribute 72000 72000 130 72000 72000 71000 71000 120 71000 71000 8000 70000 70000 110 70000 70000 7000 69000 69000 100 69000 69000 68000 68000 90 68000 68000 6000 80 67000 67000 67000 67000 70 5000 66000 66000 66000 66000 60 65000 65000 4000 50 65000 65000 64000 64000 40 64000 64000 3000 63000 63000 30 63000 63000 2000 62000 62000 20 62000 62000 61000 61000 10 61000 61000 1000 0 60000 60000 60000 60000 478000 480000 482000 484000 486000 488000 478000 480000 482000 484000 486000 488000 (m) 0 1000 2000 3000 4000 5000 (m) 1 : 78125 0 1000 2000 3000 4000 5000 1 : 78125 (c) (d)

Figure 8: Seismic attribute maps for reservoir A. (a) Acoustic amplitude map for reservoir A. (b) Rms amplitude map for reservoir A. (c) Maximum amplitude map for reservoir A. (d) Average energy for reservoir A. increased from 16.53% to 21.55% with a decrease in the water reservoirs (Table 3). Reservoir A has the highest net pay saturationandvolumeofshalefrom48.40to29.19%and51.75 in all the reservoirs (Figure 11(b) and Table 3). The buckles to 40.85%, respectively. The buckles plot (Figure 12(a))reveals plot reveals that the reservoirs are not at irreducible water that the reservoir is not at irreducible water saturation as the saturation as the data points do not align along the BVW data points do not align along the BVW hyperbolic curve. hyperbolic curve except for reservoir A which shows fair Three reservoirs (A, B, and H) were delineated in ALA 05. alignment. The reservoir intervals are 10881.07–10935.92 ft, and 11012.93– Threereservoirs(A,C,andD)weredelineatedinALA 11120.62 ft, 11179.47–11215.97 ft for reservoirs B, A, and H, 04. The reservoir intervals are 11126.00–11253.50 ft, 10540.50– respectively. Petrophysical parameters were derived for the 10630.00 ft, and 9565.50–10038.00 ft for reservoirs A, C, and The Scientific World Journal 7

Table 2: Average petrophysical parameters for ALA 06I. Φ 𝑆 𝑆 𝑉 𝑆 𝑉 𝑉 𝐾 Sand unit Net (ft) Gross (ft) 𝐸 (%) 𝑤 (%) 𝐻 (%) sh (%) NGR (%) wirr (%) BVW hydt rock (md) OWC (ft) D 22.00 670.25 18.57 35.70 64.30 45.60 80.80 11.47 0.08 0.11 0.41 490.672 10853.80

478000 480000 482000 484000 486000 488000 Seismic Surface 72000 72000 478000 480000 482000 484000 486000 488000 attribute 72000 72000 120 71000 71000 71000 71000 110 70000 70000 70000 70000 100 69000 69000 69000 69000 90 68000 68000 68000 68000 80 67000 67000 67000 67000 70 66000 66000 0 66000 66000 60 65000 65000 65000 65000 50 64000 64000 64000 64000 40 63000 63000 63000 63000 30 62000 62000 62000 62000 20 61000 61000 61000 61000 10 60000 60000 60000 60000 0 478000 480000 482000 484000 486000 488000 478000 480000 482000 484000 486000 488000 (m) 0 1000 2000 3000 4000 5000 (m) 0 1000 2000 3000 4000 5000 1 : 78125 1 : 78125

(a) (b) Surface Surface 478000 480000 482000 484000 486000 488000 attribute 478000 480000 482000 484000 486000 488000 attribute 72000 72000 140 72000 72000 16000 71000 71000 130 71000 71000 14000 120 70000 70000 70000 70000 110 69000 69000 69000 69000 12000 100 68000 68000 68000 68000 90 10000 67000 67000 67000 67000 80 66000 66000 66000 66000 8000 70 65000 65000 65000 65000 60 64000 64000 64000 64000 6000 50 63000 63000 63000 63000 40 4000 62000 62000 30 62000 62000 2000 61000 61000 20 61000 61000 60000 60000 10 60000 60000 0 478000 480000 482000 484000 486000 488000 478000 480000 482000 484000 486000 488000

(m) (m) 0 1000 2000 3000 4000 5000 0 1000 2000 3000 4000 5000 1 : 78125 1 : 78125 (c) (d)

Figure 9: Seismic attribute maps for reservoir D. (a) Acoustic amplitude map for reservoir D. (b) Rms amplitude map for reservoir D. (c) Maximum amplitude map for reservoir D. (d) Average energy for reservoir. 8 The Scientific World Journal

Table 3: Average petrophysical parameters for ALA 05. Φ 𝑆 𝑆 𝑉 𝑆 𝑉 𝑉 𝐾 Sand unit Net (ft) Gross (ft) 𝐸 (%) 𝑤 (%) 𝐻 (%) sh (%) NGR (%) wirr (%) BVW hydt rock (md) OWC (ft) B 13.00 54.84 20.33 25.30 74.70 22.50 23.70 9.43 0.07 0.14 0.51 1711.620 10928.10 A 66.35 110.36 22.39 11.00 89.00 26.50 60.10 9.56 0.03 0.19 0.64 1575.928 11121.00 H 4.33 27.51 18.46 36.50 63.50 36.50 21.80 12.09 0.07 0.11 0.44 4234.245 11209.00

478000 480000 482000 484000 486000 488000 Seismic Surface 72000 72000 478000 480000 482000 484000 486000 488000 attribute 71000 71000 72000 72000 71000 71000 90 70000 70000 70000 70000 69000 69000 80 69000 69000 68000 68000 70 68000 68000 67000 67000 67000 67000 60 66000 66000 0 66000 66000 50 65000 65000 65000 65000 40 64000 64000 64000 64000 63000 63000 63000 63000 30 62000 62000 62000 62000 20 61000 61000 61000 61000 10 60000 60000 60000 60000 478000 480000 482000 484000 486000 488000 478000 480000 482000 484000 486000 488000 (m) (m) 0 1000 2000 3000 4000 5000 0 1000 2000 3000 4000 5000 1 : 78125 1 : 78125 (a) (b) Surface Surface 478000 480000 482000 484000 486000 488000 attribute 478000 480000 482000 484000 486000 488000 attribute 72000 72000 150 72000 72000 9000 71000 71000 140 71000 71000 130 70000 70000 70000 70000 8000 120 69000 69000 69000 69000 7000 110 68000 68000 68000 68000 100 6000 67000 67000 90 67000 67000 66000 66000 80 66000 66000 5000 65000 65000 70 65000 65000 4000 64000 64000 60 64000 64000 3000 63000 63000 50 63000 63000 40 62000 62000 62000 62000 2000 30 61000 61000 61000 61000 20 1000 60000 60000 60000 60000 478000 480000 482000 484000 486000 488000 478000 480000 482000 484000 486000 488000

(m) (m) 0 1000 2000 3000 4000 5000 0 1000 2000 3000 4000 5000 1 : 78125 1 : 78125 (c) (d)

Figure 10: Seismic attribute maps for reservoir G. (a) Acoustic amplitude map for reservoir G. (b) Rms amplitude map for reservoir G. (c) Maximum amplitude map for reservoir G. (d) Average energy for reservoir G. The Scientific World Journal 9

Scale: 1 : 1200 ALA 05 Scale: 1 : 2500 ALA 06I DB: data (6) 16-Aug-12 12:58 DB: data (7) DEPTH (10600FT–11600FT) 16-Aug-12 11:32 DEPTH (10850.07FT–11249.98FT) 1 2 Gamma ray Porosity Water saturation Clay volume 1 2 Gamma ray Porosity Water saturation Clay volume GR (API) PHIE (dec) SWU (dec) VCLGR (dec) SGR (API) PHIE (dec) SWU (dec) VWCL (dec) 0 150 0.5 0 100101500.5 0 1001 Reservoir flag Reservoir flag Reservoir flag Reservoir flag Reservoir flag Reservoir flag Pay flag Pay flag Pay flag

Cutoffs Pay flag Pay flag Pay flag Cutoffs Depth (FT) Depth (FT)

10800 1

11000 11000

1 2 11200

11400 11200 3

11600 1 2 Gamma ray Porosity Water saturation Clay volume 1 2 Gamma ray Porosity Water saturation Clay volume (a) (b)

Scale: 1 : 2500 ALA 04 Scale: 1 : 5000 ALA 01 DB: data (5) Depth (9500FT–11280FT) 16-Aug-12 13:44 DB: well 01 (1) Depth (8000FT–11400FT) 16-Aug-12 15:32 1 2 Gamma ray Porosity Water saturation Clay volume 1 2 Gamma ray Water saturation Clay volume SGR (API) PHIE (dec) SWU (dec) VWCL (dec) 0 150 0.5 0 1001GR (API) SWARCH (dec) VCLGR (dec) 0 150 1001 Reservoir flag Reservoir flag Reservoir flag Reservoir flag Reservoir flag Pay flag Pay flag Pay flag

Cutoffs Pay flag Pay flag Cutoffs Depth (FT) Depth (FT)

9600 1 8200

8400 9800 1 8600 2 8800 10000 9000

9200 3 10200 9400

9600 10400 4 9800

10000 10600 2 10200

10400 10800 10600 5

10800 11000 11000

3 11200 6 11200 11400 1 2 Gamma ray Porosity Water saturation Clay volume 1 2 Gamma ray Water saturation Clay volume (c) (d)

Figure 11: Log plot showing the net pay of the reservoirs in ALA 01, 04, 05, and 06I. (a) Log plot for ALA 06I. (b) Log plot for ALA 05. (c) Log plot for ALA 04. (d) Log plot for ALA 01. 10 The Scientific World Journal

ALA 06I ALA 06I ALA 04 SW/PHIE NPHI/RHOB SW/PHIE SGR Active zone: 1 GR Active zone: 1 GR Active zone: 3 Hor A 150 40 1 150 1 2 40 150

40 135 30 0.8 120 2.2 30 120 0.8 120

20 30 105 0.6 90 2.4 20 90 0.6 90 10 20 75 10 PHIE PHIE RHOB 0.1 0.01 0.02 0.04 0.06 0.08 0.14 0.18 0.1 0.14 0.18 0.4 60 2.6 60 0.4 0.01 0.02 0.04 0.06 0.08 60 SS 0 10 LS 0 45 0.2 30 2.8 30 0.2 30 DOL 0 15 3 (SWS) density neutron (NPHI) overlay, Rho fluid= 1.0 (CP-1c 1989) 0 0 0 − 0 0 0 0.2 0.4 0.6 0.8 1 0.05 0.08 0.21 0.34 0.47 0.6 0 0.2 0.4 0.6 0.8 1 SW NPHI SW 2682 points plotted out of 2682 2644 points plotted out of 2682 236 points plotted out of 236 Zone Depths Zone Depths Zone Depths (1) 10797.25F–11467.5F (1) 10797.25F–11467.5F (3) Hor A 11126F–11243.5F (a) (b) (c) ALA 04 ALA 04 ALA 04 NPHI/RHOB SW/PHIE NPHI/RHOB SGR Active zone: 2 Hor C SGR Active zone: 2 Hor C SGR Active zone: 3 Hor A 1 150 2 150 2 150 40 40 135 135 40 40 30 30 2.2 30 2.2 30 120 0.8 120 120

20 30 105 20 30 105 20 2.4 20 90 0.6 90 2.4 90 10 20 10 20 75 75 10

10 PHIE 0.1 RHOB 0.01 0.02 0.04 0.08 0.06 0.14 0.18 RHOB 2.6 60 0.4 60 2.6 60 SS 0 SS 0 10 10 LS 0 45 LS 0 45 2.8 30 0.2 30 2.8 30 DOL 0 DOL 0 15 15 (SWS) density neutron (NPHI) overlay, Rho fluid= 1.0 (CP-1c 1989) 3 (SWS) density neutron (NPHI) overlay, Rho fluid = 1.0 (CP-1c 1989) 0 0 0 3 0 −0.05 0.08 0.21 0.34 0.47 0.6 0 0.2 0.4 0.6 0.8 1 −0.05 0.08 0.21 0.34 0.47 0.6 NPHI NPHI SW 236 points plotted out of 236 180 points plotted out of 180 180 points plotted out of 180 Zone Depths Zone Depths Zone Depths (3) Hor A 11126F–11243.5F (2) Hor C 10540.5F–10630F (2) Hor C 10540.5F–10630F (d) (e) (f) ALA 04 ALA 04 ALA 03ST SW/PHIE NPHI/RHOB SW/PHIE SGR SGR GR Active zone: 1 Hor D 2 Active zone: 1 Hor D Active zone: 1 Hor A 1 150 40 150 0.5 150

40 135 30 0.1 0.02 0.06 0.08 0.14 0.18 0.8 120 2.2 30 120 0.4 0.01 0.04 120

20 30 105 0.6 90 2.4 20 90 0.3 90 10 20 75 10 PHIE PHIE 0.1 RHOB 0.04 0.01 0.02 0.06 0.08 0.4 0.14 0.18 60 2.6 60 0.2 60 SS 0 10 LS 0 45 0.2 30 2.8 30 0.1 30 DOL 0 15 0 0 3 (SWS) density neutron (NPHI) overlay, Rho fluid = 1.0 (CP-1c 1989) 0 0 0 0 0.2 0.4 0.6 0.8 1 −0.05 0.08 0.21 0.34 0.47 0.6 0 0.2 0.4 0.6 0.8 1 SW NPHI SW 946 points plotted out of 946 945 points plotted out of 946 139 points plotted out of 139 Zone Depths Zone Depths Zone Depths (1) Hor D 9565.5F–10038F (1) Hor D 9565.5F–10038F (1) Hor A 11848.19F–11917.19F (g) (h) (i)

Figure 12: Buckles and neutron-density crossplot for reservoirs in ALA 06I, 04, and 03ST. (a) Buckles plot of reservoir D in ALA 06I. (b) Crossplot of reservoir D in ALA 061. (c) Buckles plot of reservoir A in ALA 04. (d) Crossplot of reservoir A in ALA 04. (e) Buckles plot of reservoir C in ALA 04. (f) Crossplot of reservoir C in ALA 04. (g) Buckles plot of reservoir D in ALA 04. (h) Crossplot of reservoir D in ALA 04. (i) Buckles plot of reservoir A in ALA 03ST. The Scientific World Journal 11

Proximal Distal

CS BB CS BB BB CS BB BB BB BF BF DMB TF CS CS TF DMB

PB Point bar CS Channel sands TBBL Transitional barrier bar and lagoon BB Barrier bar DDCF Delta distributary channel fill SH Shale BF Barrier foot TCS Tidal channel sands Retrogradational (transgressive system tract) TC Tidal channel DMB Distributary mouth bar Aggradational (lowstand system tract) TF Tidal flat BBS Barrier bar sand Progradational (highstand system tract)

Figure 13: Stratigraphic cross-section of reservoir sand G.

Table 4: Average petrophysical parameters for ALA 04. Φ 𝑆 𝑆 𝑉 𝑆 𝑉 𝑉 𝐾 Sand unit Net (ft) Gross (ft) 𝐸 (%) 𝑤 (%) 𝐻 (%) sh (%) NGR (%) wirr (%) BVW hydt rock (md) OWC (ft) D 15.00 481.00 24.44 22.10 77.90 36.30 78.30 8.84 0.07 0.18 0.47 2597.534 9590.00 C 36.00 89.50 18.97 25.50 74.50 25.50 70.90 11.35 0.06 0.13 0.49 523.748 10594.50 A 49.50 132.00 19.10 11.20 88.80 25.00 37.50 11.71 0.03 0.17 0.68 5030.835 11249.50

Table 5: Average petrophysical parameters for ALA 03ST. Φ 𝑆 𝑆 𝑉 𝑆 𝑉 𝑉 𝐾 Sand unit Net (ft) Gross (ft) 𝐸 (%) 𝑤 (%) 𝐻 (%) sh (%) NGR (%) wirr (%) BVW hydt rock (md) OWC (ft) A 28.00 69.00 26.22 27.10 72.90 30.30 40.60 8.37 0.08 0.19 0.44 3666.40 11911.70 Φ 𝑆 𝑆 𝑉 Net (ft): net thickness, gross (ft): gross thickness, 𝐸 (%): effective porosity, 𝑤 (%): water saturation, 𝐻 (%): hydrocarbon saturation, sh (%): volume of shale, 𝑆 𝑉 𝑉 𝐾 NGR (%): net-to-gross ratio, wirr (%): irreducible water saturation, BVW: bulk volume of water, hydt:bulkvolumeofhydrocarbon, rock:matrixvolume, (md): permeability, and OWC: oil-water contact.

Table 6: Average petrophysical parameters for ALA 02. Φ 𝑆 𝑆 𝑉 𝑆 𝑉 𝑉 𝐾 Sand unit Net (ft) Gross (ft) 𝐸 (%) 𝑤 (%) 𝐻 (%) sh (%) NGR (%) wirr (%) BVW hydt rock (md) A 36.00 97.50 — — — 23.20 36.90 — — — — —

D, respectively. Reservoir A has the highest net pay of 49.50 ft is hydrocarbon bearing with interval between 11249.00 and and reservoir D the lowest with 15 ft of net pay (Table 3, 11346.50 ft. The reservoir has a low net-to-gross ratio in this Figure 11(c)). Petrophysical properties estimated for this well well (Table 6).WellALA01standstobethemostproductive are shown in Table 3 above. The reservoirs as previously well in this field with six (6) reservoirs (A, C, D, E, F, and G) noticed in wells 06I and 05 were also not at irreducible water delineated. saturation (Figure 12). Neutron density crossplots were used The reservoir intervals are 11152.00–11264.00 ft, 10518.00– to delineate the lithology of the reservoir sands; this reveals 10620.00 ft, 9519.00–10002.00 ft, 9131.5–9367.00 ft, 8702.00– the reservoirs to be shaly sands (Figure 12). In ALA 03ST, 8765.50 ft, and 8105.5–8166.00 ft for reservoirs A, C, D, E, only reservoir sand A is hydrocarbon bearing (Table 5)with F, and G, respectively. Reservoir A has the highest net pay interval between 11848.194 and 11917.194 ft. The reservoir is of 71.00 ft and reservoir G the lowest with 7.50 ft of net pay very shaly as seen on the neutron density crossplot with the (Table 7 and Figure 11(d)). From the petrophysical analysis, data points clustering around the dolomite trend line; buckles reservoir A is the most laterally continuous and viable. plot (Figure 12(i)) shows the reservoir to be at irreducible The sandy parts of the paralic sequences (Agbada Forma- water saturation. Petrophysical attributes derived from well tion) are composed of barrier bars, point bars, distributary logs are shown in Table 4 which reveals a low net-to-gross channels, tidal channels, river-mouth bars, shallow-marine ratio for this reservoir. In ALA 02, only reservoir sand A bars, and leeves [10]. Within paralic sequences, reservoir 12 The Scientific World Journal

Table 7: Average petrophysical parameters for ALA 01. Φ 𝑆 𝑆 𝑉 𝑆 𝑉 𝑉 𝐾 Sand unit Net (ft) Gross (ft) 𝐸 (%) 𝑤 (%) 𝐻 (%) sh (%) NGR (%) wirr (%) BVW hydt rock (md) G 25.25 57.50 — 39.20 60.80 37.70 43.90 — — — — — F 12.00 64.50 — 28.50 71.50 16.50 95.70 — — — — — E 17.50 134.50 — 29.80 70.20 12.30 98.00 — — — — — D 52.00 482.00 — 21.30 78.70 28.20 79.80 — — — — — C 37.00 117.00 — 22.00 88.00 17.00 61.80 — — — — — A 71.00 114.50 — 15.60 84.40 29.10 62.40 — — — — — Φ 𝑆 𝑆 𝑉 Net (ft): net thickness, Gross (ft): gross thickness, 𝐸 (%): effective porosity, 𝑤 (%): water saturation, 𝐻 (%): hydrocarbon saturation, sh (%): volume of shale, 𝑆 𝑉 𝑉 𝐾 NGR (%): net-to-gross ratio, wirr (%): irreducible water saturation, BVW: bulk volume of water, hydt:bulkvolumeofhydrocarbon, rock:matrixvolume, (md): permeability, and OWC: oil-water contact.

Proximal Distal

BB DDCF PB PB DDCF DDCF DDCF DMB BB

DDCF CS SH SH CS CS CS CS DMB BB

Figure 14: Stratigraphic cross-section of reservoir sand F. quality is strongly linked to depositional environments. For petrophysical properties. Reservoir sand B (Figure 18)isalso example, sands of barrier bar origin are more laterally tidal channel sand. The sands are turbidities (proximal to continuous than those of distributary-channel origin. Barrier distal) and are of high energy environment. Reservoir sand C sands may commonly be correlated along the strike of fields (Figure 17) has progradational to aggradational pattern and (typically on the order of 10 km), whereas channel sands is generally clean. The sands are mostly barrier bars and may be restricted to individual wells [3]. With this in mind, distributary mouth bars. Reservoir D (Figure 16) is barrier the environment of deposition was inferred from log motifs bar to tidal sands. The sands have aggradational to prograda- forthereservoirsandsfromAtoG(Figures13–19). Field tional stacking patterns. Reservoir sand E (Figure 15)displays wide log correlations show a wide distribution, both laterally progradational to retrogradational stacking patterns but is and vertically, of regressive sandstone lithofacies sequences generally coarsening upward. The sands are massive with which are predominantly shoreface deposits varying from thin shaly interbeds. The depositional environments inferred transitional to deltaic sediments, represented by mudstone are point bars and delta distributary channel fills. The sand and thin sandstone layers, lower to middle shoreface sedi- F(Figure 14) is generally aggradational. The depositional ments represented by hummocky sandstone deposited under environments eminent are barrier bars, channel sands, and wavestorm influence, upper regressive shoreface sediments distributary mouth bars. The depositional environment of represented by coarsening upward sequences or channelized sandG(Figure 13) varies from barrier bars to channel barrier bar complexes with thick sandstone. Reservoir sand sands. The underlying sands are tidal flats, barrier foot, A(Figure 19) is generally retrogradational. The sands are tidal distributary mouth bars, and channel sands. The sands are channel sands, dominantly sand with relatively thin interbeds generally progradational. This horizon is immediately below of shale dividing the sands into three lobes with varying the delineated beginning of Agbada Formation. The Scientific World Journal 13

PB PB CF PB CF DDCF DDCF BB DDCF TBBL CS BB TBBL BB BB

BB DMB CS

Figure 15: Stratigraphic cross-section of reservoir sand E.

Proximal Distal

BB TC BB BB TCS TCS DMB PB DMB SACS BB PB PB BB CF DDCF DDCF DDCF TC PB DDCF BB DDCF BB DMB DMB BB DMB BB DMB TCS TCS TBBL BB TBBL BF DMB BB BF BF BF PB TF DMB BB

Figure 16: Stratigraphic cross-section of reservoir sand D.

5. Conclusion Kulke [11] which describes the most important reservoir types as point bars of distributary channels and coastal barrier bars From this research work, it was discovered that reservoir A intermittently cut by sand-filled channels. Deductions from which is tidal channel sands has the highest net pay; this GR log signatures suggest two (2) regimes of depositional further buttress the fact that thicker reservoirs in the Niger settings within the Ala field. The shallower sands from C delta likely represent composite bodies of stacked channels to G are very likely to be products of generally prograding, [3]. proximal, and delta-front deposits, consisting of shore-face, Most reservoirs encountered on Ala field are point bars, lower and upper mouth bars and continental shelf deposits; barrier bars, and tidal channel sands and support the work of this is buttressed by the high net-to-gross sand ratio observed 14 The Scientific World Journal

Proximal Distal

BBS BF DDCF BF BB CS DMB BB CS CS TC PB TF PB DDCF BB DDCF DDCF TF DDCF DDCF CS BF PB PB DDCF TC BBS DDCF BB DMB TC

DDCF BB

Figure 17: Stratigraphic cross-section of reservoir sand C.

Proximal Distal

BB CS TCS CS TCS TCS TCS AS

Figure 18: Stratigraphic cross-section of reservoir sand B. in these reservoirs while the relatively deeper sands A, B, splay to the south. It can be deduced from this study that andHarelikelytohavebeendepositedindistal,shallow the wells drilled on the study area were located to target the marine environments which is evidenced by the low net- rollover anticline formed on the downthrown side of the fault to-gross sand ratio. These two distinct depositional settings M2 and assisted by minor fault F2. are separated by shale (sand-starved sediments) columns of An amalgamation of the results from petrophysics, varying thicknesses. The reservoirs have moderate to high seismic structural mapping, and various seismic attributes net-to-gross ratios and expectedly have average-good poros- (acoustic amplitude, rms amplitude, average energy, and ity and very high permeability values capable of supporting maximum amplitude) has revealed closure 2 (the closure economic hydrocarbon flow rates. Structurally, the study area against the minor fault F5) as a new prospect where new is characterized by a distinctively fault-closed dominated exploration efforts can be directed to because it is more structural play. The field structure is an elongate anticline, hydrocarbon charged than closure 1 in the reservoirs. Geo- wedged between the field’s west-southeast trending major chemical and biostratigraphic studies should be employed to structure building faults to the north (which is the principal better characterize the reservoirs and reliably interpret the displacement zone) and a northeast-southwest trending fault depositional environments. Fault seal analysis should also The Scientific World Journal 15

TCS TCS TCS TCS TCS DDCF

CS BF BB TBBL

BB TF TCS TCS

Figure 19: Stratigraphic cross-section of reservoir sand A.

be carried out to check the trapping ability of the major [7] D.A.Busch,“Influenceofgrowthfaultingonsedimentationand trap which is fault F2. Seismic data for fields bounding this prospect evaluation,” AAPG Bulletin,vol.59,no.3,pp.414–419, research field should be studied to further understand the 1975. nature of the minor fault F4. [8] Schlumberger, “Log interpretation/ applications: schlumberger educational services,”order no: SMP-7017 Houston, Texas, 1985. [9]J.M.OrifeandA.A.Avbovbo,“Stratigraphyandtheunconfor- Acknowledgments mity traps in Niger Delta,” AAPG Memoire, vol. 32, p. 265, 1982. The authors’ enormous and heartfelt thanks go to Olumide [10] K. J. Weber and E. M. Daukoru, “Petroleum geology of the Niger Lawal, Salami Ibidapo, Ken Ogaga and Olonode Segun, all Delta,” in Proceedings of the Ninth World Petroleum Congress, of Chevron Nigeria Limited for welcoming all our questions vol. 2 of Geology, pp. 210–221, Applied Science Publishers, 1975. during the course of this research. They are highly indebted [11] H. Kulke, “Nigeria,”in Regional Petroleum Geology of the World. to the management of Chevron Nigeria Limited (CNL) and Part II: Africa, America, Australia and Antarctica,H.Kulke,Ed., pp.143–172,Gebruder¨ Borntraeger, Berlin, Germany, 1995. Department of Petroleum Resources (DPR) for the release of the proprietary data used for this research work. They also thank Trudy Coker of Baker Hughes UK for the paper review. Lastly, to Valenti Gerard, Onyirioha Reginald, and Segun Bankole who were instrumental in facilitating the release of the research dataset.

References

[1] W. S. Evans, “Technologies for multidisciplinary reservoir characterization,” Journal of Petroleum Technology,pp.24–25, 1996. [2] A. Whiteman, “Nigeria: its petroleum geology, resources and potential. Two volumes,” Nigeria,1982. [3] H. Doust and E. Omatsola, “Niger delta,” in Divergent/Passive Margin Basins, J. D. Edwards and P. A. Santogrossi, Eds., vol. 48, pp. 239–248, AAPG Memoir, Tulsa, Okla, USA, 1990. [4] A. A. Adesida, T. J. A. Reijers, and C. S. Nwajide, “Sequence stratigraphic framework of the Niger Delta,” in Proceedings of the AAPG International Conference and Exhibition, Vienna, Austria, 1997. [5] B. D. Evamy, J. Haremboure, P. Kamerling, W. A. Knaap, F. A. Molloy,andP.H.Rowlands,“Hydrocarbonhabitatoftertiary niger delta,” AAPG Bulletin,vol.62,no.1,pp.1–39,1978. [6] N.G.Obaje,Geology and Mineral Resources of Nigeria,Springer, 2009. International Journal of Journal of Ecology Mining

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