SPE 128353

SPE 128353

Petrophysical Evaluation and Sequence Stratigraphic Model of ‘Indigo Field’ in Greater Ughelli Depobelt, Niger Delta, Nigeria

Okeke Chinwendu O., Mode Ayonma W., Obi Ifeanyichukwu S., University of Nigeria, Nsukka; and Odokoh

Anthony O., Nigerian Agip Oil Company

Copyright 2009, Society of Petroleum Engineers Inc. This paper was prepared for presentation at the 33rd Annual SPE International Technical Conference and Exhibition in Abuja, Nigeria, August 3-5, 2009. This paper was selected for presentation by an SPE Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Papers presented at SPE meetings are subject to publication review by Editorial Committees of the Society of Petroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgement of where and by whom the paper was presented. Write Librarian, SPE, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435.

Abstract Detailed Petrophysical studies and Sequence stratigraphic analyses of three wells in the ‘Indigo Field of Niger Delta was carried out using wireline logs and high resolution biostratigraphy. Three sequence boundaries (SB 27.3Ma, 29.3Ma and 32.4Ma) and maximum flooding surfaces (MFS 26.2Ma, 28.1Ma and 31.3Ma) were identified. Three systems tracts were delineated in wells A and B, while only two were delineated in well C. Nine reservoir units (A1-A9) analyzed in well A show porosity, permeability and Vshale of 13-18%, 89.35-2775.8md and 0.026-0.05v/v decimal, respectively. Reservoirs A1, A4, A7, A8, and A9 contain oil, A2 and A3 contain gas, and A5 and A6 contain water. Porosity and Vshale values for three reservoir units in well B (B1-B3) are 16-25% and 0.03-0.045v/v decimal, respectively. Reservoirs B1 and B2 contain water, and B3 contains gas. Six reservoir units (C1-C6) delineated in well C have average porosity, permeability and Vshale values of 19-24%, 1063.92-3674.4md and 0.05-0.1v/v decimal, respectively. Reservoir C1 contains oil and water; C2, C3 and C6 contain only water, and C4 and C5 contain oil only. Water saturation, moveable hydrocarbon index (MHI) and net sand count were 14-79%, 0.42-0.46, and 6-40m respectively, in well A; 24-65%, 0.55-0.56 and 7-26m in well B; and 21-67%, 0.44-0.54 and 11-22m

in well C. Well A, being with thicker and more porous sands with lower Vshale is more productive than wells B and C.

Introduction The Niger Delta depocentres have been extensively studied to explore for subtle, structural and stratigraphic traps1. In order to meet oil demands over the years, different geophysical and geochemical methods have been employed to exploit for oil. Procedures related to the exploration of oil are very complex, expensive and require large volume of data and it is necessary to consider the risk associated with geological, economical and technological uncertainties. In this study carried out on the ‘Indigo Field’ Niger Delta Basin predictions of the reservoir units, seal, possible source rocks and fluid type in the reservoirs using petrophysical and sequence stratigraphic tools were employed to give the nature and quality of clastic reservoirs and to predict their development and distribution in this field.

Methodology

Marking distinct candidates for sequence stratigraphic surfaces using the wireline logs2,3

Interpretation of the biostratigraphic data to identify the maximum flooding surfaces (MFS) and sequence boundaries (SB)

Integrate well logs and biostratigraphic data

Evaluate the petrophysical properties of the reservoir from the wireline logs4,5

Wireline Log Description: Key sequence stratigraphic surfaces which include the maximum

2 C.O. Okeke, A.W. Mode, I.S. Obi, and A.O. Odokoh SPE 128353

flooding surface (MFS) and sequence boundary (SB) were delineated with the GR log. The MFS which corresponds to radioactive shales with high GR peak were interpreted to have been deposited across relatively flat surfaces. These shales were deposited between the retrogradational parasequence sets and progradational parasequence sets. On the other hand, the sequence boundaries (SB) lie directly beneath the sand-sized sediment fills of depressions on eroded or incised surfaces and over the progading clinoforms of highstand systems tract.

The parasequence stacking patterns were used to identify the systems tracts namely, the lowstand systems tracts (LST), the transgressive systems tract (TST), and the highstand systems tract (HST) that are enveloped by the MFS, transgressive surface (TS) and SB. The stacking patterns were identified on the basis of variations in grain size. Funnel-shaped and bell-shaped GR log signatures indicate fining and coarsening upward grain textures respectively. Biostratigraphic Interpretation: Foramniferal abundance and diversity chart was plotted for all three wells in the field. The candidate sequence boundaries and maximum flooding surfaces were determined afterwards by comparing the plots with the standard foramniferal abundance and diversity chart. The maximum flooding surfaces are marked by points in the chart that depicting maximum foramniferal abundance especially the plantonic species, maximum diversity and population. On the other hand, the SBs are marked by points that showed minimum foramniferal abundance and diversity and include an abrupt termination of older species and replacement by younger ones3,6. Across the SB, there is a change from deeper water biofacies to shallower or terrestrial biofacies3,6.

Detailed sequence stratigraphic study of the field was carried out by integrating the GR and resistivity logs with the foraminiferal abundance and diversity charts. This was to enable proper correlation of the log reading to biostratigraphic markers in order to correctly delineate the MFS and SBs. The determined surfaces and delineated systems tracts were integrated in the sequence stratigraphic modeling of the area. The pollen (P) and framinifera (F) zones of the surfaces were categorized using the Niger Delta Cenozoic chronostratigraphic chart (fig. 5) Petrophysical Analysis: Petrophysical evaluation was carried out in the three wells. The MS Excel software was used to translate the digital log data

to qualitative information (log curves). The derivation of reservoir characteristics was based on log interpretation techniques.7,8,9,4 Geologic Setting The ‘Indigo-Field’ (fig. 1) is located in the Greater Ughelli Depobelt of the Niger Delta basin. The Niger Delta is located at the southern end of Nigeria where it is bordered by the Atlantic Ocean and extends from longitudes 30 - 90 E and latitudes 40301 – 50201 N. The Benin and Calabar Flanks mark the north-western and eastern boundaries of the Delta respectively. It is bounded in the north by the Anambra basin and the Abakiliki high, and the south by the Gulf of Guinea.

Sedimentation in the basin started in the late Paleocene/Eocene when sediments began to build out beyond the troughs between the basement horst blocks at the northern flank of the present delta area. The subsurface Lithostratigraphic succession of the of the Niger Delta consist of three diachronous units namely, Akata, Agbada, and Benin formations with ages ranging from Eocene to Recent10,11,12. The Akata Formation, at the base, estimated to be up to 7000m thick, is of open marine and pro-delta origin and is composed of thick marine shale1,13. The formation is typically overpressured and ranges in age from Eocene to Recent14. The Akata Formation is overlain by the parallic Agbada Formation. It is characterized by alternating sandstones and shales that represent cyclic coarsening upwards regressive succession resulting from distributary channel migration and abandonment14,15. The strata are interpreted to have been deposited in fluvio-deltaic environments between the Eocene to Recent times. The Benin Formation comprises the top part of the Niger Delta clastic wedge, is made up of massive, highly porous, freshwater-bearing sandstones, with local thin shale interbeds considered to be of braided stream origin. The age of the formation is estimated to range from Eocene to Recent. Five major depobelts defined by synsedimentary faulting that occurred in response to variable rates of subsidence and sediment supply are generally recognized.. These are the Northern Delta (Late Eocene-Middle Miocene), Central Swamp I and II Early Miocene- Middle Miocene), Coastal Swamp I and II (Middle –Late Miocene) and Offshore depobelt (Late Miocene – Pliocene) (Fig.1). The interplay of subsidence and supply rates resulted in deposition of discrete depobelts, each with its own sedimentation, deformation and petroleum

3 Petrophysical Evaluation and Sequence Stratigraphic Model of ‘Indigo Field’ in Greater Ughelli Depobelt SPE 128353

history. These depobelts are 30-60 kilometres wide and prograde southwestward 250 kilometres over oceanic crust into the Gulf of Guinea.

Petroleum in the Niger Delta is produced from sandstone and unconsolidated sands, predominantly in the Agbada Formation. Known reservoir rocks are Eocene to Pliocene in age and are often stacked. According to reservoir geometry and quality, the most important reservoir types are described as point bars of distributary channels and coastal barrier bars intermittently cut by sand-filled channels 23. However, turbidite sands in the lower Akata Formation are potential targets in deepwater offshore and possibly beneath currently producing intervals onshore. Source rocks in the Niger-Delta might include interbedded shale in the Agbada Formation and the marine Akata Formation shales1,13,18. Structural traps formed during synsedimentary deformation of the Agbada Formation18,19 and stratigraphic traps formed preferentially along the Delta Flanks define the most common reservoir locations within the Niger Delta complex. The primary seal rocks are interbedded shales within the Agbada Formation due to clay smears along faults, interbedded sealing units juxtaposed against reservoir sands due to faulting and vertical seals produced by laterally continuous shale-rich strata1.

Sequence Stratigraphic Interpretation Sequence analysis of the three wells were carried out using digitized logs. The data were plotted using Microsoft excel. The gamma ray and resistivity logs were used for the sequence analysis (fig. 4). Gamma ray log signatures show that most of the well intervals penetrated the parallic Agbada Formation (from about 2250m to the basal units in Well B and C and the entire section of Well A). This is evident from the alternation of sand and shale units. The topmost sections of well B and C penetrated the Benin Formation (from the top to a depth of about 2250m) which is composed mainly of continental sands.

Results and Discussions

From the log signatures obtained, four (4) candidate sequence boundaries and four (4) candidate maximum flooding surfaces were recognized for each of the wells A, B and C (fig 6). A systematic correlation of the SBs and MFS was carried out to show the sequences penetrated by each well (fig. 7). Two sequences were noted to contain all three systems tracts (LST, TST and

HST) while the third sequence contain only two systems tracts (TST and HST). The LST is missing from the third sequence where the transgressive surface unconformably overlies the sequence bundary (SB). Sequence 1: The three systems tracts are found in this sequence. The LST lies on the 32.4Ma SB and displays a progradational parasequence stacking pattern. They range from coastal deltaic to inner neritic sands and shales. The TST lies directly on top of the LST. It comprises an aggradational and retrogradational parasequence stacking pattern. It ranges from shallow inner neritic to middle neritic sands and shales. The HST lies on top of the 31.3Ma MFS and displays an aggradational parasequence stacking pattern. It ranges from inner neritic to outer neritic shales. It is bounded on top by the 29.3Ma SB. Sequence 2: Three systems tracts occur in this sequence. The LST is bounded below by the 29.3Ma. SB. It shows a progradational parasequence stacking pattern and is coastal deltaic and inner neritic sands and shales. The TST lies on top of the transgressive surface (TS) and shows a retrogradational and aggradational stacking pattern. It is mainly inner neritic and middle neritic sands and shales. The 28.1Ma MFS lies directly on top of the TST and bounds the HST below. The HST in this sequence show aggradational stacking patterns and range from inner neritic to outer neritic shales.

Sequence 3: The TST lies above the 27.3Ma SB and is mainly retrogradational and aggradational stacking pattern. It is inner neritic sands and shales. Above the TST lies MFS 26.2 which bounds the HST below. The HST shows aggadational stacking pattern and is middle to outer neritic shales. Generally, the Lowstand systems tracts display thicker sands which are more productive than the other systems tracts.

The Foraminiferal abundance and diversity chart plotted from Well-A biostratigraphic data showed three maximum flooding surfaces and three sequence boundaries (figure 8), SBs 27.3, 29.3 and 32.4Ma and MFS 26.2, 28.1 and 31.3Ma respectively (red lines represent the sequence boundaries while the green lines represent the maximum flooding surfaces).


The Niger Delta Chronostratigraphic chart (fig. 5) show that the delineated surfaces belong to the greater Ughelli Depobelt. Using this table, the surfaces have been categorised into their respective P and F zones. SBs 27.3 and 29.3Ma and MFS 26.2 and 28.1Ma belong to P580 P zone and F7800 F zone. MFS 31.3Ma belongs to P560 while SB 32.4Ma belongs to P540 and they both belong to F7600. Figure 9 shows the different surfaces and their ages, paleoenvironments and their P and F zones. A systematic matching of the delineated surfaces was carried out for the wells in order to interprete the sequence stratigraphy of the area. This was based on integrating the well log and biostratigraphic results (fig 10).

Petrophysical results and Discussions Well A: Nine major reservoirs intervals (A1-A9) were delineated for this well using the gamma ray log. A cut off value of 67.2 API was determined while the resistivity of formation water was determined from the pickett plot (figure 14). The petrophysical properties fir this well are summarized in Table 1. The reservoirs sands have average net thickness which range from 8-48m. Some of the reservoir units contain interbedded shales, a major characteristic of the parallic Agbada Formation. Petrophysical analysis was carried out on most of the clean sand intervals. Porosity values obtained range between 10 and 20% (table 1). The reservoir sands are very clean with V-shale values of less than or equal to 5%. These values are far below the limit of 10-15% that can affect water saturation as postulated by Hilchie21. Reservoirs A1, A2, A3, A4, A7, A8 and A9 have average resistivity values of 62.98, 547.12, 72.7, 84.83, 27.8, 44.7 and 18.88ohmm respectively, suggesting that these reservoirs contain hydrocarbon. Also, low water saturation values of 0.34, 0.18, 0.28, 0.35, 0.48, 0.40 and 0.50 imply the occurrence of hydrocarbons in these sands. The neutron-density logs show that the fluid in Reservoirs A1, A4, A7, A8 and A9 is oil. This is demonstrated by the tracking of the deep and shallow resistivity logs (figure 12). Reservoir A2 and A3 are gas prone considering the neutron and density log separation, while reservoirs A5 and A6 contain water as evident from their low resistivity values (table 1). Permeability and MHI values were 89.35md and 0.43-0.46 respectively, indicating permeable reservoir sands with good hydrocarbon moveability. Well B: Three reservoirs (B1-B3) with average net sand ranging from 7-26m thick were delineated in

well B. The petrophysical properties are summarized in table 2. The pickett plot aided in the determination of the resistivity of the formation water (figure 15). Reservoirs B1 and B3 have good porosity values (10 – 20%), while reservoir B2 has a very good porosity value (25%). Average V-shale values for the three reservoirs are 0.04, 0.03 and 0.045v/v decimal, respectively. Average resistivity values for B1 and B2 is 5.7 Ohmm, while water saturation values are 0.65 and 0.46 v/v decimal, suggesting water as the fluid content. Reservoir B3 with a high resistivity value of 115.2ohmm and water saturation of 0.24 suggests that the fluid contained is a hydrocarbon. The neutron-density cross plot showed that reservoir B3 contains gas (figure 13). The average MHI values of 0.55 and 0.56, K value 2871.5md in these reservoirs suggest good fluid moveability. Well C: Six reservoirs (C1-C6) with average net sand thickness ranging between 8-22m were delineated in well C. The pickets plot gave the resistivity of water(figure 16). A cut off value of 64.95 API was determined using the gamma ray log and values below it were shown to be reservoir while those above it were shales. The petrophysical properties of this well are summarized in table 3. Average porosity values obtained range from 19-24%. The reservoirs are moderate to clean shown by their V-shale values of 0.05-0.1 v/v decimal. Reservoir C1 has high average resistivity value of 43.3ohm-m at 3185-3199m, this reduces to an average of 3.78 ohm-m at depths below 3199m (figure13) suggesting that the fluid content in the intervals below this depth is water. This infers an oil-water contact (OWC) at that point. The low average resistivity values (4.3, 4.32, and 8.17ohm-m) and high water saturation (0.64, 0.62 and 0.53v/v decimal) of reservoirs C2, C3 and C6 also point to the fact that the fluid content is water. Reservoirs C4 and C5 are basically hydrocarbon reservoirs typified by their high average resistivity values of 39.94ohm-m and 20.96ohm-m respectively. Low water saturation of 0.21 and 0.32 were recorded for these intervals. Average permeability values of 3674.4md, 2532.4md and 1063.92md in reservoirs C1, C4 and C5 suggest good fluid moveability. Conclusions The sequence boundaries delineated are SB 27.3, 29.3 and 32.4Ma while maximum flooding surfaces dated 26.2, 28.1 and 31.3Ma were also noted. SBs 27.3 and 29.2Ma and MFS 26.2 and


28.1Ma belong to P580 and F7800 zone. MFS 31.3 belongs to P560 while SB 32.4Ma belongs to P540. Both MFS 31.3 and SB 32.4Ma belong to F7600.

Nine reservoirs were evaluated in Well A, five were shown to contain oil, two contain oil and two contain water. Three reservoirs were evaluated in Well B, two were found to contain water and one contains gas. Six reservoirs were evaluated in Well C, the first contains oil and water, and two others contain oil while two contain oil. The three wells have good quality reservoir sands as shown by their good porosity (13-18%, 16-25%, and 19-24%), high permeability (89.35-2775.8md, 2871.5md, and 1063.92-3674.4md), and low V-shale (0.026-0.05, 0.03-0.045, 0.05-0.1) values, respectively.

A comparison of the sequence stratigraphic and petrophysical analysis revealed that the lowstand systems tract are mainly sands with shale intercalations, the highstand systems tract are dominantly shales with thin dispersed sands, while the transgressive systems tract are dominantly shaley with sand intercalations. The LST has the highest volume of hydrocarbon probably because they contain very thick clean sands which are sealed above and below by deep water shales that may also act as hydrocarbon source rocks. These basinal source rocks are known to have the best quality of organic rich oil-prone sediments.

Acknowledgments The authors gratefully acknowledge the management of Nigerian Agip Oil Company, PortHarcourt and their co-workers for their contributions to the material presented herein.

References 1. Doust, H., and Omatsola, E.M., “Niger Delta. ”

In: Divergent/Passive Margins Basins D. Edwards, and P.A. Santagrossi (eds), AAPG memoir v. 48, 239-248, 1990.

2. Edet, J.J., “Sequence Stratigraphy: Basic Principles and Practical Guidelines to the Analysis of Clastic Deposits.” EPNL/Total E&P, Port Harcourt, 54, 2007.

3. Rider, M.H., “The Geological Interpretation of Well Logs.” Whittles Publishing, 2nd Edition, Aberdeen, 278, 1996.

4. Archie, G.E., “The Electrical Resistivity Log as an Aid in Determining some Formation

Characteristics.” Transactions of the American Institute of Mining and Metallurgical Engineers, v. 146, 54-62, 1942.

5. Asquith, G. and Krygowski, D., “Basic Well Log Analysis.” AAPG Methods in Exploration Series v. 16, 204p, 2004.

6. Emery, D and Myers, K., “Sequence Stratigraphy.” Blackwell Science UK 297p, 1996.

7. Schlumberger, “Log Interpretation,” vol 1- Principles. New York, Schlumberger Limited, 31p, 1972.

8. Wyllie, M.R.J. and Rose, W.D., “Some Theoretical Considerations Related to the Qualitative Evaluations of the Physical Characteristics of Rock from Electric Log Data.” Journal of Petroleum Technology v. 189, 105-110, 1950.

9. Larionov, V.V., “Borehole Radiometry.” Moscow, U.S.S.R., Nedra, 1969.

10. Ekweozor, C.M., and Daukoru, E.M., “The Northern Delta Depobelt Portion of the Akata-Agbada (!) Petroleum System, Niger Delta, Nigeria.” NAPE Bulletin v. 7(2) 2-120, 1992.

11. Short, K.C. and Stauble, A.I., “Outline of Geology of Niger Delta.” AAPG Bulletin v. 51, 761-779, 1967.

12. Whiteman A.J., “Nigeria, its Petroleum Geology Resources and Potential I and II.” Edinburgh, Graham and Tortman: 166p, 1982.

13. Bustin, R.M., “Sedimentology and Characteristics of Dispersed Organic Matter in Tertiary Niger Delta: Origin of Source Rocks in a Deltaic Environment”. AAPG Bulletin v. 72, 277-298, 1988.

14. Weber, K.J., and Daukoru, E., “Petroleum Geology of the Niger Delta.” Proceedings of the 9th World Petroleum Congress, Tokyo v. 2, 202-221, 1975.

15. Avbovbo, A.A., “Tertiary Lithostratigraphy of the Niger Delta.” AAPG Bulletin v. 62, 295-300, 1978.

16. Doust, H. and Omatsola, E., “Niger Delta.” AAPG Memoir v. 48, 201-238, 1989.

17. Nwangwu, U., “A Unique Hydrocarbon Trapping Mechanism in the Offshore Niger Delta.” In: Geology of Deltas. Oti, M.N. and G. Postma, (eds.) Rotterdam A.A. Balkema, 269-278, 1990.


18. Evamy, B.D., Haremboure, J., Kamerling, P,. Knaap, W.A., Molloy, F.A., and Rowlands, P.H., “Hydrocarbon Habitat of the Tertiary Niger Delta.” AAPG Bulletin, v. 62,1-39, 1978.

19. Stacher, P., “Present Understanding of the Niger Delta Habitat.” In Oti M.N. and Postma G. (eds). Geology of Deltas. A. A. Balkema Publishers, Rotterdam: 1st edition, 257 – 267, 1995.

20. Haack, R.C., Sundaraman, P. and Dahl, J., “Niger Delta Petroleum System.” In: Extended Abstracts, AAPG/ABGP Headberg Research Symposium, Petroleum Systems of the South Atlantic Margin, Rio de Janeiro, Brazil, 123-134, 1997.

21. Hilchie, D.W., “Applied Openhole Log Interpretation.” Golden, Colorado, D.W. Hilchie, Inc., 161, 1978.

22. Lawrence, S.R., Munday, S., and Bray, R., “Regional geology and geophysics of the eastern Gulf of Guinea (Niger Delta to Rio Muni):” The Leading Edge, v. 21, 1112–1117, 2002.

23. Kulke, H., “Nigeria. In: Regional Petroleum Geology of the World Part II: Africa, America, Australia and Antarctica” Kulke, H., (ed.) Berlin Gebruder Borntaeger pp.143-172, 1995.

Appendix (a) IGR = GRlog – Grmin GRmax-GRmin ..........................................(1) Vsh = 0.083(23.7 I

GR – 1) ......................(2) (Larionov, 1969) for tertiary rocks ΦD = ρma - ρb ρma - ρfl ........................................(3)

ФNe = ФN – ФNshale x 0.03 x Vshale0.45

................(4)

........................................(6)

..........(5)

......................................(7)

......................................(8)

............................... (9)

......................................(11)

......................................(12)

min reading in clean sand zone zone

ndstone) 0 2.65g/cm3 reading) and

i y

lk

r

Sh=1–Sw ............

BVW = Sw x Ф ........................................... (10)

Appendix (b) GRlog = GR reading from the log

GR = GR log GRmax = GR log reading in shale IGR = Gamma ray index Vsh = volume of shale

DФ = density porosity aρma = matrix density (s

ρb = bulk density (log ρfl = fluid density = 1.0g/cm3

d poros tФND = neutron-density shale correcte) ФN = neutron porosity (from log

ФNe = shale corrected neutron porosity ated from buФD = density porosity (calcul

density values on log) ФDe = shale corrected density porosity ФNshale = neutron porosity of a nearby shale Vshale = volume of shale Sw: is the water saturation

n Sh = hydrocarbon saturatioRw: is the resistivity of wateRt = uninvaded zone resistivity determined from

the deep resistivity log Rmf = Resistivity of the mud filtrate Rxo = Invaded zone resistivity determined from

the shallow resistivity log Rw = resistivity of formation water at formation

temperature

Sw = Rxo/RtSxo Rmf/Rw

1/2

K = 250 x Ф3

Sw irr

Sxo = a x RmfRxo x Фm

1/n

Sw = a x RwRt x Фm

1/n

ФND = ФNe2 + ФDe

2

2

ФDe = ФD – ФNshale x 0.13 x Vshale0.45


Φ = formation porosity determined from the neutron and density logs

ma = 0.81 (local correction factor)

= 2 (cementation factor)

n = 2 (saturation exponent) BVW = bulk volume water K = permeability


Appendix (c) Table 1: Summary of the Petrophysical Results for Well A Interval(m) Net

sand Count (m)

Average Porosity (%)

Average Resistivity (ohmm)

Average Vshale (v/v decimal)

Average MHI

Average Permeability (md)

Average Water Saturation (%)

Fluid Type

3463-3510 (A1)

39 18 63 0.05 0.45 2775.8 34 Oil

3610-3642 (A2)

32 14 547.12 0.029 0.42 2177.2 18 Gas

3654-3690 (A3)

36 16 72.7 0.034 0.45 2338 28 Gas

3712-3730 (A4)

19 15 84.83 0.023 0.45 2084.8 35 Oil

3875-3883 (A5)

9 13 7.35 0.03 0.46 79 Water

3919-3936 (A6)

18 15 9.41 0.03 0.46 53 Water

4220-4242 (A7)

19 15 27.8 0.033 0.44 532.9 48 Oil

4249-4297 (A8)

40 15 44.7 0.03 0.42 336.2 40 Oil

4329-4336 (A9)

6 13 18.88 0.026 0.42 89.35 50 Oil

Table 2: Summary of the Petrophysical Results for Well B Interval(m) Net sand

Count (m)




Average MHI



Fluid Type

3105-3130 (B1)

26 17 5.7 0.04 0.56 65 Water

3134-3148 (B2)

15 25 5.7 0.03 0.55 46 Water

3310-3317 (B3)

7 16 115.2 0.045 0.55 2871.5 24 Gas

Table 3: Summary of the Petrophysical Results for Well C Interval(m) Net

sand Count (m)




Average MHI



Fluid Type

3185-3199

13 21 43.3 0.08 0.46 3674.4 25 Oil 3185-3210 (C1) 3200-

3210 9 22 3.78 0.10 0.54 67 Water

3249-3256 (C2)

8 22 4.3 0.07 0.52 64 Water

3263-3279 (C3)

17 22 4.32 0.05 0.53 62 Water

3315-3325 (C4)

11 24 39.94 0.10 0.44 2532.4 21 Oil

3450-3466 (C5)

15 20 20.96 0.08 0.47 1063.92 32 Oil

3473-3482 10 19 8.17 0.08 0.49 53 Water


(C6)

X-FIELD

BB

X-FIELDX-FIELD

BB

Indigo Field

Figure 1: Location map of the study area (A) Location of Niger Delta along the west coast of Africa. (B) Location of “Indigo Field,” Niger Delta.

Figure 2: Niger Delta regional stratigraphy and variable density seismic display of the main stratigraphic units with corresponding reflections22.


Figure 3: Structural Features of the Tertiary Niger Delta showing Growth Faults and Roll-over Anticlines1,19

GR Res

GR ResGR Res

Figure 4: Schematic Presentation of a GR log and Resistivity log plotted for each of the three wells


Figure 5: The Niger Delta Cenozoic Chronostratigraphic Chart (SPDC)


Figure 6: Schematic Presentation of the well logs showing the candidate SBs and MFS


Figure 7: Sequence Stratigraphic Interpretation of the Well Logs Showing the Correlated Surfaces across Wells and and the Different Systems Tracts Delineated

MFS

MFS

MFS

SB

SB

SB

MFS

S

OD

OD

OD

~4.9k~5.2k

TD @ 4404m

TD @ 3712m

TD @ 4268m LEGEND

TST

HST LST HST HST

OIL GAS

Condensate

FAU

MFS

Well_A Well_C B


Figure 8: Foramniferal Abundance and Diversity Chart of Well A


Figure 9: The Foramniferal Abundance and Diversity Chart Integrated with the Well Logs also showing the Paleoenvironment Interpretation


MFS 26.2Ma

MFS 28.1Ma

MFS 31.3Ma

SB 27.3Ma

SB 29.3Ma

SB 32.4Ma

MFS ?33.0Ma

SB

Well A

ODT

ODT

ODT

ODT

ODT

ODT

ODTGDT

ODT

Well C Well B~4.9km~5.2km

TD @ 4404m MD

TD @ 3712m MD

TD @ 4268m MD

FAU L

T

MFS ?34.0Ma

MFS 26.2Ma

MFS 28.1Ma

MFS 31.3Ma

SB 27.3Ma

SB 29.3Ma

SB 32.4Ma

MFS ?33.0Ma

SB

Well A

ODT

ODT

ODT

ODT

ODT

ODT

ODTGDT

ODT

Well C Well B~4.9km~5.2km

TD @ 4404m MD

TD @ 3712m MD

TD @ 4268m MD

FAU L

T

MFS ?34.0Ma

Figure 10: Interpreted well log showing the Positions of the MFS and SBs across Wells


3400

3500

3600

3700

3800

3900

4000

4100

4200

4300

4400

0 30 60 90 120 150D

epth

(m

)

GR Log (API Units)

1 10 100 1000 10000

ILD SN(Ohm-m)

0.6 0

NPHI

1.8 2.8

RHOB (v/v decimal)

A1

A2

A4

A5

A7

OIL GAS WATER SHALE

A3

A6

A9A8

Figure 11: Schematic Presentation of the Petrophysical Interpretation of Well A


3050

3100

3150

3200

3250

3300

3350

3400

0 30 60 90 120 150

Depth

(m

)GR Log (API Units)

1 10 100 1000 10000

LLD LLS MSFL(Ohm-m)

z

RHOB (v/v decimal)

2.81.80.6 0

B1

B3

OIL GAS WATER SHALE

B2

Figure 12: Schematic Presentation of Petrophysical Interpretation of Well B


3150

3200

3250

3300

3350

3400

3450

3500

0 30 60 90 120 150D

epth

(m)

GR Log (API Units)

1 10 100 1000 10000

ILD SN(Ohm-m)

RHOB NPHI1.8

0.6 0

2.8(v/v decimal)

C2

C4

C5

C6

OIL GAS WATER SHALE

C1

C3

Figure 13: Schematic Presentation of Petrophysical Interpretation of Well C


Pickets Plot for well A

0.01

0.1

1

10

0.01 0.1 1

Porosity (v/v decimal)

Resi

stiv

ity (o

hm-m

)

Pickets Plot

Rw = 0.1

Figure 14: A double Logarithmic Plot to Determine Rw for Well A

Picketts Plot for well B

0.01

0.1

1

10

0.01 0.1 1


Resi

stiv

ity(o

hm-m

)

Picketts Plot

Rw = 0.08

Figure 15: A double Logarithmic Plot to Determine Rw for Well B


Picketts Plot of well C

0.01

0.1

1

10

0.01 0.1 1


Resi

stiv

ity(o

hm-m

)

Pickets Plot

Rw = 0.1

Figure 16: A double Logarithmic Plot to Determine Rw for Well C

SPE 128353

Documents

Transcript of SPE 128353