RECOGNITION, CAUSES, AND EVALUATION OF LOW RESISTIVITY PAY SANDS USING WIRELINE LOGS: A CASE STUDY OF “AMO-FIELD” WITHIN
THE GREATER UGHELLI DEPOBELT OF THE TERTIARY NIGER DELTA BASIN
BY
EZE MARTINA ONYINYE
PG/M.SC/07/42789
DEPRTMENT OF GEOLOGY
FACULTY OF GEOLOGY
UNIVERSITY OF NIGERIA
NSUKKA
APRIL, 2010
RECOGNITION, CAUSES, AND EVALUATION OF LOW RESISTIVITY PAY SANDS USING WIRELINE LOGS: A CASE STUDY OF “AMO-FIELD” WITHIN
THE GREATER UGHELLI DEPOBELT OF THE TERTIARY NIGER DELTA BASIN
CERTIFICATION
EZE, MARTINA ONYINYE a postgraduate student in the Department of
Geology, University of Nigeria, Nsukka with Reg NO. P.G/M.Sc/42789, has
satisfactory completed the requirements of the course and research work for the
degree of Master of Science in Geology (Petroleum Geology). The work
embodied in this project Report is original and has not been submitted in part or
full for any other degree or diploma of this or any other University.
Dr. A.W Mode Dr. A.W Mode
……………………….. ……………………….
(Supervisor) (Head of Department)
DEDICATION
To Almighty GOD, to my beloved husband Mr. Eze Levi Obiora and to my Guardian Dr. Anthony Onyishi.
ACKNOWLEDGEMENT
My profound gratitude goes to my supervisor- Dr. A.W Mode for guiding me successfully till the
completion of this research work. He willingly provided me with materials and encouraged me even
when the work seemed impossible.
I am sincerely grateful to my Husband for his financial supports and care. My big thanks are due to
Emeka Bede who contributed immensely to the success of this work.
More so, I wish to express my warm gratitude to my colleague and friend Obi Ifeanyichukwu for his
encouragement and always being there for me. My appreciation goes to the efforts of the entire staff
of Total Elf Ltd for providing me with data and especially to my brother in-law- Mr. Ezema Cosmius.
I thank Mr. Endurance Ighodalo, for his suggestions and assistance.
Special thanks to Dr. Ugbor C.C and Mr. A. O Anyiam for their assistance. Finally, I will not forget
my classmates-Ngala Evelyn, Fidelis, Nwabueze, Brayam and Victor. For my Siblings- Chinyere,
Ifeoma, Amaka, Ike, Onyeka, Chinyere, Nnaemeka whose prayers saw me this far. I say God bless
you all in Jesus name.
TABLE OF CONTENTS
Title Page……………………………………………………………………………………..i
Certification………………………………………………………………………………….ii
Dedication……………………………………………………………………………………iii
Acknowledgement…………………………………………………………………………...iv
Table of content………………………………………………………………………………v
Lists of Figures………………………………………………………………………………vi
Lists of Tables……………………………………………………………………………….vii
Lists of Appendices………………………………………………………………………....viii
Abstract………………………………………………………………………………………..x
CHAPTER ONE: INTRODUCTION……………………………………………………….1
1.1 :Low Resistivity Pay sands Defined……………………………………………………...1
1.2 :Study Background……………………………………………………………………….1
1.3 :Location…………………………………………………………………………………..1
1.4 :Research Objective and Scope…………………………………………………………..2
1.5 :Literature Review………………………………………………………………………..2
1.6 :Methodology……………………………………………………………………………...5
1.7 :Wireline logs used for this analysis……………………………………………………..6
CHAPTER TWO: GEOLOGY OF NIGER DELTA………………………………………7
2.1: Regional setting and stratigraphy………………………………………………………7
2.2: Stratigraphy……………………………………………………………………………...8
2.2.1: Akata Formation………………………………………………………………………9
2.2.2: Agbada Formation…………………………………………………………………….9
2.2.3: Benin Formation………………………………………………………………………9
2.3 : Niger Delta Petroleum System…………………………………………………….. 12
2.3.1: Source Rock..................................................................................................................12
2.3.2: Reservoir Rock……………………………………………………………………….12
2.3.3: Traps………………………………………………………………………………….13
2.3.4: Seal……………………………………………………………………………………13
2.4: Sedimentary Evolution and Structural Evolution…………………………………14
2.5: Sedimentary growth fault or Synsedimentary Tectonics…………………………..15
2.5.1: Depobelts……………………………………………………………………………...16
CHAPTER THREE: LOW RESISTIVITY PHENONMENA…………………………..18
3.1: Impact of Clay conductivity on Reservoir……………………………………………18
3.2: Shaly sand models……………………………………………………………………..22
3.2.1: Waxman-Smits (1968) equation……………………………………………………..22
3.2.2: Double- layer Models/ Dual Water Shaly Sand Model……………………….........23
3.3: Causes of Low Resistivity pay sands/Clay distribution…………………………….25
3.3.1: Types of clay…………………………………………………………………………..25
3.3.2: Clay Distribution……………………………………………………………………..25
i: Laminar Clay………………………………………………………………………….25
ii: Dispersed Clay…………………………………………………………………………25
iii: Structural Clay………………………………………………………………………..26
CHAPTER FOUR: IDENTIFICATION AND EVALUATION OF LOW RESISTIVITY
OF “AMO” FIELD………………………………………………………………………….27
4.1: EQUATION USED IN EVALUATING THE LOW RESISTIVITY PAY ZONES...27
4.1.1: Volume of shale: ……………………………………………………………………...27
4.1.2: Total Porosity…………………………………………………………………………28
4.1.3: Water Saturation…………………………………………………………………......29
4.1.4: Modified Waxman Smits Equation………………………………………………….30
4.1.5: Selection of n* and m*………………………………………………………………..31
4.1.6: Effective water saturation and porosity…………………………………………….31
4.2: Producibility Indicators……………………………………………………………….32
4.2.1: The Bulk Water Volume……………………………………………………………..32
4.2.2: Permeability from logs……………………………………………………………….32
4.2.3: Flushed-zone Water Saturation (Archie Equation)………………………………..33
4.2.4:Moveable hydrocarbon index (MHI), Moveable oil saturation (MOS), and Residual oil
saturation (Ros)……………………………………………………………...33
4.3: Evaluation and interpretation for Well A Low Resistivity Pay Reservoir...…….33
4.3.1:Producibility of Well A……………………………………………………………….34
4.4: Evaluation and interpretation for Well B Low Resistivity Pay Reservoirs……….38
4.4.1: Producibility of Well B……………………………………………………………….39
4.5: Evaluation and interpretation for Well C Low Resistivity Pay Reservoirs………43
4.5.1: Producibility of Well C……………………………………………………………….43
CHAPTER FIVE: CLAY DISTRIBUTIONS OF “AMO-FIELD” LOW RESISTIVITY
RESERVOIRS……………………………………………………………………………….49
5.1: Clay Distribution for Well A…………………………………………………………..50
5.2: Clay Distribution for Well B…………………………………………………………..51
5.3: Clay Distribution for Well C…………………………………………………………..52
5.4: Conclusion and Recommendation…………………………………………………….54
References……………………………………………………………………………………55
Appendices…………………………………………………………………………………...62
LIST OF FIGURES
Fig 1: Map of Niger Delta showing the location of the study field.
Fig 2: Map of Niger Delta showing province outline and structural features.
Fig 3: Regional Stratigraphy of the Niger Delta.
Fig 4: Figures showing structure and associated traps.
Fig 5: Stratigraphic Evolution of Tertiary Niger Delta.
Fig 6: Megastructures and Macrostructures Types showing different kinds of faults.
Fig 7: Play map of the Niger delta showing Depobelts.
Fig 8: A schematic plot of the relationship of the conductivity of a water conductivity of a water
saturating rock as a function of the saturating fluid.
Fig 9: Dual water model.
Fig 10: Clay distributions structures.
Fig 11: Composite log showing the Low resistivity pay zones in well A.
Fig12: Composite Log of Well A.
Fig 13: Composite Log of Well B.
Fig 14: Composite log showing the Low resistivity pay zones in well B.
Fig 15: Composite log showing the Low resistivity pay zones in well C.
Table 16: Composite Log of Well C.
Fig 17: Reservoir correlation panel of the “Amo-field”.
Fig 18: A schematic plot of the relationship of the conductivity of a water saturated rock. as a
function of the saturating fluid.
Fig 19: Thomas-Steiber Triangle for Well A reservoirs.
Fig 20: Thomas-Steiber Triangle for Well B reservoirs.
Fig 21: Thomas-Steiber Triangle for Well C reservoirs.
LIST OF TABLES
Table 1: Stratigraphyic units of Niger Delta Area
Table 2: Water Saturation equations in terms of Resistivity
Table 3: Petrophysical Summary Table for well A
Table 4: Petrophysical Summary Table for well B
Table 5: Petrophysical Summary Table for well C
APPENDIX I
Validation of logs derived results with core interpretation results data
Table 6, well A Core interpretation
Table 7, well B core interpretation result
Table 8, well C core interpretation result
APPENDIX II
Picket plots for the wells
APPENDIX III
Well log results for the reservoirs evaluated
Well A
Well B
Well C
INTRODUCTION
1.1: Low Resistivity Pay Sands Defined:
Low Resistivity pay is a common term encompassing many forms of shaly sands (Fanini
et.al, 2001). Since many years ago; low resistivity formations were of no interest as wireline
logging research hinged on the principle that the hydrocarbon-filled rocks have a higher
resistivity than that of water-filled rocks depending on the salinity of the formation. By Low
resistivity pay sand, one infers that the reservoir contains a commercial quantity of
hydrocarbon but the resistivity log reads low, in other words, resistivity log is unable to
adequately “see” the hydrocarbon. More so, because of the low resistivity water saturation is
computed high and quite often the Low Resistivity zone is overlooked leading to
underestimation of net pay and hydrocarbon reserves.
1.2: Study Background:
The need for additional oil and gas reserves has increased dramatically over the years. To
meet this need, effort has been made by Petrophysicts to accurately evaluate geologic
fomations. Detecting Low resistivity pay zones has been a long standing challenge (Souvick
et.al, 2003). Because of the inherent conductivity of clay and hence shale, it is the primary
cause of low resistivity pay (Boyd et.al 1995). Hilchie (1978) notes that the most significant
effect of shale in a formation is to reduce the resistivity contrast between oil or gas and water.
.
1.3: LOCATION:
The study area-‘Amo’ field is situated within the Western onshore in the Greater Ughelli
depobelt of the Niger delta province in Nigeria (Fig 1). The Cenozoic Niger Delta is situated
at the intersection of the Benue Trough and the South Atlantic Ocean where a triple junction
developed during the separation of the continents of South America and Africa in the late
Jurassic (Whiteman, 1982).
� �
50 km
13 14
2026
39
2116
3034
32
2831
27
22
17
11
23
24
77
74
1925
72
71
29
79
33
36
46
81
4244 3545
43
40
1
3841
45
N
�������������� ���
OFFSHORE
Field Location
1.4: Research Objective and Scope:
Detailed evaluation of Low resistivity pay zones is the major aim of this work using
conventional log data.
-Delineation of the reservoir units in the wells.
-Characterization of these zones (Low resistivity pay zones).
-Accurate estimation of water saturation value of the zones using sand- shale models.
-Determination of the effective porosity.
-Validation of log data with core interpretation result.
-Determination of clay distribution in “Amo field”.
1.5: Literation review:
The Niger delta is perhaps the most important sedimentary basin in sub-Sahara Africa with
respect to petroleum production. This led to intensified investigation and work on the basic
geology, structural setting, lithology and depositional environment of the Niger Delta by
several authors. There has been an extensive study in Niger Delta Depocenters after a long
while of non-productive search in the Cretaceous sediments of Benue Trough (Doust, 1989;
Doust and Omastsola, 1990). The three major depositional cycles in the coastal sedimentary
basins of Nigeria were outlined by Short and Stauble, (1967) and Weber and Daukoru,(1975).
The megatectonic setting of the Niger Delta has been discussed by Stoneley, (1966), Burke
et.al, (1972). Short and Stauble, (1967) and Weber, (1975), reported that the first sedimentary
cycle began with an Albian marine incursion and terminated during the Santonian time while
the Proto-Niger delta commenced during the second cycle in the late Cretaceous which ended
in the Paleocene time. The third cycle marked the continuous growth of the Niger Delta from
Eocene to Recent(Murat, 1972). Sedimentation was at several stages interrupted by uplift and
erosion, which gave rise to the cutting and filling of channels known as submarine canyons.
The importance of longshore drift and submarine canyons and fans in the development of the
Niger delta also has been emphasized by Burke, (1972). The basement configuration,
deduced from geophysical data was presented by Hospers, (1965) and the synsedimentary
tectonics of the Cenozoic delta was described by Merki, (1972).
Sedimentary aspects of the upper Tertiary deltaic deposits derived from subsurface
data were described by Weber, (1972) and Weber and Daukoru, (1975). The source rock for
petroleum in the Niger Delta has been much discussed by many researchers (e.g Weber and
Daukoru, 1975; Evamy et.al 1978; Ekweozor and Okoye 1980; Haack, et.al 1997). Initially,
the shales of the Agbada Formation and the upper part of the Akata Formation were thought
to be the main source rocks for the hydrocarbons (Short and Stauble, 1967). Weber and
Daukoru, (1975) indicated that the Agbada shales are in most places immature and that the
Akata shales constitute the major source rocks for hydrocarbons of the Niger delta basin.
They concluded that the source rocks of the Niger Delta include the marine Akata Shale and
the underlying Cretaceous shale. Mature Eocene and Miocene shales of the Akata and
Agbada Formations constitute the major source rocks (Ekweozor and Okoye, 1980; Ejedawe,
1981; Nwachukwu and Chukwura, 1986; Evamy et al., 1978; Weber and Daukoru, 1975;
Bustin, 1988). They have also recognized known reservoirs as Eocene to Pliocene in age,
often stacked, ranging in thickness from 15m to 45meters. Evamy et.al, (1978) has
established a model of delta development based on the relation between rate of deposition
(Rd) and rate of subsidence (Rs). Based on reservoir geometry and quality, Weber and
Daukoru, (1975) stated that the lateral variations in reservoir thickness are strongly controlled
by growth faults with the reservoir thickening towards the fault within the downthrown
block.
Ekweozor and Daukoru, (1984) recognized only one petroleum system and is
referred as the Tertiary Niger Delta Akata-Agbada petroleum system. Knox and Omatsola,
(1989) explained the escalator regression style of the southward progradation of the Niger
delta. This style is formed by sudden shifts from one depobelts to the next and subsidence
along synsedimentary faults, recognized by the rapid seaward advance of alluvial sands over
the thick paralic sequence. The development of the Tertiary Niger delta has been related to
the evolution of the Cretaceous Benue Trough (Obi, 2000). Doust and Omatsola, (1990)
recognized six depobelts in the Niger Delta, which are defined in terms of the age of its
paralic sequence and the age of the alluvial sands that cap the paralic sequence. These
depobelts are Northern delta (Late Eocene –Early Miocene), Greater Ughelli (Oligocenc-
early Miocene), Central swamp II (middle Miocene), coastal swamp I and II (middle
Miocene), and offshore (late Miocene). The study area is located in the Greater Ughelli
depobelt.
Edward and Santogrossi, (1990) described the primary Niger delta reservoir as Miocene
paralic sandstones with porosity of 40%, Permeability of 2 Darcy and a thickness of 100
meters, while Kulke, (1995) described the most important reservoir type as point bars of
distributaries channels and coastal barriers bars intermittently cut by sand filled channels.
1.6: METHODOLOGY
This research work using available data was carried out and this include;
¬ A preliminary review of all available data and existing literature on Low
Resistivity pay sand.
¬ Delineation and interpretation of Low Resistivity reservoirs of “Amo-field”
using available wireline logs.
¬ Extracting the correct measurement of Formation resistivity by Picket plot.
¬ The permeability was predicted using empirical correlation Wyllie and Rose
equation.
¬ Accurate derivation of water saturation (sw) using Shaly sand equation.
¬ Validation of the petrophysical results using the core interpretation result data
¬ Evaluation of the effect of the clay distribution of Low Resistivity reservoirs
using Thomas-Steiber’s equations.
¬ Demonstration of the clay distribution using Thomas-Steiber’s model.
1.7: Wireline log used for analysis:
The wireline logs were obtained from three wells- well A, well B and well C of ‘Amo field’
of the Greater Ughelli depobelt. The porosity was estimated from the density log. The gamma
ray log, neutron/density logs as well as the resistivity logs were used for lithology
delineation. The neutron and density logs of clean sandstones track each other closely or with
small separation while large separation is observed in shale intervals. Volume of shale were
estimated using gamma ray log and the necessary correction for shale on available porosity
well logs were effected.
CHAPTER TWO
GEOLOGY OF NIGER DELTA
2.1: Regional setting and stratigraphy:
The Niger Delta is a prograding depositional complex within the Southern Nigeria. It
covers a 70,000 square kilometer area within the Gulf of Guinea, West Africa. (Figure 2).
Sediments began to accumulate in this region during the Mesozoic rifting associated with the
separation of the African and South American continents (Weber and Daukoru, 1975; Evamy
et al., 1978; Doust and Omatsola, 1990). Synrift marine clastics and carbonates accumulated
during a series of transgressive-regressive phases between the Cretaceous to early Tertiary;
the oldest dated sediments are Albian in age (Doust and Omatsola, 1989). These synrift
phases ended with basin inversion in the Late Cretaceous (Santonian). By Late Cretaceous
and Early Cenozoic time the continental margin subsided as the oceanic crust cooled. Proto
Niger-delta regression continued as continental margin subsidence resumed at the end of the
Cretaceous (Maastritchian). This Proto Niger-delta succession is called “Anambra delta”.
Niger Delta progradation into the Gulf of Guinea accelerated from the Miocene onward in
response to evolving drainages of the Niger, Benue and Cross rivers and continued
continental margin subsidence. The bulk of the sediment was from the North and east during
most of the Tertiary, even though there is little evidence for substantial Tertiary uplift in
much of the catchment area of the Niger-Benue river systems.
The regression rates increased in the Eocene, with an increasing volume of
sediments accumulated since the Oligocene. Delta progradation occurred along two axes, the
first paralleled the Niger River, where sediment supply exceeded subsidence rate. The second
became active during Eocene to early Oligocene basinward of the cross River where
shorelines advanced into the olumbe- 1 area (Short and Stauble, 1967).
Figure 2: Map of Niger Delta showing Province outline (maximum petroleum system); and
key structural features. Minimum petroleum system as defined by oil and gas field center
points (data from Petroconsultants, 1996); 200, 2,000, 3,000, and 4,000m bathymetric
contours shown by dotted contours; and 2 and 4 km sediment isopach shown by dashed
lines (From Tuttle et al., 1999).
2.2: REGIONAL STRATIGRAPHY
Short & Stauble, (1967) defined three lithostratigraphic units in the Tertiary of the
Niger Delta (fig 3) in which a regressive succession is properly defined. The Tertiary deltaic
complex has been divided into three major facies units based on the dominant environmental
influences. The main sedimentary environments are the continental environment, the
transitional environment and the marine environment. The three lithostratigraphic units are as
follows:
2.2.1: Akata Formation: Akata Formation ranges in age from Paleocene to Recent. This is
the basal major time transgressive lithologic unit in the Niger Delta complex. It comprises
mainly of shales with occasional turbidite sandstones and siltstone. The depositional
environment is typically marine and the maximum thickness is averaged 20,000m(Aliu,
1974).
2.2.2: Agbada Formation: Agbada Formation ranges in age from Eocene to Holocene. The
formation consists of sands or sandstones and marine shales. The sandy parts constitute the
main hydrocarbon reservoirs while the shales constitute seals to the reservoir. It is
characterized by alternating sandstones and shales of delta-front, distributary channel and
deltaic plain origin that represent a coarsening upward regressive succession (Short and
Stauble, 1967). The environment is defined as “transitional” between the upper continental
Benin Formation and the underlying marine Akata Formation. The maximum thickness is
possibly 15,000m (Aliu, 1974). The Formation is the principal reservoir of Niger delta
(Weber 1971).
2.2.3: Benin Formation: Benin Formation ranges from Eocene to Holocene in age. The
depositional environment of the sediment is mainly continental. The Formation consists of
thick bodies of sands and gravels with local thin shale interbeds. It constitutes the top part of
the Niger Delta clastic wedge from Benin to Onitsha area in the North to beyond the present
coastline (Short & Stauble, 1967).
Fig 3:Schematic of Niger Delta variable density seismic display of the main stratigraphic
units with corresponding reflections (Lawrence et al., 2002).
Table 1: Stratigraphic units of Niger Delta Area, (Short and Stauble, 1967).
Subsurface Surface Outcrops
Youngest
known Age
Oldest
known
Age
Youngest
Known Age
Oldest Known
Age
Recent
Benin
Formation
(Afam
clay
member) Oligocene Plio/Pleistocene Benin Formation
Recent
Agbada
Formation Eocene Miocene Eocene
Ogwashi-Asaba
Formation Ameki
Formation
Oligocene
Eocene
Recent Akata
Formation Eocene lower Eocene
Imo shale Formation Paleocene
Unknown Paleocene
Maestrichtian
Campanian
Campanian/Maes
trichtian
Coniacian/Santo
nia Turonian
Albian
Nsukka Formation
Ajali Formation
Mamu Formation
Nkporo Shale Awgu
Shale Eze Aku Shale
Asu River Group
Maestrichtian
Maestrichtian
Campanian
Santonian
Turonian
Turonian
Albian
2.3: Niger Delta Petroleum System: The Niger Delta province contains only one identified
petroleum system (Kulke 1995, Ekweozor and Daukoru, 1984) referred to as the Tertiary
Niger Delta (Akata-Agbada) petroleum system. However, Haack et.al (1997) defined three
petroleum systems for the Niger Delta. They are the Tertiary(deltaic), Upper Cretaceous-
Lower Cretaceous(Marine), and Lower Cretaceous(Lacustrine).
2.3.1: Source Rock: There has been much discussion about the source rock for petroleum in
the Niger Delta (Evamy et.al, 1978; Ekweozor and Okoye, 1980; Doust and omatsola, 1990).
Many authors have claimed that the main source lies in shales in the paralic Agbada
Formation. (Lambert-Aikhionbare and Ibe, 1984; Egbogah and Lambert-Aikhionbare, 1980;
Nwachukwu and Chukwura,1986), while others suggest that it lies below the former in the
continuous marine shales of the Akata Formation (Weber and Daukoru (1975) and Ekweozor
and Daukorus(1984). Source rocks in the Niger-Delta might include interbedded shale in the
Agbada Formation and the marine Akata Formation shales (Evamy et al, 1978; Doust and
Omatsola, 1990).
2.3.2: Reservoir Rock: Niger Delta petroleum is produced from sandstone and
unconsolidated sands predominantly in the Agbada Formation (Kulke, 1995). Reservoir
intervals in the Agbada Formation have been interpreted to be deposits of highstand and
transgressive systems tracts in proximal shallow ramp settings (Evamy et al, 1978). Kulke,
(1995) describes the most important reservoir units as point bars of distributary channels and
coastal barrier bars intermittently cut by sand filled channels. Reservoirs may thicken toward
down-thrown sides of growth faults. Reservoir units vary in grain size; fluvial sandstones
tend to be coarser than the delta front sandstones. Point bar deposits fine upwards; barrier bar
sandstones tend to have the best grain sorting.
2.3.3: Traps: Structural traps formed during synsedimentary deformation of the Agbada
Formation (Evamy et al., 1978; Stacher, 1995) and stratigraphic traps formed preferentially
along the delta flanks define the most common reservoir locations within the Niger Delta
complex.
Fig 4: Figure showing structures and associated traps. Modified from Doust and Omatsola, (1990) and Stacher, (1995).
2.3.4: Seal: The primary seal rocks are interbedded shales within the Agbada Formation.
Three types of seal are recognized namely: clay smears along faults, interbedded sealing units
juxtaposed against reservoir sands due to faulting, and vertical seals produced by laterally
continuous shale-rich strata (Doust and Omatsola, 1990).
Many erosion events of early to middle Miocene age formed canyons which filled
with shale; these fills provide top seals on the flanks of the delta for some important offshore
fields
2.4: Sedimentary Evolution and structural Evolution:
The early development of the deltaic is controlled by basement tectonics related to crustal
divergence and translation during the Late Jurassic (?) to Cretaceous continental rifting. It
probably determined the original site of the main river. Based on gravity data, the Cenozoic
development of the delta could have taken place under approximately isostatic equilibrium
(Hospers, 1971). The present day Niger delta is prograding into the Gulf of Guinea as a high
energy constructive lobate delta where Rd/Rs is generally greater than one. Diapiric uplift of
the delta front on the continental slope and rise is a major structural factor controlling
progradation(Whiteman, 1982). That is when Rd>Rs, the delta complex progrades, when
Rd=Rs the delta complex remains stationary and builds. When Rd<Rs, the delta complex
retreats (Whiteman, 1982). During Cenozoic time, overall Rd was greater than Rs and
regional transgression produced relatively short lived transgressions interrupting the general
prograding of the complex. However, local variations in Rs and Rd produced distractive
sedimentary and structural units of different shape and thickness within the facies. A
basement tectonics has been envisaged for the development of the delta farther south during
the progradation over the oceanic crust. Increase in the rate of subsidence is indicated in the
Tertiary overburden by the regularly spaced regional flanks associated with shale ridges and
counter regional faults in this area. This increase in the rate of subsidence may be as result of
repeated failure of the oceanic crust under the thick sedimentary pile of the outbuilding
Tertiary delta.
Fig 5 Stratigraphic Evolution of Tertiary Niger Delta (modified by Evamy et.al.,1978).
2.5: Synsedimentary growth fault or Synsedimentary Tectonics: The synsedimentary
faults called growth faults are regarded as a product of gravity sliding during the course of
deltaic sedimentation (fig 6). Down to the basin, growth faulting is initiated when relative
heavy, sandy deposits of a regressive cycle (Rs>Rd) prograde over little compacted clays
with low shear strength. When the amount of space created by growth fault is insufficient to
accommodate the supply of sediment, another fault controlled depocenters are formed
progressively in a seaward direction, where Rd=RS that is the amount of sediment is not in
excess of the space available for accumulation, the depocenter will continue to be active until
Rd>Rs. Under this condition, each new fault controlled depocenter is the result of a change in
the relation of Rs and Rd and is considered to form the beginning of a new sedimentary
megaunit. Under this condition, of Rd=Rs, the gradual development of a long regional south
flank may have been interrupted by a temporary return to conditions of Rd>Rs(fig. 6). Steep
regional flanks exist at depth in the western part of the offshore “K” block reflecting initial
conditions of a relatively high rate of subsidence (Rs>Rd). The flanks, are overlain by a new
cycle of sediments with low dips and are affected by numerous close faults (fig. 6).
Figure 6: Macrostructure and Megasructure Types Showing, A: Antithetic Faults, B: Structure-Building or Boundary Faults, MB if major, C: Crest Faults, CR: Counter Regional Fault, F: Flank Fault and K: K-type of Faults (Evamy et al., 1978)
2.5.1: Depobelts: Depobelts represent successive phases of delta growth (Fig 7). A
conceptual model known as Escalator Regression has been developed to describe the one
way stepwise outbuilding of the Niger delta through geological time (Knox and Omatsola,
1989). The units of these steps are transient depobelts. Megastructures can be subdivided into
smaller fault bounded macrostructures (Evamy et.al, 1978) (fig. 6). Along strike a series of
megastructure combine to form a depobelt. Successive depobelts contain sedimentary fills
markedly younger than the adjacent ones in a landward direction. Between successive
depobelts, on delta dip sections, a relationship is apparent. The base alluvial sand facies of an
updip (older) depobelt is time equivalent to the initiation of the base paralic sand/shale
sequence in the down-dip depobelt. The diachronous sand/shale to alluvial sand lithofacies
change at the exterior part of a depobelt is time equivalent to the deposition of the paralic
sequence of the next down dip depobelt (Knox and Omatsola, 1989). Parallic sequence
deposition is terminated by a rapid advance of an alluvial sand facies over the proximal and
central areas of the belt. This advance initiates deposition of the paralic sand/shale sequence
in the succeeding depobelt. This sequence of events repeated itself five to six times over the
last 38m yrs to define a series of depobelts. Depobelts become increasingly younger seaward
forming a more convex outer front to the Niger delta
Fig 7: Play map of the Niger delta showing depobelts (Tuttle et al., 1999).
CHAPTER THREE
LOW RESISTIVITY PAY SAND PHENONMENA
3.1: Impact of Clay conductivity on Reservoir:
Exceptionally few hydrocarbon bearing clastic reservoir rocks are essentially free of clay
minerals (Fertl and Frost, 1980). A convenient starting point for the explanation of shaly –
sand problem as it affects resistivity data can be done by defining formation factor F which is
a formation parameter.
F = Ro/Rw = Cw/Co………………………….1
Where,
Ro is the resistivity of the rock when fully saturated with aqueous electrolyte of
resistivity RW, and Co and CW is their conductivities.
A plot of Co Vs Cw should give a straight line of gradient 1/F under Archies experimental
conditions of a clean reservoir rock. The formation factor is a parameter of the formation
subject to these conditions and describes the pore geometry of the formation. It is
independent of Cw so that a plot of Cw/Co Vs Cw should furnish a straight line parallel to the
Cw axis (Fig 8).
However, there has been increasing evidence from various formations to suggest that the
ratio Cw/Co is not always a constant for a given sample but can decrease as Cw decreases
(Patnode and Wyllie 1950) for shaly sand formations. The electrical manifestation of shale
effects has been described in terms of an “excess conductivity” (Winsauer and McCardell,
1953). Thus, the ratio Cw/Co is regarded as an apparent formation factor Fa which is equal to
the intrinsic formation factor F only when Archie’s assumptions are satisfied (Worthington,
1985).
The Invalidity of Archies definition of equation in Shaly sand Formation led to the
developments of numerous equations or empirical relationships, under the generic
terminology of “shaly sand equations” (Riders, 1996), to take into account the effect of clay
and compute an accurate water saturation (Table 2). A more general relationship between
Co and Cw was proposed in order to accommodate the excess conductivity. Rewriting
equation 1 and incorporating the excess conductivity, we
have:
Co = CW/F + X …………2
For clean sand, X 0 and equation 2 reduces to 1.
Nearly every shaly sand log analysis model is in basic agreement with equation 2 above and
valid for granular reservoirs that are fully water saturated. This condition exists where the
matrix is conductive or where a second conductive path exists in the pore network. Clay
provides such a conductive path. For a given value of ‘X’, the magnitude of the shale effect
decreases as the formation water conductivity ‘CW’ increases.
Thus, where formation waters are very saline, the contribution of the shale term becomes
relatively large(Fig 8). So, it is in brackish and fresh water applications that most shaly sand
models encounter difficulties.
Fig 8: A Schematic plot of the relationship of the conductivity of a water saturated rock as a function of the saturating fluid.
Table 2: Shaly sand models in Terms of resistivity
3.2: Shaly-sand models:
3.2.1: Waxman-Smits (1968) equation: According to this model, a shaly formation
behaves like a clean formation of the same porosity, tortuosity, and fluid saturation, except
the water appears to be more conductive than its bulk salinity. Waxman-smits (1968) model
constitutes a comprehensive description of the electrical behavior (conductivity and
electrochemical potential) of water and hydrocarbon-bearing shaly sands. It is a modified
Archie equation that account for excess conductivity. An expression of the WST equation for
SwT is given by;
SWT= [Rt/�Tm*
*Rwe]^ 1/n*
Where, 1/Rwe = Cwe = 1/RW + BQV/SWT is equivalent bulk water conductivity.
�T = Total porosity, fraction bulk rock volume occupied by fluids (hydrocarbon,
free electrolyte and clay-hydration water).
m* and n*= clay corrected cementation factor and saturation exponent
respectively.
QV is cation exchange capacity per unit total pore volume (meq/cm3).
B is equivalent conductance of the (Na+) exchange cations (mho.m-1/meq.cm-3).
The excess bulk water conductivity is due to the presence of excess cations in the bulk water
surrounding the clay particles and compensating for their negative electrical charges. The
magnitude of the excess conductivity is proportional to the concentration of these
compensating cations (QV/SWT) and their equivalent conductance,
B = 1.28+0.225t - 0.0004059t2 / 1+Rw1.23 (0.45t - 0.27) where‘t’ is in oC and Rw is in
Ohmmeter.
Normalised Qv: Qv value of a reservoir rock is defined as CEC per pore volume (Ruhovets
and Walter, 1981). Qv can be estimated from well log based on gamma ray/reservoir porosity
(Johnson, 1979), Reservoir porosity (Juhaz, 1979, 1981 Kern et.al., 1976; Howells and
Wilkinson, 1977), the spontaneous potential curve ( Johnson 1979; Smits, 1968), It is “shale-
water saturation” expressed in terms of fraction total pore volume. Qv in the W-S equation is
replaced with a dimensionless expression defined as “normalised Qv” (Qvn) (Juhaz, 1981).
Its range is from zero to 1.0.
Qvn = Vsh �Tsh/ �T
3.2.2: Double- layer Models/ Dual Water Shaly Sand Model:
Clavier et al., (1977) built on the work of Waxman and colleagues to postulate the Dual
water model. Essentially all measurement, then are affected in some way by the presence of
clay and/or shale. In this method a unit volume of formation is divided into matrix,
hydrocarbon, free water, bound water, and dry clay. The matrix, hydrocarbon, and dry clay
are considered to be electrically inert (Figure 9).
Clavier, Coates and Dumanoir published the latest version of the model in 1984. Winsaur and
McCardell(1953) stated that the excess conductivity, double layer conductivity of shaly
reservoir rocks, was attributed to adsorption on the clay surface and a resultant concentration
of ions adjacent to this surface. Hence, the pore space of shaly sand is assumed to be filled
with the clay water and free water.
Both dual water model and Waxman Smits model consider that the conductivity of the
saturating fluid is complemented by the conductivity of a clay counter ions. The D-W model
characterizes the shaly sand formation by total porosity, formation factor, Fo, shaliness
parameter, Qv, and its bulk conductivity Ct observed at total water saturation, Swt. The D-W
model also assumes that the formation behaves as a clean rock of the same porosity,
tortuosity, and water saturation but containing an equivalent conductivity, Cwe.
Figure 9: Dual water model. (Schlumberger, 1998)
Where RWB = Resistivity of bound water,
RWF = Resistivity of free water (RW),
T = Total porosity,
e = Effective porosity,
SWT = Total water saturation,
SWB = Bound water saturation and
SWF = Free water saturation
3.3: Causes of Low Resistivity pay sands/Clay distribution:
How clay contributes to low Resistivity pay sands depends on the type, volume and
distribution of clay in the formation (Boyd et.al 1995).
3.3.1: Type of clay: Clay with a high Cation exchange coefficient(CEC) will have a greater
impact on lowering resistivity than those with a low CEC. For example, Montmorillonite has
a CEC 0f 80 to 150 meq/100 g whereas the CEC of Kaolinite is only 3to 15 meq/100 g (Boyd
et.al, 1995).
3.3.2: Clay Distribution
I. laminar Clays: Clay layers between sand layers. They make up significant percentage of
low resistivity formations offshore. Laminar shales are formed during deposition,
interspersed in otherwise clean sands (Boyd et.al, 1995). Laminated shales/clays replaces
porosity and matix.
II. Dispersed Clays: Presence of Clays throughout the sand, coating the sand grains or
filling the pore space between sand grains. Dispersed clays are formed during deposition of
individual particles or masses of clay. Dispersed clays can result from post depositional
processes, such as burrowing and diagenesis. In clay coated sand grains the irreducible water
saturation of the formation increases, lowering the resistivity values.Dispersed shales/clays
replaces the porosity.
III. Structural Clays: Clay grains or nodules in the formation matix. Structural clays occur
when framework grains and fragements of shale or claystone occur with a grian size equal to
or larger than the framework grains are deposited at the same time. Structural clays/shales
replaces only the matrix.
Fig 10: Clay Distribution models
CHAPTER FOUR
IDENTIFICATION AND EVALUATION OF LOW RESISTIVITY PAYS OF ‘AMO’
FIELD.
The low resstivity pay zones of three wells-well A, well B and well C was analyzed.
The porosity was estimated from the density log. The effective porosity was further deduced
by introducing the shale volume percentage into the density equation. Water saturation was
calculated using the Archie’s 1948 (Swa) and the Juhaz, 1981 modified Waxman-smits (SwT)
equations. Low resistivity sands of the Amo-Field have water saturations greater than 50%
and as often as high as 90%. The low resistivity zones were delineated using the resistivity
log, gamma ray log, the Neutron and Density logs. The Low Resistivity reservoirs delineated
in “Amo field” consists also zones with little resistivity difference between water bearing and
oil bearing zones(Low contrast zones).
4.1: EQUATIONS USED IN EVALUATING THE LOW RESISTIVITY PAYS OF
‘AMO’ FIELD ARE AS FOLLOWS:
4.1.1: Volume of Shale (Vsh): The quantity Vsh is defined as the volume of wetted shale per
unit volume of reservoir rock (Worthington, 1985). Volume of clay is the first and most
critical parameter to determine in shaly sand analysis (Dewan, 1983, and Hilchie, 1982).
Because shale is more radioactive than sand or carbonate, gamma ray log can be used to
calculate volume of shale in porous reservoirs (Asquith, 2004). There are other methods that
are used to calculate volume of shale, for this study gamma ray log was used. Linear Gamma
ray index method was used as the first step to determine the volume of shale from a gamma
ray log.
IGR = GRlog – GRmin………………………..……………(1)
GRmax - GRmin
Where, IGR = gamma ray index
GRlog = gamma ray reading of formation
GRmin = minimum gamma ray (clean sand) and
GRmax = maximum gamma ray (shale).
The shale volume was then calculated using the Larionov (1969) nonlinear response method.
Vsh = 0.083(23.7 IGR
– 1) (For tertiary unconsolidated
rocks).……………………….(2)
Vsh = volume of shale.
A direct relationship exists between increasing clay content and decreasing effective
reservoir porosity (see APPENDIX II).
4.1.2: Total Porosity: Total porosity is the total pore volume of the rock and includes
porosity filled with hydrocarbons, moveable water, capillary-bound water, and clay-bound
water (Hook, 2003). Both the Density and neutron logs are considered total porosity tools
because they detect all the porosity in a region surrounding the logging tool. Total porosity
was calculated using 2.65g/cm3 grain density. However, for a shaly sand, the porosity
calculate is usually affected by the presence of shales in the sands(Etu-Efeotor,1997). Total
Porosity was calculated from density log using the following formula:
�D = �ma - �b …………………………………………….(4)
�ma - �fl
where:
�D = density porosity
�ma = matrix density (sandstone) 2.65g/cm3
�b = bulk density (log reading) and
�fl = fluid density = 1.0g/cm ( for water), 0.7 for gas, and 0.9 for oil.
4.1.3: Water Saturation: This is the amount of pore volume in a rock that is occupied by
formation water. The water saturations were computed using the Archie’s (1942) equation,
Modified Waxman-Smits equation. A large number of models relating fluid saturation to
resistivity have been developed over the years for shaly-sands according to geometric form of
shales (Laminated, dispersed and structural), (Hamada, 1996). Simandoux or Indonesian
equation (Dresser, 1982) is essentially applicable to laminated clay models, with some
adaptation for non linear behavior of shale electrical properties and Waxman-Smits or Dual
water model (Clavier et al, 1977) is essentially designed for the case of dispersed or structural
clay models. The water saturation formulas used are as follows: Archie’s equation:
Sw = a x RwRt x �m
1/n
.....................................................................................(5)
Sw: is the water saturation
Rw: is the formation water resistivity(derived by Picket plot).
Rt: is the uninvaded zone resistivity determined from the deep resistivity log
�: is the formation porosity determined from the density log.
a: = 1 (Tortusity factor).
m = 1.6 (derived from average value of core interpretation result) cementation
factor.
4.1.4: Modified Waxman Smits Equation: This equation is based on the Juhaz (1981)
model and makes do without the BQV Waxman-Smits shaly sand equation. Two sets of
equation were used:
1. When Rw>Rwb
Ro =F* RW*Rwb/ (Rwb * (1- Vclay) + Vclay * Rw)
SWT = (Ro/RT)^ (1/n)
2. When RW<=Rwb, X=Vcl*(Rwb-Rw)/2*Rwb,
Swt= (X^ 2+F*RW)/RT)^ (1/n)+X
Where Ro = F* RW/ (Rwb * (1- Vclay) + Vclay * Rw)
Ro= Resistivity of water zone
F*= *1mt
aΦ
Rw = Resistivity of the formation.
Rwb= Resistivity of clay bound water.
Vclay= volume of clay.
m*= clay corrected cementation factor.
4.1.5: Selection of n* and m*: They were computed using equations based on common
experience obtained on core measurement of shaly formations for corrected value of m and n
respectively (Shell Petroleum Development Company).
n* =1/0.38829+0.56062* �………………………………(8)
m*= 2.008-0.946* �……………………………………….(9)
4.1.6: Effective water saturation and porosity:
Effective porosity is the ratio of the interconnected void space in the rock bulk volume
of the rock (Tao, 2003). The main purpose of converting �t and SWT values into effective
porosity (�E) and effective water saturation (SWE) is to have a better grip on terms of
distribution and productivity of the hydrocarbon present in the formation (Juhaz, 1981).
�e = �T*(1-Vcl)……………………………………….(10)
and
SWE = SWT –QVn/1-QVn. ………………………………..(11)
In shaly sandstone, significant portion of the porosity is occupied by clay-bound water that is
immobile under all conditions and consequently is not part of effective porosity for the
fraction of the total porosity that is not associated with clay minerals, thus excluding the
volume of clay-bound water but including capillary-bound water on grain surfaces (Juhaz,
1981).
4.2: Producibility Indicators:
4.2.1: The Bulk Water Volume: Because production of water in a well can affect a
prospect’s economics, It is important to know the bulk volume water and whether the
formation is at irreducible water saturation (Swirr) (Asquith, 2004). The proportion of water
in the total formation is referred to as bulk volume water (Asquith, 2004). It can be indicator
that the formation is at irreducible water saturation. Hydrocarbon production from zones at
irreducible water saturation are water free (Morris, 1967).
BVW = � * SW…………………….(3)
4.2.2: Permeability from logs:
Log-derived formulas are only valid for estimating permeability in formations at irreducible
water saturations (Sclumberger, 1977). A formation is at irreducible water saturation when
the BVW values are constant. From the result of BWVcalculated, the formation are at
irreducible water saturation. The Wyllie and Rose (1950) formula used to evaluate the
permeability is as follows:
K = 250 x �3
Sw irr........................................(12)
K = permeability.
Sw irr = water saturation (Sw) of a zone at irreducible water saturation.
� = porosity.
For Dry Gas,
4.2.3: Flushed-zone Water Saturation(Archie Equation): The flushed zone water
saturation (Sxo) is calculated from Archie’s equation, with Rmf substituted for Rw, and Rxo
substitututed for Rt.
4.2.4: Moveable hydrocarbon index(MHI),Moveable oil saturation(MOS), and Residual
oil saturation(ROS): Moveable hydrocarbon index was derived from the ratio water
saturation method.
MHI= Sw/Sxo= ( Rxo/Rt)1/2………………………………………………………………………………..13
Rmf/Rw
4.2.5: Moveable oil Saturation:
MOS = Sxo-Sw………………………………………………………………12
K = 79 x � 3S w irr
4.2.6: Residual oil saturation(ROS):
ROS= 1.0- Sxo…………………………………………………………………….13
4.3: Evaluation and interpretation for Well A Low Resistivity Pay Reservoirs:
The total depth drilled for well A is 4245meters. The Low Resistivity pay reservoirs
evaluated in this well are labeled AI-A5. They have average porosity values of a typical
Niger delta reservoirs ranging from 0.21% v/decimal in reservoir A4 and A5 to 0.28%
v/decimal in A1). The petrophysical summary table results for well B are shown in Table 3.
The reservoir thicknesses are 14m- reservoir A1, 5m- reservoir A2, 27m- reservoir A3, 14m-
reservoir A4 and 5m- reservoir A5. For the volume of shale, these criteria were the bases for
calculation: GRclean=25 API units, GRshale= 150API units.
The results from the Archie’s equation indicate high values of water saturation, ranging from
0.47% in reservoirs A1 to 0.73% in reservoir A4, while the results from Modified Waxman-
Smits equation give lower percentage water saturation values between 0.03% in reservoir A2
and 0.58% in reservoir A3. The Archie’s eqution was applied with Rw= 0.16ohm-m (derived
by picket plot), Cementation factor (m) of 1.6 (derived from average value of core
interpretation result) and saturation exponent n of 1.9. The average resistivity log responses
are 6.98ohm-meter, 4.41ohm-meter, 4.41ohm-meter, 8.53ohm-meter, 3.0ohm-meter,
4.10ohm-meter and 3.16ohm-meter for reservoir A1-A5. The low values confirms the fact
that they are low resistivity zones. Volume of shale greater than 0.10v/v decimals occurring
in sands affects their water saturation values (Hilchie, 1978). The average volume of shale
(Vsh) in reservoirs A1-A5 are within the limits that could affect the value of water saturation
(>10-15%). Their Volume of shale ranges from 0.10% v/vdecimal in reservoir A4 and A5 to
0.26% in A2. A direct relationship exists between increasing clay content and decreasing
effective reservoir porosities (see Table 3).
4.3.1: Producibility of well A: Bulk-volume-water is calculated from equation 3 above. It
shows low, fairly consistent values for all the zones, suggesting that the formation is at
irreducible water saturation(Appendix II). The permeability and porosity values for the Low
Resistivity reservoirs of the well are good. The calculated values of the moveable
hydrocarbon index(MHI), are greater than 0.7, but in the general case, moveable hydrocarbon
indices of productive reservoirs are less than 0.7(Asquith,1982). Residual oil saturations
(ROS) and moveable oil saturation(MOS) calculated are high. Analyses of MHI suggest that
hydrocarbons will not move
Wel
l
/Res
ervo
ir
Dep
th
inte
rval
(m)
GR
-
com
p(A
PI)
Rt(
ohm
-m)
Vsh
(v/v
)
�T(v
/v)
�e(v
/v)
Arc
hie’
s Sw
Wax
-sm
it Sw
Tot
al
Tk(
(m)(
m)
Flui
d
A1 2468-
2482
63 6.98 0.12 0.28 0.25 0.47 0.07 14 H-C
A2 2737-
2742
90 4.41 0.25 0.26 0.20 0.58 0.03 5 H-C
A3 3007-
3034
62 8.53 0.12 0.24 0.20 0.51 0.58 27 H-C
Wel
l -06
A4 3970- 60 4.10 0.10 0.21 0.20 0.73 0.12 14 H-C
Table 3: Petrophysical Summary Table for well A
3984
A5 4144-
4150
52 3.16 0.10 0.21 0.26 0.58 0.24 5 H-C
Gamma ray logPef, Density $ Neutron logs SP LOG Rt $ RXO LOGS
A1
A2
A3
A4
A5
Fig 11: Composite Log of well A showing the Low Resistivity pay zones
Fig 12: Composite log of well A
4.4: Evaluation and interpretation for Well B Low Resistivity Pay Reservoirs:
The total depth drilled for well B is 4413meters. Eleven Low Resistivity pay zones labeled
B1 –B11 were evaluated in this well. Their thicknesses are B1- 8m, B2- 9m, B3- 12m, B4-
6m, B5- 10m, B6-21m, B7- 22m, B8- 14m, B9- 11m, B10- 30m, and B11- 16m respectively.
The general configuration of the gamma ray and the mutual disposition of the neutron- and
density-porosity show the likelihood of shale in the reservoir (fig 13). The petrophysical
summary table results for well B are shown in Table 4. In the absence of core data, a
preliminary evaluation approach was used in well B by applying the Archie equation with Rw
= 0.14 ohm m (derived by picket plot), Cementation factor (m) of 1.6 (derived from core
interpretation result) and saturation exponent n of 1.9. The Clay was corrected for well B by
applying the modified Waxman-Smits equation. A value of 1.9 was used for the clay-
corrected cementation factor (m*). For the volume of shale, these criteria were the bases for
calculation: GRclean =20 API units, GRshale=150 API units.
The average density porosity for the reservoirs ranges from 0.17%v/v decimal for
reservoir B11 to 0.25% v/v decimal for reservoirs B6. The reservoirs have good porosity
values. The volume of shale was calculated using the non-linear response method-
Larionov(1969).The average volume of shale of the reservoir B1, B2, B3, B4, B5, B6, B7,
B8, and B11 are over the threshold (i.e. >10%-0.14%) that affect the water saturation of a
reservoir. The average volume of clay for reservoirs B9 and B10 are moderate and do not
explain the resistivity anomaly in these zones. The predominant clay mineral for reservoir B9
and B10,and may be clay mineral with low CEC like Kaolinite and this could result in a
negligible amount of electro-chemical bound water, (moderate Vsh). Examination of the
Sandstones of Agbada Formation of Niger Delta by scanning electron microscopy showed
that authigenic kaolinite and to a lesser extent authigenic smectite was present(Lambert-
Aikhionbare,1982). The average resistivity values for the reservoirs are B1-2.0ohmm, B2-
1.73ohm-meter, B3-2.02ohmm, B4-2.67ohmm, B5-2.25ohmm, B6-2.05ohmm, B7-
2.77ohmm, B8-2.74ohmm, B9-2.53ohmm, B10-2.58ohmm, B11-5.04ohmm(fig 13).
The calculated average water saturation (SWT) using the Archie’s equation ranges from
0.70% for reservoir B11 to 0.95% for reservoir B3 while the modified Waxman-Smits water
saturation gave lower values that range from 0.26% in B11-0.39% in B2. (Table 4). The
water saturation equation values calculated using the Archie’s equation are high as a result of
presence of clay in the reservoirs.
4.4.1: Producibility of well B: The Bulk volume water values at several depths in well B are
constant or close to constant and this indicate that the zone is at irreducible water saturation
(Appendix II). Bulk volume water is calculated from equation 3 above. The reservoirs have
good average porosity values. The average permeability of reservoir in this well ranges from
2.59md to 52.40md which is fair permeability value for the reservoirs. Unfortunately the Sxo
values calculated for all the zones are greater than 1.0, making the ROS calculations of no
value.The average MHI values are less than 0.7 and this suggest good fluid moveability.
Table 4: Petrophysical Summary Table for well B W
ell
/Res
ervo
ir
nam
e D
epth
inte
rval
(m)
GR
-
com
p(A
PI)
Rt(
ohm
-m)
Vsh
(v/v
)
�T(v
/v)
�e(v
/v)
Arc
hie’
s Sw
Wax
-sm
it
Sw
Tot
al
Tk(
(m)(
m)
Flui
d
B1 2867-2875 64 2.00 0.14 0.22 0.21 0.89 0.34 8 H-C
B2 2880-2889
1.73 0.12 0.23 0.25 0.89 0.39
9 H-C
B3 2923-2935 57 2.02 0.12 0.22 0.20 0.95 0.35 12 H-C
B4 2947-2953 70 2.67 0.14 0.18 0.12 0.79 0.31 6 H-C
B5 2998-3008 60 2.25 0.13 0.22 0.21 0.84 0.35 10 H-C
B6 3020-3041 60 2.05 0.12 0.24 0.23 0.82 0.33 21 H-C
B7 3430-3452 70 2.77 0.13 0.22 0.20 0.76 0.33 22 H-C
B8 3534-3548 64 2.74 0.12 0.21 0.18 0.86 0.32 14 H-C
B9 3596-3607 54 2.53 0.10 0.22 0.19 0.89 0.33 11 H-C
B10 3609-3639 55 2.58 0.10 0.20 0.19 0.86 0.32 30 H-C
W
EL
L B
B11 3930-3946 66 5.04 0.14 0.17 0.15 0.70 0.26 16 H-C
Fig 13: Composite log of well B
Fig 14: Composite Log of well B showing the Low Resistivity pay zones
4.3: Evaluation and interpretation for Well C Low Resistivity Pay Reservoirs:
The total depth drilled for well C is 3166m. The Low Resistivity pay reservoirs evaluated
in this well were five, labeled CI, C2, C3, C4, and C5. The composite log of well C is shown
in fig.15. The average True resistivity log values ranges from 1.81ohm meter in C5 to
8.2ohm meter in C3. The Low Resistivity values this confirm the fact that they are Low
Resistivity zones. It has good reservoir development. The average reservoir thickness ranges
from 9m for reservoir C4 to 50m in reservoir C3. The Volume of shale values are within the
limit that can affect the reservoir characteristics (0.10%-0.15%) except for well C5.. For the
volume of shale, these criteria were the bases for calculation: GRclean =22 API units,
GRshale=180 API units. The Archie’s equation was applied with Rw= 0.2ohm-m (derived by
picket plot), Cementation factor (m) of 1.6 (derived from average value of core interpretation
result) and saturation exponent n of 1.9.
The reservoirs have well to excellent porosity values (�D= 0.22% for C2 and C3 to 0.28 for
C4 and C5) that can accommodate good hydrocarbon saturation. The water saturation
computed by the Archie’s equation gives high that ranges from 0.52%-0.99% values as a
result of shale in the reservoir. The petrophysicl summary Table is shown in table 5. These
high water saturation values are as a result of shale in the reservoir. By using the Waxman-
Smits shaly sand equation to correct for the effect of shale, water saturation is reduced to the
range of 0.40% in C3 to 0.47% in C4.
4.3.1: Producibility of well C: The average porosities and permeability of the entire
reservoir suggest reservoir. Most value of Moveable hydrocarbon indices are higher than 0.7
except for reservoir C2 which shows good flow moveability. This was further confirmed by
the good values of the permeability of C2 reservoir(Appendix). The BWV values for the
reservoir are constant and will not produce water.
Table 5: Petrophysical Summary Table for well C
Wel
l
/Res
ervo
ir
Dep
th
inte
rval
GR
-com
p
Rt(
ohm
-
m)
Vsh
(v/v
)
�T(v
/v)
�e(v
/v)
Arc
hie’
s
Sw
Wax
-sm
it
Sw
Tot
al
Tk(
(m)(
m)
Flui
d
C1 2265-
2280
70 3.5 0.11 0.26 0.24 0.74 0.34 15 H-C
C2 2290-
2310
80 2.5 0.14 0.22 0.20 0.52 0.43 20 H-C
C3 2475-
2530
81 8.2 0.15 0.22 0.20 0.93 0.40 50 H-C
C4 2531-
2540
83 1.62 0.14 0.27 0.23 0.99 0.47 9 H-C
W
ell -
06
C5 2550-
2560
71 1.81 0.10 0.28 0.26 0.90 0.44 10 H-C
Fig 15: : Composite Log of well C showing the Low Resistivity pay zones
Fig 16: Composite Log of well C
Well A
Well B
LRP
LRP
LRP
LRP
LRP
LRP
Well C
Fig.17: Reservoir correlation panel of the “Amo-field”
2400
2450
2500
2550
2600
2650
2700
2750
2800
2850
2900
2950
3000
3050
3100
3150
3200
3250
3300
3350
3400
3450
3500
3550
3600
3650
3700
3750
3800
3850
3900
3950
4000
4050
4100
4150
4200
4250
4300
0 100 200
2400
2450
2500
2550
2600
2650
2700
2750
2800
2850
2900
2950
3000
3050
3100
3150
3200
3250
3300
3350
3400
3450
3500
3550
3600
3650
3700
3750
3800
3850
3900
3950
4000
4050
4100
4150
4200
4250
4300
1 10 100 1000
2800
2850
2900
2950
3000
3050
3100
3150
3200
3250
3300
3350
3400
3450
3500
3550
3600
3650
3700
3750
3800
3850
3900
3950
4000
0 100 200 300
2800
2850
2900
2950
3000
3050
3100
3150
3200
3250
3300
3350
3400
3450
3500
3550
3600
3650
3700
3750
3800
3850
3900
3950
4000
1 10 100 1000
2200
2250
2300
2350
2400
2450
2500
2550
2600
2650
2700
2750
2800
2850
2900
2950
3000
0 100 200 3002200
2250
2300
2350
2400
2450
2500
2550
2600
2650
2700
2750
2800
2850
2900
2950
3000
1 10 100 1000
Well A
Well B
Well C
Fig 18: Schematic Presentation of a GR log and Resistivity log plotted for the Low resistivity Pay zones of each of the three wells
CHAPTER FIVE
CLAY DISTRIBUTIONS OF “AMO-FIELD” LOW RESISTIVITY RESERVOIRS
Thomas and Steiber (1975) demonstrated that Total porosity versus Vsh plots can be used
to interpret the type of shale-distribution in the formation and its effect on porosity. The porosity
behavior of any shaly sand depends on the amount of shale added and the nature of shale
distribution in the sand.
The equations describing Total porosity as a function of Vsh for purely laminated,
dispersed and structural distribution of shale are as follows:
Laminated: �T= �sVsh*(�s-�sh)
dispersed (Pore filling): �T=�s-Vsh*(1- �sh) ……for Vsh<= �s
dispersed (grain replacing) �T=Vsh* �sh …………… for Vsh> �s
Strcutural (grain replacing) �T= �s+ Vsh* �sh …..for Vsh < 1- �s
Strctural (Pore filling) �T= 1-Vsh*(1- �sh)……for Vsh>1- �s
Where,
�T= Total Porosity
�s= Clean sand porosity
�sh= Shale porosity
Vsh= Volume of shale
5.1: CLAY DISTRIBUTION FOR WELL A:
Fig 19 is a plot of volume of shale versus total porosity for reservoirs A2 and A3. For
reservoir A2 and A3, are such a plot for a realistic case sand porosity (�s) of 0.32% bulk volume
and shale porosity (�sh) of 0.13%. The volume of shale is 0.25%. For reservoir A3, the sand
porosity (�s) is 0.32% bulk volume and shale porosity (�sh) is 0.08% bulk volume but the
volume of shale is 0.12%. Adding this shale to the sand the porosity behavior depends on the
amount of shale added. The plots reveals that the clay distribution is a mixed-type clay
distribution as they plot within the lines that defined laminated, dispersed and structural clay
distributions. Using the above equations, the total porosities for the laminated, dispersed and
structural clay distribution reduced to 0.27%, 0.10% and 0.35% respectively while in reservoir
A3, respective total porosities for laminated(Pore filling) , dispersed(Pore filling) and structural
clay(grain replacing) distributions are 0.04%, 0.14% and 0.31%.
Fig 19: Thomas-Steiber’s Triangle for Reservoir A2 and A3 of well-A
5.2: Clay Distribution For well B: The plot of Vsh versus Total porosity revealed that the clay
distribution for reservoir B2 and B2 in well B are dispersed clay distributions(Fig 20) as the data
plotted mainly along the line that defined the dispersed clay distribution. The clean sand porosity
for reservoir B2 is 0.29% and porosity of shale is 0.08% and the volume of shale is 0.12%. The
clean sand porosity for reservoir B10 is 0.24% and porosity of shale is 0.05% while the volume
of shale is 0.14. Using the equation for dispersed (Pore filling) clay, �T=�s-Vsh*(1- �sh) for
Vsh<= �s . For Reservoir B2, the dispersed (Pore filling) clay distribution total porosity is
0.1
0.2
0.3
0.4
0.1 0.2 0.3 0.4
Vsh
Tota
l Por
�s=0.32%
�sh=0.13%
Res. A3
Res. A2
0
0.05
0.1
0.15
0.2
0.25
0.3
0.35
0 0.1 0.2 0.3 0.4 0.5
VSH
Tot
al P
or
0.08%
0.32%
Dispersed clay
Structural clay
Laminated clay
Laminated clay
Dispersed clay
Structural clay
0.18%. For reservoir B10, the respective total porosity for dispersed(pore filling) clay
distributions is 0.11% .
0
0.1
0.2
0.3
0.4
0 0.1 0.2 0.3 0.4
Vsh
Tt P
or
� s=0.29%
� sh=0.08%
Laminated
Structural
Dispersed
Structural
Dispersed
Laminated
�s=0.24%
�sh=0.05%
Res. B2
Res. B10
Fig. 20: Thomas-Steiber’s Triangle for Reservoir B2 and B10 in well B
5.3: Clay distribution in well C: Fig 21 is the volume of shale versus Total porosity(Thomas –
Steiber’s Triangle) plot for reservoir C1 and C5 of well C. The clean sand porosity for reservoir
C1 is 0.30%, the porosity of shale is 0.18% and the volume of shale of the shaly sand is 0.11%.
The clean sand porosity for reservoir C5 is 0.30% and porosity of shale is 0. 20% with volume of
shale of 0.10%. The clay distributions for reservoir C1 is mixed-type clay distribution as they
plotted within the lines that defined laminated, dispersed and structural clay distributions, while
data from the reservoir C5 plot between the lines that defines dispersed and Structural clay
distributions. The Total porosities from the above equations for laminated, dispersed and
structural clay distribution for reservoir C1 are 0.29%, 0.28% and 0.32% respectively, while
Total porosities for reservoir C5 are 0.29%, 0.22% and 0.32% respectively(see fig. 20).
0.1
0.15
0.2
0.25
0.3
0.35
0 0.05 0.1 0.15 0.2 0.25
Vsh
Tota
l Por
� sh=0.18%
� s=0.30%
Res. C1
Res. C5
0.15
0.2
0.25
0.3
0.35
0.04 0.06 0.08 0.1 0.12 0.14 0.16
Vsh
To
tal P
or
�sh=0.20%
� s=0.30%
Dispersed
Structural
Laminated
Structural
LaminatedDispersed
Fig.21:Thomas-Steiber’s Triangle for Reservoir C1 and C5 in well C
CONCLUSION AND RECOMMENDATION
The primary cause of Low Resistivity pay zones is clay because of its inherent
conductivity within sands and has led to several problems during formation evaluation. All log
responses and interpretation tools are influenced by the clay. A total of twenty one Low
Resistivity pay zones were delineated using data from a complete composite log suite in the
Three wells- Well A, Well B, and Well C studied in this work.
For well A, five low Resistivity reservoir zones were delineated with their porosities
ranging from 0.21%-0.28%. The results from the Archies’ equation indicate water saturation
ranging from 0.47% to 0.73%, while the results from modified Waxman-Smits shaly sand
equation gave lower value of 0.03% and 0.58%. The average Resistivity values ranges from
3.16ohmm-6.98ohmm. The volume of shale is within the limit that can affect the reservoir
quality (0.10%-0.28%).The BWV computation suggest that the reservoirs are productive while
the MHI suggest that the hydrocarbon in the reservoir cannot move.
Eleven of the reservoir intervals recorded Low resistivity value in Well B with average
Total porosity ranging from 0.12% to 0.25%. The water saturation values ranges from 0.76%-
0.95% and 0.26%-0.39% for the Archie’s and modified Waxman-Smits model respectively.The
average resistivity values ranges from 1.73ohmm to 5.04ohmm while average volume of shale
values of 0.10%-0.14% were recorded. The BWV and MHI computation suggests that the
reservoirs are productive.
The total porosity values for Well C ranges from 0.22%- 0.28% while the water saturation
ranges from 0.34%-0.47%(Modified Waxman-Smits equation). Water saturation calculated
using the Archies equation gave higher values(0.54%-0.99%) than the those generated using the
modified Waxman-Smits equation. The average porosities, Moveable hydrocarbon Index and
permabilities values of reservoirs in well C suggest that the reservoirs are productive.
The clay distribution studies carried out using the Thomas-Steiber’s model, revealed that the
clay in “Amo-field” are distributed in the form of disperesed, laminated and structural clay
distribution. It was observed that the total porosity for dispersed clay in the reservoirs reduced
drasticaly more than that of structural and laminated clay.
In addition to the use of standard shaly sand log analyses (e.g using the Waxman-Smits,
Dual-water model), it is recommended that the logging tools with high vertical resolution and
very deep penetration should be used during data acquisition. This is in view of the fact that most
of our reservoir intervals, especially within parallic deposits petrolifereous Niger Delta basin are
characterized with intervals with thin-bedded, shaly reservoir sands(Low Resisitivity Pay zones).
When such newer technologies are used together with integrated petrophysical evaluation, the
bye-passed productive intervals are better delineated.
REFERENCES
Archie, G.E., 1942. The Electrical Resistivity Log as an Aid in Determining some Formation Characteristics. Transactions of the American Institute of Mining and Metallurgical Engineers, v. 146, pp. 54-62.
Asquith, G. 1982. Basic well log analysis: American Association of Petroleum Geologists, Methods in exploration series, no.16.244pp.
Asquith, G. and Krygowski, D., 2004. Basic Well Log Analysis. American Assiociation of Petroleum Geologists, Methods in Exploration Series v. 16, 204p.
Bos M.R.E (1982): Prolific Dry Oil Production from sands with water saturations in Excess of 50%: A Study of Dual Porosity System. The Log Analyst, Recipient of 1981-1982nSPWLA Best Paper Award.
Boyd, A., Darling, H., Tabanou, J., Davis B., Lyon, B., 1995. The Lowdown on Low Resistivity Pay. Oilfield Review, Autumn, pp.4-18.
Burke, K., 1972. Longshore Drift, Submarine Canyons and Submarine Fans in Development of Niger Delta. AAPG Bulletin v.56, pp. 1975-1983.
Burke, K., T.F.J. Dessauvagie, and A.J. Whiteman, 1972. Geological History of the Benue Valley and adjacent areas. In: 1st
Bustin, R.M., 1988. Sedimentology and Characteristics of Dispersed Organic Matter in Tertiary Niger Delta: Origin of Source Rocks in a Deltaic Environment. AAPG Bulletin v. 72, pp. 277-298.
Buckles, R.S., 1965, Correlating and averaging connate water saturation data, Journal of Canadian Petroleum Technology, v.9,no.1, p.42-52 In Asquith, G. and Krygowski, D., 2004. Basic Well Log Analysis. AAPG Methods in Exploration Series v. 16, 204p.
Clavier, C., Coastes, G. and Meunier, D., 1977. Theoretical and Experimental bases for the Dual-Water Model for Interpretation of Shaly Sands; Society of Petroleum Engineers Annual Meeting, SPE, Paper 6859.Conference on African Geology, Ibadan, 1970, Proceedings: Ibadan, Nigeria, Ibadan University Press, pp 287-305
Devarrajan,S. Tournelin.E. and C. Torres –Verdin 2006: Pore- scale Analysis of the Waxman-smits shaly sand conductivity model. SPWLA 47TH Annual Logging Symposium, June 4-7, 2006.
Dewan, J.T.(1983): Essentials of modern open Hole Log interpretation. Penn Well,Tulsa.361p In DeWhite, L., 1950, Relation Between Resistivities and Fluids Contents of Porous Rocks: Oil and Gas Journal ( August, 24 ), p. 120-132. In Hamada, G.M (2006): An
integrated Approach to Determine Shale Volume and Hydrocarbon Potential in Shaly Sand. Petroleum Engineering Dept., Faculty of Engineering, Cairo University, Giza, Egypt
Doust, H., 1989. The Niger Delta: Hydrocarbon Potential of a Major Tertiary Delta Province Coastal Lowlands, Geology and Geotechnology. Proceedings of the KNGMG Symposium “Coastal Lowland Geology and Geotechnology”. Dordrecht,Kluwe, pp. 203-212.
Doust, H., and E. M. Omatsola, 1990. Niger Delta. In: Divergent/Passive Margins Basins. Edwards, and P.A. Santagrossi (eds), AAPG memoir v. 48, pp. 239-248.
Dresser Atlass, 1982, Well Logging and Interpretation Techniques, Dresser Ind. Inc. Edwards, and P.A. Santagrossi (eds), AAPG memoir v. 48, pp. 239-248.
Ejedawe, J. E., 1981 Patterns of incidence of oil reserve in Niger Delta basin- Amer. Assoc. Petr.Geol. Bull.65: 1574-1585.
Ekweozor, C.M., and E.M. Daukoru, 1984. Petroleum Source Bed Evaluation of Tertiary Niger Delta- reply. AAPG Bulletin v. 68, pp. 390-394.
Ekweozor, C.M., and E.M. Daukoru, 1992. The Northern Delta Depobelt Portion of the Akata-Agbada (!) Petroleum System, Niger Delta, Nigeria. NAPE Bulletin v. 7(2) pp.2-120.
Ekweozor, C.M., and N.V. Okoye, 1980. Petroleum Source-bed Evaluation of Tertiary Niger Delta. AAPG Bulletin v. 64 pp. 1251-1259.
Evamy, B.D., J. Haremboure, P. Kamerling, W.A. Knaap, F.A. Molloy, and P.H. Rowlands, 1978. Hydrocarbon Habitat of the Tertiary Niger Delta. AAPG Bulletin, v. 62, pp.1-39.
Fertl, W. H., and Frost, E., Jr., 1980. Evaluation of shaly clastic reservoirs rocks. Journal of Petroleum Technology. V. 32 no.9, p.1641-1645.
Fertl, W.H. and Hammack, C.W., 1971, A Comparative Look at Water Saturation in Shaly Pay Gamze Ipek 2002: Log-derived cation exchange capacity of shaly sands: application to hydrocarbon detection and drilling optimization geology of the Niger delta Clay Minerals (1982) 17, 91-103. Geoscience, V. 6, pp. 77-92.
Haack, R.C., Sundaraman, P. and Dahl, J., 1997. Niger Delta Petroleum System. In: Extended Abstracts, AAPG/ABGP Headberg Research Symposium, Petroleum Systems of the South Atlantic Margin, Rio de Janerio, Brazil, pp123-134.
Hamada, G.M 2006: An integrated Approach to Determine Shale Volume and Hydrocarbon Potential in Shaly Sand. 1996 SCA conference paper No.9647.
Hilchie, D.W., 1978. Applied Openhole Log Interpretation. Golden, Colorado, D.W. Hilchie, Inc., 161p.
Hook, J.R., 2003, An introduction to Petrophysics, v. 44, no.3, p.205-212. In Suzanne G. Cluff and Robert M. Cluff(2004) AAPG Studies in Geology 52 and Rocky Mountain Association of Geologists 2004 Guidebook.
Hospers, J.(1965). Gravity field and Structure of the Niger Delta, Nigeria, West Africa. Bull.. Geol. Soc. Amer. 76, 407- 422.
Hospers, J.(1971). The Geology of the Niger Delta area. SCOR conference Cambridge 1970. In Continental Margin (F. M. Delany, Ed.) Geol. E. Atlantic HMSO, pp. 123-142.
Howells, H.M. and Wilkinson. J.R. 1977. Petrophysical Evaluation of the Farewell Structure and reservoirs. Mackenzie Delta Paper 1). Presented at the Sixth Formation Evaluation Symposium, CWES, Calgary, Octiber 24-26 1977. In Ruhovets. N and Walter H. Fertl 1981. Digital shaly analysis based on Waxman-Smits Model and log- Derived clay typing. The log Analyst may to June 1982.
John O. Etu-EFEOTOR, 1997. Fundamentals of Petroleum Geology.Paragraphic, 146p.
Johnson, W. Effects of Shaliness on Log Response. CWLS Journal, 10 No. 1, 29-57, 1979. In Ruhovets. N and Walter H. Fertl 1981. Digital shaly analysis based on Waxman-Smits Model and log- Derived clay typing. The log Analyst may to June 1982.
Juhaz, I.,(1979). ”The central Role of Qv and Formation-Water Salinity in the evaluation
Juhaz, I., 1981. Normalised Qv – key to Shaly Sand Evaluation Using the Waxman-Smith equation in the absence of Core data, SPWLA Twenty second Annual logging Symposium, June 23-26, pp. 1-36.
Kern. J.W., Hoyer. W.A and Spant, M.M. Low Porosity Gas Sand analysis Using Cation Exchange and Dielectric Constant Data. Trans. SPWLA, June 1976.
Knox, G.J., and E.M. Omatsola, 1989. Development of the Cenozoic Niger Delta in terms of the “Escalator Regression” Model and Impact on Hydrocarbon Distribution: Proceedings KNGMG Symposium “Coastal Lowlands,Geology and Geotechnology,” 1987: Dordrecht, Kluwer, pp. 181-202
Kulke, H., 1995. Nigeria, in Kulke, H., ed, Regional Petroleum Geology of the World Part II: Africa, America, Australia and Antarctica: Berlin Gebruder Borntaeger, pp.143-172
Kulke, H., 1995. Nigeria. In: Regional Petroleum Geology of the World Part II: Africa, America, Australia and Antarctica. Kulke, H., (ed.) Berlin Gebruder Borntaeger pp.143-172.
Lambert-Aikhionbare D.O and Shaw H. F, 1982: significance of clays in the petroleum of the Niger Delta Clay Minerals (1982) 17, 91-103.
Larionov, V.V., 1969. Borehole Radiometry: Moscow, U.S.S.R., Nedra.112P in Asquith, G. and Krygowski, D., 2004. Basic Well Log Analysis. AAPG Methods in Exploration Series v. 16, 204p.
Lawrence, S.R., Monday, S. and Bray, R. 2002. Reginal Geology and Geophysics of the Eastern Gulf of Guinea(Niger Delta to Riomuni): The leading Edge, vol.21, p.1112-1117.
Log Interpretation charts: Copyright 1985. Atlas wireline Service. Western Atlas int. Inc.
Merki, P., 1970. Structural Geology of the Cenozoic Niger Delta.: In Africa Geology (T. F. J. Dessauvagie and A. J. Whiteman Eds). 1972. Ibadan University press, pp.635-646.
Morris. R.L., and W.P Biggs, 1967, Using Log-derived values of water saturation and Porosity: Society of Professional well log Analysts, 8th Annual Logging symposium, Transactions,Paper O In Asquith, G. and Krygowski, D., 2004. Basic Well Log Analysis. AAPG Methods in Exploration Series v. 16, 204p.
Murat, R. c., 1972. Stratigraphy and paleogeography of the cretaceous and lower Tertiary in soutern Nigeria In Africa Geology (T. F. J. Dessauvagie and A. J. Whiteman Eds). 1972. Ibadan University press, pp.635-646.
Neasham J. W., 1977, The Morphologic of dispersed clay in sandstone reservoirs and its effect on sandstone shaliness, pore space and fluid flow properties : SPE 6858, 52nd AIME Fall Symposium, Denver, Colorado,October. In Waxman,M.H. and Smits, L.J.M., 1968, Electrical Conductivity in Oil Bearing Shaly Sands:Society of Petroleum Engineers Journal, June, p. 107-122.
Nwachukwu J.I. and P.I. Chukwurah, 1986. Organic Matter of Agbada Formation, Niger Delta, Nigeria. AAPG Bulletin v.70, pp. 48-55.
Obi ,G.C., 2000. Depositional Model for the Campanian-Maastrichtan Anambra Basin, Southern Nigeria. Ph.D. Thesis, University of Nigeria, Nsukka. 291P.
Patnode, J. G and Wyllie, M. R. J 1950. The presence of conductive solids in reservoir rock as a factor in electric log interpretation. Trans AIME 189, 47-52 In Worthington, P.F., 1985. The Evolution of Shaly-sand Concepts in Reservoir Evaluation. The Log Analyst, V.26 (1), pp.23-40.
Rider, M.H., 1996. The Geological Interpretation of Well Logs. Whittles Publishing, 2nd edition, Aberdeen, 278p.
Ruhovets. N and Walter H. Fertl 1981. Digital shaly analysis based on Waxman-Smits Model and log- Derived clay typing. The log Analyst may to June 1982.
Saha, S., 2003. Low Resistivity Pay (LRP): Ideas for Solution. SPE 85675. pp. 25-27
Schlumberger, 1998. Petrophysics, 31P
Schlumberger, 1975. A Guide to Wellsite Interpretation for the Gulf Coast; Schlumberger Offshore Services, 58P.Schlumberger, 1998. Petrophysics, 31P. Shaly Formation,” Revue del’Institut Francais du Petrole, Supplementary
Short, K.C., and Stauble, A.I., 1967. Outline of Geology of Niger Delta: AAPG Bulletin, V.51, pp. 761-779
Simandoux, P., 1963. “Dielectric Measurements in Porous Media and Application to Society of Petroleum Engineers Journal, June, p. 107-122.
Stacher, P. 1995. Present Understanding of the Niger Delta Habitat. In Oti M.N. and Postma G. (eds). Geology of Deltas. A. A. Balkema Publishers, Rotterdam:1 st edition, pp. 257 – 267.
Stoneley, R., 1966. The Niger Delta in the light of the theory of Continental Drift. Geological Magazine v. 105, pp. 385-397.
Taowu and Robert R. Berg (2003): Relationship of Reservoir properties for Shaly sandstones based on Effectve porositu. Petrophysics. Vol.44 No. 5(Sept-Octo.) P. 328 v.32, no.4, , pp.356-368.
Thomas, E.C and S.J. Steiber, (1975): Distribution of Shale in sandstone and its effect upon Porosity; New Orleans, paper to Soceity of professional Log analysts, 16th Annual logging Symposiun, June 4-7.
Tuttle, M.L.W., Brownfield, M.E. and Charpentier, R.R., 1999. Tertiary Niger Delta Province,Cameroon and Equatorial Guinea, Africa U.S. Geological Survey Open File Report 99-50H, pp.1-13.
Vikas. S and Sri, N 2007: Journ.Ind. Goephysics Union (July, 2007). Vol.11; no. 3, pp. 135-142.
Waxman, M. H., and Thomas, E. C., 1974. Electrical Conductivity in Shaly Sand –I; Journal of Petroleum Technology, V. 257, pp. 213 - 225
Waxman,M.H. and Smits, L.J.M., 1968, Electrical Conductivity in Oil Bearing Shaly Sands concept in Reservoir Evaluation: The Log Analyst, v.26, no.1, p.23-40.
Weber, K.J., 1971. Sedimentological Aspects of Oil Fields in the Niger Detla, Geologic en Mijinbouw, V. 50, pp. 559-576.
Weber, K.J., 1986. Hydrocarbon Distribution Patterns in Nigerian Growth Fault Structures Controlled by Structural Style and Stratigraphy: AAPG Bulletin, V. 70, pp. 661-662.
Weber, K.J., and Daukoru, E. 1975. Petroleum Geology of the Niger Delta: 9th World Petroleum Congress Proceedings 2, pp. 209-221.
Whiteman A.J., 1982. Nigeria, Its Petroleum Geology Resources and Potential. V. I and II, Edinburgh, Graham and Tortman.
Winsauer, W.O and McCardell, W. M 1953. Ionic double-layer conductivity in reservoir rock. Trans. AIME 198, 129-134. In Worthington, P.F., 1985. The Evolution of Shaly-sand Concepts in Reservoir Evaluation. The Log Analyst, V.26 (1), pp.23-40.
Worthington, P.F., 1985. The Evolution of Shaly-sand Concepts in Reservoir Evaluation. The Log Analyst, V.26 (1), pp.23-40. Worthington, P.F., 2000. Recognition and Evaluation of Low Resistivity Pay. Petroleum Geoscience, V. 6, pp. 77-92.
Wyllie, M.R.J. and W.D. Rose, 1950. Some Theoretical Considerations Related to the Qualitative Evaluations of the Physical Characteristics of Rock from Electric Log Data. Journal of Petroleum Technology v. 189, pp. 105-110.
Yu, L., O.N. Fanini, B. F. Kreigshauser, J. M. V. Koelman, and J. Van Popta 2001. Enhanced Evaluation of Low-resistivity Reservoirs Using Multi-component Induction Log Data: Petrophysics, v.42, no. 6, p. 611-623.
(www.petrolog.net/petrophysical_analysis)
APPENDIX I
Validation of logs derived results with core interpretation results data
Table 6, Well A : The core interpretations between 3692 and 4114m depth.
Measured data Calculated data
Depth �T(V/V) decimal K(md) K(md) �T(v/v) decimal
3692-3700 0.22 1119 77.6 0.19
3717-3721 0.26 909 243.0 0.25
3773-3795 0.22 1370 188 0.22
4088-4114 0.20 1120 67.5 0.20
Table 7, Well B: The core interpretations between 3162 and 4046m depth.
Measured data Calculated data
Depth �T K(md) Sw K(md) Archies’
Sw
Waxman-
Smits Sw
�T
3161-
3199
0.24 2233 0.43 59 0.55 0.28 0.22
3201-
3202
0.29 2275 0.31 83 0.88 0.30 0.21
3820-
3905
0.16 315 0.26 19 0.40 0.21 0.18
4005-
4044
0.18 1094 0.29 14 0.40 0.21 0.17
Table 8, Well C: The core interpretations between2956and 3026m depth.
Measured data Calculated data
Depth �T(V/V) decimal K(md) K(md) �T(v/v) decimal
2956-2966 0.25 143.1 216.5 0.27
2967-3000 0.22 76.9 9040 0.39
3001-3026 0.26 820.9 463 0.26
Well A
0.1
1
10
0.1 1
Por
Rt
WELL B:
APPENDIX1 11
PICKET PLOTS FOR THE WELLS
0.1
1
10
0.1 1
Por
Rt
WELL C:
0.01
0.1
1
10
0.1 1
Por
Rt
APPENDIX III
WELL LOG RESULTS FOR THE RESERVOIRS EVALUATED
WELL A:
Reservoir A1
Dept. GR RT NPHI RHOB IGR Vsh CD� �T Qvn
Swa
Eff.
Por WXSw Sxo ROS MHI MOS Perm. BWV
2469 98 3.9 0.34 2.31 0.58 0.29 0.14 0.19 0.18 0.77 0.13 0.20 0.95 0.05 0.81 0.18 239 0.14
2469 98 3.5 0.38 2.32 0.58 0.29 0.14 0.19 0.19 0.85 0.13 0.25 0.98 0.02 0.87 0.13 238 0.16
2470 96 3.0 0.37 2.31 0.57 0.28 0.15 0.19 0.17 0.94 0.14 0.33 1.02 -0.02 0.92 0.08 352 0.18
2471 100 2.8 0.33 2.33 0.60 0.30 0.13 0.18 0.20 1.02 0.13 0.37 1.10 -0.10 0.93 0.08 315 0.18
2472 69 5.4 0.32 2.27 0.35 0.12 0.20 0.21 0.07 0.55 0.19 0.10 0.74 0.26 0.73 0.20 295 0.12
2473 75 10.0 0.31 2.02 0.40 0.15 0.35 0.36 0.05 0.25 0.30 0.03 0.26 0.74 0.96 0.01 137 0.09
2474 71 5.7 0.75 1.80 0.37 0.13 0.49 0.48 0.03 0.34 0.42 0.07 0.25 0.75 1.32 -0.08 195 0.16
2475 26 16.5 0.29 2.13 0.01 0.00 0.32 0.30 0.00 0.18 0.30 0.01 0.39 0.61 0.46 0.21 261 0.05
2476 33 8.0 0.29 2.15 0.07 0.02 0.30 0.28 0.01 0.33 0.28 0.04 0.45 0.55 0.74 0.12 332 0.09
2477 34 7.7 0.28 2.14 0.07 0.02 0.30 0.29 0.01 0.34 0.28 0.05 0.35 0.65 0.97 0.01 359 0.10
2478 37 7.5 0.32 2.12 0.10 0.02 0.32 0.30 0.01 0.34 0.30 0.05 0.37 0.63 0.94 0.02 375 0.10
2479 35 8.2 0.25 2.16 0.08 0.02 0.30 0.28 0.01 0.33 0.27 0.04 0.38 0.62 0.87 0.05 342 0.09
2480 56 8.5 0.32 2.10 0.25 0.08 0.32 0.31 0.03 0.30 0.29 0.04 0.34 0.66 0.88 0.04 332 0.09
2481 74 6.9 0.31 2.14 0.39 0.14 0.28 0.29 0.06 0.37 0.25 0.06 0.39 0.61 0.96 0.01 314 0.11
2482 78 7.2 0.33 2.09 0.42 0.16 0.30 0.32 0.06 0.35 0.26 0.05 0.34 0.66 1.03 -0.01 259 0.11
Reservoir A2
2738 101 4.7 0.33 2.09 0.61 0.31 0.28 0.32 0.12 0.5 0.22 0.4 0.6 1.24 -0.1 152 0.16
2738 80 4.4 0.33 2.08 0.44 0.17 0.31 0.32 0.06 0.52 0.27 0.42 0.58 1.24 -0.1 186 0.17
2739 99 4.2 0.35 2.1 0.59 0.3 0.27 0.31 0.12 0.55 0.22 0.46 0.54 1.2 -0.1 233 0.17
2740 86 4.3 0.29 2.33 0.49 0.21 0.15 0.18 0.14 0.72 0.14 0.81 0.19 0.88 0.1 18 0.13
2741 85 4.2 0.31 2.29 0.48 0.2 0.17 0.2 0.12 0.7 0.16 0.73 0.27 0.95 0.03 16 0.14
2742 97 5.1 0.31 2.29 0.58 0.28 0.16 0.2 0.17 0.59 0.15 0.7 0.3 0.84 0.11 12 0.12
2742 101 4.8 0.32 2.32 0.61 0.31 0.13 0.18 0.2 0.64 0.13 0.8 0.2 0.81 0.15 44 0.12
Reservoir A3
3007 52 30.0 0.20 2.25 0.21 0.06 0.16 0.22 0.21 0.04 0.21 0.00 0.20 0.80 0.18 0.16 42 0.01
3008 111 7.4 0.25 2.51 0.69 0.40 0.00 0.08 4.03 0.21 0.05 0.08 0.90 0.10 0.23 0.69 0 0.02
3009 39 11.1 0.23 2.19 0.12 0.03 0.19 0.26 0.08 0.08 0.26 0.02 0.22 0.78 0.35 0.15 0 0.02
3010 71 13.9 0.21 2.52 0.37 0.13 0.03 0.07 1.43 0.13 0.06 0.03 0.62 0.38 0.21 0.50 0 0.01
3011 43 19.8 0.26 2.15 0.14 0.04 0.29 0.28 0.10 0.05 0.27 0.01 0.18 0.82 0.26 0.13 1 0.01
3012 43 27.7 0.20 2.21 0.15 0.04 0.26 0.25 0.12 0.04 0.24 0.00 0.18 0.82 0.20 0.15 4 0.01
3013 106 8.3 0.31 2.58 0.65 0.35 -0.03 0.04 7.14 0.27 0.02 0.07 1.82 -0.82 0.15 1.55 14 0.01
3014 71 7.9 0.19 2.50 0.37 0.13 0.07 0.08 1.19 0.19 0.07 0.07 0.96 0.04 0.20 0.78 40 0.02
3015 40 6.1 0.25 2.20 0.12 0.03 0.27 0.26 0.09 0.13 0.25 0.08 0.41 0.59 0.33 0.27 81 0.03
3016 33 9.1 0.30 2.11 0.07 0.02 0.32 0.31 0.04 0.08 0.30 0.03 0.22 0.78 0.38 0.14 112 0.03
3017 102 8.6 0.26 2.54 0.62 0.32 0.00 0.06 4.11 0.21 0.04 0.07 1.13 -0.13 0.19 0.92 126 0.01
3018 102 7.2 0.27 2.38 0.62 0.32 0.09 0.15 1.65 0.15 0.10 0.07 0.54 0.46 0.28 0.38 134 0.02
3019 68 12.7 0.29 2.10 0.34 0.12 0.31 0.31 0.29 0.06 0.28 0.02 0.17 0.83 0.38 0.10 99 0.02
3020 46 8.4 0.24 2.13 0.17 0.04 0.31 0.29 0.12 0.09 0.28 0.04 0.17 0.83 0.53 0.08 18 0.03
3021 70 29.7 0.27 2.12 0.36 0.13 0.29 0.30 0.33 0.03 0.26 0.00 0.24 0.76 0.13 0.21 1 0.01
3022 93 2.7 0.30 2.15 0.54 0.25 0.25 0.29 0.68 0.25 0.21 0.35 0.46 0.54 0.53 0.22 0 0.07
3023 48 2.0 0.28 2.17 0.18 0.05 0.28 0.27 0.14 0.32 0.26 0.59 0.55 0.45 0.58 0.23 0 0.09
3024 48 2.0 0.26 2.16 0.18 0.05 0.29 0.28 0.14 0.33 0.26 0.63 0.56 0.44 0.59 0.23 0 0.09
3025 64 1.9 0.29 2.15 0.31 0.10 0.28 0.30 0.27 0.33 0.27 0.69 0.60 0.40 0.55 0.27 5 0.10
3026 44 2.1 0.26 2.18 0.15 0.04 0.28 0.28 0.11 0.31 0.27 0.57 0.54 0.46 0.58 0.22 44 0.09
3027 42 1.7 0.28 2.20 0.13 0.03 0.27 0.27 0.10 0.37 0.26 0.84 0.60 0.40 0.62 0.23 145 0.10
3028 43 1.9 0.28 2.16 0.14 0.04 0.29 0.29 0.10 0.33 0.28 0.65 0.55 0.45 0.59 0.22 208 0.10
3029 43 1.8 0.25 2.17 0.15 0.04 0.28 0.29 0.10 0.35 0.28 0.75 0.59 0.41 0.59 0.24 166 0.10
3030 42 1.9 0.25 2.17 0.13 0.03 0.28 0.29 0.09 0.33 0.28 0.65 0.57 0.43 0.57 0.25 118 0.09
3031 53 1.7 0.31 2.15 0.22 0.06 0.29 0.30 0.16 0.36 0.28 0.82 0.57 0.43 0.62 0.22 106 0.11
3032 65 2.3 0.29 2.14 0.32 0.11 0.29 0.31 0.27 0.27 0.27 0.46 0.50 0.50 0.54 0.23 104 0.08
3033 75 2.4 0.28 2.14 0.40 0.15 0.28 0.31 0.37 0.26 0.26 0.42 0.48 0.52 0.55 0.21 94 0.08
3034 104 4.0 0.29 2.31 0.63 0.34 0.14 0.21 1.27 0.21 0.14 0.18 0.52 0.48 0.40 0.31 86 0.04
Reservoir A4
3970 100 7.1 0.28 2.45 0.60 0.31 0.05 0.11 0.33 0.62 0.08 0.08 0.71 0.29 0.86 0.10 54 0.07
3971 69 7.5 0.22 2.31 0.36 0.12 0.18 0.19 0.08 0.43 0.17 0.06 0.45 0.55 0.96 0.02 59 0.08
3972 48 3.2 0.24 2.21 0.18 0.05 0.25 0.25 0.02 0.79 0.23 0.27 0.50 0.50 1.60 -0.30 84 0.20
3973 48 3.1 0.25 2.22 0.18 0.05 0.25 0.24 0.02 0.82 0.23 0.29 0.47 0.53 1.72 -0.34 112 0.20
3974 58 3.7 0.27 2.21 0.27 0.08 0.25 0.25 0.04 0.69 0.23 0.20 0.41 0.59 1.67 -0.28 120 0.17
3975 49 3.4 0.23 2.23 0.19 0.05 0.24 0.24 0.03 0.76 0.23 0.24 0.48 0.52 1.60 -0.29 108 0.18
3976 58 3.4 0.22 2.24 0.26 0.08 0.23 0.23 0.04 0.76 0.22 0.24 0.47 0.53 1.61 -0.29 83 0.18
3977 93 4.5 0.23 2.41 0.55 0.26 0.09 0.14 0.22 0.80 0.10 0.17 0.62 0.38 1.30 -0.19 66 0.11
3978 51 3.9 0.24 2.22 0.21 0.06 0.25 0.24 0.03 0.67 0.23 0.18 0.46 0.54 1.46 -0.21 60 0.16
3979 68 3.9 0.25 2.35 0.35 0.12 0.16 0.17 0.09 0.82 0.15 0.21 0.59 0.41 1.37 -0.22 65 0.14
3980 73 3.6 0.27 2.37 0.38 0.14 0.14 0.16 0.10 0.89 0.14 0.25 0.66 0.34 1.35 -0.23 75 0.14
3981 41 4.4 0.22 2.26 0.13 0.03 0.23 0.22 0.02 0.63 0.22 0.15 0.47 0.53 1.35 -0.16 79 0.14
3982 39 3.0 0.22 2.24 0.11 0.03 0.24 0.23 0.01 0.84 0.23 0.30 0.52 0.48 1.62 -0.32 76 0.20
3983 38 2.9 0.22 2.19 0.10 0.02 0.27 0.26 0.01 0.84 0.25 0.32 0.54 0.46 1.54 -0.29 65 0.22
3984 84 3.9 0.19 2.28 0.47 0.20 0.18 0.21 0.11 0.72 0.17 0.19 0.51 0.49 1.40 -0.21 54 0.15
Reservoir A5
4145 69 4.1 0.17 2.38 0.35 0.12 0.14 0.15 0.10 0.81 0.13 0.19 0.61 0.39 1.34 -0.20 4 0.12
4145 79 3.7 0.19 2.32 0.43 0.17 0.16 0.18 0.11 0.81 0.15 0.22 0.56 0.44 1.45 -0.25 6 0.15
4146 75 4.4 0.18 2.38 0.40 0.15 0.13 0.15 0.12 0.78 0.13 0.18 0.63 0.37 1.25 -0.15 5 0.12
4147 47 4.0 0.19 2.22 0.18 0.05 0.25 0.24 0.02 0.66 0.23 0.18 0.48 0.52 1.37 -0.18 4 0.16
4148 29 2.5 0.25 2.22 0.03 0.01 0.26 0.24 0.00 0.29 0.24 0.43 0.59 0.41 0.49 0.30 9 0.07
4148 30 2.2 0.22 2.22 0.04 0.01 0.26 0.24 0.00 0.31 0.24 0.52 0.58 0.42 0.54 0.26 22 0.08
4149 32 2.2 0.22 2.22 0.06 0.01 0.26 0.25 0.01 0.32 0.24 0.55 0.59 0.41 0.54 0.27 49 0.08
4149 36 2.3 0.21 2.22 0.09 0.02 0.25 0.24 0.01 0.31 0.24 0.50 0.57 0.43 0.54 0.27 64 0.07
4149 38 2.4 0.20 2.23 0.11 0.03 0.25 0.24 0.01 0.31 0.23 0.48 0.58 0.42 0.53 0.28 66 0.07
4149 36 2.3 0.19 2.24 0.09 0.02 0.25 0.23 0.01 0.31 0.23 0.49 0.58 0.42 0.53 0.27 71 0.07
4149 34 2.5 0.19 2.24 0.07 0.02 0.25 0.23 0.01 0.30 0.23 0.44 0.57 0.43 0.52 0.27 71 0.07
4149 29 2.6 0.18 2.24 0.03 0.01 0.25 0.23 0.00 0.28 0.23 0.39 0.55 0.45 0.51 0.27 73 0.07
WELL B:
DEPTH GR NPHI RHOB RT IGR Vsh CDP Density Por Swa
Eff. Por Qvn
WX-Sw Sxo ROS MHI Bwv Perm. MOS
Reservoir B1
2868 35 0.22 2.24 1.74 0.12 0.03 0.22 0.23 0.91 0.22 0.01 0.35 1.58 -0.58 0.58 0.08 42.19 0.67
2868 35 0.22 2.23 1.64 0.11 0.03 0.23 0.24 0.91 0.23 0.01 0.36 1.57 0.57 0.58 0.09 52.60 0.66
2869 33 0.25 2.23 1.56 0.11 0.02 0.23 0.24 0.94 0.23 0.01 0.37 1.60 -0.60 0.59 0.09 53.13 0.65
2870 41 0.17 2.30 1.82 0.11 0.04 0.18 0.20 1.03 0.19 0.02 0.35 1.49 -0.49 0.69 0.07 13.06 0.46
2871 91 0.24 2.23 2.04 0.11 0.25 0.15 0.24 0.83 0.18 0.11 0.33 1.38 -0.38 0.60 0.08 4.49 0.55
2872 75 0.26 2.25 1.97 0.11 0.16 0.18 0.23 0.86 0.19 0.08 0.34 1.37 -0.37 0.63 0.08 10.03 0.51
2873 82 0.25 2.20 1.78 0.11 0.20 0.19 0.25 0.83 0.20 0.08 0.35 1.35 -0.35 0.62 0.09 15.24 0.52
2874 72 0.18 2.36 2.91 0.11 0.15 0.12 0.16 0.94 0.14 0.10 0.29 1.83 -0.83 0.51 0.05 0.81 0.89
2875 99 0.26 2.24 2.65 0.11 0.31 0.13 0.23 0.73 0.16 0.14 0.29 1.30 -0.30 0.56 0.07 1.59 0.57
Rservoir B2
2881 90 0.26 2.47 3.03 0.54 0.25 0.02 0.10 1.36 0.08 0.25 0.30 2.28 -1.28 0.60 0.03 0.00 0.72
2881 75 0.26 2.36 3.06 0.42 0.16 0.11 0.16 0.91 0.14 0.10 0.28 1.71 -0.71 0.53 0.05 0.65 0.58
2882 58 0.28 2.15 1.54 0.29 0.09 0.25 0.28 0.82 0.26 0.03 0.37 1.55 -0.55 0.53 0.10 89.18 0.65
2883 59 0.27 2.16 1.39 0.30 0.10 0.25 0.28 0.87 0.25 0.04 0.39 1.46 -0.46 0.60 0.11 84.76 0.62
2884 50 0.23 2.22 1.49 0.23 0.07 0.22 0.24 0.96 0.22 0.03 0.38 1.61 -0.61 0.59 0.09 39.42 0.54
2885 45 0.24 2.22 1.62 0.19 0.05 0.23 0.24 0.90 0.23 0.02 0.36 1.52 -0.52 0.59 0.09 48.49 0.53
2888 64 0.29 2.16 1.63 0.34 0.12 0.24 0.28 0.81 0.24 0.04 0.36 1.43 -0.43 0.62 0.10 19.08 0.19
2889 92 0.25 2.36 3.16 0.55 0.26 0.08 0.16 0.90 0.12 0.17 0.28 1.43 -0.43 0.63 0.11 29.69 0.48
Resevior B3
2925 65 0.20 2.35 2.98 0.35 0.12 0.13 0.17 0.89 0.15 0.07 0.28 1.73 -0.73 0.61 0.04 0.00 0.61
2926 36 0.24 2.20 1.38 0.12 0.03 0.25 0.26 0.95 0.25 0.01 0.39 1.64 -0.64 0.69 0.03 0.02 0.65
2927 32 0.26 2.19 1.38 0.09 0.02 0.26 0.26 0.92 0.26 0.01 0.39 1.50 -0.50 0.59 0.05 1.95 0.69
2928 35 0.23 2.22 1.52 0.12 0.03 0.23 0.24 0.94 0.23 0.01 0.38 1.59 -0.59 0.59 0.10 77.66 0.69
2929 36 0.26 2.19 1.32 0.13 0.03 0.25 0.26 0.95 0.25 0.01 0.40 1.61 -0.61 0.57 0.10 99.44 0.67
2930 32 0.26 2.20 1.32 0.10 0.02 0.25 0.26 0.97 0.25 0.01 0.40 1.63 -0.63 0.58 0.09 56.77 0.69
2932 35 0.20 2.28 1.77 0.12 0.03 0.20 0.21 0.97 0.20 0.01 0.35 1.62 -0.62 0.59 0.10 88.38 0.77
2933 52 0.25 2.25 1.73 0.25 0.07 0.21 0.23 0.93 0.21 0.03 0.36 1.65 -0.65 0.58 0.10 85.49 0.41
2934 49 0.25 2.18 1.51 0.22 0.06 0.25 0.27 0.87 0.25 0.02 0.37 1.72 -0.72 0.60 0.05 0.00 0.54
2935 77 0.28 2.15 1.57 0.44 0.17 0.23 0.28 0.81 0.23 0.06 0.37 1.74 -0.74 0.56 0.07 24.30 0.54
Reservoir B4
2949 60 0.26 2.32 3.90 0.31 0.10 0.15 0.18 0.72 0.17 0.06 0.24 2.10 -1.10 1.18 0.02 0.00 0.38
2950 52 0.30 2.13 2.00 0.24 0.07 0.27 0.29 0.69 0.27 0.03 0.32 1.10 -0.10 0.66 0.05 4.48 0.50
2951 51 0.28 2.15 1.57 0.24 0.07 0.26 0.28 0.81 0.26 0.03 0.36 1.19 -0.19 0.58 0.09 #### 0.23
2952 50 0.27 2.15 1.81 0.23 0.07 0.26 0.28 0.76 0.26 0.02 0.34 1.03 -0.03 0.78 0.10 #### 0.32
2953 71 0.23 2.30 2.67 0.39 0.14 0.15 0.20 0.82 0.17 0.08 0.29 1.07 -0.07 0.71 0.10 #### 0.37
2953 78 0.21 2.33 3.04 0.45 0.18 0.12 0.18 0.84 0.15 0.10 0.28 1.20 -0.20 0.69 0.06 4.57 0.49
2953 86 0.22 2.38 3.53 0.51 0.22 0.08 0.15 0.89 0.12 0.15 0.27 1.33 -0.33 0.63 0.05 1.19 0.66
Reservoir B5
2999 79 0.20 2.38 3.30 0.45 0.18 0.09 0.15 0.93 0.12 0.13 0.27 1.64 -0.64 0.57 0.04 0.21 0.71
2999 52 0.21 2.29 2.85 0.25 0.07 0.18 0.20 0.79 0.19 0.04 0.28 1.39 -0.39 0.57 0.06 11.01 0.60
3000 54 0.22 2.28 2.70 0.26 0.08 0.18 0.21 0.79 0.19 0.04 0.29 1.23 -0.23 0.65 0.06 12.95 0.43
3001 38 0.20 2.29 2.50 0.14 0.04 0.20 0.20 0.83 0.20 0.02 0.30 1.43 -0.43 0.58 0.06 18.86 0.60
3002 36 0.21 2.28 2.12 0.12 0.03 0.20 0.21 0.89 0.20 0.02 0.32 1.46 -0.46 0.61 0.07 23.67 0.57
3003 36 0.21 2.28 2.23 0.13 0.03 0.20 0.21 0.87 0.20 0.02 0.32 1.54 -0.54 0.57 0.07 21.39 0.66
3004 42 0.23 2.28 2.29 0.17 0.04 0.20 0.21 0.86 0.20 0.02 0.31 1.59 -0.59 0.54 0.07 19.40 0.73
3005 51 0.27 2.23 1.67 0.24 0.07 0.22 0.24 0.91 0.22 0.03 0.36 1.26 -0.26 0.72 0.09 34.69 0.35
3006 56 0.27 2.21 2.29 0.28 0.09 0.22 0.25 0.74 0.23 0.04 0.31 1.54 -0.54 0.48 0.08 41.69 0.81
3007 68 0.28 2.15 1.52 0.37 0.13 0.24 0.28 0.83 0.25 0.05 0.37 1.43 -0.43 0.58 0.10 66.38 0.61
3008 110 0.27 2.23 2.13 0.70 0.41 0.10 0.24 0.80 0.14 0.18 0.33 1.13 -0.13 0.71 0.08 0.43 0.33
Reservoir B6
3020 54 0.20 2.36 2.71 0.26 0.08 0.14 0.16 0.98 0.15 0.05 0.30 1.41 -0.41 0.69 0.05 2.37 0.43
3021 48 0.26 2.21 2.35 0.21 0.06 0.23 0.25 0.73 0.23 0.03 0.30 1.28 -0.28 0.57 0.08 52.03 0.55
3022 47 0.25 2.21 1.86 0.20 0.06 0.23 0.25 0.83 0.23 0.02 0.34 1.26 -0.26 0.66 0.08 50.70 0.43
3023 50 0.23 2.24 2.13 0.23 0.07 0.21 0.23 0.82 0.22 0.03 0.32 1.36 -0.36 0.60 0.07 31.46 0.54
3024 44 0.24 2.23 2.29 0.19 0.05 0.22 0.24 0.77 0.22 0.02 0.31 1.36 -0.36 0.57 0.07 40.85 0.58
3025 52 0.23 2.25 2.30 0.24 0.07 0.20 0.23 0.80 0.21 0.03 0.31 1.33 -0.33 0.60 0.07 24.97 0.53
3026 32 0.23 2.24 2.05 0.09 0.02 0.23 0.23 0.83 0.23 0.01 0.32 1.34 -0.34 0.62 0.08 48.69 0.52
3027 29 0.23 2.23 2.35 0.07 0.02 0.23 0.24 0.76 0.23 0.01 0.30 1.31 -0.31 0.58 0.07 56.02 0.55
3028 31 0.26 2.19 1.61 0.09 0.02 0.25 0.26 0.87 0.25 0.01 0.36 1.38 -0.38 0.63 0.09 89.12 0.52
3029 59 0.25 2.17 1.74 0.30 0.10 0.24 0.27 0.80 0.24 0.04 0.35 1.23 -0.23 0.65 0.09 65.42 0.43
3030 37 0.29 2.17 1.54 0.13 0.03 0.26 0.27 0.85 0.26 0.01 0.37 1.37 -0.37 0.62 0.10 #### 0.52
3031 49 0.25 2.24 2.20 0.23 0.07 0.21 0.23 0.80 0.22 0.03 0.32 1.34 -0.34 0.60 0.07 30.50 0.53
3032 67 0.25 2.24 1.91 0.36 0.12 0.19 0.23 0.87 0.20 0.06 0.34 1.35 -0.35 0.64 0.08 17.22 0.48
3033 42 0.25 2.19 1.98 0.17 0.05 0.25 0.26 0.77 0.25 0.02 0.33 1.49 -0.49 0.51 0.09 79.90 0.72
3035 92 0.26 2.25 2.07 0.56 0.26 0.14 0.23 0.84 0.17 0.12 0.33 1.31 -0.31 0.64 0.08 2.96 0.47
3036 94 0.25 2.24 2.04 0.57 0.28 0.14 0.23 0.83 0.17 0.12 0.33 1.29 -0.29 0.65 0.08 2.93 0.45
3037 56 0.28 2.18 1.64 0.28 0.09 0.24 0.27 0.83 0.24 0.03 0.36 1.32 -0.32 0.63 0.10 67.04 0.49
3038 59 0.27 2.16 1.48 0.30 0.10 0.25 0.28 0.84 0.25 0.04 0.38 1.19 -0.19 0.71 0.11 81.75 0.35
3039 75 0.25 2.17 1.82 0.43 0.16 0.22 0.27 0.77 0.23 0.06 0.34 1.05 -0.05 0.73 0.09 39.37 0.28
3040 130 0.24 2.33 2.50 0.85 0.65 -
0.03 0.18 0.94 0.06 0.38 0.32 1.33 -0.33 0.71 0.06 0.00 0.39
3041 79 0.24 2.22 2.63 0.46 0.19 0.19 0.25 0.70 0.20 0.08 0.29 1.12 -0.12 0.62 0.07 13.99 0.42
Reservoir B7
3431 91 0.21 2.37 4.23 0.55 0.26 0.07 0.16 0.79 0.12 0.17 0.24 1.50 -0.50 0.53 0.04 0.06 0.71
3431 61 0.21 2.29 3.05 0.32 0.10 0.17 0.20 0.76 0.18 0.05 0.27 1.19 -0.19 0.64 0.06 8.24 0.43
3432 58 0.20 2.31 2.90 0.30 0.09 0.16 0.19 0.81 0.17 0.05 0.28 1.16 -0.16 0.70 0.05 6.58 0.35
3433 82 0.18 2.39 3.72 0.47 0.20 0.08 0.15 0.90 0.12 0.14 0.26 1.50 -0.50 0.60 0.04 0.11 0.60
3434 83 0.25 2.21 2.37 0.48 0.20 0.18 0.25 0.73 0.20 0.09 0.30 1.02 -0.02 0.71 0.08 12.50 0.29
3435 60 0.24 2.21 2.28 0.31 0.10 0.22 0.25 0.75 0.22 0.04 0.31 1.26 -0.26 0.59 0.08 33.97 0.52
3436 46 0.24 2.21 2.42 0.20 0.06 0.23 0.25 0.72 0.23 0.02 0.30 1.27 -0.27 0.57 0.07 53.39 0.55
3437 57 0.22 2.23 2.47 0.28 0.09 0.21 0.24 0.74 0.22 0.04 0.30 1.11 -0.11 0.67 0.07 29.24 0.37
3438 52 0.20 2.30 3.55 0.24 0.07 0.18 0.20 0.71 0.18 0.04 0.25 1.15 -0.15 0.62 0.05 10.74 0.44
3439 63 0.21 2.30 3.02 0.33 0.11 0.17 0.20 0.77 0.18 0.06 0.28 1.19 -0.19 0.65 0.05 6.88 0.42
3440 112 0.23 2.41 3.85 0.71 0.43 -
0.01 0.13 0.96 0.08 0.34 0.26 1.39 -0.39 0.69 0.03 0.00 0.44
3441 68 0.25 2.26 3.15 0.37 0.13 0.18 0.22 0.70 0.19 0.06 0.27 1.13 -0.13 0.62 0.06 10.24 0.43
3442 61 0.26 2.21 2.34 0.31 0.10 0.22 0.25 0.73 0.22 0.04 0.30 1.05 -0.05 0.69 0.08 37.38 0.33
3443 96 0.21 2.32 2.78 0.59 0.29 0.09 0.19 0.85 0.13 0.16 0.29 1.13 -0.13 0.75 0.06 0.24 0.29
3444 64 0.27 2.22 2.43 0.34 0.12 0.21 0.25 0.72 0.22 0.05 0.30 0.90 0.10 0.81 0.07 28.89 0.17
3445 55 0.24 2.20 2.24 0.27 0.08 0.23 0.26 0.73 0.23 0.03 0.31 0.90 0.10 0.81 0.08 50.17 0.17
3446 49 0.25 2.19 2.90 0.22 0.06 0.24 0.26 0.62 0.25 0.03 0.27 1.00 0.00 0.63 0.07 71.90 0.37
3447 49 0.24 2.21 2.21 0.23 0.06 0.23 0.25 0.75 0.23 0.03 0.31 1.04 -0.04 0.72 0.08 51.42 0.29
3448 49 0.23 2.24 2.42 0.22 0.06 0.21 0.23 0.76 0.22 0.03 0.30 1.00 0.00 0.76 0.07 31.29 0.24
3449 55 0.27 2.22 2.03 0.27 0.08 0.22 0.24 0.80 0.22 0.04 0.33 1.03 -0.03 0.78 0.08 37.88 0.23
3450 54 0.23 2.21 2.75 0.26 0.08 0.22 0.25 0.68 0.23 0.03 0.28 1.01 -0.01 0.67 0.07 41.84 0.33
3451 105 0.24 2.23 2.84 0.66 0.36 0.12 0.24 0.69 0.15 0.16 0.28 0.98 0.02 0.70 0.07 0.89 0.29
3452 77 0.24 2.28 3.21 0.44 0.17 0.16 0.21 0.71 0.17 0.08 0.27 1.13 -0.13 0.63 0.06 5.03 0.42
Reervoir B8
3535 80 0.24 2.29 1.96 0.46 0.19 0.14 0.20 0.97 0.16 0.10 0.34 1.68 -0.68 0.58 0.07 2.65 0.71
3535 64 0.23 2.22 1.73 0.34 0.12 0.21 0.24 0.87 0.22 0.05 0.35 1.43 -0.43 0.61 0.09 27.78 0.56
3536 59 0.21 2.28 2.32 0.30 0.10 0.18 0.21 0.86 0.19 0.05 0.31 1.47 -0.47 0.59 0.06 10.40 0.61
3537 57 0.21 2.28 2.07 0.28 0.09 0.18 0.21 0.90 0.19 0.04 0.33 1.43 -0.43 0.63 0.07 12.78 0.53
3538 60 0.23 2.26 1.99 0.31 0.10 0.19 0.22 0.89 0.20 0.05 0.33 1.41 -0.41 0.63 0.07 14.83 0.52
3539 67 0.21 2.27 1.99 0.36 0.13 0.17 0.21 0.91 0.18 0.06 0.34 1.21 -0.21 0.76 0.07 8.79 0.29
3540 63 0.23 2.25 2.41 0.33 0.11 0.19 0.23 0.78 0.20 0.05 0.30 0.88 0.12 0.88 0.07 17.98 0.11
3542 62 0.24 2.24 3.15 0.32 0.11 0.20 0.23 0.67 0.21 0.05 0.26 0.98 0.02 0.68 0.06 19.77 0.31
3543 77 0.21 2.29 2.05 0.44 0.17 0.15 0.20 0.93 0.17 0.09 0.33 1.31 -0.31 0.71 0.07 3.63 0.38
3544 69 0.20 2.29 2.45 0.37 0.13 0.16 0.21 0.84 0.18 0.07 0.31 1.20 -0.20 0.70 0.06 6.60 0.36
3545 63 0.25 2.20 1.73 0.33 0.11 0.22 0.25 0.85 0.22 0.05 0.35 1.27 -0.27 0.67 0.09 36.09 0.42
3547 62 0.21 2.28 2.33 0.32 0.11 0.18 0.21 0.85 0.19 0.05 0.31 1.22 -0.22 0.70 0.07 10.06 0.37
3548 61 0.22 2.37 3.45 0.32 0.10 0.13 0.16 0.87 0.14 0.07 0.26 1.47 -0.47 0.59 0.04 1.48 0.60
Reservoir B9
3596 90 0.22 2.38 4.00 0.54 0.24 0.07 0.15 0.85 0.11 0.17 0.25 1.53 -0.53 0.55 0.04 0.04 0.68
3597 71 0.17 2.33 3.64 0.39 0.14 0.14 0.18 0.76 0.15 0.08 0.25 1.38 -0.38 0.55 0.05 2.12 0.62
3598 63 0.19 2.38 3.45 0.33 0.11 0.12 0.15 0.90 0.14 0.07 0.27 1.56 -0.56 0.57 0.04 1.02 0.67
3599 54 0.23 2.33 2.62 0.26 0.08 0.16 0.18 0.91 0.17 0.05 0.30 1.49 -0.49 0.61 0.05 4.87 0.58
3600 27 0.22 2.25 1.71 0.06 0.01 0.23 0.23 0.93 0.23 0.01 0.36 1.54 -0.54 0.60 0.08 46.09 0.61
3601 34 0.21 2.32 2.39 0.11 0.03 0.18 0.19 0.92 0.18 0.01 0.31 1.51 -0.51 0.61 0.06 12.30 0.59
3602 67 0.18 2.34 2.40 0.36 0.13 0.13 0.17 0.98 0.15 0.08 0.31 1.46 -0.46 0.67 0.05 1.99 0.48
3603 38 0.19 2.29 2.91 0.14 0.04 0.19 0.20 0.78 0.19 0.02 0.28 1.18 -0.18 0.66 0.06 17.20 0.41
3604 25 0.23 2.23 1.51 0.04 0.01 0.24 0.24 0.95 0.24 0.00 0.38 1.61 -0.61 0.59 0.09 63.42 0.66
3605 94 0.20 2.37 3.14 0.57 0.27 0.07 0.16 0.92 0.11 0.18 0.28 1.37 -0.37 0.67 0.04 0.04 0.45
3606 142 0.19 2.34 2.64 0.94 0.84 -
0.10 0.18 0.92 0.03 0.49 0.32 1.50 -0.50 0.61 0.06 0.32 0.59
3607 97 0.21 2.30 2.52 0.60 0.30 0.10 0.20 0.86 0.14 0.16 0.31 1.36 -0.36 0.63 0.06 0.32 0.50
Reservoir B10
3609 77 0.21 2.35 3.07 0.44 0.17 0.11 0.17 0.89 0.14 0.11 0.28 1.48 -0.48 0.60 0.05 0.68 0.59
3610 41 0.23 2.31 2.45 0.16 0.04 0.18 0.19 0.88 0.19 0.02 0.31 1.56 -0.56 0.57 0.06 12.66 0.67
3613 128 0.16 2.38 3.23 0.83 0.62 -
0.05 0.15 0.94 0.06 0.43 0.29 1.18 -0.18 0.80 0.04 0.01 0.24
3613 126 0.19 2.37 3.55 0.81 0.59 -
0.04 0.16 0.87 0.06 0.39 0.27 1.36 -0.36 0.64 0.04 0.00 0.49
3615 99 0.19 2.36 3.41 0.61 0.31 0.06 0.16 0.85 0.11 0.20 0.27 1.59 -0.59 0.54 0.04 0.02 0.74
3615 50 0.19 2.30 3.44 0.23 0.07 0.18 0.20 0.72 0.18 0.04 0.26 1.43 -0.43 0.51 0.05 10.95 0.70
3616 30 0.15 2.35 2.93 0.08 0.02 0.16 0.17 0.91 0.16 0.01 0.28 1.46 -0.46 0.63 0.05 6.34 0.55
3617 34 0.14 2.34 2.94 0.11 0.03 0.17 0.17 0.88 0.17 0.02 0.28 1.39 -0.39 0.63 0.05 7.52 0.51
3618 44 0.19 2.31 2.24 0.19 0.05 0.18 0.19 0.93 0.18 0.03 0.32 1.37 -0.37 0.68 0.06 10.81 0.44
3619 69 0.21 2.31 2.65 0.38 0.13 0.15 0.19 0.85 0.17 0.07 0.30 1.34 -0.34 0.63 0.06 3.90 0.49
3620 70 0.19 2.30 2.80 0.38 0.14 0.16 0.20 0.80 0.17 0.07 0.29 1.29 -0.29 0.62 0.06 4.78 0.49
3621 110 0.20 2.39 3.21 0.69 0.41 0.01 0.15 0.97 0.09 0.29 0.28 1.50 -0.50 0.65 0.04 0.00 0.53
3622 110 0.19 2.41 3.42 0.69 0.40 0.00 0.14 0.99 0.08 0.31 0.28 1.57 -0.57 0.63 0.04 0.00 0.58
3623 47 0.22 2.31 2.05 0.21 0.06 0.18 0.19 0.97 0.18 0.03 0.33 1.42 -0.42 0.69 0.06 10.27 0.45
3624 98 0.20 2.35 2.73 0.60 0.30 0.07 0.17 0.94 0.12 0.19 0.30 1.45 -0.45 0.65 0.05 0.04 0.51
3625 29 0.21 2.29 2.19 0.07 0.02 0.20 0.20 0.90 0.20 0.01 0.32 1.52 -0.52 0.59 0.06 21.79 0.62
3626 25 0.22 2.24 1.72 0.04 0.01 0.23 0.23 0.91 0.23 0.00 0.35 1.54 -0.54 0.59 0.08 52.26 0.63
3627 57 0.20 2.25 2.35 0.29 0.09 0.20 0.23 0.79 0.21 0.04 0.31 1.35 -0.35 0.59 0.07 20.40 0.56
3628 54 0.21 2.28 2.41 0.26 0.08 0.18 0.21 0.84 0.19 0.04 0.31 1.28 -0.28 0.65 0.06 13.46 0.44
3629 55 0.22 2.29 2.71 0.27 0.08 0.18 0.20 0.80 0.19 0.04 0.29 1.31 -0.31 0.61 0.06 11.00 0.51
3630 136 0.18 2.41 3.64 0.90 0.74 -
0.11 0.13 0.97 0.03 0.58 0.28 1.59 -0.59 0.61 0.04 0.58 0.61
3631 36 0.22 2.26 1.82 0.12 0.03 0.21 0.22 0.92 0.22 0.01 0.35 1.56 -0.56 0.59 0.08 33.35 0.64
3632 32 0.24 2.22 1.92 0.09 0.02 0.24 0.24 0.83 0.24 0.01 0.33 1.38 -0.38 0.60 0.08 63.45 0.55
3633 53 0.22 2.26 2.50 0.25 0.08 0.19 0.22 0.79 0.20 0.04 0.30 1.19 -0.19 0.66 0.06 18.54 0.40
3634 86 0.19 2.36 3.20 0.51 0.22 0.09 0.16 0.88 0.13 0.14 0.28 1.38 -0.38 0.64 0.05 0.22 0.50
3635 35 0.23 2.26 1.91 0.11 0.03 0.21 0.22 0.91 0.21 0.01 0.34 1.46 -0.46 0.62 0.07 31.23 0.56
3636 50 0.21 2.29 2.96 0.23 0.07 0.18 0.20 0.77 0.19 0.04 0.28 1.29 -0.29 0.60 0.06 12.20 0.52
3637 72 0.19 2.35 3.37 0.40 0.15 0.12 0.17 0.83 0.14 0.09 0.27 1.28 -0.28 0.65 0.05 1.18 0.45
3639 95 0.19 2.36 3.25 0.58 0.28 0.07 0.16 0.89 0.12 0.18 0.28 1.37 -0.37 0.65 0.04 0.04 0.49
Reservoir B11
3931 92 0.15 2.44 4.42 0.55 0.26 0.03 0.12 1.00 0.09 0.23 0.25 1.64 -0.64 0.61 0.03 0.00 0.65
3931 69 0.17 2.35 4.07 0.37 0.13 0.13 0.17 0.77 0.14 0.08 0.24 1.24 -0.24 0.62 0.04 1.29 0.47
3932 32 0.17 2.33 4.75 0.09 0.02 0.18 0.18 0.66 0.18 0.01 0.22 0.99 0.01 0.67 0.04 9.73 0.33
3933 37 0.15 2.35 5.46 0.13 0.03 0.16 0.17 0.65 0.16 0.02 0.21 1.00 0.00 0.65 0.03 5.48 0.35
3934 35 0.16 2.34 5.01 0.12 0.03 0.17 0.18 0.66 0.17 0.02 0.22 1.04 -0.04 0.63 0.04 7.86 0.39
3935 45 0.16 2.39 5.97 0.19 0.05 0.13 0.15 0.69 0.14 0.04 0.20 1.11 -0.11 0.62 0.03 1.97 0.42
3936 71 0.16 2.36 5.30 0.39 0.14 0.12 0.16 0.68 0.14 0.09 0.21 1.13 -0.13 0.60 0.03 0.88 0.45
3937 84 0.17 2.35 5.34 0.49 0.21 0.10 0.17 0.66 0.13 0.13 0.21 1.10 -0.10 0.60 0.04 0.32 0.44
3938 67 0.17 2.36 5.37 0.36 0.13 0.13 0.16 0.67 0.14 0.08 0.21 1.13 -0.13 0.59 0.03 1.35 0.46
3939 56 0.19 2.32 4.72 0.27 0.08 0.16 0.19 0.64 0.17 0.05 0.22 1.01 -0.01 0.64 0.04 5.84 0.36
3940 65 0.18 2.38 5.38 0.35 0.12 0.12 0.15 0.71 0.14 0.08 0.21 1.23 -0.23 0.57 0.03 0.88 0.53
3941 79 0.15 2.41 5.58 0.45 0.18 0.08 0.13 0.78 0.11 0.14 0.21 1.34 -0.34 0.58 0.03 0.07 0.56
3942 55 0.18 2.33 4.90 0.27 0.08 0.16 0.18 0.64 0.17 0.05 0.22 0.99 0.01 0.65 0.04 5.23 0.35
3943 79 0.22 2.31 4.53 0.45 0.18 0.14 0.19 0.64 0.16 0.10 0.23 0.99 0.01 0.64 0.04 2.14 0.35
3944 88 0.19 2.33 4.65 0.52 0.23 0.11 0.18 0.66 0.14 0.13 0.23 1.20 -0.20 0.55 0.04 0.54 0.54
3945 100 0.17 2.42 4.42 0.61 0.32 0.02 0.13 0.92 0.09 0.26 0.24 1.62 -0.62 0.57 0.03 0.00 0.70
3946 90 0.21 2.32 4.70 0.54 0.25 0.10 0.18 0.65 0.14 0.14 0.23 1.08 -0.08 0.60 0.04 0.43 0.43
WELL C:
DEPTH GR NPHI RDEEP RHOB �T IGR Vsh Swa Qvn �e C�
WX-Sw Perm. SXO RHI MHI BWV MOS
Reservoir C1
2265 101 0.48 1.42 2.33 0.18 0.50 0.22 1.52 0.45 0.14 0.13 0.57 3.29 1.53 -0.53 0.99 0.10 0.99
2266 100 0.48 1.38 2.34 0.17 0.49 0.21 1.59 0.46 0.14 0.12 0.58 2.57 1.64 -0.64 0.97 0.10 0.97
2267 100 0.31 2.39 2.21 0.25 0.49 0.21 0.88 0.32 0.19 0.20 0.39 42.80 0.88 0.12 1.00 0.10 1.00
2268 103 0.30 4.11 2.22 0.25 0.51 0.23 0.66 0.34 0.19 0.19 0.30 36.30 0.65 0.35 1.02 0.07 1.02
2269 64 0.28 4.17 2.12 0.30 0.27 0.08 0.56 0.10 0.27 0.28 0.28 358.94 0.56 0.44 1.00 0.08 1.00
2270 67 0.26 3.96 2.11 0.30 0.29 0.09 0.56 0.11 0.28 0.28 0.29 391.82 0.57 0.43 0.99 0.09 0.99
2271 42 0.23 4.22 2.18 0.27 0.13 0.03 0.61 0.05 0.26 0.26 0.29 228.98 0.61 0.39 1.00 0.08 1.00
2272 58 0.26 4.38 2.16 0.28 0.22 0.06 0.58 0.09 0.26 0.26 0.28 237.29 0.59 0.41 0.99 0.08 0.99
2273 65 0.24 4.07 2.13 0.29 0.27 0.08 0.57 0.11 0.27 0.28 0.28 322.78 0.56 0.44 1.02 0.08 1.02
2274 47 0.26 4.26 2.15 0.29 0.16 0.04 0.57 0.05 0.27 0.28 0.28 344.31 0.57 0.43 1.01 0.08 1.01
2275 52 0.25 3.58 2.12 0.30 0.19 0.05 0.60 0.06 0.29 0.29 0.30 468.03 0.57 0.43 1.04 0.09 1.04
2276 46 0.25 3.46 2.16 0.28 0.15 0.04 0.65 0.05 0.27 0.27 0.31 300.46 0.63 0.37 1.03 0.09 1.03
2277 56 0.26 3.63 2.19 0.26 0.21 0.06 0.67 0.09 0.24 0.25 0.31 171.57 0.68 0.32 1.00 0.08 1.00
2278 66 0.29 3.64 2.16 0.28 0.28 0.09 0.64 0.12 0.25 0.26 0.31 212.14 0.65 0.35 0.98 0.08 0.98
2279 76 0.34 3.06 2.24 0.23 0.34 0.12 0.82 0.19 0.20 0.20 0.35 51.59 0.80 0.20 1.03 0.08 1.03
2280 90 0.34 3.16 2.15 0.28 0.43 0.17 0.68 0.22 0.23 0.24 0.33 149.24 0.68 0.32 1.00 0.09 1.00 Reservoir C2
2290 95 0.47 1.41 2.37 0.16 0.46 0.19 0.81 0.44 0.13 0.11 0.59 1.70 1.70 -0.70 0.48 0.09 0.48
2291 93 0.47 1.41 2.37 0.16 0.45 0.18 0.82 0.43 0.13 0.11 0.59 1.68 1.70 -0.70 0.48 0.09 0.48
2292 100 0.48 1.41 2.36 0.16 0.50 0.21 0.80 0.49 0.13 0.11 0.59 1.40 1.66 -0.66 0.48 0.09 0.48
2293 102 0.40 1.44 2.36 0.17 0.51 0.22 0.78 0.50 0.13 0.11 0.58 1.48 1.49 -0.49 0.52 0.10 0.52
2294 80 0.25 3.10 2.28 0.21 0.36 0.13 0.42 0.23 0.18 0.18 0.36 24.57 0.86 0.14 0.49 0.08 0.49
2295 104 0.29 2.94 2.21 0.25 0.52 0.23 0.37 0.35 0.19 0.19 0.35 39.56 0.75 0.25 0.50 0.09 0.50
2296 61 0.26 2.97 2.19 0.26 0.25 0.07 0.36 0.11 0.24 0.25 0.35 166.80 0.73 0.27 0.49 0.09 0.49
2297 73 0.29 2.73 2.15 0.28 0.32 0.11 0.35 0.14 0.25 0.26 0.35 223.01 0.74 0.26 0.47 0.10 0.47
2298 72 0.29 2.38 2.10 0.31 0.32 0.10 0.34 0.12 0.28 0.29 0.37 451.19 0.71 0.29 0.49 0.12 0.49
2299 67 0.26 2.41 2.16 0.28 0.29 0.09 0.38 0.12 0.25 0.26 0.38 221.33 0.76 0.24 0.50 0.11 0.50
2300 63 0.25 2.50 2.15 0.28 0.26 0.08 0.37 0.11 0.26 0.26 0.37 248.13 0.76 0.24 0.48 0.10 0.48
2301 60 0.24 2.42 2.15 0.29 0.24 0.07 0.37 0.09 0.27 0.27 0.38 294.20 0.77 0.23 0.48 0.11 0.48
2302 56 0.25 2.57 2.14 0.29 0.22 0.06 0.36 0.08 0.27 0.28 0.37 328.83 0.76 0.24 0.47 0.11 0.47
2303 46 0.24 2.44 2.17 0.27 0.15 0.04 0.38 0.05 0.26 0.27 0.38 267.87 0.78 0.22 0.49 0.10 0.49
2304 42 0.26 2.62 2.15 0.28 0.13 0.03 0.36 0.04 0.27 0.28 0.36 324.34 0.75 0.25 0.48 0.10 0.48
2305 44 0.25 2.56 2.17 0.27 0.14 0.03 0.37 0.05 0.26 0.27 0.37 274.21 0.77 0.23 0.48 0.10 0.48
2306 58 0.24 2.45 2.14 0.29 0.23 0.07 0.36 0.08 0.27 0.28 0.37 329.77 0.74 0.26 0.49 0.11 0.49
2307 87 0.34 2.47 2.23 0.24 0.41 0.15 0.43 0.24 0.20 0.20 0.39 49.53 0.89 0.11 0.48 0.09 0.48
2308 98 0.30 2.37 2.30 0.20 0.48 0.20 0.51 0.38 0.16 0.15 0.42 8.52 1.03 -0.03 0.49 0.08 0.49
2309 80 0.28 2.56 2.24 0.23 0.37 0.13 0.43 0.21 0.20 0.20 0.39 49.44 0.87 0.13 0.49 0.09 0.49
2310 83 0.30 2.52 2.26 0.22 0.39 0.14 0.45 0.24 0.19 0.19 0.40 34.67 0.92 0.08 0.49 0.09 0.49
2311 94 0.35 1.79 2.31 0.19 0.45 0.18 0.61 0.36 0.16 0.15 0.49 7.61 1.26 -0.26 0.49 0.09 0.49
2312 108 0.43 1.42 2.37 0.16 0.54 0.25 0.81 0.59 0.12 0.10 0.58 0.69 1.70 -0.70 0.48 0.09 0.48
2313 101 0.45 1.33 2.36 0.16 0.50 0.21 0.82 0.49 0.13 0.11 0.60 1.41 1.70 -0.70 0.48 0.10 0.48
2314 100 0.42 1.31 2.35 0.17 0.49 0.21 0.81 0.47 0.13 0.12 0.60 1.87 1.70 -0.70 0.48 0.10 0.48
2315 102 0.49 1.31 2.37 0.16 0.51 0.22 0.84 0.52 0.12 0.11 0.61 1.08 1.76 -0.76 0.48 0.10 0.48
2316 108 0.41 1.41 2.37 0.15 0.55 0.25 0.83 0.61 0.12 0.09 0.59 0.52 1.75 -0.75 0.48 0.09 0.48
2317 106 0.42 1.54 2.39 0.15 0.53 0.24 0.82 0.61 0.11 0.09 0.57 0.40 1.69 -0.69 0.48 0.08 0.48
2318 107 0.39 1.65 2.41 0.14 0.54 0.25 0.84 0.67 0.10 0.08 0.56 0.17 1.77 -0.77 0.48 0.08 0.48
2319 106 0.36 1.90 2.39 0.15 0.53 0.24 0.73 0.60 0.11 0.09 0.51 0.43 1.49 -0.49 0.49 0.08 0.49
2320 104 0.43 1.92 2.40 0.14 0.52 0.23 0.78 0.63 0.11 0.08 0.52 0.23 1.66 -0.66 0.47 0.07 0.47
2321 109 0.45 1.78 2.39 0.15 0.55 0.26 0.77 0.66 0.11 0.08 0.53 0.28 1.58 -0.58 0.48 0.08 0.48
2322 105 0.44 1.99 2.39 0.14 0.52 0.23 0.74 0.61 0.11 0.09 0.50 0.33 1.51 -0.51 0.49 0.07 0.49
2323 63 0.23 3.69 2.19 0.26 0.26 0.08 0.32 0.11 0.24 0.24 0.31 158.91 0.67 0.33 0.48 0.08 0.48
2324 65 0.25 4.67 2.18 0.27 0.27 0.08 0.28 0.12 0.24 0.25 0.27 172.13 0.56 0.44 0.49 0.07 0.49
2325 40 0.21 4.43 2.17 0.27 0.11 0.03 0.28 0.04 0.27 0.27 0.28 281.21 0.57 0.43 0.49 0.08 0.49
2326 40 0.23 4.36 2.18 0.27 0.12 0.03 0.29 0.04 0.26 0.26 0.28 252.73 0.56 0.44 0.51 0.08 0.51
2327 47 0.22 4.35 2.17 0.27 0.16 0.04 0.28 0.06 0.26 0.26 0.28 238.73 0.58 0.42 0.49 0.08 0.49
2328 48 0.23 4.39 2.20 0.26 0.16 0.04 0.30 0.06 0.24 0.25 0.28 168.50 0.60 0.40 0.49 0.07 0.49
2329 64 0.27 4.03 2.14 0.29 0.27 0.08 0.28 0.11 0.27 0.27 0.29 304.52 0.56 0.44 0.49 0.08 0.49
2330 106 0.28 3.89 2.14 0.29 0.53 0.24 0.29 0.31 0.22 0.23 0.29 113.12 0.58 0.42 0.49 0.08 0.49
Reservoir C3
2475 96 0.46 1.60 2.40 0.14 0.47 0.19 1.75 0.51 0.11 0.10 0.57 0.56 1.75 -0.75 1.00 0.08 1.00
2476 97 0.46 1.59 2.40 0.14 0.48 0.20 1.79 0.54 0.11 0.09 0.57 0.43 1.78 -0.78 1.00 0.08 1.00
2477 99 0.45 1.62 2.41 0.14 0.49 0.21 1.79 0.56 0.11 0.09 0.57 0.34 1.81 -0.81 0.99 0.08 0.99
2478 95 0.42 1.67 2.40 0.14 0.46 0.19 1.75 0.51 0.11 0.09 0.56 0.50 1.72 -0.72 1.01 0.08 1.01
2479 76 0.18 2.78 2.34 0.17 0.34 0.12 1.09 0.25 0.15 0.15 0.40 7.54 1.23 -0.23 0.89 0.07 0.89
2480 40 0.06 23.25 2.03 0.35 0.11 0.03 0.19 0.03 0.35 0.35 0.11 1369.74 0.24 0.76 0.80 0.04 0.80
2481 45 0.07 134.74 2.00 0.37 0.15 0.04 0.07 0.04 0.35 0.36 0.04 1619.55 0.06 0.94 1.23 0.02 1.23
2482 61 0.10 107.97 2.04 0.35 0.25 0.07 0.09 0.08 0.32 0.33 0.05 977.91 0.10 0.90 0.84 0.02 0.84
2483 68 0.15 71.90 2.02 0.36 0.29 0.09 0.11 0.10 0.32 0.33 0.06 1040.25 0.11 0.89 0.98 0.02 0.98
2484 78 0.15 27.26 2.04 0.35 0.35 0.12 0.18 0.13 0.31 0.32 0.10 786.21 0.16 0.84 1.16 0.03 1.16
2485 78 0.23 10.16 2.08 0.33 0.36 0.12 0.32 0.14 0.28 0.30 0.17 501.06 0.25 0.75 1.29 0.06 1.29
2486 83 0.27 3.08 2.10 0.31 0.38 0.14 0.63 0.17 0.27 0.28 0.32 365.91 0.59 0.41 1.06 0.10 1.06
2487 83 0.29 2.03 2.14 0.29 0.38 0.14 0.84 0.18 0.25 0.26 0.41 211.20 0.80 0.20 1.05 0.12 1.05
2488 73 0.28 2.05 2.14 0.29 0.32 0.11 0.84 0.14 0.26 0.26 0.41 243.26 0.82 0.18 1.03 0.12 1.03
2489 69 0.27 2.06 2.15 0.28 0.30 0.10 0.85 0.13 0.26 0.26 0.41 236.20 0.84 0.16 1.01 0.12 1.01
2490 68 0.27 1.82 2.16 0.28 0.29 0.09 0.92 0.12 0.25 0.26 0.44 218.67 0.90 0.10 1.01 0.12 1.01
2491 63 0.26 1.81 2.15 0.28 0.26 0.08 0.91 0.10 0.26 0.27 0.44 260.44 0.89 0.11 1.02 0.12 1.02
2492 67 0.25 1.85 2.16 0.28 0.29 0.09 0.91 0.12 0.25 0.26 0.44 212.91 0.88 0.12 1.04 0.12 1.04
2493 99 0.25 2.51 2.23 0.24 0.49 0.21 0.88 0.32 0.19 0.19 0.39 35.63 0.84 0.16 1.04 0.09 1.04
2494 57 0.24 2.63 2.37 0.16 0.22 0.06 1.23 0.15 0.15 0.14 0.43 6.43 1.10 -0.10 1.12 0.07 1.12
2495 37 0.25 1.71 2.18 0.27 0.10 0.02 0.98 0.03 0.26 0.26 0.46 254.13 0.93 0.07 1.06 0.12 1.06
2496 33 0.26 1.68 2.18 0.27 0.07 0.02 0.99 0.02 0.26 0.27 0.47 269.08 1.02 -0.02 0.97 0.13 0.97
2497 37 0.25 1.65 2.15 0.28 0.10 0.02 0.95 0.03 0.28 0.28 0.47 357.20 0.94 0.06 1.01 0.13 1.01
2498 40 0.25 1.71 2.18 0.26 0.12 0.03 0.99 0.04 0.26 0.26 0.46 224.49 1.00 0.00 0.99 0.12 0.99
2499 44 0.22 1.83 2.25 0.23 0.14 0.03 1.09 0.06 0.22 0.22 0.47 85.12 1.07 -0.07 1.01 0.11 1.01
2500 55 0.25 1.76 2.20 0.26 0.21 0.06 1.00 0.09 0.24 0.24 0.46 152.09 0.98 0.02 1.03 0.12 1.03
2501 72 0.27 1.89 2.19 0.26 0.32 0.10 0.95 0.15 0.23 0.24 0.44 136.44 0.92 0.08 1.03 0.12 1.03
2502 89 0.29 2.05 2.23 0.24 0.43 0.16 0.99 0.26 0.20 0.20 0.43 46.47 0.98 0.02 1.01 0.10 1.01
2503 55 0.27 1.68 2.16 0.28 0.21 0.06 0.95 0.08 0.26 0.27 0.46 272.40 0.93 0.07 1.03 0.13 1.03
2504 52 0.28 1.62 2.17 0.27 0.19 0.05 1.00 0.07 0.26 0.26 0.48 227.91 1.02 -0.02 0.98 0.13 0.98
2505 63 0.26 1.72 2.16 0.28 0.26 0.08 0.94 0.11 0.26 0.26 0.46 239.86 0.94 0.06 1.01 0.13 1.01
2506 82 0.27 1.90 2.21 0.25 0.38 0.14 0.99 0.21 0.21 0.22 0.44 75.72 0.99 0.01 0.99 0.11 0.99
2507 105 0.27 2.13 2.26 0.22 0.53 0.24 1.02 0.40 0.17 0.16 0.43 14.86 1.00 0.00 1.02 0.10 1.02
2508 103 0.32 2.20 2.28 0.21 0.51 0.22 1.07 0.41 0.16 0.15 0.43 9.45 1.07 -0.07 1.00 0.09 1.00
2509 123 0.38 2.32 2.40 0.14 0.64 0.35 1.43 0.91 0.09 0.06 0.46 0.03 1.38 -0.38 1.03 0.07 1.03
2510 112 0.38 2.56 2.27 0.22 0.57 0.28 0.95 0.48 0.16 0.15 0.39 7.96 0.95 0.05 1.00 0.08 1.00
2511 101 0.34 2.55 2.37 0.16 0.50 0.22 1.23 0.51 0.12 0.11 0.43 1.14 1.26 -0.26 0.98 0.07 0.98
2512 84 0.27 1.82 2.18 0.26 0.39 0.14 0.96 0.20 0.23 0.23 0.45 111.51 0.94 0.06 1.02 0.12 1.02
2513 93 0.26 1.79 2.19 0.26 0.45 0.18 0.97 0.26 0.21 0.22 0.45 82.93 0.93 0.07 1.04 0.12 1.04
2514 104 0.29 2.04 2.21 0.25 0.52 0.23 0.96 0.35 0.19 0.19 0.43 35.45 0.91 0.09 1.05 0.11 1.05
2515 101 0.29 2.12 2.22 0.24 0.50 0.22 0.95 0.33 0.19 0.19 0.42 35.28 0.95 0.05 1.00 0.10 1.00
2516 100 0.28 2.01 2.17 0.27 0.49 0.21 0.89 0.29 0.21 0.22 0.42 85.29 0.90 0.10 0.99 0.11 0.99
2517 95 0.26 2.10 2.16 0.28 0.46 0.19 0.85 0.25 0.23 0.23 0.41 118.73 0.83 0.17 1.02 0.11 1.02
2518 96 0.28 2.13 2.17 0.27 0.47 0.19 0.86 0.26 0.22 0.23 0.41 103.58 0.85 0.15 1.00 0.11 1.00
2519 105 0.26 2.07 2.20 0.25 0.52 0.24 0.93 0.35 0.19 0.20 0.42 42.39 0.94 0.06 0.99 0.11 0.99
2520 113 0.27 2.29 2.24 0.23 0.58 0.28 0.94 0.45 0.17 0.17 0.41 15.01 0.94 0.06 1.01 0.09 1.01
2521 112 0.24 2.47 2.27 0.22 0.57 0.28 0.97 0.48 0.16 0.15 0.40 7.93 0.97 0.03 1.00 0.09 1.00
2522 115 0.28 2.63 2.26 0.22 0.59 0.29 0.91 0.50 0.16 0.15 0.38 8.80 0.90 0.10 1.01 0.09 1.01
2523 106 0.32 2.41 2.29 0.21 0.53 0.24 1.02 0.44 0.16 0.15 0.41 7.87 0.97 0.03 1.05 0.08 1.05
2524 91 0.29 2.14 2.15 0.28 0.43 0.17 0.83 0.23 0.23 0.24 0.40 146.37 0.81 0.19 1.02 0.11 1.02
2525 103 0.26 2.39 2.27 0.21 0.52 0.23 1.00 0.40 0.16 0.16 0.41 11.84 1.02 -0.02 0.98 0.09 0.98
2526 115 0.23 2.26 2.27 0.21 0.59 0.29 1.03 0.51 0.15 0.14 0.42 6.09 0.98 0.02 1.05 0.09 1.05
2527 94 0.27 1.73 2.15 0.28 0.45 0.18 0.93 0.24 0.23 0.24 0.45 133.43 0.94 0.06 0.99 0.13 0.99
2528 110 0.30 1.51 2.17 0.27 0.56 0.26 1.04 0.36 0.20 0.21 0.49 58.01 0.98 0.02 1.06 0.13 1.06
2529 72 0.26 1.39 2.12 0.30 0.32 0.11 0.99 0.13 0.27 0.28 0.50 335.50 0.99 0.01 1.00 0.15 1.00
2530 73 0.29 1.40 2.11 0.31 0.32 0.11 0.97 0.13 0.27 0.28 0.49 376.53 0.94 0.06 1.03 0.15 1.03
Reservoir C4
2531 85 0.29 1.40 2.16 0.28 0.40 0.15 1.06 0.20 0.24 0.24 0.51 154.73 1.03 -0.03 1.03 0.14 1.02
2532 79 0.28 1.39 2.12 0.30 0.36 0.12 0.99 0.16 0.26 0.27 0.50 297.20 0.98 0.02 1.01 0.15 1.03
2533 77 0.27 1.40 2.14 0.29 0.35 0.12 1.02 0.15 0.26 0.26 0.50 242.05 0.97 0.03 1.05 0.15 1.01
2534 79 0.29 1.45 2.14 0.29 0.36 0.13 1.00 0.16 0.25 0.26 0.49 228.29 0.99 0.01 1.01 0.14 1.05
2535 89 0.27 1.58 2.16 0.28 0.42 0.16 0.99 0.22 0.23 0.24 0.47 144.36 0.97 0.03 1.02 0.13 1.01
2536 101 0.34 1.59 2.17 0.27 0.50 0.22 1.00 0.29 0.22 0.22 0.47 90.77 0.94 0.06 1.06 0.13 1.02
2537 75 0.29 1.58 2.16 0.28 0.34 0.11 0.98 0.15 0.25 0.25 0.48 201.14 0.97 0.03 1.01 0.13 1.06
2538 88 0.28 1.84 2.19 0.26 0.42 0.16 0.96 0.23 0.22 0.22 0.45 96.42 0.94 0.06 1.02 0.12 1.01
2539 79 0.29 1.67 2.17 0.27 0.36 0.13 0.98 0.18 0.24 0.24 0.46 147.97 0.98 0.02 1.00 0.13 1.02
2540 82 0.24 1.91 2.21 0.25 0.38 0.14 0.98 0.20 0.22 0.22 0.44 81.42 0.97 0.03 1.01 0.11 1.00
Reservoir C5
2550 86 0.26 1.63 2.19 0.26 0.41 0.15 1.03 0.22 0.22 0.23 0.48 96.80 1.02 -0.02 1.01 0.12 1.01
2551 70 0.28 1.57 2.16 0.28 0.30 0.10 1.00 0.13 0.25 0.25 0.48 198.63 1.01 -0.01 0.99 0.13 0.99
2552 66 0.31 1.87 2.13 0.29 0.28 0.09 0.87 0.11 0.27 0.27 0.43 315.75 0.86 0.14 1.01 0.13 1.01
2553 63 0.31 1.94 2.12 0.30 0.26 0.08 0.83 0.10 0.28 0.28 0.42 385.40 0.83 0.17 1.00 0.13 1.00
2554 64 0.31 1.92 2.12 0.30 0.27 0.08 0.84 0.10 0.27 0.28 0.42 366.47 0.85 0.15 0.99 0.13 0.99
2555 68 0.29 1.72 2.14 0.29 0.29 0.09 0.92 0.12 0.26 0.27 0.45 275.08 0.90 0.10 1.01 0.13 1.01
2556 69 0.28 1.83 2.13 0.29 0.29 0.09 0.87 0.12 0.27 0.27 0.43 311.48 0.88 0.12 1.00 0.13 1.00
2557 66 0.26 1.99 2.15 0.28 0.28 0.09 0.86 0.11 0.26 0.27 0.42 262.25 0.83 0.17 1.03 0.12 1.03
2558 68 0.28 2.01 2.13 0.29 0.29 0.09 0.83 0.12 0.27 0.27 0.41 310.28 0.82 0.18 1.02 0.12 1.02
2559 86 0.27 1.85 2.17 0.27 0.41 0.15 0.93 0.21 0.23 0.23 0.44 124.47 0.89 0.11 1.05 0.12 1.05
2560 78 0.26 1.63 2.17 0.27 0.35 0.12 0.99 0.17 0.24 0.25 0.47 166.39 0.94 0.06 1.05 0.13 1.05
