By Glory Ibeh, Shola Arogs and Wale Ajayi

1. Hydrocarbon-In-Place
Estimation Project Report
for Alwyn North Field
[East Brent Panel]
APRIL 2018
GROUP 6
AJAYI OLAWALE ISAAC G2017/IPS/MSC/PPD/297
AROGUNDADE OLUSHOLA G2017/IPS/MSC/PPD/300
IBEH NAOMI GLORY G2017/IPS/MSC/PPD/304

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CERTIFICATION
We hereby declare that the contained report on “OOGIP Calculation & Uncertainties” was
researched, and the results thoroughly analyzed under the supervision of the project supervisor Mr.
Owil Naleimolabh and approved, having satisfied the requirements to meet project objectives for
Petroleum Engineering and Project Development (MSc.), UNIPORT/IFP School, Port-Harcourt,
Rivers state, Nigeria.

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ACKNOWLEDGEMENT
First of all, we would like to acknowledge the Lord above all for his guidance, protection, wisdom
and understanding throughout this project, also for the knowledge gained in the process, it has
been a blessing.
We also appreciate University of PortHarcourt and the IFP School for the opportunity to work as
a team which contributed to developing team-building spirit amongst ourselves.
We would also like to thank our project supervisor, Mr. Owil Naleimolabh for his guidance and
direction in the course of this project, and for his advice and sacrifice we want to use this medium
to appreciate the efforts we put in as a team, the drive, selflessness, and solidarity amongst us.
We also appreciate all teams in IPS Batch 15 for their help and brainstorming arguments, it helped
us all grow.
God bless you all.

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NOMENCLATURE
3D 3-Dimension
Bo Oil Formation Volume Factor
DAT Depth-Area-Thickness
FWL Free Water Level
GOC Gas Oil Contact
HCIIP Hydrocarbon Initially in Place
N Ness
OIIP Oil Initially In Place
N Neutron Porosity Reading
D Density Porosity Reading
PVT Pressure-Volume-Temperature
RFT Repeat Formation Test
T Tarbert
UKCS United Kingdom Continental Shelf
WOC Water – Oil Contact
WUT Water Up to

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EXECUTIVE SUMMARY
Reserves estimation is one of the most essential tasks in the petroleum industry. It is the process
by which the economically recoverable hydrocarbons in a field, area, or region are evaluated
quantitatively. The aim of this project was to estimate the Hydrocarbon-In-Place for Alwyn North
field (Brent East Reservoir) using the given field data. Four wells (wells A2, N3, N1 and A4) were
drilled to help estimate hydrocarbon. The volumetric method was used for the purpose of the
estimation taking into account reserves uncertainty. Three cases of uncertainty were considered:
minimum, average and maximum case. The sandstones in the formation are acting as a source rock
for the emergence of the petroleum.
The results showed the following conclusions:
 Well to well correlations showed geological structures showed the presence of two faults
and some folds.
 All the wells had about the same WOC showing that the reservoir is continuous and
connected and there is a high likelihood that the faults are non-sealing.
 Ness 1 was in the aquifer zone and could not be produced from.
 Tarbert 3 has the highest reservoir thickness with the best reservoir petrophysical
characteristics (permeability, oil saturation and porosity) making it the most contributor to
the estimated reserve. Tarbert 2 has a lot of mica embedded in its sandstones.
 T3 has the highest GRV contributed mainly by its massive sandstone beds.
 The Tarbert 3 holds the major portion of the trapped hydrocarbons in Brent East. The
reserves were estimated as:
- Minimum case = 19,253,824.44 m3
- Average case = 31,421,555.11 m3
- Maximum case = 39,837,677.39 m3

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TABLE OF CONTENTS
CERTIFICATION ..............................................................................................................................................II
ACKNOWLEDGEMENT................................................................................................................................. III
NOMENCLATURE ...........................................................................................................................................IV
EXECUTIVE SUMMARY.................................................................................................................................. V
TABLE OF CONTENTS ...................................................................................................................................VI
LIST OF FIGURES............................................................................................................................................IX
LIST OF TABLES............................................................................................................................................... X
1 INTRODUCTION.......................................................................................................................................1
1.1 Background ..............................................................................................................................................1
1.2 Objective and Scope..................................................................................................................................2
1.2.1 Objective.........................................................................................................................................2
1.2.2 Scope ..............................................................................................................................................2
2 DESCRIPTION OF FIELD........................................................................................................................3
2.1 Overview ..................................................................................................................................................3
2.2 Field Characteristics Tectonics...................................................................................................................4
2.2.1 Geological Setting............................................................................................................................4
2.2.2 Geological Description.....................................................................................................................5
2.2.3 Tectonics.........................................................................................................................................7
2.2.4 Sedimentology.................................................................................................................................8
2.3 Summary..................................................................................................................................................9
3 HYDROCARBON RESERVE ESTIMATION ........................................................................................ 10
3.1 Types of Reserves.................................................................................................................................... 10
3.2 Basic Definition....................................................................................................................................... 11
3.3 Methods of Estimating Reserves ............................................................................................................. 12
3.3.1 Volumetric Estimation ................................................................................................................... 13
4 METHODOLOGY.................................................................................................................................... 15
4.1 Overview of HCIIP Estimation.................................................................................................................. 15
4.2 Well logs Interpretation .......................................................................................................................... 15
4.2.1 Well to Well Surface Correlations................................................................................................... 16
4.2.2 Identification of Reservoir Zones and Thickness ............................................................................. 17

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4.2.3 Identification of Fluid Contacts ...................................................................................................... 18
4.2.4 Quick-look Porosity Calculation in Water, Oil and Gas Zones .......................................................... 18
4.2.5 Determination of Resistivity of Formation Water ........................................................................... 18
4.3 Validation of Fluid Contacts Using RFT .................................................................................................... 19
4.4 Calculation of Petrophysical Properties.................................................................................................... 20
4.4.1 Net-to-Gross ratio, GN / ............................................................................................................ 20
4.4.2 Average Porosity ........................................................................................................................... 20
4.4.3 Average Initial Water Saturation.................................................................................................... 20
4.4.4 Determination of Absolute Permeability ........................................................................................ 21
4.5 Gross Rock Volume (GRV) Estimation ...................................................................................................... 21
4.5.1 DAT Procedure (Non-Eroded Zone)................................................................................................ 22
4.5.2 DAT Procedure (Eroded Zone)........................................................................................................ 22
4.6 PVT Selection- Formation Volume factor, Bo ......................................................................................... 23
4.7 Estimation of HCIIP ................................................................................................................................. 23
4.7.1 Assessment of Reservoir Uncertainties .......................................................................................... 24
4.7.2 Estimating of HCIIP Uncertainties................................................................................................... 24
5 RESULTS AND DISCUSSIONS............................................................................................................... 25
5.1 Introduction............................................................................................................................................ 25
5.2 Well Logs Interpretation ......................................................................................................................... 26
5.2.1 Well to Well Surface Correlations................................................................................................... 26
5.2.2 Logs Interpretation- Identification of Reservoir Zones.................................................................... 27
5.2.3 Resistivity and Saturation of Formation Water in the Aquifer (Formation N1)................................. 29
5.3 Validation of Fluid Contacts .................................................................................................................... 29
5.4 Petrophysical Properties and Net to Gross Ratio...................................................................................... 30
5.5 GRV Estimation....................................................................................................................................... 31
5.6 PVT Selection- Formation Volume factor, Bo ......................................................................................... 34
5.7 Estimation of HCIIP Including Uncertainties............................................................................................. 34
6 CONCLUSION.......................................................................................................................................... 36
REFERENCES................................................................................................................................................... 38

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APPENDIX......................................................................................................................................................... 39
Appendix I: Resistivity and Saturation of Formation Water in the Aquifer (N1) ........................................ 39
Appendix II: Calculation of FVF ............................................................................................................ 39
Appendix III: Data Sheets Obtained During Calculation.............................................................................. 39

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LIST OF FIGURES
Figure 1: 3D Area View of Alwyn North Field 3
Figure 2: Area Location Map of Alwyn North Field 4
Figure 3: Stratigraphy of Alwyn North Field 5
Figure 4: The Brent Geological Cross-section of Alwyn North Field 6
Figure 5: The Brent Geological Well Section of Alwyn North Field 6
Figure 6: The Cross-section through Alwyn Showing the Faults 8
Figure 7: Depositional Setting of the Brent group 9
Figure 8: Resource flow chart 11
Figure 9: Hydrocarbon Initially in Place Estimation Process 15
Figure 10: North-South direction and the West-East Directions of Correlations 16
Figure 11: Sample Phi-K for Unit N1 21
Figure 12: Eroded Surfaces 23
Figure 13: Well to Well Correlation a) North-South and b) West-East Cross- Sections 26
Figure 14: Sections of Interpreted Well Logs for Well a) A4 b) A2 c) N1 and d) N3 28
Figure 15: Pressure gradient curve for wells A4 and N3 29
Figure 16: Minimum case depth-area plot a) non-eroded zone and b) eroded zone 31
Figure 17: Average case depth-area plot a) non-eroded zone and b) eroded zone 32
Figure 18: Maximum case depth-area plot a) non-eroded zone and b) eroded zone 33

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LIST OF TABLES
Table 1: Data Received for Alwyn North (East Brent Reservoir).................................................1
Table 2: Reserve Estimation Methods .......................................................................................12
Table 3: Properties Obtained from Reservoir Rocks ..................................................................16
Table 4: Depth-Area data for Tarbert 3......................................................................................22
Table 5: Uncertain Reservoir Estimation Cases .........................................................................24
Table 6a: Petrophysical Properties (Porosity, Saturation, N/G, Stratigraphic Tops)....................30
Table 6b: Petrophysical Properties (Absolute Permeability) ......................................................31
Table 7: Summary of Minimum GRV .......................................................................................32
Table 8: Summary of Average GRV..........................................................................................33
Table 9: Maximum GRV...........................................................................................................33
Table 10: Differences in the PVT Study for Wells A4 and N3 ...................................................34
Table 11: Summary of Results (Minimum Case) .......................................................................34
Table 12: Summary of Results (Average Case) .........................................................................35
Table 13: Summary of Results (Maximum Case) ......................................................................35
Table 14: Well to Well Correlation Data Sheet a) North- South b) West- East...........................40
Table 15: Depth-Area Data Sheet a) Non-eroded b) Eroded ......................................................40
Table 16: Petrophysical Properties Data Sheet...........................................................................41

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1 INTRODUCTION
1.1 Background
Located 340 km NE from Aberdeen and 4 and 10km south of the Stratfjord and Brent field, the
Alwyn North field was discovered in 1975 and operated by TOTAL since 1982. 2D and 3D seismic
data obtained from the field indicated the presence of a petroleum system including source rocks,
normal sealing faults with a general North-South direction, oil-bearing sandstones and a major
unconformity at the base of the cretaceous. The unconformity is related to the of the Brent
formation in the eastern Brent.
The field is divided into six panels including the Brent East and North and also comprises eight
blocks (3/4a‐ 6, 3/9a‐ 1, 2 and 3, 3/9a‐ 4 and 3/9a‐ 5 and 3/4a‐ 8). The first well (3/4a‐ 6) drilled
in 1975 with oil in the Brent group and condensate gas in the Strafjord sandstone. Five appraisal
wells; A1, A2, A3, A4 and A5 in block 3/9 were drilled between 1971 and 1982 to further confirm
the presence of oil and condensate gas.
It has been decided that the Hydrocarbon Initially in Place (HCIIP) will be estimated for the East
Brent area. The volumetric method will be used in the estimation. This is to illustrate the concept
of volumetric reserves estimate in this course taking into consideration uncertainties.
To better understand the formation and obtain data that would be further used in reservoir and PVT
studies, core and plug samples were collected from the drilled wells and have been analyzed in the
laboratory. The wells were also logged to obtain well log data. Detailed results obtained from the
analysis were received and will be used to estimate the reserve. Table 1 contains the data received.
Table 1: Data Received for Alwyn North (East Brent Reservoir)
S/N Title Description
1 Annex 1 Phi-k cross plots for Ness and Tarberts
2 Annex 4 Pressure measurement synthesis
3 Annex 5 PVT study for wells N3 and A4
4 Annex 6 N1, N3 vertical and deviated depths
5 Annex 7 Documentation for log interpretation

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1.2 Objective and Scope
1.2.1 Objective
The objective of this Engineering project is to estimate the hydrocarbons in place (HCIIP) for the
Alwyn North Field (Brent East Reservoir) by undertaking the following specific activities:
● Interprete its well logs
● Calculate the petrophysical properties
● Estimate gross rock volume (GRV)
● Selecting the formation volume factor (FVF)
● Estimating the HCIIP while considering reservoir uncertainties
1.2.2 Scope
The study was limited to the East panel of the Alwyn North field.

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2 DESCRIPTION OF FIELD
2.1 Overview
The Alwyn North Field was discovered in 1974 in the South Eastern part of the East Shetland
Basin in the UK North-sea, about 140 km East of the near most Shetland Island and about 400 km
North East of Aberdeen. The Alwyn field lie respectively 4 and 10 km south of Strathspey and
Brent field, 7 km east of Ninian field, and 10 km north of Dunbar field (see field localization map
below). The water depth is around 130 m. The field is in the UKCS Block 3/9 and extends
northward into the Block 3/4. The location map and 3D view of the area is shown in figure 1 and
2 respectively.
Figure 1: 3D Area View of Alwyn North Field

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Figure 2: Area Location Map of Alwyn North Field
2.2 Field Characteristics Tectonics
Tectonics played a significant role on the structure of ALWYN North field. Tensional movements
leading to the development of the Viking Graben from the lower Permian times to Upper Jurassic
generated a complex fault pattern. Several seismic data acquisition programs were carried out: 2D
seismic in 1974 and 1977, and 3D in 1980/81. Seismic data analysis indicates that the oil bearing
sands are controlled on one hand by normal sealing faults with a general North-South direction,
on the other hand by a major unconformity at the base of Cretaceous. This unconformity is related
to erosion of the Brent formation in the eastern part of ALWYN North field. In a bid to explore
the Alwyn North field a thorough geological description of the field is necessary to ensure
complete understanding of the geology of the area. The geological setting, sedimentology and
other related aspects of the field are described in this section
2.2.1 Geological Setting
The Brent formation was deposited in a deltaic and shallow marine environment during the Middle
Jurassic period. The Statfjord formation was deposited in a fluvial and shallow marine
environment during the Lower Jurassic period. Each panel has several pre-cretaceous tilted blocks
(see Figure 3 below). The cap-rock is made of three on lapping shaly formations:

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 Heather formation: marine transgressive shales with thin limestone stringers, which is
deposited after the tectonic activity.
 Kimmeridge clay thick in the West, thin in the East, which is the main hydrocarbon source
rock
 Thick cretaceous sequence
Figure 3: Stratigraphy of Alwyn North Field
ALWYN North reservoirs were relatively unaffected by diagenesis due probably to an
early hydrocarbon impregnation RFT shows that each panel had its own pressure regime. Water-
oil contacts were identified at different depth. All the panels were independent from the other.
2.2.2 Geological Description
The structure of Alwyn Brent East Block was generally an eroded monoclonal, with Base
Cretaceous Unconformity (BCU) setting east and south limit, Spinal Fault setting west limit
(separating Brent east from north and central west blocks), and a fault with sometimes very small
throw setting north limit. East structure under BCU is quite complicated, and described under the
generic term of slumps (linked to gravitational collapse of head blocks during Cretaceous erosion
– similar as ones encountered in Brent field). In the Brent East panel, the oil zone is in a
stratigraphic trap as shown below created by the erosion unconformity to the east, by a north -

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south fault to the west (between A-1 and A-2 wells) and by a tranverse fault to the north. The Brent
Geological Cross section is shown below.
Figure 4: The Brent Geological Cross-section of Alwyn North Field
The Brent geological well section is shown in Figure 5.
Figure 5: The Brent Geological Well Section of Alwyn North Field

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2.2.3 Tectonics
Several seismic data acquisition programs were carried out: 2D seismic in 1974 and 1977, and 3D
in 1980/81. Seismic data analysis indicates that the oil bearing sands are controlled on one hand
by normal sealing faults with a general North-South direction, on the other hand by a major
unconformity at the base of Cretaceous. This unconformity is related to erosion of the Brent
formation in the eastern part of ALWYN North field following the seismic interpretation, ALWYN
North field was divided into the following panels:
 Brent North
 Brent Northwest.
 Brent Southwest.
 Brent East.
 Statfjord
 Triassic
The first four panels are oil bearing within the Brent. The Statfjord formation is a condensate gas
reservoir with the Brent completely eroded. The underlying Triassic is gas bearing.

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Figure 6: The Cross-section through Alwyn Showing the Faults
2.2.4 Sedimentology
The Brent group is divided into three main units:
 The Lower Brent (Broom, Rannoch and Etive formations),
 The Middle Brent (Ness formations), and
 The Upper Brent (Tarbert formations).
The last two are the only oil-bearing formations in the Brent East panel. The Lower Brent
formation was deposited in a shore-face (Rannoch) to coastal barrier (Etive) environment. The
clastic reservoir is made of transgressive sandstone (Broom) and prograding sandstones
(Rannochand Etive). Thus, the petrophysical properties range from low to medium permeability.
This unit does not contain any oil in the Brent East reservoir.
The Middle Brent formation was deposited in a deltaic to alluvial plain, Ness 1(N1) and lagoon to
lower delta plain, Ness 2 (N 2) environment. Thus sandstones are inter-bedded with clay and coal.
In general, Ness 1 unit has poorer petrophysical characteristics than Ness 2 unit and its oil-bearing
leg is much lower especially to the East of the reservoir.
The Upper Brent was deposited in a prograding lower shoreface environment. Three different
types of sandstone are identified. At the top Tarbert 3 (T3) are massive sands with very good
reservoir characteristics. This is the main oil bearing unit in the Brent East reservoir. Below Tarbert
2 (T2), there are mica-rich sandstones with lower permeability. These mica-rich sandstones exhibit
a high natural radioactivity. The base of the Tarbert formation, Tarbert 1 (T1), is very similar to
the top sandstone. Despite its lower average permeability, Tarbert 2 unit is not considered as a
permeability barrier.

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Figure 7: Depositional Setting of the Brent group
2.3 Summary
To summarize, Tarbert can be described as massive shore face sands with excellent petro-physical
properties, well connected throughout the field and may be even regionally, communicating
partially with Upper Ness fluviatile system which is isolated from Lower Ness. Base Brent Etive
and Rannoch are better quality reservoirs, but mainly water bearing in Brent East Block.
Considering the small oil content in Ness 1, this unit is neglected in the reservoir model. Thus, the
reservoir model focuses on the Ness 2 and Tarbert 1, 2 and 3 units. The Brent East reservoir of
Alwyn North was characterized using data from two of the original vertical appraisal wells (3/9A-
2, 3/9A-4) and two new deviated delineation wells (N1 and N3). N3 characterized the northern
part of the field where an important oil leg was confirmed mainly in the Tarbert units. N1 located
to the West did not produce any oil and only encountered the aquifer, which does seem to be
active. The water salinity in the reservoir is about 17,000ppm.

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3 HYDROCARBON RESERVE ESTIMATION
Reserves are estimated volumes of crude oil, condensate, natural gas, natural gas liquids, and
associated substances anticipated to be commercially recoverable from known accumulations from
a given date forward, under existing economic conditions, by established operating practices, and
under current government regulations. Understanding the recoverable oil & gas reserves is
important when trying to establish their present and future value. The definition of reserves takes
into account the technical and commercial certainty of extraction using existing technology.
3.1 Types of Reserves
The Society of Petroleum Engineers (SPE) categorizes reserves into two main types based on its
degree of uncertainty using the current economic conditions including prices and costs and the
available technology prevailing at the time of the estimate (see figure 8):
1) Proved Reserves; 90% certainty of commercial extraction
2) Unproved Reserve; which is further divided as:
 Probable Reserves, 50% certainty of commercial extraction
 Possible Reserves, 10% certainty of commercial extraction.
The range of uncertainty reflects a reasonable range of estimated potentially recoverable volumes
for an individual accumulation or a project. In the case of reserves, this range of uncertainty can
be reflected in estimates for
- Proved reserves (1P),
- Proved + probable reserves (2P),
- Proved plus probable plus possible reserves (3P) scenarios.
Other categories such as low estimate, best (or average) estimate, and high estimate are also
recommended.
Total Oil and Gas Resource
UndiscoveredDiscovered

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Figure 8: Resource flow chart
3.2 Basic Definition
For a better understanding on estimating reserves, a few important terms require definition.
1) Original oil in place (OOIP) and original gas in place (OGIP): The total volume of
hydrocarbon stored in a reservoir prior to production. Reserves or recoverable reserves are
the volume of hydrocarbons that can be profitably extracted from a reservoir using existing
technology.
2) Resources: reserves plus all other hydrocarbons that may eventually become producible;
this includes known oil and gas deposits present that cannot be technologically or
economically recovered (OOIP and OGIP) as well as other undiscovered potential reserves.

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3.3 Methods of Estimating Reserves
Estimating hydrocarbon reserves is a complex process that involves integrating geological and
engineering data. Depending on the amount and quality of data available, one or more of the
following methods may be used to estimate reserves:
1) Volumetric
2) Material balance
3) Production history
4) Analogy
These methods are summarized in Table 2.
Table 2: Reserve Estimation Methods
S/N
Method Application Accuracy
1
Volumetric
OOIP, OGIP, recoverable reserves.
Use early in life of field.
Dependent on quality of
reservoir description. Reserves
estimates often high because this
method does not consider
problems of reservoir
heterogeneity.
2
Material balance
OOIP, OGIP (assumes adequate
production history available),
recoverable reserves
(assumes OOIP and OGIP known).
Use in a mature field with abundant
geological, petrophysical, and
engineering data.
Highly dependent on quality of
reservoir description and
amount of production data
available. Reserve estimates
variable.
3 Production
history
Recoverable reserves. Use after a
moderate amount of production data
is available.
Dependent on amount of
production history available.
Reserve estimates tend to be
realistic.
4
Analogy
OOIP, OGIP, recoverable reserves.
Use early in exploration and initial
field development.
Highly dependent on similarity
of reservoir characteristics.
Reserve estimates are often very
general.
The volumetric method is discussed in the next section.

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3.3.1 Volumetric Estimation
Volumetric estimates of HCIIP are based on a geological model that geometrically describes the
volume of hydrocarbons in the reservoir. However, due mainly to the decrease in temperature and
pressure from the reservoir to the surface, dissolved gases in oil evolves and expands at the surface
thereby occupying larger volume in stock tanks. This necessitates correcting subsurface volumes
to standard units of volume measured at surface or stock tank conditions. The basic volumetric
equation (in field units) used is:
𝑂𝐼𝐼𝑃 = 7,758𝐴ℎ𝛷(1 − 𝑆 𝑤)/𝐵 𝑜𝑖 (1)
𝑂𝐺𝐼𝑃 = 43,560𝐴ℎ𝛷(1 − 𝑆 𝑤)/𝐵 𝑔𝑖 (2)
Where; OIIP = Oil Initially in Place (STB)
OGIP = Gas Initially in Place (SCF)
A = Area of reservoir (acres) obtained from map data
h = Height or thickness of pay zone (ft) obtained from log and/or core data
𝛷 = Porosity obtained from log and/or core data
𝑆 𝑤 = Connate water saturation obtained from log and/or core data
𝐵 𝑤𝑖, 𝐵 𝑔𝑖 = Formation volume factor for oil (reservoir bbl/STB) and gas (reservoir bbl/SCF)
respectively at initial conditions from lab data;
Recoverable reserves are a fraction of the OOIP or OGIP and are dependent on the efficiency of
the reservoir drive mechanism. The basic equation used to calculate recoverable oil reserves is:
𝑅𝑒𝑐𝑜𝑣𝑒𝑟𝑎𝑏𝑙𝑒 𝑂𝑖𝑙 𝑟𝑒𝑠𝑒𝑟𝑣𝑒𝑠 ( 𝑠𝑡𝑏) = 𝐻𝐶𝐼𝑃 × 𝑅𝐹 (3)
Where; RF = Recovery factor
HCIIP = OIIP or GIIP
The RF is dependent on the method of recovery used in producing the hydrocarbon. It is the sum
of the primary and secondary recovery. The primary recovery factor is estimated from the type of
drive mechanism. The secondary recovery factor, RFS, is given by:

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𝑅𝐹𝑠 = 𝐸 𝐷 × 𝐸𝐴 × 𝐸𝑣 (4)
Where;
 ED = displacement efficiency
 EA = areal sweep efficiency
 EV = vertical sweep efficiency
These efficiency terms are influenced by such factors as residual oil saturation, relative
permeability, reservoir heterogeneity, and operational limitations that govern reservoir production
and management. Thus, it is difficult to calculate the recovery factor directly using these terms.
Other methods such as the decline curves are often applied.

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4 METHODOLOGY
4.1 Overview of HCIIP Estimation
The front-end activities that provided data and information used in determining the OIIP are
summarized by the flow schematic in Figure 9. The approach taken to complete each activity is
described in the sections following the figure.
Figure 9: Hydrocarbon Initially in Place Estimation Process
4.2 Well logs Interpretation
Logs data obtained from the various wells were analyzed for interpretation. . The purpose of
interpreting the logs was to:
Interpretation of
Well Logs
Calculation of
Petrophysical properties
(K, N/G, and )
Validation of Fluid
Contacts Using RFT
Estimation of Gross
Rock Volume
PVT Selection - Bo
Estimation of HCIIP
Well to Well Surface
Correlations
Identification of
Reservoir Zones
Identification of
Fluid Contacts
Quick-look Porosity
Calculation
Determination of
formation Water
Resistivity

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a) Perform well to well surface correlations.
b) Identify the reservoir rocks and obtain a number of physical parameters related to both its
geological and petrophysical properties. Parameters obtained from this process are listed
in table 3.
c) Identify, characterize and quantify the fluids present in the reservoir rocks.
Table 3: Properties Obtained from Reservoir Rocks
S/N Parameters (Rock and fluid)
1 Lithology
2 Reservoir zones and thickness
3 Fluid contacts- water-oil, gas-oil and gas-water
4 Fluids present (oil, water and gas) and net pay zones
5 Resistivity
6 Porosity
4.2.1 Well to Well Surface Correlations
Well to well correlation takes into account the various sand surfaces in each well with the
isobaths reading for correlating the surfaces. It is a structured scheme to define reservoir
architecture and quality and the relationships of the depositions in time. This is within the
context of sequence stratigraphy. The correlations were done in both the North-South
direction and the West-East directions crossing through faults and the wells as seen in
figure 10.
Figure 10: North-South direction and the West-East Directions of Correlations

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Well to well correlation was also used to show the sequence stratigraphic surfaces (tops)
of all the formations in the different wells in Alwyn North field. The stratigraphic top of
well A4 was provided. Hence, all others wells were matched to those of well A4. The
surfaces were identified based on a number of criteria which included the WUT, WOC,
GOC gamma ray and resistivity.
4.2.2 Identification of Reservoir Zones and Thickness
Reservoir zones were identified by identifying and eliminating areas considered as non-
reservoir zones namely:
- Shale
- Tight formation
- Salt
- Coals
The processes involved in identifying each are listed below.
I. Shale
- Presence of caving as observed from deviation between the caliper log and bit size.
- Highly radioactive sections with gamma ray greater than 70 API.
- No invasion: Low resistivity of less than 20 ohm-m and the resistivity readings are
close to each other.
- High Neutron values of 30%.
- Large Neutron-Density separation.
- Shale base line indicator from Spontaneous Potential readings.
II. Tight formations
- Caliper close to Bit size
- Low Gamma Ray values of less than 30 API
- High resistivity values of greater than 200 ohm-m and resistivity readings close to each
other.
- Density, Neutron, Sonic values close to matrix reference values.
- Low Neutron and Sonic readings but high density readings

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III. Other non-reservoir sections (salt, coal etc.)
- Caliper close to bit size, but caving can be observed in Salt
- Low gamma ray values for Halite and Anhydrite
- Very high resistivity values
The net thickness of the reservoir zones, uh are measured and recorded for each well.
4.2.3 Identification of Fluid Contacts
- Water - Oil contact were identified using the resistivity overlay technique
- Gas – Oil contact were identified using Density-Neutron separation (Gas effect)
4.2.4 Quick-look Porosity Calculation in Water, Oil and Gas Zones
Porosity was calculated using the formula below:
Oil and water zones:
2
DN 
 (5)
Gas zones:
4
3 ND 
 (6)
Where; N = Neutron Porosity reading
D = Density Porosity reading
4.2.5 Determination of Resistivity of Formation Water
Resistivity values were obtained from the LLD and LLS logs. LLD log represents the
water resistivity in non-invaded zone while LLS log provided the resistivity of formation
water in the flushed zone.
Archie’s formula I and II was used in calculating the resistivity of water in the water zone
and saturation of water in all the various reservoir zones.
Rxo
Rt
RmfRw  (7)
Where; Rw= Resistivity of formation water in the aquifer, Ωm
Rmf = Resistivity of mud filtrate, Ωm
Rt = Resistivity of non-invaded zone, Ωm
Rxo= Resistivity of flushed zone, Ωm

29. Page | 19
Computation of fluid saturations in various zones:
n
t
w
mw
R
R
S
a

 (8)
whc SS  1
Where: wS = Water saturation, s.u
hcS = Hydrocarbon saturation, s.u
Rt = Resistivity of non-invaded zone, Ωm
 = Porosity, p.u
m = cementation factor = 2 for clean sandstone
n = saturation exponent =1 for clean sandstone
NB: it is assumed that the formation sandstones are clean for Archie’s formula to be
applicable. Resistivity of formation water is calculated using Archie’s formular (equation
(8)). Saturation of water is 1. Rt is read off from the logs.
4.3 Validation of Fluid Contacts Using RFT
The Repeat Formation Tester (RFT) was used to validate the fluid contacts obtained from the well
logs.
Formation pressure changes vertically with depth as the fluid in the wellbore changes. The change
in the pressure gradients is the basis for determining free water level (FWL) in the wellbore. The
formation pressure versus depth data was received for well A-2, A-4 and N3.
Procedure
- Formation pressure was plotted against TVDSS for each well.
- The depths where the characteristic pressure gradient changes were recorded
Assumption: The OWC may vary from the FWL. However, it is assumed that the FWL=WOC.

30. Page | 20
4.4 Calculation of Petrophysical Properties
4.4.1 Net-to-Gross ratio, GN /
This is the ratio of the net pay thickness (corresponding to the net pay zone) to the gross
sand thickness of a geological unit. It was obtained using equation 5 below.
t
u
h
h
GN / (9)
Where; uh = Net pay thickness
th = Gross sand thickness
Net pay zones cut-offs are assigned based on the following:
- Oil saturation greater than or equal to 0.3.
- Reservoir thickness greater than 1m
- Porosity greater than 1%
- Permeability values greater than 1mD.
4.4.2 Average Porosity
The thickness weighted average porosity equation was used in obtaining the average
porosity over the net reservoir zones. For each geological unit, the average porosity Φ is
given by:


ui
ui
h
hΦ
Φ i
(10)
Where; iΦ = porosity of each sub-reservoir units in the geological unit
uih = thickness of the sub-reservoir unit
4.4.3 Average Initial Water Saturation
Like the porosity, the average initial water saturation, wiS for each reservoir zones in a
geological unit is given by:

31. Page | 21


ui
ui
hΦ
hΦ
i
iwii
wi
S
S (11)
Where; wiiS = porosity of each sub-reservoir units in the geological unit
uih = thickness of the sub-reservoir unit
iΦ = porosity of each sub-reservoir units in the geological unit
4.4.4 Determination of Absolute Permeability
The absolute permeability for each sand layer was estimated using the permeability-
porosity data for each sub-reservoir unit (see sample Annex 1 document in figure 11). The
value of average porosity obtained from section 4.2.4 was used to read off the permeability
in each case.
Figure 11: Sample Phi-K for Unit N1
4.5 Gross Rock Volume (GRV) Estimation
GRV is the volume enclosed by the top and bottom surface of a reservoir and above the water
contact. The GRV of Alwyn North was estimated using the traditional depth-area- thickness
(DAT) method. Table 4 is the depth-area-thickness data received for tops of T3.

32. Page | 22
Table 4: Depth-Area data for Tarbert 3
S/N Depth (Top of T3)
(m3
)
Area
(Km2
)
1 3,120 0.06
2 3,140 0.73
3 3,160 2.09
4 3,180 3.32
5 3,200 5.77
6 3,220 8.91
7 3231 11.33

The non-eroded zone occupies 55% of the total area.
4.5.1 DAT Procedure (Non-Eroded Zone)
- The depths of surfaces T2, T1, N2 and N1 corresponding to each given depths of T3
were calculated.
𝑍 = 𝑍𝑜 + 𝑡ℎ𝑖𝑐𝑘𝑛𝑒𝑠𝑠 𝑜𝑓 𝑏𝑒𝑑 𝑎𝑏𝑜𝑣𝑒 𝑍 (12)
Where; 𝐷( 𝑇3)= Depth (Top of T3)
- The areas occupied for the eroded zone were calculated by:
𝑁𝑜𝑛 − 𝐸𝑟𝑜𝑑𝑒𝑑 𝐴𝑟𝑒𝑎 = 0.55 × 𝐴𝑟𝑒𝑎 (13)
- The depths of all the surfaces were plotted against the non-eroded areas.
- The volume occupied between two surfaces was estimated for each geological unit.
4.5.2 DAT Procedure (Eroded Zone)
- The areas occupied for the eroded zone were calculated by:
𝐸𝑟𝑜𝑑𝑒𝑑 𝐴𝑟𝑒𝑎 = 0.45 × 𝐴𝑟𝑒𝑎 (14)
- The depths of all the surfaces were plotted against the eroded areas.
𝑍 = 𝑍𝑜 +
𝐻𝑜−𝐻
2
(15)
Where; 𝑍𝑜 = Depth (Top of T3)
𝐻𝑜 = thickness of bed when T2, T1, N2 or N1 from T3
𝐻 = thickness of bed when T2, T1, N2 or N1 from T3 is zero (see figure 12)

33. Page | 23
Figure 12: Eroded Surfaces
4.6 PVT Selection- Formation Volume factor, Bo
The formation oil volume factor is a ratio that relates the volume of oil within the reservoir to the
volume at standard conditions. The PVT study report (Annex 5-2 and Annex 5-3) provided
contains the laboratory methods used in determining Bo on well A4 and N3 respectively. They
are:
 The constant composition study
 The multi-stage separator or process test experiment
 The differential vaporization experiment
The reservoir fluid conditions temperature and pressure are 112o
C and 445.5 bar respectively. For
a better representation of Bo for the estimation of HCIIP, the composite Bo value drawn from the
constant composition study and the process test experiment were used. Since the reservoir pressure
is higher than the saturated pressure (270.1 bar), the composite Bo equation used is given by:
𝐵𝑜𝑐 =
𝑉(𝑃)
𝑉(𝑃𝑠𝑎𝑡)
× 𝐵𝑜𝑝( 𝑃𝑠𝑎𝑡) (16)
Where; 𝐵𝑜𝑝( 𝑃𝑠𝑎𝑡) = Formation volume factor of oil at saturated pressure
𝑉( 𝑃) = Volume of oil at reservoir pressure
𝑉( 𝑃𝑠𝑎𝑡) = Volume of oil at saturated pressure
Because of the absence of a PVT study report for the other wells, it is assumed that the composite
Bo for well A4 is same for all the other wells.
4.7 Estimation of HCIIP
For an oil reservoir, the Oil Initially in Place (OIIP) is given by:

34. Page | 24
𝑂𝐼𝐼𝑃 = 𝐺𝑅𝑉 × 𝛷 × 𝑆𝑜 ×
𝑁
𝐺
×
1
𝐵𝑜
(17)
For a gas reservoir, the Gas Initially in Place (GIIP) is given by:
𝐺𝐼𝐼𝑃 = 𝐺𝑅𝑉 × 𝛷 × 𝑆𝑔 ×
𝑁
𝐺
×
1
𝐵𝑜
(18)
Where; 𝑆𝑜 = Oil saturation given by:
= 1 − 𝑆𝑤
𝑆𝑔 = Gas saturation given by:
= 1 − 𝑆𝑤 − 𝑆𝑜
4.7.1 Assessment of Reservoir Uncertainties
Reservoir uncertainty is the variation of HCIIP in the range of possible outcomes. Every step taken
in estimating the HCIIP, starting from the seismic interpretation, has a level of uncertainty
attached to it. Hence, it is imperative that these uncertainties are taken into consideration before
good developmental decisions are made.
Geological uncertainties evaluation includes structural uncertainties and some dynamic
uncertainties.
4.7.2 Estimating of HCIIP Uncertainties
For this study, the deterministic method was used in estimating the HCIIP uncertainties. Three
cases were considered namely:
1) Optimistic hypotheses analyzed for maximum case (P90)
2) Reasonable hypotheses analyzed for average case (P50)
3) Pessimistic hypotheses analyzed for minimum case (P10).
The main geological uncertain parameters affected by these methods are structural uncertainties
(GRV) and the static uncertainties (N/G, 𝛷, wiS )
Table 5: Uncertain Reservoir Estimation Cases
Case Bed Thickness Porosity Water Saturation GRV

35. Page | 25
Maximum
case
Maximum value Maximum
value
Minimum value Maximum bed
thickness
Average case Average value Average Average value Average bed
thickness
Minimum
case
Minimum value Minimum
value
Maximum value Minimum bed
thickness
5 RESULTS AND DISCUSSIONS
5.1 Introduction
The following sections present the main results obtained from the determination of the HCIIP for
the Alwyn North field. More comprehensive results can be found in the Appendix section of this
report.

36. Page | 26
5.2 Well Logs Interpretation
5.2.1 Well to Well Surface Correlations
(a)
(b)
Figure 13: Well to Well Correlation a) North-South and b) West-East Cross- Sections
Figures 13 shows that there are many geological structures present in the formations of the Brent
East Group such as tilted heavy faulting which is due to the deposition of the sandstone formation
in the early Jurassic age and creating of the North Viking Graben.
The WOC line gives a clear picture of the layers that are in the aquifer.
The depths of the stratigraphic tops can be found in table 6a.
Fault
Eroded surface

37. Page | 27
5.2.2 Logs Interpretation- Identification of Reservoir Zones
(a) (b)

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(c) (d)
Figure 14: Sections of Interpreted Well Logs for Well a) A4 b) A2 c) N1 and d) N3
The green shadings indicate non-reservoir zones such as shale and micaceous. Red shading
indicates the non-shaly and non- micaceous layers.
T3 are massive sands with very good reservoir characteristics. This is the main oil bearing unit in
the Brent East reservoir. In T2, there are mica-rich sandstones with lower permeability. These
mica-rich sandstones exhibit a high natural radioactivity. Ness 2 formation is characterized by
numerous intercalations of shale, mudstones, coal and sandstones.
At a depth of about 3,120m, there is an observed deviation of RHOB, NPH curves indicating a
change in formation fluid, thereby confirming a WOC. This value conforms to 3,231m stated in
the given data.
In N1, the resistivity and density is almost constant. Since it is below the identified WOC, it can
thus be concluded that this formation is an aquifer. Hence it does not contribute to the OIIP
estimate.

39. Page | 29
Ness 1 unit has poorer petrophysical characteristics than Ness 2 unit and its oil-bearing leg is much
lower especially to the East of the reservoir.
No GOC was observed.
5.2.3 Resistivity and Saturation of Formation Water in the Aquifer (Formation N1)
In the water region, the saturation is assumed to be 1 as it the region was majorly water. Using
equation (8), the resistivity of water in the aquifer was estimated as 0.126. See Appendix II for
detailed calculations.
The average resistivity and saturation values for all zones are listed in the attached excel file in
Appendix III.
5.3 Validation of Fluid Contacts
Figure 15: Pressure gradient curve for wells A4 and N3
The pressure- gradient curves of wells A4 and N3 indicated a change in gradient. The region with
the higher gradient of 17.11bar/m is the oil and the lower gradient of 9.32 bar/m indicates water.
WOC

40. Page | 30
The pressure gradient changes at a depth of about 3,232.5m which indicates the WOC. The WOC
depth is approximately equal ad hence validate the WOC obtained from logs.
5.4 Petrophysical Properties and Net to Gross Ratio
Table 6a: Petrophysical Properties (Porosity, Saturation, N/G, Stratigraphic Tops)
The table above shows some of the results obtained from the well to well correlations exercise: the
top of the bed layers to be precise. In all the wells, T3 have the highest reservoir thickness with
good petrophysical characteristics i.e. high porosity (between 22.59 – 26 p.u) and highest oil
saturation. This makes it the bed with the highest oil leg. This is due to its high permeability as
indicated by the permeability data.
Because N1 is an aquifer with no reservoir, its thickness does not contribute to the overall
estimation of OIIP. Its water however will provide natural drive that will be useful during
production.

41. Page | 31
Table 6b: Petrophysical Properties (Absolute Permeability)
Table 6b shows the average permeability for each layer. The permeabilities range from 50-2600
mD. T3 and N2 showed similar permeability. T2 and T1 have equal lower permeability of 50 mD
mainly due to the presence of micaceous sandstones. The base of T2 and top of T3 has similar
permeability of 300mD. Despite its lower average permeability, T2 unit is not considered as a
permeability barrier.
5.5 GRV Estimation
1) Minimum Case
(a) (b)
Figure 16: Minimum case depth-area plot a) non-eroded zone and b) eroded zone

42. Page | 32
Table 7: Summary of Minimum GRV
Sand Sand GRV Total Sand GRV
Non- Eroded Eroded
T3 160,000,000 7,200,000 167,200,000
T2 16,000,000 3,600,000 19,600,000
T1 0 0 0
N2 48,000,000 31,200,000 79,200,000
Total Minimum GRV 266,000,000
2) Average Case
(a) (b)
Figure 17: Average case depth-area plot a) non-eroded zone and b) eroded zone

43. Page | 33
Table 8: Summary of Average GRV
Sand Sand GRV Total Sand GRV
Non- Eroded Eroded
T3 194,500,000 206,500,000 206,500,000
T2 18,000,000 27,800,000 27,800,000
T1 7,000,000 11,800,000 11,800,000
N2 17,000,000 69,000,000 69,000,000
Total Average GRV 315,100,000
3) Maximum Case
(a) (b)
Figure 18: Maximum case depth-area plot a) non-eroded zone and b) eroded zone
Table 9: Maximum GRV
Sand Sand GRV Total Sand GRV
Non- Eroded Eroded
T3 220,000,000 11,200,000 191,200,000
T2 40,000,000 16,000,000 44,000,000
T1 12,000,000 12,800,000 20,800,000
N2 4,000,000 59,200,000 63,200,000
Total Maximum GRV 319,200,000

44. Page | 34
Figures 16 – 18 gives a clear picture of formations that have some of its thickness below the WOC.
In all cases, T3 was above the WOC. The GRV was calculated only for the parts of the reservoir
above the WOC.
Again, T3 has the highest GRV due to it having the highest bed thickness above WOC.
5.6 PVT Selection- Formation Volume factor, Bo
The composite Bo was calculated are 1.6614 and 1.5 for well N3 (See Appendix I for detailed
calculation). The variation in their results is due mainly to the variation in the conditions under
which the experiments were conducted. Table 10 contains the major differences between each
study that may have contributed to the differences in the composite Bo..
Table 10: Differences in the PVT Study for Wells A4 and N3
S/N Well A4 Well N3
1 Study was conducted in 1980 Study was conducted in 1987
2 Three-stage process condition
separation test was conducted.
Two-stage process condition separation
test was conducted.
The composite Bo was chosen for the calculation of the OIIP due to the following reasons:
1. Because well A4 was drilled before N3, the PVT result gives more representation of the
reservoir oil in its original state.
2. 3-stage separation gives better separation than the two stage separation. hence, a better
value of Bo.
5.7 Estimation of HCIIP Including Uncertainties
1) Minimum Case (P10)
Table 11: Summary of Results (Minimum Case)

45. Page | 35
2) Average Case (P50)
Table 12: Summary of Results (Average Case)
3) Maximum Case (P90)
Table 13: Summary of Results (Maximum Case)

46. Page | 36
6 CONCLUSION
HCIIP estimation is the cornerstone of and exploration and production process. Before effective
developmental decisions can be made, it is necessary that uncertainties in estimating the HCIIP
are taken into consideration at every step of the process.
The Volumetric method was used to estimate the HCIIP for Alwyn North field. Five parameters
were obtained namely:
1) Gross rock volume obtained from DAT data and well fluid contacts
2) Net to Gross obtained from well logs
3) Porosity obtained from well logs
4) Oil/Gas saturation obtained from well logs and
5) FVF obtained from PVT analyses
To account for uncertainties in estimating the reserve, three cases were considered;
1) Minimum case (P10)- lowest OIIP
2) Average case(P50)- average OIIP
3) Maximum case (P90)- highest OIIP
The following conclusions were drawn during and after estimating HCIIP;
1) Alwyn North field Brent East is an oil field with no gas cap.
2) The geological structures showed the presence of two faults and some tilted folds.
3) The WOC was consistent at about 3,231m showing that the reservoir is continuous and
connected and there is a high likelihood that the faults are non-sealing.
4) Tarbert 3 has the highest reservoir thickness with the best reservoir petrophysical
characteristics (permeability, oil saturation and porosity) making it the most contributor
to the estimated reserve. Tarbert 2 has a lot of mica embedded in its sandstones. All the
wells had about the same WOC Ness 1 was in the aquifer zone and could not be produced
from.
5) The OIIP of the field was found to be :
Minimum case = 19,253,824.44 m3
Average case = 31,421,555.11 m3
Maximum case = 39,837,677.39 m3

47. Page | 37
T3 is the largest contributor to the OIIP in the field due to its high porosity, high reservoir
thickness and low water saturations.

48. Page | 38
REFERENCES
1) http://www.spe.org/index.php
2) Owil N (2018): Lecture Note: Hydrocarbon‐ In‐ Place Estimation. March 5‐ 9, 2018 –
IPS

49. Page | 39
APPENDIX
Appendix I: Resistivity and Saturation of Formation Water in the Aquifer (N1)
In the water zone Sw= 1 (obtained from logs), Rt = 4Ωm, up.16 , m =2, n =1,
a =0.81
Assuming the sandstones is clean,
From equation (8), mw
w
a
R
R 
2
16.0
81.0
4
x 126.0
Appendix II: Calculation of FVF
𝐵𝑜𝑐 =
𝑉(𝑃)
𝑉(𝑃𝑠𝑎𝑡)
× 𝐵𝑜𝑝( 𝑃𝑠𝑎𝑡) (16)
𝐵𝑜𝑝 =
𝑉𝑜
𝑉𝑠𝑐
=
𝑉(𝑃)
𝑉𝑠𝑎𝑡
×
𝑉𝑠𝑎𝑡
𝑉𝑠𝑐
(19)
For well A4 @ reservoir conditions (112.1℃ and 445.4 bar(g))
𝐵𝑜𝑝( 𝑃𝑠𝑎𝑡) = 1.711
𝑉𝑜
𝑉𝑠𝑎𝑡
= 0.9571
𝐵𝑜𝑐 = 0.9571 × 1.711
= 1.6376
For well N3 @ reservoir conditions (111℃ and 445 bar(g))
𝐵𝑜𝑝( 𝑃𝑠𝑎𝑡) = 1.664
𝑉𝑜
𝑉𝑠𝑎𝑡
= 0.955
𝐵𝑜𝑐 = 0.955 × 1.664
= 1.589
Appendix III: Data Sheets Obtained During Calculation
1. Excel Spreadsheet (HCIIP Estimation)
2. Well-to-Well Correlation

50. Page | 40
Table 14: Well to Well Correlation Data Sheet a) North- South b) West- East
(a)
(b)
3. Depth-Area Data
Table 15: Depth-Area Data Sheet a) Non-eroded b) Eroded

51. Page | 41
a)
b)
4. Petrophysical Properties Data Sheet
Table 16: Petrophysical Properties Data Sheet

52. Page | 42