2. Contents
1. Summary................................................................................................................................5
2. Introduction ............................................................................................................................6
2.1 Objectives ........................................................................................................................6
2.2 Given Data .......................................................................................................................7
3. PETROLEUM GEOSCIENCE ...........................................................................................8
3.1 Location of the Field....................................................................................................8
3.2 Reservoir Properties ......................................................................................................10
3.2.1 Structural Properties ...............................................................................................10
3.2.2 Petrophysical Properties .........................................................................................11
Table 3: Reservoir conditions are given as follows .........................................................12
3.2.3 Real Field Example - Brent Field, Northern North Sea, UK ...................................13
3.2.3 Deposition Environment - Stratigraphy & Facies of the field..................................15
3.5 Petroleum System.....................................................................................................19
3.5.1 Reservoir Rocks......................................................................................................19
3.5.2 Source Rocks..........................................................................................................19
3.5.3 Traps & Seal Potential ............................................................................................20
3.6 Limitations and Risks Associated With the Field......................................................20
4. Reservoir Modelling and Simulation....................................................................................21
4.1 Static Model Construction .........................................................................................21
4.2 Dynamic Model Construction ....................................................................................23
4.2.1 Fluid Model the Field...............................................................................................26
4.2.2 Petrophysical properties of the rock .......................................................................27
4.2.3 Aquifer Support .......................................................................................................30
4.3 Distribution of the Properties .........................................................................................31
4.4 Production profiles ...................................................................................................34
4.5 Wells..........................................................................................................................36
4.5.1 Well Numbers and Production Strategy .....................................................................36
4.5.2 Well Location and Type ..............................................................................................37
4.6 SENSITIVITY ANALYSIS..........................................................................................37
4.6.1 Transmissibility........................................................................................................37
5. Drilling and Well Completion ...............................................................................................38
3. 5.1 Drilling facilities ..............................................................................................................38
5.2 Drilling Planning and well completion............................................................................39
5.3 Well Location.............................................................................................................40
5.4 Casing and Tubing Designing...................................................................................41
5.4.1 Tubing Calculation.................................................................................................45
5.4.2 Casing Calculation.................................................................................................45
5.4.2.1 Conductor Casing Section.................................................................................47
5.4.2.2 Surface Casing Section .....................................................................................49
5.4.2.3 Intermediate 1 Casing Section ..........................................................................50
5.4.2.4 Intermediate 2 Casing Section ..........................................................................51
5.4.2.5 Production Casing Section ................................................................................52
5.5 Drilling Fluids..................................................................................................................54
5.5.1 Drilling Fluids for Conductor casing Section ..............................................................55
5.5.2 Drilling Fluids for Surface casing Section...................................................................55
5.5.3 Drilling Fluids for Intermediate 1 casing Section........................................................56
5.5.4 Drilling Fluids for Intermediate 2 casing Section........................................................56
5.5.5 Drilling Fluids for Production casing Section..............................................................56
6. Well Production Optimisation ..............................................................................................57
6.1 Well Modelling (PROSPER)......................................................................................57
6.1.1 Well Deliverability....................................................................................................57
6.2 Inflow Performance Relation (IPR) Curve ................................................................58
6.3 Optimum Well Flow Rate...............................................................................................59
6.4 Sensitivity Analysis....................................................................................................60
6.4.1 Sensitivity Analysis on Reservoir Pressure......................................................60
6.4.2 Sensitivity Analysis on Gas Oil ratio..................................................................61
6.4.3 Sensitivity Analysis on water cut .......................................................................62
6.5 GAP Model ................................................................................................................63
7. Surface Production Facilities...............................................................................................63
7.1 Production Fluid Separation Operations..................................................................64
7.2 Oil Treatment.............................................................................................................65
7.3 Gas Treatment ..........................................................................................................65
7.4 Water Treatment .......................................................................................................65
4. 7.5 HYSYS Simulation ....................................................................................................66
7.6.1 Base Case...............................................................................................................68
7.6.2 Mass balance ..........................................................................................................69
8. Economics ...........................................................................................................................72
8.1 Financial System.......................................................................................................72
8.2 Production Forecast ..................................................................................................72
8.3 Capital Expenditure (CAPEX)........................................................................................74
8.4 Operating Expenditure (OPEX).................................................................................76
8.5 Revenue and Cash Flow...........................................................................................78
8.6 Net Present Value (NPV) ...........................................................................................80
8.7 Payback......................................................................................................................82
8.8 Internal Rate of Return...............................................................................................83
8.9Sensitivity Analysis......................................................................................................84
87
8.9.1 Economic Justification.............................................................................................87
9. Health, Safety and Environment Impact .............................................................................87
9.1 Health and Safety Overview .....................................................................................87
9.2 Drill Cuttings Disposal....................................................................................................88
9.3 Containment of Spills of Contaminated Fluids..........................................................88
9.4 Environmental Conservation.....................................................................................90
9.4.2 Emissions Control ...................................................................................................90
10. Abandonment/Decommissioning..................................................................................90
10.1 Environment Impact Mitigation ....................................................................................90
11.References .........................................................................................................................91
12. Appendix............................................................................................................................93
13. Minutes of Meeting Group 06 for Field Development .......................................................98
5. 1. Summary
The aim of this project was to evaluate and propose the best development plan for the given
simulated field by managing and optimizing a shallow oilfield that is located Offshore using
the given data. A 3D static model for the simulated oilfield was given for the purpose of
interpretation and based on that interpretation the best plan is chosen keeping in mind all
the pros and cons necessary in the development of an oilfield. The location of the field was
concluded keeping in mind all the geological structures from the given data such has folding
and faulting that was seen on the model created using the Petrel suite and also using the
given petrophysical properties like porosity, permeability and net to gross values.
Considering all these given properties, the North Sea was chosen as the location of the field
and the real field example was chosen as Brent Oil Field. The formations that are playing
active in producing and containing the hydrocarbons in the area are all the formations
present in the Brent Group. There are excessive geological structures present in the
formations of the Brent Group like 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
model created in petrel is therefore considered to have a major lithology of sandstone, of
the Brent Group the depositional environment for the field is therefore understood to be a
combination of several energy fronts of a northward prograding marine delta fan. The
Kimmeridge is an important formation to discuss as it holds the major portion of the trapped
hydrocarbons in the Brent area. The Shales present in this formation are acting as a source
rock for the emergence of the petroleum system as overall and the tilted faults blocks are
holding and acting as an impermeable layer to stop the further movement of these
hydrocarbons. Considering the maximum, minimum and mean values for the porosity,
permeability and net to gross, the petrophysical properties for all the points for the given
simulated field were interpreted which shows that the field has a high potential to act as a
good reservoir along with the given major faults. Form the interpretation of the given model
using all the provided data and software suites the volume of oil was predicted as 373
MMSTB within the reservoir, furthermore deeper testing is recommended by all the team
members in order to obtain the total volume of the recoverable oil reserves due to the
uncertainty and compartmentalisation of the reservoir which is mainly due to the presence
of excessive folding and faulting.
At the end of the PETREL reservoir simulation, the oil and gas in place were estimated to be
373E6 STB and 153949 MSCF respectively. At the end of 20 years, 30% of the oil will have
been recovered. Sensitivity analysis was carried out on the transmissibility factor to really
ascertain the nature of the fault. After production, HYSYS simulation software was used to
perform simulation on how the produced fluids will be separated and treated before
exporting them, so as to meet the specifications for metering and or export.
A fixed steel jacketed platform was selected after taking into account all economic and
technical constraints and the depth of sea water, casing will have two section of
6. intermediate and production casing in order to reach depth of 6600 ft. Drill string and mud
fluids used were designed in a such a way that to avoid burst and collapse of wellbore.
PROSPER is used to check effect of water cut, gas oil ratio and pressure on production of
oilfield. Sensitivity analysis is carried out on these factors. Also gap was used to calculate
total production per day of the oil field, pressure and temperature at the surface separator.
Some few development plans were considered for the development of oil Field by compare
their recovery factors. Finally, to develop the oil field with 8 vertical producer wells and two
injections well was chosen. This is due to positive outcomes of important factors such as
NPV, IRR, and payback period etc.
2. Introduction
2.1 Objectives
The purpose of this group project is to make a full comprehensive field development plan
which will include all the previous knowledge of geology and geophysics for the
interpretation and information about the location of the reservoir and its properties, the
concepts of drilling and production engineering, the overall economics of the project and the
best outcome plan for the project.
To use different process and steps in Petrel (RE - G&G), PROSPER, GAP and HYSYS according
to the required information to devise a field strategy development plan for the hydrocarbon
field, to conclude the geological settings for the development and to include an economic
analysis with reference to environmental conditions.
To get the information about the hydrocarbons in place, the surface facilities that will be
required for the processing of the crude produced, the cost of development of the field and
also if required what will the required facilities costs. To obtain the highest production rate
and recovery factor with the minimum cost for the processing and extraction for the
hydrocarbons. Staying within the limited values assigned for the project like for instance
water cut. To achieve the required and planned production rate from each well for the
number of years using the best recovery method available after investigating the reservoir
properties and to keep the cost for the project to minimum.
The given field that is a three dimensional model for an unspecified reservoir with an
unknown location requires interpretation for the development and expansion of the field. To
define the location of the field, we use the regional geological data and based on this data
we compared it with the real field example. With the help of regional structural geology and
knowing that the field is offshore and in the North Sea all the nearby field were considered in
defining the simulated field with the real field. Using these strategies any uncertainties that
may are involved in the identification of the location of the simulated field and any
conclusion before moving on the next stages in the field development.
Other objective was to use the given number of wells including production and injectors by
considering the overall economies of the field and on bases of that to identify if vertical wells
are sufficient or horizontal wells are also to be considered. Produce the production profile
for the optimum well configuration with respect to the given recovery factor, this could be
7. achieve keeping the constraints agreed by the Exploration & Production Oil & Gas Company.
For the reservoir analysis the IMP suite should be used mainly GAP & PROSPER whereas for
handling, processing and exportation of the hydrocarbons produced will selected using
HYSYS.
The final objective of the report includes the overall economic strategy for the development
of the simulated field by determining the best option for the recovery factor without
compromising the important equipment’s that are required for the development of the field
to maximize the profits for the company. For this part of the report the Microsoft Excel suite
will be used to show the results and suggest the best feasible strategy for the development
of the simulated field.
2.2 Given Data
The simulated field comprises of a static reservoir model with the grid size of 21x52x10 grid
cells yielding a total of 10920 active cells which are to be build based on the given
parameters for certain formations and fluid parameters using the Petrel suite. The purpose
for using this suite is to obtain the total volume of the hydrocarbons in place. Other
parameters like porosity, permeability and Net to gross are also given which are included in
the relevant part of this report in terms of tables and figures. Rock compaction, reservoir
properties, and fluid properties were also given.
For the field development the relevant data was given including the number of producer
wells that are capped at 10 and there with the maximum two injector wells to be used in
order to achieve the target production for the simulated field. The maximum production
capacity of each well is given as 5000 STB/day.
For economics the given data includes the sales price for oil to be USD$75/barrel and water
treatment is $4.3/barrel. The cost of drilling a well is USD$29 million with operational cost
per day for each well forecasted is USD$10,000/day.
8. 3. PETROLEUM GEOSCIENCE
3.1 Location of the Field
The location of the given field is in the Northern North Sea that is the Viking Graben
Provence with the near juxtaposition to the Shetland Isles in the UK. Other nearby fields that
are prominent includes the Don Field and Thistle Field. According to the excessive faulting
that can be seen in the area under study, all this structural activity had been taken place in
the late Jurassic period beneath the formation of Viking Graben which is among the three
rifts that are linked in the North Sea region that was formed with in this period. Moreover
few factors were also considered in defining the location of the field that is the matching API
gravity of 38° of the given field with the Brent crude and also the resemblance of regional
geological data available.
Figure 1: showing the location and regional geological setting of the simulated field
9. Figure 1 (A) shows the timing of major structural events with respect to deposition of the
Brent Group. Figure 1(B) shows the regional setting of the simulated field and the position of
above lying Triassic rift basins and major faults that were active in the deposition of the
Brent deposition. Figure 1(C) shows the area of the Brent Group in the present day faults and
well locations on Brent top depth map.
Figure 2: showing the normal and thrust faulting in the North Sea
The above figure shows the series of normal and reverse-thrust faulting in the area of
northern Sea UK in which the simulated field is present and also shows the geological
differences and boundaries with in the area. Considering the development and analysing the
model we created using Petrel of the simulated field, there were few assumptions made in
order to define the reservoir geology which includes mainly lithology. Keeping in mind all the
given background information about the simulated field which includes that the field was
developed in the shallow marine environment (discussed with more detail in depositional
environment section). When interpreting the model in Petrel, the main feather seen to
identify is the substantial faulting which is primarily normal faulting which means that
hanging wall has moved in the downwards direction with respect to the footwall of the fault.
There are three major faults that can be seen on the model that are intersecting parallel to
10. one and other in the NW-SE direction. The largest fault intersects across the full length of the
given model. Due to three major faults and number of minor faults and considering the
geological structure and history of the Northern North Sea it is certain that the area has
horst and graben structure which means that there are number of normal and
reverse/thrust faults on small scale besides these three major faults in the area of interest.
Figure 3: Top surface grid with horizons showing three major faults
3.2 Reservoir Properties
3.2.1 Structural Properties
The reservoir produced from the available data set is a heterogeneous reservoir and has an
elongated shape in the N-S direction. The reservoir is divided into two zones which give a
better understanding of the presence of major faults present. There are three major faults
11. among which two are elongated in SE-NW direction (South Trending) and one in N-S
direction (North Trending) with an aquifer in the north side. There are number of folding
structures also present and some of the extensive folding and fracturing is also present along
the fault boundary which suggests that these faults can be strike slip faults. The huge
amount of folding present along the faults is in both north and south of the reservoir. The
two zones of the reservoir! That is the upper and lower zone, both contrasts with depth and
horizontal extension of the formations forming the reservoir. A pinch out structure can also
be seen in the very upper most part of the reservoir where the formations extension is
ended in a point shape south direction. The maximum depth of the reservoir is (6500ft –
6600ft) & 400ft (depth of the offshore water).
3.2.2 Petrophysical Properties
The porosity and permeability values show the heterogeneity as the reservoir itself. The
values of porosity are between 2-37 % and the values of permeability lies between 50-
700mD with the mean value of 21% & 350mD for both porosity and permeability
respectively. As it can be seen from the reservoir that the values for the porosity and
permeability are higher where the contours are closing in the figure. The close values for the
contours on the figure shows the elevated are inside the reservoir and where the values are
high contours are far apart from each other which show the low values for porosity and
permeability. The two major faults that are both SE-NW originates from the area in the
reservoir where the values of porosity and permeability are lower than the surrounding. But
both of these faults terminate in the high porosity & permeability zone. The area where the
faults are present in the reservoir has surely provided a restriction to the flow for the
hydrocarbon and therefore the value of transmissibility in there is lesser then unity and by
this fact it’s obvious that the trapping here is due to structural. All the traps are structural so
there is excessive series of folding and faulting in the area and this also suggests that there
can also be major chances for the horst and graben structures (series of normal and thrust
faulting) to be present. The water-oil contact is present at the depth of 6660ft and the API
value for oil is 38 which mean that this crude oil lies between the categories of light crude
oil.
12. Figure 4:surfaces shows High and low porosity and permeability area.
Table 1: Data for porosity, Permeability and Net to Gross
Table 2: Reservoir fluid properties are given as follows
Table 3: Reservoir conditions are given as follows
13. 3.2.3 Real Field Example - Brent Field, Northern North Sea, UK
Figure 5: showing the Brent Field location and its summary
After careful discussions between all the team members of our group and considering all the
available data provided for the simulated field including all the petrophysical properties like
porosity, permeability, transmissibility and also the geoscience related terms such as folding,
faulting and structure of the reservoir under study plus the petroleum engineering terms as
14. the values of API gravity and geographical location of the field that is North sea, Offshore
have resulted that the Brent Field in the north sea, is a probable real example for this given
simulated field. According the table below the values provided in the given data suggests
that given simulated field lies probably in the point III in the table which is the top of Ness
formation and base of Tarbert formation. So in conclusion and considering all the above
mentioned factors the Brent Field has been chosen as a practical field example to study this
simulated field in more detail
Figure 6: Comparison of the geological features between the Real Field Example and Model
15. Figure 7:
Comparis
on of
Petrophys
ical
properties
of the
Real Field
with the
Simulated
Field
3.2.3 Deposition Environment - Stratigraphy & Facies of the field
Economically, the Brent Group is geologically the most active succession in the North Sea.
Most of the hydrocarbon reserves lie in the Middle Jurassic sandstones of this group which
are mainly trapped mainly due to extensive folding and faulting in the area. After excusive
research work done by (Brown et al. 1987; Graue et al. 1987) the Brent Group has been refer
to as regressive- transgression wedge. The Northward prograding regressive part is usually
considered as the following formation that are Broom, Rannoch, Etive and Ness (Probably
Lower Ness) and the succeeding Ness formation and Tarbert formation has been deposited
during retreat of the system in rise of the relative sea level during that time.
16. Figure 8: Sequence Stratigraphy of the Brent Group with respect to all formations
The above figure shows the lateral extension of the Brent Group in the southwest-northeast
direction, showing the different formations present in the Brent Group and their possible
interpretation
Figure 9: Reservoir distribution on the surface generated on Petrel Suite
17. The Brent Group consists of five formations which are Broom, Rannoch, Etive, Ness and
Tarbert Formation. On the upper boundary the Oseberg formation is defined as the part of
Brent Group, furthermore the upper boundary is the Heather formation which consists of
mudstones of the Viking Group that are forming the regional seal for this group. The lower
boundary is mainly silts and mudstones of the Dunlin Group. The recognizable regional
location of the Brent Group originates from within the East Shetland Platform and the
northern part of the Horda Platform. At south of the Frigg area, the comparable
stratigraphical sequence of the Brent Group are termed as Vestland Group. In the north the
deltaic rocks of the Brent shale’s are the marine mudstones. There is a considerable variation
in the group’s thickness which is due to unconformable subsidence and late to middle
Jurassic faulting and erosion, this effect of erosion can be seen as near the crests of the
rotating fault block there is areas of no deposition at all. The depositional environment of
the Brent Group shows the major deltaic sequence in the south direction and the
subsequent back stepping or backward movement retreat. In the east it consists of mainly
sandstones which have number of fan shaped sand bodies – units that have relatively good
values of porosity and permeability to act as a potential reservoir. The sandstones were
deposited in shallow marine environment in the lower part of the Brent Group which is
overlain by alluvial sands.
Figure 10: showing sequence stratigraphy of Brent Group
18. The Broom Formation lithology is cracked and developed locally. Consisting of shallow
marine, coarse-grained and poorly sorted conglomeratic sandstones and is a continuation for
the regressive sequence of the above Rannoch Formation.
The Rannoch Formation lithology is well-sorted very fine sandstones which show a
coarsening upwards sequence that was deposited in deltaic environment in front of
shoreface sands. The upper boundary is identified by much finer sandstones of the above
lying Etive Formation. The thickness of the Rannoch Formation varies from 30 and 65 m.
The Etive Formation lithology contains less fine sandstones than the underlying Rannoch
Formation. The upper boundary is significantly shale and coal of the above lying Ness
Formation. The depositional environment for the Etive Formation is interpreted as upper
shoreface and can be termed as channel deposits. The thickness for this formation varies
extensively from 10 m to more than 55 m.The Ness Formation lithology consists of mixture
of coals, mudstones, siltstones and fine to medium sandstones. Consists of numerous rootlet
horizons and have a high carbonaceous content present within the formation. The upper
boundary varies from massive to cleaner sandstones of the above lying Tarbert Formation.
The formation is interpreted to have an environment of deposition as deltaic plain or coastal
plain. Siltstone and mudstone present in this formation are acting as a potential seal to the
major reservoirs. The Ness Formation has thickness variations ranging from 25 m to 145 m.
The Tarbert Formation lithology consists of dark grey to light brown sandstones. The base of
the formation is taken at the top of the last fining upward unit of the Ness Formation, which
are either coal shale’s or a coal beds. The environment of deposition for the Tarbert
Formation is marine, mainly marginal marine and the thickness for the formation lies in the
range between 12 m to 50 m.
Figure 11: Depth variations of the Mid Jurassic compared with the elevation depth from the model
19. The Brent Group is located at a wide range of depths this is due to the Upper Jurassic
faulting, uplifting of the blocks resulting in horst and graben structures throughout the area
and also due to the differential subsidence. The above figure shows the variations in depth
for the Brent Group which is also compared with the simulated field produced using Petrel,
varying from 1500 m on one nearby field to more than 3500 m on the other nearby field so
as a result there are lots of complex distribution in this area for the values of porosity and
permeability.
3.5 Petroleum System
Having good production development, the sediments of Brent group have gained excessive
significance in the province. There were more than nine major fields in the Brent Group in
1973 and due to this rapid production rate the province was considered as the 13th
largest
petroleum production province in the world by 1980. Regarding the petroleum system of the
field there are still researches going on regarding the exact time of deposition of strata,
structural evolution, sedimentation, and variation in grain size, compaction and cementation
and also the presence of unconformity. There are also vast variations in the values of
porosity and permeability, which plays and important role in recoverable reserves.
3.5.1 Reservoir Rocks
The Brent Field lies in the East Shetland Basin in the North Sea which includes the tilted fault
blocks that are playing an important role holding the Brent formation besides the boundary
faults. The formation allow the migration from the deeper side by side areas where the
Kimmeridge clay formation becomes fully mature and enrich of hydrocarbons. Due to
number of folding and faulting in this area and also due to juxtaposition of the sand units the
reservoir of this field, the reservoir geology is complex to understand. The back thrust faults
that originate from the reserves faults are the main reason for this juxtaposition of the sand
units in the reservoir. The stratigraphy of the reservoir indicates that the deposition of the
sediments was in a shallow marine to coastal plain environment and the sediments where
deposited in the form of layers and formed beds, the finer grain sediments were deposited
first followed by the medium and then coarser. The complex variations in the values of
porosity and permeability are mainly due to the Bioturbation factor
3.5.2 Source Rocks
The two main source areas for hydrocarbons in the Brent Fields include the Viking Graben
and the East Shetland Basin. As discussed in reservoir rock section that Kimmeridge
formation once matured to become enrich in terms of hydrocarbons so the dominant oil
source rock is the Kimmeridge Clay Formation. Furthermore the coals from the Brent and the
Heather formation also have the potential to act as a source rock in this field. Thickness of
Kimmeridge is nearly 480 m in the East Shetland Basin and its more than 1000 m thick in the
20. North Viking Graben. The TOC (total organic carbon) is 5.6 percent to a maximum of 12
percent in the East Shetland Basin and the kyrogen is of type II in majority. One of the most
distinguishing features present in this formation is the presence of fossils.
3.5.3 Traps & Seal Potential
Due to the tilted block faulting and number of normal and back thrust faulting which
resulted into horst and graben structure all over the Brent Field the Statfjord formation and
Brent Group reservoirs have fault bounded, monoclonal structure, dipping 8 degrees to the
west with the truncation in the form of unconformity and traps. The juxtaposition of the
faults of lower Cretaceous mudstones, and these mudstones and marls are also acting as a
seal in this field. The unconformity also plays a critical role and acts as a trapping mechanism
for this field.
Comparing to the other nearby fields in this area the Brent Field structure is much simpler
and is a closure structure (lateral closure) that is provided by an impermeable juxtaposition
of faults in the East West to North West direction. Trap was formed in the Mid Cretaceous
age before the migration of oil in the structure in the Eocene age.
3.6 Limitations and Risks Associated With the Field
There are number of limitations associated with the development of the field. For the Petrel
model as there was no seismic data given and also for the well logs, so it was difficult to
exactly know the location of the field and to achieve the detailed information about the total
number of faults and there orientation. Making the faults on the model using the Petrel suite
was also individual dependent and can vary from geoscientist to geoscientist. So there are
chances for the misinterpretation of the data given. As the location of the field was offshore
and considering the values for petrophysical properties the location of the field was chosen
and then the simulated field was compared with the real field example and then the area
was identified with lot of folding and faulting usually tiled fault blocks and geological
structures like horst and graben.
With the number of excessive faulting in the area, imprecisions in forecasting the production
rates and recoverable reserves is a limitation, with the interconnectivity between fault
blocks unknown which means there is no link between the faults hydraulics. Furthermore
which fault blocked moved and acted as an impermeable layer to resist the further flow of
the hydrocarbons is also a limitation of the project. The Petrel model helps to give the fault
probable location, but gives a little info into regarding the faults that either they are sealing
or active by which the permeability across the faults is also a limitation, conducting deeper
analysis is a must do approach in order to understand the reservoir characteristics in more
detail.
As with all model elements the results can never be considered as absolute accurate but
transmissibility analysis may be carried out in order to overcome these limitations or by
21. doing it an estimate can be made for these limitations. With the help of seismic section that
has been done on the field prior to the development of the field, the breaks in the seismic
reflections on each line are referred to as an area where there is a fault present. So as a
result of these variations in the values of velocity, amplitude and acoustic impedance
confirms the exact location of the faults which later by further analysis can also give
information about the transmissibility of the faults present in the area of interest.
Furthermore fractures and small faults are often not covered by the seismic entirely so
deeper studies are required for understanding the reservoir characteristics in more detail.
With this level of uncertainty due to the geoscience, the development of the field may be
considered as a potential risk with potentially limited recoverable reserves due to the Field
compartmentalisation. Even without consideration of the geology, there will be an essential
inaccuracy due to nature of using models, as models are based on assumptions used to
interpose. Contrariwise, excessive faulting may also advance the production opportunities of
the field as faulting can also increase the permeability of the reservoir, providing links
through fractures of lowered resistance for the channel of hydrocarbons. By accompanying
additional well tests on the Field more statistics can be gather round about the effective
volume of the reservoir.
4. Reservoir Modelling and Simulation
4.1 Static Model Construction
In order to construction the static model of our oil field, we have to show the structure of
the field by construct a grid model from the given properties.. For this project, our team
were already given the seismic and exploration data as shown in Figure below. The static
model consist of 3256 active cells with dimensions of 21 x 52 x 10 cells in the X, Y and Z
directions respectively. The model also includes some faults which were not juxtaposing in
nature. Figure12 and 13 shows the static model with horizons and layers
23. Figure 14 final simulated field
4.2 Dynamic Model Construction
.
Figures 15, 16 and 17 shows the three best cases are which are viable on the given
conditions. Figure 15 shows the development strategy with one lateral well but it got risk
involved in it i.e. uncertainty to fault extension. Hence in future well test can be performed
and lateral well can be drilled. Figure 16 and 17 show the development strategy with 8
producers and 2 injectors, both the cases are viable but the best amount of oil is
recovered by the case which is shown in figure 17. Hence the case shown in figure in 17
was chosen
25. Figure 16: case with 8 producers and 2 injectors
Figure 17: Top Surface with wells (The chosen case)
26. 4.2.1 Fluid Model the Field
A “black oil” model with three phases ( oil, gas and water ) were used to construct the fluid
model. The summary of the fluid properties that were used to create the fluid model are
shown in the table 4 below .After that we generated a graph of oil formation volume factor
versus pressure by PETREL is shown in figure 18 below.
Properties Value
Reference Pressure 3950 psi
Maximum pressure 5076 psi
Minimum Pressure 1160 psi
Bubble point pressure 1800 psi
Reservoir temperature 170
Gas gravity 0.6636 sg air
Gas- Oil ratio 412.4 SCF/STB
Oil gravity 38° API
Water salinity 30000 ppm
Water compressibility 1e-5 1/psi
Datum depth 6660
Water formation volume factor 2e9 ft3
Table 4: summary of the fluid properties
Figure 18: Oil Formation volume factor versus pressure
27. 4.2.2 Petrophysical properties of the rock
Water and oil saturation, relative permeability, capillary pressure etc. are some of the
physical properties of the rock in our oil field. The relation between relative permeability
with for oil-water and gas are shown in the Figures 19 and 120 respectively.
Table 5: Oil-Water Relative Permeability
Sw Krw Kro
0.21 0 0.9
0.23 0 0.8101
0.3 0.0002 0.5427
0.37 0.0031 0.3417
0.44 0.0158 0.1978
0.51 0.05 0.1013
0.58 0.1221 0.0427
0.65 0.2531 0.0127
0.72 0.4689 0.0016
0.79 0.8 0
1 1 0
Table 6: Gas-Oil Relative Permeabilities
Sg Krg Kro
0 0 0.9
0.05 0 0.6867
0.1163 0 0.4601
0.1825 0.0002 0.2897
0.2488 0.0022 0.1677
0.315 0.0125 0.0858
0.3813 0.0477 0.0362
0.4475 0.1424 0.0107
0.5312 0.359 0.0013
0.58 0.8 0
0.79 0.9 0
As the relative water saturation is one, which means that water is wetting phase and it
displaces oil forming it a non-wetting phase. As water displaces oil which means rock is
water wet, hence water flooding is a possible option.
28. Figure 28: oil water relative permeability
Figure 19: oil water relative permeability curve
29. Figure 20 : Rock pressure
Figure 21: Gas saturation
30. 4.2.3 Aquifer Support
According to the aquifer data given in the project specification, an active aquifer was
connected at the north end of the Field to provide the reservoir with adequate pressure
maintenance. The aquifer provides pressure support to the reservoir from the edges. Table 7
below shows the given aquifer data as an initial estimate of the aquifer strength.
Datum
Volume 2e9 ft3
Compressibility 1e-5 1/psi
Productivity Index 50 STB/psi/day
Table 7: initial estimate of the aquifer strength.
The figure below shows a static model with aquifer and oil .
Figure 22: Static model with Aquifer
Aquifer
31. 4.3 Distribution of the Properties
In order to be able to use the property model distribution function in PETREL, the seed
number of 3256 was given to use in our project. Property distribution is very important in
reservoir simulation because in reality, reservoirs are not homogenous, rather they are
heterogeneous.
Table 8 shows the data for porosity, permeability and net to gross distribution.
Properties Minimum Maximum Mean STD.Deviation Distribution
Porosity 0.0281 0.3759 0.215 0.0625 Normal
Permeability 50.414 700 350 250 Log-normal
Net to Gross 0.2304 0.79 0.4967 0.1309 Normal
Table 8: Property distribution data
Figures below shows a results obtained for the property distribution of the above mentioned
properties.
Figure 23: Static model with porosity distribution
32. Figure 24: Porosity distribution
Figure 25: Static model with Permeability distribution
Figure 26: Permeability distribution
33. Figure 27: Static model with Net to Gross distribution
Figure 28: Net to Gross distribution
34. 4.4 Production profiles
The figure27 shows the production profile of the field for 20 years, which produced
maximum in the beginning with 8 producers and 2 injectors and gradually decreases by the
end of 20years and the total recovered oil in 20years was 30%. Figure28 shows the
production profile with water cut, at the beginning of the production. Water cut is less and
gradually water cut increases with the decrease in production, giving a water cut of 51% at
the end of 20years
Figure 29: oil production profile of the field
Figure 30: oil production and water cut
35. Figure31: water cut of field
Figure 32 shows the cumulative oil productions of field for 20years
Figure 32: cumulative oil productions
36. Figure 33 shows the oil production rate of each well in which new well 4 produces maximum
amount of oil
Figure 33: production profile of each well
4.5 Wells
4.5.1 Well Numbers and Production Strategy
Case Number of
wells
Types of Wells Project life
time in
years
Water
injection
Recovery
factor
1 8 8 vertical 20 Yes 30%
2 6 5 vertical & 1
horizontal
20 Yes 29%
3 8 8 vertical 20 Yes 27%
Table 9: strategies for production
For the given field different development strategies were applied and best three production
strategies were chosen out of it and all three fields are capable of production economically as
well. The best among the three is the first one with maximum recovery of 30%. In future a
well testing can be done to know the extension of the faults and a horizontal well can be
drilled as done in case 2. The case 1 gave best as the NPV value is more when compared
with other two cases. Hence case 1 was chosen
37. 4.5.2 Well Location and Type
The best case among the three cases is case 1 with 8 producing and two injectors are shown
below. The parameters that were considered for selection of wells were the HCPV, STOOIP,
porosity and permeability. The injectors increased the overall recoverable oil by almost 5%.
Figure 33: well location of the field
4.6 SENSITIVITY ANALYSIS
4.6.1 Transmissibility
The transmissibility was carried on the best case and the following results were obtained.
With zero transmissibility i.e. no flow through faults or fault is sealed and the same sensitivity
was carried out with 0.175 and 0.35 and the difference in recovery factor is shown below
Transmissibility Recovery factor
0 30.77%
0.175 31.04%
0.35 31.08%
Table 10: Transmissibility sensitivity
38. 5. Drilling and Well Completion
5.1 Drilling facilities
The only way to get hydrocarbon from the reservoir is to drill wells safely and economically
as possible and to make sure the health and safety regulation are well conducted.
The depth of the oil field reservoir and sea water (120 meter) for Oil field all together is 7260
ft and we are expecting the reservoir to be economically viable for 20 years. Due to the fact
that the oilfield is on offshore, we needed the production facilities to be resistant to sea
condition and very stable in bad weather. Hence we decided to use fixed steel platform even
if the capital cost is very high it’s very cost effective for long lifetime like 20 years and above
and also the ability to drill and complete wells from the platform, this gives possibility of
future intervention when needed. More advantage of using fixed steel platform are
• Stands on steel and concrete legs driven into the sea-bed.
• The structure consists of multiple steel decks above sea level.
• Platforms are manned (require accommodation) or unmanned.
• Fixed platforms are economic in water depths to 500m.
• Cost effective for long lifetime developments (greater than 20 years).
• can act as hubs or production centres for production from neighbouring satellite
fields.
• Wells can be drilled and completed from the platform.
• This gives accessibility to the wells for future intervention needs.
• Fixed platforms are resistant to sea conditions, very stable in bad weather.
.
Figure 35: Fixed steel platform
39. 5.2 Drilling Planning and well completion
After taken into account multiple cases and under serious consideration with Petrel, we
decided to drill eight (8) vertical production wells and two (2) injection wells. This would give
good production recovery about 30% along with economically viable.
For well completion designing, we decided to use perforated casing completions after
considered factors including depth of the reservoir, volume of fluids to be produced, well
location, control of stimulation, pressure control, and wellbore stability. We will have two
sections of intermediate casing. All casing were cemented and finally perforated.
Figure 36: Perforated Casing
Perforated Production
casing
Packer
Tubing
40. 5.3 Well Location
The locations where the wells will be drill mostly depend on the oil saturation of the area.
From the Petrel simulation, as the oil saturation is scattered within the reservoir, we decided
to drill eight production wells and two injection wells in the place where there is high oil
content. The area marked with faults is the place where there is high oil content, as we could
find it in the Petrel simulation model, wells location and direction are shown in the table 9
below,
Wells Wellhead X Wellhead Y MD TVD
Well 1 458218.00 6784656.00 6700.00 6700.00
Well 2 455990.74 6781777.76 6850.00 6850.00
New well 1 458090.44 6785138.13 6700.00 6700.00
New well 2 457489.50 6783018.41 6700.00 6700.00
New well 3 457189.50 6782439.12 6700.00 6700.00
New well 4 456430.18 6782404.50 6700.00 6700.00
New well 5 457794.67 6783946.07 6700.00 6700.00
New well 6 457443.23 6784057.55 6700.00 6700.00
Injector 1 458274.05 6783470.72 6950.00 6950.00
Injector 2 455506.22 6783115.88 6690.00 6690.00
Table 11: well locations and measurements
41. Figure 37: Well locations
5.4 Casing and Tubing Designing
For casing, we have to design a set of casing strings capable of withstanding a variety of
external and internal pressures, thermal loads and loads related to the self-weight of the
casing. These casing strings are subjected to time-dependent corrosion, wear and possibly
fatigue, which down rate their resistance to these loads during their service life.
As the reservoir depth increases, the pore and fracture pressure increases as shown in the
pressure gradient in graph 10 below, for this reason we must have different type of casing
and tube size. The tube and casing size reduced as the depth increases.
Depth (Ft)
Pore
Pressure
(psi)
Fracture
Pressure
(psi)
Density
Pore
(lb/gal)
Density
Fractur
e
(lb/gal)
Safety
Pore
+0.3
Safety
Fracture
-0.3
0 0 0 0.0 0.0 0 0
500 225 338 8.7 13.0 9.0 12.7
1000 450 676 8.7 13.0 9.0 12.7
1500 686 1014 8.8 13.0 9.1 12.7
2000 915 1248 8.8 12.0 9.1 11.7
2500 1170 1560 9.0 12.0 9.3 11.7
3000 1482 2184 9.5 14.0 9.8 13.7
3450 1973 2601 11.0 14.5 11.3 14.2
4000 2288 2912 11.0 14.0 11.3 13.7
4500 2691 3393 11.5 14.5 11.8 14.2
5000 3250 4420 12.5 17.0 12.8 16.7
5500 4290 4862 15.0 17.0 15.3 16.7
5800 4524 5730 15.0 19.0 15.3 18.7
6000 4680 5928 15.0 19.0 15.3 18.7
6100 4758 6027 15.0 19.0 15.3 18.7
6300 4259 5405 13.0 16.5 13.3 16.2
6500 4394 5408 13.0 16.0 13.3 15.7
6600 4462 5491 13.0 16.0 13.3 15.7
6700 4529 5574 13.0 16.0 13.3 15.7
6800 4597 5658 13.0 16.0 13.3 15.7
Table 12: pore and fracture pressure
44. Figure 41: Pressure Gradient Plot
From the Figure 36 above, to drill to a depth of 6800 feet, a 16.2 lb/gal mud density will be
needed. And there are two intermediate casing between 2900 -6300 feet. In this case, we
will have to use surface casing which serves the function of protecting fresh-water aquifers
and to provide pressure integrity even if the aquifer is at the bottom (about 6000 feet). And
a mud density of 10 lb/gal has to be used. At approximately 500 feet, a conductor casing will
be set to protect the wellbore.
For the casing size, this was designed considering a production casing of 6 5/8” plug as
simulated in PETREL. From table above, a 6 5/8 ” plug production casing will require a hole of
6 1/2”. Then a 9 5/8” of diameter and 9 1/2’’ bit plug was selected to drill to the first
intermediate casing depth.
0
1000
2000
3000
4000
5000
6000
7000
8000
4.00 6.00 8.00 10.00 12.00 14.00 16.00 18.00 20.00
Depth(Ft) EMD (ppg)
Pore and Fracture gradient plot
Pore
Gradient
Conductor
Surface
Intermediate 1
Production Casing
D= 6300 - 6660 ft
Intermediate 2
Conductor Casing
D 0 -500 ft
Surface Casing
D = 500 -2900 ft
Intermediate Casing
D = 2900 - 5000
Production
Intermediate Casing
D = 5000 - 6300 ft
45. Casing
(type)
Depth
(ft)
Diameter
(OD in)
Bit size
(in)
EMD (ppg)
Production 6660 - 6300 6 5/8 6 ½ 15
Intermediate 6300 - 5000 9 5/8 9 ½ 16
Intermediate 5000 - 2900 10 ¾ 12 ¼ 13
Surface 2900 - 500 13 3/8 17 ½ 10
Conductor 500 - 0 20 24 or 26 10
Table 14: Casing Section measurements
5.4.1 Tubing Calculation
The tubing diameter can be calculate by using the data in the table and the following formula
below,
Term Value Unit Conversion Unit
IPA 38 ˚
Pwh 600 psi 4 136 854.38 Pa
Pwf 1160 psi 7 997 918.46 Pa
L 6100 ft 1859.28 m
Q 500 stb 680 t/d
Table 15: Values for calculating Tubing Diameter
D = 0.074 (
𝛾𝑙 𝐿
𝑃 𝑤𝑓−𝑃 𝑤ℎ
)
0.5
[
𝑄𝑙 𝐿
𝛾𝑙 𝐿−10(𝑃 𝑤𝑓−𝑃 𝑤ℎ)
]
1/3
× 25.4
And the value of γl = 0.66077739
The calculated value of tubing diameter, D = 4.77909531 inch
5.4.2 Casing Calculation
We need to calculate burst pressure and collapse pressure in order to design casing, as in the
internal pressure and external pressure must be equal.
Burst Pressure
The casing is exposed to burst pressure loading, If the internal pressure is higher than
external, when designing of the casing we must make sure this condition is not happening.,
Burst pressure loading conditions occur during well control operations, casing pressure
integrity tests, pumping operations, and production operations.
46. Collapse Pressure
The casing is subjected to collapse, if the external pressure exceeds internal pressure; such
conditions may exist during cementing operations, trapped fluid expansion, or well
evacuation. This is material's yield strength primary function, and it’s determined by the
yield strength and D/t.
Assumptions made,
Gas density (psi/ft) = 0.1
Design factor (burst) = 1.1
Design Factor (collapse) = 1
Table 16: casing sections size and properties
The effect of collapse pressure, Burst pressure at shoe and at the surface variation can be
calculated seen below,
Collapse Pressure
𝑃 = 𝜌𝑔ℎ
Burst Pressure at shoe
𝐵𝑢𝑟𝑠𝑡 𝑃𝑟𝑒𝑠𝑠𝑢𝑟𝑒 = 𝐼𝑛𝑡𝑒𝑟𝑛𝑎𝑙 𝑃𝑟𝑒𝑠𝑠𝑢𝑟𝑒 − 𝐸𝑥𝑡𝑒𝑟𝑛𝑎𝑙 𝑃𝑟𝑒𝑠𝑠𝑢𝑟𝑒
𝐼𝑛𝑡𝑒𝑟𝑛𝑎𝑙 𝑃𝑟𝑒𝑠𝑠𝑢𝑟𝑒 = 0.052 × (𝜌 + 𝑠𝑎𝑓𝑒𝑡𝑦 𝑚𝑎𝑟𝑔𝑖𝑛) × ℎ
𝐸𝑥𝑡𝑒𝑟𝑛𝑎𝑙 𝑃𝑟𝑒𝑠𝑠𝑢𝑟𝑒 = 𝐵𝑟𝑖𝑛𝑒 𝑃𝑟𝑒𝑠𝑠𝑢𝑟𝑒 𝐺𝑟𝑎𝑑𝑖𝑒𝑛𝑡 × ℎ
Burst Pressure at surface
𝐼𝑛𝑡𝑒𝑟𝑛𝑎𝑙 𝑃𝑟𝑒𝑠𝑠𝑢𝑟𝑒 = 𝐼𝑛𝑗𝑒𝑐𝑡𝑖𝑜𝑛 𝑃𝑟𝑒𝑠𝑠𝑢𝑟𝑒 − (0.1 × ℎ) × 𝑠𝑎𝑓𝑒𝑡𝑦𝑓𝑎𝑐𝑡𝑜𝑟
Conductor Surface Int 1 Int 2 Production
Hole size 24'' 500 17 1/2 '' 2900 12 1/4 '' 5000 9 1/2 '' 6300 6 1/2 '' 6660
Casing Size 20'' 13 3/8 10 3/4 9 5/8 6 5/8
Expected min/max pore press gradient (PPG) 8.65/8.95 9.5/9.8 12.5/12.8 13.0/13.3 13.0/13.3
Expected LOT press grad (PPG) 13 14 17 16.5 18
Mud weight (PPG) 10 10 13 16 15
Conductor Surface Int1 Int2 Production
Casing size 20'' 13.375 10.75 9.625 6 5/8
Setting depth (ft) 500 2900 5000 6300 6660
Pore pressure above 2900 ft 8.65 9.5 12.5 13 13
Mud weight casing to be run 10 10 13 16 15
Depth of next hole 17.5 2900 5000 6200 6660 0
Max pore pressure at botom of 17.5 hole 9.8 12.8 13.3 13.3 0
Frac pressure gradient at 20'' shoe 13 14 17 16.5 0
Expected gas gradient 0.1 0.1 0.1 0.1 0
47. Table 17: casing sections size and other properties
5.4.2.1 Conductor Casing Section
Conductor casing used to prevent cave in of the surface, and the burst and collapse pressure
must be calculate so that the casing used can meet its requirements. The hole size can be big
as 36 inches because as the drilling goes on the hole diameter decreases. Once the
conductor hole is drilled the casing is cemented in it.
Burst
Pore pressure at the bottom of 17.5 =
Max pore pressure at bottom of 17.5 hole * Depth of next hole 17.5*0.052
= 9.8 * 2900 = 1477.84
pressure at surface =
Pore pressure at the bottom of 17.5 8 - (0.1* Depth of next hole 17.5)
= 14477.84 – (0.1 * 2900) = 1187.84
Pressure at 20’’ casing shoe =
Fracture Pressure at 20’’ shoe – ( 0.1 * setting depth,ft)
= 1477.84 – (0.1 *500) = 1427.84
LOT pressure @ 20'' casing shoe =
Expected LOT pressure gradient – (0.0052 * setting depth)
= 13 * 0.052 *500 =338
Max pressure @ surface =
LOT pressure @ 20'' casing shoe – (0.1* setting depth)
= 338 – (0.1 * 500) = 288
Pore pressure @ casing shoe =
Pore pressure above 2900 ft * 0.052 *setting depth
= 8.65 * 0.0052 *500 = 224.9
There is no any external force acting, then External pressure at surface = 0
Collapse
Collapse calculation for conductor casing, external, internal pressure at the surface and at the shoe is
zero (0).
Pore pressure at casing shoe =
Pore pressure above 2900 ft * 0.052 *setting depth
= 8.65 * 0.0052 *500 = 224.9
48. The summary for burst and collapse pressure calculation is shown in the table 15 and 16 below,
Depth External load Internal load Net load Design Load Depth
Conductor 0 288 288 316.8 0
Casing shoe 224.9 338 113.1 124.41 500
Table 18: Burst values
Depth External load Internal load Net load Design Load Depth
Conductor 0 0 0 0 0
Casing shoe 224.9 0 224.9 224.9 500
Table 19: Burst values
Figure 42: Conductor casing Loads
The casing Data sheet which used to approximate the Burst and collapse pressures in the
casing designing with different measurements is shown in the table below
0
100
200
300
400
500
600
0 100 200 300 400
Depth(ft)
Pressure (psi)
Conductor Casing Loads
Collapse
Burst
49. Table 20: Casing Designing Data sheet
5.4.2.2 Surface Casing Section
This part of the casing used to prevent fresh water zone to inter in the drilled well. The hole
size can be up 17 inches in diameter. The depth of surface hole set by regulatory agencies
and they require the surface hole to be drilled by all fresh water zone and surface case to set
and cemented to protect the zone from damage from addition drilling operation. This casing
must be strong enough to support BOP when connected and also to be able to support the
additional casing strings hanging inside it.
Burst and collapse calculations for surface casing section is same as for conductor. And Table
18 and 19 are the summaries for their values after calculations
Depth External load Internal load Net load Design Load Depth
Surface 0 1821.2 1821.2 2003.32 0
Casing
shoe 1432.6 2111.2 678.6 746.46 2900
Table 21: Burst values
Depth External load Internal load Net load Design Load Depth
Surface 0 0 0 0 0
Casing
shoe 1432.6 0 1432.6 1432.6 2900
Table 22: Collapse values
Casing
PE STC LTC BTC STC LTC BTC
Production 65/8 24 J-55 4560 5110 5110 5110 5110 314 340 453 382 0.352 5.921 5.796 0.00858 0.03406
Intermediate2 95/8 43.5 HCL-80 5600 6330 6330 6330 936 1142 1005 0.435 8.755 8.599 0.01553 0.07446
Intermediate1 103/4 51 HCL-80 4460 5860 5860 5860 906 1316 1165 0.45 9.85 9.694 0.01801 0.09425
Surface 133/8 61 J-55 1540 3090 3090 3090 595 1025 962 0.43 12.515 12.359 0.02163 0.15215
Conductor 20 94 H-40 520 1530 1530 1530 581 1041 1077 0.438 19.124 18.936 0.03329 0.35528
I.D.
(inch)
Drift
Diamet
Displac
ement
Capaci
ty
Grade
Collap
se
InternalYieldPressureMinimum JointStrength1000lbs Body
Yield
Wall
(inch)
O.D.
(inch)
Nomin
al
50. Figure 43: Surface casing Loads
5.4.2.3 Intermediate 1 Casing Section
This part sometimes called troublesome formation, can be drill by adjusting drilling fluids,
And once drilled need to be sealed off in order to prevent problems in drilling deeper portion
of the well. The hole of this section must be easily fitted inside the surface casing, and can be
up to 12 inches in diameter. And often it the longest section of the well.
Burst and collapse calculations for this casing section is same as for conductor. And Table 20
and 21 are the summaries for their values after calculations
Depth External load Internal load Net load Design Load Depth
Inter 0 3920 3920 4312 0
Casing shoe 3250 4420 1170 1287 5000
Table 23: Burst values
Depth External load Internal load Net load Design Load Depth
Inter 0 0 0 0 0
Casing shoe 3250 0 3250 3250 5000
Table 24: Collapse values
0
500
1000
1500
2000
2500
3000
3500
0 500 1000 1500 2000 2500
Depth(ft)
Pressure (psi)
Surface Casing Loads
Collapse
Burst
51. Figure 44: Intermediate 1 casing Loads
5.4.2.4 Intermediate 2 Casing Section
We needed to divide two section of intermediate casing because it’s the longest section in
the well and function of this part is same as the intermediate 1 as in is to prevent
troublesome formation, and also can be drill by adjusting drilling fluids, And once drilled
need to be sealed off in order to prevent problems in drilling deeper portion of the well.
Burst and collapse calculations for this casing section is same as for conductor. And Table 22
and 23 are the summaries for their values after calculations
Depth External load Internal load Net load Design Load Depth
Inter 2 0 4775.4 4775.4 5252.94 0
Casing shoe 4258.8 5405.4 1146.6 1261.26 6300
Table 25: Burst values
Depth External load Internal load Net load Design Load Depth
Inter 2 0 0 0 0 0
Casing shoe 4258.8 0 4258.8 4258.8 6300
Table 26: Collapse values
0
1000
2000
3000
4000
5000
6000
0 1000 2000 3000 4000 5000
Depth(ft)
Pressure (psi)
Intermediate 1 Casing Loads
Collapse
Burst
52. Figure 45: Intermediate 2 casing Loads
5.4.2.5 Production Casing Section
The hole size of this section is between 8- 10 inches in diameter. This part of the zone
penetrate the producing zone. Once the production zone is drilled is needed to be protected
and sealed .so the production casing used to isolate the production zone and be ready for
production after perforation.
The calculation for casing burst and collapse pressure at production section is differ from all
other section and mostly depend on if there is liner or not.
Test Perforation depth 6650
Mud weight 13.3
casing shoe 6660
Press @6660 casing shoe 13
Mud weight casing to be run 15
Max pore press @ tops of production zone =
Test perforation depth * Mud weight * 0.052
= 6650 * 13.3 * 0.052 = 4599.14
CITHP at surface =
Max pore press @ tops of production zone – (0.15 * Test perforation depth)
= 4599.14 – (0.15 * 6650) = 3601.64
Pore press at top of liner =
Casing shoe *Press @6660 casing shoe * 0.052
0
1000
2000
3000
4000
5000
6000
7000
0 1000 2000 3000 4000 5000 6000
Depth(ft)
Pressure (psi)
Intermediate 2 Casing Loads
Collapse
Burst
53. = 6660 * 13 * 0.052 = 4502.16
Internal load =
Mud weight casing to be run * casing shoe *0.052
= 15 * 6660 * 0.052 = 5194.8
External pressure = 0 (there is no external force act on it)
Depth External load Internal load Net load Design Load Depth
Surface 0 3601.64 3601.64 3961.8 0
TOL 4502.16 6233.76 1731.6 1904.76 6000
Table 27: Burst values
Depth External load Internal load Net load Design Load Depth
surface 0 0 0 0 0
TOL 4502.16 0 4502.16 4502.16 6000
Table 28: Collapse values
Figure 46: Production casing Loads
0
1000
2000
3000
4000
5000
6000
7000
0 1000 2000 3000 4000 5000
Dpeth(ft)
Pressure (psi)
Production Casing Loads
burst
collapse
54. 5.5 Drilling Fluids
In order to satisfy various regulatory and environmental standards, as well as achieve the
highest performance and function, drilling mud usually serves many functions including,
Cleaning the hole, this allow the drilling bit to drill to uncut formation in the hole
Lifting cuttings to the surface
Cooling and lubricate drilling string
Carrying information about formations
Stabilizing wellbore by forming mud cake and prevent the hole walls
Control formation pressure
Suspending the cuttings
Drilling fluids have a huge impact on drilling performance from controlling wellbore stability,
allowing high penetration rates, preventing premature failure and enabling high angle and
extended reach wells to be drilled.
Technical requirements and local availability of the drilling fluid products are some of the
factors determine the type of the mud fluid to be used for drilling a well. In this project,
water based fluids (WBF) for well stability and temperature stability. Due pressure variation
in the well, types of drilling fluids used differ depend on the casing section.
The amount of the mud fluid needed are calculated by using safety factor and the volume of
the drilling string used. Our safety factor for this project is 4.
Table below summarizes the measurements, components and mud used in every part of the
casing for this project.
Table 29: Casing Properties and safety factor values
Calculation;
Radius (inch) = Bit size /2
Volume (ft3) = 𝜋 × 𝑟2
× 𝐻
Ft3 to BBL = V × (1/𝑟2
) × (1/5.615)
Safety Factor = V in bbl × 4
Total safety = ∑ of safety factor of the area
Casing ρMud Bit Size Radius(inch)Height(ft) Volume(ft3
) bbl Mud Density Safetyfactor Totalsafety
Conductor 10 24 12 500 226194.671 279.750014 WBM 10 1119.00 1119.00005
Surface 10 171/2 83/4 2900 6975313/4 862.683961 WBM 10 3450.74 4569.74
Intermediate1 13 121/4 61/8 5000 589294.059 728.819209 WBM 13 2915.28 7485.01
Intermediate2 16 95/8 44/5 6200 451110.616 557.918541 WBM 16 2231.67 9716.69
Production 15 65/8 31/3 6660 229581 283.938068 WBM 15 1135.75 10852.44
55. The mass balance equation was used to calculate the components in the mud fluid used in every part
of the casing
𝜌 𝑚 𝑉𝑚 = 𝜌 𝑤 𝑉𝑤 + 𝜌 𝐵𝑒𝑛 𝑉𝐵𝑒𝑛
𝑉𝑚 = 𝑉𝑤 + 𝑉𝐵𝑒𝑛
5.5.1 Drilling Fluids for Conductor casing Section
It was decided to use mix of water and bentonite for Mud A with density of 10 ppg and
volume of 1119 bbl for designing conductor section casing and the table below summaries
the mud used for this section.
Volume of Mud A = 1119 bbl
𝑽 𝒘 = (𝝆 𝑩𝒆𝒏
∗ 𝑽 𝒎) – (𝝆 𝒎 ∗ 𝑽 𝒎)/ (𝝆 𝑩𝒆𝒏
- 𝝆 𝒘
)
= (21.7 *1119) – (10 *1119) / (21.7- 8.54) =994.86
Volume of Bentonite = 𝑉𝐵𝑒𝑛– 𝑉𝑤
= 1119 -994.86 = 124.14 bbl
Mass of water Mw = 𝜌 𝑤 * 𝑉𝑤*42 =356834.83 Ib
Mass of Bentonite Mb = 𝜌 𝐵𝑒𝑛 ∗ 𝑉𝐵𝑒𝑛*42 =113145.19Ib
Mass of Mud A = 𝜌 𝑚 * 𝑉𝑚 =11190 Ib
Table 30: Mud fluid values for conductor
Where:
𝑉𝑚 = Volume of Mud A
𝑉𝑤 = Volume of water
𝑉𝐵𝑒𝑛 =Volume of Bentone
𝜌 𝑚= Density of Mud A
𝜌 𝑤 = Density of water
𝜌 𝐵𝑒𝑛 =Density of Bentonite
5.5.2 Drilling Fluids for Surface casing Section
By using the mass balance equation, the calculation of surface section of the casing is same
as or the conductor section and we used the same mud A fluid but with volume of 4569.74
bbl .the table 28 below shows the mud designing for surface casing.
Component ρ (ppg) V (bbl) Mass (lb) Sacs
Water 8.54 4062.76 1457230.44
Bentonite 21.7 506.98 462058.64 4620.59
Mud A 10 4569.74 45697.36
Table 31: Mud fluid values for Surface
Component ρ (ppg) V (bbl) Mass (lb) Sacs
Water 8.54 994.86 356834.83
Bentonite 21.7 124.14 113145.19 1131.45
Mud A 10 1119.00 11190.00
56. 5.5.3 Drilling Fluids for Intermediate 1 casing Section
In this section, the mix of Mud A, Mud B and barite used, the volume of Mud A needed was
6586.81 bbl. and the amount of mud A already used in the system was 45697.36 bbl. So it
was required to add up volume of 2017.07 of Mud A in the intermediate 1 section. After
calculation using the mass balance equation the Table below summarizes the properties of
mud fluid used
Component ρ (ppg) V (bbl) Mass (lb) Sacs
Mud A 10 6586.81 2766459.7
Barite 35 898.20 1320355.76 13203.558
Mud B 13 7485.01
Table 32: Mud fluid values for Intermediate 1
Component ρ (ppg) V (bbl) Mass (lb) Sacs
Water 8.54 223.78 80264.90981
Bentonite 21.7 1793.29 1634408.421 16344.1
Mud A 10 2017.07 847170.6178
Table 33: Mud fluid addition values for Intermediate
5.5.4 Drilling Fluids for Intermediate 2 casing Section
The mixing of barite and Mud B used to form volume of 9716.69 Mud C which were used as
drilling fluid in this section as shown below
Component ρ (ppg) V (bbl) Mass (lb) Sacs
Mud B 13 1325.00 723451.5065
Barite 35 8391.68 12335775.69 123358
Mud C 16 9716.69 6529613.597
Table 34: Mud fluid values for Intermediate 2
5.5.5 Drilling Fluids for Production casing Section
The amount of 10852.44 Mud D are needed for this section ,we had already the volume of
9716.69 mud C used for intermediate 2 .we only add up 857.10 bbl of water to get 10852.44
bbl of mud D.
Component ρ (ppg) V (bbl) Mass (lb) Sacs
Water 8.54 857.10 307423.0817
Mud C 16 9716.69 6529613.597 65296.1
Mud D 15 10852.44 162786.5876
Table 35: Mud fluid values for Production
57. 6. Well Production Optimisation
6.1 Well Modelling (PROSPER)
To analyse well performance and optimization of a well including determination of inflow
performance relationship, we used Prosper. The PVT analysis and VLP co-relation of well can be also
addressed by this well modelling.
Tables below were used to carry out the PROSPER AND GAP modelling.
Depth (feet) TVD (feet) Explanation
0 0 Point of original deviation survey
500 500 Sea floor level
3000 3000 surface casing section
5000 5000 Intermediate casing section
6660 6660 Top of perforation
Table 36: Deviation survey
Type Length (feet) TVD (feet) Inside
diameter (feet)
Inside
roughness
Rate
Multiplier
Tubing 6149.95 6299.95 5 0.0006 1
Casing 6660 6660 6.25 0.0006 1
Xmass tree 150 150 N/A N/A 1
Table 37: Downhole equipment
6.1.1 Well Deliverability
The well deliverability was modelled by the inflow performance relation in PROSPER as shown in
Figure 41. The data used is shown Table 35 below.
IPR model PI Entry
Reservoir Pressure 3950 psi
Reservoir Temperature 170 deg F
Water Cut 51.03
Table 38: Data given to use
58. Figure 47: IPR Graph
6.2 Inflow Performance Relation (IPR) Curve
Inflow Performance Relation (IPR) Curve
Is the relation used to assess well performance by plotting the well production rate against
the flowing buttonhole pressure (BHP). The data required to create the IPR are obtained by
measuring the production rates under various drawdown pressures. The reservoir fluid
composition and behaviour of the fluid phases under flowing conditions determine the
shape of the curve.
Inflow performance relation gives the productivity index (PI) which is ratio of flow rate upon
pressure drawdown. PI is the inverse of slope of above graph.
𝑃𝐼=𝑄/Δ𝑃
Where:
PI = Productivity Index (STB/day/psi)
Q = Flowrate (STB/day)
ΔP = Drawdown (Psi)
59. 6.3 Optimum Well Flow Rate
In order to estimate the optimum well flow rate, the fluid properties (PVT), reservoir data (IPR) and
the tubing response (VLP) have to be integrated to produce a VLP/IPR curve with the intersection of
the curve being the well flow rate. Figure below shows the IPR versus VLP plot.
Figure 48: IPR Vs VLP curve
The optimum flow rate in our case is 36055.4 STB/day., with wellhead pressure of 400 psig
and Wellhead temperature of154.97 deg F.
Optimum flow rate
60. 6.4 Sensitivity Analysis
Sensitivity analysis was carried out for the reservoir pressure, GOR, tubing diameter and water cut
will change. Therefore, sensitivities were carried out on them. Because during the life of the wells, it
is expected that some changes in the well properties.
6.4.1 Sensitivity Analysis on Reservoir Pressure
Figure 49: Sensitivity analysis on Reservoir Pressure
The sensitivity analysis on the reservoir pressure the intersection shows that the minimum and
maximum reservoir pressure needed to cause a flow, there is about 1980 psig. Below this pressure
there is will be no flow of the liquid. The liquid rate increases, as the pressure goes up shown in the
graph above.
61. 6.4.2 Sensitivity Analysis on Gas Oil ratio
Figure 50: Sensitivity on Gas Oil Ratio
The intersection of the lines shows that, as the pressure increases, there is an increase in
the gas oil ratio value while liquid rate decreases. The higher the GOR the higher the lift
curve and this indication that more gas being produced in place of oil.
62. 6.4.3 Sensitivity Analysis on water cut
Figure 51: Sensitivity on Water Cut
In the water cut sensitivity analysis we can conclude that the lower the water cut the lower the
vertical lift performance curve which indicates more oil being produce relative to water.
Figure 52: Sensitivity on tubing diameter
63. 6.5 GAP Model
After running GAP model, the surface separator pressure of 390 psig and temperature of 83.16 deg F,
with the rate of production of 40000 STB/day was obtained.
Figure 53: GAP Model without constraint
7. Surface Production Facilities
After the production, fluid is passed through the well tube to the surface, the oil; gas and
water undergo separation process. The main objective of separation process is to treat
and process production fluids that come out of the well-head so as to meet marketable
standard and specifications required for final product consumer.
Surface Production Operations facilities may include any of the following; mixers, heat
exchanger, gas/oil/water separator, Pump compressor, splitter, desalting, sweetening,
64. stabilisation, oil, water and gas treatment. It can also include treatment of produced
water for re-injection or disposal. Gas/oil/water separation are always first step followed
by other processes according to what is set out to be achieved. For our oil field will be
separation process equipment’s includes:
• 1 horizontal three phase separator, 2 vertical two phase separators – for
gas/oil/ water separation.
• Pump –to help flow of the water for reinjection.
• Heat exchangers – Two cooler and two heaters for gas and oil so as to stabilize
it before transporting it to where it will be stored or exported.
• Compressors – to compress the gas before transporting it to point of
storage/export.
• One splitter – for final water cut in the gas before exportation
7.1 Production Fluid Separation Operations
The separation of production fluid takes place in a separation plant (separator). Here is
where the production fluids are separated into respective phases (i.e. gas, oil and water),
or gas and oil if the produced fluids contains just oil and gas with very little or a negligible
quantity of water.
For our oil field, due to the high flowing pressure at the well head we decided to use 3
separator stages because the higher the inlet pressure, the higher the number of
separator stages and the operation cost. First the hydrocarbon and water will pass
through the mixer and then the mixture go through the 3 phase vertical separator where
by gas, oil and water are separated
The separator operation cost must be carefully considered, there has to be a balance in
the capital and operating costs relative to the number of separator stages.
65. 7.2 Oil Treatment
Following separation, the oil stream will undergo other processes for further Field
treatment. Then the oil will pass through heater so as to attain required temperature for
condensation and then will undergo another separation stage where by two phases
separator was used to separate any remaining of lighter ends gas in the oil. The oil will
pass through the heater again in order to reach the required temperature and pressure.
The designing of inlet separator of the surface production become more easily by using
HYSYS modelling.
7.3 Gas Treatment
To meet required specifications, the gas from three phase horizontal separator and lighter
ends gas from two phase separator will pass through the mixer and then will undergo
vaporisation process by being cooled by heat exchanger , after that the gas will go through
the vertical two phases separator where by the gas will be separated with water remaining
and the gas will be compressed so that the pressure required to be achieved before passing
through another cooler and finally the water cut process will be follow when the gas pass
through the splitter. Gas will undergo several treatments before it reach to the gas
exporting central. The H2S, CO2 and other impurities remover will be used to purify the
exporting gas.
7.4 Water Treatment
The water from inlet which was separated by three phases vertical separator will pass
through the mixer together with the water cut from gas in splitter and this will be our
final amount of water cut. There will be some of the water remaining in the gas which
was separated by two phases separator will undergo condensation by passing through
the heater and will be pumped as recycle back to the inlet mixer as water injection.
66. 7.5 HYSYS Simulation
HYSYS Simulation
The compositional below was given to be used for the HYSYS simulation modelling to design
the inlet separator of the oil field with these condition must be attained,
Oil to be exported with a True Vapour Pressure (TVP) of 1 bar and at 37.8 C and
maximum basic sediment and water (B, S & W) of 2 volume%; include a heavy liquid
“carry-over” of 0.01 mole% in the separators.
Gas to be exported at a pressure of 120 bar and temperature of 50 C with a
maximum water content of 3 lbm/MMSCF and a maximum H2S content of 500
ppm(mol) .
Produced water to be either re-injected into the reservoir or disposed of overboard
with an oil content < 30 ppm; include a light liquid “carry-over” of 0.01 mol% in your
separators.
Component
Mole
Percent
(percent)
Critical
Temperature
(deg F)
Critical
Pressure
(psig)
Critical
Volume
(ft3/lb.mole)
Acentric
Factor
Molecular
Weight
(lb/lb.mole)
N2 0.20669 -232.51 477.419 89.8 0.00064 28.01
CO2 0.62007 87.89 1054.74 93.9 0.0036 44.01
H2S 0.020669 212.09 1280.96 98.6 0.0016 34.08
C1 24.8028 -116.59 661.049 99.2 0.00018 16.04
C2 5.50063 90.05 702.615 148.3 0.00145 30.07
C3 6.28053 205.97 608.886 203 0.00233 44.1
C4 4.97155 289.49 528.539 263 0.00299 58.12
C5 4.61241 372.83 492.845 255 0.00361 72.05
C6 4.47012 442.109 449.149 400.217 0.00406 84
C7 4.16653 483.247 411.018 455.957 0.00434 94.1122
C8 3.89886 523.677 381.61 510.792 0.00462 105.063
C9 3.65668 562.42 357.885 564.724 0.00489 116.5
C10 3.43393 599.311 338.196 617.752 0.00516 128.24
C11-C13 8.84274 666.317 307.031 720.466 0.00567 151.613
C14-C25 16.0744 851.293 249.881 1020.02 0.00713 228.352
C25-C50 7.57506 1208.16 201.564 1587.61 0.00967 412.478
C50+ 0.86639 1797.91 203.784 2127.16 0.01104 769.801
Table 39: Given values of components
We used these given values to calculate weight, density percentage in weight and density of each
component as shown in the table 36 below, by using these formulas,
68. Table 41 below, shows the mole fraction and other give factors for designing the oil field
Components Mole fraction
N2 0.0020669
CO2 0.0062007
H2S 0.00020669
C1 0.248028
C2 0.0550063
C3 0.0628053
C4 0.0497155
C5 0.0461241
C6 0.0447012
C7 0.0416653
C8 0.0389886
C9 0.0365668
C10 0.0343393
C11-C13 0.0884274
C14-C25 0.160744
C25-C50 0.0757506
C50+ 0.0086639
H20 1
API 38.0 ° API
Temperature 170°F (60 °C)
Pressure 3950 psi
Daily peak production 5,000 STB/day
Table 41: mole fraction and other give factors
7.6.1 Base Case
The API gravity of a crude specific gravity (SG) is given by:
𝐴𝑃𝐼= 141.5𝑆𝐺−131.5
∴ 𝑆𝐺= 141.538.0+131.5 = 141.5169.6 = 0.8348
Also:
𝜌𝑜𝑖𝑙=𝑆𝐺∗𝜌𝑤𝑎𝑡𝑒𝑟
∴𝜌𝑜𝑖𝑙= 0.8348 * 1000 = 834.8 kgm-3
69. Conversion of daily peak production (STB/day) to mole flow (kmol/hr)
0.159 m3/day = 1 STB/day
∴ 5,000 STB/ day = (5,000 * 0.159) m3/day = 795 m3/day
Also:
𝑀𝑎𝑠𝑠=𝜌∗𝑣𝑜𝑙𝑢𝑚𝑒
Correspondingly,
∴ Mass flow = 𝜌∗𝑣𝑜𝑙𝑢𝑚𝑒 = 834.8 * 795 = 663,666 kg/day
Thus, hourly mass production = (663,666 kg/day) / 24 = 27652.75 kg/hr
Conversion of mass flow to molar flow
𝑁𝑢𝑚𝑏𝑒𝑟 𝑜𝑓 𝑚𝑜𝑙𝑒𝑠= 𝑚𝑎𝑠𝑠/𝑚𝑜𝑙𝑒𝑐𝑢𝑙𝑎𝑟 𝑤𝑒𝑖𝑔ℎ𝑡
Comparatively,
∴ 𝑀𝑜𝑙𝑎𝑟 𝑓𝑙𝑜𝑤= 𝑚𝑎𝑠𝑠 𝑓𝑙𝑜𝑤/𝑚𝑜𝑙𝑒𝑐𝑢𝑙𝑎𝑟 𝑤𝑒𝑖𝑔ℎ𝑡
∗𝐴𝑣𝑒𝑟𝑎𝑔𝑒 𝑚𝑜𝑙𝑒𝑐𝑢𝑙𝑎𝑟 𝑤𝑒𝑖𝑔ℎ𝑡=Σ 𝑚𝑜𝑙𝑒 𝑓𝑟𝑎𝑐𝑡𝑖𝑜𝑛𝑠∗𝑚𝑜𝑙𝑒𝑐𝑢𝑙𝑎𝑟 𝑤𝑒𝑖𝑔ℎ𝑡
Thus, molar flow is calculated as:
27652.75 / 123.42 = 224.05 kmol/hr
7.6.2 Mass balance
An overall mass balance for our inlet separator designing carried out by the HYSYS
simulation are as shown in the table below,
Table 42: input and output values from HYSYS
H2O HC Total Inlet Oil Export Gas Export Water Out Total Outlet Mass Balance
Nitrogen 0 54.079974 54.07997 0.1088222 53.940645 3.05E-02 54.08 0.00
CO2 0 254.88631 254.8863 3.8364878 248.51372 2.536101 254.89 0.00
H2S 0 6.5784785 6.578478 0.2286571 6.2325277 0.117294 6.58 0.00
Methane 0 3716.5585 3716.558 11.922317 3704.635 1.16E-03 3716.56 0.00
Ethane 0 1544.9051 1544.905 18.389171 1526.5159 6.33E-06 1544.91 0.00
Propane 0 2586.7992 2586.799 72.198686 2514.6005 4.36E-08 2586.80 0.00
n-Butane 0 2699.0112 2699.011 160.13524 2538.876 8.98E-11 2699.01 0.00
n-Pentane 0 3108.3338 3108.334 369.23853 2739.0952 9.97E-14 3108.33 0.00
n-Hexane 0 3598.0938 3598.094 862.40289 2735.6909 7.52E-17 3598.09 0.00
n-Heptane 0 3899.6111 3899.611 1782.6165 2116.9945 3.27E-20 3899.61 0.00
n-Octane 0 4159.8992 4159.899 3011.4774 1148.4219 1.03E-23 4159.90 0.00
n-Nonane 0 4380.5858 4380.586 3936.4816 444.10423 2.30E-27 4380.59 0.00
n-Decane 0 4563.6039 4563.604 4422.5928 141.01113 1.49E-31 4563.60 0.00
C11-C13* 0 12522.202 12522.2 8997.2326 3524.9691 2.66E-31 12522.20 0.00
C14-C25* 0 34284.434 34284.43 32927.941 1356.4928 1.69E-45 34284.43 0.00
C25-C50* 0 29183.961 29183.96 29177.989 5.9728814 3.11E-73 29183.96 0.00
C50+* 0 6229.4441 6229.444 6229.4439 2.35E-04 4.95E-97 6229.44 0.00
H2O 13445.14 0 13445.14 0.4113799 0 13444.73 13445.14 0.00
Inlet Outlet
70. Note: from the law of conservation of mass,
Σ inlet = Σ outlet
And from our results in the table above, the mass of the component have been balanced.
The flow diagram of HYSYS process is shown below. After designing inlet separator with
HYSYS simulation, all the given requirement specifications in the project were met. These
conditions include pressure, water content and B, S &W of the export gas. The true vapour
pressure of the export oil was also achieved to be 1 bar (100 kPa) at 37.8oC. In addition, the
oil content of the produced water that is to be re-injected or disposed overboard was met.
Figure 54: HYSYS Circuit Diagram
72. 8. Economics
8.1 Financial System
After the energy crisis in 1973, the United Kingdom government has introduced the PRT
(Petroleum Revenue Tax) in order to stop the exploitation of the hydrocarbons. In the
subsequent year, a corporation tax CT which is also known as ‘ring fence’ is added with the
supplementary charge in addition to PRT tax.
In the recent years, the government of United Kingdom further wants to decrease the
taxation on the projects by eliminating the supplementary charge in North Sea in order to
inspire the companies and maximise the remaining reserves
8.2 Production Forecast
The production rates for all the three forecasted development scenarios in terms of
maximum oil recovery factor are delivered to the department of Petroleum Engineering for
the economic analysis. The production of each well is capped to 5000 STB/day.
The following three cases which are selected for the economics evaluation are as follow:
During the production of first year, 4 producer wells will transported online separately with
the space of 90 days. In the following year, four more producing wells with two injector wells
are added. As in the two years’ time period, there are eight wells all together which are
producing from year 2 but all the eight wells are not producing from the beginning of that
year therefore the full production will start from year 3 onwards.
A shut in well is carried out once for three weeks after every three years to conduct well
testing and maintenance for enhancing the recovery of the well.
The table 34 given below show the production forecast of Oil, Water and Gas for the three
cases for the next 20 years.
Case Number of the wells Types of the wells Water Injection Project life time in years
1 8 8 vertical Yes 20 years
2 6 5 vertical, 1 horizontal Yes 20 years
3 8 8 vertical Yes 18 years
Table 45: Economic Evaluation of three cases
74. The table 35 shows the production forecast for Case 1 for 20 years. The water cut for the
year 2036 comes out to be 52% but for our case, the project is closed in the year 2035 with
the water cut of 51% instead of 52% and recovery factor of almost 30% because after 2035
the project start to lose money which is not economically viable.
Recovery factor can be calculated with the help volume calculation (STOIIP) which is taken
from petrel and it comes out to be 373 million STB.
8.3 Capital Expenditure (CAPEX)
Capital expenditure is the amount which is invested before the start of the production of the
project. It means that significant amount is needed to be spend before the production. The
most considerable amount is spend on vertical and lateral drilling of the wells. The cost of
drilling of each vertical well is £29,000,000 whereas for lateral well it is assumed that the
cost of each well is 2.5 times more the cost of vertical well. Altogether there are 8 producer
wells and 2 injector wells for case 1.
Abandonment cost is also added to the Capex at the end of the life of the project when the
wells are abandoned. Abandonment cost for each well is £8,000,000. Capital Expenditures
for Case 1 are shown in Table 4 given below:
Figure 55: Production of Water and Oil for Case 1
75. £ '000 £ '000
Item Description No off Each Product
a Separator 3 1000 3000
a Compressor 1 1100 1100
a Spliter 1 1000 1000
a Pump 1 1200 1200
a Scrubber 1 1000 1000
a Cooler/Heater 5 700 3500
a Control valve 3 47 141
a Hydrocyclone 2 448 896
a Coalescer modification 1 430 430
a Metering 3 996 2988
a Drilling (1 well) 10 29000 290000
a Flowline 2 7000 14000
a Total equipment cost (A) 319255
b Piping, 30% of (A) 95777
c Control Room upgrade 1 700 700
d Electrical cabling, 17% of (A) 54273.35
Subtotal a-d 470005
e Cost of site works, 32% of a-d 150401.552
Subtotal a-e 620406
f Design and engineering, 17% of a-e 105469.088
Subtotal a-f 725875
g Contractor's contingency, 4% of a-f 29035.0196
h Contractor's profit, 12% of a-f 87105.0588
i Total of plant and works contract 842016
Provision of onshore support services (20% of i) 168403.114
j Well Abandonment 10 8000 80000
k CAPEX increment ( unforeseen expediture etc) 0% 0 0
Total CAPEX investment /£ 1010419
CAPEX distribution /£ Year % total CAPEX / yr
1 60% 606251.400
2 25% 252604.750
3 15% 151562.850
Total 1010419
Table 48: Capital Expenditures for Case 1
