March 2012

Marcel&Conrad for Team B
Wytch Farm Field development Project
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March 2012

Marcel&Conrad for Team B
Wytch Farm Field development Project
Marcel&Conrad’s Health and Safety Policy Statement complies with the Health and
Safety at Work etc. Act 1974.
Our statement of general policy is:
 to provide adequate control of the health and safety risks arising from our work activities;
 to consult with our employees on matters affecting their health and safety;
 to ensure no negative impact of our activities on the environment;
 to provide and maintain safe facilities and equipment;
 to ensure safe handling and use of substances;
 to provide information, instruction and supervision for employees;
 to ensure all employees are competent to do their tasks, and to give them adequate training;
 to prevent accidents and cases of work-related ill health;
 to maintain safe and healthy working conditions; and
 to review and revise this policy as necessary at regular intervals.
Signed by:
Marcel, Chief Executive
Date: 22 th
of March 2012

2012
Petroleum System & Reservoir Characterisation
10km
Wytch Farm field within Dorset county
Field Development

Natural mechanisms allow low recovery

Water injection strategy

Environmental constraints

Source rock: Liassic Mudstone

Reservoir rock: Sherwood Sandstone

Cap rock : Mercia Mudstone

Oil accumulation: fault trap with migration during the basin extensional period
Project economics
Mitigation scheme and recommendations

Environmental regulations upheld

High profitability achieved

Shrewd reservoir management practices planned

Efficient mitigation schemes designed

Introduction
1. Characterising the reservoir
Petroleum system
Reservoir structure
Description of heterogeneities
Rock and fluid properties
Reservoir modeling
Volumetric estimation and associated uncertainties
2. Developing the field
Reservoir drive mechanisms
Production strategy
Drilling strategy
Development strategy results
Export and surface facilities
HSE policy
Field abandonment and decommissioning
Project lifecycle
3. Engineering design
Well performance
Surface facilities
Hydrocarbon export
4. Economic evaluation
Expenditures
Cash flows and economic evaluation
5. Uncertainties and risk management
Assessing the uncertainties
Risk mitigation scheme
6. Key considerations and recommendations
References
Appendices
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(key figures page)
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Marcel&Conrad for Team B
Wytch Farm Field development Project
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Marcel&Conrad for Team B
Wytch Farm Field development Project
The scope of the report is to demonstrate and justify the development proposal for
Wytch Farm field .
The integrity of the project will be ensured by meeting both HSE and economic constraints while optimising the reservoir management and the surface facility strategies.
This is the third in a series of studies focused on Wytch Farm field. Appraisal, characterisation and modelling as well as simulation and optimisation were previously carried out.
The Wytch Farm field is located in the southern coast of the United Kingdom. It lies beneath Poole Harbour and the surrounding Purbeck region of Dorset, and extends eastward towards Bournemouth. The reservoir, the Sherwood Sandstone, a Triassic fluvial sandstone, is approximately located at 1,600 m beneath the surface.
Figure 1
Location of the Wytch Farm Field and appraisal wells
9

10
The field extends from onshore blocks PL089 and PL259, to offshore block 98/6.
As part of the exploration programme, a dataset was acquired to appraise and ultimately define the recoverable assets of the Sherwood sandstone reservoir.
Environmental considerations are a key aspect in this project. The onshore areas are designated as an Area of Outstanding Natural Beauty and a Heritage Coast, and the area have statutory National Nature Reserves and Sites of Special Scientific Interest.
Consequently, any development strategy proposed will assess and try to minimise any potential adverse impact on this particularly sensitive environment. Specifically, the location and the size of the surface facilities, the number of wells and their location will be carefully considered in order to minimise the environmental, economic (tourism), aesthetic and noise impact among others.

Marcel&Conrad for Team B
Wytch Farm Field development Project
11

12
The petroleum system at Wytch Farm comprises a Triassic Sherwood Sandstone reservoir, Mercia Mudstone seal and a Liassic Mudstone source. The Sherwood
Sandstone and Mercia Mudstone represent an upwardly fining stratigraphic sequence related to an unsuccessful attempt to open the north Atlantic
1
. This produced an excellent reservoir and seal pair. The source rock was formed later during marine transgression and a successful rift of the central Atlantic. Despite being stratigraphically above the reservoir, extensive faulting in the region continued creating rotated fault blocks as shown
in Figure 2 . This not only enabled hydrocarbons to migrate but also formed traps within
the Sherwood Sandstone.
Figure 2
Wytch Farm petroleum system map showing hydrocarbon migration and traps
SOURCE: adapted from Underhill and Stonely, 1988
The structure of the Sherwood reservoir is a fault sealed, 3-way dip closed anticlinal structure, cut by a series of west-east trending normal faults. The reservoir is characterised into four zones based upon fluid flow properties for application within a reservoir model. From the depositional point of view this corresponds to the seven zones
presented in Table 1 .
1 Reference 7

Marcel&Conrad for Team B
Wytch Farm Field development Project
Table 1
Depositional characteristics of the zones
Zone Characteristics
1
2
Lacustrine
Multi-storey channel deposits
Floodplain
Thick, laterally extensive low-permeability, low-porosity, lacustrine/playa deposits of the Upper-Sherwood. In outcrop, seen as gradational transition into Mercia Mudstone.
A maximum 40 m thick multi-storey channel deposits with thinner interbedded floodplain muds, within the oil-pay zone.
3
Multi-Lateral
4 braided Channels
5 Floodplain
Laterally extensive low-permeability, low-porosity flooding events.
Multi-lateral stacked braided channel system of high net-to-gross sand, part of principal reservoir within pay-zone.
Laterally extensive low-permeability, low-porosity flooding events.
6
Multi-Lateral braided Channels
Multi-lateral stacked braided channel system of high net-to-gross sand. Beneath the OWC and not within oil-pay zone.
7
Multi-storey channel deposits
A maximum 40 m thick multi-storey channel deposits with thinner interbedded floodplain muds, beneath the OWC and not within the oil-pay zone.
A reliable top reservoir map ( Figure 3 ) was derived using the following 2-step
approach. First, the 3D seismic survey was processed in order to be zero-phase and to allow the top reservoir horizon picking. Secondly, based on the geological history of the area and the checkshots data, time to depth conversion was used to build a velocity model. The top reservoir horizon picked in the time domain was therefore converted into the final depth map.
Figure 3
Top Sherwood map from geophysical interpretation
13

14
Structural and sedimentological heterogeneities are both present in Sherwood reservoir. These heterogeneities affect reservoir continuity and potential sweep efficiency on different scales, and are analysed in determining reservoir architecture and degree of
compartmentalisation as it is shown in Table 2 .
Table 2
Hierarchy and impact of structural and stratigraphic reservoir heterogeneities
Heterogeneity Scale
Sealing Fault
Non-sealing Fault
Giga
Giga



Lacustrine muds Mega
  
Flood deposit muds
Abandoned channel mudstone
Mega
Macro


 

Cemented channel lag Macro
 
Cross bedding Macro/Micro
 
Laminations Macro/Micro
 
Mineralogical Micro

.
Horizontal stratification within the Sherwood reservoir indicates a layer-cake reservoir architecture. On the finer scale, structural and stratigraphic heterogeneities are likely to result in a more jigsaw-puzzle style of architecture.

Marcel&Conrad for Team B
Wytch Farm Field development Project
Structural heterogeneity
In Wytch Farm field two types of fault seals are expected: juxtaposition seals and fault rock seals. Fault rock seal is expected to be phyllosilicate-framework fault rocks.
Juxtaposition seal would result from juxtaposition of the Mercia formation (mudstone sequence, low permeability rock) and the Alyesbeare formation (mudstone sequence, low permeability rock) against the Sherwood sandstone (reservoir unit). These juxtapositions will seal and act as barriers to fluid flow due to the high clay percentage of 60 and 70% found in the Mercia and Alyesbeare formations.
Figure 4
Fault surfaces of the major faults within the Wytch Farm field
15
Sedimentological heterogeneity
According to the reservoir zonation scheme established, lacustrine and flood deposit mudstones can be recognised as shale intervals which are laterally extensive across the reservoir. These laterally extensive shale layers are expected to act as barriers to vertical flow, severely restricting k v
and thus resulting in stratigraphic compartmentalisation within the reservoir.
Depending on their horizontal continuity, heterogeneities within the reservoir can act as permeability baffles by impeding k h
. Examples include mud plugs and cemented channel lag deposits. Despite this, vertical connectivity and k v
within the multi-storey, multilateral sandstone units is expected to be good.
Abandoned channel mudstones and mud plugs are features synonymous with the multi-storey and multilateral channel found in the Lower Sherwood. These features represent local baffles to fluid flow due to their discontinuous nature.

16
Three appraisal wells were initially drilled and two producing wells followed. They were used to characterise the reservoir and evaluate its properties by using the following methods:
Table 3
Tests performed on the exploration wells
Well
1K-01

1F-11

 




98/6-8

1D-02




1X-02

The initial conditions of the reservoir are the following:
Table 4
Reservoir initial conditions
Initial conditions
Depth (TVDSS) 1585 m
Oil column thickness
OWC
Areal extent
Pressure
Temperature
39 m
1620 m
40 km 2
165 bar
66°C




Marcel&Conrad for Team B
Wytch Farm Field development Project
Rock properties: well logging interpretation and core analysis
Borehole logging was used to make a detailed record of the geologic formations penetrated by the five exploration wells mentioned above. The results were analysed and provided valuable information about the rock properties of the reservoir.
Also, RCAL and SCAL were performed in order to quality check the results obtained from the well logging interpretation but also to derive the relationships between porosity, permeability and water saturation. Furthermore, the sandstone reservoir was found to be water-wet.
17
Finally, RFTs were used on three wells so as to confirm the OWC location. As it
can be inferred from Figure 5 , the pressure across the field is not the same for every well
and suggests that the field might be compartmentalised. However, the uncertainties associated to these measurements being important, this assumption cannot be validated and the pressure behaviour might be the result of the surrounding producing wells.
Figure 5
Repeat formation tester as a quality check for the OWC
Reservoir depth as a function of pressure
Depth (m) Depth (m)
1580 1540
1560
1580
1600
1620
1640
1660
1680
1700
165
Well 1K-01
Water gradient 0.074 bar/m
Oil Gradient 0.11 bar/m
FWL 1624 m
170 175
Pressure (bar)
180
1600
1620
1640
1660
1680
165
Well 98/6-8
Water gradient 0.070 bar/m
Oil Gradient 0.11 bar/m
WL
170
Pressure (bar)
1622 m
175
The following table summarises the main parameters obtained from these analysis and the method(s) used to derive them:

18
Table 5
Summary of reservoir rock parameters
Parameter / Property Method
Top Sherwood (m)
OWC (m)
Porosity
Hor. Permeability (mD)
Seismic acquisition, logs
Resistivity log, cores and RFT
Logs and core analysis
Core analysis, DST
Water saturation
Net/Gross
Logs (Indonesian) and cores
Cut-offs
Fluid properties: PVT and core analysis
Well average
1556 ± 15
1624 ± 5
15% ± 2%
112
40% ± 7%
68% ± 8%
Understanding the properties of the reservoir fluids is a fundamental step as it allows setting the production strategy as well as dimensioning the surface facilities.
The bubble point pressure was determined at 76.5 bar. Because of the large differential between the bubble point pressure and the reservoir pressure, the oil behaviour and the production strategy were optimised for a dead oil model.
Composition of the crude, viscosity, formation volume factor and gas-oil ratio were
also determined and are summarised in Table 6 .
Table 6
Summary of fluid properties
API gravity
GOR
Formation volume factor
Oil density
Oil compressibility
Fluid properties 2
38.1° @ 15°C
320 scf/stb
1.21 rb/stb
0.74 g.cm
-3
1.37x10
-4 bar -1
Oil viscosity 1.03 cP
It has to be mentioned that the uncertainties associated to these results are important, as the number of sample available was limited.
2 At reservoir conditions: 165 bar, 66°C

Marcel&Conrad for Team B
Wytch Farm Field development Project
Static model
The reservoir model integrates the geological, geophysical and petrophysical results obtained from the parts above. The production of a robust reservoir model requires the integration of core and outcrop observations in collaboration with more stringent petrophysical, seismic and well test analysis interpretations.
Figure 6
Sand-shale model within the zone 6 after petrophysical modeling
19
Figure 7
Permeability model within the zone 6 after petrophysical modeling
Parameters such as channels porosity and permeability are only known in a first step around the wells locations. In our case, as the channels follow a common spatial pattern through the reservoir, some geostatistical tools were used and the results are
shown in Figure 6 and Figure 7 .

20
Dynamic model
Understanding the flow properties of the reservoir being the final purpose, the detailed static model was coarsened for simulation purposes. The following table summarises the process:
Table 7
Building a dynamic model
Parameter /
Property
Static model value
Grid dimensions 100x100
Constraint
Capture geological and petrophysical hetereogeneities
Dynamic model
390x270
Zonation and layering
7 zones, 140 layers
Capture vertical hetereogeneities
7 zones, 50 layers
Facies N/G Respect the depositional model Most of
Horizontal permeabilities
Vertical permeability k x
, k y k z
Honour the channel distribution
Capture the heterogeneities
Arithmetic
Geometric
Porosity
Φ
Honour the channel distribution
Arithmetic
The consistency of both dynamic and static models was a key aspect through the whole coarsening process and many quality checks were performed in order to ensure it:
Figure 8
Horizontal permeability 3 in zone 1: fine (left) and coarse model (right) consistency
3 Water breakthrough is expected to occur later for the coarse model as the upscaling process averages out high permeability streaks, reducing their contribution to the phenomenon. However, at later times, water production rates for both models converge.

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Wytch Farm Field development Project
Figure 9
QC of upscaled volumetric properties
QC of upscaled volumetric properties
MMbbl
12 000
10 221
9 932
10 000
8 000
6 000
4 000
2 000 1 359 1 378
Fine grid
Coarse
793 799
-
GRV PV STOIIP
A quantitative QC check of the upscaling of the volumetric properties was done by
comparing calculated volumes on the coarse and fine-grid models ( Figure 10 ).
Figure 10
Coarse model consistency: history match
Water and oil production rate history match
Water production rate (stb/d)
180
160
140
120
100
80
60
40
20
0
Simulation
Observed data
0 1 2 3 4 5 6 7 8 9
Time Elapsed (years)
Oil production rate (stb/d)
3 500
3 000
2 500
2 000
1 500
1 000
500
0
Simulation
Observed data
0 1 2 3 4 5 6 7 8 9
Time Elapsed (years)
21
To ensure that the model is representative of the real field, production rates have to match with existing production data. The history match process allows calibrating the model and fitting parameters coming from incomplete data.

22
The values of STOIIP were derived from the static model. The P50 case will be set as base case and the development strategy presented in the next section is optimised for it.
Table 8
Static model volumetrics: STOIIP and reserves
P90 P50 P10
STOIIP (MMstb)
Reserves (MMstb)
580
219
795
318
1040
412
The key uncertainties affecting the STOIIP estimate were assessed using a statistical approach
4
. The varying key parameters were:

GRV : the uncertainty associated with the total volume is explained by two parameters: the OWC position and the top Sherwood position derived by seismic interpretation;

Water saturation : each cell of the model has an associated value of water saturation and this value was assumed to be equal to one below the OWC;

Net/Gross and porosity : the net/gross uncertainty is included in the uncertainty associated with the porosity. Indeed, each cell of the model has a value of porosity that is assumed to be nil for the shale cells;

Formation volume factor : the uncertainty comes from the lab experiments and from the lack of information available to characterise the oil.
Figure 11
STOIIP sensitivity analysis
Variation parameter
GRV -65% 77%
Sw
PHIE
-22% 11%
9% -7%
Bo -4% 3%
-80% -60% -40% -20% 0% 20% 40%
Variation from base case (normalised to a 100%)
60%
4 Monte Carlo repeated random sampling method
80%

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Wytch Farm Field development Project
23

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Producing oil needs energy and that is why the drive mechanism has to be determined before adopting a production strategy. Material balance was used to determine whether some of this required energy is supplied by nature.
Before presenting the results, it is important to emphasise that only two data points were available. Thus, whatever the initial assumption on the drive mechanism may be, it will be validated
5
. The two combinations considered are presented in Figure 12 : aquifer
with solution gas drive and solution gas with compaction drive.
Figure 12
Drive mechanism determination
Aquifer with solution gas
F/E o
[10 6 stb]
1000
Solution gas with compaction drive
F [10 6 rb]
2,0
800 1,6
600
N=645 MMstb 1,2
400
0,8
N=277 MMstb
200
0,4 y = 0,004x + 644,55 y = 276,81x + 0,3409
0
0 30 000 60 000 90 000
ΔP/E o
[psi.stb/rb]
0,0
0 0,002 0,004
E o
+ E f
[rb/stb]
0,006
The mechanism that combines the aquifer and the solution gas drive gives initial oil in place closer to the STOIIP estimate (645 MMstb compared to 795 MMstb for the P50 case). Thus, oil expansion and aquifer drive will be considered as the most plausible mechanism.
Following that assumption, the size of the aquifer is around 20%
6
of the STOIIP estimate. However, the aquifer does not provide enough energy as the primary recovery estimates are as low as 4.6%. Consequently, secondary recovery methods are needed and the presence of the aquifer makes water injection the preferred option
7
.
5 There is always a straight line between two points
6 Water compressibility is assumed to be equal to 3.10
-6 Pa -1 at reservoir conditions
7 This option will be discussed further in the Production strategy

Marcel&Conrad for Team B
Wytch Farm Field development Project
The production will be supported by water injection below the oil water contact in
order to push the oil out and maintain the reservoir pressure (see Figure 13 ).
Figure 13
Using water injection to maintain the reservoir pressure
Reservoir pressure profile throughout the field life
Reservoir pressure (bar)
180
160
140
120
100
80
60
40
20
0
0 2 4 6
With injection
Without injection
8 10 12 14 16 18 20 22
Time Elapsed (year)
25
Figure 14
Water injection strategy: water source
Composition of the injected water
Percentage of water
100
90
80
70
60
50
40
30
20
10
0
0 2 4 6 8 10 12 14
Time Elapsed (years)
16
Pumped sea water
Produced water
18 20 22

26
Initially, the strategy is optimised for a 25-year production period due to the lease’s duration. However, as shown in the economic evaluation section, the field becomes uneconomic after 23 years of production and, hence, the abandonment is considered.
The injection of water will start 14 months after the first oil. Injection water will be a mixture between the produced water after treatment and the sea water. This solution was adopted as the produced water is not sufficient to cover the required injection rate, as
shown in Figure 14 . The injection is limited to 63,000 bbl/d and is injected at a pressure
that will not fracture the reservoir.
Work-overs will be made at a later stage of the production to detect and shut perforations producing too much water. Work-over operations will also allow improving the well performance by replacing the artificial lift systems installed (see Engineering design section).
The Buckley-Leverett analysis shows a sweep efficiency of 92% reached after 23 years.
Figure 15
Water injection results: high sweep efficiency
Pore volume produced versus pore volume injected
Dimensionless pore volume produced (N pD
)
0,6
0,5
Theoretical Buckley Leverett
One-to-one line
1-Swc-Sor
Simulation
0,4
0,3
0,2
0,1
0
0 0,2
Water breakthrough
0,4 0,6
Dimensionless time (t
D
)
0,8 1

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Wytch Farm Field development Project
To ensure protection of the natural heritage, the well sites were placed at strategic locations that will not affect the sensitive ecological environment.
Since offshore drilling is not permitted, extended reach wells are considered to efficiently maximise production of the field, which will help reducing footprint on land of production and save cost as platforms offshore will not be required. Directional drilling gives access to reservoir several kilometres away from the well site. This has also reduced number of satellite wells, hence conserving the outstanding beauty of the harbour. All the areas under special protection such as the UNESCO’S world heritage situated on top of the Jurassic coast have been isolated.
Figure 16
Environmental constraints and well site locations
27
SOURCE: BP and Google Earth
Production will be ensured by the use of 16 wells including 11 producers and 5 injectors distributed over 2 well sites. Each well site is equipped with one permanent rig and an extra rig is available and moveable from one site to the other.
Table 9
Well characteristics
Wellsite
1
Producer (P)
Injector (I)
1P-01
Type Length (m)
1 1P-02
Horizontal
Horizontal
Multilateral
6,856
11,305
2,700
Horizontal section length (m)
2,130
5,370
1,400

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1
1
2
1
1
1
1
2
2
2
2
2
2
2
1P-03
1P-04
1P-05
1P-06
1I-01
1I-02
2P-01
2P-02
2P-03
2P-04
2P-05
2I-01
2I-02
2I-03
Figure 17
Well configuration within the reservoir
Horizontal
Horizontal
Horizontal
Horizontal
Multilateral
Horizontal
Horizontal
Horizontal
Vertical
Multilateral
Horizontal
Horizontal
Horizontal
Horizontal
Horizontal
Horizontal
3,682
3,811
2,428
9,023
4,850
8,918
4,413
6,560
1,620
2,150
3,197
3,734
3,128
5,767
4,025
5,572
1,300
1,400
5,00
6,600
2,800
3,000
2,500
3,000
N.A.
1000
1,100
1,190
1,100
3,800
1,750
2,500

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Wytch Farm Field development Project
Drilling schedule
The target is to get the first oil produced on the 1 st
January 2017. The drilling schedule is as follows:
29
Figure 18
Detailed drilling schedule based on the highest rates
Year
Drilling 2016 2017 2018
Oil production Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4
Water injection J F M A M J J A S O N D J F M A M J J A S O N D J F M A M J J A S O N D
2P-01
2P-02
2P-03
2P-04
2P-05
2I-01
2I-02
2I-03
1P-01
1P-02
1P-03
1P-04
1P-05
1P-06
1I-01
1I-02
Some of the highest rate wells are drilled first to get a quick production build up, then lower rates and higher rates wells are drilled to maintain the plateau for a total duration of 3 years. Injectors are drilled to start injecting 14 months after the first oil.
The following mud has been used with a weight high enough to withstand the pore pressure but low enough so that the formation is not fractured. The completions have been set to get an optimum well performance; all these parameters are justified in the engineering section.
Table 10
Drilling and completion specifications
Mud type
Mud weight
Tubing ID
Bottomhole casing OD
Perforations
Water based
1.15 sg
4”
7”
All along the horizontal section, 8 SPF

30
With the aforementioned production strategy, the following results were achieved for our three scenarios (optimistic, base case and conservative).
Figure 19
Development strategy results: 3-year plateau achieved
Oil: expected rates and prodcution
Oil rate (stb/d)
80 000
70 000
60 000
50 000
40 000
30 000
20 000
10 000
250
200
150
100
50
Oil produced cumulative (MMbbl)
450
400
350
300
P90
P50
P10
0
0 2 4 6 8 10 12 14 16 18 20 22
Time Elapsed (years)
Figure 20
Development strategy results: 3-year plateau achieved
Gas: expected rates and production
Gas rate (Mscf/d)
30 000
0
Gas produced cumulative (Bscf)
140
25 000
20 000
120
100
15 000
10 000
5 000
80
60
40
20
P90
P50
P10
0
0 2 4 6 8 10 12 14 16 18 20 22
Time Elapsed (years)
0

Marcel&Conrad for Team B
Wytch Farm Field development Project
The development strategy estimates a relatively high recovery factor of 40% for the base case. Moreover, it has to be mentioned that only water injection methods were used.
The results for the optimistic and conservative case also give high recovery factors.
Table 11
Development strategy results: recovered oil
31
P90
STOIIP (MMstb)
Recovered oil (MMstb)
Recovery factor
8
580
219
38%
P50
795
318
40%
P10
1040
412
40%
The sizing of the surface facilities was optimised based upon a 3-year production plateau of 76,000 stb/d.
The fluids will be transported from the well heads through a set of pipelines to the surface facilities. The oil, water and gas mixture is separated in various stages so as to meet the market requirements. Finally, the export is split as follows:

Oil: delivered to the Fawley Refinery;

Natural gas: sent to the high pressure National Grid network pipeline at the vicinity of Iwerne Courtney;

LPG: exported by railway, by developing a gathering and loading station aside the national rail route next to Corfe Castle;

Water: treated and re-injected.
8 Refer to the engineering section for further details

32
The development plan for Wytch farm field is subject to compliance with several environmental conventions, i.e. the Purbeck Heritage, Jurassic coast heritage and various national and scientific interest parks of prominent natural beauty. Hence an in-depth location planning was developed in conjunction with directional multilateral drilling, aiming to hide the facilities from the landscape and minimise any environmental impact.
Figure 21
Health risk management workflow: hazard prevention
The operatorship will be characterised by high responsibility policy, compliance to
governmental regulations on health, safety and environment protection (see Figure 21 ). It
is a company’s commitment to continuously improve HSE performance and comply with national and European standards on HSE (ISO18000), Quality management (ISO9000) and Environment (ISO14000).
The main concerns and proposed mitigations are:

Labour accidents: by compliance to governmental regulations and continuous improvement management;

Oil and gas spillage: by monitoring pressure drops and have regular shut down valves along the pipelines and leak detectors at the facilities site;

Noise pollution and biodiversity impacts: by planting trees around the facilities and complying to Control of Pollution Act 1974, Part 3 (ch.40), Environmental
Protection Act 1990 (ch.43), Part 3 and 1995 revision, (ch.25), Part 5;

Waste disposal and emissions: All produced chemical waste is dispatched by road to chemical processing plants and CO
2
separated from gas is captured. Pollution

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Wytch Farm Field development Project control compliance is assured according to Pollution Prevention and Control Act
1999 (ch.24) and the Pollution Prevention and Control Regulations 2000 (SI
2000/1973).
Figure 22
Safety risk management workflow: hazard prevention
33
Figure 23
Environmental risk management workflow: hazard prevention

34
Proper field abandonment plans are set in place to ensure surface facilities decommissioning, and well abandonment are executed in a safe and environment friendly fashion bearing in mind cost effectiveness after 23 years of production.
Following the plans and working closely with the UK authorities will ensure a successful abandonment of the Wytch Farm field. Permission to decommission and abandon will be sought by submitting three documents: Cessation of Production document, Well Abandonment Programme document and Facility Abandonment Plan document to the Department of Energy and Climate Change (DECC) and the Department of Trade and Industry (DTI). An approval for all three documents must be obtained to implement the abandonment plan.
Funds are allocated upfront for field abandonment to guarantee the authorities that the company is committed to clean up and restore the land and properties to the original set up and thus imposing no financial burden on the government. Moreover, all wells in the field will be completely plugged and abandoned from top to bottom using cement to ensure no seepage from the reservoirs to the surface. In addition, before decommissioning, the facilities will be depressurised, drained and cleaned prior to surface facilities dismantlement. Consequently, surface facilities and associated pipelines will be dismantled in a strictly safe manner fostering an injury-free work environment in line with authority guidelines and regulations. After all abandoning operations have been performed the lands will be restored by means of reforestation.
Figure 24
Company approval
Planning FDP
Governmental approval
Project management
Front end engineering design
Engineering
Procurement
Construction
Commisioning
Drilling
Production
Decommissioning
Abandonment
2014 2012 2013 2015 2016 2017 2018 > 2038 2039 2040 2041
Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 > Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4
First oil

Marcel&Conrad for Team B
Wytch Farm Field development Project
35

36
Objective
In order to meet the production rates targeted (76,000 stb/day distributed between
11 wells during the plateau), the downhole technology performance was carefully chosen.
Tubing performance design
The casing is designed to have a 7” OD at the bottomhole. Taking this into account, the intermediate casings are determined based on the traversed formations in order to put
the casing shoes in the consolidated formation: see Figure 25 .
Figure 25
Design of the casing and the tubing with the formations
Depth
(mTVD)
0
80
Formation
----------------------------------
Unconsolidated sandstone
----------------------------------
Limestone
480 ----------------------------------
Unconsolidated sandstone
503 ----------------------------------
Mudstone
898 ----------------------------------
Sandstone
933 ----------------------------------
Mudstone
1,567 ----------------------------------
Sandstone
1,747 ----------------------------------

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Wytch Farm Field development Project
These casing specifications are then adapted to the measured depth of each well, keeping in mind that the 7” casing goes all the way through the horizontal section.
37
A sensitivity analysis on the perforation density was performed and the optimum value was 8 SPF
9
.
600
800
1 000
1 200
1 400
1 600
1 800
Mud weight determination
The completion report of the appraisal well 1F-11 indicates that the pore pressure follows a pressure gradient of 1.04 sg without variations along depth. The RFT data from the appraisal wells match with this assumption. The reports also mention leak off tests which are used to estimate the fracture pressure. Knowing this information, the mud weight is chosen to be higher enough than the pore pressure to take into account the measurements imprecisions and lower enough than the formation fracture pressure in order not to fracture the formation. A mud weight of 1.15 sg is chosen as shown in
Figure 26 .
Figure 26
Determination of the optimum mud weight
Depth (mTVD)
0
0 50 100
200
400
150 200
Pressure (bar)
250
Pore Pressure
Fracture pressure
Mud pressure
RFT 1K-01
RFT 1F-11
RFT 98/6-08
9 Shots per foot (vertical length). Please refer to Appendix 2

38
Artificial lift
With the completion design presented above, at the beginning of production when the reservoir is pressurised, there is no need for artificial lift. However, as the reservoir is depleted, the differential pressure between the reservoir and the bottomhole decreases and
the reservoir liquids cannot flow to the surface anymore (see Figure 27 ).
Figure 27
Tubing flow optimisation within the tubing: ESP
120
100
80
60
40
20
0
Tubing performance without ESP
Bottomhole pressure (bara)
180
160
IPR, Pr=160 bar
IPR, Pr=124 bar
140 IPR, Pr=103 bar
TPC, No ESP
Tubing performance with ESP
Bottomhole pressure (bara)
160
140
120
100
80
60
40
20
0
0 10 000 20 000 30 000
Bottomhole flowrate (stb/d)
0
IPR, Pr=124 bar
IPR, Pr=103 bar
TPC, ESP 10 stages
TPC, ESP 90 stages
TPC, ESP 170 stages
5 000 10 000 15 000 20 000
Bottomhole flowrate (stb/d)
Electrical submersible pumps were preferred to gas lift for three reasons:

Limited gas availability (would incur an overall higher cost);

ESP has a better performance in deviated wells;

Gas specific facilities are more complex from an HSE perspective.
The number of stages of the centrifugal pump was selected in order to achieve the desired production rates as shown above.

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Wytch Farm Field development Project
The surface facilities will ensure the transport, separation and storage of the fluids produced in each one of the two wellsites. The facilities will be mainly
10
empowered by an independent electricity supplier but a back-up power station (gas turbines) will be installed to ensure the continuity of the production in a blackout scenario. They will be located 2km southeast of wellsite 2 and a forestation programme is contemplated to reduce the visual impact.
The fluid transport
11
between the wellheads and the gathering station is ensured by a system of pipelines
12
.
Figure 28
Surface facilities design (plateau rates)
39
10 Some of the produced oil (C
6+
) will also be used as a fuel
11 Assumed isothermal at T=55ºC
12 Refer to Appendix 5 for further details on the design

40
Liquid-gas separation
The pressure at the entrance of the 3-stage separator is set to 14 bar. The number of stages and the associated pressures were determined so as to maximise the API gravity of the out coming oil as well as to maximise the volumes produced. The pressure of the oilwater mixture at the exit of the separator is kept above the bubble point pressure (1.5 bar at 55ºC) to avoid gas release during the later stages.
Oil-water separation
A mechanical and an electrostatic separator are used to separate the oil and the water. Like the rest of the facilities, they were dimensioned to support the plateau production rates 13 . The processed crude will be sent to a storage tank (2 days of production capacity) and the water removed from the liquid will be treated to be reinjected in the wells.
Table 12
Handling of the products
Gas handling
Second separation process to obtain natural gas and LPG. Dispatching by pipeline and pipeline plus train respectively 14
Oil handling Storage in tanks before dispatching via pipeline
Water handling Treatment and sea water mixing before reinjection 15
The use of chemicals to ensure the effectiveness of the process is unavoidable.
The environmental regulations will be strictly respected in terms of emissions and disposal. The products used are the following:
Table 13
Use of chemicals in the surface facilities
Chemical product
Anticorrosion
Common
Oil
Antifoam
Demulsifiers
Asphaltene / WAX inhibitors
Effect
Flow assurance hinders the formation of foam
Separate oil and water
Avoid formation of asphaltenes /
WAX
Reduce formation of hydrates Hydrate inhibitors
13 Refer to Appendix 3 for further details on the design
14 Flaring is not an acceptable option
15 The salinity of the sea water being lower than the one of the water of reservoir, there is no need for desalting

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Gas
Chemical product
Glycol dehydratation system
Calcium carbonate
Amine gas treatment
Inhibitors
Effect
Separate remaining water from the gas
CO
2
removal
Acid gas removal
Reduce organic contents Water
The surface facilities are designed to handle the fluid produced during the plateau.
In the optimistic and conservative cases, the rates are the same but the length of the plateau is longer and shorter, respectively.
Table 14
Daily fluid flow rates in the surface facilities
Produced oil (stb/d)
Gas (MMscf/d)
LPG (tonnes/d)
Injected water (bbl/d)
P50
76,000
8
126
63,000
Flow assurance
In order to ensure successful and economical flow of hydrocarbon stream from reservoir to the point of sale, flow assurance was considered.
The bottomhole temperature (68 o C) is quite accurately measured and verified from various well data. The flow in the wellbore till the bubble point pressure indicates a respective bubble point temperature of around 56 o
C. This process can be confidently considered clear of asphaltenes.
However, as fluid pressure and temperature decrease, it nears the Wax and Hydrates curves, which are subject to larger uncertainty. Two options are considered for reducing the chance of Wax and Hydrates creation: heating and chemical treatment. The heating option is dropped, as the fluid will cool down along the pipeline in any case and would initiate the formation of wax and hydrates. Therefore the proposed solution is injection of chemical additives (inhibitors) that would set the wax and hydrates's limits far from the operating conditions region.
41

42
Figure 29
Phase envelope of the reservoir fluid: flow assurance between reservoir and surface
SOURCE: PVT simulation based on the reservoir fluid composition from well 1X-02

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Table 15
Oil, gas and LPG market requirements
Client
Oil
Fawley refinery
(Esso)
Gas
National grid
API 41 o ± 5 o CH
4
> 96% (vol)
LPG
LPG processing plants
C
2
-C
5
Water cut < 0.01% Water cut < 0.01%
BS&W 16 < 0.02% No liquid phase content
H
2
S ≤ 5 mg/m
Salt < 6.0 PTB
3
18
H
2
S ≤ 5 mg/m 3
S content 17 ≤ 50 mg/m 3
H
2
≤ 0.1% (molar)
O
2
≤ 0.2% (molar)
WN 19 ≤ 52.85 MJ/m 3
ICF 20 ≤ 0.48
Pressure 1.03 bar
Tie-in Pressure 75 bar
Temperature 15 o C
Water cut < 0.01%
H
2
S ≤ 5 mg/m 3
Pressure 30 bar 21
SOURCE: Oil: Refinery processing design (Esso)
Gas Safety Regulations 1996 (UK Legislation n°551)
LPG transportation & safety standards, client demands
While designing the pipeline path, four main constraints were taken into account:

To avoid environmentally sensitive areas;

To avoid urban areas in order to minimise hazards for the local population;

To ensure smoothest and smallest elevation changes occur in order to minimise losses and ensure a stable flow along the pipeline;

To follow the public road path as much as possible in order to ensure the least number of private stakeholders impeding the project progress.
16 Base Sediment and Water
17 Including H
2
S
18 Pounds of salt per Thousand Barrels of crude oil
19 Wobbe number
20 Incomplete Combustion Factor
21 To ensure that all transported HC components are in liquid phase
43

44
The total length of pipeline proposed for crude oil delivery to the Fawley Refinery is 74.5 km with a maximum elevation difference of 74 meters.
Considering the relatively short distance and small elevation changes, a single pumping system will be installed at the output of the surface facilities. A pump with a nominal differential pressure of 10 bar and a 18” OD pipeline will be used for that purpose
22
.
Figure 30
Oil pipeline design path
The nearest high pressure National Grid network pipeline point was detected at the vicinity of Iwerne Courtney, north of Blandford Forum
23
.
The pipeline designed has a length of 34.1 km and shares common path with the oil pipeline for more than half of its length (20 km), in order to reduce digging costs and building time and it similarly follows mainly public roads and rural state properties path due to licensing concerns. The maximum elevation difference is 110 m, however due to the low density of gas, the hydraulic head pressure loss is considerably lower than for the oil pipeline. It will be built according to the regulation T/SP/SSW/22 August 2007 by
National Grid. A compressor with a nominal differential pressure of 78 bar and a 8” OD pipeline will be used for that purpose and a pressure regulating station will be built at the tie-in point 14 .
22 Please refer to Appendix 4
23 Please refer to Appendix 4

Marcel&Conrad for Team B
Wytch Farm Field development Project
Figure 31
Gas pipeline design path
45
The Liquefied Petroleum Gas will be exported by railway, by developing a gathering and loading station aside the national rail route next to Corfe Castle, 4 km from the surface facilities. The transport from the surface facilities to the loading station will be ensured by pipeline. During plateau, the Wytch farm field will be producing about 126 tonnes of LPG per day
24
. During the decline, when no more than a single truck per day would be required, LPG transport will be switched to road.
Figure 32
LPG plant location and pipeline path
24 126 tonnes are the equivalent of 6 trucks which is not economically and environmentally viable.

46

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Wytch Farm Field development Project
47

48
Assumptions, CAPEX and OPEX
The economic analysis on the Wytch Farm FDP was run using P50 case parameters
shown in Table 16 .
Table 16
Main assumptions: market and costs
Parameter
Discount Rate
Inflation Rate
Price of Oil ($/STB)
Price of Gas ($/Mscf)
Price of LPG ($/Mscf)
Average Drilling Cost/Well (USD millions)
Average Drilling Cost/ft
First Oil (Year)
GOR scf/STB
Part of methane (%)
Part of LPG (%)
Value
15%
2%
15
1.7
12.4
14.2
700
2016
320
40%
52%
All values shown in this analysis are nominal unless otherwise indicated. The capital expenditure of this project includes infrastructure, pipelines, drilling expenditure and surface facility which all amounts to $455 million:
Figure 33
Summary of expenditures over the field lifetime: CAPEX

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Wytch Farm Field development Project
Operating expenditure required to operate the field to optimum conditions include well maintenance, facility testing, inspection and maintenance, insurance on assets, operating personnel and field operations:
49
Figure 34
Summary of expenditures over the field lifetime: OPEX
As in any project, investment will cause the cash flow to be negative, however, once production is commenced revenues are gained thus making the cash flow positive.
As mentioned previously, in the field abandonment section, a $100 million will be set aside for abandonment in a secure account to be used in case the field is abandoned.
This practice is required by the government to ensure that the companies are responsible for their projects and to ensure that there will be no financial burden put on the government. This is not a practice in the industry but it proves the commitment of the company to environmental concerns.
Figure 35 shows the non-discounted nominal cash flow for the FDP alongside the
discounted cumulative net cash flow.

50
600
400
200
Figure 35
Economic viability of the project: cash flows
Cash flows throughout the field lifetime (non discounted)
USD millions
800
0
(200)
(400)
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26
OPEX
CAPEX
Total Revenue
Abondonment allocation
Abandonment
Year
Return on Abandonment Investment
Cummulative Discounted Net Cashflow
Net cash flow
Utilising the economic model, the pre-tax NPV
15% for the base case amounts to
$734 million with an internal rate of return of 39.7% indicating a commercially viable project. The breakeven price for the project was found to be $6.19.
Moreover, with a price of oil at $15 the payback period is in 5.48 years calculated from the start of the project. The field will be abandoned after 23 years of production, due
to incurred losses the consequent years. Table 17 below shows a summary of P10, P50,
P90 economic analysis.
Table 17
Economic facts: optimistic, base case and pessimistic cases
Reserves (MMstb)
NPV
15%
(USD millions)
IRR (%)
Payback in years from start of project (Date)
Breakeven Oil Price (S/stb)
Production duration (Year of
Abandonment)
B/C
P10
412
928
41.5
5.4 (Q2 2018)
5.2
P50
318
735
39.7
P90
219
442
34.0
5.4 (Q2 2018) 5.6 (Q3 2018)
6.19
25 years (2041) 23 years (2039)
2.1 1.7
8.35
19 (2035)
1

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Sensitivity analysis
The spider plots displayed in
Figure 36 and
Figure 37 exhibits the parameters that impact both NPV and IRR. The higher the slope of a particular parameter the more impact it has on NPV or IRR.
For example, from Figure 36 , it is evident that discount rate that the company sets
has the highest impact on NPV, followed by oil prices which can be unpredictable due to frequent fluctuations. However, in the case of IRR, fluctuating oil price have the highest impact and is the parameter that IRR is mostly sensitive to. Moreover, NPV and IRR are both sensitive to rate of the plateau as seen in the figure, the sharp curvature observed can be explained by the effects of time value of money.
Figure 36
Parameters affecting the Net Present Value
Sensitivity analysis on the Net Present Value (NPV)
NPV (USD million)
2 000
1 800
1 600
1 400
1 200
1 000
800
600
Oil Price
CAPEX
Plateau
Discount Rate
OPEX
400
200
0
-80% -60% -40% -20% 0% 20% 40% 60% 80% 100%
Variation from basecase
Figure 37
Parameters affecting the Rate of Return
Sensitivity analysis on the Rate of Return (IRR)
IRR (%)
60%
51
50%
40%
30%
Oil Price
CAPEX
20%
Plateau
Discount Rate
OPEX
10%
-80% -60% -40% -20% 0% 20% 40% 60% 80% 100%
Variation from basecase

52

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Wytch Farm Field development Project
53

54
Reservoir volume uncertainties
It is fundamental to keep in mind that the process of building both a static and a dynamic model was done with the final objective of defining a field development strategy and to estimate its performances. However, the uncertainties are inherently associated with each step of this process because:
 the available data are never enough to fully characterise the reservoir;
 the interpretation process adds errors;
 a model cannot fully represent the reality.
Thus, it was decided to run a sensitivity analysis that would capture both the static
and dynamic uncertainties. Figure 38 shows for each realisation (dot), the variation with
respect to the base-case cumulative production estimate. Each parameter can be assessed by looking at the spread of the realisations as well as to the maximum and minimum values.
Figure 38
Static and dynamic uncertainty assessment
Sensitivity analysis on the cumulative production
Cumulative production (MMbbl)
450
400
350
300
250
200
Base case
GRV
Porosity
Kv
Sw
Kh
Corey O/W
Corey W
Sorw
Swcr
Swmin
Faults transmissivity
Variation parameter

Marcel&Conrad for Team B
Wytch Farm Field development Project
The tornado chart ( Figure 39 ) presents the parameters according to their impact
into the final volume estimate. Three parameters stand out:

GRV: as explained in the first section, this error comes from the difficulty to estimate the exact position of the top of the reservoir as well as the OWC;

Oil relative permeability: this dynamic parameter has a great impact on the oil recovery and was poorly estimated because of the available data;

Horizontal permeability.
Figure 39
Tornado chart presenting the main uncertainties
55
Variation parameter
GRV -31%
Oil relative permeability -30%
Horizontal permeability
Oil residual saturation
Connate water saturation
Vertical permeability
Porosity
Water saturation
Water relative permeability
Faults transmissivity
Critical water saturation
-18%
1%
-9%
-8%
-6%
-4%
-2%
-2%
2%
-1% 0,5%
-0,1% 0,5%
1%
0.1%
3%
1%
0,5%
15%
13%
-35% -25% -15% -5% 5% 15% 25% 35%
Variation from basecase
This uncertainty analysis justifies the use of different scenarios (optimistic, base case, and conservative) as a decision making tool. Moreover, a mitigation scheme based on a data acquisition plan will be presented in the next section.
Economic value of the field uncertainties
The tornado chart shown in the figure above echoes the results seen in the spider plots. However, even though the tornado chart does not display the non-linearity of the economic model, it can outright show the highest parameter with the most impact on the
NPV or IRR, thus it is usually utilised in tandem with spider plots to assess risks and uncertainty. Discount rate is has the highest impact on NPV followed fluctuation in oil prices.

56
Figure 40
NPV uncertainty analysis
Variation parameter
Discount rate -60%
Oil price -31%
Production
CAPEX
-30%
-25%
8%
3%
19%
31%
Downside
Upside
OPEX -10% 10%
-100% -80% -60% -40% -20% 0% 20% 40% 60% 80% 100%
Variation from basecase

Marcel&Conrad for Team B
Wytch Farm Field development Project
Data acquisition plan
A shrewd data acquisition plan was developed in order to have a better understanding of the reservoir and to reduce the uncertainty surrounding the model that will lead to having a good geological flow model.
Seismic data will be reprocessed to reduce the uncertainty in the estimated GRV.
This is achieved by carefully picking the tops and bottoms of the reservoir and fluid contacts.
The first three wells in three different reservoir locations will be cored. Extensive
RCAL and SCAL will be run on the retrieved cores to have more accurate measurements of relative permeabilities and capillary pressure curves for both drainage and imbibition to improve the geological flow model for a more confident history matching and prediction.
Moreover, full suite logs will be run on the aforementioned three wells including
NMR and PNL to have independent sources for porosity, permeability and fluid saturations. The calculated permeabilities from NMR will be used alongside permeabilities measured from cores to improve and calibrate the permeability model.
Fluid samples will be taken from the first two drilled wells to have a detailed PVT analysis that will go into the geological flow model.
Furthermore, RFTs will be run on all the wells to evaluate reservoir connectivity, faults transmissibility, aquifer strength and will be utilised as a tool to aid in history matching.
Figure 41
Data acquisition plan
Reprocess Seismic Data
Coring
Fluid Sampling
RFT
Full Suite Logs
SBHP/T
Separator/Wellhead Samples
Well Rate Tests
PLT
PNL
Oil Production
2016 2017 2018 2019 2020 2021
Year
2022 2023 2024 2025 2026 To 2039
Further down the road in the life of the field, shut-in bottomhole pressures and temperatures will be acquired on a real-time basis using SCADA system. A multiphase flow meter will be installed on each drillsite to aid in a monthly rate testing of producers
57

58 to ensure an accurate production allocation system and to aid in material balance analysis.
PLTs will be utilised on producers that have water production to identify the perforations that needs to be squeezed to reduce that amount of water produced and optimise oil production.
Finally, wells that are unexpectedly underperforming will be shut-in for pressure measurements which in turn will be utilised in pressure transient analysis to evaluate possible problems that could hinder the subject wells and then treat them accordingly.
Following the data acquisition scheme presented above will ensure that the model can behave as closely as possible to the actual reservoir and it will also ensure that the reservoir is monitored closely during the production period, thus guaranteeing that the reservoir is being efficiently optimised for oil production.
Global risk management
The risks for development and operation of the Wytch Farm oil field have been assessed and split into three main categories:

Operational : include possible accidents and production related risks throughout the operational lifecycle of the field;

Regulatory & Commercial : mainly focused on political and market changes that may affect the profitability of the operation

Communal : refer to pressure by local groups and society, as well as workforce related issues
Figure 42
Risk assessment chart

Marcel&Conrad for Team B
Wytch Farm Field development Project
An in depth planning and risk analysis is required in order to mitigate the potential threats to the field development and operation. Main threats have been detected and
preventive actions are proposed in Table 18 .
Table 18
Risk mitigation scheme
59
Risk types Risk Mitigation
Operational
Regulatory
& Commercial
Communal
Oil spill
Flow assurance, regular facilities checks and spill constraining and cleaning plan.
Labour accidents
Oil & Gas
Price
Compulsory initial training and regular seminars. Use of working gear in every operation, housekeeping, regular inspections.
Prepare production plans with reduced production during low price periods.
Environmental
Groups
Prepare and present plans for pollution prevention, noise reduction and ensure about safety and no effects on aquifer and sea pollution by re-injecting all the produced water.
Local
Community
Promise to open work placements for locals, promote environmental plans in order not to pollute or affect local tourism and landscape.

60

Marcel&Conrad for Team B
Wytch Farm Field development Project
The development team throughout the planning phase have demonstrated that:
 health, safety and environmental regulations set by the governmental authorities are upheld and met to ensure that the proposed plan go ahead as scheduled;
 proactive reservoir management practices coupled with an effective data acquisition plan are set in place to optimise the value of the Wytch Farm field;
 risks and uncertainties have been assessed and subsequent mitigation schemes have been designed;
 the plan will achieve high profitability and economic value.
Thus, the team strongly recommends the development of the field and that the company should go ahead with the project.
Finally, this team following company values, will always produce this field safely , reliably and cost-effectively .
61

62
1. ASME. Hydrogen Piping and Pipelines B31.12, ISBN: 9780791831755, 2008.
2. Ayoade MA. Disused Offshore Installations and Pipelines, Kluwer Law International ,
2002.
3. BP. Wytch farm Sherwood development Reasons why it was developed as it is, BP for
Imperial College , 2012.
4. Buckley SE, Leverett MC. Mechanism of Fluid Displacement in Sands, Petroleum
Transactions, AIME , 1942; 146: 107-116.
5. Dake LP. Fundamentals of Reservoir Engineering, Elsevier, 1978.
6. Dall RN, Gilliver RE, Sclater R. Crawford: The first UK Field Abandonment, SPE
25062, 1992.
7. Johnson, H.D. A Field Guide to the Geological Evolution & Controls on Petroleum
Occurrences in the Wessex Basin (southern England) , 2011
8. Underhill JR, Stonely R. Introduction to the development, evolution and petroleum geology of the Wessex Basin, Geological society special publication, 1988; 133: 1-18.

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63

64
List of figures
Figure 1 - Location of the Wytch Farm Field and appraisal wells ...................................... 9
Figure 2 - Wytch Farm petroleum system map showing hydrocarbon migration ............. 12
Figure 3 - Top Sherwood map from geophysical interpretation ........................................ 13
Figure 4 - Fault surfaces of the major faults within the Wytch Farm field ....................... 15
Figure 5 - Repeat formation tester as a quality check for the OWC .................................. 17
Figure 6 - Sand-shale model within the zone 6 after petrophysical modeling................... 19
Figure 7 - Permeability model within the zone 6 after petrophysical modeling ................ 19
Figure 8 - Horizontal permeability in zone 1 ..................................................................... 20
Figure 9 - QC of upscaled volumetric properties............................................................... 21
Figure 10 - Coarse model consistency: history match ...................................................... 21
Figure 11 - STOIIP sensitivity analysis ............................................................................. 22
Figure 12 - Drive mechanism determination ..................................................................... 24
Figure 13 - Using water injection to maintain the reservoir pressure ................................ 25
Figure 14 - Water injection strategy: water source ............................................................ 25
Figure 15 - Water injection results: high sweep efficiency ............................................... 26
Figure 16 - Environmental constraints and well site locations .......................................... 27
Figure 17 - Well configuration within the reservoir .......................................................... 28
Figure 18 - Detailed drilling schedule based on the highest rates ..................................... 29
Figure 19 - Development strategy results: 3-year plateau achieved (Oil) ......................... 30
Figure 20 - Development strategy results: 3-year plateau achieved (Gas) ........................ 30
Figure 21 - Health risk management workflow: hazard prevention .................................. 32
Figure 22 - Safety risk management workflow: hazard prevention ................................... 33
Figure 23 - Environmental risk management workflow: hazard prevention ..................... 33
Figure 24 - Project lifecycle ............................................................................................... 34
Figure 25 - Design of the casing and the tubing with the formations ................................ 36
Figure 26 - Determination of the optimum mud weight .................................................... 37
Figure 27 - Tubing flow optimisation within the tubing: ESP .......................................... 38
Figure 28 - Surface facilities design (plateau rates) ........................................................... 39
Figure 29 - Phase envelope of the reservoir fluid: flow assurance .................................... 42
Figure 30 - Oil pipeline design path .................................................................................. 44
Figure 31 - Gas pipeline design path ................................................................................. 45
Figure 32 - LPG plant location and pipeline path .............................................................. 45
Figure 33 - Summary of expenditures over the field lifetime: CAPEX ............................ 48
Figure 34 - Summary of expenditures over the field lifetime: OPEX ............................... 49
Figure 35 - Economic viability of the project: cash flows ................................................. 50
Figure 36 - Parameters affecting the Net Present Value .................................................... 51
Figure 37 - Parameters affecting the Rate of Return ......................................................... 51
Figure 38 - Static and dynamic uncertainty assessment .................................................... 54
Figure 39 - Tornado chart presenting the main uncertainties ............................................ 55
Figure 40 - NPV uncertainty analysis ................................................................................ 56
Figure 41 - Data acquisition plan ....................................................................................... 57
Figure 42 - Risk assessment chart ...................................................................................... 58

Marcel&Conrad for Team B
Wytch Farm Field development Project
List of tables
Table 1 - Depositional characteristics of the zones ........................................................... 13
Table 2 - Hierarchy and impact of structural and stratigraphic reservoir heterogeneities . 14
Table 3 - Tests performed on the exploration wells .......................................................... 16
Table 4 - Reservoir initial conditions ................................................................................. 16
Table 5 - Summary of reservoir rock parameters .............................................................. 18
Table 6 - Summary of fluid properties ............................................................................... 18
Table 7 - Building a dynamic model .................................................................................. 20
Table 8 - Static model volumetrics: STOIIP and reserves ................................................. 22
Table 9 - Well characteristics ............................................................................................ 27
Table 10 - Drilling and completion specifications ............................................................. 29
Table 11 - Development strategy results: recovered oil .................................................... 31
Table 12 - Handling of the products .................................................................................. 40
Table 13 - Use of chemicals in the surface facilities ......................................................... 40
Table 14- Daily fluid flow rates in the surface facilities ................................................... 41
Table 15 - Oil, gas and LPG market requirements ............................................................ 43
Table 16 - Main assumptions: market and costs ................................................................ 48
Table 17 - Economic facts: optimistic, base case and pessimistic cases ........................... 50
Table 18 - Risk mitigation scheme .................................................................................... 59
65

66
List of abbreviations
ICF
ID in
IRR
ISO k h k v
LPG m
M
MD
°C
ΔP
Φ (or PHIE)
API bar / bara barg bbl
BHT
Bo bopd bpd
BS&W
BTU
CAPEX
CCTV cP
Csg
DECC
DST
ESD / ESV
ESP
FWL
GOR
GRV h
HSE
Degrees Celsius
Pressure difference
Porosity
American Petroleum Institute
10
5
Pa / 14.7 psi (absolute pressure)
10
5
Pa / 14.7 psi (pressure)
Barrel of liquid (volume)
Bottomhole Temperature
Oil formation volume factor
Barrel of oil per day
Barrel of liquid per day
Basic Sediments and Water
British Thermal Unit
Capital Expenditure
Closed Circuit Television
Centipoise (10 -3 Pa∙s)
Casing
Department of Energy and Climate Change
Drill Stem Test
Emergency Shutdown Valve
Electric Submersible Pump
Free Water Level
Gas to Oil Ratio
Gross Rock Volume
Hours
Health Safety Environment
Incomplete Combustion Factor
Inner diameter (for circular pipes)
Inches
Internal Rate of Return
International Organization for Standardization
Horizontal permeability
Vertical permeability
Liquefied Petrol Gas
Metres
Thousand (in front of fluid volume units)
Measured Depth

PLT
PNL
PPE ppm
PTB
PV
PVT
QC rb
RCAL
RF
RFT mD
MM
N/G
NMR
N pD
NPV
OD
OPEX
OWC
SCADA
SCAL scf sg
S o
S or stb
STOIIP
S w
S wc t
D
TPC
TVD (TVDSS)
UK
USD
WN
Marcel&Conrad for Team B
Wytch Farm Field development Project
10
-3
Darcies (permeability)
Million (in front of fluid volume units)
Net to Gross ratio
Nuclear Magnetic Resonance
Pore volume of oil produced (dimensionless)
Net Present Value
Outer diameter (for circular pipes)
Operational Expenditure
Oil Water Contact
Production Logging Tool
Pulsed Neutron Log
Personal Protective Equipment
Parts per million
Pounds of salt per Thousand Barrels of crude oil
Pore Volume
Pressure Volume Temperature
Quality Control/Check
Reservoir (condition) Barrels
Routine Core Analysis
Recovery Factor
Repeat Formation Tester
Supervisory Control And Data Acquisition
Special Core Analysis
Standard (p, T conditions) cubic feet (2.8∙10
-2
m³)
Specific gravity (mud weight)
Oil saturation
Irreducible oil saturation
Stock tank barrel
Stock Tank Oil Initially in Place
Water saturation
Connate water saturation
Dimensionless time (pore volume injected)
Tubing Performance
True Vertical Depth
United Kingdom
United States Dollar(s)
Wobbe Number
67

68
The perforation density chosen is 8 SPF. A higher density would not increase the production significantly enough.
Perforation density sensitivity
Liquid production rate
(stb/d)
15200
15000
14800
14600
14400
14200
14000
13800
0 5 10 15 20
Perforation density (shot/ft)
25 30

Marcel&Conrad for Team B
Wytch Farm Field development Project
Oil/Gas separation
Oil/Gas separation was performed in such a way that the API gravity and the volumes were maximised. The incoming and out coming compositions were:
Incoming Oil Outgoing Oil Outgoing Gas
Component
No of moles of liq
(lbmol)
Liq density
(lb/ft 3 )
Mass of liquid
(lb)
Vol of liq
(ft 3 )
No of moles of liq
(lbmol)
Vol of liq
(ft 3 )
No of mols of gas
(lbmol)
CO2 1.70E-03 51.3 0.0748 1.46E-03 1.30E-04 1.11E-04 1.72E-03
N2
C1
2.67E-02
1.47E-01
50.5
18.7
0.748
2.36
1.48E-02
1.26E-01
9.09E-06
9.07E-04
5.04E-06
7.77E-04
2.72E-02
1.53E-01
2.12 9.50E-02 2.33E-02 3.14E-02 5.84E-02 C2
C3
7.06E-02 22.3
1.00E-01 35.2
2.56E-02 36.5 iC4 nC4 6.92E-02 39.0 iC5 2.94E-02 39.4 nC5 3.85E-02 41.4
4.43
1.49
4.02
2.12
1.26E-01
4.08E-02
1.03E-01
5.39E-02
4.98E-02
2.22E-02
6.61E-02
3.46E-02
6.25E-02
3.54E-02
9.85E-02
6.33E-02
7.66E-02
1.21E-02
2.80E-02
6.59E-03
C6
C7+
5.29E-02
4.37E-01
41.7
54.3
2.78 6.70E-02 4.71E-02 8.20E-02 7.01E-03
4.56 1.09E-01 7.20E-02 1.49E-01 3.62E-03
103 1.91 6.19E-01 2.69 1.00E-02
128 2.64 9.35E-01 3.22 3.84E-01 Total 9.99E-01
Oil/water separator sizing
Vol of gas
(scf)
In order to separate oil and water, two consecutive processes will be used:

Mechanical separation

Electrostatic separation
The equipment is sized to receive a maximum liquid rate of 95,000 stb/d (maximum combined oil and water rate reached).
29.1
4.61
10.6
2.50
2.66
1.37
3.80
146
0.652
10.3
57.9
22.2
The separation is assumed isothermal at 55°C.
The mechanical separator’s volume is determined considering the fluid stays 10 min in the separator.
69

70
10
𝑉 = 95000 ∗
24 ∗ 60
= 660 𝑏𝑏𝑙 = 105 𝑚 3
The electrostatic separator’s area is determined by determining the electrostatic factor.
The water separation velocity is determined graphically knowing our operating temperature.
Water separation velocity vs temperature
Velocity (Stokes)
10
1
0 50 100 150
Temperature (deg C)
200 250
The separation is thus made at V s
=7.1 Stokes.
The separation velocity is related to the electrostatic factor and is determined as
12 0 𝑏𝑝𝑑/𝑓𝑡 2
.
So the contact area of the electrostatic separator is
𝐴 =
95000
= 792 𝑓𝑡 2
120
= 74 𝑚 2
The constraints over the operational pressure leaded to the choice of a pressure of 1.5 bar.

Marcel&Conrad for Team B
Wytch Farm Field development Project
71
Operational pressure determination
Pressure (bar)
25
20
15
10
5
Bubble point pressure
Minimum required pressure
Operational pressure
0
40 60 80 100 120
Temperature (deg C)
140 160
For contingency reasons, the separators are designed 10% larger than required.
Mechanical separator volume ( 𝒎 𝟑 )
Electrostatic separator area
( 𝒎 𝟐 )
Designed
105
74
Chosen
116
81

72
The gas pipeline has been designed to provide a delivery outlet pressure of 75 bar with a pump outlet pressure of 78 bar. As a result, a pipeline outer diameter of 8” which delivers a slightly higher pressure has been chosen, knowing that the pressure can be easily decreased using a pressure control device.
Gas pipeline design
77
75
73
71
69
67
65
Delivery outlet pressure (bar)
81
79
4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21
Pipeline OD (inches)
The oil pipeline has been designed to deliver oil at stock tank conditions (1.03 bar).
An outer diameter of 18” has been chosen to minimise the cost while targeting our specifications. The higher pressure delivered can also be controlled by the same means as the gas one.
Oil pipeline design
Delivery outlet pressure (bar)
1,06
1,04
1,02
1
0,98
0,96
0,94
0,92
0,9
13 14 15 16 17 18 19 20 21 22 23 24 25
Pipeline OD (inches)

Marcel&Conrad for Team B
Wytch Farm Field development Project
The flowline design adopted is based on a two-by-two step optimisation: the flowline is optimised for two wells at a time.
Three groups of wells were considered in order to carry on the overall optimisation.
The distance between the two rigs is assumed to be equal to 2km and the distance between the wells is around 20m.
The pressure at the gathering station is 14 bar and a multiphase booster is used in the last flowline to ensure this objective is reached.
73

74
This figure presents the high pressure pipeline of National Grid near the Dorset region. The selected tie-in location is north of Blandford Forum, at Iwerne Courtney.

Marcel&Conrad for Team B
Wytch Farm Field development Project
Economic viability of the project: cash flows, optimistic model
Cashflows throughout the field lifetime
USD millions
1 000
OPEX
CAPEX
800
600
400
Total Revenue
Abandonment Allocation
Abandonment
Return on Abandonment
Investment
Cummulative Discounted Net
Cashflow
200
75
0
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28
(200) Year
(400)
Economic viability of the project: cash flows, conservative model
OPEX
Cashflows throughout the field lifetime
USD millions CAPEX
500
Total Revenue
400
300
200
100
Abondonment allocation
Abandonment
Return on Abandonment
Investment
Cummulative Discounted Net
Cashflow
0
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22
(100)
(200)
(300)
(400)
Year

76
Cover page pictures:
Plants and our environment, ThinkQuest Library
Field Engineer with full PPE gear, Schlumberger
Safety signs, HSE UK government website
Natural Gas station road sign , Germany
Sunset at oilfield facilities, Eastern Energy Pvt Ltd, Pakistan
Iran to India Natural Gas Pipeline, Iran
Oil refinery, Earthly Issues website
New unit installations planning, General Electric Energy
Big Ben, London UK