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Marcel&Conrad for Reservoir Engineering Team B

Wytch Farm Field

development project

Plan, results and key recommendations

March 2012

Marcel&Conrad

Marcel&Conrad for Team B Wytch Farm Field development Project

This page is intentionally left blank

Marcel&Conrad for Reservoir Engineering Team B

Wytch Farm Field

development project

Plan, results and key recommendations

March 2012

Mohammed Alshawaf Lanray Hammed Bakare Francisco J. Barroso Viseras Aristeidis Karamessinis Ha Nguyen Shi Su


Health, Safety and Environment statement

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: 22th

of March 2012

Marcel&Conrad 2012

Wytch Farm field within Dorset county

10km

Source rock: Liassic Mudstone

Reservoir rock: Sherwood Sandstone

Cap rock: Mercia Mudstone

Oil accumulation: fault trap with

migration during the basin extensional

period

Petroleum System & Reservoir Characterisation

Field Development

Project economics

Mitigation scheme and recommendations

Natural mechanisms allow low

recovery

Water injection strategy

Environmental constraints

Environmental regulations

upheld

High profitability achieved

Shrewd reservoir management

practices planned

Efficient mitigation schemes

designed

Contents

Introduction 9

1. Characterising the reservoir 11

Petroleum system 12

Reservoir structure 12

Description of heterogeneities 14

Rock and fluid properties 16

Reservoir modeling 19

Volumetric estimation and associated uncertainties 22

2. Developing the field 23

Reservoir drive mechanisms 24

Production strategy 25

Drilling strategy 27

Development strategy results 30

Export and surface facilities 31

HSE policy 32

Field abandonment and decommissioning 34

Project lifecycle 34

3. Engineering design 35

Well performance 36

Surface facilities 39

Hydrocarbon export 43

4. Economic evaluation 47

Expenditures 48

Cash flows and economic evaluation 49

5. Uncertainties and risk management 54

Assessing the uncertainties 55

Risk mitigation scheme 58

6. Key considerations and recommendations 62

References 63

Appendices 64

7,492 words

(key figures page)

$735 million Net Present Value of the project

318 million Stock tank barrels of recoverable oil

23 years Production plan


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Marcel&Conrad for Team B 9 Wytch Farm Field development Project

Introduction

Aim & Objectives

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.

Location and context

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

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.


1. Characterising the reservoir

12

Petroleum system

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 Atlantic1. 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

Reservoir structure

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


Table 1

Depositional characteristics of the zones

Zone Characteristics

1 Lacustrine

Thick, laterally extensive low-permeability, low-porosity,

lacustrine/playa deposits of the Upper-Sherwood. In outcrop, seen

as gradational transition into Mercia Mudstone.

2 Multi-storey

channel deposits

A maximum 40 m thick multi-storey channel deposits with thinner

interbedded floodplain muds, within the oil-pay zone.

3 Floodplain Laterally extensive low-permeability, low-porosity flooding events.

4 Multi-Lateral

braided Channels

Multi-lateral stacked braided channel system of high net-to-gross

sand, part of principal reservoir within pay-zone.

5 Floodplain 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

14

Description of Heterogeneities

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

Ba

rrie

r

Ba

ffle

Co

mp

art

men

tali

sati

on

La

tera

lly

ex

ten

siv

e

Flo

w t

ort

uo

sity

Str

uct

ura

l

Sealing Fault Giga

Non-sealing Fault Giga

Sed

imen

tolo

gic

al

Lacustrine muds Mega

Flood deposit muds Mega

Abandoned channel

mudstone 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.


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

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 kv 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 kh. Examples include mud plugs and cemented

channel lag deposits. Despite this, vertical connectivity and kv 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

Rock and fluid properties

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

Wir

elin

e

DS

T

RF

T

RC

AL

SC

AL

PV

T

Pro

du

ctio

n

test

Ap

pra

isal

1K-01

1F-11

98/6-8

Pro

du

ctio

n

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 39 m

OWC 1620 m

Areal extent 40 km2

Pressure 165 bar

Temperature 66°C


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.

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

The following table summarises the main parameters obtained from these analysis

and the method(s) used to derive them:

1540

1560

1580

1600

1620

1640

1660

1680

1700

165 170 175 180

Depth (m)

Pressure (bar)

Reservoir depth as a function of pressure

Well 1K-01 Water gradient 0.074 bar/m Oil Gradient 0.11 bar/m FWL 1624 m

1580

1600

1620

1640

1660

1680

165 170 175

Depth (m)

Pressure (bar)

Well 98/6-8 Water gradient 0.070 bar/m Oil Gradient 0.11 bar/m WL 1622 m

18

Table 5

Summary of reservoir rock parameters

Parameter / Property Method Well average

Top Sherwood (m) Seismic acquisition, logs 1556 ± 15

OWC (m) Resistivity log, cores and RFT 1624 ± 5

Porosity Logs and core analysis 15% ± 2%

Hor. Permeability (mD) Core analysis, DST 112

Water saturation Logs (Indonesian) and cores 40% ± 7%

Net/Gross Cut-offs 68% ± 8%

Fluid properties: PVT and core analysis

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

Fluid properties2

API gravity 38.1° @ 15°C

GOR 320 scf/stb

Formation volume factor 1.21 rb/stb

Oil density 0.74 g.cm-3

Oil compressibility 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


Reservoir modeling

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

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

Constraint Dynamic model

Grid dimensions 100x100 Capture geological and

petrophysical hetereogeneities 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 kx, ky

Honour the channel

distribution Arithmetic

Vertical

permeability kz Capture the heterogeneities 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 permeability3 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.


Figure 9

QC of upscaled volumetric properties

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

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.

10,221

1,359 793

9,932

1,378 799

-

2,000

4,000

6,000

8,000

10,000

12,000

GRV PV STOIIP

MMbbl

QC of upscaled volumetric properties

Fine grid

Coarse

0

20

40

60

80

100

120

140

160

180

0 1 2 3 4 5 6 7 8 9

Water production rate (stb/d)

Time Elapsed (years)

Water and oil production rate history match

Simulation

Observed data

0

500

1,000

1,500

2,000

2,500

3,000

3,500

0 1 2 3 4 5 6 7 8 9

Oil production rate (stb/d)


Simulation

Observed data

22

Volumetric estimation and associated uncertainties

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) 580 795 1040

Reserves (MMstb) 219 318 412

The key uncertainties affecting the STOIIP estimate were assessed using a

statistical approach4. 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

4 Monte Carlo repeated random sampling method

77%

11%

9%

3%

-65%

-22%

-7%

-4%

-80% -60% -40% -20% 0% 20% 40% 60% 80%

GRV

Sw

PHIE

Bo

Variation from base case (normalised to a 100%)

Variation parameter


2. Developing the field

24

y = 0.004x + 644.55

0

200

400

600

800

1000

0 30,000 60,000 90,000

F/Eo [106 stb]

ΔP/Eo [psi.stb/rb]

Aquifer with solution gas

Reservoir drive mechanisms

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 validated5. The two combinations considered are presented in Figure 12: aquifer

with solution gas drive and solution gas with compaction drive.

Drive mechanism determination

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 option7.

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

y = 276.81x + 0.3409

0.0

0.4

0.8

1.2

1.6

2.0

0 0.002 0.004 0.006

F [106 rb]

Eo + Ef [rb/stb]

Solution gas with compaction drive

N=645 MMstb

N=277 MMstb

Figure 12


Production strategy

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

Figure 14

Water injection strategy: water source

0

20

40

60

80

100

120

140

160

180

0 2 4 6 8 10 12 14 16 18 20 22

Reservoir pressure (bar)

Time Elapsed (year)

Reservoir pressure profile throughout the field life

With injection

Without injection

0

10

20

30

40

50

60

70

80

90

100

0 2 4 6 8 10 12 14 16 18 20 22

Percentage of water


Composition of the injected water

Pumped sea water

Produced water

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

0

0.1

0.2

0.3

0.4

0.5

0.6

0 0.2 0.4 0.6 0.8 1

Dimensionless pore volume produced (NpD)

Dimensionless time (tD)

Pore volume produced versus pore volume injected

Theoretical Buckley Leverett

One-to-one line

1-Swc-Sor

Simulation

Water breakthrough


Drilling strategy

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

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 Producer (P)

Injector (I) Type Length (m)

Horizontal

section length (m)

1 1P-01 Horizontal 6,856 2,130

1 1P-02 Horizontal 11,305 5,370

Multilateral 2,700 1,400

28

1 1P-03 Horizontal 3,682 1,300

1 1P-04 Horizontal 3,811 1,400

1 1P-05 Horizontal 2,428 5,00

1 1P-06 Horizontal 9,023 6,600

Multilateral 4,850 2,800

1 1I-01 Horizontal 8,918 3,000

1 1I-02 Horizontal 4,413 2,500

2 2P-01 Horizontal 6,560 3,000

2 2P-02 Vertical 1,620 N.A.

Multilateral 2,150 1000

2 2P-03 Horizontal 3,197 1,100

2 2P-04 Horizontal 3,734 1,190

2 2P-05 Horizontal 3,128 1,100

2 2I-01 Horizontal 5,767 3,800

2 2I-02 Horizontal 4,025 1,750

2 2I-03 Horizontal 5,572 2,500

Figure 17

Well configuration within the reservoir


Drilling schedule

The target is to get the first oil produced on the 1st January 2017. The drilling

schedule is as follows:

Figure 18

Detailed drilling schedule based on the highest rates

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 Water based

Mud weight 1.15 sg

Tubing ID 4”

Bottomhole casing OD 7”

Perforations All along the horizontal section, 8 SPF

Drilling

Oil production

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

1P-01

1P-02

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

Year

2016 2017 2018

Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4

30

Development strategy results

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

Figure 20

Development strategy results: 3-year plateau achieved

0

50

100

150

200

250

300

350

400

450

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

0 2 4 6 8 10 12 14 16 18 20 22

Oil produced cumulative (MMbbl) Oil rate (stb/d)


Oil: expected rates and prodcution

P90

P50

P10

0

20

40

60

80

100

120

140

0

5,000

10,000

15,000

20,000

25,000

30,000

0 2 4 6 8 10 12 14 16 18 20 22

Gas produced cumulative (Bscf) Gas rate (Mscf/d)


Gas: expected rates and production

P90

P50

P10


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

P90 P50 P10

STOIIP (MMstb) 580 795 1040

Recovered oil (MMstb) 219 318 412

Recovery factor 38% 40% 40%

Export and surface facilities8

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

HSE policy

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 CO2 separated from gas is captured. Pollution


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

Figure 23

Environmental risk management workflow: hazard prevention

34

Field abandonment and decommissioning

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.

Project lifecycle

>

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

Company approval

Planning FDP

Governmental approval

Project management

Front end engineering design

Engineering

Procurement

Construction

Commisioning

Drilling

Production

Decommissioning

Abandonment

2012 2013 2014 2015 2016 2039 2040 20412017 2018 2038

First oil

Figure 24


3. Engineering design

36

Well performance

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)

Formation

0 ----------------------------------

Unconsolidated sandstone

80 ----------------------------------

Limestone

480 ----------------------------------

Unconsolidated sandstone

503 ----------------------------------

Mudstone

898 ----------------------------------

Sandstone

933 ----------------------------------

Mudstone

1,567 ----------------------------------

Sandstone

1,747 ----------------------------------


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.

A sensitivity analysis on the perforation density was performed and the optimum

value was 8 SPF9.

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

9 Shots per foot (vertical length). Please refer to Appendix 2

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

0 50 100 150 200 250

Depth (mTVD) Pressure (bar)

Pore Pressure

Fracture pressure

Mud pressure

RFT 1K-01

RFT 1F-11

RFT 98/6-08

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

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.

0

20

40

60

80

100

120

140

160

180

0 10,000 20,000 30,000

Bottomhole pressure (bara)

Bottomhole flowrate (stb/d)

Tubing performance without ESP

IPR, Pr=160 bar

IPR, Pr=124 bar

IPR, Pr=103 bar

TPC, No ESP

0

20

40

60

80

100

120

140

160

0 5,000 10,000 15,000 20,000

Bottomhole pressure (bara)

Bottomhole flowrate (stb/d)

Tubing performance with ESP

IPR, Pr=124 bar

IPR, Pr=103 bar

TPC, ESP 10 stages

TPC, ESP 90 stages

TPC, ESP 170 stages


Surface facilities

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 mainly10

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 transport11

between the wellheads and the gathering station is ensured by

a system of pipelines12

.

Figure 28

Surface facilities design (plateau rates)

10

Some of the produced oil (C6+) 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 oil-

water 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 rates13

. 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 re-

injected 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 respectively14

Oil handling Storage in tanks before dispatching via pipeline

Water handling Treatment and sea water mixing before reinjection15

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 Effect

Common Anticorrosion Flow assurance

Antifoam hinders the formation of foam

Oil

Demulsifiers Separate oil and water

Asphaltene / WAX inhibitors Avoid formation of asphaltenes /

WAX

Hydrate inhibitors Reduce formation of hydrates

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


Chemical product Effect

Gas

Glycol dehydratation system Separate remaining water from the

gas

Calcium carbonate CO2 removal

Amine gas treatment Acid gas removal

Water Inhibitors Reduce organic contents

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

P50

Produced oil (stb/d) 76,000

Gas (MMscf/d) 8

LPG (tonnes/d) 126

Injected water (bbl/d) 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 (68oC) 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 56oC. 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.

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


Hydrocarbon export

Table 15

Oil, gas and LPG market requirements

Oil Gas LPG

Client Fawley refinery

(Esso) National grid LPG processing plants

Sp

ecif

icati

on

s

Pro

du

ct

API 41 o ± 5o CH4 > 96% (vol) C2-C5

Co

nta

min

an

ts

Water cut < 0.01% Water cut < 0.01% Water cut < 0.01%

BS&W16 < 0.02% No liquid phase content

H2S ≤ 5 mg/m3 H2S ≤ 5 mg/m3

H2S ≤ 5 mg/m3 S content17 ≤ 50 mg/m3

Salt < 6.0 PTB18

H2 ≤ 0.1% (molar)

O2 ≤ 0.2% (molar)

WN19 ≤ 52.85 MJ/m3

ICF20 ≤ 0.48

Co

nd

itio

ns

Pressure 1.03 bar

Tie-in Pressure 75 bar Pressure 30 bar21

Temperature 15oC

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 H2S 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

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

purpose22

.

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 Forum23

.

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 point14

.

22

Please refer to Appendix 4 23

Please refer to Appendix 4


Figure 31

Gas pipeline design path

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 day24

. 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.


4. Economic evaluation

48

Expenditures

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 Value

Discount Rate 15%

Inflation Rate 2%

Price of Oil ($/STB) 15

Price of Gas ($/Mscf) 1.7

Price of LPG ($/Mscf) 12.4

Average Drilling Cost/Well (USD millions) 14.2

Average Drilling Cost/ft 700

First Oil (Year) 2016

GOR scf/STB 320

Part of methane (%) 40%

Part of LPG (%) 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


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:

Figure 34

Summary of expenditures over the field lifetime: OPEX

Cash flows and economic evaluation

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

Figure 35

Economic viability of the project: cash flows

Utilising the economic model, the pre-tax NPV15% 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

P10 P50 P90

Reserves (MMstb) 412 318 219

NPV15%(USD millions) 928 735 442

IRR (%) 41.5 39.7 34.0

Payback in years from start of

project (Date)5.4 (Q2 2018) 5.4 (Q2 2018) 5.6 (Q3 2018)

Breakeven Oil Price (S/stb) 5.2 6.19 8.35

Production duration (Year of

Abandonment) 25 years (2041) 23 years (2039) 19 (2035)

B/C 2.1 1.7 1

(400)

(200)

0

200

400

600

800

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

USD millions

Year

Cash flows throughout the field lifetime (non discounted)

OPEX

CAPEX

Total Revenue

Abondonment allocation

Abandonment

Return on Abandonment Investment

Cummulative Discounted Net Cashflow

Net cash flow


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

Figure 37

Parameters affecting the Rate of Return

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2,000

-80% -60% -40% -20% 0% 20% 40% 60% 80% 100%

NPV (USD million)

Variation from basecase

Sensitivity analysis on the Net Present Value (NPV)

Oil Price

CAPEX

Plateau

Discount Rate

OPEX

52

10%

20%

30%

40%

50%

60%

-80% -60% -40% -20% 0% 20% 40% 60% 80% 100%

IRR (%)


Sensitivity analysis on the Rate of Return (IRR)

Oil Price

CAPEX

Plateau

Discount Rate

OPEX

54

5. Uncertainties and risk management


Assessing the uncertainties

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

200

250

300

350

400

450

Cumulative production (MMbbl)

Variation parameter

Sensitivity analysis on the cumulative production

Base case

GRV

Porosity

Kv

Sw

Kh

Corey O/W

Corey W

Sorw

Swcr

Swmin

Faultstransmissivity

56

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

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.

-31%

-30%

-18%

-9%

-8%

-6%

-4%

-2%

-2%

-1%

-0.1%

15%

1%

13%

2%

1%

0.1%

3%

1%

0.5%

0.5%

0.5%

-35% -25% -15% -5% 5% 15% 25% 35%

GRV

Oil relative permeability

Horizontal permeability

Oil residual saturation

Connate water saturation

Vertical permeability

Porosity

Water saturation

Water relative permeability

Faults transmissivity

Critical water saturation


Variation parameter


Figure 40

NPV uncertainty analysis

19%

-31%

-30%

3%

10%

-60%

31%

8%

-25%

-10%

-100% -80% -60% -40% -20% 0% 20% 40% 60% 80% 100%

Discount rate

Oil price

Production

CAPEX

OPEX


Variation parameter

Downside

Upside

58

Risk mitigation scheme

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

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

Reprocess Seismic Data

Coring

Fluid Sampling

RFT

Full Suite Logs

SBHP/T

Separator/Wellhead Samples

Well Rate Tests

PLT

PNL

Oil Production

Year

Data

Acq

uis

tio

n

2016 2023 2024 2025 2026 To 2039202220212020201920182017


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

60

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

Risk types Risk Mitigation

Operational

Oil spill Flow assurance, regular facilities checks and spill

constraining and cleaning plan.

Labour

accidents

Compulsory initial training and regular seminars. Use

of working gear in every operation, housekeeping,

regular inspections.

Regulatory

& Commercial

Oil & Gas

Price

Prepare production plans with reduced production

during low price periods.

Communal

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.

62

6. Key considerations and recommendations

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.


References

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.

64

Appendices


Appendix 1: List of figures and abbreviations

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 .................................................... 55

Figure 39 - Tornado chart presenting the main uncertainties ............................................ 56

Figure 40 - NPV uncertainty analysis ................................................................................ 57

Figure 41 - Data acquisition plan ....................................................................................... 58

Figure 42 - Risk assessment chart ...................................................................................... 59

66

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 .................................................................................... 60


List of abbreviations

°C Degrees Celsius

ΔP Pressure difference

Φ (or PHIE) Porosity

API American Petroleum Institute

bar / bara 105 Pa / 14.7 psi (absolute pressure)

barg 105 Pa / 14.7 psi (pressure)

bbl Barrel of liquid (volume)

BHT Bottomhole Temperature

Bo Oil formation volume factor

bopd Barrel of oil per day

bpd Barrel of liquid per day

BS&W Basic Sediments and Water

BTU British Thermal Unit

CAPEX Capital Expenditure

CCTV Closed Circuit Television

cP Centipoise (10-3

Pa∙s)

Csg Casing

DECC Department of Energy and Climate Change

DST Drill Stem Test

ESD / ESV Emergency Shutdown Valve

ESP Electric Submersible Pump

FWL Free Water Level

GOR Gas to Oil Ratio

GRV Gross Rock Volume

h Hours

HSE Health Safety Environment

ICF Incomplete Combustion Factor

ID Inner diameter (for circular pipes)

in Inches

IRR Internal Rate of Return

ISO International Organization for Standardization

kh Horizontal permeability

kv Vertical permeability

LPG Liquefied Petrol Gas

m Metres

M Thousand (in front of fluid volume units)

MD Measured Depth

68

mD 10-3

Darcies (permeability)

MM Million (in front of fluid volume units)

N/G Net to Gross ratio

NMR Nuclear Magnetic Resonance

NpD Pore volume of oil produced (dimensionless)

NPV Net Present Value

OD Outer diameter (for circular pipes)

OPEX Operational Expenditure

OWC Oil Water Contact

PLT Production Logging Tool

PNL Pulsed Neutron Log

PPE Personal Protective Equipment

ppm Parts per million

PTB Pounds of salt per Thousand Barrels of crude oil

PV Pore Volume

PVT Pressure Volume Temperature

QC Quality Control/Check

rb Reservoir (condition) Barrels

RCAL Routine Core Analysis

RF Recovery Factor

RFT Repeat Formation Tester

SCADA Supervisory Control And Data Acquisition

SCAL Special Core Analysis

scf Standard (p, T conditions) cubic feet (2.8∙10-2

m³)

sg Specific gravity (mud weight)

So Oil saturation

Sor Irreducible oil saturation

stb Stock tank barrel

STOIIP Stock Tank Oil Initially in Place

Sw Water saturation

Swc Connate water saturation

tD Dimensionless time (pore volume injected)

TPC Tubing Performance

TVD (TVDSS) True Vertical Depth

UK United Kingdom

USD United States Dollar(s)

WN Wobbe Number


Appendix 2: Completion design

The perforation density chosen is 8 SPF. A higher density would not increase the

production significantly enough.

13800

14000

14200

14400

14600

14800

15000

15200

0 5 10 15 20 25 30

Liquid production rate (stb/d)

Perforation density (shot/ft)

Perforation density sensitivity

70

Appendix 3: Gas/ Oil and Oil / Water separator design

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

Com-

ponent

No of

moles of

liq

(lbmol)

Liq

density

(lb/ft3)

Mass

of

liquid

(lb)

Vol of

liq

(ft3)

No of

moles of

liq

(lbmol)

Vol of

liq

(ft3)

No of

mols of

gas

(lbmol)

Vol of

gas

(scf)

CO2 1.70E-03 51.3 0.0748 1.46E-03 1.30E-04 1.11E-04 1.72E-03 0.652

N2 2.67E-02 50.5 0.748 1.48E-02 9.09E-06 5.04E-06 2.72E-02 10.3

C1 1.47E-01 18.7 2.36 1.26E-01 9.07E-04 7.77E-04 1.53E-01 57.9

C2 7.06E-02 22.3 2.12 9.50E-02 2.33E-02 3.14E-02 5.84E-02 22.2

C3 1.00E-01 35.2 4.43 1.26E-01 4.98E-02 6.25E-02 7.66E-02 29.1

iC4 2.56E-02 36.5 1.49 4.08E-02 2.22E-02 3.54E-02 1.21E-02 4.61

nC4 6.92E-02 39.0 4.02 1.03E-01 6.61E-02 9.85E-02 2.80E-02 10.6

iC5 2.94E-02 39.4 2.12 5.39E-02 3.46E-02 6.33E-02 6.59E-03 2.50

nC5 3.85E-02 41.4 2.78 6.70E-02 4.71E-02 8.20E-02 7.01E-03 2.66

C6 5.29E-02 41.7 4.56 1.09E-01 7.20E-02 1.49E-01 3.62E-03 1.37

C7+ 4.37E-01 54.3 103 1.91 6.19E-01 2.69 1.00E-02 3.80

Total 9.99E-01 128 2.64 9.35E-01 3.22 3.84E-01 146

Oil/water separator sizing

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).

The separation is assumed isothermal at 55°C.

The mechanical separator’s volume is determined considering the fluid stays 10 min in

the separator.


The electrostatic separator’s area is determined by determining the electrostatic factor.

The water separation velocity is determined graphically knowing our operating

temperature.

The separation is thus made at Vs=7.1 Stokes.

The separation velocity is related to the electrostatic factor and is determined as

12 .

So the contact area of the electrostatic separator is

The constraints over the operational pressure leaded to the choice of a pressure of 1.5 bar.

1

10

0 50 100 150 200 250

Velocity (Stokes)

Temperature (deg C)

Water separation velocity vs temperature

72

For contingency reasons, the separators are designed 10% larger than required.

Designed Chosen

Mechanical separator

volume ( 105 116

Electrostatic separator area

( 74 81

0

5

10

15

20

25

40 60 80 100 120 140 160

Pressure (bar)

Temperature (deg C)

Operational pressure determination

Bubble point pressure

Minimum requiredpressure

Operational pressure


Appendix 4: Pipeline design

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.

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.

65

67

69

71

73

75

77

79

81

4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21

Delivery outlet pressure (bar)

Pipeline OD (inches)

Gas pipeline design

0.9

0.92

0.94

0.96

0.98

1

1.02

1.04

1.06

13 14 15 16 17 18 19 20 21 22 23 24 25

Delivery outlet pressure (bar)

Pipeline OD (inches)

Oil pipeline design

74

Appendix 5: Flowline design

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.


Appendix 6: National Grid gas line

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.

76

Appendix 7: Economics for P10, P90 scenarios

Economic viability of the project: cash flows, optimistic model

Economic viability of the project: cash flows, conservative model

(400)

(200)

0

200

400

600

800

1,000

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

USD millions

Year

Cashflows throughout the field lifetime

OPEX

CAPEX

Total Revenue

Abandonment Allocation

Abandonment

Return on AbandonmentInvestmentCummulative Discounted NetCashflow

(400)

(300)

(200)

(100)

0

100

200

300

400

500

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22

USD millions

Year

Cashflows throughout the field lifetime OPEX

CAPEX

Total Revenue

Abondonment allocation

Abandonment

Return on AbandonmentInvestmentCummulative Discounted NetCashflow


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

marcel&conrad for reservoir engineering team b wytch …shi.su.free.fr/wytch...

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