north sea, liberator field phase 1 - i3 energy · north sea, liberator field phase 1 competent...

Ver 1.0 March 2015

Registered office:

AGR TRACS International Limited

Union Plaza, 1 Union Wynd, Aberdeen AB10 1SL

+44 1224 629000

[email protected]

North Sea, Liberator Field Phase 1

Competent Person’s Report

2017

i3 Energy

Liz Chellingsworth, Keith Milne, Jackie Mullinor, Simon Nichol

Jill Prabucki, John Severs, Craig Webster, Mike Wynne, Tian Xia

November 2017

This report was prepared in accordance with standard geological

and engineering methods generally accepted by the oil and gas

industry, in particular the 2007 SPE PRMS. Estimates of

hydrocarbon reserves and resources should be regarded only as

estimates that may change as further production history and

additional information become available. Not only are reserves and

resource estimates based on the information currently available,

these are also subject to uncertainties inherent in the application of

judgemental factors in interpreting such information. AGR TRACS

International Ltd. (A wholly owned subsidiary of AGR Group

(Holdings) Ltd) shall have no liability arising out of or related to the

use of the report.

Status: Final

Date: November 2017

Revision: 1.0

Prepared by:

Project Manager Jill Prabucki

Approved by:

Reviewer Mike Wynne

Authorised for release by Mike Wynne

Liberator Area CPR

AGR TRACS International Limited i November 2017: rev1.0

Qualification

AGR TRACS International Limited (a wholly owned subsidiary of AGR Group AS) (“AGR TRACS”) was

founded in 1992, and currently has over 50 petroleum engineers, geoscientists and petroleum economists

working from three office locations. AGR TRACS has extensive reserves and asset valuation experience

and are recognised as industry reserve, risk and valuation experts.

The Liberator Field evaluation was performed by senior AGR TRACS staff with a combined 120+ years in

the oil and gas industry. The team members all hold at least a bachelor’s degree in geoscience, petroleum

engineering or related discipline.

This assessment has been conducted within the context of the AGR TRACS understanding of the effects of

petroleum legislation, taxation, and other regulations that currently apply to the P.1987, Block 13/23d.

However, AGR TRACS is not in a position to attest to property title, financial interest relationships or

encumbrances thereon for any part of the appraised properties.

It should be understood that any determination of resource volumes, particularly involving petroleum

developments, may be subject to significant variations over short periods of time as new information

becomes available and perceptions change. This is particularly relevant to exploration activities which by

their nature involve a high degree of uncertainty.

All volumetric calculations are based on independent mapping undertaken by AGR TRACS using data

provided to AGR TRACS. The reservoir properties input to the volumetric calculations and the associated

volume uncertainty ranges are based on AGR TRACS experience over more than 20 years of performing

evaluations, and the statement on risking in this report represents the independent view of AGR TRACS.

The resource estimates presented in this report have been prepared in accordance with reserves

definitions presented in the SPE’s Petroleum Resources Management System (“SPE-PRMS” summary in

Appendix A), and the risking of contingent and prospective resources has been done in accordance with

the LSE/AIM Guidance note for Mining, Oil and Gas Companies - June 2009 (“LSE/AIM Guidelines”).

Liberator Area CPR

AGR TRACS International Limited ii November 2017: rev1.0

Executive Summary

i3 Energy (i3) have commissioned a Competent Persons Report (CPR) to assess the resource potential of

the Liberator Field in accordance with reserves definitions presented in the SPE’s Petroleum Resources

Management System (“SPE-PRMS” Appendix A). This CPR concerns the Phase 1 Area of the Liberator Field

mainly within the P.1987 licence.

Location Map showing Phase 1 Area and Licence Boundary

The Liberator Field is located approximately 120 km northeast of Aberdeen, southwest of Blake Field and

north of Ross Field, within Licence P.1987, UKCS Block 13/23d. i3 Energy hold a 100% interest in the

licence.

The Liberator field was discovered in 2013 by exploration well 13/23d-8, which encountered a 24 foot

hydrocarbon column, with 4 feet of gas underlain by 20 feet of oil, in the lower Cretaceous Captain Sands.

Reservoir and fluid properties are analogous to those found in Blake Field. Oil is saturated with an API of

30.3. There was no well test, however, in this high porosity - high permeability reservoir, productivity was

established with the acquisition of logs and MDT pressures and samples.

Development is in the late define stage: plans are in place to commence drilling second quarter 2018, a

draft Field Development Plan (FDP) has been submitted with final submission scheduled for late November

2017, the Environmental Statement (ES) has been submitted for approval, and long lead items have been

ordered.

Key uncertainties were identified during the data review stage of the assessment, including the likely

distribution fluids, and more specifically gas over the Liberator accumulation given the presence of gas

column in the downdip discovery well. An amplitude analysis was undertaken to establish the expected

amplitude response in the presence of a gas column of various heights. Ten wells (from Liberator and

Blake areas) were included in the analysis. Based on this analysis a large gas cap greater than 10ft thick,

over the Liberator structure is very unlikely, and small gas caps are carried in the low case only.

Saturation height and depth of top reservoir also have a significant impact on in place volumes and a

range of values has been considered for each of these parameters in the static modelling and in-place

volumetric estimates. The resulting STOIIP and GIIP ranges are summarised below.

Blake

Ross

Liberator

Liberator Area CPR

AGR TRACS International Limited iii November 2017: rev1.0

Case STOIIP

MMstb

GIIP

Solution gas

Bscf

GIIP

Free gas

Bscf

Low 18.4 6.3 0.3

Mid 38.0 13.1 0

High 58.2 19.8 0

Low, Mid and High case In-Place Volumes

Three dynamic models constructed by AGR representing the low, mid and high STOIIP have been used to

forecast the recoverable volumes associated with the Phase 1 Liberator development project. In addition to

the STOIIP uncertainty the models address uncertainties in aquifer support and relative permeabilities.

The Liberator field is planned to be developed via 2 horizontal producers (LP1 and LP2) in Phase 1,

targeting the Main and Northwest culminations of the Phase 1 area. The wells will be tied back to the

Blake field manifold via a multiphase metering and tie in structure with all production liquids delivered to

the Bleo Holm FPSO for processing. The Bleo Holm FPSO processes fluids from the producing Blake/Ross

fields. Both are operated by Repsol Sinopec.

LP1 is scheduled to come onstream 01/10/2018 and LP2 a year later at 01/10/2019 (for the purposes of

this assessment a first oil date of 01/01/2019 has been assumed). The Phase 1 development and schedule

together with associated constraints have been used in the dynamic models to generate a range of

production forecasts for input into the economics and resource estimation. Recovery factors range from

24% to 32% from the modelling reflect an adequate but not overly strong aquifer in combination with a

relatively small oil column where coning/cusping will be an issue.

The well, completion and subsea designs and costs provided by i3 have been reviewed and the associated

costs have been updated where considered appropriate. No key issues with the well concepts and costs

were observed.

The Project Execution Plan has been reviewed and is at the define stage of the project. The planned

activities relating to Phase 1 are of limited scope and complexity by North Sea Standards and do not entail

any new technologies. PWE and Repsol are both experienced parties with a successful track record of

delivering complex projects in the UKCS area.

Heads of Terms for the processing, storage and offloading of production fluids from the proposed Liberator

development have not yet been agreed with Repsol Sinopec UK although discussions are underway.

Commercial terms have been estimated based on discussions with i3 and their advisors and used in the

economic analysis.

The results of the economic evaluation of the Liberator Field Phase 1 project are shown in the tables below

for the pre-tax and post-tax economics.

LP1&LP2 NPV10 $MM NPV0 $MM IRR

1P 59.5 85.9 50%

2P 327.9 472.5 211%

3P 576.3 851.6 302%

Phase 1 – LP1 & LP2 Pre-tax economics

Liberator Area CPR

AGR TRACS International Limited iv November 2017: rev1.0


1P 37.0 57.9 39%

2P 200.4 289.9 160%

3P 349.8 517.3 226%

Phase 1 – LP1 & LP2 Post-tax economics

The Liberator project demonstrates robust economics and a clear potential for material cashflow. In

particular, a circa 1 year or better project payback period demonstrates a high level of capital efficiency.

Based on the economic results the Liberator Field Phase 1 project is classified as Undeveloped Reserves,

Justified for Development. The reserves attributable to the Phase 1 development are:

LP1 & LP2 Oil MMbbl Gas Bcf MMboe

1P 4.0 3.2 4.5

2P 10.7 6.0 11.7

3P 16.9 8.7 18.3

Phase 1 – LP1 & LP2 oil and gas reserves

This assumes a cessation of production (COP) at the end of 2030 (30-year design life of the Blake FPSO).

BOE conversion used is 6000 cubic feet per barrel of oil equivalent.

There are risks and opportunities identified for the Phase 1 project that have not been explicitly accounted

for within the evaluation. These are summarised below.

Risks

Larger gas caps (considered as highly unlikely)

Insufficient pressure support, a dedicated injector may be required.

Significant shales within the Captain sands

Landing trajectories in optimum position with respect to the HC column given the thin oil column, depth uncertainty and uncertainty around the presence or absence of a gas cap. A pilot hole could mitigate this risk.

Project schedule slip, due to elements not fully in i3’s direct control, such as timely completion of host studies and commercial agreements.

A significant portion of the field extends into Block 13/23a northwest of the phase 1 area. i3 are in active discussion with the OGA to mitigate this risk. Risk of lower net interest in case the licence is not awarded to i3 Energy.

Extension of the Liberator field into the Block 13/24a, Licence P.101, and risk of lower net interest

to P.1987 licence holders. Up to 10% of the in place volume extends into the neighbouring licence.

Opportunities

Optimisation of well trajectories

Water injection project which may deliver incremental reserves.

Higher initial reservoir pressure and continued support via Blake injection.

Liberator Area CPR

AGR TRACS International Limited v November 2017: rev1.0

Contents

Qualification ............................................................................................................................. i

Executive Summary .................................................................................................................. ii

1 Introduction ....................................................................................................................... 1

1.1 Overview ................................................................................................................ 1

1.2 License history and current status .............................................................................. 1

1.3 Future activity ......................................................................................................... 2

1.4 Data availability ....................................................................................................... 2

1.5 Key uncertainties, Risks and Opportunities .................................................................. 2

2 Geological overview ............................................................................................................. 4

2.1 Wells considered ...................................................................................................... 4

2.2 Well correlation ....................................................................................................... 4

2.3 Reservoir geology .................................................................................................... 5

3 Geophysical evaluation ........................................................................................................ 7

3.1 Data ....................................................................................................................... 7

3.2 Analysis .................................................................................................................. 7

3.2.1 Interpretation .......................................................................................................... 7

3.2.2 Depth conversion ..................................................................................................... 8

3.2.3 Amplitude analysis ................................................................................................. 11

4 Petrophysical evaluation ..................................................................................................... 13

4.1 Data availability and quality .................................................................................... 13

4.2 Petrophysical interpretation ..................................................................................... 13

4.2.1 Vclay .................................................................................................................... 14

4.2.2 Porosity ................................................................................................................ 14

4.2.3 Water saturation .................................................................................................... 15

4.2.4 Permeability .......................................................................................................... 16

4.2.5 Reservoir cut-offs .................................................................................................. 16

4.3 Fluid contacts ........................................................................................................ 16

4.4 Saturation vs height function ................................................................................... 18

4.5 Results ................................................................................................................. 20

4.6 Uncertainties and sensitivities ................................................................................. 20

4.7 Conclusions and recommendations ........................................................................... 20

5 Static modelling ................................................................................................................ 21

5.1 Key Static Volume Uncertainties .............................................................................. 21

5.2 Fluid distribution .................................................................................................... 22

5.3 Input data ............................................................................................................ 23

5.3.1 Seismic horizons .................................................................................................... 23

5.3.2 Well data .............................................................................................................. 23

5.4 3D grid model ....................................................................................................... 23

5.4.1 Horizons and layering ............................................................................................. 24

5.4.2 Porosity ................................................................................................................ 25

5.4.3 NTG ..................................................................................................................... 25

Liberator Area CPR

AGR TRACS International Limited vi November 2017: rev1.0

5.4.4 Permeability .......................................................................................................... 25

5.4.5 Saturation ............................................................................................................. 26

5.4.6 Depth uncertainty gridding ...................................................................................... 27

5.4.7 Development Well Trajectories ................................................................................ 28

6 In-Place volumes .............................................................................................................. 30

6.1 STOIIP Estimation .................................................................................................. 30

6.2 Results ................................................................................................................. 30

7 Reservoir Engineering ........................................................................................................ 32

7.1 Data review .......................................................................................................... 32

7.2 Dynamic model construction ................................................................................... 32

7.2.1 Grid ..................................................................................................................... 32

7.2.2 PVT and Relative Permeability ................................................................................. 33

7.2.3 Saturation-height function and initialisation .............................................................. 34

7.2.4 Regions and aquifer model ...................................................................................... 35

7.2.5 STOIIP ................................................................................................................. 37

7.2.6 Wells .................................................................................................................... 37

7.3 Forecasts .............................................................................................................. 38

7.3.1 Phase 1 schedule and well controls .......................................................................... 38

7.3.2 Results ................................................................................................................. 38

7.3.3 Forecast profiles .................................................................................................... 40

8 Production Technology ....................................................................................................... 42

8.1 Sand Control ......................................................................................................... 42

8.2 Gas Lift................................................................................................................. 43

8.3 Metallurgy ............................................................................................................. 44

9 Well Engineering Review .................................................................................................... 45

9.1 Introduction .......................................................................................................... 45

9.2 Well location/trajectory........................................................................................... 45

9.3 Well architecture.................................................................................................... 45

9.4 Well construction risks ............................................................................................ 46

9.5 Well time and costs ................................................................................................ 47

10 Facilities ........................................................................................................................... 48

10.1 Introduction .......................................................................................................... 48

10.2 Bleo Holm FPSO facilities capacity and ullage ............................................................ 48

11 Phase 1 Project Delivery .................................................................................................... 50

11.1 Project execution plan and work packages ................................................................ 50

11.2 Commercial agreements ......................................................................................... 50

11.3 Project schedule .................................................................................................... 51

11.4 Cost review ........................................................................................................... 51

11.4.1 CAPEX .................................................................................................................. 51

11.4.2 OPEX .................................................................................................................... 51

12 Phase 1 Economics ............................................................................................................ 53

12.1 Assumptions register .............................................................................................. 53

Liberator Area CPR

AGR TRACS International Limited vii November 2017: rev1.0

12.2 Price deck ............................................................................................................. 53

12.3 Economic results .................................................................................................... 54

12.3.1 LP1 results ............................................................................................................ 54

12.3.2 Phase 1 - LP1&2 results .......................................................................................... 55

12.3.3 Sensitivities .......................................................................................................... 56

12.3.4 Summary comments .............................................................................................. 57

13 Resource Estimation .......................................................................................................... 58

13.1 Classification of Resources ...................................................................................... 58

13.2 Estimated Reserves ................................................................................................ 58

14 References ....................................................................................................................... 59

15 Glossary of Terms ............................................................................................................. 60

Appendix A - Summary of 2007 SPE Petroleum Resources Classification ........................................ 61

Appendix B – Technical Production Profiles ................................................................................ 63

Appendix C – Undiscounted Pre-Tax Cashflows ........................................................................... 66

Liberator Area CPR

AGR TRACS International Limited viii November 2017: rev1.0

Figures

Figure 1-1 Liberator Field Location Map ....................................................................................... 1

Figure 2-1 Depth Map (top K50) and exploration wells .................................................................. 4

Figure 2-2 NW-SE Well Correlation Panel including Liberator well ................................................... 5

Figure 2-3 Well Correlation Panel for the Blake Field ..................................................................... 5

Figure 3-1 Seismic data coverage (supplied by i3 Energy) ............................................................. 7

Figure 3-2 Seismic well tie line: 23-1 to Liberator to Blake ............................................................ 8

Figure 3-3 Seismic line across Main culmination in Liberator .......................................................... 8

Figure 3-4 Depth map K50 sequence boundary ............................................................................ 9

Figure 3-5 Seismic line showing small erosional features at base Chalk/top Tor.............................. 10

Figure 3-6 Vertical closure map ................................................................................................ 10

Figure 3-7 Comparison of amplitude response at three key wells .................................................. 11

Figure 3-8 Amplitude extraction at K50 sequence boundary ......................................................... 12

Figure 4-1 CPI for Liberator well 13/23d-8 ................................................................................. 14

Figure 4-2 Porosity from core analysis in Blake well 13/24a-4 in close agreement with porosity from logs ............................................................................................................................... 15

Figure 4-3 Porosity v Permeability from core in Blake well 13/24a-4 ............................................. 16

Figure 4-4 Fluid distribution (by year) in the Liberator region ....................................................... 17

Figure 4-5 Fluid distribution (by location) in the Liberator region .................................................. 17

Figure 4-6 Formation pressure from Liberator and Blake (from Liberator FDP) ............................... 18

Figure 4-7 Saturation height functions displayed with Sw from logs .............................................. 19

Figure 4-8 Saturation from the functions described displayed with the CPIs (Red-Liberator, Blue-Blake) ............................................................................................................................ 19

Figure 5-1 Effect of reservoir parameters on STOIIP ................................................................... 21

Figure 5-2 Cross Section from NW to SE showing Fluid contacts (low case GOC) ............................ 22

Figure 5-3 Map showing Fluid contacts and (low case volumetrics GOC over Liberator Area) ............ 23

Figure 5-4 Map of Modelling Grid and Segments ......................................................................... 24

Figure 5-5 View of 3D grid, looking from SE, showing layers ........................................................ 24

Figure 5-6 Porosity model view ................................................................................................ 25

Figure 5-7 NTG model view ..................................................................................................... 25

Figure 5-8 Model Permeability Distribution................................................................................. 26

Figure 5-9 Kh model view ........................................................................................................ 26

Figure 5-10 Comparison of Sw-Height functions ......................................................................... 27

Figure 5-11 Sw model view ..................................................................................................... 27

Figure 5-12 Cross Section from NW to SE showing shallow and deep top reservoir ......................... 28

Figure 5-13: Cross section through first development well (main segment) ................................... 28

Figure 5-14: Cross section through second development well (NW segment) ................................. 29

Figure 6-1 Map showing field extent and licence boundary .......................................................... 31

Figure 7-1 Phase 1 E100 model – Grids in Z direction ................................................................. 32

Figure 7-2 Paleo oil zone in the Phase 1 E100 model................................................................... 33

Figure 7-3 Relative permeability curves for Low, Mid and High cases ............................................ 34

Figure 7-4 Saturation-height functions for the Liberator Phase 1 E100 models ............................... 35

Figure 7-5 Regions in the Liberator Phase 1 E100 models ............................................................ 36

Liberator Area CPR

AGR TRACS International Limited ix November 2017: rev1.0

Figure 7-6 Aquifer models in the Liberator Phase 1 E100 models .................................................. 36

Figure 7-7 Initial gas saturation in Low case model..................................................................... 37

Figure 7-8 Well locations in Phase 1 E100 models ...................................................................... 38

Figure 7-9 Ternary plots – Mid case, Y slice 13 ........................................................................... 39

Figure 7-10 Low Case predicted oil rate, WCT, GOR and Cum. oil ................................................. 40

Figure 7-11 Mid Case predicted oil rate, WCT, GOR and Cum. oil .................................................. 41

Figure 7-12 High Case predicted oil rate, WCT, GOR and Cum. oil ................................................ 41

Figure 8-1 Particle Size Distribution .......................................................................................... 42

Figure 8-2 Metallurgy Selection for CO2 and H2S Partial Pressures ................................................ 44

Figure 10-1 Bleuwater Bleo Holm FPSO ..................................................................................... 48

Figure 11-1 High Level Development Schedule provided by i3 Energy ........................................... 51

Figure 12-1 Sproule Associates 3Q 2017 Brent price forecast ....................................................... 54

Figure 12-2 LP1 Cumulative post tax cashflow, undiscounted ....................................................... 55

Figure 12-3 Phase 1 - LP1 & LP2 post tax cumulative cashflow, undiscounted ................................ 56

Tables

Table 4-1 Liberator are wells included in IP project ..................................................................... 13

Table 4-2 Average properties in Captain sand ............................................................................ 20

Table 6-1 Summary of STOIIP cases as a basis for 1P, 2P and 3P reserves .................................... 30

Table 6-2 Low, Mid and High case In-Place Volumes ................................................................... 30

Table 7-1 Liberator oil properties ............................................................................................. 33

Table 7-2 Regional and Phase 1 Area STOIIP ............................................................................. 37

Table 7-3 Forecast recoverable oil of the Liberator Phase 1 development ...................................... 39

Table 7-4 Forecast recoverable gas of the Liberator Phase 1 development ..................................... 39

Table 8-1 Uniformity and Sorting Coefficients ............................................................................ 43

Table 8-2 Sand Control Method Selection Criteria ....................................................................... 43

Table 8-3 Gas Lift Rate v Liquid Production Rate (95% WC and Depleted Reservoir) ....................... 44

Table 10-1 Bleo Holm Datasheet and ICOP ullage estimates ........................................................ 49

Table 10-2 Blake/Ross production 2016 .................................................................................... 49

Table 11-1 Subsea CAPEX cost estimates, base year cost 2017 .................................................... 51

Table 11-2 Forecast Bleo Holm throughput for cost share allocation .............................................. 52

Table 12-1 LP1 Post tax standalone economics .......................................................................... 54

Table 12-2 LP1 Pre and Post Tax Breakeven crude price .............................................................. 54

Table 12-3 Phase 1 – LP1 & LP2 Pre-tax economics .................................................................... 55

Table 12-4 Phase 1 – LP1 & LP2 Post-tax economics ................................................................... 55

Table 12-5 Phase 1 – LP1 & LP2 Pre and Post Tax Breakeven crude price ...................................... 56

Table 12-6 Phase 1 NPV sensitivity – CAPEX plus 25% ................................................................ 56

Table 12-7 Phase 1 NPV sensitivity – CAPEX minus 25% ............................................................. 57

Table 12-8 Phase 1 NPV sensitivity – OPEX plus 25% ................................................................. 57

Table 12-9 Phase 1 NPV sensitivity – OPEX minus 25% ............................................................... 57

Table 12-10 Phase 1 NPV sensitivity – No Gas Export ................................................................. 57

Table 13-1 Phase 1 – LP1 & LP2 oil and gas reserves .................................................................. 58

Liberator Area CPR

AGR TRACS International Limited x November 2017: rev1.0

Table 15-1 Low Case .............................................................................................................. 63

Table 15-2 Mid Case ............................................................................................................... 64

Table 15-3 High Case ............................................................................................................. 65

Table 15-4 Undiscounted annual pre-tax cashflow ...................................................................... 66

Table 15-5 Undiscounted cumulative cashflow ........................................................................... 66

Liberator Area CPR

AGR TRACS International Limited 1 November 2017: rev1.0

1 Introduction

AGR TRACS (AGR) was commissioned by i3 Energy to complete a Competent Person’s Report (CPR)

assessing the resource potential of the Liberator Field in accordance with reserves definitions presented in

the SPE’s Petroleum Resources Management System (“SPE-PRMS” Appendix A).

1.1 Overview

The Liberator field is located 120 km north-east of Aberdeen (Figure 1-1), in the South Halibut Basin of the

Moray Firth Province, within Licence P.1987, UKCS Block 13/23d, which is held by i3 Energy on a 100%

basis.

Figure 1-1 Liberator Field Location Map

The Liberator field was discovered in 2013 by exploration well 13/23d-8, which encountered a 24 foot

hydrocarbon column, with 4 feet of gas underlain by 20 feet of oil, in the lower Cretaceous Captain Sands.

Productivity was established with the acquisition of MDT measurements and fluid samples. A thick

sequence of sand was encountered (over 300 feet) with a very high net to gross and excellent reservoir

quality. The Liberator accumulation is close to Blake Field, and is being considered to be developed as a

tie-back to the Blake facilities. i3 Energy have submitted a draft Field Development Plan (FDP) to the Oil

and Gas Authority (OGA) and are currently progressing the development plan. The project is in the

“Define” stage of development with sanction scheduled for March 2018.

The field extends northwestward into Block 13/23a, which is currently un-licensed. This CPR deals with the

development as proposed in the FDP and covers the area referred to as Phase 1 in Figure 1-1, above.

1.2 License history and current status

Licence P.1987 was awarded in the 27th round to Dana in 2013 on a 100% basis. The initial term was for

four years commencing 1st January 2013, with a one well commitment. This commitment was fulfilled in

2013 with the drilling of the Liberator discovery well, 13/23d-8. i3 Energy acquired the licence from Dana

in 2016. OGA approval was confirmed on December 8th 2016 with an obligation to “secure approval of a

Field Development Plan or provide evidence of funds to drill a well by 31st December 2018.” The project is

on schedule to meet this remaining obligation.

Following development sanction project execution commences under the final term of the Production

licence, which extends throughout commercial operations.

Blake

Ross

Liberator

Liberator Area CPR


1.3 Future activity

The project execution plan is described in further detail in Section 11.1. A two well development is

proposed, wells will be horizontally drilled from locations close to the Blake Manifold, and will be tied back

to the manifold (Section 11.1).

Contingent on FDP approval and project sanction, the first development well is scheduled to be drilled

some time in Q2 2018 (rig negotiations are ongoing). i3 is planning a two well development programme

with the first development well (LP1) planned to come onstream in 2019. The second development well

(LP2) will be contingent upon performance of the first well.

1.4 Data availability

Data provided for the assessment included raw data and interpretation, covering all required disciplines

including:

Seismic data and interpretation extending over the Liberator field and area, including Blake Field

Well data for exploration wells, the Liberator discovery well and offset wells, and Blake Field

production wells.

Static and dynamic models and input data.

Wells Basis of Design documents

Draft FDP

Details of data provided are described in subsequent chapters. There were no data gaps identified, which

could impede AGR in carrying out the assessment in accordance with PRMS. i3 were forthcoming with all

requests for further information and clarifications.

1.5 Key uncertainties, Risks and Opportunities

The assessment workflow is devised to ensure that the resulting ranges on volumes, in-place and

recoverable, and value are representative of P10 to P90 outcomes.

During the review of data those parameters or elements of the development which carry the greatest

uncertainty and can have a significant impact on the project, volumes and or value, are identified and

assessed in further detail. They are either considered within the range of input parameter values selected

for volumetric estimation and or economic calculations, or are identified as potential project risks and

opportunities.

Key uncertainties identified for this project include:

Depth uncertainty on a low relief structure

Presence and size of a gas cap

Saturation height distribution

Mobility of water within the transition zone

Relative permeability

Aquifer strength

First oil date

Rig costs

Input assumptions are documented in further detail in subsequent chapters.

Risks identified (ie not explicitly accounted for within input assumptions, out with the Low-Mid-High

outcomes) include:

Larger gas caps

Insufficient pressure support, a dedicated injector may be required.

Significant shales within the Captain sands

Landing trajectories in optimum position with respect to the HC column given the thin oil column,

depth uncertainty and uncertainty around the presence or absence of a gas cap. A pilot hole could mitigate this risk. The current plan for mitigation is to use AziTrak LWD which should allow

Liberator Area CPR


identification of top reservoir ahead of the drill-bit, and give an indication of fluid type. For the current assessment, neither option has been evaluated in depth. It is recommended both options

be considered.

Project schedule slip, due to elements not fully in i3’s direct control, such as timely completion of host studies and commercial agreements.

A portion of the field extends into Block 13/23a northwest of the phase 1 area. i3 are in active

discussion with the OGA to mitigate this risk. Risk of lower net interest in case this area is not awarded to i3 Energy.

Extension of the Liberator field into the Block 13/24a, Licence P.101, and risk of lower net interest to P.1987 licence holders. Up to 10% of the in place volume extends into the neighbouring licence.

Opportunities (upside outcome not explicitly accounted for within input assumptions):

Optimisation of trajectories post licence award.

Water injection project which may deliver incremental reserves.

Higher initial reservoir pressure and continued support via Blake injection.

Liberator Area CPR


2 Geological overview

2.1 Wells considered

The Liberator discovery lies 2km west of the northern part of the Blake Field (Figure 2-1). The focus of the

evaluation is on the Liberator discovery well, but exploration wells and some of the Blake Field

development wells have also been considered.

Figure 2-1 Depth Map (top K50) and exploration wells

2.2 Well correlation

The Rodby and top Valhall can be correlated confidently in nearly all wells (Figure 2-2 and Figure 2-3).

The top reservoir sand can be clearly observed on logs. It occurs at various depths below the Rodby pick,

being quite shallow in the Blake Field (~200ft) and deeper in the Liberator well (350ft). To the SE along

the axis of the channel system, the sands occur about 350ft below Rodby, similar to Liberator. The sands

are thicker to the SE, 500ft in 13/23b-8.

The top sand is thought to mostly coincide with the K50 sequence stratigraphic time line, although it is not

known how much biostratigraphic data has been used to draw this conclusion.

In the NW well 13/23a-4 the top sand reservoir is also overlain by about 350ft of shale. However, the K50

does not coincide with the top sand but is 100ft shallower within the shale interval.

West of the Liberator accumulation in well 13/23-1, there is no sand, only about 150ft of basinal shale.

Liberator Area CPR


Figure 2-2 NW-SE Well Correlation Panel including Liberator well

Figure 2-3 Well Correlation Panel for the Blake Field

2.3 Reservoir geology

The sediments are of Lower Cretaceous age. At various times within the Aptian, thick sandstone units are

developed from the Captain Field to the Blake Field and further South to the Cromarty Field.

The bulk of the sandstones in the area including the Liberator well are well sorted, clean with high porosity

(0.28) and permeability (2 Darcies). In the lower half of the reservoir, thin interbeds of shale and cement

occur in some wells, but the NTG is still very high.

Liberator Area CPR


The sands are thought to have been deposited in submarine channels predominantly running NW-SE,

parallel to the edge of the Halibut high. Significant shale intervals have not been encountered in the wells

drilled in the reservoir so far, but could occur on the flanks of channels.

In the Captain Field, the sandstones are generally featureless and massive, dewatering structures and mud

clast horizons are the most common sedimentary features seen in the sands. The encasing mudstones

consist of parallel laminated distal turbidites and pelagic mudstones interbedded with abundant slump

deposits. The sandstones are interpreted as high density turbidite deposits but abundant glauconite

indicates that the sandstones were stored originally on a shallow shelf. The isochore distribution described

above implies that the shelfal area was the East Shetland Platform. It is suggested that the sands were

redeposited in the deeper water depths to the south of the East Shetland Platform during a period of

relative sea-level low stand. Incision of the underlying basinal shales has been clearly observed in the

Captain Field (lower sequence).

Liberator Area CPR


3 Geophysical evaluation

3.1 Data

AGR was supplied with a Kingdom project with the following data:

well data (various)

TGS MF10 PSTM data – 2010 3D seismic data set (‘MF10’) comprising the following data types: PROCMIG, raw stack and near, mid & far stack data

Western Geco Q13Ph1 data – 2013 3D seismic data set (‘Q13Ph1’) comprising the PROCMIG data

various time and depth horizons/grids

The MF10 survey covers the Phase 1 area, as illustrated in Figure 3-1.

Figure 3-1 Seismic data coverage (supplied by i3 Energy)

3.2 Analysis

The objectives of the Phase 1 geophysical evaluation were as follows:

review seismic interpretation over the Phase 1 area

review depth conversion and depth uncertainty over the Phase 1 area

review seismic amplitudes as potential indicators of free gas over the Phase 1 area

3.2.1 Interpretation

AGR reviewed the supplied horizon interpretation. No faults have been picked/mapped. Two sample lines

are shown in Figure 3-2 and Figure 3-3. The K50 sequence boundary is picked on a positive event and the

interpretation is robust over the Phase 1 area. Note that the K50 sequence boundary represents a

timeline, not a lithological boundary. In well 23d-8 and over Blake the top of the K50 sequence

corresponds to the top of the Captain sand, whereas in well 23-1 it corresponds to the top of a shale.

Liberator Area CPR


Figure 3-2 Seismic well tie line: 23-1 to Liberator to Blake

Figure 3-3 Seismic line across Main culmination in Liberator

3.2.2 Depth conversion

AGR reviewed the depth conversion methodology adopted by i3 Energy. It is a layer-based model

incorporating 10 layers using constant interval velocities derived from 23d-8 and 23-1. The resulting depth

map is shown in Figure 3-4.

__ i3_top Hidra

__ i3_top Rodby

__ i3_K50 seq bd (timeline)

__ i3_intra-Captain shale

__ i3_top Valhall

SW NE

Tim

e (

s T

WT

)

MF10 Raw Stack

23-1 23d-8 24a-4

1000m

location map

__ i3_top Hidra

__ i3_top Rodby



__ i3_top Valhall

Tim

e (

s T

WT

)

MF10 Raw Stack1000m

SW NE

Liberator Area CPR


Figure 3-4 Depth map K50 sequence boundary

In general the depth conversion is considered to be robust for the Phase 1 area. Away from wells depth

uncertainty remains. The total depth uncertainty in the Phase 1 area is estimated to be ±25ft at 1km away

from the wells. It is made up of three elements: pick uncertainty, depth conversion uncertainty and

diversion of top Captain sand from the K50 sequence boundary - see below.

Horizon pick uncertainty The K50 sequence boundary is not a smooth event and the picked horizon

steps up/down in places; minor variations in interpretation are possible.

Depth conversion uncertainty The layer-based model provides a good match at the wells in Blake with

only small residuals at the various layers. Small erosional features are present at base Chalk/top Tor, see

Figure 3-5. This layer has been included in the 10-layer method but the velocity of the fill is derived from

23d-8 where no erosional channel is seen at this level. The channels are widespread and occur in some

key places, e.g. the saddle between Phase 1 and Blake and the saddle to the west of Phase 1.

Diversion of top Captain sand from K50 sequence boundary The top Captain sand depth map

supplied by i3 Energy was generated from the K50 depth map and a Net-to-Gross (NTG) map interpolated

between wells 23d-8 where the NTG is almost 1 and 23a-4 where the NTG is much lower, see Figure 2-2.

While this is reasonable for the thickest parts of the channel, away from the channel axis and especially in

the saddle areas, the diversion between the timeline and lithological boundary could change quite

suddenly.

De

pth

(ft

TV

Ds

s)

Top K50 depth map

K50 depth contours down to 5,300ft TVDss (C.I.= 10ft)

lice

ns

e b

ou

nd

ary 1000m

23d-8

Blake

Liberator

23-1

Liberator Area CPR


Figure 3-5 Seismic line showing small erosional features at base Chalk/top Tor

The vertical closure in Liberator is relatively small compared to Blake, see Figure 3-6, and flexing the

surface away from the wells by even a small amount can have a significant impact.

Figure 3-6 Vertical closure map

Time thickness map top Chalk to top Tor showing location of erosional features

Tim

e t

hic

kn

ess

(s

)

Tim

e (

s T

WT

)

MF10 Raw Stack1000m

__ i3_top Chalk

__ i3_top Tor

__ i3_top Mackerel

__ i3_top Hidra

__ i3_top Rodby


__ i3_top Valhall

line location

Th

ickn

ess (

ft)

Height above contact map

based on OWC at 5,270ft TVDss and K50 structure map

HAC contours (C.I.= 10ft)

Liberator Area CPR


3.2.3 Amplitude analysis

The aim of the amplitude analysis was to establish the expected amplitude response in the presence of a

gas column of various heights. Ten wells (from Liberator and Blake areas) were included in the analysis.

The full stack data were reviewed along with the nears and fars.

A complete like-for-like comparison of amplitudes is not possible. The total sand thickness in the Liberator

well 23d-8 is much smaller than in most Blake wells. Wells B2, B3 and B5 have a comparable sand

thickness but significantly different primary gas cap sizes: B2 and B3 have no original gas cap and B5 has

a 14ft primary gas cap. The nearest Blake wells, 24a-4 and 24a-7, have a much larger total sand thickness

but a similar gas cap to 23d-8. A comparison of three wells is shown in Figure 3-7.

Figure 3-7 Comparison of amplitude response at three key wells

The conclusion from the analysis is that a gas column greater than 10ft is expected to give high

amplitudes on seismic data. From inspection of various amplitude extractions, it is highly unlikely that

there is an extensive primary gas cap over Liberator, see Figure 3-8.

13/23d-8

181

5

19

35

thickness (ft)

total sand

gas column

oil column

paleo

__ i3_top Chalk

__ i3_top Tor

__ i3_top Mackerel

__ i3_top Hidra

__ i3_top Rodby

__ i3_K50 seq bd


__ i3_top Valhall

MF10 Raw Stack MF10 Raw StackMF10 Raw Stack

13/24a-4

278

9

98

33

13/24a-6

244

65

101

34

MF10 Raw Stack

Liberator Area CPR


Figure 3-8 Amplitude extraction at K50 sequence boundary

It should be noted that in places the data set is noisy with noise trains ringing down the section. Amplitude

maps should be sense checked against vertical seismic displays. And as always, lateral and vertical

resolution should be considered when interpreting seismic amplitude maps.

Absolute amplitude at top K50 – Raw Stack

K50 depth contours down to 5,230ft TVDss (C.I.= 10ft)

Ab

so

lute

Am

pli

tud

e

lice

ns

e b

ou

nd

ary

1000m

elevated

amplitudes in

NW culmination

some elevated amplitudes in

Main culmination

Liberator Area CPR


4 Petrophysical evaluation

The petrophysics input for this CPR is to review the well logs and core data to support the range of

reservoir properties and fluid contacts. The petrophysical data, including log analysis, was supplied as an

LR Interactive Petrophysics (IP) database. Supporting data was supplied as part of a summary

presentation and FDP.

The Liberator discovery is very close to the Blake field and is in the same formation as described in

Sections 2.2 & 2.3. Data from wells in the region, including Blake, has been included in order to

understand the variations, and consistencies, in properties.

4.1 Data availability and quality

The IP project was populated with 13 wells made up of the Liberator well, 11 Blake wells and one

exploration well to the west of the Liberator structure. Full log analysis and interpretation parameters

were included in the IP project with all input parameters and methods applied for the analysis.

Well Field

13/23a-4 Exploration

13/23d-8 Liberator

13/24a-4 Blake

13/24a-6 Blake

13/24a-7 Blake

13/24a-B1 Blake

13/24a-B2 Blake

13/24a-B3 Blake

13/24a-B4 Blake

13/24a-B5 Blake

13/24a-B7 Blake

13/29b-6 Blake

13/29b-8 Blake

Table 4-1 Liberator are wells included in IP project

Additional data necessary for log analysis was included in the IP project including temperatures and depth

in TVD and TVDSS. Core porosity and permeability are included in the IP project for Blake well 13/24a-4.

MDT data was also supplied and is included in the discussion on fluid contacts.

4.2 Petrophysical interpretation

A consistent set of petrophysical interpretation has been supplied for review. The log analysis was found

to be consistent with the quoted inputs and is supported by other data including porosity from core

analysis and fluid pressure gradients from pressure data. The review resulted in verification of the log

interpretation provided, which was then used as input going forward.

The Lower Cretaceous Captain Sand reservoir in Liberator and Blake is a high net-gross, high porosity and

permeability sandstone as illustrated in Figure 4-1.

Liberator Area CPR


Figure 4-1 CPI for Liberator well 13/23d-8

4.2.1 Vclay

Clay volume was calculated from the GR log and from the Neutron/Density (N/D) cross plot method. The

results from the two methods are similar and the minimum of the two was used as input going forward.

4.2.2 Porosity

Porosity was calculated using the combination of Neutron and Density logs. Core analysis in Blake well

13/24a-4 is a close match to the porosity calculated from logs (Figure 4-2).

Liberator Area CPR


Figure 4-2 Porosity from core analysis in Blake well 13/24a-4 in close agreement with porosity from logs

4.2.3 Water saturation

Water saturation (Sw) has been calculated using the Archie equation of the form:

Where:

Phi is porosity (dec).

Rw is water resistivity at reservoir temperature (for salinity of ~58kppm in this case)

Rt is the true resistivity (often the deep resistivity log)

Constants a, m and n have been given the default values of 1, 2 and 2 respectively in the absence of SCAL

data.

Liberator Area CPR


4.2.4 Permeability

As has been seen with porosity, permeability from core also varies little. A porosity/permeability graph

was presented in the Liberator FDP and is reproduced in Figure 4-3 with the core data from 13/24a-4

Figure 4-3 Porosity v Permeability from core in Blake well 13/24a-4

This function is fit for purpose and was used for the dynamic work.

4.2.5 Reservoir cut-offs

Figure 4-1 and Figure 4-2 illustrate that the net to gross and porosity in the Captain sand is consistently

very high. The average properties calculated are quite insensitive to the cut-offs but a porosity cut-off of

20% was used along with a 50% Vsh cut-off to remove any non-net intervals.

4.3 Fluid contacts

The fluid contacts in Liberator are clearly defined from logs, pressures and fluid samples. There are some

similarities with the oil-water contact depth for Blake but Liberator is expected to be a separate

accumulation. The gas-oil contact seen in the Liberator well is significantly different to Blake

(see Figure 4-4). The contacts in the wells consistently demonstrate a paleo-contact with 20% to 30% oil

in the interval below the current oil-water contact. The thickness of the interval between the paleo and

current oil-water contact varies illustrating some change in the structure over geological time. There is

also a clear gas cap in some of the wells with the gas-oil contact showing some variation by location. The

Liberator current oil-water contact is close to the 5270ft TVDSS being carried in work to date.

The oil-water contact in the wells around the Liberator region is illustrated in Figure 4-4.

Liberator Area CPR


Figure 4-4 Fluid distribution (by year) in the Liberator region

When the same data is displayed but with the wells ordered by location the presence and distribution of

the gas cap is not as random as it might have appeared. The gas-oil contact in the main Blake structure is

consistent with deeper small gas caps in the more north-western wells and in the Liberator well.

Figure 4-5 Fluid distribution (by location) in the Liberator region

The oil-water contact of 5270ft TVDSS is also supported by MDT data from the Liberator well 13/23d-8

(Figure 4-6) though a pressure offset of 70 psi indicates some interference and depletion from the Blake

production.

5050

5100

5150

5200

5250

5300

5350

5400

13

/24

a-4

13

/24

a-6

13

/23

a-4

13

/29

b-6

13

/24

a-7

13

/24

a-B

1

13

/24

a-B

2

13

/24

a-B

3

13

/24

a-B

5

13

/24

a-B

7

13

/23

d-8

De

pth

ft

TVD

SSLiberator and Area Fluid Distribution (by Year)

Gas

Oil

Paleo Oil

Water

Production Began 2001

5050

5100

5150

5200

5250

5300

5350

5400

13

/23

a-4

13

/23

d-8

13

/24

a-7

13

/24

a-4

13

/24

a-B

2

13

/24

a-B

5

13

/24

a-B

3

13

/24

a-6

13

/24

a-B

1

13

/24

a-B

7

13

/29

b-6

De

pth

ft

TVD

SS

Liberator and Area Fluid Distribution (By location)

Gas

Oil

Paleo Oil

Water

Production Began 2001

NW SE

Liberator Area CPR


Gas observed in 13/23d-8 could be as a result of local depletion trapped in a small culmination at the well

location.

Figure 4-6 Formation pressure from Liberator and Blake (from Liberator FDP)

4.4 Saturation vs height function

High, mid and low saturation-height functions were presented in the Liberator FDP. The mid function was

based on the Liberator well (the black line in Figure 4-7). Given the pressure depletion and the higher Sw

observed close to the contact in the Liberator well (which is on the edge of the structure and almost at the

closest point to Blake) this is possibly a low case to carry over the whole of the Liberator structure. A

slight change was made to produce a function with an improved match to the Liberator well Sw from logs

(the red line in Figure 4-7). A function was also matched to the pre-production Blake Sw in 13/24a-4.

This has been taken as the reference case since it represents the saturation as it was in its virgin state.

Liberator Area CPR


Figure 4-7 Saturation height functions displayed with Sw from logs

The Liberator and Blake saturation height functions are displayed on the CPIs for 13/23d-8 and 13/24a-4

in Figure 4-8. The Liberator function is a good fit with the data it is matched to but is pessimistic

compared to the Blake function based on a thick column, high on the structure before any production

affected the fluids.

Figure 4-8 Saturation from the functions described displayed with the CPIs (Red-Liberator, Blue-Blake)

It should also be noted that the Liberator well is on the edge of the structure and only contains a relatively

thin hydrocarbon column (24ft).

Liberator function

Previous mid-function

Blake function

13/23d-8 13/24a-4

Saturation from Liberator and Blake functions with Sw from logs

Liberator Area CPR


Considering the excellent porosity, permeability and apparent heterogeneity of the Captain Sand the

transition zone as expressed on the logs is relatively thick. Intuitively one would expect a very sharp

contact in a reservoir of this quality. Given the relief of the structure, the transition zone will have an

impact on the volumes calculated.

4.5 Results

As the CPIs and core analysis have illustrated, the Captain sands in Blake and Liberator are of excellent

reservoir quality with average net to gross of 90% and average porosity of 28% from both log analysis

and core. Average permeability from core analysis is 2331mD.

Table 4-2 Average properties in Captain sand

Average water saturation above the contact is 14% to 18% in the Blake wells and 39% in the Liberator

well. Some of the reasons for the higher Sw in the Liberator well have already been discussed. i.e. close

to the contact at the edge of the structure and potentially affected by Blake production.

4.6 Uncertainties and sensitivities

As was previously mentioned, the volumes are sensitive to the saturation-height function given the low

relief of the structure and the larger than expected transition zone. Generally all the other reservoir

properties are excellent with little variation.

4.7 Conclusions and recommendations

The reservoir sand in the Liberator well contains extremely good static reservoir properties similar to the

Blake wells. The pressure data indicates the same oil-water contact with some interference from Blake

production (possibly through the aquifer).

If cuttings or core samples are still available, mercury injection capillary pressure data would be a useful

piece of data. It might be that there is some detail in the pore throat size distribution which could help to

understand the nature of the transition zone.

Well Zone Name Top Bottom Top Bottom Gross Net N/G Av Phi

MD MD TVDSS TVDSS TVDSS TVDSS TVDSS

13/23a-4 Captain Sd. 5364.00 5577.00 5278.00 5491.00 213.00 170.00 0.80 0.26

13/23d-8 Captain Sd. 5329.50 5644.00 5247.27 5561.70 314.43 253.44 0.81 0.26

13/24a-7 Captain Sd. 5400.00 5843.00 5178.39 5601.77 423.37 393.50 0.93 0.28

13/24a-4 Captain Sd. 5252.00 5529.00 5167.00 5444.00 277.00 259.50 0.94 0.29

13/24a-B2 Captain Sd. 6388.50 6630.50 5196.04 5391.52 195.48 177.68 0.91 0.31

13/24a-B5 Captain Sd. 6869.50 7243.00 5141.93 5316.02 174.09 165.10 0.95 0.29

13/24a-B3 Captain Sd. 6066.50 6345.50 5180.21 5349.46 169.26 167.91 0.99 0.29

13/24a-6 Captain Sd. 5169.00 5413.00 5085.71 5329.70 243.98 221.99 0.91 0.28

13/24a-B1 Captain Sd. 6240.50 6620.00 5138.96 5384.00 245.06 199.44 0.81 0.25

13/24a-B7 Captain Sd. 9341.50 10052.00 5078.47 5390.52 312.14 298.31 0.96 0.29

13/29b-6 Captain Sd. 5206.50 5557.00 5123.50 5474.00 350.50 322.25 0.92 0.27

All Wells Captain Sd. 265.30 239.01 0.90 0.28

Liberator Area CPR


5 Static modelling

Based on a review of the i3 static and dynamic models it was decided to construct independent AGR static

models for this analysis. These provided more flexibility in assessing the key subsurface uncertainties.

5.1 Key Static Volume Uncertainties

Based on a review of the geology, seismic, petrophysics and fluids, the following are the key uncertainties

affecting volumes:

The top structure (deep or shallow with respect to the reference case)

The saturation-height function – the 24 ft column seen in the discovery well is mostly in transition interval

The significance of the 4ft gas interval seen in the discovery well

All of the Liberator area has been assumed to be sand (no shales at edges of the channel).

Porosity and NTG of the sand itself have a narrow range. The OWC is defined by the MDT formation

pressures and hence has a small uncertainty.

The effect on STOIIP of the uncertainties has been quantified as shown below (Figure 5-1).

Figure 5-1 Effect of reservoir parameters on STOIIP

The permeability of the sands is known from the Blake Field to be high and is not considered a key

uncertainty.

In the Liberator discovery well, an interval of about 25ft of oil saturation occurs below the present OWC.

This feature is similar to the wells in the Blake Field, being interpreted as a paleo-oil zone and is not

counted in the STOIIP.

Liberator Area CPR


5.2 Fluid distribution

The OWC is observed in the Liberator well and is assumed to be the original Liberator OWC extending

across the Liberator structure for volumetrics.

The 4ft of gas seen in the well could be interpreted in several ways:

1. Primary or secondary gas cap across Liberator

2. Local tiny trap within 100m of the well (either primary or secondary)

Evidence from the Blake Field has been considered. The Blake GOC (~5180ft) is slightly deeper in the

north than the south (~5153ft) but the gas column is still greater in south. This fits with the seismic

amplitudes which are fainter in north where thin gas column is seen in 2 wells. Hence, the gas proportion

of HCPV in the Blake Field is approximately 15% in the north and 20% in the south (Figure 5-2).

Because there is no clear seismic amplitude response over the Liberator discovery (Section 3.2.3), the

occurrence of a significant gas cap across the Liberator area is judged to be less than P10 (and has not

been used in the volumetrics cases). A 15% gas cap has been applied in the low case only (Figure 5-2).

Because there are 2 highs within the Liberator Phase 1 area, a GOC was applied at slightly different depths

to achieve the 15% (5210 and 5230ft).

Figure 5-2 Cross Section from NW to SE showing Fluid contacts (low case GOC)

Liberator Area CPR


Figure 5-3 Map showing fluid contacts and (low case volumetrics GOC over Liberator Area)

5.3 Input data

5.3.1 Seismic horizons

– Depth maps for K50, top Captain Sand, Valhall Formation

– Model area includes the Blake Field

The top Captain Sand corresponds to the K50 in the Liberator well and in the Blake Field.

5.3.2 Well data

The wells were loaded manually from the well location and deviation surveys provided by the client. Some

well paths were only available in the seismic project, so they were exported from Kingdom.

The raw log curves and petrophysical interpretation curves were loaded from LAS files generated in the IP

project provided by the client.

Well picks were entered manually into the Petrel project to correspond with those in Kingdom project.

5.4 3D grid model

The modelling was done using Petrel 2016.3 software.

Liberator Area CPR


A cell size of 100m was used, oriented parallel to the boundary of the Liberator area. There are no faults in

the seismic. Segments were created for volumetrics of each of the local highs and for the Blake Field. The

simulation model covers the Phase 1 area (Figure 5-4).

Figure 5-4 Map of modelling grid and segments

5.4.1 Horizons and layering

Only K50 and Valhall horizons are necessary to define the model. The layers are 4 ft in the upper third of

the reservoir and thicker in the deeper interval (Figure 5-5). This means there are 37 layers, resulting in

40000 cells in the Liberator dynamic model area.

Figure 5-5 View of 3D grid, looking from SE, showing layers

Liberator Area CPR


5.4.2 Porosity

The porosity from all the wells was interpolated using a simple method (Figure 5-6). This means that in

the Liberator area, the porosity is mostly influenced by the Liberator well itself. The upper hydrocarbon

bearing interval has porosity of around 0.28 while the deeper interval of the reservoir has slightly lower

porosity of 0.22.

Figure 5-6 Porosity model view

5.4.3 NTG

A net log was generated using a porosity of less than 0.1. This still results in a typical NTG of over 0.95.

The NTG was interpolated across the model (Figure 5-7).

Figure 5-7 NTG model view

5.4.4 Permeability

For permeability, the function for the Blake core was used:

Kh = 0.0412 * PHIE^3.2747

(Porosity is in percent in the i3 Energy formula. This was converted to decimal in Petrel formula)

This gives a permeability distribution mostly above 1 Darcy (Figure 5-8), decreasing with depth due to

slight porosity reduction (Figure 5-9).

Liberator Area CPR


Figure 5-8 Model Permeability Distribution

Figure 5-9 Kh model view

5.4.5 Saturation

The saturation was modelled using 2 functions: one from the 24ft column in the Liberator well itself and

one using log data from the >100ft column in the Blake Field, 13/24a-4 (see Section 4.2.3).

Liberator: Sw = 1.466/(HAFWL^0.622)

Blake: Sw = 0.61/(HAFWL^0.5)

The Blake well is in the north (closest to Liberator) and the whole oil column can be defined with a

relatively short transition zone, as expected in these Darcy sands. Hence the Blake function

(left in Figure 5-10) was used for the reference case.

Liberator Area CPR


Figure 5-10 Comparison of Sw-Height functions

The Blake Field Average log SW is 0.13. As a check, in the 3D model, using the Liberator function gives an

average of only 0.19 for the Blake Field, while using the Blake Function gives an average Sw result of

0.11, which is more consistent.

The resulting Sw model is shown below (Figure 5-11).

Figure 5-11 Sw model view

5.4.6 Depth uncertainty gridding

For generating shallow and deep top reservoir maps, the depth uncertainty away from the wells is

estimated at + 25ft at a radius of 800m (Figure 5-12). The saddle with the Blake Field and the western

edge were not changed during this process. The surfaces were generated in Petrel and corresponding

shallow and deep grids were built with the same internal properties. Sw was regenerated.

Liberator Area CPR


Figure 5-12 Cross Section from NW to SE showing shallow and deep top reservoir

5.4.7 Development Well Trajectories

The well trajectories provided by the client have been loaded into Petrel. This enables the trajectories

through the 3 model grids to be exported to Eclipse. It also enable the trajectories to be briefly evaluated

in terms of achieving the target reservoir.

The first target is in the main structural high, but this itself has 2 subtle highs within it (Figure 5-13). The

approach to top reservoir is constrained by the edge of the licence area and the dips of the structure are

not conducive to landing the well easily. The landing point is 1800m SE of the Liberator well. This is

planned to be mitigated by use of suitable LWD. However a short tangent section may be an additional

option.

Two well trajectories have been provided by the client, the latest one suggests that the two subtle highs

will be crossed through an interval of overlying shale so this eventuality needs to be incorporated into the

drilling plan. It is recognised that these are not the final trajectories.

Figure 5-13: Cross section through first development well (main segment)

The second development well targets a higher structure (Figure 5-14) and is therefore easier to achieve,

although currently constrained by the licence boundary (which may be extended later).

Liberator Area CPR


Figure 5-14: Cross section through second development well (NW segment)

Liberator Area CPR


6 In-Place volumes

6.1 STOIIP Estimation

The deterministic calculations were done in the 3 Petrel 3D grids, for low, mid and high cases, which are

summarised in Table 6-1.

Case STOIIP Struct Gas cap Sw calc

1P Low DEEP 15% LIB 23/13d-8

2P Mid REF Depth No Blake 13/24a-4

3P High SHAL No Blake 13/24a-4

Table 6-1 Summary of STOIIP cases as a basis for 1P, 2P and 3P reserves

An FVF of 1.157 RB/stb based on PVT analysis from the Liberator well (and similar to Blake Field) has been

used for all cases. NTG, Porosity and Permeability are as described in Section 5.4, with no variation

between cases.

6.2 Results

Estimates for STOIIP by case are summarised in the table below (Table 6-2).

Case STOIIP

MMstb

GIIP

Solution gas

Bscf

GIIP Free

gas

Bscf

1P Low 18.4 6.3 0.3

2P Mid 38.0 13.1 0

3P High 58.2 19.8 0

Table 6-2 Low, Mid and High case In-Place Volumes

A portion of the Phase 1 area of the Liberator Field extends outside the P.1987 licence boundary, both to

the Southeast into the Blake Partners’ exploration acreage on P.101, and into the un-licenced area to the

Northwest as indicated in Figure 6-1.

The STOIIP based volumetric split based by licence area is as follows:

68% within the P.1987 Liberator licence

22% within UKCS block 13/23a to the Northwest

10% within the currently held licence to the Southeast

Liberator Area CPR


Figure 6-1 Map showing field extent and licence boundary

Liberator Area CPR


7 Reservoir Engineering

7.1 Data review

The pressure data and PVT report on downhole samples of the Liberator discovery well 13/23d-8 were

reviewed. When the reservoir fluid samples were taken in Nov 2013, the reservoir had a small gas cap and

a thin oil column of 20 ft with a GOR of 341 scf/bbl and bubble point pressure of 2278 psia. The MDT

pressure data from well 13/23d-8 indicated that the reservoir pressure was about 70 psi lower than the

pre-production trend, probably due to aquifer depletion by the Blake production.

No SCAL data is available from the Liberator well.

As development of the Phase 1 area is “green field”, there is no production history data.

Although tNavigator simulation models for the Phase 1 development were provided by the client, following

a workshop review of the model with the client AGR focused on building a simpler simulation model in

Eclipse which would allow fit for purpose evaluation of the reservoir and recovery. A comprehensive review

of the client’s model was not undertaken.

7.2 Dynamic model construction

The 3 static model cases described in Section 5 and summarised in Table 6-1 were used to build low, mid

and high case Eclipse reservoir simulation models. Models were subsequently used to evaluate a range of

recovery factors and generate low, mid and high case forecasts for the Phase 1 development.

7.2.1 Grid

The grids and rock properties, such as porosity, permeability and NTG, were exported from the

corresponding Petrel models. The grid size is 100m×100m in X, Y directions. The cell thickness varies

from top to bottom as below:

Layer 1 -- 20: 4 ft

Layer 21 – 27: 8 ft

Layer 28 – 37: 20 ft

The fine layering at the Upper part of reservoir was to provide sufficient definition in the oil zone as the oil

column interval in the Liberator field is thin, varying from 20ft to 60ft in the Phase 1 area (Figure 7-1). The

total number of cells is 39960 (45×25×37). There are 29267 active cells in the Mid case model. The CPU

time for a simulation run was 10 to 20 minutes, which was fit for the purpose of this study.

The vertical permeability in the E100 models was generated by applying a Kv/Kh ratio of 0.8, which was

based on the measured core data from the Blake field (Ref 1).

Figure 7-1 Phase 1 E100 model – Grids in Z direction

Liberator Area CPR


The Paleo oil zone found in well logs was not explicitly modelled as the oil is immobile. However, the

impact of this immobile oil on the water relative permeability was captured in the dynamic models by

applying a transmissibility multiplier of 0.2 (Figure 7-2), which was the measured Krw from the Blake

SCAL analysis (ref. 1).

Figure 7-2 Paleo oil zone in the Phase 1 E100 model

7.2.2 PVT and Relative Permeability

PVT input data were the same as those applied in Client’s tNavigator model (Table 7-1) and are based on

the Liberator discovery well.

Oil Properties

Reservoir temperature oF 140

Reservoir pressure psia 2315

Oil gravity API 30.5

Pb psia 2278

GOR scf/bbl 341

Bo v/v 1.16

Oil viscosity

Reservoir pressure cp 1.91

Bubble point pressure cp 1.9

Table 7-1 Liberator oil properties

The water, rock and total compressibility were assumed for the aquifer were as follows:

Cr: 5.0E-06 (1/psi)

Cw: 3.0E-06 (1/psi)

Ct: 8.0E-06 (1/psi)

Liberator Area CPR


This is different from what used in the client tNavigation model but is thought to be more consistent with

the high quality, high porosity sandstone at Liberator and the low reservoir pressure.

The water/oil relative permeability curves based on the Blake SCAL measurements provided (Ref 1) were

applied in dynamic models as follows (Figure 7-3):

Corey parameters: No=2.0; Nw=2.0; Krow=1.0

Low/ Mid cases: Sorw=30%, Krw=0.2

High case: Sor=20%; Krw=0.1; SWATINIT with ENDSCALE to make initial water in the transition zone immobile

A generic gas/oil relative permeability with Sgc of 0.05 was applied to all E100 models. The three-phase rel perm model used is the default Eclipse model.

The irreducible oil saturation of 30% was assigned to the Low and Mid cases because of the Paleo oil

saturation in the well logs of Blake and Liberator wells. A lower irreducible oil of 20% applied for High case

was based on the SCAL results from Blake Field (Ref 1).

Figure 7-3 Relative permeability curves for Low, Mid and High cases

7.2.3 Saturation-height function and initialisation

Saturation-height functions described in previous sections (4.4 & 5.4.5) are used for the dynamic models

(Figure 7-4):

Low case: Liberator well S-H function

Mid and High Case: Blake well S-H function

Liberator Area CPR


Figure 7-4 Saturation-height functions for the Liberator Phase 1 E100 models

Low/Mid dynamic models were initialised via the E100 key word – EQUIL, assuming that the initial

reservoir was in the equilibration state with initial reservoir pressure of 2285 psi at a datum of

5270 ft TVDSS (i.e. OWC).

The initialisation of High case was different from Low and Mid cases. The initial water saturation array was

explicitly imported via E100 key word -- ‘SWATINIT’. Furthermore, ENDSCALE was applied to the high case

relative permeability curve to make initial water above OWC immobile. This represents a possible very

short transition zone for High case.

It was assumed that the reservoir pressure has not changed since 2013, because there is not sufficient

information available to assess the impact of Blake field operation on the Liberator phase 1 area.

7.2.4 Regions and aquifer model

The dynamic model for Phase 1 development covers only the Liberator phase 1 area, excluding the

neighbouring Blake field. There are four regions in the dynamic models (Figure 7-5).

Region 1: targeted area of the Liberator LP2 well

Region 2: area connecting to Blake field

Region 3: targeted area of the Liberator LP1 well

Region 4: other area

Regions 1/2/3 are Phase 1 areas. Region 4 is outside the Phase 1 area.

Liberator Area CPR


Figure 7-5 Regions in the Liberator Phase 1 E100 models

Based on the geological and geophysical evaluation, there are large aquifers surrounding the Liberator

Phase 1 area, which were represented by three Fetkovich aquifer models in the dynamic simulation models

(Figure 7-6). The aquifer volumes were applied based on geologic advice.

Aquifer 1: water volume =1 billion bbl



Figure 7-6 Aquifer models in the Liberator Phase 1 E100 models

The review of sand extent to the Northwest, identified a risk that aquifer 1 may not be extensive.

Therefore, the Low case model only has aquifers 2 and 3 assigned. Mid and High case models have 3

aquifers attached northwest, northeast and southeast edges. This is in addition to a large water leg below

the OWC.

Liberator Area CPR


7.2.5 STOIIP

The Initial oil in place volume of the Phase 1 area ranges from 18 MMbbl to 58 MMbbl (Table 7-2).

Structure Gas Cap S-H

Function Rel_Perm

Region Phase 1

Areas 1 2 3 4

Low Low 15% Liberator Krw=0.2,

Sor=0.3 9.53 0.76 8.09 1.83 18

Mid Mid No Blake Krw=0.2,

Sor=0.3 16.59 4.32 17.53 3.12 38

High High No Blake

Krw=0.1,

Sor=0.2;

SWATINIT

21.68 10.44 26.07 4.24 58

Table 7-2 Regional and Phase 1 Area STOIIP

There is a small amount (0.3 bcf) of free gas in place in Low case, mainly located in regions 1 and 3

(Figure 7-7).

Figure 7-7 Initial gas saturation in Low case model

7.2.6 Wells

The Liberator field is planned to be developed via 2 horizontal producers in Phase 1, targeting the Main

and Northwest culminations of the Phase 1 area. The well trajectories for these two wells were imported

from the Petrel models, which were provided by the client in the Kingdom project. Trajectories are shown

in Figure 7-8, the planned wells were aimed to create maximum coverage and to optimise stand-off.

Liberator Area CPR


(a) 3D view: 2 wells (b) Section view: well LP1

Figure 7-8 Well locations in Phase 1 E100 models

7.3 Forecasts

7.3.1 Phase 1 schedule and well controls

The prediction run start date was 01/01/2019; forecasts were run to 01/01/2041. Based on the

information provided by the client, the schedule and well controls applied to the dynamic models are listed

below:

01/01/2019, LP1 onstream

o Max. oil rate: 10000 stbd

o Max. liquid rate: 20000 stbd

o Max. pressure drawdown: 15 psi

o THP: 523 (psia)

o VLP table (provided by i3E)

o Gas lift gas rate: 2 MMscf/day

o Well Uptime: 0.86

01/01/2020, LP2 onstream

o Max. oil rate: 10000 stbd/well

o Max. liquid rate: 10000 stbd/well

o Max. pressure drawdown: 15 psi

o THP: 523 (psia)

o VLP table (provided by i3E)

o Gas lift gas rate: 2 MMscf/day/well

o Well Uptime: 0.86

There is sufficient ullage to accommodate the above rates and constraints. The uptime assumption for the

prediction runs was 86% (based on the reported uptime of the for Blake field production).

7.3.2 Results

The predicted recoveries for Low/Mid/High cases were as follows.

Liberator Area CPR


E100 Model

STOIIP

(Phase 1

Areas)

Cum oil (@01/01/2041)

RF LP1 LP2 Total

Low 18 1.6 2.7 4.3 24%

Mid 38 5.8 6.2 12.0 31%

High 58 9.9 8.6 18.6 32%

Table 7-3 Forecast recoverable oil of the Liberator Phase 1 development

E100 Model

Phase 1 area Cum. gas (@01/2041)

Bscf RF Free GIIP

Bscf Dissolved GIIP

Bscf Total Bscf

LOW 0.304 6.26 6.57 3.74 57.0%

MID 0 13.09 13.09 7.51 57.3%

HIGH 0 19.81 19.81 11.17 56.4%

Table 7-4 Forecast recoverable gas of the Liberator Phase 1 development

Although there are strong aquifers surrounding the Liberator field, the pressure support from aquifers are

not sufficient to prevent the decline of the reservoir pressure below the bubble point shortly after the start

of the production. The models predict in the mid and high cases the development of a secondary gas cap

after year 2020 (Figure 7-9 Ternary plots – Mid case), which resulted in the change of single recovery

mechanism of pure bottom water drive to the combined mechanism of bottom water and gas cap drive.

Once the free gas is released from the reservoir, the reservoir pressure decline is accelerated.

Theoretically, the combination of strong aquifer and gas cap drives would enable a high recovery factor

around 50%, similar to the current recovery factor achieved from the Blake field. However, the ultimate

recovery factors of Phase 1 development is lower. This is mainly due to the thin oil column in the Phase 1

targeted area and unavoidable cusping of water from below. Note that i3 Energy intend to try to optimise

the well placement and stand off through the use of AziTrak and ViziTrak. This together with draw down

management and the use of inflow control devices may lead to more efficient management of water

production. These mitigations and controls may help to improve sweep efficiency and recovery.

(a) Mid case, 01/2020 (b) Mid case, 01/2021

Figure 7-9 Ternary plots – Mid case, Y slice 13

Liberator Area CPR


7.3.3 Forecast profiles

The forecast for the Low, Mid and High Cases are shown in Figure 7-10, Figure 7-11 and Figure 7-12.

These forecasts provided a basis for economic evaluation. A table of rates is provided as Appendix A.

Figure 7-10 Low Case predicted oil rate, WCT, GOR and Cum. oil

Liberator Area CPR


Figure 7-11 Mid Case predicted oil rate, WCT, GOR and Cum. oil

Figure 7-12 High Case predicted oil rate, WCT, GOR and Cum. oil

Liberator Area CPR


8 Production Technology

The production technology section primarily considers the completion and factors affecting this such as:

Solids (sand) production

Artificial lift

Metallurgy

Flow assurance (scale, wax etc.)

The Liberator well will be completed with standalone sand screens, inflow control devices and gas lift for

artificial lift. The proposed metallurgy for the completion is 13 Cr tubing due to the presence of CO2 in the

produced fluids.

8.1 Sand Control

Detailed analysis in terms of sand control method selection and sizing has been carried out. Additionally,

an assessment of the potential for screen erosion is presented in the Basis of Design Document (SPD-IEN-

WEL-BOD-00416 Liberator Basis of Design-C&WT- Rev C).

Particle Size Distribution (PSD) analysis provides the information for determining the uniformity and

sorting of the sand grains as well as defining the volume of fines (<44µm) in the reservoir sands. The

results of the analysis based on sample from wells 13/24a-4 and 13/24a-6 are shown in Figure 8-1.

Figure 8-1 Particle Size Distribution

The results show a medium-coarse grained sandstone with no fines (smallest measured grain size is above

50 microns). Note that these are based on sieve analysis. Laser Particle Size Analysis (LPSA) would

provide a higher resolution of any fines content, but extrapolating existing results indicates that maximum

fines content would be <5%.

Selection of the sand control type is based on the Uniformity Coefficient (d40/d90) and the Sorting

Coefficient (d10 / d95) both of which express a ratio of the %fines size over a range. The values are

shown in Table 8-1.

Liberator Area CPR


Weight percentage retained at

sieve

Average grain size at cumulative weight percentage (µm)

Well 13/24a-4 Well 13/24a-6

d10 600 420

d40 360 275

d50 310 230

d90 180 78

UC = d40 / d90 2 3.5

SC = d10 / d95 3.0 5.3

Table 8-1 Uniformity and Sorting Coefficients

Based on the UC and SC values, the sand control type can be defined from pre-defined limits as defined by

Bennet et al 2009 (SPE65140, Design Methodology for Selection of Horizontal Open-Hole Sand Control

Completions Supported by Field Case Histories) and shown in Table 8-2.

d50

Sorting

Coefficient

d10/d95

Uniformity

Coefficient

d40/d90

Fines Coefficient

(<44Microns)

Sand Control

Medium

>75 microns <10 <3 <2 wt% Wire Wrap Screens

>75 microns <10 <5 <5 wt% Premium Screens

any failure to meet above criteria Gravel Pack or ESS

Table 8-2 Sand Control Method Selection Criteria

The extremely low volume of fines and good uniformity coefficients indicated that premium screens are an

acceptable choice for the sandface completion, i.e. a gravel pack is not required. It has been noted that

final selection and sizing will take place during detailed design, which is industry standard practice.

8.2 Gas Lift

The artificial lift selection for the Liberator development is gas lift. Nodal analysis has been carried out to

ascertain the optimum depth of the gas lift valves and the gas requirements for various stages in the field

life. The maximum gas lift available is 4 MMscf/day.

The analysis shows that in order to maintain the target liquid production rate of 7,000 bpd, gas lift will be

required for water cut increasing beyond 50%. At 50% water cut, 1.8 MMscf/day of gas lift is required and

as water cut continues to increase to 95%, gas lift rates will increase to 2.6 MMscf/day. There is little

incremental benefit in liquid production for gas lift rates higher than 3 MMscf/day and thus the upper limit

of 4 MMscf/day is more than adequate for the purposes of the artificial lift design.

Liberator Area CPR


Table 8-3 Gas lift rate v liquid production rate (95% WC and depleted reservoir)

8.3 Metallurgy

The Liberator produced fluids contain 0.9% CO2, but no H2S. This gives a partial pressure of 20.4 psi at

2,263 psi (BHFP). Mapping this pressure onto a metallurgy selection matrix confirms that for this level of

CO2, the selection of 13 Cr tubing is appropriate for the completion tubing as shown in Figure 8-2.

Figure 8-2 Metallurgy selection for CO2 and H2S partial pressures

Liberator Area CPR


9 Well Engineering Review

9.1 Introduction

The Well Engineering Assessment was completed based on the following provided documentation:

Phase 1 Development FDP Draft

Drilling Basis of Design

Subsea Wellhead & Tree Basis of Design

Completion & Well Test Basis of Design

Blake offset date files – EOWR’s & Well Logs

The current plan for well construction is in alignment with typical North Sea analogues, the nominated

slim-hole casing design is supported on the basis that this allows the BOP’s to be run after the conductor

has been cemented in-place. This will then allow the drilling of the 17-1/2” hole section with a closed loop

mud system in order to inhibit the potential swelling shales in this area. Due to the prospect being classed

within the ‘normal pressure normal temperature’ range – no enhanced ‘long lead’ tubulars are required in

order to meet the desired casing & completion design. Casing point selection and subsequent kick

tolerance limitations have all been met for the proposed slim-hole design.

9.2 Well location/trajectory

The well trajectory is designed as a j-shaped horizontal production well with a tangent angle of 76°, the

plan will be to drill the 12-1/4” hole section into the Captain formation where 9-5/8” casing will be set. It

should be noted that there is the potential for 2 bit trips through the abrasive chalk interval (Tor & Hidra),

which has been present in some of the offset wells.

In order to navigate the wells and maximise stand-off from the OWC, geo-steering will be required within

the 8-1/2” reservoir hole section where ROP will need to be secondary in order to meet this well objective.

The possibility of drilling a pilot well was considered by i3 and their 3rd party advisors early in the drilling

planning phase. Together with Petrofac, i3’s Well Management contractor, and Baker Hughes, i3’s Oilfield

Services supplier, i3 concluded that including AziTrak and ViziTrak in the LWD suite will negate the need

for a pilot well. In AGR’s view a pilot hole to fully optimise the well trajectory should still be considered in

the well execution phase as formational top uncertainties become realised. Contingency planning should be

in-place in order to mitigate this well risk.

The 4000ft+ reservoir section has been achieved on the nearby Blake field however, hole cleaning (torque

& drag), wellbore stability (wellbore breakout) and hydraulics (ECD management) should all be primary

focus in order to deliver a hole condition fit for running standalone sand screens. Some attention should be

given to the drive mechanism selected for drilling the reservoir section where hole spiralling can be

minimised by the use of rotary steerable drive systems. This has been addressed by the engagement of

Petrofac and Baker Hughes who both have experience in wells such as this including some of the Blake

wells.

9.3 Well architecture

The slim-bore well design is the preferred option that allows the BOP to be run and hence use a closed

inhibitive WBM system to drill the 17-1/2” hole section. The casing design load cases are all met based on

the materials and weights selected for the design. One point of note would be to run a kick tolerance

sensitivity for the 8-1/2” hole case whereby the 12-1/4” hole section does not penetrate the reservoir.

Although not forecast to present an issue (due to the small open-hole length) it will provide information for

well examination purposes if this contingency is required.

Many offset wells have required conductor top-up jobs, consideration should be given to good top-hole

drilling practices in order to avoid hole washout to maximise the ability to get cement to surface.

Baker have performed a wellbore stability study but this was not sighted during the review. It was fed

back by i3 that the results of the study will be incorporated in the next Well Basis of Design document. It

would also be recommended to use a reputable ‘geo-mechanics’ company with previous knowledge in the

area to support this work.

Liberator Area CPR


The top of cement requirement for the 9-5/8” casing string is critical for production packer placement,

hydraulic calculations should take into account the proposed use of WBM, which could generate higher

mud weights for wellbore stability (minimum breakout) requirements. There is no intention to run a

cement bond log across the production packer setting point to confirm annulus isolation, this should be re-

considered or sensitivities within the tubing design should incorporate an un-supported packer case.

It was not clear from the documentation provided if torque and drag modelling for running stand-alone

sand screens had been evaluated. Sensitivities should be run with varying trajectory profiles to better

understand if the screens can be fully deployed to well TD. If, from modelling the running of screens to

bottom is deemed marginal then the following can be used to aid deployment.

Swivel master

Self-aligning eccentric shoe profile

Low friction centralisers

Enhanced lubricants for torque and drag reduction

Finally, from a well architecture stand point, a conductor analysis study should be initiated at the earliest

opportunity to incorporate the selected rig, wellhead/conductor and casing arrangement in order to

understand whether additional fatigue mitigation measures are required for the proposed duration of the

well construction phase. Although an intervention phase is not expected for this well, some allowance for

fatigue should be included for the abandonment phase. No issues have been identified with abandonment

phase from such a well.

9.4 Well construction risks

The top 10 well construction risks identified in chronological order are as follows:

1. Conductor cementation job – potential requirement for top-up job

2. Shallow directional work required through potentially soft formations – potential to fall behind the curve

3. Hard abrasive chalk drilling with directional work planned through Ekofisk, Tor & Hidra – potential to increase tangent angle to catch up

4. Wellbore stability requirements through base 17-1/2” hole section & base 12-1/4” hole section – potential for wellbore breakout in Lista / Maureen & Rodby formations, especially at high angle –

avoid build & turn profile through Rodby formations

5. 9-5/8” production casing cementation – potential for un-cemented production packer

6. Directionally landing well horizontally at top reservoir with top reservoir depth uncertainty – pilot

hole recommendation

7. Geo-steering requirements to optimise stand-off through 40ft sand body – potential to steer out of captain and back into Rodby

8. Deployment of sand screens through 4000ft+ horizontal reservoir section – setting production packer high and non-optimally placing screens / blanks in reservoir

9. Fluid compatibility between drilling fluid & completion fluids

10. Reservoir characteristics doesn’t follow offset – incorrect lower completion selection

Liberator Area CPR


9.5 Well time and costs

The proposed time and cost estimate for the liberator SE well (LP1) was 71.7days at a cost of £23.9 MM;

this was based on a semi-submersible drilling rig rate of $90,000 day. Based on current industry

knowledge (unless a rig has already been secured) then this rate appears to be rather aggressive. A

recommended rate for a campaign through the summer months of 2018 would be more in the region of

$110,000/day. (75 days at $20,000/day additional £1.2 MM)

Additional time has been added based on the probable requirement for a conductor cement top-up job

(15hours - additional £0.2 MM – based on a spread rate of $400K/day & exchange rate of 1.25 from

GBP/USD).

No changes have been made to the proposed NPT or WOW used within the time/cost analysis, these are

maintained at 15% and 10% respectively.

Including the additional time/costs highlighted above would reflect in a revised total duration of ~75days

and a well cost of £25.3 MM

Liberator Area CPR


10 Facilities

10.1 Introduction

The Liberator field is located in the Moray Firth province in the UKCS approximately 120 km northeast of

Aberdeen. It lies in close proximity to the Bleo Holm FPSO which processes fluids from the producing

Blake/Ross fields. Both are operated by Repsol Sinopec.

Figure 10-1 Bluewater Bleo Holm FPSO

The Phase 1 Liberator development consists of two wells LP1 and LP2 that will be tied back to the Blake

field manifold via a multiphase metering and tie in structure with all production liquids delivered to the

Bleo Holm for processing.

Well control and chemical injection capability will be delivered through the existing Blake system as will

any future gas lift requirements. The proposed drilling location of LP1 which targets the central and

eastern structural highs is at minimal distance from the Blake manifold while LP2 which targets the

western high is expected to be located some 2km distant. On completion it will be connected by a 6 inch

production pipeline to the LP1 production spool.

Production fluids from Liberator will be comingled with existing Blake/Ross production for processing. The

combined production stream will be offshore loaded in parcel sizes of up to 500,000 bbls for delivery to UK

and northwest European refiners. Crude oil quality is comparable to the existing Blake/Ross stream

(30.5 deg. API) which is reported by Repsol (Operator) as trading at around parity to Brent or a slight

premium. A 24 km 6 inch gas export line connects the Bleo Holm FPSO to the Frigg trunk line for the

dispatch of surplus associated gas to the St Fergus terminal.

10.2 Bleo Holm FPSO facilities capacity and ullage

Production from the Blake/Ross fields is currently running at approximately 10,000 bopd and sufficient

processing capacity exists to accommodate Phase 1 production volumes from the Liberator field.

Estimates of current ullage are derived from the Bleo Holm Datasheet provided by Bluewater (vessel

owner) and data available in ICOP (Infrastructure Code of Practice) documents. Water injection is the only

activity with constrained capacity.

Liberator Area CPR


Activity Capacity* Ullage 2018-2021**

Processing

Fluid Capacity 140,000 blpd >25%

Crude Oil 100,000 bpd >25%

Produced Water 135,000 bwpd >25%

Storage

Export Crude ~690,000 bbls

Load out rate 33,000 bbls/hour

Max cargo size 500,000 bbls

Slop Tanks ~42,000 bbls

Injection

Water 140,000 bwpd at 3,500 psi <5%

Gas 58 MMscf/d at 2,900 psi >25%

* Bluewater Bleo Holm Datasheet

** Infrastructure code of practice (ICOP) data

Table 10-1 Bleo Holm Datasheet and ICOP ullage estimates

Based on 2016 production data, ullage is likely to be considerably higher than indicated above

Production Blake Ross Total Capacity

Oil bbls/day 9,660 373 10,033 100,000

Water bbls/day 27,454 672 28,126 135,000

Total Fluid

bbls/day 37,114 1,045 38,159 140,000

Associated Gas

MMscf/day 5.369 0.189 5.568 >58

Table 10-2 Blake/Ross production 2016

Liberator Area CPR


11 Phase 1 Project Delivery

11.1 Project execution plan and work packages

The final draft of FDP for the Liberator discovery has not yet been submitted to the Oil and Gas Authority

although AGR were provided with an advanced draft of the FDP, which i3 have issued to OGA for review.

The Environmental Statement (ES) has been completed and submitted to the OGA for review and

approval.

The work packages described in the FDP consist of the drilling of two horizontal wells and the installation

of a limited scope subsea system; LP1 will be tied into the Blake manifold using a 6 inch diameter

100 metre spool and 4.5 inch 100 metre control jumper. The flowline between well LP2 and LP1 will be

approximately 2km long and will tie in to the LP1 production spool. A 4.5 inch control umbilical will run

from LP1 and LP2 to deliver power, chemicals and well control.

Well engineering and design has been developed by Petrofac Well Engineering (PWE) who will also be

managing the well delivery process. Permitting and approvals will be managed jointly between i3 and PWE.

The prime contractor for the design, construction and commissioning of the subsea system has not been

identified and will be the subject of further discussions between i3 and Repsol Sinopec UK. A steering

committee or similar group will be established to manage the interface activities between the Liberator

subsea system and the Respol Sinopec tie in point and will include i3, PWE and Repsol Sinopec.

No new processing facilities are required and sufficient ullage exists to process anticipated production

fluids from the Liberator field.

Although the Project Execution Plan is at the stage of definition, the planned activities relating to Phase 1

are of limited scope and complexity by North Sea Standards and do not entail any new technologies. PWE

and Repsol are both experienced parties with a successful track record of delivering complex projects in

the UKCS area.

11.2 Commercial agreements

Heads of Terms for the processing, storage and offloading of production fluids from the proposed Liberator

development have not yet been agreed with Repsol Sinopec UK although discussions are underway.

The key issue for the parties is to define and agree the processing fee calculation methodologies – dollars

per barrel fee and cost share – as well as the duration of each.

AGR have applied a tariff they consider to be reasonable for the first 3 years of production followed by cost

share for the remainder of the term, with FPSO costs allocated according to each party’s share of

production. At the request of i3 the tariff for the first 3 years is not quoted due to the sensitivity with

respect to the ongoing negotiations.

As Liberator production will be comingled with existing Blake/Ross production, the most effective means of

placing Liberator volumes into market will be to agree terms for Repsol Sinopec to market i3’s entitlement

and for i3 to receive pro rata payment for each cargo. This has multiple advantages – for example it

avoids the duplication of marketing/trading organizations, it improves operational efficiency by reducing

the volume of crude held in storage and reduces cashflow volatility. AGR have applied a lifting/marketing

fee based on a $/bbl agreement. This is again not quoted due to the sensitivity with respect to ongoing

negotiations.

A gas transportation tariff to the Frigg system will also need to be agreed. The amount of gas available for

export will depend on fuel requirements for the FPSO as well as net gas injection for artificial lift. In the

economic evaluation it is assumed that all gas produced has an economic value equivalent to 10% of the

value of Brent Crude. This applies to the direct value from gas exports as well as gas used in process heat

requirements.

It is noted that the addition of third party volumes for processing on the Bleo Holm will reduce OPEX costs

per barrel – this is fully aligned with the 2016 Wood Report recommendations, “maximizing economic

recovery” of oil and gas from the UKCS.

Liberator Area CPR


11.3 Project schedule

For the purposes of this report AGR have assumed a 1/1/2019 date for first oil from LP1 and 1/1/2020 for

LP2. i3’s high level schedule is included as Figure 11-1.

Figure 11-1 High Level Development Schedule provided by i3 Energy

11.4 Cost review

AGR were provided with estimates of CAPEX and OPEX costs for Phase 1 of the development of the

Liberator field.

Well engineering and design work has been completed to a high level of definition and is widely informed

by vendor quotes. Only conceptual work had been completed on the subsea component.

As the Liberator project relies on third party processing on the Bleo Holm, no facilities CAPEX is included in

this review, instead 3rd party tariffs and processing fees are reviewed under the OPEX section.

11.4.1 CAPEX

AGR TRACS conducted a detailed review of estimated well times and costs for LP1 and LP2 and a number

of amendments have been carried forward into the economic evaluation as described in Section 0.

Well cost estimates provided by i3 included 15% non-productive time (NPT) and 10% waiting on weather

(WoW). No additional contingency was added by AGR with final well cost estimates of $31.6 MM used in

the economic evaluation.

No detailed engineering and design work was available relating to the subsea system although the broad

design parameters are described in both the Environmental Statement and the FDP. AGR has adopted i3’s

sub-sea cost estimates with the only amendment being the addition of 15% contingency. The potential for

costs to further deviate from i3’s initial estimate is addressed through a +/-25% CAPEX cost sensitivity

which is reported in the economics section.

Subsea Packages Initial Cost

(US$ MM) Contingency Rate

Total Cost

(US$ MM)

LP1 9.1 15% 10.5

LP2 22.1 15% 25.4

Total 31.2 15% 35.9

Table 11-1 Subsea CAPEX cost estimates, base year cost 2017

Decommissioning costs of $29.9 MM include 15% contingency.

11.4.2 OPEX

The key issue on OPEX is the calculation of cost share from 2022 onwards and the uncertainty associated

with production forecasts for the Blake/Ross fields used to allocate FPSO costs between Repsol Sinopec

and i3.

Liberator Area CPR


Year Blake/Ross

Production Mb/d

Phase 1 2P

Production Rate

Mb/d

Total Bleo Holm

Mb/d

Liberator Cost

Share %

2019 10.0 6.3 16.2 39%

2020 8.3 8.8 17.1 51%

2021 9.0 3.8 12.8 30%

2022 7.8 2.4 10.2 24%

2023 8.3 1.7 10.0 17%

2024 7.9 1.4 9.2 15%

2025 7.1 1.1 8.2 14%

2026 6.4 1.0 7.3 13%

2027 5.7 0.8 6.5 12%

2028 5.2 0.7 5.9 12%

2029 4.6 0.6 5.3 12%

2030 4.2 0.6 4.8 12%

Table 11-2 Forecast Bleo Holm throughput for cost share allocation

The latest lease and operating and maintenance costs for the FPSO have not been shared with i3 but are

stated by Repsol to be around $80 MM per year. This is in line with AGR’s experience of $73-82 MM/year

and the $80 MM/year proposed by i3 is considered to be a reasonable estimate. Further information will

be available once negotiations with Repsol Sinopec have been concluded.

Overhead costs are expected to be minimal and a value of $2 MM per year for Phase 1 is reasonable.

Liberator Area CPR


12 Phase 1 Economics

12.1 Assumptions register

To aid the interpretation of project economics, the register sets out the parameters used in the economic

evaluation. For Liberator, they are:

i3 working interest: 100%

Duration of Licence: To end of commercial operations

Price Deck: Sproule 3Q 2017 Brent forecast

Gas price at 10% of Brent price

Liberator differential: None, Brent parity per Blake

Corporate Income Tax: 30%

Supplementary Charge: 10%

Investment Allowance: 62.5%

Depreciation schedule: 100% year 1

Wells Contingency: 15% non-productive time, 10% waiting on weather

Subsea contingency 15%

Discount rate: 10%

Exchange Rate: 1 GBP = $1.25

Escalation: 2%/year

Base year (costs): 2017

Variable OPEX: Volume based tariff for 3 years followed by FPSO cost share

Offtake and marketing fee: $/bbl based tariff

Fixed OPEX: $2 MM/year

Decommissioning: ~30% of CAPEX cost

The evaluation time frame for the estimation of economics and reserves is 2019 to 2030 inclusive. Beyond

2030 there is the potential for continuing economic production but this is dependent on a number of

factors including FPSO design life and continuing production from the Blake/Ross fields.

12.2 Price deck

The economics were run using Sproule Associates 3Q 2017 price forecast. Additionally, runs were

performed to determine the Brent price required to generate an NPV10 of zero (project breakeven).

• Blake oil trades at parity or a slight premium to Brent crude (as reported by Repsol) • Liberator crude oil quality expected to be no worse than Blake

• Economic evaluation assumes Brent parity for Liberator • No segregation of Blake and Liberator volumes, streams are comingled for export with no

quality bank adjustment

Liberator Area CPR


Figure 12-1 Sproule Associates 3Q 2017 Brent price forecast

12.3 Economic results

The economic evaluation was conducted in two stages; the first stage reviewed well LP1 on a standalone

basis in the context of a statement contained in the i3 FDP that stated that the second well (LP2) was

contingent on the success of LP1. Positive NPVs for LP1 were recorded for all three production cases so

the second stage economic evaluation combining LP1 and LP2 was conducted (the Phase 1 development).

12.3.1 LP1 results

The post-tax economics results for LP1 on a stand-alone basis are presented in Table 12-1. Under the

price assumptions used in this report, LP1 economics are positive for all production cases and the 3P

production case demonstrates the potential materiality of the project with an NPV10 approaching $200

million.

LP1 NPV10 $MM NPV0 $MM IRR $ CAPEX/boe $ OPEX/boe

1P 7.7 11.7 25% 25.4 16.2

2P 96.5 134.0 148% 7.5 15.4

3P 186.3 268.9 211% 4.3 15.9

Table 12-1 LP1 Post tax standalone economics

Further analysis was conducted to determine the crude price required for each of the production cases to

generate a pre and post-tax NPV10 of zero. Results are summarised as follows:

Production Case

LP1&LP2

Pre-tax Post-tax

1P $50.8 $51.5

2P $24.0 $24.0

3P $18.5 $18.7

Table 12-2 LP1 Pre and Post Tax Breakeven crude price

2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

Brent 53.5 57 67 72 75 76.5 78.0 79.6 81.2 82.8 84.5 86.2 87.9

40

50

60

70

80

90

100

$

/

B

b

l

2024 onwards escalated at 2%/yr

Liberator Area CPR


On an undiscounted basis, the post-tax payback period for LP1 is 1 year or less for all cases and under the

3P production cases free cashflow would be sufficient to fully fund the second well, LP2.

Figure 12-2 LP1 Cumulative post tax cashflow, undiscounted

12.3.2 Phase 1 - LP1&2 results

The pre-tax and post-tax economics results for the combined LP1 and LP2 wells (Phase 1 project) are

presented in Table 12-3 and Table 12-4, respectively. Under the price assumptions used in this report,

Phase 1 economics are positive and robust for all production cases.


1P 59.5 85.9 50%

2P 327.9 472.5 211%

3P 576.3 851.6 302%

Table 12-3 Phase 1 – LP1 & LP2 Pre-tax economics

LP1&LP2 NPV10 $MM NPV0 $MM IRR $ CAPEX/boe $ OPEX/boe

1P 37.0 57.9 39% 22.8 15.5

2P 200.4 289.9 160% 8.7 15.2

3P 349.8 517.3 226% 5.6 14.7

Table 12-4 Phase 1 – LP1 & LP2 Post-tax economics

As with LP1, further analysis was conducted to determine the crude price required for each of the

production cases to generate a pre-tax and post-tax NPV10 of zero. Results are summarised as follows:

-100

-50

0

50

100

150

200

250

300

2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

$

/

M

M

1P

2P

3P

Liberator Area CPR


Production Case

LP1&LP2

Pre-tax Post-tax

1P $45.4 $46.3

2P $24.7 $24.8

3P $19.6 $19.8

Table 12-5 Phase 1 – LP1 & LP2 Pre and Post Tax Breakeven crude price

Figure 12-3 Phase 1 - LP1 & LP2 post tax cumulative cashflow, undiscounted

The undiscounted pre-tax cash flows are presented in Appendix C.

12.3.3 Sensitivities

Sensitivities were carried out on LP1 and the combined Phase 1 development to test the impact on

economics of a +/-25% range in CAPEX and OPEX costs.

In all production cases the NPV10 values remain positive after adding 25% to costs of both the LP1 and

the full Phase 1 CAPEX program

LP1 NPV10 $MM NPV0 $MM IRR LP1&2 NPV10 $MM NPV0 $MM IRR

1P 0.3 5.0 11% 1P 22.4 44.2 24%

2P 90.6 128.2 114% 2P 187.0 276.1 120%

3P 180.4 263.1 168% 3P 336.6 503.6 177%

Table 12-6 Phase 1 NPV sensitivity – CAPEX plus 25%

Reductions in CAPEX clearly support project economics although due to the reliance on 3rd party

processing on the Bleo Holm the CAPEX program is relatively light and the impact on post tax project

economics from variations in CAPEX is thus less significant than in situations where new build facilities are

also required.

-100

0

100

200

300

400

500

600

2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

$

/

M

M

1P

2P

3P

Liberator Area CPR


LP1 NPV10 $MM NPV0 $MM IRR LP1&2 NPV10 $MM NPV0 $MM IRR

1P 14.1 17.5 46% 1P 51.1 71.7 63%

2P 102.4 139.7 203% 2P 213.6 303.6 223%

3P 192.2 274.6 283% 3P 362.7 531.1 303%

Table 12-7 Phase 1 NPV sensitivity – CAPEX minus 25%

A similar sensitivity was conducted varying OPEX by +/-25% and as with the CAPEX sensitivity, project

economics remains positive in all production cases.

LP1 NPV10

$MM

NPV0

$MM IRR LP1&2

NPV10

$MM

NPV0

$MM IRR

1P 4.8 7.6 20% 1P 30.7 47.6 35%

2P 88.6 120.8 141% 2P 185.0 263.3 153%

3P 172.6 245.3 203% 3P 326.5 477.0 217%

Table 12-8 Phase 1 NPV sensitivity – OPEX plus 25%

LP1 NPV10

$MM

NPV0

$MM IRR LP1&2

NPV10

$MM

NPV0

$MM IRR

1P 10.5 15.8 30% 1P 43.4 68.3 42%

2P 104.4 147.2 154% 2P 215.8 316.4 167%

3P 200.1 292.4 219% 3P 373.0 557.7 235%

Table 12-9 Phase 1 NPV sensitivity – OPEX minus 25%

In the reference case economic evaluation it is assumed that all gas produced has an economic value

equivalent to 10% of the value of Brent Crude. This applies to the direct value from gas exports as well as

gas used in process heat requirements. As commercial negotiations have not been completed, a sensitivity

has been performed where the gas is given no value (i.e. i3 are unable to capture the value from their

share of associated gas). The results are presented in Table 12-10. The sensitivity shows that the gas

generally carries less than 10% of the value of the project compared with the reference case economics

and the project remains economically robust.

LP1 NPV10

$MM

NPV0

$MM IRR LP1&2

NPV10

$MM

NPV0

$MM IRR

1P 4.1 6.4 19% 1P 28.1 44.0 33%

2P 88.4 120.8 141% 2P 184.2 263.1 153%

3P 173.9 247.6 203% 3P 327.0 478.4 217%

Table 12-10 Phase 1 NPV sensitivity – No Gas Export

12.3.4 Summary comments

The Liberator project demonstrates a clear potential for material cashflow. In particular, a circa 1 year or

better project payback period demonstrates a high level of capital efficiency.

The conclusion of commercial terms with Repsol Sinopec and detailed engineering and design work on the

subsea system are essential next steps. i3 are already engaged in these and will be able to draw on the

support of the OGA, if needed, to conclude reasonable commercial terms with Repsol Sinopec for

processing on the Bleo Holm.

Liberator Area CPR


13 Resource Estimation

13.1 Classification of Resources

Resources are classified as Undeveloped Reserves Justified for Development, on the basis that:

The low case NPV is positive based on an IRR of 10%; i.e. is clearly commercially viable.

Resources are discovered; well 23/13d-8 proved the presence of moveable hydrocarbons of significant quantity to meet the criteria for discovery.

There is a development plan of sufficient maturity; the development project is in late Define Stage.

13.2 Estimated Reserves

Reserves attributable to the Phase 1 development are:

LP1 & LP2 Oil MM bbl Gas Bscf MMboe

1P 4.0 3.2 4.5

2P 10.7 6.1 11.7

3P 16.9 8.7 18.3

Table 13-1 Phase 1 – LP1 & LP2 oil and gas reserves

This assumes COP at the end of 2030 (30-year design life of the Blake FPSO). Boe conversion used is 6000

cubic feet per barrel of oil equivalent.

Liberator Area CPR


14 References

1. K. E. Du*, S. Pai, J. Brown, R. M. Moore and M. Simmons (BG International): Optimising the Development of Blake Field under Tough Economic and Environmental Conditions, SPE 64714, SPE International Oil and Gas Conference and Exhibition in China held in Beijing, China, 7–10 November 2000.

2. Bennet et al: Design Methodology for Selection of Horizontal Open-Hole Sand Control Completions Supported by Field Case Histories, SPE 65140, SPE European Petroleum Conference, Paris, 24-25 October 2000

Liberator Area CPR


15 Glossary of Terms

$ US Dollars

% percent

3D Three Dimensional

API American Petroleum Institute

bbls Barrels

Bscf Billion standard cubic feet of natural

gas

boe barrels of oil equivalent

bopd barrels oil per day

bpd barrels per day

bwpd barrels of water per day

CAPEX capital expenditure

CPR Competent Persons Report

CPI Computer Processed Interpretation (of

logs)

EOWR End Of Well Report

FDP Field Development Plan

ft feet

FVF Formation Volume Factor

FWL Free Water Level

GIIP Gas Initially In Place

GOC Gas Oil Contact

GOR Gas to Oil Ratio

HAFWL Height Above Free Water Level

HC Hydrocarbon

HCPV Hydrocarbon Pore Volume

IRR Internal Rate of Return (from MOD

cashflows)

K Permeability

km Kilometre

km2 Square kilometres

m metre

Mbbls thousand barrels of oil (unless

otherwise stated)

Mboe thousand barrels of oil equivalent

Mbopd thousand barrels of oil per day

Mcf thousand cubic feet

Mcfd thousand cubic feet per day of natural

gas

MD Measured Depth

mD milli Darcies

MDT Modular Formation Dynamic Test

MM million

MMbbl million barrels of oil

MMstb million stock-tank barrels of oil

MMbo million barrels of oil

MMboe million barrels of oil equivalent

MMcf million cubic feet of natural gas

MMscf/day million cubic feet of natural gas per

day

NTG Net to Gross

Neu Neutron log

NPV Net Present Value

OGA Oil and Gas Authority

OPEX operating expenditure

OWC Oil Water Contact

P10 10% probability of being exceeded



POS Possibility Of Success

ppm Parts per million

PRMS Petroleum Resource Management

System

psi pounds per square inch

psia pounds per square inch absolute

PVT Pressure Volume Temperature

RB/stb Reservoir Barrels per stock tank barrel

RF Recovery Factor

RFT Repeat Formation Tester

RT Real Terms

SG Specific Gravity

SMT

Kingdom

a PC-based interpretation workstation

SPE Society of Petroleum Engineers

sq km square kilometres

ss subsea

stb

STOIIP Stock Tank Oil Initially In Place

Sw water Saturation

Swavg average water Saturation

TD Total Depth

TVD true vertical depth

TVDSS true vertical depth subsea

Liberator Area CPR


Appendix A - Summary of 2007 SPE Petroleum Resources

Classification

The following table has paragraphs that are quoted from the 2007 SPE PRMS Guidance Notes and

summarise the key resources categories, while Figure B-1 shows the recommended resources classification

framework.

Class/Sub-class Definition

Reserves

Reserves are those quantities of petroleum anticipated to be

commercially recoverable by application of development projects to

known accumulations from a given date forward under defined

conditions.

On Production The development project is currently producing and selling petroleum to

market.

Approved for Development

All necessary approvals have been obtained, capital funds have been

committed, and implementation of the development project is under

way.

Justified for Development

Implementation of the development project is justified on the basis of

reasonable forecast commercial conditions at the time of reporting, and

there are reasonable expectations that all necessary approvals/contracts

will be obtained.

Contingent Resources

Those quantities of petroleum estimated, as of a given date, to be

potentially recoverable from known accumulations by application of

development projects, but which are not currently considered to be

commercially recoverable due to one or more contingencies.

Development Pending A discovered accumulation where project activities are ongoing to justify

commercial development in the foreseeable future.

Development Unclarified or on Hold

A discovered accumulation where project activities are on hold and/or

where justification as a commercial development may be subject to

significant delay.

Development Not Viable

A discovered accumulation for which there are no current plans to

develop or to acquire additional data at the time due to limited

production potential.

Prospective Resources Those quantities of petroleum which are estimated, as of a given date, to

be potentially recoverable from undiscovered accumulations.

Prospect A project associated with a potential accumulation that is sufficiently well

defined to represent a viable drilling target.

Table A-1 Summary of 2007 SPE Petroleum Resources Classification

Liberator Area CPR


SPE CLASSIFICATION SYSTEM (April 2007)

TO

TA

L P

ET

RO

LE

UM

INIT

IAL

LY

IN P

LA

CE

DIS

CO

VE

RE

D P

ET

RO

LE

UM

– IN

ITIA

LL

Y IN

PL

AC

E

CO

MM

ER

CIA

L

PRODUCTION

INC

RE

AS

ING

CH

AN

CE

OF

CO

MM

ER

CIA

LIT

Y →

RESERVES

Proved (1P)

Proved + Probable (2P)

Proved + Probable + Possible (3P)

SU

B-C

OM

ME

RC

IAL

CONTIGENT RESOURCES

Low Estimate (1C)

Best Estimate (2C) High Estimate (3C)

UNRECOVERABLE

UN

DIC

OV

ER

ED

PE

TR

OL

EU

M –

INIT

IAL

LY

IN P

LA

CE

PROSPECTIVE RESOURCES

Low Estimate Best Estimate High Estimate

UNRECOVERABLE

← RANGE OF UNCERTAINTY →

Figure A-1 SPE PRMS Petroleum Resources Classification Framework

Liberator Area CPR


Appendix B – Technical Production Profiles

Table B-1 Low Case

Oil Rate Water Rate Gas Rate Oil Rate Water Rate Gas Rate Oil Rate Water Rate Gas Rate

MMbl/year MMbl/year bcf/year MMbl/year MMbl/year bcf/year MMbl/year MMbl/year bcf/year

2019 0.81 2.64 0.32 0.81 2.64 0.32 0.00 0.00 0.00

2020 1.48 4.33 0.92 0.23 2.50 0.15 1.26 1.83 0.77

2021 0.43 4.11 0.40 0.10 2.05 0.14 0.32 2.06 0.25

2022 0.27 3.35 0.29 0.07 1.68 0.11 0.20 1.67 0.18

2023 0.21 2.83 0.23 0.05 1.42 0.09 0.16 1.41 0.14

2024 0.17 2.44 0.21 0.05 1.22 0.08 0.12 1.22 0.13

2025 0.14 2.12 0.18 0.04 1.05 0.07 0.10 1.07 0.11

2026 0.11 1.85 0.16 0.03 0.91 0.06 0.08 0.94 0.10

2027 0.10 1.60 0.14 0.03 0.79 0.05 0.07 0.82 0.09

2028 0.08 1.41 0.13 0.03 0.69 0.05 0.06 0.72 0.08

2029 0.07 1.22 0.11 0.02 0.60 0.04 0.05 0.62 0.07

2030 0.06 1.08 0.11 0.02 0.52 0.04 0.04 0.55 0.07

2031 0.05 0.93 0.09 0.02 0.46 0.04 0.04 0.48 0.05

2032 0.05 0.83 0.08 0.01 0.40 0.03 0.04 0.43 0.05

2033 0.04 0.72 0.07 0.01 0.35 0.02 0.03 0.38 0.04

2034 0.04 0.64 0.06 0.01 0.30 0.02 0.03 0.33 0.04

2035 0.04 0.56 0.06 0.01 0.27 0.02 0.03 0.30 0.04

2036 0.04 0.49 0.05 0.01 0.24 0.02 0.03 0.26 0.03

2037 0.03 0.43 0.04 0.01 0.20 0.02 0.02 0.22 0.03

2038 0.03 0.38 0.04 0.01 0.18 0.01 0.02 0.20 0.03

2039 0.03 0.34 0.04 0.01 0.15 0.01 0.02 0.19 0.02

2040 0.03 0.28 0.03 0.01 0.13 0.01 0.02 0.15 0.02

Cum 4.33 34.58 3.74 1.60 18.73 1.42 2.73 15.85 2.32

Field Well -- PL1-5 Well -- PL2-2

Liberator Area CPR


Table B-2 Mid Case



2019 2.29 1.51 0.77 2.29 1.51 0.77 0.00 0.00 0.00

2020 3.21 3.08 1.10 0.80 2.35 0.28 2.41 0.74 0.82

2021 1.39 4.89 0.81 0.53 2.61 0.35 0.86 2.28 0.47

2022 0.88 4.74 0.66 0.33 2.46 0.30 0.55 2.28 0.36

2023 0.64 4.06 0.50 0.25 2.09 0.23 0.39 1.97 0.27

2024 0.51 3.59 0.43 0.21 1.85 0.21 0.30 1.74 0.22

2025 0.42 3.22 0.38 0.18 1.66 0.19 0.24 1.56 0.19

2026 0.35 2.92 0.35 0.15 1.51 0.17 0.20 1.42 0.17

2027 0.30 2.63 0.31 0.13 1.36 0.16 0.16 1.28 0.15

2028 0.26 2.38 0.27 0.12 1.22 0.14 0.14 1.16 0.13

2029 0.24 2.18 0.25 0.11 1.12 0.13 0.13 1.06 0.12

2030 0.21 2.00 0.23 0.10 1.03 0.12 0.12 0.97 0.11

2031 0.19 1.83 0.21 0.09 0.94 0.11 0.10 0.88 0.10

2032 0.18 1.68 0.19 0.08 0.87 0.10 0.09 0.81 0.09

2033 0.16 1.53 0.17 0.08 0.79 0.09 0.08 0.74 0.08

2034 0.14 1.40 0.16 0.07 0.72 0.09 0.07 0.68 0.08

2035 0.13 1.28 0.15 0.06 0.66 0.08 0.07 0.62 0.07

2036 0.12 1.18 0.13 0.06 0.61 0.07 0.06 0.57 0.06

2037 0.11 1.07 0.12 0.05 0.56 0.07 0.06 0.52 0.06

2038 0.11 0.98 0.11 0.05 0.51 0.06 0.06 0.47 0.05

2039 0.10 0.90 0.10 0.05 0.47 0.05 0.05 0.43 0.05

2040 0.09 0.83 0.10 0.04 0.43 0.05 0.05 0.39 0.04

Cum 12.02 49.88 7.51 5.82 27.33 3.82 6.20 22.55 3.68


Liberator Area CPR


Table 15-3 High Case



2019 2.97 0.77 0.99 2.97 0.77 0.99 0.00 0.00 0.00

2020 4.31 1.98 1.42 1.37 1.78 0.45 2.94 0.21 0.96

2021 2.68 3.60 0.94 1.22 1.92 0.42 1.46 1.68 0.52

2022 1.83 4.30 0.80 0.94 2.12 0.38 0.89 2.18 0.43

2023 1.25 4.52 0.79 0.62 2.30 0.42 0.63 2.22 0.37

2024 0.95 4.24 0.72 0.48 2.22 0.39 0.48 2.02 0.33

2025 0.74 3.79 0.64 0.38 2.00 0.36 0.36 1.79 0.28

2026 0.59 3.40 0.57 0.30 1.79 0.32 0.29 1.60 0.24

2027 0.48 3.09 0.52 0.25 1.63 0.30 0.24 1.45 0.22

2028 0.41 2.81 0.47 0.21 1.49 0.27 0.20 1.32 0.20

2029 0.36 2.53 0.43 0.19 1.35 0.26 0.17 1.18 0.18

2030 0.30 2.31 0.39 0.16 1.22 0.23 0.14 1.08 0.16

2031 0.26 2.12 0.36 0.14 1.12 0.21 0.12 0.99 0.15

2032 0.23 1.94 0.33 0.12 1.04 0.20 0.11 0.90 0.14

2033 0.21 1.76 0.30 0.10 0.95 0.18 0.11 0.81 0.12

2034 0.19 1.60 0.28 0.09 0.87 0.16 0.10 0.74 0.11

2035 0.17 1.46 0.25 0.08 0.79 0.15 0.09 0.67 0.10

2036 0.16 1.32 0.23 0.08 0.72 0.13 0.08 0.60 0.10

2037 0.14 1.20 0.21 0.07 0.65 0.12 0.07 0.54 0.09

2038 0.12 1.08 0.19 0.06 0.59 0.11 0.06 0.49 0.08

2039 0.11 0.97 0.17 0.05 0.53 0.10 0.05 0.44 0.07

2040 0.10 0.88 0.16 0.05 0.48 0.09 0.05 0.40 0.07

Cum 18.56 51.67 11.17 9.94 28.34 6.25 8.62 23.33 4.92


Liberator Area CPR


Appendix C – Undiscounted Pre-Tax Cashflows

LP1 LP1 and LP2

Year 1P 2P 3P 1P 2P 3P

2018 -42.9 -42.9 -42.9 -42.9 -42.9 -42.9

2019 40.5 117.3 152.3 -18.8 57.9 93.0

2020 12.5 47.9 83.2 93.1 198.0 266.2

2021 5.5 34.3 80.0 28.3 93.3 178.3

2022 3.9 17.5 50.8 14.7 49.5 107.8

2023 3.2 13.8 34.8 11.8 36.4 74.6

2024 2.9 11.6 26.8 9.8 28.7 56.4

2025 2.4 10.0 21.6 7.8 23.5 43.6

2026 1.9 8.2 16.5 6.2 19.3 33.5

2027 1.6 6.7 13.1 5.1 15.5 26.7

2028 1.3 5.6 10.7 4.2 12.8 21.7

2029 1.1 4.7 9.2 3.4 10.9 18.0

2030 0.9 3.9 7.0 2.8 9.0 14.0

Table C-1 Undiscounted annual pre-tax cashflow

LP1 LP1 and LP2

Year 1P 2P 3P 1P 2P 3P

2018 -42.9 -42.9 -42.9 -42.9 -42.9 -42.9

2019 -2.4 74.4 109.4 -61.7 15.0 50.1

2020 10.2 122.2 192.6 31.4 213.1 316.3

2021 15.7 156.5 272.7 59.7 306.4 494.6

2022 19.6 174.0 323.5 74.4 355.8 602.4

2023 22.7 187.8 358.3 86.2 392.3 677.0

2024 25.6 199.5 385.2 95.9 420.9 733.4

2025 28.0 209.4 406.8 103.7 444.5 777.0

2026 29.9 217.6 423.3 109.9 463.7 810.5

2027 31.4 224.3 436.4 115.0 479.2 837.3

2028 32.8 229.9 447.2 119.2 492.0 859.0

2029 33.9 234.6 456.3 122.6 502.9 877.0

2030 34.8 238.5 463.3 125.4 511.9 891.0

Table C-2 Undiscounted cumulative cashflow

north sea, liberator field phase 1 - i3 energy · north sea, liberator field phase 1 competent...

Documents