North Sea, Liberator Field â Phase 2 - i3 Energy

North Sea, Liberator Field – Phase 2 Competent Person’s Report 2017 i3 Energy

Liz Chellingsworth, Keith Milne, Jackie Mullinor, Jill Prabucki November 2017

Registered office: AGR TRACS International Limited Union Plaza, 1 Union Wynd, Aberdeen AB10 1SL +44 1224 629000 [email protected] Ver 1.0 March 2015

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:

01

Prepared by:

Project Manager

Jill Prabucki

Reviewer

Mike Wynne

Authorised for release by

Mike Wynne

Approved by:

Liberator Area CPR

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. 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”).

AGR TRACS International Limited

i

November 2017: rev1.0

Liberator Area CPR

Executive Summary i3 Energy (i3) have commissioned a Competent Persons Report (CPR) to assess the resource potential of the Liberator Field Extension in accordance with resource definitions presented in the SPE’s Petroleum Resources Management System (“SPE-PRMS” Appendix A). This CPR concerns the Phase 2 Area of the Liberator, northwest of the discovery well 13/23d-81.

Location map showing Phase 2 Area

The Liberator structure is located approximately 120 km northeast of Aberdeen, west of Blake Field and north of Ross Field. The Phase 2 area is currently un-licenced; i3 Energy are applying for Block 13/23c in the 30th Offshore Licensing Round. The Liberator discovery well 13/23d-8 was drilled in 2013, and encountered a 24 foot hydrocarbon column, 4 feet of gas and 20 feet of oil, in Early Cretaceous Captain Sands. Reservoir and fluid properties are analogous to those found in Blake Field, with a very high net to gross and excellent reservoir quality. The Captain sands were deposited in NW-SE trending submarine channels and the sands extend northwestward into 13/23c (the Phase 2 area). The objective of the Phase 2 CPR assessment was to determine how far away from the discovery well the well results could be confidently extrapolated north-westwards, in order to justify classification of resources as discovered. Because the area is un-licenced, resources cannot be classified as Reserves. In order to assess whether or not resources are discovered two aspects were evaluated in detail, these are the potential for hydrocarbon column continuity across the saddle west of the discovery well, and continuity of the sands across that saddle and along the structure. For the purposes of this evaluation the Phase 2 area has been divided into two regions based on proximity to the discovery well, as well as change in seismic character and structural trend:

1

AGR has also provided i3 with a CPR for the Phase 1 Area of Liberator, which includes the discovery well; the assessments have been carried out in parallel and are fully consistent. AGR TRACS International Limited

ii


Liberator Area CPR



Phase 2 East immediately to the NW of Liberator Phase 1, and



Phase 2 West, in the region of 23a-4.

Phase 2 regions

Based on the initial review of data the following key uncertainties, i.e. those that have a significant impact on volumetric estimates or are relevant in determining the probability of success, commercial and/or geological, were identified, including: 

Depth uncertainty on a low relief structure with sparse well control (distance between key wells defining Liberator greater than 5 km)



Size and continuity of channel sands



Fluid distribution - Presence and size of gas caps



Fluid distribution – Depth of oil water contact



Aquifer strength and connectivity



Acquisition of Block 13/23c Licence

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 and reference cases. The porosity and NTG of the sands themselves are thought to have a relatively narrow range based on properties of the exploration wells and other fields with Captain sands. The same applies for the saturations. The permeability of the sands is known from the Blake Field and is expected to be moderately high at this reservoir depth and is not considered a key development uncertainty Three deterministic cases representative of a P90 to P10 range, were established combining a range of values for those parameters with the greatest impact. The resulting in-place volumes are summarised below.


iii


Liberator Area CPR

Phase 2 East

Phase 2 West

STOIIP MMstb

GIIP Solution gas Bscf

GIIP Free gas Bscf

STOIIP MMstb

GIIP Solution gas Bscf

GIIP Free gas Bscf

Low

4.3

1.5

0.1

26

9

0.7

Mid

64

22

1.7

135

46

3.6

103

35

0

329

112

0

Case

High

Low, Mid and High case In-Place Volumes

Given the uncertainty associated with volumes in the Phase 2 area, its commercial status, and with no development selected, only a high level assessment of recovery factors was undertaken based on observations and findings from Blake Field and the results of the Phase 1 Area CPR assessment. Basic reservoir and fluid parameters were assumed to be the same for the Phase 2 area as for the Phase 1 area (Ref. 1). Phase 1 area expected recovery factors for Liberator are significantly lower than the range established for Blake Field based on production data. This is attributable primarily to hydrocarbon column thickness; a thin hydrocarbon column, high vertical permeability and thick high quality sand below the oil column, results in cusping of water and reduced sweep despite optimum well placement and low drawdown. The recovery factor range for Phase 2 area accounts for the uncertainties including variation in hydrocarbon column thickness, and sand continuity and extent (impacting aquifer size). Generally, the average column height increases north-westward. The recovery factor range presented below, has been used in estimating recoverable resource volumes:

Case

RF (%)

Scenario

Low

20

Similar to Liberator Phase 1 Low Case

Mid

35

Average of Low and High Cases

High

50

Blake type recovery factor

Summary of Recovery Factors

Scale of development may also impact recoveries; the recovery factor range accounts for a variety of development concepts. A stand-alone development may be justified if a large enough in-place volume can be confirmed. Higher end recovery factors would most likely require water injection and gas lift. The simplest concept would be an extension of the Phase 1 Area development, i.e. further tie-backs to the Blake manifold or Phase 1 area wells. Feasibility of such a concept has not been reviewed. Phase 2 East is closer to the Liberator discovery well and the sands are likely to be part of the main sand channel fairway based on seismic interpretation. Taking into account depth uncertainty the hydrocarbon column is likely to be continuous across the saddle between Phase 2 East and the discovery well. The Low case considers separate oil columns, with a small four-way dip closure trapping oil in Phase 2 East. Phase 2 East volumes are considered Discovered and are classified as Contingent Resources, Development Unclarified. Overall Chance of Commercial Success (COSc) is estimated to be 63% for the contingent resources based on the following: 

A 90% chance of licence award required for appraisal and development



70% chance of finding a sufficiently large enough volume to develop (STOIIP). It has been assumed that the Low case would not be economically viable, although this has not been rigorously tested.


iv


Liberator Area CPR

Contingent resources are summarised in the table below.

Case

STOIIP MMSTB

RF %

Recoverable MMSTB

Associated Gas Bscf

Low

4

20

1

0

Mid

64

35

22

8

High

103

50

52

18

COSc

63%

Resource Summary Table for Contingent Resources, Phase 2 East

In Phase 2 West the sand observed in exploration well 23a-4 may not be the same sand that was encountered in 23d-8. The sand may not lie on the continuation of the Liberator fairway and/or it may be sourced from a different location. No hydrocarbons were encountered within the Captain interval in 23a-4. On this basis resources are classified as Prospective. For Prospective Resources the overall chance of commercial success considers the technical risk, in addition to any commercial risk. The Chance of Geological Success (COSg) is assessed as follows: 

Charge – 100%



Trap – 75%



Top Seal – 100%



Reservoir Presence (and Effectiveness) – 75%



Total COSg is 56.3%

The chance of a commercial project is 90% and is reliant on obtaining the licence for the Phase 2 area. Inplace volumes are considered to be sufficiently large, so that if geologically successful a commercial development would be viable. For Phase 2 West an overall Chance of Commercial Success of 51% has been estimated. Prospective resources are summarised in the table below.

STOIIP MMstb

RF

Recoverable Oil MMstb

Associated Gas Bscf

Low

26

20%

5

2

Mid

135

35%

47

16

High

329

50%

165

56

Chance of Commerciality

51%

Resource Summary Table for Prospective Resources, Phase 2 West


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Liberator Area CPR

Contents Qualification ............................................................................................................................. i Executive Summary .................................................................................................................. ii 1

2

3

4

5

6

Introduction ....................................................................................................................... 1 1.1

Overview ................................................................................................................ 1

1.2

Licence history and current status .............................................................................. 2

1.3

Future Activity ......................................................................................................... 3

1.4

Data availability ....................................................................................................... 3

1.5

Key uncertainties ..................................................................................................... 3

Geology Overview ............................................................................................................... 4 2.1

Introduction ............................................................................................................ 4

2.1

Well Correlation ....................................................................................................... 4

2.2

Reservoir Geology .................................................................................................... 5

Geophysical evaluation ........................................................................................................ 6 3.1

Analysis .................................................................................................................. 6

3.1.1

Interpretation .......................................................................................................... 6

3.1.2

Depth conversion ..................................................................................................... 9

3.1.3

Amplitude analysis ................................................................................................. 13

Petrophysical evaluation..................................................................................................... 14 4.1

Data Availability and Quality ................................................................................... 14

4.2

Petrophysical Interpretation .................................................................................... 14

4.3

Saturation vs Height Function .................................................................................. 15

Static Modelling ................................................................................................................ 17 5.1

Key Uncertainties ................................................................................................... 17

5.2

Reservoir Distribution ............................................................................................. 17

5.3

Fluid Distribution ................................................................................................... 18

5.4

Input Data ............................................................................................................ 19

5.5

3D Model .............................................................................................................. 19

In-Place Volumes .............................................................................................................. 20 6.1

7

8

9

STOIIP evaluation .................................................................................................. 20

Reservoir Engineering ........................................................................................................ 21 7.1

Data Review .......................................................................................................... 21

7.2

Evaluation............................................................................................................. 21

7.3

Recovery Factors ................................................................................................... 22

Exploration, Appraisal and Development Plans ...................................................................... 24 8.1

Overview .............................................................................................................. 24

8.2

Development Options ............................................................................................. 24

Resource Estimation .......................................................................................................... 25 9.1

Classification ......................................................................................................... 25

9.2

Contingent Resources - Phase 2 East ........................................................................ 25

9.3

Prospective Resources - Phase 2 West ...................................................................... 25

10 References ....................................................................................................................... 27


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Liberator Area CPR

11 Glossary of Terms ............................................................................................................. 28 Appendix A - Summary of 2007 SPE Petroleum Resources Classification ........................................ 29


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Liberator Area CPR

Figures Figure 1-1 Liberator Field location map ....................................................................................... 1 Figure 1-2 Phase 2 regions ........................................................................................................ 2 Figure 2-1 Depth Map: top Captain sand ..................................................................................... 4 Figure 2-2 NW-SE well correlation panel including Liberator well .................................................... 5 Figure 3-1 Seismic data coverage (supplied by i3 Energy) ............................................................. 6 Figure 3-2 Seismic line from 23a-4 (Phase 2) to 23d-8 (Phase 1) ................................................... 7 Figure 3-3 Seismic line from Phase 2 East to 23d-8 (Phase 1) ........................................................ 7 Figure 3-4 Seismic line across topographic high ........................................................................... 8 Figure 3-5 Seismic line through 23a-4 ........................................................................................ 8 Figure 3-6 Depth map K50 sequence boundary ............................................................................ 9 Figure 3-7 Effect of including the shallow channel as a layer in the depth conversion on the Target 1 area............................................................................................................................... 10 Figure 3-8 Seismic line showing small erosional features at base Chalk/top Tor.............................. 11 Figure 3-9 Phase 2 East: vertical closure map with spot values .................................................... 12 Figure 3-10 NTG map used to derive top Captain sand depth map ................................................ 12 Figure 3-11 Amplitude response at 23a-4 and 23d-8 .................................................................. 13 Figure 4-1 CPI for 13/23-4 and 13/23d-8 .................................................................................. 14 Figure 4-2 Saturation-Height functions based on pre-production Blake analogues and on Liberator well ..................................................................................................................................... 16 Figure 5-1 Map of Phase 2 area with sand polygons .................................................................... 18 Figure 5-2 Cross section from NW to SE showing fluid contacts .................................................... 18 Figure 7-1 Relative permeability curves for Low, Mid and High cases ............................................ 22

Tables Table 4-1 Thicknesses in 23a-4 and 23d-8 ................................................................................ 15 Table 4-2 Key rock properties in 23a-4 and 23d-8 ...................................................................... 15 Table 6-1 Case Summary Phase 2 Area ..................................................................................... 20 Table 6-2 Low, Mid and High case In-Place Volumes ................................................................... 20 Table 7-1 Liberator oil properties and initial conditions ................................................................ 21 Table 7-2 Recovery factors summary ........................................................................................ 22 Table 9-1 Resource estimate for Phase 2 East ............................................................................ 25 Table 9-2 Prospective resource summary .................................................................................. 26


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Liberator Area CPR

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 Extension in accordance with resource 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. The field extension, which is the subject of the current CPR, is located in the neighbouring UKCS Block 13/23c and is designated as “Phase 2” area, see Figure 1-1. This area is currently un-licenced, but i3 Energy are applying for Block 13/23c in the 30th Offshore Licensing Round.

Figure 1-1 Liberator Field location map

The Liberator Field was discovered in 2013 by exploration well 13/23d-8, which found a 24 foot hydrocarbon column in Early Cretaceous Captain Sands. A thick sand was encountered (over 300 feet) with a very high net to gross and excellent reservoir quality. The Captain sands were deposited in NW-SE trending submarine channels and the sands extend north-westward into 13/23c and the Phase 2 area. In well 13/23a-4 in the west (down-dip) the Captain sands are wet and capped by a thick shale. To the SW the sands pinch out and are completely absent in 13/23-1. The dimensions of individual sand channels (width, length, thickness) are uncertain and it is possible that the sand encountered in 23a-4 is a different sand to the one observed in Liberator Phase 1. It is clear that


1


Liberator Area CPR

away from wells there is uncertainty surrounding the continuity of sand bodies and the net-to-gross distribution. The focus of the Phase 2 CPR assessment was to determine how far away from the discovery well the well results could be confidently extrapolated north-westwards, in order to justify classification of resources as discovered; i.e. whether resources are contingent or prospective. Two aspects were evaluated in detail, these are the potential for hydrocarbon column continuity across the saddle west of the discovery well, and continuity of the sands across that saddle and along the structure. For the purposes of this evaluation the Phase 2 area has been split into two regions, see Figure 1-2: 1. Phase 2 East lies immediately to the NW of Liberator Phase 1 2. Phase 2 West is the region around 23a-4

Figure 1-2 Phase 2 regions

This CPR deals with Phase 2. A CPR assessment of the Phase 1 Area, has also been undertaken by AGR. The assessment of both areas have been carried out in parallel, and findings presented in the CPRs are fully consistent (Ref. 1).

1.2 Licence history and current status Phase 2 Area is currently unlicenced in UKCS Block 13/23c. i3 Energy are applying for Block 13/23c in the 30th Offshore Licensing Round with the bid deadline closing November 21st 2017. Awards are expected to be announced Q2 2018. i3 Energy hold a 100% interest in the P.1987 licence, Block 13/23d, encompassing the Liberator discovery well 13/23d-8 and most of the Liberator Field and Phase 1 development area. Development of the Phase 1 area is in late Define stage and comprises a 2 well development tied back to the Blake manifold.


2


Liberator Area CPR

1.3 Future Activity Dependent on success of the 30th round bid, i.e. award of a Block 12/23c licence, i3 are considering a step out appraisal well in late 2018 /early 2019. Further exploration or appraisal well activities will be dependent on results of the step out appraisal and results of ongoing evaluation of the Phase 2 area.

1.4 Data availability The ‘Phase 2 Area’ CPR assessment was carried out as an integral part of broader Liberator evaluation, i.e. Phases 1 and 2 areas. As such data provided for Phase 1 also formed the basis for this evaluation. Relevant data included: 

Seismic data and interpretation extending over Phase 1 and Phase 2 areas, and Blake Field



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



Static and dynamic models extending over the Phase 2 area and including all input files

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 The assessment workflow is devised to ensure that the resulting ranges of volumes, in-place and recoverable are representative of P10 to P90 outcomes. During the review of data those parameters which carry the greatest uncertainty and can have a significant impact on the volumetric estimates are identified and assessed in further detail. They are either considered within the range of input parameter values selected for volumetric estimation or identified as potential risks which are relevant in determining the probability of success, commercial and or geological. Key uncertainties identified for this area are listed below Subsurface: 

Depth uncertainty on a low relief structure with sparse well control (distance between key wells defining Liberator greater than 5 km).



Size and continuity of channel sands



Fluid distribution - Presence and size of gas caps



Fluid distribution – Depth of oil water contact



Aquifer strength and connectivity

Commercial: •

Acquisition of Block 13/23c Licence

Input assumptions and assessment of probabilities of success are documented in further detail in subsequent chapters.


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Liberator Area CPR

2 Geology Overview 2.1 Introduction The Liberator discovery lies 2km west of the northern part of the Blake Field. Exploration wells and some of the Blake Field development wells have been considered. The depth map to top Captain Sand (as supplied by i3 Energy) is shown in Figure 2-1 with the Phase 2 East and West polygons shown in red dashed outline.

license boundary

Depth (ft TVDss)

Top Captain Sand (as supplied) C.I. = 25ft

Figure 2-1 Depth Map: top Captain sand

2.1 Well Correlation A correlation panel across Phase 2, Phase 1 and Blake is shown in Figure 2-2. The top Rodby and top Valhall can be correlated confidently (Figure 2-2). The top reservoir sand is 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). The top sand is generally considered to coincide with the K50 sequence boundary, although it is not known how much biostratigraphic data has been used to draw this conclusion. In well 13/23a-4 the top sand reservoir is overlain by about 350ft of shale, but the K50 occurs 100ft shallower than top sand. West of the Liberator accumulation in well 13/23-1, there is no sand, only approximately 150ft of basinal shale. 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.


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Liberator Area CPR

Figure 2-2 NW-SE well correlation panel including Liberator well

2.2 Reservoir Geology The sediments are of Lower Cretaceous age. At various times within the Aptian, thick sandstone units were developed along the margin of the Halibut High. These form the Captain Field, the Blake Field and further SE, the Cromarty Field. The bulk of the sandstones in the area, including Liberator, are well sorted, clean with high porosity (0.28) and permeability (2 Darcy). In the lower half of the reservoir, thin interbeds of shale and cement occur in some wells, but the NTG is still very high. In general, the sands are thought to have been deposited in submarine channels predominantly running NW-SE, parallel to the edge of the Halibut High. In the Liberator Phase 1 and Phase 2 area, the western and southwestern margins of the channel system have been interpreted where there is a marked thinning in the K50 to Valhall isochore. This pinch out is consistent with the absence of reservoir in well 13/23-1. The sands observed in 23d-8 can be assumed to extend in a NW direction into the Phase 2 East area. However, there is uncertainty as to the width of individual sand channels and their thickness. In the Phase 2 West area, it is not clear if the sand seen in the 23/13a-4 well is the same as seen in the Liberator area. It may be a sand lobe with a different orientation to the main NW-SE trend. It cannot, therefore, be assumed that the entire Phase 2 area, some 3km by 8km, is composed of a single sand reservoir with the same OWC. A series of polygons has been used to subdivide the Phase 2 area for calculating in-place volumes. These polygons are based on: 

areas with a higher confidence in seismic facies



areas of thicker isochore which are more likely to contain sand reservoir

Examples of the potential complexity of this type of reservoir have been documented in the Captain Field: the lower sand fills a channel in a background of shale. This geometry was only recognised after extensive drilling across the entire field and its margins.

Trapping Mechanism In the Phase 2 area, the K50 seismic event dips gently towards the north and NE, providing a dip closure. To the southwest, the closure is stratigraphic pinch-out.


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Liberator Area CPR

3 Geophysical evaluation 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 and part of Phase 2, whereas the Q13Ph1 survey covers only Phase 2, as illustrated in Figure 3-1.

Q13Ph1

MF10

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

3.1 Analysis The objectives of the Phase 2 geophysical evaluation were as follows: 

review seismic interpretation over the Phase 2 area



assess depth uncertainty over the Phase 2 area



review seismic amplitudes as potential indicators of free gas over the Phase 2 area

3.1.1 Interpretation AGR reviewed the supplied horizon interpretation. No faults have been picked/mapped. The K50 sequence boundary is picked on a positive event; note that reflector continuity is not as clear as over the Phase 1 area with an increased number of mis-picks between the Line/Trace interpretation. Overall the K50 time horizon is robust but variations in interpretation are possible especially where the structure is flat. The K50 sequence boundary represents a timeline, not a lithological boundary. In well 23d-8 the top of the K50 sequence corresponds to the top of the Captain sand, whereas in well 23a-4 it corresponds to the top of a thick (103ft) shale which overlies a thick (213ft) water-bearing sand, see Figure 2-2. An overview seismic line is shown in Figure 3-2. The seismic interpretation is discussed separately for Phase 2 East and Phase 2 West, see below.


6


Liberator Area CPR

NW

SE 23d-8

Time (s TWT)

23a-4

1000m

Q13PH1 PROCMIG

MF10

__ i3_top Mackerel __ i3_top Hidra __ i3_top Rodby __ i3_K50 seq bd (timeline) __ i3_intra-Captain shale __ i3_top Valhall (v1) __ i3_top Valhall (v2)

Figure 3-2 Seismic line from 23a-4 (Phase 2) to 23d-8 (Phase 1)

Phase 2 East Two sample lines are shown in Figure 3-3 and Figure 3-4. In this region the structure is relatively flat and subtle, see above comment about mis-picks. Overall, the structure is not as defined as it is in Liberator (Phase 1). A topographic high is present about 3km to the NW of Liberator Phase 1; in the time domain it is not as distinct as the Liberator Phase 1 structure. It may be affected by velocity effects related to the shallow channel that runs north-south between 23a-4 and Phase 1. The difference in seismic character could indicate a change in incision/deposition and/or sand content in the Phase 2 East area. NW

SE

Time (s TWT)

23d-8

Phase 2

1000m

Phase 1

MF10 Raw Stack

__ i3_top Hidra __ i3_top Rodby __ i3_K50 seq bd (timeline) __ i3_top Valhall

location map

Figure 3-3 Seismic line from Phase 2 East to 23d-8 (Phase 1)


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Liberator Area CPR

SW

Time (s TWT)

NE

Phase 2

1000m

MF10 Raw Stack

__ i3_top Mackerel __ i3_top Hidra __ i3_top Rodby __ i3_K50 seq bd (timeline) __ i3_top Valhall

location map

Figure 3-4 Seismic line across topographic high

Phase 2 West In 23a-4 the K50 sequence boundary corresponds to a shale. AGR mapped a peak event corresponding to the top of the sand in 23a-4 well, see Figure 3-5. It is laterally restricted and may be sourced from another direction – see inset map. The ‘extra loop’ does not extend into the Phase 2 East area or beyond and it is, therefore, interpreted as not being connected to the same sand seen in Phase 1. SW

SE 23a-4

Time (s TWT)

extra loop corresponds to top sand in 23a-4

Q13PH1 PROCMIG

1000m

location map

__ i3_top Mackerel __ i3_top Hidra __ i3_top Rodby __ i3_K50 seq bd (timeline) __ AGR_top sand 23a-4 __ i3_intra-Captain shale __ i3_top Valhall (v1) __ i3_top Valhall (v2)

Figure 3-5 Seismic line through 23a-4


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Liberator Area CPR

3.1.2 Depth conversion The depth conversion methodology adopted by i3 Energy was reviewed as part of the Phase 1 CPR. It is a layer-based model incorporating 10 layers using constant interval velocities derived from 23d-8 and additionally 23-1 for the fill within a shallow channel present over the Phase 2 area. The resulting depth map is shown in Figure 3-6.

23a-4

Depth (ft TVDss)

license boundary

1000m

Phase 1

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

Figure 3-6 Depth map K50 sequence boundary

The depth conversion methodology relies heavily on well 23d-8 but it might be more appropriate to adopt a Phase 2-centric approach given the complexities in the region. Away from wells depth uncertainty remains. The total depth uncertainty in the Phase 2 area is assumed to be ±50ft at 2km 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. As mentioned previously, mispicks between Line/Trace interpretation are evident. Depth conversion uncertainty. The layer-based model provides a good match at the wells in Blake with only small residuals at the various layers. However, there are features present in the Phase 2 area that complicate the layer-based model away from well control. 

A shallow channel runs north-south between 23a-4 and Phase 1. The velocity of the channel fill is derived from 23-1, which may not be representative for the whole channel. It is possible that the velocity effects have been overcompensated. The effect of incorporating the shallow channel into the depth conversion methodology is shown in Figure 3-7. In the Target 1 area of Phase 2 East, the map is raised by 40-60ft in the depth domain which seems quite large given the subtlety of the structure in the time domain and the dissimilarities between it and the Phase 1 structure. Further well control and/or seismic velocity analysis would help to calibrate the velocity of the channel fill.



Small erosional features are present at base Chalk/top Tor, see Figure 3-8. 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. The channels are widespread and occur in some key places, e.g. the saddle between Phase 1 and Phase 2. While these may seem like innocuous events, flexing the


9


Liberator Area CPR

surface away from the wells by even a small amount can have a significant impact on size and connectivity of an accumulation (Figure 3-9).

5,240

5,180

Map raised by 4060ft in Target 1 area

5,240

5,200 5,160

5,200

Top K50 depth map WITHOUT correction for shallow channel (C.I.= 20ft); three spot depths marked (ft TVDss)

Top K50 depth map WITH correction for shallow channel (C.I.= 20ft); three spot depths marked (ft TVDss)

---- edge of shallow channel license boundary

Target 1 area

Depth (ft TVDss)

1000m

approximate location Target 1 area

Phase 2 East

Phase 1

context map

Top K50 depth map HAC contours based on OWC 5,270ft TVDss (C.I.= 10ft)

Figure 3-7 Effect of including the shallow channel as a layer in the depth conversion on the Target 1 area


10


Liberator Area CPR

NW

SE

Time (s TWT)

23d-8

Phase 2

Phase 1

Time thickness (s)

MF10 Raw Stack

1000m

__ i3_top Chalk __ i3_top Tor __ i3_top Mackerel __ i3_top Hidra __ i3_top Rodby __ i3_K50 seq bd (timeline)

Phase 2

Phase 1

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

Figure 3-8 Seismic line showing small erosional features at base Chalk/top Tor


11


Liberator Area CPR

Thickness (ft)

license boundary

1000m

+6ft -27ft +33ft +12ft

-17ft

Height above contact map based on OWC at 5,270ft TVDss and K50 structure map HAC contours (C.I.= 5ft)

Figure 3-9 Phase 2 East: vertical closure map with spot values (Blue = below OWC; green = above OWC)

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 3-10. This is a simple, practical approach based on the limited well data available but may give spurious results, for instance if a channel sand stops abruptly (e.g. by erosion), additional sands suddenly appear or if a heterolithic interval develops at the top of the channel sand. NTG (fraction)

NTG set to 1 within all of Phase 2 East (and Phase 1)

Figure 3-10 NTG map used to derive top Captain sand depth map


12


Liberator Area CPR

In summary, there are three independent sources for depth uncertainty and the combination of a deeper structure (e.g. from depth conversion error within the shallow channel polygon) with a deeper top sand (e.g. from appearance of shaley layer at the top of the sand) could be sufficient to push the saddle between Phase 1 and Phase 2 East below the OWC observed in the Liberator discovery well (this is considered as a Low case, Section 5.5).

3.1.3 Amplitude analysis The amplitude analysis is discussed in the Phase 1 CPR and the conclusion from the analysis was that a gas column greater than 10ft is expected to give high amplitudes on seismic data. Amplitude characteristics at 23a-4 and 23d-8 are shown in Figure 3-11; in 23a-4 the amplitudes relate to a shale response.

23a-4

23d-8

Q13PH1 PROCMIG thickness (ft) total sand gas column oil column paleo

MF10 PROCMIG

13/23a-4 13/23d-8 213 181 5 19 35

Figure 3-11 Amplitude response at 23a-4 and 23d-8

From inspection of various amplitude extractions, it is highly unlikely that there is an extensive primary gas cap over Phase 2. 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.


13


Liberator Area CPR

4 Petrophysical evaluation The objective of the petrophysical evaluation was to review the nearby well logs and core data to support the range of rock properties used in the volumetric calculations. The two key wells for Phase 2 are 13/23a-4 in the west and 13/23d-8 in Liberator.

4.1 Data Availability and Quality Petrophysical data, including log analysis, for Liberator and Blake wells were supplied in an LR Interactive Petrophysics (IP) database. All interpretation inputs were included in the IP database and were found to be robust. Basic and interpreted logs for 13/23-1, to the south, were transferred from the Kingdom project. This well found no sand in the K50, only a shale interval with some carbonaceous material indicated on logs.

4.2 Petrophysical Interpretation The petrophysical interpretation of the well logs is described in the Phase 1 CPR (Ref. 1)

13/23d-8

13/23a-4

Figure 4-1 CPI for 13/23-4 and 13/23d-8

A CPI for the two key wells is shown in Figure 4-1. The Liberator well 23d-8 encountered a thick Captain sand with an Upper Captain sand separated from the Lower Captain sand by the Mid Captain shale. The well found a small gas column overlying oil. Well 23a-4 found water-bearing Captain sands overlain by a thick K50 shale (which is not present in 23d8). The sands are undifferentiated in this well. There is a WUT at 5,278ft TVDss at the top of the Captain sand. There is a thin shale present within the K50 shale, it is also water-bearing with a WUT at 5,222ft TVDss. The thicknesses of the total and individual sand packages are given in Table 4-1.


14


Liberator Area CPR

Well

Zone Name

Gross thickness (ft)

13/23a-4

K50 shale

104.0

13/23a-4

Captain Sand

213.0

13/23a-4

Total K50

317.0

13/23d-8 Upper Captain Sand

182.0

13/23d-8 Mid Captain Shale

26.0

13/23d-8 Lower Captain Sand

106.5

13/23d-8

314.5

Total K50

Table 4-1 Thicknesses in 23a-4 and 23d-8

The average porosity of the individual sands is 26% The NTG varies depending on which intervals are considered but individual sands have a NTG of between 75% and 95% with the lower figure representative of the Lower Captain sand.

Well

Zone Name

Top MD

Bottom Top Bottom Gross Net NTG Av Phi MD TVDSS TVDSS ft TVDSS ft TVDSS

13/23a-4

Captain Sand

5364.0 5577.0 5278.0 5491.0

213.0

170.0 0.80 0.26

13/23a-4

Total K50

5260.0 5577.0 5174.0 5491.0

317.0

173.5 0.55 0.26

13/23d-8 Upper Captain Sand 5329.5 5511.5 5247.3 5429.2

182.0

173.5 0.95 0.28

13/23d-8 Lower Captain Sand 5537.5 5644.0 5455.2 5561.7

106.5

79.7

13/23d-8

314.4

253.4 0.81 0.26

Total K50

5329.5 5644.0 5247.3 5561.7

0.75 0.24

Table 4-2 Key rock properties in 23a-4 and 23d-8

4.3 Saturation vs Height Function The only well with hydrocarbons relevant to Phase 2 is 23d-8. The saturations in 23d-8 are possibly pessimistic due to its down dip position and potential depletion as a result of Blake production. The saturation-height function based on the analogue data of the pre-production Blake wells has been used as the reference case saturation-height function for the Phase 2 area (the blue Blake function in Table 4-2).


15


Liberator Area CPR

Blake function Liberator function Figure 4-2 Saturation-Height functions based on pre-production Blake analogues and on Liberator well


16


Liberator Area CPR

5 Static Modelling 5.1 Key Uncertainties Based on a review of the geology, geophysics, petrophysics and fluids, the following are the key uncertainties affecting volumes in the Phase 2 area: 

reservoir presence and continuity



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



contact



possible gas column

The porosity and NTG of the sands themselves are thought to have a relatively narrow range based on properties of the exploration wells and other fields with Captain sands. The same applies for the saturations. The permeability of the sands is known from the Blake Field and is expected to be moderately high at this reservoir depth and is not considered a key development uncertainty. Phase 2 West is considered to have greater uncertainty than Phase 2 East. The wells 23d-8 and 23a-4 are 8km apart and show somewhat different stratigraphy and reservoir character. Phase 2 East is closer to the Liberator discovery well and the sands are likely to be part of the main sand channel fairway; oil is considered to be proven. However, in Phase 2 West the sand observed in exploration well 23a-4 may not be the same sand that was encountered in 23d-8. The sand may not lie on the continuation of the Liberator fairway and/or it may be sourced from a different location. Note that no hydrocarbons were encountered within the Captain sands in 23a-4.

5.2 Reservoir Distribution In order to cover the range of possible sand distribution, Low-Mid-High estimates were made for the Phase 2 East and West areas using a series of polygons (Figure 5-1). 

The Low estimate is based on the most confident areas from seismic facies mapping.



The Mid estimate also includes areas with a thick isochore which is inferred to correlate with sand presence.



The High estimate assumes sand is present in the whole area.


17


Liberator Area CPR

Volumetric polygons: Low Case Mid Case High Case

Depth (ft TVDss)

Top Captain Sand (as supplied) C.I. = 25ft

Figure 5-1 Map of Phase 2 area with sand polygons

5.3 Fluid Distribution In Phase 2 East the OWC is likely to be the same as in Liberator, i.e. at 5,270ft (Figure 5-2), with the exception of the Low case where the mapped saddle could be deeper than the OWC encountered in the discovery well. For this case a shallower OWC consistent with four-way dip closure of 5,170 ft is considered. In Phase 2 West the OWC could be 5,270ft or shallower, e.g. 5,170ft. The exploration well encountered a WUT at 5,278ft at the top of the Captain sand. Note that a thin sand within the K50 shale also has a WUT at 5,222ft; it is thought to be an isolated sand. Unlike the wells in Liberator and Blake, no residual oil (paleo-column) has been interpreted in 23a-4. As with Liberator, and by analogy to the Blake Field, a 15% HCPV gas cap has been applied in all but the High case.

Phase 2 West 0

800

1600

2400

Phase 2 East 3200

4000

4800

5600

6400

Phase 1 7200

13_23a-4

8000

8800

Blake 9600

13_23d-8_Lib

-4900

10400

11200

12000

13_24a-4

12800

13_24a-6

shallow map

-5000

-4900 -5000

K50 -5100

-5100 GOC

-5200

Shale

WUT -5300

-5279.68

5,270 ft deep map

-5400

Saddle to NW of Liberator

-5500 -5600

GOC OWC

-5252.30 -5270.19

Interbedded

-5430.66

GOC -5150.00 GOC GOCGOC-5156.00 -5154.00 -5157.68 -5176.00 -5200

OWC OWC OWC OWC -5264.00 -5273.50

OWC OWC -5251.00 -5258.00 -5260.00 -5264.00 -5300 -5400 -5500 -5600

Valhall 0

800

1600

2400

3200

4000

4800

5600

6400

7200

8000

8800

9600

10400

11200

12000

12800

Figure 5-2 Cross section from NW to SE showing fluid contacts


18


Liberator Area CPR

5.4 Input Data The following geophysical input maps were used to generate the static model: 

Depth map for K50



Depth map to top Captain Sand



Depth map for Valhall Formation

No faults were mapped. The model area includes the Blake Field. The top Captain Sand corresponds to the K50 in the Liberator well and in the Blake Field but the two surfaces diverge away from Phase 2 East towards 23a-4 and Phase 2 West. The wells were loaded manually from the well location and deviation surveys provided by the client. Some well paths were only available in the Kingdom project, so these 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 the Kingdom project.

5.5 3D Model A simple 3D geocellular model was created for volumetric purposes only. The model was created using Petrel 2016.3 software and extended from the Liberator Phase 1 model. Only the K50 and Valhall horizons are necessary to define the model. AGR has used the K50 structure to define the top of the Gross Rock Volume (GRV) ‘container’. The K50 shale seen in the western well, 13/23a-4, has been modelled only within a 1km radius. The porosity and NTG from all the wells were interpolated between the wells (‘REF’). The saturation was modelled using a petrophysical saturationheight function, as for Phase 1, see Section 4.3. The depth uncertainty away from the wells is assumed to be + 50ft at a radius of 2000m, see Section 3.1.2 (Figure 5-2). Low case (deep) and High case (shallow) surfaces were generated in Petrel and corresponding Low and High case GRVs were calculated. Note that in the Low case there is a possibility that the saddle separating the Liberator Field from Phase 2 is deeper than currently mapped in which case the NW extension could be a separate accumulation.


19


Liberator Area CPR

6 In-Place Volumes 6.1 STOIIP evaluation The elements described in Section 5 were brought together to calculate in-place volumes for three deterministic cases. The input parameters are summarised in Table 6-1. In all cases a FVF of 1.157 was used, as determined from samples in the Liberator well (and similar to Blake Field).

Phase 2 split into west and east

STOIIP MMstb

Case

Structure

Gas Cap

Sand Areas

NTG

Porosity

Sw

OWC

WEST

EAST

TOTAL

Low

DEEP

15%

Low

0.95

REF

REF

5170

26

4.3

30

Mid

REF

15%

Mid

0.95

REF

REF

5270

135

64

199

High

SHAL

0

Max

0.95

REF

REF

5270

329

103

432

Table 6-1 Case Summary Phase 2 Area

In-Place volumes are summarised in Table 6-2. Phase 2 East

Case

STOIIP MMstb

Phase 2 West

GIIP Solution gas

GIIP Free gas

Bscf

Bscf

STOIIP MMstb

GIIP Solution gas

GIIP Free gas

Bscf

Bscf

Low

4.3

1.5

0.1

26

9

0.7

Mid

64

22

1.7

135

46

3.6

103

35

0

329

112

0

High

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


20


Liberator Area CPR

7 Reservoir Engineering 7.1 Data Review Data provided consisted of: 

The Client’s tNavigator simulation model over the full Liberator structure (Phase 1 and 2 areas) and Blake Field



PVT data and pressures from the Liberator discovery well



PVT and SCAL data from Blake



Production history data from Blake including recovery to date

7.2 Evaluation Given the uncertainty associated with volumes in the Phase 2 area, only a high level assessment of recovery factors was undertaken taking into account information available from Blake Field and the results of the Phase 1 Area CPR assessment, which included reservoir simulation. Basic reservoir and fluid parameters were assumed to be the same for the Phase 2 area as for the Phase 1 area (Ref. 1). These include: 

Initial conditions (Table 7-1)



Oil properties; oil is saturated with moderate viscosity (Table 7-1)



Relative permeability functions; water-wet based on Blake field SCAL measurements (Figure 7-1).



Mobility ratios



Aquifer properties such as compressibility, and presence of sand beneath the HC column (bottom drive) as well as presence of some edge drive aquifers. It should be noted there is uncertainty with respect to size and distribution of aquifers for the Phase 2 area.

Oil Properties oF

140

Reservoir pressure

psia

2315

Oil gravity

API

30.5

Pb

psia

2278

scf/bbl

341

v/v

1.16

@ Reservoir pressure

cp

1.91

@ Bubble point pressure

cp

1.9

Reservoir temperature

GOR Bo Oil viscosity

Table 7-1 Liberator oil properties and initial conditions


21


Liberator Area CPR

Figure 7-1 Relative permeability curves for Low, Mid and High cases

A range of sensitivities were evaluated using the Phase 1 area simulation model, in order to develop an understanding of the key recovery mechanisms and the influence of various parameters on recovery factor. A key conclusion from this work is that recovery factors are expected to be somewhat lower than North Sea averages in reservoirs of this quality. This is attributable primarily to hydrocarbon column thickness; a thin hydrocarbon column, high vertical permeability and thick high quality sand below the oil column, results in cusping of water and reduced sweep despite optimum well placement and low drawdown. The resulting recovery factor range for Phase 1 area was 22 to 29%. A value of 22% corresponds to a Low case with a deep top reservoir and therefore thinner oil column, average of only circa 30 feet, and smaller total aquifer volume. The higher recovery factor of 29% corresponds to a slightly thicker oil column, circa 50+ feet. Additional injection support potentially improves recovery to 35%. In Blake Field, where the oil column is consistently closer to 100 feet, a recovery factor of at least 50% has already been achieved (STOIIP estimates have not been reviewed by AGR, therefore percent recovery can only be an estimate). With oil decline, GOR and WCUT trends well established, recovery may exceed 60% based on field level decline analysis. Blake benefits from water injection support and horizontal wells optimised with respect to both GOC and OWC.

7.3 Recovery Factors With these observations and findings in mind a recovery factor range which accounts for the uncertainties including variation in HC column thickness, and sand continuity and extent (impacting aquifer size), the following range for recovery factor has been used in to estimate recoverable resource volumes:

Case

RF %

Scenario

Low

20

Similar to Liberator Phase 1 Low Case

Mid

35

Average of Low and High Cases

High

50

Blake type recovery factor

Table 7-2 Recovery factors summary


22


Liberator Area CPR

It is important to note that, the average column height increases north-westward (from Phase 1 Area to Phase 2 Area) correspondingly the mid case recovery factor is expected to be higher for a similar type of development (Ref. 1, Section 8). Scale of type of development may also impact recoveries, see Section 8.2. Recovery factors for gas have not been evaluated, as this will be development plan dependent. For example in the case of pressure maintenance through water injection, minimum recovery of gas would be associated gas only.


23


Liberator Area CPR

8 Exploration, Appraisal and Development Plans 8.1 Overview There are no firm plans for exploration or appraisal drilling, as the Phase 2 Area is currently un-licenced. Sub-surface evaluation is ongoing, and potential appraisal well locations have been assessed and the first appraisal well location has been identified. There are no firm plans for development currently, although development screening is ongoing. Economics have not been run for the current CPR given the uncertainty around which development options would be pursued in the case of appraisal and or exploration success.

8.2 Development Options Development strategy and options have only been considered at a very high level. The recovery factor range accounts for a variety of development concepts; horizontal wells optimised with respect to contacts, similar to the Liberator Phase 1 FDP concept and Blake Field development, have been assumed. Higher end recovery factors would most likely require water injection and gas lift. The simplest concept would be an extension of the Phase 1 Area development, i.e. further tie-backs to the Blake manifold or Phase 1 area wells. Feasibility of such a concept has not been reviewed. Stand-alone development may be justified if a large enough in place volume can be confirmed.


24


Liberator Area CPR

9 Resource Estimation The primary objective of the current CPR assessment has been to evaluate how far the results from the Liberator discovery well can be confidently extrapolated North-westwards, in order to classify resources as discovered, or where not confident, as prospective resources.

9.1 Classification The Phase 2 area has been divided into two regions based on proximity to the discovery well, as well as change in seismic character and structural trend (Figure 1-2). Resource classification for the two areas has been assessed separately; however, the criteria are the same. It is worth noting that because the licence has not been awarded, resources cannot be classified as Reserves. This means that resources can be either Contingent or Prospective, depending on whether the area can be considered Discovered. In order to assess whether or not resources are discovered two aspects were evaluated in detail, these are the potential for HC column continuity across the saddle west of the discovery well, and continuity of the sands across that saddle as described in Section 3. On this basis Resource Categories are as follows: 

Phase 2 East - Contingent Resources, Development Unclarified



Phase 2 West - Prospective Resources

9.2 Contingent Resources - Phase 2 East Overall Chance of Commercial Success (COSc) is estimated to be 63% (= 70% x 90%) for the contingent resources based on the following: 

A 90% chance of licence award required for appraisal and development



70% chance of finding a sufficiently large volume to develop (STOIIP). 70% is based on Swanson’s mean applied to low, mid and high case outcomes (i.e. 30%-40%-30% probability for low- midhigh outcomes, respectively). It has been assumed that the Low case would not be economically viable, although this has not been rigorously tested.

Contingent resources are summarised in Table 9-1.

Case

STOIIP MMstb

RF %

Recoverable MMstb

Associated Gas Bscf

Low

4

20

1

0

Mid

64

35

22

8

High

103

50

52

18

COSc

63%

Table 9-1 Resource estimate for Phase 2 East

9.3 Prospective Resources - Phase 2 West For Prospective resources the overall Chance of Commercial Success considers the technical risk, in addition to any commercial risk. For Phase 2 West an overall chance of commercial success of 51% has been estimated, with a Chance of Geological Success of 56% and chance of a commercial project of 90%. The latter is reliant on obtaining the licence for the Phase 2 area. In place volumes are considered to be sufficiently large, so that if geologically successful a commercial development would be viable. The Chance of Geological Success (COSg) is assessed as follows:


25


Liberator Area CPR



Charge – 100%



Trap – 75%



Top Seal – 100%



Reservoir Presence (& Quality) – 75%



Total COSg is 56.3%

Note that if the Mid or High realisations for Phase 2 East were proven this would in part de-risk Phase 2 West. Prospective resources are summarised in Table 9-2:

STOIIP MMstb

RF

Recoverable Oil MMstb

Associated Gas Bscf

Low

26

20%

5

2

Mid

135

35%

47

16

High

329

50%

165

56

COSc

51%

Table 9-2 Prospective resource summary


26


Liberator Area CPR

10 References 1. AGR TRACS International Ltd, CPR Phase 1 Area, October 2017


27


Liberator Area CPR

11 Glossary of Terms %

percent

MM

million

3D

Three Dimensional

MMbbls

million barrels of oil

API

American Petroleum Institute

MMstb

million stock-tank barrels of oil

Av Phi

Average Porosity (from log evaluation)

NTG

Net to Gross

Av Sw

Average water Saturation (from log evaluation)

OGA

Oil and Gas Authority

Opex

operating expenditure

OWC

Oil Water Contact

P10

10% probability of being exceeded

P50


P90


PRMS

Petroleum Resource Management System

bbls

Barrels

Bscf

Billion standard cubic feet of natural gas

boe

barrels of oil equivalent

bopd

barrels oil per day

bpd

barrels per day

Capex

capital expenditure

psia

pounds per square inch absolute

COSc

Chance of Commercial Success

PVT

Pressure Volume Temperature

COSg

Chance of Geological Success

RF

Recovery Factor

CPR

Competent Persons Report

RT

Real Terms

FDP

Field Development Plan

SPE

Society of Petroleum Engineers

FVF

Formation Volume Factor

sq km

square kilometres

ft

feet

ss

subsea

GIIP

Gas Initially In Place

STOIIP

Stock Tank Oil Initially In Place

GOR

Gas to Oil Ratio

Sw

water Saturation

GR

Gamma Ray log

Swavg

average water Saturation

GRV

Gross Rock Volume

Sxo

water Saturation in invaded zone

HC

Hydrocarbon

TD

Total Depth

HCPV

Hydrocarbon Pore Volume

TVD

true vertical depth

K

Permeability

TVDss

true vertical depth subsea

km

Kilometre

WCUT

Water Cut

km2

Square kilometres

WI

Working Interest

m

metre

WUT

Water Up To

Mbbls

thousand barrels of oil (unless otherwise stated)

MD

Measured Depth

mD

milli Darcies

MDT

Modular Formation Dynamics Tester


28


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


29


Liberator Area CPR

SPE CLASSIFICATION SYSTEM (April 2007)

RESERVES Proved (1P)

Proved + Probable (2P)

INCREASING CHANCE OF COMMERCIALITY →

COMMERCIAL SUB-COMMERCIAL

DISCOVERED PETROLEUM – INITIALLY IN PLACE UNDICOVERED PETROLEUM – INITIALLY IN PLACE

TOTAL PETROLEUM INITIALLY IN PLACE

PRODUCTION

Proved + Probable + Possible (3P)

CONTIGENT RESOURCES Low Estimate (1C)

Best Estimate (2C)

High Estimate (3C)

UNRECOVERABLE

PROSPECTIVE RESOURCES Low Estimate

Best Estimate

High Estimate

UNRECOVERABLE

← RANGE OF UNCERTAINTY →

Figure A-1 SPE PRMS Petroleum Resources Classification Framework


30


North Sea, Liberator Field â Phase 2 - i3 Energy

North Sea, Liberator Field â Phase 2 - i3 Energy

North Sea, Liberator Field â Phase 2 - i3 Energy

North Sea, Liberator Field â Phase 2 - i3 Energy