Independent Review and Audit of Prospective Resources ...Vesta Italy C.R149.NP 100% Exploration...
Transcript of Independent Review and Audit of Prospective Resources ...Vesta Italy C.R149.NP 100% Exploration...
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Reference:
PRJ11086541
Reporting date:
November 2018
Report status:
Final
Independent Review and Audit of Prospective
Resources - Vesta Prospect, Offshore Italy
A Competent Person’s Report for:
Cabot Energy plc.
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Lloyd’s Register has made every effort to ensure that the interpretations, conclusions and recommendations presented
herein are accurate and reliable in accordance with good industry practice and its own quality management
procedures. Lloyd’s Register does not, however, guarantee the correctness of any such interpretations and shall not
be liable or responsible for any loss, costs, damages or expenses incurred or sustained by anyone resulting from any
interpretation or recommendation made by any of its officers, agents or employees. This report has not been prepared
to be compliant with the regulations of any specific financial exchange.
Author(s)
Jon Wix
Technical Audit
Joanne Cranswick
Quality Audit
Jennifer Ives
Release to Client
David Tobias
Date Released 16th November 2018 (final report)
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The Directors
Cabot Energy Plc
93-95 Gloucester Place
London, W1U 6JQ.
16th November 2018
Dear Sirs,
In accordance with the instructions of the Directors of Cabot Energy Plc, Lloyd’s Register (LR or Senergy (GB) Limited) has
undertaken an independent review and audit of Prospective Resources of the Vesta prospect, offshore Italy.
Recoverable volumes are expressed as gross resources and are the total estimated petroleum to be produced. The portion of the
gross resources attributable to the 100% Working Interest currently owned by Cabot’s associate companies is not the same as net
entitlement as the latter will be net of any applicable contract and fiscal terms attributing a portion of the recoverable volumes to
the government as per the contractual terms of the licence at the time of any eventual hydrocarbon production and can only be
estimated by economic analysis which has not been carried out for this report.
The content of this report and LR’s estimates of resources are based on data provided by Cabot and its associate companies in
September and October 2018. LR confirms that to its knowledge there has been no material change of circumstances or available
information since the report was compiled.
This report covers the estimation of Low (1U), Best (2U) and High (3U) Prospective Resources corresponding to stochastic P90, P50
and P10 volume estimates respectively. In auditing the estimation and allocation of resources to these categories, we have assessed
their consistency with the 2018 Petroleum Resources Management System (PRMS) prepared by the Oil and Gas Reserves Committee
of the Society of Petroleum Engineers (SPE) and reviewed and jointly sponsored by the World Petroleum Council (WPC), the
American Association of Petroleum Geologists (AAPG), the Society of Petroleum Evaluation Engineers (SPEE), the Society of
Exploration Geophysicists (SEG), the Society of Petrophysicists and Well Log Analysts (SPWLA) and the European Association of
Geoscientists and Engineers (EAGE) (Reference 3). The report has not been prepared to be compliant with the regulations of any
specific financial exchange.
In conducting this review, LR has used information and interpretations supplied directly or indirectly by Cabot, its associate
companies and independent third parties, comprising basic geological, geophysical, petrophysical and engineering data, digital
models and technical reports. LR has carried out independent analyses of these data as appropriate to audit the work conducted
by Cabot and its associate companies to derive the gross Prospective Resources attributable to the prospects. Site visits were not
considered necessary for the purposes of this report. LR has not verified the legal entitlement of Cabot and its associate companies
to the interests covered in this report since this is outside the remit of this technical evaluation.
Standard geological and engineering techniques accepted by the petroleum industry were used in reviewing the estimates of
recoverable hydrocarbons. These techniques rely on engineering and geo-scientific interpretation and judgement; hence the
resources included in this evaluation are estimates only and should not be construed to be exact quantities. It should be recognised
that such estimates of hydrocarbon resources may increase or decrease in future if there are changes to the technical interpretation,
economic criteria or regulatory requirements.
Yours faithfully,
David Tobias
Head of Reserves and Asset Evaluations
For and on behalf of Lloyd’s Register
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Executive Summary
This report comprises an evaluation of the Vesta prospect, offshore Italy.
Table ES.1 gives a summary of the licence for the Vesta prospect:
* Working Interest is defined here as the interest held in the licence that gives the owner of the interest the right to drill and produce oil and gas
on the leased acreage. It requires the owner to pay the Working Interest percentage of the costs of operations. The share of production to which
a working interest owner is entitled will always be smaller than the share of costs that the working interest owner is required to bear.
Table ES 1: Cabot Licence Interests
The primary data provided by Cabot includes subsurface data, reports, technical notes and meeting presentations.
The effective date is 29th October 2018 incorporating data provided by Cabot during September and October 2018.
LR have reviewed and evaluated the available technical data and reports for the Vesta prospect, as requested by
Cabot. Independent volumetric stochastic calculations and risk evaluations were carried-out by LR for the prospect.
The Prospective Resources for oil are reported in Table ES 2. The Prospective Resources assume that licence extensions
will be granted. Gross volumes apply to the total accumulation which may extend onto adjacent licences in which
Cabot does not hold equity. Net volumes are those wholly contained within the licenses held by Cabot, in all of which
the company has 100% working interest.
Oil Prospective Resources (MMstb) Unrisked
Prospect Low (1U) – P90 Best (2U) – P50 High (3U) – P10 Chance of
Discovery %
Gross* Net* Gross* Net* Gross* Net*
Vesta 31 31 187 187 642 642 13
* Gross volumes apply to the total accumulation which may extend onto adjacent licences in which Cabot does not hold equity. Net volumes are
those wholly contained within the licenses held by Cabot, in all of which the company has 100% working interest. Assuming Geological Discovery,
with its estimated chance of success, the Low Estimate then implies at least a 90% probability (P90) that the quantities actually recovered will equal
or exceed the low estimate. The Best Estimate then implies at least a 50% probability (P50) that the quantities actually recovered will equal or
exceed the best estimate. The High Estimate then implies at least a 10% probability (P10) that the quantities actually recovered will equal or exceed
the high estimate.
Chance of Geologic Discovery is defined and discussed in Section 2.2.1 and pertains to the chance of finding a sufficient quantity of petroleum to
justify estimating the in-place volume demonstrated by a well(s) and for evaluating the potential for technical recovery and does not relate
specifically to the discovery of Low, Best or High volumes quoted.
Table ES 2: Oil Prospective Resources at October 2018 (MMstb)
Prospect Country Licence Cabot Working
Interest* Status
Vesta Italy C.R146.NP 100%
Exploration License
Suspended pending
Government approvals
Vesta Italy C.R149.NP 100% Exploration License
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LR estimate the unrisked Gross (which is the same as the Net) Mean Prospective Resources to be 280 MMstb oil.
PRMS 2018 guidelines have been used in the Resources evaluation in this project. LR acknowledges that this is a new
amendment to the PRMS guidelines. LR has used its best endeavours to assess the new guidelines and apply them
to this project, but cannot be responsible for alternative interpretations of the guidelines.
Prospective Resources are quantities of petroleum which are estimated, as of a given date, to be potentially
recoverable from undiscovered accumulations. There is no certainty that any hydrocarbons will be discovered when
exploration well(s) is/are being drilled. Furthermore, should any hydrocarbons be discovered there is no assurance
that it is commercially viable to produce any portion of these resources.
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Contents
1. Introduction 1
1.1 Sources of Information 1
1.2 Requirements 1
1.3 Standards Applied 1
1.4 Site Visit 2
1.5 Liability 2
1.6 Consent 2
2. Vesta Prospect, Licences C.R146.NP & C.R149.NP 3
2.1 Introduction 3
2.2 Subsurface Evaluation 3
2.2.1 Prospect Risk 4
2.2.2 Prospect Volumes 6
3. References 10
Appendix 1 – Lloyd’s Register and Author Credentials 11
Appendix 2 - Resource and Risk Evaluation Method 12
Nomenclature 21
Figures 24
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List of Tables
Table ES 1: Cabot Licence Interests ...................................................................................................................... iii Table ES 2: Oil Prospective Resources at October 2018 (MMstb) ...................................................................... iii
Table 2.1: Vesta Prospect, Chance of Geologic Discovery Assessment ............................................................. 6 Table 2.2: Vesta Prospect Volumetric Input Parameters ..................................................................................... 7 Table 2.3: Vesta Prospect, Unrisked STOIIP .......................................................................................................... 8 Table 2.4: Vesta Prospect, Unrisked Prospective Resources ............................................................................... 8
List of Figures
Figure 2.1 Location of Licenses C.R146.NP & C.R149.NP
Figure 2.2 Vega Field Seismic & Structure
Figure 2.3 Vesta Play Concept
Figure 2.4 Better Quality 2D Seismic Data Example
Figure 2.5 Poorer Quality 2D Seismic Data Example
Figure 2.6 Mapping Basis for Low/Best/High GRVs
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1. Introduction
This report was prepared in October 2018 by Lloyd’s Register (LR or Senergy (GB) Limited) at the request of
and for the benefit of the Directors of Cabot Energy Plc (Cabot or the Company). The report consists of an
evaluation of the Vesta Prospect in the Sicily Channel (Licence C.R146.NP and C.R149.NP), offshore Italy.
The rights of Cabot in the licences have not been verified by LR as this is considered outside the scope of this
technical geological and engineering report. Therefore, LR makes no comment on the legal entitlement of
Cabot or its affiliates to these areas.
LR was requested to provide an independent review and audit of the Prospective Resources.
Some of the resources for these prospects attributable to Cabot assume licence extensions are granted.
1.1 Sources of Information
In conducting this review LR has utilised information and interpretations supplied by Cabot and its affiliates
comprising subsurface, field and other data along with various technical reports and presentations. The
report is based on data and information made available to LR by Cabot during September and October 2018.
LR has reviewed the information provided and modified assumptions where appropriate. LR has accepted,
without independent verification, the accuracy and completeness of the data.
LR has had access to a dataset supplied by Cabot and its affiliates of both raw and interpreted data. However,
LR has not attempted a systematic re-interpretation of the raw data but has performed a critical assessment
of the existing interpretations.
1.2 Requirements
In accordance with your instructions LR confirms that:
LR is professionally qualified and a member in good standing of a self-regulatory organisation of
engineers and/or geoscientists;
LR has at least five years’ relevant experience in the estimation, assessment and evaluation of oil and gas
assets;
LR is independent of Cabot, its directors, senior management and advisers;
LR will be remunerated by way of a time-based fee and not by way of a fee that is linked to the value
of Cabot or its assets;
LR is not a sole practitioner;
LR has the relevant and appropriate qualifications, experience and technical knowledge to appraise
professionally and independently the assets, being all assets, licences, joint ventures or other
arrangements owned or proposed to be exploited or utilised (“Assets”) and liabilities, being all liabilities,
royalty payments, contractual agreements and minimum funding requirements relating to the work
programme and Assets (“Liabilities”).
1.3 Standards Applied
In compiling this report, LR has been guided by the definitions and guidelines set out in the Petroleum
Resources Management System (PRMS) (2018) prepared by the Oil and Gas Reserves Committee of the
Society of Petroleum Engineers (SPE) and reviewed and jointly sponsored by the World Petroleum Council
(WPC), the American Association of Petroleum Geologists (AAPG) and the Society of Petroleum Evaluation
Engineers (SPEE), the Society of Exploration Geophysicists (SEG), the Society of Petrophysicists and Well Log
Analysts (SPWLA) and the European Association of Geoscientists and Engineers (EAGE) (References 1 to 4).
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The report has not been prepared to be compliant with the regulations of any specific financial exchange.
1.4 Site Visit
A site visit has not been required as all the data pertaining to this project is subsurface information available
digitally.
1.5 Liability
All interpretations and conclusions presented herein are opinions based on inferences from geological,
geophysical, engineering or other data. The report represents LR’s best professional judgment and should
not be considered a guarantee of results. Our liability is limited solely to the Company for the correction of
erroneous statements or calculations. The use of this material and report is at the user’s own discretion and
risk.
1.6 Consent
The report relates specifically and solely to the subject assets and is conditional upon various assumptions
that are described herein. The report must therefore be read in its entirety. This report was provided for the
use of the Company on a fee basis.
Lloyd’s Register assumes no responsibility and shall not be liable to any person for any loss, damage or
expense caused by reliance on the information or advice in this document or howsoever provided, unless
that person has signed a contract with the relevant Lloyd’s Register entity for the provision of this information
or advice and in that case, any responsibility or liability is exclusively on the terms and conditions set out in
that contract.
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2. Vesta Prospect, Licences C.R146.NP & C.R149.NP
2.1 Introduction
The Vesta prospect lies on licenses C.R146.NP and C.R149.NP in the Sicily Channel offshore region of Italy
(Figure 2.1). The licenses lie approximately 60 km from the coastline in around 120 m water depth. Cabot
operate the licenses with 100% Working Interest (Table ES-1). The Vesta prospect comprises platform shoal
carbonates with both primary and secondary (fracture and karst) porosity and is considered analogous to the
currently producing Vega field, which lies 60 km to the north-west and is operated by Edison.
The C.R146.NP licence was awarded in September 2004 for an initial six year period. The work programme
for this licence comprised the acquisition of 150 km of 2D seismic and the drilling of an exploration well to
3,500 m TD within 42 months of award. In 2006, 508 km of 2D seismic was acquired in C.R146.NP. EIA
approval to drill a well was granted in April 2018, and the C.R146.NP permit is currently in suspension
pending drilling. As it is believed that the Vesta prospect extends eastwards into the C.R149.NP permit, this
acreage was applied for by the Company, and subsequently awarded in July 2014. Licence C.R149.NP has
a first exploration period of six years, with a work programme consisting of one exploration well to 3,500 m
TD within 60 months of award. The Company is looking for partners to help progress the work programmes
offshore Sicily.
2.2 Subsurface Evaluation
The Vesta prospect is considered an analogous dip-closed structure to the Vega field, but with upside
potential in the form of a possible stratigraphic trapping element. The prospect is mapped on variable quality
2D seismic and constrained by a few key wells in its vicinity. The proposed reservoirs are the same Liassic
fractured oolitic limestones and dolomites as encountered in the Vega field.
The Vega field
The Vega oil field lies approximately 60 km to the northwest of Vesta. Vega was discovered in 1981 by
Edison, and has an estimated STOIIP in the order of 431 MMstb and an EUR of 95 MMbbl. 63.4 MMstb of
heavy 15.5o API oil have been produced to date from 21 wells. The oil density is high and the amount of gas
dissolved in the oil is negligible (10-20 Sm3 / m3). Vega is described by Edison in a 2011 technical report
supporting the extension of the term of the field’s production concession (Reference: Concession “C.C6.EO”
Depository, Technical Report of Campo Vega, November 2011, Edison).
The trap is a 4-way dip closure located on the platform margin and is believed to be full to spill (Figure 2.2).
The Liassic Siracusa Formation reservoir is a low porosity fractured carbonate, with a variety of facies belts
including platform top, emergent areas dominated by paleo-karstic porosity, and more marginal facies
towards the Streppenosa Basin to the north. The two main lithologies of the reservoir sequence are limestone
and dolomite, with the latter thought to originate in a fresh/salt water mixing zone within a karst system.
The dolomites are generally characterised by better reservoir properties. Five main stages of diagenesis have
been identified by Edison from a study of cored material and regional analogues. Tectonic fractures played
an important role in the development of the karst system and subsequent dolomitisation, and their continued
development through the complex structural history to the present-day impacts on reservoir storage and
productivity.
The sealing unit of the Vega oil field is the Buccheri Formation which was deposited following an extensive
regional carbonate platform drowning event during the latest Liassic. The main source rock for the Vega oil
field is considered to be the Late Triassic Noto Formation.
Vega and Vesta are interpreted to occupy a similar Siracusa Platform margin location. Comparable reservoir
properties are expected due to the analogous depositional patterns along the platform margin, similar
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diagenetic and post-diagenetic histories, analogous tectonic histories and comparable reservoir depths (Vega
crest ~2,450 m TVDSS and Vesta crest ~2,670 m TVDSS).
2.2.1 Prospect Risk
Trap
The Vesta prospect low case scenario is a 4-way, dip-closed structure. The High case scenario invokes
stratigraphic trapping arising from facies changes, effectively from reservoir to non-reservoir, across the
Siracusa Platform margin to the north and represents substantially higher exploration risk. A sketch cross-
section illustrating the play concept is shown in Figure 2.3. Vesta is mapped on a grid of 2D seismic data of
varying vintages and quality. Figure 2.4 and Figure 2.5 illustrate the variation in 2D seismic data quality over
the Vesta prospect, the former showing one of the better quality lines, and the latter, one of the poorer.
Unfortunately, there is a lack of coverage of better quality data to the north and east of the prospect, resulting
in significant uncertainty in mapping in this critical area. This data coverage-related mapping uncertainty is
compounded by the additional uncertainties introduced by the ambiguity in the key seismic pick, top Liassic,
and the difficulty in interpreting this event reliably on the often poorly imaged seismic data. Synthetic
seismograms for key wells Spigola Mare-1 and Alexia-2, which both penetrate the top Liassic, suggest that
the existing Cabot seismic pick (a trough across the 2D dataset) does not represent a consistent ‘near top
Liassic’ event. In Spigola Mare-1 the existing Cabot top Liassic seismic pick appears to correspond with a
strong trough event, but at the top Buccheri Formation rather than its base; the top being in the order of
150 m above the base Buccheri/top Liassic reservoir in this well. However, in Alexia-2 the existing seismic
pick appears to loosely correspond to an intra-Buccheri lithology change 40 m above the base Buccheri/top
Liassic reservoir, and the top Buccheri Formation in this well is a clear peak due to the different lithologies in
the formations in the two wells. In addition to this uncertainty in identifying the top Liassic reservoir event,
at best the 2D seismic data over Vesta allows a ‘near top Liassic’ pick to be interpreted with some degree of
confidence. However, there are a number of lines where the imaging is insufficient to allow a reliable
interpretation to be made. This becomes critical in the north-eastern area of Vesta where the seismic dips
required to set up the 4-way dip closure in time are not clearly demonstrated on the reprocessed dataset.
A layer-cake depth conversion methodology was used based on mapping well interval velocities for key
overburden velocity units. This single deterministic depth conversion appears to be reasonable as far as it
goes, but no alternative velocity models have been generated to assess the uncertainty in the mapped Vesta
depth closure. LR consider that the size of the 4-way dip closure will be sensitive to the depth conversion
methodology and have taken this into account in the Monte Carlo volumetric assessment, together with the
uncertainty due to the time interpretation of the seismic.
In addition to the uncertainty in presence and size of a 4-way dip closed trap, LR consider that the
‘stratigraphic’ trapping element cannot be clearly defined on the existing seismic and well database. The
existing well data, the Vega field analogue and the semi-regional depositional model potentially support the
concept of a northwards and basinwards change in facies from carbonate platform associations to marginal
and basinal associations (refer to Cabot’s non-unique interpretation of the time equivalent stratigraphic
intervals in Spigola Mare-1 and Cernia-1 to the north). However, LR do not consider that the quality of the
existing 2D seismic data is sufficient to clearly define the location of the change from reservoir to sealing
facies at the platform margin and northern edge of Vesta which is necessary to delineate the ‘stratigraphic’
trapping element. Cabot themselves state that: “the available seismic data do not allow a clear definition of
the platform to basin transition” (Reference: 2018_09_07 Vesta Prospect Technical Report), and the seismic
can only give suggestions of the required transition on one or two better imaged lines. This upside trapping
element is thus considered very uncertain and subject to significantly higher level of risk than a smaller 4-way
dip closed structure.
LR consider that the case for acquiring 3D data prior to drilling is very strong.
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Prospect Trap Chance = 57% (contributes to Chance of Geologic Discovery).
Reservoir
Cabot propose that reservoir at Vesta will comprise similar Liassic Siracusa Formation platform shoal
carbonates to those present in the Vega field. Edison’s work on this field has shown that the reservoirs are
complex, with the original depositional variations in quality being modified significantly by a multi-phase
diagenetic and tectonic post-depositional evolution to produce a system with both primary and secondary
porosity. The fact that approximately 50% of the total Vega oil production arises from 4 of the 21 wells
illustrates the marked differences in reservoir quality and productivity which are present within the reservoir.
Well Spigola Mare-1 was drilled by Elf Italiana in 1984 and lies on the western flank of the Vesta prospect.
A DST in the upper reservoir section recovered 11.5 m3 of fluids comprising water with a salinity of 58g/l,
and an emulsion of gas (C1 to C4) with traces of bituminous oil without direct fluorescence. Elf reported
that the calculated permeability from the test was only in the order of 2 mD from a productive zone of
cumulative thickness around 5 m with reported average porosity in excess of 11%. The Siracusa Formation
in this well does not appear to have been fully logged and hence there is uncertainty over the reservoir quality
deeper in the drilled interval. Therefore the well does not prove effective reservoir quality at this down-flank
location to Vesta, and increases the risk on encountering better reservoir quality up-dip to the east.
Given the absence of a fully logged reservoir interval in Spigola Mare-1, Cabot have used the data from the
Vega field for the volumetric assessment of the Vesta prospect. LR have accepted this approach, but have
ensured that reservoir risk takes into account the results of Spigola Mare-1.
There is also the risk that the amount of net reservoir within the proposed Siracusa Formation interval may
be reduced by the presence of interbedded volcanic rocks, such as those proven in some of the offset wells.
Cabot have used seismic amplitudes to assess the risk of a significant proportion of volcanics within Vesta,
and consider that this is relatively low.
Prospect Reservoir Chance = 64% (contributes to Chance of Geologic Discovery).
Seal
An effective top seal, the basal part of the Buccheri Formation, is proven in the Vega field, and this interval
is also present in nearby wells Alexia-2 and Spigola Mare-1. However, the main clay-rich sealing interval
appears to be thinning from Vega south-eastwards towards Vesta, as indicated by the thicknesses in wells
Vega-1 (>120 m), Alexia-2 (~70 m) and Spigola Mare-1 (~10 m). There is thus the risk that an effective top
seal may not be present over the whole of Vesta, and this is considered the main risk element for the 4-way
dip-closed prospect trap.
Side/lateral seal is also required for the upside ‘stratigraphic’ trapping mechanism at Vesta. This element is
not thought to be present at Vega, and is thus a new play element and only supported at the conceptual
level by the existing well and seismic data. This upside seal element is considered very high risk at present.
Prospect Seal Chance = 45% (contributes to Chance of Geologic Discovery).
Charge
The proposed source rock for Vesta is the same Triassic Noto Formation anoxic back-lagoonal shales as
identified from the geochemical fingerprint in the oils of the Vega field. These shales are expected to be
present to the south of Vesta in the same general depositional environment found in the Vega field. The
presence of shows in some of the offset Vesta wells suggests the presence of migrating oil.
Maturity modelling carried out by Cabot suggests that most of the oil charge took place during the
Cretaceous for the Vega field, with the potential for a later charge in the Tertiary at Vesta depending on the
poorly constrained depth of the Noto Formation source in the Vesta catchment area. The key outcome of
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the modelling work is that hydrocarbon migration is thought to post-date Jurassic to Cretaceous trap
formation and modification.
One interpretation of the available data for the Spigola Mare-1 well is that live oil shows were present in
poor quality rock. It is also possible that the shows correspond to residual oil, but in either case this provides
support for hydrocarbons having passed through the rocks at this location at some point in time.
In summary, hydrocarbon charge is considered to be relatively low risk with the key sub-element being the
available volumes of generated and expelled oil.
Prospect Oil Charge Chance = 80% (contributes to Chance of Geologic Discovery).
Chance of Geologic Discovery
The LR assessment for the chance of geologic discovery for Vesta is summarised in Table 2.1. The Chance of
Geologic Discovery is defined (PRMS 2018) as the chance that the potential accumulation will result in the
discovery of a significant quantity of petroleum. “Significant” in this context implies that there is then
evidence of a sufficient quantity of petroleum to justify estimating the in-place quantity demonstrated by the
discovery well(s) and for evaluating the commercial discovery. Such volume can best be estimated by
identifying a development scenario and evaluating its potential economic threshold but this has not been
undertaken for this report. The Chance of Geologic Discovery thus pertains to discovery of volumes
corresponding at a maximum to the lowest end of the Prospective Resource range. No risking has been
attempted to correspond to the mid or high range of resource estimates for which there would be a
correspondingly higher risk element.
Prospective Resources are also subject to further risking associated with the Chance of Development. (see
Section 2.2.2).
In assessing Prospective Resources, a recovery factor has been applied which corresponds to a nearby
developed field analogue.
Prospect Trap % Reservoir % Seal % Charge % Chance of
Discovery %
Vesta 57 64 45 80 13
Table 2.1: Vesta Prospect, Chance of Geologic Discovery Assessment
2.2.2 Prospect Volumes
The input parameters and volumes are based on the work presented by Cabot which itself draws heavily on
the Vega studies undertaken by Edison.
LR has reviewed Cabot’s 2D seismic interpretation and mapping, and has accepted the most recent top Liassic
depth grid as the basis for calculating gross rock volumes (GRVs) within Kingdom for input to the REP Monte
Carlo software.
LR have used a Beta distribution for GRV, with a best-case input value anchored to the largest 4-way dip-
closed depth structure which can be mapped on the present 2D data (Figure 2.6). This is consistent with the
main Vega field analogue, which is a full-to-spill, 4-way dip closed accumulation based on the work we have
seen from Edison. The best-case GRV results from a lowest closing contour at 2,910 m TVDSS, producing a
column height of 240 m which compares well with the average 260 m column in the five Vega wells for
which we have information. The low case GRV is based on a lowest closing contour of 2,825 m TVDSS, and
is driven by assuming an oil column half of the maximum height seen in the Vega field (which is 310 m). A
reduced oil column at Vesta in comparison with Vega is considered a distinct possibility given that the top
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seal is thinning towards Vesta. This level of low case GRV is considered appropriate to capture a realistic
downside scenario, which although based on column height, may in effect arise for a variety of reasons such
as the large uncertainty in mapping the structure due to well ties, poor quality 2D data, depth conversion
uncertainty, etc. LR emphasise that confidence in the existing top Liassic depth map is moderate at best,
given the quality and availability of data and the complex geology of the play. The high case GRV is based
on a lowest closing contour of 3,190 m TVDSS and is the maximum closure which can be mapped given the
results of Spigola Mare-1. In the high-case the necessary lateral ‘stratigraphic’ trapping element is taken as
the east-west line interpreted by Cabot. The ‘P1’ lowest closing contour (3,280 m TVDSS) which equates to
the GRV defined by the input Beta distribution would require an oil column of 610 m which can be
accommodated by the Siracusa Formation reservoir thickness seen in well Alexia-2. The fact that the ‘P1’
lowest closing contour lies beyond Spigola Mare-1 can be accepted on the basis of the large uncertainty in
depth mapping due to well ties, poor quality 2D data, and depth conversion uncertainty.
Cabot’s dual-porosity system reservoir parameters are based on the Vega work undertaken by Edison. This
work accounts for porosity variation due to limestone and dolomite matrix properties and relative proportion,
karst zone variation, fracture intensity range and the variation in net reservoir (via a NTG) due to the presence
of interbedded volcanic rocks within the Siracusa Formation reservoir. LR have benchmarked Cabot’s
parameters using our broad experience with fractured carbonate reservoirs worldwide: they are considered
reasonable, with a realistic range to capture the significant uncertainty within the complex reservoir system,
and hence suitable for input to the REP volumetric calculation.
Edison’s reported figures for the Vega field (STOIIP 431 MMstb, EUR c. 94.5 MMstb) suggest a recovery factor
of 21.9%, which has been rounded down to by Cabot to a best case input of 20%. LR have used an input
recovery factor range of 10%-20%-30%, considering that Cabot’s presented range (15%-20%-25%) was
too narrow for this type of complex carbonate reservoir.
Table 2.8 presents the dual-porosity system reservoir parameters used by LR.
Vesta Volumetric Input Parameters
Low Best High
Gross Rock Volume (MMm3) 1,089 4,070 32,580
Matrix Net to Gross (%) 50 70 90
Matrix Porosity (%) 0.4 2.5 4.6
Matrix Water Saturation (%) 30 40 50
Fracture Net to Gross (%) 50 70 90
Fracture Porosity (%) 0.2 0.5 0.8
Matrix Water Saturation (%) 0 0 0
Formation Volume Factor (oil) (vol/vol) 1.08 1.11 1.16
Matrix Oil Recovery Factor (%) 10 20 30
Fracture Oil Recovery Factor (%) 10 20 30
Table 2.2: Vesta Prospect Volumetric Input Parameters
The Prospective Resources are expressed as a range of gross technical resources estimated to be potentially
recoverable from the accumulation, subject to successful exploration. Prospective Resources are not the same
as net entitlement as the latter will be net of any applicable contract and fiscal terms attributing a portion of
the recoverable volumes to the government as per the contractual terms of the licence at the time of any
eventual hydrocarbon production. Cabot have informed LR that the applicable Government royalty is 7%.
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Net entitlement can only be estimated after discovery, definition of a development project and by economic
analysis none of which stages have been reached by this project.
Low (P90), Best (P50) and High (P10) oil in place (Table 2.3) and Prospective Resources (Table 2.4) are
tabulated below for the Gross accumulation (which is the same as the Net volumes).
The Mean case STOIIP is calculated as 1,392 MMstb.
Oil Initially in Place (STOIIP) Unrisked
Vesta Gross equals Net (Total Accumulation Is On Licence, 100% Cabot Equity) Low Estimate – P90 Best Estimate – P50 High Estimate – P10
MMstb 173 991 3,104
Table 2.3: Vesta Prospect, Unrisked STOIIP
Prospective Resources Unrisked
Vesta Gross equals Net (Total Accumulation Is On Licence, 100% Cabot Equity) Low Estimate (1U) P90 Best Estimate (2U) P50 High Estimate (3U) P10
MMstb 31 187 642
Table 2.4: Vesta Prospect, Unrisked Prospective Resources
LR estimate the unrisked Gross (which is the same as the Net) Mean Prospective Resources to be 280 MMstb
oil.
The volatility ratio for the high to low cases is approximately 21, indicating a high level of uncertainty for this
unexplored play due to the significant but high-risk upside volumes associated with an unproven
‘stratigraphic’ lateral sealing element to the trap.
With regards to Chance of Development, the evaluation of a development scenario, regulatory and
contractual context and the economic threshold of the project were outside of the scope of LR’s technical
project review and so the Chance of Development could not be assessed nor quantified. LR have insufficient
information to assess if a discovery at the low end of the estimated probabilistic volume range would be
commercial. However, subject to favourable commercial terms and based solely on volume considerations,
a discovery in the estimated P50 to P10 probabilistic range would likely provide a basis for a commercial
project considering the size of the developed Vega field, an apparently economic analogue.
Vesta Triassic Potential, Licences C.R146.NP and C.R149.NP
Cabot have identified a possible Triassic exploration play at depth below the Vesta Liassic prospect. The
Triassic Gela Formation fractured carbonates form the reservoir in number of oil fields producing in the
region, for example the Gela field, onshore Sicily, in the northern part of the basin. This deep play remains
to be explored to any great degree in the offshore area. These deep Triassic reservoirs are likely to contain
light oil and condensate, with a potentially significant amount of gas.
Cabot describe how “the characterization of the Triassic prospectivity over the Vesta prospect is hindered by
the poor quality of the seismic data for those depths and by the lack of any deep Triassic penetration near
the prospect which could be used to constrain the Triassic horizon interpreted in TWT”. However, by
mimicking the shallower Liassic structure (which is itself poorly imaged by seismic), Cabot have reported that
a “large structure has been mapped covering an area of appr. 115.8km2 down to the closing contour of
4100m ss”. Using the same dual-porosity system reservoir parameters as for the Liassic, Cabot have assessed
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possible P50 STOIIP and Prospective Resource Triassic oil volumes of 1,940 MMstb and 380 MMstb
respectively for their Vesta Triassic ‘lead’.
LR have reviewed Cabot’s presentation of this deeper Triassic reservoir target in an interpreted 4-way dip
closed structure. It is considered that there are presently very significant risks on reservoir, seal and structure,
and the source/charge aspects are also somewhat uncertain. The reservoir and seal elements are
demonstrated elsewhere in the area, but the platform-margin location means that finding effective reservoir
and seal in the correct spatial configuration given the lateral facies changes is uncertain. Structure cannot
be mapped on the existing low quality 2D data which does not image the reservoir target. Creating a
structure map by hanging a Liassic-top Gela isopach (based on nearby well Alexia-2) on a top Liassic depth
grid is also considered extremely unreliable, as variation in the true isopach beneath Vesta could dramatically
change the shape of any 4-way dip closure, or completely kill it. LR also note that if a top Triassic depth grid
was created by isochoring down from the current top Liassic depth grid (as used for the Liassic evaluation)
rather than the older version as presented by Cabot, a significantly smaller depth closure would result. It
would thus appear that Cabot’s volumes are likely to be optimistic and also to not reflect the downside
sufficiently.
For these reasons, LR believes the definition of the feature is insufficiently mature to regard it as a lead and
hence that prospective volumes and risks for the feature cannot at this time be reliably estimated. The
acquisition of 3D seismic data would be expected to assist in maturing any potential at this level, provided
that the recording parameters of such survey are designed to image the Triassic as a secondary objective.
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3. References
1. “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve information”, published by the
Society of Petroleum Engineers (SPE) in June 2001, SPE website (www.spe.org).
2. “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information Approved by SPE
Boards June 2001 - Revision as of February 19, 2007”, published by the Society of Petroleum Engineers (SPE);
SPE website (www.spe.org).
3. “Petroleum Resources Management System”, Sponsored by SPE, AAPG, WPC, SPEE, SEG, SPWLA and EAGE,
published 2018; SPE website (www.spe.org).
4. “Petroleum Reserves Definitions” approved by SPE and WPC March 1997; SPE website (www.spe.org).
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Appendix 1 – Lloyd’s Register and Author Credentials
LR is a global engineering, technical and business services organisation wholly owned by the Lloyd’s Register
Foundation, a UK charity dedicated to research and education in science and engineering. Founded in 1760 as a
marine classification society, LR now operates across many industry sectors, with over 8,000 employees based in 78
countries.
In September 2013, Senergy became a member of the LR Group. The LR Group provides a broad service portfolio to
the upstream sector of the energy industry, from reservoir to refinery and beyond. LR specialises in petroleum reservoir
engineering, geology and geophysics and petroleum economics. All of these services are supplied under an accredited
ISO9001 quality assurance system. Except for the provision of professional services on a fee basis, LR has no
commercial arrangement with any person or Company involved in the interest that is the subject of this report.
Jon Wix – Principal Geophysicist
Jon is a highly experienced, and business focused Principal Geophysicist and Technical Project Manager with a strong
record of achievement and extensive experience of international exploration and exploitation projects. With over 30
years of industry experience, he has the ability to work in both leadership and technical roles to deliver successful
projects within timeframes and budgets. Jon also has a demonstrable record of technical excellence and creativity
making a material difference to geoscience challenges. Having a working knowledge of many petroleum basins in
the world, with specialised experience in plays in the North Sea, Africa, Europe, FSU, Americas and the Middle & Far
East, Jon is equally happy working on major integrated studies or short-fuse, dataroom style evaluations. He has broad
experience gained in both operating oil companies (Marathon, Petrobras, Chevron, Hess) and premium consulting
companies (LR Senergy, Gaffney-Cline). Jon holds an MSc in Applied Geophysics and a BSc in Geological Sciences
both from the University of Birmingham.
David Tobias – Head of Reserves and Asset Evaluations
David Tobias is a Geoscientist with a broad commercial and economics background obtained over 40 years in projects
and project management in diverse cultural settings with LR, Texaco, Phillips Petroleum, the Lundin Group, Enterprise
Oil and BHP Billiton Petroleum. Resource assessment and valuation activities span geological and geophysical
interpretation, commercial and economic analysis and petroleum resource classification for fields and prospective
acreage. Worldwide experience with an Africa, Europe, South America and South East Asia focus. David leads the
London-based Reserves and Asset Evaluation team delivering a range of Competent Persons Reports, Due Diligence
Reports and Acreage and Asset Evaluation studies. David (FGS) has a BSc (Hons) Geology, MSc. Marine Geotechnics
and MBA.
Neville Brookes – Principal Commercial Geoscientist
Neville Brookes has a BSc degree in Geology and Chemistry and an MSc in Stratigraphy from London University. He
is a Principal Commercial Geoscientist with over 30 years of oil industry experience working the full exploration-
development-production life cycle for several mid-sized independent oil companies. Neville has a strong technical
background and has working in several world class basins. Neville has extensive experience of geological analyses and
evaluation of oil and gas prospects and fields, including auditing and classification of resources. He is a Fellow of the
Geological Society of London and a member of the AAPG and PESGB.
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Appendix 2 - Resource and Risk Evaluation Method
LR was requested to provide an independent evaluation of the recoverable hydrocarbons expected for the asset.
Standard geological and engineering techniques accepted by the petroleum industry were used in estimating
recoverable hydrocarbons. These techniques rely on engineering and geo-scientific interpretation and judgement;
hence the resources included in this evaluation are estimates only and should not be construed to be exact quantities.
It should be recognised that such estimates may increase or decrease in future if there are changes to the technical
interpretation, economic criteria or regulatory requirements.
The recoverable hydrocarbons expected for each asset are categorised in accordance with the Petroleum Resources
Management System (2018) prepared by the Oil and Gas Reserves Committee of the Society of Petroleum Engineers
(SPE) and reviewed and jointly sponsored by the World Petroleum Council (WPC), the American Association of
Petroleum Geologists (AAPG), the Society of Petroleum Evaluation Engineers (SPEE), the Society of Exploration
Geophysicists (SEG), the Society of Petrophysicists and Well Log Analysts (SPWLA) and the European Association of
Geoscientists & Engineers (EAGE).
Prospective Resources can be defined for projects at one of three stages of maturity: play, lead or prospect. In each
case the opportunities are verified through review of Operator data, studies and maps, and by comparison with
analogue play type and basin information where available.
A prospect is an opportunity at a sufficient level of maturity to be drilled. A lead is an opportunity that requires
additional data and/or analysis before it is considered to be ready for drilling. In addition, LR refer to a potentially
drillable opportunity as a prospect if the database is adequate for us to quantify the potential resource size and
undertake a meaningful risk assessment. If the database is inadequate we assign lead status and assess the resource
size potential of the play to which the lead or leads belong. In some circumstances, a lead may be sufficiently well
defined to quantify the prospective resource size range.
A play is defined as a project associated with a prospective trend of potential prospects, but which requires more data
acquisition and/or evaluation in order to define specific leads or prospects. Project activities are focused on acquiring
additional data and/or undertaking further evaluation designed to define specific leads or prospects for more detailed
analysis of their chance of discovery and, assuming discovery, the range of potential recovery under hypothetical
development scenarios.
Estimating a total resource volume for a portfolio of opportunities can be performed arithmetically or stochastically.
In this report, we have arithmetically summed the predicted low, best and high case volumes.
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Appendix 3 - PRMS Reserves and Resources Definitions
The following figures and tables have been extracted from the 2018 Petroleum Resources Management System (PRMS)
prepared by the Oil and Gas Reserves Committee of the Society of Petroleum Engineers (SPE) and reviewed and jointly
sponsored by the World Petroleum Council (WPC), the American Association of Petroleum Geologists (AAPG) and the
Society of Petroleum Evaluation Engineers (SPEE). The complete document is available from:
https://www.spe.org/en/industry/Petroleum-Resources-Management-System-2018
The following two illustrations;
Figure A1-1 and Figure A1-2 pertain to the Classification Framework and the Project maturity sub-classes of the PRMS,
which are discussed in Table A1-1 to Table A1-3.
Figure A1-1: Petroleum Resources Classification Framework
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Figure A1-2: Project Maturity Sub-Classes
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Class/Sub-Class Definition Guidelines
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.
Reserves must satisfy four criteria: discovered, recoverable, commercial,
and remaining based on the development project(s) applied. Reserves
are further categorized in accordance with the level of certainty
associated with the estimates and may be sub-classified based on
project maturity and/or characterized by the development and
production status.
To be included in the Reserves class, a project must be sufficiently
defined to establish its commercial viability. This includes the
requirement that there is evidence of firm intention to proceed with
development within a reasonable time-frame.
A reasonable time-frame for the initiation of development depends on
the specific circumstances and varies according to the scope of the
project. While five years is recommended as a benchmark, a longer
time-frame could be applied where, for example, development of an
economic project is deferred at the option of the producer for, among
other things, market-related reasons or to meet contractual or strategic
objectives. In all cases, the justification for classification as Reserves
should be clearly documented.
To be included in the Reserves class, there must be a high confidence in
the commercial maturity and economic producibility of the reservoir as
supported by actual production or formation tests. In certain cases,
Reserves may be assigned on the basis of well logs and/or core analysis
that indicate that the subject reservoir is hydrocarbon-bearing and is
analogous to reservoirs in the same area that are producing or have
demonstrated the ability to produce on formation tests.
On Production The development
project is currently
producing and selling
petroleum to market.
The key criterion is that the project is receiving income from sales,
rather than the approved development project necessarily being
complete. Includes Developed Producing Reserves.
The project decision gate is the decision to initiate or continue
economic production from the project.
Approved for
Development
All necessary approvals
have been obtained,
capital funds have been
committed, and
implementation of the
development project is
under way.
At this point, it must be certain that the development project is going
ahead. The project must not be subject to any contingencies, such as
outstanding regulatory approvals or sales contracts. Forecast capital
expenditures should be included in the reporting entity’s current or
following year’s approved budget.
The project decision gate is the decision to start investing capital in the
construction of production facilities and/or drilling development wells.
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.
To move to this level of project maturity, and hence have Reserves
associated with it, the development project must be commercially
viable at the time of reporting and the specific circumstances of the
project. All participating entities have agreed and there is evidence of a
committed project (firm intention to proceed with development within
a reasonable time-frame}) There must be no known contingencies that
could preclude the development from proceeding (see Reserves class).
The project decision gate is the decision by the reporting entity and its
partners, if any, that the project has reached a level of technical and
commercial maturity sufficient to justify proceeding with development
at that point in time.
Contingent
Resources
Those quantities of
petroleum estimated,
as of a given date, to
be potentially
Contingent Resources may include, for example, projects for which
there are currently no viable markets, where commercial recovery is
dependent on technology under development, where evaluation of the
accumulation is insufficient to clearly assess commerciality, where
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Class/Sub-Class Definition Guidelines
recoverable from
known accumulations
by application of
development projects,
but which are not
currently considered to
be commercially
recoverable owing to
one or more
contingencies.
the development plan is not yet approved, or where regulatory or social
acceptance issues may exist.
Contingent Resources are further categorized in accordance with the
level of certainty associated with the estimates and may be sub-
classified based on project maturity and/or characterized by the
economic status.
Development
Pending
A discovered
accumulation where
project activities are
ongoing to justify
commercial
development in the
foreseeable future.
The project is seen to have reasonable potential for eventual
commercial development, to the extent that further data acquisition
(e.g., drilling, seismic data) and/or evaluations are currently ongoing
with a view to confirming that the project is commercially viable and
providing the basis for selection of an appropriate development plan.
The critical contingencies have been identified and are reasonably
expected to be resolved within a reasonable time-frame. Note that
disappointing appraisal/evaluation results could lead to a reclassification
of the project to On Hold or Not Viable status.
The project decision gate is the decision to undertake further data
acquisition and/or studies designed to move the project to a level of
technical and commercial maturity at which a decision can be made to
proceed with development and production.
Development
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.
The project is seen to have potential for commercial development.
Development may be subject to a significant time delay. Note that a
change in circumstances, such that there is no longer a probable
chance that a critical contingency can be removed in the foreseeable
future, could lead to a reclassification of the project to Not Viable
status.
The project decision gate is the decision to either proceed with
additional evaluation designed to clarify the potential for eventual
commercial development or to temporarily suspend or delay further
activities pending resolution of external contingencies.
Development
Unclarified
A discovered
accumulation
where project activities
are under evaluation
and where justification
as a commercial
development
is unknown based on
available information.
The project is seen to have potential for eventual commercial
development, but further appraisal/evaluation activities are ongoing to
clarify the potential for eventual commercial development.
This sub-class requires active appraisal or evaluation and should not be
maintained without a plan for future evaluation. The sub-class should
reflect the actions required to move a project toward commercial
maturity and economic production.
Development
Not Viable
A discovered
accumulation for which
there are no current
plans to develop or to
acquire additional data
at the time because of
limited production
potential.
The project is not seen to have potential for eventual commercial
development at the time of reporting, but the theoretically recoverable
quantities are recorded so that the potential opportunity will be
recognized in the event of a major change in technology or commercial
conditions.
The project decision gate is the decision not to undertake further data
acquisition or studies on the project for the foreseeable future.
Prospective
Resources
Those quantities of
petroleum that are
Potential accumulations are evaluated according to the chance of
geologic discovery and, assuming a discovery, the estimated quantities
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Class/Sub-Class Definition Guidelines
estimated, as of a given
date, to be potentially
recoverable from
undiscovered
accumulations.
that would be recoverable under defined development projects. It is
recognized that the development programs will be of significantly less
detail and depend more heavily on analog developments in the earlier
phases of exploration.
Prospect A project associated
with a potential
accumulation that is
sufficiently well defined
to represent a viable
drilling target.
Project activities are focused on assessing the chance of geologic
discovery and, assuming discovery, the range of potential recoverable
quantities under a commercial development program.
Lead A project associated
with a potential
accumulation that is
currently poorly defined
and requires more data
acquisition and/or
evaluation to be
classified as a Prospect.
Project activities are focused on acquiring additional data and/or
undertaking further evaluation designed to confirm whether or not the
Lead can be matured into a Prospect. Such evaluation includes the
assessment of the chance of geologic discovery and, assuming
discovery, the range of potential recovery under feasible development
scenarios.
Play A project associated
with a prospective
trend of potential
prospects, but that
requires more data
acquisition and/or
evaluation to define
specific Leads or
Prospects.
Project activities are focused on acquiring additional data and/or
undertaking further evaluation designed to define specific Leads or
Prospects for more detailed analysis of their chance of geologic
discovery and, assuming discovery, the range of potential recovery
under hypothetical development scenarios.
Table A1-1: Recoverable Resources Classes and Sub-Classes
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Status Definition Guidelines
Developed
Reserves
Expected quantities to be
recovered from existing
wells and facilities.
Reserves are considered developed only after the necessary equipment has
been installed, or when the costs to do so are relatively minor compared
to the cost of a well. Where required or when facilities become
unavailable, it may be necessary to reclassify Developed Reserves as
Undeveloped. Developed Reserves may be further sub-classified as
Producing or Non-Producing.
Developed
Producing Reserves
Expected to be recovered
from completion intervals
that are open and
producing at the time of
the estimate.
Improved recovery reserves are considered producing only after the
improved recovery project is in operation.
Developed Non-
Producing Reserves
Shut-in and behind-pipe
Reserves.
Shut-in Reserves are expected to be recovered from (1) completion
intervals which are open at the time of the estimate, but which have not
yet started producing, (2) wells which were shut-in for market conditions
or pipeline connections, or (3) wells not capable of production for
mechanical reasons. zones in existing wells that will require additional
completion work or future re-completion before start of production with
minor cost to access these reserves.
In all cases, production can be initiated or restored with relatively low
expenditure compared to the cost of drilling a new well.
Undeveloped
Reserves
Quantities expected to be
recovered through future
investments:
Undeveloped Reserves are to be produced (1) from new wells on undrilled
acreage in known accumulations, (2) from deepening existing wells to a
different (but known) reservoir, (3) from infill wells that will increase
recovery, or (4) where a relatively large expenditure (e.g., when compared
to the cost of drilling a new well) is required to (a) recomplete an existing
well or (b) install production or transportation facilities for primary or
improved recovery projects.
Table A1-2: Reserves Status Definitions and Guidelines
Category Definition Guidelines
Proved Reserves Those quantities of
petroleum that, by
analysis of geoscience
and engineering data, can
be estimated with
reasonable certainty to be
commercially recoverable
from a given date forward
from known reservoirs
and under defined
economic
conditions, operating
methods, and
government regulations.
If deterministic methods are used, the term “reasonable certainty” is
intended to express a high degree of confidence that the quantities will be
recovered. If probabilistic methods are used, there should be at least a
90% probability (P90) that the quantities actually recovered will equal or
exceed the estimate.
The area of the reservoir considered as Proved includes (1) the area
delineated by drilling and defined by fluid contacts, if any, and (2) adjacent
undrilled portions of the reservoir that can reasonably be judged as
continuous with it and commercially productive on the basis of available
geoscience and engineering data.
In the absence of data on fluid contacts, Proved quantities in a reservoir
are limited by the LKH as seen in a well penetration unless otherwise
indicated by definitive geoscience, engineering, or performance data. Such
definitive information may include pressure gradient analysis and seismic
indicators. Seismic data alone may not be sufficient to define fluid contacts
for Proved.
Reserves in undeveloped locations may be classified as Proved
provided that:
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Category Definition Guidelines
A. The locations are in undrilled areas of the reservoir that can be judged
with reasonable certainty to be commercially mature and economically
productive.
B. Interpretations of available geoscience and engineering data indicate
with reasonable certainty that the objective formation is laterally
continuous with drilled Proved locations.
For Proved Reserves, the recovery efficiency applied to these reservoirs
should be defined based on a range of possibilities supported by analogs
and sound engineering judgment considering the characteristics of the
Proved area and the applied development programme.
Probable Reserves Those additional Reserves
that analysis of
geoscience and
engineering data
indicates are
less likely to be recovered
than Proved Reserves but
more certain to be
recovered than Possible
Reserves.
It is equally likely that actual remaining quantities recovered will be greater
than or less than the sum of the estimated Proved plus Probable Reserves
(2P). In this context, when probabilistic methods are used, there should be
at least a 50% probability that the actual quantities recovered will equal
or exceed the 2P estimate.
Probable Reserves may be assigned to areas of a reservoir adjacent to
Proved where data control or interpretations of available data are less
certain. The interpreted reservoir continuity may not meet the reasonable
certainty criteria. Probable estimates also include incremental recoveries
associated with project recovery efficiencies beyond that assumed for
Proved.
Possible Reserves Those additional reserves
that analysis of
geoscience and
engineering data
indicates are less likely to
be recoverable than
Probable Reserves.
The total quantities ultimately recovered from the project have a low
probability to exceed the sum of Proved plus Probable plus Possible (3P),
which is equivalent to the high-estimate scenario. When probabilistic
methods are used, there should be at least a 10% probability (P10) that
the actual quantities recovered will equal or exceed the 3P estimate.
Possible Reserves may be assigned to areas of a reservoir adjacent to
Probable where data control and interpretations of available data are
progressively less certain. Frequently, this may be in areas where
geoscience and engineering data are unable to clearly define the area and
vertical reservoir limits of economic production from the reservoir by a
defined, commercially mature project.
Possible estimates also include incremental quantities associated with
project recovery efficiencies beyond that assumed for Probable.
Probable and
Possible Reserves
See above for separate
criteria for Probable
Reserves and Possible
Reserves.
The 2P and 3P estimates may be based on reasonable alternative technical
and commercial interpretations within the reservoir and/or subject project
that are clearly documented, including comparisons to results in successful
similar projects.
In conventional accumulations, Probable and/or Possible Reserves may be
assigned where geoscience and engineering data identify directly adjacent
portions of a reservoir within the same accumulation that may be
separated from Proved areas by minor faulting or other geological
discontinuities and have not been penetrated by a wellbore, but are
interpreted to be in communication with the known (Proved) reservoir.
Probable or Possible Reserves may be assigned to areas that are structurally
higher than the Proved area. Possible (and in some cases, Probable)
Reserves may be assigned to areas that are structural lower than the
adjacent Proved or 2P area.
Caution should be exercised in assigning Reserves to adjacent reservoirs
isolated by major, potentially sealing, faults until this reservoir is penetrated
and evaluated as commercially productive. Justification for assigning
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Category Definition Guidelines
Reserves in such cases should be clearly documented. Reserves should not
be assigned to areas that are clearly separated from a known accumulation
by non-productive reservoir (i.e., absence of reservoir, structurally low
reservoir, or negative test results); such areas may contain Prospective
Resources.
In conventional accumulations, where drilling has defined a highest known
oil elevation and there exists the potential for an associated gas cap, Proved
oil Reserves should only be assigned in the structurally higher portions of
the reservoir if there is reasonable certainty that such portions are initially
above bubble point pressure based on documented engineering analyses.
Reservoir portions that do not meet this certainty may be assigned as
Probable and Possible oil and/or gas based on reservoir fluid properties and
pressure gradient interpretations.
Table A1-3: Reserves Category Definitions and Guidelines
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Nomenclature
Variable Meaning Units
2D Two dimensional
3D Three dimensional
1U Denotes the unrisked low estimate qualifying as Prospective Resources
2U Denotes the unrisked best estimate qualifying as Prospective Resources
3U Denotes the unrisked high estimate qualifying as Prospective Resources
AAPG American Association of Petroleum Geologists
API American Petroleum Institute Api
bbl/d Barrels per day bbl/d
Best Estimate With respect to resources categorisation, the most realistic assessment of
recoverable quantities if only a single result were reported. If probabilistic
methods are used, there should be at least a 50% probability (P50) that the
quantities are actually recovered will equal or exceed the best estimate
Bscf Billions of standard cubic feet Bscf
COD (PRMS 2018) Chance of Development is the estimated probability that a known
accumulation, once discovered, will be commercially developed
COGD (PRMS 2018) Chance of Geologic Discovery the estimated probability that exploration
activities will confirm the existence of a significant accumulation of
potentially recoverable petroleum
Contingent Resources Contingent Resources are 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 owing to one or more contingencies
d Day d
DST Drill stem test
º F / º C Degrees Fahrenheit / Centigrade
EAGE European Association of Geoscientists and Engineers
EUR Estimated ultimate gas recovery
GRV Gross Rock Volume
Mean The arithmetic average of a set of values ft or m
m ss Meters subsea
MM Million
MM m3 Million cubic meters
MMbbl Million barrel/s
MMbo Million barrels of oil
MMboe Millions of barrels of oil equivalent
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MMscf/d Million standard cubic feet per day
MMstb Millions of barrels of stock tank oil
OWC Oil water contact
P99 The probability of that a stated volume will equal or exceed. In this example
a 99% chance that the actual volume will be greater than or equal to that
stated.
PRMS Petroleum Resources Management System
Producing Related to development projects (e.g. wells and platforms): Active facilities,
currently involved in the extraction (production) of hydrocarbons from
discovered reservoirs.
Prospective Resources Prospective Resources are those quantities of petroleum estimated, as of a
given date, to be potentially recoverable from undiscovered accumulations
by application of future development projects. Prospective Resources have
both an associated chance of geologic discovery and a chance of
development.
Proved Proved Reserves are those quantities of petroleum, which, by analysis of
geosciences and engineering data, can be estimated with reasonable
certainty to be commercially recoverable, from a given date forward, from
known reservoirs and under defined economic conditions, operating
methods, and government regulations. If deterministic methods are used,
the term reasonable certainty is intended to express a high degree of
confidence that the quantities will be recovered. If probabilistic methods are
used, there should be at least a 90% probability that the quantities actually
recovered will equal or exceed the estimate.
Proved plus Probable Probable Reserves are those additional Reserves which analysis of
geosciences and engineering data indicate are less likely to be recovered
than Proved Reserves but more certain to be recovered than Possible
Reserves. It is equally likely that actual remaining quantities recovered will be
greater than or less than the sum of the estimated Proved plus Probable
Reserves (2P). In this context, when probabilistic methods are used, there
should be at least a 50% probability that the actual quantities recovered will
equal or exceed the 2P estimate.
Proved plus Probable
plus Possible
Possible Reserves are those additional reserves which analysis of geosciences
and engineering data suggest are less likely to be recoverable than Probable
Reserves. The total quantities ultimately recovered from the project have a
low probability to exceed the sum of Proved plus Probable plus Possible (3P)
Reserves, which is equivalent to the high estimate scenario. In this context,
when probabilistic methods are used, there should be at least a 10%
probability that the actual quantities recovered will equal or exceed the 3P
estimate.
psi Pounds per square inch psi
PRJ11086541 / November 2018
www.lr.org 23 Final
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. Reserves must further
satisfy four criteria: they must be discovered, recoverable, commercial, and
remaining (as of the evaluation date) based on the development project(s)
applied. Reserves are further categorised in accordance with the level of
certainty associated with the estimates and may be sub-classified based on
project maturity and/or characterized by development and production
status.
RF Recovery Factor dec
or %
scf Standard cubic foot scf
SEG Society of Exploration Geophysicists
SPE Society of Petroleum Engineers
SPEE Society of Petroleum Evaluation Engineers
SPWLA Society of Petrophysicists and Well Log Analysts
stb/d Stock tank barrels per day stb/d
STOIIP Stock tank oil initially in place
TD Total depth
TVDSS True vertical depth sub-sea ft or m
WPC World Petroleum Council
PRJ11086541 / November 2018
www.lr.org 24 Final
Figures
Figure 2.1 – Location of Licenses C.R146.NP & C.R149.NP
Lloyd's Register 1
Source: Cabot/LR
Approximate marginof Siracusa Platform
Figure 2.2 – Vega Field Seismic & Structure
Lloyd's Register 2
Source: Cabot
NB: Mapped LCC corresponds
with OOWC @2,750 m TVDSS
Figure 2.3 – Vesta Play Concept
Lloyd's Register 3
Source: Cabot
South North
proposed
Figure 2.4 – Better Quality 2D Seismic Data Example
Lloyd's Register 4
Source: LR
Top Liassic grid Cyan
SW NE
Top Liassic horizon Yellow
Cabot possible Top Triassic grid Green
Figure 2.5 – Poorer Quality 2D Seismic Data Example
Lloyd's Register 5
Source: LR
SW NE
Top Liassic grid Cyan
Top Liassic horizon Yellow
Cabot possible Top Triassic grid Green
Figure 2.6 – Mapping Basis for Low/Best/High GRVs
Lloyd's Register 6
Source: LR
LR Best Case GRV‘Full to Spill’lcc 2,910 m TVDSS
LR/Cabot High Case GRVlcc 3,190 m TVDSS
Cabot Low Case GRVlcc 2,875 m TVDSS
LR Low Case GRV
lcc 2,825 m TVDSS (half max Vega column of 310 m, so
crest 2670+155 m)
Spill Point
Cabot Top Liassic Depth Grid (c.i.=30 m)
LR ‘P1’ Case GRVlcc 3,280 m TVDSS
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