Licence P1578 Block 13/22b including Phoenix Discovery · Seismic interpretation, petrophysical,...
Transcript of Licence P1578 Block 13/22b including Phoenix Discovery · Seismic interpretation, petrophysical,...
Licence P.1578 Relinquishment Report - March 2015 Page 1 of 16
Relinquishment Report
for
Licence P1578
Block 13/22b including Phoenix Discovery
March 2015
N
Top Phoenix
Reservoir level
Depth ft TVDSS
Phoenix
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Contents
Page
1. Licence Information 3
2. Synopsis 4
3. Exploration & Development Activities 4
4. Phoenix Resource Analysis 8
5. Analysis of Other Potential Resources 12
6. Clearance 16
Tables
Table 1 Details of Licence Award
Table 2 Phoenix Total Gas & Condensate in Place (assuming flash separation)
Table 3 Recoverable Sales Gas & Condensate Resources for Phoenix Development via a
nearby host field and infrastructure
Table 4 Probabilistic Modelling Inputs and Outputs for Phoenix Deep Lead
Table 5 Geological Chance of Success Assessment for the Phoenix Deep Lead
Table 6 Probabilistic Modelling Inputs and Outputs for Ashes Lead
Table 7 Geological Chance of Success Assessment for the Ashes Lead
Figures
Figure 1 Geographic Setting of UK Block 13/22b and the Phoenix Discovery
Figure 2 Block 13/22b Time Structure at Top Phoenix Reservoir (mS)
Figure 3 North-South Geoseismic Section to Illustrate Structural Character of Phoenix
Figure 4 Petrophysical Interpretation of Phoenix Discovery and Associated DST Results
Figure 5 Phoenix Depth Structure
Figure 6 Structural Cross-section Phoenix Geocellular Model
Figure 7 Phoenix Reservoir Correlation
Figure 8 Optimal Horizontal Well Design Determined for Phoenix
Figure 9 Ashes Lead at Top Phoenix Reservoir Level
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1. Licence Information
Licence Number P1578
Round & Start Date 25th
Licence Type Traditional
Licence Start Date 12/02/2009
Block 13/22b
Equity Holding Chrysaor (CNS) Limited 100%
Work Program Summary Drill or Drop Commitment Drill one well to 3625m or 150m below the top Phoenix reservoir, whichever is the shallower
Relinquishment 11/12/2014
Table 1 Details of Licence Holding
Figure 1 Geographic Setting of UK Block 13/22b and the Phoenix Discovery
PHOENIX
CAPTAIN
ROSSBLAKE
ATLANTIC/CROMARTY
BEATRICE
St.Fergus.
13/22b
13/22c
13/22d
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2. Synopsis
Licence P1578 was awarded to Chrysaor Limited on 16 March 2009 with a start date of 12 February
2009. The basis of the Chrysaor application for block 13/22b was the Phoenix gas condensate
accumulation discovered in 1990 which Chrysaor believed to be commercially developable as a
single well tieback to existing infrastructure provided it could reach satisfactory transportation,
processing and tie-in agreements. The accumulation, which is well defined on 3D seismic, is
considered to be adequately appraised by the existing discovery well and associated production
tests.
Technical studies over the course of the P1578 licence strongly supported the technical feasibility of
Phoenix development as a single well tieback but it has proved impossible to reach an acceptable
commercial agreement with any of the local infrastructure owners. In part this reflects the relatively
high CO2 and liquids content of the produced fluid, which is particularly challenging for a small gas
accumulation. Chrysaor tried a number of different approaches to progress the development of
Phoenix, and ultimately agreed to purchase a nearby field interest and associated infrastructure with
the aim of redeveloping it jointly with Phoenix. This redevelopment would have had particular
synergy for both fields, with P50 sales gas resources for Phoenix estimated as 32 Bscf and
incremental liquids production as 3.8mmbc.
After reaching agreement to acquire that nearby field, Chrysaor requested and obtained a licence
extension for Phoenix and committed to drilling of the Phoenix development well to fulfil the licence
conditions. Unfortunately the asset purchase was subsequently pre-empted. Chrysaor was
therefore forced to relinquish the licence as there was then no commercial or technical justification
for drilling a well in the absence of an export route.
3. Exploration & Development Activities
Block 13/22b was applied for by Chrysaor solely on the basis of the Phoenix accumulation, a gas
condensate discovery within the Banff sub-basin of the Moray Firth area.
3.1 Seismic
Block 13/22b is fully covered by the PGS Megamerge 3D. There is no material structural closure
within block 13/22b down to Base Cretaceous. However, small tilted fault blocks are developed
within the Jurassic sequence, one of which provided structural closure for the Phoenix accumulation
(Figures 2, 3). The next tilted fault block to the south and the only other closure within the licence
areas was tested by dry well 13/22b-19. Another dry hole targeting the same stratigraphic level
13/22c-30 was drilled some three kilometres to the south east.
The quality of the data is good and the Phoenix structure itself is small but well defined.
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Figure 2 Block 13/22b Time Structure at Top Phoenix Reservoir (mS)
Figure 3 North-South Geoseismic Section to Illustrate Structural Character of Phoenix
Hallibut Horst Southern Bounding Fault
Top Phoenix Reservoir
Depth Structure (ft TVDSS)
N
13/22b
Top Phoenix Reservoir Time Structure (mS)
NORTH SOUTH
13/22B-4
DISCOVERY
13/22B-19
DRY HOLE
Hydrocarbon
kitchen -
Jurassic “Hot
Shales” deeply
buried.
HALIBUT
HORST
Reservoir section
Seismic Data Courtesy of PGS
Hallibut Horst Southern Bounding Fault
Top Phoenix Reservoir
Depth Structure (ft TVDSS)
N
13/22b
Line of section
Top Phoenix Reservoir Time Structure (mS)
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3.2 Wells
The only well on the licence area is 13/22b-4, drilled by Kerr McGee in 1990 to a total depth of
13670ft MD within Permian subcrop. This well discovered the Phoenix accumulation trapped within
deepwater sand reservoirs of Lower Volgian age towards the base of the Kimmeridge Clay (Figure 4).
Figure 4 Petrophysical Interpretation of Phoenix Discovery and Associate DST Results
DST-2
11,498 – 11,798 ft MD
Cond. Rate = 3898 stb/d
Gas Rate = 17.2 MMSCFD
CGR = 227 STB/MMSCF
80/64” Choke
DST-1
11,895 – 11,826 ft MD
Cond. Rate = 1146 stb/d
Gas Rate = 5.2 MMSCFD
CGR = 221 STB/MMSCF
64/64” Choke
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Average porosity within the net reservoir of the Phoenix accumulation is just under 10%, average
hydrocarbon saturation relatively low at around 60% and the reservoir is normally pressured.
However the well was successfully flowed at a rate 17.2mmscf/day + 3,898bcpd consistent with
average DST permeability 1-2mD.
Shows were also encountered within the poor quality Rhaxella Spiculite at base Jurassic but the
underling Permian sands were water-wet.
3.3 Studies
Seismic interpretation, petrophysical, geological and reservoir engineering studies were undertaken
during 2008/2009 prior to and immediately after licence award, resulting in development of an
integrated geoscience model covering the whole of the licensed acreage with detailed Petrel/Eclipse
models for the Phoenix accumulation.
Subsequent geotechnical work has concentrated on upgrading the Phoenix simulation model from
black oil to fully compositional, refining the compositional model with improved equation of state
modelling collection/understanding of performance information from producing analogues (work
conducted in-house as well as on behalf of Chrysaor by Senergy, Petrophase and OPC between 2010
and 2013). The refined compositional simulation model was then used to carry out detailed
development well optimisation work (Chrysaor 2013) and provide information for detail process
design in different export scenarios (both in-house and through Atkins/ODE in 2013 and 2014). The
most recent studies are summarized in a Competent Persons Report produced by Senergy in June
2014.
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4. Phoenix Resources Analysis
4.1 Structural Definition
The Phoenix field is a three way dip closure that is fault bounded to the south (Figures 5 & 6).
Figure 5 Phoenix Depth Structure
Figure 6 Structural Cross-section Phoenix Geocellular Model
N
Top Phoenix
Reservoir level
Depth ft TVDSS
Phoenix
Phoenix FWL
NorthSouth
Well 13/22b-4Gamma Ray Signature
UMA
MMA
LMA
Phoenix FWL 11842ft TVDSS
Phoenix Crest c 11050ft TVDSS in this line of section
1 km
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Simple structuring, good quality seismic data, small size and central control well tying down the gas-
water contact mean that uncertainty in Phoenix gross rock volume is low. The gas column extends
significantly below the pure elevation closure, indicating that the southern bounding fault of the
field is an effective gas seal.
Depth conversion uncertainty at the FWL is unlikely to exceed +/- 50ft. It is possible in a downside
scenario that the low throw WNW/SSE cross-faults downdip in the eastern part of the field may act
as material production baffles for about 10% of GIIP.
4.2 Reservoir Architecture and Quality
Major reservoir units in 13/22b-4 correlate excellently into 13/22b-19 just over 2km away, with no
significant changes in reservoir quality (Figure 7).
Figure 7 Phoenix Reservoir Correlation
Section flattened on ASD3
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Detailed pressure data and compositional variation between DST1 and DST2 suggest that unit ADS2,
the 28ft thick mudstone whose top lies at 11700ft TVDSS, is a fieldwide pressure barrier. However,
most of the reservoir within closure should be connected to a single suitably planned producer.
Reservoir quality is modest with well test analysis suggesting an overall permeability to hydrocarbon
of 1-2mD. From a practical viewpoint development is best undertaken with a near horizontal well
cutting stratigraphy close to the crest of the structure in order to minimise the risk of water influx
(Figure 8). To maximise condensate recovery and total economic value (if produced through the
nearby field and its infrastructure) it was also desirable to restrict Phoenix off-take rate to maximum
25mmscf/day at wellhead.
Figure 8 Optimal Horizontal Well Design Determined for Phoenix (via a nearby host field)
Top Reservoir Structure Map
H4a
Well Surface LocationReservoir Entry PointReservoir Completion Zone
W E
AAUUMA
MMA
LMA
MAD
IAU
FWL -11842 ft TVDss
400 ft 250 m
H4a Short
Reservoir Completion Zone
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4.3 Hydrocarbon Quality
RFT data and DST build-up data indicate the Phoenix accumulation is normally pressured with a
reference pressure of 5,348psia and a temperature of 213oC at the predicted hydrocarbon water
contact of 11,842ft TVDSS.
The overall pressure gradient in the hydrocarbon bearing interval of DST 2 is 0.196psi/ft. This is in
line with expectations from PVT data which suggest a rich retrograde gas condensate with a
dewpoint of 5,225psia, only a little below its current reservoir pressure. This notwithstanding,
detailed analysis of the well test and fluid samples suggest liquid condensate in the reservoir was
mobile, at least within the condensate bank adjacent to the well where flow velocities were high.
Around 12% of the total well-stream composition was CO2 which helps condensate mobility even
though it is an undesirable impurity that needs to be removed from sales gas.
4.4 Resource Estimation
Latest estimates of Phoenix Gas and Condensate in place are summarised below:
Total Gas and Condensate Initially in Place for Phoenix (assuming flash separation)
P90 P50 P10
Gas (bscf) 78.3 103.9 129.9
Condensate (mmstb) 13.9 18.5 23.1
Total (mmboe) 27.4 36.4 45.5
Table 2 Phoenix Total Gas & Condensate in Place (assuming flash separation)
Recoverable sales resource volumes estimates depend on precise development, detailed process
design, fuel losses and commercial cut-off of the host facilities (as well as Phoenix itself). The balance
of gas and condensate is also impacted by the desired plateau production rate and the properties of
other fluids being co-processed. The resource estimates below are based on simple depletion with
detailed process engineering of liquids/CO2 separation processes for co-production with host field
fluids. This gives an 18% increase in condensate recovery compared to flash separation of fluids
produced at wellhead, though sales gas is reduced to 77.4% of total flash gas.
Recoverable Resources for Planned Phoenix Development 2014 (Host Process Separation)
P90 Simulation P50 Simulation P10 Simulation
Sales Spec Gas (bscf) 25.0 32.1 37.4
Condensate (mmstb) 2.9 3.8 4.6
Total (mmboe) 7.2 9.3 11.1
Table 3 Recoverable Sales Gas & Condensate Resources for Phoenix Development via nearby
host field and infrastructure
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The relatively low recovery of condensate reflects the reservoir being close to dewpoint at initial
conditions, with most produced early in the production profile. Gas cycling is not commercially
practical for such a small low permeability accumulation with the field best developed through a
single horizontal producer whose design is shown in Figure 8 (maximising spread of depletion while
contacting all reservoir units directly and maintaining offset from aquifer in a single drillable well).
The relatively low recovery factor for sales gas primarily reflects the low permeability of the
reservoir, the impact of CO2 removal and the impact of fuel deductions to power facilities.
4.5 Export Options
Technically, with the support of suitable infrastructure owners, it would be possible to engineer a
subsea development to onshore processing or to nearby facilities in the Moray Firth for offshore
processing followed by gas export or fuel use.
However the small size of the accumulation, combined with the challenge of processing high CO2
condensate rich gas (even as a fuel) and a changing tax situation has limited the desire of
infrastructure holders to host Phoenix facilities. Initial plans to use the Atlantic-Cromarty pipeline to
export onshore for processing floundered following the tax changes of 2010/2011. Subsequent
plans for processing to sales specifications offshore through a nearby host field and infrastructure
floundered when other partners pre-empted sale of the asset to Chrysaor.
In the absence of a commercial development option, it is not possible to justify drilling a
development well on Phoenix. Nor is it possible to justify an appraisal well on Phoenix that is
considered technically unnecessary or an offset exploration well where there is considered to be
zero chance of commercial success.
5. Analysis of Other Potential Resources
5.1 Phoenix Deep Lead
Although the Permian sands encountered by 13/22b-4 were water-wet, the crest of the Phoenix
structure at Permian level lies some 500ft above this with some attic potential at this level, the
Phoenix Deep Lead.
Although the Phoenix Deep structure is robust, there is a significant angular unconformity between
the Permian and the overlying Jurassic with the former dipping more steeply to the north and west.
As a result, the Permian sand unit proven by 13/22b-4 is partially eroded at the south-eastern
extremity of the structure at either the Base Triassic or the Base Jurassic unconformity. This
introduces the possibility of leakage to Rhaxella Sand waste zone if the Smith Bank Shale is missing.
Although the existence of some potential trapping geometry is highly likely, associated GRV is
uncertain. The distribution used in probabilistic modelling is tied by a downside where sand is
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restricted to the interval that was seen in 13/22b-4 while the upside assumes the Permian sub-crop
is sandy right across closure. Details of the resource potential and risking are tabulated below.
Property Distribution
Type P90 Tie P10 Tie
Low End
Truncation
High End
Truncation
Gross Rock Volume (millions of m3) Lognormal 37 88 20 125
Mean Volumetric Net: Gross Ratio Lognormal 0.3 0.6 0.2 0.85
Mean Porosity in Net Sand (%) Uniform 8 12 7.5 12.5
Mean Gas Saturation in Net Pay (%) Uniform 39 71 35 75
Wellhead Dry Gas Expansion Factor (scf/rcf) Normal 200 248 180 270
Condensate Gas Ratio (bc/mmscf dry gas) Normal 193 223 180 236
Dry Wellhead Gas Recovery Efficiency (%) Normal 50 65 45 70
Condensate Recovery Efficiency (%) Uniform 11 19 10 20
Loss to Sales Gas (%) Uniform 11 16.5 8.0 19.5
Output Prediction P90 Mode P50 Mean P10
Gas Initially in Place (bscf) 5 7 10 12 20
Condensate Initially in Place (mmbc) 1.0 1.3 1.9 2.2 3.8
Sales Gas (bscf) 2.4 4 5.0 5.8 10.0
Sales Condensate (mmbc) 0.1 0.2 0.3 0.3 0.6
Total Oil Equivalent Sales (mmboe) 0.6 0.9 1.1 1.3 2.3
Table 4 Probabilistic Modelling Inputs and Outputs for Phoenix Deep Lead
Risk Factor Chance of
Success (%)
Reservoir Effectiveness (chance of commercial reservoir thickness and deliverability) 70
Hydrocarbon Charge (chance of adequate charge to fill trap to modelled capacity) 80
Seal Effectiveness (chance of adequate lateral and vertical containment since time of migration) 30
Trap Definition (chance of minimum geometry being present) 100
POSg Overall 17
Table 5 Geological Chance of Success Assessment for the Phoenix Deep Lead
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The small resource potential of the Phoenix Deep Lead combined with its low chance of success rules
it out as an attractive incremental exploration target.
5.2 Ashes Lead
The Ashes Lead is the potential attic volume within the fault block tested by 13/22b-19.
Figure 9 Ashes Lead at Top Phoenix Reservoir Level
Trap definition is fairly robust, although the seismic image is not as good as at Phoenix. Hydrocarbon
charging is considered to be low risk, as the fault block would be able to access the same
hydrocarbon kitchen that sources Phoenix itself. All of the properties of the reservoir and fluids are
expected to be similar to those in the Phoenix accumulation, or even slightly improved, as this
culmination is at a depth of 10,500’ss, about 1,000’ shallower than the Phoenix discovery.
Seal effectiveness is a major risk for the Ashes Lead. The first element of this is that the overall trap
relies on a downthrown-to-the-north fault at the south-western end of the feature to seal (marked
in red on the map in Figure 9). This is possible but carries a high level of risk, as the fault throw is
small and the juxtaposition across the fault will be Phoenix Reservoir against Phoenix Reservoir, not
an ideal scenario for trapping hydrocarbons. The fault throw varies from less than 50’ to perhaps
150’, while the Phoenix Reservoir is about 600’ thick. The crestal part of the Ashes feature is in
contact with this fault.
Ashes Lead
Key geological risk is downthrown fault seal
highlighted in red
Top Phoenix Reservoir
Depth Structure (ft TVDSS)
Hallibut Horst Southern Bounding Fault
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The second element of seal effectiveness risk is on the main south-downthrown bounding fault.
Although this fault provides upthrown closure, it has a maximum throw of about 250’. This throw
does not offset the reservoir completely, and so it is necessary to have shale smear across the fault
to seal more than a 250’ column. The lead itself has a vertical relief of about 600’ on the structure
above the penetration at the 13/22b-19 location but is very narrow giving low GRV potential.
Because seal capacity is a big volumetric uncertainty, it is modelled separately as a fill proportion
variable separate to conventional GRV uncertainty related to seismic picking and depth conversion.
Fill proportion is modelled as between 40 and 100% on the basis that any exploration well drilled as
production keeper would need be drilled at the centre of the potential accumulation and have failed
geologically if it did not prove fill of at least 40% fill. Above this there is no rationale to pick a most
likely fill so a uniform distribution is used. Hydrocarbon properties and dynamic performance of any
accumulation are expected to be similar to those of the Phoenix Field.
Property Distribution
Type P90 Tie P10 Tie
Low End
Truncation
High End
Truncation
Gross Rock Volume (millions of m3) Lognormal 68 92 55 110
Fill Proportion Uniform 44 66 40 70
Mean Volumetric Net: Gross Ratio Lognormal 0.4 0.6 0.3 0.7
Mean Porosity in Net Sand (%) Normal 8.6 10.6 7.7 11.5
Mean Gas Saturation in Net Pay (%) Normal 40 60 35 70
Wellhead Dry Gas Expansion Factor (scf/rcf) Normal 200 248 180 268
Condensate Gas Ratio (bc/mmscf dry gas) Normal 193 223 180 236
Dry Wellhead Gas Recovery Efficiency (%) Normal 51 67 43 75
Condensate Recovery Efficiency (%) Custom (8.8) (16.3) 7.0 20
Loss to Sales Gas (%) Normal 11.0 16.5 8.0 19.5
Output Prediction P90 Mode P50 Mean P10
Gas Initially in Place (bscf) 5.1 6.5 7.9 8.3 12.0
Condensate Initially in Place (mmbc) 1.0 1.2 1.5 1.6 2.3
Sales Gas (bscf) 2.5 3.3 4.0 4.2 6.2
Sales Condensate (mmbc) 0.10 0.15 0.18 0.19 0.30
Total Oil Equivalent Sales (mmboe) 0.54 0.75 0.86 0.92 1.35
Table 6 Probabilistic Modelling Inputs and Outputs for Ashes Lead
Risk Factor Chance of
Success (%)
Reservoir Effectiveness (chance of commercial reservoir thickness and deliverability) 95
Hydrocarbon Charge (chance of adequate charge to fill trap to modelled capacity) 95
Seal Effectiveness (chance of adequate lateral and vertical containment since time of migration) 15
Trap Definition (chance of minimum geometry being present) 95
POSg Overall 13
Table 7 Geological Chance of Success Assessment for the Ashes Lead
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Given its very small size, high estimated risk and requirement for a dedicated well, it is unlikely that
drilling of the Ashes lead will ever be commercially attractive.
6. Clearance
The Management of Chrysaor has reviewed this document and verified that DECC is free to publish
it.
The annotated seismic line is based on PGS Megamerge data and its inclusion has been approved by
them as the data owner.
No liability whatsoever is accepted by Chrysaor Holdings Limited or Chrysaor CNS Limited in respect
of the contents of this relinquishment report and no representation, warranty or undertaking is or
will be made regarding the information herein contained.