licence p1578 block 13/22b including phoenix discovery · seismic interpretation, petrophysical,...

Licence P.1578 Relinquishment Report - March 2015 of 16

Relinquishment Report

for

Licence P1578

Block 13/22b including Phoenix Discovery

March 2015

N

Top Phoenix

Reservoir level

Depth ft TVDSS

Phoenix


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


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


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.


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




N

13/22b

Line of section

Top Phoenix Reservoir Time Structure (mS)


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


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.


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


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


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


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


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


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


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





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


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.

licence p1578 block 13/22b including phoenix discovery · seismic interpretation, petrophysical,...

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