[1]
Fairfield Cedrus Limited
Bayerngas Europe Limited
UKCS Licence P1746
Blocks 48/11c and 48/12b
Relinquishment Report
January 2015
Fairfield Cedrus Limited
January 2015
Relinquishment Report
P.1746
[2]
Table of Contents
1. Licence Information ......................................................................................................................... 3
1.1 Summary ..................................................................................................................................... 3
1.1.1 Area Affected ...................................................................................................................... 4
1.2. History ........................................................................................................................................ 5
2.0 Field and Reservoir Description .................................................................................................. 6
2.1 Seismic Interpretation ............................................................................................................... 6
2.2 Reservoir Quality ....................................................................................................................... 8
2.6 Initial Reservoir Pressure and Temperature........................................................................ 10
2.7 Fluid Composition .................................................................................................................... 12
2.8 Gas and Water Properties ...................................................................................................... 14
3.0 Static Reservoir Model ................................................................................................................ 15
3.1 Gas Initially In Place ................................................................................................................ 17
4.0 Dynamic Reservoir Model .......................................................................................................... 19
4.1 Conclusions .............................................................................................................................. 22
5. Clearance ........................................................................................................................................ 23
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1. Licence Information
Licence Number: P.1746
Licence Round: 26th
Licence Type: Traditional
Block Number(s): 48/11c and 48/12b
Operator: Fairfield Cedrus Limited (50%)
Partners: Bayerngas Europe Limited (50%)
Work Programme Summary:
DRILL OR DROP WORK PROGRAMME
The Licensee shall reprocess 192km2 of 3D seismic data to PreSDM.
The Licensee shall drill one well on the Glein discovery to 60m below the top Leman
sandstone; provided that he shall not be required to do so and the licence shall expire at the
end of the initial term if the Minister confirms in writing that he agrees that it would not be an
appropriate use of resources, having regard to the policy objective of maximising successful
and expeditious exploration and exploitation of the UK’s oil and gas resources, information
available to him at the time, and in particular the evaluation of the following technical study:
the interpretation of the reprocessed 3D seismic data showing a robust Glein Discovery
structure.
1.1 Summary
The Licence P.1746 comprises blocks 48/11c and 48/12b (figure 2.1), was awarded to
Fairfield Cedrus Limited (50% Operator) and Bayerngas Europe Limited (50%) in the 26th
Seaward Licensing Round.
The Licence was awarded on the basis of a traditional four year period beginning 10th
January 2011. The Licence commitment was met by the reprocessing of 192km2 3D seismic
data through to Pre-SDM, which covers the whole of the licence. The contingent well
commitment was waived by DECC in a letter dated 5th December 2014.
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1.1.1 Area Affected
Nearby fields to the license P.1746 include Perenco’s West Sole field (formerly owned by
BP) approximately 5km to the north and the Pickerill field which lies 11km to the south, see
figure 1.1.
Block 48/11c is the region bounded by the following coordinates.
(1)
53° 40’00.000”N 1° 00’00.000”E
(2)
53° 40’00.000”N 1° 12’00.000”E
(3)
53° 33’00.000”N 1° 12’00.000”E
(4)
53° 33’00.000”N 1° 10’00.000”E
(5)
53° 34’00.000”N 1° 10’00.000”E
(6)
53° 34’00.000”N 1° 05’00.000”E
(7)
53° 35’00.000”N 1° 05’00.000”E
(8)
53° 35’00.000”N 1° 02’00.000”E
(9)
53° 37’00.000”N 1° 00’00.000”E
(10)
53° 37’00.000”N 1° 00’00.000”E
(11)
53° 40’00.000”N 1° 00’00.000”E
The above coordinates were specified using “European Datum 1950”. The lines joining
coordinates (1) to (11) are navigated as loxodromes.
Block 48/12b is the region bounded by the following coordinates.
(1)
53° 40’00.000”N 1° 12’00.000”E
(2)
53° 40’00.000”N 1° 14’00.000”E
(3)
53° 38’00.000”N 1° 14’00.000”E
(4)
53° 38’00.000”N 1° 17’00.000”E
(5)
53° 34’00.000”N 1° 17’00.000”E
(6)
53° 34’00.000”N 1° 19’00.000”E
(7)
53° 33’00.000”N 1° 19’00.000”E
(8)
53° 33’00.000”N 1° 18’00.000”E
(9)
53° 32’00.000”N 1° 18’00.000”E
(10)
53° 32’00.000”N 1° 16’00.000”E
(11)
53° 33’00.000”N 1° 16’00.000”E
(12)
53° 33’00.000”N 1° 15’00.000”E
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(13)
53° 34’00.000”N 1° 15’00.000”E
(14)
53° 34’00.000”N 1° 12’00.000”E
(15)
53° 40’00.000”N 1° 12’00.000”E
The above coordinates were specified using “European Datum 1950”. The lines joining
coordinates (1) to (15) are navigated as loxodromes.
Figure 1.1: Location map showing the P.1746 Licence and the 48/11 and 48/12b Blocks.
1.2. History
This report covers the Glein gas discovery, located in blocks 48/11c and 48/12b of
the UK Sector, Southern North Sea. The Glein discovery is approximately 70km to
the north of the Norfolk coast in water depth of 83ft. Five wells lie within the licence
area; 48/11b-3 (1977), 48/12b-3z (1985), 48/12b-5 (1988), 48/11a-12 (1994) and
48/11c-13 (2007).
Glein was discovered by the 48/11a-12 well, drilled by ARCO in 1994 was designed
to target a fault bounded and inverted anticline structure to the south of BP’s West
Sole field. The well encountered 499ft of Rotliegendes sandstone and a full gas
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column. This well was subsequently tested and flowed at a rate of 0.4mmscf/d, with
initial estimates of reservoir permeability in the range of 0.1 to 0.7mD.
The Gas Initially In Place (GIIP) estimates confirmed by the 48/11a-12 well and
resulting from the field modelling are estimated to be in the range of 86 to 126 BCF.
2.0 Field and Reservoir Description
2.1 Seismic Interpretation
The principal seismic data volume used for the evaluation of the Glein discovery was
the Ion-GXT 2011 reprocessing of three separate 3D seismic surveys, through to
PreSDM. The well-ties at the 48/11a-12, 48/12b-3z and 48/12b-5 wells were
examined using synthetics but this did not change the location of the Top
Rotliegendes horizon pick at any of the well locations. However the Top
Carboniferous pick was adjusted by a cycle at the 48/11a-12 well, though it was
unchanged at the other wells. This resulted in a more consistent pick, and less
variable isochron. The Top Rotliegendes is picked as a peak and is generally of
good quality except in the more complex crestal locations where image-quality
deteriorates. Top Carboniferous is picked as a trough, although the event is weaker
than the Top Rotliegendes and so the robustness will not be quite as good.
The Glein structure is interpreted to be an inverted anticline in the hangingwall of an
originally extensional fault, figure 2.1. This assessment is based on the geometry of
the primary seismic signal that is observed in many places across Glein that does
not seem to be compatible with a normal fault. Also reversed faults are frequently
seen in many of the offset fields (for example West Sole), and are more consistent
with the narrow but complex nature of the Glein structure. The Top Rotliegendes
horizon surface itself is generally unchanged from previous versions of the
interpretation apart from near faults (due to changes in the faulting, as mentioned
above), and some small areas on the crest of the Glein structure where the data is
poorer and subject to more uncertainty. The resulting Top Rotliegendes depth
structure map can be seen in figure 2.2.
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Figure 2.1: Seismic dip line through the Glein structure showing the inverted normal
fault (blue) and associated hanging wall anticline.
Figure 2.2: Base Case Top Rotliegendes depth structure map.
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2.2 Reservoir Quality
The Rotliegendes strata of Glein are Lower Permian in age with hydrocarbons found
in the Lower Leman Sandstone formation, which here represents the whole Lower
Permian succession. Upper Leman sands are seen in the nearby West Sole field
(~5km away), and it is thought that sabkha progradation over Glein prevented the
development of Upper Leman sands in this area.
The Rotliegendes formation unconformably overlies the Upper Carboniferous
(Westphalian) coal measures; the unconformity resulting from tilting and erosion
during the Hercynian Orogeny. The Carboniferous coal measures provide the source
rock for the Southern Gas Basin.
The quality of the Rotliegendes sediments, in terms of permeability, is usually quite
poor. The studies of Glennie (1978), Prosser & Maskall (1993), Howell & Mountney
(1997), North & Prosser (1993) and Rossel (1982) have all shown that kaolinite and
illite are the most frequently occurring clay minerals in the Lower Permian reservoirs
of the Southern North Sea. The amount of consolidation and diagenesis of these
reservoir facies is, in part, a reflection of deeper burial in the Jurassic and
Cretaceous than seen in the present day. The presence and degree of illite
crystallinity is a function of the maximum temperature to which it has been subjected.
Kubler (1968) and Glennie (1978) suggest that the point of maximum illite
crystallinity in the Rotliegendes reservoirs was in the Late Cretaceous, prior to the
Alpine Orogeny and subsequent uplift.
The cross plot in figure 2.3 shows core porosity versus core permeability for the
Glein 48/11a-12 well. What is apparent from this plot is the variation in permeability
for a given porosity. The average permeability appears to be in the range of 0.01 to
0.1mD, with high permeability “streaks” also observed. For aeolian reservoirs this
average permeability is low; permeabilities up to a Darcy would not be uncommon
for aeolian sands that have undergone minimal alteration (Glennie 1978). The low
permeabilities in the 48/11a-12 well are most likely to have been caused by the
presence of illite in the reservoir.
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Figure 2.3: Porosity .vs. Permeability cross plot for the Glein 48/11a-12 well.
The low permeability of the Rotliegendes reservoir in Glein means that the
development of the field requires the use of hydraulic fracturing. Nearby fields,
including West Sole and Barque have used hydraulic fracturing in deviated and
horizontal wells respectively, to improve reservoir performance.
Natural fractures are observed in the 48/11a-12 well and are both open and
cemented, with cemented being the more common. The fractures occur as both
swarms and individual fracture planes and show no preference for lithology when
occurring as swarms or individual planes. The fractures, due to their predominantly
cemented nature are not expected to contribute to production.
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2.6 Initial Reservoir Pressure and Temperature
RFT data over the reservoir interval was taken for well 48/11a-12. Of the 24 tests
carried out only 4 tests were reported as good owing to the low permeability rock
which results in supercharged, failed or partial build-ups. Regional data atthe
Pickerill and West Sole Field suggests initial pressure in the range of 4500 psia at a
datum depth of 10,000ft TVDSS and the RFT results shown in figures 2.4 and 2.5
are within the area trend.
It is difficult to ascertain a definitive estimate of the initial reservoir pressure from the
DST carried out on well 48/11a-12, this is due to the pressure gauge failure
observed during the well test. The initial reservoir pressure in Glein is taken to be
4,490 psia at a datum depth of 9794 ft TVDSS.
The reservoir temperature observed in the RFT tests was in the range of 197 – 204°
degrees Fahrenheit. Petrophysical analysis carried out by Jenner Associates
involved the use of a temperature profile equation based on the general North Sea
temperature gradient i.e. T = 60 + TVD * 0.015 deg. F and calculated a reservoir
temperature of 206 ° degree Fahrenheit at a reference depth of 9750 ft TVDSS and
this has been used in the subsurface workflow.
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Figure 2.4: RFT data from the Schlumberger well test report.
Figure 2.5: RFT plot for well 48/11a-12
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2.7 Fluid Composition
Glein discovery well 48/11a-12 was tested between the 2nd and 8th of November
1994 at a rate of ~0.4 mmscf/d with an estimated CGR of 0.5 STB/MMscf. Four test
separator samples were taken and analysed by Corelab. The PVT samples were of
good quality and generally of consistent composition as shown in the table below. An
average fluid composition was derived from the four samples, and used to model the
characteristic Glein field PVT properties, see figure 2.6. The Hydrogen component
with average value of 0.61% was ignored as it appeared to be unusual; consequently
the resulting fluid composition was normalised to 100%. The simulation results were
reasonable with an acceptable degree of divergence from the normalised reservoir
fluids. Figures 2.8 and 2.9 show the overall good match. The gas property is that of a
typical Rotliegendes formation of high methane content of 95 mol% with no
Hydrogen Sulphide.
48/11a-12
Sample
Gas Composition
C1
C2
C3
i-C4
n-C4
i-C5
n-C5
C6
C7+
N2
CO2
H2
H2S
check
Specific Gravity
A17620
A16994
A16114
A16962
Average Fluid
(mole %)
94.04
95.3
95.81
95.77
95.23
1.75
1.79
1.79
1.8
1.78
0.18
0.19
0.18
0.18
0.18
0.03
0.03
0.03
0.03
0.03
0.04
0.04
0.04
0.04
0.04
0.02
0.01
0.02
0.02
0.02
0.01
0.01
0.01
0.01
0.01
0.02
0.02
0.04
0.02
0.03
0.07
0.04
0.06
0.05
0.06
1.02
1.01
1.01
1.08
1.03
0.93
1.01
1.01
1
0.99
1.89
0.55
0
0
0.61
0
0
0
0
0.00
100.00
100.00
100.00
100.00
100.00
0.574
0.580
0.584
0.583
0.580
Figure 2.6: Gas composition.
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Average Fluid
Gas Composition
C1
C2
C3
C4
C5
C6
C7+
N2
CO2
H2S
95.23
1.78
0.18
0.07
0.03
0.03
0.06
1.03
0.99
0.00
Norm_Ave Fluid
(mole %)
95.81
1.79
0.18
0.07
0.03
0.03
0.06
1.04
0.99
0.00
Check
99.39
100.00
PVT_SIM
Error
95.27
0.74
0.28
0.13
0.07
0.07
0.20
0.79
2.38
0.08
-0.55
-1.05
0.10
0.06
0.04
0.04
0.14
-0.24
1.39
0.08
100.00
0.00
Figure 2.7: Simulated gas composition.
A17620
A16994
A16114
A16962
Average Fluid
100
90
80
70
60
50
40
30
20
10
0
C1
C2
C3
i-C4
n-C4
i-C5
n-C5
C6
C7+
N2
CO2
H2
H2S
Figure 2.8: Corelab sample composition.
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Norm_Ave Fluid
PVT_SIM
100
90
80
70
60
50
40
30
20
10
0
C1
C2
C3
C4
C5
C6
C7+
N2
CO2
H2S
Figure 2.9: Normalised average .vs. simulated composition
2.8 Gas and Water Properties
The summary of the gas and water properties, at initial reservoir conditions is
presented below.
Table 2.1: Initial reservoir gas and water properties
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3.0 Static Reservoir Model
A static reservoir model was built following on from regional and Glein specific
studies, to try and best capture the geology of the discovery and ultimately the
volume of gas in place in the structure. The inputs to the model were the Top
Rotliegendes and Top Carboniferous depth maps and fault interpretation that were
the products of the seismic interpretation.
Net to Gross is typically high in Leman sandstone reservoirs, with the average in
Glein being 74%. Porosity is also good averaging 11%, with porosities as high as
20% observed. Water saturation was calculated using Archie derived log saturations
and also a saturation height function calculated using capillary pressure data from
the 48/11a-12 well.
The log suite for the 48/11a-12 well do not show a clear fluid contact, but it is clear
from the logs that the well is gas bearing throughout, so a Gas Down To (GDT) is
interpreted at the base of the well, 10096ft TVDss, giving a full gas column of 499ft,
figure 3.1.
Given the low permeability seen in the 48/11a-12 core it is unlikely that we will go
from gas to water over a distance of a few feet; it is unlikely that we will see free
water at, for example, 10100ft TVDss, we would expect to see a transition zone.
The capillary pressure data from the 48/11a-12 well core suggests a mercury
injection height of 100ft, meaning that the free water level could be 100ft deeper than
the GDT in the 48/11a-12 well at 10200ft TVDss.
A range of contacts was taken into the volumetric assessment for the Glein
discovery; the low-mid-high contacts that were used are 10150-10200-10250ft
TVDss.
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Figure 3.1: Log suite for the 48/11a-12 well, showing a full gas column.
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3.1 Gas Initially In Place
A range of Gas Initially In Place values have been calculated for the Glein discovery,
as outlined in table 3.1. The map in figure 3.2 shows Glein and the West Glein region
to which the GIIP pertains. The gas expansion factor is 240.
GIIP [bcf]
West Glein
Low case
Base case
High case
(contact:
(contact:
(contact:
10150ftTVDss)
10200ftTVDss)
10250ftTVDss)
86
113
126
Table 3.1: Gas Initially In Place in BCF for the West Glein structure.
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Figure 3.2: Top Rotliegendes Depth structure map showing the subdivision of the
Glein structure.
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4.0 Dynamic Reservoir Model
The dynamic modelling of the Glein field has taken into account all aspects of the
field development work.
The Eclipse simulation model is based on the Geological Static realisations of the
field and has been volumetrically matched to the Static Model.
The hydraulic fracture design and modelling has been completed by Fenix
Consulting and incorporated into the Eclipse model using Local Grid refinement.
Figure 4.1 below.
Figure - 4.1
Effective Fracture Length modeled in Eclipse.
Material Balance, MBal and GAP, have been used to provide an analytical bench
mark to the Eclipse simulation work, with low, mid and high recoverable resources
forecasted to be 26-35 BCF, 34-47 BCF and 38-52 BCF respectively (Figure 4.2).
However, the reserves range obtained through MBal were deemed to be on the high
side, primarily because the Glein reservoir is very tight, and a simple MBal model
does not represent variable pressure depletion in tight reservoirs very well.
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Figure 4.2
Material Balance Analysis – Reserves Range a Function of Abandonment Pressure
Therefore the MBal/GAP model on Glein was used primarily to define the pipeline
pressure regime from the reservoir to the Subsea Manifold in order to provide a
guide to the BHP and THP constraints on the Eclipse model, as illustrated in Figure
4.3 below.
Figure 4.3
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Simple GAP model – 10 Barg (145 psig) export node.
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Eclipse simulation has been used for the more detailed sensitivity analysis,
accounting for reservoir geometry, relative permeability effects, the impact of high
permeability thin sands and varying elements such as the number and length of
horizontal wells combined with number and size of Fracture design.
Eclipse modelling has provided the more conservative and credible reserves ranges
of 31.4 – 35.5 – 52.4 BCF for the low, medium and high realisations respectively.
Figure - 4.4
High, Mid and Low Development Production Profile.
Table - 4.1
Reservoir Simulation Results for Development Option.
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4.1 Conclusions
In summary, Eclipse simulation work carried out on sensitivity cases demonstrates
that:
 The high permeability layers do not materially contribute to the recovery
mechanism of the reservoir, because they are thin discontinuous bodies of
sands that do not provide a flow path back to the fractured well.
 Despite establishing that well length was important in maximising forecasted
reserves, the assumed
2.7 Km horizontal section for a development well
ultimately needed to be constrained to a 2.2 Km horizontal length for drilling
and coiled tubing operation reasons.
 Achieving a longer horizontal length by drilling two 1.5 Km laterals proved to
give the highest reserves estimates, but due to high costs, was uneconomic
as a development concept.
 Hydraulic fracture sensitivities showed that there were clear diminishing
returns with additional fractures being added to a fixed horizontal length, once
5 fractures had successfully been implemented.
 The maximum number of fractures that can be initiated on a 2.2Km well is
seven; with the recommendation that 6 fractures are initiated with the
objective that at least 5 are successful. Adopting the logic that the 6 th fracture
is mitigation against failure.
In conclusion, the base case well construction option selected comprises a 2.2 Km
horizontal section in the Rotliegendes and 6 hydraulic fractures. This delivers a 25
year recovery range of 31.4 BCF to 52.4 BCF with a base case recovery of 35.5
BCF.
The capital costs required to support this modest level of recovery were analysed in
detail and found to be too high to deliver a commercial project.
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5. Clearance
Fairfield Cedrus Ltd confirms that the Department of Energy and Climate Change is
free to publish the contents of this report.
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