Blowout scenario and subsea release analysis for Statfjord operating year 2021
Page 1 of 19
Classification: Internal Status: Draft www.equinor.com Title:
Blowout scenario and subsea release analysis for Statfjord operating year 2021
Document no.: Contract no.: Project:
Classification: Distribution: Internal Expiry date: Status: Final
Distribution date: Rev. no.: Copy no.: 04.12.2020
Author(s)/Source(s): Mette Roland
Subjects: Blowout scenario and subsea release analysis for the Statfjord field during operation year 2021, input to ERA for oil spills
Remarks:
Valid from: Updated:
Responsible publisher: Authority to approve deviations:
Prepared by (Organisation unit / Name): Date/Signature: X TPD R&T FT SST TOS / Mette Roland
Responsible (Organisation unit/ Name): Date/Signature: X
Recommended (Organisation unit/ Name): Date/Signature: X TPD R&T FT SST TOS / Kari Apneseth Gjerde
Approved by (Organisation unit/ Name): Date/Signature: X
Page 2 of 19
Classification: Internal Status: Final www.equinor.com Summary
This note presents a quantitative assessment of blowout risk related to the Statfjord oil field. Blowout probability, flow rates and duration are quantified for application in the Statfjord environmental risk analysis (ERA). Also, frequencies and volumes for subsea releases are given. The assessment is based on the activity level in 2021 [3].
The overall oil blowout frequency is judged to be 1,15∙10-2 for the year 2021. The P90 blowout rates for the field is 190 Sm3/d for surface releases and 540 Sm3/d subsea releases. The weighted P90 rate is 270 Sm3/d. Production from the Brent reservoir is the main contributor to the frequency.
It is found that the duration of a blowout could potentially amount to 84 days with 1 % probability.
Other subsea leak scenarios – from flowlines/pipelines – will be covered in the BSSA for the period 2022-2026, to be carried out in 2021.
Page 3 of 19
Classification: Internal www.equinor.com Table of contents
1 Introduction ...... 5 2 Field Specific Information ...... 5 3 Assumptions regarding activities and blowout rates...... 6 4 Activity level and frequencies...... 6 5 Blowout rates...... 8 5.1 Blowout scenarios ...... 8 5.2 Blowout rates...... 8 5.3 Reservoir properties...... 9 6 Results, blowout frequency and rates ...... 10 6.1 General...... 10 6.2 P90 rate...... 10 7 Blowout duration...... 14 8 Subsea releases ...... 17 8.1 Method ...... 17 8.2 Subsea releases, Statfjord field (excluding offshore loading system)...... 18 8.3 Oil loading system...... 18 9 References...... 19 A.1 Appendix 1 Reservoir and fluid data ...... 21
Page 4 of 19
Classification: Internal www.equinor.com 1 Introduction
The purpose of this note is to provide input to the environmental risk analysis for the Statfjord field regarding oil blowout probability, rates and duration.
The assessment of risk figures in this note is based on: Blowout and well leak frequencies [1] Guideline for blowout scenario analysis Error! Reference source not found. MRABA activity spreadsheet [3] Input scheme for BSA for Statfjord [4] Input to environmental risk analysis Error! Reference source not found. Risk analyses for SFA, SFB and SFC ( Error! Reference source not found.Error! Reference source not found.Error! Reference source not found.) Judgements and considerations in TPD R&T FT SST and in dialogue with the Statfjord organisation.
2 Field Specific Information
The Statfjord field is located in the North Sea in water depths of 130 to 220 meters. The oilfield was discovered in 1974, first production in 1979 with production and drilling operations continuing to the present day. The field was developed with three integrated processing, drilling and accommodation facilities with concrete bases and steel topsides called Statfjord A, B and C. The subsea structures Statfjord Nord (“SFN”), Statfjord Øst (“SFØ”) and Sygna are also part of the Statfjord Field and referred to in this analysis as Statfjord Satellites.
The Norwegian share of the field lies in blocks 33/9 and 33/12 in production licence 037, while the British part is in UK block 211/25 in licences 104 and 293. The field will remain in production until 2025 and possibilities to further expand the lifetime are being looked into.
A layout of the Tampen field, which includes Statfjord, is shown below in Figure 1. Reservoir and fluid data are given in Appendix 1.
Page 5 of 19
Classification: Internal www.equinor.com Figure 1 Tampen area – connections between Statfjord, Gullfaks, Snorre and Visund and satellites
3 Assumptions regarding activities and blowout rates
The Statfjord field consists of both oil and gas producing wells1 as well as injection wells. In 2021 there will be circa 95 oil and gas producing wells on Statfjord including satellites and eight water injectors. The gas injectors are not planned to be used in 2021.
The ESP wells on SFC are not included in the tables above nor in the calculations as it is assumed that they will not be able to cause oil spills they produce water below the water/oil contact.
4 Activity level and frequencies
The blowout frequencies in Lloyds’ Blowout and Well release frequency report 2019 [1] are used to assign blowout frequencies for the different activities. The number of the different activities are multiplied with the relevant blowout frequency given in the Lloyds report [1].
The activity specific flow path distribution for the blowout for fixed and floating installations as recommended in [1], is presented in Table 1 and is based on an overall assessment of scenarios and type of platform. The distributions are adjusted so that the sum for each activity is 1.
Table 1 Flow path distribution /1/ Fixed installation Floater Surface Seabed Surface Seabed Drilling 0,76 0,24 0,21 0,79 Completion 1 0 0,84 0,16 Wireline 1 0 0 1 CT 1 0 0,5 0,5 Workover 0,65 0,35 0,21 0,79 Production 0,75 0,25 0 1
Flow path distributions for abandoned wells are not reported in[1]. The but the following assumptions are made:
Abandoned wells – assume subsea release Water injection – same distribution as for producing wells For satellites, the flow path distribution for floaters are applied, as all work on the satellite wells will be performed by a floater (and blowout occurs at seabed)
In Table 2 the different well activities given in [3] is combined with the base frequencies from the Lloyds report [1] and Table 1 above. Table 2 thus gives the activity in different reservoirs, frequency for blowout from these, and the distribution between surface and subsea release. The total blowout frequency for the Statfjord field in 2021 amounts to 1,18E-02, where 78 % are surface releases and 22 % subsea releases.
1 Oil well is considered to be a well with a gas oil ratio (GOR) less than 1,000 and a gas well to have a GOR over 1,000.
Page 6 of 19
Classification: Internal www.equinor.com Table 2 Activities in year 2021, and corresponding frequencies Subsea WH Surface WH (SFA/B/C) (Satellites) Scenario probability Surface Subsea Oil wells Per activity Topside Subsea Surface Subsea frequency frequency
Drilling:
Cook 3,25E-05 2 6,50E-05 0 0 4,94E-05 1,56E-05 Statfjord 3,25E-05 2 6,50E-05 0 0 4,94E-05 1,56E-05 Sprocket 3,25E-05 1 3,25E-05 0 0 2,47E-05 7,80E-06 Completion 1,32E-04 5 6,60E-04 0 0 9,24E-04 0,00E+00 Wireline 3,59E-06 25 8,98E-05 3 1,08E-05 8,98E-05 1,08E-05 Coiled tubing 4,46E-05 1 4,46E-05 0 0 4,46E-05 0 Production wells: Brent 2,14E-05 12 2,57E-04 2 4,28E-05 1,93E-04 1,07E-04 Cook 2,14E-05 5 1,07E-04 0 0 8,03E-05 2,68E-05 Statfjord 2,14E-05 7 1,50E-04 0 0 1,12E-04 3,75E-05 SFØ 2,14E-05 1 2,14E-05 6 1,28E-04 1,61E-05 1,34E-04 SFN/Sygna 2,14E-05 0 0,00E+00 11 2,35E-04 0 2,35E-04 Sprocket 2,14E-05 1 2,14E-05 0 0 1,61E-05 5,35E-06 Water injection wells 8,99E-06 8 7,19E-05 4 3,60E-05 5,39E-05 5,39E-05 Abandoned 8,75E-06 15 1,31E-04 5 4,38E-05 0,00E+00 1,75E-04 Surface Subsea Gas wells Per activity Topside Subsea Surface Subsea frequency frequency
Drilling: Brent 3,86E-05 3 1,16E-04 0 0 8,80E-05 2,78E-05 Statfjord 3,86E-05 6 2,32E-04 0 0 1,76E-04 5,56E-05 Completion 2,99E-04 9 2,69E-03 0 0 2,69E-03 0,00E+00 Workover 3,47E-04 4 1,39E-03 0 0 9,02E-04 4,86E-04 Wireline 8,15E-06 35 2,85E-04 0 0 2,85E-04 0 Production wells: 0 Brent 6,65E-05 58 3,86E-03 0 0 2,89E-03 9,64E-04 Statfjord 6,65E-05 11 7,32E-04 0 0 5,49E-04 1,83E-04 Sum SFA/B/C + Satellite, oil & gas 1,15E-02 8,97E-03 2,54E-03 Distribution surface/subsea: 78 % 22 %
The frequency used for drilling of the Sprocket well (C16) is the frequency for developments drilling, as it will be drilled after Sprocket C2 well is finished, thus C16 will be drilled in a familiar reservoir the well is intended for injection, so it is planned to be a well to be used
Page 7 of 19
Classification: Internal www.equinor.com 5 Blowout rates
5.1 Blowout scenarios
For exploration wells, during a drilling operation a blowout may result if a reservoir is penetrated while well pressure is in under balance with the formation pore pressure (well pressure < reservoir pressure), and a loss of well control follows. Three different scenarios are defined: 1. Top penetration Kick and loss of well control after 5 m reservoir penetration, typically due to higher reservoir pressure than expected.
2. Drilling ahead Kick and loss of well control after penetration of half the pay zone depth. Represents various causes of under balance while drilling ahead. 3. Tripping Kick and loss of well control after full reservoir penetration, typically due to swabbing during tripping The overview of blowout causes given in /1/ combined with an assumption of annular flow do, in our opinion, justify the following probabilities: P(Top penetration | blowout) = 0,20 P(Tripping | blowout) = 0,40
Given the above definition of scenarios: P(Drilling ahead | blowout) = 1,0 – P(Top penetration or Tripping| blowout) = 0,40.
For development drilling, the top penetration is considered less likely as the drilling is performed in a reservoir which properties are known, so the allotted 20 % is split between the “drilling ahead” and “tripping” scenario. This gives 50 % probability for each of the two scenarios.
5.2 Blowout rates
For blowout rates during drilling, the simulations are performed under the conservative assumptions:
Unrestricted annulus flow where the BOP has failed entirely. Gas coning is not considered. As time passes reservoir pressure will decline from production, this factor is not accounted for.
Historical data during drilling has few recordings of open hole blowouts /1/ and the likelihood of such a scenario is seen as negligible. Flow through annulus is considered the most likely flow path and annulus rates are therefore used to represent the flow potential of a blowout during drilling operations.
For completed wells blowouts through drill string, annulus and tubing have been recorded in /1/ with drill string and tubing as the most likely flow paths. Thus, for production wells and wireline activities potential blowout rates have been calculated for through production tubing scenario (with no restrictions).
For assessment of environmental risk, only the oil blowout rates are relevant. The blowout rates are presented in Table 3 combined with relevant activities taken from Table 2.
Table 3 Activity and corresponding blowout rates
Page 8 of 19
Classification: Internal www.equinor.com Statfjord Satellites SFA SFB SFC Rate A/B/C Oil wells (GOR<1000) 2021 2021 2021 2021 2021 Sm3/d Cook drilling ahead 2 0 1 0 1 1500 Cook tripping 2 0 1 0 1 1900 Statfjord. drilling ahead 2 0 1 1 0 1950 Statfjord tripping 2000 Sprocket top*) 1 0 0 0 1 6900/6900 Sprocket drilling ahead*) 8300/8500 Sprocket tripping*) 8700/8900 Completion 4 0 2 1 4 150 Completion Sprocket 1 2000 Wireline 25 3 5 10 10 100 Coiled tubing 1 0 0 1 0 100 Production: Brent 12 2 3 2 7 1**) Cook 5 0 3 1 1 150 Statfjord 7 0 2 4 1 90 SFØ 1 6 0 0 1 800 SFN/Sygna 0 11 0 0 0 300 Sprocket 1 0 0 0 1 2000 Water injection wells 8 4 2 5 1 150 Abandoned 15 5 13 2 90 Gas wells (GOR>1000) Statfjord Satellites SFA SFB SFC Brent drilling ahead 3 0 0 1 2 750 Brent tripping 800 Statfjord drilling ahead 6 0 4 2 0 1950 Statfjord tripping 2000 Completion 9 0 4 3 2 200 Workover 4 0 0 2 2 90 Wireline 35 0 15 10 10 100 Production Brent 58 0 14 26 18 70 Statfjord 11 0 3 4 4 200 *) Sprocket rates given for surface/subsea releases **) Most Brent wells are dependent on gas lift, others may give more oil spill. The rate 1 Sm3/d is used in the calculations to show that we may have some oil spill from these wells
For blowouts at abandoned wells, the lowest blowout rate given for oil/gas wells respectively are used. The rates applied for Completion (only applicable for SFA/SFB/SFC) is the highest production blowout rate for oil and gas respectively given for the three installations.
5.3 Reservoir properties
Below some of the most relevant properties for the MRABA is given. Further reservoir data is given in Appendix 1.
Page 9 of 19
Classification: Internal www.equinor.com Table 4 Some fluid properties for the reservoirs Section Scenarios Scenario probability SFN and Brent Cook Statfjord Sprocket SFØ Sygna Water cut, % (water not included in rate) 87 20 92 0 83 88 GOR 5400 300 1700 150 420 98
6 Results, blowout frequency and rates
6.1 General
In the following sections the main results from the calculations are given in tables. Also, a histogram showing distribution of the rates and pie charts showing distribution of activities are given. All blowout rates are rounded to nearest 10 or 50 Sm3/d depending on the size of the rate. This may give an impression of higher accuracy than is the case. However, it is in the same range as the basic blowout rates given.
6.2 P90 rate
The distribution of blowout rates for surface and subsea releases are given in Figure 2. To calculate the P90 rate (90-percentile) the different rates have been grouped and collated before being normalised, see Table 5.
Distribution of blowout rates minus Sprocket
3.50E-03
3.00E-03
2.50E-03
2.00E-03 Surface 1.50E-03 Subsea
1.00E-03
5.00E-04
0.00E+00 1 70 90 100 150 200 300 750 8001500190019502000
Figure 2 Blowout rate distribution. Sprocket is not included as it is to low frequency to be visualized in the graph
Table 5 Normalised rate distribution
Blowout Blowout frequency Normalized Cumulative rates Sm3/d Surface Seabed Surface Seabed 1 1,93E-04 1,07E-04 2,15E-02 4,21E-02 2,15E-02 4,21E-02
Page 10 of 19
Classification: Internal www.equinor.com Blowout Blowout frequency Normalized Cumulative rates Sm3/d Surface Seabed Surface Seabed 70 2,89E-03 9,64E-04 3,22E-01 3,80E-01 3,44E-01 4,22E-01 90 1,01E-03 6,98E-04 1,13E-01 2,75E-01 4,57E-01 6,96E-01 100 4,20E-04 1,08E-05 4,68E-02 4,24E-03 5,04E-01 7,01E-01 150 7,94E-04 8,07E-05 8,85E-02 3,18E-02 5,92E-01 7,32E-01 200 3,24E-03 1,83E-04 3,61E-01 7,20E-02 9,53E-01 8,04E-01 300 0 2,35E-04 0 9,27E-02 9,53E-01 8,97E-01 750 4,40E-05 1,39E-05 4,90E-03 5,47E-03 9,58E-01 9,03E-01 800 6,01E-05 1,48E-04 6,69E-03 5,81E-02 9,65E-01 9,61E-01 1500 2,47E-05 7,80E-06 2,75E-03 3,07E-03 9,68E-01 9,64E-01 1900 2,47E-05 7,80E-06 2,75E-03 3,07E-03 9,70E-01 9,67E-01 1950 1,13E-04 3,56E-05 1,26E-02 1,40E-02 9,83E-01 9,81E-01 2000 1,29E-04 4,09E-05 1,43E-02 1,61E-02 9,97E-01 9,97E-01 6900 4,94E-06 1,56E-06 5,51E-04 6,14E-04 9,98E-01 9,98E-01 8300 9,88E-06 0 1,10E-03 0 9,99E-01 9,98E-01 8500 0 3,12E-06 0 1,23E-03 9,99E-01 9,99E-01 8700 9,88E-06 0 1,10E-03 0 1,00E+00 9,99E-01 8900 0 3,12E-06 0 1,23E-03 1,00E+00 1,00E+00
To find the P90 rate the graphical method is used, i.e. plotting the cumulative distribution in a graph and find the crossing point of 90 % and corresponding rate for surface and subsea blowouts. These graphs (enlargements are required) are given in Figure 3.
Page 11 of 19
Classification: Internal www.equinor.com Rate distribution
1.20E+00
1.00E+00
8.00E-01
6.00E-01 90 percentil Distribution Surface 4.00E-01 Seabed 2.00E-01
0.00E+00 1 10 100 1000 10000 Rate, Sm3/d
Surface
100% 98% 96% 94% 92% 90% 90 percentil Distribution 88% Surface 86% P90 Surface 84% 82% 80% 100 120 140 160 180 200 Rate, Sm3/d
Subsea
92% 92% 91% 91% 90% 90 percentil Distribution 90% Seabed 89% P90 Seabed 89% 88% 400 500 600 700 800 Rate, Sm3/d
Figure 3 Graphs to find P90 rate
From the graphs above, the resulting P90 values are given in Table 6Error! Reference source not found..
Page 12 of 19
Classification: Internal www.equinor.com Table 6 P90 rates Surface Sm3/d Seabed Sm3/d Weighted surface/seabed Sm3/d P90 190 540 270
To easily identify the blowout rates with the highest blowout frequency, the pie charts for surface and subsea releases are given in Figure 4 and Figure 5. As can be seen, production from Brent contributes to a major part of the total blowout frequency. However, the blowout rates are low – no release from the oil reservoir, and 70 Sm3/d for the gas reservoir.
Surface
O Completion
CO Sprocket*)
PO Brent
G Completion
G Workover
G Wireline
PG Brent
PG Statfjord
Figure 4 Pie chart, surface blowout distribution above > 2 % (O = Oil, G = Gas, C = Completion, P = Producing wells)
Subsea
PO Brent
PO SFØ
PO SFN/Sygna
Water injection wells
Abandoned
G Workover
PG Brent
PG Statfjord
Figure 5 Pie chart, subsea blowout distribution above > 2 % (O = Oil, G = Gas, C = Completion, P = Producing wells)
Page 13 of 19
Classification: Internal www.equinor.com 7 Blowout duration
An oil blowout can be stopped by: 1. Operator actions – mechanical (capping) 2. Wellbore collapse and/or rock material plugging the well – (bridging)
3. Altered fluid characteristics resulting from water or oil coning during a blowout 4. Drilling a relief well and applying kill mud The probability distribution of the duration of a possible blowout is derived by way of the approach utilised in /1/. Water and oil coning or capping stack are not considered in the assessment. Well specific input about time to drill a relief wells is given by the Statfjord field organisation and presented in Table 7. One assumption in the assessment of blowout duration is that one relief well is sufficient to kill the well. The wells are mainly vertical wells, but there are also some horizontal wells. To cover blowouts from the latter, the maximum number for days for the geo magnetic steering is applied. Need for a second relief well would require a re- evaluation.
Table 7 Time to drill a horizontal relief well (days) Min days Most likely days Max days Comments 1- Decision to mobilize 1 3 4
2- Mobilization of rig, including: collection 3 6 12 of equipment/rearmament, transit, anchoring and preparation2 3- Drilling down to the specific depth 25 35 50
4- Geo magnetic steering into the well3 7 12 30
5- Killing of well 1 2 5
The required time to drill a relief well and kill a blowout is judged by the project to be between 37 and 101 days. A Monte Carlo simulation is performed to produce a duration distribution from the well specific input in Table 7. The statistical normal time for drilling a relief well if not killed by other remedies/occurrences, is 65 days. A probability distribution is presented in Figure 6.
2 It is a requirement in NORSOK D-010, chapter 4.8.2 that initiation of relief well drilling should start no later than twelve days after the decision to drill relief wells, i.e. the expected time in step 2 should not be higher than 12d for operations on NCS. 3 default values for horizontal/vertical wells (in order of appearance) are provided based on expert judgement. An argument must be provided for alterations in these numbers.
Page 14 of 19
Classification: Internal www.equinor.com 0.4000
0.3500
0.3000
0.2500
0.2000 PROBABILITY 0.1500
0.1000
0.0500
0.0000 56 63 70 77 84 TIME TO DRILL A RELIEF WELL (DAYS)
Figure 6 Duration distribution, ‘Time to drill a relief well’
The probability distribution, found in Table 8 below, is constructed by combination of the well specific duration distribution for drilling a relief well and the probabilities that a blowout will end by the mechanisms capping and bridging /1/. Based on Table 8 maximum blowout duration is suggested to be 84 days.
Table 8 Probability distribution for a blowout to end as a function of time (days)
Page 15 of 19
Classification: Internal www.equinor.com Duration Seabed blowout Duration Seabed blowout Surface blowout Surface blowout (days) (days) 0,5 0,235 0,167 35 0,006 0,011 1 0,109 0,084 42 0,004 0,006 2 0,133 0,111 49 0,003 0,005 5 0,180 0,173 56 0,017 0,025 7 0,056 0,063 63 0,046 0,064 10 0,048 0,060 70 0,051 0,070 14 0,035 0,047 77 0,026 0,036 21 0,028 0,043 84 0,010 0,013 28 0,013 0,021 *Probabilities in the tail end of the duration distribution (< 0,005) are added to the probability of the preceding duration category.
Different probability descriptions of the duration of a seabed or surface blowout are produced. Possible durations of a seabed or surface blowout are described by probabilities in Figure 7. In Figure 8 blowout duration and ‘time to drill a relief well’ are described by cumulative probability curves.
0.250
0.200
0.150
0.100
0.050
0.000 0.5 1 2 5 7 10 14 21 28 35 42 49 56 63 70 77 84 BLOWOUT DURATION (DAYS)
Surface Seabed
Figure 7 Blowout duration described by probability distributions
Page 16 of 19
Classification: Internal www.equinor.com 1.0
0.9
0.8
0.7
0.6
0.5
Probability 0.4
0.3
0.2
0.1
0.0 0 7 14 21 28 35 42 49 56 63 70 77 84 Number of Days ReliefW Surface Seabed
Figure 8 Cumulative Probability distribution for number of days for blowout duration
8 References
[1] Lloyds: “Blowout and Well Release Frequencies – based on Sintef Offshore Blowout Database 2019”,
report 19101001-8/2020/R3, rev Final, March 2020
[2] Equinor: GL0498 “Guideline for Blowout Scenario Analysis as input to Environmental Risk Analysis
[3] Statfjord: “MRA activity table 2020-11”, November 2020
[4] Statfjord: “Input scheme for blowout scenario analyses”
Page 17 of 19
Classification: Internal www.equinor.com Doc. No.
Valid from: Rev. no.
A.1 Appendix 1 Reservoir and fluid data
Reservoir Data Unit Sygna SFØ SFN Sprocket Brent Iso Cook Statfjord Brent Brent Brent (Munin) Name Brent Top reservoir m TVD MSL 2344 2600 2458 2545 2622 2436 2705 2650 Reservoir pressure bar 108 150 255 229 330 210 330 300 Total formation thickness m TVT 200 50 40 250 125 237 165 30 HC bearing formation thickness m TVT 200 50 19 130 75 60 55 30 Net/Gross v/v 0.70 0.70 0.45 0.75 0.89 0.72 0.90 0.8 Porosity v/v 0.26 0.26 0.16 0.25 0.23 0.25 0.22 0.24 Permeability mD 1916 1916 250 2117 258 769 872 750 Temperature (top res) °C 91 91 91 97 98 91 98 110 Water cut % 87 9 20 92 88 83 89 0 Productivity Index (PI)4 Sm3 oil/d/bar 73 18 1 109 186 68 107
Fluid data Unit SFU SFU SFU Sygna SFØ SFN Reference field/well for fluid properties SFU Brent Iso Brent Dunlin Statfjord Brent Brent Brent Gas/oil/water contact(s) m TVD MSL 2413.5
FLUID PROPERTIES AT SURFACE CONDITIONS Oil density kg/m3 833 851 843 838 833 834 833 Gas gravity sg 0.77 0.72 0.94 0.85 0.76 0.77 0.76 GOR Sm3/Sm3 5400 1300 300 1700 98 420 100
4 When PI data are included reservoir width/ length, X-/Y- position and well location data are optional.
Page 18 of 19
Classification: Internal www.equinor.com Doc. No.
Valid from: Rev. no.
Fluid data Unit
FLUID PROPERTIES AT RESERVOIR CONDITIONS CO2 % 0.51 0.71 0.49 0.36 N2 % 0.35 0.83 0.36 0.59 H2S % 13 ppm 3 ppm 2 ppm 24 205 8 29
Page 19 of 19
Classification: Internal www.equinor.com