Blowout potentials are defined as the maximum expected blowout rates for various scenarios. Most likely expected parameters are to be used, or a weighted distribution of the same parameters. Whenever necessary, parameters and calculation results should be risked in order to establish the most reliable probability distributions for expected rates.
The “OLF Guidelines for estimation of blowout potentials” [1] are used as basis for all flow rate calculations presented in this report. Distributions of possible flowpaths are given in accordance with data from the Sintef Offshore Blowout Database [3] and the latest evaluation of the Sintef Database data in the report from Scandpower Risk Management AS [2].
3.1 Blowout scenarios in general
A blowout is defined as an unwanted and uncontrolled flow from a subsurface formation which is released at surface, seabed or into a secondary formation, and cannot be closed by the predefined and installed barriers.
Blowout potentials, i.e. the expected rates of oil, water and gas, are highly dependent on the scenario in which the blowout occurs. Lost pipe, junk or complex escape paths for the fluid will result in dramatically lower blowout rates than a fully open 9⅝” casing all the way from formation to surface.
For the NewField North exploration well, an unrestricted blowout through the 9 ⅝” casing, with exposure to fully penetrated Res-1 and Res-2 formations, will result in a maximum blowout rate of 4445 Sm3/day of condensate and 17.8 MSm3/day of gas. This rate is related
This unrestricted blowout scenario will in this well set up a drawdown onto the formation of more than 110 bars (11 MPa). This drawdown might induce a risk of collapse of the surrounding formation, or initiate production rates of sand, both consequences that can reduce the rate of fluids flowing from the well. Formation collapse might even kill the well and thereby stop the blowout entirely.
3.2 Case scenario definitions
Hypothetical blowout scenarios have been investigated in this study, all relevant for drilling operations. The analyzed case scenarios include blowouts through drill pipe, annulus and open hole to drill floor and to seabed, implying several blowout scenarios. The last case is a collective case for simulations of restricted flow.
In order to limit the number of scenarios to analyze, two main categories of incidents are simulated and are intended to cover all possible scenarios conservatively. The two scenarios are Kick and Swab, which covers all kicks when entering a formation and all swab scenarios when pulling out of hole, respectively.
Kick scenarios are represented by a partly penetrated reservoir, while swab scenarios are conservatively represented by a fully penetrated reservoir.
The following principles in selection of scenarios have been used as basis for simulation cases:
Blowout through casing/open hole, reservoir partly penetrated, kick scenarios
Blowout through casing/open hole, reservoir fully penetrated, swab scenarios
Blowout through drillpipe, reservoir partly penetrated, kick scenarios
Blowout through drillpipe, reservoir fully penetrated, swab scenarios
Blowout through annulus, reservoir partly penetrated, kick scenarios
Blowout through annulus, reservoir fully penetrated, swab scenarios
Restricted blowout through topside leak, 64/64'' choke All scenarios listed above have been investigated in this report.
Figure 7: Possible blowout paths for the defined scenarios (Illustrative only).
A find in Res-1 and Res-2 is related such that a find in Res-2 is not possible with no find in Res-1. This result in the following possibilities:
a) HC find in Res-1
b) HC find in Res-1 and Res-2
HC find in none is not evaluated in this report.
Based on this, the following definition is made for simulations performed in this study.
1) Kick scenarios are represented by a partly penetrated Res-1
2) Swab scenarios are represented by fully penetrated Res-1 and Res-2.
See Section 3.5.2 for illustration and results from final risk procedure.
For cases involving a partly penetrated reservoir, i.e. the kick scenarios, a gross penetration pay of 5 meters is used. The N/G ratio is 1.0, which is considered conservative.
Drilling BOP Sealevel
Drilling BOP Sealevel
Drilling BOP Sealevel
3.3 Distribution of flowpath probabilities
In order to establish the best possible statistical estimate for the well, a distribution between all investigated scenarios and the expected duration for these are to be calculated based upon the Guidelines from OLF [1]. The statistical values are found based on the Sintef Offshore Blowout Database [3] and the annual report from Scandpower [2], that are based upon a more comprehensive analysis of the Sintef database. Hence, irrelevant cases are removed and probability distributions are adjusted according to observed trends.
Furthermore the operational experience from the Acona Wellpro group of companies, with more than 25 years of relevant operations is implemented in the calculation of the probability distribution. These evaluations and their weighting are discussed in detail below.
Table 3 summarizes relevant statistical findings from drilling-, completion and workover activities from the Scandpower report from January 2010 [2]. In addition to the incidents listed within drilling, incidents within both completion and workover activites are added to expand the statistical foundation. These activities are considered to have a similar type of barrier system, with drilling mud as the first barrier and the BOP as the second barrier.
Table 3: Probability distribution of flow paths from 20 years of historical data –Floaters.
When implementing these data for calculation of flow path distribution the following assumptions and methodology have been used:
The number of incidents is relatively low and small variations might cause relatively large alterations in the distribution coefficients, i.e. from one year to another as incidents older than the limitations set are removed from the statistical material. The statistical uncertainty will increase even more if some of the findings from the table above are considered irrelevant for the operation that is to be analyzed.
In order to try predicting the probabilities for the different flow paths possible, a more detailed analysis is needed. A well operation with “dead well”, defined as operation where
Full Restricted Full Restricted Outside casing 22.70 % 4.50 %
Outer annulus 18.20 % 4.50 %
Annulus 31.80 % 4.50 % 4.50 %
Openhole 4.50%
Inside drillstring
Insidetesttubing 4.50%
Annulus 4.50%
Inside drillstring 4.50 % 40.90 %
Inside prod tubing 4.50 % 45.50 %
Outer annulus 27.00 %
Annulus 27.00%
Inside drillstring 24.30 %
Inside prod tubing 16.20 % 5.40 %
Workover
(7.4 incidents)
Drilling
(22 incidents)
Completion
(4.4 incidents)
Data update: January 2009
Distribution - Floaters
Subsea Topside
properties, lack of operational fluid control or swabbing of reservoir fluids from “pulling out of hole” activities or lack of heave compensation.
Since all these three incidents (kick or loss from/to reservoir, lack of fluid control and swabbing) also are possible from completion and workover operations and that the secondary barrier in these operations also includes the drilling BOP, the statistical data from these two groups are included in the statistical summary together with the data from drilling operations.
In the final distribution used in this report, the outside casing and outer annulus flow paths are neglected. Such rejection is supported by the fact that kick procedures are to be established in order to minimize the risk of an underground blowout. Also, the modeling process would be too complicated, in terms of describing the flow paths. Hence, reliable modeling results are beyond reach.
Similar the flow through production/test tubing is interpreted as flow through open hole/casing.
When drilling production wells, i.e. in mature areas, the risk of running into unknowns are clearly lower than when drilling exploration wells, i.e. experiencing reservoirs with pore pressure higher than the corresponding ECD which might induce a formation kick. The formation’s pore pressures are provided through estimation for exploration wells. When a formation kick is observed, an operational procedure normally instructs the driller to stop further penetration and to close a secondary barrier in the drilling BOP. Furthermore the kick will be circulated out through the choke lines. In the risk and weighting process it is anticipated that such kick will be observed relatively shortly after penetrating the formation.
In this report a penetration depth of 5 meters is used, similar to half a joint of drillpipe, assuming that the bit did not penetrate the formation when the drillpipe last was made up.
5 meter penetration of top reservoir is assumed to be a conservative number.
In reality, the choice of penetration length into the reservoir, i.e. 5 m, is not of importance when evaluating the probability distribution. In fact, it is the mechanisms leading to the blowout that is important. For the partly penetrated case, the occurrence of a blowout is due to a kick scenario in the well. For the fully penetrated case, a swab scenario leads to the possible blowout. The loss of primary barrier by swabbing of reservoir fluids when pulling out of hole can be caused by pulling to fast, insufficient compensation of the pumping rates or by a combination of these. Borehole collapse or partly collapse of some strings or formations might increase the risks of swabbing reservoir fluids. Theoretically such swabbing may not be discovered before the BHA is at surface.
Accordingly, for this exploration well, the following probabilities are used between partly and fully penetrated reservoirs.
Blowout initiated when the formation is partly penetrated 60 %
Blowout initiated when the formation is fully penetrated 40 %
For the kick scenarios, i.e. partly penetration, 5 m penetration is used, with a N/G ratio of
Note: It is worth to notice that the risk of flowing through OH, when penetrating top reservoir only, is assumed irrelevant and the probability of this is given a 0.0 % value. This is founded upon the fact that the top reservoir cannot be penetrated without having the DP
and the bit in the hole.
Therefore the flow path probabilities in the top penetration scenario, i.e. a kick scenario, are given the following values:
Blowout through drill pipe has a probability of 25 %
Blowout through annulus has a probability of 75 %
Blowout through open hole to surface has a probability of 0 %
Similar, the fully penetrated, i.e. swab scenario, are given the following probability distribution:
Blowout through drill pipe has a probability of 21 %
Blowout through annulus has a probability of 62 %
Blowout through open hole to surface has a probability of 17 %
In all drilling operations, and most other well operations as well, a Blowout Preventer (BOP) stack of valves and rams defines the secondary barrier against uncontrolled outflow of reservoir fluids. The BOP testing program and its procedures ensure that a BOP stack is experienced as “extremely reliable equipment”. This is further emphasized by the number of independent rams in the BOP and the requirement for accumulator capacity. Based on this, the risk of a total failure of the BOP is assumed to be very low.
Once a blowout has occurred, the BOP has failed or has not been activated. Given such unlikely failures, and based on the “OLF Guidelines for estimation of blowout potentials”[1], the following distribution has been used for partly or full BOP failure:
Restricted flow area has a probability of 70 %
No restriction has a probability of 30 %
The different consequences of a partial failure in the BOP are difficult to predict. In the “OLF Guidelines for estimation of blowout potentials” it is proposed to model a partly failure as 95% reduction of the available fluid flow area. As restriction in available flow paths also can be caused by pipe in hole, fish/junk or collapse of the borehole itself, Wellpro Academica suggest that modeling of a partly failure is better described with a restriction similar to 64/64” flow area for all scenarios. This is justified by the fact that the remaining flow area now is independent of the wellbore design or the size of the drillpipe used.
3.4 Blowout duration
A blowout may be stopped by several remedial actions. These are divided into the following categories:
- Bridging, i.e. collapse of the near wellbore due to low pressure and/or high production rates.
If one or more relief wells are necessary to regain control of the well, the time needed for mobilization and drilling may vary. We can assume that the relief wells can be drilled with the same rate as the exploration well, but in addition ranging runs are required, e.g. with electromagnetic ranging tools. The time required to run such equipment must be taken into account. The time will depend upon drilling intersection depth, rig availability in general and in the specified area and weather conditions.
For the 5505/5-5 NewField North well, drilling of one relief well is estimated as follows:
Decision to drill the relief well: 3 days
Termination of work, sail to location, anchoring and preparation : 12 days
Drilling relief well to intersection: 45 days
Homing in: 10 days
Total time to kill well: 70 days
Assumptions are made that the relief well will successfully kill the well after 70 days.
In order to give best possible distribution estimate, the probability distribution for the different historical incidents must be found. The figure below is presented from the Scandpower reported data from 2010 and presents the probability that a blowout is still active after a certain number of days and several mechanisms may have been tried.
Figure 8 describes the probability of killing a well after a number of days based on the use of one single kill mechanism.
Figure 8: Blowout duration data from the Sintef Database and the Scandpower report 2010 [2].
As can be seen from the figure above, multiple mechanisms may “work together” in order to stop the blowout. Scandpower reports that 77% of all blowouts can be stopped by bridging, 70% can be stopped by intervention topside and 43% can be stopped by intervention
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
0 5 10 15 20 25 30 35 40 45 50
P e r c e n t a g e
Days
Wells still flowing after subsea attempts Wells still flowing after topside attempts Wells still flowing after natural bridging
Table 4: Risk criteria in duration distribution.
Risk of a blowout duration of 2 days P2 The blowout could be controlled by measures performed from the existing rig Risk of a blowout duration of 15 days P15 The blowout could be controlled by bringing
in additional equipment
Risk of a blowout duration of 70 days P70 The blowout will have to be killed by drilling a dedicated relief well.
3.5 Risk process and distributions
From the detailed analysis presented in the previous section the probabilities for all relevant scenarios were found. According to the “OLF Guidelines for estimation of blowout potentials” all possible scenarios should be risked and blowout potentials shall be weighted
respectively.
Note: The overall probability of finding hydrocarbons in a well, which again introduces a certain risk for a blowout shall be included either in the environmental analysis or in the blowout analysis (this report). This value is neglected in this report and will have to be included in the environmental analysis.
3.5.1 Permeability risking
The formations to be investigated in this report are all presented with a permeability range.
A log normal probability distribution gives highest probability for the low case, as shown in Table 5:
Table 5: Permeability risk distribution
Formation Low Medium High
Res-1 50 mD 100 mD 200 mD
Res-2 1 mD 3 mD 5 mD
Probability 50% 30% 20%
All Kick scenarios are risked according to the input in Table 5. The risked rates presented in Table 6 and Table 7 (far right column) are used as input to the final risk process in Section 3.5.2.
Kick scenario –5m penetration of Res-1
Table 6 and Table 7 list gas condensate rates for the specified scenarios. The far right column of the individual tables represents the risked rate of gas condensate for the range of permeability. Risking of flowpaths are introduced in Section 3.5.2.
Table 6: Permeability risking –Kick scenario –5m reservoir exposure
Unrestricted Flowpath 50 mD 100 mD 200 mD Risked [Sm³/d] [Sm³/d] [Sm³/d] [Sm³/d]
OH 5 m Subsea 635 1232 2156 1118
Surface 647 1243 2172 1131
Restricted Flowpath
50 mD 100 mD 200 mD Risked Sm³/d] [Sm³/d] [Sm³/d] [Sm³/d]
OH 5 m Subsea 424 543 621 499
Surface 423 540 616 497
Note: The methodology for estimating most likely duration of a blowout are under revision and the methodology are likely to be changed or updated later in 2010.
Swab scenario –Fully penetrated Res-1 and Res-2
To simplify the model and restrict the number of scenarios, the reservoir permeability of Res-1 and Res-2 is modeled in a low, medium and high permeability scenario. I.e. all combinations of permeability are not simulated. This leads to the following permeability scenarios:
Table 7: Swab scenario - Permeability risk distribution
Low Medium High
Res-1+Not / Ile+Tilje 50/1 mD 100/3 mD 200/5 mD
Probability 50% 30% 20%
Table 8: Permeability risking –Swab scenario –Full reservoir exposure
Unrestricted Flowpath
3.5.2 Final blowout risk procedure
The process diagram in Figure 9 shows the risk process which is implemented in the analysis presented in this report, and the resulting weighted blowout rates of oil for a surface release.
Surface release vs. subsea release
When drilling from a floater, anchored or dynamically positioned, the OIM will try to pull the rig off from location shortly after an uncontrollable well integrity issue is unveiled and any surface attempt to stop the flow has not succeeded or have been evaluated as unlikely to succeed. This leads to the two different duration estimates for a surface and a subsea release as presented in Table 9 and Table 10.
Step 5 Step 6
All values in Figure 9 above are repeated in the tables below for improved readability. The risked blowout rates and duration distributions are listed in the following tables; Table 9 for surface release, and Table 10 for subsea release.
Table 9: Blowout rates and duration distributions for a potential surface release
Table 10: Blowout rates and duration distributions for a potential subsea release
The risk process illustrates the most likely expected blowout rates for an uncontrolled blowout from the 5505/5-5 NewField North well. These values are risk weighted; therefore both higher and lower rates may be experienced in a real blowout. The risked values are qualified numbers for likely volumes expected, and are to be used when evaluating the possible environmental impact from the well.
As can be seen from Figure 9 and the tables above, the expected gas condensate blowout rate from the NewField North exploration well is 701 Sm³/day for a surface release point and 706 Sm3/day for a subsea release point. The corresponding risked blowout rates of gas are 2.80 MSm3/day for a surface release point and 2.82 MSm3/day for a subsea release point.
There is no significant difference in blowout rates between surface and seabed releases.
The risked durations for surface and subsea release, are 13.1 days and 23.4 days, respectively.
Note: The risked blowout rates shall not be used for evaluating possible kill methods or requirement.
The worst case scenario is described by the scenario with an open and unrestricted flowpath and fully penetration of Res-1 and Res-2 formations with maximum permeability estimates.
In such an unlikely event, the maximum blowout potential is found to be 4445 Sm³/day of gas condensate and 17.8 MSm3/day of gas.
Step 5 Step 6
100.00 % 701 Sm³/day 2.80 MSm³/day Risked duration (days) 13.1
Duration distribution
100.00 % 706 Sm³/day 2.82 MSm³/day Risked duration (days) 23.4
Total sum:
3.6 Possibility for underground blowout
An underground blowout is defined as uncontrolled flow from one or more formations, into one or several formations. If the receiving formations are located above possible sealing rocks, such a blowout might develop into an uncontrolled release to seabed.
In a well control situation, the formation below the last casing shoe could be exposed to pressures higher than the corresponding fracture pressures. Based on lightest possible fluid column from the reservoir to the casing shoe, an analysis is performed to evaluate possible pressure conditions at the last casing shoe.
In the NewField North well, a 9 ⅝” casing is planned set at 3450 m TVD RKB. At this casing
In the NewField North well, a 9 ⅝” casing is planned set at 3450 m TVD RKB. At this casing