4.4 Main observational results
4.4.2 Kinematics and fluxes of the di fferent ISM components detected by
The surface equipment for well clean up shall follow updated NORSOK requirements. The well stream is flowed via the temporary well test plant and further to the flare boom. Heavier fluid components that cannot be burned will be routed from separator to stock tank before final transfer to slop tanks.
The well test PSD system and the subsea workover PSD system will be integrated into the ESD system on the rig.
A similar surface test plant delivered as by Expro for Kristin and Morvin will be the base case for Zidane.
Drilling and Completion Support Document PL435 Blocks Zidane
R-018832
Figure 15-1: Simplified P&ID of surface test plant used for clean-up of Kristin wells (ref /17/).
Drilling and Completion Support Document PL435 Blocks Zidane
R-018832
16 WELL INTEGRITY 16.1 Barrier Elements
Barrier schematics for all well types and all phases of the operations will be prepared in the DG3 phase.
With reference to OLF 117 “OLF Recommended Guidelines for well integrity”, a report based on a joint solution developed between the operating companies including support from the Petroleum Safety Authority (PSA) has been announced. A survey of operators’ well-integrity-training practices, experiences, opinions and ideas has been carried out and used as a basis for developing a well-integrity-training guideline.
The preliminary barrier drawings for Verification and Monitoring the Zidane production well are based on the best practice from the OLF 117 document. The diagrams assume
horizontal XMT are used. Test pressures are based on Zidane 2 reservoir conditions.
Drilling and Completion Support Document PL435 Blocks Zidane
R-018832
Figure 16-1: Zidane Production Well – Verification of barriers
20"
Subsea Gas Producer - Verification
4870 m MD, 4245 m TVD
Well type: HPHT Gas producer
MWDP 655 bar
Revision no: 0 Date 05.09.2012
Prepared: Bjørn Olav Dahle
Verified: Thilo Theloy
Approved: Jan Petter Rød
Well barrier elements NORSOK
D-010 Method: Cement bond logs 2. Formation at casing shoe 22 LOT 2.15 SG EMW 200 m above reservoir Method: Cement bond logs
2. Casing 2 PT: 680 bar, 1.08 SG MEG/FW
well integrity issues Comment
None Barrier packer
Drilling and Completion Support Document PL435 Blocks Zidane
R-018832
Figure 16-2: Zidane Production Well – Monitoring of barriers Well data
Field: Zidane
Well no: Base Case
Well type: HPHT Gas producer
MWDP 655 bar
Revision no: 0 Date 05.09.2012
Prepared: Bjørn Olav Dahle
Verified: Thilo Theloy
Approved: Jan Petter Rød
Well barrier
1. Casing cement 22 N/a after initial verification 2. Formation at casing shoe 22 N/a after initial verification 3. Casing 2 N/a after initial verification 4. Production Packer 7 Continuous pressure
monitoring of A-annulus.
5. Completion string 25 Continuous pressure monitoring of A-annulus.
6. DHSV 8 Periodic leak testing:
Acceptance criteria: TBA
SECONDARY
1. Casing cement 22 N/a after initial verification 2. Formation at second
casing cement barrier 22 N/a after initial verification 3. Casing 2 N/a after initial verification 4. Wellhead 5 N/a after initial verification 5. Tubing hanger 10 Continuous pressure
monitoring of A-annulus.
6. Tubing hanger plugs 11 Regular monitoring of pressure above plug 7. Sub-sea production tree 31 Periodic leak testing
Acceptance criteria: TBA Notes
Disp. no.
well integrity issues Comment
None
Drilling and Completion Support Document PL435 Blocks Zidane
R-018832
16.2 Well Control
All Zidane wells will be designed, planned and drilled/completed in accordance with prevailing rules and regulations, including RWE Dea Norge’s internal steering documents.
During operations, the drilling contractor's well control procedures will be used in addition to an interface document covering any discrepancies between RWE Dea Norge and drilling contractor’s procedures.
16.3 Well Monitoring
As a minimum, following realtime well monitoring facilities will be established:
Downhole pressure and temperature gauges above production packer
Wellhead pressure and temperature transmitters between PMV and PWV
Annulus pressure and temperature transmitters between AMV and AWV
Pressure and temperature transmitters upstream and downstream choke module
Pressure transmitter on the scale inhibitor line
Acoustic sand sensor downstream choke module
16.4 Annulus Management
In order to avoid abnormal pressures in annulus, the following annulus management actions are planned to be implemented (also ref /18/).
A-annulus:
Continuous pressure monitoring of annulus block through open AMV on XMT. A-annulus shall be operated within defined pressure limits (< MWDP) set with high and high-high alarms. Annulus shall be bled-off during clean-up and re-pressurized with methanol through annulus service line.
B-annulus:
Currently, no monitoring technique is available for subsea pressure monitoring of B-annulus during the production phase. However, technology for realtime B-B-annulus monitoring is under development and a pilot installation can be expected through 2012.
Regardless of this technology will be available for Zidane, the B-annulus is planned to be bullheaded from drilling mud to clear CaCl2 or CaCl2x CaBr2 brine after
cementing of the production casing. This will prevent trapped fluid and temperature expansion due to debris settling and plugged annulus.
Weight should be sufficient to overbalance the open formation above 9 7/8” casing cement. Further, rupture discs will be installed in the 13 3/8” intermediate casing in order to avoid collapsing of production casing. The rupture discs will be installed at in intermediate casing depth close to 20” shoe, i.e. ensuring possible bleed-off from B-annulus to the 20” shoe.
C-annulus:
No pressure monitoring is possible after installation. The C-annulus can be either dressed with rupture discs at 20” shoe or bullheaded from drilling mud to clear brine
Drilling and Completion Support Document PL435 Blocks Zidane
R-018832 in order to avoid trapped annulus pressures, as the intermediate casing has a low collapse rating. Weight should be sufficient to overbalance the open hole formation.
16.5 Annular Fluid Expansion (AFE)
Initial AFE calculations have been performed using the WellCat software. The calculations indicate that high annular pressures will occur if pressures are not relieved in the A, B and C annulus, respectively.
If the production (A) annulus is kept closed the pressure could rise to 750+ bars due to fluid expansion. If the DHSV is closed accidentally in such a situation, the tubing above the DHSV could collapse. Hence, it is important that the actions as proposed in the previous chapter are executed in order to avoid problems related to heated
annulus.
Drilling and Completion Support Document PL435 Blocks Zidane
R-018832
17 WELL INTERVENTION
The wells will be designed to cover more than the expected lifetime of the field, in order to avoid costly rig operations.
Still well interventions cannot be ruled out, since material failures, leaks, reservoir
management measures or other unforeseen circumstances can occur. Hence the well and the subsea structure will be designed to allow for well interventions.
Currently well intervention is only seen feasible with semi-submersible drilling rigs.
Light well intervention vessels (LWIV) are difficult to contract due to existing long term contracts and limited availability.
To investigate the possibly of establishing a LWIV consortium will be part of DG3.
17.1 Types of Intervention
Well intervention can be subdivided by two different criteria.
Foreseeable intervention purposes that may be required:
Repair and maintenance o Well integrity issues:
Leaking tubing, packers, valves, casing/ tubing hangers
other issues o Subsea structure issues
Leakage in the subsea production tree/ manifold system
other issues
Reservoir management o Stimulations, washes o (Re)perforation o Water Shut-Off o Production log
Recompletion for one of the above reasons
17.2 Failure Frequency and Intervention Plan
A study done by Subsurface AS (ref. /9/) shows that the failure frequency of HPHT wells is about 0,09 failures per well-year.
Input to the study was data of 88 North Sea HPHT wells (UK and Norway) with a total of 625 well-years. 55 failures were registered were registered in early- and mid-field life.
Drilling and Completion Support Document PL435 Blocks Zidane
R-018832
Figure 17-1: Failure frequency of North Sea HPHT wells
The main findings of the study were:
Failure rates on HPHT wells are about 2 times higher than on conventional wells
More than 75% of the failures are mechanical failures due to material selection or leaks.
80% of the interventions were done with low cost wireline and pumping operations to improve flow assurance or reservoir management.
85% of the OPEX on HPHT wells is spent on rig based work overs.
The anticipated field life is 8 years, which results in 32 well-years for the field. By applying the failure frequency of 0,09 failures per well-year approximately 3 failures can be expected.
In case a single producer fails and the remaining 3 producers are able to compensate no intervention is required. Also at the end of field life intervention is seen as uneconomic.
Therefore, 2 interventions with a drilling rig are planned for.
Additionally, a work over campaign of all four wells with a LWIV of 56 days is assumed. This covers issues like installing an insert safety valve, treatment of scaling or doing wireline work etc. As these vessels are very weather sensitive extra time for WoW due to operation in the Norwegian Sea is included.
Drilling and Completion Support Document PL435 Blocks Zidane
R-018832
18 RIG REQUIREMENTS AND LONG LEAD ITEMS 18.1 Rig Requirements
Authority Requirements
The rig must hold a valid AoC for working in Norway.
Minimum Basic Specification
The rig must be in accordance with the following:
Capable of working in water depths up to 420 meters.
Fully certified to meet all statutory requirements for operations in Norwegian Waters.
Meet NORSOK HPHT requirements.
Be fitted with a subsea BOP stack, with a minimum pressure rating of 15,000 psi. The BOP stack shall be capable of shearing and sealing all proposed drilling and tubulars (including downhole control lines) excluding drill collars and casing strings with size above 7".
Install a 9 7/8” 66,4# x 10 3/4” 65,7# production casing string without the need of tie-back.
The rig shall be fitted with a logic override to enable a completion string or workstring to be dumped in the well in an emergency.
The rig shall be fully equipped to handle and contain oil based mud and must be capable for skip and ship equipment to be rigged up for cuttings handling containment and transport.
The rig shall be complete with the suitable drill strings (5 1/2" or 5 7/8") for wells up to 6000 m MD, inspected to DS-1 Category 4
The rig shall have a BOP with suitable connector for the wellhead
The rig shall have a dedicated brine storage with a minimum capacity of 300 m³ 1.83 s.g. brine.
The rig shall have a dedicated Mud storage with a minimum capacity of 300 m³, 1.83 s.g. mud.
Completion Requirements
The rig shall be capable of running completions and so must have the following:
Laydown areas for subsea, completion, testing and workover equipment.
The rig shall have a dedicated well test line from the rig floor to the main deck well test area.
Accommodate well test package including nitrogen generator and nitrogen tanks.
Minimum access for skidding of industry standard surface x-mas trees with associated accessories into moonpool.
The bridge crane, if applicable, must have a minimum SWL rating to handle all planned weights in the moonpool.
Drilling and Completion Support Document PL435 Blocks Zidane
R-018832
BOP storage must not hinder access to the moon-pool area.
Fully Certified Burner Booms and necessary cooling systems.
A lay-down area in the moonpool for workover stack while simultaneously being able to skid in/out other subsea components (XMT, HPC etc)
Stacking system on cellar deck for building and testing subsea equipment (LRP, EQDP, XMTRT etc)
Clean brine line from flow line/bell nipple and with branch to select discharge directly into process pits or the active/reserve pits with the purpose of bypassing the shaker system.
18.2 Identification of Long Lead Items
Items with a delivery time of 12 months and more are identified as Long Lead for Drilling and Completion:
All subsea production equipment including XMT, HPC, LRP/EQDP and relevant running tools has at least 2 years lead time. This does NOT include tender phase.
Rig
Workover riser (if not available third party or through rig)
Subsurface equipment and tubular goods, such as casing and liner hangers and tubing.
Completion equipment and accessories (minimum 18 months delivery time). This does NOT include tender phase.
Drilling and Completion Support Document PL435 Blocks Zidane
R-018832
19 PERMANENT PLUG AND ABANDONMENT STRATEGY
All wells will be plugged and abandoned to prevailing rules and regulations at time of operation. Time and cost is based on P&A according to NORSOK D-010 rev.3.
Both the permeable Garn reservoir and the permeable sands in Lange and Lysing formation need to be plugged with regards to achieving two permanent barriers. Thus, the cement jobs of the 13 3/8” and 9 7/8” casing are not only important for achieving production barriers, but also for planning and executing permanent barriers for future permanent P&A of the Zidane wells.
Therefore, it is recommended to perform cement logging of the 13 3/8” casing, and not only 9 7/8” casing, after initial installation and cementing. Good cement jobs with hydraulic isolation will dramatically reduce the required operations time for future permanent P&A operations, and time consuming and demanding operations like section milling, casing milling and additional cut & pull operations can be avoided.
The main P&A strategy involves using the 9 7/8” and 13 3/8” casing cement for achieving 2 ea full cross sectional cement barriers of the well (both vertically and horizontally) against the Garn reservoir and the Lange and Lysing sands, respectively.
The barrier diagrams below illustrate the base case Zidane permanent plug and abandonment strategy.
Drilling and Completion Support Document PL435 Blocks Zidane
R-018832
Figure 18-19-1: Permanent Plug and Abandonment schematic for the Garn reservoir.
20" Casing 1323m MD/ 1320 m TVD
GARN Screens or predrilled liner
WELL BARRIER SCHEMATIC
Permanent Plug and Abandonment of Garn Reservoir
Top Garn reservoir 4870
Well type: Permanent Plug and Abandonment
MWDP 655 bar
Revision no: 0 Date 05.09.2012
Prepared: Bjørn Olav Dahle
Verified: Thilo Theloy
Approved: Jan Petter Rød
Well barrier elements NORSOK
D-010
Method: Cement bond logs 2. Formation bottom of
primary cement plug fundament to 70 bar above frac. Load tested with 10 ton.
SECONDARY
1. Casing cement 22 Length = 50 m
Method: Cement bond logs 2. Formation bottom of fundament to 70 bar above frac. Load tested with 10 ton.
Environmental Isolation Plug
1. Formation at bottom of
surface well barrier 22 FG 1.50 SG Method: Pore pressure prognosis
2. 20” casing cement 22 Surface casing. LOT performed to 1.69 SG EMW
3. Cement plug 24 Set on pressure tested
mechanical plug to 35 bar above formation strength
Notes: Formation pressure top Garn Fm: 1.73 sg EMW
Disp. no.
well integrity issues Comment
None Barrier packer
TOP INTRA LANGE SST 4209 m MD/ 3590 m TVD
Drilling and Completion Support Document PL435 Blocks Zidane
R-018832
Figure 18-2: Permanent Plug and Abandonment schematic for the Lange and Lysing permable formations.
20" Casing 1323m MD/ 1320 m TVD
GARN Screens or predrilled liner
WELL BARRIER SCHEMATIC
Permanent Plug and Abandonment of Lange and Lysing formations
Top Garn reservoir 4870
Well type: Permanent Plug and Abandonment
MWDP 655 bar
Revision no: 0 Date 05.09.2012
Prepared: Bjørn Olav Dahle
Verified: Thilo Theloy
Approved: Jan Petter Rød
Well barrier elements NORSOK
D-010
Method: Cement bond logs 2. Formation bottom of
primary cement plug fundament to 70 bar above frac. Load tested with 10 ton.
SECONDARY
1. Casing cement 22 Length = 50 m
Method: Cement bond logs 2. Formation bottom of fundament to 70 bar above frac. Load tested with 10 ton.
Environmental Isolation Plug
1. Formation at bottom of
surface well barrier 22 FG 1.50 SG Method: Pore pressure prognosis
2. 20” casing cement 22 Surface casing. LOT performed to 1.69 SG EMW
3. Cement plug 24 Set on pressure tested
mechanical plug to 35 bar above formation strength
Notes: Formation pressures Zidane West: Intra Lange Sst: 1.59 SG EMW Lysing Fm: 1.32 SG EMW
Disp. no.
well integrity issues Comment
None Barrier packer
TOP INTRA LANGE SST 4209 m MD/ 3590 m TVD
Drilling and Completion Support Document PL435 Blocks Zidane
R-018832
20 RISK MANAGEMENT AND REGISTER
A Project Risk Register has been developed as a tool to organize, systemize and track all identified risks in the project. Risk assessments, HAZIDs and HAZOPs have to be initiated throughout the project and findings will be collected into the Project Risk Register.
The Risk Register uses the Risk Acceptance Criteria (CMS-PR-Q-110) developed by the Company to categorize risks. The risks will then end up in the green (acceptable), yellow (ALARP) or red (unacceptable) region.
The ALARP principle (As Low As Reasonably Practicable) is applicable for all part of the project and includes that risk reducing measures shall be considered in all aspects of the operation.
Well design should thus implement measures that reduce the frequency for blowout and the related blowout rate.
The risk register will be part of the BOV document.
Drilling and Completion Support Document PL435 Blocks Zidane
R-018832
21 TIME ESTIMATES
Time and cost estimates are within -20% / +30% accuracy. This is in agreement with a
“Class 3 Concept Section estimate” according to the RWE Dea Cost Engineering Guideline (ref. /10/).
The cost estimates for this report are part of the “Cost report – BOV support document”.
Time estimates are based on experience form the exploration well Zidane 1 (6506/7-14 S) and Zidane 2 (6507/7-15 S) as well as on available data from the Kristin and Morvin field developments.
Kristin and Morvin are seen as most relevant due to:
Similar reservoir conditions as Zidane
Recent developments (2005-2011)
Similar completion concepts as Zidane
Norwegian development, NORSOK standard followed
The scope for the estimates covers the drilling and completion of four production wells. X-mas trees, tubing hanger and subsea operations are part of the subsea scope.
21.1 Drilling and Completion Time Model
AGR’s P1 software was used to compute probabilistic and risked time estimates for the production wells.
Four different cases were simulated:
Predrilled liner in S-shape well (Base case)
Cased & perforated liner in S-shape well
Predrilled liner in horizontal well
Cased & perforated liner in horizontal well
For all cases the southern producer in Zidane West (ZWGPR1) was chosen as it has the longest step out in case of S-shape wells and represents an average horizontal reservoir section in case of horizontal wells.
21.1.1 Drilling
The drilling time estimate is based on the experience of the Zidane exploration wells. For deviated 17 ½” and 12 ¼” sections ROP was reduced and wellbore stability risks were increased supported by information provided by Subsurface AS (ref. /9/).
Horizontally/highly deviated drilled 8 ½” sections proved to be challenging in the offset fields and more detailed durations of drilling operations were provided by Subsurface AS.
Drilling and Completion Support Document PL435 Blocks Zidane
R-018832 21.1.2 Completion
The following assumptions were made for the completion time estimate.
• No batch completion operations
• Predrilled liner or standalone screens is base case
• Middle completion (barrier assembly)
• Horizontal XMT system
• Assumed Cs/K-formate brine used for completion
• Super 13%Cr-110 tubing metallurgy and alloy 625 / 718 completion equipment metallurgy as per Zidane material selection
• Downhole gauges in all producer wells
• Landing completion on drill pipe
• Clean-up operation through LRP/EQDP
Offset wells on Kristin and Morvin completed with open hole style completion (pre-drilled liner or SAS) and cased and perforated liner are found in the tables below, as reported to the Rushmore KPIs database:
Well Completion time [days]
Table 21-1: Completion reference wells - Predrilled liner or standalone screens
Drilling and Completion Support Document PL435 Blocks Zidane
R-018832
Well Completion time [days]
Liner length [m]
TD [m MD]
Kristin
5 106 687 6352
6 37 922 5316
7 31 746 6001
8 80 423 5512
9 57 740 5743
10 39 771 5912
11 46 700 6122
12 38 263 5853
Average 54,3 657 5851
Table 21-2: Completion reference wells - Cased and perforated liner completions
Based on experience from these reference wells, an average C&P well will operationally require 12,3 days extra compared to a well completed with open hole style.
21.2 Drilling and Completion Time Estimate
The simulated time estimates include time from spud of the well until clean-up and move to the next well or demobilization. No batching drilling benefits are included.
Figure 21-1: P1 time estimate for ZWGPR1 with base case predrilled liner and s-shape well path
Drilling and Completion Support Document PL435 Blocks Zidane
R-018832
For mobilization / demobilization of the drilling rig additional 6 days are assumed, which are
For mobilization / demobilization of the drilling rig additional 6 days are assumed, which are