Gap analysis between OLF s Summary report to Deepwater Horizon (Macondo) accident and NORSOK D-010, Rev.4 Draft

Transcription

1 Gap analysis between OLF s Summary report to Deepwater Horizon (Macondo) accident and NORSOK D-010, Rev.4 Draft The table below shows where and how NORSOK D-010 rev. 4 responds to the recommendations in the OLF s Summary report to Deepwater Horizon (Macondo) accident. Color denotes that recommendation; 1 : is fully complied with. No further enhancement required. 2: is partially complied - further enhancement may be required. 3: is not complied with, Reason and action is stated in the table. 1 Norsok D-010 should be updated to include the term critical cement job. A requirement for independent design verification of critical cement jobs should also be introduced. This verification can be performed by either an independent in-house department or an external third party Critical cement job defined as the cement job which isolates: the production casing/liner annulus, when set into/through the reservoir, the production casing/liner annulus, when the same casing cement job is a part of the primary and secondary well barriers, or the production casing/liner annulus set into the reservoir, when the well injection pressure 2 Norsok D-010 should furthermore require that cement and casing design for slurries placed across hydrocarbon zones be verified in cementing company labs prior to use. For critical slurry designs, such as those EAC Table 22, Casing Cement: C.1: For critical cement jobs, HPHT conditions and complex slurry designs the cement program should be verified internally or by a third party company. exceeds the cap rock integrity D.1: Critical casing cement shall be logged EAC Table 22, Casing Cement: D.2.a: The cement length shall be verified by: Bonding logs: Logging methods/tools shall be selected based on ability to provide conclusive data for verification of bonding. The measurements shall provide

2 containing foam cement or gas block additives, the slurry design, slurry properties, waiting on cement times and cementing plan should be independently verified. This verification can be performed by either an independent in-house department or an external third party. azimuthal/segmented data. The logs shall be verified by qualified personnel and documented in a report. C.2. For critical cement jobs, HPHT conditions and complex slurry designs the cement program should be verified internally or by a third party company. C.3. The cement recipe shall be lab tested with dry samples from the rigsite under representative well conditions. The tests shall provide thickening time and compressive strength development. 3 a) Norsok D-010 should be updated to define the requirements related to inflow (negative) pressure testing clearly. b) Well programmes should provide a detailed procedure and acceptance criteria for all inflow tests. Inflow tests should be conducted in a controlled manner with detailed procedures which have been approved by an authorized person, and accompanied by a demonstrated risk analysis. This should be covered in Norsok D Pressure test direction The test pressure should be applied in the direction of flow. If this is not possible or introduces additional risk, the test pressure can be applied against the direction of flow, provided that the well barrier element is constructed to seal in both flow directions Inflow testing during drilling and well activities Inflow testing is performed to verify the well barrier element(s) ability to withstand pressure. This applies when displacing the well to underbalanced fluid in preparation for subsequent operations such as completion, well testing, riser disconnect, etc. An inflow (negative pressure) test shall be described in a detailed procedure, which should contain the following information: a) an identification of the well barriers to be tested; b) identification of the consequences of a leak; c) the risk of inconclusive results due to large volumes, temperature effects, migration, etc.; d) a plan of action in the event that leak occurs or if the test is inconclusive; e) a schematic diagram showing the configuration of test lines and valve positions; f) all operational steps and decision points; g) defined acceptance criteria for the test. The following apply for the execution of an inflow test: a) verification of the secondary well barrier s ability to withstand differential pressure; b) volume and pressure control shall be maintained at all times during displacement and testing; c) during inflow testing it shall be possible to displace the well to back overbalanced fluid at indication of flow or in case of inconclusive results; d) during displacement, non-shearable components

3 4 Norsok D-010 should be further clarified to state that, when changing out the fluid barrier element while the remaining barrier consists of untested cement or mechanical plugs, all displacement to a lighter underbalanced fluid should be done with a closed BOP and through the choke and kill lines. 5 Norsok D-010 should be updated to include descriptive values for full/partial/seepage and static/dynamic fluid losses so that deviations in return flow can be reported using a common frame of reference. Such data can be used to generate acceptable downhole loss rates for specific fields. shall not be placed across the BOP shear ram; e) displacement to a lighter fluid should be performed with constant bottom hole pressure; f) when the displacement is complete, the well shall be closed in without reducing the bottom hole pressure; g) the inflow test should be performed by bleeding down pressure in steps, to a pre-defined differential pressure; h) the pressure development should be monitored for a specified time period for each step. See response above (#3) Comment: Descriptive values (i.e. 1,5 m3/hr) has been evaluated, but discarded as it is very difficult to set specific values based on objective/logical argumentation. EAC Table 22, Casing Cement, D.2.b: In case of losses, it shall be documented that the loss zone is above required TOC. Acceptable documentation is job record comparison with similar loss case(s) on a reference well that has achieved sufficient length verified by logging. 6 7 OLF recommends that well control bridging documents be prepared for all future drilling operations. (OLF issued this recommendation to Norwegian operators and contractors in January It has also been referred to the Norsok D-010 revision committee.) Well control action procedures There shall be a plan for activating well barrier(s)/well barrier elements (well control action procedure), prior to commencement of all well activities and operations. These plans shall be made known to all involved personnel. A well control bridging document between Operator and Contractor shall be prepared defining: a) well control roles and responsibilities during the operation; b) shut-in procedures; c) methods for re-establishing well barriers: activation of alternative well barrier elements/envelopes; kill procedures; normalization. c) specific well control configuration for the well activity (including ram configuration).

4 8 9 The need for more practice with well control emergencies is recognised. Norsok D-010 should be updated to include requirements for routine well control exercises, specifically in the areas of: - spacing out and centralising pipe prior to shearing and disconnecting - diverter line-up to overboard lines - well control exercises to be conducted (scope, frequency, acceptance, etc). 10 Norsok D-010 should specify and require periodic testing of emergency subsea well control activation systems, with due regard to operational activities. 11 Norsok D-001 and D-010 should include more explicit requirements for primary and back-up BOP control systems, their ability to perform in emergencies and testing of them Well control action drills The following well control action drills should be performed: (See this chapter table too large to insert here) Annex A, Table A.1: Specifies testing of secondary emergency system : Emergency Acoustic system All ROV hot stab functions Emergency disconnect system Deadman (el.&hyd.power lost) Autoshear (when disconnecting) Not addressed in D-010. See D Operators should conduct a risk assessment to determine the optimum BOP configuration for each well, utilising the latest BOP reliability, performance and assessment data, the design of the well to be drilled, and the rig in use. The findings should be recorded in the well control bridging document. 14 EAC 15.4 Drilling BOP : C.2. A risk analysis shall be performed to decide upon the best BOP configuration for the location in question. The risk analysis should take the following into account: a) Position of different ram types b) Choke and kill line access position c) Ability to hang off pipe and retain ability to close shear ram, including contingency closure of rams if available d) Ability to centralize pipe prior to closing shear ram e) Back-up shear ram

5 15 Norsok D-001 should be updated to ensure that subsea wellhead casing/tubing hangers are locked down on all strings in contact with hydrocarbon-bearing zones. EAC Table 5 Wellhead: D.5. For casing exposed to hydrocarbon flow potential the casing hanger shall have adequate lockdown capacity to guarantee seal integrity during normal working loads as well as well control situations. Casing hangers shall have adequate lockdown capacity to guarantee seal integrity during normal working loads as well as well control situations. 16 to A recommendation on management of change (MOC) should be implemented in Norsok D-010 as follows: a) An MOC procedure covering the well life cycle should be included in the operator s management system steering documentation. The MOC procedure should describe the processes used to assess risk and to mitigate, authorise and document material changes to previously approved information or procedures. Material changes subject to an MOC process include, but are not limited to, the following: - changes in surface and downhole well control equipment - changes that impact well barriers - change in well type (eg, producer to injector) - changes in procedures - changes in rig or contractor well control equipment while on hire to an operator -changes of key personnel. b), applies for Drilling Contractor Management of change A Management of Change (MoC) procedure covering the life cycle of the well shall be implemented. The procedure should describe the processes used to assess risk, mitigate, authorize, and document technical, operational or organizational changes to previously approved information or procedures. A MoC process should cover changes to: g) surface well control equipment; h) impact on well barriers; i) well type (i.e. conversion from producer to injector) j) procedures; k) rig or contractor well control equipment; l) key personnel. A proposed change shall be supported by a justification that should address the following: a) reason for change; b) description of the new proposed solution; c) possible consequences and uncertainties; d) updated risk assessment in line with the proposed change. All appropriate and applicable disciplines shall be involved in the preparation of the proposed solution and/or endorse the proposal. Changes to programmes and procedures shall be approved at the level of the original approval and include input of those affected by the change

6 22 OLF recommends the inclusion of a requirement in Norsok D-010 for setting either pass/fail criteria or assessment KPIs for all key well control and safety exercises. 23 to OLF recommends that Norsok D-010 should require an outline plan and procedure for capping and shut-in of a flowing subsea well, in which the operator demonstrates how to access and install equipment to shut in the well within a reasonable time Drills Regular and realistic drills pertaining to on-going or upcoming operations shall be conducted to train involved personnel in detection and prevention of a lost well barrier. The objective of the drill shall be pre-defined. Pass/fail criteria for all key well control and safety drills shall be established. All relevant personnel with emergency duties should be involved in the drills. The drills should be repeated with sufficient frequency to achieve the acceptable response. All drills shall be approved, evaluated for improvements and documented Plan for capping and shutting in a flowing subsea well An outline plan for capping and shutting in a flowing subsea well should be in place to demonstrate mobilization and installation of capping equipment within a reasonable timeframe. The plan should a) evaluate the feasibility of capping a blow-out scenario at the given water depth, b) identify all connections and possible interfaces from wellhead to flexible joint, c) identify all connections and possible interfaces from XMT to interface to workover equipment, d) include an overview of equipment requirements and availability to allow installation of a capping stack, including an adapter to enable connection of the capping stack, e) consider additional well load cases resulting from a capping operation. 35 To 45