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INTERNAL Well Integrity within Norsk Hydro. INTERNAL Date: 2005-01-13 Page: 2 Objective Develop a consistent procedure for management of annular leaks.

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Presentation on theme: "INTERNAL Well Integrity within Norsk Hydro. INTERNAL Date: 2005-01-13 Page: 2 Objective Develop a consistent procedure for management of annular leaks."— Presentation transcript:

1 INTERNAL Well Integrity within Norsk Hydro

2 INTERNAL Date: Page: 2 Objective Develop a consistent procedure for management of annular leaks Risk based approach Routines for early detection and how to handle the leaks Procedure made in collaboration between NH, Exprosoft and Kåre Kopren(PTG) Key items in the procedure: Include detection, diagnosis, assessment and responses to well annular leaks No increase in installation risk (QRA modelling) Specific risk reduction measures Variations in risk level (subsea vs. topside, gas vs. oil, etc.) Applicable to all well types operated by Norsk Hydro In compliance with regulations and standards

3 INTERNAL Date: Page: 3 Principles Overview of well data and limitations shall follow the well throughout the lifetime All leaks shall trigger an internal deviation (synergi) – verification in B&B Well data shall be updated when a leak is detected Checkout of integrity of next casing Test program to identify leak above or below BSV, surface pressure after stabilizing of pressure, leak rate Update of well risk level, based on Wellmaster database Update of operational procedures

4 INTERNAL Date: Page: 4 Status procedure for management of well annular leaks Procedure is finished Remains: Implementation Training of offshore personnel to detect leakages + diagnostic work A pilot course has been held in april. Standard course package will be developed based on the experience from the pilot course All personell involved in detection and diagnostic work offshore and onshore will be invited

5 INTERNAL Date: Page: 5 Historical Norsk Hydro downhole annulus well integrity (WI) issues by field Note: Based on Norsk Hydro WellMaster phase V data (Snorre and Visund currently Statoil), last major database update April 2004 Figure shows “Cumulative #Annulus WI Issues / Cumulative #Completions” by Year

6 INTERNAL Date: Page: 6 Task Force : Well leaks - Root Cause Analysis Reference group : Bj ø rn Engedal (leader), Nils Romslo, Geir Slora, Eli Tenold, Bjarne Syrstad, Torbj ø rn Ø vreb ø, Siamos Anastasios

7 INTERNAL Date: Page: 7 Ongoing work: Well Integrity Management System (WIMS) New database to be developed until 2007 JIP managed by Exprosoft with Hydro, Statoil and Total as participants. A development based on the procedure for management of well annular leaks Purpose: A uniform and structured approach for handling of well integrity during the lifetime of a well. All information available through one system A clear indication of the well barrier status at all times

8 INTERNAL Date: Page: 8 Well Integrity Management System (WIMS) WellMaster software used as a basis – additional applications to be developed Important functionalities: Visualising the well barriers and well barrier elements (WBE) through use of barrier diagrams and barrier sketches Identify the functions and and requirements that the well and each WBE should fulfil Present the status/condition of each WBE (leak, erosion, etc.) Keep record of performed tests and results of tests Keep record of diagnosis results when deviations are identified Keep record of changes in well integrity and resulting corrective actions Overview of well risk status Structured / uniform approach to analyze and evaluate risk

9 INTERNAL Risk based procedure for management of well annular leaks

10 INTERNAL Date: Page: 10 Rationale for risk based approach Reflect variations in actual well risk level Subsea, topside Gas, oil, water Etc. In principle no tubing and casing leaks accepted by the PSA ”to be on the safe side” – leak(s) will affect the operational risk in a negative way However; Regulations and NORSOK D-010 open for risk assessment Departure normally granted by submission of supporting risk analysis results Must incorporate principle of ”risk reduction” – risk should not be significantly higher as a result of the deviation

11 INTERNAL Date: Page: 11 Procedure outline Procedure split in three main tasks (guidelines): 1. Detection and diagnosis 2. Evaluation 3. Implementation and follow-up Main results Extensive diagnosis part Risk assessment method – Specific risk acceptance criteria – Extensive use of quantitative risk analysis (fault tree analysis with WellMaster data as input) – Specific risk reduction measures Documentation of process

12 INTERNAL Date: Page: 12 Task 1; Detection and diagnosis Collection of basic well data (preparatory) Well schematic, P- tests/FIT/LOT, annulus capabilities (as well barrier), annular volumes, fluid densities, etc. When is it needed to assess if there is a leak? Establish Max operational A-annulus pressure (MOASP) = default bleed off alarm limit Establish pressure domain for initiation of diagnosis activities “External factors” diagnosis Abnormal pressure readings may not be attributed to downhole failure/degradation “Internal factors” diagnosis” The potential leak rate to the wellhead surroundings (if blowout through leak path) Amount of hydrocarbon influx to the annulus Leak location (depth and relative to well barriers) Leak failure cause (deterioration/escalation potential) Leak directions Leak location (P vs. TVD) and leak rate estimation tools provided

13 INTERNAL Date: Page: 13 Task 2; Risk assessment and response evaluation Risk assessment stepwise covers several risk factors A risk status code (RSC) is assigned to the well in each step Most severe RSC determines the RSC for the well The well RSC determines a set of actions/risk reducing measures to be implemented - Each risk factor have specific risk factor acceptance criteria Risk factor acceptance criteria basis: No risk increase on installation level (as modelled in QRA) Quantitative analysis performed for a representative ”library” of well types in order to measure relative increase in leakage risk and effect of risk reducing measures Rule based/deterministic acceptance criteria (based on industry practice) – Minimum two well barriers – No leak to surroundings – Allowable hydrocarbon (HC) storage in annuli – Risk of escalation/further detoriation – Change in well kill opportunity

14 INTERNAL Date: Page: 14 Task 2; Well risk status code overview RSCWell RSC descriptionWell risk acceptance ANo downhole leakAcceptable BDegraded well. Small increase in risk (none or only related to HC in annuli) Acceptable. Risk can be controlled CDegraded well. High risk increase (e.g. P A above MOASP during normal operation) Acceptable only if risk factors can be controlled (e.g, reduce P A to below MOASP during normal operation) DDual barrier philosophy not fulfilled / well barriers severely degraded / leak to surroundings Not acceptable

15 INTERNAL Date: Page: 15 RA step 1; Risk factor = Look at well barrier leak rate consequences Leak rate acceptance criteria based on leak sizes reflected in QRA’s on installation level API 14B leak rate criteria (SCSSV) Norsk Hydro risk matrix Different leak rate acceptance criteria for Non-natural flowing or Non-hydrocarbon flowing wells vs. Hydrocarbon flowing wells CriteriaRSC Well barrier leak rate lower than acceptance criterion (not considered a failed barrier) B Leak (any size) to a volume not enveloped by qualified well barriers D

16 INTERNAL Date: Page: 16 RA step 2; Risk factor = Relative change in blowout probability – example Risk status codes based on calculated blowout probability and risk reduction potential assigned toblowout probability and risk reduction potential Surface and subsea wells Conventional wells (applies to production and injection wells) and gas lift wells Informative calculations performed for multipurpose well, and gas lift well alternatives with combinations of deep set SCSSV, no SCASSV, annulus tail pipe SCSSV. Interm. Csg. Barrier Well barrier leak rates greater than acceptance criterion (RAC Item no. 5) T/A leak below SCSSV T/A leak above SCSSV A/B leak T/A leak above SCSSV AND A/B leak Conventional platform well No DCDD Yes DCCC

17 INTERNAL Date: Page: 17 RA step 3; Risk factor = Look at well release risk (HC storage - single failure scenario) Hydrocarbon storage criteria relates to: For surface wells the quantity of hydrocarbons stored in the well annuli should not be greater than the typical mass of lift gas in the A- annulus above the SCASSV in a gas lift well OR alternatively the max recommended volume stored in other vessels on surface For subsea wells the release quantity criterion is based on distance to permanent surface installations (rising gas plume) and environmental acceptance criteria CriteriaRSC The hydrocarbon storage mass in the well annuli is, or may become, greater than the acceptance criterion OR Well annuli fluids are highly toxic (platform well) C OtherwiseB

18 INTERNAL Date: Page: 18 RA step 4; Risk factor = Look at leakage cause (well functionality- degradation) Further escalation that cannot be controlled should not be accepted If further escalation/degradation of the well can be controlled by given risk reducing measures this can be accepted CriteriaRSC Material corrosion or erosion is the (most likely) leak cause. D There is, or is a potential for, exposure of equipment to H2S/CO2 levels that are outside design/NACE specifications. OR There is crossflow (unintended flow) in the well C OtherwiseB

19 INTERNAL Date: Page: 19 RA step 5; Risk factor = Look at mechanical/ pressure loads (well functionality – loads/single failure scenario) Maximum Operational A-annulus Surface Pressure (MOASP) is the limiting wellhead pressure that the A-annulus is deemed safe to be operated under for an extended period of time (years), e.g., for well production. – MOASP = Max known P-integrity of next outer functional annulus (from P- tests, LOT, FIT, recognised field formation fracture gradient data) Checklist for MTP vs. MOASP provided If A-annulus pressure can be controlled <= MOASP this can be accepted CriteriaRSC The maximum potential A-annulus pressure - PA (MTP / A- annulus injection pressure) is greater than MOASP OR Mechanical / Pressure loads causing burst/fracture/collapse is the (likely) leak cause C OtherwiseB

20 INTERNAL Date: Page: 20 RA step 6; Risk factor = Look at well kill/recoverability (well functionality – well kill /single failure scenario) If well kill procedures/preparations can be revised and be equally effective as the base case (well with no failure) this can be accepted CriteriaRSC An additional single well barrier leak situation may affect the ability to efficiently kill the well with mud. C OtherwiseB

21 INTERNAL Date: Page: 21 Response actions The resulting Well RSC determines a set of mandatory (M) and alternative (S) remedial actions/risk reducing measures to be implemented Remedial actions for each RSC based on Norsk Hydro and industry best practice The risk assessment (step 1 through 6) RSC A B C D Response (illustrative example only) ABCD Revise alarm settings MMMM Increased monitoring MM Increased well barrier testing MS Make plans for well kill MM Immediate intervention to restore two well barrier envelopes M

22 INTERNAL Date: Page: 22 Summary Applicable to the well types Norsk Hydro operates In compliance with regulations and standards for the upstream sector of the oil industry Guidelines and worksheets included for detection, diagnosis, and risk assessment and response to well barrier leaks Support tools and formulas for diagnosis included Modular system. Easy to update risk factor acceptance criteria, include additional risk factors, revise risk reduction measures, etc. Documentation of well “history” ”Library” of relative well leak probabilities - The well leak probability for a wide variety of well types and leak locations are modelled for future reference

23 INTERNAL Date: Page: 23 Questions ?

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