Well Control Rule Impacts - Bureau of Safety and ......Well Control Rule Impacts . Nick Mitchell ....
Transcript of Well Control Rule Impacts - Bureau of Safety and ......Well Control Rule Impacts . Nick Mitchell ....
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Well Control Rule Impacts
Evan Zimmerman
Offshore Operators Committee Presentation to BSEE Well Control Rule Forum
September 20, 2017
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Importance of Technical Dialogue
• Appreciation for opportunity to maximize the safety impact of the rule
• Appreciation for the regional and district staff that have been working implementation of the rule
• Confirmation today on impacts of the rule
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Well Control Rule (WCR) Assessment
Cost – Benefit Analysis (OOC) • Report submitted along with joint
trade detailed technical comments to proposed rule.
• Overall BSEE accounted for 2.3% of the estimated direct costs.
• OOC members asked if they can confirm estimated impacts from the unchanged components found in the final WCR rule.
Economic Impact Analysis (GEST) • Woodmac report submitted along with
comments on proposed rule. • Captured indirect impacts. • Detailed assessment of lost
government revenue and impact to investment on the OCS.
• OOC members asked if they can confirm estimated root impacts of this study.
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Operator WCR Observations – Drilling Margins
$-
$1,000,000,000
$2,000,000,000
$3,000,000,000
$4,000,000,000
$5,000,000,000
$6,000,000,000 • 100% of operators confirmed this impact
Industry Estimated BSEE Estimated
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Operator WCR Observations – Cementing
$-
$100,000,000
$200,000,000
$300,000,000
$400,000,000
$500,000,000
$600,000,000
$700,000,000
$800,000,000
$900,000,000
$1,000,000,000 • 88% of operators confirmed this impact
Industry Estimated BSEE Estimated
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Operator WCR Observations – Rig Move Required Shut ins
$-
$10,000,000
$20,000,000
$30,000,000
$40,000,000
$50,000,000
$60,000,000 • 38% of operators confirmed this impact
Industry Estimated BSEE Estimated
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Operator WCR Observations – BOP Modifications
$-
$1,000,000,000
$2,000,000,000
$3,000,000,000
$4,000,000,000
$5,000,000,000
$6,000,000,000
$7,000,000,000
$8,000,000,000 • 75% of operators confirmed this impact
Industry Estimated BSEE Estimated
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Operator WCR Observations – Exploration Cost
• 63% of operators confirmed this impact
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Operator WCR Observations – Basin Investment • Exploration drilling: decreased by 35 – 55% or up to
10 wells per annum • Industry investment: reduced by up to $11 Billion
per annum, on average • Production at risk by 2030: >1 mmboe/d (~35%) • Jobs at risk by 2030: 105 – 190k • GDP reduction: cumulative reduction of $260 -
$390 Billion through 2030 • GDP could decrease by $27 – 45 Billion (25 – 40%)
in 2030 • Government taxes: cumulative drop of up to $70
Billion (20%) through 2030 • Lease sale bonuses: reduced by $3.5 Bil (>40%)
over the period through 2025 in $80 world • Rig decline: 25-50% by the year 2030
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Indication of Staff Resource Impact
0
500
100 0
150 0
200 0
250 0
Pre-WCR Post WCR
APD RPD
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Ii! Years
Well Control Rule Impacts
Nick Mitchell
Offshore Operators Committee Presentation to BSEE Well Control Rule Forum
September 20, 2017
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Key Messages on BSEE WCR • OOC supports the goal of strengthening safety and operations integrity
• Regulations should focus on prevention via a risk based approach
• If the Well Control Rule is not revised, it will result in:
− Unintended consequences (higher risks)
− Compromised ability for Operators to effectively manage risk
− Significant impact to future OCS activity
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Drilling Margin Impacts • WCR does not provide sufficient certainty for Operators to make project investments
– WCR creates prescriptive drilling margin requirements (0.5ppg between MW and integrity of the weakest formation) – Alternative drilling margins are approved on a case by case basis at the time of operations; years after investment decisions
• If strictly enforced feasibility of wells would be challenged; Deepwater and depleted fields most at risk – Some fields have insufficient static margins to meet the regulation as written – Regulation applies broadly indiscriminate of risk; enforced on zones where absence of hydrocarbons has been confirmed – Areas safely drilled with known, manageable loss zones can no longer be penetrated without alternative compliances
• Incentivizes Operators to drill with mud weights closer to pore pressure – Limits ability to manage risk; Results in reduced wellbore stability and increased risk of well control incidents – In some cases, the only alternative would be for prospects to be left undrilled, stranding reserves
• OCS competitiveness reduced; Economic viability of wells requiring redesign would be challenged – Additional casing strings will increase execution time, cost, and potentially complexity – Completion size may be limited and reduce productivity
• Drilling margin requirements should be risk based and enable Operators to apply Industry best practices and technologies to manage narrow margins / lost returns
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Drilling Margin Proposal • To provide additional certainty for operators prior to investment decisions, OOC recommends that BSEE delineate
additional approved drilling margin scenarios as outlined below: – Clarify that drilling margin requirements in the CFR only apply for hole sections with anticipated hydrocarbons
– Implement a tiered analysis for drilling margin application similar to BSEE approach contained in the WCST
• Tier 1: 0.5 pound per gallon or greater drilling margin; approved as outlined in current WCR text
• Tier 2: Drilling margin of at least 0.3 ppg, 2.5% of fracture gradient, or 200 psi with supporting documentation (such as risk assessment data, offset well data, analog data, or seismic data) for the adjusted margin; approved contingent upon supporting documentation
• Tier 3: In lieu of meeting the criteria in Tier 1 or Tier 2, Operator may request alternative Drilling Margin requirements as specified in their APD with adequate documentation for District Manager review and approval on a case by case basis
• OOC recommends that this tiered approach to drilling margin review be applied utilizing the District Manager’s authority outlined in §250.414(c)(2) through a regional policy directive during the ongoing review of the WCR to provide additional clarity for Operators and BSEE Districts
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WCR BOP Impacts • Requirements beyond API Standard 53 (BOP Equipment) - create unintended consequences
– WCR conflicts with API STD 53 which is the product of 2+yrs of Industry collaboration with input from BSEE
– WCR focus is on worst case events rather than early detection and safe handling of well control events
• Requirements inconsistent with API 53 introduce additional complexity and risks to BOPs without adequate justification
• Global rig fleet built to meet established API requirements; incremental requirements above API Standards create
increased investment cost to develop OCS resources compared with foreign opportunities
• OOC recommends that API 53 be incorporated without incremental requirements to avoid unintended consequences
– All future implementation dates for incremental requirements should be delayed until the WCR review is completed
– If BSEE desires to retain incremental requirements to API 53, a comprehensive analysis of the net risk, cost and operational
impacts as a result of each proposed change should be completed in collaboration with industry
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BOP Recommendations • §250.730 - What are the general requirements for BOP systems and system components?
– Remove reference to “flowing conditions” due to ambiguity in application; revert to API 53 requirement for sealing under MASP
– Limit BOP failure reporting to events during operation that required immediate repair; reduce reporting for low impact items
• §250.734 – What are the requirements for a subsea BOP system?
– Update to require the combination of shear rams to shear and seal the wellbore consistent with API 53
– Remove flying lead requirements; insert goal based regulation ensuring BOP allows ram closure with ROV within 45 sec (API 53)
– Subsea accumulator requirements should be focused on performing critical emergency functions and allow shared volume
between autoshear, deadman, and acoustic / ROV flying lead systems consistent with API 53
– Remove prescriptive requirements for “centering mechanisms” which limit technology development; regulation should allow
flexibility for the best technical solution
– Limit subsea deadman test to intervals outlined in API 53; inherent risk without electrical / hydraulic communication with the BOP
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BOP Recommendations • §250.735 - What associated systems and related equipment must all BOP systems include?
– Codify BSEE clarification that surface accumulator systems compliant with API 53 meet WCR intent
• §250.737 – What are the BOP system testing requirements?
– Revise BOP pressure / function test frequency to align with API 53; WCR more than doubles the cycles on critical BOP components impacting operating life and reliability
– Revert to API 53 for subsea BSR test pressures; WCR increases risk and requires absolute test pressures that exceed casing integrity
– Codify clarification that only one test per component to the high pressure test value is required on a surface / subsea test sequence
• §250.738 – What must I do in certain situations involving BOP equipment or systems?
– Limit areas where critical path approval is required; revise to 72hr notification vs. pre-approval for resuming operations with:
• New or repaired BOPs that comply with permitted BOP configuration and are certified by an independent third party
• BOPs that comply with the CFR, but have redundant components that have reduced or lost functionality (e.g. acoustic system)
– Recognize kill weight fluid as a barrier per API 65-2 in situations where it can be continuously monitored and maintained
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Realtime Monitoring • WCR creates new requirements for onshore monitoring systems not supported by Industry Standards
– Risks shifting focus of decision making; compromises long term effectiveness of wellsite supervision – Remote monitoring stations lack the situational awareness of wellsite personnel – Requires a shift from Operators’ global operations integrity management systems and procedures – Critical that regulations ensure Operators have clear authority for their respective operations; regulation should focus on
specifying the range of risks that need to be addressed
• Onsite staff are best positioned to make effective real-time decisions and minimize risk – Experienced and trained to confirm safety, environmental and well control standards are met – Familiar with governing procedures and operations integrity guidelines – Will have the most complete understanding of any operation, especially during a dynamic situation
• Realtime data feeds are frequently employed to assist offsite engineers – Mainly used for analyzing trends and further enhancing performance on subsequent operations – Data is available for viewing from individual engineering workstations – Reviewed by the offsite team in regular surveillance discussions, especially during critical operations
• Recommend removing §250.724; utilize performance-based assessments of well monitoring capabilities – Enables fit-for-purpose approach and effective management of risk in daily operations – Allow Operators to deploy personnel in the most effective manor to manage operations
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Cementing Requirements • WCR cement design and evaluation requirements do not allow for consideration of well specific job objectives
– Prescriptive requirement results in supplementary evaluation after job objectives are confirmed per API STD 65-2
– Limits ability for operators to manage risk; inconsistent application across districts
• WCR increases BSEE’s role in critical path decision making; results in operational delays waiting for approval
• Ambiguity in cement evaluation requirements can result in Operators waiting for approval prior to setting
mechanical barriers; enhanced clarity would reduce risk
• Alternative compliances for cement evaluation and remediation are responsible for a large portion of re-permitting
obligations due to the prescriptive nature of the regulation
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Cementing Recommendations §250.421 What are the casing and cementing requirements by type of casing string?
• 250.421 defines cementing design requirements without consideration of well specific details
– Deviation from prescriptive requirements regularly needed (trapped annulus concerns, known lost returns intervals, ECD concerns, etc.)
– §250.420(a) clearly outlines goal based requirements for casing and cementing programs; §250.415 incorporates API 65-1 and API 65-2
– Regulation should allow Operators to outline how they have met BSEE defined job objectives (250.420(a)) leveraging industry standards
§250.428 What must I do in certain cementing and casing situations? • 250.428(c) outlines when cement evaluation is required and the accepted evaluation methods
– Adequacy of cement job should be based on well specific cementing objectives per API 65-2 and not generic requirements outlined in 250.421
– BSEE should allow for planned lost returns where pre-job engineering design demonstrates that cement objectives can be achieved
– Cement evaluation utilizing lift pressure in combination with volumetric analysis should be allowed to confirm that job objectives were achieved
• 428(d) defines requirements for review and approval of remedial cementing operations
– Incorporate pre-approval of standard remedial cement operations as part of the APD if PE certification is provided
– Removes requirement for critical path approvals and potential operational delays
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BAVO Requirements • WCR requirement for creation of BSEE Approved Verification Organizations misaligned with Executive Order for
Implementing an America First Offshore Energy Strategy
– If WCR remains unchanged clarification of BSEE’s assumed responsibility, accountability, and liability is required for
equipment / operational issues related to mandated BSEE Approved Verification Organizations • WCR created multiple redundant certification requirements increasing regulatory burden and cost of operations for
OCS projects without an enhancement in the safety of operations
– Mechanical Integrity Report (MIA) is redundant to the per well certification of equipment fitness for service
– WCR even requires a certification that Operators have submitted the appropriate certifications (§250.731(f)) • Recommend removing §250.732(BAVO Requirements) and reverting to interim safety rule requirements previously
contained in §250.416 (e), (f), and (g) for independent third party verification
– Interim safety rule required verification of critical well control equipment; no justification provided for additional regulatory burden and prescriptive use of BSEE Approved Verification Organizations
– Leverage API 53 for BOP inspection and maintenance requirements; per well certification of BOP maintenance and inspection is required by §250.731(c)