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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.

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

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

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

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

Operator WCR Observations – Exploration Cost

• 63% of operators confirmed this impact

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

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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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

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)