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WHITE PAPER

INTERIM FINAL DRILLING SAFETY RULE - “SHOULD” TO “MUST” ISSUE

Background

This white paper outlines the adverse and unintended consequences of the BOEMRE‘s Interim 

Final Drilling Safety Rule‘s (IFR) implementation of a prescriptive regulatory action. 

Specifically, the IFR‘s new provision codified at 30 C.F.R. § 250.198(a)(3) through a single 

administrative mandate changes the substantive meaning of 80 API standards and RPs 

incorporated by reference in BOEMRE‘s rules by converting approximately 14,000 instances of 

the word ―should‖ to ―must.‖ Moreover, because § 250.198(a)(3)‘s ―should‖ to ―must‖ change 

by its terms applies to all of the standards and RPs incorporated by reference in Part 250 and 

listed in § 250.198, the change has impacts that are outside the scope of drilling safety. We note 

that 30 CFR § 250.198(a)(3) applies to many more documents than the 80 API standards 

incorporated by reference. For example, BOEMRE regulations also incorporate documents 

published by American Concrete Institute (ACI), American Institute of Steel Construction 

(AISC), American Society of Mechanical Engineers, (ASME), American National Standards 

Institute (ANSI), American Society of Testing and Materials (ASTM), American Welding 

Society (AWS), and National Association of Corrosion Engineers (NACE), we believe this could 

include at least an additional 20 incorporated standards. In fact, it affects all aspects of offshore 

production, from exploration seismic work through production and abandonment of production 

facilities. This white paper recommends an alternative better fitted to the IFR‘s stated purpose of 

enhancing the safety of drilling operations than § 250.198(a)(3) and avoids the adverse 

consequences for safety, internal regulatory contradictions, administrative burden and general 

confusion caused by the section.

As comments submitted on the IFR by API and other industry representatives demonstrate (see, 

e.g., excerpts from API comments attached as Appendix A), compliance with 30 CFR 

§ 250.198(a)(3), as promulgated, would lead to increased safety risks in some situations and is 

under certain circumstances impossible. Further, because API standards are not drafted with the 

intent that discretionary provisions will become regulatory prescriptions, the experts who 

develop the standards do not draft them to create concrete requirements that could be effectively 

audited by any government regulator.

Although BOEMRE‘s intent in the IFR appears to have been to convert industry‘s best practices

for drilling operations into mandatory regulatory requirements, the IFR‘s unnecessarily 

overbroad attempt to implement this intent through a single administrative mandate in § 

250.198(a)(3) creates the need for clarification. API‘s standards and RPs by their nature do not 

lend themselves to a simplistic conversion into inflexible regulatory mandates. API‘s 

standardization policy is that ―API standards shall be based on performance to the maximum 

extent feasible.‖ This policy allows the voluntary consensus committee members to consider 

―designs, techniques, processes and materials that have been demonstrated to be satisfactory for 

the service intended.‖ ―Innovation is encouraged‖ and ―[n]ew designs, techniques, processes 

and materials shall be considered for standards when reasonable proof of fitness is available.‖ 

Thus, API‘s standards and RPs often present a number of options for protecting safety, 

depending on individual circumstances, and defer to the best professional judgment of the 

engineers and other personnel responsible for safety. Fundamentally, performance based 
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standards are designed to allow for safe operations and innovation and by design provide for a 

variety of compliance modes and methodologies rather than a single, mandated approach.1

Recommendation

The Final Rule should be modified to fit its express purpose of enhancing drilling safety. Based 

on the preamble to the IFR and conversations with BOEMRE personnel, it appears that the areas 

of focus intended by the IFR are those addressed by: (1) API RP 53, Recommended Practices for 

Blowout Prevention Equipment Systems for Drilling Wells, Third Edition, March 1997; 

reaffirmed September 2004, Order No. G53003 (―RP 53‖), certain provisions of which are 

incorporated by reference at 30 C.F.R. §§ 250.442(c), 250.446(a), 250.516(g)(1), 250.516(h), 

250.617(a)(1), and 250.617(a)(1) (b); and (2) API RP 65–Part 2, Isolating Potential Flow Zones 

During Well Construction; First Edition, May 2010; Product No. G65201 (―RP 65–Part 2‖), 

which is incorporated by reference at 250.415(f) as a result of the IFR.2See, e.g., 75 Fed Reg 

63,356. 

Modify the Final Rule to mandate that operators consider RP 53 and RP 65–Part 2 in the 

development of their well plans, but do not convert these two or any other recommended 

practices or standards to prescriptive regulatory requirements by administrative mandate. 

Additionally, mandate that operators include documentation of their evaluation of the best 

practices contained in RP 53 and RP 65–Part 2 in their well planning with their Applications for 

Permits to drill. (Note that the BOEMRE‘s Gulf of Mexico OCS Region Office currently has a 

form that it instructs operators to use and submit with their APDs, and that form is attached for 

reference at Appendix B. This form is substantially based on Annex D contained in API RP-65-

2. This annex has been updated in Standard 65-2, 2nd edition, published December 2010.

Proposed Modifications:

(1) Modify the introductory paragraph of § 250.420 entitled ―What well casing and 

cementing requirements must I meet?‖ to read as follows:

You must case and cement all wells. Your casing and cementing programs must 

meet the requirements of this section and of §§ 250.421 through 250.428, and in 

developing your well plan you must evaluate the best practices included in API 

 

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In fact, the Special Notes to all API standards and Recommended Practices state: 

API publications are published to facilitate the broad availability of proven, sound engineering and 

operating practices. These publications are not intended to obviate the need for applying sound 

engineering judgment regarding when and where these publications should be utilized. The 

formulation and publication of API publications is not intended in any way to inhibit anyone from 

using any other practices.

2 API has superseded RP 65–Part 2 with API Standard 65—Part 2, Isolating Potential Flow Zones During Well 

Construction, Second Edition, December 10, 2010 (―Standard 65—Part 2‖). API‘s comments recommend that 

BOEMRE update the interim final rule to incorporate Standard 65—Part 2 by reference rather than the nowsuperseded RP 65–Part 2.
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Standard 65—Part 2, Isolating Potential Flow Zones During Well Construction, 

Second Edition, December 10, 2010.

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(Proposed new text appears in italics.) This proposed new requirement aligns with new 

§ 250.415(f), which requires operators to submit ―a written description of how you 

evaluated the best practices included in API RP 65–Part 2 . . . .‖

(2) Modify § 250.416, which appears in the section describing information submittal 

requirements for drilling permit applications (§§ 250.410 through 250.418) and is entitled 

―What must I include in the diverter and BOP descriptions?‖ to add a new provision (f) as 

follows:

(f) A written description of how you evaluated the best practices included in API 

RP 53, Recommended Practices for Blowout Prevention Equipment Systems for 

Drilling Wells, Third Edition, March 1997; reaffirmed September 2004, Order 

No. G53003.

This proposed new requirement aligns with the requirements of: § 250.442(c) (―The 

accumulator system must meet or exceed the provisions of Section 13.3, Accumulator 

Volumetric Capacity, in API RP 53 . . . .‖); § 250.446(a) (―The BOP maintenance and 

inspections must meet or exceed the provisions of Sections 17.10 and 18.10, Inspections; 

Sections 17.11 and 18.11, Maintenance; and Sections 17.12 and 18.12, Quality 

Management, described in API RP 53 . . . .); § 250.516(g)(1) (―The BOP inspections 

must meet or exceed the provisions of Sections 17.10 and 18.10, Inspections, described in 

API RP 53 . . . .‖); § 250.516(h) (―The BOP maintenance must meet or exceed the 

provisions of Sections 17.11 and 18.11, Maintenance; and Sections 17.12 and 18.12, 

Quality Management, described in API RP 53 . . . .‖); and § 250.617(a)(1) (―The BOP 

inspections must meet or exceed the provisions of Sections 17.10 and 18.10, Inspections, 

described in API RP 53 . . . .‖), and (b) (―The BOP maintenance must meet or exceed the 

provisions of Sections 17.11 and 18.11, Maintenance; and Sections 17.12 and 18.12, 

Quality Management, described in API RP 53 . . . .‖). This proposed new requirement 

would necessitate that a verification process similar to that developed by the BOEMRE‘s 

Gulf of Mexico OCS Region Office for RP 65–Part 2 be developed for RP 53.

(3) Delete new regulation § 250.198(a)(3).

We thank you for your consideration and welcome the opportunity to discuss these matters 

further with you at your convenience.

 

3 The reference in our proposed language to Standard 65–Part 2 rather than RP 65–Part 2 is premised on the 

assumption that BOEMRE accepts the recommendation that Standard 65–Part 2 rather than RP 65–Part 2 should be 

incorporated by reference into the Final Rule.
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APPENDIX A - Excerpt from Comments regarding Increased Safety Measures for Energy 

Development on the Outer Continental Shelf, 1010–AD68 Submitted to Bureau of Ocean Energy 

Management, Regulation and Enforcement by API, IADC, IPAA, NOIA, OOC and USOGA on 

December 13, 2010.

There is no reasonable regulatory basis for adopting a blanket requirement for all 

discretionary language to become mandatory.

BOEMRE has not stated any added safety benefit to be gained from revising language in 

over 14,000 discretionary provisions. 

The change would render many provisions impossible to comply with, it is not logical 

that safety benefits are available for all 14,000-plus currently-existing discretionary 

provisions. 

BOEMRE did not state why it was changing its interpretation of the word ―should‖ as 

used in API standards to mean ―must.‖ 

BOEMRE‘s interim final rule should not replace the open process used to arrive at API‘s 

standards and the broad expertise which goes into setting these standards. 

The API standards-setting process that resulted in the discretionary provisions at issue 

incorporated the collective judgment of thousands of industry experts. API sets its 

standards through an open process involving thousands of industry experts. The 

extensive deliberations have resulted in language which is crafted to unequivocally 

communicate the document‘s intent. 

“Mandatory compliance” with discretionary API standards provisions is impossible in 

many cases, as the standards were not drafted with mandatory compliance in mind.

The experts who created these provisions did not phrase them with the intent to create provisions 

that can be effectively audited by any government regulator, and in some cases, mandatory 

compliance would result in increased safety risks. Further, many of the provisions, when read as 

mandatory, are internally inconsistent for compliance purposes and may conflict with each other. 

1. Changing discretionary provisions to mandatory provisions will result in serious 

confusion and is not likely to result in auditable mandatory provisions.

The immediate effect of BOEMRE‘s interim final rule will be confusion, both in industry and 

among BOEMRE‘s own enforcement personnel. This is because the provisions BOEMRE has 

revised were drafted to afford operators discretion to adopt the appropriate options that best fit 

their operating circumstances and were never drafted with mandatory ―compliance‖ in mind. 

These provisions often present a number of options for protecting safety, depending on 

individual circumstances, and defer to the best professional judgment of the responsible safety 

engineers. Under 30 CFR § 250.198(a)(3), companies would be required to consider which 

discretionary options to require, which to ignore, what the elements of the often-unelaborated 

discretionary elements actually are, and make attempts at compliance. Once the companies have 

made attempts at compliance based on their own opinions, BOEMRE enforcement personnel 

will then impose their own opinions on what the discretionary language actually requires, and 

attempt to audit compliance based on their own understanding. The result will be confusion and 

wasted compliance and enforcement resources. Though BOEMRE apparently intended to 
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require industry best practices, this rule will effectively demand revision of the API standards by 

interpretations made by individual companies and government enforcement inspectors, which is 

likely to lead to conflicting interpretations and less-uniform application. 

Part of the reason for this likely outcome is that API‘s standardization policy states that:

―API standards shall be based on performance to the maximum extent feasible.‖

This is to allow the voluntary consensus committee members to consider ―designs, techniques, 

processes and materials that have been demonstrated to be satisfactory for the service intended.‖ 

―Innovation is encouraged‖ and ―[n]ew designs, techniques, processes and materials shall be 

considered for standards when reasonable proof of fitness is available.‖

Performance based standards are designed to allow for safe operations and innovation and by 

design will provide for a variety of compliance modes and methodologies. Therefore, requiring 

industry to treat over 14,000 ―shoulds‖ as ―musts‖ in the 80 referenced API standards will create 

conflicts due to potential confusion and existing mutually-exclusive requirements. 

2. Blanket revisions of the word “should” to be read as mandatory would actually increase 

safety risks in some cases.

A very preliminary review of one the API standards BOEMRE should be most focused on, 

Recommended Practice 53, Recommended Practices for Blowout Prevention Equipment Systems 

for Drilling Wells, immediately revealed at least two instances where the interim final rule would 

increase safety risks for offshore workers. For example, section 17.4.1 of RP 53, outlining 

installation testing requirements for the diverter system, states:

d) A pressure integrity test [200 psi (1.38 MPa) minimum] should be made on the 

diverter system after each installation. The tests may be made on parts of the system on 

individual components of the system should certain components of the casing string or 

riser components not support a complete system test. (emphasis added).

However, mandatory pressure integrity testing will not be possible when installing a diverter 

system on strings which are not cemented, such as drive pipe. A mandatory testing requirement 

would be detrimental to the formation integrity of the casing shoe, resulting in increased safety 

risks to workers and increased environmental risk. 

Another example of increased safety risks that would be caused by the interim final rule‘s 

blanket language is found in section 18.10.1, which states:

After each well, the well control equipment should be cleaned, visually inspected, 

preventative maintenance performed, and pressure tested before installation on the next 

well. (emphasis added).

Revising this section to include a mandatory requirement for cleaning, visual inspection, 

preventative maintenance, and pressure testing will increase the risk to worker safety. The 

mandatory requirement would eliminate the ability to use a subsea BOP on batch operations on 
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multiple wells on a template location without pulling and inspecting the stack. There would be 

no additional safety benefit for this, since the stack is still subject to pressure testing 

requirements when it is moved from well to well. Most importantly, pulling, handling, and rerunning the riser and BOP creates additional risk to offshore workers that can be avoided under 

the current language found in section 18.10.1.

3. Some provisions are simply impossible to “comply” with in a mandatory compliance 

regime.

An initial review identified major conflicts presented by 30 CFR 250.198(a)(3), which make 

compliance with those standards impossible. To highlight this issue and these conflicts, 

commentary is provided on the following key standards: Spec 6A, RP 65-2, RP 53, MPMS 

Chapter 7, 20.1 and 21.1. These documents represent an important subset of the referenced 

standard and include valves, blow-out preventers, cementing practices, and measurement 

techniques.

API Spec 6A, Specification for Wellhead and Christmas Tree Equipment, 19th Edition, July 

2004 

The following are requirements in conflict if must is substituted for should: 

10.2.2.3 Thread counter-bores - End and outlet connections, equipped with internal threads, may 

be supplied with or without a thread-entrance counter-bore. Internal threads, furnished without a 

counter-bore, should have the outer angles of 45° to a minimum depth of P/2, as illustrated in 

the figure belonging to Table 61* and Figure 10. Internal threads, furnished with a counter-bore, 

should conform to the counter-bore dimensions specified in Table 61* and the bottom of the 

counter-bore should be chamfered at an angle of 45°. As an alternative, counter-bore dimensions 

may be as specified in API Spec 5B.

Conflict: Clause prescribes bore dimensions with no option, and then allows for alternatives.

Annex A, Informative, Purchasing guidelines, A.1 General - To use this annex, a copy of the 

data sheets should be completed as accurately as possible. The typical configurations should be 

referred to, as needed, to select the required equipment. The decision tree, given in Figure A.14, 

together with its instructions, provides the recommended practice as to which PSL each piece of 

equipment should be manufactured. A copy of the data sheet should then be attached to the 

purchase order or request for proposal. 

Conflict: Highlighted clause is prescriptive and does not allow for changes to accommodate any 

needed variations specific to unique site conditions.

Annex D, Informative, Recommended flange bolt torque, D.1 General - It has been shown that 

the torque values given in the tables of this annex are acceptable values for use in type 6B and 

6BX flanges in some services. The user should refer to API TR 6AF, API TR 6AF1, API TR 

6AF2 and API Spec 6FA for data on the effects on flange performance of bolt preload stress and 
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other factors. It should be recognized that torque applied to a nut is only one of several ways to 

approximate the tension and stress in a fastener.

Conflict: Makes API TR 6AF, API TR 6AF1 and API TR 6AF2 no longer bibliographic 

references, but now normative references.

Annex H, Normative, Design and manufacture of surface wellhead running, retrieving and 

testing tools, clean-out tools and wear bushings, H.2.3 End connections - Torque-operated tools 

should preferably be threaded left-hand for make-up and right-hand for release to prevent 

inadvertently backing off of casing/tubing/drill pipe connections during operation/disconnection. 

Conflict: Does not allow for changes necessary for the specific site configuration.

H.3.3 Mechanical property requirements - The material requirements for wear bushings shall 

comply with the manufacturer's written specification; however, the hardness must be between 

241 HBW and 321 HBW.

Conflict: Potential conflict with manufacturer specification.

API RP 65-2, Recommended Practice for Isolating Potential Flow Zones During Well 

Construction, 1

st Edition, May 2010

4.2, Hole Geometry - The relationship between hole size and casing size should, from a 

cementing perspective, always strive to achieve the best balance between displacement 

efficiency and equivalent circulating density.

Conflict: This is a recommendation for designing and modeling of the well. It would be 

impossible to quantify ―achieving the best balance.‖ There are many other factors that also need 

to be taken into account during the modeling and simulation.

4.3.1, Drilling Fluid Selection - Low-gravity or active solids should be effectively controlled, 

and adequate shale inhibition should be provided for aqueous drilling fluid systems. HTHP filter

cakes should exhibit thin, low permeability characteristics. Gel strength and low shear rheology 

at HTHP conditions should be low and non-progressive, but not at the sacrifice of drill cuttings 

transport or barite support.

Conflict: While the listed characteristics of drilling fluids can result in a drilling fluid that is 

more effectively displaced during cementing, it is not always the case that these characteristics 

can be met within the well conditions. Requiring all of this would create significant 

impediments.

4.3.3, Hydrate Prevention - Pre-emptive measures should be taken to insure [sic] that hydrates 

do not form and do not become a safety/well control problem.

Conflict: Hydrates are not found in every drilling condition, they are mainly found in high 

pressure locations (e.g. deepwater), and so making this recommendation a requirement would 
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introduce an undue burden for (at least) onshore applications of the document. Further, it is not 

possible to ensure that hydrates do not form, since they can occur naturally.

4.5, Close-tolerance and Other Flow Restriction Considerations - Close mechanical tolerances 

should be examined for mechanical (drift) compatibility with all components involved in the 

cementing operations including wiper plugs and associated operating components.

Conflict: This recommendation would become an ambiguous requirement as there is no guidance 

as to what are the failure criteria.

4.6.5.3, Fluid Type - In addition, all fluids used in the cementing operation should be 

compatible.

Conflict: Making this a requirement would unduly burden the operator. The intent of this 

 ̳should‘ is that all fluids that come into contact with each other should be compatible, not just 

every fluid used in cementing.

4.6.5.5, Mud Compressibility - For more accurate cement computer displacement simulations, 

mud samples should be tested at a laboratory under higher, more realistic confining pressure.

Conflict: It is not necessary to lab test under higher pressures if actual downhole pressure 

measurements can be used. Such lab testing can also significantly increase costs since there are 

only a limited number of labs outfitted with pressurized testing facilities

4.7.1, Slurry Design, General - Cement should be placed in the wellbore and provide good 

contact with the casing and borehole wall, prevent the formation of channels within the cement 

and prevent the invasion and propagation of fluid through the cement as it sets, and provide 

mechanical support. The cement should maintain its integrity throughout the life of the well.

Conflict: Cementing is not only done between the borehole and casing, it can also be done 

between pipe and pipe. It would be needlessly restrictive to impose only cementing between 

borehole and casing.

4.7.8, Gel Strength - Additives for controlling other properties of the cement should be selected 

with control of gel strength in mind.

Conflict: Not every additive will impact gel strength, and occasionally, the properties being 

controlled by those additives may be more important to control than selecting it based on 

abilities to control gel strength.

4.8, Wellbore preparation and conditioning - Every effort should be made to minimize the time 

between completion of the hole interval and cementing when flow hazards exist.

Conflict: This recommendation is not auditable if made a requirement. It is not possible to 

quantify what ―every effort‖ is.
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4.8.3.2, Centralizer Program - The recommended standoff should be determined from computer 

modeling of mud removal and will vary with well conditions (see discussion above in 4.6). 

Centralizers should be run according to an engineering design for optimum cementing results. 

Conflict: There are times when experience and actual well conditions will supersede a computer 

model or theoretic engineering design in determining proper centralizer placement. While 

following these recommendations will help in developing an adequate centralizer program, it 

does not take the place of sound engineering practices and real in-situ conditions.

4.9.3 Transportation and Storage of Cementing Materials - ... Tanks should be physically swept 

out after a cement blend is stored in the tank

Conflict: Safety. Requiring a tank to be physically swept out will require workers to enter the 

storage tanks to sweep them out. Workers will be required to work in dusty, confined space entry 

work conditions, exposing them to health and safety hazards. (If the First Edition is used this 

remains a conflict. If BOEMRE incorporates API Standard 65-2 Second Edition by reference 

this is no longer a conflict) 

4.9.4, Mixing and Pumping - The cement spacer(s) and slurries should be mixed at the planned 

densities.

Conflict: Some variance in density will occur with field mixing equipment which is allowable, as 

long as the acceptable performance properties of the fluids are met.

4.9.5, Implementing the Job Design and Adhering to Planned Procedures - All the  ̳shoulds‘ in 

the section.

Conflict: One could unintentionally affect the integrity of the cementing job if the pumping is 

done only with consideration to the planned rates and volumes. While these should be 

considered and it should be done as close to these rates as possible, density control should not be 

compromised. Further, information from the computer simulation should be used to determine 

the rates, in conjunction with sound engineering practices, not just with the computer simulation 

alone.

Additionally, BOEMRE should refer to 4.6, Engineering Design, of RP 65-2 with regards to 

when to test cement. (4.6.3 for determining the ―waiting on cement‖ or WOC time). In the 

current regulations, BOEMRE requires 8- to 12-hr periods, which could be detrimental if the 

cement is hydrating. The method described in 4.6.3 is specific to attaining a minimum 

compressive/sonic strength, which is a more reliable practice than just a time period.

In addition to the RP conflicts with operations as noted above, the current CFR‘s have conflicts 

with the RP which will now need to be resolved. Some examples of the conflict are as follows;

Clarify that all zones capable of flow do not have to be isolated by cement. However abnormal 

pressure must be isolated from normal pressure and hydrocarbon bearing zones must be covered 

by cement as stipulated under 30CFR250.421(d) & (e).
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30 CFR 250.423 requires a pressure test on casing for at least 30 minutes. RP-65 requires a 

transition time of less than 45 minutes. Thus performing the required casing test per the CFR will 

likely create a micro annulus that all are trying to avoid. Thus the CFR's and RP-65 are not 

compatible.

API RP 53, Recommended Practice for Blowout Prevention Equipment Systems for Drilling 

Operations, 3rd Edition, March 1997, Reaffirmed: September 2004, 2-Year Extension: May 

2010

While the regulations only cite six sections of RP 53, some potential conflicts do exist:

17.11.6 and 18.11.6, Maintenance, Lubricants and Hydraulic Fluids - The original equipment 

manufacturer should be consulted for the proper lubricants and control fluids to be used on 

surface applications, a light mineral-based hydraulic fluid can be used.

17.11.7, Maintenance, Weld Repairs - The original equipment manufacturer should be consulted 

to verify proposed weld procedures.

Conflict: The above statements will be impossible to comply with if the BOP Original 

Equipment Manufacturer (OEM) is no longer in business.

Manual of Petroleum Measurement Standards Chapter 7, Temperature Determination, 1

st

Edition, June 2001, Reaffirmed March 2007

While there are already several ―musts‖ already used in the document, in regard to calibration of 

devices for custody transfer and safety requirements, there are still potential conflicts in the 

following areas:

5.1, Fixed Automatic Tank Thermometers (temperature measurement in tanks) - The selection of 

a single-point (spot), mid-level, multiple-point, or an averaging ATT should be made based on 

the expected tank temperature stratification and the accuracy requirements (custody transfer 

versus inventory control).

Conflict: Should and shall (must) requirements require that temperature measurements be taken 

at certain depths in tanks. It could be difficult to ―hit‖ these depths exactly as the conditions are 

not always conducive to perfect measurement due to field conditions.

5.3, Glass Thermometers and traceability - Glass reference thermometers include completeimmersion thermometers, partial-immersion thermometers, and total-immersion thermometers 

(see Figure 4 and refer to ASTM E 344). These thermometers should conform to ASTM E 1 

specifications for thermometers or to National Institute of Standards and Technology (NIST) 

specifications. Calibration must be traceable to NIST-certified instruments.
11

Conflict: All thermometers should be traceable to the National Institute of Standards and 

Technology, NIST. NIST recently announced that they will no longer calibrate Mercury in Glass 

Thermometers after March of 2011.

Appendix D: Test Procedures for determining immersion times of measuring devices – All tests 

start with glass thermometers in their assemblies stabilized at the ice point...suggested bath 

temperatures at which immersion times should be measured are provided in Table D-1.

Conflict: Immersion times are specified for PETS and woodback case assemblies. These times 

are listed as ―recommended‖, but the standard implies ―should‖ in the use of these times as they 

are also referenced as required. This could pose problems as the times vary from 30 seconds to 

45 minutes for in motion measurements and 10 minutes to 60 minutes for stationary 

measurements. The field personnel taking these measurements may not be able to time 

immersions exactly according to the required values, again influenced by field conditions. 

Manual of Petroleum Measurement Standards Chapter 20, Section 1 – Allocation 

Measurement, 1st Edition, September 1993, Reaffirmed March 2006

1.1, Introduction - Although allocation measurement may not meet the requirements for custody 

transfer measurement in all cases, it is still possible to refer to existing custody transfer industry 

standards for the basis of measurement. Where this allocation standard does not specifically 

address a measurement related issue, it should be assumed that custody transfer standards apply.

Conflict: Allocation measurement and custody transfer standards may not always be assumed to 

be one in the same. In fact, the API Committee on Production Allocation and Measurement is 

developing an entire series of standards to address these unique issues. Changing this ―should‖ 

to a ―must‖ would obviate the entire need for these documents, at least from a regulatory 

perspective.

1.5.2.3 Differential Pressure Devices - Generally, on a bellows secondary element, the gauge 

lines should be connected to the top connections of the bellows assembly. However, depending 

on the liquid being measured, it may be preferable to connect to the bottom bellows connections. 

Conflict: Changing the ―should‖ to a ―must‖ means the second sentence is no longer an option, 

even though this option may be preferable in some cases depending on field and reservoir 

conditions.

1.7.2.3.1.1, Factory calibration - The relationship between dielectric constant and water cut 

varies with different types of hydrocarbons and water. The analyzer should be calibrated in the

factory using the hydrocarbon liquid and water identical or similar to those in the actual 

application. A calibration curve between the actual water cut and probe output should be 

developed and incorporated into an associated electronic processor device.

Conflict: How would industry prove that the hydrocarbon liquid and water used to calibrate the 

analyzer in the factory will be similar to that found in the upstream production environment? 
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And as the crude oil/gas may vary greatly in composition as production progresses, how can this 

be addressed by calibrating the analyzer in the factory?

1.15.2, Calculation Procedure - Allocation calculations should account for 100 percent of sales 

and shrinkage. This can be done on a volume basis, on an energy content basis, and by test car 

GPM. The last step is to prorate each volume to actual field or system sales.

Conflict: This is the very core of allocation measurement, and in certain cases the calculation 

procedure may yield 100%, but may not in others due to field and reservoir conditions. 

Manual of Petroleum Measurement Standards Chapter 21, Flow Measurement Using 

Electronic Metering Systems, Section 1 – Electronic Gas Measurement, 1st Edition, August 

1993, Reaffirmed July 2005

1.7.2, Gauge/Impulse lines – Whenever possible, pulsation should be eliminated at the source.

Conflict: Field conditions may require pulsation be eliminated at both the source and at other 

locations to achieve optimal results.

1.8.5.1, Ambient temperature Effect – Operating temperature range and its corresponding effect 

on measurement uncertainty (that is, percent full scale/degrees temperature change from 

reference) should be listed in the manufacturer‘s performance specifications and should be 

considered when selecting and installing EGM equipment

Conflict: Changing these ―shoulds‖ to ―musts‖ would add a performance criteria not specifically 

envisioned by the consensus committee and would add an additional requirement to the 

manufacturers of these measurement devices that may not be appropriate in all cases.

Additionally, we would like to comment on proposed revisions to RP 17H, Recommended 

Practice for Remotely Operated Vehicles (ROV) Interfaces on Subsea Production Systems, 1st 

Edition, July 2004, Reaffirmed: January 2009, and RP 17M, Recommended Practices on 

Remotely Operated Tool (ROT) Intervention Systems, 1st Edition, April 2004, Reaffirmed: 

January 2009:

One important note to consider on the ROV document (17H) is that it is currently under revision. 

When completed, it will be a merged document of the current 17H and 17M (Remotely Operated 

Tools, ROT) documents.

With this initial effort in revising the document, the emphasis was placed on integrating the two 

components (ROV and ROT) into one document. Therefore most of the current design 

recommendations/considerations in both documents are not impacted. The document is about to 

undergo a technical review ballot, so the following items may be impacted by the end of that 

review.

The new document will include the following changes (if left in its current state through the 

ballot process):
13

ROVs are to be classified dimensionally (small, medium, large) and 

recommended sizes are noted in order to introduce a standardized method of 

increasing access to the interface

Additional design considerations for working platforms

Increased docking receptacle loading and consideration of failsafe requirements

Additional handle (used in conjunction with a ROV manipulator or purpose-built 

tooling to allow direct operation of the interface) design considerations.

An entire new section on Coloring and Marking (to be used as a guidance map for 

the intervention operations by identifying the structure and orientation; 

identifying the equipment mounted on the structure and intervention interface; 

identifying the position of any given part of the structure relative to the complete 

structure; and identifying the operational status of the equipment, e.g., connector 

lock/unlock and valve open/close.)

Although the new (combined ROV and ROT) document is about 1.5 years away from 

publication, if it does get cited by reference in the regulations, it will incorporate ROT equipment 

by default, currently not part of the on-going discussions. Furthermore, a review of that 

proposed document shows 362 uses of the work ―should‖. If they were to be elevated to a 

―must‖, it would have serious impact on the equipment since there are 13 clauses that deal with 

equipment configuration/conceptualization and 193 clauses that deal with equipment design that 

would become prescriptive. At that time, this document would need to be reviewed for potential 

internal conflicts associated with such a change. The subcommittee plans to simultaneously 

withdraw the current 17H and 17M documents when the new 17H document is released.
14

APPENDIX B - BOEMRE Gulf of Mexico OCS Region Checklist to Validate Compliance with 

API RP 65-2 in Applications for Permits to Drill

Regulatory Requirement: §250.415(f) A written description of how you evaluated the best 

practices included in API RP 65-Part 2, Isolating Potential Flow Zones During Well 

Construction (incorporated by reference as specified in §250.198). Your written description 

must identify the mechanical barriers and cementing practices you will use for each casing string 

(reference API RP 65-Part 2, Sections 3 and 4).

The following questions are listed to provide guidance on how an operator must comply with the 

written description required in 30 CFR 250.415(f). An operator may answer the questions in the 

table, along with the written descriptions where needed. If the operator supplies a written 

description in their own format, then the District Engineer needs to complete the table below and 

answer the descriptions utilizing the information the operator supplied. If the operator does not 

supply enough information, return the permit for clarification.

GENERAL QUESTIONS:

1 Have you considered the following in your well planning and drilling plan 

determinations: evaluation for flow potential, site selection, shallow 

hazards, deeper hazard contingency planning, well control planning for fluid 

influxes, planning for lost circulation control, regulatory issues and 

communications plans, planning the well, pore pressure, fracture gradient, 

mud weight, casing plan, cementing plan, drilling plan, wellbore hydraulics, 

wellbore cleaning, barrier design, and contingency planning? [API 65-2 1.5]

Yes/No

2 Have you considered the general well practices while drilling, monitoring 

and maintaining wellbore stability, curing and preventing lost circulation, 

and planning and operational considerations? [API 65-2 1.6]

Yes/No

FLOW POTENTIAL

3 Will a pre-spud hazard assessment be conducted for the proposed well site? Yes/No

4 List all potential flow zones within the well section to be cemented. Describe 

below

5 Has the information concerning the type, location, and likelihood of 

potential flow zones been communicated to key parties (cementing service 

provider, rig contractor, or 3rd parties)? 

Yes/No

CRITICAL DRILLING FLUID PARAMETERS

6 Are fluid densities sufficient to maintain well control without inducing lost 

circulation?

Yes/No

CRITICAL WELL DESIGN PARAMETERS

7 Will you use a cementing simulation model in the design of this well? Yes/No

7a If yes, how is the output of this simulation model used in your decisionmaking process? Describe 

below

7b If no, include discussion of why a model is not being used. Describe 

below

7c Either way, include the number and placement of centralizers being used. Describe 

below
15

8 Will you ensure the planned top of cement will be 500 feet above the 

shallowest potential flow zone?

Yes/No

9 Have you confirmed that the hole diameter is sufficient to provide adequate 

centralization?

Yes/No

10 If there are any isolated annuli, how have you mitigated thermal casing 

pressure build-up.

NA or 

Describe 

below

11 Will you ensure the well will be stable (no volume gain or losses, drilling 

fluid density equal in vs. out) before commencing cementing operations?

Yes/No

12 List all annular mechanical barriers in your design. Describe 

below

13 Has the rathole length been minimized or filled with drilling fluid with a 

density greater than the cement density?

Yes/No

14a If you have any liner top packers exposed to the production or intermediate 

annulus, what is the rating for differential pressure across this packer? 

NA or 

Describe 

below

14b If you have any liner top packers exposed to the production or intermediate 

annulus, have you confirmed that your negative test will not exceed this 

rating?

Yes/No/NA

15 What type of casing hanger lock-down mechanisms will be used? Describe 

below

16 For all intermediate and production casing hangers set in subsea, HP 

wellhead housing, will you immediately set/energize the lock-down ring

prior to performing any negative test?

Yes/No

17 For all production casing hangers set in subsea, HP wellhead housing, will 

you set/energize the lock-down sleeve immediately after running the casing 

and prior to performing any negative test?

Yes/No

CRITICAL OPERATIONAL PARAMETERS

18 Will you have 2 mechanical barriers in addition to cement in your final 

casing string (or liner if it is your final string)?

Yes/No

19 Do you plan to nipple down BOP in accordance with the WOC requirements 

in 30 CFR 250.422 and API RP 65 Part 2 First Edition? 

Yes/No

20 Do you plan on running a cement bond log on the production and 

intermediate casing/liner prior to conducting the negative test on that string? 

Yes/No

Are contingency plans in place for the following:

21 Lost circulation? Yes/No

22 Unplanned shut-down? Yes/No

23 Unplanned rate change? Yes/No

24 Float equipment does not hold differential pressures? Yes/No

25 Surface Equipment issues? Yes/No

26 Will you monitor the annulus during cementing and WOC time? Yes/No

27 If using foam cement, is a risk assessment being conducted and incorporated 

into cementing plan?

Yes/No

28 If using foam cement, will the foamer, stabilizer, and nitrogen injection be 

controlled by an automated process system?

Yes/No

CRITICAL MUD REMOVAL PARAMETERS
16

28 Have you tested your drilling fluid and cementing fluid programs for 

compatibility to reduce possible contamination?

Yes/No

29 Have you considered actual well conditions when determining appropriate 

cement volumes? 

Yes/No

30 Has the spacer been modeled or designed to achieve the best possible mud 

removal?

Yes/No

CRITICAL CEMENT SLURRY PARAMETERS

31 Have all appropriate cement slurry parameters been considered to ensure the 

highest probability of isolating all potential flow zones?

Yes/No

32 Do you plan on circulating bottom up prior to the start of the cement job? Yes/No

If any question is answered “No”, additional explanation will be needed as to why that 

practice is not being followed; identify the question and provide that explanation below. The 

follow questions are not ―Yes/No‖ questions and will require a description (if not applicable, 

state ―Not Applicable‖). 

4.

7a.

7b.

7c.

10a.

12.

14a.

15.