The last 60 days: what site clearance verification actually requires

Decommissioning ends with a survey, not a lift.

The structure is gone, the wells are plugged, the vessel has demobilised. What remains is a legal obligation to prove that the seabed is clear — and a short clock to prove it in. 30 CFR 250.1740 gives an operator 60 days after permanently plugging a well or removing a platform or other facility to verify the site is clear of obstructions.

That requirement is the smallest line item in most decommissioning budgets and one of the most procedurally exact. It is also a service scope that gets quoted badly, because the regulation specifies more than people remember.

Which method is allowed where

The permitted methods depend on what was removed and how deep the water is.

For a well site, §250.1740 allows any of: trawl dragging across the site, sonar scanning, diver inspection, videotaping by remotely operated vehicle, or another method approved by the District Manager for the particular site conditions.

For a platform or other facility site in water less than 300 feet deep, trawl dragging is the method. Not an option among several — the required approach.

For a platform or other facility site in water 300 feet or deeper, the operator chooses between trawl dragging, sonar scanning across the site, or another method the Regional Supervisor approves as suited to the particular conditions.

That 300-foot line is the single most commercially significant number in the subpart’s clearance provisions. It divides the shelf, where a trawl vessel is effectively mandatory, from deeper water, where a survey spread with sonar can do the work. Areas carrying dense shallow infrastructure — Main Pass, South Timbalier, South Marsh Island, as our platform-removal scope analysis shows — are therefore trawl markets. Green Canyon and Mississippi Canyon are not.

Water depth does not just change the removal method. It changes which clearance contractor can legally do the job.

The radii, and what they mean in acres

Section 250.1741 sets the trawl limits as circles centred on the location, and the sizes differ sharply by asset type.

What was removed	Radius	Area
Well site	300 ft	about 6.5 acres
Subsea well site	600 ft	about 26 acres
Single-well caisson, jacket, template or manifold	600 ft	about 26 acres
Platform site	1,320 ft	about 126 acres

A 1,320-foot radius is a quarter of a mile. The circle it describes is half a mile across and covers roughly 126 acres of seabed — about nineteen times the area of a conventional well-site circle.

That ratio is the reason site clearance cannot be priced per structure. A campaign of twenty shelf wells and one platform is not twenty-one similar surveys. It is twenty small circles and one large one, and the large one may dominate the vessel time.

The pattern is specified too

Three further requirements in §250.1741 are routinely under-scoped.

Coverage. The operator must trawl 100 percent of the specified limits in two directions. A single pass across the circle does not satisfy the rule. The grid-like pattern in two directions roughly doubles the track miles against a naive estimate.

Positioning. The vessel must carry a calibrated navigational positioning system capable of position accuracy of plus or minus 30 feet. That is a documentation requirement as much as an equipment one: the calibration has to be evidenced.

Gear. The net must be representative of those used in the commercial fishing industry. The logic is in the purpose of the rule. The site is being proven safe for the vessels that will actually fish it, so the test gear mirrors the gear at risk.

Taken together, these turn a “survey” into a defined marine operation with a vessel specification, a navigation specification, a gear specification and a coverage specification. Each one is a line a contractor can be measured against after the fact.

Then the paperwork clock starts

Verification is not the deliverable. Certification is.

Section 250.1743 requires submission within 30 days after completing the verification activities, and the required contents differ by asset type.

For well sites, the operator submits form BSEE-0124 to the District Manager, including a signed certification that the well site area is cleared of all obstructions, the date of the verification and the vessel used, the extent of the area surveyed and the method employed, the results including a list of debris recovered or a contractor statement that no objects were recovered, and a post-trawling job plot or map.

For platform and other facility sites, the operator submits letters to the Regional Supervisor containing a signed certification from an authorised company official that the site is cleared, with a witness notation, plus a separate signed certification from the verification contractor, along with the same date, vessel, extent, method, results and post-trawling map.

Read that contractor-certification requirement twice. On platform sites the clearance contractor signs its own certification into the federal record. The firm is not simply invoicing a survey; it is attesting to a regulatory conclusion under its own name.

Section 250.1742 addresses what other methods may be used to verify a site is clear, which is the route for conditions where the default pattern does not fit.

Where the clock actually bites

The 60-day and 30-day windows look generous on paper. In practice they land at the worst moment in a campaign.

The trigger is the completion of plugging or removal — in other words, the moment the main spread is finished and demobilising. The clearance survey is a separate, smaller, differently equipped operation that has to be mobilised just as the campaign’s budget and attention are winding down.

Three failure modes follow:

• Weather. A 60-day window that opens in late summer on the shelf can be consumed by a single storm cycle. The clock does not care.
• Vessel availability. Trawl vessels and survey spreads are not the vessels that did the removal. A separate charter has to be arranged for a short, low-value job.
• Sequencing inside a campaign. Where wells and a platform are removed on different dates, each completion starts its own clock. A campaign with staggered completions carries staggered clearance deadlines, not one.

The South Pass 28 incident is a reminder that this phase is real work with real hazards: that injury happened on a lift boat performing diving support for decommissioning and site clearance, not during a lift.

The commercial shape of the clearance market

For a service company, clearance work has an unusual profile. It is small, mandatory, time-boxed, document-heavy and poorly suited to opportunistic bidding.

Public contract pricing is correspondingly thin. Our comparison of two North Sea subsea-removal cost signals with the Gulf market shows what a disclosed contract band and a recovery credit can reveal — and why neither should be imported as a Gulf rate.

That combination favours firms that can do three things:

1. Attach to the campaign early. The clearance scope is defined by what gets removed and where. It is knowable at application stage, long before the 60-day clock starts.
2. Bundle across a campaign. Several well circles and one platform circle in the same block are a single mobilisation. Our pipeline analysis makes the same point about line ends and structure footprints — adjacency is the economics.
3. Produce the certification pack, not just the survey. The deliverable the operator needs is the §250.1743 submission: certifications, date, vessel, extent, method, results, debris list and plot. A contractor that hands over a compliant pack removes work from the operator’s regulatory team.

A qualification checklist for clearance scope

Before treating a removal as addressable clearance work, resolve:

1. Asset type. Well, subsea well, caisson or jacket, or platform? This sets the radius and the area.
2. Water depth. Above or below 300 feet? This may dictate trawling.
3. Completion trigger. What date started the 60-day clock, and for which asset?
4. Count of circles. How many separate verifications does the campaign generate?
5. Method approval. Is an alternative method being sought under §250.1742, and from the District Manager or the Regional Supervisor?
6. Submission route. Form BSEE-0124 to the District Manager for wells, or letters to the Regional Supervisor for platforms?
7. Certification exposure. Is your firm prepared to sign the contractor certification?
8. Evidence. Positioning calibration records, net specification, track plots.

Clearance is the phase where a decommissioning project becomes finally, legally finished. The regulation treats it that way. Estimates that treat it as a rounding error are the ones that get revised.

Where a campaign’s clearance scope is genuinely ambiguous — staggered completions, mixed depths, unclear asset classification — that is the kind of question a one-off Opportunity Brief is meant to close: the structures, the depths, the dates and the evidence in one place.

Sources

• Electronic Code of Federal Regulations, 30 CFR Part 250, Subpart Q — Decommissioning Activities.
• 30 CFR 250.1740 — When must I verify that a site is clear of obstructions? (60-day requirement; permitted methods by asset type and water depth).
• 30 CFR 250.1741 — How must I verify that a site is clear by trawling? (radii, two-direction 100 percent coverage, plus or minus 30-foot positioning accuracy, commercial-representative net).
• 30 CFR 250.1742 — What other methods can I use to verify that a site is clear?
• 30 CFR 250.1743 — Site clearance certification and reporting (30-day submission; form BSEE-0124 for well sites; letters and contractor certification for platform and facility sites).
• Acreage figures are derived from the radii in §250.1741 (area equals pi times radius squared, converted at 43,560 square feet per acre).