Drilling Failure Costs Quickly Add Up
- Cliff Berry (Centek)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- August 2009
- Document Type
- Journal Paper
- 32 - 33
- 2009. Copyright is retained by the author. This document is distributed by SPE with the permission of the author. Contact the author for permission to use material from this document.
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Annual downtime during drilling or running casing is only marginally better than it was 20 years ago. Operators’ estimates suggest that drilling efficiency is approximately 50% when taking into account all rig activities from spud to completion, including running casing tubing.
Trying to estimate the cost of this is not straightforward, but if 50,000 wells are drilled each year worldwide, ranging in day-cost from USD 135,000 on land to USD 450,000 for a semisubmersible, or a drillship at USD 1 million, then the average daily cost could be approximately USD 250,000. For wells that encounter trouble, the average time lost per well is probably approximately 6 days, which would give average downtime costs of USD 1.5 million for each well. Stuck drillstrings are one of the major contributors to drilling downtime, and a common cause of sticking downhole is a failed centralizer. A conservative estimate is that, annually, 400 wells worldwide (less than 1% of active drilling operations) are affected by centralizer problems, at a probable cost of 400 times USD 1.5 million, or USD 0.6 billion.
With downtime attributed to centralization problems reaching that amount, industry improvement in this area is essential. Centralizers are relatively cheap, but when they fail because of damage, breakage, or simply getting stuck in hole due to insufficient fitting at the correct intervals, then they assume a consequential cost out of proportion to their price. Losses at this level would not be tolerated in other industries, such as the automotive, marine, or aeronautical industries. Why should the oil industry be different?
Most centralizer failures are caused by using an incorrect unit for the job. Every day someone, somewhere, is pulling casing and leaving debris in the hole for the simple reason that the wrong type of centralizer was used. The oil industry seems surprisingly tolerant of these failures.
Centralizers since the early 1950s have been of multipart design and construction, being either welded or interlocked and having hinges and pins to hold them together. That design has remained largely unchanged to this day. With vertical wells, this type of construction is ideal as the string is in tension and no radial loads are applied. However, these units were oversized to the borehole, had high start and drag forces, and were weak in restoring force. This type of centralizer is still a regular choice in the industry but it is the single largest contributor to downtime and overspend.
As the industry developed, and well trajectories and types changed, the demands on centralizer technology increased. Some wells now have extremely close tolerance casings, some are under-reamed, and many are horizontal. The gravity effects on casings in angular and horizontal wellbores have made radial and axial forces crucial factors.
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