BHA standoff is critical in drilling assemblies for directional control, performance and borehole quality. The selection of the correct standoff has long been a matter for research and publication, from an initial position of slick assembles and minimal standoff to the multiple stabiliser assemblies common today. For example in Weaver, D.K., Practical Aspects of Directional Drilling (1946) the only application of standoff was a reamer either placed a short sub above the bit to act as a pivot to build, or placed 30 ft above with low weight to promote a drop after initial deflection with the potential to use a second reamer when the hold section was reached. Later work would support the idea that reamers were not effective stabilizers, and personal experience has shown that to be the case.
By the early 1950’s increasing stabilization was becoming more common for straight holes in ‘crooked hole country’ where the options to deliver an straight borehole tended to be limited to using lower weight on bit which impacted performance, or on using stabilizers in the BHA to prevent buckling and maintaining a high weight. In commentary on an API paper from Humble Oil, Current Drilling Practices in West Texas (1953), Stanley C. Moore of Drilco Oil Tools highlighted how in straight (vertical) holes in West Texas ‘crooked hole country’ stabilization of the BHA was being seen to improve performance even with weights of 60 klb in 8-3/4” hole and proposed this was due to a reduction in buckling and bit tilt. Rotary directional tendencies managed through multiple stabilizers became better understood through the 1950's, improving the predictability and performance of the directional drilling of the 1940’s, though even in 1996 a Directional Drilling manuals included statements such as:
"A DD may think he’s got his BHAs all figured out until he moves to a new area. He may be baffled to find that few or none of his previous BHAs work as expected. This is understandable."
In 1986 McKown & Williamson of Drilco took an engineering approach to stabilizer selection in their paper IADC/SPE-14766. Figure 1 (adapted from the paper) shows the approach taken by them for straight hole drilling, building on many of the empirical findings since the 1950’s for drilling straight holes in ‘crooked hole country’. A similar, though smaller, flow chart was published for directional hole stabilization.
While this paper is over 30 years old it does provide a good background in stabilizer selection, including some effective guidelines for stabilizer design that have been further proven with more research to the present day.
As the industry and directional drilling evolved delivering more challenging wells, improving consistency and predictability with bent housing motors and more recently rotary steerable tools, the use of stand-off became has become more critical to successful delivery and it’s design, selection and placement became better understood. For example, an operator drilling long stepout high angle wells in the 1990s-2000’s had requirements of vendors to provide stabilizers that:
Were integral blade on every occasion.
Had approximately 270 degree open wrap. It was mandatory that the blades did not overlap.
Had a good “watermelon” shape.
Had a blade width should be in excess of 2-1/2 inches, with 3 to 4 inches being preferable.
The angle of the stabilizer blade to the axis of the hole should be in the region of 30 degrees.
That had full manufacturing and maintenance history available and was inspected to the appropriate standard and category.
Should look in reasonable condition.
These criteria didn’t stop the operator from having to inspect stabilizers provided by vendors though, equipment even had to be sent back surprisingly for the last of these criteria. How many of the stabilizers in figure 2 do you think were sent back? This highlights the importance of contractor management if specific stabilizer designs are requested. In the words of a Russian proverb and also Ronald Reagan we should "trust but verify".
While this operator had defined its criteria based on needs and experience, there is significant similarity not only to the previous work mentioned but also the subsequent work published in 2018 by Paul Pastusek at ExxonMobil based on their forensic observations. leassons learned and inputs after a SPE Gulf Coast presentation in 2015 (IADC/SPE-189649-MS). Like the earlier operator experience this paper concluded that usually a smooth taper of <= 30°, and a wrap angle between 270 and 360 degrees (ie. Open wrap) would be preferable and rather than defining a blade width a more detailed approach of using a pad pressure (total side load / pad area of 180° contact) criteria was stated. It was clearer on minimum bypass areas though. The value in this paper is that along with the description of the various tool features it provides a generic checklist provided, which if all else fails should ensure that the stabilizers will be acceptable to balance the many standoff requirements, or at least enforce a review of proposed, but not acceptable, stabilization.
Then the question how many stabilisers should be run? As a general rule it is recommended to aim for as few well designed stabilizers as you can get away with and as many as you need to ensure good borehole quality! Poorly thought out stabilization can cause worse problems. Though today many times stabilizer numbers can be driven as much by logging tools requirements as it is by the needs to maintain trajectory, borehole quality and even BHA integrity. It is important to remember that these tool stabilizers should be considered and reviewed with the same technical criteria requirements as standalone stabilizers, with reviews being needed when stabilizers don't meet the defined technical criteria.
Ultimately we shouldn't take stabilisers for granted, we should get to know them and only accept stabilizers that will support the delivery of the well rejecting those that could cause more problems. In the words of McKown and Williamson:
"Stabiliser gauge, stiffness and wall contact greatly affect BHA performance"
.....but don't forget the bypass area
Stabilizer placement? That's a whole other story......
References:
Weaver, D.K., Practical Aspects of Directional Drilling, API-46-009, Presented at the 26th Annual Meeting, Chicago, Illinois, Nov. 1946.
Johnston, D., Johnston, W.R., Current Drilling Practices in West Texas, API-53-035, Presented at the API Southwestern District Meeting, Fort Worth, Texas, March 1953.
Lubinski, A., Woods, H.B., Use of Stabilisers in Controlling Hole Deviation, American Petroleum Institute, 1955
Wilson, G.E., Operators Slash Deep-Drilling Costs with RWP Stabilisers, Oil & Gas J. (Aug. 1977) 83-84 and 86-87
Williamson, J.S. and Lubinski, A., Predicting Bottom Hole Assembly Performance, IADC/SPE 14764, Presented at the 1986 IADC/SPE Drilling Conference held in Dallas, Texas, Feb. 10-12, 1986.
McKown, G.K., Williamson, J.S., An Engineering Approach to Stabilization Selection, IADC/SPE-14766, Presented at the 1986 IADC/SPE Drilling Conference held in Dallas, Texas, Feb. 10-12, 1986.
Applied Drilling Engineering, Bourgoyne, Millheim, Chenevert & Young. SPE Textbook Series Vol. 2, edition 1, 1986, ISBN: 978-1-55563-001-0
Dupriest, F.E., Thus, The Lowly Stabiliser, presentation to the IADD, Greenspoint Club, July 25, 2013
Pastusek, P.E., Stabilizer Selection Based on Physics and Lessons Learned, IADC/SPE-189649-MS, Presentation at the IADC/SPE Drilling Conference and Exhibition held in Fort Worth, Texas, 6-8 March 2018.