Can we use MWD surveys to detect Hole Spiraling?
The concept of hole spiraling is not new and there has been recognition of the problem for many years;
Henry Woods and Arthur Lubinski stated in 1954 that the size of drill collar just above the bit is the limiting factor for the lateral movement of bit causing hole deviation.
They gave a formula to calculate the Minimum Effective Hole Diameter (MEHD) for lowering the casing. The formula is: MEHD = (Bit Size + Drill Collar OD) / 2
Later, Robert S. Hotch came up with a theory that while drilling with an unstabilized bit an abrupt change of hole angle can occur if hard ledges are encountered. With reference to his theory, he suggested that the minimum permissible drill collar OD should always be greater than twice the casing coupling diameter to be run minus the bit size. i.e. Minimum Drill Collar OD = 2 x Casing Coupling OD – Bit size
At the Same time, H.E. Triecher pointed out that the lateral movement of an unstabilized bit in non dipping formation tends to cut a spiral hole. The spiralling will be more severe in soft formations where penetration rate is high and this will produce a hole of reduced drift diameter.
Modern theory would have us believe the condition is a cumulative result of Bit cutter design, BHA design and stabilization and formation susceptibility.
Another undesirable effect is when running wire-line logs in that the logging tools will most likely be longer that the wavelength of the spiral and so produce a variable standoff that can be interpreted as a change in hole diameter. A common manifestation of this as a wave on the caliper log.
In trying to diagnose Spiral Hole in the drilling phase there has never (or the author’s knowledge) been a recognized proof of existence. Though like all things in Science it is presumed to exist if (a) a model can prove it, and (b) an alternative is not proven – The changes in observed parameters (torque, drag ect) can often be masked by the drilling process itself.
Surveys have traditionally not been seen as an adequate real-time analysis tool either – due to the subtle nature of the changes, and also that the MWD tool is normally at least 15m above the bit.
Analysis of real field values.
By analyzing Torque and Drag data of actual versus theoretical there are sections where the friction factors change for no apparent reason.
I looked at ways to apply a factor to the well path to simulate the actual surveys and bring friction factors back into line.
The standard formula for applying tortuosity I suggest is;
? = (((Summation between n and j=1)(DL^2)) – ((Summation between m and i=1)(DL^2))) / MDj - MDi
This, however gives a very conservative result.
If a sine wave is applied, using the magnitude (amplitude) and period (wavelength) specified, then the angle change would be;
M sin (MD/p)2π
Where MD is measured depth, p is the period and M the magnitude of the maximum variation of angle to be applied to the inclination and azimuth value.
New inclination and azimuth are as follows;
Inc2 = a + a1
azi2= Azi1 + a1 + crv (cross vertical correction)
I applied the equations above and made a rough Excel sheet to convert actual surveys to correct to include the sine wave.
By applying these factors into my torque and drag program, the friction factors stabilize out at normal and expected values.
Looking at some of the surveys for recent wells, and particularly vertical wells, it seems possible that the BHAs are producing spiraled well-bores that we cannot readily identify with MWD survey QA/QC standard techniques.
By analyzing Torque and Drag data of actual versus theoretical there are sections where the friction factors change for no apparent reason.
I looked at ways to apply a factor to the well path to simulate the actual surveys and bring friction factors back into line. Though not a tool to use in real time, it would be nice to have a tool that we can at least predict and factor into future well plans.
The grey areas are as follows;
? Amplitude of the sine curve – can we simply apply stabilizer size minus tubular size (similar as the calculations for minimum effective hole diameter).
? Period of the sine curve – my initial suggestion is as per stabilizer spacing (points on maximum diameter and so likely to follow a straighter trajectory); added to this is the effect of stabilizer blade length.
? How to eliminate the effect on negative inclination (though I suspect this is a matter of applying Algebraic logic to the argument).
? When the MD of the survey is an exact multiple of the period – how to avoid. As per point above, I suspect this can be cured by creative nesting in the calculation. (sin(MD/p)2π then becomes zero).
By putting my "corrected" surveys into a spreadsheet the effects of the math can be seen below;
MWD Survey Corrected
MD Inc Azi Inc Azi
1234 3.25 165 3.55 165.30
1500 3 165.5 2.52 165.02
1600 3.5 167 4.50 168.00
1700 3.12 167.5 2.66 167.04
1800 3.45 168 2.89 167.44
1900 3.65 169 4.64 169.99
The corrected survey matches with real time data on a Torque and Drag program.
Global Design Of Service Advisor at Halliburton
6 年One of the inputs that sometimes gets neglected is the fixed motor bend acting as an eccentric stabiliser.
Global Design Of Service Advisor at Halliburton
6 年Yep, there are a lot of inputs and I'm not saying they are all understood. Some of them are though. Largest input, in my experience is length of the gauge pad of the bit and the gauge of the first stab. Formation, inclination, trajectory, penetration rate and parameters, that is to say 'useful drilling parameters' at acceptable penetration rates are secondary inputs. Want me to design an assembly that will spiral? No problem. Want me to design one that won't? Again - no problem.
Global Risk Management, Engineering & Technology, Halliburton Boots & Coots, Well Control - Project Management
6 年We've all seen the high resolution CAST images displaying well defined spiraling with variable amplitude, BHA components are unknown except for the conventional mud motor . This was compared to a CAST image of a slick hole using an assembly with a long gauge bit and short bearing section motor. I guess what I'm inferring is that the period of the "wave" depends on more than simply the geometry of the assembly and will be influenced by formation, direction and inclination and whatever drilling parameters are being used, including the efficiency of or even the dampening affect of the drilling fluid. Add anti-slick slip technology and multibody influences become even more complex. Particular paper of interest: SPE/IADC 79919 on which Chris himself collaborated, states "... typical 3 to 4 feet pitch corresponded to the distance from the bit to the first contact point on the steerable motor." but does not draw a definitive conclusion to the mechanisms behind spiraling. Even rotary assemblies spiral. Just sayin'.
Global Design Of Service Advisor at Halliburton
6 年The depth intervals ( let's presume ft) seem long for spiral. We typically see spiral on conventional motor assemblies and rotary pendulum (undergauge nearbit stabilisers). The period of the spiral being the distance between the bit and the first stabiliser (as you identify in the post). The period is generally between 1 and 2m in these assemblies ( undergauge motor bearing stab or the rotary nearbit stab as mentioned). We address these by increasing the gauge pad of the bit and use of point the bit technology. There are lots of papers on this with Exxon and Halliburton Sperry's Tom Gaynor leading the charge for the interested. Nice post Chris.