Rotary Steerable Drilling Systems

Effective rotary steerable drilling systems overcome most of the problems with steerable motors by providing continuos pipe rotation while drilling. This is accomplished, with the tool reported on in this paper, with a non-rotating steerable sleeve containing three extendable pads that push against the borehole wall.

The drillstring, which is connected to the bit, rotates inside the sleeve. Independently varying the force on each of the pads steers the tool along the desired well path. The tool can be programmed for inclination or steering force and deviations are automatically adjusted for by a closed loop control. Any adjustments needed can be downlinked to the tool without interrupting drilling.

Drilling Fluids for Directional Drilling

Two linear motion shale shakers

Drilling Fluid Characteristics

Several mud characteristics play key roles in directional drilling, which apply almost equally well to rotary steerable drilling or steerable motor drilling. Some, however, become more of an issue with rotary steerable drilling systems.

Borehole stabilization

Borehole stability is always a concern in any type of drilling and is even more of an issue during directional drilling due to the convergence of the collapse pressure and fracture gradient with inclination angle.

As the safe mud weight range for a stable wellbore in shales shrinks with inclination angle, any reduction in wellbore strength due to shale hydration or pore pressure elevation becomes much more critical. This is even truer for rotary steerable drilling tools using extendable pads for steering. These pads have a finite extension and require a firm wellbore against which to push to supply the steering force to maintain the desired well path.

Suspended solids.

Suspended solids, including both the type and concentration, are also of universal concern, as they tend to lower drilling rate and decrease the rate-of-penetration (ROP).

Sand is abrasive and can damage rotary seals, motor stators, rotors, bearings as well as other downhole and surface fluid handling components. Lost circulation material (LCM), is notorious for plugging off narrow flow passages or screens in motors, measurement while drilling (MWD) tools, pulsers as well as bit nozzles.

Elastomer compatibility

Materials compatibility is also always of concern in drilling but is particularly important where motor stators and elastomeric seals are concerned and needs special attention when using invert emulsion drilling fluids as well as some specialty drilling fluids.


The pertinent coefficient of friction between the drill string and borehole when slide drilling is initiated is the static coefficient of friction that is always higher than the dynamic coefficient of friction, which is most pertinent in rotary drilling.

This makes the lubricating characteristics of the drilling fluid extremely important during slide drilling to help lower drag, minimize stick slip and facilitate tool face orientation. This accounts for some of the popularity of oilbased mud (OBM), pseudo oil-based mud (POBM) and synthetic-based mud (SOBM) for slide drilling due to their typically lower coefficient of friction.

While lubricity might be expected to be less important for rotary steerable tools due the reduced torque and drag from the reduced wellpath tortuosity, wells where rotary steerable tools are used are typically more complex pushing the limits of even rotary steerable technology. The net result is that lubricity is just as important as in steerable motor drilling.

Some water-based mud (WBM) formulations, such as fluids containing polyglycol, have significantly lower coefficient-of-friction between the drillstring and borehole/casing than others. A variety of different lubricants have been used to reduce the coefficient-of-friction even more.

Lubricants such as fatty acids, alcohols, detergents/surfactants and esters have been used and in some cases these WBM’s can be formulated with lubricity measured in the laboratory similar to invert emulsion drilling fluids. Mechanical lubricants such as beads, ground nut hulls and graphite have also been used to facilitate slide drilling with mixed results.


The importance of cuttings removal in the absence of drill string rotation has been discussed earlier and hole cleaning can be influenced by the rheological characteristics of the drilling fluid, if only indirectly. While investigators have not always agreed on which characteristics are most desirable, turbulent flow has usually been found advantageous for hole cleaning in high inclination intervals.

All things being equal, turbulence is facilitated by lower fluid viscosity, although hole cleaning efficiency may be reduced when low viscosity fluids drop back into laminar flow. Use of turbulence may only be practical in non-permeable formations, however, due to the tendency to scour off the mud cake in more permeable zones.

This can be minimized if turbulence is confined to the occasional low-viscosity pill used to “pick up” cuttings that have collected on the low side of the borehole. The net result is that laminar flow may be safest and most efficient overall in which case rheology manipulations may have little impact on cuttings removal, especially while slide drilling.

Balling characteristics

Argillaceous formations such as shales, mudstones and siltstones as well as some marls or chalks often exhibit a tendency to “ball” the bit and/or BHA components when drilling with WBM. Balling, at least in shales, appears to be the result of chips or cuttings insufficiently commingled with mud or chips/cuttings which initially were adequately commingled with sufficient mud but have since been re-compacted.

This tendency is particularly pronounced when drilling at high ROP with PDC bits at high bottom hole pressure. Balled material can vary in consistency from a soft jelly-like material to material with almost as much mechanical structure as the original shale, and virtually everything in between. Hydration tendencies are strong and cuttings typically recovered at the shale shaker, rig floor or from laboratoy drilling simulator are often soft and sticky on the material’s surface, but much firmer toward the interior.

While bit balling is always a concern with any type of drilling, it is more pernicious in slide drilling due to the size and characteristics of the cuttings and balled material. During rotary drilling, low level balling can be mechanically dislodged to some extent due to the rotation of the drill string. This same level of balling may stop drilling in the slide mode without the benefit of the rotation energy and attrition.

When balling is mild to moderate, the balled material tends to adhere to the bit and BHA in clumps or islands and does not necessarily pack off all the bit junk slots or BHA annulus. Dislodging any of this material and/or circulating any of this balled material out of an inclined borehole while slide drilling can be extremely difficult.

In the event balled material does break free, it tends to settle and accumulate in the low side of the hole where it reduces annular clearance and can be recompacted by movement of the drill string, re-adhering to the bit and BHA.

The net result is increasing drag, stick slip, tool face orientation difficulty and lower ROP. When balling is  severe, the material can easily pack off all the bit junk slots as well as the entire annulus and stop BHA movement.

While pipe rotation helps minimize balling in rotary steerable drilling applications, the ability to use more aggressive PDC bits in place of roller cone bits offsets some of the benefit as PDC bits are more prone or sensitive to balling. The key is to prevent balling from occurring.

Rotary Steerable Fluid Design

The fluid design proposed for use with rotary steerable drilling systems is a low solids/non-dispersed/electrolyte/encapsulating polymer/2- phase polyglycol mud system to address the directional drilling fluid issues discussed in the previous section.

Fluid components

This fluid design is built around the following products:

  • Electrolyte. Electrolytes are low cost, readily available hydration suppressors for use against active hydratable clays that can be very problematic when drilled with WBM’s. Potassium chloride (KCl) is the most cost efficient, when environmental regulations permit it’s use, and has a long and successful history of use in WBM in many drilling basins of the world including the North Sea and South East Asia. 
  • Encapsulating polymer. Encapsulating polymers are high molecular weight polymers that bind to chip and borehole surfaces minimizing dispersion of chips, and damaged borehole wall rock fragments, into the fluid system. The products keeps drill solids build up in the mud system and filtercake to a minimum to assist ROP and minimize sticking. The specific product used is a polyacrylamide / polyacrylate copolymer (PAM/PA) which is highly efficient at encapsulation in 2-phase polyglycol mud systems.
  • 2-phase polyglycol. 2-Phase polyglycols are non-aqueous polyglycol liquids that exhibit reversible inverse solubility with temperature in aqueous fluid systems in which they are used. The polyglycols are soluble in these aqueous systems below a transition temperature, defined as the Cloud Point or Cloud Point Temperature, at which the polyglycols reach their solubility limit.
    1. Above this temperature the polyglycol becomes partially insoluble and the aqueous polyglycol system separates into two immiscible liquid phases: a polyglycol-rich phase that is typically suspended as droplets in an aqueous-rich phase. The phase separation is reversible and once the temperature drops below the Cloud Point the polyglycolrich phase dissolves again in the aqueous-rich phase.
    2. 2-Phase polyglycol systems mechanically stabilize chips and shales by forming polyglycol complexes with clays and assist the encapsulating polymers in minimizing drill solids build-up in the mud. More importantly 2-phase polyglycol systems can also stabilize the borehole and chips by minimizing filtrate invasion that raises pore pressure and eliminates the confining stress provided by the mud column overbalance.
    3. Filtrate invasion is minimized by adjusting the 2-phase polyglycol system Cloud Point to match the Circulating Bottom-Hole Temperature (CBHT) of the well which is typically well below the Static Bottom-Hole Temperature (SBHT).
    4. The temperature gradient between the two ensures that any filtrate that invades immediately exceeds the CPT, provided the 2-phase polyglycol system has been designed appropriately, and the 2-phase system droplets that form can shut down any further filtrate invasion15.
    5. This prevents pore pressure build up in the shale which maintains wellbore support.The polyglycol used in the fluid design for the beta testing and the Hui Zhou 21-1 field, Polyglycol A, was selected to most closely match the CHBT’s expected given the electrolyte and electrolyte concentration used.
    6. 2-Phase polyglycol systems are also fairly efficient at minimizing balling and as a result improve ROP and assist hole cleaning by reducing chip adhession / agglomeration. This feature is most likely a result of both the formation of clay complexes and minimizing pore pressure transmission.
    7. 2-Phase polyglycol systems also exhibit goodlubricity with a low coefficient-of-friction and are used to prevent differential sticking.
  • Xanthan gum. Xanthan gum is a high molecular weight polysaccharide polymer used for suspension of dispersed solids including drilled chips, weight material and dispersed drill solids. Xanthan gums are highly effective suspension aids, contribute no suspended solids to the mud system in keeping with the low-solids nature of the mud design and are highly tolerant of electrolytes unlike bentonite-based systems.
  • Fluid loss control polymers. Moderately high molecular weight polymers of appropriate chemistry minimize filtrate leak-off into permeable zones, help provide lubricious filtercakes and minimize differential sticking. These polymers contribute virtually no suspended solids to the mud system in keeping with the low-solids nature of the mud design and many are highly tolerant of electrolytes unlike bentonite-based mud systems. Low viscosity polyanionic cellulosic’s such as PAC LV are excellent choices as they are efficient, resist fermentation and do not require a biocide. Driller’s starch, used with a biocide, is a low cost alternative where environmental regulations permit use and discharge of biocides.
  • Caustic soda. Caustic soda is sodium hydroxide (NaOH) utilized for pH and alkalinity control.

Rotary Steerable Fluid System Beta Test

2-Phase polyglycol systems have a long history of success in vertical and directional drilling applications with steerable motors but use with rotary steerable drilling systems is fairly new. The system was therefore beta tested in a controlled full-scale test program drilling to horizontal with the rotary steerable tool at an experimental drilling site.

Well Design

Our primary interests in including joint fluids testing with the rotary steerable tool drilling tests at the experimental test site were:

  • to try to assist the rotary steerable tool team in achieving maximum performance of their tool.
  • minimize any chances of lost-in-hole tools.
  • to evaluate our rotary steerable fluid design concept with a rotary steerable tool under realistic field-based conditions.

The basic rotary steerable fluid design is a flexible design capable of accommodating varying operational, lithological and environmental requirements in the differing markets where rotary steerable tool are deployed. As shale is the most problematic formation typically drilled with water-based mud, a big problem in most offshore drilling and expected to be a substantial problem for rotary steerable tools drilling shale with water-based fluid, the rotary steerable fluid design incorporates many features that specifically address shale.

We originally intended to include an electrolyte typically used in South East Asia shale drilling, such as potassium chloride or a more environmentally suitable potassium salt which could be disposed of at the experimental test site area, but this proved economically prohibitive due to land-based disposal regulations. The performance of this mud formulation was compared with the performance of the control mud used in well BHA-E2. The BHA-E2 control mud was a simple fresh-water/gel mud typically used at the experimental test site and identified in Table 1 as “Gel”.

table 1

Mud Properties

The range of properties for the muds used in these wells are also listed in Table 1. Measured mud properties for the systems were fairly similar with the exception of the expected differences in polyglycol concentration, gel strengths and reactive clay content as measured by the Methylene Blue Test (MBT), as a result of the differences in the formulations.

The glycol concentration was maintained at 2 volume % in the BHA-E3 well. The retort analyses that were conducted on the drilling fluids were accurate to within ± 1% of the actual concentration of the glycol maintained in the mud systems. The encapsulating polymer and Xanthan gum both were maintained at 0.5 lbm/bbl (pounds per barrel) on the BHA-E3 well.


The primary performance improvements expected from the rotary steerable fluid design were increased penetration rates, possibly improved build rates, improved hole quality, improved hole cleaning and possibly lower torque and drag.

Penetration rates and build rates.

This information will be published at a later date with a more complete evaluation of all fluid designs tested.

Hole quality.

The wells were not caliper logged so our best indication of borehole quality was the incidence of cavings seen on the shaker and the extent of reaming/washing required on trips. Cavings were seen periodically throughout wells BHA-E2 and BHA-E3 particularly when drilling new hole or on entering a previously drilled hole for the first time. Site personnel believe this is simply characteristic of these formations and the low borehole pressures and is not necessarily a good indicator of insufficient mud weight or hole instability.

Reaming/washing details were collected from the daily driller’s report and all pertinent comments were reviewed. BHA’s, bits and well paths were essentially the same for both wells with the exception of azimuth, so the accumulated total depth intervals which was reamed/back-reamed/washed down on all trips over the entire interval should be an indicator of hole stability and/or hole cleaning.

Figure 1 gives the cumulative amount of hole reamed/back-reamed/washed for each well for all trips and shows that the use of the 2-phase polyglycol system on well BHA-E3 reduced the cumulative amount of hole requiring reaming/washing by approximately 37% relative to well BHA-E2. This improvement is consistent with laboratory and field observations with this mud design which helps stabilize the borehole as well as the cuttings by increasing mechanical strength and minimizing cuttings’ swelling and stickiness.

Figure 1: Cummulative Beta Test Washing/Reaming versus Mud Type
Hole cleaning

No quantitative measurements of cuttings recovered versus time were made so the best indicator of hole cleaning efficiency was the indirect measurement of total washing / reaming/back-reaming recorded over the entire interval as discussed above.

Torque and drag

Torque and drag were monitored real time using a new force and torque equilibrium technique based on both surface and/or downhole values of actual rigsite data. This approach is superior to the pre-calculated hook load and surface torque comparison technique more commonly used; several unknowns are filtered out of the equations and current drilling conditions are used automatically and directly in the calculations. Figure 2 displays the friction factors determined for the BHA-E2 and BHA-E3 wells and shows the improved lubricating characteristics of the 2-phase polyglycol mud system: the friction factor was reduced approximately 60% from >0.25 to <0.1 over much of the interval.

HZ/21-1-7Sa Drilling Rig Well

The HZ/21-1-7Sa was a re-entry sidetrack from the original previously producing well that had been plugged back and abandoned. The well is located offshore Hong Kong, China at the HZ/21 platform in the Huizhou 21-1 field in Block 16/08 of the Pearl River Mouth Basin area, South China Sea.

Directional Plan

The objective was to drill an 8½-in. sidetrack from a milled window in the 9 5/8-in. casing of the original well and to land the sidetrack well horizontally in the target reservoir. A 6-in. horizontal section would be then be drilled following the reservoir contour body and completed to produce from the M-10 sand reservoir.

The wellpath trajectory required the sidetrack well to aggressively turn and build angle from the kick-off point. The reason for using a rotary steerable tool was to increase average ROP and to improve hole cleaning through continuous rotation of the string with rotary steerable drilling. Past achievements drilling with this particular rotary steerable drilling system were very successful, making it an obvious choice for this application.

Fluid Design

The fluid design chosen for use with the rotary steerable drilling system in this application was a low solids non-dispersed encapsulating polymer 2-phase polyglycol fluid consistent with the recommendations outlined above in Rotary Steerable Fluid Design. The proposed mud formulation along with the actual formulation used, are included in Table 2 along with the measured fluid properties.

table 2

Solids Control Equipment

The rig was equipped with two high performance linear motion shakers along with a centrifuge and desilter. Shale shaker #1 was fitted with 230-mesh screens and shale shaker #2 was fitted with 180-mesh screens due to the shortage of 200-mesh screens. The centrifuge suction was from the desilter underflow.


Steerable motor drilling (2245-2320 m). A conventional steerable mud motor with a tricone bit was used to cut the window and kick-off. The purpose of this assembly was to drill 15 m of directional rathole past the casing window until the MWD assembly was clear of magnetic interference from the casing. The assembly was run in hole and drilling proceeded ahead smoothly. Good azimuth readings were achieved by 2303 m. Drilling continued to 2320 m, and the hole was circulated clean and the bottom hole assembly (BHA) was tripped out of hole and laid down.

Fluid performance.

The only fluid related problem was higher than necessary dilution as a mud treatment. The initial dilution rates were based on required dilution from the two previous wells. The dilution rate proved to be too high, and was latter reduced. Whether this was due to improved chip/cuttings removal efficiency, improved chip/cuttings integrity from the stabilizing nature of the fluid system, and/or reduced downhole losses is unknown. A whole mud displacement is an option to be considered on future wells.

Rotary steerable drilling system (2320-3351 m). The rotary steerable drilling tool and MWD sub were made up to a new 8½-in. PDC bit (TFA= 0.60). The system passed through the window with ease and was washed to bottom as a precautionary measure. Drilling continued, closely following the proposed well trajectory, building angle and turning azimuth from 21.26° to 45° and 319.77° to 300.66°respectively. Inclination was then dropped to 6°, while holding azimuth, before finally turning 180°, and then building angle to intercept the target entry point. The target entry point was located at 3322 m MD, and 2974 m TVD at an 86.5° angle. Twenty-two meters of tangent section was drilled, before a final build of angle to achieve horizontal position to land the well at 3351 m MD, 2975 m TVD.

The interval was drilled smoothly achieving the required dogleg gradient. The bit was nursed through hard streaks and formation changes. When drilling these hard sequences, negative drilling break practices were carried out to ensure the maximum life of the bit. The hole was circulated to remove drill cuttings, prior to a wiper trip to the window. After checking for well flow, the drilling assembly was run back to the bottom of the hole. Drilling Fluid was again circulated again, to ensure a clean bore hole, prior to pulling out of hole and laying down tools.

Fluid performance

The only setback encountered was believed to be bit balling at 2457 m when the pump rate was reduced and WOB increased for directional control. A 30-bbl caustic / seawater sweep was pumped and appeared to successfully clean the bit.

Dilution rates were extremely low. The final circulating volume was 955 bbls, with a net dilution volume of 445 bbls. This gives a dilution rate of 0.402 bbls/m, or, about half of the previous two wells. The low dilution rate is probably due to:

  • Drilling time was extremely fast with this rotary steerable drilling system: 75.5 hours for the entire interval. Fewer day’s means less time for dispersion of retained drill solids.
  • Continuous rotation that helped hole cleaning which minimizes dispersion of chips/cuttings.
  • Excellent solids control equipment.
  • Superior chip/cuttings stabilization from the fluid system. Potassium chloride, the encapsulating polymer PAM/PA and the 2-phase polyglycol all work together to stabilize chips/cuttings to ensure their size is large enough at surface for removal with the solids control equipment on the first pass.


  • The primary concerns to drilling fluid design for use with rotary steerable drilling tools are identified and include borehole stabilization, suspended solids, elastomer compatibility, lubricity, rheology and balling characteristics.
  • A low solids non-dispersed encapsulating polymer/2- phase polyglycol water-based mud system addresses the primary fluid concerns with rotary steerable drilling tools.
  • Full-scale beta testing in a controlled test program drilling to horizontal with a rotary steerable tool system and 8½- in. bits at an experimental drilling site confirmed the effectiveness of the rotary steerable drilling fluid design. Reaming/back-reaming/washing was reduced 37% and the real time friction factor was reduced approximately 60% (0.25 to <0.1) using the rotary steerable fluid design relative to a conventional mud system.
  • The fluid system was successful used to drill a difficult sidetrack in the Huizhou 21-1 field, Block 16/08 of the Pearl River Mouth Basin area, South China Sea. with minimal fluids related problems and with half the dilution rate of previous wells.


BHA= bottom-hole-assembly
CBHT= circulating bottom-hole-temperature, ºF
CPT= cloud-point temperature,
KCl= potassium chloride
LCM= lost circulation material
MBT= methylene blue test
MD= measured depth
MWD= measurement-while-drilling
NaOH= sodium hydroxide ( caustic soda)
OBM= oil-based mud
PAM/PA= polyacrylamide/polyacrylate (copolymer)
PDC= polycrystalline-diamond compact
POBM= pseudo oil-based mud
ROP= rate-of-penetration
SBHT= static bottom-hole-temperature
TFA= total flow area, in.2
TVD= total vertical depth
WBM= water-based mud