by Michael Mims, President/CEO of K&M Technology Group Introduction

Directional drilling technology has come so far in the last 15 years that it is difficult to imagine drilling a long horizontal or extended reach well without the use of at least 6 high speed computers, downhole motors, fancy drilling fluids, adjustable BHAs, top drives and PDC bits. In fact, when you look at the industry’s current use of today’s technologies, we’re very often using these technologies where they are either inappropriate or ill fit for purpose.

This paper will take a look at today’s global drilling practices as seen through the eyes of engineers and operations superintendents participating on a leading edge performance improvement team for many of the major operators and drilling contractors around the world. This team has been contributing to improved drilling performance in shallow extended reach, deep water directional, long horizontal and conventional directional development wells. Performance improvement statistics will be presented from some of these programs. Fit-for-purpose technology applications will be shown to have tremendous positive impacts on drilling operations.

Discussion

We don’t have to look back very far, say to 1985, and compare the drilling technologies that we have commercially available to us today and our utilization of that technology to become astounded. Think back with us for a moment to drilling wells without PHPA, glycol, synthetic based muds, top drives, steerable motors, PDC bits and computers…….how did we ever drill anything successfully? Don’t get us wrong, we’re big fans of these new technologies and their positive effects on drilling performance. What has become evident to our team over the past couple of years, however, is that the new technology is very rarely being applied in the field as a true “system”. In other words, our industry has yet to put together the proper combinations of these technologies, which optimizes overall drilling efficiency.

A “systems approach” to drilling simply means that we’re taking all aspects of the drilling environment into account when applying products and practices in the field and prioritizing our objectives for that operation. Our objectives need to look at the entire drilling picture with a “real world” eye and determine what is fit-for-purpose in each individual case. For example, placing the same BHA in a well because it worked well for an offset well or for another operator in a similar field is a poor way to approach modern BHA designs.

Our objectives need to consider the length of the hole section, the drilling fluid that will be utilized, the rig capabilities with respect to flowrate at TD of the section, rotary speed limitations on surface and proposed downhole equipment, bit selection relative the available hydraulics, motor usage relative to available hydraulics and bit selection, the angle of the hole, and finally, the overall hole cleaning ability of the system that is selected. Most of our field personnel and service companies have yet to appreciate the added complexities that have come with our new technologies. If a PDC bit drilled well on a rotary assembly in oil-based mud in a given field, why wouldn’t the same bit work in a dispersive system on a motor in the same interval? If we’ve been able to clean the hole with a dispersive mud system rotating the string at 30 rpm, why do we need 120 rpm with an inhibitive drilling fluid?

Hole Cleaning

Our team has been teaching drilling performance improvement practices for just over 5 years and the hub of these courses is always hole cleaning. With the introduction of more sophisticated drilling fluids we’ve significantly improved hole condition through inhibition (keeping the water out of the rock). This improved inhibition of the wellbore also translates to cuttings coming out of the hole in much the same condition as they were when they left the bit, therefore, more cuttings are reaching the surface whole rather than being dissolved into the drilling fluid.

As these new fluids were being introduced into high angle well applications and the problems with cuttings were recognized, much debate surrounded the issues of fluid rheologies, flow rates, hole washout and tripping procedures. There were two primary philosophies:

1. High rheologies and low flow rate (plug flow)
2. Low rheologies and high flow rate (turbulent flow)

As the industry gained more experience, we were handed rules for hole cleaning such as, “flow rate, flow rate & flow rate”. What all of these rules were missing was the importance of pipe rotation and rotary speed on hole cleaning efficiency.

Today, we can recognize hole cleaning in a deviated well as a complex system that has many elements that must be considered. First, we recognize that hole cleaning is effected by hole size, pipe size, fluid rheology, flow rate, penetration rate, rotary speed, cuttings size and density, fluid density, wellbore stability, tortuosity, bit & BHA design, drilling mode and pipe movement. We also recognize that cuttings flowing over the shale shakers is indicative of the hole being cleaned, the issue then is “rate”. If the hole cleaning system is removing cuttings at a slower rate than we’re generating them, then the hole will load up with cuttings and begin showing signs such as tight hole on connections and packing off.

The goal of today’s hole cleaning system should be to design the drilling fluid rheologies and drilling strategies such that the hole can be cleaned at an acceptable rate without the use of sweeps (more later on this subject), or other remedial actions. If this goal is accomplished, then the only other ingredients for effective hole cleaning are proper procedures and patience. These proper procedures are based on the following:

• Pipe rotation at speeds >120 rpm (lower speeds are OK in small hole sizes)
• Maximizing flow rate at all times
• Avoiding BHA components that don’t allow the first two elements to occur
• Cleaning the hole up with pipe rotation and maximum flow rate while working the last stand on bottom prior to all trips.
• Minimizing the use of backreaming and downreaming
• If tight hole is encountered on a trip, the first assumption is always cuttings
• Maximizing rotary drilling through use of downhole adjustable components
• Using motors for correction runs with rock bits deep in the hole section
• Carefully monitoring hole condition using torque, drag and PWD data to ensure that ROP does not exceed hole cleaning rate.
• Placing a focus on daily penetration rates and not on instantaneous ROPs

Finally, we recognize that with our pipe nearly concentric, most of the fluid flow takes place at the top of the hole. With the classic “bullet shaped” flow profile both inside of the pipe and in the annulus, we rarely find that the use of sweeps has proven effective in getting more cuttings to the surface. In fact, the sweeps almost always spread themselves out in the hole (to a degree dependent on the drilling mode) and then act to “contaminate” the entire system with properties that are unwelcome to our hole cleaning system. Sweeps generally pass along the high side of the hole and elongate. If they do anything productive in the annulus, they move cuttings up the hole until gravity pulls those cuttings back down to the low side of the hole.

Our most important element in the hole cleaning system is our drilling fluid. Its selection will be dependent upon a great number of factors, however, its maintenance once it is in operation should be treated as a top priority on the rig. Our rule of thumb for an effective drilling fluid keys on the 6 rpm reading at ~1.1 x the hole size in inches. The installation of premium solids control equipment such as high-G shakers and centrifuges and a desilter bank capable of processing 100% of the fluid flow is critical to maintaining a low PV and maximizing the fluids “pumpability”. Most importantly, don’t skimp on the chemical maintenance of the system. Playing catch-up is much more costly in rig time and hole condition. These very general rules apply to any inhibitive drilling fluid used for directional drilling.

Bit and BHA Selection

Our focus thus far has been on getting the hole clean by choosing the right equipment and utilizing the proper procedures. The one facet of directional drilling that adversely effects good hole cleaning performance is Bit and BHA Selection. It is also the area of “modern technology” that is most widely mis-used.

There are a few key facts that must be considered:

• Steerable motors are not effective at turning today’s PDC bits in highly directional wells. To effectively slide drill with a reasonably aggressive PDC bit the motor must be run at its maximum flow rate for maximum power output. Further, as the angle of the well increases it becomes more difficult to smoothly control weight on bit and repeated stalling of the motor is immanent.
  
• The use of steerable motors with PDC bits means that a large stall buffer must also be built into the operating system to ensure that the pressure relief valves are not blown when the motor stalls. This generally amounts to 400-500 psi.
  
• In order for the motor to operate effectively, it is realizing its maximum pressure drop (upwards of 800 psi), which is a further drain on available flow rate.
  
• When slide drilling, hole cleaning rate is nil. Therefore, once rotation is commenced, the system is playing catch-up.
  
• Slide drilling to stay on the line is inefficient and un-necessary in most cases. The only goal is to hit the target and leave behind a useful wellbore.
  
• Rotary drilling minimizes tortuosity (doglegs) and, therefore, minimizes torque and drag effects later in the well.
  
• A recent study showed that 97% of slide drilling with a steerable assembly is done to correct for inclination. Therefore, an azimuth correction deep in the hole section with a motor and rock bit would be an effective way to complete the interval.
  
• Downhole adjustable stabilizers are now available, reliable and cost effective.
  
• With rotary assemblies in the hole, hole cleaning is continuous which allows for more aggressive bits to be utilized (though achievable ROP almost always exceeds achievable hole cleaning rate). This leads to increased productivity, a smoother wellbore and lower casing running friction factors.

Bit and BHA component selection should consider the hole cleaning system from other perspectives, as well. Full 360-degree wrap stabilizers should be avoided, instead, partial wrap or straight bladed stabilizers should be utilized in order to maximize the junk slot area of the assembly. This same principal applies to bit selection in order to maximize the “trip-ability” of the BHA. Junk slot area in third party service stabilizers (such as on LWD tools) must also take this into account.

Gravity is working both for and against you in a deviated well. It helps us by holding the pipe to the low side of the hole, which allows us to drill with the drill string in compression. Dependent upon the angle and the length of the hole, all of the string could be in compression even when rotary drilling. Gravity also works against us by creating torque and drag in the well. With both of these facts in mind, BHA design should be kept to a minimum for steerability, evaluation and transition back to the drill string. Hevi-Wate drill pipe in a highly directional well (well over 45°) is only in the string to provide a place to put the jars and to provide transition to the drill pipe. Long BHA’s only act to reduce available flowrate through the smaller inside diameter of the pipe and increase torque and drag through the increased weight of the pipe.

A few final thoughts on bit selection. PDC design criteria will change substantially as the angle of the well increases. Where ROP will be a primary design criteria in a low angle well, it will fall nearly to the end of the priority list in and extended reach well. Make a prioritized list of the requirements for the bit that you’re choosing for a given hole section, then design the bit around those priorities. A sample list for a high angle well might look like this:

• Short gauge section for good rotary drilling control
  
• Small cutters for improved bit life
  
• Good side cutting action for good drilling control on rotary assembly
  
• Steel body for maximum junk slot area
  
• Increased back rake for improved bit life (as ROP will exceed hole cleaning ability)
  
• High impact cutters for dolomite sections in well
  
• Good hydraulics for maximum bit cleaning
  
• Ability to drill at >100 ft/hr

Rock bit selection should focus on the bit’s ability to drill in the environment. The rotary requirement of >120 rpm may mean that the bit is spinning at >250 rpm even with a low speed motor.

Hole Condition Monitoring

One of the added benefits to rotary drilling a long section of hole is that a fairly smooth hole will result. If hole condition is looked after as described herein, then the intervals between wiper trips can be stretch considerably and even eliminated in some cases. Tools have been introduced into the industry to monitor hole condition both from the surface and through downhole tools. Our team has worked extensively with these tools to develop a proven hole condition monitoring system that has significantly cut back on reaming time, wiper tripping and hole conditioning.

The use of surface gathered torque and drag data is one of the key tools to an effective hole condition monitoring system. When coupled with downhole data (such as PWD) and carefully monitored drilling parameters, the system becomes a reliable real-time tool for determining remedial actions during drilling. It is particularly effective at identifying cuttings loading in the hole, thus helping to set maximum drilling rates (i.e., equal to hole cleaning rates). Data gathered during tripping operations is useful for identifying deteriorating hole conditions (wellbore instability) and for avoiding stuck pipe during trips. The overall database is also quite valuable to the planning engineer when looking forward to future operations or future wells.

Pressure while drilling data has proven useful at identifying key areas of the well where Equivalent Circulating Densities (ECDs) are critical. This data has vastly improved our understanding of wellbore hydraulics, the effects of annular pressures on wellbore stability, cuttings loading effects on wellbore pressures and the effects of pipe rotation on annular pressures. ECDs generally become a problem in hole sizes 8-1/2” and smaller in either long extended reach wells or in deep water drilling environments. Ultimately, the importance and impact of PWD data will be dependent upon the application. Design and procedural changes can often help to minimize the effect of wellbore pressure problems if they are know (or suspected to) exist.

Effective Implementation

Performance improvement training is now available for rig crews, operations personnel and engineers, which teaches this “systems” approach to directional drilling design and implementation. This training has proven invaluable to many operations around the world:

• In Australia the complete implementation of this “system” approach to drilling operations improved overall drilling performance by >40% (as claimed by the operator).
  
• In Canada, drilling performance reached a critical stage before these practices were put into place. Hole cleaning problems, regular stuck pipe occurrence and poor overall drilling performance were all overcome once the interaction of all of the drilling components was understood and implemented.
  
• In California, record extended reach wells are being drilled with rigs that would be considered severely undersized by conventional standards.
  
• In Alaska, two wells which were lost in the final hole section for unknown reasons (at the time) were completed successfully once a “systems” approach was used to ensure that the critical aspects of the well were considered in both the design and implementation.
  
• In the Gulf of Mexico, extended reach and deep water programs have benefited from these same principles which ensure not only a successful program, but one that is often so economic that other previously non-viable targets become attractive to pursue.

The importance of training the entire team in these practices cannot be understated. Courses focusing on all aspects of the operations (from cuttings surveillance techniques to BHA design criteria to drilling parameter control to surveying practices) bring each and every person’s job on the team into focus to ensure that their element is contributing to the overall system. Further, ensuring that the entire design team (engineer, supervisor, superintendent, geologist, reservoir engineer, etc) understand the design concepts and that each of the team member’s goals are met for the well is critical.

It has been our pleasure to be in the oil and gas industry during a time of such exciting technological developments. Our goal is to see the industry utilizing these developments effectively and in a fit-for-purpose manner which minimizing drilling times, maximizing well productivity and gives us all more wells to drill.

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