Drilling the Severnaya Truba field in Aktobe, Kazakhstan, has been costly and time consuming. In combination with a drilling-fluid-powered percussion hammer (FPPH), a fit-for-application polycrystalline-diamond-compact (PDC) bit with depth-of-cut (DOC) -control features was used to minimize the exposure of the cutting structure and prevent breakage. The mechanical lifting and falling action creates a rapid variation in weight on bit (WOB), allowing the bit’s DOC to fluctuate while overcoming different stresses. These variations, along with the percussion pulse created with each stroke, led to increased rates of penetration (ROPs).

Drilling with an air hammer is a technique whereby gases (typically compressed air or nitrogen) are used to operate a pneumatic hammer, to cool the drill bit, and to lift cuttings out of the wellbore. Air forced down the drillstring actuates the percussion tool, which, in turn, creates an axial percussion force directed down to a specially designed drill bit.

The advantages of air drilling are that it is usually much faster than using drilling fluid and may eliminate lost-­circulation problems. The disadvantages are the inability to control the influx of formation fluids into the wellbore and the destabilization of the borehole wall in the absence of wellbore pressure typically provided by the mud column. Air hammers are also limited to a lower WOB and will stop working if that weight is exceeded.

An FPPH is the next step in performance drilling. Using the same flow rates and operating WOB of a conventional assembly, the tool offers the benefit of an axial percussion force to facilitate the cutting action of the bit. Like an air hammer, the axial percussion force is generated near the bit to give the cutting structure more energy and overcome the formation’s compressive strength.

The FPPH consists of a conventional power section and the adjustable housing from a motor, which are attached to a specially designed bearing assembly where the axial motion is created. The power section, consisting of a rotor and stator, supplies the rotation speed and torque to actuate the FPPH and turn the bit. Within the bearing assembly, a two-piece mandrel is used to create the axial movement in sequence with the exterior housing movement. This movement, or stroke length, and the frequency of lifts can be varied on the basis of the application and bit type being used.

The falling action is a function of the weight applied at the surface, which reaches the tool and is variable as borehole friction with the drillstring increases. With each cycle (up and down action), the WOB at the tool is lifted until the roller reaches the peak of the slope.

Once the roller loses contact with the surface, it accelerates downward. As it falls, the weight, which was being lifted, goes into free fall, creating a drop in weight that reaches the bit. The downward travel is stopped when the mass impacts the solid plate below, creating a downward percussion force.

The percussion force generated by this impact is transferred directly to the bit, which remains stationary throughout each cycle. As weight is increased, the falling speed is increased, in turn increasing the impact force.

With a normal drilling system, increasing the DOC would increase the power-section load, resulting in torque spikes or even a stall that can stop the rotation of the drill bit. The reaction time for changing the DOC through added weight from the surface is too long to reach the bit, resulting in little benefit to the bit’s performance. Having the DOC change through weight fluctuations only inches from the bit can enhance the cutting efficiency without causing power-section stalls.

The axial movement and weight variation work with the cutting action of a PDC bit. A PDC bit uses a shearing cutting action, wherein the cutter is scraped across the formation surface to shear or fail the rock as it slides. However, most formations do not comprise uniformly smooth rock, forcing the cutters to overcome different compressive strengths and failing methods. As harder formations are encountered, the cutter is forced to slow down and build up energy before it is able to shear.

This slowing is followed by a sudden increase in speed once the rock fails and the stored energy is released. This process of rapid bit slowing and acceleration is commonly referred to as stick/slip and is prevalent in some degree with all fixed-cutter-bit applications. When stick/slip reaches severe levels, it can lead to cutter breakage and a shorter run life.

By use of an FPPH, this stick/slip is reduced because of the weight being oscillated directly behind the bit at a high frequency, increasing the cutter’s reaction time. When the cutter interacts with a formation that requires more energy to drill, the added energy released by the axial motion allows the cutter to overcome the resistance without slowing or building extra torque. The cutter can shear through the resistant formation while nearly maintaining its original speed, reducing torque on the power section and providing consistent performance.

To power the FPPH tool, a lobe power section was used (Fig. 1 above). This system comprises five stages and is filled with an elastomer formulated to maximize power output.

A power section is a power converter that converts fluid power into mechanical power by use of flow and pressure. Mechanical power is then used to provide rotation and torque to the FPPH component. The power section consists of a steel rotor within a steel tube filled with a rubber compound matched to fit the rotor dimensions.

The steel tube is referred to as a stator (being stationary) and contains several stages, which are measurements of length from one lobe crest to the next one, as a full 360° spiral is created (Fig. 2). The more stages on a power section, the more pressure it is able to hold, corresponding to more power and torque. As fluid is forced into the open cavity between the rotor and stator, it applies pressure to the rotor, forcing it to turn so fluid can continue to pass down the length of the rotor.

The rotor is connected to the mandrel within the FPPH tool, and the drill bit is connected to the opposite end of the mandrel. The speed of the rotor is directly proportional to the bit-­rotation speed and will slow as more weight is applied to the bit, creating more resistance from the formation. Higher-strength power sections are able to resist this drop in speed and hold a constant revolution speed as more weight is applied.

This resistance is tracked by monitoring the hydraulic pressure in the drillstring, comparing the off-bottom pressure to on-bottom pressure. Higher pressure differentials (difference between on-bottom and off-bottom pressure) mean more torque is being applied to the bit.

The objective of one run was to validate the performance gains achievable with the FPPH tool combined with a PDC bit compared with standard positive-­displacement mud motors. The offset wells used a combination of three-cone insert bits and PDC bits to drill the same interval as the subject well.

The subject run drilled 750 m in 108 drilling hours, for an overall average ROP of 6.9 m/hr. The entire interval was finished in one run, taking half the time of the two offset runs. Drilling time was reduced from 14 to 7 days, and one bit ­replaced two runs on the offsets, also reducing bit cost. The result is substantial cost savings compared with previously drilled wells in the area.

The combination of new technologies to build a complete performance drilling package has reduced overall well costs and drilling time by increasing ROP.

Not all wells and formations are created alike, which is why drill bits come in a variety of shapes, sizes, and styles meant to tackle most known applications in the world. This new FPPH system is the same, with a variety of sizes and configurations that allow it to be tailored to a particular application and bit type.

Current applications for the tool are geared toward hard-rock solutions because of the nature of the tool’s function and performance drivers. As new configurations are developed, they will be paired with fit-for-purpose bit solutions, allowing the system to expand into even more regions of drilling and cover a wider range of applications.

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 172935, “Hydraulic Percussion Drilling System With PDC Bit Increases ROP and Lowers Drilling Costs,” by Scott W. Powell, NOV, and Ertai Hu, Greatwall Drilling Company, prepared for the 2015 SPE Middle East Unconventional Gas Conference and Exhibition, Muscat, Oman, 26–28 January. The paper has not been peer reviewed.

The Journal of Petroleum Technology, the Society of Petroleum Engineers’ flagship magazine, presents authoritative briefs and features on technology advancements in exploration and production, oil and gas industry issues, and news about SPE and its members.

ISSN: 1944-978X (Online) ISSN: 0149-2136 (Print)