Russia shares technical know-how with U.S.

Rigs similar to this Burovaya Ustanovka 75 metric-ton unit on location in the Sergeevskiya field, helped drill more than 3,200 wells in Bashkiria using electrodrill technologies. In 1988, Bashneft drilled 205 wells with the electrodrill, falling to 37 in 1997 (Fig. 1). Photo courtesy of Bashneft.

• This workshop in Ufa, Bashkiria, shows the variety of components used in electrodrill technologies (Fig. 3). Photo courtesy of Bashneft. [42,507 bytes]
• Electrodrill technologies require specially designed drill pipe that allows box and pin-end contacts to be easily made up during connections (Fig. 4). Photo courtesy of Bashneft. [34,470 bytes]
• This current-collector power supply will be installed between the swivel and kelly, providing a constant power source from the surface to the downhole electric motor (Fig. 5). Photo courtesy of Bashneft. [55,298 bytes]
• A recent demonstration at Maurer Engineering Inc., sponsored by the U.S. DOE, showed the dynamic interacting components of the retractable drill bit configured in the drilling mode (Fig. 8). Photo courtesy of Maurer Engineering Inc. [22,996 bytes]
• This photo shows the assembly as it appears in transport mode (Fig. 9). Photo courtesy of Maurer Engineering Inc. [11,304 bytes]

Russian drilling technologies may provide alternative methods for improving the drilling process. Some of these technologies may complement or replace existing technologies, depending on the level of exchange between engineers from both countries.

Bill Gwilliam, a geologist in the U.S. Department of Energy's (DOE) drilling and completion technologies group, feels several technologies hold promise for future technology-transfer programs, including the electrodrill, retractable drill bits, aluminum drill pipe, hollow glass sphere muds, and mud hammers.

This conclusion of a two-part series discusses two of these promising Russian technologies.

Rotary drilling vs. downhole motors

Until the early 1980s, American drillers restricted commercial development to one technology-the rotary drilling system-although research into positive-displacement motors (PDM) and turbodrills had been ongoing for decades. Rotary systems proved to be the most cost-effective means for drilling a well.

At the same time, Russian engineers committed most of their resources towards the commercial development of three distinct downhole motor technologies, depending on these high-rpm systems to drill faster hole as dictated by the quota system (OGJ, July 6, 1998, p. 68).

In 1990, the turbodrill, rotary system, PDM, and electrodrill accounted for 83.2%, 9.3%, 6.0%, and 1.5% of the market share in the FSU, respectively, resulting in about 42.6 million m of hole.1 As with the U.S. rotary system, the development of downhole Russian motor technologies spurred the development of many ancillary products, many of which were used to reduce cycle time or overcome geologic barriers.

Today, the rotary drilling system still dominates most western drilling activity in terms of wells drilled and footage. However, the use of mud-motor technology (PDM) has steadily grown in direct relation to deviated, horizontal, and multilateral drilling needs.

According to Bob McDonald, vice-president of drilling and evaluation technologies for Baker Hughes Inteq, about 15% of total U.S. footage is drilled with downhole motors, vs. 30% internationally.

Working together

This growing trend towards the use of downhole motors, driven by the need to find innovative ways to cut drilling costs and increase production rates, has prompted western firms to develop alternative drilling systems. On the other side of the world, Russian engineers, encumbered by reduced research and development funding, seek foreign investment. Engineers from both sides may find much in common by examining each others' technologies, then begin searching for ways to marry the best of both.

William C. Maurer, president of Maurer Engineering Inc., said, "The Russians had about 1,000 scientists working on drilling research for 30 to 40 years, so they have about 30,000 to 40,000 man-years into this work, which is orders of magnitude more than what we have done in the U.S."

Maurer and the DOE began documenting these technologies in the mid-1990s, hoping to save this knowledge before the inventors, many of whom are in their 70s and 80s, retire.^{2 3}

"I realized that many American engineers were not aware of the thousands of man-years and the major accomplishments made by Russian engineers on advanced and novel drilling techniques, and that without knowledge of this work, there would be much duplication of effort," Maurer said.

Two examples of this include the electrodrill and retractable drill bit.

Electric downhole motors

The electrodrill has many advantages over conventional mud motors and turbodrills. First and foremost, it allows drillers independent control of the three major drilling parameters: rotary speed, flow rate (fluid hydraulics), and axial load (bit weight). In contrast, PDM and turbodrill systems depend on fluid hydraulics for the control of drill-bit speed and torque.

According to Bairas I. Abyzbaev, a scientist at the Russian Academy of Sciences' Oil and Gas Research Institute, the electrodrill has been used in vertical, directional, horizontal, and multilateral applications across the FSU, with more than 12 million m drilled in Bashkiria, Turkmenistan, Azerbaijan, and Ukraine since 1940.

Bashneft, one of the 15 major oil companies in Russia, drilled the majority of this footage (Fig. 1), encompassing about 70% of all electrodrilling activity. In Bashkiria, the maximum total electrodrill footage/year reached 404,532 m in 1988, falling to 57,577 m in 1997 (Fig. 2 [107,008 bytes]). Cumulative electrodrill footage for Bashneft totaled 6.42 million m from 1950 to 1997.

According to Naeel Z. Gebaduilin, general director for Bashneft, "In the territory where there is electrodrilling activity (Bashkiria), we have drilled about 100 horizontal and numerous superdeep wells with the electrodrill. To service this work, we have created a specialized service base for the purpose of maintenance and repair. This organization lets us service up to 25 (drilling) crews, allowing up to 400,000 m/year if needed."

Hydraulic independence

Abyzbaev said competing downhole systems including PDMs and turbodrills are limited in operability because flow rate, torque, rotary speed, and axial bit load are interrelated. In other words, a change in one operating parameter, such as flow rate, will alter other parameters, such as rotary speed and torque.

With hydraulic motors, there must be enough power (flow rate) to rotate the bit at an optimum angular velocity, while maintaining enough annular flow velocity to clean the hole without creating wash outs. These interrelationships often place stressful operating conditions on the motors, drillstring, mud pumps, standpipe, kelly, and swivel.

According to Victor I. Khalyavkin, chief technologist for the Ufa Drilling Co., Bashkiria, "With the electrodrill, the need for hydraulic power transmission is negated." Thus, the main concerns for the circulating system are confined to bit cooling, optimal hole cleaning, and the maintenance of mud properties.

For hydraulic downhole motors, the quantitative parameters for power transmission losses include the drilling mud flow rate, fluid density, pressure, and well length; whereas, for the electrodrill, electrical voltage, current, length of cable, and contact-joint insulation represent these parameters.²

In essence, PDMs and turbodrills often use excessive hydraulics in comparison to the electrodrill, resulting in enhanced mud-flow rates and pump pressures above and beyond that necessary for maintaining optimal hole conditions. This results in increased borehole erosion and caving while shortening the life of the drillstring and mud pump components.

Diagnostics and control

In addition, Khalyavkin says that because bit torque is related to electric current, drillers can diagnose bit wear by monitoring current meters. And because the electrodrill's rotary speed is proportional to the supply-voltage frequency, rotary bit speed can be accurately controlled.

Finally, Abyzbaev said heterogeneous rock properties can be recorded by monitoring torque values under a constant voltage-power supply, providing geologists with a tool to depict variations in lithologic properties such as sand-shale boundaries.

Information technology

The electrodrill has been used in conjunction with as a measurement-while-drilling (MWD) and logging-while-drilling (LWD) system for several decades. One of the great advantages is its ability to gather information while drilling in any medium, be it air, oil-based mud, or water.

The MWD tool, located above the electrodrill assembly, transmits well-bore azimuth, inclination, and tool-face orientation to the surface. "Since the 1970s," Abyzbaev said, "Russian drilling engineers have been able to record rotary speed, axial load, flow rate, bit torque, gamma ray, and resistivity readings, "using very simple recording systems."

On the other hand, when directional and horizontal wells are drilled with air or gas using rotary, turbodrill, or PDM systems, the acquisition of MWD and LWD data becomes a problem because of the shortcomings of mud-pulse telemetry systems.

Mud-pulse telemetry requires a liquid phase from which to transmit bits of data to the surface. Hence, downhole measurements become nearly impossible to transmit real-time readings to the surface unless a costly electric-magnetic wave or acoustic-telemetry system is used.

Furthermore, pulses transmitted in the liquid phase must overcome noise problems associated with the drillstring "banging" against the side of the hole, mud-pump pulsations, rig noise, and the drill bit's grinding, cutting, or shearing action.

This usually forces the operator to take more precise, yet time-consuming MWD readings during connections. Rig-noise problems do not hinder electrodrill MWD recording systems because the information is sent directly through the electric cable.

Design

The basic components of the electrodrill system include (OGJ, Feb. 9, 1998, p. 46):

• An electrodrill and drillstring assembly
• A telemetric system
• A drillstring with power cable
• An automatic bit feed regulator
• A control station
• A control board
• A transformer used to supply power to the electrodrill.

The electrodrill consists of a three-phase, oil-filled, squirrel-cage induction electric motor and bearing pack fitted with a separate oil cavity.2 In many cases, an oil-filled speed reducer located between the electric motor and bearing pack is used to reduce rotary speed and to increase torque. The drilling mud is supplied to the bottom-hole assembly through a hollow electrodrill shaft.

Electrodrills are designed to function at bottom-hole temperatures up to 135° C. and come in a variety of sizes and performance ratings Table 1 [107,008 bytes] and Fig. 3. Power is conducted through a two-wire, 35 x 15-mm cable that runs up inside the drillstring to the surface.

Electric connectors, located at the box and pin ends of the drill pipe, make up and seal automatically during connections (Fig. 4). A current-collector power supply installed between the swivel and kelly provides continuous power (Fig. 5).

Typically, drill pipe sizes include 114-mm and 140-mm, external-upset drill pipe and 127-mm, internal-upset drill pipe.

Development

Initial commercial applications of the electrodrill downhole motor system began in 1939 by a team of Soviet engineers under the guidance of A.P. Ostrovsky. The first well, located in Azerbaijan, successfully drilled 1,500 m with a borehole diameter of 324 mm. Significant improvements in design did not begin until 1963, however, when a special technological bureau was established in Kharkov.

From that time until the late 1970s, several improvements were made to increase the serviceability and performance of electrodrills including:²

• Electromagnetic frequency converters that allow varying the electrodrill rotary speed from 70 to 700 rpm.
• Improved speed reducers.
• Diesel generating plants for use in nonelectrical areas-most Russian rigs use local power lines and electric motors instead of diesel engines.
• A voltage-control system and downhole instruments to control azimuth, inclination, and tool-face orientation.
• Automatic drillers that control bit torque and bit weight.
• Various bent-angle mechanisms for directional and horizontal drilling.
• Improved properties for gas and heat-resistant cables (2,000 v).

However, despite the advantages of the electrodrill system, Abyzbaev says the technology is still in its infancy. "Since the late 1970s, we discontinued developing this technology, instead choosing to investing in other technologies."

Accomplishments

From 1970 to 1990, the electrodrill has drilled in a variety of geologic environments, proving its ability to drill under extreme conditions (OGJ, Feb. 9, 1998, p. 46). In the 1970s, a series of five deep wells were drilled in Turkmenistan (Kotur and Komsomoolskaya fields), ranging in depth from 4,700 to 5,250 m. The last well drilled in the program broke a record, drilling 1.8 time faster than other wells using the rotary method.

The multilateral well, Dolina No. 801, located in Western Ukraine, also used the electrodrill to drill one lateral off the parent bore hole and three branches off the lateral. In addition, air and foam have been successfully used in Western Ukraine (Bitkov No. 726) and Azerbaijan (Zagly-Zeiva field).

Finally, the electrodrill has drilled numerous horizontal wells in Bashkiria, Turkmenistan, and Western Siberia. In 1997, the electrodrill continued to drill horizontal wells in Bashkiria and Tatarstan, targeting zones with thickness of 1.5-2 m.

Retractable drill bits

According to Roy Long, project manager for the Department of Energy, "the next obvious step [in reducing cycle time] is to attack trip time. Retractable drill bit technology may allow us to do just that."

Retractable drill bits can be retrieved through the drill pipe or casing string without tripping, providing drillers with a quick means for replacing worn drill bits or swapping to other cutting mechanisms such as core bits.

In Russia, oil field testing began on the technology near Perm in 1949. From 1965 to 1975, the Experimental Turbine Drilling Office, Saratov, tested retractable drill bits in 26 exploratory and commercial wells under complex geologic conditions ranging in depth from 2,700 to 3,050 m (Table 2 [19,135 bytes]).³

The technology has also been successfully used in casing drilling tests dating back to 1974 in Western Siberia. In the 1980s, the technology was primarily used for hard-rock scientific drilling, both on and offshore, as well as for offshore stratigraphic drilling projects.²

Mikhail Gelfgat, president of Aquatic Co. in Moscow and former manager for the Drilling Research Institute Vniibt, says other applications include under-reaming, ultra-deep, geothermal, coiled-tubing, and riserless offshore drilling.

Transport, drilling modes

The bit is run in two modes: a transport mode and a drilling position ( Fig. 6 [45,372 bytes]) (Fig. 8-9). In the transport mode, tri-cones arrangements are usually suspended garland style while dual-cones are arranged in pairs. The main elements of the retractable drill bit include the retrievable parts and the housing.

The retrievable assembly consists of the downhole motor, torque/WOB reaction latch, and retractable drill bit (Fig. 7 [56,848 bytes]). The retractable drill bit includes two or three cutter sections and the expanding mechanism (Fig. 10).⁴

The expanding mechanism consists of a barrel that has cone and crossover subs integrated with an outer movable system of parts. This movable system, used to retract and contract the cone assembly, contains an assembly embedded with radial bearings and a collet.

The cone sub contains two holders for the cutter sections. The outer movable system of parts is designed to accommodate the cones during actuation while the collet provides a simple system for transferring the bit to the transport position.

The retractable drill bit is transported to the bottom and pulled out to the surface inside the drillstring. The transfer of cutting elements from the transport to the operational position is carried out hydraulically. However, in the reverse direction, this action is actuated by the interaction of the collet and bottom-hole assembly

Gelfgat says that most cone designs have been manufactured without bearing seals because of time restrictions related to changing out cutter sections and lubrication system cost and design limitations. He feels that western bit manufacturers like Baker Hughes, Smith, and Reed, however, may further advance this technology through the incorporation of improved cutting and bearing structures.

Operation

There are three methods for transporting the bit to bottom and back to the surface: hydraulically, mechanically, and by wire line. "Mud circulation provides the best method for transferring the bit back and forth between drilling and tripping positions," Gelfgat said.

Bit-operation reliability is provided by a slide valve that closes the bit channels in the transport and intermediate positions while opening the channel when the bit reaches the operation position (Fig. 10 [60,685 bytes]).

Gelfgat said the hydraulic mechanism and slide valve assembly provides the driller with a distinct pressure signal at the rig floor as the bit is transferred into the operating position. "Thanks to the slide valve, the automatic restoration of the cones into the operating position is achieved while the bit is off bottom. It is important during the bottom-hole motor process that the bit comes into the operating position before the bottom-hole motor shaft starts to rotate."

When it comes time to retrieve the bit, the driller reverse circulates the drill bit up the drill pipe by closing the blowout preventer and pumping fluids down the backside.

References

1. Neft i Kapital (Oil and Money), September 1997.
2. Eskin, M., and Maurer, W.C., (editors), "Former-USSR R&D on Advanced Drilling Motors," DOE contract no. DE-FG21-95MC31171, 1997.
3. Eskin, M., Maurer, W.C., and Leviant, A. (editors), "Former-USSR R&D on Novel Drilling Technologies," DOE contract no. DE-FG21-95MC31171, 1997.
4. Gelfgat, M., and Alikin, R., "Retractable Bits Development and Application," Journal of Energy Resources Technology, June 1998.

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