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Vietnamese rental expert rolls out Asia’s first 12-bar CP compressor for piling

Asia's first 12-bar Chicago Pneumatic (CP) compressor, a CPS 375, is being used on a foundations contract in Hanoi, Vietnam to ‘flush out’ 50m-deep borings for concrete piles.

The first Chicago Pneumatic (CP) high-pressure 12-bar portable air compressor to have been sold in Asia is working on a foundations contract in Vietnam, where it is being used to flush water and soil from the bottom of 50m-deep piling bore holes.

Hanoi-based compressor rental specialist Truong Loc (TLC), which owns the CPS 375, is supplying the unit to foundations contractor Delta Construction.

TLC was the first company in Vietnam to buy CP portable compressors.

The launch of the CP brand in Vietnam earlier this year was a significant move, because the portable compressor market is dominated by second-hand machines, mostly from Japan. However, the nation’s construction sector is performing increasingly strongly, with an enormous public-sector infrastructural programme and the private sector also showing powerful growth, and contractors are beginning to appreciate the advantages of new compressors.

Established in 2003 and specialising in the rental of generating sets to the construction, transport and military sectors, TLC represents a new generation of Vietnamese plant specialists prepared to invest in advanced brand-name technology.

Previously relying on used Japanese-brand compressors, the two CP machines – the second unit is a 7-bar CPS 275 compressor – are the first new units in its fleet.

Delta Construction is using the CPS 375 on a three-month contract to install the foundations for the Toan Cau Oil & Gas office building project in Hanoi, where the contractor is boring 200 holes for piling.

The holes, 50m deep and varying in diameter from 80cm to 1m, pass through soft mud and layers of impacted clay and sand.

When the bored hole has reached its full depth and the steel lining has been installed, the compressor is used to blow the water and soil back up out of the hole, so that the reinforcing steel cage can be inserted and the concrete poured. It takes about a day to complete one pile.

Delta had earlier used a larger compressor for the project, but, after 80 holes had been bored, the machine had to be deployed elsewhere, so TLC supplied the CPS 375 for use on the remaining 120 holes.

The CPS 375 has a free air delivery of 10.4m3/min (367cfm) at 12 bar for high-pressure applications and is powered by a Deutz four-cylinder diesel engine rated at 104 kW.

Each unit is assigned an operator for the duration of the rental, ensuring competent operation and eliminating any misuse that can happen with unskilled operatives.

Mr Hoang Tri Tho, the TLC operator on the Delta project, says that the compressor is working for only about an hour per day but that it has to work quickly and cleanly so that the contractor can install the reinforcement and the concrete.

He said: “I’m used to working with second-hand compressors, which give problems with reliability and servicing, but we have had no difficulties, even in the bad weather we have been experiencing during the typhoon season.”
It’s all in the method
Discovering ways

Discovering ways to increase well output is an evolving science. Getting the most production from a well once revolved only around the size of the hole or how the well was developed using various fracking or casing methods. Today, optimal production is also determined by how the well is drilled.

Pense Brothers Drilling, based in Fredericktown, Missouri, is working with Scientific Drilling to develop a directional well in coalbed methane (CBM) for Constellation Energy Partners (CEP). The Cherokee Basin reservoir in Osage County, Oklahoma, has the potential to produce more from drilling directionally.

Pense Brothers operates 23 rigs, 13 of which are Atlas Copco RD20 drills in the five south-central states of Utah, Colorado, Arkansas, Alabama and Oklahoma. CEP is an energy company that markets gas from three reservoirs, including the Black Warrior Basin, Woodford Shale and Cherokee Basin.

Scientific Drilling specialises in directional drilling, hiring out its skills to energy companies such as CEP. The CBM gas potential of the Cherokee Basin lies in thin strata, ranging from 1-4ft (30-122cm) thick, which allows for greater recovery when the boreholes are drilled directionally.

Larry Pense, manager of Pense Brothers’ Glenpool office in Oklahoma, says the method of drilling is dictated by the formation and customer. “Our job is to keep equipment operating on the surface. CEP tells us where to drill and the method to be used. Scientific Drilling drills the hole. I don’t want to make it sound too simple, but our job is to go up and down, and round and round, and Scientific tells us what move to make.”

Rodney Tate, drilling engineer with CEP, says: “Cherokee lends itself to directional drilling. The formation is hardly ever flat and following it allows more contact area.”

The deepest that Pense has drilled is about 5,600ft (1,707m). According to Pense, the deepest well drilled to date in Oklahoma is 4,500ft (1,372m), with wells as shallow as 500-600ft (152-183m). Mr Tate adds: “Some wells are as much lateral as they are vertical.”

Total vertical depth (TVD) measures the actual ‘straight down’ depth from the ground surface to the bottom of a well. Total depth (TD) includes all of the measured depth, from the surface to the end of the drill string. The gas formation is shallower on the eastern side of the basin than the west, with a 700-2,300ft (213-700m) TVD variance. “We could have a lateral well from 0-2,000ft (0-610m),” says Mr Tate.

Speed is the primary thing that makes the RD20 fit CEP’s drilling programme. “Anything that reduces time to TD is beneficial,” according to Mr Tate. “The RD20 is mobile and the auxiliary equipment has a smaller footprint.” He says it can take a conventional rig 20 days to complete what an RD20 can do in two days – from rig-up to rig-down.

“Daily rig costs are much greater for a double or triple conventional rig, and the leased footprint costs are much greater. Economically, this just makes sense,” adds Mr Tate.

The RD20 works well for directional drilling. “Top drive is useful because it allows you to turn on top verses just rotating the mud motor. Also, the hydraulic pull-back and pull-down allows the driller to accommodate the formation,” says Mr Tate.

Scientific Drilling’s directional driller, Walter Hancock, is the man on-site working with Pense. His role is to direct the operation and give guidance to Pense’s driller, Jose Pedraza. He reads the data feedback on his computer and keeps an eye on the cuttings, and then conveys to Mr Pedraza to turn the rotary head or increase/decrease mud flow, which ultimately translates into directing the bit.

The directional mud-motor turns by the flow of mud moving through it. For example, 150gpm of mud equals 70rpm. “Directional drilling is much the same if you’re at 2,000ft or 12,000ft (610m or 3,658m),” points out Mr Hancock. “It comes down to knowing the weight on the bit. That’s how the hole talks to you.”

To drill at an angle, a mud motor is needed. Pumping mud down the string through the motor turns the bit. The position of the drill string determines the angle that the hole will take. Mr Pedraza has a gauge showing him the direction in which he is going. Compare the round drill-pipe to the 360° face of a compass: the gauge points to the location on the drill pipe that indicates the direction in which the bit is moving (as seen in the photo, the bit is turned 240° southwest).

For Mr Hancock, directional drilling with the RD20 is somewhat different from conventional rigs. The RD20 has 30,000lb of hydraulic pulldown, whereas with conventional drilling the weight of the string puts weight on the bit. As the gas zones are much shallower in Oklahoma, the pulldown on the RD20 places more control in the hands of the driller. A gamma sensor within the drill string tells the operator the location of the bit and the formation’s composition or contents. The sensor feeds data back to the driller’s laptop.

Mr Tate says: “As technology improves, sensors have moved closer to the bit and the motors have become smaller, and deciding which to use comes down to economics.”

The gamma sensor used by Scientific is 28ft (8.5m) behind the bit, but Mr Tate says it is possible to get within a few feet of it. In addition to the inclination and azimuth as the drill string advances away from the surface, the gamma sensor indicates the radiation in the formation, allowing the driller to follow the gas in the formation.

Scientific’s proprietary sensor technology is in a section added to the drill string that Mr Hancock will only describe as a “hybrid sub that looks like two sections of pipe with a plastic piece in the middle”.The non-metal section is needed to separate the sensor’s antenna from the mud motor, keeping it from shorting out.

The gamma sensor is powered by three long lithium batteries. When the mud motor turns, the sensor sends information to the surface. When the rotary head on the drill turns the drill string the sensor does not send information, but neither does it use any battery life. The batteries last about 150h. The advantage of turning from the surface and saving on battery power is greater time spent in the hole and less time tripping.

Drilling in the Cherokee Basin is fast. Using a 77/8in (20cm) polycrystalline diamond, compact, fixed-cutter bit, the crew makes good time as the formation is predominantly shale. The average well in this region is about 3,000ft (914m) to TD and takes about three days, according to Mr Pedraza.

As with all drilling, speed is dictated by the formation and Mr Hancock says he was averaging 26-36ft/h (8-11m/h) on the well when the job was photographed, but that it had been as high as 216ft/h (66m/h) at times. Moving through coal seams, for example, is very fast because the coal is soft and the cuttings float so they come out of the hole fast.

It is optimal to move through the gas zone as quickly as possible to avoid damaging the formation, which could impede gas recovery. Although the RD20 is capable of 30,000lb of pull down, Mr Hancock says he works with Mr Pedraza to pull back on the drill string, placing no more than 20,000lb on the bit.

Transitioning to a top-drive rotary-head rig took some getting used to for Mr Hancock because the hydraulic gauge tells him the weight on the bit. On a kelly-drive rig, the weight indicator on the string and pump gauge tells Mr Hancock how fast to go.

Drilling this hole, the crew set and cemented 85/8in (22cm) surface casing to 120ft (37m). When drilling resumed, about 60ft (18m) past the steel casing, the sensor could be used. This is where Mr Hancock began turning the corner, steering the bit at a 20° angle per 100ft (30m), increasing to 40° and then 53° to TD. The TD was 2,990ft (911m). The TVD was 1,936ft (590m) and passed through four gas zones.
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