To a golfer, 22 holes-in-one would represent a fantasy, if not a lifetime goal. To Tulsa, Oklahoma's The Williams Cos., it represents the ability to drill 22 wells from a single drillpad. That ability, combined with a work process called "simops," is giving Williams a competitive edge in the Piceance Basin.

Simops, or simultaneous operations, combines a new rig design with efficient work processes to enable drilling, completion and production of 22 wells from one drill pad. The concept was born when Williams worked with its Tulsa neighbor, drilling contractor Helmerich & Payne Inc. (H&P), on a new rig for its Piceance Basin gas exploration program in Colorado.

H&P's FlexRig4 has a bi-directional rail-and-track system to accommodate two-row drilling. The rig has a hydraulic-ram skidding system with two sets of cylinders, two reversible claws and a hydraulic control console.

The well pattern consists of two rows of 11 possible wells with a maximum spacing of 10 feet between each row and 7.5 feet of space between wells within each row. The system also includes a drag chain for all electrical components and low-pressure piping to serve the substructure, or cellar beneath the rig floor. The wellheads are in a very compact location to drill without the need to reposition the drillpad.







"We helped develop the technology with H&P. We collaborated on the design, especially with the pipe handling, the mud system and the size of the top drives," says Steve Harris, Williams completion manager in the Piceance Basin. "We said we wanted to drill multiple wells on the same pad and minimize the footprint. The FlexRig4 is what H&P came back with."

Drilling multiple directional wells in record time is a big part of Williams' strategy to monetize huge gas reserves in its Piceance holdings. The company has more than 160,000 net acres in the basin. Overall, the basin holds one of the largest gas deposits in North America, thought to be in the neighborhood of 200- to 300 trillion cubic feet of gas resource in place. Williams' gross production in the basin is 600 million cubic feet per day and a majority of its E&P capex budget for 2007, some $1.4 billion, will be invested in the Piceance.

"We've now received 10 rigs from H&P, each under contract for a term of three years," says Robert Vincent, Williams production-engineering manager. "The FlexRig4s were designed and engineered for Williams' operations in western Colorado. The directional-drilling capability is very critical to our operations."

Williams put the rigs to work on its Parachute and Rifle plays. The first rig was delivered in December 2005 and the others followed at a rate of one per month. The company went back to H&P for four more of the new-generation rigs but there had been a surge in demand for them-other operators had orders in for 60 of them.

"Although we wanted more rigs, we would have had to get in line, so we went to Nabors to get those other four rigs," Harris says. Houston-based Nabors Industries Ltd. also builds an efficiency rig, the SuperSundowner (SSD), modeled after its successful offshore design. Williams has one of these at work and expects delivery of the other three in the next few months.

The SSD rig also allows simultaneous drilling, completion and production activities for multiple wells on one drillpad. "It's a maximum-efficiency rig," says Brent Wulf, vice president, marketing and sales for Nabors. "It's similar in design to our offshore rig in that it allows more wells on one location using a small footprint.

"Also, with conventional land rigs, it takes between three to five days to move the rig to a new well location. With the SSD, it takes one to two hours, and the rig can stay on one pad for six to eight months for optimal utilization."

All of Williams' contracted efficiency rigs, along with three more ordered, will be working in the Piceance within a 16-mile radius of Parachute in western Colorado. Williams put all the rigs to good use, paring drilltime throughout its large production portfolio in the basin.

"The conventional average before was around 21 days to drill a well. Now, we have drilled some in as few as six days. Our current average drilltime is 11 days, so we have just about cut it in half," Harris says.

The number of people operating the efficiency rigs is the same as Williams would have on a conventional rig, given that the number of personnel required is a function of the mud system and solids handling.

"Still, we can keep up with drilling by working just 12 hours a day. We don't have to have relief crews to man the equipment. Just running one shift on the completion equipment reduces the manpower requirement substantially," he says.



Rig features

The FlexRig4 and SSD were designed to deliver a trifecta of advantages to Williams: They are faster, safer and less intrusive to the environment than conventional rigs. "The rig has the ability to move north, south, east and west along tracks to get to the next well without dismantling the rig and setting it up again," Vincent says. "The rigs can move between 22 different slots before having to dismantle and move on."

Conventional rigs drill about eight wells per pad before moving to another location. "So, in essence, we've reduced the number of pads by two-thirds," Vincent says.

A conventional rig could take four or five years to complete full-field development due to transition time between drilling, fracturing and completion activities. "With an efficiency rig, you can drill an entire area once and then be gone.

"That is one of the advantages that has been well-received by landowners and regulators. We minimize the intrusion time and still develop the reserves. The development time is very short and succinct, and then the wells produce for 30 years."

While the surface locations are almost adjacent, the subsurface targets are reached directionally. The rig can drill 2,200 feet laterally, allowing up to 16 miles of reach from a single pad. That's about as far as Williams has taken the technology to date, and it isn't the maximum capability, Vincent says.

The rig has variable-frequency drives for increased precision and measurability, and a computerized electronic driller to precisely control weight on the bit, rotation and pressure.

As for safety, the rig has an automatic pipe-loading system, a mechanical iron roughneck and hydraulic lifts to minimize pipe handling. "We have a no-touch pipe-handling system that consists of a V boom. It's a mechanical handling device that actually unloads the casing, picks it up and hands it to the iron roughneck," says Harris.

"So the operators don't have to handle pipe very much. It's almost completely handled mechanically. This technology is still under development and has a lot of promise. The biggest single advantage is safety. It eliminates the risk of injury. It also allows for faster operation."

Another safety feature is the indoor driller console. On a conventional rig, the driller stands outside in the weather with a hand on the brake handle. On new-generation rigs, the driller sits inside the doghouse and operates the rig by computer. The arrangement also puts more information and control at the fingertips of the driller.

The efficiency rig uses fewer electric generators than a conventional rig, thereby reducing noise pollution at the site. Conventional rigs require about seven diesel engines. The efficiency rig uses two, with higher horsepower and fewer emissions.

The rigs also have a blowout-prevention system and satellite-based communication.

The reduced footprint of the rig is a two-fold advantage. Notwithstanding the substantial reduction in the number of drillpads, fewer new roads are required to transport equipment. Furthermore, the rig includes a self-contained mud system to ensure that drilling fluids and cuttings are kept enclosed to eliminate open drilling-fluid pits-again, contributing to safety and a less intrusive and smaller footprint.

"One of the main reasons that Williams went with this type of rig is to reduce the footprint needed to drill the wells necessary to effectively cover the reserves," Vincent says. "This way, we can drill many wells from one surface location as opposed to many wells from many surface locations. That's probably one of the stronger reasons and selling points for going with this technology, as opposed to faster drilling time."

Harris agrees: "For a one-section development, about a square mile, it would typically take 16 pads to produce 64 wells. Now, in that same section, we are looking at only three or four pads."

Also, he says, the terrain in this part of the Piceance Basin isn't flat, so it isn't possible to put pads throughout sections.



Simops method

The efficiency rig is half of the equation. The other half is the method of operations.

"We are not only drilling from the pad, we are actually completing the wells and producing gas at the same time," says Vincent. "As soon as we drill two to four wells, we start fracturing. Typically, from the day the last well is drilled, and after we get the logs and programs written, we start frac'ing-usually about 14 days later."

With simops technology, Williams is selling gas while the rig is still drilling on the same pad. When using a conventional rig, Williams waits until all the wells are drilled and must move the rig off the pad before starting completion.

"Simultaneous operations has really shortened the time period from spudding one well to bringing it onto production," Vincent says. Williams' operators used lessons learned from the first installed efficiency rig to improve operations on rigs subsequently delivered.

Harris says, "The planning cycle of how we were going to do the drilling, completion and production is not anywhere near what we originally conceived. We found better ways of doing things than were originally planned."

For example, the engineers planned to have all fracturing and completion equipment onsite on the rig. Williams has since discovered that, by moving some of the equipment offsite, they can better complete multiple pads simultaneously, further reducing costs and improving efficiency.

"There is a lot of equipment in a very compact area at the wellsite," Vincent says. "In some cases it makes better sense to move completion equipment, such as pump trucks and sand trucks, to a place offsite to give us more space. Space is at a premium and we need to manage that space extremely well to conduct simultaneous operations effectively."

Williams still has a need for conventional drilling, however. "No matter how much modeling and simulation you do, sooner or later you have to actually go drill holes and make sure the reserves are there. The conventional rig is still best suited to do that. You need the preliminary drilling activity to prove the reserves are there before you make the investment in FlexRig technology," says Harris.

"There are a lot of operators that see the advantage of doing this," he says. "In this play, it is rare to drill a dry hole. Virtually every well Williams has drilled, within its 10-acre bottomhole spacing, has hit economic gas. Rather, the challenge is to drill, fracture and complete wells efficiently to enhance well economics. I think there is a definite trend showing that efficiency rigs are catching on."

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