Drillers rise to the challenge

If history teaches us anything, 2010 – although challenging – will improve the industry’s status moving forward. Oil prices found some stability over that of 2008-2009. Although natural gas prices have remained low, the “shale gale” should lead to improved technology that will, in turn, increase demand for what is becoming one of the world’s most abundant natural resources.

While there are many high points to discuss, a fair look at 2010 requires a mention of one of the lowest points.

Macondo onward
On April 20, 2010, Transocean Ltd.’s Deepwater Horizon suffered a blowout and ensuing fire. Eleven workers were killed, and the eyes of the world were on BP and the relief effort that followed.

The well was drilled in 5,000 ft (1,525 m) water depth approximately 42 miles (68 km) off the Louisiana coast in Mississippi Canyon Block 252 in the US Gulf of Mexico (GoM). Although Macondo was not the deepest well, it had the misfortune of becoming the deepest blowout on record in the history of offshore drilling.

Due to the extreme high pressure at this water depth, the relief effort proved to be daunting. Contrary to reports by mainstream media critics, the industry stepped up, putting some of the greatest minds in the business to work to bring this problem to a resolution.

Several attempts were made to rapidly engineer a solution, but in the end, it was more drilling that killed the leak.

On Sept. 16, Transocean’s Development Driller III semisubmersible intercepted the annulus of the deepwater Macondo well. It is easy to oversimplify the vast amount of technology that goes into the drilling process. In the case of this relief well, it reached a total measured depth of 17,977 ft (5,479 m).

A hybrid CT unit drilling in South Texas’s Chittim Ranch, where a major operator cut drilling
time from 4.4 days to 1.67 days using highly mobile CT units.(Image courtesy of Advanced Drilling Technologies)

Considering that the Macondo’s annulus was a mere 7.5-in. casing, this feat is even more impressive. The tragic Macondo blowout set the scene that in the end proved the precision and skill of the drilling community.

On Oct. 13, the US government lifted its ban on deepwater drilling – seven weeks earlier than the proposed six-month term. Officials cited new rules as the catalyst for preventing repeat accidents. Even with the ban lifted, the effects lingered. Some equipment fled the GoM in search of additional contracts. Small independents were hit hard by the work stoppage.

Today, even though offshore drillers are returning to work, the final outcome remains uncertain. As of Nov. 10, FBR Capital Markets announced its belief that the Department of the Interior is likely to cancel the March GoM Lease Sale 216 due to the Bureau of Ocean Energy Management, Regulation and Enforcement’s commitment to prepare supplemental environmental reviews prior to future lease sales and the agency’s significant workload on other offshore regulations, including permitting and public comment period requirements. In addition, the firm says the August Lease Sale also could be at risk. Time will tell if GoM activity will return to normal.

Real-time advances
From a technological perspective, 2010 delivered real improvement in the arena of real-time information. With land wells becoming more expensive and technically challenging, real-time applications are growing in importance. The Deepwater Horizon event has solidified the drive to improve safety and compliance of offshore operations from a real-time perspective.

In plays such as the Eagle Ford in South Texas, rotary steerable systems (RSSs) made their first foray into drilling from surface to total depth (TD). In a joint effort between Weatherford and Swift Energy Co., RSS technology was applied in the horizontal drilling program and benefitted both sides of the cost-per-barrel equation by reducing drilling time and overall cost per well. After setting multiple records using Weatherford’s RSS accompanied by a long gauge PDC devised by Reed Hycalog to reduce vibrations, Swift successfully reduced drilling time – spud to TD – from 40 to 16 days. The reduced drilling time has resulted in an overall per-well cost reduction of US $4.4 million and cut dry-hole cost to $1.8 million. Despite the inherent risk of stuck tools, the operating company has managed to maintain above-average performance in the Eagle Ford by closely monitoring its workflow.

Earlier this year, Baker Hughes and Statoil successfully tested the world’s first rotary steerable liner-while-drilling system from the operator’s Brage platform in the Norwegian sector of the North Sea. By eliminating the need to pull the drillstring before running liner into the borehole, the operator saved time and cost while minimizing the risk of hole collapse and reducing nonproductive time (NPT). Performing these tasks with real-time capability helped the operator stay in zone and mitigated the risks associated with low-pressure, unstable formations.

In the northeastern US, the Marcellus shale is rapidly transforming into one of the world’s most prolific unconventional natural gas plays. In partnership with an operator in the region, Tesco successfully set multiple records with its Casing Drive System. After drilling a record lateral well section in northwestern West Virginia, the operator was unable to run the 5.5-in. casing to TD. Despite three separate attempts to open and condition the hole and to run conventional casing, the casing string was unable to pass the heel of the well bore just before the lateral begins.

While the final conventional casing run was made, Tesco was called in to mobilize its top drive, casing running, wireless torque sub (TesTork), and casing drilling services to get the casing to bottom. Tesco set a casing running record for the 5.5-in. lateral of the operator’s first well in the Marcellus and went on to break that record in a second horizontal well, which was drilled to TD of 16,670 ft (5,081 m) with about a 9,400-ft (2,865-m) horizontal section to maximize the length of the production lateral and increase per-well production.

Automation, rig advances
Drilling automation has seen extensive growth within the last decade. Improvements in hydraulic systems, the need to improve safety on the rig floor, and the prospect of eliminating costly NPT have pushed automation to the forefront of engineered solutions.

B-Series rigs are equipped with a Columbia Walking System. The system allows the rig to travel from wellhead to wellhead on a pad in a fraction of the time required for conventional rigs. This system can move approximately 30 in. in 90 seconds and is capable of walking up to 100 ft (30.5 m) without moving the backyard with full setback. A well-to-well move can be accomplished in as little as one hour. The B-Rig can then be returned to a previously drilled well with an accuracy of plus or minus one-sixteenth of an inch. (Image courtesy of Nabors Drilling USA)

Nabors Drilling USA (NDUSA) commercialized its original series of programmable AC electric (PACE) rigs in 2005. These 1,000-hp AC electric rigs feature programmable logic control. After several evolutions from the company’s M-Series to offshore multiwell platform designs as in its Super Sundowner Series, NDUSA recently unveiled its B-Series – a custom- designed box-on-box 1,500-hp rig specifically built for use in plays such as North Dakota’s Bakken shale.

The inaugural rigs – B-01 and B-02 – were designed to accommodate multi-well pads while carrying out simultaneous operations. B-Series rigs are equipped with a Columbia Walking System. Various NDUSA subsidiaries have been working with Columbia on the development of land rig moving systems since 1976. Moving technology has evolved from the pioneering rigs in Alaska to pad drilling in the Rocky Mountains and now to a new walking fleet using PACE technology.

The system allows the rig to travel from wellhead to wellhead on a pad in a fraction of the time required for conventional rigs. This unique system can move approximately 30 in. in 90 seconds and is capable of walking up to 100 ft (30.5 m) without moving the backyard with full setback. A well-to-well move can be accomplished in as little as one hour. The B-Rig can then be returned to a previously drilled well with an accuracy of plus or minus one-sixteenth of an inch.

In other land rig news, Italy-based DrillMec opened a new base of operations in the US to accommodate its clients in both the North American shale market and in South America. The company’s HH Series rigs have been in operation since 1996. These Hydraulic Hoist rigs have gained popularity for several reasons. The HH Series offers a low-profile, low-impact option for drillers in semi-urban areas. The 100% hydraulic rigs also drastically reduce noise to a maximum of 60 decibels at the location limit, compared to conventional rigs where ambient noise can register up to 120 decibels.

The company has developed six classes of the HH Series ranging from the 100-ton HH102 to its largest rig, the HH350.

Originally for use in marginal fields in highly populated areas, the HH Series was designed to fit a small footprint in a region where land costs are very high. The HH Series footprint ranges from 131 ft by 164 ft (40 m by 50 m) up to 197 ft by 262 ft (60 m by 80 m). The conventional rig’s footprint is about 328 ft by 328 ft (100 m by 100 m). Benefits of the HH Series include a highly mobile, low-profile rig with sufficient hook load in a noise-reduced environment.

Water management
In the shadow of the Deepwater Horizon, environmental concerns were raised throughout 2010 about hydraulic fracturing and the public’s concern that the process is capable of contaminating groundwater.

In the face of the possibility that future regulations could limit access to many of North America’s prolific shale plays, the industry took a hard look at water management. Millions of gallons are needed for most staged-fracture completions, which has led to challenges being met in the transportation, storing, treatment, and reuse of frac water.

In an effort to provide full disclosure, Range Resources announced in mid-2010 that it would make public the contents of its frac fluid in the Marcellus region. On July 14, the operator announced, “Range’s disclosure initiative will provide regulators, landowners, and citizens of the commonwealth an accounting of the highly diluted additives used at each well site, along with their classifications, volumes, dilution factors, and specific and common purposes.” The move was preemptive and lauded by the industry as a step forward to ensure shale gas development could proceed unimpeded by speculation and regulatory threats. Whether Range has accomplished that goal remains to be seen.

On the technological side, water management is reaching critical mass. A number of service and supply companies have cropped up with a variety of solutions from central treatment plants to mobile units that mitigate water onsite. In addition to facilities, several companies are making moves to improve water use by reusing flowback water. Earlier this year, Cabot Oil and Gas in conjunction with Superior Well Services and Kroff were able to perform frac jobs in the Marcellus by reusing 100% flowback water.

Although costly, this technology will vastly improve the way hydraulic fracturing is performed. Time and a little positive PR should ease the public mindset as to the ultimate benefit of the fracturing process.