By Tom Kellock, ODS-Petrodata

Figure 1: Jackups remain the leading type of rigs being ordered or planned in new offshore rig projects – even though less than 65% of the existing jackup fleet is at work. Overall for all rig types, 72 new rigs projects have been announced since mid-2010; there are also options for 51 additional new rigs.

The last time I had the privilege of writing an article for Drilling Contractor was in March 2009, when the offshore drilling industry was reeling from the effects of the more than 70% drop in oil prices in less than a year. Today, while oil prices have recovered, although they are still considerably below the level seen in July 2008, there is still a host of unresolved issues facing both contractors and operators.

First and foremost is “Where are oil and gas prices going next?” Most observers feel that current troubles in North Africa and the Middle East, sparked by Tunisia’s revolution, are keeping prices higher than they would otherwise be. However, Japan’s reduction in energy demand due to idled refineries and factories must presumably be having a negative effect on prices, although by how much is not clear.

Longer term, the virtually inevitable slowing of nuclear power development in the United States and probably other countries, following the damage caused  to a number of Japanese nuclear reactors by the March earthquake and tsunami, will almost certainly lead to increased oil and gas demand. This will be supportive of higher prices.

For US natural gas prices, the key issue is whether shale gas development will survive the environmental challenge it is now facing.

Meanwhile, the rest of the world is only in the very early stages of large-scale shale gas development, but these could conceivably lead to massive new supplies at a cost that makes offshore production an uneconomic proposition – as appears to have already happened in the United States, where jackup demand was declining rapidly even before the slowdown in the issuing of permits following the Macondo incident.

More immediately, the eagerly awaited first post-Macondo permits for deepwater drilling in the US Gulf are being issued but, as yet, with no assurance that these will come in a sufficiently steady flow to justify operators chartering rigs on a long-term basis for use in the region; any significant amount of downtime between wells would be prohibitively expensive. Meanwhile the longer-term impact of Macondo on equipment specifications and additional regulation in both the United States and the rest of the world is still by no means clear.

Interestingly, the reaction of many drilling contractors, both large and small, to this situation is to rush out and order new rigs in large quantities. Since the middle of 2010, no less than 72 new rig projects have been announced, and these involve options for 50 additional rigs, although there is no guarantee that many of the latter, let alone a majority, will be converted into firm orders.

The stated rationales for this new building boom vary with the rig type. For jackups, three reasons for building new rigs – at a time when less than 65% of the existing fleet is at work – are commonly given:

1. Most of the existing jackups are old and need to be replaced.

2. The work being done by jackups is technically more demanding and requires modern high-specification units.

3. Operators want new rigs for reasons of safety and efficiency even when older rigs could do the work.

There is certainly some truth in each of these statements, but at the same time they are to some extent misleading.

“Most of the existing jackups are old….” – With 202 jackups 30 years or older, there are certainly a lot of old rigs in the fleet. However, the average age of today’s rigs is 24, just under what was probably their original design life, and several 40-year-old rigs are working.

“… and need to be replaced” – It should be pointed out that age by itself does not necessarily tell you very much; many of these older rigs have gone through major refurbishment and life-extension projects. Given the costs involved, their owners clearly did not feel that these rigs needed to be replaced.

“The work being done by jackups is technically more demanding and requires modern high-specification units” – While there is no doubt that this is the case for some work today, it is not always applicable. There has been very little change in the average water depth in which jackups have been working over the past 10 years, and today few of these rigs are working in water depths greater than 300 ft. When it comes to drilling capability, it is perhaps significant that a 2008 extended-reach well, whose measured depth was a record-setting 40,320 ft, was drilled by a rig built in 1981.

“Operators want new rigs for reasons of safety and efficiency even when older rigs could do the work” – This has some validity but, at the same time, is clearly not true for all operators, who are today using more than 100 jackups 30 years old or older.

Figure 2: The demand for jackups has been insensitive to changes in oil prices over the past decade. Even if oil prices remain at current levels, it is unlikely that there will be a large increase in jackup demand.

The newer, higher-specification jackups are enjoying higher utilization and dayrates than their more “lowly” brethren, but it may be rash to assume that there is unlimited scope for additional units to be added to the fleet without affecting one or both of these parameters.  Given the length of time that water depths of less than 400 ft have been accessible for drilling, most prospective areas are fairly mature. With overall demand for jackups remarkably insensitive to changes in oil prices over the last decade, it appears unlikely that there will be any great increase from today’s even if oil prices stay at current levels.

The arguments listed above supporting the need for newer and more powerful jackups could be applied equally well to the mid-water floater fleet, which on average is actually older than the jackup fleet, primarily because it has not seen an influx of new rigs in the past decade.

However, with the exception of a handful of new rigs aimed at the harsh-environment markets of Norway and the Barents Sea, almost all contractors are ignoring this segment and, as far as floaters are concerned, are concentrating entirely on ultra-deepwater units. All of the recent orders and options are for rigs with a rated water depth of 10,000 ft or more.

To justify the construction of these rigs, most of which – other than the seven drillships for Petrobras – are being ordered on a speculative basis, two arguments are being put forward.

1. These rigs are available at prices that will probably never be repeated.

2. The deepwater market is where the growth in rig demand will come.

It is hard to argue with either statement. As this article was being written, Maersk Drilling just announced that it expected to pay approximately US$650 million for each of two 12,000-ft water depth drillships from Samsung, including owner-furnished equipment, project management, commissioning, startup costs and capitalized interest, i.e. everything except the cost of mobilization to the first drilling location.

This compares to almost $1 billion being paid for at least one (non-harsh environment) ultra-deepwater semisubmersible ordered in 2008.

Figure 3: Despite increases in the water depths at which floaters are operating, the average working water depth for floaters is still only around 3,000 ft.

With regard to growth in demand for these rigs, there is little doubt that, if current trends in terms of discoveries continue and oil prices do not fall below US$75/bbl for any extended length of time, many more rigs will indeed be needed. Whether they all need to be capable of drilling in 10,000 ft or even 12,000 ft of water is, however, much more debatable.

While the trend in floater use has seen a fairly steady rate of increase over the years, the average water depth in which floaters are currently drilling is only around 3,000 ft.

For the ultra-deepwater rigs, defined here as those equipped for work in water depths greater than 7,500 ft, the average well water depth has remained fairly constant over the past 10 years at a little more than 5,000 ft. Of course the number of rigs in this category has increased substantially over this period, from 17 in 2001 to 81 in April 2011, so the volume of drilling in deepwater has also increased greatly, but we are still a long way from needing many rigs to drill in more than 10,000 ft of water.

In summary, we are seeing a dynamic market with a shift in the nature of some jackup drilling, although overall demand in this segment remains fairly flat, little expected change in the use of the midwater fleet, and growing demand for deepwater rigs but perhaps not for ultra-deepwater units.

Operators should be thanking their lucky stars that drilling contractors are taking steps today to ensure that there will be enough rigs, perhaps more than enough, with the appropriate capabilities to meet their demands in the future, by ordering rigs today without, in most cases, the security of a long-term contract. Hopefully they, and the organizations involved in the financing of these units, will be well rewarded for this strategy, but undoubtedly there will be some surprises in store in the years to come.

By Jerry Greenberg, contributing editor

Unit Drilling’s Rig 103 is working for QEP Energy in the Granite Wash in the Anadarko Basin. QEP has 41,000 net acres under lease that are prospective for the Granite Wash.

Drilling and completion technologies have helped US shale plays to gain more attention than even a few years ago. Vertical wells used to be the name of the game in some oil-rich areas such as the Niobrara shale in the Denver-Julesberg basin in parts of Colorado, Wyoming, Kansas and Nebraska. Very few horizontal wells had been drilled in the Niobrara until a few years ago.

Drilling contractors have helped the boom by building fit-for-purpose rigs with enhanced drilling capabilities that reduce operational cycle times and costs. Rigs built for the Bakken are winterized, and most also have skidding capabilities for pad drilling. Better fracturing and completion techniques allow operators to drill longer horizontal laterals to optimally drain the formation without having to drill additional wells.

Unit Drilling Corp owns and operates 122 rigs and is active in virtually all US shale plays, from Haynesville, Barnett and Eagle Ford in Texas to the Woodford, Cana Woodford, and the Mississippi and the Marmaton plays in Oklahoma.

“The interesting thing about the Mississippi and Marmaton plays is that both are targeting shallow formations between 5,000 and 7,000 ft before going horizontal,” said John Cromling, executive vice president for Unit Drilling. “That opens up a new area for another class of rigs, 1,000-hp rigs that are equipped for horizontal drilling.”

Unit Drilling also has rigs contracted in the Niobrara in southwestern Wyoming and is active in the Bakken.

Key rig technologies

Unit Drilling’s Rig 106 is working for Ursa Resources in the Bakken in North Dakota. The rig is located near New Town, N.D., on a Slawson Exploration location.

“Shale plays have progressed from vertical wells to highly deviated wells to horizontals, and horizontals with long laterals,” Mr Cromling said. “Drilling rigs evolved accordingly.”

He listed five key technologies that helped rigs to successfully drill the various shale plays, and each has helped to reduce operational cycle time and/or improve safety.

First is top drives. Second is larger and higher horsepower mud pumps, “because hydraulics are the key to drilling horizontal wells,” he explained. “The pre-eminent factor for drilling horizontal wells, much more so than the hookload of the derrick or drawworks horsepower, is hydraulic horsepower.”

The third technology is the mud system. “During horizontal drilling with high rates of penetration and with a large volume of solids being removed during the process, a good mud system is necessary to remove the solids,” Mr Cromling explained.

Another key area is the drillstring. “We are doing things with drillstrings now that we had been taught for 50 years not to do,” Mr Cromling said. “Pipe in compression, for example, and running heavy-weight pipe instead of drill collars and running it above the drill pipe.”

The fifth technology is skidding systems. “All of the shale plays are in the development process to some extent,” he said. “Most of the rigs in the Barnett shale can skid, and a lot of wells in the Bakken are at the development stage and they are drilled with rigs that can skid over multiple well pads.”

“It could take as little as three hours to prepare for the skidding operation and another three hours to restore the unit for drilling operations, while the actual move is usually less than one hour,” Mr Cromling said.

Other equipment that helps reduce operational cycle time includes a BOP handling system, which is critical for rigs that skid from wellhead to wellhead. The system picks up the BOP in a single unit from one wellhead, suspends it in the rig’s substructure while moving and then lowers it to the next well via hydraulic winches. “All of our skidding rigs have BOP handling systems, and it is a key factor in saving a lot of time in the preparation and restoration of the rig when skidding,” Mr Cromling explained.

Some operators also prefer the hydraulically operated catwalk, not necessarily because it saves time but because it eliminates third-party service and improves safety.

It’s interesting to note that most of Unit Drilling’s rigs do not incorporate cyber chairs with joystick controls. “We have some rigs with joysticks and a lot of rigs that do not,” Mr Cromling said. “Most of our newbuild rigs do not use joystick controls. Some people are convinced that if you don’t have a joystick your rig doesn’t have all of the new technology that is available,” he continued.

“I’m not against them, I just don’t think that is the only solution.”

When asked if using a rig without a joystick is more of an operator preference, Mr Cromling said, “That is more my preference. I think our rigs drill just as fast and efficient” as rigs with joysticks and automatic drilling systems.”

A Precision Drilling rig drilling for Anadarko Petroleum rises above the cactus in Southwest Texas’ Eagle Ford Shale, where Anadarko recently completed a joint venture agreement with Korea National Oil Company.

Anadarko Petroleum’s total 2011 capital expenditures are expected to be between $6.2 and $6.6 billion, with about 10% allocated to US shale plays. In the Eagle Ford, the company increased its average estimated ultimate recoveries to more than 450,000 barrels of oil equivalent per existing well. Its 200-plus planned wells for 2011 also signify a doubling of drilling activities from 2010 levels.

In the Marcellus, Anadarko plans to operate 10 rigs and participate in more than 250 wells this year. “The Marcellus will continue to be the only domestic dry natural gas field where the company will be actively drilling due to the play’s proximity to premium natural gas markets that enhance already robust economics,” the company said in a news release.

“Anadarko had nine rigs operating in the Marcellus play as of late March,” said Steve Bosworth, vice president of worldwide drilling for Anadarko, “including one rig that spuds and air-drills the vertical section of the wells from a multi-well pad to the kick-off depth to begin drilling the horizontal lateral portion.”

The company said it will continue to invest in other emerging onshore oil plays, including Bone Spring, Avalon shale and Wolfcamp in the Permian Basin, and the horizontal Niobrara play. Anadarko was operating two rigs in the Niobrara in late March and expected to increase that to three rigs by early April. “We are drilling Niobrara wells on a limited basis at the moment,” Mr Bosworth said. “It’s still early in the evaluation, but we hope to be running six operated rigs there by the end of this year.”

Reducing operational cycle time, costs

Mr Bosworth is convinced that, even if some line items are higher in cost than other methods resulting in the same end, operators will always save money by reducing the operational cycle times. Anadarko looks for higher-quality, higher-technology rigs for its horizontal shale drilling programs.

“The reason we feel we do as well as we have on the operational end is by utilizing these higher-quality rigs,” Mr Bosworth explained. “We look for a rig that will not compromise safety, and in fact improve safety, while improving our operational cycle time.”

He said the automatic catwalk is a safety improvement and eliminates additional third-party service personnel on location. He has similar feelings about separate crews to run casing. “Basically we are connecting two pieces of pipe,” he said. “It should not be dramatically different for a rig crew to run casing versus having a third-party casing crew and timing the logistics of that crew to the rig.”

Anadarko has been able to eliminate having a third-party casing crew about 20% of the time, but Mr Bosworth believes that will increase not only for Anadarko but across the industry. In time, a rig crew running casing will become more proficient at it, he added.

With about 95% of Anadarko’s current Eagle Ford production flowing to sales, the company’s operations are already tied in to a large and expanding network of gathering and processing infrastructure in Southwest Texas.

Pad drilling has also brought operational and economic benefits by allowing the company to batch together certain operations and “make it more like a manufacturing process,” Mr Bosworth said. “We are trending toward operating rigs with skidding capabilities because they are becoming more important to us from an operational efficiency standpoint by moving from wellhead to wellhead in a matter of hours rather than days.”

Mr Bosworth is not convinced that all technology is necessary from an economic standpoint. For example, while some operators often use rotary steerable systems in horizontal shale plays, “we think we do well with conventional tools depending on the particular area,” he said.

On the other hand, Anadarko’s success with rotary steering is resulting in increased use, depending on the area. “We are very encouraged by the rotary steerable wells we drilled in the Eagle Ford,” he said. “About 10% of those wells are drilled with rotary steerables, and I think we will be at about 50% during the next month or two. If you really want to get the consistent, repeatable good results, you are going to have to do that with technology.”

Helmerich & Payne’s Rig 385, a FlexRig3 unit, is drilling for Pennsylvania General Electric Co in the Marcellus.

Helmerich & Payne has been building FlexRigs since the late 1990s and the A/C drive FlexRig3 since 2002. Today, the company boasts a 100% utilization rate of more than 200 FlexRigs in its US fleet. Most of them are working in shales.

“From our perspective, for the shale and unconventional plays, the more complex directional and horizontal wells, you need to begin with a platform that is A/C variable-frequency drive,” said John Lindsay, H&P executive vice president and COO. “We believe those rigs are the most efficient in the industry from a drilling performance viewpoint.”

The company has about 50 FlexRigs in the Eagle Ford, 21 in the Bakken, 20 in the Cana Woodford in Oklahoma, 16 in Haynesville (down from 29 last year due to low natural gas prices), and 11 rigs in the Barnett (down from about 25 rigs at the peak, also due to lower gas prices).

The FlexRig design concept is better safety and efficiency. “There are significant time savings to be gained in addition to the drilling process that benefits from lean manufacturing concepts,” Mr Lindsay said. “Only about 30% to 40% of the total well cycle is drilling; other areas for improvement include running casing, BOP nipple up and down, tripping pipe and moving the rig.”

The industry is also working on systems that will use real-time downhole data, for example, to deliver better performance based on the well that is being drilled, Mr Lindsay said. “With unconventional plays, there is a much more focused approach on factory delivery. The industry is set up much better today to look at a factory approach to exploiting reserves, which is a continuous focus on high-performance drilling.

“There also are a lot of lean techniques that go along with that – fit-for-purpose lean technology that continues to drive down drilling times by driving waste out of the process,” he continued. “After all, that’s what we are doing – we are manufacturing a hole.”

Helmerich & Payne’s Rig 260, a FlexRig3 design, is drilling for Penn Virginia Oil & Gas Corp in the Haynesville in East Texas.

About 450 of the approximately 1,700 rigs working onshore US are A/C drive rigs, Mr Lindsay noted, and H&P owns just over 40% of those 450 units. There are also more than 700 mechanical rigs working in the US today, and it is estimated that over 200 of those are drilling in unconventional shale plays. But he added, “It’s not a function of the (mechanical) rigs not being able to drill the well. It is a function of the rigs not being able to drill the well as efficiently and economically as an A/C drive rig.

“Drilling has become more complex,” he continued. “Several years ago only 30% of the rigs working in the US were drilling horizontal and directional wells. Today, it is a direct inverse of that, with over 70% of the rigs drilling horizontal and directional wells. And the horizontal laterals have increased in length an average of 30% to 50% over the past two years.”

Those factors are why A/C variable frequency drive (VFD) technology will continue to gain market share, Mr Lindsay believes. “A/C VFD technology has enabled the deployment of the first generation of true high-efficiency multi-parameter electronic drillers,” he said.

H&P is able to drill concurrently using multiple parameters such as weight-on-bit, torque, Delta P and rate of penetration compared with a traditional auto driller that controlled only weight-on-bit.  “We are just scratching the surface of what these systems will be able to do in the future.”

Many of the company’s rigs can skid over multi-well pads, and it manufactures its own skid system rather than buying from a third party. The skid system for its onshore rigs was adapted from its bidirectional skidding system used for offshore platform rigs, and in 2006 the first FlexRig4S unit was introduced in the Piceance Basin in Colorado that was capable of drilling 22 wells on a single pad. Shale development programs typically use drilling pads with between three to 10 wellheads, and this same system is being used today in the Marcellus, Bakken, Barnett and Eagle Ford.

Nabors Drilling’s Rig 266 drilled Brigham Exploration’s Abelmann 23-14 #1H in the Bakken Shale. All of Brigham’s rigs in the Bakken are Nabors rigs. Nabors photo courtesy of Jim Blecha Photography

Brigham Exploration said it will increase its operated fleet to 12 rigs this year in the Williston Basin’s Bakken and Three Forks plays by adding a rig every month beginning after May, when an eighth rig joins the fleet of rigs Brigham operates. “Accelerating from eight to 12 operated rigs is anticipated to increase Brigham’s drilling pace by approximately 44 gross wells per year” when the 12-rig level is met, which is anticipated to occur by September 2012.

“We are going to drill about 11 gross wells per rig per year,” said Erik Hoover, operations manager for Brigham. That translates into about 100 wells during 2011 and increasing to about 130 wells in 2012.

“With oil prices the way they are, liquid-rich fields are king,” Mr Hoover said. “Some plays are liquid rich, but the Bakken is probably the only true oil resource shale play.”

All of Brigham’s rigs in the Bakken are Nabors rigs, and the operator recently contracted two newbuild Nabors B Series PACE rigs. “I think many of the future Williston Basin rigs will be newbuilds because we’re now in more of a manufacturing mode, and newer rigs will likely be able to ‘walk’ from location to location and therefore reduce drilling costs,” Mr Hoover said.

Reducing drilling and completion times

Brigham’s wells average 17-23 days to TD, including a 10,000-ft vertical section and a 10,000-ft horizontal lateral. Three years ago, these wells took 30-35 days to drill.

Better drilling techniques account for some of the time reduction. For example, some operators who use oil-base mud in the lateral section are drilling 30-day wells. “We use oil-base mud in the intermediate section of our wells and brine water in the lateral,” Mr Hoover explained. “We typically set the bar at 20 days, but our record well was drilled in 14 days.

“With brine water we can drill up to 2,500 ft per day, but with oil-base mud we are lucky to get 1,000 to 1,200 ft per day,” he added. Most of the time, it would make sense that oil-base mud would result in a slicker downhole environment, reducing drilling time. However, when viscosity is added to the Bakken formation, it changes the drilling dynamics, Mr Hoover said. In some areas, oil-base mud is required where higher mud weights are necessary, but most of Brigham’s acreage is in normally pressured areas.

“The water drills like butter in the Bakken and Three Forks,” he said.

The rig and experienced drilling crews account for the faster drilling times as well. “Rigs are customized for the Williston Basin, and there are a few differentiators,” Mr Hoover noted. “One is an AC electric top drive drilling system, which is installed on virtually every Williston Basin newbuild rig.”

“New technologies and equipment on the rigs include BOP handling systems and automatic catwalks, which make these rigs more efficient,” Mr Hoover said. “There also are new drill bit technologies and directional drilling tool improvements.

“We’ve learned how to drill better, and that knowledge is combined with improved rig quality to contribute to fewer days drilling the well,” he added. “There also is a big push for safety, and some of the new technologies and equipment also increase safety on the rig.”

Nabors Drilling is active in numerous shale plays around the US and says it holds the largest market share in the Bakken shale, for which the company’s B Series PACE rig is designed. The B Series is essentially a winterized iteration of its 1,500-hp rigs for shales and conventional fields in warmer climates.

“The B series rigs with walking capability are well-suited for simultaneous operations when development drilling begins,” said Ronnie Witherspoon, senior vice president and general manager, Nabors Drilling Northern Division. “The rig can clear existing wellheads, and its skidding capability is conducive to pad layouts.”

Most new B Series units are delivered with Columbia substructure moving systems. Additionally, the rigs can be fitted with a moving system later if they are not delivered so equipped. The rigs are also equipped with technologies from CanRig, a Nabors company, including an automated catwalk, Torq-Matic floor wrench, a top drive drilling system with Soft Torque software to mitigate stick-slip and downhole vibration, and Rockit, a surface rotary steerable system that rotates the drillstring in horizontal wells to reduce downhole friction.

“All of our technology enhancements are geared toward optimizing drilling efficiencies while addressing the operator’s ultimate goal of minimizing the number of days on a well and shaving costs,” Mr Witherspoon said.

“When shale plays are in development, they will be in a manufacturing mode, so to speak, where well after well will be drilled from a multi-well pad,” he explained. “What we are trying to do with our rigs, equipment and software is to optimize the process and continue to drive down the number of days on a well.”

By Georgie Macfarlan, Andrew Reid, Rod Westwood and Matt Loffman, Douglas-Westwood

North America has experienced a steep increase in demand for high-horsepower rigs over the past five years due to rapid shale and tight-gas development. Douglas-Westwood forecasts that over 80% of newbuild demand over the coming years will be for high-hp rigs.

According to Douglas-Westwood analysis, total onshore drilling demand may reach a requirement for more than 7,300 active rigs drilling by 2015, with 52% of the demand coming from regions outside North America. In China, for example, the count is now greater than those in Canada and Russia. The global development of unconventional gas outside of North America will also have a profound effect on the global rig fleet toward the end of this decade. To meet the forecast production figures for European shale gas, for example, high-HP rig construction in the region would need to increase by over 1,000%.

The North American drilling market is the most documented in the world, with information regarding available and active rig fleets on a state-by-state basis kept by government and industry organizations. The market itself is highly commoditised and is marked by the presence of a large number of relatively small contractors that compete predominantly on price for an equally large volume of work.

The majority of North American drilling activity is in the hands of local oil and gas operators, while national oil company (NOC) presence is almost nonexistent. The vast number of small indigenous operators in the US is partially due to a legal regime that provides exploration rights to landowners; the US is the only country in the world with such a regime.

Dayrates are also lower in North America in part due to greater well program efficiency and the ability to easily move rigs between developments. Meanwhile, the oversupply of oilfield service and the numbers of companies operating in the US and Canadian markets do not represent a norm compared with other major regional bases of drilling activity.

Data from the Douglas-Westwood World Land Rig Market Report, which provides analysis of the international drilling markets in frontier and developing regions, as well as the established North American market, show that the global supply of land rigs is provided by more than 400 contractors, with the latest count exceeding 7,400 rigs. North America continues to lead the way in drilling and workover rig supply, although the majority of rigs are operating outside the US and Canada.

The growth in land rig demand since the beginning of the 21st century has been exceptional. Globally, the volume of rigs drilling for oil and gas increased by more than 100% between 2002 and 2008. Inevitably, North America accounted for a large proportion of this growth, although other key regions such as Russia and Middle East/North Africa (MENA) also contributed substantially to the growing demand for active drilling units.

It is estimated that at the start of 2008, an average of more than 6,200 rigs were actively drilling. Demand faltered in 2009, with the effects of the global economic recession reducing the operational rig fleet to an estimated 4,800. Although drilling demand fell in all primary hydrocarbon-producing regions, the demand reduction was led by North America – a market that has historically been highly sensitive to commodity prices. The widespread use of short-term contracts facilitated the rapid cutback of well requirements, compounding the steep decline in rig demand.

Outside of North America, reductions were far less severe. While key markets such as the mature provinces of Russia saw decline, much of this was E&A-driven. Ongoing development activity remained more stable due to the necessity to offset production declines in mature regions. The combination of a less sensitive international drilling market and a higher proportion of drilled wells present outside of North America led to a less dramatic downturn than in previous cycles. Furthermore, many operators work on yearly contracts, leading them to react slower to market trends and movements.

The outlook is clear: While North American demand has been re-incentivised through growth in commodity prices, activity in the region is unlikely to reach historic levels. Internationally, the opposite is true, with strong demand growth expected over the next five years and beyond. Douglas-Westwood estimates that growth in rig demand will average in excess of 5% per annum over the next five years, with strong growth set to occur within key markets on each continent.

Mexico will become an increased focus within Latin America, due primarily to increased expenditure by Pemex on exploratory activities. Although the mature environments of Libya and Egypt may witness a flat profile, other key MENA countries – including Saudi Arabia, UAE and most notably Iraq – are all expected to see substantial growth in the volume of rigs. In countries such as Algeria and Libya, the majority of this rig demand will be seen for horizontal and deviated drilling. Companies will seek to maintain production in maturing oil fields, and over 80% of newbuild demand will be for high HP rigs.

Douglas-Westwood’s analysis concludes that, by 2015, total onshore drilling demand may require more than 7,300 active rigs, and 52% of that demand will come from outside North America.

Growth of such scale inevitably requires an increased volume of rig construction – to increase the number of rigs currently available in international markets and to repair and replace existing fleets, which have suffered from a lack of investment over the last few decades.

Increased transparency on the part of Chinese contractors, particularly CNPC and its subsidiaries, confirms that the Chinese count is now greater than those in Canada and Russia; a number of other countries are also experiencing growth following the economic downturn in 2009. The increased activity and demand requirements are not solely from North America, with higher growth rates now evident in other regions, particularly MENA. Development of Chinese rig-building firms was particularly evident given the new opportunity to enter the global market.

Competition between manufacturers of rig components in frontier and international markets is strong. More than 100 companies now provide drawworks worldwide, with many of these also providing mud pumps and top drives. Development outside North America arguably provides more opportunities for oilfield service companies than producers, due to the number of NOCs within frontier markets.

Outside North America, the global development of unconventional gas will also have a profound effect on the global rig fleet toward the end of this decade. North America has experienced a steep increase in high-HP drilling rig demand as a result of rapid shale and tight-gas development over the past five years, while directional drilling is set to increase by nearly 25% over the next five years.

A total of 40% of US rigs are currently drilling directional wells while the vast majority of operational rigs are high-spec and of good quality. However, the size and specification of existing rig fleets in other regions will need to be increased dramatically to meet predicted E&A and well development demand. Although common across all regions, Europe and Australia will see the largest demand increases.

To meet the forecast production figures for European shale gas, for example, high-HP rig construction in the region would need to increase by over 1,000%.

Future demand within the rig market and the requirement to construct new fleet will be driven primarily by the age of rigs. The existing fleet is aging rapidly, the average rig 20 years old. The maintenance and replacement of this fleet is necessary in order to ensure suitability for continued and, in many cases, accelerated drilling programs.

Older rigs are likely to continue to be used for the drilling of in-fill wells. Equally, the complexity and depth of wells is increasing on a global basis. The depth of wells is increasing in key operating environments, such as Russia and MENA, while the use of deviated drilling is increasing, particularly within prolific gas-producing basins. Between 2010 and 2015, the global fleet of higher-HP rigs is set to increase by 46%, compared with only 27% for lower-HP rigs over the same period.

Newbuild activity has resumed in order to satisfy increased demand and to replace the aging fleet. Rig manufacturing capacity was put under pressure, and firms across the world prospered.

Recent activity has remained strong. While economic turmoil has put downward pressure on the number of rigs required to be working, this downturn has impacted to a lesser extent to previous cycles, and demand remains, relatively speaking, high.

By Dan Themig, Packers Plus Energy Services

Figure 1: Pumping acid enlarges the borehole, which can hinder isolation in the horizontal for multistage fracturing.

Drilling and completion operations in faulted reservoirs present a unique set of challenges. With the advent of multistage fracturing and multistage acidizing, the requirements for drilling methodology in reservoirs that contain faults or major fractures have changed. Additional considerations must be made for horizontal wells in faulted reservoirs as they behave differently than vertical wells. Understanding the shortfalls of certain methodologies, as well as the challenges of drilling in these reservoirs, is key to success.

The location of a fault in tight reservoirs may have both positive and negative implications. If the fault is connected to a series of natural fractures, then it can become the most productive segment of the well. We have seen applications where drilling across a single fault has produced a more prolific producing well than a standard multistage fractured well in a similar area of the field without faults.

Conversely, the fault may connect to water or may become a sinkhole for the stimulation fluids used on all of the stages during hydraulic fracturing.

In the past, faults were generally considered favorable unless connected to water. Stimulation of the faulted area was quite easy. It typically involved removing drilling damage caused by mud and filter cakes. Once these were removed, the wells produced easily, whether horizontal or vertical.

Because today’s target formations are tighter, the challenges are quite different. Not only do we need to provide prolific initial productivity – something you might see out of a single fault – but more importantly, we need to effectively drain all of the rock in the targeted area, which usually requires multistage fracturing.

Figure 2a: Cement leaking into the fault/fracture can result in a lack of fault isolation in a cemented liner completion.

Drilling horizontal wells in faulted reservoirs can be challenging. In particular, the specific location of faults is nearly always in question. When drilling a horizontal well, the chance of crossing one or more faults becomes very high. Sudden fluid loss after drilling through a fault or fracture can be difficult from a well control standpoint and can cause issues such as differential sticking of the drillstring.

In the past, nearly any practice was acceptable to rectify differential sticking; as long as the drill pipe released, drilling could resume. In tighter reservoirs, there are secondary objectives, such as maintaining hole integrity due to the requirement for multistage fracturing.

In one particular case, the common practice for releasing differential sticking was to pump significant volumes of hydrochloric acid to get the drill pipe to release. This process has been an acceptable drilling procedure for years. However, the operator is now drilling on the flanks of the field, and these wells require significant stimulation along the entire horizontal. Spotting acid is no longer an acceptable method to resolve differential sticking because the evolution in completion practices requires wellbore integrity.

After spotting significant volumes of acid, it is nearly impossible to establish isolation in the horizontal well to perform multistage fracturing operations because the borehole becomes significantly enlarged when the acid is pumped (Figure 1). Now the preferred process to release stuck pipe is to spot fluids with high lubricity and change the hydrostatic pressure by lightening the mud weight.

The requirement for multistage fracturing is driving change toward finding different solutions to drilling problems. Drillers may need to deal with sticking, maintaining hole integrity, reducing dogleg severity and controlling build radius.  In addition, more attention must be paid to hole preparation for multistage fracturing in that a reamer run is usually required immediately prior to installing a multistage fracturing system.

Figure 2b: Hydraulic-set mechanical packers placed on either side of the fault location can provide isolation.

In the past, the objective of drilling may have been to cross as many faults as possible, thereby increasing the potential productivity of the well. Intersecting faults in tight reservoirs may still be a desirable objective in shales and tight reservoirs. However, this practice alone may still leave the majority of the reservoir unproductive because it is not effectively stimulated.

It is clear that multistage fracturing and effective isolation during stimulation is now a key objective in shale and tight carbonate formations in faulted areas. In addition, effective isolation over the long term for issues such as water shut-off may be an important consideration.

Historically, cement was used to provide isolation between intervals. In vertical wells with faulting, this is fairly straightforward. The cement top may fall back or void spaces may be created in the annulus, but it is possible to squeeze these voids in the cement in an economic fashion. However, in horizontal wells with faulting, leak-off during the cementing operation or while the cement is setting up can be detrimental or even catastrophic to establishing isolation.

Now that the casing is lying horizontal, any significant leak-off (to a fault or fracture) after the cement is placed can create a void space at the top of the borehole that can extend for hundreds or even thousands of feet (Figure 2a). This void space can make it difficult or impossible to perform multistage fracturing because, once the fracture fluid is in the annulus, it will travel along the borehole and join a fracture from a previous stage.

Through microseismic data, we have seen instances where the fracture did not propagate at the perforations but instead traveled hundreds of feet down the wellbore (apparently through the annulus), where the fracture initiated and propagated. To make matters even worse, if a fault exists, it is likely that numerous fracture treatments will move one by one down the casing annulus and restimulate the same fault or major fracture.

Long-term use of cemented casing in faulted reservoirs with failed cement jobs are cost-prohibitive due to the multiple cement squeeze jobs required to repair them. Future water shut-off or enhanced recovery operations, such as waterflood and CO₂ injection, may prove unfeasible or even impossible.

Studies have shown that refracturing can be an effective practice in tight reservoirs over long periods of time. In some cases, refracturing has been done three to four times during the life of a vertical producing well. Faulted wells with poor cement jobs will make restimulation of specific intervals nearly impossible.

How can these above completion issues in faulted reservoirs be addressed? One key answer is effective isolation along the horizontal wellbore. Historically, the way to achieve this was cementing; however, issues with cement fallback are much more common than previously thought. Although we typically do not know where faulting will occur as the well is drilled, ample evidence is acquired during drilling to indicate when a fault has been crossed. By knowing the precise location of faults, further issues can be mitigated through the completion design.

For example, faults can be blanked off by placing packers on either side of the fault location (Figure 2b). Through experience, we have found that hydraulic-set mechanical packers can provide extremely high differential pressure ratings (in excess of 10,000 psi) in a variety of downhole environments. These appear to be the only packers installed in an open-hole environment that will hold high differential pressures over the long term.

In some areas of North Dakota, open-hole multistage (StackFRAC) systems, dual-element, hydraulic-set (RockSEAL II) packers have isolated water-bearing faults for more than 10 years at pressures in excess of 4,000 psi and 300°F. Therefore, they provide an excellent alternative to cement for both short-term isolation required in multistage stimulation, as well as long-term isolation for water shut-off, secondary recovery and refracturing operations.

The ability to locate a fault during drilling and effectively isolate that fault to either shut it off or provide appropriate stimulation injection, both to the fault and more importantly to the tighter segments of the rock, has emerged as a better solution in shale and other tight formations.

Figure 3: A fault is isolated during a stimulation treatment via specific packer placement in an open-hole, multistage fracturing system.

In one area of the Barnett Shale play in Texas, faulting is a common issue. In some cases, faults will be initially productive. Recovery issues, however, dictate that multistage fracturing using slick water and sand is required to effectively drain this area of the field. After evaluating the option of cementing, the operator initially decided that it was the best methodology to use.

However, upon review of these wells, they determined that stimulation treatments in the vicinity of a fault or natural fracture all went into the same area. In some cases, it was believed that as many as four fracture treatments were lost to faults, which not only wasted those treatments but failed to stimulate the adjoining tight rock. The problem was attributed to cement leak-off into the naturally occurring fractures and faults.

The decision was made to change from cemented to a non-cemented liner and open-hole mechanical packers. During drilling, faults and major fractures were identified based on drilling breaks, gas shows and lost circulation. Placement of the packers as isolation points in the horizontal was determined based on where the natural fractures and the faults in the horizontal well were located (Figure 3).

Post-completion results showed that, for the first time in this area of the field, faults in the well had effectively been isolated to allow successful multistage fracturing. Higher productivity, significantly better decline curves and longer-term productivity were observed. In addition, an unexpected result was that water cuts were significantly reduced because the faults were not overstimulated into deeper water-bearing formations.

The completion method for this part of the Barnett was changed to incorporate open-hole packers and ball-activated ports as the primary multistage fracturing completion and operation.

The Trawick field in East Texas contains a carbonate formation called the James Lime. It is a relatively tight carbonate reservoir that contains primarily gas and associated produced liquids. Historically, the operator used acid and water fracturing operations to stimulate these wells. The advent of horizontal drilling in the Trawick field presented a new set of challenges. The initial approach to fracturing the horizontal wells consisted of installing a preperforated, uncemented liner in the horizontal well. The liner provided wellbore integrity and the ability to place stimulation fluids effectively.

The method of diversion used was pumping ball sealers during the treatment to distribute the stimulation fluid. This approach did not provide mechanical diversion along the annulus. Because major faults/fractures were commonly located in the horizontal, once the fault was contacted by acid, all the stimulation fluids pumped there. This happened regardless of where the fluids exited the liner because they would travel along the annulus into the fault/fracture.

The net result was a highly stimulated fault. It was also determined that once a fault broke down in the presence of acid, no actual fracturing took place anywhere else along the horizontal.

The tight rock (not the fault) was the best candidate for massive stimulation because it contained the largest percentage of the reserves and required a high contact area to drain. Establishing mechanical diversion was determined to be essential. Cement was ruled out because it was viewed that cementing off natural fractures would greatly decrease productivity. Instead, open-hole mechanical packers were chosen. Installations were done during a two-year program in this field. Mechanical packer placement was determined by the location of faults/fractures crossed during the drilling operation.

Unlike shale, where the faults were isolated from stimulation (Figure 3), in the carbonate formation both the tight rock and areas with fault/fractures were stimulated.  Stimulation jobs were strategically designed to produce long hydraulic fractures in the tight rock using slick water and high pumping rates, and areas with natural fractures or faults were stimulated with smaller volumes of acid and water to remove drilling mud and drilling damage.

Open-hole, multistage fracturing systems with mechanical packers were run in this field on more than 30 wells. First, the verification of effective mechanical diversion was immediately evident. Intervals commonly exhibited distinctly different stimulation pressure charts as each interval was stimulated individually. Second, it was determined that the issue with faults and large fractures thieving fracture fluid from other segments of the horizontal was no longer happening. This methodology was used for two years on the drilling project in the Trawick field. Once it was determined that effective isolation of faults and major natural fractures could be achieved, the design of the stimulation treatments evolved, including a combination of both acid and sand fracturing.

The net result was a two- to four-fold improvement on initial productivity on a per-well basis. The cumulative productivity of the project doubled as a result.

• Faults and natural fractures in shales and tight reservoirs can be both beneficial and detrimental.
• Cement is unreliable at establishing diversion and isolation in faulted reservoirs.
• Open-hole packers have proven reliable at isolating faults both for stimulation and long-term production.
• In higher-pressure applications, mechanical packers provide excellent long-term isolation.
• Open-hole completions in faulted or fractured reservoirs provides the benefit of maintaining conductivity of natural fractures.

Unique considerations in tight reservoirs requiring multistage fracturing may also require changes in current drilling practices. Cement, historically viewed as a good isolation media, may not be the correct choice in horizontal wells with faults or fractures. Significant success has been achieved using mechanical, open-hole packers as a replacement for cement to establish diversion and isolation. Productivity and ultimate recovery have been significantly enhanced due to the flexibility of the stimulation process as well as the non-damaging nature of open-hole completions.

Seadrill recently announced several newbuild orders, as well as contracts for existing drilling units.In late March, the company entered an agreement with Singapore’s Jurong Shipyard for the construction of a new jackup. The rig, scheduled to be completed by the end of Q3 2013, is already contracted to ConocoPhillips for a five-year period on the Norwegian Continental Shelf. The harsh-environment rig will be capable of drilling in water depths up to 150 meters.Seadrill also exercised an option to build a new ultra-deepwater drillship at the Samsung Shipyard in South Korea, with delivery scheduled for Q3 2013. The rig has a design similar to the two drillships previously ordered from Samsung and will be able to operate in water depths up to 12,000 ft. It will be outfitted with a seven-ram configuration of the BOP stack and a 165-ton capacity heave-compensated crane.A new tender barge, T17, is also being constructed at the COSCO Nantong Shipyard in China, to be delivered in Q1 2013. Its design is similar to the two tender rigs Seadrill ordered from COSCO in February 2011.In April, Seadrill’s semi-tender rig West Menang was awarded an 18-month contract by Murphy Sabah Oil to operate on the Kikeh Spar deepwater field in Malaysia.Further, through its affiliate Sea Dragon de Mexico, Seadrill settled an agreement with Pemex for the provision of the ultra-deepwater semi West Pegasus, previously named the Seadragon I. The rig was recently delivered from the Jurong yard and is mobilizing to Mexico. Commencement of the five-year contract is scheduled to begin in Q3 2011.

Finally, Seadrill was awarded two contracts by BHP Billiton for the Offshore Vigilant in Trinidad and the Offshore Resolute in Vietnam. The three-well contract for the Offshore Vigilant is expected to commence in Q3 2011 and take 150 days. The two-well assignment for the Offshore Resolute is expected to begin in mid-2011 and last 90 days, although there are options for four additional wells that could take 200 more days.

Rotary Drilling Rig 67

Rotary Drilling Rig 67 drilling in Iraq’s Kurdistan region for Kalegran

Rotary Drilling Company, a subsidiary of CROSCO Integrated Drilling & Well Services, is providing drilling services to MOL Hungarian Oil and Gas subsidiary Kalegran Ltd with the 2,000-hp Rotary 67 rig. The Bekhme 1 well, the first of a two firm well contract, is being drilled in the Akre-Bijeel Block, in the Kurdistan region of Iraq. Rotary Drilling has established an office in Erbil and expects to mobilize additional equipment there soon.

6 Noble jackups win contracts to drill for Pemex

Noble Corp has been awarded contracts for six jackups with Pemex, all expected to commence in March or April 2011:

• Noble Bill Jennings for 286 days;
• Noble Leonard Jones for 272 days;
• Noble John Sandifer for 624 days;
• Noble Lewis Dugger for 588 days;
• Noble Gene Rosser for 248 days; and
• Noble Earl Frederickson for 139 days.

“These long-awaited contracts are a significant step towards putting our jackup fleet back to work in Mexico,” said Noble chairman, president and CEO David Williams.

Additionally, the contract for the Noble Carl Norberg has been extended for 146 days.

Statoil hires Songa Delta

Songa Offshore subsidiary Songa Rig has been awarded a contract from Statoil for the Songa Delta semi. Statoil intends to use the rig for its fast-track portfolio on the Norwegian Continental Shelf. The contract is for a firm three years plus a one-year option.

Japan Drilling orders new jackup from Keppel FELS

Japan Drilling Company has entered an agreement to construct a KFELS Super B Class jackup in Singapore. Delivery of the rig, which will be able to operate in up to 425 ft of water and drill to 35,000 ft, is expected in Q1 2013.

Korea National Oil Corp to partner with Anadarko in Maverick Basin/Eagle Ford

Anadarko Petroleum has signed a joint venture agreement with a subsidiary of Korea National Oil Corp (KNOC) giving KNOC a third of Anadarko’s interest in the Maverick Basin of Southwest Texas. “This transaction demonstrates the substantial embedded value of our Eagle Ford acreage position,” Anadarko president and COO Al Walker said.

Samsung to build 2 drillships for Maersk

Maersk Drilling has signed a contract with Samsung Heavy Industries to construct two ultra-deepwater drillships, scheduled for delivery in Q3 and Q4 2013. These will be the first drillships in Maersk Drilling’s ultra-deepwater fleet. They will be able to operate in up to 12,000 ft and drill to more than 40,000 ft. “We see an increasing share of the global oil and gas production coming from deepwater, and this trend will drive a solid growth in the demand for ultra-deepwater drilling services in areas such as Brazil, West Africa and the Gulf of Mexico,” said Claus V Hemmingsen, Maersk Drilling CEO and AP Moller-Maersk Group Executive Board member.

COSL Drilling Europe has signed a 12-month contract for the accommodation unit COSLRigmar with ConocoPhillips Skandinavia.
The unit will be used in the Greater Ekofisk area.

Barents Sea discovery could open new oil province

Statoil and its partners Eni Norway and Petoro have made a significant oil discovery on the Skrugard prospect in the Barents Sea. Statoil has called this a breakthrough discovery and one of the most important finds on the Norwegian Continental Shelf in the past decade.The well was drilled in a water depth of 373 meters using Transocean’s Polar Pioneer rig, built specifically for the Arctic. The Skrugard prospect is located approximately 100 km north of the Snohvit gas field in the Barents Sea. The estimated volume of the discovery is between 150-250 million recoverable bbl of oil equivalent, and Statoil sees opportunities for further upside in the license of up to 250 million bbl, for a potential of 500 million bbl of oil equivalent. The discovery may open “a new oil province,” said Statoil executive VP for exploration Tim Dodson.

Statoil has plans for the drilling of a new prospect in the same license next year and for a possible appraisal drilling at Skrugard.

Large gas find confirmed near Gorgon in Western Australia

Apache Corp and its partners have made a large gas discovery in the Zola-1 discovery well in license WA-290-P offshore Western Australia. The well logged 410 ft of net pay in three Triassic Mungaroo sands over a depth range of 13,450 ft to 15,100 ft below sea level. Logging tools and formation pressure tests confirmed at least two separate natural gas columns.
Zola-1 is located in the Carnarvon Basin 60 miles north-northwest of Onslow, Western Australia, in a water depth of 930 ft. The discovery is on trend with the Gorgon gas field 16 miles to the north and is near both existing and developing gas infrastructure.

A new seismic survey covering the Zola structure is planned for later in 2011.

Brunei Shell strikes oil in deepwater Brunei

Brunei Shell Petroleum (BSP) has made a significant oil discovery in deepwater Brunei. The discovery, named Geronggong, is located approximately 100 km offshore in 1,000 meters of water – the deepest water depth at which BSP has discovered hydrocarbons in Bruneian acreage.The discovery well was drilled using the Noble Phoenix drillship. Follow-up plans involve assessment of the full field recovery potential, including further appraisal drilling over the next two years.

Keppel to build jackups for Jasper, Perforadora Central

Jasper Investments has exercised an option with Keppel FELS to build a second KFELS B Class jackup for delivery in the first half of 2013. The option was given when Jasper ordered its first jackup from Keppel in December 2010. Similar to the previous rig, the new jackup will be able to operate in water depths up to 400 ft and drill to 30,000 ft.
Separately, Keppel AmFELS has won a contract from Mexico’s Perforadora Central to build a repeat jackup for delivery in Q1 2013. The rig will be based on the LeTourneau Super 116E design, able to drill wells up to 30,000 ft in water depths up to 375 ft.

Xtreme Coil expands fleet of coiled-tubing service rigs

Xtreme Coil Drilling has agreed to purchase five masted coiled-tubing service rigs as part of a fleet expansion to broaden its coiled-tubing well servicing capability in North American resource plays. The five rigs are intended for re-entry, coiled-tubing clean-outs, fracturing, wellbore extensions, production logging, perforating, stimulations and other well servicing work. They are expected to be service-ready later in 2011 after planned upgrades.

Hydraulic fracturing has been an area of aggressive research and development over the past several years, with operators and service companies introducing a number of “green” technologies as a response to public concerns and as part of the effort to improve well economics. Hydraulic fracturing to restore or enhance well productivity is performed in all types of formations and reservoirs and has become a high-profile operation as a result of its increased use in the prolific shale plays in North America and in other unconventional reservoirs.

Halliburton, Baker Hughes, Schlumberger, Weatherford International, GasFrac Energy Services, Universal Well Services and Frac Tech Services spoke with Drilling Contractor about the environmental aspects of hydraulic fracturing and “green” developments. These developments primarily address concerns of potential drinking water contamination, toxic chemical use and water use in fracturing operations.

According to Harold Brannon, pressure pumping senior advisor for Baker Hughes, fracturing is far and away the most efficient stimulation technique. Aside from its application in shales, hydraulic fracturing allows for drilling of fewer wells and can more effectively drain a given reservoir. Shales and most unconventional wells could not be successfully and economically produced without hydraulic fracturing stimulation.

“The US and North America in general is blessed with the most prolific shale formations on the planet,” he said. “Well stimulation makes the recoverable cost of hydrocarbons beyond what alternative energies can even approach. The cost is a fraction of what it is for nuclear, solar or wind.”

For those who question whether the hydraulic fracturing technique must be used at all, the answer is yes; it is the most common method used today to stimulate a well in tight sands, shale and coalbed methane. It is an economic way to improve productivity.

The size of the area drained by a hydraulically fractured well is larger than wells that are not stimulated by the process. And, according to the Independent Petroleum Association of America, fewer wells need to be drilled if hydraulic fracturing is used.

Service providers are anything but complacent about the process and have improved the technology to meet the needs of producers and address environmentalists’ concerns.

Hydraulic fracturing technology has advanced significantly in the 60-plus years it’s been around. According to Ted Lafferty, vice president of stimulation services for Schlumberger, historically the most important hydraulic fracturing technology developments have been in the area of fracture diagnostics. The introduction of pressure transient and net pressure analyses in the 1970s and ’80s provided the first link between well performance and fracture geometry and conductivity.

The development of analytical reservoir simulation techniques provided a means to more rigorously model and evaluate fractured well performance. With the development of RA tracers, measuring the near-wellbore behavior of hydraulic fracture treatments became possible.

“The most enlightening fracture diagnostic to date has been microseismic mapping, which has shown a surprising diversity in fracture growth and played a key role in advancing shale gas development,” Mr Lafferty said.

Microseismic mapping has shown that fracture growth can be much more complex than initially envisioned and has led to the understanding that fracturing complexity can be the key to economic success in some shale plays.

“We have seen significant improvements in our ability to model hydraulic fracture growth, from simple 2D models in the 1980s to widespread application of pseudo/lumped 3D models and fully 3D models in the 1990s,” Mr Lafferty said. “Our fracture-modeling capabilities have taken another major step forward with the recent introduction of complex fracture models that address the interaction of the hydraulic fracture with natural fractures. However, the industry still struggles with the integration of hydraulic-fracture modeling, G&G modeling and production simulation, resulting in predictable well performance.”

Advances in proppant and fluid technology in the 1980s contributed to the tight-gas boom. The application of hydraulic fracturing expanded with the introduction of high-strength sintered bauxite and intermediate strength ceramics and resin-coated proppants and the development of cross-linked fracturing fluids. Foamed, emulsified, alcohol and oil-based fluids also were developed for water-sensitive and underpressured reservoirs.

According to Mr Lafferty, the industry’s understanding of fracturing conductivity has improved dramatically in the past 60 years, with lab and field data suggesting that there could be significant reductions in conductivity due to stimulation fluid additives (e.g., polymers), embedment, non-Darcy flow and multiphase flow. These insights have led to the development of encapsulated breakers and advancements in novel fracture construction processes. Tip screen-out fracture designs for higher-permeability reservoirs contributed to the application of hydraulic fracturing in offshore environments, including sand-control applications and horizontal wells.

Improvements in multistage completion technologies and processes over the past 10 years have enabled large-scale development of many tight-gas and most shale-gas resources where 15-plus fracture treatment stages are now common practice in both vertical and horizontal wells. These improvements include drillable and flow-through bridge plugs, coiled-tubing perforating and fracturing, pump-down plug and perf operations and other uncemented isolation systems.

“One notable improvement was the introduction of a continuous mix system in the 1980s, eliminating the need to batch-mix large volumes of fluid,” Mr Lafferty said. Topside metering and measurement technology has also improved, including the use of mass and magnetic flow meters to monitor additives, on-site viscometers, computer data acquisition and control, and remote data transmission via satellites.

“Although there have been significant advances in hydraulic fracturing technology, there is still considerable uncertainty when relating fracture design to well performance. This uncertainty is partly due to the variability and heterogeneity of the reservoirs we are stimulating, but the industry continues to be fragmented when it comes to the evaluation of hydraulic fracture growth and well performance,” Mr Lafferty said. “We still lack routine and accurate measurements or reservoir characteristics in unconventional reservoirs. In addition, even when data are available, it is often not fully utilized.”

He believes that future advances in hydraulic fracturing will likely result from the routine integration of G&G, reservoir  and production data. This is achieved with fracture diagnostic measurements, geomechanical models and advanced fracture models.

“Schlumberger takes the concerns and regulations of the environments we work in extremely seriously,” said Mr Lafferty, who added that the company has continued to advance chemistries that are favorable from an environmental perspective. In 2010, the company commercialized the OpenFrac fully disclosed hydraulic fracturing fluids, a family of fluids that avoid the use of analytes listed on the US EPA Priority Pollutants and National Primary Drinking Water Contaminants.

Although chemistry has traditionally been the means of achieving fluid performance in hydraulic fracturing, the company is looking for improvements in non-chemical processes, such as bacteria control, proppant transport and proppant flowback control, as well as new approaches in hydraulic fracture construction. The most recent service is the Schlumberger HiWAY hydraulic fracturing technique, which is a process for fracture construction that delivers a step-change in fracture conductivity and uses 45% less proppant material.

Several of these technologies were introduced over the past decade and include the proppant-pack additives to prevent flowback in the reservoir and fracturing fluids that create a fiber-based network within the fracturing fluid, providing a mechanical means to transport, suspend and place the proppant.

Potential contamination of drinking water aquifers as a result of hydraulic fracturing is the key issue that has been debated for years by environmentalist groups and communities in which the technique is being used.

According to David Adams, vice president of product enhancement for Halliburton, the first step to protecting drinking water aquifers is providing adequate casing and zonal isolation in wellbores.

“We, as an industry, have to be sure these two items are completed,” he said. “The other thing we must be cognizant of is that perforating takes place in the hydrocarbon production sections of the wellbore.”

From a hydraulic fracturing perspective, there are additional means of protecting water aquifers – environmentally conscious chemistry, monitoring the path of treatments using microseismics and replacing biocides with ultraviolet light. Halliburton has introduced CleanSuite technologies – including CleanStim, CleanStream and CleanWave – in addition to 3D subsurface fracture mapping and dry polymer blending technology. In an effort to be transparent when it comes to the fracturing process, the company has also launched a micro-website that details what components are used during its fracturing process and compares them with common household products.

The CleanStim fracturing fluid is made with ingredients sourced from the food industry, offering an extra margin of safety if there is an incident at the wellsite. The product is not edible, but it does include a complete frac fluid system offering, a gelling agent, crosslinker/ buffer, breakers and a surfactant. Each of these components are rooted in the US Food and Drug Administration’s CFR 21 list, which defines foods for human consumption.

The amount of chemistries present on site has also been reduced. “Once we’re on location, we go to extreme measures to ensure that there is no spillage on the surface,” Mr Adams said. “We also monitor the pressures and rate to determine the characteristics of the fracture downhole.”

Halliburton’s Advanced Dry Polymer Blender, in use in roughly 40% to 50% of the company’s North American stimulation fleet, eliminates the need to use mineral oil as a carrier mechanism to deliver the gelling agent to the fluid system. Use of this blender has conservatively eliminated more than 10 million gallons of mineral oil from fracturing treatments in 2010, according to Mr Adams.

The company also uses an electrocoagulation technology to treat frac or flowback water on site for re-use. It features a mobile electrocoagulation unit that uses electricity to treat up to 26,000 bbl/day of water.

A new container system, called a SandCastle, is also in use to store proppants in a vertical state, enabling delivery by  gravity into the fluid system. In the past, conveyor belts with hydraulic engines were used; eliminating the engine has resulted in reduced emissions on site.

High-horsepower pumping equipment, high-performance friction reducers and efficient completion technologies all help to reduce surface impacts of hydraulic fracturing. Photo courtesy of Baker Hughes

Baker Hughes agrees that the first and foremost method of protecting water aquifers is the use of best practices for well construction – good cementing and casing jobs. A secondary method is to evaluate the environmental efficacy of additives, a process that the company began about a year and half ago in conjunction with Entrix, an environmental consulting firm. The BJ SmartCare system gives Baker Hughes the ability “to assess the products that we had and identify suitable alternatives which we could run through the same process and get an environmental footprint of them,” Mr Brannon, pressure pumping senior advisor for the company, said.

“We see the SmartCare selection system being pervasive throughout all of our pumping operations,” Mr Brannon said. “We’re taking a proactive step in trying to address cementing, acidizing, well completion processes, and all the various chemicals we might pump downhole, and ultimately have all those be green.”

“We’ve been able to do so in the fracturing treatments without really adding to the cost, which was a concern going in for us and for most operators,” he said.

Passive microseismic technology is also used to monitor subsurface fractures as they are being created. Should a fracture begin to develop in an unwanted direction, that fracturing stage can be shut down immediately. “It gives the information in real time of whether or not you are approaching a hazard and to shut down the treatment,” Mr Brannon said.

To minimize environmental risks, the BJ SmartCare family of fracturing fluids and additives uses quantifiable and standardized chemical evaluations to assess products and identify possible alternatives. Photo courtesy of Baker Hughes

Going beyond the chemicals, a process involving ultra-high quality foams is being used to minimize the amount of water needed in the fracturing treatment by 95%, which also reduces truck traffic at the wellsite. Baker Hughes’ VaporFrac fracturing fluid also eliminates post-frac cleanup, water disposal costs, frac tank rentals, sand haulers and proportioning units. Further, the lack of polymer residue means there’s virtually no formation damage. According to Mr Brannon, the process is already being used successfully on vertical wells in New York.

The company is also working on water treatment systems, including thermal evaporation technology. “We’re also using viscoelastic surfactants and recovering viscosified fluids that can be recycled. The limitation is that we only get a maximum of 30% of the fluid back when the treatment is completed,” Mr Brannon said.

When it comes to protecting drinking water aquifers, Steve King, US sales and technical manager for Weatherford, cites proper drilling, casing and cementing programs as the primary protection mechanism, along with the fact that these aquifers are typically shallow and close to the surface. “The intervals in which we perform hydraulic fracturing treatments are very deep, so you literally have thousands of feet of separation between the drinking water aquifer and the reservoir rock that is undergoing fracturing treatment,” he said.

There are two additional lines of defense in protecting drinking water aquifers: monitoring the rate and pressure of the fracturing treatment and the use of microseismic techniques. “Specifically, we monitor the process in real time, taking injection rates and pressures at which the treatment goes into the ground. Any abrupt change in rate or pressure is an indication that the process is going somewhere unanticipated,” Mr King said. “Any job can be easily stopped if those rates and pressures are not what were predicted.”

Mr King said his company is “taking a closer look at the (environmental) requirements that are in place and projecting those requirements into the future. For example, what will those requirements be in six months?”

With regard to reclamation and re-use of frac water, Weatherford’s Johnson Screens division reclaims water through a two-step process that involves the physical separation of the solids from the water and further filtering and clarification. “The distillation process has been around for a long time, but it’s never been an economical solution,” Mr King said. “But in today’s terms, as water becomes more difficult to acquire and the expense of acquiring, recovering and disposal increases, the cost of distillation may become an option.”

Calgary-based GasFrac Energy Services takes a different approach to hydraulic fracturing that eliminates the need for water use, cleanup and disposal. According to Robert Lestz, GasFrac chief technology officer, the company has completely removed the need to use water in the fracturing process. Rather than using water treated with chemicals, it uses 100% liquefied petroleum gas (LPG) gelled with proprietary chemicals.

The use of LPG evolved as the result of an evaluation process that was undertaken in 2000 to find the cause of well underperformance, said Mr Lestz, who previously worked with Chevron. Although the wells that were being fractured may have been economic successes, from a pure technical perspective, they were underperforming. “We came to understand that it was because we were using water-based fluids. In lower-permeability, tighter reservoirs, the use of water became more damaging or created sub-optimal performance after stimulation,” he said.

The effort to arrive at a better stimulation solution set out to remove water from the equation, Mr Lestz said, “but it was not an issue of water supply or potential for water contamination but more so it was about reservoir performance.”

The removal of water from the fracturing process serves more than an environmental function. “There are fewer impurities with which to contend,” Mr Lestz explained. “Water may contain impurities that affect viscosity. However, LPG is a refined product having minimum impurities. When gelled with GasFrac proprietary chemicals, it has a consistent viscosity.”

Another benefit to using LPG is that it occurs naturally in gas wells and results in little or no formation damage. Adding water to undersaturated reservoirs can reduce and impair its effective permeability, Mr Lestz said. “We describe the process to landowners as ‘not even a drop is needed,’” he continued. “We’re using a natural gas byproduct to produce more natural gas and oil. It’s a closed-loop, sustainable and recyclable process with 70% to 80% of the LPG recovered in the first week.”

According to Mr Lestz, there are no carcinogens in the proprietary chemicals used to gel the LPG. In fact, one of the additives is used in antacid pills and another is used in water treatment plants; no biocide is required.

Universal Well Services personnel direct hydraulic fracturing operations for an operation in the Marcellus Shale near Pittsburgh, Pa. Photo courtesy of Universal Well Services

“There’s never been a greater time of innovation in our industry. This innovation is being driven by the fact that this shale resource is truly a world-class reservoir. Rather than working towards wringing more out of dwindling reserves, we now have a paradigm shift that makes investment in new techniques an appealing target,” Roger Willis, president of Pennsylvania-based Universal Well Services, said.

“People all over the world are seeing that shale is a development of historic proportions. We’re seeing companies getting into this business that would have in the past seen American energy development as a backwater,” he said.

Universal Well Services’ market niche is providing on-site hydraulic fracturing expertise in addition to sand handling, blending and high-horsepower pumping equipment and piping packages. “From a product development standpoint within this industry segment, we’re seeing innovation occurring at a breathtaking rate right now, and it’s coming from more suppliers than we’ve seen in the past,” Mr Willis said.

“We’re seeing interest from every degree of the spectrum of companies with which we partner, whether they’re developing pumps, additives or electronic components. … It gives us the ability to have much greater choices with the idea of environment in mind.”

Universal Well Services performed a hydraulic fracturing operation on a five-well horizontal pad with full location containment. The operation took place in the Marcellus Shale in north-central Pennsylvania. Photo courtesy of Universal Well Services

One additive that the company is looking to replace is winterizing agents used to keep liquid material from freezing and replace them with benign substances, Mr Willis said. “We’re also working on the use of dry products to eliminate the need to use a winterizing agent and not have to worry about a liquid phase.”

According to Mr Willis, there’s now a whole palette of technologies that can enable evaluation, monitoring and measuring the geometries of fractures as they are created. “This gives us the ability to apply much stronger design techniques and to better link the creation of the fracture in with the things that we can control, such as the type of fluids that we pump, the rates at which we pump, the orientation of the casing and how the fracture propagates in the ground.”

“Our job, creating the fracture in the ground, is a complex process; I think the pace of refinement in hydraulic fracturing techniques is right now at the steepest it’s ever been,” Mr Willis commented, adding that the bulk of research and development expenditures at the company is focused on environmental protection.

“At every turn we are trying to answer questions. We’re spending an inordinate amount of time making sure that, if someone has a question, there is someone there to answer it truthfully in a form that’s understandable and defendable.”

Frac Tech Services is mobilized to conduct a hydraulic fracturing job in the Haynesville Shale. Currently the average lateral length for wells in the Haynesville is 4,500 ft, with an average of 14 fracturing stages. Photo courtesy of Frac Tech Services

Frac Tech Services, headquartered in Cisco, Texas, is solely focused on providing hydraulic fracturing and well stimulation services and owns sand mines and resin-coating facilities. The company recently introduced a dry formulation, Slickwater Green, to its family of environmentally friendly products that eliminates the need for many liquid products currently used in hydraulic fracturing, according to Brad Holms, senior vice president of marketing and technology for the company. This reduces the amount of truck traffic to the wellsite.

The company also has introduced Venus Green, an emulsified acid that uses an environmentally friendly formulation to stimulate carbonate reservoirs. “Some of the ingredients in our products are actually also used in the cosmetics and food industries,” Mr Holms said.

Risers extend from the frac stack to connect mobile frac units, each equipped with a proprietary high-pressure pump, with the wellbore. The risers are steel lines through which fracturing fluids and proppant (usually sand) are pumped down into the wellbore. Photo courtesy of Frac Tech Services

The company is also exploring the development and use of thermal evaporative technologies for water conservation. Testing of the new Slickwater Green fluid has demonstrated that it can be used with recycled water.

“The introduction of nanoparticle dispersion (NPD) is a prime example of our quest for new technology development,” Mr Holms said. NPD is used to separate hydrocarbons from rock, especially in older existing wells, and has been used to clean up injection and disposal wells, to clean up formation damage and in water block removal, he explained. “Over the next years, major leaps in nanotechnology will offer substantial improvements in efforts to improve production.”

By A.L. Martins, A.F.L. Aragão, P.E. Aranha, M.G Folsta and A.T.A. Waldmann, Petrobras

Figure 1: Drilling fluid invasion analysis for deepwater exploratory wells is applied to minimize fluid invasion into reservoir rocks. This was one topic studied as part of Petrobras’ efforts to support its ultra-deepwater projects.

Approximately 80% of Brazilian oil production comes from offshore fields. Campos Basin is the major producing area while Espirito Santo and Santos represent relevant reserves for the future. In most offshore scenarios, Petrobras faces deepwater (greater than 800 meters) and ultra-deepwater (greater than 2,000 meters), as well as reservoir-related issues such as salt drilling, nonconsolidated sands, heavy oil reservoirs and heterogeneous carbonates.This article presents a brief history of offshore well construction in Brazil, along with a discussion of wellbore hydraulic and the main R&D efforts focusing on hydraulics that the company has undertaken in association with a number of Brazilian universities.

Water depths in Brazil range from 500 meters to 3,000 meters while reservoir depths are typically 3,000 meters to 3,500 meters. Pre-salt cluster reservoirs are deeper (5,000 meters to 6,000 meters).

Development wells for the Campos Basin are typically directional or horizontal. Horizontal sections ranging from 500 meters to 700 meters are common in deepwater developments, and these long horizontal sections pose the first challenge for well trajectory. Particularly in heavy oil reservoirs, to maximize the reservoir area and guarantee an economical flow rate, a big challenge is to assure sand control in horizontal sections that are longer than 1,200 meters.

Another big challenge is drilling deepwater extended-reach wells. This may be a good option for dry completion projects, or even to consider shallow-water vessels to drill deepwater reservoirs. A ratio of lateral departure and vertical depth greater than two is considered to be critical and challenging.

Major issues in hydraulics include drilling fluid substitution and completion/ sand control, described below.

Monitoring Pressures during Drilling Operations

Figure 2: Flow loop tests were conducted with synthetic nonconsolidated sand cores saturated in heavy oil, using CT scanning to monitor hole enlargement. The aim was to optimize hydraulic parameters to drill heavy oil reservoir sections.

The main goals of a good hydraulic project are to obtain proper hole cleaning and maintain pressures inside the operational window. Another important issue is to make good use of real-time monitoring of downhole pressures. The industry has invested significantly in sensors and data transmission, but real-time interpretation is still far from the desired levels.

In some conditions, drilling hydraulics may limit the feasibility of the construction process. Dynamic pressures should be maintained inside the operational window defined by the pore, collapse and fracture pressures, guaranteeing that no influxes, losses or rock instability issues occur while drilling. Moreover, minimum flow rates are required to ensure that adequate drill cuttings transport occurs.

Downhole pressures are generated by two origins: hydrostatic forces and friction losses. Hydrostatic depends on fluid density and vertical depth while friction losses depend on fluid density and rheology, flow rate, flow geometry and flow path.

The hydrostatic term depends on the solids concentration and solid density-fluid mixture in the annulus. The solids concentration, on the other hand, depends on the cuttings transport process, affected by fluid rheology, flow rate and wellbore geometry. In critical scenarios, where the operational window is narrow, annular friction losses start to play an important role in downhole pressures. This is especially critical in deepwater reservoirs, deep reservoirs and fields that require long horizontal wells.

Minimizing downhole dynamic pressures depend on keeping good hole-cleaning conditions by defining an adequate rheological profile for the fluid and using proper drillstring geometry. Normally, in overbalanced drilling operations, the fluid density is designed in a way that a comfortable overbalance exists between the wellbore hydrostatic pressure and the formation pore pressure.

Fluid Displacement

There are two specific situations where minimizing contamination while displacing fluids is mandatory. First, when displacing a synthetic drilling fluid by water, there is a tendency for contamination in the riser due to the low annular velocities. Excessive amounts of contaminated fluids may generate environmental concerns and additional transport costs.

Another important situation is during the substitution of the drill-in fluid by a solids-free completion fluid in open-hole horizontal sections. In this case, any drill-in fluid left in the well may have detrimental effects on well productivity. Primary and plug cementing operations also require optimal displacement to guarantee proper zonal isolation.

Open-Hole Gravel Pack

This is the primary sand-control strategy adopted by Petrobras for offshore horizontal wells. Open-hole gravel packs consist of filling the open space between the wellbore walls and the production screens with sized gravel, generating a high-permeability pack, which would be able to allow oil production but restrict sand. The conventional operation is based on the conventional alpha-beta wave placement and is associated with large pressure drops during its final steps. During beta wave placement, the flow is diverted to the narrow annulus formed by the screen and the washpipe. In long horizontal wells, downhole pressures may exceed operational limits.

Figure 3: A completion fluid (red) displacing a drill-in fluid (yellow) in a horizontal section is simulated at different pump rates – 420 gpm (a), 500 gpm (b) and 600 (c) – due to concerns with fluid contamination.

In the early 1980s, the discovery of the Marlim and Albacora fields in the Campos Basin led to Petrobras gradually changing its profile into a deepwater company. To provide technical support for challenges encountered on these fields, the company started a corporate R&D program in 1986 called PROCAP. The deepwater technological program focused on areas such as reservoir engineering, well construction, flow assurance, subsurface equipment, surface facilities and risers, aiming at water depths up to 1,000 meters (3,300 ft).

Well construction challenges were encountered with the drilling of inclined wells in these scenarios. Wellbore stability and cuttings transport started to play a major role, especially after stuck pipe events. During this period, Petrobras’ well technology R&D team built a comprehensive two-phase flow model to account for cuttings transport in horizontal and highly inclined wells.

In parallel, experimental work concerning friction losses and cementing design for inclined wells were also performed. Knowledge about hydraulics design tools were very limited at this time and had to be gradually gained with experience.

The Marlim field was developed in the ’90s mainly with open-hole completion horizontal injector and producer wells, with 400 meters to 600 meters of horizontal length. Technological development was required to guarantee sand control: After the failure of prepacked screen technologies, Petrobras pushed the service industry to support the implementation of open-hole gravel-pack technology for open-hole horizontals.

Figure 4: Flow loop experiments with cores and CT scanning were conducted to try to minimize the interaction between the drilling fluid and the salt zone.

In 1991, a new corporate R&D program called PROCAP 2000 was started to support new discoveries in deeper waters (1,000 meters to 2,000 meters), including new phases Marlim, as well as Marlim Sul and Roncador. This program lasted until 2000 and hosted several technology projects focused on extended-reach wells and complex-trajectory wells – both situations where hydraulics played a fundamental role.

Cuttings transport modeling evolved for transient approaches and coupling with shale stability analysis, flow loop experiments and the search for field measurements of cuttings removal. During this period, successive versions of the in-house hydraulics software were delivered and widely used within the company. Feedback from field staff and continuous improvements gained from modeling and experimental work made this software a reference in the company even today.

An important achievement of this period was the construction of the extended-reach well 7-MLS-42H in 2001. The well, at the time a record in oil production, was drilled in 1,212-meter water depth to a depth of 5,211 meters – 2,896 meters vertical depth and 3,528 meters lateral departure.

In the past decade, as a result of the increase in exploratory drilling in ultra-deepwater, Petrobras has discovered new areas with heavy oil and, more recently, light oil in the pre-salt cluster.

PROCAP 3000 was launched in 2000 to support the ultra-deepwater scenarios for Marlim Sul and Roncador and other challenging exploratory prospects. Hydraulic topics included:

• Real-time decision systems based on downhole pressure data. The authors proposed a methodology and software to anticipate drilling problems based on PWD and other downhole data, mudlogging data and artificial intelligence techniques. The system has been in continuous improvement through tests run at rig sites and onshore decision support rooms.
• Managed pressure drilling (MPD) for floating platforms. The projects aimed to test and validate commercial systems in Brazilian offshore environments.
• Minimizing drilling fluid invasion into reservoir rocks. In these studies, the authors proposed a methodology to optimize drilling fluid composition for given reservoir properties. Rig-site testing, inverse log analysis, anisotropic and compressible flows were relevant topics in the study. Figure 1 highlights an invasion analysis for a deepwater exploratory well.

Figure 5: A numerical simulation of hole enlargement while drilling salt zones was developed, showing typical outputs.

In October 2002, Petrobras launched PROPES, a program focusing on offshore heavy oil fields. It covered most upstream disciplines and included an interface with the downstream area. The objective was to develop or integrate existing technologies that may turn into reality the challenge of producing heavy oil discovered in the Campos and Santos Basins. Hydraulic topics included:

• Drilling and completion of long horizontal well sections in deepwater environments. The focus was on gravel packing, Petrobras’ preferred sand control strategy. Several strategies were developed to guarantee proper gravel-pumping within the operational window.
• Optimization of hydraulic parameters to drill heavy oil reservoir sections: Flow loop tests conducted with synthetic nonconsolidated sand cores saturated in heavy oil indicated that water-based muds and low Reynolds numbers minimize leach ing. CT scanning was used to monitor hole enlargement during the tests (Figure 2).
• Fluid substitution in deepwater long horizontals: Fluid contamination in the riser and open-hole horizontals led to technical and environmental concerns. Cementing quality was also heavily affected by poor fluid substitution. Simulation of transient displacement flows enabled the establishment of dedicated pumping and spacer pill design procedures for each specific scenario. Aranha et al (2011) describe useful procedures for cement plug displacement, still a risky task today in deepwater scenarios where free-fall effects cause flow rate fluctuations while pumping. Figure 3 illustrates simulation results for completion fluid displacing drill-in fluid in a horizontal section.

In 2007, Petrobras announced the discovery of huge oil accumulations below the salt layer in the southeastern shelf. The development of such fields imposed the need for new technological development in several E&P disciplines, but with special focus on reservoir geology and well construction. To address these issues, PROSAL was launched. Important well construction issues included drilling build-up sections through salt zones, optimizing ROP in hard-rock reservoirs and stimulating heterogeneous carbonates. Hydraulic concerns address the following aspects:

• Minimizing the interaction between the drilling fluid and salt zone, avoiding leaching and change in fluid properties. Flow loop experiments with real cores and CT scanning were conducted to optimize fluid composition and hydraulic parameters for different salts (Figure 4). Mechanistic models to predict leaching and define design parameters while drilling and cementing salt zones were developed. Typical outputs are highlighted in Figure 5.
• Dynamics of acid wormholing generation in carbonates, including CFD simulation and experiments.
• Minimizing losses while drilling rubble zones and naturally fractured reservoirs. Figure 6 illustrates a unique strategy coupling computational fluid dynamics (CFD) with discrete element methods (DEM) simulation for bridging fractures.

Fundamental Work

Figure 6: Computational fluid dynamics is coupled with discrete element methods in a simulation for bridging fractures.

In order to achieve the technological results required in the previously described programs, a team effort was necessary. While R&D and E&P staff in Petrobras

was in charge of identifying priorities for future developments, foreseeing future trends, coordinating the projects and conducting internally strategic tasks, several other institutions played important roles in the process. Universities and research institutes accounted for fundamental and applied research, and service companies were the natural gateways for the introduction of new technologies. Whenever possible and convenient, partner operators shared costs, risks and benefits of the introduction of new technology.

Supported by Brazilian legislation, with R&D investments in Brazilian institutions with tax reductions, several projects have been developed by Brazilian academia in the past decade. Well construction projects were grouped into the Well Construction Technological Network – REDEP, with an annual budget of approximately US$20 million. Several universities and research institutes participated and conducted relevant wellbore hydraulics projects (Table 1).

Table 1: Supported by Brazilian legislation, Petrobras has undertaken well construction research projects with several universities and research institutes.

This article presented information about the R&D and technological implementation efforts on hydraulics by Petrobras and its partners. Relevant field results included:

• Massive exploratory drilling and reservoir evaluation in subsalt/ultra-deepwater environments.
• Offshore extended-reach wells.
• More than 270 open-hole gravel packs in sections as long as 1,200 meters.
• 2,000-meter horizontal section drilled in shallow-water carbonate heavy oil reservoir.
• Unique managed pressure drilling offshore experiences.
• Open-hole gravel packing with synthetic low-viscosity fluids.

Future scenarios present additional challenges that need to be addressed. All technological limits will have to be pushed to economically develop newly discovered fields.

This article is based on SPE/IADC 140145, “Well Construction Hydraulics in Challenging Environments,” presented at the 2011 SPE/IADC Drilling Conference & Exhibition, 1-3 March, Amsterdam.

All signs point to drilling activity increasing slightly in the Middle East oil and gas province. While activity was down in 2009 and 2010, contractors, operators and a rig yard in this region are reporting increases in activity and demand for drilling units. Rigs in the 1,500-hp to 2,000-hp range with top drives and increased personnel capacity are being favored.

“We’re seeing a huge rise in refurbishment activity,” said Lamprell marketing manager Ian Anderson. Lamprell, a major ship and rig builder in the Middle East that is bidding to take over neighboring Maritime Industrial Services, reports that Saudi Arabia and Iraq are taking up a lot of previously stacked rigs, and the former is bringing in new high-spec rigs as well.

Lamprell recently built two LeTourneau 116E units for Seadrill and is building two jackups for National Drilling Company and two land rigs for Weatherford Drilling International. It’s also refurbishing one rig for Dubai-based  Momentum.

“We’ve already seen quite a dramatic change in the drilling climate this year; Saudi Aramco is ramping up by 25% to 30% in drilling activity,” Larry Perras, general manager for Nabors Arabia, said. “They’re going from 90 to 118 rigs, we understand, and already we’ve seen most of those incremental contracts being awarded.”

Iraq also continues to demand more rigs, as does Jordan, Abu Dhabi and Oman, he said. “The whole Middle East region, with the exception of Libya, is trying to pick up the slack. Unrest in Libya has really affected the whole region in that Aramco is turning up operations to meet the demand shortfall. The company is needing to create infrastructure in some of its fields, so that’s created a major change in the number of rigs they need,” Mr Perras said.

He believes that activity will be greatest for Nabors Arabia this year in Saudi Arabia, where the company expects to run between 27 and 31 land rigs, followed by Iraq and Oman. There’s a lot of gas development going on, but the upturn in the market is mostly targeted for oil, according to Mr Perras.

“There’s a big increase we’ve just seen in March for oil rigs. One oilfield project in Saudi currently has eight rigs working, and they want to go up to 23,” he said. More workover rigs for oil projects have also been picked up.

Demand for rigs in Iraq is also high, he continued, although the lack of infrastructure there is having a slowing effect. “As the infrastructure gets in place, I think the rig count will go up significantly.”

And in Oman, the government is attempting to create more jobs for their citizens. “They’ve said they want more drilling,” Mr Perras said.

Nabors is looking at a 72% rig utilization in Saudi Arabia, but “with mobilization of some of the rigs from Saudi into Iraq and incremental rigs going back to work, we will be going to 91% utilization,” Mr Perras said.

Utilization in Iraq is 100% because rigs are sent there only against contract, and utilization in Oman is above 85%, he said. The company also has four rigs in Yemen, one operating and three on standby.

“Our current commitments to clients are going to pretty much take up the stacked rigs that we have, so the company purchased the newly built rigs so we can meet market demand quicker,” Mr Perras said.

In Saudi Arabia, Mr Perras reports that new contract specifications are requiring a huge capital investment on the part of  drilling contractors. “For example, they’re asking for API-monogrammed BOPs. There will probably be hundreds of millions of dollars spent on well control equipment to get up to that specification,” he said. “Then there are 7,500-psi mud systems; we’ve upgraded several rigs for that now.”

Offshore, Nabors Arabia had four jackups working, although two are now in the shipyard being retrofitted. “We’ll finish the year with four jackups working in Saudi,” Mr Perras said.

Rowan Companies’ Bob Palmer LeTourneau Super Gorilla XL 224-C jackup can operate in water depths up to 550 ft. Currently at a shipyard in Bahrain, the jackup is undergoing preparations for a contract in Saudi Arabia.

 

Rowan Companies’ Middle East manager Kelly McHenry reported that the region has witnessed an increase in drilling activity starting with Q4 2010. “We’re expecting the increase to continue, he said. “Our utilization is running about 70%. That hasn’t really changed from last year, but it will be increasing through this year. Dayrates are holding steady. We’re predicting that they will go higher.”

“As far as drilling plans and operations, unrest in the region has not affected us at all,” Mr McHenry said. “Just like every company, it has brought our awareness up. We did evacuate in Egypt. We and a lot of companies have gone back in. From a personnel perspective, we’re keeping a close watch on the situation in Bahrain.”

Offshore Saudi Arabia and Qatar are where Rowan is seeing the most activity now and expects to see the most drilling activity in the near future. While gas has been the predominant type of wells being drilled, there has been an increase in oil drilling as well. Mr McHenry said Rowan is contracting out rigs ranging from units with 10k BOPs and 1.2 million lbs of hookload to 15k BOPs with 2.5 million lbs of hookload.

“We are increasing personnel-on-board accommodations along with skidding capacities,” he said. “These are the big demands we’re seeing on tenders right now.”

Three of Rowan’s Marathon LeTourneau 116 cantilever jackups – the  Rowan Middletown, the Arch Rowan and the Charles Rowan – have been completely refurbished and steel has been replaced. These rigs are ready to come out of the yard in the United Arab Emirates.

The J.P. Bussell, a Tarzan-class rig, recently finished a contract in Egypt and is hot stacked. Three other Tarzan-class rigs working in Saudi Arabia – the Scooter Yeargain, the Hank Boswell and the Bob Keller – are coming to the end of their contracts.

In Qatar, three LeTourneau 116 rigs are in operation, though contracts are finishing up on a time frame of as little as two months to Q3 this year. Rowan has three LeTourneau 116 cantilever rigs working in the United Arab Emirates, and the Bob Palmer, a Gorilla-class rig, is undergoing modifications in a Bahrain shipyard and being prepared for a contract in Saudi Arabia.

According to Mr McHenry, Rowan has no plans for newbuilds for the region. “That could change any day,” he said. “There’s going to be quite a few (newbuilds) coming into the market through the next two years. It will impact everyone, but I think that the demand will compensate for it.”

Jim Ulch, country manager for Hercules Offshore Saudi Arabia, is optimistic about seeing an increase in the level of drilling activity in the Middle East this year and next. “Aramco recently announced they are going to increase their rig fleet this year,” he said. “We’re definitely seeing more tenders out this year.”

“There is a lot of equipment sitting in the yard right now; however, there is a lot of new equipment on the market,” he said. “It’s going to be tough for the older-style rigs to compete with that.”

Hercules has two high-specification harsh-environment rigs under construction in Singapore. Delivery is expected in mid- and late 2013. The rigs are being built to Saudi Aramco standards.

“Last year was a pretty slow year. You didn’t see any tenders at all basically; a few here and there. There’s been a big change from last year to this year,” Mr Ulch said. “As far as dayrates, we’re seeing a definite decrease in dayrates as rigs are coming off of three-year contracts, but I think there is an increase over what was being awarded at the first of the year. I expect that to continue on to the end of the year.”

The company has the Hercules 261 and 262, two cantilever Marathon LeTourneau Class 82-SD-C jackups rated to 20,000-ft drilling depths, on contract with Saudi Aramco. Jackup 261 is drilling for oil from a platform, and jackup 262 is performing workovers. Contracts on both rigs expire in September this year.

Mr Ulch said that Saudi Aramco is increasing its offshore rig fleet. On land, as well, an increase in activity is expected in Saudi Arabia, along with Iraq and Bahrain. In Qatar, he believes that the level of activity will remain the same.

“Hercules is basically concentrated in Saudi Arabia, but we are bidding equipment in Kuwait and will be bidding offshore tenders for Bahrain,” Mr Ulch said.

United Gulf Energy Resources has seen an increase in drilling activity in Oman of approximately 10% to 12% since 2009, according to Pat O’Shaughnessy, chief executive officer for the company. He expects to see another 10% increase in 2012 to 2013. In particular, 1,500-hp and 2,000-hp rigs are being requested. “Twenty-three operators hold concessions in Oman, and 10 of them are keeping 63 rigs, ranging from 750-hp to 2,000-hp, busy. The majority of contracts are from one to four years fixed term.”

“Operators are requesting that rigs be equipped with top drives, three mud pumps, three to four shale shakers, enhanced instrumentation-hydraulics-robotics-mud systems and fast moving features,” Mr O’Shaughnessy noted. “Also, tightly controlled certification requirements for blowout preventer equipment are common. Most desert rigs here have at least 100-man capacity, and some operators are now asking for 150-man capacity.”

Total rig count in Oman is 75, slightly higher than last year, with 12 idle rigs. According to Mr O’Shaughnessy, most of the idle rigs will be going to Iraq if they are not put to work soon. There are also 30 active workover rigs in the country.

He also said that newbuild super-single and automated drilling rigs are starting to have an impact in Oman by displacing older-style 750-hp to 1,000-hp rigs. The company plans to put six newbuild light drilling units to work in Kuwait.

“While Oman dayrates have held steady, albeit lower than in other Middle East countries, the rates must now increase by $1,000 to $2,000 a day after general unrest by the civilian population,” Mr O’Shaughnessy said. “These increases will not benefit rig owners since they are only to cover additional labor costs as mandated by the government.”

With 70% of its total business in Egypt and the rest in Libya, Syria, Saudi Arabia and Qatar, Egyptian Drilling Company (EDC) has seen an increase in rig utilization since the second half of 2010, according to Jens Byrialsen, EDC managing director. Operating primarily onshore, the company has 70 rigs and all are working except for eight units in Libya.

Dayrates are slightly better than in 2010, and Mr Byrialsen sees them firming up. The utilization rate has increased, and dayrates are starting to reflect that, he said.

“The Mediterranean is the fastest-growing market in Egypt for drilling,” Mr Byrialsen said, noting that it’s more of a gas play than oil today. While the company is primarily involved in oil drilling, EDC has taken note of increasing requirements for rigs associated with gas drilling, such as HPHT, well control, safety, restrictions on cuttings cleaning and disposal and skidding capability.

EDC has one 1,500-hp newbuild land rig under construction and is planning two more, one 1,500-hp unit and one 2,000-hp unit. “We’re optimistic about the future,” he said.

“I’m a little bit concerned about the number of newbuild offshore jackup rigs; there are still a lot of newbuilds to come this year and in 2012,” Mr Byrialsen said. “I have to be concerned about whether the market can sustain the influx. What we don’t know is how the market is going to react to the older part of the fleet.”

Regarding recent political unrest in the Middle East region, the company has shut down and evacuated all three of its rigs in Libya while drilling operations in Egypt have not been affected.

PEDEX, a non-government owned contractor, has entered the Iranian market with five land rigs and plans to add five more to its land fleet along with two jackups. The company’s Rig 201 is drilling in the central Iran Basin.

A new, non-government owned land rig contractor has entered the market in Iran – Pars-Energy-gostar Drilling & Exploration (Pedex). The company owns five land rigs and expects to increase its land fleet by another five units along with two offshore jackups, according to Masoud Eidi, managing director for Pedex.

The company was established back in 1981 as a contractor for construction machinery, then moved into the field of technical services for infrastructure projects in 1996. It entered the upstream oil and gas sector in 1999 after winning a tender as part of a consortium to drill 19 wells and to work over two wells in the Tabnak gas field in southwestern Iran. Pedex provides both drilling and technical services in addition to exploration.

The company’s primary area of activity is in the central Iran basin; however, according to Mr Eidi, Pedex plans to bid on both onshore and offshore projects outside of Iran.

In Iran, there is a real and urgent demand for drilling rigs, he said. To meet this demand, Pedex purchased one 1,000-hp trailer-mounted rig and four 2,000-hp units capable of drilling to an average depth of 7,000 meters. All of the rigs are equipped with selective catalytic reduction (SCR) units and top drives.

“Given that the geopolitical situation is going to be pretty dynamic for the remainder of this year and next year, I do think there’s going to be an increase in demand for onshore rigs, especially in Egypt,” David Blanchard, Egypt country manager for El Paso Energy, said. “There has been a rise in demand for the past six months for proven 2,000-hp top drive units. Onshore activity is increasing, and I think it will continue to increase.”

According to Mr Blanchard, larger 2,000-hp units are in demand because exploration wells are continuing to push depth limits and companies are seeking better cost efficiency and flexibility to drill shallow wells or 15,000-ft plus wells. El Paso itself concentrates entirely on onshore projects, and it has only one rig under contract because its current project is in the exploration phase.

“There are some premium 2,000-hp and maybe even 2,500-hp rigs coming into Egypt from Libya, and I wouldn’t be surprised if that supply is soaked up by the demand in Egypt this year in both oil and gas development,” Mr Blanchard said. “This year will be higher rig utilization than last year, around 90%.”

Dayrates are holding steady in the region, he said. “They’ve certainly bounced off bottom and are rising, although they’re not quite up to 2007 levels. Of course, if there’s a flood of rigs coming from Yemen and Libya or other places, all bets are off.”

With regard to the geopolitical situation in Egypt, Mr Blanchard commented, “We’re proceeding with our partners to fulfill our work commitment and program, and we’re not seeing any overtly negative impact from the unrest. All of the operators are keeping an eye on the situation, but so far it’s been fine. We’ve had support from the interim government; they are keeping things on track and the country regulators are getting things done. As an operator, we’ve not seen any negative impact.”

Ensco

“We’re bullish about what’s happening around the world. The Middle East might have been the last area to see the upswing. We’re starting to see an increase in interest and activity, so I think that in 2011 we’ll start to see everything improving in this region in terms of rig utilization, along with dayrates,” Steven Brady, general manager of Middle East and Asia Pacific for Ensco, said.

Operating solely offshore in the Middle East region, Ensco is currently has drilling operations in Saudi Arabia, Qatar and the United Arab Emirates. “I think that Saudi Arabia is going to be a high point for a lot of people as there is a lot of renewed interest from Aramco,” Mr Brady said. “We’ve seen a pick up in activity in Qatar and Abu Dhabi is also looking up. Interest is also increasing in Bahrain, although the country is not a big offshore rig user today.”

“In terms of well types, extended-reach wells are becoming more popular and require more horsepower,” he continued. “There’s more interest in HPHT work, so demand for 15k equipment is on the increase, and we’re seeing a desire for shallower-draft rigs. There are fields in Saudi that are environmentally sensitive and have some fairly shallow water depths.”

According to Mr Brady, “the demand for high-spec rigs is growing disproportionately to the demand for more standard-duty rigs and we expect that trend to continue for the long term.”

“Utilization bottomed out a few months ago to the low to mid-70%,” Mr Brady said. “Since late last year, it’s been on the upswing. I think that by late this year, utilization will be back in a much healthier range, maybe mid-80% or even a little better.”

Dayrates are tracking right along with utilization numbers, which found the bottom late last year, according to Mr Brady. “They’re starting to edge up a bit and we’re starting to see a healthy trend.”       

National Oilwell Varco

Offering an onshore perspective, National Oilwell Varco (NOV) sees the drilling climate in the Middle East “improving but at the normal recovery pace,” Kosay El-Reyes, vice president of business development for NOV said. “In general, things don’t change dramatically like they do in North America. Things slow down slowly and pick up slowly. This is with the exception of Iraq, where activity is increasing at a very fast rate.”  

NOV has facilities for drill pipe and region management in Dubai and Abu Dhabi as well as service facilities in Saudi Arabia, Kuwait, Egypt and Oman. “We are seeing increased business in top drives with higher-torque requirements of a longer drilling stem, pipe handling systems, the grade and length of drill pipe needed, and drilling controls for optimization and instrumentation to enable efficiencies to be realized, ” Mr El-Reyes said. “We’re also seeing increased need for iron roughnecks and better running tools.”

 NOV is opening a new coating plant in Abu Dhabi and building a fiberglass pipe plant in Oman. 

Noble Corporation

With its Middle East operations solely in the Arabian Gulf, Noble Corp. is seeing a moderate increase in rig activity. “Demand is not high, call it average. There are still a lot of rigs not working in the Middle East,” Charlie Yester, vice president and general manager for Noble, said.

In terms of utilization, Mr Yester notes that about 86% of Noble’s rigs in the region are under contract. Noble has 14 rigs operating there, two of which are among the company’s newest high-spec rigs. The company also has four newbuilds under construction in Singapore. “They are ideally suited for deep gas drilling in the Arabian Gulf,” Mr Yester said. “They could go anywhere; it depends on demand at the time the rig becomes available.” Also, the Marathon LeTourneau 116-C Noble Roy Rhodes, a jackup rig that has been in the region since it was built, has recently received a major upgrade.

“For our company, work is going to be pretty much split equally between Saudi Arabia, Qatar and the United Arab Emirates,” Mr Yester said. “Dayrates are up for rigs that have specialty tools and for standard jobs.”

Commenting on whether incoming newbuilds will have an effect on the market in the Middle East, Mr Yester said, “I think the latest round of newbuilds will not have a major effect on this market simply because the requirements here are not as great as they are in other places. Most of the wells here can be drilled with a standard 300-ft jackup. Of course, that could change in the future and we want to be ready to meet anticipated demand for higher-spec units.”

Wells being drilled are about 40% gas and 60% oil, according to Mr Yester. “We are seeing requests for higher specifications, 15 k pressure rating and extended-reach rigs in some cases,” he said. Larger top drives and more mud volume are among recent requirements. “Most of our rigs already have mud-cleaning equipment and three mud pumps,” Mr Yester said.  

Dalma Energy

“I don’t see any increase in the volume of tenders, maybe even 5% less than last year,” Dr Frederick Young, CEO of Dalma Energy, said. “I expect the drilling climate to stay pretty much the same as it was last year. The problem we have this year is that with the political changes in the Middle East, people are probably hesitating to award more work; so I expect it to stay the same.”

Dalma operates 22 land rigs in Oman, Algeria and Saudi Arabia. The company’s rig utilization rate is 100%. “We operate 22 rigs and all have contracts,” Dr Young said. “This year is an increase of around 15% utilization. We are now mobilizing on the contracts that we got awarded last year.” Dalma is currently drilling deep-gas wells for E.ON Ruhrgas in Algeria and horizontal wells for BP in Oman as well as performing workovers for Saudi Aramco.

According to Dr Young, the biggest increase in rig activity is expected in Saudi Arabia as Saudi Aramco announced that it intends to increase the number of working rigs by 35%. “But this work may not have been tendered at the moment,” he said.

“Rig demand is supposed to become high in Saudi Arabia, but I don’t see it yet. I’ve not seen tenders coming in to confirm what operators have announced,” he continued.

Activity levels in Oman in Algeria will remain the same, he said. Dayrates are holding steady in Algeria and are continuing to decrease in Oman and Saudi Arabia, according to Dr Young. “This is based on heavy competition from China and other low-cost countries.”

By Diane Langley, editorial coordinator

Hydraulic fracturing has been an area of aggressive research and development over the past several years, with operators and service companies introducing a number of “green” technologies as a response to public concerns and as part of the effort to improve well economics. Hydraulic fracturing to restore or enhance well productivity is performed in all types of formations and reservoirs and has become a high-profile operation as a result of its increased use in the prolific shale plays in North America and in other unconventional reservoirs.

Halliburton, Baker Hughes, Schlumberger, Weatherford International, GasFrac Energy Services, Universal Well Services and Frac Tech Services spoke with Drilling Contractor about the environmental aspects of hydraulic fracturing and “green” developments. These developments primarily address concerns of potential drinking water contamination, toxic chemical use and water use in fracturing operations.

Click to continue reading… Politics muddy debate over hydraulic fracturing risks 

By Diane Langley, editorial coordinator

Besides exploring for and producing energy resources, the energy industry is tasked with debunking myths and clarifying techniques used in hydraulic fracturing. Brian Petty, IADC executive vice president for government affairs; Lee Fuller, vice president for government relations for the Independent Petroleum Association of America (IPAA); Bob Moran, vice president for governmental affairs for Halliburton; and David Adams, vice president of product enhancement for Halliburton, spoke with Drilling Contractor regarding the politics of hydraulic fracturing.

Even though the US Environmental Protection Agency (EPA) has thus far not imposed a federal regulatory system usurping states’ regulatory authority in the area of hydraulic fracturing, the debate between the energy industry and environmentalists rages on.

Click to continue reading… ]]> http://www.drillingcontractor.org/technology-advances-push-greener-side-of-fracingpolitics-muddy-debate-over-hydraulic-fracturing-risks-9422/feed 0 http://www.drillingcontractor.org/unique-use-of-hse-mentality-gets-results-9342 http://www.drillingcontractor.org/unique-use-of-hse-mentality-gets-results-9342#comments Wed, 04 May 2011 20:13:26 +0000 Wr1t3rz http://www.drillingcontractor.org/?p=9342 Kuwait Oil implements psychology-based program to improve safety behavior

By Mohannad Al-Mehailani, Khaled Al-Hindi, Ashis Gohain, Saleh Muqeem, Safi Akhtar, Abdulwahab Al-Rakdan, Kuwait Oil Company

Before the introduction of a new psychology-based HSE program, Kuwait Oil Company faced a challenge to significantly increase its working rig count while retaining high safety standards. Following implementation of a new drilling HSE initiative, the number of recognized incidents became more accurately recorded.

“Making sure people are not harmed is how we do things in our workplaces” is the slogan consistently instilled into the minds of all personnel at Kuwait Oil Company (KOC). However, despite consistent campaigns for HSE compliance, crew members are often caught in unsafe acts. To minimize such unsafe acts, the KOC Drilling & Workover Team conceptualized and implemented a new approach for improving safety performance through psychology. Proper implementation of this safety program can result in higher effectiveness than some traditional safety programs.

Since the program was launched on a company drilling rig, it has yielded amazing results, with the number of near-misses and incidents declining substantially. The program is ongoing, and efforts are under way to further strengthen its effectiveness.

KOC’s strategy for increased oil production by 2030 called for a dramatic increase in the number of rigs. This created a pressing demand for increasing the rig count by twofold and to make them fully operational within a span of one year.

With the advent of a vast number of new rigs, the HSE setup within KOC faced a significant challenge to retain standards at the highest levels. Most of the new rigs were quick-moving and environmentally sensitive units equipped with state-of-the-art technologies. They had joystick-operated braking systems, electronic drilling systems, top drives, automated catwalks, iron roughnecks, BOP handling systems, etc.

However, the company recognized that, although technologically advanced equipment plays a big part in ensuring drilling efficiency, it’s really the experience, dedication and knowledge of the crews involved in the process that was key. KOC management recognized that an increased focus on worksite HSE systems would be a key component to achieving the company’s 2030 strategy.

Rig contractors also faced a significant challenge as they strived to mobilize and commission a huge number of rigs within the contractual time frame. Because of the advanced technologies and equipment found on the newly supplied drilling and workover rigs, adequate crew skills were required for correct and safe operation. The recruitment of experienced crews for each rig was undoubtedly an uphill task for all rig contractors.

As new rigs were introduced, the number of safety violations increased substantially. To find the reason for such violations, surprise visits to the rigs were carried out, and one strong reason found was the violator’s attitude. Proper implementation of different safety programs had not made a positive impact on HSE behavior. To put an end to such violations, a new safety approach was undertaken to change crew attitudes.

Rig 38, a KOC-hired drilling unit, was commissioned in April 2009. It is a 1,500-hp rig that was used to drill vertical and directional development wells with a maximum depth of 5,000 ft. The casing design for these wells were fairly typical – 18 ^5/8 in. at surface, 13 ^3/8 in. intermediate and 9 ^5/8-in. for production. The type of completion was either single or dual, depending on the well objective.

In short, the rig was not handling any extraordinary or new operation, yet near-misses, incidents and accidents occurred frequently. Compared with other similar-design rigs conducting similar activities, the number of incidents on Rig 38 was alarmingly high. Despite significant efforts and consistent campaigns for HSE compliance, there was no reduction in incident rates and crews on Rig 38 displayed a declining trend in their HSE behavior. Even senior crew members who knew the potential hazards were caught off-guard committing such unsafe acts.

Injuries were related to crews’ lax working behavior, such as fingers getting trapped at pinch points while housekeeping. Near-misses were also recorded, such as working at height without a safety harness. In one incident, a person was handling a 2-in. gate valve on section A of the wellhead with the help of an air hoist. The valve slipped from the lifting strap and struck the person’s left leg. The individual suffered a fracture in his left leg.

As part of an HSE initiative established at Kuwait Oil Company, crew members who are caught committing an unsafe act three times in a row are required to wear a jacket with a special slogan on the back as penalty for the violation. He must continue to wear the jacket until it is passed to another crew member who is caught committing an unsafe act. This new psychological approach to improving safety performance has proved effective for the company’s rigs.

The KOC team desperately underwent several rounds of brainstorming sessions before conceiving of an innovative idea involving human psychology in the form of a safety program called Psychological Effect on HSE Behavior. The program involves a jacket with a slogan printed on the back: “Caught in unsafe act … our company needs you.”

The jacket is kept by the company man on the rig, and any crew member caught in an unsafe act consecutively for the third time must wear the jacket as penalty for the violation. The person must continue to wear the jacket until another crew member is caught doing some unsafe act. The jacket is then passed to the new violator.

The violator is given clemency only for the two unsafe acts committed within that duty cycle.

The team also reviewed existing safety control measures to identify shortcomings. New measures were added, including safety control measures and safety observation and conversations. These efforts involved the use of HSE moments, stop cards, safety logo quizzes, lotteries, daily HSE tours, outdoor parties/barbecues, HSE knowledge evaluations, site verification visits, leadership visits, rig safety audits and training.

Lottery

The lottery is held on a weekly basis by drawing stop cards submitted by crew members. There is no limitation on the number of stop cards that can be submitted by an individual crew member, although each card is scrutinized for HSE relevance by the toolpusher before they can be dropped into the lottery box. Three winners are selected each time, drawn from the box by the drilling supervisor. Winners then read the stop card aloud and explain its contents to his fellow crew members. Failure to explain forfeits the win, and the drawing is repeated. The idea behind the drawing is not only material gain but also to facilitate the development of hazard identification skills and to express them.

Each winner gets an international calling card; the intent is to help him realize that back home he has family members who are solely dependent on him. The personal feeling that the individual experiences after the phone call may help to generate awareness about his personal safety.

Safety Logo Day

Safety Logo Day is held once a month where crews write short safety slogans in four to five words – for example, “No Safety, No Money.” Standard safety slogans are not entertained. All participants are entitled to gifts, and the best slogans along with the participant’s name are displayed in conference rooms and mess halls. T-shirts are generally provided as gifts.

Safety quiz

The safety quiz is another initiative to arouse HSE awareness and enhance safety in the workplace. The quiz date and its topic are announced one week beforehand. One quiz topic was, “How many eye pads are there on your rig and their condition.” Crews would locate the eye pads and check for any abnormality or noncompliance. The quiz is conducted by the drilling supervisor and toolpusher, and three winners are selected based on the nearest correct information provided. High-value prizes such as wrist watches, mobile phones and digital cameras are often awarded to the winners.

Administrative measures

Additional administrative measures to enhance safety included no frequent change of personnel, encouraging friendly behavior among crews, maintaining discipline and obedience and close observation of new crew members.

Engineering measures

Engineering measures that were taken included isolation of source, auto shutoff, auto stops; design, process or procedural changes; monitoring and warning equip ment; well-defined emergency plan for fire, H₂S and well control; and drills.

Inspection and certification

Inspection and certification ensured that job-specific safety rules were followed; pre-job safety meetings were conducted; job safety analysis was performed before all critical jobs; hydrogen sulfide training was completed and all employees have a certificate; the H₂S monitor and audible alarms were working properly; and periodic equipment inspections and certifications were conducted.

PPE

When it came to personal protective equipment (PPE), it was recognized that PPE should not be used as a substitute for engineering, work practice.

Root cause analysis

Root cause analyses found these reasons for safety violations: lack of coordination among coworkers; overconfidence concerning jobs; lack of job awareness; poor performance in a team environment despite good individual performance; poor assessment of hazards and risks; and not reporting near-misses.

Implementing all these measures resulted in maximizing the recognition of safe actions, employees’ overall skills, site safety awareness, employee participation in safety processes and employee skills in making observations. On the other hand, the measures minimized substandard practices, substandard conditions, injuries, incidents, property damage, worker compensation costs and production delays.

Merits of the program were:

• Incident prevention.
• Violator is vigilant in finding an unsafe act among coworkers in order to pass the jacket to another person.
• Better reporting of unsafe acts.
• Crew becomes more aware not to indulge in unsafe acts.
• Crew can differentiate between safe and unsafe acts.

Demerits of the program were:

• Violator may be mentally depressed and lose his concentration.
• Violator may stay focused only to find someone in an unsafe act.
• Could trigger an altercation between coworkers.

KOC is dedicated to identifying, correcting and preventing health, safety and environmental hazards that could adversely affect company employees, service providers’ employees or the general public. Further, management is committed to ensuring that all applicable regulatory health, safety and environmental protection requirements are complied with and that adequate resources are provided to ensure the health and safety of all employees, as well as the preservation of environment.

The ultimate goal is zero incidents. Both KOC and its contractors have greatly increased their loss prevention efforts in recent years. However, one of the toughest problems was coordinating and enforcing safety programs on drilling projects involving multiple contractors supplying different services.

However, as a result of our intense commitment toward proper implementation of all safety programs, the lost-time incident rate has significantly declined over a period of one year. The increase in minor injuries could be attributed to the  increased number of rigs. Moreover, better reporting is reflected by a higher number of near-misses in our HSE record.

Achieving results of this kind requires constant management commitment and focus, a trained and knowledgeable work force, work processes and controls that are understandable and enforced and, above all, a culture and belief that our work is never so important that we cannot take the time to do it safely.